## GREENHOUSE GAS EMISSIONS REPORTING FROM THE
PETROLEUM AND NATURAL GAS INDUSTRY

BACKGROUND TECHNICAL SUPPORT DOCUMENT

The Environmental Protection Agency (EPA) re gulations cited in this technical support document (TSD) contain legally-binding requirement s. In several chapters this TSD offers illustrative examples for complying with the minimum requirements indicated by the regulations. This is done to provide inform ation that may be helpful for reporters’ implementation efforts. Such recommendations are prefaced by the words “may” or “should” and are to be considered advisory. They are not required elements of th e regulations cited in this TSD. Therefore, this document does not substitute for the regulations cited in this TSD, nor is it a regulation itself, so it does not impose legall y-binding requirements on EPA or the regulated community. It ma y not apply to a particular situation based upon the

circumstances. Mention of trade names or commercial products does not constitute

endorsement or recommendation for use.

While EPA has made every effort to ensure th e accuracy of the discussion in this document, the obligations of the regulated community are determined by statutes, regulations or other legally binding requirements. In the event of a conflict between the discussion in this document and any statute or regulation, th is document would not be controlling.

U.S. ENVIRONMENTAL PROTECTION AGENCY

CLIMATE CHANGE DIVISION

WASHINGTON DCTABLE OF CONTENTS

1. Segments in the Petroleum and Natural Gas Industry

......................................................... 4 a. Petroleum Industry

............................................................................................................ 4 b. Natural Gas Industry

........................................................................................................ . 5

2. Types of Emissions Sources and GHGs

.............................................................................. 6
3. GHG Emissions from the Petrol eum and Natural Gas Industry

......................................... 7

4. Methodology for Selection of Industry Se gments and Emissions Sources Feasible for Inclusion in a GHG Reporting Rule

.................................................................................. 10 a. Review of Existing Regulations

...................................................................................... 11 b. Review of Existing Programs and Studies

...................................................................... 12 c. Selection of Emissions Sources for Reporting

................................................................ 19

i. Facility Definition Characterization

............................................................................ 19

ii. Selection of Potential Em issions Sources for Reporting

............................................ 20

iii. Address Sources with Large Uncertainties

................................................................ 24

iv. Identify Industry Segments to be Included

................................................................ 25

5. Options for Reporting Threshold

....................................................................................... 27 a. Threshold Analysis

.......................................................................................................... 28

6. Monitoring Method Options

.............................................................................................. 33 a. Review of Existing Relevant Reporting Programs/ Methodologies

............................... 33 b. Potential Monitoring Methods

........................................................................................ 33

i. Equipment Leak Detection

......................................................................................... 33

ii. Emissions Measurement

............................................................................................ 36

A. Direct Measurement

............................................................................................... 36

B. Engineering Estimation and Emission Factors

....................................................... 39

C. Emission Factors

.................................................................................................... 47

D. Combination of Direct Measurement and Engineering Estimation

....................... 47

c. Leak detection and leaker emission factors

.................................................................... 63 d. Population Count and Emission Factors

......................................................................... 63

e. Method 21

...................................................................................................................... 64

f. Portable VOC Detection Inst ruments for Leak Measurement

........................................ 66 g. Mass Balance for Quantification

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

.............................................. 67
i. Additional Questions Regarding Potential Monitoring Methods

.................................... 67
i. Source Level Equipment L eak Detection Threshold

............................................... 67
ii. Duration of Equipment Leaks

................................................................................. 69
iii. Equipment Leak and Vented Emissi ons at Different Operational Modes

............. 69
iv. Natural Gas Composition

....................................................................................... 70

v. Physical Access for Leak Measurement

................................................................. 71

7. Procedures for Estimating Missing Data

............................................................................ 71

a. Emissions Measurement Data

......................................................................................... 72 b. Engineering Estimation Data

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

.............................................. 72

d. Emissions Estimation Data Using Emissions Factors

.................................................... 73

8. QA/QC Requirements

........................................................................................................ 73

Background Technical Support Document – Petroleum and Natural Gas Industry 2a. Equipment Maintenance

.................................................................................................. 73 b. Data Management

........................................................................................................... 73

c. Calculation checks

.......................................................................................................... 74

9. Reporting Procedure

........................................................................................................... 75

10. Verification of Reported Emissions

.................................................................................. 75

Appendix B: Development of revised estimat es for four U.G. GHG Inventory emissions

Appendix D: Analysis of potential facility de finitions for onshore petroleum and natural gas

Appendix E: Development of multipliers to scale emissions or miscellaneous sources Appendix A: Segregation of Emissions Sources using the Decision Process

........................ 76

sources

............................................................................................................................... 84 Appendix C: Development of threshold analysis

................................................................... 92

production

....................................................................................................................... 106

connected to storage tanks

.............................................................................................. 110 Appendix F: Development of leaker emission Factors

......................................................... 113 Appendix G: Development of population emission factors

.................................................. 123 Appendix H: Glossary

........................................................................................................... 134 Appendix I: References

......................................................................................................... 141

Background Technical Support Document – Petroleum and Natural Gas Industry 3

### 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 use energy and emit greenhouse ga ses (GHG). It is co nvenient to view the industry in the following discrete segments:

 Petroleum Industry – petroleum production, petroleum transportation, petroleum refining, petroleum storage terminals, and

 Natural Gas Industry –natur al gas production, natural gas gathering and boosting (natural gas gathering and boosting are not in cluded in this rulemaking), natural gas processing, natural gas transmission and underground storage, liquefied natural gas (LNG) import and export terminal s, and natural gas distribution.

Each industry segment uses common processes and equipment in its facilities, most of which

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



### a. Petroleum Industry

Petroleum Production. Petroleum or crude oil is produced from underground geologic formations. In some cases, natural gas is also produced from 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 production pressure. The produced crude oil is typically separated from water and gas, injected with chemi cals, heated, and temporarily

stored. GHG emissions from cr ude oil production result from combustion-related activities, and equipment leaks and vented emissions. Equipment counts and GHG-emitting practices are related to the number of producing crude oil wells and thei r 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 natu ral gas, nitrogen, or carbon dioxide (CO 2 ), to decrease the viscosity of the petroleum a nd push it towards and up the producing well. Chemical injection EOR is carried out by injecting surfactants or polymers to improve the flow of petroleum and/or enha nce a water flood in the reser voir. Emissions sources from EOR operations are similar to those in convent ional petroleum production fields. However,

additional emissions occur when CO 2 is used for recovery. Th is 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 emissions sources is a major

source of emissions.

Background Technical Support Document – Petroleum and Natural Gas Industry 4Petroleum 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. These operationa l practices and storage tanks release mainly process GHG emissions. Em issions are related to the amount of crude oil transported 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 GHG reporting rule (40 CFR Part 98) published in the Federa l Register on October 30, 2009, addresses refineries and hence is no t 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.



### 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 emissions, equipment leaks, and vented emissions arise from the wells themselves, gathering pipelines, and all well-site natural gas treatm ent processes and related equipment and control devices. Determining emissions, equipmen t counts, and frequency of GHG emitting practices is related to the num ber of producing wellheads and the amount of produced natural gas. Further details are provided on the indi vidual sources of GHG emissions in Appendix

A.

Natural Gas Processing In the processing facility, natural gas liquids and various other constituents from the raw gas are separated, resulting in “pipeline quality” gas that is compressed and injected into the transmission pipelines. These separation processes include acid gas removal, dehydration, and fractionation. Most equipment and practices have associated GHG equipment leaks, energy c onsumption-related combustion GHG emissions, and/or process control related GHG vented em issions. Equipment counts and frequency of GHG emitting practices are related to the number and size of gas processing facilities. Further details are provided on the individua l 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 pl ants. Compressor station facilities containing

Background Technical Support Document – Petroleum and Natural Gas Industry 5large reciprocating and / or centrifugal co mpressors, move the gas throughout the U.S. transmission pipeline system. Equipment c ounts and frequency of GHG emitting practices

are related to the number and size of compressor stations a nd 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, pumps, and dehydrators are the prim ary 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 and exported LNG also requires transportation and stor age. These processes are similar to LNG storage and require compression and cooling processes. GHG emissions in this segment are related to the number of LN G import and export terminals and LNG storage facilities. Further details are provided on the individual 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. There are also underg round regulating vaults between distributio n mains and service lines. GHG emissions from distribution system s are related to the pipelines, regulating stations and vaults, and customer/residenti al meters. Equipment counts and GHG emitting practices can be related to the number of regul ating stations and the length of pipelines. Further details are provided on the individua l 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 ), carbon dioxide CO 2 , and nitrous oxide (N 2 O). All three gases were 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-derived fuels and natural gas as fuel in equipment (e.g., h eaters, engines, furnaces, etc.) in the petroleum and gas industry. CO 2 is the predominant combustion-related emission; however, because combustion equipment is less than 100 percent efficient, CH 4 and other unburned hydrocarbons are emitted. N 2 O results from both fuel-bound nitrogen and nitrogen from atmospheri c air. For methodologies to quantify GHG emissions from combustion, please refer to Subpart C of the GHG reporting rule

Background Technical Support Document – Petroleum and Natural Gas Industry 6(40 CFR Part 98), except for GHG em issions from flaring, onshore production stationary and portable combustion GHG emissions, and combustion emissions from stationary equipment involved in natural gas distribution. For methodologies to quantify combustion emissions from fl aring, onshore production stationary and portable equipment, and combustion emissi ons from stationary equipment involved in natural gas dist ribution, please refer to Subpart W.

Equipment leaks 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 tear or damage to the equipment. For ex ample, valves result in emissions due to

wear and tear from continuous use over a period of time. Also, pipelines damaged during maintenance operations or corrosi on result in unintentional emissions.

IPCC’s definition is not intuitive since f ugitive in itself means unintentional. Therefore, this document henceforth distinguishes between fugitive emissions (referred to as equipment leaks in the final subpart W) and vented emissions.

Equipment leaks are those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening.

Vented emissions are intentional or designed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not includi ng stationary combustion flue gas), including process designed flow to the at mosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas used to power equipment (such as pneumatic devices).



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

The U.S. GHG Inventory provides estimat es of equipment leaks and vented CH 4 and CO 2 emissions from all segments of the petroleum and natural gas industry. These estimates are based mostly on emissions factors available from two major studies conducted by EPA/Gas

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 7Research 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.

Petroleum Segment According to the 2006 U.S. GHG Inventory, EPA estimates that crude oil production operations accounted for over 97 percent of total CH 4 emissions from the petroleum industry. Crude oil transportation activitie s accounted for less than one half of a percent of total CH 4 emissions from the oil industry. Crude oil refi ning processes 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 2006 U.S. GHG Inventory for Petroleu m Systems currently estimates CO 2 emissions from only crude oil production operations. 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 equipment leaks from gate stations and pipelines.

Updates to Certain Emissions Sources

The EPA/GRI study used the best available da ta and somewhat restricted knowledge of industry practices at the time to provide esti mates 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; scrubber dump valves ; onshore combustion; 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 8The understatement of emissions in the U.S. GHG Inventory were re vised using publicly

available information for all sources and incl uded in the analysis, except crude oil and condensate storage tanks and flar es, and scrubber dump valves. 4 The revised estimates for storage tanks are available in “Analysis of Tank Emissi ons”, found in the EPA-HQ-OAR2009-0923-0002 docket, but the revised emissions have not been included in this analysis (See Appendix C for further details). For furt her discussion on the inclusion of scrubber dump valves in this rulemaking please see the analysis “Scrubber Dump Valves” in EPAHQ-OAR-2009-0923 docket. EPA has limited publicly available information to accurately

revise estimates on a national level for flaring and scrubb er dump valves. For onshore combustion emissions, EPA used emissions es timates from the GHG inventory which are

based on EIA data which EPA believes to be unde restimated. Refer to section 4(c)(iii) of the TSD for further details. This is explained further below. Appendix B provides a detailed

discussion on how new estimates were devel oped for each of the four underestimated

sources. Table 1 provides a comparison of emissions factors as available from 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 available in the U.S. GHG Inventory 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 Revised

Emissions

Factor Units

1) Well venting for liquids unloading 1.02 11 CH 4 – metric tons/yearwell

2) Gas well venting during completions

Conventional well completions 0.02 0.71 CH 4 – metric tons/yearcompletion

Unconventional well completions 0.02 177 CH 4 – metric tons/yearcompletion

3) Gas well venting during well workovers

Conventional well workovers 0.05 0.05 CH 4 – metric tons/yearworkover

Unconventional well workovers 0.05 177 CH 4 – metric tons/yearworkover 4) Centrifugal compressor wet seal degassing venting 0 233 CH 4 – metric tons/yearcompressor

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 9Table 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 90.2 198.0

Processing 35.9 39.5

Transmission and Storage 48.4 52.6

Distribution 27.3 27.3

1. U.S. EPA (2008) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006.
2.Production includes equipment leaks and vente d emissions from both the natural gas and petroleum sectors’ onshore and offshor e facilities.

After revising the U.S. GHG Inventory emissions estimates for the sources listed in Table 1, total equipment leak and vented CH 4 and CO 2 emissions from the petroleum and natural gas industry were 317 million metric tons of CO 2 equivalent (MMTCO 2 e) in 2006. Of this total, the natural gas industry emitted 261 MMTCO 2 e of CH 4 and 28.50 MMTCO 2 e of CO 2 in

2006. Total CH 4 and CO 2 emissions from the petrol eum industry in 2006 were 27.74

MMTCO 2 e and 0.29 MMTCO 2 e respectively.



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

It 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 GHG reporting rule, two prelimin ary steps were taken; 1) review existing regulations to identify emissi ons sources already being regul ated, and 2) review existing programs and guidance documents to identify a comprehensive list of emissions sources for potential inclusion in the proposed rule.

The first step in determining emissions source s to be included in a GHG reporting rule was to review existing regula tions that the industry is subjec t to. Reviewing existing reporting requirements highlighted those sources that ar e currently subject to regulation for other pollutants and may be good candidates for a ddressing GHG emissions. The second step was to establish a comprehensive list of emissi ons sources from the various existing programs and guidance documents on GHG emissions 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.

Background Technical Support Document – Petroleum and Natural Gas Industry 10

### a. Review of Existing Regulations

The first step was to understand existing regula tions and consider adapting elements of the existing regulations to a reporting rule for GHG emissions. When the Mandatory Reporting Rule development process began, there were three emissions reporting regulations and six emissions reduction regulations in place for the petroleum and natural gas industry, including one voluntary reporting program incl uded in the Code of Federal Regulations. This table also includes EPA’s final GHG reporting rule, which re quires certain petroleum and gas facilities to report their combus tion-related emissions. Table 3 provides a summary of each of these nine reporting and re duction 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 Rule: Mandatory Reporting of

Greenhouse Gases Mandatory

Emissions Reporting Point, Area, Biogenic CO 2 , CH 4 , N 2 O, HFCs, PFCs, , SF 6 , NF 3 , and HFE Annual reporting of GHG

emissions from direct emitters (including petroleum and natural gas systems) and suppliers of

industrial GHGs in the

United States.

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

EPA 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

Background Technical Support Document – Petroleum and Natural Gas Industry 11EPA 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 Pa rt 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 cannot serve as the foundation for a GHG emissions reporting rule.



### b. Review of Existing Programs and Studies

The second step was to review existing mon itoring and reporting programs to identify all emissions sources that are already monitored under these programs. When the Mandatory Reporting Rule development process began, 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 programs 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 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 emissions sources in the petroleum and

Background Technical Support Document – Petroleum and Natural Gas Industry 12natural gas industry was then undertaken to identify the speci fic emissions sources (e.g., equipment or component) for inclusion in a GHG reporting rule.

Background Technical Support Document – Petroleum and Natural Gas Industry 13Table 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 Industry14for 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 ActionAll legal entitiesCH4, non-combustionAll activities resulting inProvides references for use in making fugitiveRegistry General Reporting(e.g. corporations,CO2and other GHGindirect and direct emission ofcalculationsProtocol, March 2007institutions, andorganizations)registered inCalifornia,includingpetroleum and gas– all segmentsgasesGHG gases for the entityThe CCAR does not specify methodology to calculatefugitive emissionsCalifornia Mandatory GHGPetroleum –CH4, non-combustionAll activities resulting in CH4Continuous monitoring methodologies and equipmentReporting ProgramRefineriesCO2and other GHGgasesand CO2fugitive emissions forpetroleum refineriesor 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 ReportingPetroleum andCH4, non-combustionAll activities resulting inDirect, site-specific measurements of emissions or allof Greenhouse GasesGas- All SegmentsCO2and other GHGdirect and indirect emissionsmass balance factorsProgram (1605(b))gasesof GHG gases for thecorporation or organizationMass-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 Industry15Mass 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 EmissionsGas -CH4, non-combustionSegment-level counts,Equipment or segment emissions ratesEstimation Guidelines forTransmission/StoraCO2equipment discharges (i.e.Natural Gas Transmissiongevalves, open-ended lines, ventTier I (IPCC)- segment level emissions rates fromand Storage, Volume 1stacks), and segmentcapacities, facility counts andcapacitiesintentional 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 - PetroleumPetroleum and GasCH4, non-combustionRefers to API CompendiumTiers I, II, and III (IPCC) definitions and reportingIndustry Guidelines for– all segmentsCO2and other GHGpoints of monitoring:methods for all fugitive and vented GHG emissions inReporting GHG EmissionsgasesEquipment discharges (e.g.valves, open-ended lines, ventstacks), vent stacks forequipment types, tankPRV/vents, and facility inputthe 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 Industry16The Climate RegistryAll legal entitiesCH4, non-combustionAll activities resulting inContinuous monitoring methodologies and equipment(General Reporting(e.g.CO2and other GHGemission of GHG gases for theor process emissions ratesProtocol for the Voluntarycorporations,gasesentityReporting Program), 2007institutions, andorganizations)includingpetroleum andgas – allsegmentsMeasurement-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 AirPetroleum andCH4, non-combustionAll activities resulting inProvides quantification methods for all sources from allPartnership (WRAP)Gas – allsegmentsCO2and other GHGgasesemission of GHG gases for theentitysectors 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 factorsBackground Technical Support Document –Petroleum and Natural Gas Industry17i. EPA 2007 Cooperative Agreement with Univers ity of Texas (UT) Austin to Update GRI/ EPA Study Estimated Emission Factors

In the past decade, there has been growing interest in better understanding CH 4 emissions sources from the petroleum and natural gas industry. As mentioned above, the seminal study, upon which much of the current knowledge on CH 4 emission factors is based, is Methane Emissions from the Natu ral Gas Industry (GRI/EPA 1996). In the United States, the GRI/EPA Study serves as the basis for most CH 4 estimates from natural gas systems in

EPA’s Inventory of U.S. GHG Emissions and Sinks , EPA’s Natural Gas STAR Program, Methane to Markets International Program, St ate Inventories, the American Petroleum Institute (API) Compendium, a transmission a nd distribution protocol by the Interstate Natural Gas Association of America (INGAA), as well as all of th e organizations that reference these documents and programs in their individual work. The GRI/EPA Study was also evaluated for its relevance for a separate effort to develop a transmission and distribution GHG accounting protocol by the California Clim ate Action Registry. Internationally, the GRI/EPA Study is the source for many of the emission factors included in the Intergovernmental Panel on Climate Change Guidelines for National Greenhouse Gas

Inventories.

Although the GRI/EPA Study has been the cornerstone for estimating CH 4 emissions from the natural gas industry to date, the data on which the study is based are now over a decade and a half old and in some cases (e.g., wells, co mpressors), not always reflective of current conditions in the United States. In recognition of the fact that existing methane emission factors were becoming quickly outdated, in 2007 EPA funded a 4-year cooperative agreement with UT Austin to support research and, as appropr iate, measurement studies to update selected CH 4 emission factors from the 1996 GRI study. The cooperative agreement identified a small set of 11 prio rity sources in different industry segments on which to focus emission factor development. With the limite d budget available, as of mid-2010, the project has begun work on updating emission factors for reciprocating and centrifugal compressors only. Specifically, the project team has initia ted preliminary measurement studies at compressor stations at natural gas transm ission and storage facilities owned by two companies. Now approaching its final year, the project team is curren tly evaluating the most efficient use of the remaining resources; specifically whether to undertake additional

measurements on transmission and storage facilities to gain the most robust data set possible, or to use remaining funds on another source of emissions in the production, processing, transmission, or distribution segments.

The UT Austin cooperative agreement was in itiated to develop representative national

emission factors- it was not designed, like the GHG reportin g rule, to comprehensively collect actual GHG emissions data to support a ra nge of future climate policies. To meet the goals of the reporting rule, for larger sources, such as compressors, it is critical that EPA

collect actual emissions data in order to und erstand trends and also connect emissions to specific equipment and types of operations. For example, if there is a trend regarding the maintenance of rod packing over time, this information would not be obtained through a

static data set based on national co mpressor-level emission factors. .

Background Technical Support Document – Petroleum and Natural Gas Industry 18Further, the limited budget available for the UT Austin study will not allow for emissions information from a large number of sources ; the GHG reporting rule will be collecting comprehensive actual emissions data and othe r relevant information from major sources across the United States petroleum and natural gas industry for all U.S. facilities over 25,000 mtCO2e. In addition, the GHG reporting rule will collect applicable information (e.g., equipment component counts and operational da ta) needed to verify the reported GHG data and support future climate policy analysis.



### c. Selection of Emissions Sources for Reporting

When identifying emissions sources for incl usion in a GHG reporting rule, two questions need addressing. The first is defining a facility. In other words, what physically constitutes a facility? The second is determining which sour ces of emissions should a facility report? Including or excluding sources from a GHG re porting rule without knowing the definition of a facility is difficult. Therefore, both the facility definition and emissions source inclusion (or exclusion) were reviewed 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 locate d in a contiguous area and u nder the common control of the same person (or persons). This definition can be easily applied to offshore petroleum and natural production, onshore natural gas processing, ons hore natural gas transmission compression, underground natural gas storage, and LNG import and export equipment since the operations are all located in a clearly de fined boundary. However, as discussed further below, this definition does not as directly lend itself to all industry segments, such as onshore petroleum and natural gas production, natural ga s distribution, and petroleum transportation

sectors.

Onshore petroleum and natural gas producti on operations can be very diverse in arrangement. Sometimes crude oil and natura l gas producing wellheads are far apart with individual equipment at each wellhead. Altern atively, several wells in close proximity may be connected to common pieces of equipmen t. Whether wells are connected to common equipment or individual equipment depends on factors such as distance between wells, production rate, and ownership a nd royalty payment. New well drilling techniques such as horizontal and directional drilling allow for mu ltiple wellheads to be located at a single location (or pad) from where they are drilled to connect to different zones in the same reservoir. Therefore, the conventional faci lity definition of a “contiguous area” under a common owner/ operator cannot be easily applied to the onshor e petroleum and natural gas production industry segment. Refer to Section 4(c)(iv) in the TSD for a more detailed discussion of the facility definition for onshore petroleum and na tural gas production.

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

Background Technical Support Document – Petroleum and Natural Gas Industry 19operating in and determine if its total emissi ons surpass the threshold. See Appendix D for

further discussion of this issue.

In the natural gas distribution segment the mete rs and regulators in the distribution segment are primarily located at small stations or underground vaults di stributed over large urban or suburban regions. Individually defining each station or vault as a facility is impractical owing to the size and expected magnitude of emissi ons from single stations. However, a logical grouping of distribution equipment exists at th e regulated local distribution company level. The precedent for reporting at this type of f acility already exists under the Pipeline and Hazardous Materials Safety Administration (PHMSA) requirements under CFR Title 49 Section 191.11. Refer to Section 4(c)(iv) of th e TSD for a more detailed discussion of the definition for natural gas distribution. As ex plained in the Response to Comments, the PHMSA regulations primarily relate to pipeli ne safety provisions, and are unrelated to

information EPA seeks to collect under this rule.



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

Given that there are ove r 100 emissions sources 1 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 t echnical studies were used to identify the different 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 reporti ng. Typically, in petroleum and natural gas facilities, 80 percent or more of the faci lity 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 number of emissions sources required for reporting thus, keeping the re porting burden to a minimum. Emissions sources in each segment of the natural gas a nd petroleum industry can be sorted into two

Background Technical Support Document – Petroleum and Natural Gas Industry 20main categories: (1) top sour ces contributing to 80 percent of the emissions from the segment, and (2) the remaining sources contri buting to the remaining 20 percent of the emissions from that particular segment. Th is can be easily achieved by determining the

emissions contribution of each emissions sour ce to the segment it belongs to, 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 provides a listing of all emissions sources in the U.S. GHG Inventory and a breakdown of the top emissions sources by industry segment.

 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 equipment leak emissions from a unit source. For example, emissions from compressor blowdown venting for one compressor are much higher than equipment leak 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 equipment leak emission sources when the same monitoring method is used. Therefore, vented sources could be treated separately fr om equipment leak 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.

o 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 use of bucket trucks or scaffolding to access

Background Technical Support Document – Petroleum and Natural Gas Industry 21them. In such cases requiring emissions de tection and measurement may not always be feasible such as with leak detection equipmen t that requires the operator to be in close physical proximity to the equipment. Als o, such requirements c ould pose health and safety hazards or lead to large cost burde n. The accessibility of emissions sources was considered when addressing monitoring require ments and determining the type of leak detection equipment allowed under Subpart W.

 Geographical dispersion of emissions sources – The cost burden for detecting and measuring emissions will largely depend on the distance between various sources. Monitoring methods will have to be chosen considering the dispersion of emissions

sources.

 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 an emissions detection and meas urement 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

Requiring emissions leak detec tion and application of a corresponding emissions factor results in lower reporting burden as comp ared to conducting actual measurements. Furthermore, the use of leaker emissions factors provides an estimate of “actual” emissions as opposed to the us e of population emissions fact or 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 th e reporting rule. Error! Reference source not
found. shows the resulting decisi on tree that includes these criteria and supported the decision-making process. The decision process provided in Error! Reference source not
found. was applied to each emissions source in the natural gas segment of the U.S. GHG Inventory. The onshore petroleum production segment has emissions sources that either are equivalent to their counterparts in the natural gas onshore pr oduction segment or fall in the 20 percent exclusion category. Only CH 4 emissions from the petroleum segment were taken into consideration for this exercise give n that, for most sources, non-combustion CO 2 emissions from the petroleum segment are negligible in comparison to CH 4 emissions from the same sources. The exception to these are fl ares and acid gas recovery units in EOR operations that have large CO2 emission, but EPA does not have any emissions estimates for these source (see Section 3 and (4)(c)(iv) of th e TSD). Appendix A summarizes the results of this analysis and provides guidance on the feas ibility of each of the monitoring options discussed previously.

Background Technical Support Document – Petroleum and Natural Gas Industry 22Figure 1: Decision Process for Emissions Source Selection

Is the emission source an equipment leak?

Is source accessible for equipment leak detection?

Use equipment leak
detection and leaker
emission factors to
estimate emissions Use popul ation
emissions facto r and source coun t to estimate
emissions No N o Yes N o

Is vented emissions source geographicall y dispersed? Does credible
emission facto r exist? Yes

Use population
emissions factor an d

source count to estimate emissions Y es

Use Engineering
Estimation
metho d N o Does engineering estimation methodology
exist ? N o

U se E ngineerin g E stimation

m etho d Yes

Use continuous or period
monitorin g N o Is source contributing to top 80% o f emissions from each segment?

Yes No Potentially exclude

Is the equipment leak
emissions source geographicall y dispersed? Yes Yes

Background Technical Support Document – Petroleum and Natural Gas Industry 23

### iii. Address Sources with Large Uncertainties

As described in Section 3 of the TSD, the petr oleum and natural gas in dustry inventories are primarily based on the EPA/GRI 1996 Study, howev er the emissions for several sources in the EPA/GRI study do not correctly reflect toda y’s operational practices. In some cases, comprehensive and sufficient information is not publicly available to revise the national Inventory estimates. In cases where public data are available, it is often incomplete and does not represent the industry at a national level.

Over the years, new data and increased knowle dge of industry operations and practices have highlighted the fact that emissions estimates for certain sources are understated in the US Inventory

o Condensate and petroleum storage tanks

o Natural gas well workovers

o Natural gas well completions

o Natural gas well liquid unloading

o Centrifugal compressor wet seals

o Flares

o Scrubber dump valve emissions through tanks

o Onshore combustion emissions

The decision tree was not necessa rily ideal for the sources li sted above because they are

known to be underestimated in current inventorie s. Therefore, after careful evaluation, EPA determined that these are significant emission sources that should be included in a comprehensive petroleum and natural gas systems GHG reporting rule. The following emissions sources are believed to be significan tly underestimated in the U.S. GHG Inventory: well venting for liquids unloading; gas we ll venting during well completions; gas well venting during well workovers; crude oil a nd condensate storage tanks; centrifugal compressor wet seal degassing venting; scr ubber dump valves; onshore combustion; and flaring. Refer to Appendix B for a detailed discussion on ho w new estimates were developed for each of the underestimated sources; natu ral gas well workovers, natural gas well completions, and natural gas well blowdowns . For centrifugal wet seals, EPA used an emission factor from a presentation given at the 24 th World Gas Conference. 5

In addition, the U.S. GHG Inventory includes reasonable estimation of CH 4 and CO 2 combustion emissions from natural gas engines and turbines (except in onshore production), as well as petroleum refineries. Emissions fr om these sources were not considered further here because methods for calculating and re porting emissions from these sources are addressed in the background technical supp ort documents for Stationary Combustion

5 The Bylin, Carey (EPA) study reported we t seal degassing emission measurements from 48 centrifugal compressors. Five centrifugal compressors were found not emitting while, the remaining 43 emitted 14,860 thousand cubic meters per year. Twenty-three cubic feet per minute was determined by dividing the 14,860 by the 43 centrifugal compressors. Bylin, Carey (EPA), et. al (2009) Methane’s Role in Promoting Sustainabl e Development in Oil and Natural Gas Industry . <presented at 24th World Gas Conference>

Background Technical Support Document – Petroleum and Natural Gas Industry 24described in Subpart C and Petr oleum Refineries described in Subpart Y of the of the final GHG reporting rule (40 CFR Pa rt 98) respectively.

Onshore Combustion Emissions: The EPA estimates onshore production co mbustions emissions in its national GHG inventory. However, there are two challenges with the way these data are collected that make it difficult to use this data to support potenti al future climate policies. First, combustionrelated emissions are reported in the national inve ntory at a fairly high level of aggregation, making it difficult to discern facility-level em issions. Second, there are concerns that this aggregate estimate is underestimating the tota l emissions from this source. The National Inventory of U.S. GHG Emissions and Sinks uses the “lease and plant” fuel consumption data as reported by the Energy Information Administration (E IA) as activity data to apply an

emissions factor to estimate emissions. Howe ver, EIA estimates the lease and plant volume using data available from indi vidual petroleum and natural ga s producing States. The States in turn require only the voluntary reporting of this data from petroleum and natural gas producing operators raising questions as to whether the national data are complete. In addition, this estimate may not include all of the combustion emissions resulting from contracted and/ or por table combustion equipment. Given th e high level of aggregation of this data and the potential omi ssions of some fuel consump tion in onshore production in the National Inventory, this source ty pe would be valuable to incl ude in the rule for a more complete picture of facility-related emissions from onshore production facilities.



### iv. Identify Industry Se gments to be Included

Based on the understanding of facility definiti ons for each segment of the petroleum and natural gas industry and the id entification of potential s ources for inclusion in a GHG reporting rule, the industry segmen ts could be defined 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. However, in order to include this segment, it is important to clearly articu late how to define the facility and identify who is the reporter. Onshore production ope rations are a challe nge for emissions reporting using the conventional facility de finition of a “con tiguous area” under a common owner/ operator. EPA evaluated possi ble options for defining a facility for onshore petroleum and natural gas production in order to ensure that the reporting delineation is clear, to avoid double coun ting, and ensure appropriate emissions coverage. One potential option considered was to define a facility for this segment as all petroleum or natural gas equipment on a well pad or associated with a well pad

and CO 2 EOR operations that are under comm on ownership or common control and that are located in a single hydrocarbon basin as defined in 40 CRF Part 98.238. This includes leased, rented, or contracted activ ities by an onshore petroleum and natural gas production owner or operator. Where a pe rson or entity owns or operates more than one well in a basin, then all onsho re petroleum and natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility. In this case, the operator would be the

Background Technical Support Document – Petroleum and Natural Gas Industry 25company or corporation holding the require d permit for drilling or operating. If the petroleum and natural gas wells operate wi thout a drilling or operating permit, the person or entity that pays the state or federal business income taxes may also be considered the owner or operator. Operational boundaries and basin demarcations are clearly defined and are widely known, and reporting at this leve l would provide the necessary coverage of GHG emissions to info rm policy. This facility definition for onshore petroleum and natural gas produc tion will result in 85% GHG emissions coverage of this industry segment.

EPA reviewed other possible alternatives to define a production facility such as at the field level. In such cases, the company (o r corporation) operating in the field would report emissions. EPA analyzed this option a nd found that such a field level definition would result in a larger number of reporters and in lower emissions coverage than basin level reporting, sin ce fields are typically a segment of a basin.

In addition to basin and field level reporti ng, one additional altern ative is identifying a facility as an individual well pad, incl uding all stationary 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 petroleum heater-treaters, gas powered pneumatic inst ruments and pumps, electrical generators, steam boilers and crude oil and gas liquids stock tanks. In review ing this option, EPA found that defining a facility as a single wellhead would signi ficantly increase the number of reporters to a program, lower emissions coverage, and potentially raise implementation issues. For a complete di scussion of the threshold analysis and estimated emissions coverage for each of the onshore petroleum and natural gas production facility options considere d, refer to Section 5 of the TSD.

 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 –Processing plants process the gas received from production and/ or gatheri ng or boosting segments to remove hydrogen sulfide (H 2 S) and/ or CO 2 from the natural gas, if any, separate the higher molecular weight hydrocarbons (ethane, propane, butane, pentanes, etc.) from the natural gas and compress the natural gas to be injected into the onshore natu ral gas transmission segment. Natural gas processing facilities have a well defined boundary within which all processes take place. All emissions so urces in processing facilities could be monitored and included in a GHG reporting rule.

Background Technical Support Document – Petroleum and Natural Gas Industry 26 Onshore Natural Gas Transmission Compression – Transmission compressor stations are the largest source of emissions 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.

.

 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 GHG reporting rule.

 Natural Gas Distribution Segment – The distribution segment metering and regulator above ground stations and belo w ground vaults are identifiabl e as facilities. However, the magnitude of emissions from a single station or vault may not be significant,

which would result in minimal coverage of emissions from this segment. Multiple

stations or vaults collectivel y contribute to a significant share of emissions from the natural gas industry nationally, but they ma y not be considered one facility because they are not contiguous and there is no lo gical grouping unless the entire system is

considered.

Another option for including distribution sector is adapting the facility definition from Subpart NN, Suppliers of Natural Gas and Natural Gas Liquids, of the MRR which defines a local distribution company (LDC) as a facility. In this case, the definition of natural gas dist ribution would be the distri bution pipelines, metering and regulator stations and vaults that ar e operated by a Local Distribution Company (LDC) that is regulated as a separa te operating company by a public utility commission or that are operated as an independent municipally-owned distribution system This facility definition provi des clear reporting delineation because the equipment that they operate is clearly known, the ownership is clear to one company, and reporting at this level is consistent with the final MRR as well as other existing data reporting mechanisms. Additionally, th is aggregation of equipment will include all the significant sources of emissions from the segment.

 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.



### 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

Background Technical Support Document – Petroleum and Natural Gas Industry 27an 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 was conducted consider ing equipment leak 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 com bustion emissions from f acilities not already reported under Subpart C of the 40 CFR Part 98, but are required to be reported because the combined process emissions from Subpar W plus combustion emissions exceed the 25,000

metric tons CO 2 e reporting threshold. The equipment leak and vented emissions estimates

available from the U.S. GHG Inve ntory were used in the anal ysis. However, the emissions estimates for four sources, well venting for liquids unloading, gas well venting during well completions, gas well venting during well work overs, and centrifugal compressor wet seal degassing venting from the U.S. GHG Invent ory were replaced with revised estimates developed as described in Appendix B. Centri fugal compressor emissions were revised using centrifugal compressor activity data from the U.S. Inventory and an emi ssion factor from the

24 th World Gas Conference 5 . Incremental combustion emissions were estimated using gas engine methane emissions factors available fr om the GRI study, back calculating the natural gas consumptions in engines, and finally applying a CO 2 emissions factor to the natural gas

consumed as fuel. Nitrous Oxide emissions we re also calculated similarly. In the case of offshore petroleum and natural gas production platforms combustion emissions are already

available from the GOADS 2000 st udy analysis and hence were directly used for the threshold analysis. It must be noted that th e threshold analysis for 40 CFR Part 98, Subpart W includes all equipment leak 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 a ll segments of the petroleum and natural gas industry. A detailed discussion on the threshol d analysis is available in Appendix C.

The general rationale for selecti ng a reporting threshold could be to identify a level at which the incremental emissions reporting between thresholds is the highest for the lowest

incremental increase in number of facilities reporting between the same thresholds. This would ensure maximum emissions reporting cove rage with minimal burden on the industry. For example, for onshore production the emissi ons reporting coverage is 74 percent and the corresponding reporting facili ties coverage is 2 percent for a threshold of 100,000 MtCO 2 e per year. The incremental emissions and facili ties coverage is 11 and 2 percent (85 percent minus 74 percent and 4 percent minus 2 percent), respectively, for a 25,000 MtCO 2 e per year threshold. However, at the next reporting threshold level of 10,000 MtCO 2 e per year the incremental emissions and entities coverage is 6 and 5 percent, respectively. It can be seen that the incremental coverage of emissions decr eases but the coverage of facilities increases.

Background Technical Support Document – Petroleum and Natural Gas Industry 28Table 5 provides the details of the threshold anal ysis at all threshold levels for the different segments in the petroleum and gas industry. It must be noted that the threshold analysis estimates of emissions in this table are slightly different from the estimate of emissions in the April 2010 proposal. The slight decr ease in reported emissions of 4 percent for the entire oil and gas sector resulted from data and calculation corrections in the transmission and LNG storage segments and use of different well property databases in onshore production (HPDI ®
in the final, as opposed to LASSER ® in the April 2010 proposal). The same note applies to

Table 7 below.

Background Technical Support Document – Petroleum and Natural Gas Industry 2910,000Table 5: Threshold Analysis for the Petroleum and Gas Industry SegmentsEmissions CoveredFacilities CoveredSource CategoryThresholdLevelTotalNationalEmissionsNumber ofFacilitiesProcessEmissions(MtCO2e/year)CombustionCO2Emissions(Mt/year)Total Emissions(tonsmtCO2e/yr)PercentNumberPercent100,000 265,349,383 22,510 136,547,53560,732,073 197,279,608 74% 385 2%25,000 265,349,383 22,510 152,395,74673,695,453 226,091,199 85% 981 4%10,000 265,349,383 22,510 158,499,89782,061,519 240,561,416 91% 1,929 9%Onshore Natural Gas ProductionFacilities (Basin)1,000 265,349,383 22,510 165,212,24496,180,842 261,393,085 99% 8,169 36%100,00011,261,3053,2353,217,22825,1613,242,38929%40.12%25,00011,261,3053,2354,619,175500,2295,119,40545%581.79%10,00011,261,3053,2355,515,4191,596,1447,111,56363%1845.69%Offshore Petroleum and Natural GasProduction Facilities1,00011,261,3053,2356,907,8123,646,07610,553,88994%1,19236.85%100,000 33,984,015 566 24,846,992 27,792 24,874,783 73% 130 23%25,000 33,984,015 566 29,551,689 1,677,382 31,229,071 92% 289 51%10,000 33,984,015 566 30,725,532 2,257,443 32,982,975 97% 396 70%Onshore Natural Gas ProcessingFacilities1,000 33,984,015 566 31,652,484 2,331,531 33,984,015 100% 566 100%100,00047,935,1581,94424,197,4017,83424,205,23550%43322%25,00047,935,1581,94436,154,0616,155,31342,309,37488%1,14559%10,00047,935,1581,94437,593,6279,118,60346,712,23097%1,44374%Onshore Natural Gas TransmissionFacilities1,00047,935,1581,94437,993,6039,934,47447,928,077100%1,69587%100,000 9,730,625 397 3,557,040 0 3,557,040 37% 36 9%25,000 9,730,625 397 6,585,276 1,276,239 7,861,516 81% 133 34%10,000 9,730,625 397 7,299,582 1,685,936 8,985,518 92% 200 50%Underground Natural Gas StorageFacilities1,000 9,730,625 397 7,762,600 1,951,505 9,714,105 100% 347 87%100,0002,113,601157596,15425,956622,11029%43%25,0002,113,6011571,524,652188,5521,713,20581%3321%2,113,6011571,626,435204,2971,830,73187%4126%LNG Storage Facilities1,0002,113,6011571,862,200252,8952,115,095100%5434%100,000 315,888 5 314,803 0 314,803 100% 4 80%25,000 315,888 5 314,803 0 314,803 100% 4 80%10,000 315,888 5 314,803 0 314,803 100% 4 80%LNG Import Facilities11,000 315,888 5 315,048 840 315,888 100% 5 100%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 Industry30Note: Totals may not add exactly due to rounding. Equipment leak and vented emissions in the threshold analysis are a sum of facility level emissions for each segment. Hence the total equipment leak 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 applying the th reshold at the field level. Table 7 provides the results of the th reshold analysis for a field level facility

definition. The results of this analysis show th at at a 25,000 metric ton CO 2 e threshold, 1,157 facilities would be covered and only 57 percent of national emissions. If the threshold were decreased to 1,000 metric tons CO 2 e, over 80 percent of national emissions would be covered but the number of reporters would increase to over 22,000.

Table 7. Emissions coverage and number of rep orting entities for field level facility
definition

Threshold

Level 2 Emissions Covered Facilities Covered

Metric tons
CO 2 e/year Percent Number Percent

100,000 110,437,470 42% 306 0%
25,000 150,297,681 57% 1,157 2%

10,000 171,902,688 65% 2,549 4%

1,000 219,121,375 83% 22,459 33%

A third alternative for a facility definition wa s individual well pads as facilities for onshore petroleum and natural gas production segment. F our different scenarios were also considered below for applying thresholds at individual well pads.

 Case 1 (highest well pad emissions ): Drilling and co mpletion of an unconventional gas well early in the year w ith the well producing the remainder of the year with a full complement of comm on, higher process emissions equipment on the well pad including a compressor, glyc ol 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 wi th 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 dehy drator, gas pneumatic controllers, and condensate tank without vapor recovery.

 Case 3 (third highest well pad emi ssions): Drilling and completion of a conventional oil well early in the year w ith the well pr oducing the remainder of the year with a full complement of common, higher process emissions equipment on the well pad including an associat ed gas compressor, glycol dehydrator, gas pneumatic

Background Technical Support Document – Petroleum and Natural Gas Industry 31controllers, chemical injectio n pump, an oil heater-treater , and a crude o il stock tank without vapor recovery.

 Case 4 (fourth highest well pad emissi ons): 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.

Table 8 below illustrates the average emissions fo r each scenario and the number of facilities that have emissions equal to or greater than that average. 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 petroleum and gas production. Fo r the other cases, the threshold would have to be set lower

than the thresholds considered for other sect ors of the GHG reporting rule to capture even relatively small percentages of total emissions. In all cases, the number of reporters is higher

than would be affected under the field 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)

Number of Reporters

Covered Emissions (metric tons CO2e)

Percent Coverage 4,927

3,349

16,498,228

6% 700

38,949

40,943,092

16% 700

66,762

50,572,248

19% 370

166,690

87,516,080

33%

Background Technical Support Document – Petroleum and Natural Gas Industry 32The petroleum and natural gas industry may be somewhat uni que when calculating facility emissions to be applied against a threshol d for reporting. Subpart C in the GHG reporting

rule excluded the calculation a nd reporting of emissions from portable equipment. This was one option considered for the petroleum and natural gas industry. However, given that portable equipment is so central to many of the operations in the petroleum and natural gas industry and such a large contributor to emi ssions for the industry, particularly for onshore petroleum and natural gas production, portable e quipment emissions are an important source of emissions for inclusion a reporting rule. If these emissions were excluded from the threshold calculation, EPA estimates that a la rge number of facilities would fall below the threshold, preventing the collec tion of significant data from the industry that would be beneficial to the development of future climate policies and programs. Please see “Portable

Combustion Emissions” memo under rulemaking docket EPA-HQ-OAR-2009-0923.

Another issue that concerns onshore petroleum and natural gas producti on is the number of equipment operating contractor s that support the well operato rs. It is typical to find production well operators contracting out the ma jority of their process equipment from separation, dehydration, and tanks, up to ga thering and boosting and transport. Hence requiring well operators to report only emissions from equipment they own or directly operate could lead to a signifi cant reduction in emissions covera ge. Accordingly, the final rule provides that emissions from such equipm ent must be reported whether from equipment contracted to, leased from, owned or run by a th ird party. For a more full discussion of this issue, see Vol. 9, Response to Legal Issu es on Mandatory Greenhous e Gas Reporting Rule Subpart W – Petroleum and Natural Gas.



### 6. Monitoring Method Options

a. Review of Existing Relevant Reporting Programs/ Methodologies

To determine applicability of the different monitoring methods available, existing programs and guidance documents were reviewed. Table 4 shows a listing of the existing programs and guidance documents that 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.



### 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. Equipment Leak Detection
Traditional equipment leak det ection technologies like the Toxic Vapor Analyzer (TVA) and the Organic Vapor Analyzer (OVA) are appropriate for use in sm all facilities with few pieces of equipment. However, comprehensive leak de tection in large facilities can be cumbersome, time consuming, and in many cases costly. But ne w infrared remote equi pment leak detection technologies are currently being used in the Un ited States and internationally to efficiently

Background Technical Support Document – Petroleum and Natural Gas Industry 33detect leaks across large facilities. Considering these factors, one of the following two technologies can be used to detect leak s in facilities depending on suitability;

Infrared Remote Equipment Leak Detectors Hydrocarbons in natural gas emissions absorb infrared light. The infrared remote equipment leak detectors use this property to detect leak ages in systems. There are two main types of detectors; a) those that scan the an area to produce images of equipment leaks from a source (passive instruments), and b) those that point or aim an IR beam towards a potential source to indicate presence of equipmen t leaks (active instruments).

An 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 equipment leak source. The camera can actually “see” equipment leaks. The advantages of IR cameras are that they are easy to use, very efficient in that they can detect multiple leaks at the same time, and can be used to do a comprehensive su rvey of a facility. The main disadvantage of an IR camera is that it may involve substantia l upfront capital investment depending on the features that are made available. Therefore, th ese 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 equipment leaks. Such devices do not have screens to view equi pment leaks, but pin point the location of the emissions with a visual guide (such as a visi ble 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 equipment leaks 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 equipment leaks, 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 leaks along its circumference and such surfaces will ha ve to be monitored completely by tracing the instrument along each surface.

Calibration The minimum detectable quantity of equi pment leaks using an IR instrument depends on a number of factors including manu facturer, viewing dist ance, wind speed, gas composition, ambient temperature, gas temper ature, and type of background behind the equipment leaks. For best survey results, e quipment leak detection can be performed under

Background Technical Support Document – Petroleum and Natural Gas Industry 34favorable conditions, such as duri ng daylight hours, in the ab sence of precipitation, in the absence of high wind, and, for active laser de vices, in front of a ppropriate reflective backgrounds within the detecti on range of the instrument. The EPA Alternative Work Practice (AWP) requires optical imaging devices to detect a minimum flow rate, specified in Title 40 CFR Part 65 Section 7, before each use. The AWP specifies instructions for determining the minimum detectable flow rate , the purity of the calibration gas, and the allowed viewing distance. Equipment leak de tection and measurement instrument manuals can also be used to determine optimal operating conditions to help ensu re best results.

Toxic Vapor Analyzer (or Organic Vapor Analyzer)

TVAs and OVAs consist of a flame ionization detector that is used to detect the presence of hydrocarbons and measure the concentr ation of equipment leaks. It consists of a probe that is moved close to and around the potential emissions source and an emissions detection results in a positive reading on the instrument monitori ng scale. The concentration can be used in conjunction with correlation equa tions to determine the leak rate. However, concentration is

not a true measure of an emi ssion’s magnitude. Therefore concen tration data from TVAs and OVAs, for the purposes of the rule, may be be st suited for screening purposes only. The advantage of these instruments is that they have lower costs than IR cameras and several facilities conducting Leak Detec tion and Repair (LDAR) program s might already have these instruments, thereby reducing capital investme nt burden. But these instruments screen very slowly given that each potential emissions source has to be individually and thoroughly

circumscribed less than 1 centimeter from th e potentially leaking joints or seals.

Method TVAs and OVAs can be used for all equi pment leak 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 equipment leak, 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.

Acoustic Leak Detectors

Acoustic leak detectors are simple devices that filter out the low frequency vibrations and noise of heavy machinery operating and sense and measure the decibel reading of high frequency vibrations and noise of fluids leaking through small cracks or openings. Fluid flow through open valves has little difference in soni c generated noise betwee n the inlet and outlet of a valve, or the valve body itself. Similarly ti ghtly closed valves have little difference in

sonic noise measured on the inle t, outlet or valve body. Valves which are not tightly closed (i.e. a crevice or deformation of the valve plug and seat) will generate a high frequency noise depending on the valve type and size, the pressu re drop across the closed valve, and the fluid density. This frequency can be measured in decibels and correlate d with through valve leakage rate.

Background Technical Support Document – Petroleum and Natural Gas Industry 35Method
The instrument operator place s the “stethoscope” like prob e on the valve body or valve flange in one or more of the recommende d locations, and observes the decibel reading displayed on the instrument digital signal indica tor. This reading is doc umented in the field, along with the valve identificati on (valve number or location desc riptor). The type of fluid, its density, and the system pressure upstream and downstream of the closed valve are also recorded to be entered along with the valve type (ball, plug, gate, pressure relief, etc) and nominal size) into an Excel spreadsheet s upplied by the valve manufacturer. The through valve leakage rate is calculated by correla tion algorithms developed by the instrument

manufacturer.

Calibration

Calibration requirements are as provided by th e manufacturer, depending on the type of

acoustic detector.



### 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 and have a potential capacity for measuring up to 30 leaking components per hour with high precision at 0.02 percent methane. This allows for reduced labor costs and survey times while main taining precise results. For this reason, high volume samplers are considered the preferred and most cost-effective direct 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 instrument, 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

Background Technical Support Document – Petroleum and Natural Gas Industry 36from the source then anti-static wraps or othe r aids can 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 conducted away by th e emissions. The 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 bring 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

Background Technical Support Document – Petroleum and Natural Gas Industry 37differential that is converted to mass emissi ons rate. The pitot tube detects the flow velocity at only one point along the flowst ream, hence the placement of the pitot tube inside the pipe where the flow is to be measured is critical to determine a representative flow volume, and not a location-specific fl ow volume, which can give erroneous results. It has relatively low accuracy compared to most flow meters, due to the low pressure drop measured. This al so makes it vulnerable to fluctuations from turbulence changes in the flow stream. Although inacc urate compared to most meters, the pitot tube is one of the le ast expensive flow meters available.

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.

(C) The Final GHG Reporting Program provides guidance on calibrati on for meters in section §98.3(i).

Calibrated Bagging A calibrated bag (also known as a vent bag) made of anti-static material is used to enclose an emissions source to completely capture all the leaking gas. The time required to fill the bag with emissions is measured using a stop watc h. The volume of the bag and time required to

Background Technical Support Document – Petroleum and Natural Gas Industry 38fill 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 within 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 can be used only wher e the emissions are at near-atmospheric pressures and the entire emissions volume can be captured for measurement. Using these bags on high pressure vent stacks can be da ngerous. 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 re quired to completely fill the bag. Three measurements of the time required to fill the bag can be conducted to estimate the emissions rates. The average of the three rates will provi de 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 convert the natu ral gas emissions into CO 2 and CH 4 emissions, speciation factors determined from natural gas composition analysis must be applied. Another key issue is that all measur ement technologies discussed require physical access to the emissions source in order to quantify emissions.



### B. Engineering Estimation and Emission Factors

For several emissions sources, there are viable alternatives to physical measurement for calculating emissions. 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 esti mation. Emission factors can be considered for nearly every source where emissions data is available, how ever, they usually have high uncertainties. Emissions factors may be appropriate for freq uent, geographically sparse emission sources such as pneumatic devices. Several sour ces are outlined below 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

Background Technical Support Document – Petroleum and Natural Gas Industry 39Leaks from natural gas driven pneumatic pumps can be calculat ed using data obtained from the manufacturer for natural gas emissions pe r unit volume of liquid pumped at operating pressures. This information is available fr om the pump manufacturer in their manuals. Operators can maintain a log of the amount of liquids pumped annually for individual pneumatic pumps and use Equation 1 below for calculating emissions:

E

s , n  F

s * V Equation 1

where,

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 characteristics 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.

Due to the geographically isolat ed nature of pneumatic pumps, if manufacturer data is not readily available or would result in high burden to obtain the data, pneumatic pump emissions can also be quantified using publis hed emission factors. The use of emission factors is less burdensome than collecting manufacturer data from each pneumatic pump but

can be inaccurate due to limited data and variable pump design. However, the resulting information can still be useful for the purposes of informing policy because it will provide updated activity data on the nu mber and type of pneuma tic pumps in operation. See Appendix G for a discussion of population emi ssion factors for pneumatic pumps and see Section (6)(d) of the TSD for how to calculate emissions from population factors. Emissions from natural gas driven pneumatic pumps can be calculated using an emissions factor as follows;

Mass  Count * EF * GHG * Conv * 24*365 Equation 2

s , i i i

where,

Mass s,i = Annual total mass GHG emissions in metric tons per year at standard conditions from all natural gas driven pneumatic pumps at the facility,

for GHG i

Count = Total number of natural gas driv en pneumatic pumps at the facility

Background Technical Support Document – Petroleum and Natural Gas Industry 40EF = Population emission factors for natural gas driven pneumatic pumps listed in Appendix G for onshore pe troleum and natural gas production, onshore natural gas transmission, a nd 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; 0.000410 for

CH 4 , and 0.00005357 for CO 2
24 * 365 = conversion to yearly emissions estimate

2. Natural Gas Driven Pneumatic Manual Valve Actuators

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

data obtained from the manufacturer for natu ral gas emissions per actuation. Operators can maintain a log of the number of manual actuations annually for individual pneumatic devices

and use Equation 3 below:

E

s , n  A

s * N Equation 3

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 pneuma tic device was actuated through the reporting period

As an alternative to manufact urer data, the operator coul d conduct a one-time measurement to determine natural gas emissions per actuation using a calibrated bag for each pneumatic

device.

3. Natural Gas Driven Pneumatic Bleed Devices

Pneumatic devices typically fall in three categ ories; low bleed devices , high bleed devices,

and intermittent bleed devices. Low bleed devices are devices that bleed less than 6 scf of natural gas per hour. High bleed de vices are devices that bleed mo re than 6 scf of natural gas per hour. 6, 7 Intermittent bleed devices are snap-acting or throttling devices that discharge the full volume of the actuator intermittently when control action is necessary, but do not bleed continuously. Given the vast difference in bl eed rates, low bleed de vices contribute to a

6 "Opportunities to Reduce Anthropogenic Methane Emissions in the United St ates," EPA 430-R-93-012, October 1993

7 PG&E (Pacific Gas and Electric). 1990. Unaccounted for Gas Project Summary Volume, PG&E Research and Development; San Ra mon, CA: GRI-90/0067.1

Background Technical Support Document – Petroleum and Natural Gas Industry 41small portion of the total emissions from pneuma tic devices nationally. Therefore, it may be feasible to provide an emissions factor appr oach for low bleed pneum atic devices to reduce burden. The following are two different options for determining emissions from low bleed, high bleed, and intermittent 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;

E

s , n  B

s * T Equation 4

where,

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

B
s = Natural gas driven pneumatic device bleed rate volume 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

Due to the geographically isolated nature of pneumatic devices, if ma nufacturer data is not readily available or would result in high burden to obtain the data, pneumatic device emissions can also be quantified using publis hed emission factors. The use of emission factors is less burdensome than collecting manu facturer data from each device, but can be inaccurate due to limited data and variable design. However, the resulting information can still be useful for the purposes of informing policy because it will provide updated activity data on the number and type of pneumatic pumps in operation. See Appendix G for a discussion of population emission factors for pneum atic devices and see S ection (6)(d) of the TSD for how to calculate emissions from popula tion factors. Emissions from natural gas pneumatic low bleed device venting can be calc ulated using emissions factor as follows;

Mass

s , i  Count * EF * GHG i * Conv i * 24*365 Equation 5

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 G for onshore petroleum and natural gas

Background Technical Support Document – Petroleum and Natural Gas Industry 42production, 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; 0.000410 for

CH 4 , and 0.00005357 for CO 2
24 * 365 = conversion to yearly emissions estimate

4. 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 continuous emissions monitoring (CEMS) systems, mass balance approach, or one of the standard simulation software packages. CH 4 emissions can only be estimated using simulation software packag es. It must be noted, however, that CH 4 emissions from AGR vents are insignificant, 0.06 percent of the to tal volume of CO 2 and CH 4 emissions. The mass balance approach has the adva ntage 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.

Some facilities may have CEMS installed on thei r AGR unit vent stacks. In such a case, if the CEMS can reliably measure CO 2 volumes then the measurements from CEMS can sufficiently inform on the CO 2 emissions from AGR units. Altern atively, if the vent stack has

a meter on it then the CO 2 emissions can be estimated using this metered vent stack gas volume and the percent CO 2 in the vent stack gas.

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 unit. However, there are some parame ters that directly impact 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 stacks ca n also be calculated using mass balance approach from the throughput of the AGR unit and gas composition as follows;

Background Technical Support Document – Petroleum and Natural Gas Industry 43E

a , CO 2  

##  V   * 

##  V * 

##  Vol I  Vol O 

##  * 

##  Vol I  Vol O 

##  Equation 6

where,

E

a,CO2 = Annual volumetric CO2 emissions at act ual condition, in cubic feet per

year.

V = Total annual volume of natural gas fl ow into or out of the AGR unit in cubic feet per year at actual cond ition as determined using methods specified in paragraph (d)(5) of this section of the TSD.

α = Factor is 1 if the outlet stream flow is measured. Factor is 0 if the inlet

stream flow is measured.

Vol I = Volume fraction of CO2 content in natural gas into the AGR unit as determined in paragraph (d)(7) of this section.

Vol O = Volume fraction of CO2 content in natural gas out of the AGR unit as determined in paragraph (d)(8) of this section of the TSD.

Sometimes AGR units have a continuous gas anal yzer in which case they can be used to

determine Vol I and Vol O

. There are gas processing 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 physical volume between isolation valves (incl uding all natural gas-containing pi pelines and vesse ls) and logs of the number of blowdowns for each piece of equipment using Equation 7 below:

  

##  459.67  T

s 

##  P

a  

E  N *  V

v 

  

 V * C  Equation 7

s , n v     

##  459.67  T

a 

##  P

s  

where,

Es,n = Annual natural gas venting emissions at standard conditions from blowdowns in cubic feet.

N = Number of repetitive blowdowns for each equipment type of a unique volume in calendar year.

Vv = Total volume of blowdown equipment chambers (including pipelines, compressors and vessels) between is olation valves in cubic feet.

C = Purge factor that is 1 if the equipment is not purged or zero if the equipment is purged using non-GHG gases.

Background Technical Support Document – Petroleum and Natural Gas Industry 44Ts = Temperature at standard conditions ( o F).

Ta = Temperature at actual conditi ons in the blowdown equipment chamber ( o F).

Ps = Absolute pressure at standard conditions (psia).

Pa = Absolute pressure at actual conditions in the blowdown equipment chamber (psia).

6. Dehydrator Vent
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 for 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 vents can be calculated us ing a simulation software package, such as GLYCalcTM. There may be several other simulation packages, such as Aspen HYSYS, that can also estimate emissions from glycol dehydrators. Ho wever, GLYCalcTM is the most widely used software and referenced by several State and Federal agencies in their programs and regulations. Different software pa ckages might use different calculations and input parameters to determine emissions from dehydration systems. However, there are some parameters that directly impact the accura cy 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 t o, 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.

Background Technical Support Document – Petroleum and Natural Gas Industry 45For 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 Equation 8 below:

( H * D 2 * P * P 2 * % G *365 days / yr ) E

s , n  Equation 8 (4 * P 1 * T *1,000 cf / Mcf *100)

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)

100 = Conversion of %G to fraction.

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

vents sent to flares can be calculated using the methodology under Section 8 of the TSD for flares. Alternatively, a simple combustion efficien cy factors, such as 98 percent, 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.

EOR 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 CO 2 released to during such blow down pract ices can be calculated using the total volume between isolation valves (including, but not limited to, pipelines, compressors and vessels).The emissions can be calculated using Equation 9 below.



### Mass  N * V * R * GHG *10

 3 Equation 9

c , i v c i

where,

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

conditions “c” from blowdowns.

Background Technical Support Document – Petroleum and Natural Gas Industry 46N = Number of blowdowns for the equipment in calendar year.

V

v = Total volume in cubic meters of blowdown equipment chambers (including, but not limited to, pipelines, 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 gas industry. These can potentially be used to estimate emissions for reporting under the rule . However, the emissions factors are not appropriate for all the emissions sources. The emissions factors were developed more than a decade ago when the industry practices were mu ch different from now. In some cases, the emissions factors were developed using lim ited sample data and knowledge about the industry’s operations (e.g., wells, compressors). While the available emission factors alone may not be appropriate for GHG reporting, certain emission fact ors may be sufficient, under certain circumstances, to calculate and char acterize GHG emissions. Also, the introduction of many emissions reduction technol ogies are not reflected in the emissions factor estimates. However, the two studies provide raw emi ssion data that in conjunction with newer publically available data (e.g., Clearstone 2006 study) could be used for developing emission

factors for certain sources. Re fer to Section 4(c)(ii), 6(c), and Appendix F and G of the TSD for a complete discussion of the use of emission factors in the reporting rule.



### 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 measuremen t 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 individual emissions

source level.

Background Technical Support Document – Petroleum and Natural Gas Industry 47Flare emissions whether from continuous or in termittent streams 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 calendar year.

Method 2:

Another option is to require the estimation of all streams of hy drocarbons going to the flare at

an individual emissions source level. Here engineering calculation and other methods

described for different sources in this Section of the TSD 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 gas sent to flare. The GHG volumetric emissions at

actual conditions can then be calculated as follows.

E 

###  un

 combusted 

### 

 V *(1

  ) * X Equation 10

a , CH 4 a CH 4

E

a , CO 2 

###  un

 combusted 

### 

 V

a * X CO 2 Equation 11

E , 2 ( combusted )  

##   * V

a * Y j * R j a CO j Equation 12

E

a , i  E

a , CO 2 ( combusted )  E

a , i ( un

 combusted ) Equation 13

where,

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

both CH 4 and CO 2 as described in Equation 10 and Equation 11

. E

a,CO2 (combusted) = Contribution of annual emissions of CO 2 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

Background Technical Support Document – Petroleum and Natural Gas Industry 48η = Percent of natural gas co mbusted by flare (default is 98 percent)

X

i = Concentration of GHG i in gas to the flare; where i = CO 2 or CH 4

. Y

j = Concentration of natural gas hydrocarbon constituents j (such as methane, ethane, propane, 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 ga s with significant differences in composition. The natural gas stream upstream of the de-methanizer can be expected to have higher C2+ components as opposed to the residue stream downstream 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 vents emit flash ga s from degassed oil straight into or close to the compressor engine exhaus t 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 velocity 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 vent. If a veloci ty measuring device is used then the volume of natural gas sent to vent can be calculate d from the velocity measurement using the

manufacturer manual for conversion. Annual em issions can be estimated using meter flow

measurement as follows:

E

a , i  MT * T * M i * (1

 B ) Equation 14

where,

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

conditions

Background Technical Support Document – Petroleum and Natural Gas Industry 49MT = Meter reading of gas emissions per unit time

T = Total time the compressor associated with the wet seal(s) is operational in the calendar 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 reciprocating 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 first option is to use an emi ssions factor for rod packing al ong with a popul ation count. The second option is to require equipment leak dete ction and measurement 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 isol ation valve through the rod packing. But rod packing emissions from leaking unit isolation va lves is for the most part negligible because unit isolation valves leak primarily through th e blowdown vent stack. Hence to correctly

Background Technical Support Document – Petroleum and Natural Gas Industry 50characterize annual emissions from rod packi ng, estimation of emissions at two compressor modes, operating and standby pr essurized, may be required.

11. Compressor isolation valve and blowdown valve

Blowdown valves on a compressor are used to de pressurize and release all of the natural gas in the compressor chambers when the compresso r is taken offline. These blowdown valves, however, can leak in some cases when the co mpressor is in operating or standby pressurized

modes. Isolation valves are us ed to isolate the compressor ch ambers from the pipeline that connects the natural gas flow into and out of th e compressor. These isolation valves can leak when the compressor is take offline. Both the blowndown valve and isolation valve are typically connected to the blowdown vent system . The emissions from leaks in an isolation

valve or blowdown valve can be detected a nd measured using detection and measurement methods as discussed in Sections (6 )(b)(i) and (6)(b)(ii)(A) of the TSD.

12. Storage tanks

Emissions from storage tanks can be estimat ed using one of the following four 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 tanks, it is necessary to conduct multiple measurements during a cycle of operation that is representative of the tank operations through the year. Equation 15 below can be used to calculate GHG emissions:

E

a , h  Q  ER Equation 15

where,

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

Q = storage tank total annual throughput, in barrels

ER = measured hydrocarbon vapor emissions 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.

Background Technical Support Document – Petroleum and Natural Gas Industry 51 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.

Method 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 to estimating emissions from storage tanks is to use the Peng-Robinson equation directly instead of using a simulati on software. The Peng-Robi nson equation is the

basis behind most of the simulation softwares and therefore will result in estimates similar to

Method 2 above.

p

where:

p R

T

V

m

‘

α

where:

Ω

Tc RT a 

  2 2 Equation 16

V

 b V  2 bV

 b

m m m

= Absolute pressure

= Universal gas constant

= Absolute temperature

0.45724 R 2 T 2 0.7780 RT

= Molar volume = c = c
p

c p

c   2  

2 T  

=  1  

#  0.37464  1.54226 

 0.26992  

#   1

     T

c    

= Acentric factor of the species

= Critical temperature

Background Technical Support Document – Petroleum and Natural Gas Industry 52Pc = Critical pressure

Method 4:

A conservative method to estimate GHG emissions from flashing in storage tanks is to take a sample of liquids at the low pressure separator (i.e. the last separator before the liquids enter the storage tank) and then assume that all the CH 4 and CO 2 dissolved in this sample is released to the atmosphere.

Method 5:

A fifth method for storage tank ve nted emissions quantification is use of the Vasquez-Beggs equation. This correlation equation provides an estimate of the gas-to-o il 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 17 demonstrates the use of this correlation equation:

 
GOR  A  G fg  

#  P

sep  14.7 

#   exp  C  G oil  Equation 17  

T  460  sep 

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 ga s, 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 ve ssel 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

such 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 multipliers on emissions es timated from Methods 1 and 2 above. Two such potential multipliers are as below,

Background Technical Support Document – Petroleum and Natural Gas Industry 53(i) The emissions for sales oil less th an 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 E.

Dump Valve Emissions Estimation

Storage tank vented emissions quantification co uld include the emissions that result from a gas-liquids separator liquid dump valve malf unction. Liquid dump or scrubber dump valves open periodically to reduce th e accumulation of liquids in the separator. Scrubber dump valves can get stuck open due to debris preventin g it from closing proper ly. In such a case, natural gas from the separator is lost through the dump valve ultimately passing through the storage tank’s atmospheric vent. Equation 18 , below, can be used to account for storage tank emissions with improperly closed scrubber dump valves.

E

s , i  

##  CF

n  E

n  T

n 

##   

##  E

n  

##  8760

 T

n 

##  Equation 18

where,

E s,i = Annual total volumetric GHG emissions at standard conditions from each storage tank in cubic feet.

E
n = Storage tank emissions as determin ed in calculation methods 1, 2, or 5 (with wellhead separators) of this section of the TSD during time T

n in cubic feet per hour.

T
n = Total time the dump valve is not clos ing properly in the calendar year in

hours. T

n is estimated by maintenance or operations records (records) such

that when a record shows the valve to be open improperly, it is assumed the valve was open for the entire time period preceding the record starting at either the beginning of the calendar year or the previous record showing it closed properly within the calendar year. If a subsequent record shows it is closing properly, then assume from that time forward the valve closed properly until either the next record of it not closing properly or, if there is no subsequent record, the e nd of the calendar year.

CF
n = Correction factor for tank emissions for time period T

n is 3.87 for sales oil less than 45 API gravity. Correcti on factor for tank emissions for time period Tn is 5.37 for sales oil equal to or greater than 45 API gravity. Correction factor for tank emissions for time period T

n is 1.0 for periods when the dump valve is closed.

E t = Storage tank emissions as determined in calculation methods 1, 2, or 3 of

this section of the TSD at maintena nce or operations during the time the dump valve is closing properly (ie.8760-T

n ) in cubic feet per hour.

Transmission Storage Tanks:

Background Technical Support Document – Petroleum and Natural Gas Industry 54Storage tanks in the onshore natural gas transm ission segment typically store the condensate from the scrubbing of pipeline quality gas. The 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 condensat e itself in the transmission segment are insignificant. However, scrubber dump valves of ten get stuck due to debris in the condensate and can remain open resulting in natural gas lo ss via the open dump valve. If the scrubber dump valve is stuck and leaking natural gas to the tank then the emissions will be visibly significant and will no t subside to inconspicuous volumes . If the scrubber dump valve functions normally and shuts completely af ter the condensate has been dumped then the storage tank emissions 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 significant emissions from the storage tank. If persistent and significant emissions are

detected then a measurement of those emissions may be required usin g a temporary meter or
ultrasonic devices that can detect and measure the emissions in a non-invasive way.

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

accounted for in the above methods.

13. 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 estimat e emissions from well testing venting using Equation 19 below:

E  GOR * FR * D Equation 19

s , n

where,

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

under actual 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.

14. Associated gas venting and flaring

Often times when onshore petroleum production fi elds are located in a remote location, the associated gas produced is sent to a vent or flar e. This is because th e associated natural gas is stranded gas, meaning that it is not economical to send th e usually low volumes to the market via a pipeline system. Also, gas from producing wells may sometimes be routed to a

Background Technical Support Document – Petroleum and Natural Gas Industry 55vent or a flare due to system upset conditions or for maintenance of field equipment. 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 em issions can be estimated using Equation 20 below:

E

a , n  GOR * V Equation 20

where,

E a,n = Annual volumetric natural gas emi ssions from associated gas venting under actual 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 calendar 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.

15. 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. But 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.

The 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 ta nk. The emissions from this hydrocarbon dissolved CO2 can be estimated using Equation 21 below:

Mass s, CO2 = S hl * V hl Equation 21

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.

Background Technical Support Document – Petroleum and Natural Gas Industry 56V hl = Total volume of hydrocarbon liq uids produced in barrels in the calendar year.

16. Produced water dissolved CO 2 EOR operations may use water injection techniqu es to pressurize the reservoir and drive the hydrocarbons containing CO 2 through the reservoir and up th e production well. This water, like the liquid petroleum, contains dissolved CO 2 , since CO 2 readily dissolves in water. This produced water is re-circulated for injection into the 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 22

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 calendar year.

EOR 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.

17. 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 spike e ngineering analysis acr oss 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 emi ssions. Each of the thr ee 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

Background Technical Support Document – Petroleum and Natural Gas Industry 57accumulated 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 app lied to all wells in the field that have the same tubing diameter and producing horizon /formation combination, multiplied by the

number of minutes of venti ng 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 pressure and flow potential.

Method 2:

For each unique well tubing diameter and produc ing 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 ev ents can be conducted. An em issions factor as an average flow rate per minute of venting can then be calculated through such an analysis. This emissions factor can be applied to all wells in the field that have th e same tubing diameter and producing horizon/formation combination, multiplied by the number of minutes of venting all wells of the same tubing diameter and producing horizon/formation combination

in that field. A new emission factor can be determined peri odically to track field declining formation pressure and flow potential. Emissions from we ll venting for liquids unloading can be calculated using Equation 23 below:

E

s,n = T * X * EF Equation 23

where,

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

T = Amount of time of well venting

X = 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 cal culating the volume of gas in the tubing st ring calculated at sales pipeline pressure can be used. This e quation is unique for each category of wells with the same well depth and tubing size. The emi ssions 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.

Background Technical Support Document – Petroleum and Natural Gas Industry 58Method 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 characteristi cs of the well that are usually well known. Using this method, emissions from well venting for liquids unloading can be calculated using Equation 24 below:

E

a,n = {(0.37×10 -3 ) * CD 2 * WD * SP * V} + Equation 24 {SFR*(HR-T)*Z}

where,

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

0.37×10 -3 = {pi(3.14)/4}/{(14.7*144) psia con verted 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 = Average 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

T = 1 hour for average well to blowdown casing volume at shut-in pressure for wells without plunge r lift assist; 0.5 hour for average well to blowdown tubing volume at sales line pressure when using plunger lift assist.

Z = If HR is less than 1.0 then Z is equal to 0. If HR is greater than or equal to 1.0 then Z is equal to 1.

For details on the time taken to blowdown a casi ng and tubing to unload a well, see “Change to Rule Equation W-7: Time to Vent the Casing Gas from Well Liquids Unloading” in the rulemaking docket (EPA-HQ-OAR-2009-0923)

18. 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 installati on of a recording flow meter on the vent line to the atmosphere or to a flare. Method 2 is an engineering calculation for flow based on the pressure drop across the well choke for subs onic and sonic flow. Method 3 uses the production of the well to determine emissions.

Method 1:

A recording flow meter can be in stalled on the vent line to the atmosphere or to a flare during each well completion or workover event. This on e time reading can be extrapolated to yearly emissions based on the time taken for completi on or workover and the number of times the

Background Technical Support Document – Petroleum and Natural Gas Industry 59well is worked over (if more than once per year). Such emissions factors can be developed for representative wells in a field on a yearly ba sis. 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 co mpletions and workovers can be calculated using Equation 25 below:

E

a,n = T * FR – EnF - SG Equation 25

where,

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

T = Cumulative amount of time in hours of well venting du ring the reporting period

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

EnF = Volume of CO 2 or N 2 injected gas in cubic feet at standard conditions that was injected into the reservoir during an energized fracture job. If the fracture process did not inject gas in to the reservoir, then EnF is 0. If injected gas is CO 2 then EnF is 0.

SG = Volume of natural gas in cubic feet at standard conditions that was recovered into a sales pipe line. If no gas was recovered for sales, SG is 0.

Method 2:

Using pressures measured upstream and downstream of the well choke, the average flow rate

across the choke can be calculate d. Using engineering judgment and the total time that flow across the choke is occurring, the total volume to the atmosphere or a flare during the backflow period can be estimated. 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). Such emissions factors can be developed for representative wells in a field on a yearly basis.

Emissions from gas well venting during well co mpletions and workovers can be calculated using Equation 26 for subsonic flow and Equation 27 for sonic flow below:

1.515 1.758  

 P   P 

5 2 2 FR  1.27  10 * A * 3430* T

u *     

      Equation 26   P 1   P 1    

where

,

Background Technical Support Document – Petroleum and Natural Gas Industry 60FR = Average flow rate in cubic feet per hour, under subsonic flow

conditions.

A = Cross sectional area of orifice (m 2 ).

P 1 = Upstream pressure (psia).

T

u = Upstream temperature (degrees Kelvin).

P 2 = Downstream pressure (psia).

3430 = Constant with units of m 2 /(sec 2 * K).

1.27*10 5 = Conversion from m 3 /second to ft 3 /hour.

FR  1.27  10 5 * A * 187.08* T

u Equation 27

where,

FR = Average flow rate in cubic f eet per hour, under sonic flow conditions.

A = Cross sectional area of orifice (m 2 ).

T

u = Upstream temperature (degrees Kelvin).

187.08 = Constant with units of m 2 /(sec 2 * K).

1.27*10 5 = Conversion from m 3 /second to ft 3 /hour.

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 Equation 28 below:



### E V * T

a , n 

###  

#  f f Equation 28
f

where,

E a,n = Annual natural gas emissions in cubic feet at actual conditions from gas well venting during well completions and workovers without hydraulic fracturing.

f = Total number of well completions wit hout hydraulic fracturing in a field.

V

f = Average daily gas production rate in cubic feet per hour of each well completion without hydraul ic fracturing. This is the total annual gas production volume divided by total nu mber of hours the wells produced to the sales line. For completed wells that have not established a production rate, you may use the average flow rate from the first 30 days of production. In the event that the well is comple ted less than 30 days from the end of the calendar year, the first 30 days of the production straddling the current and following calendar years shall be used.

Background Technical Support Document – Petroleum and Natural Gas Industry 61T f = Time each well completion without hydraulic fracturing was venting in hours during the year.

19. Onshore production combustion emissions

The combustion process is well understood in te rms of GHG emissions. The use of emissions

factors is reliable if the quantity and type of fuel combus tion is known. The al ternative is to use combustion emissions stack monitors, wh ich are cost prohibitive and may not be considered appropriate for onshore production. Onshore production segment does not meter its fuel, since most of the equipment in the field is located upstream of the lease meter. However, requiring meters at ev ery single well site to measure fuel volume is not feasible in terms of cost. Hence, the use of heat rati ng of the equipment along with the hours of operations is the most feasible approach to es timate the amount of fuel consumed. Using the emissions factors approach, GHG emissions fr om combustion equipment can be estimated using broadly two methods; fuel specific emi ssions factors and equipment specific fuel factors. Fuel specific emissions f actors are related to a particular type of fuel in use and do not take into account the type of equipment (e.g. whether internal or external combustion equipment). The advantage of this type of approach is that if the fuel volume for a facility is

known then there is no need to identify the particular equipment that is combusting it. The disadvantage in this method though is that it doe s not take into account the differing levels of efficiency between different types of equipm ent. On the other hand, equipment specific

emissions factors take into account the effi ciency levels of each equipment type corresponding with the type of fuel it combusts. However, the disadvantage of using equipment specific emissions factors is that fuel consumption has to be known at an equipment level. Both fuel specific and equi pment specific emissions factors are available form the API Compendium and EPA AP-42 documents.

20. Natural gas distribution combustion emissions

The combustion emissions from natural gas distri bution result mainly from inline gas heaters, small compressors, etc. Heaters are used to prevent natural ga s dropping below the dew point (where liquids, mainly water, might condense) or to maintain the temp erature of gas let-down in pressure from high pressure transmission pipe lines to low pressure di stribution gate station metering systems. The Joule-Thompson effect cau ses gas temperature to drop when the gas is suddenly expanded across a valve or orifice. Thus, transmission pressure gas at, for example 1000 psig and ambient temperature of 70 ° F can drop well below freezing when depressurized to 100 psig. This gas may be heated to a temp erature above so-called “dry” gas dew point or a range consistent with distri bution gate station meter calibra tions. These are usually small sources of emissions and may not contribute significantly to the total emissions from the distribution segment. However, some natura l gas distribution systems operate compressor

stations that are similar in si ze and operations to the natural gas transmission or gas storage systems. These compressor stations may have significant emissions and could be captured under combustion emissions reporting.

Background Technical Support Document – Petroleum and Natural Gas Industry 62

### c. Leak detection and leaker emission factors

For leaks from standard components such as co nnectors, valves, meters , etc. emissions can be estimated by conducting an equipment leak detection program a nd applying a leaker

emissions factor to those sources found to be emitting. This option may be considered over direct measurement (e.g., high flow sampler) to avoid the capital cost in measurement equipment and labor hours to conduct measur ement. Estimating emissions using leaker emission factors is more accurate than populatio n factors because leaker factors are applied to leaks once they are identif ied. Since equipment leaks occur randomly within a population of components, determining the number of actual leaking component improves the emissions

estimate. Equation 29, below, can be used for this purpose.

E

s , i  GHG i * 

##  EF X * T

x Equation 29

x

where,

E s,i = Annual total volumetric GHG emissi ons at standard conditions from each equipment leak source in cubic feet.

x = Total number of this type of emi ssions source found to be leaking during

T
x . EF E = Leaker emission factor for specific sources

GHG i = For onshore petroleum and natural gas production facilities and onshore natural gas processing facil ities,, concentration of GHG i , CH 4 or CO 2 , in the total hydrocarbon of the feed natural gas; other segments GHG i equals 1 for CH 4 and 1.1 × 10 -2 for CO 2

. T

x = The total time the component wa s found leaking and operational, in hours. If one leak detection survey is conducted, assume the component was leaking for the entire calendar year. If multiple leak detection surveys are conducted, assume that the component found to be leaking has been leaking since the previous survey or the beginning of the calendar year. For the last leak dete ction survey in the calendar year, assume that all leaking components con tinue to leak until the end of the calendar year.

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 natu ral gas storage facilities, liquefied natural gas import and export facilities, and natu ral gas distribution

facilities. These leaker em issions factors and a discussi on on their development are available in Appendix F.



### d. Population Count and Emission Factors.

For equipment leaks that are geographically disp ersed or where the cost burden is an issue, emissions can be estimated using the popu lation count of emi ssions sources and a

Background Technical Support Document – Petroleum and Natural Gas Industry 63corresponding population emissions factor. This option may be consid ered over direct measurement to avoid the cost of purchasing a high volume sampler, screening device, and the labor hours to use both. Such an option ma y 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 overestimate overall GHG emission s. The disadvantage of using population

factors is that it will only provide an estimate of potenti al emissions, not actual emissions. It will also not provide any trends in changes in emissions over time, since the only variable is equipment/ component count, which in most oper ations does not change significantly. Hence, petroleum and natural gas operators who are voluntarily reducing emissions by conducting periodic leak detection and repair will end up reporting more emissions than is actually occurring in their operations. Emissions from a ll sources listed in this paragraph of this section can be calculated using Equation 30.

E

s , i  Count * EF * GHG i * T Equation 30

where,

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

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

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

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 equipment leak was operational in the repo rting period, 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 storage facilities, liquefied natural gas storage f acilities, liquefied natural ga s import and export facilities, and natural gas distribution facilities. These population emissions factors and a discussion on their references are available in Appendix G.



### 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 perf ormance 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 wher e a leak could occur. The probe must be maintained in close proximity to (but not to uching) the interface; ot herwise it could be damaged by rotating shafts or plugg ed with ingested lubricants or greases. In most cases, it can be no more than 1 centimeter away from th e leak interface. Method 21 does not specify

Background Technical Support Document – Petroleum and Natural Gas Industry 64leak definitions; they are defined within specif ic subparts of the Title 40 CFR. Method 21

also allows certain al ternative equipment leak detection methods, such as soap solutions (where the leaking 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 li quid leakage). Method 21 does not specify any emissions mass or volumetric quantification methods, but onl y specifies an emissions concentration expressed in parts per million of combustible hydrocarbons in the air stream of the instrument probe. This leak detection data ha s been used by state emission inventories with “leaker” factors developed by the Synthetic Organic Chemicals Manufacturing Industry (SOCMI) 8 to estimate the quantity of VOC emissions. SOCMI factors were developed from petroleum refinery and petrochemical plant data using Method 21.

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 equipment leaks. 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 study conducted by API at seven California refineries 9 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. eq uipment leaks 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 final rule to detect and quantify leaking sources beyond the scope of Method 21.

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 LDAR.

In a typical Method 21 program, the costs of conducting emissions detection remain the same during each recurring study period. This is because 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 instruments were found to be more cost effective for leak detection for this reporting rule as these instruments are able to scan hundreds of source components quickly, including components out of reach for an OVA/TVA.

8 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

9 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 65Although 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 ad opted for estimating emissions from minor sources such as equipment leaks 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 rarely ingest all of the emissions from a component leak, they are used primarily fo r equipment leak det ection. 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 “leak/no-leak,” where equipment is determined to be leaking when the portable instrument indicates the provided leak defi nition. Different leak definiti ons 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 instrument . 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 for 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 definition. Portab le leak detection instruments normally peg at 10,000 ppm, and so are unsuitable for use with the “stra tified” quantification

factors.



### g. Mass Balance for Quantification

There are mass balance methods that could be considered to calculate emissions for 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. Fo r transportation, the mass balance is often not recommended because of the uncertainties surrounding meter readings and the large volumes of throughput relative to equipment leaks. 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

Background Technical Support Document – Petroleum and Natural Gas Industry 66is 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 Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) conducts a comprehensive activity data collect ion effort under its Gulf Offshore Activity Data System program (GOADS) in comp liance with 30 CFR 250.302 through 304. This requires all petroleum and natural gas production platforms located in the Federal Gulf of Mexico (GoM) to report their activities to BOEM RE once in every three to four years. The activity data reported includes counts of emissions sources, volumes of throughputs from several pieces of equipment, fuel consumpti on by combustion devices, and parametric data related to certain emissions sources such as gl ycol dehydrators. This activity data is then converted into emissions estimates by BO EMRE and reported subsequently by BOEMRE. The BOEMRE 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 potentially use this data re ported by the GOADS program. Ho wever, since the data has historically been collected once every three to four years, EPA will not receive new emissions information for every reporting pe riod. This means that between BOEMRE reporting periods if a new platform is commi ssioned, an old platform is de-commissioned, new equipment is installed on existing platform s, or operating levels of platforms change then this information will not get recorded and reported for periods when BOEMRE GOADS is not being conducted. This issue however, can be resolved by requiring new platforms to

use the most recent GOADS methods to estimate em issions and other reporte rs to adjust their emissions annually based on the time each platform was operating in comparison to the GOADS reporting year. Finally, the BO EMRE GOADS program does not collect information from platforms in the GoM under Stat e jurisdiction, as well as platforms in the

Pacific and Alaskan coasts. These platforms not under GOADS purview will not have existing data to report if GOADS reporting were to be adopted by EPA. Nevertheless, a reporting rule can potentially require non-GOADS platforms to adopt the GOADS methodology to calculate emissions. If BOEMRE discontinues or delays their GOADS, then platform operators under a reporting rule us ing GOADS may refer to the most recently published version of the GOADS program instructions to continue reporting.



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

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



### i. Source Level Equipment Leak Detection Threshold

This document does not indicate a particular eq uipment leak definition or detection threshold requiring emissions measurement. This is b ecause different equipment leak detection instruments have different levels and types of detection capabilities, i.e. some instruments provide a visual image while others provide a digital value on a scale (not necessarily

Background Technical Support Document – Petroleum and Natural Gas Industry 67directly related to mass emissions). Hence th e 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 small emissions (as lo w as 3 grams per hour) and it might not be practical to measure 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 e quipment leak 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 final rule may requi re measurement and reporting. This avoids the necessity of specifying performance standards.

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 technol ogy 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).

Equipment Leak 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 thre shold 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. In the case of an optical imaging instrument, which does not provide the magnitude of emissions, either c oncentration or mass emissions, quantification would be required using a separa te measurement instrument to determine whether a source is an emitter or not. This could be very cost prohibitive for the purposes of this rule.

Background Technical Support Document – Petroleum and Natural Gas Industry 68

### ii. Duration of Equipment Leaks

Equipment leaks by nature occur randomly within the facility. Therefore, there is no way of knowing when a particular source started emitting. If the potential monitoring method requires a one time equipment leak detection and measurement, then assumptions will have to be made regarding the durat ion of the emissions. There are several potential options for calculating the duration of emissi ons. If a component leak is detected, total emissions from each source could be quantified under one of the following three scenario s: 1) if a facility conducts one comprehensive leak survey each reporting period, applicable component leaker emissions factors could be applied to all spec ific component emissions sources and emissions quantified based on emissions occurring for an entire reporting period; 2) if a facility conducts two comprehensive leak surveys dur ing a single reporting period, applicable component leaker emissions factors could be app lied to all component em issions sources. If a specific emission source is found not leaking in the first survey but leaking in the second survey, emissions could be quantified from the da te of the first leak survey conducted in the same reporting period forward through the rema inder of the reporting period. If a specific emissions source is found leaking in the first su rvey but is repaired and found not leaking in the second survey, emissions could be quantified from the first day of the reporting period to

the date of the second surve y. If a component is found leak ing in both surveys, emissions could be quantified based on an emission occurring for an entire reporting period; 3) if a facility conducts multiple co mprehensive leak surveys du ring the same reporting period, applicable component leaker emissions factor s could be applied to component emissions sources. Each specific source found leaking in one or more surveys is quantified for the period from a prior finding of no leak (or beginn ing of the reporting period) to a subsequent finding of no leak (or end of th e reporting period). If a com ponent is found leaking in all surveys, emissions could be quantified base d on an emissions occu rring for an entire reporting period.



### iii. Equipment Leak 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 which a particular technology operates throughout the reporting period. This may be particularly true for measurements taken at compressors. Compressor leaks are a function of the mode in which the compressor is operating: i.e. offline pressurized, or offlin e de-pressurized. Typically, a co mpressor station consists of several compressors with one (or more) of them on standby based on system redundancy requirements and peak delivery capacity. When a compressor is taken offline it may be kept pressurized with natural gas or de-pressurized . When the compressor is offline and kept pressurized, equipment leaks and vented emissi ons result from closed blowdown valves and reciprocating compressor rod packing leaks, re spectively. When the compressor is offline and depressurized, emissions result from l eaking 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 equipment leak and vented emissions are signifi cantly different. One potential approach to account for these varying le vels of equipment leak and vented emissions is to have operators measure all compressors in each operating mode once a reporting period. Operators would

Background Technical Support Document – Petroleum and Natural Gas Industry 69also need to report the time for which the compressor is in the different modes. The disadvantages to this approach is that it will increase the re porting burden because

measurements will have to be taken at each mode of compressor operation in each reporting period and the time that the equipment is in vari ous operational modes would also have to be tracked. In addition, it is not feasible to require operators to take compressors off-line every year to conduct measurements in offline pr essurized and depressurized modes. One alternative approach is to report compressor emissions in the mode the compressors are found, also known as reporting compressor emissi ons “as-is”. The reporters could then determine emission factors for each mode and apply them to the period of time each compressor was not in the mode it was measur ed in for the reporting period. Since most compressors would be found in the, pressurize d, operating mode, reporte rs could be required to measure each compressor in an offline mode less frequently (e.g. every three reporting periods) to ensure sufficient data points are co llected in the less common offline modes.

A similar issue exists with ta nks where the operating conditions change more often than for 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 be st judgment and characterize a few different modes for the storage tanks and make adjustments to the monitored emissions accordingly.



### iv. Natural Gas Composition

When measuring equipment leaks and vented emissions using the various measurement instruments (high volume sampler, calibrate d bags, and meters) or using engineering estimation for vented emissions, only flow rate is measured or calcula ted and the individual

CH 4 and CO 2 emissions are estimated from the natu ral gas mass emissions using natural gas composition appropriate for each facility. Fo r this purpose, the monitoring methodologies discussed above would require that faciliti es use existing gas composition estimates to

determine CH 4 and CO 2 components of the natural gas em issions (acid gas recovery units, flare stacks, and storage tank ve nted emissions are an exception to this general rule). These gas composition estimates are assumed to be ava ilable at facilities. Bu t this may or may not be a practical assumption for reporting. 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.

Background Technical Support Document – Petroleum and Natural Gas Industry 70For 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.



### 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 gr ound or fixed platforms. Leaks from flanges, valve stems, equipment covers, etc. are generally smaller than emissions from vents. Component leaks are expensive to measure where they are not accessible within arms reach from the ground or a fixed platform. For thes e inaccessible sources, the use of emission factors for emissions quantification may be appr opriate. Vent stacks are often located out of access by operators for safety purposes, but ma y represent large emission sources. Where emissions are detected by optical gas imaging instruments, emissions measurement may be cost-effective using the follo wing 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 acce ssible from the ground, fixed platforms

and out of reach of bucket trucks.



### 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 periods’ data point to replace missing data in the current reporting peri od, this is not ideal si nce varying operating conditions can dramatically impact emissions estimates. Where using previous reporting periods’ data are not desirable, then a reporting rule might require 100% data availability. In other words, there would be no missing data proc edures provided. If any data were identified as missing, then there would be an opportunity to recollect the emission s data over the course of the current reporting period.

Background Technical Support Document – Petroleum and Natural Gas Industry 71

### 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

lost 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 peri od’s data could be used to estimate equipment leaks 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 reporting periods’ data are not as desirable as there could be significant differences from period to period based on operating conditions.

 Process conditions data. Estimating vented emissions from acid gas removal vent stacks, blowdown vent stacks, dehydrator ve nts, natural gas driven pneumatic valve bleed devices, natural gas dr iven pneumatic pumps, and storage tanks requires data on the process conditions (e.g., process temper ature, pressure, throughputs, and vessel volumes). If, for any reason, these data are incomplete or not avai lable for the current reporting period, field operators or engineers could recollect data wherever possible.

If this data cannot be collect ed, 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 repo rting periods’ estimate of “emissions per throughput” measured data could be used with current period throughput 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.

Background Technical Support Document – Petroleum and Natural Gas Industry 72

### 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 repl aceable by undertaking a counting exercise for locations from which the data is missing. Alte rnatively, previous re porting period activity data can be used to fill in missing data. However, if facility and/ or equipment modifications have 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 equipment leak detection. In such cas e, missing data may not be easily replaceable. Previous period reported activity data may be used but it may not be representative of current period emissions. A detection 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 needed to main tain the monitoring system in proper operating condition and a schedule for those procedures;

o Keep a record of all tes ting, maintenance, 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 description of any testing, adjustment, repair, replacement, or preventive maintenan ce 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.?

Background Technical Support Document – Petroleum and Natural Gas Industry 73o 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,

 Changes concerning the emitting process (e.g. energy efficiency improvements). 10

 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. 10

 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 sa mple of calculations, by hand or electronically,

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

10 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/EC of 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 74o Check the aggregation of data across source categories, business units, etc.,

o When methods or data have changed, check consistency of time series inputs

and calculations. 11



### 9. Reporting Procedure

(a) 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.

(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 calculating emissions when using engineering estimation

methods.

In addition, the following reporting requirement s could be considered for a reporting rule;

(b) Equipment leaks by nature occur randomly w ithin the facility, theref ore, where emissions are reported on an annual basis, it may not be possible to determine when the equipment leaks began. As discussed in more detail in Section (I)(ii) of the TSD, under these circumstances, annual emissions could be determined assuming that the equipment leaks were continuous from the beginn ing of the reporting period or from the last recorded not leaking in the current reporting period and until th e equipment leak is repaired or the end of the reporting period.

(c) Due to the point-in-time natu re of direct measurements, 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.



### 10. Verification of Reported Emissions

As part of the data verification requirements , the owner or operator could submit a detailed explanation of how company reco rds of measurements are used to quantify equipment leaks 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 us e of electronic mail can be made acceptable).

11 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 75

### Appendix A: Segregation of Emissions Sources using the Decision Process

The tables provided in this appendix represent the outcome of the decision process used to identify a starting list of potential sources that were evaluated for inclusion in the final rule. The decision process was applied to each emi ssion 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 the exclusion category. Petroleum trans portation was not analyzed further due to the

level of emissions and refineries ar e treated separately in Subpart Y.

Sources Contributing to 80% of Equipment Leaks and Vented Emissions from Each Industry Segment

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 Rive r 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%

A cid 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 pro cess. 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.S. GHG Inventory.

Background Technical Support Document – Petroleum and Natural Gas Industry 76Inventory of Methane Emissions from Natural Gas SystemsPRODUCTION OFFSHORETotal EmissionsNationally(MMcf/year)TonnesCO2e/ Year% of SectorEmissions% of totalInventoryEmissionsActivityFactorsLeakDetectionDirectMeasurementEngineeringEstimateAccesibleSourceAmine gas sweetening unit0.2800.01%0.0001%NEccanBoiler/heater/burner0.83320.05%0.0002%cdanDiesel or gasoline engine0.0160.001%0.000004%cdanDrilling rig31,1340.17%0.001%cdanFlare249,5831.47%0.01%ccbnCentrifugal Seals358144,54722%0.10%aaabConnectors0.83090.05%0.0002%bbbbFlanges2.389600.15%0.001%bbbbOEL0.1320.005%0.00002%bbbbOther4417,5762.70%0.01%bbbbPump Fugitive0.51910.03%0.0001%bbabValves197,7581%0.01%bbbbGlycol dehydrator259,9142%0.01%ccbnLoading operation0.1510.01%0.00004%cdanSeparator796321,56649%0.23%ccbbMud degassing83,0710.47%0.002%cdanNatural gas engines19177,00012%0.05%Natural gas turbines31,3990.22%0.001%Pneumatic pumps72,6820.41%0.002%cbabPressure/level controllers26360.10%0.0005%cbabStorage tanks72,9330.45%0.002%ccanVEN exhaust gas12148,8148%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 Industry77PRODUCTION 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 Flaring0 188 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 Industry78GAS 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 Industry79TRANSMISSIONTotal 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 Industry80STORAGETotal 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 Industry81LNG 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 Turbines1 261 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 Industry82DISTRIBUTIONTotal 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.Background Technical Support Document –Petroleum and Natural Gas Industry83

### 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 purpos es 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 venting 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) 12 . The unconventional well column only includes CBM wells and shale gas wells, but does not include tight sands formations because that data is not readily av ailable either publically or in the U.S. Inventory. Thus, this analysis underestimates the activity associat ed with unconventional well completions and

workovers.

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 ca lculate that there was a ne t 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 es timates that 35,600 gas

wells were drilled in 2006. This 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.

19,994 wells  

##  50%  

##  35,600 wells

 19,994 wells 

## 

 27,797 wells

That is 78% of the total gas wells drilled in 2006. We assume d this same percentage of completed wells applies to the year 2007. EPA (2008) estimates 37,196 gas wells were

12 EPA.. (2008) U.S. Inventory of Greenhouse Gas Emissions and Sinks: 1990 – 2007 . Available online at:

< http://epa.gov/climatechange/emissions/usgginv_archive.html >.

Background Technical Support Document – Petroleum and Natural Gas Industry 84drilled 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 Exhibit 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 al l 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. B ecause these completions and workovers only account for CBM wells and shale ga s wells, it is a significant underestimate since tight sands

formations are omitted.

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) 13 provides activity data for 1992 on conven tional workovers. It reported that 9,324 workovers were performed with 276,014 produc ing 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

2007 GasWells 2007 ConventionalWorkovers  1992 ConventionalWorkovers  1992 GasWells

431,035 wells 2007 ConventionalWorkovers  9,324 workovers  276,014 wells

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 factors for conventi onal and unconventional ga s well workovers are

summarized in Exhibit B-4.

Exhibit B-4. Summary of 2007 Workover Activity Factors

13 GRI. Methane Emissions from the Natural Gas Industry . 1996. Available online at:

< http://epa.gov/gasstar/tools/related.html >.

Background Technical Support Document – Petroleum and Natural Gas Industry 852007 Conventional

Well Workovers   wells wells workovers 276,014 431,035 9,324 14,569

2007 Unconventional

Well Workovers   41,790 wells 10% 4,179

► Estimate the Emission Factor for Conventional Well Completions GRI (1996) estimated that c onventional 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 volume. 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 workove rs 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 14 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 15 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 produced from low-pressure wells that year, 17,769 of those wells can be attributed to onshore, nonlow-pressure formations. The Handbook al so 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 assume d 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 1 ) approximately 5,188 low-pressure wells

emitted 0.3 Bcf .

49,570 scf 1 Bcf 40%  12,971 wells   9  0.3 Bcf well 10 scf

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 great variability in the natu ral 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.

14 EPA. Green Completions . Natural Gas STAR Producer’s Technology Transfer Workshop. September 21,

2004. Available online at: <http ://epa.gov/gasstar/works hops/techtransfer/20 04/houston-02.html>.

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

Background Technical Support Document – Petroleum and Natural Gas Industry 8644.7 Bcf 10 6 Mcf

  6,000 Mcf / completion 60%  12,971 wells Bcf

The same Natural Gas STAR presentation 14 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 different 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 14 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 ro unded to the nearest hundred Mcf – 700 Mcf/completion.

The final Natural Gas STAR presentation 16 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 comple tions; 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 workovers 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 Flowback: 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

16 EPA. Reducing Methane Emissions During Completion Operations . Natural Gas STAR Producer’s Technology Transfer Workshop. Septem ber 11, 2007. Available online at:

< http://epa.gov/gasstar/doc uments/workshops/glenw ood-2007/04_recs.pdf >.

Background Technical Support Document – Petroleum and Natural Gas Industry 87Unconventional 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

► Estimate the Volume of Emissions That Are Not Flared Some states regulate that completion and re-com pletion (workover) flowb acks must be flared or recovered. Industry representatives have sh ared with EPA that flaring of completions and workovers is required in Wyoming; however, it is not required in Texas, New Mexico, and

Oklahoma. EPA assumed that no completions were flared in the Texas, New Mexico, and Oklahoma, then took the ratio of unconventio nal wells in Wyoming to the unconventional wells in all four sample states to estimate the percentage of well completions and workovers that are flared. EPA assumed that this sample was indicative of the rest of the U.S. This ratio was estimated to be approximately 51%.

The portion of flared natural gas was deducted fr om the results of Exhibit B-5 so that only the vented portion of natural gas from well co mpletions and workovers was estimated. It then converted these natural gas emissions to methane emissions using an average methane content in produced natural gas of 78.8% by volume. The results are in Exhibit B-6, below.

Exhibit B-6. Summary of Methane Emission s: U.S. Completion and Workover Venting

2007
Activity Unmitigated Flowback Natural Gas Vented Methane Vented

Conventional Gas Well Completions ~0.7 Bcf ~0.37 Bcf ~0.29 Bcf

Conventional Gas Well
Workovers << 1 Bcf << 1 Bcf << 1 Bcf

Unconventional Gas Well Completions ~85 Bcf ~43 Bcf ~34 Bcf

Unconventional Gas
Well Workovers ~38. Bcf ~19 Bcf ~14 Bcf

Note: The emission factors and calculated emissions as presented in this table were rounded independently. TOTAL: ~48 Bcf

The final resulting methane emissions from well completions and workovers is 48 Bcf . This estimate does not include hydraulic fracturing due to completions and workovers of gas wells in tight sands formations. Tight sands wells are not tracked by the U. S. Inventory and may substantially increase this es timate of unconventional well completions and workovers. A 2008 INGAA study 17 estimated that, in fact, approximately twice as many unconventional wells were completed than this analysis and approximately twice as many unconventional wells exist, 10% of which may require workover. This increase in activity is due to the inclusion of tight sands formations. If this anal ysis were to account for that activity level, not only would the number of hydraulic fractures incr ease substantially, but also the distribution of wells that are required to flare by law woul d be shifted such that only 15% of hydraulic

17 INGAA Found ation Inc.. Availability, Economics, And Production Pote ntial of North American Unconventional Natural Gas Supplies . November 2008.

Background Technical Support Document – Petroleum and Natural Gas Industry 88fracture flowbacks would be estimated to be flared. Using INGAA’s estimates of activity,

emissions would increase to 141 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 conventi onal 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, and casing diameter. The equation for this calculation is available in an EPA, Natural Gas STAR technical study 18

. The equation is displa yed in Exhibit B-7.

Exhibit B-7. Well Blowdown Em issions for Liquid Unloading

 2 V

v = 

#  0.37  10 6 

# 
 D  h  P

where,

V
v = Vent volume (Mcf/blowdown)

D = casing diameter (inches)

h = well depth (feet)

P = shut-in pressure (psig)

A combination of GASIS 19 and LASSER 20 databases provided we ll depth and shut-in pressures for a sample of 35 natural gas basins . 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.

One 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 21 . Using the

18 EPA. Installing Plunger Lift Systems in Gas Wells: Le ssons Learne d from Natural Gas STAR Partners

. October, 2003. Available on line at: <http://epa.gov /gasstar/documents/ll_plungerlift.pdf>.

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

20 LASSERTM database.

21 EPA. Natural Gas STAR Partner Update: Spring 2004 . Available online at:

< http://epa.gov/gasstar/documents/partner-updat es/spring 2004.pdf >.

Background Technical Support Document – Petroleum and Natural Gas Industry 89data 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 18 . 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 wells which will not require liquid unloading. EIA posts maps that display the concentra tion of conventional gas wells in each basin 22 , the concentration of gas wells in tight formations by basin 23 , and the concentration of coal bed methane gas wells by basin 24 . These maps were used to estimate the approximate percentage

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

► Estimate Emissions from 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 25 estimated that there were 389,245 conventional gas wells in 2007. The emission 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

.

22 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>.

23 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>.

24 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>.

25 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2006 . 2007. Available online at http://www.epa.gov/climatechange/ emissions/usinventoryreport.html

.

Background Technical Support Document – Petroleum and Natural Gas Industry 90This estimate does not include emission reduc tions from control methods such as plunger lifts, plunger lifts with “smart” automation, or ot her artificial lift techniques.

Background Technical Support Document – Petroleum and Natural Gas Industry 91

### Appendix C: Development of threshold analysis

As the main text has pointed out the petroleu m and natural gas sector includes hundreds, and in some cases thousands, of operators, many of them with few emission sources as well as ones with over 100 emission sources. Requiring all operators to repor t 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 performed 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 fo r the threshold analysis for the onshore petroleum and natural gas production segment

 The threshold analysis for onshore (inclu ding EOR) production sector estimated the equipment leaks, vented emissions, and combustion emissions per unique operator per basin.

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

HPDITM database 2006. The total onshor e 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: gas well hydraulic fracture completion ve nting, gas well liqui ds unloading venting, and gas well workover venting following hydraulic fracture. Natural Gas STAR emission reductions reported by partners fr om these sources are higher than the current inventory emission estimates. As a result emissions from these sources are currently under-e stimated in the inve ntory. The methodology used to revise these emissions estimates can be found in Appendix B. In addition, emissions from storage

tanks vented and flared emissions are believ ed to be under estimated in the U.S. GHG Inventory. EPA independently estimated the storage tank emissions using publicly

available data described in docket memo “Analysis of Tank Emissions” (EPA-HQOAR-2009-0923-0002). EPA’s estimated emissions from onshore production storage tanks may be as high as 75 billion cubic feet (Bcf) as compared with the 12 Bcf estimate provided in the 2006 inventory. In addition, the threshold analysis does not account for several sources that are not repr esented in the U.S. GHG Inventory such as associated gas venting and flaring, well testing venting and fl aring and gas well hydraulic fracture completion venting in tight sands, the latter because these wells are not included in state data (See Appendix B). For all of these sources which are believed to be under estimated in the U.S. GHG Inventory, there are Natural Gas STAR reductions reported by production partne rs for year 2006 of 67 Bcf. However, Natural Gas STAR reports generally do not state exactly where the reported reductions were made, and in the case of production, whether they were onshore or offshore or included oil and ga s gathering equipment. Th erefore, EPA has concluded that the increase in emissions not accounted for in the U.S. GHG Inventory approximately offset the reductions reported by Natural Gas STAR production

Background Technical Support Document – Petroleum and Natural Gas Industry 92partners. Because it is not feasible to map the emissions reductions reported by Natural Gas STAR Partners to their resp ective facilities, apportioning reductions equally would distort the thre shold analysis. Hence, the threshold analysis does not

include both the revised estim ates from storage tanks (and other missing sources) and

reductions from Natural Gas ST AR because they cancel out. 26

 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 C 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, obtained from the EPA’s Lesson Learned 2006, Replacing Glycol Dehydrators with Desiccant Dehydrator . The total national throughput was assumed to be equal to the total nationa l gas produced obtained from the EIA.

CO 2 and N 2 O combustion emission factor for natural gas from the API compendium 2004 was used to estimate the total national CO 2 and N 2 O

emissions. The total emissions were a pportioned 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 stat es based on the pe rcentage 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

.

26 A similar issue occurs w ith the other segments of th e industry. For processing facilities, emissions from flares are not included in the threshold analysis. For transmission segment, emissions from scrubber dump valves and compressor unit isolation valves are not in cluded in the threshold analysis. For the distribution segment, the emission from combustion sources are not included in the threshold analysis. The missing and under accounted emissions estimates roughly offset the Natural Gas STAR reductions reported. Hence, EPA has assumed that the missing and under-accounted cancel out the Natural Gas STAR Reductions and therefore did not include them in the threshold analyses.

Background Technical Support Document – Petroleum and Natural Gas Industry 93 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 factor 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 natural 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 leaking, ve nted, 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

o 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 fact or. The natural gas emission factor was adjusted to EOR operation using th e 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

Background Technical Support Document – Petroleum and Natural Gas Industry 94requirements 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 assuming 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 the 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 operator was assigned a “1 ” if it crossed a threshold and a “0” otherwise, by running the following logic checks:

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

Background Technical Support Document – Petroleum and Natural Gas Industry 95o 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 equipment leak emissions (CO 2 e), CH 4 equipment leaks (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 BOEMRE Goad s Summary 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 produc tion platforms was obtained from the

BOEMRE 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 27 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 ga s wells to federal platforms 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 equipment leak, vented, and combustion emissions were estimated by applying the ratio of stat e to federal platforms and mu ltiplying it by the federal offshore equipment leak, 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 equipm ent leak, vented, and combustion emissions

to calculate the volume of state offshore em issions 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

27 Emery, Brian M. et al. Do oil and gas platforms off California re duce recruitment of bocaccio (Sebastes paucispinis) to natural habitat? An analysis based on trajectories derived from high frequency radar

. http://www.icess.ucsb.e du/iog/pubs/DrifterSim ulationsFinal_v5.pdf

Background Technical Support Document – Petroleum and Natural Gas Industry 96Threshold Analysis for Processing

 US gas processing plants, plant throughputs, and equipment 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 wet seals was obtained from Bylin et al 5

. Due to the uncertainty in centrifugal compressor wet seal emissions, the point that it is not possible to ascribe Natural Gas STAR pr ocessing partner emission reductions to a particular processing plant or even to proces sing plants in general as opposed to gas gathering equipment, the Natural Gas ST AR reported processing reductions of 6 Bcf/year were not incorporated into this analysis 26

.

 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 combusti on emission factors to the fuel gas used by each plant. The fuel gas consum ption was estimated using the horsepower requirements of engines a nd 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

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 ex ceeding 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 burdens 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 natu ral gas transmission segment is de fined as a compressor station. Data for individual compressor stations on interstate transmission pipelines are

Background Technical Support Document – Petroleum and Natural Gas Industry 97reported to FERC Form 2 28 , and data for compressor sta tions 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 intrasta te 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 specifie d, the analysis assumes that 81% of the installed capacity is reciprocating. In cas es where the provided installed capacity is both centrifugal and reciprocating, it is assu med that 81% is for engines. The 81% assumption is the ratio of reciprocati ng 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 1 ) to interstate station design th roughput capacity (MMcfd, FERC 28 ) 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 hor sepower is provided, it was used directly for installed turbine capacity (Hp). In cases where the installed capacity was provided, 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 reciprocating, 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 1 ) to interstate station design th roughput capacity (MMcfd, FERC 28 ) 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 equipment leak methane and nonenergy CO 2 , were estimated in the U.S. G HG Inventory. Emission factor for centrifugal compressor wet seals was obtained from Bylin et al 5

. Due to the uncertainty in centrifugal compressor wet seal emissions, the point that it is not possible to ascribe Natural Gas STAR tran smission partner emission reductions to a

28 FERC. Form 2 Major and Non-major Natural Gas Pipeline Annual Report. Available online at:

< http://www.ferc.gov/docs -filing/eforms/form-2/da ta.asp#skipnavsub >.

Background Technical Support Document – Petroleum and Natural Gas Industry 98particular compressor station or even to transmission in genera l as opposed to gas storage equipment, the Natural Gas STAR reported transmission reductions of 25 Bcf/year were not incorporated into this analysis 26 . The total emissions were allocated to each facility based on its porti on of the segment’s total station throughput capacity, as shown in the following equation:

StationCapacity i Station “ i ” process emissions =  TotalInventoryEmissions 

##  StationCapacity

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 ex ceeding 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 29

.

 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:

29 EIA. EIA-176 Query System . Available online at:

< http://www.eia.doe.gov/oil_gas/natural_gas/applications/eia176query_historical.html >.

Background Technical Support Document – Petroleum and Natural Gas Industry 99MaximumDailyDelivery Compressor energy i (MMHphr) = i  TotalSegmentMMHphr 

##  MaximumDailyDelivery

i Where, index “ i ” denotes an individual facility

 The total process emissions for 2006, both ve nted and equipment leak methane and non-energy 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 ex ceeding 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 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 the Additional Changes to Activity Factors for Portions of the Gas Industry background memo for EP A’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 th e background memo for EPA’s U.S. GHG Inventory. LNG company c ontacts provided 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”

Background Technical Support Document – Petroleum and Natural Gas Industry 100season. 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:

38,706 MMcf 750 Hp 24 hours 1 MMHphr LEU =    200 days  50%  200 days 1 MMcfd day 1,000,000 Hphr
where, LEU = total liquefaction energy us e 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:

LC i Facility “i” liquefaction MMHphr =  TotalSegmentMMHphr 

##  LC

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 st andard 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:

SC i  0.05% 750 Hp  24 hours  MMHphr FBEU i =     365 days     365 days MMcfd  day  1,000,000 Hphr

where,

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

 Vaporization and send-out compressor ener gy 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 f acilities compared to 8.7 Bcf from satellite facilities in 2003. This equates to 89.6% of send-out coming fr om peak shaving plants in 2003; the analysis assumes the same is true for 2006. EIA 30 provides that in 2006, total LNG withdrawals were 33,743 MMcf. The send-out compressor energy

30 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>

.

Background Technical Support Document – Petroleum and Natural Gas Industry 101use by all peak shaving plants in the se gment was calculated using the following equation:

33,743 MMcf 1.86 MMHphr Total send-out energy use =   89.6% 365 days MMcfd

 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 ne cessary for boil-off. We performed the above analysis on the “average” satellite facility to estimate its energy use and emissions. The only differen ce was that 10.4% of EIA reported LNG

withdrawals was attributed to the satellite facilities.

 The total process emissions for 2006, both ve nted and equipment leak methane and non-energy CO 2 , were estimated in the U.S. GHG Inventory. These total emissions were allocated to each facility based on its portion 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)

 The total emissions for each facility were calculated by summing the calculated equipment leak, 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 ex ceeding that threshold.

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

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

Threshold Analysis for LNG Import Terminals

Background Technical Support Document – Petroleum and Natural Gas Industry 102 “Facility” in the LNG import segment is defined as the import terminals. Data is

available for this on the FERC website 31 . 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. Inventory assumptions were used to estimate liquefaction, boil-off liquefaction, and send-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 boi l-off liquefaction compressor energy use was thus estimated for each facility using the following equation:

IV i  0.05% 750 Hp  24 hours  MMHphr FBEU i =     365 days     365 days MMcfd  day  1,000,000 Hphr

where,

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

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

 Vaporization and send-out compressor ener gy 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 compression, satellite facilities require 1.86 MMHphr for each MMcfd of send-out. The following equation estimates the energy use at each facility:

IV i 1.86 MMHphr Facility “i” send-out energy use =  365 days MMcfd

 The total process emissions for 2006, both ve nted and equipment leak methane and non-energy 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:

IV i Facility “i” process emissions =  InventorySegmentEmissions 

##  IV

i where,

IV i = import volume and “i” represents 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

31 FERC. Import Terminals . Available online a t: < http://www.ferc.gov /industries/lng.asp >.

Background Technical Support Document – Petroleum and Natural Gas Industry 103EF 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 ex ceeding that threshold.

 Multiplying the logic checks above by the total emissions for each facility, then summing the results yielded the total emissions 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) 32 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.

 CO 2 and CH 4 equipment leaks from distributi on 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 1

.

Exhibit C-8: LDC’s Equipmen t Leak Emission Factors

Pipeline Type/Material Equipment Leak 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 equipment leak methane and non-energy CO 2 , were estimated by EPA

32 DOT. 2006 Distribution Annuals Data . Available online at:

< http://www.phmsa.dot.gov/pip eline/library/data-stats >.

Background Technical Support Document – Petroleum and Natural Gas Industry 104U.S GHG Inventory. These total emissions we re allocated to each facility based on its portion of the segment’s total import volume, using the following equation:

MM i Facility “i” M&R emissions =  InventorySegmentEmissions 

##  MM

i where,

MM = total miles of mains pipelin e, and “i” represents individual

facilities

 The total emissions for each facility were calculated by summing the calculated pipeline leaks and M&R station emissions 26

.

 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 ex ceeding 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.

Background Technical Support Document – Petroleum and Natural Gas Industry 105

### 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 configuration will need specific definitions on what constitutes a facility.

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 33 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 definition of hydro carbon production basins which are referenced to County boundaries. The Unite d States Geological Survey (USGS)

33 EIA Oil and Gas Field Master – 2007, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_ publications/field_code_master_list/current/pdf/fcml_all

. pdf

Background Technical Support Document – Petroleum and Natural Gas Industry 106also provides such a definition, which is different than the AAPG definition. The AAPG definition identified by the “geologic 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 basin, 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 reporting 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 individual facilities.

C. Qualitative Analysis of Facility Options

The following qualitative evaluation provi des a discussion on the advantages and disadvantages of using any of the three reporting level defini tions, based on expert opinion.

i. Ease of practical application of reporter and facility definitions

1) 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

Background Technical Support Document – Petroleum and Natural Gas Industry 107boundaries, 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 defin ition. This means that the required threshold for emissions reporting may not be reached due to exclusion of the equipment leaks as well as the com bustion emissions from compressors. Alternatively, the threshold will have to be set very low to capture any

reasonable amount of emissions from field level definition.

Geographic field definition: The EIA publishes its Field 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 facility 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 level 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.

2) 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 identified sources from the entire U.S. onshore oil and gas operations.

Background Technical Support Document – Petroleum and Natural Gas Industry 1083) 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

xi. American Association of Petroleum Geologists

Background Technical Support Document – Petroleum and Natural Gas Industry 109

### Appendix E: Development of mult ipliers 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 34 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 e quation, as shown in Exhibits E-9 and E-10.

Exhibit E-9. Oil Tank Correction Factors

34 Texas Commission on Envi ronmental Quality (TCEQ). Upstream Oil and Gas Storage Tank Project Flash
Emissions Models Evaluation . July 16, 2009.

Background Technical Support Document – Petroleum and Natural Gas Industry 110y = -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) Oil Tanks (  ̊ API<45)

Measurement - E&P Tank Linear (Measurement - E&P Tank)

Exhibit E-10. Condensate Tank Correction Factors

600[Measurement] - [E&P Tank estimates](scf/bbl) 500

400

300

200

100

- y = -0.6673x + 248.34

R 2 = 0.0045

E&P Tank Estimate (scf/bbl) Condensate Tanks (  ̊ API>45)

20 30 40 50 60 70 80

Measurement - E&P Tank Linear (Measurement - E&P Tank)

The equation for the line of best fit can be used on E&P Tank (GEO-RVP) results where non-flashing emission affects are detected to estimate the true ta nk emissions. The data used to derive this relationship range from 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) emission estimate and “CE” is the corrected

emission estimate.

As demonstrated in Exhibits E-9 and E-10, the correlations for the correction factor are very weak, with R 2 values of 0.0719 for oil and 0.0045 for condensate.

Background Technical Support Document – Petroleum and Natural Gas Industry 111Method 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) emissi on 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) emission 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 th e 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.

Background Technical Support Document – Petroleum and Natural Gas Industry 112

### Appendix F: 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 35 . Hydrocarbon liquids greater th an 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 facility type are taken from API’s Emission Factors for Oil and Gas Production Operations 35

. Hydrocarbon liquids less than 20°API are considered “heavy

crude.” The methane content of associated natural gas with onshor e 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
Connector (other) 1.38 1.497 Open-Ended Line 1.48 1.6

Other 3.56 3.846

35 API. Emission Factors for Oil an d Gas Production Operations . Table 10, page 16. API Publication Number 4615. January 1995.

Background Technical Support Document – Petroleum and Natural Gas Industry 113EF: 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 cr ude 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 36 and

Clearstone’s Cost-Effective Directed Inspection and Maintenance C ontrol Opportunities at Five Gas Processing Plants and Upstream Gath ering Compressor Stations and Well Sites 37

. The components were categorized into th ree groups: reci procating compressor related, centrifugal compressor related and all other components. Furthermore, the components related to reciprocating and cen trifugal compressor were segr egated 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 )

Component

Name Reciprocating Compressor Component, (scf/hour/comp) Centrifugal Compressor Component, (scf/hour/comp) Other Components, (scf/hour/comp) Before De-
Methanizer After DeMethanizer Before DeMethanizer After DeMethanizer

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

Conversions:
C: 24 hours / day

E: 1000 scf / Mscf

36 EPA. Identification and Evalua tion of Opportunities to Reduce Methan e Losses at Four Gas Processing
Plants . Clearstone Engineering Ltd. June 20, 2002. <www.epa.gov/gasstar/documents/four_plants.pdf>

37 National Gas Machinery Laboratory, Kansas State Un iversity; Clearstone Engin eering, Ltd; Innovative Environmental Solutions, Inc. Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Ga thering Compressor Sta tions and Well Sites . For EPA Natural Gas STAR Program. March 2006.

Background Technical Support Document – Petroleum and Natural Gas Industry 114

### 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 38 and the Measurement of Natural Gas Emissions from the Canadian Natural Ga s Transmission and Distribution Industry 39

. All compressor related components were separated fr om 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



### Methane Emission Factors for LNG Storage

Leaker Emission Factors – LNG Storage Components, LNG Service

Methodology

38 Clearstone. Handbook for Estimating Methane Emission s from Canadian Natural Gas Systems . Clearstone Engineering Ltd., Enerco Engineering Ltd, and Radian International. May 25, 1998.

39 Clearstone. Measurement of Natural Gas Em issions from the Canadian Na tural Gas Transmission and Distribution Industry . Clearstone Engineering Ltd., Canadian Energy Partnership for Environmental Innovation (CEPEI). April 16, 2007.

Background Technical Support Document – Petroleum and Natural Gas Industry 115The light liquid emission factors with leak concentrations greater than or equal to 10,000 ppmv were taken from Protocol for Equipment Leak Emission Estimates 40 . The emissions
are assumed to be 100% methane.

Component EF, scf/hour/component = (Light Liquid >= 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



### Total Hydrocarbon Emission Factor s for Processing, Transmission, and Underground Storage

Leaker Emissions Factors –Compressor Co mponents, Non-Compressor Components,
Gas Service

Methodology
Several leaker emission factors for the processing segment, su ch as open-ended lines before the de-methanizer for reciprocating compressors, did not have sufficient data points to justify a representative emission factor. To eliminate th is issue, the segregation of components into reciprocating versus centrifugal and before the de-methanizer ve rsus after the de-methanizer

was eliminated.

In addition, the leaker emission factors from transmission were combined with those from processing. Equipment leak emissions from transmission compressors and processing compressors are similar because they are comparable in size and discharge pressure. Compressors in processing either inject residue gas into high pressure transmission pipelines or pressurize large volumes of production gas for processing facility processes.

The same LEFs can also be used for compre ssor related components in underground natural gas storage because compressors in this sector have a large throughput and inject gas at high pressure into the ground or into transmission pipelines. The final emission factors were

corrected to 68  ̊ F and 14.7 psia per the defi nition of “standard conditions” set forth in subpart
A of Title 40 CFR 98.

40 EPA. Protocol for Equipment Leak Emission Estimates . Emission Standards Division. U.S. EPA. SOCMI
Table 2-7. November 1995.

Background Technical Support Document – Petroleum and Natural Gas Industry 116Component EF, scf/hour/component = (Leak rate
, Mscf/day/component) * ( E ) / ( C )

Component Name Emission Factor (scf/hour/component)

Leaker Emission Factors – Compressor Components, Gas Service

Valve 15.07
Connector 5.68 Open-ended Line 17.54
Pressure Relief Valve 40.27

Meter 19.63 Leaker Emission Factors – Non -Compressor Components, Gas Service

Valve 6.52
Connector 5.80 Open-ended Line 11.44
Pressure Relief Valve 2.04

Meter 2.98

Conversions:
C: 24 hours / day

E: 1000 scf / Mscf



### 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 40

.



### 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 38 and Measurement of Natural Gas Emissions from the Canadian Natural Ga s Transmission and Distribution Industry 39

.

Component 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

Background Technical Support Document – Petroleum and Natural Gas Industry 117Block 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 41

.

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

Emission Factor Onshore production (scf/hour/component)
Leaker Emission Factors - All Components, Gas Service

Valve

Connector Open-ended Line

Pressure Relief Valve

Low-Bleed Pneumatic Device Vents Gathering Pipelines

CBM Well Water Production Compressor Starter Gas Vent
Conventional Gas Well Completion NA

NA

NA

NA

NA

NA

NA

NA

NA

41 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 >

Background Technical Support Document – Petroleum and Natural Gas Industry 118Conventional Gas Well Workover NA
Leaker Emission Factors - All Components, Light Crude Service 1

Valve

Connector Open-ended Line Pump

Other 2.03

0.90

0.96

2.35

2.31
Leaker Emission Factors - All Components, Heavy Crude Service 2

Valve Flange Connector (other) Open-ended Line

Other

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" 3.13

4.15

1.38

1.48

3.56

T OTAL 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

Connector Open-ended Line

Pressure Relief Valve

Meter 6.42

5.71

11.27

2.01

2.93

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

Background Technical Support Document – Petroleum and Natural Gas Industry 119Control Valve Compressor Blowdown Valve

Pressure Relief Valve

Orifice Meter

Other Meter Regulator Open-ended Line Leaker Emission Factors - Other Components, Gas Service

Low-Bleed Pneumatic Device Vents

1 Emission Factor is in units of "scf/hour/mile" 3.4

543.5

37.2

14.3

0.1

9.8

21.5

NA

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

Valve

Pressure Relief Valve Open-ended Line Leaker Emission Factors - Other Components, Gas Service

Low-Bleed Pneumatic Device Vents NA

NA

NA

NA

NA

T OTAL H YDROCARBON E MISSION F ACTORS FOR P ROCESSING, T RANSMISSION, A ND, U NDERGROUND S TORAGE

Processing, Transmission, and Underground Stor age Emission Factor (scf/hour/component)

Leaker Emission Factors – Compressor Components, Gas Service

Valve

Connector Open-Ended Line

Pressure Relief Valve

Meter 15.07

5.68

17.54

40.27

19.63
Leaker Emission Factors – Non-compressor Components , Gas Service

Valve 6.52

Connector 5.80 Open-Ended Line 11.44

Background Technical Support Document – Petroleum and Natural Gas Industry 120Pressure Relief Valve 2.04

Meter 2.98

1 Valves include control valves, bl ock valves, and regulator valves.

M ETHANE E MISSION F ACTORS FOR LNG S TORAGE

Emission Factor LNG Storage (scf/hour/component)
Leaker Emission Factors - LNG Storage Components, LNG Service

Valve Pump Seal

Connector

Other 1.19

4.00

0.34

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 Pump Seal

Connector

Other 1.19

4.00

0.34

1.77 Leaker Emission Factors - LNG Terminals Compressor, Gas Service Vapor Recovery Compressor NA

M ETHANE E MISSION F ACTORS FOR D ISTRIBUTION

Emission Factor Distribution (scf/hour/component)
Leaker Emission Factors - Above Grade M&R Stations Components, Gas Service

Connector

Block Valve

Control Valve

Pressure Relief Valve

Orifice Meter Regulator Open-ended Line 1.69

0.557

9.34

0.270

0.212

26.131

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 - Distribution Mains, Gas Service 1
Unprotected Steel

Background Technical Support Document – Petroleum and Natural Gas Industry 121 6.02Protected 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

1 Emission Factor is in units of "scf/hour/leak" 0.88

Summary This Appendix provides leaker emissions factors 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.

Background Technical Support Document – Petroleum and Natural Gas Industry 122

### Appendix G: Development of population emission factors

Natural Gas Emission Factors for Onshore Production

Whole Gas Population Emission Fact ors – All Components, Gas Service

Methodology
The well counts and emission fact ors were taken from GRI’s Methane Emissions from the Natural Gas Industry 42

. 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%.

Eastern/Western U.S. Component EF, scf/hour/component = (EF Eastern/Western U.S., mscf/yr) * ( A ) * ( B ) / ( C ) / ( D )

Component Eastern U.S. EPA/GRI EF (mscf
CH 4 /year) Eastern U.S. Subpart W EF (scf natural gas/hour)

Valve 0.184 0.027

Connector 0.024 0.004 Open-Ended Line 0.420 0.062

Pressure Relief Valve 0.279 0.041

Component Western U.S. EPA/GRI EF (mscf
CH 4 /year) Western U.S. Subpart W EF (scf natural gas/hour)

Valve 0.835 0.123

Connector 0.114 0.017 Open-Ended Line 0.215 0.032

Pressure Relief Valve 1.332 0.196

Conversions:
A: 1,000 scf/mscf

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions
C: 8,760 hours/year

D: 78.8% methane by volume in produced natural gas

“High Continuous Bleed Pneumatic Device Vents” Methodology Methane emissions per pneum atic device are from API’s Compendium of Greenhouse Gas Emissions Methodologies fo r the Oil and Gas Industry 43 . The average methane content of natural gas is assumed to be 78.8%.

48.1 scf/hour/component EF = ( 896 [scfd CH 4 /pneumatic devises, high bleed]) * ( B ) / ( D ) / ( E )

42 GRI. Methane Emissions from the Natural Gas Industry . Volume 8. June 1996.

< www.epa.gov/gasstar/documents/emissions_report/8_equipmentleaks.pdf >

43 API. Compendium of Greenhouse Gas Emissions Me thodologies for the Oil and Gas Industry . American Petroleum Institute. Table 5-15, page 5-68. August 2009.

Background Technical Support Document – Petroleum and Natural Gas Industry 123Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

D: 78.8% – production quality of natural gas (% methane) 44

E: 24 hours/day

“Low Continuous Bleed Pneumatic Device Vents” Methodology Methane emissions per pneum atic device are from API’s Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry 43 . The average methane content of natural gas is assumed to be 78.8%.

1.80 scf/hour/component EF = ( 33.4 [scfd CH 4 /pneumatic devises, low bleed]) * ( B ) / ( D ) / ( E )

Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

D: 78.8% – production quality of natural gas (% methane)

E: 24 hours/day

“Intermittent Bleed Pneumati c Device Vents” Methodology Methane emissions per pneum atic device are from API’s Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry 43 . The average methane content of natural gas is assumed to be 78.8%.

17.4 scf/hour/component EF = ( 323 [scfd CH 4 /pneumatic devises, low bleed]) * ( B ) / ( D ) / ( E )

Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

D: 78.8% – production quality of natural gas (% methane) 44

E: 24 hours/day

“Pneumatic Pumps” Methodology Methane emissions per pneumatic pump are from GRI’s Methane Emissions from the Natural Gas Industry 45 . The average methane content of natural gas is assumed to be 78.8%.

13.3 scf CH 4 /hour/component EF = ( 248 [scfd CH 4 /pneumatic devises, low bleed]) * ( B ) / ( D ) / ( E )

44 GRI. “Vented and Combustion Source Summary,” Methane Emissions from th e Natural Gas Industry, U.S. EPA, Volume 6, Appendix A, page A-2.

45 GRI. Methane Emissions from the Natural Gas Industry . Volume 13. Tables 4-4. June 1996.

< http://epa.gov/gasstar/documents/e missions_report/13_chemical.pdf >.

Background Technical Support Document – Petroleum and Natural Gas Industry 124Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

D: 78.8% – production quality of natural gas (% methane) 46

E: 24 hours/day

Population Emission Factors – All Components, Light Crude Service

Methodology Average emissions factors by facili ty type were taken from API’s Emission Factors for Oil

and Gas Production Operations. 47 Hydrocarbon liquids greater th an or equal to 20°API are considered “light crude.”

Component EF, scf/hour/component = (Average Emissions Factors by Facility Type, lb/component-day) * ( B ) / ( E ) / ( F )

Component Name Component EF, scf/hr/comp Average EF by Facility Type, lb/component-day

Valve 0.04 7.00E-02
Flange 0.002 4.07E-03

Connector 0.005 8.66E-03 Open-Ended Line 0.04 6.38E-02
Pump 0.01 1.68E-02

Other 0.23 3.97E-01

Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

D: 24 hours/day

F: 0.072 gas density lb/scf – assumes a gas co mposition of 61.2% methane, 20% ethane, 10% propane, 5% butane, and 3.8% pentanes+

Population Emission Factors – All Components, Heavy Crude Service

Methodology Average emissions factors by facil ity type were taken from API’s Emission Factors for Oil and Gas Production Operations 48 . Hydrocarbon liquids less than 20°API are considered “heavy crude.” The methane content of associ ated natural gas with onshore light crude is 94.2% from the same study.

46 GRI. “Vented and Combustion Source Summary,” Methane Emissions from th e Natural Gas Industry, U.S. EPA, Volume 6, Appendix A, page A-2.

47 API. Emission Factors for Oil an d Gas Production Operations . Table 9, page 10. API Publication Number 4615. January 1995.

48 API. Emission Factors for Oil an d Gas Production Operations . API Publication Number 4615. page ES-3, Table ES-4, January 1995.

Background Technical Support Document – Petroleum and Natural Gas Industry 125Component EF, scf/hour/component = (Average Emi ssions Factors by Facility Type, lb/component-day) * ( B ) / ( D ) / ( F )

Component Name Component EF, scf/hr/comp Average EF by Facility Type, lb/component-day

Valve 0.0004 6.86E-04
Flange 0.0002 1.16E-03
Connector (Other) 0.0004 4.22E-04 Open-Ended Line 0.004 8.18E-03

Other 0.002 3.70E-03

Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

D: 24 hours/day

F: 0.072 gas density lb/scf – assumes a gas co mposition of 61.2% methane, 20% ethane, 10% propane, 5% butane, and 3.8% pentanes+



### Methane Emission Factors For Processing

Population Emission Factors – All Components, Gas Service

There are no population emission factors in subpart W for the onshore natural gas processing
segment.



### Methane Emission Factors for Transmission

Population Emission Factors – All Components, Gas Service

Gas transmission facility emission factors were taken from the Handbook for Estimating Methane Emissions from C anadian Natural Gas Systems 49 . “Connector” includes flanges, threaded connections, and mechanical couplin gs. “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 pl ug valves). Leakage past the valve seat is accounted for the Open-Ended Line emission cate gory. Leakage 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 account ed for by the Instrument Cont roller and Open-Ended Line categories respectively. This f actor applies to all valves with automatic actuators (including fuel gas injection valves on the drivers of re ciprocating compressors). “Orifice Meter” accounts for emissions from the orifice changer. Emissions from sources on pressure tap

lines etc. are not included in th e factor (i.e., these emissions must be calculated separately).

49 CEPEI. Handbook for Estimating Methane Emissions from Canadian Natural Gas Systems . May 25, 1998.

Background Technical Support Document – Petroleum and Natural Gas Industry 126“Other Meter” accounts for emissions from othe r 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) * ( B )

* ( I ) / ( F )

Component Name Component EF, scf/hour/comp Gas Transmission Facility Avg. Emissions, kg/hr/src

Connector0.01 2.732E-04

Block Valve 0.11 2.140E-03

Control Valve 1.04 1.969E-02

Pressure Relief Valve 14.74 2.795E-01

Orifice Meter 0.18 3.333E-03

Other Meter 0.0005 9.060E-06 Regulator0.17 3.304E-03
Open-Ended Line 4.40 8.355E-02

Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

F: 0.04246 CH 4 density lb/scf

I: 2.20462262 lb/kg

Population Emission Factors – Other Components, Gas Service

“Low Continuous Bleed Pneumatic Device Vents” Methodology Methane emissions per pneum atic device are from API’s Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry 43 . The average methane content of natural gas is assumed to be 78.8%.

1.41 scf/hour/component EF = ( 33.4 [scfd CH 4 /pneumatic devises, low bleed]) * ( B ) * ( J ) / ( D ) / ( E )

Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

D: 78.8% – production quality of natural ga s (% methane) from: “Vented and Combustion Source Summary,” Methane Emissions from the Natural Gas Industry,

U.S. EPA, Volume 6, Appendix A, page A-2.

E: 24 hours/day

J: 93.4% – pipeline quality 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.

“High Continuous Bleed Pneumatic Device Vents” Methodology

Background Technical Support Document – Petroleum and Natural Gas Industry 127Methane emissions per pneumatic device are from GRI’s Methane Emissions from the Natural Gas Industry 50 . The average methane content of natural gas is assumed to be 78.8%.

18.8 scf/hour/component EF = ( 162,197 [scfy CH 4 /pneumatic devises, low bleed]) * ( B ) / ( C )

Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions
C: 8,760 hours/year

“Intermittent Bleed Pneumati c Device Vents” Methodology Methane emissions per pneumatic device are from GRI’s Methane Emissions from the Natural Gas Industry 50 . The average methane content of natural gas is assumed to be 78.8%.

18.8 scf/hour/component EF = ( 162,197 [scfy CH 4 /pneumatic devises, low bleed]) * ( B ) / ( C )

Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions
C: 8,760 hours/year



### 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 42

.

Component EF, scf/hour/component = (Injection/Withdrawal Wellhead) ( A ) * ( B ) / ( C )

Component Name Component EF, scf/hr/comp Injections/Withdrawal Wellhead, Mcf/yr

Connector 0.01 0.125

50 GRI. Methane Emissions from the Natural Gas Industry . Volume 12. Page 52. June 1996.

< http://epa.gov/gasstar/documents/emissions _report/12_pneumatic.pdf >.

Background Technical Support Document – Petroleum and Natural Gas Industry 128Valve 0.10 0.918

Pressure Relief Valve 0.17 1.464
Open-Ended Line 0.03 0.237

Conversions:
A: 1,000 scf/mscf

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions
C: 8,760 hours/year

Population Emission Factors – Other Components, Gas Service

Methodology “Low Continuous Bleed Pneumatic Device Vents” Methodology

See “Low Continuous Bleed Pneumatic Device Vents” Methodology for Population Emission Factors – Other Components, Gas Service for Transmission.

“High Continuous Bleed Pneumatic Device Vents” Methodology See “High Continuous Bleed Pneumatic Device Vents” Methodology for Population Emission Factors – Other Components, Gas Service for Transmission.

“Intermittent Bleed Pneumati c Device Vents” Methodology

See “Intermittent 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 EPA’s Inventory of U.S. Greenhouse Gas Emissions

and Sinks 51 . 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) ( B ) * ( I ) / ( F )

Component Name Component EF, scf/hour/comp Component EF, Mscf/comp-yr

Valve 0.10 0.867
Open-ended Line 1.30 11.2

Connector 0.02 0.147

PRV 0.72 6.2 Conversions:

51 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2006 . Available online at

< http://www.epa.gov/climatechange/emissions/usinventoryreport.html >.

Background Technical Support Document – Petroleum and Natural Gas Industry 129B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

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 51

.

4.23 scf/hour/component EF = ( 100 scfd CH 4 /compressor) * ( B ) / ( D )
Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

D: 24 hours/day



### 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.



### 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 49 . “Connector” includes flanges, threaded connections, and mechanical couplings. “Block Valve” accoun ts for emissions from the stem packing and the valve body, and it applies to all types of bl ock valves (e.g., butterfly, ball, gl obe, gate, needle, orbit, and plug valves). Leakage past th e valve seat is accounted for the Open-Ended Line emission category. Leakage from the end connections is accounted for by the connector category

Background Technical Support Document – Petroleum and Natural Gas Industry 130(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 valves with automatic actuators (includi ng 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) * ( B ) * ( I ) / ( F )

Component Name Component EF, scf/hour/comp Gas Distribution Meter/Regulator Station Avg. Emissions, kg/h/src

Connector 5.79E-03 1.098E-04

Block Valve 5.85E-02 1.109E-03

Control Valve 1.04E+00 1.969E-02

Pressure Relief Valve 8.78E-01 1.665E-02

Orifice Meter 1.76E-01 3.333E-03

Other Meter 4.78E-04 9.060E-06 Regulator 1.01E-01 1.915E-03 Open-Ended Line 4.39E+00 8.355E-02

Conversions:

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions

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 Average emission factors are from GRI’s Metering and Pressure Regulating Stations in

Natural Gas Transmission and Distribution 52

. (Converted to 68  ̊ F)

Below Grade M&R Station, In let Pressure > 300 psig: 1.32 scf/hour/station EF

Below Grade M&R Station, Inlet 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 – Distribut ion Mains and Services, Gas Service

Methodology

52 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 >.

Background Technical Support Document – Petroleum and Natural Gas Industry 131Emission factors for pipeline leak s (mains and service) are from the Inventory of U.S.

Greenhouse Gas Emissions and Sinks: 1990-2007 53

Component EF, scf/hour/service = (P ipeline Leak ms cf/mile/year) ( A ) * ( 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 12.77 110.19 0.19 1.70

Protected Steel 0.36 3.07 0.02 0.18

Plastic 1.15 9.91 0.001 0.01

Cast Iron 27.67 238.7
Copper 0.03 0.25

Conversions:
A: 1,000 scf/mscf

B: 1.015 = ( 68+459.67)/(60+459.67 ) = conversion from 60  ̊ F to 68  ̊ F per subpart A

definition of standard conditions
C: 8,760 hours/year



### Nitrous Oxide Emission Factors for Gas Flaring

Population Emission Factors – Gas Flaring

Methodology
Emission factors are from API’s Compendium of Greenhouse Ga s Emissions Methodologies for the Oil and Gas Industry

.

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 pro duction 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

Summary This Appendix provides population emissions fact ors for potential emissions sources. These population emissions factors could be used in conjunction with population counts that make it more cost effective in estimating emissions . However, these population emissions factors estimate potential emissions as the percentage of emissions sources leaking may or may not

53 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2007 . Available online at

< http://www.epa.gov/climatechange/emissions/usinventoryreport.html >.

Background Technical Support Document – Petroleum and Natural Gas Industry 132be the same as the assumption made when de veloping the emissions factors. Also, the population emissions factors assume that a subs et of leaking emission sources is leaking continuously throughout the year.

Background Technical Support Document – Petroleum and Natural Gas Industry 133

### Appendix H: 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/or carbon dioxide (CO 2 ) contaminants that are separated from sour natural gas by an acid gas removal unit.

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 emissions mean the acid gas separated from the acid gas absorbing medium (e.g., an amine solution) a nd 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 gas.

Basin means geologic provinces as define d by the American Association of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991) (incor porated by reference, see §98.7) and the Alaska Geological Province Boundary Map, Co mpiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see §98.7).

Blowdown vent stack emissions mean natural gas and/or CO 2 released due to maintenance and/or blowdown operations including compressor blowdown and emergency shut-down (ESD) system testing.

Calibrated bag means a flexible, non-el astic, anti-static bag of a calibrated volume that can be affixed to an emitting source such that the emissions inflate the bag to its

calibrated volume.

Centrifugal compressor means any equipment that increas es the pressure of a process natural gas or CO 2 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 or CO 2 from escaping to the atmosphere.

Background Technical Support Document – Petroleum and Natural Gas Industry 134Centrifugal compressor dry seal emissions mean natural gas or CO 2 released from a dry seal vent pipe and/or th e seal face around the rotating sh aft where it exits one or both ends of the compressor case.

Centrifugal compressor wet s eal degassing vent emissions means emissions that occur when the high-pressure oil barri ers for centrifugal compressors are depressurized to release absorbed natural gas or CO 2 . High-pressure oil is used as a barrier against escaping gas in centrifugal compressor shafts. Very little gas es capes through the oil barrier, but under high pressure, considerably more gas is absorbed by the oil. The seal oil is purged of the absorbed gas (using heaters, flash tanks , and degassing techniques) and recirculated. The separated gas is commonly vented to the atmosphere.

Component means 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.

Continuous bleed means a continuous flow of pneu matic supply gas to the process measurement device (e.g. level control, temper ature control, pressure control) where the supply gas pressure is modulated by the proc ess condition, and then flows to the valve controller where the signal is compared with th e process set-point to ad just gas pressure in

the valve actuator.

Compressor means any machine for raising the pressure of a natural gas or CO 2 by drawing in low pressure natural gas or CO 2 and discharging significantly higher pressure natural gas or CO 2

.

Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, separated from natural ga s that condenses due to changes in the temperature, pressure, or both, and re mains liquid at storage conditions.

Dehydrator means a device in which a liquid absorb ent (including desi ccant, ethylene glycol, diethylene glycol, or tr iethylene glycol) directly cont acts a natural gas stream to absorb water vapor.

Dehydrator vent emissions means natural gas and CO 2 released from a natural gas dehydrator system absorbent (typically glycol) re boiler or regenerator to the atmosphere or a flare, including stripping natura l gas and motive natural gas us ed 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 or absorption. Desiccants include activated alumina, pelletized

Background Technical Support Document – Petroleum and Natural Gas Industry 135calcium chloride, lithium chloride and granular silica gel material. Wet natural gas is passed through a bed of the granular or pelletized solid adsorbent or ab sorbent in these dehydrators. As the wet gas contacts the surface of the partic les of desiccant materi al, water is adsorbed

on the surface or absorbed and dissolves the su rface of these desiccant particles. Passing through the entire desiccant bed, al most all of the water is adsorbed onto or absorbed into the desiccant material, leaving the dry gas to exit the contactor.

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 subpart, EOR applies to injection of critical phase or

immiscible carbon dioxide into a crude oil rese rvoir to enhance the recovery of oil.

Equipment leak means those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening.

Equipment leak detection means the process of id entifying emissions from equipment, components, and other point sources.

External combustion means fired combustion in wh ich the flame and products of combustion are separated from contact with the process fluid to which the energy is delivered. Process fluids may be air, hot water, or hydrocarbons. External combustion equipment may include fired heaters, indus trial boilers, and commercial and domestic

combustion units.

Natural gas distribution facility means the collection of all distribution pipelines, metering stations, and regulating stations that are operated by a Local Distribution Company (LDC) that is regulated as a separate opera ting company by a public utility commission or that are operated as an independent municipally-owned distribution system.

Onshore petroleum and natural gas production facility means all petroleum or natural gas equipment on a well pad or a ssociated with a well pad and CO 2 EOR operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petroleum and natural ga s production owner or op erator and that are located in a single hydrocarbon basin as define d in §98.238. Where a person or entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility.

Farm Taps are pressure regulation st ations that deliver gas di rectly from transmission pipelines to generally rural customers. The ga s may or may not be metered, but always does not pass through a city gate station. In some cases a nearby LDC may handle the billing of the gas to the customer(s).

Background Technical Support Document – Petroleum and Natural Gas Industry 136Field means oil and gas fields identified in the United States as defined by the Energy

Information Administration Oil and Gas Fi eld Code Master Li st 2008, DOE/EIA 0370(08) (incorporated by refe rence, see §98.7).

Flare stack emissions means CO 2 and N 2 O from partial combustion of hydrocarbon gas sent to a flare plus CH 4 emissions resulting from the incomplete combustion of hydrocarbon gas in flares.

Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole basis, that is combus ted at the flare burner tip.

Gas conditions mean the actual temperature, volume, and pressure of a gas sample.

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.

Gas well means a well completed for production of natural gas from one or more gas

zones or reservoirs. Such wells contain no co mpletions for the production of crude oil.

High-bleed pneumatic devices are automated, continuous bleed flow control devices powered by pressurized natural gas and used for maintaining a pro cess condition such as liquid level, pressure, delta-pre ssure and temperature. Part of the gas power stream that is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate in excess of 6 standard cubic feet per hour.

Intermittent bleed pneumatic devices mean automated flow control devices powered by pressurized natural gas and used for maintain ing a process condition such as liquid level, pressure, delta-pressure and temperature. Th ese are snap-acting or throttling devices that discharge the full volume of the actuator interm ittently when control action is necessary, but does not bleed continuously.

Internal combustion means the combustion of a fuel that occurs with an oxidizer (usually air) in a combustion chamber. In an in ternal combustion engine the expansion of the high-temperature and –pressure gases produced by combustion applies direct force to a component of the engine, such as pistons, turb ine blades, or a nozzle. This force moves the component over a distance, generating useful mechanical energy. Internal combustion equipment may include gasoline and diesel indust rial engines, natural gas-fired reciprocating engines, and gas turbines.

Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric pressure.

Background Technical Support Document – Petroleum and Natural Gas Industry 137LNG boil-off gas means natural gas in the gase ous phase that vents from LNG storage tanks due to ambient heat leakage through the tank insulation and 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 that is regulated by the process condition flows to a valve actuator c ontroller where it vent s continuously (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 seaward of the terrestrial bor ders of the United States, including waters subject to the ebb and flow of the ti de, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and

control of the United States under the Outer Continental Shelf Lands Act.

Oil well means a well completed for the producti on of crude oil from at least one oil

zone or reservoir.

Onshore petroleum and natural gas production owner or operator means the person or entity who holds the permit to operate petroleu m and natural gas wells on the drilling permit or an operating permit where no drilling permit is issued
, which operates an onshore petroleum and/or natural gas production faci lity (as described in §98.230(a)(2). Where petroleum and natural gas wells operate without a drilling or operating permit, the person or entity that pays the State or Federal busine ss income taxes is considered the owner or
operator.

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 from 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 or CO 2 by positive displacement, employ ing linear movement of a shaft driving a piston in a cylinder.

Background Technical Support Document – Petroleum and Natural Gas Industry 138Reciprocating comp ressor rod packing means a series of flexible rings in machined metal cups that fit around the re ciprocating compressor piston r od to create a seal limiting the amount of compressed natural gas or CO 2 that 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 hydrocar bon liquids and/or gases.

Residue Gas and Residue Gas Compression mean, respectively, production lease natural gas from which gas liquid products and, in some cases, non-hydrocarbon components have been extracted such that it meets the sp ecifications set by a pipeline transmission company, and/or a distribution company; and the compressors operated by the processing facility, whether inside the pro cessing facility boundary fence or outside the fence-line, that deliver the residue gas from the processi ng facility to a transmission pipeline.

Sales oil means produced crude oil or condens ate measured at the production lease automatic custody transfer (LACT) meter or custody transfer tank gauge.

Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase.

Sour natural gas means natural gas that contains significant concentrations of hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) that exceed the concentrations 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) and/or carbon dioxide (CO 2 ) that does not require (or has alrea dy had) acid gas treatment to meet pipeline corrosion-prevention specifica tions for transmission and distribution.

Transmission pipeline means high pressure cross c ountry pipeline transporting saleable quality natural gas from production or natural gas processing to natural gas distribution pressure let-down, me tering, regulating stations where 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.

United States means the 50 States, the District of Columbia, the Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam, and any other Commonwealth, territory or possession of the United States, as well as the territori al sea as defined by

Presidential Proc lamation No. 5928.

Background Technical Support Document – Petroleum and Natural Gas Industry 139Vapor recovery system means any equipment located at the source of potential gas emissions to the atmosphere or to a flare, th at is composed of pipi ng, 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 combustion flue gas), including process designed flow to the atmosphere thr ough seals or vent pipes, equipment blowdown for maintenance, and direct ve nting of gas used to power equipment (such as pneumatic devices).

Well completions means the process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling an d reservoir fluids and te st the reservoir flow characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. Well completion also involves connecting the well bore to the reservoi r, which may include treating the formation or installing tubing, packer(s ), or lifting equipmen t, steps that do not significantly vent natural gas to the atmosphere. This proce ss may also include high-rate flowback of injected gas, wate r, oil, and proppant used to fr acture or re-fracture and prop open new fractures in existing lower permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere.

Well workover means the process(es) of performing one or more of a variety of remedial operations on producing petroleum an d natural gas wells to try to increase production. This process also in cludes high-rate flowback of in jected gas, water, oil, and proppant used to re-fracture and prop-open new fractures in existing low permeability gas reservoirs, steps that may vent large quan tities of produced gas to the atmosphere.

Wellhead means the piping, casing, tubing and c onnected valves protruding above the

earth’s surface for an oil and/ or natural gas well. The wellh ead ends where the flow line connects to a wellhead valve. Wellhead equipm ent includes all equipment, permanent and portable, located on the improved land area (i.e. well pad) surrounding one or multiple

wellheads.

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 gas dehydrator is refe rred to as “wet gas.”

Background Technical Support Document – Petroleum and Natural Gas Industry 140

### Appendix I: References

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Background Technical Support Document – Petroleum and Natural Gas Industry 142IPIECA (2003) Petroleum Industry Guidelines fo r Reporting Greenhouse Gas Emissions

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.

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Background Technical Support Document – Petroleum and Natural Gas Industry 143U.S. EPA (2007) Natural Gas STAR Emissions Reducti on Quantification Reference Guide

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Background Technical Support Document – Petroleum and Natural Gas Industry 144