UnitedStates Environmental Protection Agency 

# Research and Development

METHANE EMISSIONS FROM THE NATURAL GAS INDUSTRY Volume 6: Vented and Combustion Source Summary


# Prepared for

Energy Information Administration (U.S. DOE)


# Prepared by National Risk Management Research Laboratory ResearchTriangle Park, NC27711 GRI-9410257.23 EPA

-600/R-96-0801 June 1996FOREWORD The U.S. Environmental Protection Agency is charged by Congress with protecting the Nation's land. air. and water resources. Under a mandate of national environmental laws, the Agency strives to formulate and implement actions leading to a compatible balance between human
**activiti~s** and the ability of natural 

### systems to support and nurture life. To meet this mandate, EPA 1

### s research program is providing data and technical support for solving environmental problems today andbuilding

**~** 

### science knowledge base necessary to manage our ecological resources wisely. understand how pollutants affect ourhealth. and prevent or reduce environmental risks in 

### the future. The National Risk Management Research Laboratory is the Agency's center for 

### investigation of technological andmanagement approaches for reducing risks from threats to human

### health and 

### the environment. Thefocus of 

### the Laboratory's research program is on methods for the prevention and controlof pollution to 

### air. land, water. and subsurface resources; protection ofwater qualityin public water systems; remediation of 

### contaminated sites and groundwater; and prevention and 

### control of indoor air pollution. The goal of this 

### research effort is to 

### catalyze development and 

### implementation ofinnovative, cost-effective environmental technologies; develop scientific 

### and engineering information needed by 

### EPA to support regulatory and 

### policydecisions; and provide technical.support and infor

### mation transfer to ensure effective implementation of environmentalregulations and 

### strategies. This 

### publication has been produced as part of the Laboratory's strategic longterm research plan. It

### is published and 

### made available by EPA's 

### Office of Research and Development to assist the user community and 

### to link 

### researchers with their clients.
E. 

### TimothyOppelt. Director National Risk 

### Management Research Laboratory


### EPAREVIEWNOTICE This report has been peerandadministrativefyreviewed bythe U.S. Environmental Protection Agency, and approved for publication. Mention of trade names or commercial productsdoes notconstitute endorsementorrecommendationforuse. This document is availabletothe publicthrough the National Technical lnfonnation Service, Springfield, Virginia22161.METHANE EMISSIONS FROM TIIE NATURAL GAS INDUSTRY, 

# &f\;-

**7'/jo;~_S7.23** EPA-600/R-96-080f June 1996

VOLUME 6: VENTED AND COMBUSTION SOURCE SUMMARY 

### FINAL REPORT

Prepared by: Theresa M. Shires Matthew 

### R. Harrison Radian International LLC

8501 N. 

### Mopac Blvd. P.O. Box 201088 Austin, TX 

### 78720-1088

DCN: 95-263-081-01
For GRI ProjectManager: Robert A. 

### Lott GAS RESEARCH INSTITUTE

Contract No. 5091-251-2171 8600 West Bryn Mawr Ave. Chicago, IL 60631 and EPA Project Manager: David A. Kirchgessner 

### U.S. ENVIRONMENTAL PROTECTION AGENCY Contract No. 68-DI-0031 National Risk Management Research Laboratory Research Triangle Park, NC 27711

### DISCLAIMER LEGAL NOTICE: This report 

### was prepared by Radian International LLC as an account ofwork sponsored by Gas Research Institute (GRI) and the U.S. Envirotunental Protection Agency (EPA). Neither EPA, GRI, members ofGRI, nor any person acting on behalfof either:



### a. Makes any warranty orrepresentation, express orimplied, with 

### respect to the accuracy, completeness, or usefulness ofthe information contained in this report, or that the use ofany apparatus, method, orprocess disclosed in this report may not infringe privately owned rights; or b. Assumes anyliability with respect to the use of, orfor damages resulting from the use of, any information, apparatus, method, orprocess disclosed 

### in this report. NOTE: EPA's Office ofResearch and Development quality assurance/quality control 

### (QNQC) requirements are applicable to some ofthe count data generated by this project. Emission data and additional count data are from industry or literature sources, and are not subject to 

### EPNORD's QNQC policies. In all cases, data and results were reviewed by the panel ofexperts listed in Appendix D ofVolume 2.

uTitle

Contractor

Principal Investigators 

### Report Period Objective

Technical Perspective

Results 

### RESEARCH SUMMARY
Methane Emissions From Vented and Combusted 

### Sources Final Report Radian International LLC GRI Contract Number 5091-251-2171 EPA Contract Number 68-D1-0031 Theresa M. Shires Matthew 

### R. Harrison March 1991 -June 1996 Final Report This report summarizes methane emissions from vented and combusted sources. Significant sources ofvented and combusted emissions are discussed, as well as miscellaneous minor sources ofemissions. In addition, docmnentation for the methane compositions used for each industry segment is provided. This report also discusses inconsistencies inreported vented and flared emissions reported 

### by other sources. The increased use ofnatural gas 

### has been suggested as a strategy for reducing the potential for global warming. During combustion, natural gas generates less carbon dioxide (CO;) per unit ofenergy produced 

### than 

### either coal or oil. On the basis ofthe amount ofC02 

### emitted, the potential for global warming could 

### be reduced by substituting natural gas for coal or oil. However, since natural gas is primarily methane, a potent greenhouse gas, losses ofnatural gas during production, processing, transmission, and distribution could reduce the inherent advantage of

### its lower C02 emissions. To investigate this, Gas Research Institute (GRI) and the U.S. Envirorunental Protection Agency'sOffice ofResearch and Development (EP A/ORD) cofunded a major study to quantify methane entissions from U.S. natural gas operatior.s for the 1992 base year. The results ofthis study can be used to construct global methane budgets and to determine the relative impact on global warming ofnatural gas versus coal and oil. Vented emissions account for approximately 94 Bscfofmethane 

### emissions annually. Compressor exhaust is the primary 

### source of
iiiTechnical Approach

Project Implications combustion emissions, contributing approximately 25 Bscfofmethane emissions annually. Based on data from the entire program, methane emissions :from natural gas operations are estimated to be 314 

### ± I05 Bscffor the 1992 base year. This is about 1.4 

### ±0.5% ofgross natural gas production. The overall program also showed that the percentage ofmethan' entitted for an incremental increase 

### in natural gas sales 

### would be significantly lower than the baseline case. Theproject reached its accuracy goal and provides an accurate estimate ofmethane emissions that can be used to conduct methane inventories and analyze fuel switching strategies. Vented emissions primarily result from three categories: I)pneumatic devices, 2) blow and purge entissions, and 3) dehydrator entissions. Combusted emissions result from the incomplete combustion of methane in burners, flares, and engines. Vented and combusted emissions are 

### typically considered unsteady emission sources, that is. sources with 

### highly variable emissions. These emission sources vary from company to company and site to site. because ofdifferent maintenance practices 

### and operating conditions. Therefore, itis impractical to measure every source continuously for a year. Each unsteady emission soUrce requires a unique set ofequations and gathered data based onthe equipment type, various components, and operating modes to produce an emissions factor. Data on unsteady emissions were gathered at multiple sites in each segment ofthe industry: production, gasprocessing, transmission, storage. and distribution. Thisreport swnmarizes methane emissions from significant, as well as minor miscellaneous sources ofvented and combusted emissions. In addition, this report serves to document the data sources used to determine methane compositions for the various industry segments. Finally, a discussion ofinconsistencies in reported vented and flared emissions isprovided to support the decision for using a bottom-up approach in this project to more accurately account for emissions from these sources. Forthe 1992 base year the annnal methane entissions estimate for the U.S. natural gas industry is 3!4 Bscf

### ± 105 Bscf

### (±33%). This is equivalent to 1.4% 

### ± 0.5% ofgross natural gas production. Results from this program were used to compare greenhouse gas emissions from the fuel cycle for natural gas, oil, and cnal using the global warming

IV

### potentials (GWPs) recendy published by the Intergovernmental Panel on Climate Change (IPCC). The analysis showed that natuta! gas contributes less to potential global wanning than coal or oil, which supports the fuel switchbg strategy suggested by IPCC aud others. In addition, results from this study are being used by the natural gas industry to 

### reduce operating costs while reducing emissions. Some companies are also participating in the Natural Gas-Star program, a 

### voluntary program sponsored by EPA's Office of

### Air and Radiation m cooperation with 

### the American Gas Association to implement costeffective emission reductions and to report reductions to the EPA. Since this program was begun after the 1992 baseline year, any reductions 

### in methane emissions from this program are not reflected in this study's total emissions.



### Robert A. 

### Lott Senior Project Manager, Environment and Safety



### vTABLE OF CONTENTS Page 1.0 SUMMARY ................................................. I 

### 2.0 INTRODUCTION ............................................. 2 3.0 DATA COLLECTION .......................................... 4 4.0 RESULTS .................................................. 8 4.1 Compressor Exhaust ...................................... 8 4.2 Pneumatic Devices

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I

### 0 

### 4.3 Chemical IJ1jection Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 4.4 Dehydrator Vents ....................................... 13 

### 4.5 Dehydrator Glycol Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 4.6 Blow and Purge ......................................... 15 5.0 MISCELLANEOUS MINOR CATEGORIES . . . . . . . . . . . . . . . . . . . . . . . . . I8 5.1 Burners .............................................. 18 5.2 Flares ................................................ 20 5.2.1 

### Combustion Efficiency ............................... 21 5.2.2 Total Natural Gas 

### Flow to Gas Industry Flares .............. 24 5.3 Acid Gas Recovery Vents .................................. 27 5.4 Salt Water Tanks ........................................ 28 5.5 

### Drilling . . . ................. '
. . . . . . . . . . . . . . . . . . . . . . . . . 29 

### 5.6 Drips ................................................ 30 5.7 Sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 6.0 REFERENCES

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 APPENDIX A Methane Composition ........................... A-1 APPENDIX B Reported "Vented and Flared" Data
. . . . . . . . . . . . . . . . . . B-1

Vl

### LIST OF TABLES Page 3-1 Emission Sources ........... , .................................. 6 3-2 Emission Source Groups by Type .................................. 7 

### 4-1 Swnmary ofUnsteady Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 4-2 Blow and Purge Emission Results
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 5-l Burner Fuel Gas Activity Factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 5-2 Summary ofPrevious Flare Combustion Efficiency Studies
. . . . . . . . . . . . . . . 22 5-3 Non-Combusted Emissions from Production and Gas Processing 

### (GRI!EPA Estimate Basis) ...................................... 25 5-4 Maximum Flaring Emissions ..................................... 27 5-5 Salt Water Tank Emissions ...................................... 29 A-1 Methane Composition by Industry Segment . . . . . . . . . . . . . . . . . . . . . . . . . A-2 A-2 Average State Methane Content and Production Rate . . . . . . . . . . . . . . . . . . . A-4 

### A-3 Methane Composition ofProduction Gas A-5 A-4 

### Methane Composition 

### in Gas Processing A-5 B-1 Comparison of45-I Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-9 B-2 1991 Flaring Pennits for Oklahoma .............................. B-10 B-3 Supply and Disposition ofGas in the United State&-1989 .............. B-13

vii1.0 SUMMARY
This report is one ofseveral volumes that provides backgrotmd information 

### supporting the Gas Research Institute and U.S. Environmental Protection Agency, Office of Research and Development (GRl-EPAJORD) 

### methane emissions project. The objective of this comprehensive program is to quantify the methane emissions from the gas industry for 

### the 1992 base year to within 

### ±0.5% ofnatural gas production starting at the wellhead and ending immediately downstream ofthe customer's meter. 

### This report swnrnarizes methane emissions from vented and combustion sources. Vented emissions primarily result from three categories: I) pneumatic devices, 2) blow and purge emissions, and 3) dehydrator emissions, which combined account for 

### approximately 94 

### Bscfofmethane emissions armually. Combustion emissions result from the incomplete combustion ofmethane 

### in burners, flares, and engines. Compressor engine exhaust is the only significant source ofmethane in this category, accounting for 

### approximately 25 Bscfofmethane emissions annually.

I

### 2.0 INTRODUCTION
For this project, sources ofmethane emissions from the natural gas industry were classified as follows:

• Vented

- Vented emissions are intentional releases from equipment blowdown for maintenance, releases from emergency depressuring (from safety valves and station emergency blowdown), direct venting ofgas used to power equipment (such as pneumatic devices), or accidental releases due to mishaps (such as pipeline dig-ins). • Combustion

- Combustion emissions refer to methane that enters the atmosphere due to the incomplete combustion ofnatural gas. Examples are methane 

### in compressor engine exhaust and methane from flare stacks and burners.
• Fugitive · Fugitive emissions are unintentional leaks from sealed surfaces (such as valve stem packing, flange gaskets, compressor shaft seals, and pipelines). 

### This report summarizes emissions from vented and combustion sources. Vented and combustion emissions are typically considered "unsteady." Unsteady

**emitte~s** are defined as sources 

### with highly variable emissions, such as a pneumatic device on an isolation valve or a maintenance activity that requires blowdown. These·emission sources vary from company to company and site to site, because 

## Ofdifferent maintenance practices and operating conditions.
In contrast, emission sources 

### with continuous bleed rates, or with reasonably steady bleed rates over a typical measurement time, are considered "steady" sources. Fugitive emissions are generally considered steady. Extensive measurements offugitive emissions have been made in this and other studies in ali segments ofthe gas industry. 1• 2 • 3 Section 3 ofthis report discusses data collection techniques used to estimate unsteady emissions. Results from vented and combustion sources considered significant are presented in Section 4. Details on emission estimates for compressors, pneumatic devices, 2

### dehydrators, chemical injection pumps, mishaps, etc. are available 

### in other volumes. 4• 5•6• 7•8• 9 

### Section 5 discusses miscellaneous minor emission sources. Documentation supporting the methane compositions used for each industry segment is provided 

### in Appendix A. This report also discussed inconsistency in vented and 

### flared emissions 

### in Appendix B.

3

### 3.0 DATA COLLECTION This GRI!EPA studycalculated emission factors for unsteady emission sources, rather than measuring them. Each unsteady source requires a unique set of equations and gathered data based on the equipment type, various components, and operating modes to produce the emission factor quantity. However, all sources require the following general infonnation: I) A detailed technical description oftbe source, identifying the 

### important emission-affecting parameters (i.e., equipment components and operating modes). This was generally accomplished through a source characterization report. 2) Data to estimate the volume ofnatural gas released and the frequency ofreleases from multiple site visits or existing reports. 3) Data on gas composition (percent methane) in various industry segments (production, gas processing, transmission, and distribution). Details on the methane composition results are provided 

### in Appendix 

### A. Step 1 was accomplished byresearching each particular source and gathering 

### manufacturer, operator, and site data 

### so 

### that a full technical description ofthe important emission characteristics ofthe source category could be written. Using this description, data on the emission-affecting characteristics ofeach source were gathered through site visits orexisting resources. Formany emission sources, the frequency ofrelease events was measured (such as strokes/minute for pneumatic actuators); but for extremely infrequent releases (such as equipment maintenance blowdowns), the frequency was estimated by gas industry field personnel. The emission volume perevent 

### was not measured for most sources (as in the case ofcompressor exhaust methane) but 

### was often calculated using gathered site data, existing reports, and first principles.

4During this study, data on unsteady emissions were gathered at multiple sites in each segment ofthe industry: production, gas processing, transmission, storage, and distribution. Details on the industry segments and boundaries are provided in Volume 5 on the activity factors. 10 The site visits and literature searches allowed construction ofa matrix that shows all the emission sources within the gas industry grouped by process segment and operation mode. Table 3-1 shows this grouping. The industry characterization also allowed a grouping ofsolU'Ces by emiss'ion type, as shown 

### in Table 3-2.

5

### TABLE 3-1. EMISSION SOURCES
.·. Emtnion

**So~rces** IndustrySegment-- Operating Mode (Equipment or Activities) Production StanUp Drilling (mud emissions) Well completion testing No:mal Operations Fugitives Pneumatic devices

-control valves Chemical injection pumps Glycol dehydrators Compressor exhaust Compressor starts Maintenance Well bore maintenance Blow and purge Upsets/Mishaps Emergency blowdowns Dig-ins Gas Processing Plants Stan Up Not applicable ornegligible activity Normal.Operations Fugitives Pneumatic devices

- isolation valves Glycol dehydrators Acid Gas Recovery vents Engine exhaust Compressor starts Maintenance Blow and purge Upsets/Mishaps Emergency blowdowns NO MISHAPS Transmission and Storage Start Up Not applicable ornegligible activity Nonnal Operations Fugitives Pneumatic devices

• control valves

- isolation valves Glycol dehydrators


### . Engine exhaust Compressor starts Maintenance Blow and purge Upsets/Mishaps Emergency blowdown Dig-ins Distribution Start Up Normal Operations Fugitives Pneumatic devices

- control valves

- isolation valves Glycol dehydrators Engine exhaust Compressor starts Maintenance Blow and purge UpsetsMishaps Emergency blowdown Dig-ins


### 6

### Source Combustion Sources TABLE 3-2. EMISSIONSOURCE GROUPS BY TYPE Type 

### Emission Sources Unsteady Engine exhaust (compressors and other gas-drivenengines) Flares Burners 

### Vented Sources Unsteady Pneumatic devices Chemical injection pumps Glycol circulationpumps Glycol dehydrator vent

Fugitive 

### Sources Steady Acid Gas recovery (AGR) vent Blow and purge Mishaps (for start up, maintenance, and 

### upsets/emergency conditions) Leaks from sealed surfaces (flange gaskets, valve stempacking, valve seats 

### open to the atmosphere, pressure reliefvalve seats, compressor seals. etc.) Leaks from small holes inpipelines



### 74.0 

### RESULTS
This section reviews the characterization results on the majorunsteady categories. (Major categories were defmed as any source over I Bscf.) Minor categories are discussed in Section 

### 5. Table4-1 summarizes the results determined foreach category of unsteady emissions ineach industry segment. Details on the techniques used and the data gathered for each ofthe unsteady emission categories are provided inother documents ofthis multi-volume setonmethane emissions.4•6•8• 9•11•12 

### 4.1 CompressorExhaust Methane emitted to the atmosphere 

### incompressorengineexhaust is 

### a significant source ofunsteady emissions and accounts for approximately 25 Bscfofmethane emissions.4 Methane emissions result from the incomplete combustionofthe natural gas fuel, which allows some ofthe methane inthe fuel to exit inthe exhaust stream. There are two primary types ofcompressordrivers: I)reciprocating gas engines, and 2) gas turbines. A few compressors in the industry are driven by other means such as electrical motors, but the majority are natural gas-fueled drivers. Inadditionto compressors, there are some natural gas drivers that operate siteelectrical generators for gas plants and compressor stations. Reciprocating engines emitmore methane per horsepower orperunit offuel consumed than turbine drivers: 0.24 scf/HP•hrforreciprocating versus 0.0057 scf/HP•hrfor turbines. Reciprocating engines account for overtwo-thirds ofaU installed horsepower inthe gas industry (100,500MMhp•brcompared to 44,300MMhp•hr for gas turbines). Therefore, reciprocating engines account for 98% ofthe methane emissions for this category. Emissions were determined by analyzing and combining several databases. A GRI database, the GRI TRANSDAT compressor module, 13 contains data from AmericanGas Association (A.G.A.}on types and models ofcompressors in use, as well as data on
8TABLE 4-1. SUMMARYOFUNSTEADY EMISSIONS 

### Source Compressor Exhaust Production Gas Processing Transmission Pneumatic Devices 

### Production Gas Processing 

### Transmission Chemical Injection Pumps Dehydrator Vents 

### Production Gas Processing 

### Transmission Storage Dehydrator Glycol Pumps 

### Production Gas Processing Transmission Storage 

### Acid Gas Recovery Vents Blow and Purge 

### Production Gas Processing 

### Transmission Distribution TOTAL 

### AnnualMethane 

### Emissions, Bscf 6.6 6.9 

### 11.4 31.4

0.1 

### 14.1

1.5 

### 3.4 

### 1.05 0.10 0.23 

### 11.0

0.17
0.82 6.6 3.0 18.5

2.2 119

9 

### .. 90% Confidence Interval ±200% 

### ± 130%



### ± 15%

± 65% 

### ± 64% 

### ± 60% ± 203%

± 193% ± 208% ± 392% ± 166% ±110% ± 228%

± 109%
± 329% ± 262% ± 177% ± 1,783% ±54%

### compressor driverexhaust from the Southwest Research Institute (SwRI). A.G.A. gathers its data from government agencies, such as DOE and FERC, and from surveys ofits member 

### companies in 

### transmission and distribution. SwRI data were generated through actual field testing. The data were combined to generate emission factors for this project by correlating compressor driver type, 

### methane emissions, fuel use rate, and annual operating hours for 775 reciprocating engines and 86 gas turbines. 

### Horsepower•houractivityfactors were developed for each industry segment using TRANSDAT, FERC, A.G.A., company databases, and site-visit data. TRANSDAT includes horsepowerdata for 7,489reciprocating engines and 793 gas turbines in 

### transmission. Transmission operating hours were based on FERC 

### data for 1992 and 

### one company's data for 524 reciprocating engines and 89 gas turbines. Storagehorsepower was based onA.G.A. data and operating hours are based on data from II storage stations. Since 

### national totals. for transmission and storage horsepower are available, no industry 

### extrapolation was necessary for theseactivity factors. Productionhorsepower•hours were based on one company's data for 516reciprocating engines. Horsepower and 

### operating 

### hours for the gas processing segmentwere based on 10 site visits and company data 

### for 18 gas processing plants. **Horsepowe~hours** 

### for production and processing were extrapolated to a total for the industry byusing published data for nationally marketed gas produced and gas 

### processed, respectively. 

### 4.2 Pneumatic Devices Pneumatic devices in 

### the 

### natural gas industry are 

### valve actuators and controllers that use natural gas pressure as the force for valve movement. Gas from the valve actuator is vented during every valve stroke, and gas may bleed continuously from the valve controller pilot

### as well. Pneumatic devices 

### are asignificant source ofunsteady emissions and account for 45.6

### Bscfof

### methane emissions annually.6 

### Methane emissions from pneumatic devices were calculated based 

### on field measurements, site data, 

### and manufacturers' data.

10There are two primary types ofthese devices: 1) control valves that regulate flow, and 2) isolation valves that block or isolate equipment and pipelines. Ofthe two main types, isolationvalves typically have lower annual emissions, although the emission rate per actuationcan be large. This is because isolation valves are moved infrequently, for emergency ormaintenance activities that require isolating a piece ofequipment or section of pipeline. Alternatively, control valves typically move frequently to make adjusttnents for changes inprocess conditions, and some types ofcontrol valves bleed gas continuously. Each segment ofthe industry has very differentpractices regarding the pneumatic devices, as described below: 

### Production
Theproduction segment accounts for the majority ofpneumatic emissions: 31.4Bscf, or 69% ofall pneumaticemissions. Compressed air is rarely used as a pneumatic operating medium inthe production segment, since compressed 

### airrequires electricity at the oftenremote well sites, and since gas is readily available and less expensive. A typical productionpneumatic device releases 126 Mscfmethane annually and there are an estimated 249,000pneumatic devices associated with natural gas production. Gas Processing Pneumaticemissions from the gas processing segment are very small: 0.12 Bscfannually, or approximately I% ofall pneumatic emissions. Only one-half(56%) ofthe gasprocessing plants participating inthis projectuse natural gas to operate pneumatic controllers and isolation valves; other sites use compressed air orelectric motors. The natural gas-powered isolation valves 

### in this industry segment are operated infrequently (once/month or once/year), so the annual emissionsper site are relatively small (approximately 165 Mscfofmethane pergasprocessing plant).

IITransmission/Storage Pneumatic emissions from the t:ra.nsmission compression stations and storage stations account for 

### 14.1 Bscfannually, or 31% ofpneumatic emissions. In this industry segment, most ofthe pneumatics are gas-actuated isolation valves. There are a few pneumatic control valves used to reduce pressure orto control liquid flow from a separator orscrubber. The annual methane emissions from a transmission pneumatic device are 162 Mscf, and there are approximately 87,000 ofthese devices nationally. Distribution Pneumatic emissions for the distribution segment are included 

### in the meterand regulation station "fugitive" emission factor.2 

### 4.3 Chemical InjectionPwnps Chemical injectionpumps are a source ofunsteady emissions and account for 1.5 Bscfofannual methane emissions.8 Gas-drivenchemical injectionpumps use gas pressure to move a piston which pumps the chemical onthe opposite end ofthe piston shaft; the powergas is then vented to the atmosphere at the end ofthe stroke. The power

**ga~** may be natural gas orcompressed air. Twotypes ofchemical injectionpumps were observed: 1) pistonpumps, and 2) diaphragm pumps. The largerdiaphragm pumps

### emit more gas per stroke, and they are used 

### to pump a higher flow rate ofchemical or

### to pump the chemical into highpressure equipment. Chemical injectionpumps are used to add chemicals suchas corrosion inhibitor, scale inhibitor, biocide, demulsifier, clarifier, and hydrate inhibitor

### to operating equipment. These additives protect the equipmentorhelp maintainthe flow ofgas. The vast majority ofthese pumps exist inthe production segment. located at the well sites, so that the chemical can protect all ofthedownstream and downhole equipment. As with
12

### pneumatic control valves, the chemical injection pumps in production are primarily powered by natural gas. 

### In the production segment, significantregional differences exist. Depending on the gas composition and conditions, some regions use very few pumps, while other regions use the pumps frequently. Many pumps also have seasonal operation since they protect against hydrate formation, which winter temperatures exacerbate. Approximately 17,000chemical injection pumps are associated with natural gas production. A typical methane emission rate is 248 scfd per pump, based on site and manufacturer data. 

### Only a few pumps exist inthe gas processing and transmission segments. The 

### pumps that do exist are powered by compressed air at these stations, and as aresult, have no methane emissions.
4.4 DehydratorVents 

### Glycol dehydrator vents are a significant source ofmethane emissions and account for 4.8Bscfofmethane emissions annually." The majority ofthe glycol 

### dehydrators are located in 

### production, but dehydrators are also present in the gas processing, transmission, and storage segments ofthe natural gas industry. Methane emissions are higher inthe production segment (71% ofthe total emissions are attributed to glycol dehydrator vents) due to the high activity factor for this 

### segment and the lack offlash tanks 

### in 

### mostproduction dehydrators. Glycol dehydrators remove water from the natural gas through continuous glycol absorption. The water-rich glycol is 

### then regenerated, orheated, which drives the water backout ofthe glycol. The glycol also absorbs some othercompounds from the gas, 

### including asmall amount ofmethane. The methane is driven offwith the water in the regenerator and vented to the atmosphere.



### 13The importantemission-affecting variables for dehydrators are: gas throughput, use ofa flash tank, ·use ofstripping gas, and use ofvent controls routed to a 

### burner. An 

### emission factor was established for glycol dehydrator regenerator vents using three sources ofdata: 1) 

### computersimulations ofdehydratoroperationsusing first principles; 2) data from actUal on-line analyzer samples taken from regenerator vents; and 3) multiple site visits. The resulting annual methane emission factors are: 276 scf/ill1scf drroughput forproduction, 122 scf/MMscfforgasprocessing, 94 scf/MMscffor transmission, and 117 scf/MMscffor storage. Foreach industry segment, the emission 

### factor was combined 

### with an activity factor to generate the national emission rate, where the activity factors are based on the annual volume ofgas dehydrated (12.4 Tscfforproduction, 8.6Tscffor gas processing, 1.1 Tscffor transmission, and 2.0Tscffor gas storage). 

### 4-5 DehydratorGlycol Pumps Glycol dehydratorcirculationpumps are a signitlcant source ofunsteady 

### emissions and account for approximately 11 Bscfofannual methane emissions. 12 

### These pumps use the high pressure ofthe rich glycol from the absorbertopowerpistons that pump the low-pressure, lean glycol from the regenerator. Thepump configurationpulls additioual gas from the absorberalong with the rich glycol (moregas than would flow with the rich glycol ifconventional electrical pumps and level control were used). This gas is emitted along with other absorbed methane drrough the dehydrator vent stack. Gas-powered glycol circulationpumps are commonthroughout the industry, 

### even in 

### sites where electrical pumps are the standard for otherequipment. The dehydrator equipment is often specified as aseparate bidpackage, and the vendors most oftenuse the Kimray gas pump as their standard pumping unit. 

### The pumps are an integral part ofthe 

### glycol dehydrator unit and 

### their emissions occurthrough the same point. However. the pumps are the cause for most ofthe methane emissions from dehydrators, so they are considered separately.

14Unlike chemical injectionpumps which vent the driving gas directly to the atmosphere, dehydrator pumpspass the driving gas along with the wet glycol to the reboiler. Therefore, methane emissions from the pump depend on the design ofthe dehydrator, since gas recovery onthe dehydrator will also recover gas from the pump. The demographics generated for the glycol dehydrator control system (flash drum recovery and vent vapor recovery) were also used to determine the net emission rate for glycol pumps. Based ona gas throughput basis, emissionfactors for glycol pumps were estimated to be 

### 992 scfmethane/MMscffor production and 

### 178 scf/MMscffor gas 

### processing. The corresponding annual activity factors are 1.1 Tscfand 0.96 Tscf, respectively. 

### 4.6 Blow and Purge
Blow 

### and purge is a large source ofunsteady emissions and accounts for approximately 30 Bscfofmethane emissions annually.9 Blow (or blowdown) gas refers to gas that is vented due to maintenance, routine operations, oremergency conditions. A piece 

### ofprocess.equipmentor an entire site is 

### isolated from other gas-containing equipment and depressured to the atmosphere. Thegas is discharged tothe atmosphere for one ofthe following reasons: 1) Maintenance Blowdown

- the· gas is vented from equipment to eliminate the flammable material inside the equipment, thus providing a safer working environment for workers that service the equipment or enter the equipment. 2) Emergency Slowdown

- the gas is vented from a site to eliminate a potential fuel source. For example, ifanequipment flre begins at a compressor station, the station emergency shutdown and emergency blowdown system blocks the station away from the pipelines and discharges the gas inside the station, thus reducing the fuel that could feed the fire.

15The factors that affect the volume ofmethane blowdownreleased to the aonosphere are: frequency, volume ofgas blowdownper event, and the disposition ofthe blowdowngas. Biowdown from maintenance releases was detennined for eachequipment category: compressorblowdown, compressor starts, pipeline blowdown, vessel blowdown, gas wellbore blowdown, and miscellaneousequipmentblowdown. Emergency blowdown refers to the unexpected release ofgas by a safety device, such as a pressure-reliefvalve (PRV) ona vessel or the automatic shutdown/emergency blowdownofa transmission compressor station. Dig-ins, which are pipeline ruptures caused by unintentionaldamage, were also classified as an emergency release ofgas. Table 4-2 summarized the emission factors and activity factors for the various blow and purge sources. Emissionestimates for eachindustry segment were based ondata from one or more ofthe following sources: I) site-visit data; 2)company-tracked data; 3) company studies; and 4)equipmentcharacteristics. Data quality inthe transmission segment was considered superior since it was based uponrigorous company-tracked data. Gas-processing data were extrapolated from transmission data based upon the similarities betweengas plant compression and transmissioncompressor stations. Distribution segmentdata were considered good since they were based uponcompany studies. Productiondata were considered poor (and may 

### be underestimated) since they are based upon operator recollections ofblowdown frequency gathered during site visits.

16TABLE 4-2. BLOWAND PURGE EMISSION RESULTS National Annual



### ..Methane Emission Industry Segment AnnualEmission Factor Activity Factor Rate, Bscf Production:

Gas Wells Unloading 49,570 

### ± 344% scf/well 114,139 

### ± 45% wells 5.66 

### ± 380% 

### Compressor Slowdowns 3,774 

### ± 147% scf/comp. 17,112 

### ± 52% compressors 0.065 

### ± 173% 

### Compressor Starts 8,443 

### ± 157% scf/comp. 17,112 

### ± 52% compressors 0.144 

### ± 184% 

### Pipeline Miles 309 

### ± 32% scf/mile 340,000 

### ± 10% miles 0.105 

### ± 34% 

### Production Vessels 78 

### ± 266% scf/vessel 255,996 

### ± 26% vessels 0.020 

### ± 276% 

### Completion Flaring 733 

### ± 200% scf/completion 

### 844 

### ± 10% completions 0.0006 

### ± 201% 

### Well Workovers 2,454 

### ± 459% scf/workover 9,329 

### ± 258% workovers 0.023 

### ± 1,296% PRY Releases 34 

### ± 252% scfy/PRY 529,440 

### ± 53% PRYs 0.018 

### ± 289% ESD Releases 256,888 

### ± 200% scf/platform 1,115 

### ± 10% platforms 0.286 

### ± 201% Dig-ins 669 

### ± 1,925% scf/mile 340,000 

### ± 10% miles 0.23 

### ± 1,934%


# - Gas Processing 4,060 

### ± 322% Mscf/plant 726 

### ± 2% plants 2.95 

### ± 262% 

### .._, Transmission and Storage: Stations 4,359 

### ± 322% Mscf/station 2,175 

### ± 8% stations 9.48 

### ± 263% 

### Pipeline Miles 31.6 

### ± 343% Mscf/mile 284,500 

### ± 5% miles 9.00 

### ± 236% 

### Distribution:

PRY Releases 0.050 

### ± 3,914% Mscf/main 836,760 

### ± 5% miles main 0.04 

### ± 3,919% Dig-ins 

### mile 1,297,569 

### ± 5% miles 2.06 

### ± 1,925% 

### Slowdowns 1.59 

### ± 1,922% Mscf/mile 1,297,569 

### ± 5% miles 0.13 

### ± 2,524% 0.102 

### ± 2.521 Mscf/mile

### 5.0 MISCELLANEOUSMINORCATEGORIES 

### There were many emissioncategories that

### contributed negligibleamounts of methane (less than I Bsc!). Although small, these categories are discussed in order to provide acomplete picture ofthe industry, butthese emission sources are not itemized in 

### the summary of

### annual emissions reponed by this study. Emissions from afew other minor 

### categories are quantified in

### Volume7on blow and purge activities.9 

### 5.1 Burners Burner combustion refers to the controlled burning ofnatural gas j.n 

### order to add heat to aprocess stream. Burners combine air and 

### gas 

### in acontrolled manner to maximize combustion efficiency. Inthe natural gas industry, burners are used in 

### all industry segments. Inthe production segment, a-high-pressure gas well requires achoke and an 

### inline heater to avoid freezing water in the line from the pressure drop flash. Glycol dehydrators, which are present inall 

### industry segments, require areboiler burner to beat and 

### regenerate the glycol. Above-ground liquefiednatuial gas (LNG) facilities may have boilers orhot oil furnaces for methane vaporization. Some gas plants may have additional burners in 

### boilers and other sources. Non-combusted methane may he 

### emittedby burners in two ways: I) since combustion is not 100% efficient, there is asmall amountofmethane that escapes from the burner uncombusted, and 2) ifthe burner has a flameout, all ofthe methane sent to the burner can be emitted uncombusted. This report 

### has assumed 

### that flameout emissions are negligible, based upon interviews 

### with gas industry personnel. Therefore only incomplete combustion emissions are calculated in 

### this section. The combustion efficiency ofnatural gas in burners was determined from Section !.4ofthe U.S. EPA's AP-42 document." The burners inthe natural gas industry fall under the industrial furnace category (between 10 and 100 MMBtu/hr offuel fired). AP

### 1842 shows that uncontrolled methane emissions from natural gas burners inindustrial boilers are three pounds ofmethane per million cubic feet offuel. The accuracy ofthese numbers is low, since AP-42 gives the data a rating of "C."
In general, annual averages ofcombustionemissions are generated by estimates ofthe total gas flow to the burners, combustion efficiency, and flameout frequency and duration. The activity factor for this category is the total amount ofburner fuel used in the industry. Nationally published numbers are available that show thetotal annual "lease and plant fuel use" and "pipeline fuel use," as shown 

### in Table 5-1. 15•16 However, compressor engine fuel must be subtracted from these totals to detennine burner fuel use. Since there are no nationally available numbers'forcompressorengine fuel, compressor fuel use was estimated.
TABLE 5-1. BURNERFUEL GAS ACTIVITY FACTOR National Fnel Use Ul' scf "Lease and Plant Fuel" (Gas

### Facts, Table 3-3)"

- ProductionCompressor Fuela

- Gas PlantCompressor Fuer

- Estimated Burner Fuel (Production) "Pipeline Fuel Use" 

### (Gas Facts, Table 3-4) "

- Transmission Compressor Fuela

- Storage Compressor Fuel"

- Estimated Burner Fuel (T &s) 1,070,452 -219,700 -469,500 381,252 630,083 -400,100

-53,210 176,773 'Estimatedbased on HP·hrfrom Volume 11 oncompressor driver exhaust, the AP-42 "C02

per HP•hr" emissionfactor, and the combustionequation.4•14

In addition, gas lift compressors also consume natural gas as fuel. Emissions from these compressors are considered to be attributed to the petroleum industry, based on the industry boundaries defmed by this project.10 Methane emissions from this source have not been quantified and subtracted from the natural gas industry emissions.

19

### The burner combustion efficiency was determined by using the AP-42 emission factors. The AP-42 emission factor (3 lb/10' ft') 

### canbe converted to a combustionefficiency 

### as follows: 3 lb CH 4 

### 10 6 

### cffuel X 

### lbmol CH 4 

### 16 lb CH 4 X 

### 379 scf = 

### 0.000071 lbmol 

### scfCH, scffuel Multiplying the emission factor by the activity factor yields the emission rate for burners: (I)



### scf CH (381,252 

### MMscf • 176,773 MMscf) x 

### 0.000071 4 = 

### 0.039 Bscf (2) 

### scffuel 

### This value is insignificant. and 

### therefore 

### is not listed as an emission source 

### in the total emissions estimate for this project. 

### 5.2 Flares 

### Flares are devices used to provide asafe and economical means ofgas disposal from routine operations, upsets, oremergencies via combustion ofthe gas. Flares prevent a controlled release ofmetbane from building up into a large cloud ofgas that could explode. There is 

### a wide variety offlares used inthe natural gas industry ranging from small open· 

### ended pipes at wellheads to large, horizontal, or vertical flares with pilots, such as those at gas plants. 

### Methane emissions from flares result from the incomplete combustion ofgas in the flare's flame or from time periods where there is 

### no flame at the flare tip (flame-out)due 

### to flare operational problems. Either ofthese cases results in 

### emissions ofnon-combusted methane to the annospbere. To determine the total emissions from flares in the 

### gas industry. two factors must be 

### known: 1) the average methane combustionefficiency offlares (including flame-out periods) and 2) the total annual amount ofnatural gas flowing to flares in the United States.



### 20

### 5.2.1 CombustionEfficiency
The combustion efficiency offlares is primarily dependent upon the flame stability which, in tum, depends on the gas velocity, heat content, and wind conditions. There are many problems in testing industrial flares for combustionefficiency; some ofthese include flare (and therefore flame) size, radiant heat, wind conditions, and proper probe placement withinthe flare flame. Therefore, most ofthe studies have beenconducted on 

### pilot flares, with 

### the results extrapolated to the larger industrial-size flares. Table 5-2 provides a summary offlare combustionefficiency studies compiled

### by Pohl and Soelberg. 17 

### Only two ofthese studies used natural gas as the flare gas. The study by Straitz has a wide-efficiency range, but instrumentproblems are also noted. The only other study to use natural gas (Howes) shows anexcellent combustionefficiency (>99%). However, the composition ofthe natural gas is unknown inHowes' combustion efficiency. Although methane is.a clean-burning gas, the composition ofthe natural gas in the production segment can vary substantially. As shown 

### in Table 5-2, gas streams with heavier hydrocarbons or with a substantial sulfur cOntent, such as sour gas, result in lower combustion efficiencies.
Table 5-2 shows two studies for open-ended pipes with combustion efficiency ranges of90 to 99.9% and 92 to 99.7%. The lower efficiencies for these studies are due 

### in part to the lack offeatures and controls, which are used to ensure flame stability in the larger, more efficient commercial flares. Another reason for the lower efficiency was that these two studies were conducted on heavier gas mixtures that did not include methane or natural gas. In the article by Straitz, "Flare Technology Safety,n the author claims that typical flare combustion efficiencies are 99+% for natural gas. 18 The author also points out that the combustion efficiency will be lower for gases with low-Btu heat content (due to nitrogen, water vapor, or H2S). Other sources give typical flare efficiencies as 98 to 99% as long as the flare is operated within the stability limits ofthe flame. 19• 20



### 21

### TABLE 5-2. SUMMARY OF PREVIOUS FLARE COMBUSTION EFFICIENCY STUDIES" ·Flare Gas E:dt GasHeating Measured

Size Velocity

.. Value· Combustion Study Year (in) Design (f/s) (Btu/It') GasFlared Eff. (%) 

### -.Comments Palmer 1972 0.5 Steam assisted 50-250 1448 Ethylene <97.8 Helium tracer for experimental full-size flare nozzle evaluation Merget 1977 47 Fullsize NA NA Carbon black 2500ol EPA ROSE remote vinyl monomer reduction sensing system in CO Straitz 1978 2-6 Steam and pilot

- 1000-2350 Natural gas, 75-99 Results oflimited propane validity due to instrument range sensitivity Siegel 1980 17 Conunercial flare 0.7-16 1500 Refinery gas• 97-99 Multipositionplume gas extractivesampling Lee& 1981 2 Holes in 2

**~** cap 1.8 2190-2385 Propane 96-100 Whipple (I.I in2open area) Howes, et al. 1981 (j> Conunercial air 40-60 2385 Propane 92-100 Bothextractive and assist. Zink EPA ROSE plume STF-LH sampling 1982 3at Commercial H.P. Near Sonic 1000 Natural gas >99 4' (estimate) McDaniel 1983 8 Commercial Zink 0.03-62 209-2183 Propylene/N2 67-100 Extractive and EPA STF-S-8 ROSE plume sampling 1983 6' Commercial air 1.4-218 83-2183 Propylene/N2 55-100 assist. Zink STF-LH-457-5 Continued

### TABLE 5-2. (Continued) Flare Gas Exit GasHeating Size Velocity Value Study Year (In) D<slgn (fis) (Btuift') Pohl, et al. 1984 3-12 Open pipe and 0.2-420 291-2350 commercial
Pohl and 1985 0.042 Nozzle 31-854 923-3320 Soelberg

1985 1.5- Commercial 0.2-591 122-2350 12 coanda steam injection, pressure assisted, air assisted, open pipe, pilot assisted 1985 0.042 Nozzle 5.6-891 588-2350 -2.5 1985 3 Open pipe 0.15-139 145-877

NA ' Not Avat •bie NM = Not Measured • 50% hydrogen plus light hydrocarbons. "Supplied through spiders; high Btu gas through area is 5.30 in2 and low Btu gas through 11.24 in2

. eThree spiders, each with an open area of l.3 in2

. Measured Combustion Gas Flared Eff. (%) Comments Propane/N1 90-99.9 Multiprobeplume extractive sampling 25 different gas >98 Comparative mixtures (80-99.99 screening tests destruction efficiency) Propane/N2 36-99.9 Comparative commercia! flare type evaluation

Propane/N2 NM Flame aerodynamic tests H2S/propane/N1 92-99.7 Gas mixture testing NHlpropane/N2 (92-99.9 1,3 bmadiene/N2 destruction Ethylene efficiency) Oxide/N2

### Additional problemsexist in the case ofopen-ended pipes used for flaring in the production segment ofthe gas industry. These flares typicallydo not have apilotand 

### must be 

### lit 

### manually. Therefore, the potential exists for the gas to be vented ratherthan flared whenoperating personnel are not available to light the flare (i.e., gas vented through a 

### pressure reliefvalve to aflare). Much ofthe flaring 

### done in the 

### production segment occurs at well completion. Since operating personnel

## are always present during this activity, the volume ofgas vented during well completionis smalL Inaddition, most state agencies require that any ongoing (post-completion)vent ofwellhead gas be burned; the agencies have 

### field auditors to ensure that 

### this requirement is followed. On the basis that 

### natural gas is predominantly methane (as presented in Appendix A), a combustion efficiency of98% was used for the productionsegment ofthe natural gas industty and 99% for the otherindustry segments. A lower efficiency was used 

### for the production segment to provide amore conservative estimate ofemissions due to the variability ofthe compositionofthe natural gas as it is 

### extracted from the well. Both 

### efficiencies assume the flare to be operatingunderoptimum flame stability. Flame-out inthenatural gas industry was assumed to 

### be negligible. Most gas processing plants are manned, so thatflame-out atthe flare would be observed and corrected 

### quickly. In addition, many ofthese sites havepilots and/or ignitors 

### thatensure that 

### the flame remains 

### lit. Fortransmission,·flare stacks atcompressor stations are uncommon; where they do exist, they have pilots and/or ignitors that

### ensure that the flame remains 

### lit. In the production segment, most flaring 

### from natural gas industry wells 

### is performed either with operator supervision oroccasionally withpiloted flares, so thatflame-out is minimaL 

### 5.2-2 Total NaturalGasFlow to Gas IndustryFlares There are no published sources for the total volume ofgas flared in

### the natural gas industty. While the American Gas Association (A.G.A.) doespublish natural gas 

### production and distribution volumes 

### that include anumbercailed "Vented and Flared,"15 

### this 

### 24number does not split the amount vented from the amount flared. For 1992, A.G.A. reports 167.5 Bscfofnatural gas "vented and flared" from production and gas processing. The 

### A.G.A. 

### number is derived by a pseudo material balance and includes all gas that 

### is not marketed, reinjected, or used in the production field. Therefore, the A.G.A. estimate includes fugitive gas losses and vented losses, as well as flared volumes. Ifthe A.G.A. 

### estimate were reduced by 

### the actual amount "vented" to the atmosphere (fugitive 

### + vented volumes), the result would be the amount ofnatural gas that A.G.A. assumes is flared. This GRI/EPA study estimates 48.4 Bscfofmethane from production and processing fugitive 

### emissions and 58.9Bscfofmethane from production and 

### processing vented emissions. Converting the GRI/EPA numbers to natural gas, based onthe methane compositionfor each industry segment, results in 132.3 Bscfofnatural gas as shown in Table 5-3. TABLE 5-3. NON-COMBUSTED EMISSIONS FROMPRODUCTION AND GAS PROCESSING(GRI!EPA ESTIMATE BASIS) 

### Fugitive Emissions Production 

### Processing Vented Emissions Production Processing TOTAL Bscfy

### Methane···
24.0 24.4
53.8 5.1 107.3 BscfyNaturalGas.
30.4 28.1
67.9 5.9 132.3

If the differencebetween the A.G.A. "Vented and Flared" volume (167.5 Bscfnatural gas) and the non-combusted emission volume from this study (132.3 Bscfnatural gas) is assumed to result in the flared volume, then 35.2 Bscfofnatural gas would be flared. Using a flaring efficiency ofapproximately 99% (as discussed in Section 5.2.1) and an average methane composition for production and processing of82.9%, a flared emission rate 

### can be 

### estimated:
250.829 scfCH 4 35.2e9

### set gas x x scfgas 0.01 scf CH4 non-combusted >dCH, flared • 029 BscfCH, (3) There are concerns with the accuracy ofthis approach, in that the "Vented and Flared" volume report

### by A.G.A. is fraught 

### with inconsistencies: it includes items not 

### truly vented orflared, 

### itdoes not include all vented and flared volumes (some sources from production

### and processing 

### are overlooked, and transmission and distribution sources are not included). and each state may have differentreporting requirements for the number. Appendix B discusses 

### why 

### this number is an inaccurate representation ofthe total vented and flared volume. 

### Selected Method Without reasonable nationally-tracked numbers forflaring, site data were sought. Most sites, however, did not measure nortrack flared volumes. lbis was especially true intheproduction segment. Therefore, analternate approach was used based onan assumption that the total amount ofgas flared would be equal to halfofthe total amount directly vented to the atmosphere by the industry. Table 5-4 shows the mefuane volumes vented ineach industry segment, as presented in Volume7 (MethaneEmissionsfrom Blow andPurgeActivities). 9 Using the flaring efficiencies for each industry segmentdiscussed earlier, a flare emission rate can 

### be calculated by multiplying the assumed flow by the combustion inefficiency term.
As shown 

### in Table 5-4, this alternate approach produces an estimate of 15.2 Bscfofnatural gas flared, which is significantly smallerthan the A.G.A. approach. Since the A.G.A. approach 

### is believed to overstate the flared amount, 

### this alternate approach was selected.



### 26TABLE S-4. MAXIMUM FLARING EMISSIONS Assumed Maximum Annual Flow

### to Flare, a MethaneEmissions 

### Industry Segment Bscf FlaringEfficiency from Flaring, Bscf 

### Production 0.5 (6.6 

### ± 329%) 98% 0.066 

### + 329% Gas Processing 0.5 (3.0 

### ± 262%) 99% 0.015 

### ± 262% Transmission and 0.5 (18.5 

### ± 177%) 99% 0.093 

### ± 177% Storage 

### Distribution 0.5 (2.2 

### ± 1,783% 99% 0.011 

### ± 1,783% TOTAL 15.2 

### ± 185% 0.185 

### ± 183% "Tile methane volume is assumed to be equivalent to halfthe vented quantity, where the vented volumes are reponed in the Blow and Purge Report.9
With eithercalculation approach, theestimated annual emissions from flares are negligible (less than 0.3 Bscf), and may be conservatively high, given the problems built into the A.G.A. number and that the flow to natural gas industry flares flare may be overestimated in the second approach. Therefore, this small category does not show up as an itemized contributionto total emissions 

### in this report. 5.3 Acid Gas Recovery Vents
Acid Gas Recovery (AGR) vents are a very minor source ofmethane emissions and account for only 0.82 Bscfofmethane emissions. AGR systems are used to remove acid gases (H2S and C02) 

### by contacting the stream with a solvent (usually amines) and then driving the absorbed components from the solvent. The amines can also absorb methane and, therefore, methane can be released to the atmosphere through the reboiler vent.

27

### Methane emissions were calculated using an ASPEN PLUS" process simulation. The disposition ofAGR vent gas and the number ofAGR 

### units were taken from an API survey ofU.S. Natural Gas Reserve Demographics.21 

### The following assumptions were used in determining the emission rate: I) AGR units do not use 

### flash drums or stripping gas; 2) AGRs have an absorption ofmethane similar to water; 3) the total 

### number ofAGR 

### units 

### in the United States are in 

### the gas processing segment; and 4) 82% ofAGR emissions are controlled (I8% ofthe emissions are vented). 

### 5.4 Salt Water Tanks Methane emissions from production salt 

### water tanks 

### were estimated using an ASPEN PLUS* process simulation. 

### The 

### flash calculations were based on the following assumptions: 

### I) The natural gas industry produces 497 million barrels ofsalt water annually, ofwhich approximately !00 million barrels are from coal bed methane wells.21 

### 2) 70'/o ofthe water from gas wells is reinjected, leaving 30% ofthe water stored in atmospheric 

### tanks.22 3) The hydrocarbon composition is 100% methane. 

### The 

### flash calculation results are summarized in 

### Table 5-5 for cases with 

### the salt content varied from 2 to 20%, and the pressure varied from 50 psi to 1000 psi. The 

### simulation results indicate that methane emissions from salt water tanks are negligible.

*ASPEN PLUS" is a registered trademark ofAspen Tecimology, Inc. 28

### TABLE 5-5. SALT WATER TANK EMISSIONS Methane Methane Emissions, 

### Emissions,. Salt Content, 

### Wt % 

### Pressure, pSi 106 

### lb/yr Bscf 20% Salt 50 1.6 0.0 250 10.8 0.0 1000 38.8 0.0 10% Salt 250 16.4 0.0 1000 58.7 0.0 2% Salt 250 19.4 0.0 1000 69.5 0.0


### 5.5 Drilling; Drilling operations typically use hydraulic pressure from the drilling mud 

### to keep the oil and gas 

### in the formation while drilling. The intent is to prevent the uncontrolled flow ofoil and gas up the well bore (a potential blowout) until the snrface equipment is ready to receive the material. Drilling mud does absorb some gas and releases it in the degasser at the snrface. The quantity is typically small 

### and has been excluded for 

### this project.
Blowouts during driliing or completion can be a large individual source of emissions, since the formation flows uncontrolled to the surface. The drilling industry has developed procedures and devices throughout the evolution ofoil 

### and gas production to prevent such an event. As a result, blowouts today are very infrequent and have not been 

### considered.
Once the desired formation or depth is hit, the well must be "completed" before 

### it can be produced. Less expensive tubing replaces the strong drill string and an outer annular casing is cemented in place. The casing has many uses. It prevents the formation from caving in around the tubing, allows easier well maintenance, and allows 

### 29onshore, dead (no surface pressure) oil wells to produce oil up the tubing string and gas up the outer casing. Ifthe oil and gas were produced in the tubing, the pumps would become vapor locked.
Once the 

### casing is 

### inplace, it is perforated and the formation begins to flow into the well. A clear completion fluid is used (heavy salt water) instead ofmud, and the completion fluid will flow orbe pumped to surface tanks orpits. Again, some small amount ofgas may evolve from the completion fluid, but it is typically insignificant. After the completion fluid is out ofthe well, oil and/or gas flow begins. Depending on thetype ofweii, the gas may be vented, flared, orimmediately produced. If the well was drilled in a known field with other existing wells, it is called a Developmental, or

### an Infill well. Inthat circumstance, the reservoir pressure and size are already defined, and

## the operator 

### can have production meters 

### and equipment sized and 

### in place for completion. Very little venting and flaring would occur at completion, ifany. Ifthe well was an exploratory "discovery" well (i.e., one drilled in a new area ofunknown reservoir potential), facilities may not be ready for the well's production. The 

### well is flared for the time that ittakes to measure the flow rates so that equipment can be sized. This period is referred to 

### as completion, completi<?n flaring, or well testing. Emissions from completion flaring are minimal but 

### are included 

### in the blow 

### and purge emissions.9 

### 5.6
Some longer sections ofgas-gathering and transmission pipelines may have small liquid collection pots located along the line. These pots are periodically blown down to clear collected hydrocarbon condensate, and the blowdown vents methane directly to the atmosphere. 

### An unaccounted-for (UAF) gas study by Pacific Gas and Electric (PG&E)



### 30

### defined drip blowdown emissions under urunetered company gas usage.23 

### They found the 

### category to be insignificant, at 0.00035% oftheir total throughput. 5.7 Sampling
Gas is consumed in sampling and analyzing gas for composition and heating value. Much ofthis gas is then emitted to the atmosphere from the on-line analyzers or from the sample containers. Most sampling efforts begin 

### in the gas processing areas, and 

### field sampling represents a small fraction ofthe total samples. The PG&E UAF gas project estimated this category as insignificant, at 0.00107% oftheir total throughput.23

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### 3. Campbell, 

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### Gas Facts: I993 Data, (Table 3-4), Arlington, VA, 1994. Pohl, 

### J.H. and N.R. Soelberg. "Evaluation ofthe Efficiency ofIndustrial Flares: H,S Gas Mixtures and Pilot Assisted .Flares," EPA-60012-86-080 (NTIS PB87-102372), September 1986. Straitz, J.F., III. "Flare Technology Safety," Chemical Engineering Progress, Volume 83, No.7,July 1987, pp. 53-62. 

### Romano, R.R. "Control Emissions 

### with Flare Efficiency," Hydrocarbon Processing, Volume 62, No. 10, October 1983, pp. 78-80.

33

### 20. Pohl, J.H., J. Lee, 

### R. Payne, and B. Tichenor. "Combustion Efficiency of Flares," 77th Annual 

### Meeting and Exhibition ofthe Air

### Pollution Control Association, San Francisco, CA, June 24-29, !984. 21. American Petroleum Institute. Survey ofU.S. Natural Gas Reserve Demographics, Washington, DC, !992. 22. 

### Energy Environmental Research Center, University ofNorth Dakota, and ENSR Consulting and Engineering. Atlas of Gas RelatedProduced Water for 1990. 

### Gas Research Institute, 95/00!6, May !995. 23. 

### Pacific Gas & 

### Electric Company. "Unaccounted-For Gas Project." Volume I, 

### 1989.

34

### APPENDIX A Methane Composition

A-1APPENDIX A 

### METHANE COMPOSffiON The composition ofmethane in natural gas is needed to calculate methane emissions from natural gas that is emitted to the atmosphere. This section describes the characteristics 

### ofnatural gas streams in productio:t, processing, transmission, and distribution. The methane composition for each segment is presented in Table A-1. 

### TABLE A-1. METHANE COMPOSffiON BY INDUSTRY SEGMENT Segment Production Gas 

### Processing Transmission/Storage Distribution Methane (volume o/o) 

### 78.8 ± 5% 87.0 

### ± 5% 93.4 

### ± !.5% 93.4 

### ± !.5% Production Segment · The production segment ofthe gas industry includes natural 

### gas produced from gas wells (non-associated) and oil wells (associated). Data from the United States Bureau ofMines, Division ofHelium Field Operations, and A.G.A. Gas Facts were used to calculate the production methane composition. 1'1 The Bureau ofMines 

### (BOM) has been collecting analytical data from oil and gas wells and natural gas pipelines since 1917 in an effort to locate sources ofhelium. Under another GRl project, all 

### published BOM data through 1987 were obtained on magnetic tape and loaded it into an Empress® database.3 The focus ofthis earlier project was to determine the major contaminants in sour natural gas, specifically, hydrogen sulfide and carbon dioxide. Over 14,000 records were used 

### to determine county and state averages for natural 

### gas composition, including methane content. The BOM data were corrected since a few non-gas industry wells that have very high helium or carbon dioxide content with little or no methane were included in the data A-2set. For the largest producing states, the Empress data files were reviewed and the entries with less than 40% methane were removed. Table A-2 shows the average methane content and marketed production by state. This information was regionalized to estimate the national average methane content of78.8 mol % 

### ± 5% as shown inTable A-3. Gas Processing Segment

- The only source ofmethane data identified for the processing segment is from the 

### Gas Engineer's Handbook. 4 These data are from November 1951 and consist ofeight data points with only two states, California and Texas, represented (see Table A-4). The data are reported as nafter processing plant" and were assmned to represent typical speciation data for natural gas leaving this industry segment. Due to the limited data set, an average methane content was calculated instead ofa weighted average based on the state's fraction ofU.S. production. The average methane content for the processing segment is 87 mol percent. A 90% confidence interval of5% was calculated based on the spread ofthe available data. Transmission and Storage Segments

- The methane composition for transmission and storage was based on the GRI TRANSDAT database,' which 

### has analyses offifty fuel gas samples from various transmission compressor stations. Since the fuel gas is from the pipeline, these should represent transmission gas quality. The resulting average methane composition for transmission is 93.4 mol% 

### ± 1.5% (90% confidence interval is based on the spread ofdata).
Distribution Segment

- The 

### Gas Engineer's Handbook provided methane composition data for the distribution segment.4 This data set includes distribution in 48 cities, representing 29 states and the District ofColumbia, for the fall of 1962. A weighted average was not used for this industry segment since the distribution ofnatural gas does not necessarily reflect the origin ofthe gas. The resulting average methane content is approximately 89 mol %.

A-3The composition ofgas leaving the processing segment should agree with the methane composition 

### in the transmission and distribution segments, since the gas is only transported or stored. However, the distribution value is less 

### than the methane composition determined for the 

### transmission segment. Because the transmission data are based on the more recent and more extensive data source, 

### the same composition is 

### used for distribution. Therefore, the distribution methane composition used 

### in determining emission factors is 93.4 vol % 

### ± 1.5%.



## ' TABLE A-2. AVERAGE STATE METIIANE CONTENT AND PRODUCTION RATE Methane Composition, 1989.Marketed Gas Region 

### s·tates•

.Volume 

### o/o ·· PrOduction, Bscf 

### GulfCoast 

### AL 86.4 !51 

### FL 60.2 ·8 

### LA 87.8 5,087 

### MS 79.8 165 

### TX 75.1 6,401 Central Plains 

### AR 87.7 174 

## co 65.4 227 KS 69.4 60! 

### MO 69.4 4 

### MT 69.4 

### 51 ND 62.5 

### 56 NE 53.4 I NM 64.4 856 

### OK 79.8 2,237 

### SD 4 WY 69.9 756 Pacific and Mountain 

### AK 76.5 394 AZ I CA 75.3 364 

### OR 3 

### UT 120 Atlantic & Great 

### IL 86.2 2 

### Lakes 

### KY 76.2 

### 72 MI 74.4 !56 

### NY 90.0 20 

### OH 82.0 160 PA 91.0 192 

### TN 85.2 

### 2 VA 88.0 18 

## wv 86.9 177 States not shown had insignificant 1989 marketed gas production rates. A-4

### TABLE A-3. METHANE COMPOSITION OFPRODUCTION GAS 

### Volume Percent

### MetbllDe (from 

### state vol %'sweighted by 

### state Region GulfCoast Central Plains


### Pacific and Mountain Atlantic and Great Lakes
Total U.S. 

### production) Comments 80.76 All states but

### GA represented 73.68 Some states with insignificant 

### production were excluded (lA. MN) 

### 75.92 Alaska and California only 83.59 Some states with insignificant 

### production were excluded (CT, DE, IN, MA, MD, ME, NC, NH, NJ, Rl, 

### SC, VT, WI) 78.8 Weighted average by regional 

### production

TABLE A-4. METHANE COMPOSITION IN GAS PROCESSING Location 

### CA, Kettleman North Dome CA. Ventura TX, Agua Dulce TX, Carthage TX, Hugoton 

### TX, Keystone TX. Panlumdle TX. Wasson 

### Average

A-5 

### Methane Composition, Vol % 

### 93.0 92.7 93.0 9!.7 79.0 86.2 81.5 76.9 86.8

### REFERENCES: 1. U.S. Bureau ofMines. Analyses of Natural Gases, 1917-1987. 

### 6 vols. Helium Field Operations, Amarillo TX. February !988 (magnetic tape and hard copy). 2. American Gas Association. Gas Facts: 1990Data, 

### (Table 3-3), Arlington, VA, 1991. 3. Radian Corporation. Investigation ofU.S. Natural Gas ReserveDemographicsand Gas 

### Treatment Processes, 

### Topical Report. Gas Research Institute, January 1991. 4. "Natural Gas from Various Gas Fields (As ofNovember !951)," Table 2-12, Gas 

### Engineers Handbook, 

### Industrial Press Inc., New Yorlc, NY, 1977. 5. Biederman, N. GRI TRANSDATDatabase: Compressor Module. (prepared for Gas Research Institute) npb Associates with TomJoyce and Associates, Chicago, IL, August 1991.

A-6

### APPENDIXB Reported "Vented andFlared" Data

B-1

### APPENDIX B REPORTED "VENTEDAND FLARED" DATA National numbers for "vented and flared" volumes are reported 

### by production and processing companies to state agencies. which thenreport to the Department ofEnergy (DOE)Energy InfonnationAdministration (EIA). 

### Gas Facts publishes this EIA national number for "venting and flaring" (V&F) at approximately 0.71% ofthe total natural gas production. 1 Initially, it was assumed 

### that the reponed V&Fnumberwas valid, and the approach for this project focused on simply splittingthis number into a vented volume and a flared volume, so that vented emissions could be accurately quantified. However, this study discovered that the reported V&Fnumber has many problems, and it is not a useful measure ofactual venting orflaring. Thereported numbers do not represent actual "vented and flared" quantities ofgas, since companies do notuse a standard practice orprotocol for determining their V&F amount. In fact, many sitesuse a protocol 

### that results in anerroneous value forV&F. Many gasplants simplyreport all material balance discrepancies as "vented and flared," even thoughmost material balance losses are due to otherfactors, such as metering inaccuracies. Othercompanies have operators simply guess the amount ofgas vented orflared 

### in order to fill out 

### a state form. Very few sites actually measure oraccurately calculate V&F volumes. Even if

### the reponed V&F volumes were accurate. there is not 

### a reliable method ofsplitting the numberinto the amounts flared (burned) and the amounts vented. Furthermore, there is no method for separating the amount of

### vented, unmarketed 

### natural gas attributable to oil production.
The GRI/EPAproject abandoned use ofthe reported V&Fnumber, and turned to a technique that identified each source ofvented emissions, and estimated emissions from each source type. This technique is described 

### inmore detail 

### in Volwne 3 ongeneral methodology.2 Tills appendix discusses the problems withthe V&F numbers reported by operators to various state and federal governmentagencies. This section is only intended to B-2

### offerdata supporting the decision not to use the reported V&F numbers in this GRI/EPA project. Sources ofdata for the United States and for individual states, as well as the quality 

### ofthe data are covered in detail in the following subsections. 

### B.l Specific States 

### Specific state data were analyzed 

### for Texas, Oklahoma, and Louisiana. These three states comprise 68% ofall the gas produced inthe U.S. in 1989 and are representative ofgas 

### production facilities. States that are major producers ofoil and gas generally have state governmental agencies 

### that regulate and maintain 

### data on the oil and gas industry. The regulating agencies for Texas, Louisiana, and 

### Oklahoma are the Texas Railroad Commission (RRC), the Louisiana Department ofNatural Resources (DNR), and the Oklahoma 

### Corporation Commission, respectively.
The primary goal ofthese agencies 

### is to control the industry (provide "fairplay" for all operators), collect fees, and

### protect the 

### community and the environment. Methane 

### emissions have not been aconcern for these agencies except where the emitted methane 

### represents. 1) 

### an unnecessary waste ofnatural resources that 

### should come outofacompany's "allowable" productionquota; 2) a toxic gas 

### hazard (H2

### S); or3) a fire orexplosive hazard. 

### To the extent that methane emissions represent ameasurable loss ofnatural resources, the agencies track data on "venting and flaring! For many agencies, the V&F numbers are grouped together. No differentiation is made between amounts acrually burned versus amounts vented; however, there is one exception. Permits filed under Rule 32 in the Texas RRC code do differentiatebetween venting and flaring.


### The accuracy and extent ofthe reported V &F numbers are afunction ofthe V&F defmition the state uses 

### in the reporting regulations, the state's enforcement ofreporting regulations, and the exclusions that the state allows. Given abroader definition, more emissions are included; however, given more exclusions, fewer events will be 

### reported.



### B-3

### Finally, given weakerenforcement, more unreported quantities will exist. Some ofthe statespecific data are discussed below. 

### B.I.l Texas 

### For Texas, most ofthe V &F numbers are reported as one number to the RRC on a monthly basis. Gas plant operators send in R-3 forms, and oil and gas producers send in P-1 and P-2 forms, respectively. Oil wells are tracked by the lease, and gas wells are tracked by the individual well. The data from these forms are summed into tables in the RRC's published 

### Oiland Gas

### AnnualRepon' The RRC 

### also requires a permitfor flares orvents 

### lasting more 

### than 24 hours in 

### the R-32 form. The 

### specific forms are discussed in

### more detail below. Amongthe states, Texas probably has the strongest regulations, the strongest enfor

### cement, and the mostcomprehensivepublished 

### data. Nevertheless, the reported vented and flared numbers in 

### Texas are difficultto assess; there are areas over-reported and underreported due to definition. Amounts vented from compressor engine exhausts, pneumatic actuators, glycol vents, and acid gas recovery vents have never been considered as part 

### of the V&F definitionfor reporting. 

### Inaddition, the definition ofV&F is differentevenamong the various RRC forms. R-3 Gas Plants- Forgasplants, the V&Fnumberonthe R-3 is simply the result of 

### amaterial balance closure around the gas plant. The rule 

### is: GAS IN

- PRODUCTS OUT- CONSUMPTION = V&F Measured outlet dispositions (pipeline gas, fuel, extraction loss, etc.) are subtracted from the inletplant meter, and the difference is reported as V&F. The difference is reallyjust an "unaccounted-for" (UAF) number arrived at by an accounting procedure; it is usually 

### positive and in the range of0.3% ofthe total gas processed. The flare, which 

### in the 

### gas B-4

### plant has orifice meter readings near zero, 

### is not considered in 

### the calculation ofthe reported V&Fnumber.
Ifthe gas plant material balances are absolutely accurate (all quantities included are on the same basis) and have a zero meterbias (doubtful, but possible), then the reported V&F number, even though a calculated value, is a true "emitted, vented, orflared" amount. From the V&F number, the flare meter reading could be subtracted, the fugitive emissions subtracted, and 

### the remaining value would be 

### material actually vented. This is the "topdown" yardstick that the "bottom-up" emissions rates for gas plants can be 

### compared to. R-3 Cycling Plants (Pressure Maintenance)

- Cycling plants process gas to reduce the dew point ofcondensibles in

### the formation and thus extend the life ofa field. In

### most cases, not all ofthe gas is returned to the formation 

### in acycling plant. Again, data 

### from the Texas Railroad Commission indicate that for the 15 pressure maintenance facilities in Texas, 51.6% ofthe residue gas is used for repressurizing orcycling, while 26.6% 

### is sentto transmission pipelines.3 

### It should be 

### noted also that the V&Festimate for cycling plants is 0.3% ofthe total gas processed, which is the same as for gas plants. P-1, P-2 Production- A P-1 report is generated for each oil lease and a P-2 report for each gas well. Forproduction facilities, V&F on the P-1 and P-2 reports is meant to represent a real vented and 

### flared quantity at the wellhead. Nevertheless, many releases are exceptions to the reponing requirements, including: well completionflaring for up to 10 days, events less than 

### 24 hours in

### duration, well cleanups, and venting and flaring from certain field equipment (glycol separators and pneumatic devices). This excludes many of the true release events from the numbers recorded by 

### the RRC.
Even the accuracy ofthe categories that are included in reporting is questionable. Production flares have no pilot and no meter, so reported values are operator estimates. The operators generally base their estimates upon the most recent well test data 

### orupon the



### B-5

### field's gas-to-oil ratio. No actual measurements are used for P-1 orP-2 reported values, and the RRC admittedly has no way to verifY the reported values. 

### There are so many exceptions and estimations in 

### the reported production numbers 

### that it is impossible to intuitively tell whether the number is over- orunder-reported. As 

### with gas plants, a method that does notuse the reported V&F numbers must be used to estimate 

### real production emissions. The reported numbers can then 

### be adjusted to use only as acheck value for the bottom-up calculations. Rule R-32- The Texas RRC Rule 32 does have some impacton the V&Famounts. The rule allows 10 days ofventing following completionofa well, and thenrequires all gas to be flared. 

### Inaddition, permits are required for flares orvents beyond initial completion (exceptions are well cleanups orrepairing/modifying a gas-gathering system). The permit 

### form has one very useful piece ofdata: 

### ·a designation ofventing that 

### is different from flaring. The form is the only place in the reported V&Fcategory where the operator must 

### designate whetherhe intends to ventor to flare for the specific release permit. The RRC tracks Rule 32 pennits to make sure that sourgas is burned and that large 

### vented releases are notnearmajor roadways norpopulated areas. Releases ofunburned sour gas can be toxic, and large vented releases can

### be explosion or fire hazards. The R-32 

### data 

### were used for this project to establish apercentage splitbetween vented versus flared for all the production V&Ftotals that are reported. The data were reviewed for 1991 permits and showed that the amount vented was 7.7% and the amount 

### flared was 92.3% ofthe total V&F. However, the assumptionthatthe non-permittedquantities have the same splitmay be 

### incorrect, since events less 

### than 24 hours and well cleanups are exceptions. Therefore, many venting events may not 

### be partofthese data. Oil and GasAnnualReport

- With all ofthe above limitations in mind, the data from annual reported values were analyzed. Most ofthe reported venting and flaring volumes were for casinghead gas (oil well gas). There are many more oil wellsthan gas B-6wells. For that reason. there is a significant quantity ofcasinghead gas produced. 

### In Texas. 23% ofall gas produced 

### is casinghead gas. Ofthe total reported V&Famounts, V &F from casinghead gas at the well accounts for 47.5%, while V&F from gas at the well accounts for only 5%. Gas well gas V&F is likely under-reported, since well cleanups are not reported. The data show that a disproportionate amount ofthe reported V&F 

### is due to casinghead gas. The remainder ofthe reported V&Famounts is due to V&F reported at gas plants. This accounts for 47.5% of the reported total V&Famount. These data show that gas wells typically vent or flare infrequently. This makes sense from an economic point ofview, since vented gas represents a direct loss ofthe well's only revenue. Casinghead gas (oil well gas) is vented or flared more frequently. Gas lost. through V&Fat oil wells is also a loss ofrevenue but on a much less significant scale. The oil revenue is typically much larger than the gas revenue. Casinghead gas that 

### is V&Fmay he from wells that never produce gas to a pipeline and, therefore, should not be considered part ofthe gas industry emissions. Those wells would eitherconsume all oftheproduced gas as lease fuel, reinject all ofthe gas, or vent/flare all ofthe gas. Summing those 

### three disposition categories for the RRC's casinghead gas annual table shows that 4.3% ofthe total casinghead gas is used for those purposes. Ifall oil wells had identical gas production, tltis would mean that the maximum amount ofoil wells that should beexcluded is 4.3%. For amore exact answer, the number ofoil wells that do not market gas must

### be known.
The reported V&F numbers for Texas imply that 0.53% ofall gas produced is vented or 

### flared. However, the following problems are associated 

### with the Texas statistics [pluses (+) are shown for comments that would raise the reported numbers when corrected, and minus (-) symbols are shownfor items that would reduce the reported numbers]:

B-7

### (-) Approximately one-halfofthe V&Famount is due to gas plant V&F, which is 

### an accounting closure numberand not really venting and flaring. Even ifa gas plant material balance is assumed to have azero bias. fugitives should be subtracted from the V &F numbers reported. (-) Nearlyhalfofthe reported venting and flaring gas is from casinghead gas. 

### Some ofthis casinghead gas is associated 

### with oil wells 

### that do not produce to a gas pipeline, and 

### that fraction is, therefore, not partofthe namral gas industry as defined by this

### project. This amount could be 

### excluded ifa 

### defensible basis were derived to separate those wells. (-) Venting and flaring permit rates are usually overestimated (in the 

### RRC's 

### opinion) because many ofthe producers do not want to 

### apply for pennit exceptions ifthe rate increases. (+) 

### Many events are exempted from the reportingrules (such as well cleanup, well completion, and events less than 

### 24 hours). (+) 

### Some oil wells that produce associated ordissolved gases do notreport V&F. (+) 

### Emissions from tank 

### batteries, glycol dehydrators, AGRs, and other 

### miscellaneous sources are not reported. Therefore, even though Texas' reported V&Fnumbers appear to give an overall entission 

### estimate for V&F

### emissions. they cannot

### be used as aquantitativemeasurement. 

### B.l.2 Louisiana The Louisiana DepartmentofNamral Resources (DNR) tracks 

### V&Fina manner 

### similar to the 

### Texas RRC. Operators report the monthly production (wellhead) disposition data onthe R-5D forttt and

### the gas plant data on the R-6 forttt. The DNR, like the Texas RRC, compiles all ofthe monthly data on computerfiles. The DNR, however, only makes the data available through specific, standardized computer runs which must be 

### pre-paid by the requestor.

B.SRadian has not requested Louisiana runs; however, Louisiana provided the 1988 Parish Report during a visit to the DNR. The report showed a total onshore V&F number similar ro Texas, ar 0.47% oftotal gas production (Texas was 0.51%). Louisiana's definitions ofventing and flaring for reported numbers appear to be similarto Texas; and, therefore, Louisiana data will have the same problems that were described for the Texas data. Louisiana also has no method ofseparating the split between vented and flared quantities from the single V&F numbers reported on the R-5D and R-6 forms. In fact, the term "venting," such as the "vented" column on the R-6 form, refers to venting or flaring. AlthoughLouisiana does not have a Rule 32 flare pennitrequirement as Texas does, it has a Statewide Order45-I thatrequires a semiannual status report, which lists casinghead and natural gas "vented" by lease and explains why the gas is not being recovered. Unfortunately, the DNR does not aggregate these data; the data are received in nonstandard letter format and stored as received. It would be very difficult and time-consuming to assemble all ofthese data into a meaningful form. ·Forexample, Radian's examination of three 45-I status reports indicated very different results as shown inTable B-1.
Company Mid-size company
Large company Small company TABLE B-1. COMPARISON OF45-1 REPORTS 

### Type

### ofGas Reason

### for Venting Casinghead gas Uneconomical to recover. Most vent points were lowpressure heater treaters. Some fields used intermittent gas lift, thus, consuming all ofthe produced gas . intermittently. Unknown Majority ofemissions were from compressor downtimes. Unknown Compressor downtimes.

B-9B.l.3 Oklahoma 

### The Oklahoma Corporation Commission's Oil and Gas Conservation Division issues venting and tlating permits. However, only rates above 50Mcfd require a permit, and few wells fall into that category. The permit file 'or 1991 badonly nine permits issued as shown in Table

### B-2. 

### TABLE B-2. 1991 FLARING PERMITS FOR OKLAHOMA Numberof

Permits 6 1 2 

### PercentofTotal Permits 

### 67 11 22 

### ReasonforRequest Recover load water from gas well (well clean-up). 

### H,S found, pulled from gathering system and flared. Other (unknown) Oklaboma appears to have significantly fewerreporting requirements than Texas or Louisiana and had no otherdata onV&Favailable. Interestingly, Oklaboma does not appear 

### to exclude well cleanups from the permit 

### requirements as Texas does. As shownabove, well cleanups constitute a largepercentage ofthepermits issued in Oklaboma. B.2 United States 

### There are several sources ofinformation gathered on the natural gas industry for the entire 

### United States. These sources include federal agencies, such as the Federal Energy Regulatory Commission (FERC) and the Department ofEnergy (DOE), and gas industry representatives, such as the American Gas Association (A.G.A.). Numerous publications are compiled bythese agencies and include informationongas industry fmancials, gas 

### production and disposition, and 

### gas storage and reserves. Data are also collected from regulatory agencies and otherprivate agencies, suchas the American Petroleum 

### Institute (APD.

B-10

### There are five PERC forms that deal specifically with the natural gas industry. The main form completed by gas companies regulated by FERC is the FERC Form No. 2, 

### "Annual Report for Major Natural Gas Companies." This 

### form is an annual requirement for major gas companies, which are defined by the FERC as "baving combined gas sold for resale and gas transported or stored for a fee exceeding 50 Bcf (at 14.73 psia 60"F) in each 

### ofthe three previous calendar years." Mostofthe information collected on this form is fmancial and, therefore, does notcontribute to the data gathering effort for V&F. The other FERC forms collect informationonunderground storage (FERC-8), gas pipelines (FERC11,-15), and gas supply (FERC-16).
TheEnergy InformationAdministration (EIA) ofthe DOE, publishes many reports on 

### the natural gas industry. One ofthe mostuseful publications is the Natural 

### GasAnnual.4 

### Two EIA forms provide most ofthe informationused in this report; EIA-176, "Annual Report ofNatural and Supplemental Gas Supply and Disposition," and EIA-627, "Annual Quantity and Value ofNatural Gas Report." The EIA-176 is a mandatory form to be 

### completed by all companies that deliver natural gas to consumers or transport 

### interstate gas, The EIA-627 is avoluntary form completed by energy or conservation agencies in gasproducing states. Other sources ofinformation used by EIA for theNatural 

### Gas Annual 

### include the FERC, the United States Geological Survey (USGS), and the Interstate Oil Compact Commission (IOCC). Information directly from the USGS and the IOCC bas not 

### been gathered for this venting and flaring task. The Natural Gas Annual

### provides information on gas production, transmission, and consumption for the United States as awhole and for each gas-producing state individually. Included in this report are numbers for gas V&F. Both the EIA-176 and the EIA-627 collect 

### gas V&F information. Since these data are taken directly from the responsible state agencies, any differences in reporting requirements and/or the definition ofvented and flared are not accounted for in this publication. Some 

### ofthese differences were identified 

### in the previous sections on individual state reporting. The EIA is aware ofthis inherentproblem, but it 

### is not known if

### the agency adjusts the data to 

### reflect these differences. B-11The A.G.A.'s GasFacts is anannual publicationcontainingdata on the gas utility 

### industry. The data concentrate on gas distribution and 

### transmission but also include some information from the gas-producing segment ofthe industry. Most ofthe information is gathered by the A.G.A. in its survey entitled "Uniform Statistical Report. The only 

### information on venting and flaring provided 

### in the GasFacts

### was taken from the EIA Natural GasAnnual. 

### Again, this infonnationisjust areiteration ofthe numbers reponed by 

### the responsible state agencies 

### with the inherent problems already discussed. A summary of the national statistics in Gas Facts 

### is shown in 

### Table B-3. 1 It

### appears that any data

**~hich** 

### are derived from an overall United States approach are justa summation ofthe data reported by the individual gas-producing states. Due to the variability in these data, the task ofcharacterizing V&Fin the natural gas industry should 

### follow abottom-up approach and begin 

### with the identification ofthe individual sources. Then, respective methane emissionestimates could be 

### calculated and added to determine the overall emissionnumber for the entire United States. REFERENCES I. American Gas Association: GasFacts: 1990Data, (Table 3-3), Arlington, VA, 1991. 2. Harrison, M.R., HJ. Williamson, and L.M. Campbell. Methane Emissionsfrom the Natural GasIndustry. Volume 3: GeneralMethodiJlogy, Final Report, GRI94/0257.20 and EPA-600/R-96-080c, Gas Research Institute and U.S. Envirotunental Protection Agency, 

### June 1996. 3. Texas Railroad Co!Illlrission. Oiland GasAnnualRepon. Volume I "Cycling Plant Operations in Texas," Data Source: RRC FormR-3, 1991. 4. U.S. Department ofEnergy. "Quantity ofNatural Gas Used as Lease Plant Fuelby State," Natural GasAnnuall992, Volume I. Energy InformationAdministration, Office ofOil and Gas, U.S. Dept. ofEnergy, Washington, DC, November 1993, p. 240.

B-12

### TABLE B-3- SUPPLY AND DISPOSITION OFGAS IN THEUNITED STATES

- 1989' 

### MMcf PercentofTotal Production Gas Wells Oil Wells Total Disposition 

### Extraction Loss Fuel and Lease Use Pipeline Fuel Gas Lift 

### Repressure and Pressure Maintenance Cycled Underground Storage (Net Charge) 

### To Transmission Lines To Carbon BlackPlants Vented or Flared Acid Gas (H2S, C02, H,O) PlantMeter Difference (UAF)

a 

### Data reported includes gas processing. 15,735,849 5,262,981 20,998,030 784,502 1,070,452

630,083 Unreported



### 2,451,342 Unreported



### (310,802) 15,688,047 Unreported 

### 140,532 362,457 182,217



### B-13 74.9 25.1 100.0
3.7 5.1 3.0



### ·- 11.7 (1.5) 73.3

0.7 1.7 0.9TECHNICAL REPORTDATA

**(PI~** rou/1/IIUnlt:tiOIU01t

**th~ ~be/~**  **compl~tingj** T. REPORTNO. 

# I' 3.RECIPIENT'SACCESSIONNO. 

### EPA-600/R-96-0SOf 4.TITLEANDSUBTITLE 5.REPORTDATE Methane Emissions from the Natural Gas Industry, 

### June 1996

Volumes 1-15 (Volume 6: Vented and Combustion 6.PERFORMINGORGANIZATIONCODE Source Summary)

.,_AUTHOR(s' 

### L. camf1bell.

### M. camrfbelL

### M. **Cow~l.**

### D.Ep- .PERFORMINGORGANIZATIONREPORT NO **~erson,** M.Hall, •Harrison. •Hummel, D. yers. 

### DCN 96-263-081-17

•Shires,B.Stapper. C.Stapper.J.Wessels, and 

## * g_PERFORMINGOROANIZATIONNAMEANOADDRESS 10.PROGRAMELEMENTNO. RadianInternational LLC 

### P.O. Box 20!088 11.CON RAC /GRANTNO. Austin, Texas 

### 78720-1088 5091-251-2171 (GRI) 68-DI-0031 (EPA) 12.SPONSORINGAGENCYNAMEANDADDRESS 13.TYPEOF iPORT/NOPERIODCOliEREO 

### EPA, Office of Research and 

### Development Final; 3 91-4 96 14.SPONSORING_..CENCYCODE .Air Pollution Prevention and Control Division 

### Research Triangle Park, 

### NC 277ll EPA/600/13 1f.SUPPLEMENTARYNOTEs EPA project officer is 

### D. A.Kirchgessner.

### MD-63.919/541-4021. Cosponsor GRI project officer is R
.. A
.. Lott. Gas ResearchInstitute, 8600 West Bryn 

### Mawr Ave., Chicago, IL 60631. (*)H. Williamson (Block 7). 1G

•.i:!STRACTTheTO-volume report summarizes the results of a comprehensive program o quantifymethane (CH4) emissions from the D.S. natural gas industry for the base **~~ar.** The objective was to determine CH4 emissions from the wellhead and ending

ownstream at the customer's meter. The accuracy goal was to determine these **~missions** within

### +/-Of5% of natural gas production for a 

### 90% confidence interval. For [the 

### 1992 base year. total CH4 emissions for the 

### U
.. S. natural gas industry was 

### 314 

### +I- 105 Bscf (6.04 

### +I- 2.01 Tg). This is equivalent to I.4 

### +I- 0.5% ofgross natural gas production. and reflects neither emissions reductions (per the voluntary AmeriGas Association/EPA Star Program) nor incremental increases (due to increased gas usage) since 

### 1992. Results from this program were used to compare greenhouse

as emissions from the fuel cycle for natural gaS;. oil, and coal using the global warming potentials (GWPs) recently published by theIntergovernmental Panel on Climate Change (IPCC). The analysis showed that natural gas contributes less to potential global warming than coal or oil. which supports the fuel switching strategy suggested by the IPCC and others. In addition. study results are being used by the n"a.tural gas industry to reduce operating costs while reducing emissions. I 

## I 

## ' 

# "· KEYWORDSANODOCUMENTANALYSIS 

# .. DESCAIPTORS b.IDENTIFIERS/OPENENOEOTEAMS c COSATl Field/Group Pollution lPollution Prevention 

### 13B Emission Stationary Sources 

### 14G Greenhouse 

### Effect Global Warming 

### 04A Natural Gas 

### 21D Gas Pipelines 

### l5E Methane 

### 07C 18.OISTA19UTIONSTATEMENT 19.SECURITYCLASS (This
**R~port)** 21.No 

### 6

yFPAGES 

### Unclassified Release to Public 20.SECURITYCLASS (Thisp4gej 22.PRICE 

### Unclassified EPA Form2220·1 (9-73) 

### B-14U.S. ENVIRONMENTALPROTECTIONAGENCY 

### OfficeofResearch andDevelopment NationalRiskManagement Research Laboratory TechnologyTransferandSupportDivfsfon Cincinnati, Ohio45268 OFFICIAL BUSINESS PENALTY FOR PRIVATE USE. S300 AN EQUAL OPPORTUNITY EMPLOYER

Ifyour4ddress is incorrect. plellSfl ch11nge on the above label tf/llro/1; andreturn to the above ¥/dress. IIyou donot desire to continuerecttivingthese ttJchnic81 reports. CHECKHER£0: teat offlabel. andteturn it ro the aboveaddress. 

## Publication No. EPA- 600/R-96-0BOf