Identification and Evaluation of Opportunities To … · natural gas losses at gas processing plants through ... facilities that process sweet and sour gas and use ... and also submit

United States Air and Radiation EPA-430-N-01-004Environmental Protection 6202J Summer 2001Agency

Identification and Evaluation of Opportunities ToReduce Methane Losses at Four Processing PlantsRecent findings reveal that significantopportunities exist for cost-effectively reducingnatural gas losses at gas processing plants throughthe control of leaking equipment componentsand leakage of process gas into vent and flaresystems. The study, led by the Gas TechnologyInstitute (GTI, formerly the Gas ResearchInstitute) in cooperation with EPA’s Natural GasSTAR Program and industry participants, wasconducted in late 2000 at four gas processingfacilities that varied in terms of age, types, andthroughputs. The selected facilities wereexpected to offer a range of opportunities forcost-effective reduction of natural gas losses.

Directed inspection and maintenance at gasprocessing plants is among several bestmanagement practices and partner reportedopportunities recommended by the Gas STARProgram for reducing methane emissions. Theobjective of the study was to demonstrate withactual field data that a comprehensive leakdetection and repair program could reduce gaslosses while enhancing profits. GTI’s Hi-FlowTM

Sampler technology was used to gather data onemissions from continuous vents, combustionequipment, and flare systems. Assessment of theemissions data coupled with diagnostic checks ofnatural gas-fueled equipment provided anopportunity to examine whether reductions inmethane gas emissions could be achievedsensibly, could be verified, and could create aneconomic opportunity for the industry.

Most leak detection and repair programs in thenatural gas industry rely on EPA’s Method 21,which measures the concentration of methaneleaked into the air and then uses a correlation

Summer 2001

equation to estimate the leak rate. In con-ventional leak programs, Method 21 is used toscreen the facility at a prescribed frequency suchas annually or quarterly. Based on the method’sspecifications, all components that producescreening values greater than 10,000 parts permillion (ppm) are required to be repaired.Because the Method 21 equations are applicableonly between 10,000 and 100,000 ppm, any leakthat screens beyond this upper concentrationresults in the same estimated leak rate. Incontrast, the methodology employed by GTI inthis and other studies differs from Method 21 inthat a special device (the Hi-FlowTM Sampler) isused to measure the actual leak rate by volume.These volumetric measurements can then beused as reliable data in a cost-benefit analysis todecide which leaks are cost-effective to repair.

Program Tools .....................................................3The Natural Gas STAR Program is developing three newtools (Online Analytic Tool, Online Reporting Tool, andEmission Reduction Tracking and Data Collection Tool) that will be available this fall.

Partner Experiences ............................................4Natural Gas STAR partners share their experiences in implementing methane emission reduction technologiesand practices in two new Lessons Learned.

In the Spotlight ...................................................6The Natural Gas STAR Program provides partners with case studies that show how companies reduced emissionsand saved money by joining the Natural Gas STAR Program,and partner reported opportunities (PRO) fact sheets thatdescribe processes and technologies reported by partnersas “other Best Management Practices” in their annualreports.

Workshop Registration Form............................11The 8th Annual Natural Gas STAR Workshop will be heldon October 23-25, 2001. Register now! Workshop detailsare provided on page 4.

IN THIS ISSUE

Natural Gas STAR Partner Update ■ Summer 20012

Data from GTI studies show that only about 10percent of the fugitive emissions that screen above the10,000-ppm threshold are cost effective to repair. Thisis due to the fact that leaks with a high concentrationreading may actually have a low leak rate. Thereforethe gas savings alone may not justify high repair costs.On the other hand, 20 percent of the components thatscreen at values less than 10,000 ppm are costeffective to repair, but would not be repaired based onthe Method 21 criteria. GTI’s method relies on cost-efficient leak detection techniques and on its Hi-FlowTM Sampler—a leak measurement device—which accurately measures leak volume. This methodsignificantly reduces the cost of leak programs atnatural gas facilities. Their data have shown thatimplementing this procedure at natural gas compressorstations can reduce emissions by 80 to 90 percent witha payback period of 6 to 12 months. They have alsoshown that 10 percent of the leaks are responsible for80 to 90 percent of the emissions, and thus, significantreductions can be achieved by repairing a relativelysmall number of leaks.

The intensive fugitive-component and screening-measurement program conducted by GTI targetedfacilities that process sweet and sour gas and usecompression, separation, stabilizing, deep cryogenicrecovery and rejection, mole sieve and triethylene anddiethylene glycol dehydration, and other gas-refining

Gas-Plant Testscontinued from page 1

techniques. The four plants had been operating from20 to 50 years. Table 1 provides the type, age,throughputs (mmscfd), and the number ofcomponents for the four plants. The survey at eachfacility included screening to detect leaks; measuringemission rates from leakers and from continuous flowsand emergency vents during passive periods; countingsurveyed equipment components; measuring residualgas flare rates; testing natural gas-fueled combustionequipment; sampling process and waste streams;developing an emissions inventory; determining site-specific average emission factors for fugitive leaks; andpreparing cost-benefit analyses to identify controlopportunities.

Equipment components on all process, fuel, and wastegas systems were screened for leaks. Surveyedcomponents included flanged and threadedconnections, valves, pressure relief devices, open-ended lines, blowdown vents, instrument fittings,regulator and actuator diaphragms, compressor seals,compressor crankcase vents, engine crankcase vents,sewer drains, and sump and drain tank vents. Leakdetection was conducted with bubble tests using soapsolution, portable hydrocarbon gas detectors, and anultrasonic leak detector. Bubble tests were performedon most components because that is the most rapidscreening test. Values greater than 10,000 ppm wereconsidered to be leaks. Leaking components weretagged; the specific source and date were noted; andmeasurements were taken.

The Hi-FlowTM Sampler was the primary method used to determine emission rates. This device wasdeveloped by GTI as an economic means ofmeasuring the emission rate from leaking componentswith sufficient accuracy to allow an objective cost-benefit analysis of each repair opportunity. Relative tothe two-orders-of-magnitude error rates (plus orminus) of the Method 21 correlation equations, the

continued on page 9

Throughput Number of Plant No. Type Age (mmscfd) Components

1 sweet 35 54 16,050

2 sweet 50 60 14,424

3 sweet 20 210 56,463

4 sour 35 120 14,168

Table 1 Summary of Surveyed Plants

Natural Gas STAR Partner Update ■ Summer 2001 3

New Natural Gas STAR ToolsThe Natural Gas STAR Program is developing three new Web-based tools that will allow companies to analyze benefits of theBest Management Practices (BMPs) and Partner Reported Opportunities (PROs); enable partners to submit their annualreports online; and facilitate the emissions reduction tracking process for partner companies. These tools are expected to beavailable on the Natural Gas STAR Web site in the fall of 2001.

PROGRAM TOOLS

Analyze and Evaluate BMPs and PROsThe Online Analytic Tool will allow companies to performeconomic evaluations of the Program’s BMPs and PROs andestimate potential gas savings. Users will be able to do acustomized site-specific or company-wide evaluation ofselected BMPs and/or PROs that they may be interested inimplementing. These evaluations can then be used in thedecision making process to determine the optimal level ofimplementation of a specific BMP or PRO.

For each BMP or PRO that is being selected, users will beprompted to enter operational information and economicparameters, such as capital cost, operating costs, andcurrent gas price. Where available, the user will be able toselect default values for both economic and operationalinputs. Using this information, the tool will perform aneconomic analysis for the selected BMP or PRO, providingdetails on the total cost, return on investment, paybackperiod, and net present value.

Annual Reporting on the WebThe Online Reporting Tool will provide yet another option forpartners to submit their annual reports. This Web-based toolwill guide the user through the reporting process, makingannual reporting even easier than before. The tool willprompt users to enter company-specific emission reductiondata and then perform various calculations, such as totalemission reductionsand the value of thegas saved. Onlinereporting will be password protected to ensure security of allinformation. Partners will be able to return to partiallycompleted reports and finish them as time allows. Once thereport is complete, partners will be able to print the final formand also submit the report to the Natural Gas STAR Programat the click of a button. Partners who choose not to use theOnline Reporting Tool will still have the option of filling outthe form by hand, filling out the standard form in MS Word,or using their own reporting format.

Collect and Track Company Data from the FieldIn response to requests from partner companies, the Natural Gas STAR Program is developing anemission reduction tracking and data collection tool. This tool will enable implementation managerswith a simple Web-based mechanism to collect information from different facilities across theircompanies, aggregate these data, analyze the results, and generate and submit an annual report. Thetool will allow individuals from different facilities across the company to record project-level emissionreduction information. All data entry can be done at the facility level via the Internet. This password-protected system will allow the implementation manager to run summary reports of the company’semission reduction activity, including summaries of individual practices as well as company-wideactivities. Reports can be shared internally or submitted to the Natural Gas STAR Program as part of theannual reporting process.


PARTNER EXPERIENCES

Lessons Learned Summaries serve as effective guides for implementing Best Management Practices(BMPs) and Partner Reported Opportunities (PROs). In these summaries, Natural Gas STAR partnersshare their experiences in implementing methane emission reduction technologies and practices.Cost/benefit information, helpful implementation tips, and reference sources are provided. TwelveLessons Learned Summaries are currently available on the Natural Gas STAR Web site, under TechnicalSupport Documents. The following are synopses of the two most recently released Lessons LearnedSummaries.

Convert Gas Pneumatic Controls to Instrument Air

Natural Gas STAR WorkshopJoin us at the 8th Annual Natural Gas STARImplementation Workshop October 23-25, 2001 inHouston. During the workshop, EPA will provide anoverview of the program’s accomplishments, introducenew tools, and present awards to outstanding partners.Participants will exchange ideas on research andemission-reduction successes during round tables and insmall sector-oriented discussions. EPA AdministratorChristine Todd Whitman has been invited to give akeynote address and to present this year’s awards, andMr. Arthur E. Smith Jr., VP of Environmental Health &Safety and Environmental Counsel for NiSourceCorporation will give the industry keynote address. Aregistration form is provided on page 11 of this update.We look forward to seeing you there!

Lessons Learned from GAS STAR Partners

Pneumatic instrument systems powered by high-pressurenatural gas are used across the natural gas industry forprocess control. Typical process control applications includepressure, temperature, liquid level, and flow rate regulation.The constant bleed of natural gas from these controllers iscollectively one of the largest sources of methane emissionsin the natural gas industry, estimated at approximately 24billion cubic feet (Bcf) per year from the production sector,16 Bcf from the processing sector, and 14 Bcf per year fromthe transmission sector.

Companies can achieve significant cost savings and methaneemission reductions by converting natural gas-poweredpneumatic control systems to compressed instrument airsystems. Instrument air systems substitute compressed air forthe pressurized natural gas, eliminating methane emissionsand providing additional safety benefits. Cost-effectiveapplications, however, are limited to those field sites withavailable electrical power, either from a utility or self-generated source. Instrument air conversion is mosteconomical when a large number of pneumatic devices areconsolidated in a relatively small area.

Natural Gas STAR Partners have reported savings of up to 70 million cubic feet (Mmcf) per year per facility byreplacing natural gas-powered pneumatic systems withinstrument air systems. This represents annual savings of upto $210,000 per facility. Partners have found that mostinvestments to convert pneumatic systems pay forthemselves in just over one year. Individual savings will vary,depending on design, condition, and specific operatingconditions of the controllers. Per year, individual companieshave recovered an average of 20 Mmcf of methane gas worth $60,000, while their costs of implementationaveraged $50,000. The value of gas saved is based on theassumption that methane gas is worth $3.00 per thousandcubic feet (Mcf). The implementation costs include the costof installing a compressor, dryer, and other accessories, aswell as the cost of annual electricity requirements.


Natural gas transmission and distributioncompanies often need to make new connectionsbetween pipelines to expand or modify theirexisting system. Historically, this has necessitatedshutting down a portion of the system andpurging the gas to the atmosphere to ensure asafe connection. This procedure, referred to as ashutdown interconnect, results in methaneemissions, loss of product and sales, customerinconvenience, and costs associated withevacuating the existing piping system.

Hot tapping is an alternative procedure thatmakes a new pipeline connection while thepipeline remains in service. The hot tapprocedure involves attaching a branchconnection and valve on the outside of anoperating pipeline, and then cutting out thepipeline wall within the branch and removing thewall section through the valve. Hot tappingavoids product loss, eliminates methaneemissions, and prevents disruption of service tocustomers.

While hot tapping is not a new practice, recentdesign improvements have reduced thecomplications and uncertainty that operators mayhave experienced in the past. Several NaturalGas STAR transmission and distribution partnersreport using hot tap procedures regularly—smalljobs are performed almost daily while larger taps(greater than 12 inches) are made two or threetimes per year.

By performing hot taps, Natural Gas STARPartners have achieved methane emissionreductions and increased revenues, whileavoiding transmission and distribution serviceinterruptions. Gas savings are generally sufficientto justify making all new connections to operatinglines by hot tapping. Per year, individualcompanies have recovered 24,440 Mcf ofmethane gas worth $80,160, while their costsaveraged $79,200 the first year, and $43,000 the

Using Hot Taps for In Service Repairfollowing years. The average payback is 12months. Savings include $3.00 per Mcf of gassaved and other expenditures avoided whenoperators use hot taps instead of shutdowns. Thecosts included capital costs and other costs (e.g.,O&M and contract services cost).

New Gas STAR PartnersNatural Gas STAR is pleased to welcome new partners NorthCarolina Natural Gas and Columbia Natural Resources.

North Carolina Natural Gas Company(NCNG) is based in Fayetteville, NorthCarolina and is a subsidiary of Progress

Energy. NCNG provides natural gas services to 173,000 customersin southcentral and eastern North Carolina. The company’s primarybusiness is the sale and transportation of natural gas to residential,commercial, and industrial customers located in 86 towns and citiesand on four municipal gas distribution systems. Visit NCNG’s Website at www.ncng.com.

Columbia Natural Resources (CNR),headquartered in Charleston, WV, is theexploration, production, and gatheringcompany of NiSource Inc. CNR is one of the

largest producers of natural gas and oil in the Appalachian Basin,with more than three million net acreage holdings, a reserve base ofone trillion cubic feet equivalent and nearly 8,500 natural gas andoil wells located in nine states and two Canadian provinces. As anISO-certified company, CNR is committed to an environmental,health, and safety management system of the highest standard. "Weare proud to join EPA's Natural Gas STAR program," said JimAbcouwer, President and CEO of Columbia Natural Resources. "Thisgives us a formal mechanism to continue the progress we havemade over the last decade in reducing methane emissions. It is alsoa great match to our environmental management system, which setsforth a goal of continual improvement." For more information,contact CNR at (304) 353-5000. Information about NiSource Inc.can be found at www.nisource.com.

the natural gas business fromexploration and production totransmission, storage, and distribution,as well as electricity generation, transmission, and distribution.NiSource companies serve a high-growth energy corridor fromthe Gulf of Mexico to the Midwest to New England.

Formerly subsidiaries of ColumbiaEnergy Group, Columbia Gas

Transmission and Columbia GulfTransmission are now part of NiSource Inc. NiSource is aholding company with headquarters in Merrillville, Indiana,whose operating companies engage in virtually all phases of


The Natural Gas STAR Program is continuing its series of case studies focusing on the mechanisms that partner companieshave used to successfully promote and implement a profitable methane emission reduction program. These case studiesprovide insights as to how companies effectively overcome administrative and organizational barriers to joining andimplementing the program. The following are short summaries of the most recent case studies highlighting the implementationefforts of Kerr-McGee Corporation, Columbia Gas and Gulf Transmission, and Unocal Gulf Region USA. The complete versionsof these and other case studies (Keyspan, El Paso Natural Gas, and Texaco Exploration and Production, Inc.) are available onthe Natural Gas STAR Web site, under Technical Support Documents (http://www.epa.gov/gasstar/case_studies.htm).

Kerr-McGee CorporationKerr-McGee Corporation, based in Oklahoma City, Oklahoma, is one ofthe largest U.S.-based independent oil and gas exploration and production

companies. Kerr-McGee operates key facilities onshore inthe United States, in the Gulf of Mexico, and in the UnitedKingdom sector of the North Sea. In 2000, the company’snatural gas sales averaged 531 Mmcf.

Kerr-McGee joined the Natural Gas STAR Program inSeptember 1996. The company’s operations andenvironmental staff developed an implementation plan tofocus the company’s Gas STAR efforts. The plan included(1) identifying program best management practices (BMPs)that the company could integrate into all new facilitieswhere practicable; (2) evaluating the usefulness of theBMPs and partner reported opportunities (PROs) at olderfacilities; and (3) conducting inventories of existing facilitiesto determine and document past methane emissionreduction activities.

Since 1992, Kerr-McGee has reduced methane emissions bymore than 10.8 billion cubic feet (Bcf), of which over 6 Bcfwere identified from an inventory of prior reductions. Thisinventory was instrumental in helping them understand andimprove efficiency at newly acquired properties. At the2000 Annual Gas STAR Workshop, EPA honored Kerr-McGee as the Gas STAR Production Partner of the Year inrecognition of its methane emission reductionaccomplishments. Kerr-McGee attributes its success withGas STAR to these main principles: building alliances amongenvironmental, health, and safety staff, as well as operations,construction, and maintenance divisions; maintaining opencommunications to ensure program awareness throughoutthe company; and involving field personnel to keep theminformed on the issues and the importance of their efforts tothe success of the environmental programs.

Natural GAS STAR Case Studies

Columbia Gas and Columbia Gulf Transmission

IN THESPOTLIGHT


Unocal Gulf Region USAUnocal GulfRegion USA,formerly Spirit Energy, is an explorationand production unit of UnocalCorporation. It focuses on oil and gasresources in the Gulf of Mexico andonshore in Texas, Louisiana, and Alabama.Unocal Gulf Region operates more than200 offshore platforms and about 1,500active wells in numerous onshore andoffshore fields. In 1999, Unocal GulfRegion’s net gas production was 747 Mmcfper day, and net crude oil productionreached 40,000 barrels per day.

Unocal Gulf Region had alreadyimplemented several best managementpractices before it joined the Natural GasSTAR Program in 1998. These activitiesincluded: installation of flash tankseparators on glycol dehydrators;replacement of high-bleed pneumaticdevices; use of compressed air, rather than natural gas, in instrument systems;installation of vapor recovery units;installation of flare systems, consolidationof production tank batteries; and

Before joining the Natural Gas STAR Program, Columbia GulfTransmission and Columbia Gas Transmission created a NaturalGas STAR Steering Team, composed of representatives from alllevels of the company. The Team considered the costs ofimplementing the program, the level of participation to whichthe pipelines could commit, and whether the partnership couldhave a positive environmental impact.

Columbia Gulf Transmission and Columbia Gas Transmissionjoined the Natural Gas STAR Program in 1999. The SteeringTeam began contacting field managers and technicians to assessand catalog methane emission reduction opportunitiescompany-wide. The Steering Team worked with Columbia’sEnvironmental Excellence Program, which “promotes bestpractices and innovative ideas that protect the environmentand bring benefit to the company.” The Environmental

Excellence Program, created in 1996, has saved more than$7.1 million and generated more than 100 new ideas.

Columbia attributes its success to four key elements of theGas STAR implementation plan:

• Integrating the Gas STAR program into existing practicesand programs promotes participation and gives Gas STARinstant credibility.

• Creating a leadership team composed of employees fromall levels and all divisions ensures company-wide buy-in.

• Carefully considering up front the program’s ultimategoals and how it fits into the existing corporate structure.

• Setting goals and objectives, measuring them, andfollowing through to maintain and increase momentumare essential.

performance of fugitive emission tests.From 1991 to 1999, Unocal GulfRegion recovered 640 Mmcf ofmethane emissions, worth $1.9 million.

When Unocal Gulf Region joined theNatural Gas STAR Program, thecompany began promoting the NaturalGas STAR partnership internally bysending its employees reports on thecompany’s successes in reducingmethane emissions and by encouragingthem to think about other methanereduction opportunities. Unocal GulfRegion attributes its success with theNatural Gas STAR Program to four keyfundamentals:

• Stress revenue gains: Manycompanies do not realize thatreducing methane emissions savesmoney.

• Gain management support: This is important for implementingvoluntary programs because it addssignificance to the program andensures employee cooperation.

• Share results: Sharing success storiesencourages teamwork and enthusiasmcompany-wide.

• Form a team: It is often easier toachieve good results when employeeswork together on targeted issues.

Unocal Gulf Region also attributes itssuccess to the implementation of pilotprojects to test new methane emissionreduction activities. The companyconducts a four-step analysis to evaluatethe cost-effectiveness of pilot projects.The steps are (1) establishing thetechnical feasibility, (2) estimating capitalcosts, (3) estimating potential savings, and (4) evaluating the economics of theproject. Pilot projects allow the companyto establish which practices will be themost cost effective to incorporate on alarger scale (i.e., corporate wide). Theseprojects also help determine associatedcosts and savings, timeframes, staffing,and operational requirements before the company invests in large-scaleimprovements.


Partner Reported OpportunitiesThe Natural Gas STAR Programencourages partners to identify,implement, and report on theadditional activities they haveundertaken to reduce methaneemissions that are outside theprogram’s core set of BestManagement Practices (BMPs). Many of these activities, referred to as Partner Reported Opportunities(PROs), have been summarized inone-page fact sheets and are availableon the Natural Gas STAR Web siteunder Technical Support Documents.

To date, over 40 PRO Fact Sheets areavailable, with additional fact sheets indevelopment. Recently, the PRO FactSheets were improved and updatedwith more detailed economic andoperational information.

Partners can use the PRO Fact Sheetsas a guide when analyzing additionaloptions for reducing methaneemissions cost-effectively andimproving operational efficiency. The new fact sheets are organized by emission source (e.g. compressors/engines, pipelines, wells) and byindustry sector, and they providedetailed information in three majorareas. The first section describes thePRO, giving details on cost,economics, and any special operatingconditions. The second sectionexplains how the methane reductionsare achieved and gives information onthe potential methane emissionreductions available by implementingthe PRO. The third section presents aneconomic analysis of the PRO,including information on costs andany additional benefits of the PRO,such as reduced maintenance orincreased operational efficiency.

The following 10 PROs are the mostrecent fact sheet additions and are nowavailable on the Gas STAR Web site.

• Insert Gas Main Flexible Liners.Pulling flexible plastic piping throughleaking cast iron and unprotected steellines prevents underground lines fromleaking and can save 225 Mcf ofmethane gas annually, per mile ofleaking pipeline.

• Isolation Valves by Design.Designing a compressor station so thatisolation valves are placed to minimizeventing by reducing the length of gas-filled piping can save 130 Mcf ofmethane gas per year, based on 2isolation valves positioned to exclude1,000 feet of 24" pipeline at 600 psia.

• Install Excess Flow Valves. Excessflow valves activate upon detection ofhigh-pressure drops (due to a rupturedor severed pipeline) to shut off gasflow in the line, saving about 16 Mcfof methane gas per year, based on 1activation per 350 valves in a 1/2" 50psig service line.

• Move Fire Gates In at CompressorStations. Moving fire gate valvescloser to compressor stations reducesemergency gas venting and can save1,700 Mcf of methane gas per stationper year, based on fire gate valvespositioned to avoid blow down of2,000 feet of 24" pipeline at 900 psia.

• Install Evactor. Evactors transfer gasto adjacent, operating pipelines duringpipeline outages, saving 700 Mcf ofmethane gas per year, based on 2miles of 18" pipeline reduced from600 to 50 psig through bleeder vents.

• Replace Glycol Dehydrators withSeparator/In-line Heater/Dehydrator.Cyclone separators and in-line heatersor dehydrators reduce methane gasventing from glycol processing

operations and can save 130 Mcf ofmethane gas per dehydrator peryear, based on dehydrating 10MMcf/day of gas to a level of 4-7 lbsof water per MMcf.

• Require Improvements in GasQuality. Revising gas processingand compression agreements withproducers to require reduced levelsof contaminants can reduce linecleanings and, therefore, gas ventedduring maintenance operations andcan save up to 50 Mcf of methanegas per year, based on 16 fewerfiltration unit blow downs per yearat 600 psia.

• Main/Unit Valves Closed. Closingmain and unit valves prior to blowdown prevents venting of gasbetween the main and unit valves,saving 4,500 Mcf of methane gasper year, based on excluding 1 mileof 24" pipeline at 900 psia 4 timesper year.

• Clock Spring Repair. The use ofclock spring repair to repair pipelineleaks eliminates gas venting andallows for continuous operation ofthe pipeline. This practice can save5,400 Mcf of methane gas per year,based on repairing a 10-foot sectionof a 10-mile 20" pipeline at 800 psi.(although partners have reportedsavings up to 27,500 Mcf perapplication).

• Install Velocity Tubing Strings.Replacing existing tubing withsmaller diameter, high-velocitytubing prevents venting during wellunloading and can save 4,680 Mcfof methane gas per well per year,based on one well blown to theatmosphere bi-weekly.

*Cost and benefits will vary based onsite circumstances.


Sampler yields more accurate data—with an errorrange of 10 to 15 percent. Its operating principle isbased on a variable-rate, induced-flow samplingsystem that captures the emissions from a leakingcomponent. Special attachments ensure totalemissions capture and help prevent interferences fromnearby sources. A dual-element hydrocarbon detectordirectly inserted into the main sample line measureshydrocarbon concentrations ranging from 0.01 to 100percent. Background measurements allow the samplesto be corrected for ambient gas concentrations. Athermal anemometer monitors the mass flow rate ofthe sampled air-hydrocarbon gas mixture.

Emission rates from open-ended lines and vents weremeasured with a precision rotary meter, diaphragmflow meter, or rotameter, depending on the flow rate.In some cases, flows were determined by measuringthe velocity profile across the vent line and flow areaat that point, using a pitot tube, hot-wire anemometer,or thermal dispersion anemometer. Screening at open-ended lines and vents was conducted with ahydrocarbon sensor.

Flows in flare lines were determined by one of twomethods—measuring the velocity profile and flowarea in the line, or back-calculating based on pressuredrops between the flare tip and an upstream point onthe flare line. A portable combustible-gas detector or adetailed lab analysis of the flare gas determined thehydrocarbon concentration.

Performance testing involved testing each natural gas-fueled engine and process heater or boiler to identifyavoidable inefficiencies resulting in excessive fuelconsumption and emissions. The focus was onidentifying situations in which equipment neededtuning or repairs, or was mismatched for the currentprocess demands. Testing involved analyzing the fluegas, measuring the flue gas temperature, obtaining ananalysis of the fuel gas composition, and wherepossible, measuring the flow rate of the fuel gas,combustion air, or flue gas.

continued on page 10

Average emission factors were determined for eachtype of equipment component in service at thesurveyed sites. These factors were calculated bydividing the total emissions from all tested componentsby the total number of components of that type.Emissions from non-leaking components were based onvalues taken from the literature. There were somediscrepancies between the counts in this study andthose provided by the facilities, resulting in emissionfactors that are generally higher than those published inEPA’s protocol for estimating equipment leak emissions.

Total natural gas losses at the four plants areapproximately 501 Mmcf per year, worth $2,225,590per year (based on $4.50 per Mcf, the long-termcontract price for natural gas at the time the study wascompleted). Figure 1 shows the relative distribution ofnatural gas losses at the case study sites by sourcecategory. The losses include direct leakage or venting ofnatural gas to the atmosphere and losses in the processthat yield no benefit. Leaking equipment componentsand leakage into flare systems are the major sources ofnatural gas losses at the plants. Open-ended lines


Fig. 1 Distribution of Natural Gas Lossesby Emissions Source



contribute most of the emissions from equipment leaks, although valves, connectors, and compressorseals are also important sources as shown in Figure 2.

Fig. 2 Emissions from FugitiveEquipment Leaks

Fig. 3 Methane Emissions fromEconomically Repairable Sources

Practical opportunities for reducing emissions from fugitive equipment leaks and process venting wereidentified and assessed on a source-by-source basis. The sources with the greatest emissions were notnecessarily the most economical to repair or replace. About three-quarters of the identified natural gaslosses at the surveyed gas plants were economical to avoid or recover, based on preliminary estimatesof repair costs, as presented in Figure 3. Once leaks are repaired, however, they are assumed to leakagain at some point. The mean time between failures depends on the type, style, and quality of thecomponent; the demands of the specific application; component activity levels (number of valveoperations); and maintenance practices at the site. In a formal leak detection and repair program, meantimes between failures are tracked continuously and used to identify problem service applications andto evaluate the potential need for changes to component specifications and maintenance practices.

"Identification and Evaluation of Opportunities To Reduce Methane Losses at Four Processing Plants," a Draft Report from the GasTechnology Institute and Clearstone Engineering, May 25, 2001.

For more information, contact Jeff Panek at GTI, 847-768-0884, or Carrie Henderson at EPA, 202-564-2318. Copies of the studyreport will be made available when finalized.



DOCUMENT REQUEST FORM

PLEASE INDIC ATE WHICHMATERIALS YOU WOULDLIKE TO RECEIVE:

Name & Title: _________________________________________________

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E-Mail Address:________________________________________________

Telephone #:_______________________ FAX #: __________________

Date Requested: _______________________________________________

Date Info Needed: _____________________________________________

FedEx/UPS # (if info needed asap): ______________________________

Please fax to your STAR ServiceRepresentative at703-841-1440or directly to theNatural Gas STAR Program at202-565-2079.

LESSONS LEARNED

________ 1. Directed Inspection and Maintenance at Compressor Stations________ 2. Directed Inspection and Maintenance at Gate Stations and Surface Facilities________ 3. Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry________ 4. Installation of Flash Tank Separators________ 5. Reducing Methane Emissions from Compressor Rod Packing Systems________ 6. Reducing Emissions When Taking Compressors Off-Line________ 7. Installing Vapor Recovery Units on Crude Oil Storage Tanks________ 8. Replacing Wet Seals with Dry Seals in Centrifugal Compressors________ 9. Reducing the Glycol Circulation Rates in Dehydrators________ 10. Replacing Gas-Assisted Glycol Pumps with Electric Pumps________ 11. Installing Plunger Lift Systems in Gas Wells________ 12. Using Pipeline Pump-Down Techniques To Lower Pipeline Pressure Before Maintenance________ 13. Convert Gas Pneumatic Controls to Instrument Air________ 14. Using Hot Taps for In Service Repair

STAR IMPLEMENTATION TOOLS

________ Video-Production________ Video-Transmission/Distribution________ Case Study-El Paso Natural Gas________ Case Study-Brooklyn Union/Keyspan Energy________ Case Study-Texaco Exploration and

Production, Inc.________ Case Study-Columbia Gas and Columbia Gulf

Transmission________ Case Study-Kerr-McGee Corporation________ Case Study-Unocal Gulf Region USA

OUTREACH MATERIALS

________ Natural Gas STAR Program Brochure________ Natural Gas STAR Marketing Package________ Natural Gas STAR Communications

Toolkit________ STAR Partner Update, Summer 1998________ STAR Partner Update, Spring 1999________ STAR Partner Update, Winter 1999________ STAR Partner Update, Fall 2000________ STAR Partner Update, Winter 2001

Most of these materials are available on the Internet at www.epa.gov/gasstar