Lessons Learned NaturalGas EPA POLLUTION PREVENTER SBl N \ CD From Natural Gas STAR Partners DIRECTED INSPECTION AND MAINTENANCE AT COMPRESSOR STATIONS Executive Summary The U.S. natural gas transmission network contains more than 279,000 pipeline miles. Along this network, com- pressor stations are one of the largest sources of fugitive emissions, producing an estimated 50.7 billion cubic feet (Bcf) of methane emissions annually from leaking compressors and other equipment components such as valves, flanges, connections, and open-ended lines. Data collected from Natural Gas STAR partners demon- strates that 95 percent of these methane emissions are from 20 percent of the leaky components at compressor stations. Implementing a directed inspection and maintenance (DI&M) program is a proven, cost-effective way to detect, measure, prioritize, and repair equipment leaks to reduce methane emissions. A DI&M program begins with a baseline survey to identify and quantify leaks. Repairs that are cost-effective to fix are then made to the leaking components. Subsequent surveys are based on data from previous surveys, allowing operators to concentrate on the components that are most likely to leak and are profitable to repair. Baseline surveys of Natural Gas STAR partners' transmission compressor stations found that the majority of fugitive methane emissions are from a rela- tively small number of leaking components. Natural Gas STAR transmission partners have reported significant savings and methane emissions reductions by implementing DI&M. One 1999 study that looked at 13 compressor stations demonstrated that the average value of gas that could be saved by instituting a DI&M program at a compressor station is $88,239 per year, at an average cost of $26,248 per station. Leak Source Compressor Station Components Potential Average Gas Savings (Mcf/yr) 29,413 per com- pressor station Method for Emissions Reduction Identify and measure leaks. Make cost- effective repairs. Value of Gas Saved ($/yr)1 $88,239 per com- pressor station Average Initial Implementation Cost2 $26,248 per com- pressor station Potential Average First Year Savings $61,991 per com- pressor station 1Gas valued at $3.00 per Mcf. Total cost for initial baseline survey and leak repairs. This is one of a series of Lessons Learned Summaries developed by EPA in cooperation with the natural gas industry on superior applications of Natural Gas STAR Program Best Management Practices (BMPs) and Partner Reported Opportunities (PROs). ------- Introduction Technology Background Transmission compressor stations boost pressure at various points along natural gas transmission pipelines to overcome the pressure losses that occur along a long distance pipeline. The more than 279,000 miles of natu- ral gas transmission pipeline are supported by approximately 1,790 com- pressor stations. Most compressor stations are equipped with either gas- fired reciprocating compressors or centrifugal compressors (turbines). These compressors and associated components, such as pipelines and valves, are subjected to substantial mechanical and thermal stresses, and as a result are prone to leaks. A DI&M program at compressor stations can reduce methane emissions and yield significant savings by locating leaking components and focusing maintenance efforts on the largest leaks that are profitable to repair. Subsequent emissions surveys are directed towards the site components that are most likely to leak, as well as cost-effective to find and fix. DI&M programs begin with a comprehensive baseline survey of all equip- ment components at the compressor stations in the transmission system. Operators first identify leaking components and then measure the emissions rate for each leak. The repair cost for each leak is evaluated with respect to the expected gas savings and other economic criteria such as payback peri- od. The initial leak survey results and equipment repairs are then used to direct subsequent inspection and maintenance efforts. Leak Screening Techniques Leak screening in a DI&M program may include all components in a com- prehensive baseline survey, or may be focused only on the components that are likely to develop significant leaks. Several leak screening techniques can be used: * Soap Bubble Screening is a fast, easy, and very low-cost method to screen for leaks. This technique involves spraying a soap solution on small, accessible components such as threaded connections. Soaping is effective for locating loose fittings and connections, which can be tightened on the spot to fix the leak, and for quickly checking the tight- ness of a repair. Operators can screen about 100 components per hour by soaping. * Electronic Screening using small hand-held gas detectors or "sniff- ing" devices provides another fast and convenient way to detect accessible leaks. Electronic gas detectors are equipped with catalytic oxidation and thermal conductivity sensors designed to detect the presence of specific gases. Electronic gas detectors can be used on ------- larger openings that cannot be screened by soaping. Electronic screening is not as fast as soap screening (averaging 50 components per hour), and pinpointing leaks can be difficult in areas with high ambient concentrations of hydrocarbon gases. * Organic Vapor Analyzers (OVAs) and Toxic Vapor Analyzers (TVAs) are portable hydrocarbon detectors that can also be used to identify leaks. An OVA is a flame ionization detector (FID), which measures the concentration of organic vapors over a range of 9 to 10,000 parts per million (ppm). A TVA combines both an FID and a photoionization detector (PID) and can measure organic vapors at concentrations exceeding 10,000 ppm. TVAs and OVAs measure the concentration of methane in the area around a leak. * Acoustic Leak Detection uses portable acoustic screening devices designed to detect the acoustic signal that results when pressurized gas escapes through an orifice. As gas moves from a high-pressure to a low-pressure environment across a leak opening, the turbulent flow produces an acoustic signal, which is detected by a handheld sensor or probe, and read as intensity increments on a meter. Although acoustic detectors do not measure leak rates, they provide a relative indication of leak sizea high intensity or "loud" signal corresponds to a greater leak rate. Acoustic screening devices are designed to detect either high frequency or low frequency signals. High Frequency Acoustic Detection is best applied in noisy environ- ments where the leaking corn- Exhibit 1: Acoustic Leak Detection iij ponents are accessible to a hand-held sensor. As shown in Exhibit 1, an acoustic sen- sor is placed directly on the equipment orifice to detect the signal. Alternatively, Ultrasound Leak Detection is an acoustic screening method that detects airborne ultrasonic signals in the fre- quency range of 20 kHz to 100 kHz. Ultrasound detec- tors are equipped with a hand- held acoustic probe or scanner that is aimed at a potential leak source from a distance up to 100 feet. Leaks are pinpointed by listening for an increase in sound intensity through headphones. Ultrasound detectors can be sensitive to back- Source: Physical Acoustics Corp. ------- ground noise, although most detectors typically provide frequency tun- ing capabilities so that the probe can be tuned to a specific leak in a noisy environment. Leak Measurement Techniques An important component of a DI&M program is measurement of the mass emissions rate or leak volume of identified leaks, so that manpower and resources are allocated only to the significant leaks that are cost-effective to repair. Four leak measurement techniques can be used: * Toxic Vapor Analyzers (TVAs) can be used to estimate mass leak rate. The TVA-measured concentration in ppm is converted to a mass emissions rate by using a correlation equation. A major drawback to TVAs for methane leak measurement is that the correlation equations are typically not site-specific. The mass leak rates predicted by general TVA correlation equations have been shown to deviate from actual leak rates by as much as three or four orders of magnitude. Similarly, a study conducted jointly by Natural Gas STAR partners, EPA, the Gas Research Institute (GRI-now GTI, the Gas Technology Institute), and the American Gas Association (AGA) found that TVA concentration thresholds, or "cut-off" values, such as 10,000 ppm or 100,000 ppm, are ineffective for determining which methane leaks at compressor sta- tions are cost-effective to fix. Because the use of general TVA correla- tion equations can increase measurement inaccuracy, the develop- ment and use of site-specific correlations will be more effective in determining actual leak rates. * Bagging Techniques are commonly used to measure mass emissions from equipment leaks. The leaking component or leak opening is enclosed in a "bag" or tent. An inert carrier gas such as nitrogen is conveyed through the bag at a known flow rate. Once the carrier gas attains equilibrium, a gas sample is collected from the bag and the methane concentration of the sample is measured. The mass emis- sions rate is calculated from the measured methane concentration of the bag sample and the flow rate of the carrier gas. Leak rate meas- urement using bagging techniques is a fairly accurate (within ± 10 to 15 percent), but slow process (only two or three samples per hour). Although bagging techniques are useful for direct measurement of larger leaks, bagging may not be possible for equipment components that are very large, inaccessible, and unusually shaped. * High Volume Samplers capture all of the emissions from a leaking component to accurately quantify leak emissions rates. Exhibit 2 ------- Exhibit 2: Leak Measurement Using a Might Volume Sampler Source: Oil & Gas Journal, May 21, 2001 shows leak measurement using a high volume sampler. Leak emissions, plus a large volume sample of the air around the leaking component, are pulled into the instrument through a vacuum sampling hose. High volume samplers are equipped with dual hydrocarbon detec- tors that measure the concen- tration of hydrocarbon gas in the captured sample, as well as the ambient hydrocarbon gas concentration. Sample measurements are corrected for the ambient hydrocarbon concentration, and a mass leak rate is calculated by multiplying the flow rate of the measured sample by the difference between the ambient gas concentration and the gas concentration in the measured sample. Methane emissions are obtained by calibrating the hydrocarbon detectors to a range of con- centrations of methane-in-air. High volume samplers are equipped with special attachments designed to ensure complete emissions capture and to prevent inter- ference from other nearby emissions sources. High volume samplers measure leak rates up to 8 standard cubic feet per minute (scfm), a rate equivalent to 11.5 thousand cubic feet per day (Mcfd). Leak rates greater than 8 scfm must be measured using bagging techniques or flow meters. Two operators can measure thirty components per hour using a high volume sampler, compared with two to three measure- ments per hour using bagging techniques. * Rotameters and other flow meters are used to measure extremely large leaks that would overwhelm other instruments. Flow meters typi- cally channel gas flow from a leak source through a calibrated tube. The flow lifts a "float bob" within the tube, indicating the leak rate. Because rotameters are bulky, these instruments work best for open- ended lines and similar components, where the entire flow can be channeled through the meter. Rotameters and other flow metering devices can supplement measurements made using bagging or high volume samplers. Exhibit 3 summarizes the application and usage, effectiveness, and approxi- mate cost of the leak screening and measurement techniques described above. ------- Exhibit 3: Screening and Measurement Techniques Instrument/Technique Soap Solution Electronic Gas Detectors Acoustic Detectors/ Ultrasound Detectors TVA (flame ionization detector) Bagging High Volume Sampler Rotameter Application and Usage Small point sources, such as connectors. Flanges, vents, large gaps, and open-ended lines. All components. Larger leaks, pressured gas, and inaccessible components. All components. Most accessible components. Most accessible components (leak rate <11.5Mcfd). Very large leaks. Effectiveness Screening only. Screening only. Screening only. Best for screening only. Measurement requires site- specific leak size correlations. Measurement only. Time- consuming. Screening and measurement. Measurement only. Approximate Capital Cost $100-$500 (depends on cost of facility) Under $1,000 $1,000-$20,000 (depends on instrument sensitivity, size, associated equipment) Under $10,000 (depends on instrument sensitivity/size) Under $10,000 (depends on sample analysis cost) > $10,000 Under $1,000 ------- Decision Process A DI&M program is implemented in four steps: (1) conduct a baseline sur- vey; (2) record the results and identify candidates for cost-effective repair; (3) analyze the data, make the repairs, and estimate methane savings; and (4) develop a survey plan for future inspections and follow-up monitoring of leak-prone equipment. Step 1: Conduct Baseline Survey. A DI&M program typically begins with baseline screening to identify leaking components. As the leaking compo- nents are located, accurate leak rate measurements are obtained using bag- ging techniques, a high volume sampler, or TVAs that have site-specific con- centration correlations. Partners have found that leak measurement using a high volume sampler is cost-effec- tive, fast, and accurate. 1. 2. 3. 4. Decision Steps for DI&M Conduct baseline survey. Record results and identify candi- dates for repair. Analyze data and estimate savings. Develop a survey plan for future DI&M. The cost of the baseline sur- vey to find and measure leaks at the 13 compressor sta- tions included in the 1999 EPA/GRI/PRCI study was approximately $6,900 per compressor station or about $2.55 per component. A baseline survey that focuses only on leak screening is substantially less expensive. However, leak screening alone does not provide the information needed to make cost- effective repair decisions. Partners have found that follow-up surveys in an ongoing DI&M program cost 25 percent to 40 percent less than the initial survey because subsequent surveys focus only on the components that are likely to leak and are economic to repair. For some equipment components, leak screening and measurement can be accomplished most efficiently dur- ing a regularly scheduled DI&M survey program. For other components, sim- ple and rapid leak screening can be incorporated into ongoing operation and maintenance procedures. Some operators train maintenance staff to con- duct leak surveys, others hire outside consultants to conduct the baseline survey. Step 2: Record Results and Identify Candidates for Repair. Leak meas- urements collected in Step 1 must be evaluated to pinpoint the leaking com- ponents that are cost-effective to repair. Leaks are prioritized by comparing the value of the natural gas lost with the estimated cost in parts, labor, and equipment downtime to fix the leak. Some leaks can be fixed on the spot by simply tightening a connection. Other repairs are more complicated and require equipment downtime or new parts. For these repairs, operators may ------- choose to attach identification markers, so that the leaks can be fixed later if the repair costs are warranted. Repair costs for components such as valves, flanges, connections, and open-ended lines are likely to be determined by the size of the component, with repairs to large components costing more than repairs to small components. Some large leaks may be found on equipment normally scheduled for routine maintenance, in which case the maintenance schedule may be advanced to repair the leak at no additional cost. As leaks are identified and measured, operators should record the baseline leak data so that future surveys can focus on the most significant leaking components. The results of the DI&M survey can be tracked using any con- venient method or format. The information that operators may choose to collect include: * An identifier for each leaking component. * The component type (for example, blowdown OEL). * The measured leak rate. * The survey date. * The estimated annual gas loss. * The estimated repair cost. This information will direct subsequent emissions surveys, prioritize future repairs, and track the methane savings and cost-effectiveness of the DI&M program. Understanding of fugitive methane emissions from leaking equipment at compressor stations has evolved since the mid-1990s as the result of a series of field studies sponsored by EPA, GRI, and AGA's Pipeline Research Committee International (PRCI). A study published in 1996 reported on emissions factors from emissions measurements at six compressor stations in 1994. An extension of this study published by Indaco Air Quality Services in 1995 reported on the results of emissions surveys of 27,212 components at 17 compressor stations. The third study published in 1999 by EPA, GRI, and the PRCI is the most comprehensive to date, and surveyed fugitive emissions from 34,400 components at 13 compressor stations. The compressor stations surveyed in the 1999 EPA/GRI/PRCI study range in size from stations with 15 reciprocating compressors to stations with only two reciprocating compressors. Three of the compressor stations surveyed contain two centrifugal compressors (turbines) each, and no reciprocating ------- compressors. Two stations contain both reciprocating compressors and tur- bines. The compressor stations equipped with reciprocating compressors contain an average of seven reciprocating compressors per station. Compressor stations with turbines contain an average of two turbines per station. The compressors are typically installed in parallel so that individual compressors can be on- or off-line as needed, and each compressor can be isolated and depressurized as needed for maintenance. The inlet pressure at the compressor stations typically ranges from 500 psig to 700 psig, while the outlet pressure ranges from 700 psig to 1,000 psig. On average, the number of components surveyed per compressor station was 2,707, and 5 percent of these components were found to be leaking. The total leak rates at the 13 compressor stations ranged from 385 Mcf per year to 200,000 Mcf per year. The average total station leak rate was 41,000 Mcf per year. The largest 10 percent of leaks were found to contribute more than 90 percent of emissions. Exhibit 4 summarizes average emissions fac- tors for the compressor station components. At the site emitting 200,00 Mcf per year, a single source accounted for 142,000 Mcf per year of emissionsa vent from the gas system used to control compressor unloaders. This was not a significant source of gas emissions at the other sites. The compressor station with the extraordinary emissions was otherwise quite average, containing only seven reciprocating compressors. The experience of this station underscores the value of DI&M for detecting huge and costly gas leaks at compressor stations of all sizes. Exhibit 5 illustrates the average leak repair costs for the 13 compressor sta- tions included in the 1999 EPA/GRI/PRCI study. The repair costs include the fully loaded cost of labor as well as parts and materials. ------- Exhibit 4: Average Fugitive Emissions Factors For Equipment Leaks From Compressor Station Components COMPONENTS UNDER MAIN LINE PRESSURE1 Component Description Ball/Plug Valve Blowdown Valve Compressor Cylinder Joint Packing Seal- Running Packing Seal - Idle Compressor Valve Control Valve Flange Gate Valve Loader Valve Open-Ended Line (DEL) Pressure Relief Valve (PRV) Regulator Starter Gas Vent Connector -Threaded Centrifugal Seal - Dry Centrifugal Seal - Wet Unit Valve3 ON COMPRESSOR Natural Gas Emissions Factor2 (Mcf/Yr/Comp.) 0.64 (±1.04) 9.9 (±11.1) 865 (± 247) 1,266 (±552) 4.1 (± 3.8) 0.81 (± 0.89) 17.2 (±5.6) 0.74 (± 0.46) Total No. Components Measured 189 148 178 42 2,324 864 940 1,625 OFF COMPRESSOR Natural Gas Emissions Factor2 (Mcf/Yr/Comp.) 5.33 (±3.71) 207.5 (±171.4) 4.26 (±7.13) 0.32 (±0.21) 0.61 (±0.43) 81. 8 (±79.6) 57.5 (±63.2) 0.2 (± 0.2) 40.8 (± 43.3) 0.6 (± 0.3) 62.7 (± 66.3) 278 3,566 Total No. Components Measured 2,406 57 33 2,727 1,476 168 117 171 5 10,338 14 2 12 COMPONENTS UNDER FUEL GAS PRESSURE4 Ball/Plug Valve Control Valve Flange Fuel Valve Gate Valve Open-Ended Line Pneumatic Vent Regulator Connector Threaded ON COMPRESSOR 0.1 (±0.1) 27.6 (± 13.5) 1.21 (±1.66) 414 479 2,511 OFF COMPRESSOR 0.51 (± 0.37) 2.46 (±3.89) 0.2 (±0.2) 0.43 (± 0.36) 2.53 (±2.1 9) 76.6 (±118.1) 4.03 (±3.98) 0.32 (±0.1 6) 654 69 1,650 640 42 14 103 3,654 10 1Main line pressure range from 500 psig to 1,000 psig. Emission factors with associated 95% confidence intervals. 3Unit valve leakage is measured on depressurized compressors. Most of the compressors surveyed remained pressurized when taken off-line. fuel gas pressure is typically 70 psig to 100 psig. The components on the compressor are located at the top of pistons on reciprocating compres- sors and are subjected to substantial vibration and heat. These components only leak when the compressor is running. Source: Indaco Air Quality Services, Inc., 1999, Cost Effective Leak Mitigation at Natural Gas Transmission Compressor Stations, Report No. PRC- 246-9526. ------- Exhibit 5. Average Repair Cost and Payback Period For Equipment Leaks At Compressor Stations Component Description Ball Valves -1" Bull Plug on Valve Compressor Blow Down Compressor Blow Down Compressor Valve Cap Flange -30" Flange - 6" Fuel Valve Gate Valve Grease Port Head End of Compressor Loader Valve Flange Loader Valve Stem Needle Valve DEL on Valve Pig Receiver Door Pipe Thread Fitting Plug Valves Pressure Relief Valve -1" PRV Flange Rod Packing Rod Packing Rod Packing Station Blow Down Tubing Union Unit Valve Unit Valve -10" Plug Type of Repair Replace Add Teflon Tape & Tighten Replace Rebuild Replace Gasket Change Gasket Change Gasket Replace Teflon Repack Replace Pull & Change Gaskets Replace Gasket Rebuild Replace Grease Tighten Tighten, Add Teflon Tape Grease Replace Tighten Change Packing Rings Without Removing Rods Pull Packing Case and Rods to Change Rings, Rework Packing Case Pull Packing Case and Rods to Change Rings, Rework Packing Case & Replace Rod Reverse Plug Tighten Tighten Clean & Inject Sealant Replace Average Cost $120 $15 $600 $200 $60 $1,250 $300 $200 $40 $80 $450 $80 $300 $100 $45 $120 $30 $40 $1,000 $40 $750 $2,600 $ 5,600 $720 $10 $10 $70 $2,960 Source: Indaco Air Quality Services, Inc., 1999, Cost Effective Leak Mitigation at Natural Gas Transmission Compressor Stations, Report No. PRC-246-9526. 11 ------- Step 3: Analyze Data and Estimate Savings. Cost-effective repair is a criti- cal part of successful DI&M programs because the greatest savings are achieved by targeting only those leaks that are profitable to repair. In all cases, the value of the gas saved must exceed the cost to find and fix the leak. Partners have found that an effective way to analyze baseline survey results is to create a table listing all leaks, with their associated repair cost, expected gas savings, and expected life of the repair. Using this information, economic criteria such as net present value or payback period can be easily calculated for each leak repair. Partners can then decide which leaking com- ponents are economic to repair. Exhibit 6 shows the total potential savings at the 13 compressor stations included in the 1999 EPA/GRI/PRCI study, based on fixing only the leaks with an estimated payback of less than one year. Repair life is assumed to be two years. For most sites the initial expense of the baseline survey and repair costs were quickly recovered in gas savings. For two sites, (station 11 and station 12) the baseline survey and repair costs never payback within the two-year repair period because the total leakage at these compressor stations is low. This example illustrates that a comprehensive DI&M baseline survey, which includes all of a partner's transmission compressor stations, may uncover a few individual stations where the baseline DI&M survey may not be prof- itable. If DI&M program is profitable for the transmission system as a whole, the information gained from the few unprofitable stations is still useful. At the very least, the unprofitable compressor stations for DI&M are identified and managed separately in future surveys. Such stations may be excluded from future DI&M surveys, surveyed less frequently, or screened with more highly focused and cost-effective techniques to reduce costs. 12 ------- si g. 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An effective DI&M survey plan should include the following ele- ments: * A list of components to be screened and tested, as well as the equip- ment components to be excluded from the survey. * Leak screening and measurement tools and procedures for collecting, recording, and accessing DI&M data. * A schedule for leak screening and measurement. * Economic guidelines for leak repair. * Results and analysis of previous inspection and maintenance efforts, which will direct the next DI&M survey. Operators should develop a DI&M survey schedule that achieves maximum cost-effective methane savings yet also suits the unique characteristics of a facility (e.g., the age of the compressors, the number and size of reciprocat- ing and centrifugal compressors in service, the line pressure and the fuel gas pressure). Some partners schedule DI&M surveys based on the anticipated life of repairs made during the previous survey. Other partners base the fre- quency of follow up surveys on maintenance cycles or the availability of resources. Since a DI&M program is flexible, if subsequent surveys show numerous large or recurring leaks, the operator can increase the frequency of the DI&M follow-up surveys. Follow-up surveys may focus on compo- nents repaired during previous surveys, or on the classes of components identified as most likely to leak. Over time, operators can continue to fine- tune the scope and frequency of surveys as leak patterns emerge. Estimated Savings The potential gas savings from implementing DI&M programs at compressor stations will vary depending on the size, age, equipment, and operating characteristics of the compressor stations. Natural Gas STAR partners have found that the initial expense of a baseline survey is quickly recovered in gas savings. Exhibit 7 presents three partners' experience in implementing DI&M pro- grams. Note that the benefit/cost ratio is positive in each case, but varies widely from 1.7:1 to 95:1. 14 ------- Exhibit 7: Natural Gas STAR Transmission Partners' Experience Company A: Fifteen compressor stations were surveyed annually. Total costs for the DI&M survey and repairs were $350 per station. Leaks were most commonly found at unit valves. Gas savings totaled 166,010 Mcf, averaging 11,067 Mcf per station. Total Gas Savings Total Cost of Survey and Repairs $498,030 $5,250 Net Savings Year One Benefit/Cost Ratio $492,780 95:1 Company B: Two compressor stations were surveyed quarterly. Survey costs averaged $200 per station. Leaks were most commonly found at valve stem packings, shaft seals, and flange leaks. Of 24 leaks detected, 23 were repaired at an average cost of $50. Gas savings totaled 17,080 Mcf, averag- ing 8,540 Mcf per station. Total Gas Savings Total Survey Costs Total Cost of Repairs $51,240 $1,600 $1,150 Net Savings $48,490 Year One Benefit/Cost Ratio 19:1 Company C: Sixty-seven compressor stations were surveyed (survey sched- ule included both quarterly and annual surveys, depending on the station). Leaks were most commonly found at gaskets and loose fittings, as well as at compressor valves and packing. Close to 1,150 repairs were made. Gas sav- ings totaled 132,585 Mcf, averaging 1,978 Mcf per station. Total Gas Savings Total Survey Costs Total Cost of Repairs $397,755 $176,175 $57,180 Net Savings $164,400 Year One Benefit/Cost Ratio 1.7:1 Assumes gas price of $3/Mcf. 15 ------- Lessons Learned DI&M programs can reduce survey costs and enhance profitable leak repair. Targeting problem stations and components saves time and money needed for future surveys and helps identify priorities for a leak repair schedule. The principal lessons learned from Natural Gas STAR partners are: * A relatively small number of large leaks contribute most of a compres- sor station's fugitive emissions. * Screening concentrations do not accurately identify the largest leaks, nor do they provide the information needed to identify which leaks are cost-effective to repair. Effective leak measurement techniques must be used to obtain accurate leak rate data. * A cost-effective DI&M program will target the components that are most likely to leak and are economic to repair. * Natural Gas STAR partners have also found that some compressor stations are more leak-prone than others. Tracking of DI&M results may show that some compressor stations may need more frequent follow-up surveys than other stations. * Partners have found it useful to look for trends, asking questions such as "Do gate valves leak more than ball valves?" and "Does one station leak more than another?" * Re-screen leaking components after repairs are made confirms the effectiveness of the repair. A quick way to check the effectiveness of a repair is to use the soap screening method. * Institute a "quick fix" step that involves making simple repairs to simple problems (e.g., loose nut, valve not fully closed) during the survey process. * Develop a system for repairing the most severe leaks first, incorporat- ing repair of minor leaks into regular O&M practices. * Focus future surveys on stations and components that leak most. * Record methane emissions reductions at each compressor station and include annualized reductions in Natural Gas STAR Program reports. References Bascom-Turner Instruments, personal communication. Foxboro Environmental Products, personal communication. Gas Technology Institute (formerly the Gas Research Institute), personal communication. Henderson, Carolyn, U.S. EPA Natural Gas STAR Program, personal com- munication. 16 ------- Howard, louche, Indaco Air Quality Services, personal communication. Indaco Air Quality Services, Inc., 1995, A High Flow Rate Sampling System for Measuring Leak Rates at Natural Gas Facilities. Report No. GRI- 94/0257.38. Gas Technology Institute, Chicago, Illinois. Indaco Air Quality Services, Inc., 1995, Leak Rate Measurements at U.S. Natural Gas Transmission Compressor Stations. Report No. GRI- 94/0257.37. Gas Technology Institute, Chicago, Illinois. Indaco Air Quality Services, Inc., 1999, Cost Effective Leak Mitigation at Natural Gas Transmission Compressor Stations, Report No. PRC-246-9526. PRC International (report available from the American Gas Association, Arlington, Virginia). King Instrument Company, personal communication. Omega Engineering, personal communication. Physical Acoustics Corporation, personal communication. Radian International, 1996, Methane Emissions from the Natural Gas Industry, Volume 2, Technical Report, Report No. GRI-94/0257.1. Gas Technology Institute, Chicago, Illinois. Radian International, 1996, Methane Emissions from the Natural Gas Industry, Volume 8, Equipment Leaks, Report No. GRI-94/0257.1. Gas Technology Institute, Chicago, Illinois. Thermo Environmental Instruments Inc., personal communication. Tingley, Kevin, U.S. EPA Natural Gas STAR Program, personal communication. UE Systems Inc., personal communication. U.S. Environmental Protection Agency, 1994 - 2001, Natural Gas STAR Program, Partner Annual Reports. U.S. Environmental Protection Agency, 1995, Natural Gas STAR Program Summary and Implementation Guide for Transmission and Distribution Partners. 17 ------- &EPA United States Environmental Protection Agency Air and Radiation (6202J) 1200 Pennsylvania Ave., NW Washington, DC 20460 EPA430-B-03-008 October 2003 ------- |