# Lessons Learned

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 mile s. Along this network, compressor 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 demonstrates 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 likel y to leak and are profitable to repair. Baseline surveys of Natural Gas STAR partners' transmission compressor statio ns found that the majority of fugitive methane emissions are from a relatively 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.



### Introduction

Transmission compressor stat ions boost pressure at various points along natural ga s transmission pipelines to overcome the pressure losses that occur along a long distance pipeline. The more than 279,000 miles of natural gas transmission pipeline ar e supported by approximately 1,790 compressor 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. Additionally, compressor station op erations place sign ificant pressure, thermal, and mechanical st resses on blowdown valves. These stresses wear down valve components (e.g., plugs, seals, seats) making them significant methane emissions

sources.

A DI&M program at compressor stations can reduce methane emissions and yiel d significant savings by locating leaking components and focusing maintenance efforts on the largest leaks that are profitable to repair. Subsequent emissions survey s are directed towards the site components that are most likely to leak, as well as cost
-effective to find and fix.



### Technology Background

DI&M programs begin with a comprehensive baseline survey of all equipment components at the compressor

Method for Reducing

Natural Gas Losses Volume of

Natural Gas Savings (Mcf) Value of Natural Gas Savings ($) Implementation Cost ($) 1 Payback (Months)

$3 per

Mcf $5 per

Mcf $7 per

Mcf $3 per

Mcf $5 per

Mcf $7 per

Mcf

Identify and measure

leaks.

Make cost-effective repairs. 29,413 per compressor station $88,239 $147,065 $205,891 $26,248 4 Months 3 Months 2 Months

1 Average total cost for initial baseline survey and leak repairs. 

### Economic and Environmental Benefits

1

# Directed Inspection and Mainte nance at Compressor Stations
(Cont’d)

Methane Content of Natural Gas

The average methane content of natural gas varies by natural gas industry sector. The Natural Gas STAR Program assumes the following methane content of natural gas when estimating methane savings for Partner Reported Opportunities.

Production 79 %

Processing 87 %

Transmission and Distribution 94 %

stations in the transmission system. Operators first identify leaking components and then measure the
emissions rate for each leak. Th e repair cost for each leak is evaluated with respect to the expected gas savings and other economic criteria such as payback period. The initial leak survey results and equipm ent 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 comprehensive baseline survey, or may be focused only on the components that are likely to develop significant leaks. Blowdown vent stacks are normally elevated and inconvenient to access. As a result, it is difficult to test frequently for gas leakage through the blowdown valves, making them good candidates for screening as part of a DI&M program. Several leak screening techniques can be used:

 Soap Bubble Screening is a fast, easy, and very low-cost leak screening technique. Soap bubble screening 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 tightness of a repair. Operators can screen about 100 components per hour by soaping.

 Electronic Screenin g using small hand-held gas detectors or “sniffing” 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 exceedin g 10,000 ppm. TVAs and
OVAs measure the concentration of methane in the
area around a leak.

 Infrared Cameras work according to the principle that hydrocarbon emissions absorb infrared light in a certain wavelength. Infrared (IR) cameras use this characteristic to detect the presence of gas emissions from equipment by converting the scanned area into a moving image in real time such that the gas plumes are visible due their absorption of the IR light. Because of this, an IR camera is able to screen hundreds of components per hour. An additional advantage is the ability to screen inaccessible equipment: components in confined spaces or in elevated locations can be screened remotely from an accessible location within viewing distance. In addition, IR cameras can be hand-held for walking surveys of individual components, mounted on trucks and other vehicles for close-range inspection over moderate distances, or mounted on aircraft for aerial inspection to locate major leaks and vents over long distances. While it may not be able to pinpoint individual leaking components with low leak rates, aerial inspection is useful to screen many
miles of transmissi ons pipelines or dispersed equipment to detect plumes from large emissions sources.

 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, turbulent flow produces an acoustic signal, which is detected by a hand-held sensor or probe, and read as intensity 

### Exhibit 1: Acoustic Leak

Detection

Source: Physical Acoustics Corp.

2

# Directed Inspection and Mainte nance at Compressor Stations
(Cont’d)

increments on a meter. Although acoustic detectors do not measure leak rates, they provide a relative indication of leak size—a 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 environments where the leaking components
are accessible to a handheld sensor. As shown in Exhibit 1, an acoustic sensor 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 frequency range of 20 kHz to 100 kHz. Ultrasound detectors are equipped with a handheld 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 background noise, although most detectors typically provide frequency tuning 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 areallocated only to the significant leaks that are costeffective 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 meth ane leaks at compressor
stations are cost-effective to fix. Because the use of general TVA correlation equations can increase measurement inaccuracy, the development and use of site-specific correlations wi ll 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 equi librium, a gas sample is collected from the bag and the methane concentration of the sample is measured . The mass emissions rate
is calculated from the measured methane concentration of the bag sample and the flow rate of the carrier gas. Leak rate measurement 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 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. Hi gh volume samplers are equipped with dual hydrocarbon detectors that measure the concentration 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 concentrations of methane-in
-air.

High volume samplers are equipped 

### Exhibit 2: Leak Measurement Using a High Volume Sampler

Source: Oil & Gas Journal, May 21, 2001.

3

# Directed Inspection and Mainte nance at Compressor Stations
(Cont’d)

with special attachments designed to ensure complete emissions capture and to prevent
interference from other ne arby 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 measurements per hour using bagging techniques.

 Rotameters and other flow meters are used to measure extremely large leaks that would overwhelm other instruments. Flow meters typically 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 approximate cost of the leak screening and measurement techniques described above.



### Decision Points

A DI&M program is implemented in four steps: (1) conduct a baseline survey; (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 components are located, accurate leak rate measurements are obtained using bagging techniques, a high volume sampler, or TVAs that have site-specific concen tration correlations. Partners have found that leak measurement using a high volume sampler is cost-effective, fast, and accurate.

The cost of the baseline survey to find and measure leaks at the 13 compressor stations 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 s creening 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 during a regu larly scheduled DI&M survey program. For other components, simple and rapid leak screening can be incorporated into ongoing operation and maintenance procedures. Some operators train maintenance staff to conduct leak surveys, others hire outside consultants to conduct the baseline survey.



### Exhibit 3: Screening and Measurement Techniques

Instrument/Technique Application and Usage Effectiveness Approximate Capital Cost

Soap Solution

Electronic Gas

Detectors

Acoustic Detectors/

Ultrasound Detectors

TVA (flame ionization detector)

Bagging

High Volume Sampler

Rotameter Small point sources, such as connectors. Screening only. Under $100

Flanges, vents, large gaps, and openended lines. Screening only. Under $1,000

All components. Larger leaks, pressurized gas, and inaccessible components. Screening only. $1,000 to $20,000 (depends on instrument sensitivity, size, associated equipment)

All components. Best for screening only. Measurement requires site-specific leak size correlation. Under $10,000 (depends on instrument sensitivity/size)

Most accessible components. Measurement only; time-consuming. Under $10,000 (depends on sample analysis cost)

Most accessible components (leak rate <11.5 Mcfd) Screening and measurement. > $10,000

Very large leaks. Measurement only. Under $1,000

4

# Directed Inspection and Mainte nance at Compressor Stations
(Cont’d)

Step 2: Record Results and Identify Candidates for Repair.

Leak measurements collected in Step 1 must be evaluated to pinpoint the leaking components 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 signific ant leaking components. The results of the DI&M survey can be tracked using any
convenient 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 comprehens ive 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 reci procating compressors and turbines. The compressor stations equipped with reciprocating compressors co ntain an average of seven reciprocating compressors per st ation. 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 summarize s average emissions factors 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 emissions—a vent from the gas system used to control compressor unloaders. This was not a significant sou rce 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 compre ssor stations of all sizes.

Exhibit 5 illustrates the averag e leak repair costs for the 13 compressor stations included in the 1999 EPA/GRI/ PRCI study. The repair costs include the fully loaded cost of labor as well as parts and material.

Step 3: Analyze Data and Estimate Savings.

Cost-effective repair is a criti cal part of su ccessful 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

5

# Directed Inspection and Mainte nance at Compressor Stations
(Cont’d)

Exhibit 4: Average Fugitive Emissions Factors for Equipment Leaks from Compressor Station Components

COMPONENTS UNDER MAIN LINE PRESSURE 1

Component Description ON COMPRESSOR OFF COMPRESSOR

Natural Gas Emissions Factor 2 (Mcf/yr/component) Total Number of Components Measured Natural Gas Emissions Factor 2 (Mcf/yr/component) Total Number of Components Measured

Ball/Plug Valve 0.64 (±1.04) 189 5.33 (±3.71) 2,406

Blowdownn Valve 207.5 (±171.4) 57

Compressor Cylinder Joint 9.9 (±11.1) 148

—- —-

Packing Seal—Running 865 (±247) 178

Packing Seal—Idle 1,266 (±552) 42

—- —-
Compressor Valve 4.1 (±3.8) 2,324

Control Valve

—- 4.26 (±7.13) 33

Flange 0.81 (±0.89) 864 0.32 (±0.21) 2,727

Gate Valve

—- 0.61 (±0.43) 1,476

Loader Valve 17.2 (±5.6) 940

Open-Ended Line (OEL)

—- 81.8 (±79.6) 168

Pressure Relief Valve (PRV) 57.5 (±63.2) 117

Regulator

—- —- 0.2 (±0.2) 171

Starter Gas Vent 40.8 (±43.3) 5

Connector—Threaded 0.74 (±0.46) 1,625 0.6 (±0.3) 10.338

Centrifugal Seal—Dry 62.7 (±66.3) 14

Centrifugal Seal—Wet

—- —- 278 2

Unit Valve 3 3,566 12

COMPONENTS UNDER FUEL GAS PRESSURE 4

ON COMPRESSOR OFF COMPRESSOR

Ball/Plug Valve 0.1 (±0.1) 414 0.51 (±0.37) 654

Control Valve 2.46 (±3.89) 69

Flange

—- —- 0.2 (±0.2) 1,650

Fuel Valve 27.6 (±13.5) 479

Gate Valve

—- —- 0.43 (±0.36) 640

Open-Ended Line 2.53 (±2.19) 42

Pneumatic Vent

—- —- 76.6 (±118.1) 14

Regulator 4.03 (±3.98) 103

Connector—Threaded 1.21 (±1.66) 2,511 0.32 (±0.16) 3,654

1 Main line pressure range from 500 psig to 1,000 psig.

2 Emission factors with associated 95% confidence intervals.

3 Unit valve leakage is measured on depressurized compressors. Most of the compressors surveyed remained pressurized when taken off-line.

4 Fuel gas pressure is typically 70 psig to 100 psig. The components on the compressor are located at the top of pistons on reci procating compressors 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 Miti gation at Natural Gas Transm ission Compressor Stations , Report No. PRC-246-9526.

6

# Directed Inspection and Mainte nance at Compressor Stations
(Cont’d)

Exhibit 5: Average Repair Cost and Payback Period for Equipment Leaks at Compressor Stations

Component Description Type of Repair Average Cost

Ball Valves — 1” Replace $120

Bull Plug on Valve Add Teflon Tape & Tighten $15

Compressor Blow Down Replace $600

Compressor Blow Down Rebuild $200

Compressor Valve Cap Replace Gasket $60

Flange — 30” Change Gasket $1,250

Flange — 6” Change Gasket $300

Fuel Valve Replace $200

Gate Valve Teflon Repack $40

Grease Port Replace $80

Head End of Compressor Pull & Change Gaskets $450

Loader Valve Flange Replace Gasket $80

Loader Valve Stem Rebuild $300

Needle Valve Replace $100

OEL on Valve Grease $45

Pig Receiver Door Tighten $120

Pipe Thread Fitting Tighten, Add Teflon Tape $30

Plug Valves Grease $40

Pressure Relief Valve — 1” Replace $1,000

Rod Packing Pull Packing Case and Rods to Ch ange Rings, Rework Packing Case $2,600

Rod Packing Pull Packing Case and Rods to Change Ri ngs, Rework Packing Case & Replace Rod $5,600

Station Blow Down Reverse Plug $720

Tubing Tighten $10

Union Tighten $10

Unit Valve Clean & Inject Sealant $70

Unit Valve — 10” Plug Replace $2,960 PRV Flange Tighten $40

Rod Packing Change Packing Rings Without Removing Rods $750

Source: Indaco Air Quality Services, Inc., 1999, Cost Effective Leak Miti gation at Natural Gas Transm ission Compressor Stations , Report No. PRC-246-9526.

7

# Directed Inspection and Mainte nance at Compressor Stations
(Cont’d)

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 components 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 

### Nelson Price Indexes

In order to account for in flation in equipment and operating & maintenance costs, Nelson-Farrar Quarterly Cost Indexes (avail able in the first issue of each quarter in the Oil and Gas Journal ) are used to update costs in the Lessons Learned documents.

The “Refinery Operation Index” is used to revise operating costs while the “Machinery: Oilfield Itemized Refining Cost Index” is used to update equipment

costs.

To use these indexes in the future, simply look up the most current Nelson-Farrar index number, divide by the February 2006 Nelson-Fa rrar index number, and, finally multiply by the appropriate costs in the Lessons
Learned.



### Exhibit 6: Example of Repair Costs and Net Savings for Selected Equipment Components

Station Total Station

Leak Rate (Mcf/yr) Estimated

Baseline Survey Cost 1 ($/site) Estimated Total Repair

Cost Total Gas Saved by Leak Repair (Mcf/yr) Year 2 2 Total Net Savings Survey and Repair Payback

Period (years) Value of Gas

Saved Annually (at $3/Mcf) Year 1 Net Savings Total Cost to

Find and Fix

Leaks

1 23,000 $7,344 $18,800 17,850 $80,956 0.5

2 24,500 $9,287 $16,000 16,450 $73,413 0.5

12 385 $3,473 $100 245 ($2,103) 4.9 3

13 7,000 $3,473 $1,600 5,400 $27,327 0.3

Total 536,100 $89,730 $251,500 382,365 $1,952,870 0.30

Avg 41,238 $6,902 $19,346 29,413 $150,230 0.30 $53,550

$49,350

$735

$16,200

$1,147,095

$88,239 $27,406

$24,063

($2,838)

$11,127

$805,820

$61,991 $26,144

$25,287

$3,573

$5,073

$341,215

$26,248 11 2,965 $6,181 $320 620 $1,860 $6,501 ($4,641) ($2,781) 3.5 3 10 55,650 $5,309 $32,400 51,300 $153,900 $37,709 $116,191 $270,091 0.25 9 16,350 $6,304 $4,650 11,900 $35,700 $10,954 $24,746 $60,446 0.3 8 75,000 $6,538 $50,100 66,000 $198,000 $56,638 $141,362 $339,362 0.3 3 3,650 $3,019 $315 1,250 $3,750 $3,334 $416 $4,166 0.9

7 56,500 $9,734 $31,000 49,600 $148,800 $40,734 $108,066 $256,866 0.3 6 48,400 $8,856 $34,200 35,400 $106,200 $43,056 $63,144 $169,344 0.4 5 22,700 $9,318 $20,700 20,350 $61,050 $30,018 $31,032 $92,082 0.5 4 200,000 $10,894 $41,300 106,000 $318,000 $52,194 $265,806 $583,806 0.2

1 Based on estimated baseline survey cost of $2.55 per component surveyed (assumes use of high flow sampler & roatemeters for le ak measurement).

2 Assumes repair life is 2 years.

3 For this station, a full DI&M program is not profitable. Survey modifications as described at the end of Step 3 should be inve stigated. Source: Indaco Air Quality Services, 1999, Co st Effective Leak Mitigation at Natural Gas Transmission Compressor Stations, Repo rt No. PRC-246-9526.

8

# Directed Inspection and Mainte nance at Compressor Stations
(Cont’d)

baseline survey, which includes all of a partner’s transmission compressor st ations, may uncover a few individual stations where the baseline DI&M survey may not be profitable. If DI&M program is profitable for the transmission system as a wh ole, 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 tec hniques to reduce costs.

Step 4: Develop a Survey Plan for Future DI&M.

The final step in a DI&M program is to develop a survey plan that uses the results of the initial baseline survey to direct future inspection and maintenance practices. The DI&M program should be tailored to the needs and existing maintenance practices of the facility. An effective DI&M survey plan should incl ude the following elements:

 A list of components to be screened and tested, as well as the equipment 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 reciprocating 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 frequency of follow up surveys on maintenance cycles or

One Partner’s 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 $498,030 Total Cost of Survey and Repairs $5,250 Net Savings $492,780
Year One Benefit/Cost Ratio 95:1 the availability of resource s. 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 components repaired during previous surveys, or on the classes of components identified as most likely to leak.

Decision Steps for DI&M:

1. Conduct baseline survey.

2. Record results and identify candidates for repair.

3. Analyze data and estimate savings.

4. Develop a survey plan for future DI&M.

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 statio ns 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

One Partner’s Experience: 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 le aks. Of 24 leaks detected, 23 were repaired at an average cost of $50. Gas savings totaled 17,080 Mcf, averaging 8,540 Mcf per station.

Total Gas Savings $51,240 Total Survey Co sts $1,600 Total Cost of Repairs $1,150 Net Savings $48,490
Year One Benefit/Cost Ratio 19:1

One Partner’s Experience: Company C

Sixty-seven compressor stations were surveyed (survey schedule 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. Cl ose to 1,150 repairs were made. Gas savings totaled 132,585 Mcf, averag ing 1,978 Mcf per station.

Total Gas Savings $397,755 Total Survey Co sts $176,175 Total Cost of Repairs $57,180 Net Savings $164,400
Year One Benefit/Cost Ratio 1.7:1

9

# Directed Inspection and Mainte nance at Compressor Stations
(Cont’d)

quickly recovered in gas savings.

Below are three partners' ex perience in implementing DI&M programs. Note that the benefit/cost ratio is positive in each case (assuming a gas price of $3 per Mcf), but varies widely from 1.7:1 to 95:1.



### 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 compressor statio n’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 pr ogram 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 st ations 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, incorporating 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 Natu ral Gas STAR Program, personal
communication.

Howard, Touché, Indaco Air Quality Services, personal communication.

Indaco Air Quality Services, Inc., 1995, A High Flow Rate Sampling Systemfor Measuring Leak Rates at Natural Gas Facilities. Report No. GRI94/0257.38 . Gas Technology Institute, Chicago, Illinois.

Indaco Air Quality Services, Inc., 1995, Leak Rate Measurements at U.S.Natural Gas Transmission Compressor Stations. Report No. GRI94/0257.37 . 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 Agen cy, 1995, Natural Gas STAR Program Summary and Implementation Guide for Transmission and Distribution
Partners.

10

# Directed Inspection and Mainte nance at Compressor Stations
(Cont’d)

United States Environmental Protection Agency Air and Radiation (6202J) 1200 Pennsylvania Ave., NW Washington, DC 20460

EPA430-B-03-008

October 2003

EPA provides the suggested methane em issions estimating methods contained in this do cument as a tool to develop basic methane e missions estimates only. As regulatory reporting demands a higher-level of accuracy, the methane emission estimating methods and terminology contained in t his document may not conform to the Greenhouse Gas Reporting Rule, 40 CFR Part 98, Subpart W methods or those in other EPA regulations.

11