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 miles. 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 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 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 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 natural 

gas transmission pipeline are 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 operations place significant pressure,

thermal, and mechanical stresses 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 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. 

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 Maintenance 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. The 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 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 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 Screening 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 exceeding 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 transmissions 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 Maintenance 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 are 

allocated 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 methane 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 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 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. High 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 Maintenance at Compressor Stations 

(Cont’d) 

with special attachments designed to ensure 

complete emissions capture and to prevent 

interference 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 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 concentration 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 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 during a regularly 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 Maintenance 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 significant 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 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 

turbines. 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 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 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 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 critical 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 

5 
 

 

Directed Inspection and Maintenance at Compressor Stations 

(Cont’d) 

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

Components 

COMPONENTS UNDER MAIN LINE PRESSURE1 

Component Description 

ON COMPRESSOR OFF COMPRESSOR 

Natural Gas Emissions Factor2 

(Mcf/yr/component) 

Total Number of 

Components Measured 

Natural Gas Emissions Factor2 

(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 Valve3 3,566 12 

COMPONENTS UNDER FUEL GAS PRESSURE4 

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 reciprocating 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 Mitigation at Natural Gas Transmission Compressor Stations, Report No. PRC-246-9526. 

6 
Directed Inspection and Maintenance 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 Change Rings, Rework Packing Case $2,600 

Rod Packing Pull Packing Case and Rods to Change Rings, 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 Mitigation at Natural Gas Transmission Compressor Stations, Report No. PRC-246-9526. 

7 
 

 

 

 

Directed Inspection and Maintenance 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 inflation in equipment and 

operating & maintenance costs, Nelson-Farrar 

Quarterly Cost Indexes (available 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-Farrar 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 Cost1 

($/site) 

Estimated 

Total Repair 

Cost 

Total Gas Saved 

by Leak Repair 

(Mcf/yr) 

Year 22

 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) 4.93 

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) 3.53 

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 leak 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 investigated. 

Source: Indaco Air Quality Services, 1999, Cost Effective Leak Mitigation at Natural Gas Transmission Compressor Stations, Report No. PRC-246-9526. 

8 
 

 

 

 

 

 

 

 

 

Directed Inspection and Maintenance at Compressor Stations 

(Cont’d) 

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 profitable. 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. 

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 include 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 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 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 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 

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 leaks. 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 Costs $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. Close to 1,150 repairs were made. Gas 

savings totaled 132,585 Mcf, averaging 1,978 Mcf per station. 

 Total Gas Savings $397,755 

Total Survey Costs $176,175 

Total Cost of Repairs $57,180 

Net Savings $164,400 

Year One Benefit/Cost Ratio 1.7:1 

9 
 

 

 

 

Directed Inspection and Maintenance at Compressor Stations 

(Cont’d) 

quickly recovered in gas savings. 

Below are three partners' experience 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 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, 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 Natural Gas STAR Program, personal 

communication. 

Howard, Touché, 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. 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 Agency, 1995, Natural Gas STAR Program 

Summary and Implementation Guide for Transmission and Distribution 

Partners. 

10 
Directed Inspection and Maintenance 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 emissions estimating methods contained in this document as a tool to develop basic methane emissions estimates only. As 

regulatory reporting demands a higher-level of accuracy, the methane emission estimating methods and terminology contained in this document may not conform to 

the Greenhouse Gas Reporting Rule, 40 CFR Part 98, Subpart W methods or those in other EPA regulations. 

11