Lessons Learned 

from Natural Gas STAR Partners 

Directed Inspection and Maintenance 

at Gas Processing Plants and Booster 

Stations 

Executive Summary 

Natural gas processing plants and their associated 

compressor booster stations emit an estimated 36 billion

cubic feet (Bcf) of methane annually. More than 24 Bcf of 

total methane losses from gas plants are fugitive emissions

from leaking compressors and other equipment

components such as valves, connectors, seals, and openended lines. 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 are then made to only the 

leaking components that are cost-effective to fix, based on

criteria such as repair cost, expected life of the repair, and 

payback period. Subsequent surveys are designed 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' gas processing facilities found that

the majority of fugitive methane emissions are from a

relatively small number of leaking components. Valves are

the largest source (30 percent), followed by connectors (24

percent), and compressor seals (23 percent). The remaining 

23 percent of methane losses are primarily from openended lines, crankcase vents, pressure relief devices, and

pump seals. 

Natural Gas STAR processing partners have reported 

significant savings and methane emissions reductions by 

implementing DI&M. A four-plant pilot study conducted 

by EPA and the Gas Technology Institute (GTI)

demonstrated that instituting a DI&M program at gas 

processing facilities could reduce methane emissions by up

to 96 percent and save up to $164,000 per plant. 

Introduction 

Fugitive emissions from equipment leaks account for more

than 80 percent of annual natural gas losses from gas

processing plants and booster stations. Emissions from

continuous vents, combustion equipment, and flare 

systems contribute to the remaining 20 percent of gas 

losses and methane emissions. Natural Gas STAR 

partners have demonstrated that a DI&M program can 

profitably eliminate as much as 96 percent of gas losses 

and a corresponding 80 percent of methane emissions from

equipment leaks. This Lessons Learned study describes

the practices and technologies that can be used to 

successfully implement a DI&M program. 

Technology Background 

DI&M programs begin with a comprehensive baseline 

survey in which equipment components are screened to

identify the leaking components. The mass emissions rates

from the leaking components are measured, repair costs 

are estimated, and the repair payback period is calculated

for each leak. Both the leak and repair cost data obtained

from the baseline survey are then used to guide 

subsequent surveys, allowing operators to focus on 

components that are most likely to leak and are profitable 

to repair. 

Leak Source 

Fugitive 

Methane 

Emissions 

Method for 

Reducing 

Methane 

Losses 

Potential 

Emissions 

Reduction 

Typical 

Implementation Cost 

$3 per Mcf $5 per Mcf $7 per Mcf 

Fugitive Methane 

Emissions from Gas 

Processing Plants and 

Booster Stations 

45,000 to 

128,000 Mcf/yr 

per gas plant 

Directed 

Inspection & 

Maintenance 

Up to 96 

percent; 

average 77 

percent 

$14,000 to $50,000 for 

leak screening and 

measurement; $39,000 

to $78,000 for repairs 

$58,000 to 

$164,000 

$97,000 to 

$273,000 

$135,000 to 

$382,000 

Typical Partner Savings 

(per year per gas plant) 

Economic and Environmental Benefits 

1 
Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations 

(Cont’d) 

The following sections describe various 

leak screening and measurement 

techniques that can be employed as part of 

a DI&M program at gas processing plants

and booster stations. 

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. 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.

Many methane emissions sources that are costeffective to locate, measure, and fix are generally

larger than the small leaks likely to be found by

soaping. However, because soap screening is rapid 

and of negligible cost, it can easily be incorporated

into routine maintenance procedures. 

Electronic Screening using small handheld gas 

detectors or “sniffing” devices provides another fast 

and convenient way to detect accessible leaks. 

Electronic gas detectors have catalytic sensors 

designed to detect the presence of specific gases.

Depending on the sensitivity of the instrument, 

detecting leaks in areas with elevated ambient 

concentrations of hydrocarbon gas 

can be difficult. Electronic gas 

detectors can be used on larger

openings that cannot be screened by

soaping. 

Organic Vapor Analyzers 

(OVAs) and Toxic Vapor 

Analyzers (TVAs) are portable 

hydrocarbon detectors that can also

be used to quantify 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 is a combination device 

Exhibit 1: Toxic Vapor 

Analyzer 

Source: Thermo Environmental 

Instruments Inc 

containing both an FID and a 

photoionization detector (PID), which can 

measure organic vapors at concentrations 

exceeding 10,000 ppm. Exhibit 1 shows a 

typical TVA, consisting of a probe attached

to a portable analytical instrument. TVAs 

and OVAs measure the concentration of 

methane in the area around a leak. 

Screening is accomplished by placing a 

probe inlet at an opening where leakage

can occur. Concentration measurements 

are observed as the probe is slowly moved 

along the interface or opening, until a

maximum concentration reading is 

obtained. The maximum concentration is 

recorded as the leak screening value. 

Screening with TVAs is somewhat slow— 

approximately 40 components per hour—and the 

instruments require frequent calibration. In larger

facilities TVAs are commonly used for volatile 

organic compound (VOC) leak screening, so these 

instruments may be readily available to screen for

methane leaks. 

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 highpressure to a low-pressure environment across a leak

opening, 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 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 2, 

the acoustic sensor is placed directly on 

the equipment orifice to detect the signal.

Acoustic sensors are particularly useful

for detecting leaking valves where the 

line vent is inaccessible, such as 

blowdown valves and pressure relief 

devices connected to elevated vent stacks 

Alternatively, Ultrasound Leak Detection 

is an acoustic screening method that 

Exhibit 2: Acoustic Leak 

Detection 

Source: Physical Acoustics Corp. 

2 
 

 

Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations 

(Cont’d) 

detects airborne ultrasonic signals in the frequency 

range of 20 kHz to 100 kHz. Ultrasound detectors are 

equipped with a handheld acoustic probe that is 

aimed from a distance at the potential leak source. 

Ultrasound detection is directional, making it 

possible to pinpoint the location of leaks from 

distances as great as 100 feet. Although ultrasound 

detection may be sensitive to background noise, this 

technique is useful for identifying gas leaks at 

inaccessible equipment components. 

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 to 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. 

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 

measurement techniques are 

commonly used: 

Toxic Vapor Analyzers
 

(TVAs) can be used to estimate
 

mass leak rate. Concentration
 

measurements in ppm are
 

converted to mass emissions
 

estimates by means of correlation

equations. 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 

measured concentration thresholds, or “cut-off” 

values, such as 10,000 ppm or 100,000 ppm are 

ineffective for determining which methane leaks 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 inaccessible, unusually shaped, 

or very large. 

High Volume Samplers capture all of the

emissions from a leaking component to accurately 

quantify leak emissions rates. Exhibit

3 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 

Exhibit 3: Leak Measurement 

Using a High Volume Sampler 

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

3 
 

 

Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations 

(Cont’d) 

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 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 cubic feet per minute 

(scfm), a rate equivalent to 11.5 thousand cubic feet 

(Mcf) per day. Leak rates greater than 8 scfm must 

be measured using bagging techniques or flow

meters. Two operators can measure 30 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 

compressor seals, where the entire flow can be 

channeled through the meter. Rotameters and other

flow metering devices can supplement surveys made 

using TVAs, bagging, or high volume samplers. 

Exhibit 4 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 conducted 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. 

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. 

Step 1: Conduct Baseline Survey. 

A DI&M program typically begins with baseline screening

to identify leaking components. As leaking components are 

located, accurate leak rate measurements are obtained 

using bagging techniques, a high volume sampler, or TVA 

surveys that have site-specific concentration correlations. 

Partners have found that leak measurement using a high 

volume sampler is cost-effective, fast, and accurate. 

Prior to conducting a baseline survey, gas plant operators 

may not have accurate counts of their equipment 

components. Initial estimates of equipment components 

have been shown to be 40 percent lower than the actual 

Exhibit 4: 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 Gas Processing Plants and Booster 

Stations 

(Cont’d) 

component counts developed during a baseline survey. The

number of equipment components depends upon the size

and complexity of the facility. Baseline leak screening 

conducted by EPA and GRI at four gas processing plants

found that the physical component

counts ranged from approximately Rule of Thumb: 

14,200 components at the smallest Initial baseline survey cost 

= $1.00 per component facility to more than 56,400 

components at the largest facility

surveyed. 

The cost of a complete baseline screening using a high 

volume sampler is approximately $1.00 per component, or 

approximately $15,000 to $20,000 for a medium-size gas 

plant (in 2000 dollars). Partners have found that the cost 

of follow-up surveys in an ongoing DI&M program are 25 

percent to 40 percent less than the initial survey.

Subsequent surveys focus only on the components that are

likely to leak and are cost-effective to repair. For some gas

plant components, leak screening and measurement may

be best accomplished during a regularly scheduled DI&M

survey program. For other components, simple and rapid 

leak screening can be seamlessly incorporated into ongoing 

routine operation and maintenance procedures. Some 

operators train maintenance staff to conduct leak surveys, 

while others hire outside consultants to conduct the 

baseline survey. 

Step 2: Record Results and Identify Candidates for 

Repair. 

Leak measurements collected in Step 1 must be evaluated

to pinpoint the leaking plant components that are costeffective to repair. Leaks are prioritized by comparing the 

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. 

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 % 

Methane Content of Natural Gas 

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 warranted 

by the repair costs. Some large leaks might 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. Easy 

repairs should be completed on the spot, as soon as the

leaks are found. Others leaks might be tagged for later

attention. The results of the DI&M survey can be tracked

using any convenient method or format. The information

that plant operators may choose to collect include: 

An identifier for each leaking component. 

The component type (for example, blowdown OEL, 3­

inch valve) 

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. 

Baseline surveys conducted on more than 100,000 

equipment components at four partner-operated gas 

5 
 

 

Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations 

(Cont’d) 

processing plants found that only 3 percent of equipment 

components were leaking. However, these leaking 

components contributed 82 percent of total methane 

emissions from the four plants, a total of more than 265 

million cubic feet (MMcf) per year. Results indicate that

components subject to vibration, high use, or temperature

cycles are the most leak-prone. 

Exhibit 5 shows average methane emissions measured 

from leaking gas plant equipment components, as well as

the average leak repair costs for the various components.

Exhibit 5 can be used to identify which gas plant

equipment leaks are likely to be cost-effective to find and

fix. For example, many of the largest leaks may be 

associated with compressors, but these leaks tend to be the 

most costly to repair. Leaking connectors, on the other 

hand, are inexpensive to repair. Exhibit 5 suggests that 

other equipment components such as flanges, valves, and 

open-ended lines may offer cost-effective opportunities to

reduce fugitive emissions. 

Step 3: Analyze Data and Estimate Savings. 

By comparing the estimated repair cost to the measured

leak rate, a determination can be made whether the leak is 

cost-effective to repair. Cost-effective repair is a critical

part of a successful DI&M program because the greatest

savings are achieved by targeting only those leaks that are 

profitable to repair. 

A survey of equipment leaks and estimated repair costs at

four gas plants found that for a payback of 6 months or 

Exhibit 5: Average Methane Emissions Factors and Repair Costs for Selected Gas Processing Plant 

Components 

Component Description Gas Plant Non-Compressor 

(Mcf/yr/component) 

Reciprocating Compressor 

(Mcf/yr/component) 

Centrifugal Compressor 

(Mcf/yr/component) 

Average 

Repair Cost 

($) 

Compressor Blowdown Open-Ended Line (OEL) - 1,417 2,887 

Starter OEL - 1,341 1,341 

Site Blowdown OEL 742 - -

Other OEL 43 - -

Compressor Seal - 1,440 485 

Cylinder Valve Cover; Fuel Valve - 127 63.4 

Connection 6.7 - -

Flange 88.2 89.7 115 

$5,000 

-

$75 

$65 

$2,000 

$125 

$25 

$150 

Valve 25 - - $130 

Pressure Relief Valve 3.9 308 - $150 

Source: Methane emissions factors represent weighted average of measured fugitive emissions reported in two studies: U.S. EPA, Gas Research Institute (now 

the Gas Technology Institute), and Radian Intl., 1996, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks; and Gas Technology 

Institute and Clearstone Engineering, Processing Plants. Repair cost data are in 2000 dollars from GTI/Clearstone study. 

Note: Methane emissions factors are adjusted to account for the average volume percent of methane in the natural gas, which is 87 percent. Similarly, emissions factors are also adjusted to account for 11 percent of compressors that are routed to a flare, plus the fraction of compressors that do not use natural gas 

starters. 

6 
 

 

 

Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations 

(Cont’d) 

less, 78 percent of leaking components were cost-effective

to repair. In addition, 92 percent of leak repairs were

found to payback in less than 1 year, and 94.5 percent of 

leaks paid back in less than 4 years. 

Exhibit 6 provides an example of the gas savings that

would be possible by fixing the 10 largest leaks at a single 

gas plant. This exhibit illustrates the straightforward 

calculation that should be made for each measured leak to 

determine which leaks are cost-effective to repair. 

Natural Gas STAR 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 

components are economic to repair. 

Exhibits 7 and 8 illustrate the type of analysis that can be

completed to determine the relative profitability of DI&M

for selected types of gas plant components. The cost data, 

component counts, and average component emissions 

factors are based on the data obtained from a pilot study of

DI&M at four gas processing plants. Exhibit 7 illustrates 

Exhibit 6: Example of Potential Gas Savings from 

Fixing the Ten Largest Leaks at a Single 

Processing Plant 

Component Description 

Gas Savings 

(Mcf/yr) 

Value of Gas 

Saved at $3.00 

per Mcf ($/yr) 

Repair 

Cost 

Payback 

Period 

Plug valve (leakage at 

bottom of valve body) 4,214 $12,642 $200 5—6 days 

Union on fuel gas 

lines 4,052 $12,156 $100 3—4 days 

Threaded connections 3,482 $10,446 $10 Immediate 

Plug valve on flare 

line 3,030 $9,090 $200 8 days 

Governor 2,572 $7,716 $200 10 days 

Distance piece on 

recompressor cylinder 2,550 $7,650 $2,000 3 months 

Open-ended line 2,320 $6,960 $60 3—4 days 

Union on fuel gas line 2,204 $6,612 $100 5—6 days 

Compressor seals 1,928 $5,784 $2,000 4 months 

Gate valve 1,576 $4,728 $60 4—5 days 

TOTAL 27,928 $83,784 $4,930 21 days 

Exhibit 7: Cost Basis for Cash Flow Analysis of DI&M for Selected Gas Processing Plant Components 

Type of Component 

Number of 

Components 

per Gas Plant 

Estimated 

Survey Cost 

Assume 

3% Leaking 

Estimated 

Repair Cost 

($/Component) 

Total Repair 

Cost 

Total Cost to 

Find & Fix 

Connections 

Compressor-Related 2135 $2,135 64 $5 $320 $2,455 

Non-Compressor Related 7664 $7,664 230 $— $0 $7,664 

Connections Total 9299 $9,799 294 $10,119 

Pressure 

Relief Valve 

Compressor-Related 13 $13 1 $150 $150 $163 

Non-Compressor Related 48 $48 1 $150 $150 $198 

Pressure Relief Valve Total 61 $61 2 $361 

OEL 

Compressor Blowdown OEL 15 $15 1 $5,000 $5,000 $5,015 

Compressor Starter OEL 15 $15 1 $1,000 $1,000 $1,015 

Site Blowdown OEL 1 $1 1 $75 $75 $76 

Other OEL— Non-Compressor Related 171 $171 5 $65 $325 $496 

OEL Total 202 $202 8 $6,602 

Compressor-Related 309 $309 9 $175 $1,575 $1,884 

Non-Compressor Related 1825 $1,825 55 $130 $7,150 $8,975 

Valve Total 2134 $2,134 64 $10,859 

Other Valves 

Assumptions: Cost data and component counts from 2000 GTI/Clearstone study. Cost for non-compressor connection repair assumes that repair is made on the 

spot by tightening the connection. 

7 
 

Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations 

(Cont’d) 

Exhibit 8: Example Economic Analysis of DI&M for Selected Gas Processing Plant Components 

Type of Component 

Total Cost 

to Find & 

Fix 

Gas Savings 

(Mcf/Component/Yr) 

Total Annual 

Gas Savings 

(Mcf) 

Value of 

Gas Saved 

($3.00/ 

Mcf) 

NPV 

Payback 

Period 

(Years) 

Cash Flow 

Year 2 

Cash Flow 

Year 1 

Connections 

CompressorRelated $2,455 6.7 429 $1,287 $2 1.9 

NonCompressor 

Related 

$7,664 6.7 1,540 $4,621 $1,053 1.6 

Connections 

Total $10,119 6.7 1,970 $5,909 $1,056 1.7 

$1,287 

$4,621 

$5,909 

($1,168) 

($3,043) 

($4,210) 

Pressure 

Relief Valve 

CompressorRelated $163 308 308 $924 $1,455 0.2 

NonCompressor 

Related 

$198 3.9 4 $12 ($160) 16.9 

Pressure 

Relief Valve 

Total 

$361 312 $936 $1,296 0.4 

$924 

$12 

$936 

$761 

($186) 

$575 

OEL 

Compressor 

Blowdown OEL $5,015 2,152 2,152 $6,456 $6,456 0.8 

Compressor 

Starter OEL $1,015 1,341 1,341 $4,023 $6,059 0.3 

Site Blowdown 

OEL $76 742 742 $2,226 $3,794 0.3 

Other OEL— 

NonCompressor 

Related 

$496 43 215 $645 $669 0.8 

OEL Total $6,602 4,450 $13,350 $17,168 0.5 

$6,456 

$4,023 

$2,226 

$645 

$13,350 

$1,441 

$3,008 

$2,150 

$149 

$6,748 

CompressorRelated $1,884 95 855 $2,565 $2,739 0.7 

NonCompressor 

Related 

$8,975 25 1,375 $4,125 ($1,000) 2.2 

Valve Total $10,859 2,230 $6,690 $1,739 $10,859 

Other Valves 

$2,565 

$4,125 

$6,690 

$681 

($4,850) 

($4,169) 

Assumptions: Average repair life is two years. Emissions data represent weighted average component emissions from EPA/GRI/Radian study and GTI/Clearstone 

study. NPV discount rate = 10%. 

the cost basis for the initial baseline survey and repair of 

leaking connectors, pressure relief valves, open-ended lines

(OEL), and other valves. Exhibit 8 uses the cost bases 

shown in Exhibit 7 for an economic analysis of DI&M for

the selected equipment components. 

Exhibit 8 shows that DI&M is most cost-effective for 

components such as open-ended lines and compressorrelated pressure relief valves. These components are

relatively easy to locate, screen, and measure, and have 

the potential for significant gas savings. Compressor and

non-compressor related connections can also be costeffective to repair. Potential economic benefit from these 

components, however, may be constrained due to small

average leak rates and higher “find and fix” costs 

associated with a larger number of connections. Economic 

benefits are maximized when “on-the-spot” repairs, such as 

tightening a loose fitting, can be performed. For “other 

valves,” the benefits of a DI&M program depend on the 

size of the leak, the potential gas savings, and the repair 

8 
 

 

Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations 

(Cont’d) 

cost. Exhibit 8 suggests that DI&M is cost-effective for 

leaking valves associated with compressors, but may not 

be economic for other valves with smaller average leak 

rates, unless the leak survey and repairs can be 

incorporated into routine maintenance procedures. 

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. 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 and operations of their

facility. 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 company 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 

components 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 a DI&M

program will vary depending upon the age and size of the 

facility, the number and types of components included in

the DI&M program, and operating characteristics of the 

facility. Natural Gas STAR partners have found that the

initial expense of a baseline survey is quickly recovered in

gas savings. The following are two examples of the 

potential savings from a DI&M program. The first example

is a joint EPA/GTI pilot study that looked at four gas

plants, and the second is a study conducted by Natural 

Gas STAR partner, Dynegy Inc. 

Pilot Study of DI&M at Four Gas Processing Plants 

Four partner-operated gas plants were selected for a joint

EPA/GTI pilot study of directed inspection and 

maintenance practices. The facilities ranged in age from 20

to 50 years. Plant throughput ranged from 60 MMcfd to

210 MMcfd. Leak screening was conducted by soaping and

portable hydrocarbon gas detectors. Leaking components

were tagged and leak rates were measured using a high

volume gas sampler. Exhibit 9 illustrates the estimated 

annual volume of natural gas lost as fugitive emissions 

and the potential savings for these four plants from

implementing DI&M. Some of the key findings of the study

include: 

The cost of the initial baseline survey in each pilot 

plant was estimated to be approximately $1.00 per 

Exhibit 9: Estimated Potential Savings from DI&M at Four Gas Processing Plants, Pilot Study 

Site 

Annual Volume 

of Gas Lost 

(Mcf/yr) 

Value of Lost 

Gas at $3/Mcf 

($/yr) 

% Emissions 

Cost-Effective to 

Repair 

Baseline Survey Cost ($) Total Repair 

Cost ($) 

Net Savings at $3/Mcf 

($/yr) 

Site Fugitive 

Emissions 

(Mcfd) 

1 123 44,895 $134,685 90% $16,050 $44,725 $60,442 

2 207 75,555 $226,665 95% $14,424 $39,300 $161,608 

3 352 128,480 $385,440 50% $56,463 $77,900 $58,357 

4 211 77,015 $231,045 96% $14,168 $43,450 $164,185 

TOTAL 893 325,945 $977,835 77% $101,105 $205,375 $444,592 

9 
 

 

 

 

Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations 

(Cont’d) 

component, or $15,000 to $20,000 per gas plant. 

Valves, connectors, compressor seals, and open-ended 

lines contributed the majority of fugitive methane 

emissions. 

Less than 3 percent of components were found to be 

leaking. 

Of all the leaks identified at the individual plants, 50 

to 96 were cost-effective to repair. 

Repair costs ranged from negligible to $5,000, 

depending on the type of component and the nature

of the repair. Most of the repairs were estimated to 

have a repair life of two years. 

Dynegy Study 

Natural Gas STAR partner, Dynegy Inc., conducted a pilot 

DI&M study at two gas processing plants. Both plants are 

large (greater than 50 MMscfd gas throughput) and 

approximately 35 years old. One plant processes sweet gas; 

the other is a sour-gas processing facility. Leak screening 

was conducted using soap bubble tests, portable 

hydrocarbon detectors, and an ultrasound detector. Leak 

measurement was conducted using a high volume sampler, 

and bagging and rotameter measurements for leak rates

that exceeded the upper limit of the high volume sampler.

For each identified leak, cost-effective opportunities to

reduce methane emissions were identified by comparing 

the cost of repair or equipment replacement with the value

of the gas that would be saved in one year. Exhibit 10 

summarizes the results of this study. 

Exhibit 10: One Partner’s Experience—Dynegy 

DI&M Pilot Study 

Cost of initial baseline survey $35,000 ($15,000—$20,000 per plant) 

Total components surveyed in 

two plants 30,208 

Total leaking components 1,156 (3.8%) 

% of leaking components 

repaired 80% at one facility; 90% at the other 

Total annual methane emissions 

reductions 100,000 Mcf/year 

Annual savings (at $3/Mcf) $300,000/year 

Follow-up surveys planned 

(based on expected life of Once every 3 years 

equipment repairs) 

Lessons Learned 

DI&M is a proven management practice for cost-effective

reduction of methane emissions. Recent implementation of

DI&M at four partner-operated gas processing plants

indicate that DI&M programs have the potential to 

significantly reduce methane emissions from the gas 

processing sector. The principal lessons learned from

Natural Gas STAR partners are: 

The costs of the initial baseline survey can be 

recovered in gas savings during the first year. The 

cost of subsequent surveys can be reduced by

focusing the survey efforts on those components that 

were identified through earlier studies as the most

likely to leak. 

Partners estimate that the cost of follow-up surveys

will be 25 percent to 40 percent less because 

subsequent surveys will focus only on the equipment 

components that are likely to leak and are profitable 

to repair. 

No two gas processing plants are alike. Opportunities

for cost-effective gas savings will vary widely

depending upon such factors as the age and size of

the facility, types of plant components, and the 

operating time since the last major plant 

maintenance. 

A combination of screening and measurement devices

can be used to obtain accurate leak data. A high

volume gas sampler is an effective tool for identifying

and quantifying leaks. 

A DI&M program should target the five categories of

equipment components that contribute to the 

majority of methane losses: block valves, control 

valves, connectors, compressor seals, and open-ended 

lines. 

If possible, partners should repair the most severe 

leaks first. Typically only a few leaking components 

are responsible for the majority of fugitive methane

emissions. 

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. 

10 
 

Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations 

(Cont’d) 

Repair of minor leaks can be incorporated into 

regular maintenance practices. Repairs that require 

shutting down a system may be undertaken during 

the next scheduled outage. 

Institute a “quick-fix” step that involves making

simple repairs to simple problems (e.g., loose stem

packing, valve not fully closed) during the survey 

process. 

Screening or measuring leaking components after 

repairs are made confirms the effectiveness of the 

repair. Soap bubble screening is a quick way to check 

the effectiveness of a repair. Post-repair

measurements with a high volume sampler allow the 

gas savings to be quantified and recorded. 

Record methane emissions reductions for each gas 

processing plant and/or booster station and include 

annualized reductions in Natural Gas STAR Program 

reports. 

References 

Ananthakrishna, S. and Henderson, C., 2002, Cost-effective Emissions 

Reductions Through Leak Detection, and Repair, Hydrocarbon 

Processing, May 2002. 

Clearstone Engineering, 2002, Identification and Evaluation of 

Opportunities to Reduce Methane Losses at Four Gas Processing 

Plants, internal report prepared under U.S. EPA Grant No. 827754-01­

0 for Gas Technology Institute, Des Plaines, IL. 

Connolly, Jan, Toxic Vapor Analyzers, personal communication. 

Frederick, J., Phillips, M., Smith, G.R., Henderson, C., Carlisle, B., 2000, 

Reducing Methane Emissions Through Cost-Effective Management 

Practices, Oil & Gas Journal, August 28, 2000. 

Gas Technology Institute (formerly the Gas Research Institute), personal 

communication. 

Henderson, Carolyn, U.S. EPA Natural Gas STAR Program, personal 

communication. 

Henderson, C., Panek, J., Smith, M., Picard, D., 2001, Gas-Plant Tests 

Reveal Cost-Effective Inspection and Maintenance Practices, Oil & 

Gas Journal, May 21, 2001. 

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

communication. 

McMillan, L.W. and Henderson, C., 1999, Cost-Effectively Reduce 

Emissions for Natural Gas Processing, Hydrocarbon Processing, 

October 1999. 

Mohr, Gary, UE Systems Inc., personal communication. 

Phillips, M. and Lott, R., 1999, Emissions Reductions Can Be CostEffective, Pipeline and Gas Journal, October 1999. 

Radian International, 1996, Methane Emissions from the Natural Gas 

Industry, Volume 2, Technical Report, Report No. GRI-94/0257.1, Gas 

Technology Institute (formerly Gas Research Institute), Chicago, IL. 

Radian International, 1996, Methane Emissions from the Natural Gas 

Industry, Volume 8, Equipment Leaks, Report No. GRI-94/0257.1, 

Gas Technology Institute (formerly Gas Research Institute), Chicago, 

IL. 

Tamutus, Terry, Physical Acoustics Corporation, personal communication. 

Tingley, Kevin, U.S. EPA Natural Gas STAR Program, personal 

communication. 

11 
Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations 

(Cont’d) 

United States 

Environmental Protection Agency 

Air and Radiation (6202J) 

1200 Pennsylvania Ave., NW 

Washington, DC 20460 

EPA430-B-03-018 

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. 

12