# Lessons Learned

from Natural Gas STAR Partners



# Directed Inspection and Maintenance
at Gate Stations and Surface Facilities

Executive Summary

In 2001, fugitive methane emis sions from gate stations
and surface facilities in the United States totaled about 27 million cubic feet (MMcf) from leaking meters and regulating equipment. Implementing a directed inspectionand maintenance (DI&M) program is a proven, costeffective 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. This Lessons Learned study focuses on maxi mizing the savings that can be achieved by implementing DI&M programs at gate
stations and surface facilities.

Natural Gas STAR distribution partners have reported significant savings and methane emissions reductions by implementing DI&M. Based on partner data, implementing DI&M at gate stations and surface facilities can result in gas savings worth up to $1,800 per year, at a cost of between $20 and $1,200.



### Introduction

Gate stations (or ‘city gates’ ) are metering and pressure regulating facilities located at the custody transfer points where natural gas is delivered from transmission pipelines into the high-pressure lines of a local distribution company. Gate stations typically contain metering runs as well as pressure regulators, wh ich reduce the transmission line pressure from several hundred pounds per square inch gauge (psig) to a suitable pr essure for the distribution system (usually less than 300 psig). Other surface facilities within a distribution system include heaters to replace the heat lost from gas expansio n, and downstream pressure regulators, which further reduce gas pressure so that gas can be delivered safely to customers. Exhibit 1 is a schematic illustration of a ga s distribution system showing a gate station and pressure regulating facilities.



### Exhibit 1: Distribution System Schematic Showing Gate Station and Pressure Regulators

Gate stations and surface facilities contain equipment components such as pipes, va lves, flanges, fittings, openended lines, meters, and pneumatic controllers to monitor and control gas flow. Over time, these components can develop leaks in response to temperature fluctuations, pressure, corrosion and wear. In general, the size of the

Method for Reducing

Natural Gas Losses Volume of

Natural Gas Savings (Mcf) 1 Value of Natural Gas Savings ($) Implementation Cost ($) 2 Payback (Months)

$3 per

Mcf $5 per

Mcf $7 per

Mcf $3 per

Mcf $5 per

Mcf $7 per

Mcf

Locating and Repairing Leaks 600 per site $1,800 $3,000 $4,200 $20 – $1,200 1 – 8 1 – 5 1 – 4

1 Savings are modeled as 600 Mcf per site. Typical estimates for leaking facilities tend to range between 30 and 200 Mcf per sit e.

2 The implementation cost will vary depending on facility size and types of repairs. 

### Economic and Environmental Benefits

1

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

facility and the facility leak rate correspond to the inlet or upstream gas pressure; the higher the inlet pressure, the larger the gate station and the greater the number of equipment components that may develop leaks.



### Technology Background

DI&M is a cost-effective way to reduce natural gas losses from equipment leaks. A DI&M program begins with a comprehensive baseline survey of all the gate stations and
surface facilities in the di stribution system. Operators identify, measure, and evaluate all leaking components

and use the results to direct subsequent inspection and
maintenance efforts.

The following sections describe various leak screening and measurement techniques that can be cost-effective at gate stations and pressure re gulating facilities. The appropriateness of the various screening and measurement techniques will depend upon the configuration and operating characteristics of individual distribution system facilities.

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. Operators can screen about 100 components per hour by soaping.

 Electronic Screenin g using small handheld 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.

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.

 Acoustic Leak Detection uses portable acoustic screening devices designed to detect the acoustic signal that results when pressurized gas escapesthrough 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, 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 ultras onic signals in the 

### Exhibit 2: Acoustic Leak

Detection

Source: Physical Acoustics Corp.

2

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

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.

 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.

Leak Measurement Techniques

An essential 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 costThe 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 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.

effective to repair. Four leak measurement techniques can be used: conversion of TVA and OVA screening concentrations using general correlation equations; bagging techniques; high volume samplers; and

rotameters.

Data available for total fugitive emissions rates from gate
stations and surface facilities indicates that the leak rate for many components is relatively small. For most gate stations, DI&M will only be cost-effective using the lowest cost measurement technique, which is likely to be conversion of TVA/OVA screening values using EPA correlation equations and TVA or OVA instruments that may already be at hand.

 OVAs and TVAs can be used to estimate mass leak rate. The screening concentration detected at a leak opening is not a direct measurement of the mass emissions of the leak. However, the screening concentration in ppm is converted to a mass emissions rate by using EPA correlation equations. The EPA correlation equa tions can be used to estimate emissions rates for the entire range of screening concentrations, from the detection limit of the instrument to the “pegged” screening concentration, which represents the upper limit of the instrument. If the upper measurement limit of the TVA is 10,000 ppm, a dilution probe can be used to detect screening concentrations up to 100,000 ppm.

OVAs and TVAs must be calibrated using a reference gas containing a known compound at a known concentration. Methane in air is a frequently used

3

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

reference compound. The calibration process also determines a response factor for the instrument, which is used to correct the observed screening
concentration to match the actual concentration of the leaking compound. For example, a response factor of “one” means that the screening concentration read by the TVA equals the actual

concentration at the leak. the carrier gas. Leak rate measurement using bagging techniques is accurate (within ± 10 to 15 percent) but, slow and labor intensive (only two or three samples per hour). Bagging techniques can be expensive due to the labor involved to perform the measurement, as well as the cost for sample analysis.

 High Volume Samplers capture all of the emissions from a leaking component to accurately quantify leak Screening concentrations detected for individual components are corrected using the response factor (if necessary) and are entered into EPA correlation equations to extrapolate a leak rate measurement for the component. Exhibit 3 lists the EPA correlation equations for equipment components at oil and gas industry facilities.

Exhibit 4 provides a table based on the above EPA correlation equations for TVAs and OVAs. This can
be used to estimate mass leak rate from the screening concentrations detected at leaking components at gate stations and surface facilities.

 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 

### Exhibit 4: Example Scr eening Concentration/Leak

Rate Correlations

Screening

Concentra

tion (ppmv) Estimated Mass Leak Rate (Mcf/yr)

Valves Pump

Seals Connec

tors Flanges OpenEnded

Lines Other 1

1 0.001 0.023 0.001 0.002 0.001 0.006

10 0.006 0.093 0.004 0.011 0.005 0.024

100 0.032 0.380 0.021 0.053 0.026 0.093

1,000 0.180 1.547 0.112 0.269 0.130 0.362

10,000 1.004 6.301 0.606 1.360 0.655 1.404

100,000 5.593 25.669 3.293 6.864 3.313 5.450

Screening value pegged at
>10,000 29.109 33.657 12.735 38.660 13.645 33.203

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 Screening value pegged at
>100,000 63.676 72.773 13.645 38.206 35.931 50.031

1 “Other” equipment components include: instruments, loading arms, pressure relief valves, stuffing boxes, and vents. Apply to any equipment component other than connectors, flanges, open-ended lines, pumps, or valves. Source: U.S. EPA, 1995, Protocol for Equipment Leak Emission Estimates.



### Exhibit 3: U.S. EPA Leak Rate/Screening Value Co rrelation Equations for Equipment Components in the Oil and Gas Industry

Equipment Component EPA Leak Rate/Screening

Value Correlation

(kg/hr/source) Leak Rate Correlation (kg/hr) for “Pegged” Screening Value >10,000 ppm Leak Rate Correlation (kg/hr) for “Pegged” Screening Value >100,000 ppm

Valves 2.29 E-06 x (SV) 0.746 0.064 0.140

Pump Seals 5.03 E-05 x (SV) 0.610 0.074 0.160

Open-Ended Lines 2.20 E-06 x (SV) 0.704 0.030 0.079

Other Components (instruments, pressure relief, vents, all others) 1.36 E-05 x (SV) 0.589 0.073 0.110 Flanges 4.61 E-06 x (SV) 0.703 0.085 0.084 Connectors 1.53 E-06 x (SV) 0.735 0.028 0.030

The correlations presented are revised petrol eum industry correlations. Co rrelations predict total or ganic compound emissions r ates. Correlation factors for methane: 1 kg me thane = 51.92 scf; 1kg/hr = 1.246 Mcfd
Source: U.S. EPA, 1995, Protocol for Equipment Leak Emission Estimates.

4

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

emissions rates. Leak emissi ons, plus a large volume sample of the air around the leaking component, are pulled into the instrument through a vacuum sampling hose. Sample measurements are corrected for the ambient hydrocarbon concentration, and 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. 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. Two operators can measure 30 components per hour using a high volume sampler, compared with two to three measurements per hour using bagging techniques. High volume samplers can cost approximately $10,000 to purchase. Alternatively, contractors can provide leak measurement services at a rate that ranges from $1.00 to more than $2.50 per component measured.

 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.



### Decision Points

A DI&M program can be 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; component the mass leak rate is estimated using one of the techniques described above. In the distribution sector, the emissions from leaking equipment components at gate stations and surface facilities may be one or more orders of magnitude less than emission s from leaks at compressor
stations. For DI&M to be cost-effective at gate stations and surface facilities, the baseli ne survey costs must be
minimal.

Some distribution sector part ners elect to conduct leak screening only, using very low cost and rapid leak detection techniques, which are incorporated into ongoing maintenance operations. In these cases, all of the leaks that are identified are repaired. A baseline survey that focuses only on leak screening is substantially less expensive. However, leak screening alone does not quantify leak rate or potentia l gas savings, each of which
is critical information needed to make cost-effective repair decisions in cases where pa rtners do not have the
resources to repa ir all leaks.

Step 2: Record Results and Identify Candidates for Repair.

Leak measurements collected in Step 1 must be recorded to pinpoint the leaking components that are cost-effective to repair. 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 includes: (1) an identifier for each leaking component; (2) the component type (e.g., gate valve); (3) the measured leak rate; (4) the survey date; (5) the estimated annual gas loss; and (6) the estimated repair cost. This information will direct subsequent emissions surveys, pr ioritize future repairs, and track the methane savings and cost-e ffectiveness of the DI&M

program.

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.

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. For each leaking Natural Gas STAR partners report that the most common leaks at gate stations and surface facilities are pinhole leaks and component flaws, loose connections, and loose or worn valve stem seals. High frequency leak locations identified by partners include: orifice plate/fittings, plugs installed on test points, grease fittings on valves, multiple or large diameter meter runs, couplings, valve stem packing, and flanges. The largest leaks are generally located at pressure relief valves, open-ended lines, flanges, gate valves, and gate valve stem packing. 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.

5

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

Gate stations and surface facilities vary significantly in size and pressure capacity depending upon the size and complexity of the distribution system. As a result, there can be substantial variation in fugitive methane emissions 9 from such facilities. A 1994 field study sponsored by EPA and the Gas Research Institute (GRI—now GTI, the Gas Technology Institute) used a tracer gas technique to measure total facility methane emissions at 40 gate stations and 55 district pre ssure regulators. This study found that average annual methane emissions ranged from 1,575 Mcf per year for gate st ations with inlet pressures greater than 300 psig to less than 1 Mcf per year for district regulators with inle t pressures less than 40 psig. Average annual facility emission s, based on all 95 sample
facilities were 425 Mcf. This study estimated that a large component of total site emissions are contributed by pneumatic controllers, which are designed to bleed gas to the atmosphere.

In 1998, EPA, GRI, and the American Gas Association Pipeline Research Committee International (PRCI) conducted a second study of methane emissions from equipment components at 16 natural gas metering and regulating facilities in transm ission and distribution. Four
of the facilities studied were distribution system gate stations. This analysis included component counts for each site, and leak screening and measurement of individual component leaks using a high volume sampler. As in the earlier study, pneumatic controllers were found to contribute most of the total site emissions (more than 95 percent). Because pneumatic devices are designed to bleed gas during normal operation, these emissions are not
considered leaks. Pneuma tic controllers provide a significant opportunity to re duce methane emissions from gate stations and surface facilities, which is the subject of
Lessons Learned: Convert Gas Pneumatic Controls to

Instrument Air and Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry.

Exhibit 5 summarizes average component emissions factors obtained during the 1998 field study. Approximately 5 percent of the 2,261 total components screened were found to be leaking.

Exhibit 5 shows that pressure relief valves were found to be the largest leak source, followed by gate valves and
control valves. The smallest leaks were found at connectors, flanges, and ball/plug valves. Exhibit 5 indicates that the typical leak to be expected at gate state stations and surface facilities is relatively small, and the number of components to be su rveyed at each facility is 

### Exhibit 5: Average Emissions Factors for Equipment Leaks at Sixteen Metering and Regulating Facilities

Component Emissions

Factor (Mcf/yr/ component) Total Number of Components

Screened Average Number of Components per Site

Ball/Plug Valve 0.21 248 18

Control Valve 0.46 17 1

Flange 0.13 525 38

Gate Valve 0.79 146 10

Pneumatic Vent 134.3 40 1

Pressure Relief

Valve 4.84 5 1

Connectors 0.11 1,280 91

TOTAL 2,261 162

Source: Indaco Air Quality Services, 1998.

over 100.

Based on the leak measurements of individual equipment components, the 1998 study determined the average total gas emissions from metering and regulating facilities to be 409 Mcf per year. Excluding the total facility emissions contributed by pneumatic controllers, the average total emissions contributed by equipment leaks was in the range of 20 to 40 Mcf per site, although substantial leaks in the range of 60 to 100 Mcf per year were reported for
some of the sites.

The 1998 field study reinforces the point made in Step 1, that a cost-effective DI&M program at gate stations and surface facilities must rely upon very low cost and rapid screening techniques. Otherwise, the cost of finding the leaks might not outweigh the savings gained from fixing

the leaks.

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.

6

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

Some leaks can be fixed on the spot, for example, by simply tightening a valve stem packing-gland. 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.

Easy repairs should be done on the spot, as soon as the leaks are found. In all cases, the value of the gas saved
should exceed the cost to find and fix the leak. Partners have found that an effective way to analyze baseline survey results is to create a table listing all leaks with their associated repair cost , expected gas savings, and expected life of the repair. Using this information, economic criteria such as pa yback period can be easily calculated for each leak repair. Partners can then decide which leaking components are economic to repair.

Exhibit 6 provides an example of this type of repair cost analysis, which summarizes the repair costs, total gas savings, and the estimated net savings for the anticipated repairs. The leak and repair data featured in Exhibit 6 are from the 1998 EPA/GRI/PRCI field study, during which leak repairs were evaluated for two of the sixteen facilities included in the study. Because of safety concerns, so me partners repair all leaks found at gate stations and meter stations. In this case, aDI&M program may be useful for improving the costeffectiveness of ongoing inspection and maintenance operations by prioritizing repairs—the major leaks are identified and repaired first, or inspection and maintenance is conducted more frequently at facilities with the greatest leak frequency.

As leaks are identified, measured, and repaired, operators
should record baseline data so that future surveys can focus on the most significant leaking components. This
information will direct subs equent emissions surveys, prioritize future repairs, and track the methane savings and cost-effectiveness of the DI&M program.

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



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

Component Descriptions Type of Repair Repair Cost 1 (includes labor & material) Total Number of Components Fixed

at Two Sites Total Gas Savings (Mcf/yr) Estimated Net Savings 2 ($/yr) Repair Payback Period (years)

Ball Valve Re-grease $13 5 60 Mcf $115 0.4

Gate Valve Replace valve stem packing $3 5 67 Mcf $36 0.8

Gate Valve Replace valve stem packing $3 1 92 Mcf $243 0.1

Connectors Tighten Threaded Fittings $3 4 11 Mcf $21 0.4

Sr. Daniel Orifice

Meter Tighten Fittings $33 1 68 Mcf $171 0.2

Flange 3 Tighten (estimated) $40 5 99 Mcf $97 0.7

1 Average repair costs are in 2002 dollars.

2 Assumes gas price of $3/Mcf.

3 Repair cost not reported in original study. Flange repair cost estimated based on similar 1997 data on leak repair cost of “of f-compressor” flanges at compressor stations. Source: Indaco Air Quality Services, 1998, Trends in Leak Rates at Metering and Regulating Facilities and the Effectiveness of Leak Detection and Repair (LDAR) Programs, Draft Report.

7

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

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 gas savings yet also suits the unique characteristics of the facility—for example, the age, size, and configuration of the facility and the inlet pressure. Some partners sche dule 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 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

Savings achieved by Natural Gas STAR partners implementing DI&M programs at gate stations and surface facilities vary wide ly. Factors affe cting results include the number of stations in the DI&M program, the stage of program developmen t (i.e., new versus mature program), and the level of implementation and repair
costs. Costs differ between faci lities because of the type of screening and measurement equipment used, frequency of surveys, and number and type of staff conducting the

surveys.

Exhibit 7 provides a hypothetical example of the costs and benefits of implementing DI&M at three gate stations. The leak rates and number of leaking components in this example are based on actual leak rates reported for three sites in the 1998 EPA/GRI/PRCI study. Exhibit 7 illustrates the type of calculations that distribution partners should make to evaluate whether DI&M could be cost-effective for th eir operations.

Exhibit 7 illustrates that although the costs of finding and fixing leaks may not be recovered by the value of the gas saved at each and every site, if multiple sites are included in the DI&M program, the overall program can still be profitable. For the hypothetical example in Exhibit 7, DI&M is not cost-effective at Site 2, although DI&M is profitable for the three sites considered as a whole. In this case, the operator would use the experience gained from the baseline survey of Site 2 to direct subsequent surveys; possibly excluding Site 2 fr om subsequent surveys, screening Site 2 less frequently, or screening only a selected group of components.

Partner Experience

From 1995 to 2000, 18 Natural Gas STAR partners reported gas savings from im plementing DI&M at gate
stations and surface facilities.

One Partner’s Experience: Company A

During 2000, this company surveyed 86 facilities and found leaks at 48

sites. A total of 105 leaks were iden tified, and 66 leaks (63 percent) were repaired. The total cost to find and fix the leaks was $2,453, an average of $29 per facility surveyed. Total gas savings were 1,519 Mcf per year, worth $6,557 at $3 per Mcf. Total savings from DI&M was $4,104. Net savings were approximately $50 per facility surveyed.

Total Gas Savings $6,557

Total Survey Costs $1,700

Total Cost of Repairs $753

Net Savings $4,104

One Partner’s Experience: Company B

Eighteen facilities were surveyed in 1997 for a total cost of $1,080. Fifteen small leaks were identified including 1 flange, 2 swage lock fittings, and 12 small valves. The average leak rate was 17.5 Mcf per year. The 15 leaks were repaired for a total cost of $380, which resulted in gas savings of 263 Mcf per year. At $3 per Mcf, the value of the gas saved was $789. The total cost of the leak survey an d repairs, $1,460, was not recovered in the first year. The average survey and repair cost was $60 per facility surveyed.

Total Gas Savings $789

Total Survey Costs $1,080

Total Cost of Repairs $380

Net Savings $(671)

8

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

Exhibit 7: Example of Estimating the Savings from Implementing DI&M at Gate Stations and Surface

Facilities

General Assumptions:

Leak Screening by soaping; 80 components per hour 2 hours x $/hour labor cost

Leak measurement using TVA correlations 1 hour x $/hour labor cost

Hourly labor rate $50/hour

TVA capital cost $0 (assume already owned by partner) 1

Estimated repair life 12 months

Site 1

Number of leaks 20 leaks (six valves repaired —2 x 30 Mcf/yr; 2 x 10 Mcf/yr; 2 x 1 Mcf/yr)

Hypothetical repair cost Assume 3 repairs x $10 and 3 repairs at $3

Total gas savings 82 Mcf

Site 2

Number of leaks (assume fewer leaks to measure) 8 leaks (2 x 10 Mcf/yr; 6 x 2 Mcf/yr)

Hypothetical repair cost Assume 2 repairs x $5; 6 repairs at no cost

Total gas savings 32 Mcf

Site 3

Number of leaks 16 leaks (1 x 60 Mcf/yr; 2 x 30 Mcf/yr; 1 x 15 Mcf/yr; 6 x 10 Mcf/yr; 6 x 1 Mcf/yr)

Hypothetical repair cost Assume 1 repair x $33; 2 repair x $15; 5 re pair x $3; remaining repairs at no cost

Total gas savings 201 Mcf

Total Survey Cost Total Repair Cost Value of Gas Saved Payback Period (months)

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

Site 1 $150 $39 $246 $410 $574 10 Months 6 Months 4 Months

Site 2 $125 $10 $96 $160 $224 17 Months 11 Months 8 Months

Site 3 $150 $78 $603 $1,005 $1,407 5 Months 3 Months 2 Months

Total $425 $127 $945 $1,575 $2,205 7 months 5 Months 3 Months

1 TVAs can cost up to $2,000. Savings from avoided emissions may not support purchasing a TVA.

9

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

The number of facilities included in partners’ DI&M programs ranged from less than 20 facilities to more than 2,100 facilities. Leaks were found at 50 percent of facilities, and an average of two leaks were found per leaking facility. The average emissions saved per leak repair was 100 Mcf per leak.

Partner-reported survey and repair costs varied substantially. Incremental co sts for DI&M surveys ranged from “negligible” for partners with ongoing leak inspection programs already in place, to more than $1,200 per facility. The highest DI&M survey cost s were reported for large distribution systems in urban areas where labor costs are higher, and the gate stations are presumed to be larger and to have more components. Repo rted repair costs similarly ranged from negligible for simp le repairs made on the spot, to more than $500 per repair.



### 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 pr iorities for a leak repair schedule. The principal lessons learned from Natural Gas STAR partners are:

 To be cost-effective, DI&M at gate stations and
surface facilities must use th e most low cost and rapid screening and measurement techniques. Soaping, listening for audible leaks, portable gas “sniffers,” and TVAs/OVAs are recommended for leak screening. TVA screening concentrations and EPA’s correlation equations are recommended as a cost-effective method for estimating mass le ak rate, especially if a

One Partner’s Experience: Company C

This company surveyed 306 facilities and identified and repaired 824 leaks. Four leaks were described as “large”, seven were described as “medium”, and the remaining leaks we re described as “small”, meaning that an electronic detector or soaping was required to locate the leak. Total survey and repair costs were approximately $16,500, an average of $54 per site surveyed. Total gas savings were 117,800 Mcf, an average of 143 Mcf per leak. Net savings were approximately $1,100 per facility surveyed (at $3 per Mcf).

Total Gas Savings $353,430

Total Cost of Surveys $16,500 and Repairs

Net Savings $336,930 TVA or OVA is already av ailable at the facility.

 A small number of large leaks contribute to most of a facility’s fugitive methane emissions. Part ners should focus on finding leaks at equipment components thatare cost-effective to repair. One of the most costeffective repairs is simply to tighten valve packings or
loose connections at the time the leak is detected. Partners have found it useful to look for trends, asking questions such as “Do gate valves leak more
than ball valves?”

 Partners have also found that some sites are more leak-prone than others. Tracking of DI&M results may show that some facilities may need more frequent follow-up surveys.

 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.

 Re-screen leaking components after repairs are made to confirm the effectiveness of the repair. A quick way to check the effectiveness of a repair is to use the soap screening method.

 Frequent surveying (e.g., quarterly or twice yearly) during the first year of a DI&M program helps identify components and fa cilities with the highest leak rates and leak recurrence, and builds the information base necessary to direct less frequent surveying in subsequent years.

 Record methane emissions reductions for each gate
station and/or other surface facilities 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 t he Gas Research Institute), personal

communication.

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

Indaco Air Quality Services, Inc., 1995, A High Flow Rate Sampling System for Measuring Leak Rates at Natural Gas Facilities. Report No. GRI

94/0257.38 . Gas Technology Institute (formerly Gas Research

10

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

Institute), Chicago, IL.

Indaco Air Quality Services, Inc., 1998, Trends in Leak Rates at Metering and Regulating Facilities and the Effectiveness of Leak Detection and Repair (LDAR) Programs, Draft Repor t prepared for PRC International, Gas Research Institute, and the U.S. Environmental Protection Agency.

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 10, Metering and Pressure Regulating Stations in Natural Gas Transmission and Distribution, Report No. EPA600-R-96

- 080j.

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

U.S. Environmental Protection Agency, 1995, Protocol for Equipment Leak Emission Estimates, Office of Air Quality Planning and Standards, EPA453-R-95-017, November 1995.

U.S. Environmental Protection Agency, 2001, Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air, EPA430-B-01-002.

U.S. Environmental Protection Agency, 2003, Lessons Learned: Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry, EPA430-B-03-004.

11

# Directed Inspection and Ma intenance at Gate Stati ons and Surface Facilities
(Cont’d)

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

EPA430-B-03-007

October 2003

12