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8.0 EQUIPMENT LEAKS

Leaks from components in the oil and gas sector are a source of pollutant emissions. This 

chapter explains the causes for these leaks, and provides emission estimates for “model” 

facilities in the various segments of the oil and gas sector. In addition, nationwide equipment 

leak emission estimates from new sources are estimated. Programs designed used to reduce 

equipment leak emissions are presented, along with costs, emission reductions, and secondary 

impacts. Finally, this chapter discusses considerations in developing regulatory alternatives for 

equipment leaks.

8.1 Equipment Leak Description

There are several potential sources of equipment leak emissions. Components such as pumps, 

valves, pressure relief valves, flanges, agitators, and compressors are potential sources that can 

leak due to seal failure. Other sources, such as open-ended lines, and sampling connections may 

leak for reasons other than faulty seals. In addition, corrosion of welded connections, flanges, 

and valves may also be a cause of equipment leak emissions. The following sub-sections 

describe potential equipment leak sources and the magnitude of the volatile emissions from 

typical facilities in the oil and gas industry.

Because of the large number of valves, pumps, and other components within an oil and gas 

production, processing, and transmission facility, total equipment leak VOC emissions from 

these components can be significant. Tank batteries or production pads are generally small 

facilities as compared with other oil and gas operations, and are generally characterized by a 

small number of components. Natural gas processing plants, especially those using refrigerated 

absorption, and transmission stations tend to have a large number of components.

8.2. Equipment leak Emission Data and Emissions Factors

5.2.1 Summary of Major Studies and Emission Factors

Emissions data from equipment leaks have been collected for chemical manufacturing and 

petroleum production to develop control strategies for reducing HAP and VOC emissions from 

these sources.123In recent years, studies have been conducted to estimate greenhouse gas 
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8-2

emissions from equipment leaks. A summary of these studies is presented in Table 8-1, along 

with an indication of the type of information contained in the study.

8.2.2 Model Plants

Facilities in the oil and gas sector can consist of a variety of combinations of process equipment 

and components. This is particularly true in the production segment of the industry, where 

“surface sites” can vary from sites where only a wellhead and associated piping is located to sites 

where a substantial amount of separation, treatment, and compression occurs. In order to 

conduct analyses to be used in evaluating potential options to reduce emissions from leaking 

equipment, a model plant approach was used. The following sections discuss the creation of 

these model plants.

Information related to equipment counts was obtained from a natural gas industry report. This 

document provided average equipment counts for gas production, gas processing, natural gas 

transmission and distribution. These average counts were used to develop model plants for 

wellheads, well pads, and gathering line and boosting stations in the production segment of the 

industry, for a natural gas processing plant, and for a compression/transmission station in the 

natural gas transmission segment. These equipment counts are consistent with those contained in 

subpart W. These model plants are discussed in the following sections.

8.2.2.1 Oil and Natural Gas Production

Oil and natural gas production varies from site-to site. Many production sites may include only a 

wellhead extracting oil or natural gas from the ground. Other production sites consist of 

wellheads attached to a well pad. A well pad is a site where the production, extraction, recovery, 

lifting, stabilization, separation or treating of petroleum and/or natural gas (including 

condensate) occurs. These sites include all equipment (including piping and associated 

components, compressors, generators, separators, storage vessels, and other equipment) 

associated with these operations. A well pad can serve one well on a pad or several wells on a 

pad. A wellhead site consisting of only the wellhead and affiliated piping is not considered to be 

a well pad. The number of wells feeding into a well pad can vary from one to as many as 7

wells. Therefore, the number of components with potential for equipment leaks can vary 
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Table 8-1. Major Studies Reviewed for Consideration or Emissions and Activity Data

Report Name Affiliation Year of 

Report

Activity

Factor (s)

Emissions 

Data

Control 

Options

Greenhouse Gas Mandatory 

Reporting Rule and Technical 

Supporting Documents 

U.S. Environmental 

Protection Agency 2010 Nationwide X X

Inventory of Greenhouse Gas 

Emissions and Sinks: 1990-20084

U.S. Environmental 

Protection Agency 2010 Nationwide X

Methane Emissions from the 

Natural Gas Industry567

Gas Research Institute 

/ US Environmental 

Protection Agency

1996 Nationwide X X

Methane Emissions from the US 

Petroleum Industry (Draft) 8

U.S. Environmental 

Protection Agency 1996 Nationwide X

Methane Emissions from the US 

Petroleum Industry 9

U.S. Environmental 

Protection Agency 1999 Nationwide X

Oil and Gas Emission Inventories 

for Western States 10

Western Regional Air 

Partnership 2005 Regional X X

Recommendations for 

Improvements to the Central States 

Regional Air Partnership's Oil and 

Gas Emission Inventories 11

Central States 

Regional Air 

Partnership

2008 Regional X X

Oil and Gas Producing Industry in 

Your State12

Independent 

Petroleum Association 

of America

2009 Nationwide

Emissions from Natural Gas 

Production in the Barnett Shale and 

Opportunities for Cost-effective 

Improvements 13

Environmental 

Defense Fund 2009 Regional X X

Emissions from oil and Natural 

Gas Production Facilities 14

Texas Commission for 

Environmental Quality 2007 Regional X X

Petroleum and Natural Gas 

Statistical Data15

U.S. Energy 

Information 

Administration

2007-

2009 Nationwide

Preferred and Alternative Methods 

for Estimating Air Emissions from 

Oil and Gas Field Production and 

Processing Operations 16

U.S. Environmental 

Protection Agency 1999 X X

Protocol for Equipment Leak 

Emission Estimates17

U.S. Environmental 

Protection Agency 1995 Nationwide X X

Natural Gas Star Program U.S. Environmental 

Protection Agency

2000-

2010

Nationwide/

Regional X X
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depending on the number of wells feeding into the production pad and the amount of processing 

equipment located at the site. 

In addition to wellheads and well pads, model plants were developed for gathering lines and 

boosting stations. The gathering lines and boosting stations are sites that collect oil and gas from 

well pads and direct them to the gas processing plants. These stations have similar equipment to 

well pads; however they are not directly connected to the wellheads. 

The EPA/GRI report provided the average number of equipment located at a well pad and the 

average number of components for each of these pieces of equipment.4The type of production 

equipment located at a well pad include: gas wellheads, separators, meters/piping, gathering 

compressors, heaters, and dehydrators. The types of components that are associated with this 

equipment include: valves, connectors, open-ended lines, and pressure relief valves. Four model 

plants were developed for well pads and are presented in Table 8-2. These model plants were 

developed starting with one, three, five and seven wellheads, and adding the average number of 

other pieces of equipment per wellhead. Gathering compressors are not included at well pads 

and were included in the equipment for gathering lines and boosting stations.

Table 8-2. Average Equipment Count for Oil and Gas Production Well Pad Model Plants

Equipment Model Plant 

1

Model Plant 

2

Model Plant 

3

Gas Wellheads 1 5 48

Separators --- 4 40

Meter/Piping --- 2 24

In-Line Heaters --- 2 26

Dehydrators --- 2 19

Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: 

Equipment Leaks, Table 4-4 and Table 4-7, June 1996. (EPA-600/R-96-080h)
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Component counts for each of the equipment items were calculated using the average component 

counts for gas production equipment in the Eastern U.S and the Western U.S. for the EPA/GRI 

document. A summary of the component counts for oil and gas production well pads is 

presented in Table 8-3.

Table 8-3. Average Component Count for Oil and Gas Production Well Pad Model Plants

Component Model Plant 

1

Model Plant 

2

Model Plant 

3

Model Plant 

4

Valve 9 122 235 348

Connectors 37 450 863 1,276

Open-Ended Line 1 15 29 43

Pressure Relief Valve 0 5 10 15

Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: 

Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-080h)

Gathering line and boosting station model plants were developed using the average equipment 

counts for oil and gas production. The average equipment count was assigned Model Plant 2 and 

Model Plants 1 and 3 were assumed to be equally distributed on either side of the average 

equipment count. Therefore, Model Plant 1 can be assumed to be a small gathering and boosting 

station, and Model Plant 3 can be assumed to be a large gathering and boosting station. A 

summary of the model plant production equipment counts for gathering lines and boosting 

stations is provided in Table 8-4.
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Table 8-4. Average Equipment Count for Oil and Gas Production Gathering Line and 

Boosting Station Model Plants

Equipment Model Plant 1 Model Plant 2 Model Plant 3

Separators 7 11 15

Meter/Piping 4 7 10

Gathering Compressors 3 5 7

In-Line Heaters 4 7 10

Dehydrators 3 5 7

Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: 

Equipment Leaks, Table 4-4 and Table 4-7, June 1996. (EPA-600/R-96-080h)

Component counts for each of the equipment items were calculated using the average component 

counts for gas production equipment in the Eastern U.S and the Western U.S. from the EPA/GRI 

document. The components for gathering compressors were included in the model plant total 

counts, but the compressor seals were excluded. Compressors seals are addressed in a separate 

section of this document. A summary of the component counts for oil and gas gathering line and 

boosting stations are presented in Table 8-5.

Table 8-5. Average Component Count for Oil and Gas Production Gathering Line and 

Boosting Station Model Plants

Component Model Plant 1 Model Plant 2 Model Plant 3

Valve 547 906 1,265

Connectors 1,723 2,864 4,005

Open-Ended Line 51 83 115

Pressure Relief Valve 29 48 67

DataSource: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: 

Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-080h)
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8.2.2.2 Oil and Natural Gas Processing

Natural gas processing involves the removal of natural gas liquids from field gas, fractionation of 

mixed natural gas liquids to natural gas products, or both. The types of process equipment used 

to separate the liquids are separators, glycol dehydrators, and amine treaters. In addition, 

centrifugal and/or reciprocating compressors are used to pressurize and move the gas from the 

processing facility to the transmission stations. 

New Source Performance Standards (NSPS) have already been promulgated for equipment leaks 

at new natural gas processing plants (40 CFR Part 60, subpart KKK), and were assumed to be the 

baseline emissions for this analysis. Only one model plant was developed for the processing 

sector. A summary of the model plant production components counts for an oil and gas 

processing facility is provided in Table 8-6.

Table 8-6. Average Component Count for Oil and Gas Processing Model Plant

Component Gas Plant (noncompressor components)

Valve 1,392

Connectors 4,392

Open-Ended Line 134

Pressure Relief Valve 29

Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: 

Equipment Leaks, Table 4-13, June 1996. (EPA-600/R-96-080h)
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8.2.2.3 Natural Gas Transmission/Storage

Natural gas transmission/storage stations are facilities that use compressors that move natural gas 

at elevated pressure from production fields or natural gas processing facilities, in transmission 

pipelines, to natural gas distribution pipelines, or into storage. In addition, transmission stations 

may include equipment for liquids separation, natural gas dehydration, and tanks for the storage 

of water and hydrocarbon liquids. Residue (sales) gas compression operated by natural gas 

processing facilities are included in the onshore natural gas processing segment and are excluded 

from this segment. This source category also does not include emissions from gathering lines 

and boosting stations. Component counts were obtained from the EPA/GRI report and are 

presented in Table 8-7.

Table 8-7. Average Component Count for a Gas Transmission Facility

Component Processing Plant

Component Count

Valve 704

Connection 3,068

Open-Ended Line 55

Pressure Relief Valve 14

Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: 

Equipment Leaks, Table 4-16, June 1996. (EPA-600/R-96-080h)

5.3 Nationwide Emissions from New Sources

5.3.1 Approach

Nationwide emissions were calculated by using the model plant approach for estimating 

emissions. Baseline model plant emissions for the gas production, processing, and transmission 

sectors were calculated using the component counts and the component gas service emission 

factors.5 Annual emissions were calculated assuming 8,760 hours of operation each year. The 

emissions factors are provided for total organic compounds (TOC) and include non-VOCs such 

as methane and ethane. The emission factors for the production and processing sectors that were 
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used to estimate the new source emissions are presented in Table 8-8. Emission factors for the 

transmission sector are presented in Table 8-9. Emissions for VOC, hazardous air pollutants 

(HAP), and methane were calculated using TOC weight fractions.6 A summary of the baseline 

emissions for each of the sectors are presented in Table 8-10.

Table 8-8 Oil and Gas Production and Processing Operations Average Emissions Factors

Component Type Component Service Emission Factor 

(kg/hr/source)

Valves Gas 4.5E-03

Connectors Gas 2.0E-04

Open-Ended Line Gas 2.0E-03

Pressure Relief Valve Gas 8.8E-03

Data Source: EPA, Protocol for Equipment Leak Emission Estimates, Table 2-4, November 

1995. (EPA-453/R-95-017)

Table 8-9 Oil and Gas Transmission/Storage Average Emissions Factors

Component Type Component Service Emission Factor 

(kg/hr/source)

Valves Gas 5.5E-03

Connectors Gas 9.3E-04

Open-Ended Line Gas 7.1E-02

Pressure Relief Valve Gas 3.98E-02

Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: 

Equipment Leaks, Table 4-17, June 1996. (EPA-600/R-96-080h)
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Table 8-10. Baseline Emissions for the Oil and Gas Production, Processing, and Transmission/Storage Model Plants

Oil and Gas Sector Model Plant TOC Emissions 

(Tons/yr)

Methane 

Emissions 

(Tons/yr)

VOC Emissions 

(Tons/yr)

HAP Emissions 

(Tons/yr)

Well Pads

1 0.482 0.335 0.0930 0.00351

2 13.3 9.24 2.56 0.0967

3 139 96.5 26.8 1.01

Gathering & Boosting

1 30.5 21.2 5.90 0.222

2 50.6 35.2 9.76 0.368

3 70.6 49.1 13.6 0.514

Processing 1 74.0 51.4 14.3 0.539

Transmission/Storage 1 108.1 98.1 2.71 0.0806
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8.3.2 Activity Data

Data from oil and gas technical documents and inventories were used to estimate the number of 

new sources for each of the oil and gas sectors. Information from the Energy Information 

Administration (EIA) was used to estimate the number of new wells, well pads, and gathering 

and boosting stations. The number of processing plants and transmission/storage facilities was 

estimated using data from the Oil and Gas Journal, and the EPA Greenhouse Gas Inventory. A 

summary of the steps used to estimate the new sources for each of the oil and gas sectors is 

presented in the following sections.

8.3.2.1 Well Pads

The EIA provided a forecast of the number of new conventional and unconventional gas 

wells for the Year 2015 for both exploratory and developmental wells. The EIA projected 

19,097 conventional and unconventional gas wells in 2015. The number of wells was converted 

to number of well pads by dividing the total number of wells by the average number of wells 

serving a well pad which is estimated to be 5. Therefore, the number of new well pads was 

estimated to be 3,820. The facilities were divided into the model plants assuming a normal 

distribution of facilities around the average model plant (Model Plant 2).

8.3.2.2 Gathering and Boosting

The number of new gathering and boosting stations was estimated using the current 

inventory of gathering compressors listed in the EPA Greenhouse Gas Inventory. The total 

number of gathering compressors was listed as 32,233 in the inventory. The GRI/EPA document 

does not include a separate list of compressor counts for gathering and boosting stations, but it 

does list the average number of compressors in the gas production section. It was assumed that 

this average of 4.5 compressors for gas production facilities is applicable to gathering and 

boosting stations. Therefore, using the inventory of 32,233 compressors and the average number 

of 4.5 compressors per facility, we estimated the number of gathering and boosting stations to be 

7,163. To estimate the number of new gathering and boosting stations, we used the same 

increase of 3.84% used to estimate well pads to estimate the number of new gathering and 

boosting stations. This provided an estimate of 275 new gathering and boosting stations that 
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would be affected sources under the proposed NSPS. The new gathering and boosting stations 

were assumed to be normally distributed around the average model plant (Model Plant 2). 

8.3.2.3 Processing Facilities

The number of new processing facilities was estimated using gas processing data from 

the Oil and Gas Journal. The Oil and Gas Journal Construction Survey currently shows 6,303 

million cubic feet of gas per day (MMcf/day) additional gas processing capacity in various stages 

of development. The OGJ Gas Processing Survey shows that there is 26.9 trillion cubic feet per 

year (tcf/year) in existing capacity, with a current throughput of 16.6 tcf/year or 62% utilization 

rate. If the utilization rate remains constant, the new construction would add approximately 1.4 

tcf/year to the processing system. This would be an increase of 8.5% to the processing sector. 

The recent energy outlook published by the EIA predicts a 1.03 tcf/year increase in natural gas 

processing from 21.07 to 22.104 tcf/year. This would be an annual increase of 5% over the next 

five years. 

The EPA Greenhouse Gas Inventory estimates the number of existing processing 

facilities to be 577 plants operating in the U.S. Based on the projections provided in Oil and Gas 

Journal and EIA, it was assumed that the processing sector would increase by 5% annually. 

Therefore the number of new sources was estimated to be 29 new processing facilities in the U.S.

8.3.2.4 Transmission/Storage Facilities

The number of new transmission and storage facilities was estimated using the annual 

growth rate of 5% used for the processing sector and the estimated number of existing 

transmission and storage facilities in the EPA Greenhouse Inventory. The inventory estimates 

1,748 transmission stations and 400 storage facilities for a total of 2,148. Therefore, the number 

of new transmission/storage facilities was estimated to be 107.

8.3.3 Emission Estimates

Nationwide emission estimates for the new sources for well pads, gathering and boosting, 

processing, and transmission/storage are summarized in Table 8-11. For well pads and gathering 
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Table 8-11. Nationwide Baseline Emissions for New Sources

Oil and Gas Sector Model Plant Number of 

New Facilities

TOC 

Emissions 

(Tons/yr)

Methane 

Emissions 

(Tons/yr)

VOC 

Emissions 

(Tons/yr)

HAP 

Emissions 

(Tons/yr)

Well Pads

1 605 292 203 56.3 2.12

2 2,610 34,687 24,116 6,682 252

3 605 84,035 58,389 16,214 612

Total 3,820 119,014 82,708 22,952 866

Gathering & 

Boosting

1 44 1,312 912 254 9.55

2 187 9,513 6,618 1,835 69.2

3 44 3,106 2,160 598 22.6

Total 275 13,931 9,690 2,687 101

Processing 1 29 2,146 1,490 415 15.6

Transmission/Storage 1 107 11,567 10,497 290 8.62
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and boosting stations, the numbers of new facilities were assumed to be normally distributed 

across the range of model plants.

8.4 Control Techniques

EPA has determined that leaking equipment, such as valves, pumps, and connectors, are a 

significant source of VOC and HAP emissions from oil and gas facilities. The following section 

describes the techniques used to reduce emissions from these sources.

8.4.1 Potential Control Techniques

The most effective control technique for equipment leaks is the implementation of a leak 

detection and repair program (LDAR). Emissions reductions from implementing an LDAR 

program can potentially reduce product losses, increase safety for workers and operators, 

decrease exposure of hazardous chemicals to the surrounding community, reduce emissions fees, 

and help facilities avoid enforcement actions. The elements of an effective LDAR program 

include:

Identifying Components;

Leak Definition;

Monitoring Components;

Repairing Components; and

Recordkeeping.

The primary source of equipment leak emissions from oil and gas facilities are from valves and 

connectors, because these are the most prevalent components and can number in the thousands. 

The major cause of emissions from valves and connectors is a seal or gasket failure due to 

normal wear or improper maintenance. A leak is detected whenever the measured concentration 

exceeds the threshold standard (i.e., leak definition) for the applicable regulation. Leak 

definitions vary by regulation, component type, service (e.g., light liquid, heavy liquid, 

gas/vapor), and monitoring interval. Most NSPS regulations have a leak definition of 10,000 

ppm, while many NESHAP regulations use a 500-ppm or 1,000-ppm leak definition. In 

addition, some regulations define a leak based on visual inspections and observations (such as 
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fluids dripping, spraying, misting or clouding from or around components), sound (such as 

hissing), and smell.

For many NSPS and NESHAP regulations with leak detection provisions, the primary method 

for monitoring to detect leaking components is EPA Reference Method 21 (40 CFR Part 60, 

Appendix A). Method 21 is a procedure used to detect VOC leaks from process equipment using 

toxic vapor analyzer (TVA) or organic vapor analyzer (OVA). In addition, other monitoring 

tools such as; infrared camera, soap solution, acoustic leak detection, and electronic screening 

device, can be used to monitor process components. 

In optical gas imaging, a live video image is produced by illuminating the view area with laser 

light in the infrared frequency range. In this range, hydrocarbons absorb the infrared light and 

are revealed as a dark image or cloud on the camera. The passive infrared cameras scan an area 

to produce images of equipment leaks from a number of sources. Active infrared cameras point 

or aim an infrared beam at a potential source to indicate the presence of equipment leaks. The 

optical imaging camera is easy to use and very efficient in monitoring many components in a 

short amount of time. However, the optical imaging camera cannot quantify the amount or 

concentration of equipment leak. To quantify the leak, the user would need to measure the 

concentration of the leak using a TVA or OVA. In addition, the optical imaging camera has a 

high upfront capital cost of purchasing the camera. 

Acoustic leak detectors measure the decibel readings of high frequency vibrations from the noise 

of leaking fluids from equipment leaks using a stethoscope-type device. The decibel reading, 

along with the type of fluid, density, system pressure, and component type can be correlated into 

leak rate by using algorithms developed by the instrument manufacturer. The acoustic detector 

does not decrease the monitoring time because components are measured separately, like the 

OVA or TVA monitoring. The accuracy of the measurements using the acoustic detector can 

also be questioned due to the number of variables used to determine the equipment leak 

emissions.

Monitoring intervals vary according to the applicable regulation, but are typically weekly, 

monthly, quarterly, and yearly. For connectors, the monitoring interval can be every 1, 2, 4, or 8 

years. The monitoring interval depends on the component type and periodic leak rate for the 
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8-16

component type. Also, many LDAR requirements specify weekly visual inspections of pumps, 

agitators, and compressors for indications of liquids leaking from the seals. For each component

that is found to be leaking, the first attempt at repair is to be made no later than five calendar 

days after each leak is detected. First attempts at repair include, but are not limited to, the 

following best practices, where practicable and appropriate:

Tightening of bonnet bolts;

Replacement of bonnet bolts;

Tightening of packing gland nuts; and

Injection of lubricant into lubricated packing.

Once the component is repaired; it should be monitored daily over the next several days to 

ensure the leak has been successfully repaired. Another method that can be used to repair 

component is to replace the leaking component with “leakless” or other technologies. 

The LDAR recordkeeping requirement for each regulated process requires that a list of all ID 

numbers be maintained for all equipment subject to an equipment leak regulation. A list of 

components that are designated as “unsafe to monitor” should also be maintained with an 

explanation/review of conditions for the designation. Detailed schematics, equipment design 

specifications (including dates and descriptions of any changes), and piping and instrumentation 

diagrams should also be maintained with the results of performance testing and leak detection 

monitoring, which may include leak monitoring results per the leak frequency, monitoring 

leakless equipment, and non-periodic event monitoring. 

Other factors that can improve the efficiency of an LDAR program that are not addressed by the 

standards include training programs for equipment monitoring personnel and tracking systems 

that address the cost efficiency of alternative equipment (e.g., competing brands of valves in a 

specific application).

The first LDAR option is the implementation of a subpart VVa LDAR program. This program is 

similar to the VV monitoring, but finds more leaks due to the lower leak definition, thereby 

achieving better emission reductions. The VVa LDAR program requires the annual monitoring 

of connectors using an OVA or TVA (10,000 ppm leak definition), monthly monitoring of valves
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(500 ppm leak definition) and requires open-ended lines and pressure relief devices to operate 

with no detectable emissions (500 ppm leak definition). The monitoring of each of the 

equipment types were also analyzed as a possible option for reducing equipment leak emissions. 

The second option involves using the monitoring requirements in subpart VVa for each type of 

equipment which include: valves; connectors; pressure relief devices; and open-ended lines for 

each of the oil and gas sectors.

The third option that was investigated was the implementation of a LDAR program using an 

optical gas imaging system. This option is currently available as an alternative work practice (40 

CFR Part 60, subpart A) for monitoring emissions from equipment leaks in subpart VVa. The 

alternative work practice requires monthly monitoring of all components using the optical gas 

imaging system and an annual monitoring of all components using a Method 21 monitoring 

device. The Method 21 monitoring allows the facility to quantify emissions from equipment 

leaks, since the optical gas imaging system can only provide the magnitude of the equipment 

leaks.

A fourth option that was investigated is a modification of the 40 CFR Part 60, subpart A 

alternative work practice. The alternative work practice was modified by removing the required 

annual monitoring using a Method 21 instrument. This option only requires the monthly 

monitoring of components using the optical gas imaging system.

8.4.2 Subpart VVa LDAR Program

8.4.2.1 Description

The subpart VVa LDAR requires the monitoring of pumps, compressors, pressure relief devices, 

sampling connection systems, open-ended lines, valves, and connectors. These components are 

monitored with an OVA or TVA to determine if a component is leaking and measure the 

concentration of the organics if the component is leaking. Connectors, valves, and pressure 

relief devices have a leak definition of 500 parts per million by volume (ppmv). Valves are 

monitored monthly, connectors are monitored annually, and open-ended lines and pressure relief 

valves have no monitoring requirements, but are required to operate without any detectable 

emissions. Compressors are not included in this LDAR option and are regulated separately.
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8.4.2.2 Effectiveness

The control effectiveness of the LDAR program is based on the frequency of monitoring, 

leak definition, frequency of leaks, percentage of leaks that are repaired, and the percentage of 

reoccurring leaks. A summary of the chemical manufacturing and petroleum refinery control 

effectiveness for each of the components is shown in Table 8-12. As shown in the table the 

control effectiveness for all of the components varies from 45 to 96% and is dependent on the 

frequency of monitoring and the leak definition. Descriptions of the frequency of monitoring 

and leak definition are described further below.

Monitoring Frequency: The monitoring frequency is the number of times each component is 

checked for leaks. For an example, quarterly monitoring requires that each component be 

checked for leaks 4 times per year, and annual monitoring requires that each component be 

checked for leaks once per year. As shown in Table 8-12, monthly monitoring provides higher 

control effectiveness than quarterly monitoring. This is because leaking components are found 

and repaired more quickly, which lowers the amount of emissions that are leaked to the 

atmosphere.

Leak Definition: The leak definition describes the local VOC concentration at the surface of a 

leak source that indicates that a VOC emission (leak) is present. The leak definition is an 

instrument meter reading based on a reference compound. Decreasing the leak definition 

concentration generally increases the number of leaks found during a monitoring period, which 

generally increases the number of leaks that are repaired. 

The control effectiveness for the well pad, gathering and boosting stations, processing facilities, 

and transmissions and storage facilities were calculated using the LDAR control effectiveness 

and leak fraction equations for oil and gas production operation units in the EPA equipment 

leaks protocol document. The leak fraction equation uses the average leak rate (e.g., the 

component emission factor) and leak definition to calculate the leak fraction.7 This leak fraction 

is used in a steady state set of equations to determine the final leak rate after implementing a 

LDAR program.8 The initial leak rate and the final leak rate after implementing a LDAR 

program were then used to calculate the control effectiveness of the program. The control 
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July 22, 2011. 

8-19

effectiveness for implementing a subpart VVa LDAR program was calculated to be 93.6% for 

valves, 95.9% for connectors, 100% for open-ended lines, and 100% for pressure relief devices. 

8.4.2.3 Cost Impacts

Costs were calculated using a LDAR cost spreadsheet developed for estimating capital and 

annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing 

industry. The costs are based on the following assumptions:

Subpart VVa monitoring frequency and leak definition were used for processing plants 

since they are already required to do subpart VV requirements. Connectors were assumed 

to be monitored over a 4-year period after initial annual compliance monitoring.

Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for 

pressure relief valve disks, $3,852 for pressure relief valve disk holder and valves, and 

$102 for open-ended lines.

Subsequent monitoring costs are $1.50 for valves and connectors, $2.00 for pressure 

relief valve disks, and $5.00 for pressure relief valve devices and open-ended lines.

A wage rate of $30.46 per hour was used to determine labor costs for repair.

Administrative costs and initial planning and training costs are based on the 

Miscellaneous Organic NESHAP (MON) analysis. The costs were based on 340 hours 

for planning and training and 300 hours per year for reporting and administrative tasks at 

$48.04 per hour.

The capital cost also includes $14,500 for a data collection system for maintaining the 

inventory and monitoring records for the components at a facility.

Recovery credits were calculated assuming the methane reduction has a value of $4.00 

per 1000 standard cubic feet.

It was assumed that a single Method 21 monitoring device could be used at multiple locations for 

production pads, gathering and boosting stations, and transmission and storage facilities. To 

calculate the shared cost of the Method 21 device, the time required to monitor a single facility 

was estimated. For production pads and gathering and boosting stations, it was assumed that it 

takes approximately 1 minute to monitor a single component, and approximately 451 

components would have to be monitored at an average facility in a month. This calculates to be 
Internal Draft. Do not Cite, Quote or Distribute. 

July 22, 2011. 

8-20

451 minutes or 7.5 hours per day. Assuming 20 working days in a typical month, a single 

Method 21 device could monitor 20 facilities. Therefore, the capital cost of the Method 21 

device ($6,500) was divided by 20 to get a shared capital cost of $325 per facility. It was 

assumed for processing facilities that the full cost of the Method 21 monitoring device would 

apply to each individual plant. The transmission and storage segment Method 21 device cost 

was estimated using assuming the same 1 minute per component monitoring time. The average 

number of components that would need to be monitored in a month was estimated to be 1,440, 

which calculates to be 24 hours of monitoring time or 3 days. Assuming the same 20 day work 

month, the total number of facilities that could be monitored by a single Method 21 device is 7. 

Therefore, the shared cost of the Method 21 monitoring device was calculated to be $929 per 

site.

A summary of the capital and annual costs and the cost effectiveness for each of the model plants 

in the oil and gas sectors are provided in Table 8-13. In addition to the full subpart VVa LDAR 

monitoring, a component by component LDAR analysis was performed for each of the oil and 

gas sectors using the component count for an average size facility. This Model Plant 2 for well 

pads, Model Plant 2 for gathering and boosting stations, and Model Plant 1 for processing plants 

and transmission and storage facilities.

The component costs were calculated using a LDAR cost spreadsheet developed for estimating 

capital and annual costs for applying LDAR to the Petroleum Refinery and Chemical 

Manufacturing industry. The costs are based on the following assumptions:

Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for 

pressure relief valve disks, $3,852 for pressure relief valve disk holder and valves, and 

$102 for open-ended lines.

Subsequent monitoring costs are $1.50 for valves and connectors, $2.00 for pressure 

relief valve disks, and $5.00 for pressure relief valve devices and open-ended lines.

A wage rate of $30.46 per hour was used to determine labor costs for repair.

Administrative costs and initial planning and training costs are were included for the 

component option and are based on the Miscellaneous Organic NESHAP (MON) 
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July 22, 2011. 

8-21

analysis. The costs were based on 340 hours for planning and training and 300 hours per 

year for reporting and administrative tasks at $48.04 per hour. 

The capital cost for purchasing a TVA or OVA monitoring system was estimated to be 

$6,500.

The component control effectiveness’s for the subpart VVa component option were 93.6% for 

valves, 95.9% for connectors, 100% for open-ended lines, and 100% for pressure relief devices. 

These were the same control effectiveness’s that were used for the subpart VVa facility option. 

The control effectiveness for the modified subpart VVa option with less frequent monitoring was 

estimated assuming the control effectiveness follows a hyperbolic curve or a 1/x relationship 

with the monitoring frequency. Using this assumption the component cost effectiveness’s were 

determined to be 87.2% for valves, 81.0% for connectors, 100% for open-ended lines, and 100% 

for pressure relief devices. The assumption is believed to provide a conservative estimate of the 

control efficiency based on less frequent monitoring. A summary of the capital and annual costs 

and the cost effectiveness for each of the components for each of the oil and gas sectors are 

provided in Tables 8-14, 8-15, 8-16, and 8-17.

8.4.2.4 Secondary Impacts

The implementation of a LDAR program reduces pollutant emissions from equipment 

leaks. No secondary gaseous pollutant emissions or wastewater are generated during the 

monitoring and repair of equipment leaks. Therefore, there are no secondary impacts expected 

from the implementation of a LDAR program.
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July 22, 2011. 

8-22

Table 8-13. Summary of the Model Plant Cost Effectiveness for the Subpart VVa Option

Model Plant

VOC 

Emission 

Reduction

(Tons/yr)

HAP 

Emission 

Reductions 

(Tons/yr)

Methane 

Emission 

Reductions 

(Tons/yr)

Capital Cost 

($)

Annual Cost 

($/yr)

Annual Cost 

w/ Recovery 

Credits 

($/yr)

VOC Cost 

Effectiveness

($/Ton)

HAP Cost 

Effectiveness 

($/Ton)

Methane 

Cost 

Effectiveness

($/Ton)

Well Pads

1 0.0876 0.00330 0.315 $15,418 $23,423 $23,363 $267,386 $7,088,667 $74,253

2 2.43 0.0915 8.73 $69,179 $37,711 $36,033 $15,549 $412,226 $4,318

3 25.3 0.956 91.3 $584,763 $175,753 $158,213 $6,934 $183,835 $1,926

Gathering and Boosting Stations

1 5.58 0.210 20.1 $148,885 $57,575 $53,717 $10,327 $273,769 $2,868

2 9.23 0.348 33.2 $255,344 $84,966 $78,577 $9,203 $243,987 $2,556

3 12.9 0.486 46.4 $321,203 $105,350 $96,431 $8,174 $216,692 $2,270

Processing Plants

1 13.5 0.508 48.5 $7,522 $45,160 $33,915 $3,352 $88,870 $931

Transmission/Storage Facilities

1 2.62 0.0780 94.9 $94,482 $51,875 N/A $19,769 $665,155 $546

Note: Transmission and storage facilities do not own the natural gas; therefore they do not receive any cost benefits from reducing the 

amount of natural gas as the result of equipment leaks.
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July 22, 2011. 

8-23

Table 8-14. Summary of Component Cost Effectiveness for Well Pads for the Subpart VVa Options

Component

Average 

Number of 

Components

Monitoring 

Frequency 

(Times/yr)

VOC 

Emission 

Reduction

(Tons/yr)

HAP 

Emission 

Reductions 

(Tons/yr)

Methane 

Emission 

Reductions 

(Tons/yr)

Capital

Cost ($)

Annual 

Cost 

($/yr)

VOC Cost 

Effectiveness

($/Ton)

HAP Cost 

Effectiveness 

($/Ton)

Methane 

Cost 

Effectiveness

($/Ton)

Subpart VVa Option

Valves 235 12 1.84 0.0696 6.64 $11,175 $27,786 $15,063 $399,331 $4,183

Connectors 863 1/0.25a0.308 0.0116 1.11 $7,830 $22,915 $74,283 $1,969,328 $20,628

PRD 10 0 0.164 0.00619 0.591 $48,800 $29,609 $180,537 $4,786,215 $50,135

OEL 29 0 0.108 0.00408 0.389 $9,458 $22,915 $211,992 $5,620,108 $58,870

Modified Subpart VVa – Less Frequent Monitoring

Valves 235 1 1.31 0.0496 4.73 $11,175 $23,436 $17,828 $472,640 $4,951

Connectors 863 1/0.125b0.261 0.00983 0.938 $7,830 $22,740 $87,277 $2,313,795 $24,237

PRD 5 0 0.164 0.00619 0.591 $48,800 $29,609 $180,537 $4,786,215 $50,135

OEL 29 0 0.108 0.00408 0.389 $9,458 $22,915 $211,992 $5,620,108 $58,870

a

It was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter.

b

It was assumed that all the connectors are monitored in the first year for initial compliance and every 8 years thereafter.
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July 22, 2011. 

8-24

Table 8-15. Summary of Component Cost Effectiveness for Gathering and Boosting Stations for the Subpart VVa Options

Component

Average 

Number of 

Components

Monitoring 

Frequency 

(Times/yr)

VOC 

Emission 

Reduction

(Tons/yr)

HAP 

Emission 

Reductions 

(Tons/yr)

Methane 

Emission 

Reductions 

(Tons/yr)

Capital

Cost ($)

Annual 

Cost 

($/yr)

VOC Cost 

Effectiveness

($/Ton)

HAP Cost 

Effectiveness 

($/Ton)

Methane 

Cost 

Effectiveness

($/Ton)

Subpart VVa Option

Valves 906 12 7.11 0.268 25.6 $24,524 $43,234 $6,079 $161,162 $1,688

Connectors 2,864 1/0.25a1.02 0.0386 3.69 $10,914 $24,164 $23,603 $625,752 $6,555

PRD 48 0 0.787 0.0297 2.83 $195,140 $57,091 $72,523 $1,922,648 $20,139

OEL 83 0 0.309 0.0117 1.11 $14,966 $23,917 $77,310 $2,049,557 $21,469

Modified Subpart VVa – Less Frequent Monitoring

Valves 906 1 5.07 0.191 18.2 $24,524 $24,461 $5,221 $138,417 $1,450

Connectors 2,864 1/0.125b0.865 0.0326 3.11 $10,914 $23,584 $27,274 $723,067 $7,574

PRD 48 0 0.787 0.0297 2.83 $195,140 $57,091 $72,523 $1,922,648 $20,139

OEL 83 0 0.309 0.0117 1.11 $14,966 $23,917 $77,310 $2,049,557 $21,469

a

It was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter.

b

It was assumed that all the connectors are monitored in the first year for initial compliance and every 8 years thereafter.
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July 22, 2011. 

8-25

Table 8-16. Summary of Incremental Component Cost Effectiveness for Processing Plants for the Subpart VVa Option

Component

Average 

Number of 

Components

Monitoring 

Frequency 

(Times/yr)

VOC 

Emission 

Reduction

(Tons/yr)

HAP 

Emission 

Reductions 

(Tons/yr)

Methane 

Emission 

Reductions 

(Tons/yr)

Capital

Cost ($)

Annual 

Cost 

($/yr)

VOC Cost 

Effectiveness

($/Ton)

HAP Cost 

Effectiveness 

($/Ton)

Methane 

Cost 

Effectiveness

($/Ton)

Incremental Component Cost for Subpart VV to Subpart VVa Option

Valves 1,392 12 10.9 0.412 39.3 $6,680 $1,576 $144 $3,824 $40

Connectors 4,392 1/0.25a1.57 0.0592 5.65 $2,559 $6,845 $4,360 $115,585 $1,211

PRD 29 0 0.499 0.0188 1.80 $0 $0 $0 $0 $0

OEL 134 0 0.476 0.0179 1.71 $0 $0 $0 $0 $0

a

It was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter.
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July 22, 2011. 

8-26

Table 8-17. Summary of Component Cost Effectiveness for Transmission and Storage Facilities for the Subpart VVa Options

Component

Average 

Number of 

Components

Monitoring 

Frequency 

(Times/yr)

VOC 

Emission 

Reduction

(Tons/yr)

HAP 

Emission 

Reductions 

(Tons/yr)

Methane 

Emission 

Reductions 

(Tons/yr)

Capital

Cost ($)

Annual 

Cost 

($/yr)

VOC Cost 

Effectiveness

($/Ton)

HAP Cost 

Effectiveness 

($/Ton)

Methane 

Cost 

Effectiveness

($/Ton)

Subpart VVa Option

Valves 673 12 0.878 0.0261 31.8 $19,888 $37,870 $43,111 $1,450,510 $1,192

Connectors 3,068 1/0.25a0.665 0.0198 24.1 $11,229 $24,291 $36,527 $1,229,005 $1,010

PRD 14 0 0.133 0.00397 4.83 $61,520 $32,501 $243,525 $8,193,684 $6,732

OEL 58 0 0.947 0.0282 34.3 $12,416 $23,453 $24,762 $833,137 $684

Modified Subpart VVa – Less Frequent Monitoring

Valves 673 1 0.626 0.0186 22.6 $19,888 $25,410 $40,593 $1,365,801 $1,122

Connectors 3,068 1/0.125b0.562 0.0167 20.3 $11,229 $23,669 $42,140 $1,417,844 $1,165

PRD 14 0 0.133 0.00397 4.83 $61,520 $32,501 $243,525 $8,193,684 $6,732

OEL 58 0 0.947 0.0282 34.3 $12,416 $23,453 $24,762 $833,137 $684

a

It was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter.

b

It was assumed that all the connectors are monitored in the first year for initial compliance and every 8 years thereafter.
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July 22, 2011. 

8-27

8.4.3 LDAR with Optical Gas Imaging

8.4.3.1 Description

The alternative work practice for equipment leaks in §60.18 of 40 CFR Part 60, subpart A allows 

the use of an optical gas imaging system to monitor leaks from components. This LDAR

requires monthly monitoring and repair of components using an optical gas imaging system, and 

annual monitoring of components using a Method 21 instrument. This requirement does not 

have a leak definition because the optical gas imaging system can only measure the magnitude of 

a leak and not the concentration. However, this alternative work practice does not require the 

repair of leaks below 500 ppm. Compressors are not included in this LDAR option and are 

regulated separately.

8.4.3.2 Effectiveness

No data was found on the control effectiveness of the alternative work practice. It is believed 

that this option would provide the same control effectiveness as the subpart VVa monitoring 

program. Therefore, the control effectiveness’s for implementing an alternative work practice 

was assumed to be 93.6% for valves, 95.9% for connectors, 100% for open-ended lines, and 

100% for pressure relief devices. 

8.4.3.3 Cost Impacts

Costs were calculated using a LDAR cost spreadsheet developed for estimating capital and 

annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing 

industry. The costs are based on the following assumptions:

Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for 

pressure relief valve disks, $3,852 for pressure relief valve disk holder and valves, and 

$102 for open-ended lines.

Monthly optical gas imaging monitoring costs are estimated to be $0.50 for valves, 

connectors, pressure relief valve devices, and open-ended lines.
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July 22, 2011. 

8-28

Annual monitoring costs using a Method 21 device are estimated to be $1.50 for valves 

and connectors, $2.00 for pressure relief valve disks, and $5.00 for pressure relief devices 

and open-ended lines.

A wage rate of $30.46 per hour was used to determine labor costs for repair.

Administrative costs and initial planning and training costs are based on the 

Miscellaneous Organic NESHAP (MON) analysis. The costs were based on 340 hours 

for planning and training and 300 hours per year for reporting and administrative tasks at 

$48.04 per hour. 

The capital cost also includes $14,500 for a data collection system for maintaining the 

inventory and monitoring records for the components at a facility.

Recovery credits were calculated assuming the methane reduction has a value of $4.00 

per 1000 standard cubic feet.

It was assumed that a single optical gas imaging and a Method 21 monitoring device could be 

used at multiple locations for production pads, gathering and boosting stations, and transmission 

and storage facilities. To calculate the shared cost of the optical gas imaging system and the 

Method 21 device, the time required to monitor a single facility was estimated. For production 

pads and gathering and boosting stations, it was assumed that 8 production pads could be 

monitored per day. This means that 160 production facilities could be monitored in a month. In 

addition, it was assumed 13 gathering and boosting station would service these wells and could 

be monitored during the same month for a total of 173 facilities. Therefore, the capital cost of 

the optical gas imaging system (Flir Model GF320, $85,000) and the Method 21 device ($6,500) 

was divided by 173 to get a shared capital cost of $529 per facility. It was assumed for 

processing facilities that the full cost of the optical gas imaging system and the Method 21 

monitoring device would apply to each individual plant. The transmission and storage segment 

Method 21 device cost was estimated assuming that one facility could be monitored in one hour, 

and the travel time between facilities was one hour. Therefore, in a typical day 4 transmission 

stations could be monitored in one day. Assuming the same 20 day work month, the total 

number of facilities that could be monitored by a single optical gas imaging system and Method 

21 device is 80. Therefore, the shared cost of the Method 21 monitoring device was calculated 

to be $1,144 per site. 
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July 22, 2011. 

8-29

A summary of the capital and annual costs and the cost effectiveness for each of the model plants 

in the oil and gas sectors using the alternative work practice monitoring is provided in Table 8-

18. A component cost effectiveness analysis for the alternative work practice was not 

performed, because the optical gas imaging system is not conducive to component monitoring, 

but is intended for facility-wide monitoring.

8.4.3.4 Secondary Impacts

The implementation of a LDAR program reduces pollutant emissions from equipment leaks. No 

secondary gaseous pollutant emissions or wastewater are generated during the monitoring and 

repair of equipment leaks. Therefore, there are no secondary impacts expected from the 

implementation of a LDAR program.

8.4.4 Modified Alternative Work Practice with Optical Gas Imaging

8.4.4.1 Description

The modified alternative work practice for equipment leaks in §60.18 of 40 CFR Part 60, subpart 

A allows the use of an optical gas imaging system to monitor leaks from components, but 

removes the requirement of the annual Method 21 device monitoring. Therefore, the modified 

work practice would require only monthly monitoring and repair of components using an optical 

gas imaging system. This requirement does not have a leak definition because the optical gas 

imaging system can only measure the magnitude of a leak and not the concentration. However, 

this alternative work practice does not require the repair of leaks below 500 ppm. Compressors 

are not included in this LDAR option and are regulated separately.

8.4.4.2 Effectiveness

No data was found on the control effectiveness of this modified alternative work practice. 

However, it is believed that this option would provide the similar control effectiveness and 

emission reductions as the subpart VVa monitoring program. Therefore, the control 

effectiveness’s for implementing an alternative work practice was assumed to be 93.6% for 

valves, 95.9% for connectors, 100% for open-ended lines, and 100% for pressure relief devices. 
Internal Draft. Do not Cite, Quote or Distribute. 

July 22, 2011. 

8-30

Table 8-18. Summary of the Model Plant Cost Effectiveness for the Optical Gas Imaging and Method 21 Monitoring Option

Model Plant

VOC 

Emission 

Reduction

(Tons/yr)

HAP 

Emission 

Reductions 

(Tons/yr)

Methane 

Emission 

Reductions 

(Tons/yr)

Capital Cost 

($)

Annual Cost 

($/yr)

Annual Cost 

w/ Recovery 

Credits 

($/yr)

VOC Cost 

Effectiveness

($/Ton)

HAP Cost 

Effectiveness 

($/Ton)

Methane 

Cost 

Effectiveness

($/Ton)

Well Pads

1 0.0876 0.00330 0.315 $15,428 $21,464 $21,404 $245,024 $6,495,835 $68,043

2 2.43 0.0915 8.73 $64,858 $39,112 $37,434 $16,127 $427,540 $4,478

3 25.3 0.956 91.3 $132,891 $135,964 $118,425 $5,364 $142,216 $1,490

Gathering and Boosting Stations

1 5.58 0.210 20.1 $149,089 $63,949 $60,091 $11,470 $304,078 $3,185

2 9.23 0.348 33.2 $240,529 $93,210 $86,821 $10,096 $267,659 $2,804

3 12.9 0.486 46.4 $329,725 $121,820 $112,900 $9,451 $250,567 $2,625

Processing Plants

1 13.5 0.508 48.5 $92,522 $87,059 $75,813 $6,462 $171,321 $1,795

Transmission/Storage Facilities

1 2.62 0.0780 94.9 $20,898 $51,753 N/A $19,723 $663,591 $545

Note: Transmission and storage facilities do not own the natural gas; therefore they do not receive any cost benefits from reducing the 

amount of natural gas as the result of equipment leaks.
Internal Draft. Do not Cite, Quote or Distribute. 

July 22, 2011. 

8-31

8.4.4.3 Cost Impacts

Costs were calculated using a LDAR cost spreadsheet developed for estimating capital and 

annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing 

industry. The costs are based on the following assumptions:

Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for 

pressure relief valve disks, $3,852 for pressure relief valve disk holder and valves, and 

$102 for open-ended lines.

Monthly optical gas imaging monitoring costs are estimated to be $0.50 for valves, 

connectors, pressure relief valve devices, and open-ended lines.

A wage rate of $30.46 per hour was used to determine labor costs for repair.

Administrative costs and initial planning and training costs are based on the 

Miscellaneous Organic NESHAP (MON) analysis. The costs were based on 340 hours 

for planning and training and 300 hours per year for reporting and administrative tasks at 

$48.04 per hour. 

The shared capital cost for optical gas imaging system is $491 for production and 

gathering and boosting, $85,000 for processing, and $1,063 for transmission for a FLIR 

Model GF320 optical gas imaging system.

The capital cost also includes $14,500 for a data collection system for maintaining the 

inventory and monitoring records for the components at a facility.

Recovery credits were calculated assuming the methane reduction has a value of $4.00 

per 1000 standard cubic feet.

A summary of the capital and annual costs and the cost effectiveness for each of the model plants 

in the oil and gas sectors using the alternative work practice monitoring is provided in Table 8-

19. A component cost effectiveness analysis for the alternative work practice was not 

performed, because the optical gas imaging system is not conducive to component monitoring, 

but is intended for facility-wide monitoring.
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July 22, 2011. 

8-32

8.4.4.4 Secondary Impacts

The implementation of a LDAR program reduces pollutant emissions from equipment leaks. No 

secondary gaseous pollutant emissions or wastewater are generated during the monitoring and 

repair of equipment leaks. Therefore, there are no secondary impacts expected from the 

implementation of a LDAR program.

8.5 Regulatory Options

The LDAR pollution prevention approach is believed to be the best method for reducing 

pollutant emissions from equipment leaks. Therefore, the following regulatory options were 

considered for reducing equipment leaks from well pads, gathering and boosting stations, 

processing facilities, and transmission and storage facilities:

Regulatory Option 1: Require the implementation of a subpart VVa LDAR program;

Regulatory Option 2: Require the implementation of a component subpart VVa LDAR 

program;

Regulatory Option 3: Require the implementation of the alternative work practice in 

§60.18 of 40 CFR Part 60;

Regulatory Option 4: Require the implementation of a modified alternative work practice 

in §60.18 of 40 CFR Part 60 that removes the requirement for annual monitoring using a 

Method 21 device.

The following sections discuss these regulatory options.
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July 22, 2011. 

8-33

Table 8-19. Summary of the Model Plant Cost Effectiveness for Monthly Gas Imaging Monitoring

Model Plant

VOC 

Emission 

Reduction

(Tons/yr)

HAP 

Emission 

Reductions 

(Tons/yr)

Methane 

Emission 

Reductions 

(Tons/yr)

Capital Cost 

($)

Annual Cost 

($/yr)

Annual Cost 

w/ Recovery 

Credits 

($/yr)

VOC Cost 

Effectiveness

($/Ton)

HAP Cost 

Effectiveness 

($/Ton)

Methane 

Cost 

Effectiveness

($/Ton)

Well Pads

1 N/A N/A N/A $15,390 $21,373 N/A N/A N/A N/A

2 N/A N/A N/A $64,820 $37,049 N/A N/A N/A N/A

3 N/A N/A N/A $537,313 $189,174 N/A N/A N/A N/A

Gathering and Boosting Stations

1 N/A N/A N/A $149,051 $59,790 N/A N/A N/A N/A

2 N/A N/A N/A $240,491 $86,135 N/A N/A N/A N/A

3 N/A N/A N/A $329,687 $11,940 N/A N/A N/A N/A

Processing Plants

1 N/A N/A N/A $92,522 $76,581 N/A N/A N/A N/A

Transmission/Storage Facilities

1 N/A N/A N/A $20,817 $45,080 N/A N/A N/A N/A

Note: This option only provides the number and magnitude of the leaks. Therefore, the emission reduction from this program cannot 

be quantified and the cost effectiveness values calculated.
Internal Draft. Do not Cite, Quote or Distribute. 

July 22, 2011. 

8-34

8.5.1 Evaluation of Regulatory Options for Equipment Leaks

The first regulatory option of a subpart VVa LDAR program was evaluated for well pads, which 

include the wells, processing equipment (separators, dehydrators, acid gas removal), as well as 

any heaters and piping. The equipment does not include any of the compressors which will be 

regulated separately. For well pads the VOC cost effectiveness for the model plants ranged from

$267,386 per ton of VOC for a single well head facility to $6,934 ton of VOC for a well pad 

servicing 48 wells. Because of the high VOC cost effectiveness, Regulatory Option 1 was 

rejected for well pads. 

The second regulatory option that was evaluated for well pads was Regulatory Option 2, which 

would require the implementation of a component subpart VVa LDAR program. The VOC cost 

effectiveness of this option ranged from $15,063 for valves to $211,992 for open-ended lines. 

These costs were determined to be unreasonable and therefore this regulatory option was 

rejected.

The third regulatory option requires the implementation of a monthly LDAR program using an

Optical gas imaging system with annual monitoring using a Method 21 device. The VOC cost 

effectiveness of this option ranged from $5,364 per ton of VOC for Model Plant 3 to $245,024

per ton of VOC for Model Plant 1. This regulatory option was determined to be not cost 

effective and was rejected.

The fourth regulatory option would require the implementation of a monthly LDAR program 

using an optical imaging instrument. The emission reductions from this option could not be 

quantified; therefore this regulatory option was rejected.

8.5.1.2 Gathering and Boosting Stations

The first regulatory option was evaluated for gathering and boosting stations which include the 

processing equipment (separators, dehydrators, acid gas removal), as well as any heaters and 

piping. The equipment does not include any of the compressors which will be regulated 

separately. The VOC cost effectiveness for the gathering and boosting model plants ranged from 

$10,327 per ton of VOC for Model Plant 1 to $8,174 per ton of VOC for Model Plant 3. 

Regulatory Option 1 was rejected due to the high VOC cost effectiveness. 
Internal Draft. Do not Cite, Quote or Distribute. 

July 22, 2011. 

8-35

The second regulatory option that was evaluated for gathering and boosting stations was 

Regulatory Option 2. The VOC cost effectiveness of this option ranged from $6,079 for valves 

to $77,310 per ton of VOC for open-ended lines. These costs were determined to be 

unreasonable and therefore this regulatory option was also rejected.

The third regulatory option requires the implementation of a monthly LDAR program using an 

Optical gas imaging system with annual monitoring using a Method 21 device. The VOC cost 

effectiveness of this option was calculated to be $10,724 per ton of VOC for Model Plant 1 and 

$8,685 per ton of VOC for Model Plant 3. This regulatory option was determined to be not cost 

effective and was rejected.

The fourth regulatory option would require the implementation of a monthly LDAR program 

using an optical imaging instrument. The emission reductions from this option could not be 

quantified; therefore this regulatory option was rejected.

8.5.1.3 Processing Plants

The VOC cost effectiveness of the first regulatory option was calculated to be $3,352 per ton of 

VOC. This cost effectiveness was determined to be reasonable and therefore this regulatory 

option was accepted.

The second option was evaluated for processing plants and the VOC cost effectiveness ranged 

from $0 for open-ended lined and pressure relief devices to $4,360 for connectors. Because the 

emission benefits and the cost effectiveness of Regulatory Option 1 were accepted, this option 

was not accepted.

The third regulatory option requires the implementation of a monthly LDAR program using an 

Optical gas imaging system with annual monitoring using a Method 21 device. The VOC cost 

effectiveness of this option was calculated to be $6,462 per ton of VOC and was determined to 

be not cost effective. Therefore, this regulatory option was rejected.

The fourth regulatory option would require the implementation of a monthly LDAR program 

using an optical imaging instrument. The emission reductions from this option could not be 

quantified; therefore this regulatory option was rejected.
Internal Draft. Do not Cite, Quote or Distribute. 

July 22, 2011. 

8-36

8.5.1.4 Transmission and Storage Facilities

The first regulatory option was evaluated for transmission and storage facilities which include 

separators and dehydrators, as well as any heaters and piping. The equipment does not include 

any of the compressors which will be regulated separately. This sector moves processed gas 

from the processing facilities to the city gates. The VOC cost effectiveness for Regulatory 

Option 1 was $19,769 per ton of VOC. The high VOC cost effectiveness is due to the inherent 

low VOC concentration in the processed natural gas, therefore the VOC reductions from this 

sector are low in comparison to the other sectors. Regulatory Option 1 was rejected due to the 

high VOC cost effectiveness. 

The second option was evaluated for transmission facilities and the VOC cost effectiveness

ranged from $24,762 for open-ended lined to $243,525 for connectors. This option was not 

accepted because of the high cost effectiveness.

The third regulatory option that was evaluated for transmission and storage facilities was 

Regulatory Option 3. The VOC cost effectiveness of this option was calculated to be $19,723

per ton of VOC. Again, because of the low VOC content of the processed gas, the regulatory 

option has a low VOC reduction. This cost was determined to be unreasonable and therefore this 

regulatory option was also rejected.

The fourth regulatory option would require the implementation of a monthly LDAR program 

using an optical imaging instrument. The emission reductions from this option could not be 

quantified; therefore this regulatory option was rejected.

8.5.2 Nationwide Impacts of Regulatory Options

Regulatory Option 1 was selected as an option for setting standards for equipment leaks at 

processing plants. This option would require the implementation of an LDAR program using the 

subpart VVa requirements. For production facilities, 29 facilities per year are expected to be 

affected sources by the NSPS regulation annually. Table 8-15 provides a summary of the 

expected emission reductions from the implementation of this option. 
Internal Draft. Do not Cite, Quote or Distribute. 

July 22, 2011. 

8-37

Table 8-15. Nationwide Emission and Cost Analysis of Regulatory Options

Category

Number 

of 

Sources 

subject 

to 

NSPS*

Capital 

Cost ($)

Nationwide Emission 

Reductions (tpy)†

VOC Cost 

Effectiveness 

($/ton)

Methane Cost 

Effectiveness 

($/ton)

Total Nationwide Costs

(million $/year)

VOC Methane HAP without

savings

with 

savings

without 

savings

with 

savings

Capital 

Cost

Annual

without 

savings

Annual 

with 

savings

Regulatory Option 2 (Subpart VVa LDAR Program)

Processing Plants 29 $7,522 392 1,409 14.8 $3,343 $2,508 $928 $697 0.218 1.31 0.983
Internal Draft. Do not Cite, Quote or Distribute. 

July 22, 2011. 

8-38

8.6 References

 

1 Memorandum from David Randall, RTI and Karen Schaffner, RTI to Randy McDonald, 

U.S. Environmental Protection Agency. Control Options and Impacts for Equipment 

Leaks: Chemical Manufacturing Area Source Standards. September 2, 2008.

2 Memorandum from Kristen Parrish, RTI and David Randall, RTI to Karen Rackley, U.S. 

Environmental Protection Agency. Final Impacts for Regulatory Options for Equipment 

Leaks of VOC on SOCMI. October 30, 2007.

3 Memorandum from Kristen Parrish, RTI, David Randall, RTI, and Jeff Coburn, RTI to 

Karen Rackley, U.S. Environmental Protection Agency. Final Impacts for Regulatory 

Options for Equipment Leaks of VOC in Petroleum Refineries. October 30, 2007.

4 U.S. Environmental Protection Agency. Methodology for Estimating CH4 and CO2

Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and 

Sinks1990-2008. Washington, DC.

5 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 2: 

Technical Report. Prepared for the Gas Research Institute and Environmental Protection 

Agency. EPA-600/R-96-080b. June 1996.

6 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 3: 

General Methodology. Prepared for the Gas Research Institute and Environmental 

Protection Agency. EPA-600/R-96-080c. June 1996.

7 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 5: 

Activity Factors. Prepared for the Gas Research Institute and Environmental Protection 

Agency. EPA-600/R-96-080e. June 1996

8 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 5: 

Activity Factors. Prepared for the Gas Research Institute and Environmental Protection 

Agency. EPA-600/R-96-080e. June 1996

9 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 6: 

Vented and Combustion Source Summary Emissions. Prepared for the Gas Research 

Institute and Environmental Protection Agency. EPA-600/R-96-080f. June 1996.

10 Radian International LLC, Methane Emissions from the U.S. Petroleum Industry, draft 

report for the U.S. Environmental Protection Agency, June 14, 1996.

11 ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry. Prepared 

for the U.S. Environmental Protection Agency. 1999. 

12 ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western 

States. Prepared for Western Governors’ Association. December 27, 2005. 
Internal Draft. Do not Cite, Quote or Distribute. 

July 22, 2011. 

8-39

 

13 ENVIRON International Corporation. Recommendations for Improvements to the 

Central States Regional Air Partnership's Oil and Gas Emission Inventories Prepared for 

Central States Regional Air Partnership. November 2008

14 Independent Petroleum Association of America. Oil and Gas Producing Industry in Your 

State. 

15 Armendariz, Al. Emissions from Natural Gas Production in the Barnett Shale Area and 

Opportunities for Cost-Effective Improvements. Prepared for Environmental Defense 

Fund. January 2009. 

16 Eastern Research Group, Inc. Emissions from Oil and Gas Production Facilities. Prepared 

for the Texas Commission on Environmental Quality. August 31, 2007.

17 U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price. 

Energy Information Administration. Natural Gas Navigator. Retrieved online on 12 Dec 

2010 at <http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm>

18 Eastern Research Group, Inc. Preferred and Alternative Methods for Estimating Air 

Emissions from Oil and Gas Field Production and Processing Operation. Prepared for the 

U.S. Environmental Protection Agency. September 1999.