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- 1 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. Compone nts 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 i n 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 batte ries 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 trans mission 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 a nd petroleum production to develop control strategies for reducing HAP and VOC emissions from
these sources. 1 2 3 In recent years, studies have been conducted to estimate greenhouse gasInternal Draft. Do not C ite, Quote or Distribute.

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- 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 b oosting 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. T hese 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. O ther 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 s ite 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 varyInternal Draft. Do not C ite, Quote or Distribute.

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- 3 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

- 2008 4 U

. S

. Environmental Protection Agency 2010 Nationwide X

Methane Emissions from the Natural Gas Industry 5 6 7 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 State 12 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 Data 15 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 Estimates 17 U

. S

. Environmental Protection Agency 1995 Nationwide X X

Natural Gas Star Program U

. S

. Environmental Protection Agency 2000

- 2010 Nationwide/

Regional X XInternal Draft. Do not C ite, Quote or Distribute.

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- 4 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 lin es 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 pro vided the average number of equipment located at a well pad and the average number of components for each of these pieces of equipment. 4 The type of production equipment located at a well pad include: gas wellheads, separators, mete rs/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 m odel plants were developed for well pads and are presented i n 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 equip ment for gathering lines and boosting stations

.

Table 8

- 2 . Average Equipment Count for Oil and Gas Production Well Pad Model Plant s

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)Internal Draft. Do not C ite, Quote or Distribute.

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- 5 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 Pro duction 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

.Internal Draft. Do not C ite, Quote or Distribute.

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- 6 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. fr om 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 Pro duction 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)Internal Draft. Do not C ite, Quote or Distribute.

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- 7 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 e quipment 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 comp onents counts for an oil and gas processing facility i s provided in Table 8

- 6

.

Table 8

- 6 . Average Component Count for Oil and Gas Pro cessing Model Plant

Component Gas Plant (non

compressor 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)Internal Draft. Do not C ite, Quote or Distribute.

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- 8 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 stati ons 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 pr ocessing 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 . Aver age 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 as suming 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 wereInternal Draft. Do not C ite, Quote or Distribute.

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- 9 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 basel ine 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

- 1 7 , June 1996. (EPA

- 600/R

- 96

- 080h)Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 10 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 0.0806Internal Draft. Do not C ite, Quote or Distribute.

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- 11 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 e stimate 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

w ells 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 Gath ering 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 inve ntory. 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 f or 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 s t ations 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 s tations thatInternal Draft. Do not C ite, Quote or Distribute.

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- 12 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 S urvey 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 co nstant, 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 predict s a 1.03 tcf/year increase in natural gas

proces sing 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 projection s provided in Oil and Gas Journal and EIA, it was assumed that the processin g 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

T he 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 es timates 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 gatheringInternal Draft. Do not C ite, Quote or Distribute.

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- 13 Table 8

- 11. Nationwide Baseline Emissions for New Sources

Oil and Gas Sector Model Plant Number of New Facilities T OC

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 ,6 87 24 ,1 16 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 18 7 9 , 513 6 , 618 1, 835 69.2
3 44 3,106 2,160 598 22.6
Total 2 75 1 3 , 931 9 , 690 2, 687 1 01 Processing 1 29 2,146 1,490 415 15.6 Transmission/Storage 1 107 11,567 10,497 290 8.62Internal Draft. Do not C ite, Quote or Distribute.

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- 14 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 fa cilities. 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 ope rators, 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 Com

ponents ; 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 o f 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. Le ak 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 m any NESHAP regulations use a 500

- ppm or 1,000

- ppm leak de finition. In addition, some regulations define a leak based on visual inspections and observations (such asInternal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 15 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 (T VA) 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 i mage 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 inf r ared cameras scan an area to pr oduce 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 addit ion, 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 dev ice. 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 tim e 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 int ervals 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 theInternal Draft. Do not C ite, Quote or Distribute.

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- 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

.

On c e the component is repaired; it should be monitored daily over the next se veral 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 ma intained 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 resul ts 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 val ves 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 monit oring of connectors using a n OVA or TVA (10,000 ppm leak definition), monthly monitoring of valvesInternal Draft. Do not C ite, Quote or Distribute.

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- 17 (500 ppm leak definition) and requires open

- ended lines and pressure relief devices to operate with no detectable emissions (500 ppm leak definition). The m onitoring 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 compon ents 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 investi gated 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 co mponents 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 an d 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, an d open

- ended lines and pressure relief
valves have no monitoring requirements, but are required to operate without any d etectable emissions. Compressors are not included in this LDAR option and are regulated separately.Internal Draft. Do not C ite, Quote or Distribute.

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- 18 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 b e 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 leaki ng 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 eq uations 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 fr action 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 controlInternal Draft. Do not C ite, Quote or Distribute.

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- 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 develop ed 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 de finition 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 f or 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 d evices 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 NESHA P (MON) analysis. The costs were based on 340 hours for planning and training and 300 hours pe r 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
invent ory 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 requ ired 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 beInternal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 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 div ided 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 th e 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 cost s 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 f or well pads , Model Plant 2 for gathering and boosting stations , and Model Plant 1 for processing plants and transmission and storage facilities.

The component c osts were calculat ed using a LDAR cost spreadsheet develop ed for estimating capital and annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing industry. The costs are base d on the following assumptions:

Initial monitoring and setup costs are $1 7.70 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 d evices 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 op tion and are based on the Miscellaneous Organic NESHAP (MON)Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 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 re lationship 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 t o 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.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 22

Table 8

- 1 3 . Summary of the Model Plant C ost 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 $ 2 3 , 423 $ 2 3 , 363 $ 2 67 , 386 $ 7, 088 , 667 $ 7 4 , 253

2 2.43 0.0915 8.73 $ 69 , 179 $ 3 7 , 711 $ 3 6 , 0 33 $ 1 5 , 549 $ 4 1 2 , 226 $ 4 , 318

3 25.3 0.956 91.3 $ 584,763 $ 1 7 5 , 753 $ 15 8 , 213 $ 6, 934 $ 1 8 3 , 835 $1, 926
Gathering and Boosting Stations

1 5.58 0.210 20.1 $1 48 , 885 $ 5 7 , 575 $ 5 3 , 717 $ 10, 327 $ 2 7 3 , 769 $ 2 , 868

2 9.23 0.348 33.2 $2 55 , 344 $ 8 4 , 966 $ 7 8 , 577 $ 9, 203 $ 2 4 3 , 987 $ 2 ,5 56

3 12.9 0.486 46.4 $32 1 , 203 $ 10 5 , 350 $ 9 6 , 431 $ 8 , 1 74 $ 21 6 , 692 $ 2 , 270
Processing Plants

1 13.5 0. 508 48.5 $ 7 , 522 $ 4 5 , 160 $ 33 , 915 $ 3, 352 $ 8 8 , 870 $ 931
Transmission/Storage Facilities

1 2.62 0. 0780 9 4

. 9 $ 94 , 482 $ 5 1 , 875 N/A $ 19 , 769 $ 6 65 , 155 $ 5 46
Note: Transmission and storage facilities do not own the natural gas; therefore they do not receive any cost benefits f rom reducing the amount of natural gas as the result of equipment leaks

.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 23

Table 8

- 1 4 . Summary of Component C ost Effectiveness for Well Pads for the Subpart VVa Option s

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 $ 1 5 ,063 $ 399 , 331 $ 4 , 183

Connectors 863 1/0.25 a 0. 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 , 80 0 $ 29 , 609 $ 180 , 537 $ 4,786 , 215 $ 50 , 135

OEL 29 0 0.108 0.00408 0.389 $ 9 , 4 58 $ 22,915 $ 211 ,9 92 $ 5,620 , 108 $ 58 , 870
Modified Subpart VVa

– Less Frequent Monitoring

Valves 235 1 1. 31 0.0 4 96 4.73 $ 11,175 $ 23 , 436 $ 17 , 828 $ 472 , 640 $ 4 , 951

Connectors 863 1/0. 1 25 b 0. 261 0.0 0983 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 I t 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.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 24 Table 8

- 1 5 . Summary of Component C ost 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 ($) Ann ual

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 1/0.25 a 1.02 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 $ 1 38 , 417 $ 1 , 450

Connectors 2,864 1/0.125 b 0.865 0.0326 3.11 $10,914 $23,584 $ 2 7 , 274 $ 723 , 067 $ 7 , 5 74

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.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 25 Table 8

- 1 6 . Summary of Incremental Component C ost Effectiveness for Processing Plants for the Subpart VVa Option

Component Aver age

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 ($/ T on ) 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 1/0.25 a 1.57 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.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 26 Table 8

- 1 7 . Summary of Component C ost 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 1/0.25 a 0.665 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 1/0.125 b 0.562 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.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 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 usin g 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 l eaks 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 a n alternative work practice
was assumed to be 93.6% for valves, 95.9% for connecto rs, 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 develop ed for estimating capital and annual costs for applying LDAR to the Petroleum Refinery and Chemical Manuf acturing 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 f or open

- ended lines. Monthly optical gas imaging monitoring costs are estimated to be $ 0 .50 for valves
, connectors, pressure relief valve d evices , and open

- ended lines.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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

a nd 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 coll ection 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 optic al 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 p roduction 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 opt ical 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 t he Method 21 monitoring device would apply to each individual plant. The transmission and storage segment Method 21 device cost was estimated assuming th at 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, t he shared cost of the Method 21 monitoring device was calculated to be $ 1,144 per site.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 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 monito ring is provided in Table 8

- 1 8

. 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 believ ed 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 C ite, Quote or Distribute.

July 22 , 2011

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- 30 Table 8

- 1 8 . Summary of the Model Plant C ost Effectiveness for the Optical Gas Imaging and Method 21 Monitoring Option

Model Plant VOC

Emission Reduction (Tons/yr) HAP

E mission 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 $ 2 1 , 464 $ 2 1 , 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 $ 1 35 , 964 $ 118 , 425 $ 5 , 364 $ 1 42, 216 $ 1 ,4 9 0
Gathering and Boosting Stations

1 5.58 0.210 20.1 $ 149 , 089 $ 63 , 949 $ 60 , 091 $ 1 1 , 470 $ 3 04 , 078 $ 3 , 185

2 9.23 0.348 33.2 $ 240 , 529 $ 93 , 210 $ 86 , 821 $ 1 0 , 096 $ 267 , 659 $ 2 , 804

3 12.9 0.486 46.4 $ 329 , 725 $ 12 1 , 820 $ 1 12 , 900 $ 9 , 451 $ 2 50 , 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 re ducing the amount of natural gas as the result of equipment leaks.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 31 8.4. 4 .3 Cost Impacts

Costs were calculated using a LDAR cost spreadsheet develop ed 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 valv es, 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 repa ir. 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 c apital 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

- 1 9 . 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.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 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 station s, 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.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 33

Table 8

- 1 9 . Summary of the Model Plant C ost 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: T his 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 C ite, Quote or Distribute.

July 22 , 2011

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- 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

regu lated 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 , Regula tory 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 optio n 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 $ 2 4 5 , 024 per ton of VOC for Model Plant 1

. T his 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 regul atory 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 $1 0 , 327 per ton of VOC for Model Plant 1 to $ 8 , 174 per ton of VOC for Mod el Plant 3. Regulatory Option 1 was rejected due to the high VOC cost effectiveness.Internal Draft. Do not C ite, Quote or Distribute.

July 22 , 2011

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- 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 $ 7 7 , 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 usin g an Optical gas imaging system with annual monitoring using a Method 21 device . The VOC cost effectiveness of this option was calculated to be $ 1 0 , 724 per ton of VOC for Model Plant 1 and $ 8 , 685 per ton of VOC for Model Plant 3. T his regulatory option w as 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; therefo re 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. Th i s cost effectivenes s w as determined to be reasonable and therefore this regulatory option was a ccepted

. 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 m onitoring 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 requi re 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 C ite, Quote or Distribute.

July 22 , 2011

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- 36 8.5.1. 4 Transmission and Storage Facilities

The first reg ulatory 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, ther efore 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. Th is cost w as 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 o ption 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

- 1 5 provides a summary of the expected emission reductions from the implementation of this option.Internal Draft. Do not C ite, Quote or Distribute.

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8

- 37 Table 8

- 15 . Nationw ide Emission and Cost Analysis of Regulatory Options

Catego ry 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 0.983Internal Draft. Do not C ite, Quote or Distribute.

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- 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 Agen cy. Methodology for Estimating CH 4 and CO 2 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. Pr epared 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 Emiss ions 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 C ite, Quote or Distribute.

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- 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 fr om 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 th e 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.