FROM: Kristin Sroka and Karen Schaffner, RTI International 

TO: Brenda Shine, EPA/OAQPS/SPPD 

FOR: Docket ID No. EPA-HQ-OAR-2010-0682 

DATE: January 23, 2014 

SUBJECT: Impacts for Equipment Leaks at Petroleum Refineries 

1. Purpose 

This memorandum documents the costs and environmental impacts for several regulatory 

options considered as part of the technology review for equipment leaks at petroleum refineries. 

2. Background 

Section 112(f) of the Clean Air Act Amendments (CAA) directs the U.S. Environmental 

Protection Agency (EPA) to assess source categories regulated under section 112(d) of the CAA 

and determine whether any human health or environmental risks remain from the continued 

emissions of hazardous air pollutants (HAP) following implementation of maximum achievable 

control technology (MACT) standards. The CAA further states that if the MACT standards do 

not reduce lifetime excess cancer risk to the most exposed individual to less than one in one 

million, the EPA must set additional standards to protect human health and the environment. 

Additionally, the EPA is required to review these technology-based standards and to revise them 

“as necessary (taking into account developments in practices, processes and control 

technologies)” no less frequently than every 8 years, under CAA section 112(d)(6). The 

Refinery MACT 1 (40 CFR part 63, subpart CC, National Emission Standards for Hazardous Air 

Pollutants From Petroleum Refineries) was promulgated over 8 years ago and is now being 

reviewed. 

3. Approach and Results 

In the first quarter of 2011, the EPA conducted a detailed information collection request (ICR) of 

the petroleum refining industry (EPA, 2011). Included in this ICR is information about the 

number of pieces of equipment (such as valves, pumps, connectors, open-ended valves and lines 

(OEL), and pressure relief devices (PRD)) at the refinery, the number of pieces of equipment that 

are currently monitored at the refinery and under what regulation (and what type of monitoring is 

currently conducted), and the current leak definition. We used the detailed information for each 

refinery in the ICR to estimate the refinery-specific impacts of several regulatory options; to 

generate nationwide impacts estimates, we summed the refinery-specific impacts. 

In a previous memorandum, Analysis of Emissions Reduction Techniques for Equipment Leaks, 

we identified control alternatives for equipment leaks and estimated the costs and environmental 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

2 

impacts for the alternatives (Hancy, 2011). Refer to that memorandum for background on 

control alternatives and options, details on the emission factors and emission reductions 

achieved, and the cost estimates and assumptions for monitoring and repair. 

Baseline Emissions. Current equipment leak monitoring reported by refineries in the ICR 

included a variety of monitoring approaches and leak definitions. Information on options 

provided in the ICR for equipment leak monitoring approaches is provided in Table 1. The leak 

emission rates, or emission factors, developed for each equipment type based on the leak 

definition are provided in Table 2. In general, for leak definitions where there is not a current 

leak definition requirement, we assigned the emission factors for the next most stringent leak 

definition (e.g., valves in gas service with a leak definition of 1,000, 2,000 and 5,000 parts per 

million (ppm) were all assigned the emission factors for a leak definition of 10,000 ppm). 

Table 1. Baseline Control Levels for Equipment Leaksa

Control Technique code Control Technique 

0 None 

1 Detection by sensory monitoring 

2 Instrument monitoring, with leak definition of 10,000 ppm 

3 Instrument monitoring, with leak definition of 5,000 ppm 

4 Instrument monitoring, with leak definition of 2,000 ppm 

5 Instrument monitoring, with leak definition of 1,000 ppm 

6 Instrument monitoring, with leak definition of 500 ppm 

7 Instrument monitoring, with leak definition of <500 ppm 

a

 Source: EPA, 2011. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

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Table 2. Emission Factors for Equipment Typesa

Code Control Technique 

Emission Factor, ton/equip/yr VOCb

Valves Gb Valves LLb Pumps LLb Connectors 

0 None 0.003586 0.003618 0.01015 0.0009112 

1 Detection by sensory monitoring 0.003586 0.003618 0.01015 0.0009112 

2 Monitoring, with leak definition of 

10,000 ppm 0.002162 0.002156 0.006868 0.0009112 

3 Monitoring, with leak definition of 

5,000 ppm 0.002162 0.002156 0.006868 0.0009112 

4 Monitoring, with leak definition of 

2,000 ppm 0.002162 0.002156 0.003147 0.0009112 

5 Monitoring, with leak definition of 

1,000 ppm 0.002162 0.002156 0.003147 0.0009112 

6 Monitoring, with leak definition of 

500 ppm 0.0008544 0.0008578 0.003109 0.0003248 

7 Monitoring, with leak definition of 

<500 ppm 0.0002030 0.0001946 0.003109 0.0003248 

a

 See Attachment A for emission factors in kilograms per piece of equipment per hour. b

 ton/equip/yr = tons per piece of equipment per year; VOC = volatile organic compounds; G= in gas service; LL = in 

light liquid service. 

The baseline emission factor for OEL is 0.0007086 tons per piece of equipment per year 

(ton/equip/yr) of volatile organic compounds (VOC), and was applied to OEL that have a cap 

and plug and that have a leak definition greater than 500 ppm. The baseline emission factor for 

compressors is 0.3701 ton/equip/yr VOC. We estimated baseline emissions from the pieces of 

equipment and the appropriate emission factor based on the current monitoring conducted and 

the leak definition. The baseline emissions estimate included the reported equipment count for 

each type of equipment currently monitored and the appropriate emission factor, plus the 

reported equipment counts for each type of equipment that are not monitored and the 

uncontrolled emission factor. The reported equipment counts are provided in Table 3. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

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Table 3. Nationwide Counts for Pieces of Equipment (Rounded)a

Equipment type a

Number of pieces of 

equipment 

Number of pieces of 

equipment monitored 

Valves, G and LL 3,710,000 3,670,000 

Valves, HL 1,180,000 NA 

Pumps, LL 41,400 43,000 

Pumps, HL 21,800 NA 

Connectors, G and LL 9,000,000 4,910,000 

Connectors, HL 3,130,000 NA 

OEL 320,000 194,000 

PRD 15,100 3,130 

Compressors 3,130 NA 

Sampling, Any 23,100 NA 

Other 219,000 NA 

Total 17,700,000 8,830,000 

a

 Source: EPA, 2011. 

b

 HL = heavy liquid. 

The nationwide baseline emissions for equipment leaks, as estimated and summed for each 

refinery, are 11,100 tons per year (tpy) VOC, and the HAP baseline emissions for equipment 

leaks are 778 tpy. We assumed that the HAP content of VOC emissions from equipment leaks at 

refineries is approximately 7 percent based on the 2010 emissions inventories reported by the 

ICR respondents (EPA, 2011). (Note: Some of the information for individual refineries is 

confidential business information (CBI), so refinery-specific values are not presented in this 

memorandum.) 

Since any revisions to Refinery MACT 1 would only affect equipment subject to that rule, we 

also used the ICR responses to determine the number of pieces of equipment affected by the 

options described in the next section. Table 4 presents the numbers of valves in gas (G) and 

light liquid service (LL), LL pumps, G and LL connectors, and PRD located in process units that 

ICR respondents indicated are subject to the leak detection and repair (LDAR) provisions of 

Refinery MACT 1. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

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Table 4. Nationwide Counts for Select Types of Equipment Subject to Refinery MACT 1 

(Rounded)a,b

Equipment type 

Number of pieces of 

equipment 

Number of pieces of 

equipment monitored 

Valves, G and LL 3,000,000 3,000,000 

Pumps, LL 30,500 32,500 

Connectors, G and LL 7,290,000 4,110,000 

PRDc 11,900 1,170d

a

 Source: EPA, 2011. 

b

 Refinery MACT 1 includes requirements for other types of equipment as well, such as valves and pumps in heavy 

liquid service and OEL, but since none of the regulatory options involve potential revisions to the requirements 

for these types of equipment, the counts of equipment subject to Refinery MACT 1 are not included for these 

types of equipment. c

 The ICR asked respondents for counts of PRD, which was defined differently than “relief valves” that are subject to 

Refinery MACT 1. However, for the purposes of this analysis, the count of PRD located in a process unit 

subject to Refinery MACT 1 LDAR requirements was assumed to be equal to the count of “relief valves” that 

would be subject to any amendments to the relief valve requirements in Refinery MACT 1. d

 This number represents the number of PRD that have a monitoring system that would record the time and duration 

of a release as well as alert operators when there is a release, not necessarily all PRD that ICR respondents 

indicated were monitored in some way. 

Labor Rates. Wage rate estimates used to calculate costs were based on data from the 

U.S. Department of Labor, Bureau of Labor Statistics for petroleum industry sector 

(Sector 324100) (BLS, 2010). Overhead factors and fringe benefits were added to labor rates 

when necessary. Table 5 summarizes the wage rates and overhead factors used to estimate 

costs. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

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Table 5. Summary of 2009 Hourly Labor Rates 

Activity $/hour Basis for Estimate 

Installation, maintenance, repair 26.48 

Mean hourly wage for Installation, Maintenance, and Repair 

Occupations 

(Standard Occupational Classification (SOC) Code 49-0000) 

(BLS, 2010) 

Plant and system operators 28.96 Mean hourly wage for Plant and System Operators, All Other 

(SOC Code: 51-8099) (BLS, 2010) 

Environmental engineering 40.45 Mean hourly wage for Environmental Engineers 

(SOC Code: 17-2081) (BLS, 2010) 

General and operations 

managers 

62.03 Mean hourly wage for Engineering Managers 

(SOC Code: 11-9041) (BLS, 2010) 

General office and admin 

support 19.61 

Mean hourly wage for Office and Administrative Support 

Occupations 

(SOC Code: 43-0000) (BLS, 2010) 

Planning and training labor 

chargea 95.57 

Weighted average for technical (40.45), management (62.03), 

and clerical labor (19.61). The weighted average assumes 

5 hours of management time and 10 hours of clerical effort per 

100 hours of technical labor. Includes overhead factor for 

planning and training. 

Leak Repair Labor Chargeb 79.44 

The general manufacturing sector - Installation, Maintenance, 

and Repair Occupations labor rate with the overhead factor 

applied was used for all repairs 

a

 A planning and training overhead factor of 2.1 was used based on Revised Impacts for Heat Exchange Systems at 

Petroleum Refineries (Coburn, 2011). b

 A maintenance and repair overhead factor of 3 was used based on a 200 percent overhead factor (which correlates 

to a factor of 3) based on the overhead factor for test personnel for continuous emission monitoring system 

installation (EPA, 2002). 

Monitoring Options. Based on the information provided in Analysis of Emissions Reduction 

Techniques for Equipment Leaks (Hancy, 2011), we analyzed several options for improvements 

to the existing LDAR program in Refinery MACT 1, including LDAR using EPA Method 21 (in 

40 CFR part 60, Appendix A-7), LDAR using optical gas imaging, and requiring monitoring of 

PRD for compliance assurance. We assessed several monitoring options, including: 

 Option 1, where the leak threshold that required repair was defined as 500 ppm for valves 

in G and LL service, 2,000 ppm for pumps in LL service. 

 Option 2, where the leak thresholds were the same as Option 1 but a majority of 

refineries were assumed to conduct monitoring with an optical gas imaging device. 

 Option 3, monitoring and repair for connectors in G and LL service, where the leak 

threshold that required repair was defined as 500 ppm. 

 We also assessed continuous monitoring requirements for PRD that would record the 

time and duration of a release as well as alert operators when there is a release. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

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The incremental costs for the control options analyzed for each type of equipment and the 

“emission reduction” factor for each type of equipment are provided in Table 6. These values 

were derived from the memorandum Analysis of Emissions Reduction Techniques for Equipment 

Leaks (Hancy, 2011). 

Option 1 

Valves G and LL (Leak Definition of 500 ppm) 

Under Option 1, we estimated the capital and annual costs and emission reductions for valves in 

organic HAP G and LL service for each refinery (i.e., in the ICR, the valves in G and LL service 

that are located in a process unit subject to the LDAR requirements in Refinery MACT 1). The 

emission reduction was estimated based on the reported equipment counts for valves in G or LL 

service that currently are not monitored to the level of the control option (i.e., at the leak 

definition of 500 ppm). We applied the emission reduction factor for moving from a leak 

definition of 10,000 ppm to a leak definition of 500 ppm (see Table 6 for valves in G service and 

valves in LL service). These emission reduction factors were applied to all valves in organic 

HAP G service with a leak definition of greater than 500 ppm, and to all valves in organic HAP 

LL service with a leak definition of greater than 500 ppm (i.e., control technique codes 2 

through 5). We assumed that those valves that are located in a process unit subject to the LDAR 

requirements in Refinery MACT 1 but are not currently monitored are difficult-to-monitor or 

valves for which repair has been delayed. Since a change in the leak definition would not affect 

the delay of repair provisions or how difficult-to-monitor valves are handled, we did not include 

these in the cost or emission reduction estimate. 

The incremental monitoring and repair costs (per piece of equipment) for valves in G and LL 

service are shown in Table 6. For monitoring costs, we assumed that there are no incremental 

capital costs (or incremental annualized capital costs) for monitoring for a leak definition of 

500 ppm when equipment leak monitoring is already occurring at a leak definition of 

10,000 ppm. We assumed that there would be incremental annual expenses for monitoring due 

to remonitoring to verify repair, as the number of leaking valves at a leak definition of 500 ppm 

is expected to be more than the number of leaking valves at a leak definition of 10,000 ppm, at 

least initially. For repair costs, we assumed there would be incremental capital and annualized 

capital associated with repair of leaks found at the new leak definition of 500 ppm, as well as 

incremental annual expenses associated with the repair. 

Pumps LL (Leak Definition of 2,000 ppm) 

Under Option 1, we estimated the capital and annual costs and emission reductions for pumps in 

organic HAP LL service for each refinery (i.e., in the ICR, the pumps in LL service that are 

located in a process unit subject to the LDAR requirements in Refinery MACT 1). The emission 

reduction was estimated based on the reported equipment counts for pumps in LL service that 

currently are not monitored to the level of the control option (i.e., at the leak definition of 

2,000 ppm). We applied the emission reduction factor for moving from a leak definition of 

10,000 ppm to a leak definition of 2,000 ppm (see Table 6 for pumps in LL service). These 

emission reduction factors were applied to all pumps in organic HAP LL service with a current 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

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leak definition of greater than 2,000 ppm (i.e., control technique codes 2 and 3). We assumed 

that those pumps that are located in a process unit subject to the LDAR requirements in 

Refinery MACT 1 but are not currently monitored are difficult-to-monitor or pumps for which 

repair has been delayed. Since a change in the leak definition would not affect the delay of 

repair provisions or how difficult-to-monitor valves are handled, we did not include these in the 

cost or emission reduction estimate. 

The incremental monitoring and repair costs for pumps in LL service are shown in Table 6. For 

monitoring costs, we assumed that there are no incremental capital costs (or incremental 

annualized capital costs) for monitoring for a leak definition of 2,000 ppm when equipment leak 

monitoring is already occurring at a leak definition of 10,000 ppm. We assumed that there 

would be incremental annual expenses for monitoring due to remonitoring to verify repair, as the 

number of leaking pumps at a leak definition of 2,000 ppm is expected to be more than the 

number of leaking pumps at a leak definition of 10,000 ppm, at least initially. For repair costs, 

we assumed there would be incremental capital and annualized capital for repair of leaks found 

at the new leak definition of 2,000 ppm, and there are incremental annual expenses associated 

with repair as well. 

Nationwide Cost Summary for Option 1 

The nationwide incremental capital cost, incremental annualized capital cost, incremental annual 

expenses, and emission reductions achieved for monitoring and repair of valves in G and LL 

service and pumps in LL service under Option 1 are shown in Tables 8 and 9. 

Option 2 

Optical Gas Imaging Instrument 

Use of an optical gas imaging instrument is an alternative to monitoring for equipment leaks 

using EPA Method 21 for all types of equipment at a facility. The EPA previously published an 

Alternative Work Practice To Detect Leaks From Equipment (AWP) (see 73 FR 73202, 

December 22, 2008), which established three sets of monitoring frequencies and detection levels. 

The AWP also includes a requirement to monitor equipment annually using EPA Method 21 as a 

check on the performance of optical gas imaging. We note that the EPA is currently developing 

a protocol for using optical gas imaging that would not require this annual EPA Method 21 

monitoring. The protocol is expected to include equipment specifications, calibration 

techniques, required performance criteria, procedures for conducting surveys, training 

requirements, the potential impact field conditions may have on results, and information 

addressing difficulties with identifying equipment and leaks in dense industrial areas. 

Since the protocol is still in development, we do not yet know what requirements it will include, 

including how the requirements in the protocol may compare to those in the AWP. Therefore, it 

is not possible at this time for us to estimate cost and emission reduction impacts for an optical 

gas imaging option with a reasonable level of certainty. However, we have developed estimates 

of the potential cost and emission reduction impacts that could be associated with optical gas 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

9 

imaging assuming the protocol’s relevant monitoring techniques, such as monitoring frequency, 

will be similar to those in the AWP. 

Note that we anticipate that use of an optical gas imaging instrument would be added to Refinery 

MACT 1 as a monitoring alternative and not a requirement. The nationwide costs of monitoring 

alternatives are not always estimated, partly because it is difficult to anticipate which 

sources/facilities may elect to use the monitoring alternative. However, since optical gas 

imaging is currently expected to result in a reduction in burden for each facility that could use 

that monitoring option, we elected to estimate the potential nationwide costs of optical gas 

imaging assuming that all of the facilities that could elect to monitor using optical gas imaging 

would choose to do so. 

Based on the AWP, we selected a monitoring frequency of bimonthly (i.e., monitoring occurs 

every other month) and evaluated the costs of conducting monitoring with an optical gas imaging 

instrument without any other instrument monitoring. The cost estimates for monitoring using an 

optical gas imaging instrument are based on the number of pieces of equipment that the 

instrument can image in an hour. We estimated the annual costs assuming the instrument would 

be used to monitor all pieces of equipment in all types of service at each refinery. While the rule 

would not require monitoring of all equipment at the refinery, we assumed, as a conservative 

estimate, that the operator would “see” all the equipment while using the optical gas imaging 

instrument (e.g., the operator may see a pump in heavy liquid service as the instrument moves 

from one pump in LL service to another). Therefore, we summed the equipment counts for all 

equipment types at each refinery, including pumps, valves, connectors, OEL, compressors, gas 

sampling connections, liquid sampling connections, and any other equipment type. 

Refineries reported their total equipment counts and indicated whether the site already had an 

optical imaging device at the refinery. A total of 117 refineries have at least one process unit 

subject to the LDAR requirements of Refinery MACT 1. Currently, there are no provisions for 

using an optical gas imaging instrument that are considered equivalent to an LDAR program 

with instrument monitoring at a leak definition of less than 500 ppm. Therefore, if a facility 

reported having a current leak definition for specific equipment types (typically valves in G and 

LL service) of less than 500 ppm, we assumed that the facility would not be able to use an 

optical gas imaging instrument in place of an EPA Method 21-based LDAR program. Of the 

117 refineries with at least one process unit subject to the LDAR requirements of Refinery 

MACT 1, we assumed 12 refineries would not be able to use an optical gas imaging instrument 

in place of an EPA Method 21-based LDAR program because they have a leak definition lower 

than 500 ppm. Therefore, there are 105 facilities that potentially could use an optical gas 

imaging instrument for LDAR; of those 105, 54 refineries already have an optical gas imaging 

instrument. 

According to the AWP, any leak imaged by the optical gas imaging instrument would be a leak 

that the owner or operator would be required to repair. Based on that provision, and the current 

understanding of the sensitivity of the optical gas imaging instrument, we anticipate that the 

potential emissions reductions (and by extension, the repair costs) for an LDAR program with 

monitoring conducted using an optical gas imaging instrument would be equivalent to the 

emissions reductions estimated for Option 1. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

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Total potential capital costs include the capital costs for the purchase of an optical gas imaging 

instrument for monitoring and for the repair costs for leaking equipment. 

Monitoring, Capital Costs: The capital costs for purchasing an optical gas imaging instrument 

are assumed to be $85,000 (Meister, 2009), and the annualized costs are estimated to be $12,100 

(assuming an interest rate of 7 percent and an equipment life of 10 years, which results in a 

capital recovery factor (CRF) of 0.1424). For the 51 refineries that could conduct monitoring 

with an optical gas imaging instrument and that currently do not have an optical gas imaging 

instrument,1 the capital costs include the purchase of an optical gas imaging instrument 

($85,000) plus an additional 30 hours for conducting extra planning and training ($2,867) related 

to optical gas imaging instrument monitoring. As noted above, 54 refineries reported that they 

already have an optical gas imaging instrument at the facility, so no capital or annualized capital 

costs for the purchase of a monitor were included for these facilities, although 10 hours for 

additional planning and training for optical gas imaging instrument use specific to the LDAR 

program were included ($956). The nationwide potential incremental capital cost and potential 

incremental annualized capital cost for the optical gas imaging instrument are shown in the first 

row of Table 7. 

Repair, Capital Costs: Repair costs were estimated for valves in G and LL service and for pumps 

in LL service, based on the incremental capital costs for repair and the number of these pieces of 

equipment reported by the refinery. As noted above, we estimated that the repair costs for 

Option 2 are identical to the repair costs for Option 1, (i.e., we expect that since the leaks found 

by the optical gas imaging instrument will be equivalent to the leaks found by instrument 

monitoring with EPA Method 21, the cost to repair those leaks will also be equivalent) (see 

repair costs for valves in G service, valves in LL service, and pumps in LL service in Table 6; 

for potential nationwide costs, see the second row of Table 7). 

The nationwide total potential capital costs for Option 2 were summed from the capital costs 

related to monitoring and the capital costs related to repair. The total potential annualized costs 

were estimated based on the capital costs and the repair costs. These potential costs for Option 2 

are shown in Table 7. 

Monitoring Costs (with Optical gas imaging instrument): To develop the potential costs for 

conducting optical gas imaging monitoring, we started with a refinery-provided estimate that the 

optical gas imaging instrument can monitor 4,500 pieces of equipment per hour (Siegell, 2011). 

As a conservative estimate, we assumed that this number was based on the number of pieces of 

equipment monitored per hour of video footage from the study. Therefore, we assumed that for 

every hour of video footage, the operator would spend an additional 1.4 hours conducting 

activities such as calibrating the optical gas imaging instrument, walking around the refinery to 

different vantage points to conduct monitoring, adjusting the optical gas imaging instrument 

settings to ensure the best view for each situation, tagging any leaks found, and other activities. 

These assumptions resulted in an estimate that 1,875 pieces of equipment could be monitored 

each hour. The annual labor hours to monitor using an optical gas imaging instrument were 

 

1 The total number of refineries that would be able to use an optical gas imaging instrument (105) minus the number 

that already own one (54). 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

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estimated based on the total number of pieces of equipment reported by each refinery divided by 

the 1,875 pieces of equipment per hour, and assuming six monitoring events per year (i.e., 

bimonthly monitoring). The potential nationwide cost to monitor using optical gas imaging is 

shown on the first row of costs in Table 7. 

Repair, Incremental Annual expenses: The potential repair costs are the same for those facilities 

that already have an optical gas imaging instrument and for those with no optical gas imaging 

instrument; in addition, the repair costs are identical to the repair costs for EPA Method 21 

monitoring (see repair costs for valves in G service, valves in LL service, and pumps in LL 

service in Table 6). The potential incremental annual repair expenses were estimated based on 

the number of these three equipment types and the incremental costs (Table 6) and are shown on 

the second row of Table 7. 

Administration, Incremental Annual expenses: An incremental annual expense for 10 hours was 

included for the extra administration and reporting required for monitoring with an optical gas 

imaging instrument. This cost was applied to both those facilities that already have an optical 

gas imaging instrument and those that do not because the costs would be specific to using the 

optical gas imaging instrument for the LDAR program of interest. These potential costs are 

shown the third row of Table 7. 

Monitoring Costs for Baseline Monitoring Method (with EPA Method 21): We estimated the 

costs to conduct baseline monitoring for valves and pumps at the reported current leak definition 

as the cost for refiners to conduct instrument monitoring using EPA Method 21 to meet their 

current LDAR requirements. 

For the 105 refineries at which all equipment has a current leak definition of 500 ppm or higher, 

the potential cost to monitor with an optical gas imaging instrument was estimated as the cost of 

the labor time to monitor equipment using an optical gas imaging instrument minus the baseline 

monitoring costs to monitor valves and pumps using EPA Method 21.2 Because monitoring with 

an optical gas imaging instrument alone is considered equivalent to the LDAR program in 

Option 1, owners and operators who could use the optical gas imaging instrument would no 

longer incur the cost to conduct instrument monitoring using EPA Method 21. The potential 

nationwide cost savings associated with no longer incurring this cost is shown on the fourth row 

of Table 7. 

The total potential nationwide incremental annual expenses were summed for the annual 

expenses related to monitoring and the annual expenses related to repair. Total potential 

nationwide annual costs were estimated by summing the annualized capital and incremental 

annual expenses. These potential costs are shown in Table 7. 

 

2 Baseline monitoring costs per piece of equipment are provided in Analysis of Emissions Reduction Techniques for 

Equipment Leaks (Hancy, 2011). Also, for the purposes of this analysis, we assumed that pumps are monitored 

monthly and valves are monitored semiannually at baseline, consistent with Analysis of Emissions Reduction 

Techniques for Equipment Leaks (Hancy, 2011). 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

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The potential incremental capital cost, potential incremental annualized capital cost, potential 

incremental annual expenses, and potential emission reductions achieved for monitoring and 

repair of all equipment under Option 2 are shown in Tables 8 and 9. 

Option 3 

Connectors 

Under Option 3, we estimated the capital and annual costs and emission reductions for 

connectors in organic HAP G and LL service for each refinery (i.e., in the ICR, the pumps in 

LL service that are located in a process unit subject to the LDAR requirements in Refinery 

MACT 1). The emission reduction was estimated based on the reported equipment counts for 

connectors in organic HAP G or LL service that currently are not monitored to the level of the 

control option (i.e., at the leak definition of 500 ppm) or that are monitored using sensory 

methods. We applied the emission reduction factor for moving from uncontrolled connectors to 

a leak definition of 500 ppm (see Table 6 for connectors in G and LL service). These emission 

reduction factors were applied to all connectors in organic HAP G and LL service with no 

numeric leak definition or a leak definition of greater than 500 ppm (i.e., control technique 

codes 1 through 5). 

The incremental monitoring and repair costs (per piece of equipment) for connectors in G and 

LL service are shown in Table 6. For monitoring costs, we assumed that there are no 

incremental capital costs (or incremental annualized capital costs) for monitoring for a leak 

definition of 500 ppm, and we assumed that there would be incremental annual expenses for 

monitoring of connectors. For repair costs, we assumed there would also be incremental capital 

and annualized capital costs associated with repair of leaks found at the new leak definition of 

500 ppm, as well as incremental annual expenses associated with repair. 

Other facility costs are also incurred for monitoring of connectors in organic HAP G and LL 

service. Incremental costs were included for capital costs related to adding and implementing 

the connectors and monitoring of connectors to the data collection system, planning and training 

costs for monitoring connectors, and the incremental annualized capital costs were also included. 

Incremental annual expenses related to annual recordkeeping, reporting, and administrative costs 

were also included. 

The nationwide incremental capital cost, incremental annualized capital cost, incremental annual 

expenses, and emission reductions achieved for monitoring and repair of connectors in G and LL 

service under Option 3 are shown in Tables 8 and 9. 

Monitoring of PRD

Baseline requirements for PRD include a seal that prevents emissions to the atmosphere except 

as a result of a pressure release. In addition, at baseline, PRD in G service are required to 

operate at 500 ppm at all times except during pressure releases. Therefore, assuming there are no 

pressure releases, baseline emissions are expected to be 0 tpy. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

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When pressure releases occur, they result in emissions that are not considered part of the 

baseline, and the EPA has determined that for Refinery MACT 1, no releases from PRD in G or 

liquid service are allowed. (See the preamble to the proposed rule for the legal basis for this 

determination.) Therefore, we estimated the capital and annual costs for installing monitors 

capable of monitoring the PRD continuously, alerting owners and operators immediately if there 

is a release, and measuring the duration of the release. However, it is assumed that there are no 

emission reductions for monitoring of PRD because this type of monitoring is intended to ensure 

compliance with the requirement to have no releases from a PRD. 

We estimated the capital and annual costs for monitoring of PRD in G and liquid service for each 

refinery. We estimated the capital cost to install a monitor for each PRD where the refinery 

reported not to have a monitor currently in place. As shown in Table 6, the costs were based on 

the total number of G and liquid service PRD that are not monitored at the refinery and the 

capital cost of $7,500 for purchase of a monitor (Hancy, 2011). We estimated the annualized 

capital costs assuming an interest rate of 7 percent and an equipment life of 10 years (i.e., a CRF 

of 0.1424). We assumed there are no annual expenses related to PRD. 

We note that these costs are conservative in that they assume each owner or operator installs a 

specific type of monitoring device on each individual PRD. Owners and operators may be able 

to lower these costs if they determine that an existing monitoring system or a system that can 

monitor more than one PRD would meet the requirements of the rule. 

The nationwide capital cost and annualized capital cost for monitoring of PRD in G and liquid 

service are shown in Table 8. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

14 

Table 6. Incremental Costs per Piece of Equipment for Equipment Leak Options 

Control Option Description Service 

Monitoring Repair 

Incremental 

Capital 

Costs 

($) 

Annualized 

Capital 

Costs ($/yr) 

Incremental 

Annual 

Expenses 

($/yr) 

Incremental 

Capital 

Costs 

($) 

Annualized 

Capital 

Costs 

($/yr)a

Increm

Ann

Expe

($/y

Option 1 Valves leak definition from 10,000 ppm to 500 ppm.

G 0.00 0.00 0.02 4.33 0.61 1.3

LL 0.00 0.00 0.02 4.48 0.64 1.0

Pumps leak definition from 10,000 ppm to 2,000 ppm

LL 0.00 0.00 0.02 37.89 6.08 22.

Option 3 Connectors leak definition at 500 ppm 

G/LL 0.00 0.00 2.52 24.67 3.50 0.4

Monitoring to Ensure Compliance PRD monitoring G, liquid b c NA NA NA Na Annualized capital costs for repair are based on a CRF of 0.142 (Hancy, 2011). b Capital costs for PRD monitors are calculated by facility, based on the following equation: Capital cost = (No. PRD – No. PRD monitor

$7,500 is the cost for a monitor capable of recording the duration of each release to the atmosphere and quantifying the emissions

c The annualized capital cost for PRD monitors is calculated by facility, based on a CRF of 0.1424, for an interest rate of 7 percent and a

10 years. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

15 

Table 7. Summary of Estimated Potential Nationwide Costs for Option 2 (Optical Gas Ima

Parameter 

Incremental Capital 

Cost (million $) 

Incremental 

Annualized Capital 

Cost (million $/yr) 

Incremental Annual 

Expenses (million $/yr) 

Option 2 monitoringa 4.53 0.645 3.88 

Repair costs 1.23 0.176 0.350 

Administration and reporting N/A N/A 0.100 

Cost savings from not monitoring with 

EPA Method 21b,c N/A N/A (8.66) 

Totalc 5.76 0.821 (4.33) 

a Costs are estimates of the potential costs of monitoring with an optical gas imaging instrument using an EPA protocol still in developme

analysis, the costs are based on monitoring with optical gas imaging instrument for equipment with current leak definitions of 500 pmonitoring with EPA Method 21 for equipment with current leak definitions lower than 500 ppm. 

b Equipment monitored using an optical gas imaging instrument under Option 2 would not be required to also monitor using EPA Method c Parentheses indicate cost savings. 

Table 8. Nationwide Costs for Equipment Leaksa

Option 

Incremental Capital 

Cost (million $) 

Incremental 

Annualized Capital 

Cost (million $/yr) 

Incremental Annual 

Expenses (million $/yr) 

Option 1 Valves G and LL, Pumps LL 1.23 0.176 0.355 

Option 2b Optical gas imaging instrument 5.76 0.821 (4.33) 

Option 3 Connectors 52.1 7.40 6.52 

PRD G and liquid 9.54 1.36 NA 

a Parentheses indicate cost savings. b Costs for Option 2 are estimates of the potential costs of monitoring with an optical gas imaging instrument using an EPA protocol still i
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

16 

Table 9. Nationwide Emission Reductions (VOC and HAP) and Cost Effectiveness for Equipme

Option 

Emission 

Reduction (tpy) 

Total Annualized 

Cost, without 

recovery credit 

(million $/yr) 

Cost Effectiveness ($/ton) 

Total Annualized 

Cost, with 

recovery credit 

(million $/yr) 

VOC 

1 Valves G and LL, Pumps LL 343 0.531 1,550 0.339 

2b Optical gas imaging instrument 343 (3.51) (10,200) (3.70) 

3 Connectors 1,230 13.9 11,300 13.2 

HAP 

1 Valves G and LL, Pumps LL 24 0.531 22,100 0.339 

2 b Optical gas imaging instrument 24 (3.51) (146,000) (3.70) 

3 Connectors 86 13.9 161,000 13.2 

a Parentheses indicate cost savings. b Emission reductions for Option 2 are estimates of the potential emission reductions of monitoring with an optical gas imaging instrumen

still in development. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

17 

5. References 

BLS (U.S. Department of Labor, Bureau of Labor Statistics). 2010. Occupational Employment 

Statistics: May 2009 Employment and Wage Estimates. Available at 

http://www.bls.gov/oes/2009/may/oes_nat.htm; Last accessed in March 2012. 

Coburn, J. 2011. Memorandum from Jeff Coburn, RTI International, to Brenda Shine, 

EPA/OAQPS. Revised Impacts for Heat Exchange Systems at Petroleum Refineries. July 

13, 2011. Docket Item No. EPA-HQ-OAR-2003-0146-0230. 

EPA (U.S. Environmental Protection Agency). 2002. EPA Air Pollution Control Cost Manual 

Section 1 Chapter 2. Sixth Edition. Office of Air Quality Planning and Standards. 

EPA/452/B-02-001. January 2002. 

EPA (U.S. Environmental Protection Agency). 2011. Petroleum Refinery Database, based on 

Refinery Information Collection Request (ICR) for Calendar Year 2010. September 2011. 

Docket Item Nos. EPA-HQ-OAR-2010-0682-0061 through 0069. 

Hancy, C. 2011. Analysis of Emissions Reduction Techniques for Equipment Leaks. 

Memorandum from Cindy Hancy, RTI International, to Jodi Howard, EPA/OAQPS, for EPA 

Docket No. EPA-HQ-OAR-2010-0869. December 21, 2011. Docket Item No. EPA-HQOAR-2010-0869-0029. 

Meister, M. 2009. “Smart LDAR – More Cost-Effective?” Environmental Quarterly, Issue No. 

2, Summer 2009. Trinity Consultants: July 6, 2009, pp 4-6. Available at 

http://trinityconsultants.com/templates/trinityconsultants/news/article.aspx?id=1293. 

Siegell, J. 2011. Review of OGI Wind Tunnel Tests and Refinery and Chemical Plant OGI and 

Bagging Studies. Presented to EPA August 18, 2011. 
Technical Memorandum – Impacts for Equipment Leaks at Petroleum Refineries 

January 23, 2014 

A-1 

Attachment A 

Emission Factors for Equipment Typesa

Code 

Control 

Technique 

Valves G Valves LL Pumps LL Connectorsb OEL 

kg/equip/hr ton/equip/

yr 

kg/equip/ 

hr 

ton/equip/

yr 

kg/equip/ 

hr 

ton/equip

/yr 

kg/equip/hr ton/equip/

yr 

kg/equip/hr 

0 None 0.0003714 0.003586 0.0003747 0.003618 0.001051 0.01015 0.00009436 0.0009112 0.00007338 01 Detection by 

sensory monitoring 

0.0003714 0.003586 0.0003747 0.003618 0.001051 0.01015 0.00009436 0.0009112 0.00007338 0

2 Monitoring, 

with leak definition of 10,000 ppm 

0.0002238 0.002162 0.0002233 0.002156 0.0007113 0.006868 0.00009436 0.0009112 0.00007338 0

3 Monitoring, 

with leak definition of 5,000 ppm 

0.0002238 0.002162 0.0002233 0.002156 0.0007113 0.006868 0.00009436 0.0009112 0.00007338 0

4 Monitoring, 

with leak definition of 2,000 ppm 

0.0002238 0.002162 0.0002233 0.002156 0.0003259 0.003147 0.00009436 0.0009112 0.00007338 0

5 Monitoring, 

with leak definition of 1,000 ppm 

0.0002238 0.002162 0.0002233 0.002156 0.0003259 0.003147 0.00009436 0.0009112 0.00007338 0

6 Monitoring, 

with leak definition of 500 ppm 

0.0000885 0.0008544 0.0000888 0.0008578 0.0003219 0.003109 0.00003363 0.0003248 0 

7 Monitoring, 

with leak definition of <500 ppm 

0.0000210 0.0002030 0.0000202 0.0001946 0.0003219 0.003109 0.00003363 0.0003248 0 

a Emissions factors in ton/equip/yr were calculated based on multiplying the emission factors in kilograms per piece of equipment per ho

conversion factor of 2.2046 pounds per kilogram and by 8,760 operating hours per year. 

b The connector emission factor is based on the average for G connectors (which is based on the average of flanges in G service and co

the average for LL connectors (which is based on the average of flanges in LL service and connectors in LL service)