FROM: Kristin Sroka and Karen Sc haffner, 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 revi ew for equipment leaks at petroleum refineries.

2. Background

Section 112(f) of the Clean Air Act Amendmen ts (CAA) directs the U.S. Environmental Protection Agency (EPA) to assess source catego ries regulated under section 112(d) of the CAA and determine whether any human health or e nvironmental risks remain from the continued emissions of hazardous air pollutants (HAP) fo llowing implementation of maximum achievable control technology (MACT) standards. The CAA fu rther states that if the MACT standards do

not reduce lifetime excess cancer ri sk to the most exposed indivi dual 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 developm ents in practices, pr ocesses and control technologies)” no less frequently than ever y 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 prom ulgated over 8 years ago and is now being
reviewed.

3. Approach and Results

In the first quarter of 2011, the EPA conducted a de tailed information coll ection request (ICR) of the petroleum refining industry (EPA, 2011). Incl uded 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 re finery, the number of piec es of equipment that are currently monitored at the refinery and under what regulati on (and what type of monitoring is currently conducted), and th e current leak definition. We used the detailed information for each refinery in the ICR to estimate the refinery-spe cific 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 environmentalTechnical Memorandum – Impacts for Equi pment Leaks at Petroleum Refineries January 23, 2014

2 impacts for the alternatives (Hancy, 2011). Refer to that memorandum for background on control alternatives and opti ons, details on the emission f actors and emission reductions achieved, and the cost estimates and a ssumptions for monitoring and repair.

Baseline Emissions. Current equipment leak mo nitoring reported by refineries in the ICR included a variety of monitoring approaches a nd 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, develope d for each equipment type based on the leak definition are provided in Table 2 . In general, for leak definiti ons where there is not a current leak definition requirement, we assigned the emi ssion 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 f actors for a leak definition of 10,000 ppm).

Table 1. Baseline Control Levels for Equipment Leaks a

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 Equi pment Leaks at Petroleum Refineries January 23, 2014

3 Table 2. Emission Factors for Equipment Types a

Code Control Technique Emission Factor, ton/equip/yr VOC b

Valves G b Valves LL b Pumps LL b 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 equipm ent per year; VOC = volatile organic co mpounds; 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 organi c compounds (VOC), and was appl ied 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 es timate included the report ed 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 reporte d equipment counts are provided in Table 3

.Technical Memorandum – Impacts for Equi pment Leaks at Petroleum Refineries January 23, 2014

4 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, an d the HAP baseline emissions for equipment leaks are 778 tpy. We assumed that the HAP cont ent 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 refine ry-specific values are not presented in this memorandum.)

Since any revisions to Refinery MACT 1 would only affect equipm ent 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 Equi pment Leaks at Petroleum Refineries January 23, 2014

5 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

PRD c 11,900 1,170 d

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 count s 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 assu med 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). Overh ead 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 Equi pment Leaks at Petroleum Refineries January 23, 2014

6 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 charge a 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 Charge b 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 ba sed on a 200 percent overhead factor (which correlates to a factor of 3) based on the overhead factor for te st 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 optic al gas imaging, and requiring monitoring of PRD for compliance assurance. We assess ed several monitoring options, including:

 Option 1, where the leak threshol d that required repair was defined as 500 ppm for valves in G and LL service, 2,000 pp m 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 monito ring with an optical gas imaging device.

 Option 3, monitoring and repair for connector s in G and LL service, where the leak threshold that required repa ir was defined as 500 ppm.

 We also assessed continuous monitoring requ irements 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 Equi pment Leaks at Petroleum Refineries January 23, 2014

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

“emission reduction” factor for each t ype of equipment are provided in Table 6 . These values
were derived from the memorandum Analysis of Emissions Reduc tion 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 emi ssion reductions for valves in organic HAP G and LL service for each refinery ( i.e. , in the ICR, the valv es in G and LL service that are located in a process unit subject to th e LDAR requirements in Refinery MACT 1). The
emission reduction was estimated based on the re ported equipment counts for valves in G or LL service that currently are not monitore d to the level of the control option ( i.e. , at the leak definition of 500 ppm). We applied the emi ssion 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 defini tion of greater than 500 ppm, and to all valves in organic HAP
LL service with a leak defin ition of greater than 500 ppm ( i.e. , control technique codes 2 through 5). We assumed th at 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 de finition 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 al ready occurring at a leak definition of 10,000 ppm. We assumed that th ere would be incremental annua l expenses for monitoring due to remonitoring to verify repair, as the number of leaking valves at a l eak definition of 500 ppm is expected to be more than the number of leak ing valves at a leak de finition of 10,000 ppm, at least initially. For repair cost s, we assumed there would be in cremental capital and annualized capital associated with repair of leaks found at the new leak definition of 500 ppm, as well as incremental annual expenses a ssociated with the repair.

Pumps LL (Leak Definition of 2,000 ppm)

Under Option 1, we estimated th e 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 re quirements in Refinery MACT 1). The emission reduction was estimated based on the reported e quipment 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 f actor for moving from a leak definition of 10,000 ppm to a leak defi nition of 2,000 ppm (see Table 6 for pumps in LL service). These emission reduction factors were applied to all pu mps in organic HAP LL service with a currentTechnical Memorandum – Impacts for Equi pment Leaks at Petroleum Refineries January 23, 2014

8 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 proce ss unit subject to the LDAR requirements in Refinery MACT 1 but are not currently monito red are difficult-to-monitor or pumps for which repair has been delayed. Since a change in th e leak definition would not affect the delay of repair provisions or how difficult-to-monitor valves are handle d, 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 l eak definition of 2,000 ppm when equipment leak monitoring is already occurring at a leak definition of 10,000 pp m. 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 l eak definition of 10,000 ppm, at leas t initially. For repair costs, we assumed there would be incremental capital and annualized capital fo r repair of leaks found at the new leak definition of 2,000 ppm, and ther e 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 servic e 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 pr eviously published an
Alternative Work Practice To Detect L eaks 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 mon itor 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, pr ocedures for conducti ng surveys, training requirements, the potential impact field condi tions may have on results, and information addressing difficulties with identifying equi pment 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 reasonab le level of certainty. However, we have developed estimates of the potential cost and emissi on reduction impacts that could be associated with optical gasTechnical Memorandum – Impacts for Equi pment Leaks at Petroleum Refineries January 23, 2014

9 imaging assuming the protocol’s relevant monito ring techniques, such as monitoring frequency,
will be similar to those in the AWP.

Note that we anticipate that use of an optical ga s imaging instrument woul d be added to Refinery MACT 1 as a monitoring alternative and not a re quirement. The nationwide costs of monitoring alternatives are not always es timated, 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 re duction 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 m onitoring frequency of bimonthly ( i.e. , monitoring occurs every other month) and evaluate d the costs of conducting monitori ng with an optical gas imaging instrument without any other instrument monitori ng. The cost estimates for monitoring using an optical gas imaging instrument are based on th e 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 liq uid service as the instrument moves from one pump in LL service to another). Ther efore, we summed the equipment counts for all equipment types at each refinery, including pum ps, valves, connectors, OEL, compressors, gas sampling connections, liquid sampling conn ections, 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 ar e considered equivalent to an LDAR program with instrument monitoring at a leak definition of less than 500 ppm. Th erefore, if a facility reported having a current leak definition for specifi c equipment types (typically valves in G and LL service) of less than 500 ppm, we assumed th at 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 s ubject 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 progra m because they have a leak definition lower than 500 ppm. Therefore, ther e are 105 facilities that potentially could use an optical gas imaging instrument for LDAR; of those 105, 54 refi neries already have an optical gas imaging

instrument.

According to the AWP, any leak imaged by the op tical 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 ga s imaging instrument, we anticipate that the potential emissions reductions (a nd by extension, the repair cost s) for an LDAR program with monitoring conducted using an optical gas imagi ng instrument would be equivalent to the emissions reductions estimated for Option 1.Technical Memorandum – Impacts for Equi pment Leaks at Petroleum Refineries January 23, 2014

10 Total potential capital costs include the capital co sts 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 fo r purchasing an optical gas imaging instrument are assumed to be $85,000 (Meister, 2009), and th e 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 refine ries 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 trai ning ($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 in cluded 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 poten tial incremental capita l 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 cost s for repair and the numb er of these pieces of equipment reported by the refinery. As noted ab ove, 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 repa ir 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 cost s, 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 capita l costs related to repair. Th e 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 instru ment): To develop th e potential costs for conducting optical gas imaging mon itoring, we started with a refine ry-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 th is 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 calib rating the optical gas im aging instrument, walki ng around the refinery to different vantage points to c onduct monitoring, adjusting the op tical 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 usi ng 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 Equi pment Leaks at Petroleum Refineries January 23, 2014

11 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 pot ential nationwide cost to monito r 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 t hose facilities that already have an optical ga s imaging instrument and for th ose with no optical gas imaging instrument; in addition, the repair costs are id entical to the repair costs for EPA Method 21 monitoring (see repair costs for valves in G se rvice, valves in LL service, and pumps in LL
service in Table 6 ). The potential incremental annual re pair 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 administra tion and reporting required for mon itoring with an optical gas imaging instrument. This cost was applied to bot h those facilities that already have an optical gas imaging instrument and those that do not beca use the costs would be specific to using the optical gas imaging instrument for the LDAR pr ogram 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 monitori ng 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 valv es and pumps using EPA Method 21. 2 Because monitoring with an optical gas imaging instrument alone is c onsidered 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 we re summed for the annual expenses related to monitoring and the annual ex penses related to repa ir. Total potential nationwide annual costs were estimated by su mming the annualized capital and incremental annual expenses. These poten tial 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 Equi pment Leaks at Petroleum Refineries January 23, 2014

12 The potential incremental capital cost, potential incremental annualized capital cost, potential incremental annual expenses, and potential em ission 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 a nd 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 s ubject 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 de finition 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 annual ized capital costs) for monitoring for a leak definition of 500 ppm, and we assumed that th ere would be incremental annual expenses for monitoring of connectors. For re pair costs, we assumed there w ould also be incremental capital and annualized capital costs associated with repa ir 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 m onitoring 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 th e data collection system , planning and training costs for monitoring connectors, and the incrementa l annualized capital costs were also included. Incremental annual expenses related to annual re cordkeeping, reporting, and administrative costs
were also included.

The nationwide incremental capital cost, incrementa l annualized capital cost, incremental annual expenses, and emission reductions achieved for m onitoring 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 releas e. In addition, at baseline, PR D in G service are required to operate at 500 ppm at all times except during pre ssure releases. Therefore, assuming there are no pressure releases, baseline emissi ons are expected to be 0 tpy.Technical Memorandum – Impacts for Equi pment Leaks at Petroleum Refineries January 23, 2014

13 When pressure releases occur, they result in emissions that are not c onsidered part of the baseline, and the EPA has determined that for Re finery 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, alerti ng owners and operators immediately if there is a release, and measuring the duration of the rel ease. 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 mon itoring of PRD in G and liquid service for each refinery. We estimated the capital cost to in stall 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 liqui d service PRD that are not mon itored 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 indivi dual 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 m eet 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 RefineriesJanuary 23, 201414Table 6. Incremental Costs per Piece of Equipment for Equipment Leak OptionsControl Option DescriptionServiceMonitoringRepairEmissionreduction factor(ton/equip/yr)IncrementalCapitalCosts($)AnnualizedCapitalCosts ($/yr)IncrementalAnnualExpenses($/yr)IncrementalCapitalCosts($)AnnualizedCapitalCosts($/yr)aIncrementalAnnualExpenses($/yr)Option 1Valves leak definition from 10,000ppm to 500 ppm.G 0.00 0.00 0.02 4.330.61 1.30 0.001307LL 0.00 0.00 0.02 4.48 0.64 1.05 0.001299Pumps leak definition from 10,000ppm to 2,000 ppmLL0.00 0.00 0.02 37.896.08 22.78 0.003721Option 3Connectors leak definition at 500ppmG/LL0.00 0.00 2.52 24.673.50 0.40 0.0005864Monitoring to Ensure CompliancePRD monitoringG,liquidb cNA NA NA NA NAaAnnualized capital costs for repair are based on a CRF of 0.142 (Hancy, 2011).bCapital costs for PRD monitors are calculated by facility, based on the following equation: Capital cost = (No. PRD – No. PRDmonitored)0.6* $7,500, where$7,500 is the cost for a monitor capable of recording the duration of each release to the atmosphere and quantifying the emissions.cThe annualized capital cost for PRD monitors is calculated byfacility, based on a CRF of 0.1424,for an interest rate of 7 percent and an equipment life of10 years.Technical Memorandum – Impacts for Equipment Leaks at Petroleum RefineriesJanuary 23, 201415Table 7. Summary of Estimated Potential Nationwide Costs for Option 2 (Optical Gas Imaging)ParameterIncremental CapitalCost (million $)IncrementalAnnualized CapitalCost (million $/yr)Incremental AnnualExpenses (million $/yr)Total AnnualizedCost (million $/yr)Option 2 monitoringa4.53 0.645 3.88 4.53Repair costs 1.23 0.176 0.350 0.526Administration and reporting N/A N/A 0.100 0.100Cost savings from not monitoring withEPA Method 21b,cN/A N/A (8.66) (8.66)Totalc5.76 0.821 (4.33) (3.51)aCosts are estimates of the potential costs of monitoring with an optical gas imaging instrument using an EPA protocol still indevelopment. For purposes of thisanalysis, the costs are based on monitoring with optical gas imaging instrument for equipment with current leak definitions of500 ppm or greater; andmonitoring with EPA Method 21 for equipment with current leak definitions lower than 500 ppm.bEquipment monitored using an optical gas imaging instrument under Option 2 would not be required to also monitor using EPA Method 21 as in Option 1.cParentheses indicate cost savings.Table 8. Nationwide Costs for Equipment LeaksaOptionIncremental CapitalCost (million $)IncrementalAnnualized CapitalCost (million $/yr)Incremental AnnualExpenses (million $/yr)Total AnnualizedCost (million $/yr)Option 1 Valves G and LL, Pumps LL 1.23 0.176 0.355 0.531Option 2bOptical gas imaging instrument 5.76 0.821 (4.33) (3.51)Option 3 Connectors 52.1 7.40 6.52 13.9PRD G and liquid 9.54 1.36 NA 1.36aParentheses indicate cost savings.bCosts for Option 2 are estimates of thepotential costs of monitoringwith an optical gas imaginginstrument using an EPA protocol still in development.Technical Memorandum – Impacts for Equipment Leaks at Petroleum RefineriesJanuary 23, 201416Table 9. Nationwide Emission Reductions (VOC and HAP) and Cost Effectiveness for Equipment LeaksaOptionEmissionReduction (tpy)Total AnnualizedCost, withoutrecovery credit(million $/yr)Cost Effectiveness ($/ton)Total AnnualizedCost, withrecovery credit(million $/yr)Cost Effectiveness,with recovery credit($/ton)VOC1 Valves G and LL, Pumps LL3430.5311,5500.3399862bOptical gas imaginginstrument343 (3.51) (10,200) (3.70) (10,800)3 Connectors1,23013.911,300 13.210,700HAP1 Valves G and LL, Pumps LL240.53122,1000.33914,1002bOptical gas imaginginstrument24 (3.51) (146,000) (3.70) (154,000)3 Connectors8613.9 161,000 13.2 153,000aParentheses indicate cost savings.bEmission reductions for Option 2 are estimates of the potential emission reductions of monitoring with an optical gas imaginginstrument using an EPA protocolstill in development.Technical Memorandum – Impacts for Equi pment Leaks at Petroleum Refineries January 23, 2014

17 5. References

BLS (U.S. Department of Labor, Bur eau 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 Cobur n, 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 (I CR) 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 Internationa l, to Jodi Howard, EPA/OAQPS, for EPA Docket No. EPA-HQ-OAR-2010-0869. Decembe r 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/tr inityconsultants/news/article.aspx?id=1293

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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 RefineriesJanuary 23, 2014A-1Attachment AEmission Factors for Equipment TypesaCodeControlTechniqueValves GValves LLPumps LLConnectorsbOELCompressorkg/equip/hrton/equip/yrkg/equip/hrton/equip/yrkg/equip/hrton/equip/yrkg/equip/hrton/equip/yrkg/equip/hrton/equip/yrkg/equip/hrton/equip/yr0 None 0.0003714 0.003586 0.0003747 0.003618 0.001051 0.01015 0.00009436 0.0009112 0.00007338 0.0007086 0.0318 0.30711 Detection bysensorymonitoring0.0003714 0.003586 0.0003747 0.003618 0.001051 0.01015 0.00009436 0.0009112 0.00007338 0.0007086 NA NA2 Monitoring,with leakdefinition of10,000 ppm0.0002238 0.002162 0.0002233 0.002156 0.0007113 0.006868 0.00009436 0.0009112 0.00007338 0.0007086 NA NA3 Monitoring,with leakdefinition of5,000 ppm0.0002238 0.002162 0.0002233 0.002156 0.0007113 0.006868 0.00009436 0.0009112 0.00007338 0.0007086 NA NA4 Monitoring,with leakdefinition of2,000 ppm0.0002238 0.002162 0.0002233 0.002156 0.0003259 0.003147 0.00009436 0.0009112 0.00007338 0.0007086 NA NA5 Monitoring,with leakdefinition of1,000 ppm0.0002238 0.002162 0.0002233 0.002156 0.0003259 0.003147 0.00009436 0.0009112 0.00007338 0.0007086 NA NA6 Monitoring,with leakdefinition of500 ppm0.0000885 0.0008544 0.0000888 0.0008578 0.0003219 0.003109 0.00003363 0.0003248 0 0 NA NA7 Monitoring,with leakdefinition of<500 ppm0.0000210 0.0002030 0.0000202 0.0001946 0.0003219 0.003109 0.00003363 0.0003248 0 0 NA NAaEmissions factors in ton/equip/yr were calculated based on multiplying the emission factors in kilograms per piece of equipment per hour (kg/equip/hr) by theconversion factor of 2.2046 pounds per kilogram and by 8,760 operating hours per year.bThe connector emission factor is based on the average for G connectors (which is based on the average of flanges in G serviceand connectors in G service) andthe average for LL connectors (which is based on the average of flanges in LL service and connectors in LL service)