FROM: Jeff Coburn, RTI International

TO: Brenda Shine, EPA/OAQPS/SPPD

DATE: November 15, 2013

SUBJECT: Refinery Emissions and Risk Estima tes for Modeled “Allowable” Emissions

1. Purpose

This memorandum documents the methodology used to estimate the emi ssions allowed by the current National Emissions Standards for Hazar dous Air Pollutants (NESHAP) for petroleum refineries and summarizes the projected risks for these “allowable” emissions.

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 environmental 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 in order to achieve an ample margin of safety, in accordance with the interpretation set forth in the Benzene NESHAP (54 FR 38044, September 14, 1989). Additionally, the EPA is required to review these technology-based standards and to re vise them “as necessary (taking into account developments in practices, processes and contro l technologies)” no less fr equently than every 8 years, under CAA section 112(d)(6). The Refi nery MACT 1 (40 CFR part 63, subpart CC) and Refinery MACT 2 (40 CFR part 63, subpart UUU) were promulgated over 8 years ago and are now being reviewed. As part of the risk review , an evaluation of the risk associated with the emissions allowed under the MACT standards is needed.

To support the risk and technology review, the EPA conducted a detailed information collection request (ICR) of petroleum refineries (EPA, 2011), including requests for actual and allowable emission estimates following the guidelines provided in the Emission Estimation Protocol for Petroleum Refineries (RTI, 2011) (also referred to as “Emi ssions Protocol”). After reviewing the data received as a result of the ICR, many data gaps and other issues were identified with the emission estimates, particularly for the reporte d “allowable” emissions. The allowable emission estimates are difficult to determine, particular ly for sources that do not have a direct HAP emissions limit. For example, most catalytic cracking units comply with a particulate matter (PM) emissions limit of 1 pound per 1,000 pounds (lb/ 1,000 lb) of coke burn-off as the surrogate limit for metal HAP. As no direct HAP emission limits apply to this source, the “allowable” emission rates were commonly left blank. Simila rly, emissions from equipment leaks are subject to work practice standards rather than direct emission limits, so the allowable emissions forTechnical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

2 equipment leaks were often left blank. Due to the issues identified when reviewing the reported allowable emissions, it was determined that a modeling approach for projecting allowable emissions would provide a more comprehensive and defensible approach for estimating the allowable emissions for the risk analysis.

3. Summary of Modeling Approach

A detailed model plant analysis was used to estimate the allowable HAP emissions from all emission sources at the petroleum refinery. The basic default modeling approach and assumptions are described elsewh ere (RTI, 2002). The emission m odel uses refinery-specific, process unit-specific capacity information to estim ate the emissions for a given refinery. This capacity information was updated based on the Refinery Capacity Report 2010 (EIA, 2010). Enhancements to the model’s defa ult emission factors were made to make the model consistent with the emission factors presented in the Emission Estimation Protocol for Petroleum Refineries (RTI, 2011). Further adjustments were made to the emission factors based on the results of additional source test data collecte d in response to the detailed I CR as well as a consideration of the “allowable” emission limits in the MACT standards.

Both long-term and short-term inhalation exposure concentrations and health risks from each of the source categories addressed in this propos al were estimated usi ng the Human Exposure Model HEM-3. The HEM–3 performs the followi ng three primary risk assessment activities: (1) conducting dispersion modeling to estimate th e concentrations of HAP in ambient air, (2) estimating long-term and shor t-term inhalation e xposures to individuals residing within 50 kilometers (km) of the modeled sources, a nd (3) estimating individu al and population-level inhalation risks using the exposure estimates and quantitative dose-response information. AERMOD, the air dispersion model used by HEM–3, is one of the EPA’s preferred models for assessing pollutant concentrations from industrial f acilities. Additional deta il regarding the risk assessment analysis is provided in the draft risk assessment report in the docket (Docket ID No. EPA-HQ-OAR-2010-0682).

It is important to note that em ission source-specific lo cations are not include d in the model plant analysis used for this allowable emissions analys is; all emissions were released from the centroid of the facility using default emi ssion source parameters. As such, differences in the risk results between the allowable emissions model plant an alysis and the ICR inventory data may be a function of differences in the emissions magnit ude, release characteristics, and/or emissions locations.

Section 4 of this memorandum provides a summary of the risk estimates at the “allowable” emission rates. Section 5 provides additional de tails regarding emission estimates used in the allowable emissions model plant analysis. Se ction 6 provides additi onal details regarding comparison of the sources and pollutants that co ntributed most to the calculated risks based on the actual and allowable emissions estimates. Based on the comparison provided in Section 6, Section 7 describes post-processing methods empl oyed to derive a more conservative allowable emission risk estimate.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

3 4. Summary of Modeling Results

Table 1 summarizes the projected risks from pe troleum refinery facilities based on modeled allowable emission estimates. The maximum in dividual [cancer] risk (MIR) and the maximum hazard quotient (HQ) presented in Table 1 ar e the result of a summation of individual pollutant/source risk estimates across all pollutant s and sources. No consideration was given to the target organ or modes of action, so the MIR and maximum HQ presented in Table 1 are conservatively high estimates. As stated in the Benzene NESHAP, the “EPA will generally presume that if the risk to [the maximum expos ed] individual is no higher than approximately one in 10 thousand, that risk level is consider ed acceptable.” 54 FR at 38045. As the MIR for the post-processed (conservative) allowable risk estimates is no higher than 1-in-10 thousand ( i.e. , 100-in-1 million), the allowable ri sks can be considered “acceptable.”

Table 1. Summary of Risk Results for “Allowable” Emissions at Petroleum Refineries

Parameter Value based on Actual Emission Inventory Estimates Value based on Allowable Emission Model Estimates Value based on Post-Processed Allowable Risk Estimates Maximum Individual Cancer Risk (MIR) (from a single facility) 70-in-1 million 90-in-1 million 100-in-1 million

Maximum Chronic Hazard Quotient (from a single facility) 1.0 1.0 1.0

Annual Cancer Incidence 0.34 0.42 0.61

Number of Facilities with MIR of 1 in 1-million or greater 114 120 131

Number of Facilities with MIR of 10 in 1-million or greater 53 60 82

Number of Facilities with MIR greater than 100 in 1-million 0 0 0

Number of Facilities with Chronic HQ greater than 1 0 0 0

5. Details of Modeling Approach

The model plant analysis uses facility-specific da ta on the types of processes and their capacities to estimate emissions for each refinery in the Unite d States and its territories. Refinery-specific, process unit-specific capacity informati on was based on values reported in the Refinery Capacity Report 2010 (EIA, 2010). Process throughput or produc tion capacities for most processes are reported in terms of a quantity per “stream day.” These “stream day” capacities were converted to “calendar day” capacities ba sed on the ratio of the crud e distillation column throughputTechnical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

4 reported in barrels per calendar day (bbl/cd) (adj usted for idled capacity) to the crude distillation column throughput reported in ba rrels per stream day (bbl/sd). 1

The original refinery emissions model (aka , REM or REM Model) includes algorithms for estimating emissions from storage vessels, equi pment leaks, wastewater treatment systems, cooling towers, flares, product loading, as well as from process heaters, boilers, catalytic cracking units, catalytic reforming units (CRU), and sulfur recovery plants (RTI, 2002). An algorithm was added to estimate emissions from delayed coking units (DCU). Specific considerations for estimating the allowable em issions for each modeled emissions source are described in this section. The sources are presented in the order they appear in the Emission Estimation Protocol for Petroleum Refineries (RTI, 2011).

Emission Factors for Equipment Leaks

Equipment leaks are difficult to assign an “allo wable” emissions rate. The existing requirements in Refinery MACT 1 include monitoring to de tect leaking equipmen t components and then repairing the leaks identified within certain time constraints. There is no direct limitation on the number or size of leaks detected, so there is no direct maximum allowable emissions rate. Instead, emission factors for equipment leak co mponents based on historical data on the number and distribution of leaks for diffe rent stringencies of leak dete ction and repair (LDAR) programs as developed during the review of the equipment leaks NSPS for 40 CFR part 60, subparts VV, VVa, GGG, and GGGa were used (P arrish, et al., 2007). For this analysis, the emissions per component were estimated based on the assumed dist ribution at the time of the monitoring event. This would tend to overestimate the emissions as this approach assumes the leak occurs for the entire duration of the monitoring period rather than assuming the leak occurs midway between monitoring periods as allowed in the Emissions Protocol.

The emission factors for benzene were project ed using the small and large model plant equipment component counts and average benzene concentrations for various refinery process units from Locating and Estimating Emissions of Benzene (EPA, 1998), which is the approach used in the original REM (RTI, 2002). While ne wer benzene composition data are presented in the Emissions Protocol, the data are less refined as to type of fluid within the equipment (gas, light liquid, or heavy liquid). Additionally, for most processe s, the benzene content in the original REM model was higher than in the Emissi ons Protocol, so this lead to slightly higher estimates of benzene emissions. The benzene em ission rates per process unit are summarized in Table 2.

Equipment leaks are unusual in that the emissions are not as dependent on the throughput as they are the number of equipment components. While larger units tend to have more components, some refineries may have multiple process units of a given type, which would tend to have a greater number of components and th erefore higher emissions. The Refinery Capacity Report

1 For the purposes of assessing “allowable” emissions, it might have been more appropriate to use the stream day capacities and not to have accounted for idled capacity, but these adjustments were made when developing the main process input data set as the model was anticipated to be used to project actual risk and risk reductions from various control options.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

5 2010 (EIA, 2010) provides information about the type s of units present a nd the overall capacity for a given process type, but it does not provide the number of process units present at the facility. Some very large refineries have multip le process trains and may have two or three of each type of process unit. To estimate the number of process units, a maximum process unit throughput was established; these maximum throughput values are also provi ded in Table 2. The process unit’s capacity (in bbl/cd) was divi ded by the appropriate maximum process unit throughput. The resulting values (if greater than 0) were roun ded to the next larger whole number. Thus, facilities with a 250,000 bbl/cd crude distillation cap acity were assumed to have two crude distillation columns.

Table 2. Process Unit Emission Rates for Benzene from Equipment Leaks

Process Unit LargeRefinery Cutoff (bbl/cd) Maximum Process Unit Size (bbl/cd) Emissions of Benzene (tons per year per process unit)

Small Large
Crude Distillation 50,000 160,000 0.0628 0.1247
Vacuum Distillation 25,000 80,000 0.0074 0.0265 Catalytic Cracking 17,500 80,000 0.0456 0.0475 Catalytic Reforming 10,000 40,000 0.1688 0.2253 Hydrocracking 5,000 40,000 0.0741 0.1347 Thermal Cracking (coking) 10,000 40,000 0.0277 0.0481 Thermal Cracking (visbreaking) 10,000 40,000 0.0432 0.0769 Hydrotreating/Hydrorefining 35,000 80,000 0.0545 0.0790 Alkylation (sulfuric acid) 5,000 20,000 0.0180 0.0187 Isomerization 2,500 15,000 0.1584 0.1295 Polymerization/Dimerization 1,000 10,000 0.0064 0.0062 Aromatics (as CRU) 5,000 20,000 0.1688 0.2253 Product Blending 5,000 50,000 0.1003 0.1195 Hydrogen Plant (MMcfd) a 10 80 0.0002 0.0021
Other Lube Oil Processes 5,000 30,000 0.0509 0.0412 MEK Dewaxing 5,000 30,000 0.0078 0.0206 Asphalt Plant 5,000 20,000 0.0022 0.0006
Sulfur Plant 75 200 0.0006 0.0004

a MMcfd = million cubic feet per day.

The process unit emission rates for benzene were multiplied by the calculated number of process units of that type and these pr oducts were summed across all pr ocess types present at a given refinery to calculate the facility’s total benzen e emissions from equipment leaks. The facility total benzene emissions were subsequently multi plied by refinery-wide av erage process stream individual HAP to benzene concentration ratios to calculate the emissions of other HAP at the refinery. The refinery wide average stream con centrations and the concentration multipliers used for equipment leaks analysis are summarized in Table 3.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

6 Finally, the source characterist ics for the process equipment area were revised from those presented in RTI (2002) to minimize the chance of overlap with receptors located near the refinery. The revised release areas associated with the process equipment leaks are summarized in Table 4.

Table 3. Concentration Ratios Used for Equipment Leak Emission Estimates

CASRN a HAP Average Liquid Concentration b (wt%) Concentration Ratio for Equipment Leaks c
106-99-0 1,3-Butadiene 0.0007 0.0006 540-84-1 2,2,4-Trimethylpentane 2.27 1.97
71-43-2 Benzene 1.15 1 92-52-4 Biphenyl 0.040 0.034
1319-77-3 Cresols 0.29 0.25

98-82-8 Cumene 0.43 0.37 100-41-4 Ethylbenzene 1.02 0.88
110-54-3 Hexane 4.05 3.50 1634-04-4 Methyl tertiary butyl ether 0.67 0.58

91-20-3 Naphthalene 0.33 0.29
108-93-0 Phenol 0.21 0.18 100-42-5 Styrene 0.67 0.58
108-88-3 Toluene 3.86 3.34 1330-20-7 Xylene 4.13 3.57

a CASRN = Chemical Abstracts Service Registry Number.

b Weighted average composition of all liquid proc ess streams (Lucas, 2007); wt% = weight percent.

c Ratio of weighted average liquid concentration of sele cted HAP to weighted average liquid concentration for benzene.

Table 4. Model Plant Areas for Fugitive Equipment Leaks

Model Unit Crude Capacity Model Unit Applied to Refineries with Crude Capacity in Range Equipment Leak Process Area (MM ft 2 ) a
50,000 0 to <125,000 0.3 200,000 125,000 to <225,000 1.7 250,000 ≥ 225,000 4

a MM ft 2 = million square feet.

Emission Factors for Storage Vessels

Similar to equipment leaks, “allowable” emissions are difficult to assess for storage vessels. The existing requirements in Refinery MACT 1 include a requirement to use either a floating roofTechnical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

7 tank or a fixed roof tank vented to a control device when st oring petroleum liquids above a certain vapor pressure threshold in tanks above a certain size. The floating roofs often have guidepoles, hatches, and sampling we lls. Refinery MACT 1 does not require these fittings to be controlled ( e.g. , gasketed seals).

Emissions from storage vessels we re originally developed for crude oil, light distillates, heavy distillates, and aromatics base d on emission estimates reported in permit applications (RTI, 2002). The heavy distillates emission factors we re based on emission estimates for fixed roof tanks. As heavy distillates ar e expected to be Group 2 storage vessels due to low vapor pressures, the emission factors for these tanks we re expected to be indicative of allowable emission for these tanks. The emission factors for aromatics storage ta nks were not revised either. While most aromatics have vapor pressu res below the Refinery MACT 1 threshold, these vessels are primarily regulated under the H azardous Organic NESHAP (HON) or benzene storage rule, so the emission factors develope d from the permit estimates were expected to represent the allowable emissions.

The “light distillates” originally included gasoline, naphtha, jet fu el, and diesel fuel ( i.e. , No. 2 fuel oil), which are the storage vessels subject to Refinery MACT 1 control requirements. To provide better modeling estimates, the original light distillates categor y was divided into two categories: “light distillates,” which includes gasoline and jet naphtha, a nd “middle distillates,” which includes other jet fuels, kerosene and diesel fuel. To represent the allowable emissions, revised emission factors were deve loped for the new light and middle distillate categories as well as the crude oil category based on TANKS v4.09 mode l estimates for external floating roof tanks assuming the tank employed an uncontrolled slotted guidepole and did not have fitting controls on other openings or hatches on the floating roof ( i.e. , the minimal control requirements in Refinery MACT 1 for Group 1 storage vessels).

The results of the TANKS model run are summ arized elsewhere (Lucas, 2008). The specific HAP composition of the volatile organic compound (VOC) emissions were estimated based on the average liquid and vapor phase composition for cr ude oil, gasoline (for light distillates), and jet naphtha (for middle distillates). It was assu med that most of the VOC losses would be via gaseous losses, but that 20 percent of the losses would be via liquid losses ( e.g. , liquid clinging to the sides of the wall or guidepole). The av erage HAP concentrations of the VOC losses used in the analysis are presented in Table 5. Thes e concentrations combined with the model tank emission losses and throughputs yield the em ission factors presented in Table 6.

In addition to revising these emission factors, the area associated w ith the tank farm were revised, again to limit overlap with potential receptors. The revi sed tank farm release areas are presented in Table 7.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

8 Table 5. HAP Concentration of VOC Storage Vessel Emissions

CASRN HAP Crude Oil (wt%) Gasoline (wt%) Jet Naphtha (wt%) 106-99-0 1,3-Butadiene 0 0.022 0 540-84-1 2,2,4-Trimethylpentane 0.25 1.71 0.44
71-43-2 Benzene 0.73 0.82 1.10 92-52-4 Biphenyl 0.012 0.002 0
1319-77-3 Cresols 0.044 0.16 0.004

98-82-8 Cumene 0.034 0.18 0.21 100-41-4 Ethylbenzene 0.12 0.37 0.37
110-54-3 Hexane 6.18 4.97 9.72 1634-04-4 Methyl tertiary butyl ether 0 3.60 0

91-20-3 Naphthalene 0.045 0.089 0.081
108-93-0 Phenol 0.067 0.011 0.013 100-42-5 Styrene 0 0.776 0
108-88-3 Toluene 0.56 2.12 2.05 1330-20-7 Xylene 0.46 1.62 1.41

Table 6. Storage Vessel HAP Emissions Factors for Allowable Emission Estimate

CASRN HAP Crude Oil (lb/MMbbl) a Gasoline (lb/MMbbl) a Jet Naphtha (lb/MMbbl) a
106-99-0 1,3-Butadiene 0.00 1.83 0.00 540-84-1 2,2,4-Trimethylpentane 3.39 144.62 22.00
71-43-2 Benzene 9.95 69.73 54.38 92-52-4 Biphenyl 0.17 0.17 0.00
1319-77-3 Cresols 0.60 13.42 0.19

98-82-8 Cumene 0.46 15.45 10.48 100-41-4 Ethylbenzene 1.62 31.48 18.23
110-54-3 Hexane 83.72 421.21 482.02 1634-04-4 Methyl tertiary butyl ether 0.00 305.44 0.00

91-20-3 Naphthalene 0.61 7.57 4.00
108-93-0 Phenol 0.91 0.94 0.67 100-42-5 Styrene 0.00 65.78 0.00
108-88-3 Toluene 7.55 179.30 101.44 1330-20-7 Xylene 6.19 137.47 70.11

a lb/MMbbl = pounds per million barrels.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

9 Table 7. Model Plant Areas for Storage Vessel Tank Farms

Model Unit Crude Capacity Model Unit Applied to Refineries with Crude Capacity in Range Storage Vessel Tank Farm Area (MM ft 2 ) 50,000 0 to <125,000 0.5 200,000 125,000 to <225,000 4 250,000 ≥ 225,000 7

Emission Factors for Stationary Combustion Sources

The emission factors for process heaters and boil ers were revised based on the emission factors reported in the Emission Estimation Protocol for Petroleum Refineries (RTI, 2011) for natural gas/refinery gas. The fuel use factors and s ource characteristics were not changed from the original model estimates (RTI, 2002). As stationa ry combustion sources were not a focus of this analysis, these default emission factors were de emed to be acceptable for the allowable emission estimate.

Emission Factors for Catalytic Cracking Units

Refinery MACT 2 (40 CFR 63 subpart UUU) requi res fluid catalytic cr acking units (FCCU) to either meet a PM emission limit of 1 lb/1,000 lb coke burn-off or one of two nickel emissions limits (0.029 pounds per hour (lb/hr) or 0.001 lb/ 1,000 lb coke burn-off). Based on a typical coke make rate of 16 pounds per barrel (lb/bbl) of feed and given an allowable PM emission rate of 1 lb/1,000 lb coke burn-off, the PM emissions rate in terms of throughput is approximately 16,000 pounds per million barrels (lb/MMbbl). Based on data from the original MACT 2 study (EPA, 1997), a typical nickel concentration on the PM fines is approximately 1,300 parts per million by weight (ppmw), so an “allowable” emi ssion limit of 20 lb/MMbbl was used for this analysis. This is slightly higher than the direct conversion of th e nickel emission limit (0.001 lb/1,000 lb coke burn-off × 16,000,000 lb coke/MMbbl = 16 lb/MMbbl), but most refineries comply with the PM emissions lim it unless they have particularly low nickel concentrations in their FCCU feed. The metal c oncentration ratios for FCCU as reported in the Emission Estimation Protocol for Petroleum Refineries (RTI, 2011) were used to estimate the emissions for the other metal HAP.

Except for hydrogen cyanide (HCN), the emission factors for non-metal HAP from the FCCU as reported in the Emission Estimation Protocol for Petroleum Refineries (RTI, 2011) were used in the analysis. Results of source tests conducted in response to the petr oleum refining industry ICR indicated that HCN emissions were signific antly higher than expected. The average HCN emission factor derived from the ICR source test s was approximately 10 times greater than the emission factor reported in the Emissions Prot ocol. Therefore, the HCN emission factor was increased by a factor of 10 (to 7,700 lb/MMbbl) fo r the allowable emissions analysis. Based on the modeled emissions (and the default FCCU stack parameters), HCN is not projected to result in an HQ exceeding 1 even with this factor of 10 increase in the HCN emission factor.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

10 Emission Factors for Delayed Coking Units

Delayed coking units were not considered in th e previous REM. Default emission factors for DCU are available in the Emission Estimation Protocol for Petroleum Refineries (RTI, 2011); these factors are in units of mass pollutant em issions per depressurizat ion cycle. Based on available data, it was estimated that 1,680 tons of coke are produced per cycle. The emission factors in the Emissions Protocol were divided by this value to cal culate an emission rate per ton of coke produced. The original and converted emission factors are prov ided in Table 8. The emissions factors in the Emissions Protocol (and Table 8) were deri ved from units that vented to atmosphere in the range of 7 to 9 pounds per square inch gauge (psig). If these sources elected to vent at higher vessel pressures, the emissions would be higher but w ould still not requ ire control. Therefore, to estimate the allowable emissions, the default emission factors in Table 8 were multiplied by a factor of 3 to estimate the allowable emissions.

In order to use the emission factors, one n eeds to know the coke production rate. The Refinery Capacity Report 2010 (EIA, 2010) provides petroleum coke production capacity in terms of barrels per stream day and they pr ovide in the definition of petrol eum coke that the conversion is 5 barrels per short ton of petroleum coke. The coke production rate for a given facility was converted to tons using this factor and then multiplied by the emission factors in Table 8 and an “allowable” factor of 3 (as described above) to estimate the allowable pollutant emissions.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

11 Table 8. Default Emission Factors for Delayed Coking Units

CASRN Compound Emissions Factor (lb/cycle) Emissions Factor (lb/ton coke)
74-82-8 Methane 200 1.2E-01
74-84-0 Ethane 42 2.5E-02

VOC Nonmethane/nonethane VOC 57 3.4E-02
71-43-2 Benzene 0.1 6.0E-05
108-88-3 Toluene 5.6 3.3E-03 100-41-4 Ethylbenzene 0.03 1.8E-05 1330-20-7 Xylene 0.24 1.4E-04
108-95-2 Phenol 0.12 7.2E-05 1319-77-3 Cresols (total) 0.23 1.4E-04 105-67-9 2,4-Dimethylphenol 0.086 5.1E-05
62-53-3 Aniline 0.057 3.4E-05

POM Total all POM a (excluding naphthalene) 0.64 3.8E-04 83-32-9 Acenaphthene 0.07 4.2E-05 208-96-8 Acenaphthylene 0.004 2.4E-06
120-12-7 Anthracene 0.15 8.9E-05 56-55-3 Benzo(a)anthracene 0.031 1.8E-05 50-32-8 Benzo(a)pyrene 0.027 1.6E-05 205-99-2 Benzo(b)fluoranthene 0.007 4.2E-06 191-24-2 Benzo(g,h,i)perylene 0.014 8.4E-06 207-08-9 Benzo(k)fluoranthene 0.005 3.0E-06 218-01-9 Chrysene 0.032 1.9E-05 53-70-3 Dibenz(a,h)anthracene 0.01 6.0E-06
206-44-0 Fluoranthene 0.024 1.4E-05
86-73-7 Fluorene 0.18 1.1E-04 193-39-5 Indeno(1,2,3-cd)pyrene 0.007 4.2E-06 91-20-3 Naphthalene 1.7 1.0E-03
85-01-8 Phenanthrene 0.46 2.7E-04 129-00-0 Pyrene 0.08 4.8E-05

a POM = polycyclic organic matter

As DCU were not included in the previous REM model, default stack characteristics needed to be established. Default stack parameters for the DCU steam vent were estimated based on a cursory review of source test do cumentation and ICR Component 1 responses. The default stack parameters for the DCU steam vent used in the analysis were:

 Height = 30 feet (ft)

 Diameter = 0.5 ftTechnical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

12  Velocity = 42 feet per second (ft/sec)

 Temperature = 212 degrees Fahrenheit (°F)

 Operating time = 480 hours/yr

Emission Factors for Catalytic Reforming Units

Refinery MACT 2 requires purging and depressuri zation of the CRU to be controlled until the unit reaches a pressure of 5 psig or less and requires wet (or dry) scrubbing to remove hydrogen chloride (HCl) during coke burn-off. The de fault organic HAP emission factors in the REM (which are the same as those in the Emission Estimation Protocol for Petroleum Refineries (RTI, 2011)) are commensurate with this control strate gy as the wet scrubbers are not expected to reduce the organic HAP emissions. The inorgani c HAP (specifically HCl and chlorine) default emission factors in the REM (and Emissions Prot ocol) are based on uncontrolled coke burn-off vent emissions. Refinery MACT 2 requires two different levels of control depending on the type of CRU: semi-regenerative CRU are required to achieve a 92 percent re duction of HCl or down to an outlet concentration of 30 parts per m illion (ppm); and continuous and cyclic CRU are required to achieve a 97 percent re duction of HCl or down to an ou tlet concentrati on of 10 ppm. As a significant portion of the catalytic reform ing capacity is semi-regenerative and subject to the 92 percent control efficiency requirement in Refinery MACT 2, the allowable emission estimates for HCl and chlorine were calculated using the default (uncontrolled) emission factor multiplied by 0.08 to account for the minimal c ontrol level required by Refinery MACT 2. There were no changes in the default release characteristics for CRU.

Emission Factors for Sulfur Recovery Plants

The primary HAP emitted from sulfur recovery units (SRU) are car bonyl sulfide (COS) and carbon disulfide (CS 2 ). Refinery MACT 2 requires SRU to meet a reduced sulfur standard of 300 ppm (by volume, corrected to 0 percent oxyg en). The default controlled SRU emission factor in the REM (RTI, 2002) a nd in the Emissions Protocol (R TI, 2011) are from units meeting this emission limit. As most facilities target to operate at approxima tely half the allowable emission limit to ensure continuous compliance with the standards, a factor of 2 was applied to the default controlled emission factor to esti mate the allowable emissions. There were no changes in the default release charact eristics for SRU for this analysis.

Emission Factors for Flares

The default emission factors for flares in the RE M were updated to reflect the emissions factors presented in the Emissions Prot ocol (RTI, 2011). However, it is difficult to determine an allowable emission rate for flares. There is not currently a limit to how much gas can be combusted in a flare. There are operational requir ements that are generally expected to achieve 98 percent destruction efficiency. Given the f act that flares function as both an emergency control device and routine contro l device and can handle an extrem ely large range of variable flow, and given the uncertainty in the amount of flare gas being generated from a given refining operation, we applied a factor of 3 to the defau lt emissions factor to conservatively estimateTechnical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

13 allowable emissions from flares. There were no ch anges in the default release characteristics for flares for this analysis.

Emission Estimates for Wastewater Treatment Systems

Refinery MACT 1 requires refinery wastewater treatment systems to comply with the Benzene Waste Operations NESHAP (40 CFR part 61, subpa rt F, commonly referred to as “BWON”). The 2002 version of the REM used a simple correl ation to estimate the benzene emissions for wastewater systems subject to the BWON gi ven the total mass benzene loading rate to wastewater. The methodology used to estimate the “controlled” BWON emissions were revised to more closely match the BWON control requirements.

The benzene loading rates to wastewater are estimated using the methodology from Locating and Estimating Air Emissions from Sources of Benzene (EPA, 1998) as was done previously. For facilities that have benzene wast ewater loadings (assumed to be the total annual benzene or TAB quantity) exceeding 10 megagrams per year (Mg/yr), th en the facility is projected to be subject to BWON requirements. For BWON facilities, the wa stewater collection syst em is required to be 98 percent efficient, so that 2 percent of the TAB was assumed to be released from the wastewater collection system. It is assumed that approximate ly 50 percent of the remaining benzene is recovered in the oil water separator and that 50 percent of the original TAB enters a biological treatment unit. The expected performance of a petr oleum refinery’s biological treatment system that meets the criteria of an enhanced biological treatment unit (EBU) in BWON is to degrade 92 percent of the inlet benzene load. Ther efore, benzene emissions from the EBU were assumed to be 8 percen t of the benzene load to the EBU.

For wastewater systems not subject to BWON (t hose with a projected TAB less than 10 Mg/yr), 85 percent of the initial benzene load is assume d to be emitted across the refinery; 50 percent of these emissions were attributed to the wastewat er collection area and 50 pe rcent were assigned to the wastewater treatment area.

Emissions of other HAP were estimated from th e calculated benzene emissions using adjustment factors based on the relative concen tration of the HAP in wastewater streams, its octanol-water partition coefficient, and WATER9 emission es timates as was done previously (RTI, 2002).

The release areas for wastewater treatment sources were revised to reduce the likelihood that the wastewater sources would overlap a receptor; the revised release areas are provided in Table 9.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

14 Table 9. Model Plant Areas for Wastewater Collection and Treatment

Model Unit Crude Capacity Model Unit Applied to Refineries with Crude

Capacity in Range Wastewater Collection Area (MM ft 2 ) Wastewater Treatment Area (MM ft 2 ) 50,000 0 to <125,000 0.10 0.10 200,000 125,000 to <225,000 0.43 0.43 250,000 ≥ 225,000 1.7 1.7

Emission Factors for Cooling Towers

As with emissions from equipment leaks, it is difficult to estimate “allowable” emissions from cooling towers. Similar to equipment leaks, Refinery MACT 1 requires monitoring of the cooling water within a heat exchange system for hydrocarbon leaks. Strippable hydrocarbons in the cooling water above 80 parts per billion by weight (ppbw) woul d require facilities to find and fix (or block-off) the leak. The heat excha nge monitoring requirement is new, so direct performance data are not available from which to project the allowable emissions. Therefore, as an estimate of the allowable emissions, it was assumed that all cooling water at the refinery contained a strippables organic content of 80 ppbw. This concentration is equivalent to the controlled AP-42 emission factor of 0.7 pounds per million gallons (lb/MMgal) (EPA, 1995).

Based on default factors provide d in AP-42, cooling water flow rates were assumed to be 40 times the crude capacity. The HAP content of the organics in the cooling water were estimated based on the weighted average refine ry stream composition considering both liquid and gaseous streams as summarized by Lucas (2007). The resulting HAP emission factors normalized by crude throughput ar e summarized in Table 10.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

15 Table 10. Concentration Ratios Used for Cooling Tower Emission Estimates

CASRN HAP Controlled AP-42 Emission Factor (tpy/bbl/d) a
106-99-0 1,3-Butadiene 1.5E-09 540-84-1 2,2,4-Trimethylpentane 3.2E-06
71-43-2 Benzene 2.3E-06 92-52-4 Biphenyl 4.2E-08
1319-77-3 Cresols 3.1E-07

98-82-8 Cumene 4.7E-07 100-41-4 Ethylbenzene 1.2E-06
110-54-3 Hexane 1.1E-05 1634-04-4 Methyl tertiary butyl ether 1.4E-06

91-20-3 Naphthalene 3.6E-07
108-93-0 Phenol 2.2E-07 100-42-5 Styrene 7.4E-07
108-88-3 Toluene 5.1E-06 1330-20-7 Xylene 4.7E-06

a tpy/bbl/d = tons per year HAP emissions per barrel per day crude throughput.

Emission Factors for Loading Operations

The default emission factors in the REM model were based on the allowable VOC emission rate for gasoline loading in Refinery MACT 1 and an average gasoline vapor composition. While some HAP, notably benzene, are present in gasoli ne at lower concentrations than they were historically, the default REM emi ssion factor are expected to pr ovide a reasonable estimate of the allowable emissions from loading operations. Therefore, no changes in the default emission factors or release characteri stics for loading operations we re made for this analysis.

6. Comparison of Emission and Risk Estimates by Source and Pollutant

As noted in Section 3 of this memorandum, th e allowable emissions were released from the centroid of the facility using default emission source parameters whereas the actual emissions were released at source-specific locations based on the release characterist ics reported in the ICR inventory. As such, differences in the risk results between the allowable emissions model plant analysis and the ICR inventory data may be a fu nction of differences in the emissions magnitude, release characteristics, a nd/or emissions locations.

Risk estimates were produced by source and pollutant for each f acility for the following risk indicators: MIR, HQ, and cancer incidence. Figure 1 provides a summary of the sources that contributed most to the cancer incidence.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

16 Figure 1. Comparison of cancer incidence determined from the reported “actual” emissions and the modeled “allowable” emissions.

In order to assess if the difference in risks were primarily attributable to differences in the magnitude of emissions or the release charac teristics and locations, the reported “actual” emissions of benzene were compared to the modeled “allowable” emissions. Benzene was selected for this comparison because benzene is emitted from most refinery sources, it contributes significantly to cancer risk associat ed with refinery emissions, and the emission model used to project the “allowable” emissions often estimates the emissions of benzene first and then uses default concentration proportions to estimate emissions of other HAP. Figure 2 provides a comparison of the reported “actual” benzene emissions to the modeled “allowable” benzene emissions.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

17 Figure 2. Comparison of benzene emissions between reported “actual” emissions and modeled “allowable” emissions.

While the “allowable” emission estimates for storag e tanks, wastewater, and flares appear to be reasonably conservative, the “allowable” emission estimates for equipment leaks and cooling towers were lower than the actual emissions reported by the refineries . As noted in our discussion of these sources, establishing an a llowable emissions estimate for these sources is difficult. Emissions from leaking process equi pment (including leaking heat exchangers that impact cooling tower emissions) are highly variable and can fl uctuate significantly based on small variation in the number of “high leak” so urces identified. While these high leak sources typically represent less than 1 pe rcent of the total equipment co mponents, these sources tend to drive the overall emissions. If a facility has more “high le ak” sources than normal, their emissions can be significantly higher than projected by the “all owable” emission factors used. The owner or operator of the facility is not out of compliance when these leaks occur (provided that they implement corrective action to correct the leak), so these actual emissions do not suggest that the facility is out of compliance.

In addition to high variability, the cooling to wer emissions reported in the “actual” emission inventory were reported for th e 2010 inventory year. However, the new heat exchange provisions in Refinery MACT 1 were not require d to be fully implemented until October 2012. 0 50 100 150 200 250 300 350 400 450 500

Equip Leaks Storage Tanks Wastewater Flares Cooling Towers OtherAnnualBenzeneEmissions

Emissions Source Actual

AllowableTechnical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

18 Therefore, the emission inventories for cooling towers could have included emission estimates for cooling towers that were not yet subject to these new standards so that the actual emissions inventory may overestimate the “allowable” emi ssions after implementation of the new heat exchange system monitoring and repair requirements.

It is not unexpected that the emissions for “other ” sources are larger in the actual emissions file than in the “allowable” emissions file because th e model used to project the allowable emissions was limited to a select number of key sources. Emission sources such as miscellaneous process vents are very site-specific and difficult to model and are, therefore, not included in the modeled “allowable” emission estimates. Non-refinery em ission sources such as co-located HON units were also not modeled. The larg est contributor of benzene emissi ons from “other” sources in the actual emissions file was fugitive dust/bulk material handling, which is a source that is not included in the emission model. The benzene em issions for fugitive dust/bulk material handling were driven by two facilities, one reporting 35 tons and other reporting 9.2 tons of benzene emissions. Most facilities reporte d negligible emissions from this source and cumulatively, all of the other facilities reported less than 1.6 tons of benzene from any type of fugitive dust (bulk material handling, paved and unpaved roads, cons truction, and blasting operations). For the sources covered by the model (CRU , sulfur recovery plants, DCU, process heaters and boilers, and loading operations), the allowable benzene emission estimate exceeded the actual benzene emissions reported in the inventory.

In looking at Figure 1, it is also evident that, for some sources, certain pollutants contributed a reasonable portion of the cancer incidence from that source, but those pollutants did not contribute much to the cancer incidence for the allowable run. The emission model focused on the primary pollutants expected to be emitted from a particular source. As such, the emissions for some pollutants, such as ethylene dibromid e, were not included in the emission model for allowable emissions. For the DCU, the emi ssion factor for 2-methylnaphthalene was inadvertently excluded from the DCU emission factor table used in the model, so 2- methylnaphthalene emissions were not included in the DCU allowable emission estimates. This is why the overall DCU risk from polycyclic organic matter (POM) is higher in the actual emissions than in the allowable emissions. Finally, the ratio of na phthalene wastewater emissions to benzene wastewater emissions is significantly higher in the actual emissions inventory compared to the allowable emissions inventory. It appears that the concentration (and/or partitioning) of naphtha lene in wastewater is much higher than projected by the REM model.

7. Post-processed Allowable Risk Estimates

Due to the variability and uncertainty in the emissions from equipment leaks and potentially from cooling towers (from leaking heat exchan ge systems), and due to the limited number of pollutants and sources included in the REM for projecting the allowable emission estimates, it was evident that the allowable emission estimate did not always reflect a conservative emission estimate. This section describes the analysis performed to essentially combine the results of the actual and original allowable risk estimates to develop a more conservative post-processed allowable risk estimate.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

19 As noted previously, risk estimates were produ ced by source and pollutant for each facility for the following risk indicators: MIR, HQ, and cancer incidence. The same risk indicators were produced for the actual emissions inventory run and the allowable emission inventory run. The first step in the process was to match the faci lity/source-type/pollutant records between the two risk estimate results. Step 2 was to compile all unmatched records into the post-processed file. If an allowable record did not match a record in th e actual file, the record was retained. Similarly, if an actual record did not match a record in the allowable file, it was retained. Retaining risk results from the actual risk results file that were not in the allowable risk results file and vice versa provided us with a means to conservative ly account for the risk a ssociated with sources and/or pollutants that were not previously included in one of the two emission inventories.

The third step in generating a post-processed allo wable file was to compare the results where the facility/source-type/pollutant records were incl uded in both emission inventories. The general default was to retain the allowable risk results for that source-type/pollutant combination, given the fact that it was expected to be a more cons ervative model in estimati ng both higher emissions and higher risk (see Table 1) compared to the actua ls estimates. However, in looking at Figures 1 and 2 above, the actuals emission estimates were consistently higher for the equipment leaks (all pollutants), cooling towers (all pollutants), and naphthalene from wastewater. For equipment leaks, cooling towers, and naphthale ne from wastewater, the risk resu lts from the actual file were used instead of the risk results from the allowable file. This post-processed (or combined) allowable risk result file was then used to estim ate the “post-processed allowable” risk from each facility and from each emission source. The resu lt of the facility risk totals are provided in Table 1; Figure 3 provides a comparison of the “post-processed allowable” cancer incidence (by source and pollutant) with the cancer incidence fro m the actual file. As seen in Figure 3, the cancer incidence estimated using the post-processe d allowable file always exceeds that from the actual file.Technical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

20 Figure 3. Comparison of cancer incidence determined from the reported “actual” emissions and the “post-processed allowable” risk estimates.

8. References

EIA (U.S. Energy Informati on Administration). 2010. Refinery Capacity Report 2010

. Prepared by the Energy Information Admi nistration, Washington, DC. June 25, 2010. Available at: http://www.eia.gov/petroleum/refine rycapacity/archive /2010/refcap2010.html

. EPA (U.S. Environmental Protection Agency). TANKS 4.09d Software. www.epa.gov/ttn/chief/sof tware/tanks/index.html

. EPA (U.S. Environmental Protection Agency). 1995. Compilation of Air Pollutant Emission Factors. Volume 1: Stationary Point and Area Sources . AP-42, Fifth Edition. Office of Air Quality Planning and Standard s, Research Triangle Park, NC. 0.000 0.020 0.040 0.060 0.080 0.100 0.120 0.140 0.160 0.180CancerIncidence(casesperyear)

Refinery Source 

### Actuals vs Post

‐ processed Allowables Cancer Incidence Comparison

Other

Arsenic compounds

Chromium (VI) compounds
Formaldehyde
Ethyl benzene
Ethylene dibromide

1,3

‐ Butadiene

Benzene

Nickel compounds

2

‐ Methylnaphthalene
Naphthalene

Other POMTechnical Memorandum – “Allowabl e” Emissions Risk Estimates November 15, 2013

21 EPA (U.S. Environmental Protection Agency). 1998. Locating and Estimating Air Emissions from Sources of Benzene . EPA-454/R-98-011. Office of Air Quality Planning and Standards, Research Triangle Park, NC. J une 1998. Available as Docket Item No. EPAHQ-OAR-2010-0869-0016.

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.

Lucas, B. 2007. Memorandum from Bob Lucas, EPA/SPPD, to Project Docket File (EPA Docket No. EPA-HQ-OAR-2003-0146). Average Refinery Stream Composition . August 6, 2007. Docket Item No. EPA-HQ-OAR-2003-0146-0003.

Lucas, B. 2008. Memorandum from Bob Luca s, EPA/SPPD, to EPA Docket No. EPA-HQOAR-2003-0146. Storage Vessels: Revised Cont rol Options and Impact Estimates

. October 30, 2008. Docket It em No. EPA-HQ-OAR-2003-0146-0144.

Parrish, K., D. Randall, and J Coburn. 2007. Me morandum from Kristin Parrish, David Randall, and Jeff Coburn, RTI International, to Karen Rackley regarding “Final Impacts Analysis for Regulatory Options for Equipment Leaks of VOC in Petroleum Refineries.” October 30, 2007. Docket Item No. EPA-HQ-OAR-2006-0699-0089.

RTI (RTI International). 2002. Petroleum Refinery Source Characterization and Emission Model for Residual Risk Assessment . Prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC. EPA Contract No. 68-D6-0014. July 2, 2002. Docket Item No. EPA-HQ-OAR-2003- 0146-0083.

RTI (RTI International). 2011. Emission Estimation Protocol for Petroleum Refineries

. Version 2.1.1, Final ICR Version Corrected. Pr epared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC. May 2011. Docket Item No. EPA-HQ-OAR-2010-0682-0060.