FROM: Jeff Coburn, RTI International 

TO: Brenda Shine, EPA/OAQPS/SPPD 

DATE: November 15, 2013 

SUBJECT: Refinery Emissions and Risk Estimates for Modeled “Allowable” Emissions 

1. Purpose 

This memorandum documents the methodology used to estimate the emissions allowed by the 

current National Emissions Standards for Hazardous 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 Amendments (CAA) directs the U.S. Environmental 

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

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

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

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

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

million, the EPA must set additional standards to protect human health and the environment 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 revise them “as necessary (taking into account 

developments in practices, processes and control technologies)” no less frequently than every 

8 years, under CAA section 112(d)(6). The Refinery MACT 1 (40 CFR part 63, subpart CC) 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 “Emissions 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 reported “allowable” emissions. The allowable emission 

estimates are difficult to determine, particularly 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. Similarly, emissions from equipment leaks are subject 

to work practice standards rather than direct emission limits, so the allowable emissions for 
Technical Memorandum – “Allowable” 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 elsewhere (RTI, 2002). The emission model uses refinery-specific, 

process unit-specific capacity information to estimate 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 default 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 collected in response to the detailed ICR 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 proposal were estimated using the Human Exposure 

Model HEM-3. The HEM–3 performs the following three primary risk assessment activities: 

(1) conducting dispersion modeling to estimate the concentrations of HAP in ambient air, 

(2) estimating long-term and short-term inhalation exposures to individuals residing within 

50 kilometers (km) of the modeled sources, and (3) estimating individual 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 facilities. Additional detail 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 emission source-specific locations are not included in the model plant 

analysis used for this allowable emissions analysis; all emissions were released from the centroid 

of the facility using default emission source parameters. As such, differences in the risk results 

between the allowable emissions model plant analysis and the ICR inventory data may be a 

function of differences in the emissions magnitude, 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 details regarding emission estimates used in the 

allowable emissions model plant analysis. Section 6 provides additional details regarding 

comparison of the sources and pollutants that contributed 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 employed to derive a more conservative allowable 

emission risk estimate. 
Technical Memorandum – “Allowable” Emissions Risk Estimates 

November 15, 2013 

3

4. Summary of Modeling Results 

Table 1 summarizes the projected risks from petroleum refinery facilities based on modeled 

allowable emission estimates. The maximum individual [cancer] risk (MIR) and the maximum 

hazard quotient (HQ) presented in Table 1 are the result of a summation of individual 

pollutant/source risk estimates across all pollutants 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 exposed] individual is no higher than approximately 

one in 10 thousand, that risk level is considered 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 risks 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 data on the types of processes and their capacities 

to estimate emissions for each refinery in the United States and its territories. Refinery-specific, 

process unit-specific capacity information was based on values reported in the Refinery Capacity 

Report 2010 (EIA, 2010). Process throughput or production capacities for most processes are 

reported in terms of a quantity per “stream day.” These “stream day” capacities were converted 

to “calendar day” capacities based on the ratio of the crude distillation column throughput 
Technical Memorandum – “Allowable” Emissions Risk Estimates 

November 15, 2013 

4

reported in barrels per calendar day (bbl/cd) (adjusted for idled capacity) to the crude distillation 

column throughput reported in barrels per stream day (bbl/sd).1

The original refinery emissions model (aka, REM or REM Model) includes algorithms for 

estimating emissions from storage vessels, equipment 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 emissions 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 “allowable” emissions rate. The existing requirements 

in Refinery MACT 1 include monitoring to detect leaking equipment 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 components based on historical data on the number 

and distribution of leaks for different stringencies of leak detection 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 (Parrish, et al., 2007). For this analysis, the emissions per 

component were estimated based on the assumed distribution 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 projected 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 newer 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 processes, the benzene content in the 

original REM model was higher than in the Emissions Protocol, so this lead to slightly higher 

estimates of benzene emissions. The benzene emission 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 therefore 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 – “Allowable” Emissions Risk Estimates 

November 15, 2013 

5

2010 (EIA, 2010) provides information about the types of units present and 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 multiple 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 provided in Table 2. The 

process unit’s capacity (in bbl/cd) was divided by the appropriate maximum process unit 

throughput. The resulting values (if greater than 0) were rounded to the next larger whole 

number. Thus, facilities with a 250,000 bbl/cd crude distillation capacity were assumed to have 

two crude distillation columns. 

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

Process Unit 

Large 

Refinery 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 products were summed across all process types present at a given 

refinery to calculate the facility’s total benzene emissions from equipment leaks. The facility 

total benzene emissions were subsequently multiplied by refinery-wide average process stream 

individual HAP to benzene concentration ratios to calculate the emissions of other HAP at the 

refinery. The refinery wide average stream concentrations and the concentration multipliers used 

for equipment leaks analysis are summarized in Table 3. 
Technical Memorandum – “Allowable” Emissions Risk Estimates 

November 15, 2013 

6

Finally, the source characteristics 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 

CASRNa HAP 

Average Liquid 

Concentrationb (wt%) 

 Concentration Ratio for 

Equipment Leaksc

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 process streams (Lucas, 2007); wt% = weight percent. c

 Ratio of weighted average liquid concentration of selected 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 ft2)

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 ft2 = 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 roof 
Technical Memorandum – “Allowable” Emissions Risk Estimates 

November 15, 2013 

7

tank or a fixed roof tank vented to a control device when storing petroleum liquids above a 

certain vapor pressure threshold in tanks above a certain size. The floating roofs often have 

guidepoles, hatches, and sampling wells. Refinery MACT 1 does not require these fittings to be 

controlled (e.g., gasketed seals). 

Emissions from storage vessels were originally developed for crude oil, light distillates, heavy 

distillates, and aromatics based on emission estimates reported in permit applications (RTI, 

2002). The heavy distillates emission factors were based on emission estimates for fixed roof 

tanks. As heavy distillates are expected to be Group 2 storage vessels due to low vapor 

pressures, the emission factors for these tanks were expected to be indicative of allowable 

emission for these tanks. The emission factors for aromatics storage tanks were not revised 

either. While most aromatics have vapor pressures below the Refinery MACT 1 threshold, these 

vessels are primarily regulated under the Hazardous Organic NESHAP (HON) or benzene 

storage rule, so the emission factors developed from the permit estimates were expected to 

represent the allowable emissions. 

The “light distillates” originally included gasoline, naphtha, jet fuel, 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 category was divided into two 

categories: “light distillates,” which includes gasoline and jet naphtha, and “middle distillates,” 

which includes other jet fuels, kerosene and diesel fuel. To represent the allowable emissions, 

revised emission factors were developed for the new light and middle distillate categories as well 

as the crude oil category based on TANKS v4.09 model 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 summarized 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 crude oil, gasoline (for light distillates), and 

jet naphtha (for middle distillates). It was assumed 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 average HAP concentrations of the VOC losses used 

in the analysis are presented in Table 5. These concentrations combined with the model tank 

emission losses and throughputs yield the emission factors presented in Table 6. 

In addition to revising these emission factors, the area associated with the tank farm were 

revised, again to limit overlap with potential receptors. The revised tank farm release areas are 

presented in Table 7. 
Technical Memorandum – “Allowable” 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 – “Allowable” Emissions Risk Estimates 

November 15, 2013 

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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 ft2) 

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 boilers 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 source characteristics were not changed from the 

original model estimates (RTI, 2002). As stationary combustion sources were not a focus of this 

analysis, these default emission factors were deemed to be acceptable for the allowable emission 

estimate. 

Emission Factors for Catalytic Cracking Units 

Refinery MACT 2 (40 CFR 63 subpart UUU) requires fluid catalytic cracking 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” emission limit of 20 lb/MMbbl was used for this 

analysis. This is slightly higher than the direct conversion of the 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 limit unless they have particularly low nickel 

concentrations in their FCCU feed. The metal concentration 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 petroleum refining industry 

ICR indicated that HCN emissions were significantly higher than expected. The average HCN 

emission factor derived from the ICR source tests was approximately 10 times greater than the 

emission factor reported in the Emissions Protocol. Therefore, the HCN emission factor was 

increased by a factor of 10 (to 7,700 lb/MMbbl) for 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 – “Allowable” Emissions Risk Estimates 

November 15, 2013 

10

Emission Factors for Delayed Coking Units 

Delayed coking units were not considered in the 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 emissions per depressurization 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 calculate an emission rate per ton 

of coke produced. The original and converted emission factors are provided in Table 8. The 

emissions factors in the Emissions Protocol (and Table 8) were derived 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 would still not require 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 needs 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 provide in the definition of petroleum 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 – “Allowable” 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 POMa (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 documentation 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 ft 
Technical Memorandum – “Allowable” 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 depressurization 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 default 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 strategy as the wet scrubbers are not expected to 

reduce the organic HAP emissions. The inorganic HAP (specifically HCl and chlorine) default 

emission factors in the REM (and Emissions Protocol) 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 reduction of HCl or down 

to an outlet concentration of 30 parts per million (ppm); and continuous and cyclic CRU are 

required to achieve a 97 percent reduction of HCl or down to an outlet concentration of 10 ppm. 

As a significant portion of the catalytic reforming 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 control 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 carbonyl sulfide (COS) and 

carbon disulfide (CS2). Refinery MACT 2 requires SRU to meet a reduced sulfur standard of 

300 ppm (by volume, corrected to 0 percent oxygen). The default controlled SRU emission 

factor in the REM (RTI, 2002) and in the Emissions Protocol (RTI, 2011) are from units meeting 

this emission limit. As most facilities target to operate at approximately 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 estimate the allowable emissions. There were no 

changes in the default release characteristics for SRU for this analysis. 

Emission Factors for Flares 

The default emission factors for flares in the REM were updated to reflect the emissions factors 

presented in the Emissions Protocol (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 requirements that are generally expected to achieve 

98 percent destruction efficiency. Given the fact that flares function as both an emergency 

control device and routine control device and can handle an extremely 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 default emissions factor to conservatively estimate 
Technical Memorandum – “Allowable” Emissions Risk Estimates 

November 15, 2013 

13

allowable emissions from flares. There were no changes 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, subpart F, commonly referred to as “BWON”). 

The 2002 version of the REM used a simple correlation to estimate the benzene emissions for 

wastewater systems subject to the BWON given 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 wastewater loadings (assumed to be the total annual benzene or TAB 

quantity) exceeding 10 megagrams per year (Mg/yr), then the facility is projected to be subject to 

BWON requirements. For BWON facilities, the wastewater collection system 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 approximately 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 petroleum 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. Therefore, benzene emissions from 

the EBU were assumed to be 8 percent of the benzene load to the EBU. 

For wastewater systems not subject to BWON (those with a projected TAB less than 10 Mg/yr), 

85 percent of the initial benzene load is assumed to be emitted across the refinery; 50 percent of 

these emissions were attributed to the wastewater collection area and 50 percent were assigned to 

the wastewater treatment area. 

Emissions of other HAP were estimated from the calculated benzene emissions using adjustment 

factors based on the relative concentration of the HAP in wastewater streams, its octanol-water 

partition coefficient, and WATER9 emission estimates 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 – “Allowable” 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 ft2) 

Wastewater 

Treatment Area 

(MM ft2) 

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) would require facilities to find and 

fix (or block-off) the leak. The heat exchange 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 provided 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 refinery stream composition considering both liquid 

and gaseous streams as summarized by Lucas (2007). The resulting HAP emission factors 

normalized by crude throughput are summarized in Table 10. 
Technical Memorandum – “Allowable” 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 gasoline at lower concentrations than they were 

historically, the default REM emission factor are expected to provide a reasonable estimate of 

the allowable emissions from loading operations. Therefore, no changes in the default emission 

factors or release characteristics for loading operations were made for this analysis. 

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

As noted in Section 3 of this memorandum, the 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 characteristics 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 function of differences in the emissions magnitude, 

release characteristics, and/or emissions locations. 

Risk estimates were produced by source and pollutant for each facility 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 – “Allowable” 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 characteristics 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 associated 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 – “Allowable” 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 storage 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 allowable emissions estimate for these sources is 

difficult. Emissions from leaking process equipment (including leaking heat exchangers that 

impact cooling tower emissions) are highly variable and can fluctuate significantly based on 

small variation in the number of “high leak” sources identified. While these high leak sources 

typically represent less than 1 percent of the total equipment components, these sources tend to 

drive the overall emissions. If a facility has more “high leak” sources than normal, their 

emissions can be significantly higher than projected by the “allowable” 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 tower emissions reported in the “actual” emission 

inventory were reported for the 2010 inventory year. However, the new heat exchange 

provisions in Refinery MACT 1 were not required 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 Other

Annual Benzene Emissions

Emissions Source

Actual

Allowable
Technical Memorandum – “Allowable” Emissions Risk Estimates 

November 15, 2013 

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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” emissions 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 the 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 emission sources such as co-located HON units 

were also not modeled. The largest contributor of benzene emissions 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 emissions 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 reported 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, construction, 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 dibromide, were not included in the emission model for 

allowable emissions. For the DCU, the emission 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 naphthalene 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 naphthalene 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 exchange 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 – “Allowable” Emissions Risk Estimates 

November 15, 2013 

19

As noted previously, risk estimates were produced 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 facility/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 the 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 conservatively account for the risk associated 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 allowable file was to compare the results where the 

facility/source-type/pollutant records were included 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 conservative model in estimating both higher emissions 

and higher risk (see Table 1) compared to the actuals 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 naphthalene from wastewater, the risk results 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 estimate the “post-processed allowable” risk from each 

facility and from each emission source. The result 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 from the actual file. As seen in Figure 3, the 

cancer incidence estimated using the post-processed allowable file always exceeds that from the 

actual file. 
Technical Memorandum – “Allowable” 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 Information Administration). 2010. Refinery Capacity Report 2010. 

Prepared by the Energy Information Administration, Washington, DC. June 25, 2010. 

Available at: 

http://www.eia.gov/petroleum/refinerycapacity/archive/2010/refcap2010.html. 

EPA (U.S. Environmental Protection Agency). TANKS 4.09d Software. 

www.epa.gov/ttn/chief/software/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 Standards, Research Triangle Park, NC. 

0.000

0.020

0.040

0.060

0.080

0.100

0.120

0.140

0.160

0.180

Cancer Incidence (cases per year)

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 POM
Technical Memorandum – “Allowable” 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. June 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 Lucas, EPA/SPPD, to EPA Docket No. EPA-HQOAR-2003-0146. Storage Vessels: Revised Control Options and Impact Estimates. 

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

Parrish, K., D. Randall, and J Coburn. 2007. Memorandum 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. Prepared 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.