FROM: Jeff Coburn, RTI International

TO: Brenda Shine, EPA/OAQPS/SPPD

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

DATE: September 12, 2013

SUBJECT: Impacts Estimates for Delayed Coking Units

1. Purpose

This memorandum documents the costs and envi ronmental impacts asso ciated with control options for delayed coking units.

2. Background
Delayed coking units (DCU) use thermal crackin g to upgrade heavy feedstocks and to produce petroleum coke. Unlike most othe r refinery operations that are continuous, DCU are operated in a semi-batch system. Most DCU consist of a la rge process heater, two or more coking drums, and a single product distillation co lumn. The DCU feed is actuall y fed to the unit’s distillation column. Bottoms from the distillation column ar e heated to near cracking temperatures and the heavy oil is fed to one of the coking drums. As the cracking reactions occu r, coke is produced in the drum and begins to fill the drum with s ponge-like solid coke material. When one coking drum is filled, the feed is diverted to the sec ond coke drum. The full coke drum is purged and cooled by adding steam and later water to the ve ssel. The initial water added to the vessel quickly turns to steam, and the st eam helps to cool and purge organi cs in the coke matrix. After the coke drum is sufficiently cooled, and filled with water in sufficient volumes to cover the coke, the drum is opened, the water drained, and the coke is removed from the vessel using high pressure water. Once the coke is cut out of th e drum, the drum is closed, and prepared to go back on-line. A typical coke drum cycle is typically 28 to 36 hours from start of feed to start of feed.
During the reaction process, the DCU is a closed sy stem. When the coke drum is taken off line, the initial steaming process gas is also recovere d through the unit’s product distillation column. As the cooling cycle continues, the produced stea m is sent to a blowdown system to recover the liquids. The uncondensed gas is either directed to the unit’s product disti llation column or to a flare or other combustion device. Refinery MA CT 1 (40 CFR part 63, subpart CC) defines the releases to the blowdown system as the dela yed coker vent and these emissions must be controlled following the requirements for miscellaneous process vents.
Near the end of the cooling process, a vent is opened on the drum to allow the remaining steam and vapors to be released directly to the atmo sphere prior to draini ng, deheading, and decoking (coke cutting) the coke from the drum. Emissions from DCU that occur during this atmosphericTechnical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

2 venting (commonly referred to as the steam vent ) and subsequent decoking steps are primarily light organics (methane, ethane, and propane), but may include some light aromatics (like benzene and toluene) and light polycyclic or ganic matter (predominately naphthalene and 2- methyl naphthalene).
The Refinery MACT 1 definition of “miscellaneous process vents” specifically excludes the DCU steam vent when the vessel pressure is less than 15 pounds per square inch gauge (psig) and also excludes all releases associated with other deocking operations (draining, deheading, and coke cutting). As part of its review of the Refinery MACT 1 standards, the U.S. Environmental Protection Agency (EPA) is considering specific regulatio ns to reduce volatile organic compound (VOC) and hazardous air po llutant (HAP) emissions from DCU.

3. Emission Estimation Approach
Evaluation of DCU Emissions Data
The precise mechanism of the emissions from the DCU is not well understood. The coke drum is typically filled with water to cover the coke bed within th e coke drum. There may be void spaces within the coke bed that are not filled with water, and the gases in these void areas are subsequently released when the pressure of the sy stem is decreased or when the coke is cut out of the drum. However, emissions may also occur as a result of volatilizatio n of contaminants in the water. The steam/water used to purge and fi ll the coke drum can contact and dissolve various organic contaminants. Some of these contaminants can subsequently volatil ize from the water as the pressure of the system is reduced.
Initially, emissions from depressuring the coke dr um were expected to be a function of the drum size, void fraction, and pressure of the coke drum when first venting to the atmosphere. Estimates using this simple gas depressuring m odel were used in developing impacts for DCU emissions in Refinery NSPS Ja (40 CFR part 60, subpart Ja) (Coburn and Richardson, 2008) and to estimate methane emissions in the greenhous e gas (GHG) mandatory reporting rule (40 CFR part 98, subpart Y, equation Y-18). However, the additional source tests conducted on the DCU steam vent suggested that these simple gaseous depressuring correlations tend to underestimate the vent gas volumes and emissions from the DC U. Later, fixed emission quantities per vent cycle were recommended for estimating the DC U emissions (RTI, 2011) because there did not appear to be a distinct correlation between the emissi ons and venting pressures.

In 2011, the EPA conducted a detailed informati on collection request (ICR) of the petroleum refining industry (EPA, 2011). As part of this IC R, facilities that had performed source tests of their units were required to submit copies of th ese test reports. Additionally, the EPA required selected facilities to conduct source tests to measure the emissions from certain process units, including DCU. Finally, the EPA conducted site visits to several petroleum refineri es to observe the DCU operations and better unde rstand the emissions that occur during the decoking process. Based on this additional information, it is clea r that the simple gas depressuring model is incorrect for several reasons. Fi rst, there is little gaseous voi d space in the coke drum because the coke drum is filled with water. Second, ther e is a significant quantity of steam generated and released from the coke drum during the depres suring process because the boiling point of theTechnical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

3 water decreases as the pressure of the vessel decr eases. To phrase it another way, the coke drum contains superheated water and additional steam is boiled off during coke drum depressuring.

Therefore, the available emissions source test data were evaluated to determine if any trends in the data (SCAQMD 2004a-d; URS 2008a-b; EPA, 2011) . From this evaluation, the key factor influencing the DCU emissions was the steam ge neration quantities. Figure 1 shows the VOC and methane emissions as a function of steam generation.

0 100 200 300 400 500 600 700 800 900

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000PollutantEmissions(lbs/cycle)



### Steam Generation (scf/cycle) VOC

Methane

Figure 1. Emissions of VOC and methane as a function of steam released via the DCU steam vent. Each data point is the average for a specific DCU test.

While there is variability within a test for a gi ven DCU, the trend of the emissions with steam generation rates appears to be consis tent for a variety of pollutants. Table 1 provides the average emissions per cycle acro ss all DCU tests (for which the pollutant was measured) and average emission factors; it also includes the relative percent standard deviation of these emission factors. Again, while there is significant variability, the emissions of all pollutants appear to be best correlated as a function of steam generation.Technical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

4 Table 1. Summary of DCU Emission Factors for Specific HAP

Pollutant Average Emission Factor (lb/cycle) a %RSD b of lb/cycle emission factor Average Emission Factor (lb/1,000 lb

steam) a %RSD b of lb/1,000 lb steam emission factor
Benzene 0.45 85% 0.039 11%
Toluene 3.9 165% 0.12 23% Ethylbenzene 0.060 94% 0.011 50% Xylenes 0.48 91% 0.089 42% Naphthalene 0.56 142% 0.014 18% 2-Methylnaphthalene 0.97 138% 0.028 33%

a lb/cycle = pounds per cycle; lb/1,000 lb = pounds per 1,000 pounds.

b %RSD = percent relative standard devia tion = standard deviation/average × 100%.

Attempts were made to find correlations with th e vessel pressure or temperature with the steam generation rates. Any correlations of this type we re difficult to identify because of differences in how different units were operated, particularly when draining of the coke drum was initiated. Tests conducted when the coke drums were not dr ained at all had higher steam releases from the DCU steam vent; tests conducted when the coke drum was drained after a fixed period (say 30 minutes) after venting had moderate steam rel eases from the DCU steam vent; tests conducted when the coke drum was drained immediately upon venting had lower steam releases from the DCU steam vent. Therefore, the timing of draining the water was cons idered as a potential method to reduce emissions from the DCU. Howeve r, it was also evident during the site visits that there can be significant steam releases during the draining process. Certainly, if superheated water is drained from the coke drum, a significant quantity of steam will be generated and released from the drain water until the water co ols to below 212 degrees Fahrenheit (°F). As HAP and other pollutant emissions appear to be co rrelated with the steam releases, it is expected that HAP emission from the draining area will increa se when the water is drained earlier and the steam is released in the drain area rather than from the steam vent stack. As indicated in the heat balance on the coke drum and its contents (as presented below), th e amount of steam generated is expected to be a function of th e size and average temperature (or pressure) of the coke drum. The total amount of steam generated will not be significantly altered by draining the vessel earlier or later; the timing of draining will prim arily impact where the steam that is generated is released. Thus, it is important to consider a ll emissions from the decoking operations (venting, draining, deheading and coke cut ting), rather than focus on the emissions from the steam vent alone simply because the steam vent emissions are released via a stack and can be more easily measured.
Baseline Emission Estimation Approach
Typically, the temperature of the water/coke within the coke drum will be greater than 212 °F and the pressure greater than 1 atmosphere (atm ) (14.7 pounds per square inch absolute (psia)). As mentioned previously , correlations of venting volumes based only on the pressure and voidTechnical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

5 fraction of the coke drum tend to underestimat e the vent gas volumes and emissions from the DCU. As the coke drum depressurizes, additi onal steam will be generated until the water in the coke drum falls to 212 °F. A heat balance can be used to estimate the volume of steam produced based on the temperature of the coke bed and the mass of water in the coke drum when venting first occurs. This approach uses the enthal py of steam formation to determine the steam generation volume needed to cool the water in the bed to 212 °F usi ng evaporative cooling. Venting volumes determined solely based on pressu re expansion is typically small compared to the volume of steam generated based on a heat balan ce to cool the bed to 212 °F. Therefore, the pressure expansion term was ignored and the volume of gas vented from the system was determined solely based on the water bed temperature.
A heat balance for the coking drum is: 

#       final initial cokep, coke waterp, water vap steam TTCMCM HM    ss ConvHeatLo (Eqn. 1)

where:

M steam = Mass of steam generated and releas ed during vessel depressurization and opening, pounds (lb).

Δ H vap = Heat of vaporization of water, Br itish thermal units per pound (Btu/lb).

ConvHeatLoss = Convective heat loss from si des of the coke vessel, Btu.

M water = Mass of water in the coke vessel pr ior to depressuriza tion and opening, lb.

C p,water = Heat capacity of wate r, British thermal units per pound per degree Fahrenheit (Btu/lb/°F).

M coke = Mass of petroleum coke in the coke vessel prior to depressurization and opening, lb.

C p,coke = Heat capacity of petr oleum coke, Btu/lb/°F.

T initial = Average temperature of the coke drum when the drum is first vented to the atmosphere, °F.

T final = Temperature of the coke drum when steam generation stops = 212 °F.

The convective heat loss is dependent of the surf ace area of the drum, its construction, and the ambient temperature. For conveni ence, it was assumed that the c onvective heat loss is a fraction of the total latent heat loss from the drum. Solving fo r the mass of steam generated yields: 

##   

#    

vap final initial cokep, coke waterp, water ConvLoss
steam H TTCMCM f1 M   

 (Eqn. 2)Technical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

6 where:

f ConvLoss = Fraction of the total heat loss that is due to convective heat loss from the sides of the coke vessel, unitless.

As noted previously, the EPA conducted a detailed ICR of the petroleum refining industry in 2011 (EPA, 2011). In response to the ICR, fac ilities reported the number of coke drums, dimensions of drums, coke drum outage, coke drum cycle times (including venting time), and pressure, temperature, and water level when vent ing starts. The reported data were used to estimate the volume of coke and volume of water in the drum when venting first starts. Each coke drum was assumed to be a perfect cylinde r when calculating the total volume of the coke drum based on the reported diameter and height of the drum. The fraction of the drum volume filled with coke (f_coke_bed) was calculated usi ng the drum outage as follows: f_coke_bed = 1 – outage/drum height. The volume of the coke bed is the volume of the coke drum times f_coke_bed; mass of coke in the drum is calcula ted from the volume of the coke bed (1 – coke porosity) times the coke particle density. The fraction of the coke drum filled with coke and water was initially estimated using the reported wate r height when first vented to the atmosphere divided by the coke drum height. One facility reported a water height exceeding the coke drum height; the fraction of the coke drum filled with coke and water was set to 1 for this facility’s DCU. When a negative water height was repor ted (indicating “unknown” va lue), the fraction of the drum filled with coke and water was assumed to be 0.85. The volume of water in the drum was initially calculated from the fraction of the coke drum filled with coke and water times the volume of the coke drum minus the particle volume of the coke ( i.e. , volume of coke bed times (1 – porosity)). A couple of facilities reported a water level of 0 or a very low water level, leading to a negative vol ume of water in the drum. The minimum volume of water in the drum was set at 10 percent of the drum volume when the volume of water in the drum (based on the coke bed volume and water heights) resulted in a negative volume estimate. This assumption was made to account for residual water within the coke bed even if the water level did not exceed the height of the coke bed. Using this assumption, the mass of water available within the coke drum always exceeded the amount of steam generate d as calculated in Equation 2. The porosity and density of coke, as well as other parame ters needed for Equation 2, are provided in Table 2

. While the heat capacity and heat of vaporization parameters ar e dependent on the temperature and pressure of the system, these parameters do not vary that significan tly over the (generally) limited temperature range considered for this analysis, so temperature/pressure dependencies of the input parameters for the heat balance were not specifically consider ed within the impacts model for DCU.Technical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

7 Table 2. Heat Balance Default Input Parameters
Input Parameter Input Parameter Description Default Value Units Reference

ε coke Porosity of coke bed 0.50 volume fraction Engineering judgment

ρ coke Particle density of delayed coke 84.3 lb/ft 3 a Perry’s, 1999, p. 27-7
C p,coke Heat capacity of petroleum coke 0.265 Btu/lb/°F Perry’s, 1999, p. 2-186

ρ water Density of water (at 220 °F) 59.5 lb/ft 3 a ASME Steam Tables, 2006
C p,water Heat capacity of water (at 220 °F) 1.0 Btu/lb/°F Perry’s, 1999, p. 2-174

∆ H vap Heat of vaporization of water (at 228 °F, 20 psia) 960 Btu/lb ASME Steam Tables, 2006

f ConvLoss Fraction of total heat loss via convective cooling 0.10 fraction Engineering judgment

a lb/ft 3 = pounds per cubic foot.

The initial temperature (T initial ) used in Equation 2 was the temperature reported in the ICR. The median reported temperature was 250 °F. There were two DCU for which the reported venting temperatures were 800 °F or higher. These va lues were much higher than any of the other reported venting temperatures. It was assumed that these temperatures were reported in degrees Rankine (°R) rather than °F, so these outlying da ta were corrected to °F (by subtracting 460 from the reported value), when projecting the steam generation for these two units. The final temperature (T final ) for this analysis was set at 212 °F (the temperature below which steam generation would stop). The re ported venting temperatures fo r a few DCU were below 212 °F; T initial for these DCU were set to 212 °F to yield zero steam generation (rather than a negative steam generation rate).
The total volume of vent gas re leased was determined using the mass of steam generated, the ideal gas law, and the vent gas moisture conten t. Based on available source test data for the coking unit steam vent (SCAQMD 2004a-d; URS 2008a -b), the vent gas moisture content was assumed to be 99 percent by volume. Using 68 °F and 1 atm as “standard conditions,” each pound of steam equates to 21.4 cubic feet at standard conditions (1 lb × 1 pound-mole (lbmol)/18 lb × 0.73 ft 3 -atm/(lb-mol °R) × 528 °R / 1 atm) and is projected to produce 21.6 standard cubic feet (scf) of vent gas ( 21.4 scf water/0.99 moisture conten t). The dry gas flow rate is determined from the total vent gas flow rate a nd the moisture content to be 0.216 dry standard cubic feet per pound (dscf/lb) steam generated [21.6 scf vent gas × (1 – 0.99)]. Data from the Hovensa source test (URS, 2008b) was used to characterize the dry gas composition. Table 3 provides a summary of the assumed vent gas composition. Emission estimates for various pollutants (per cycle) were determined based on the projected dry gas flow rates and the dry gas composition. Annual emissions for the DCU were then calculated using the per cycle emissions times the number of cycles per drum that could be completed in one year (based on the reported cycle times) and the number of coke drums reporte d for the unit. The emissions projected using the default compositions in Table 3 compared well with, but were slightly lower than, the emission projected using lb/1,000 lb steam em ission factors developed from the additionalTechnical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

8 source tests. Therefore, these concentrations were not revised in or der to develop a more conservative (lower) estimate of the emission reductions achieved by lowering the control option.

Table 3. Delayed Coker Steam Vent Gas Default Composition

Input Parameter Description Default Value Units Reference

Vent gas moisture content 0.99 volume fraction Engineering judgment, considering SCAQMD 2004a-d and URS 2008a-b.

Methane content 0.7 volume fraction, dry basis URS, 2008b

Methane molecular weight 16 lb/lb-mol a

VOC concentration 0.06 volume fraction as propane, dry basis URS, 2008b

VOC molecular weight 44 lb/lb-mol a Used molecular weight of propane as NMNEVOC a was determined “as propane” Polycyclic organic matter (POM) concentration 0.085 grams/dscf URS, 2008b

a lb/lb-mol = pound per pound-mole; NMNEVOC = non-met hane and non-ethane volatile organic compounds.

Control Option Emission Estimates
The control option evaluated was to reduce the coke bed pressure to 2 psig prior to venting to the atmosphere. At a vessel pressure of 2 psig, th e equilibrium water temperature is approximately 220 °F. Although steam is continuously being removed during the quenching/ cooling process so that the system is not in perfect equilibrium, the coke drum pressure is expected to be a good indicator of the average coke be d temperature understanding that the lower portion of the coke bed will be cooler than the upper portion. Wh ile direct data for the average coke bed temperature would be more dir ectly applicable for the model estimates, due to the operating conditions and coke cutting activitie s that are performed in the coke drum, it is not possible to install temperature probes within the coke be d. Therefore, direct coke bed temperature measurement data are not available. Temperatur e measurements are typically made in the steam vent line measuring the temperature of steam l eaving the vessel and th is measurement location would tend to overestimate the average coke be d temperature. Therefore, the coke drum pressure measurement is expected to be a better an indicator of the average coke bed temperature than the steam temperature in the stea m vent line just above the coke drum.
While a facility may elect to change operational pr ocedures and have more or less water in the drum at the time the vessel is first vented to the atmosphere, it is expected that most facilities will either extend the cooling period or use a syst em to improve the steam evacuation rate from the drum so that the water level within the drum at baseline is effectivel y identical to the waterTechnical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

9 level within the drum under the control scenarios. For a given DCU with a set mass of water and coke in the drum, the ratio of steam generated when the vess el pressure is at 2 psig ( i.e. , average coke bed temperature of 220 °F) to the steam gene rated under the baseline conditions is equal to the ratio of the temperature differences as follows: 

#    
final baseline initial, final control initial,

baseline steam, control steam, T T T T
M M Ratio

 

  (Eqn. 3)

where:

Ratio = Ratio of steam generation under th e control option to the steam generation under the baseline conditions, unitless.

M steam,control = Mass of steam generated and releas ed during vessel depressurization and opening under the control option, lb.

M steam,baseline = Mass of steam generated and releas ed during vessel depressurization and opening based on the Refinery ICR responses, lb.

T initial,control = Average temperature of the coke drum when the drum is first vented to the atmosphere under the control option, °F.

T initial,baseline = Average temperature of the coke drum when the drum is first vented to the atmosphere as reported in the Refinery ICR responses, °F.

T final = Temperature of the coke drum when steam generation stops = 212 °F.

As pollutant emissions are projected to be dir ectly dependent on the steam generation rate, this “Ratio” also reflects the ratio of emissions under the control option to the emissions at baseline. If T initial,baseline is less than the designated control opti on venting temperature, the “Ratio” is set to 1. A “Ratio” of 1 indicates that no emission reductions occu r under the control option. The emissions under the control option are simply:

Ratio EE baselinei,

controli,   (Eqn. 4)

where:

E i,control = Mass emissions of pollutant “i” under the control option, lb/cycle.

E i,baseline = Mass emissions of pollutant “i” under the baseline case, lb/cycle.

Based on the available data from the DCU test reports, the emissions of HAP (on a mass basis) are approximately 20 percent of the VOC emissions (SCAQMD 2004a-d; URS 2008a-b). This factor was used to estimate the total HAP emi ssions. Note also that the dry gas compositionTechnical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

10 estimates presented in Table 2 indicate that polycyclic organic matter (POM) emissions are approximately 2.7 percent by weight of the VOC emissions.

4. Control Cost Estimates
Facilities that vent at temper atures or pressures exceeding the limits provided for the specific control option were assumed to e ither extend their cooling cycle or install a system to increase their steam evacuation rate (a ccomplishing additional cooling within the same cooling cycle time). The median reported preheat/standby cycle time is 4 hours and the 80 th percentile reported preheat/standby cycle time is 6 hours. Coking units that have preheat/standby cycle time greater than 6 hours and that require less than a 50 percent reduction in emissions (Ratio > 0.5) are expected to comply with the standard by operational changes ( i.e. , by prolonging the quench time of cycle and reducing the standby time) without impacting production rates and without any capital expenditures. All other DCU that have to reduce the coke drum bed temperature to comply with the control option li mit are expected to install and operate a steam ejector system to increase the evacuation ra te of steam generated in the coke drum. Table 4 provides the cost estimates for a steam ejector system.

Table 4. Cost Estimate for Steam Ejector System for a Delayed Coking Unit

Parameter Description Parameter Value, Units Reference A. Capital Investment Cost (installed) $1.0-million Wilkins (2011) B. Operating Costs (for purchased steam) $46,000/yr Wilkins (2011) C. Other Direct Annual Costs (taxes, insurance, and administration) $40,000/yr Estimated as 4 percent of the capital investment cost
D. Capital Recovery Factor 0.1098 Based on 15 year equipment life at 7 percent annual interest E. Total Annualized Cost $195,800/yr B+C+(A×D)

The additional gas collected from the coke drum is expected to go to a closed blowdown system where the steam is condensed to water and either recycled directly for reuse in the DCU or sent to the sour water system for treatment prio r to being reused. The uncondensed gases are typically either sent to the DCU distillation column where they would be recovered in the distillation column overheads as fuel gas. Altern atively, the uncondensed gases can be directly routed to a nearby process heater or boiler or discharged to a flar e. The uncondensed dry gas is expected to consist primarily of methane (70 pe rcent) with some ethane and propane (5 to 10 percent each). As such, the dry gas recovered from the DCU is expected to have a heating value approximately equivalent to natural gas (approximately 1,000 British thermal units per dry standard cubic foot (Btu/dscf)). Assuming the recovered gas is directed to the distillation column or directly used as fuel, the additional dry gas recovered is expected to offset natural gas purchases. A dry gas recovery credit was esti mated using natural gas costs of $5.00/1,000 cubic feet (EIA, 2011).Technical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

11 5. Results

Cost and emission reductions were evaluated on a DCU-specific basi s using the data reported by petroleum refineries in the de tailed ICR responses. These results were summed to get a total estimate of the costs and emissions reduction for the 148 petroleum refineries that responded to the survey. The cumulative nationwide cost s and emission reductions calculated for the petroleum refining industry for the control option are summarized in Tables 5 and 6
, considering VOC and HAP emissi ons, respectively. Although th e control cost estimates for DCU were developed from 2011 ve ndor quotes, the impacts for other petroleum refinery sources are reported in 2009 dollars to be consistent with other cost estimates developed for other Refinery MACT 1 emission sources. Given th e low inflation across this time period, it was assumed that the DCU costs developed from the 2011 vendor quote could be used without correction to estimate the DCU control costs in 2009 dollars. The cost effectiveness is approximately $1,000/ton of VOC reduced. The control option is also projected to reduce methane emissions from the DCU by approximately 18,000 tons, which in terms of CO 2 equivalence (CO 2 e) is a reduction of 378,000 t ons (343,000 metric tonnes).

Table 5. Nationwide VOC Impacts for Delayed Coking Unit Control Options (2009$)

Control Option Total CapitalInvestment (million $) Total Annualized Costs w/o Recovery (million $/ yr) Recovery Credits (million $/ yr) Total Annualized

Costs w/ Recovery (million $/ yr) VOC Emissions (tons per year (tpy)) VOC Emission Reduction (tpy) CostEffectiveness ($/ton VOC Reduced Baseline 4,760 Venting at 2 psig $52.0 $10.2 ($6.20) $3.98 510 4,250 $940

Table 6. Nationwide HAP Impacts for Delayed Coking Unit Control Options (2009$)

Control Option Total CapitalInvestment (million $) Total Annualized Costs w/o Recovery (million $/ yr) Recovery Credits (million $/ yr) Total Annualized

Costs w/ Recovery (million $/ yr) HAP Emissions (tons per year (tpy)) HAP Emission Reduction (tpy) CostEffectiveness ($/ton HAP Reduced
Baseline 950 Venting at 2 psig $52.0 $10.2 ($6.20) $3.98 100 850 $4,700

6. References
ASME (founded as the American Society of Mechanical Engineers). 2006. ASME Steam Tables – Compact Edition . ISBN: 0-7918-0254-X. ASME, New York, New York.Technical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

12 Coburn, J. and C. Richardson. 2008. Final Impacts Analysis for Delayed Coker Depressurization Emissions . Memorandum from Jeff Cobur n and Carrie Richardson, RTIInternational, to Bob Lucas, EPA/SPPD. April 28, 2008. Docket Item No. EPA-HQ-OAR2007-0011-0226.
EIA (U.S. Energy Informati on Administration). 2011. Monthly United States Natural Gas Industrial Price (2001-2011) . Available at: http://www.eia.gov/dnav/ng/hist/n3035us3m.htm

. 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.
Perry, R.H., and D.W. Green (Editors). 1999. Perry’s Chemical Engineers’ Handbook

. Seventh Edition; CD Version (book version co pyright is 1997). McGraw-Hill Companies, Inc., New York, New York.
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 St andards, Research Triangle Park, NC. May 2011. Docket Item No. EPA-HQ-OAR-2010- 0682-0060. Most current version also available at http://www.epa.gov/ttn/chief/efpac/protocol/

. SCAQMD (South Coast Air Quality Ma nagement District). 2004a. Source Test Report 03-194 Conducted at Chevron / Texaco Refinery, El Segundo, California—Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Par ticulate Matter (PM) Emissions From a Coke Drum Steam Vent . May 14, 2004. Docket It em No. EPA-HQ-OAR-2007-0011-0187.
SCAQMD (South Coast Air Quality Ma nagement District). 2004b. Source Test Report 03-197 Conducted at Conoco-Phillips Refinery, Carson, California—Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions From a Coke Drum Steam Vent . July 23, 2004. Docket Item No. EPA-HQ-OAR-2007-0011-0186.
SCAQMD (South Coast Air Quality Ma nagement District). 2004c. Source Test Report 03-198 Conducted at Exxon Mobil Refinery, Torrance, California—Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions From a Coke Drum Steam Vent . March 4, 2004. Docket Item No. EPA-HQ-OAR-2007-0011-0188.
SCAQMD (South Coast Air Quality Ma nagement District). 2004d. Source Test Report 03-200 Conducted at Shell Oil Refinery, Wilmington, California—Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions From a Coke Drum Steam Vent . July 1, 2004. Docket Item No. EPA-HQ-OAR-2007-0011-0189.
URS Corporation. 2008a. Source Test Report of the Coker Steam Vent for Non-Methane and Non-Ethane Volatile Organic Compounds . URS Report No. 40941948.04. Prepared forTechnical Memorandum – Impact Es timates for Delayed Coking Units September 12, 2013

13 CITGO Refining and Chemicals Co mpany LP, West Plant Refinery , Corpus Christi, Texas. April 25, 2008.
URS Corporation. 2008b. Source Test Report of the Coker Steam Vent . URS Report No. 40942073. Prepared for Hovensa, LLC, St. Croix, U.S. Virgin Islands. September 8, 2008. Docket Item No. EPA-HQ-OAR-2007-0011-0272.

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