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 environmental impacts associated with control 

options for delayed coking units. 

2. Background 

Delayed coking units (DCU) use thermal cracking to upgrade heavy feedstocks and to produce 

petroleum coke. Unlike most other refinery operations that are continuous, DCU are operated in 

a semi-batch system. Most DCU consist of a large process heater, two or more coking drums, 

and a single product distillation column. The DCU feed is actually fed to the unit’s distillation 

column. Bottoms from the distillation column are heated to near cracking temperatures and the 

heavy oil is fed to one of the coking drums. As the cracking reactions occur, coke is produced in 

the drum and begins to fill the drum with sponge-like solid coke material. When one coking 

drum is filled, the feed is diverted to the second coke drum. The full coke drum is purged and 

cooled by adding steam and later water to the vessel. The initial water added to the vessel 

quickly turns to steam, and the steam helps to cool and purge organics 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 the 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 system. When the coke drum is taken off line, 

the initial steaming process gas is also recovered through the unit’s product distillation column. 

As the cooling cycle continues, the produced steam is sent to a blowdown system to recover the 

liquids. The uncondensed gas is either directed to the unit’s product distillation column or to a 

flare or other combustion device. Refinery MACT 1 (40 CFR part 63, subpart CC) defines the 

releases to the blowdown system as the delayed 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 atmosphere prior to draining, deheading, and decoking 

(coke cutting) the coke from the drum. Emissions from DCU that occur during this atmospheric 
Technical Memorandum – Impact Estimates 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 organic 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 regulations to reduce volatile 

organic compound (VOC) and hazardous air pollutant (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 the 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 system is decreased or when the coke is cut out 

of the drum. However, emissions may also occur as a result of volatilization of contaminants in 

the water. The steam/water used to purge and fill the coke drum can contact and dissolve various 

organic contaminants. Some of these contaminants can subsequently volatilize from the water as 

the pressure of the system is reduced. 

Initially, emissions from depressuring the coke drum 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 model 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 greenhouse 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 DCU. Later, fixed emission quantities per vent 

cycle were recommended for estimating the DCU emissions (RTI, 2011) because there did not 

appear to be a distinct correlation between the emissions and venting pressures. 

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

refining industry (EPA, 2011). As part of this ICR, facilities that had performed source tests of 

their units were required to submit copies of these 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 refineries to observe 

the DCU operations and better understand the emissions that occur during the decoking process. 

Based on this additional information, it is clear that the simple gas depressuring model is 

incorrect for several reasons. First, there is little gaseous void space in the coke drum because 

the coke drum is filled with water. Second, there is a significant quantity of steam generated and 

released from the coke drum during the depressuring process because the boiling point of the 
Technical Memorandum – Impact Estimates for Delayed Coking Units 

September 12, 2013 

3 

water decreases as the pressure of the vessel decreases. 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 generation 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 2,500,000

Pollutant Emissions(lbs/cycle)

SteamGeneration (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 given DCU, the trend of the emissions with steam 

generation rates appears to be consistent for a variety of pollutants. Table 1 provides the 

average emissions per cycle across 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 Estimates 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

%RSDb of 

lb/cycle 

emission factor 

Average 

Emission Factor 

(lb/1,000 lb 

steam)a

%RSDb 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 deviation = standard deviation/average × 100%. 

Attempts were made to find correlations with the vessel pressure or temperature with the steam 

generation rates. Any correlations of this type were 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 drained 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 releases 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 considered as a potential 

method to reduce emissions from the DCU. However, 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 cools to below 212 degrees Fahrenheit (°F). As 

HAP and other pollutant emissions appear to be correlated with the steam releases, it is expected 

that HAP emission from the draining area will increase 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), the amount of steam generated is 

expected to be a function of the 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 primarily impact where the steam that is generated is 

released. Thus, it is important to consider all emissions from the decoking operations (venting, 

draining, deheading and coke cutting), 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 void 
Technical Memorandum – Impact Estimates for Delayed Coking Units 

September 12, 2013 

5 

fraction of the coke drum tend to underestimate the vent gas volumes and emissions from the 

DCU. As the coke drum depressurizes, additional 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 enthalpy of steam formation to determine the steam 

generation volume needed to cool the water in the bed to 212 °F using evaporative cooling. 

Venting volumes determined solely based on pressure expansion is typically small compared to 

the volume of steam generated based on a heat balance 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: 

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

where: 

 Msteam = Mass of steam generated and released during vessel depressurization and 

opening, pounds (lb). 

ΔHvap = Heat of vaporization of water, British thermal units per pound (Btu/lb). 

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

 Mwater = Mass of water in the coke vessel prior to depressurization and opening, lb. 

 Cp,water = Heat capacity of water, British thermal units per pound per degree Fahrenheit 

(Btu/lb/°F). 

 Mcoke = Mass of petroleum coke in the coke vessel prior to depressurization and 

opening, lb. 

 Cp,coke = Heat capacity of petroleum coke, Btu/lb/°F. 

 Tinitial = Average temperature of the coke drum when the drum is first vented to the 

atmosphere, °F. 

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

The convective heat loss is dependent of the surface area of the drum, its construction, and the 

ambient temperature. For convenience, it was assumed that the convective heat loss is a fraction 

of the total latent heat loss from the drum. Solving for the mass of steam generated yields: 

     

vap

ConvLoss water waterp, coke cokep, initial final

steam H

f1 TTCMCM

M



   (Eqn. 2) 
Technical Memorandum – Impact Estimates for Delayed Coking Units 

September 12, 2013 

6 

where: 

 fConvLoss = 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, facilities 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 venting 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 cylinder 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 using 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 calculated 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 water 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 reported (indicating “unknown” value), 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 volume 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 generated as calculated in Equation 2. The porosity 

and density of coke, as well as other parameters needed for Equation 2, are provided in Table 2. 

While the heat capacity and heat of vaporization parameters are dependent on the temperature 

and pressure of the system, these parameters do not vary that significantly 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 considered within the impacts 

model for DCU. 
Technical Memorandum – Impact Estimates for Delayed Coking Units 

September 12, 2013 

7 

Table 2. Heat Balance Default Input Parameters 

Input 

Parameter Input Parameter Description 

Default 

Value Units Reference 

εcoke Porosity of coke bed 0.50 volume 

fraction Engineering judgment 

ρcoke Particle density of delayed coke 84.3 lb/ft3 a Perry’s, 1999, p. 27-7 

Cp,coke Heat capacity of petroleum coke 0.265 Btu/lb/°F Perry’s, 1999, p. 2-186 

ρwater Density of water (at 220 °F) 59.5 lb/ft3 a ASME Steam Tables, 

2006 

Cp,water Heat capacity of water (at 220 °F) 1.0 Btu/lb/°F Perry’s, 1999, p. 2-174 

∆Hvap

Heat of vaporization of water (at 228 

°F, 20 psia) 960 Btu/lb ASME Steam Tables, 2006 

fConvLoss

Fraction of total heat loss via 

convective cooling 0.10 fraction Engineering judgment 

a

 lb/ft3 = pounds per cubic foot. 

The initial temperature (Tinitial) 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 values 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 data were corrected to °F (by subtracting 460 from 

the reported value), when projecting the steam generation for these two units. The final 

temperature (Tfinal) for this analysis was set at 212 °F (the temperature below which steam 

generation would stop). The reported venting temperatures for a few DCU were below 212 °F; 

Tinitial 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 released was determined using the mass of steam generated, the 

ideal gas law, and the vent gas moisture content. 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 ft3

-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 content). The dry gas flow rate is 

determined from the total vent gas flow rate and 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 reported 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 emission factors developed from the additional 
Technical Memorandum – Impact Estimates for Delayed Coking Units 

September 12, 2013 

8 

source tests. Therefore, these concentrations were not revised in order 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-mola 

VOC concentration 0.06 volume fraction as 

propane, dry basis URS, 2008b 

VOC molecular weight 44 lb/lb-mola

Used molecular weight of propane 

as NMNEVOCa 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-methane 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, the 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 bed temperature understanding that the lower portion of the coke 

bed will be cooler than the upper portion. While direct data for the average coke bed 

temperature would be more directly applicable for the model estimates, due to the operating 

conditions and coke cutting activities that are performed in the coke drum, it is not possible to 

install temperature probes within the coke bed. Therefore, direct coke bed temperature 

measurement data are not available. Temperature measurements are typically made in the steam 

vent line measuring the temperature of steam leaving the vessel and this measurement location 

would tend to overestimate the average coke bed 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 steam vent line just above the coke drum. 

While a facility may elect to change operational procedures 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 system to improve the steam evacuation rate from 

the drum so that the water level within the drum at baseline is effectively identical to the water 
Technical Memorandum – Impact Estimates 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 vessel pressure is at 2 psig (i.e., average 

coke bed temperature of 220 °F) to the steam generated under the baseline conditions is equal to 

the ratio of the temperature differences as follows: 

 

  initial,baseline final

initial,control final

baseline steam,

steam,control

T T

T T

M

M

Ratio 

   (Eqn. 3) 

where: 

 Ratio = Ratio of steam generation under the control option to the steam generation 

under the baseline conditions, unitless. 

 Msteam,control = Mass of steam generated and released during vessel depressurization and 

opening under the control option, lb. 

 Msteam,baseline = Mass of steam generated and released during vessel depressurization and 

opening based on the Refinery ICR responses, lb. 

 Tinitial,control = Average temperature of the coke drum when the drum is first vented to the 

atmosphere under the control option, °F. 

 Tinitial,baseline = Average temperature of the coke drum when the drum is first vented to the 

atmosphere as reported in the Refinery ICR responses, °F. 

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

As pollutant emissions are projected to be directly dependent on the steam generation rate, this 

“Ratio” also reflects the ratio of emissions under the control option to the emissions at baseline. 

If Tinitial,baseline is less than the designated control option venting temperature, the “Ratio” is set 

to 1. A “Ratio” of 1 indicates that no emission reductions occur under the control option. The 

emissions under the control option are simply: 

 Ratio controli,  EE baselinei,  (Eqn. 4) 

where: 

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

 Ei,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 emissions. Note also that the dry gas composition 
Technical Memorandum – Impact Estimates 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 temperatures or pressures exceeding the limits provided for the specific 

control option were assumed to either extend their cooling cycle or install a system to increase 

their steam evacuation rate (accomplishing additional cooling within the same cooling cycle 

time). The median reported preheat/standby cycle time is 4 hours and the 80th 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 limit are expected to install and operate a steam 

ejector system to increase the evacuation rate 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 prior 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. Alternatively, the uncondensed gases can be directly 

routed to a nearby process heater or boiler or discharged to a flare. The uncondensed dry gas is 

expected to consist primarily of methane (70 percent) 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 estimated using natural gas costs of $5.00/1,000 cubic 

feet (EIA, 2011). 
Technical Memorandum – Impact Estimates for Delayed Coking Units 

September 12, 2013 

11 

5. Results 

Cost and emission reductions were evaluated on a DCU-specific basis using the data reported by 

petroleum refineries in the detailed 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 costs and emission reductions calculated for the 

petroleum refining industry for the control option are summarized in Tables 5 and 6, 

considering VOC and HAP emissions, respectively. Although the control cost estimates for 

DCU were developed from 2011 vendor 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 the 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 CO2

equivalence (CO2e) is a reduction of 378,000 tons (343,000 metric tonnes). 

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

Control 

Option 

Total 

Capital 

Investment 

(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) 

Cost 

Effectiveness ($/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 

Capital 

Investment 

(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) 

Cost 

Effectiveness ($/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 Estimates 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 Coburn and Carrie Richardson, RTI 

International, to Bob Lucas, EPA/SPPD. April 28, 2008. Docket Item No. EPA-HQ-OAR2007-0011-0226. 

EIA (U.S. Energy Information 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 copyright 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 Standards, 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 Management District). 2004a. Source Test Report 03-194 

Conducted at Chevron / Texaco Refinery, El Segundo, California—Volatile Organic 

Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions From a 

Coke Drum Steam Vent. May 14, 2004. Docket Item No. EPA-HQ-OAR-2007-0011-0187. 

SCAQMD (South Coast Air Quality Management 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 Management 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 Management 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 for 
Technical Memorandum – Impact Estimates for Delayed Coking Units 

September 12, 2013 

13 

CITGO Refining and Chemicals Company 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. 

Wilkins, J. 2011. E-mail to Brenda Shine, EPA, from James Wilkins, Marathon Petroleum 

Company LP, regarding “Requested Information.” November, 7, 2011.