FROM: Jeff Coburn, RTI International 

TO: Brian Cook, EPA/CCD 

DATE: June 4, 2015 

SUBJECT: Revised Emission Methodology for Delayed Coking Units 

1. Purpose 

This memorandum presents a new emission methodology for estimating methane emissions from 

delayed coking units (DCU). 

2. Background 

On October 30, 2009, the U.S. Environmental Protection Agency (EPA) promulgated rules for 

mandatory reporting of greenhouse gas emissions (GHG) from various source categories (74 FR 

56260). These standards, in 40 CFR part 98, are collectively referred to as the GHG Reporting 

Program (GHGRP). “Petroleum Refineries” is one of the source categories in the GHGRP; GHG 

emissions from petroleum refineries must be reported according to the requirements of 40 CFR 

part 98, subpart Y. Subpart Y includes calculation methodologies for a variety of emission 

sources, including DCU. At the time the mandatory reporting requirements were being 

developed, emissions from delayed coking units were not well understood. The methodology 

originally established to estimate methane emissions from DCU is based on a simple gas 

expansion model (i.e., Equation Y-18). Since the development of this methodology, numerous 

source tests have been conducted on the DCU “depressurization” vent. These tests suggest that 

the simple gas expansion model tends to underestimate the actual methane emissions from the 

DCU. 

In efforts to address this issue, the EPA developed a heat balance approach to estimating the 

emissions from DCU by estimating steam generation quantities. This approach was first 

publically disseminated by South Coast Air Quality Management District (SC AQMD, 2013). 

The EPA used this approach to estimate impacts of proposed new requirements for DCU 

decoking operations (Coburn, 2014). This methodology was also incorporated into the Emission 

Estimation Protocol for Petroleum Refineries (RTI, 2015, hereafter referred to as the “Refinery 

Protocol”) as part of EPA’s efforts to update emissions factors for petroleum refineries. This 

memorandum presents this new calculation methodology for potential inclusion into 40 CFR part 

98 subpart Y of the GHGRP. 

2. Process and Emission Source Description 

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, 
Technical Memorandum – Revised Emission Methodology for Delayed Coking Units 

June 4, 2015 

2 

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, 

recovered and treated in the facility’s gas treatment plant, or combusted in a flare or stationary 

combustion device. GHG emissions arising from the combustion of this fuel gas is considered in 

methodologies for flares (in subpart Y) or for stationary combustion devices (in 40 CFR part 98 

subpart C). 

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 (i.e., removing 

a gasketed lid to provide access for the drilling apparatus that is used to cut coke out of the 

drum), and coke cutting. Atmospheric emissions of methane and other organics occur during the 

venting, draining, deheading, and coke cutting steps, which will be referred to collectively as the 

decoking operations. The DCU methodology was developed to estimate the methane emissions 

that occur during these decoking operations. 

3. Emission Estimation Approaches 

Initial DCU Emissions Model 

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 to estimate methane emissions 

from DCU in the GHGRP (40 CFR part 98, subpart Y, equation Y-18, as provided below). This 

equation is still in use by the GHGRP. 

( )

















× × ×

×

× ×

+

= × × .0 001 16

14 7. 4

14 7.

4

2

4 void CH

CV MF

MVC

D

f

P

CH N H

π

(Eq. Y-18)

Where: 

CH4 = Annual methane emissions from the delayed coking unit vessel opening (metric 

ton/year). 
Technical Memorandum – Revised Emission Methodology for Delayed Coking Units 

June 4, 2015 

3 

N = Cumulative number of vessel openings for all delayed coking unit vessels of the 

same dimensions during the year. 

H = Height of coking unit vessel (feet). 

PCV = Gauge pressure of the coking vessel when opened to the atmosphere prior to coke 

cutting or, if the alternative method provided in (i)(2) of this section is used, 

gauge pressure of the coking vessel when depressurization gases are first routed to 

the atmosphere (pounds per square inch gauge, psig)

14.7 = Assumed atmospheric pressure (pounds per square inch, psi) 

fvoid = Volumetric void fraction of coking vessel prior to steaming (cf gas/cf of vessel); 

default = 0.6. 

D = Diameter of coking unit vessel (feet). 

16 = Molecular weight of CH4 (kg/kg-mole). 

MVC = Molar volume conversion factor (849.5 scf/ kg-mole). 

MFCH4 = Mole fraction of methane in coking vessel gas (kg-mole CH4/kg-mole gas, wet 

basis); default value is 0.01. 

0.001 = Conversion factor (metric ton/kg). 

This method has several shortcomings that have been identified as knowledge about emissions 

from this source improved. Equation Y-18 was originally developed considering only coke and 

void space and did not consider the volume of the DCU coke drum vessel filled with water. If 

one considers the water in the vessel when calculating the volumetric void fraction, fvoid, the 

gaseous void fraction will generally be much less than the 0.6 default value. The mole fraction of 

methane in the coking vessel gas, MFCH4, is currently estimated on a wet basis to account for the 

fact that much of the vapor released from the coke drum is primarily steam; however, it does not 

account for phase changes that occur during vessel depressurization, i.e., the generation of more 

steam during the depressuring process. The model also intentionally omitted the temperature 

term that would typically be included in an ideal gas law gaseous expansion model. This was 

because DCU with higher venting temperatures had higher emissions, but the direct ideal gas law 

gaseous expansion model would estimate lower mass emissions at higher gas temperatures. 

New DCU Emissions Model 

At pressures above atmospheric pressure, the boiling point of water increases. Prior to venting, 

the pressure in the coke drum vessel will be greater than 1 atmosphere (atm) (14.7 pounds per 

square inch absolute (psia)), so the temperature of the water can be greater than 212 °F. As the 

coke drum depressurizes, steam will be generated from the superheated water until the 

temperature of the water and coke in the coke drum falls to 212 °F. A heat balance can be used 

to estimate the quantity of steam generated based on the temperature and mass of coke and water 

in the coke drum vessel when venting first occurs and the pollutant emissions have been found to 

be strongly correlated to the quantity of steam generated. The new approach is described in 

detail in the Refinery Protocol (RTI, 2015) and it provides emissions factors for a variety of 

pollutants including methane. 
Technical Memorandum – Revised Emission Methodology for Delayed Coking Units 

June 4, 2015 

4 

The primary equation for estimating the mass of steam produced per cycle is: 

( ) ( ) ( )

vap

ConvLoss water p,water coke p,coke initial final

steam H

1 f M C M C T T

M

∆

− × × + × × −

= (Eqn. 1) 

where: 

 Msteam = Mass of steam generated and released per decoking cycle (metric tons/cycle). 

 fConvLoss = Fraction of the total heat loss that is due to convective heat loss from the sides 

of the coke vessel, unitless. Default value is 0.10 (based on engineering 

judgement). 

 Mwater = Mass of water in the delayed coking unit vessel at the end of the cooling cycle 

just prior to atmospheric venting, (mt/cycle). 

 Cp,water = Heat capacity of water, (British thermal units per metric ton per degree 

Fahrenheit; Btu/mt-°F). Default for water at 220 °F is 2,205 Btu/mt-°F (Perry 

and Green, 1999). 

 Mcoke = Typical dry mass of petroleum coke in the delayed coking unit vessel at the 

end of the coking cycle (mt/cycle). 

 Cp,coke = Heat capacity of petroleum coke, (Btu/mt-°F). Default is 584 Btu/mt-°F (Perry 

and Green, 1999). 

 Tinitial = Average temperature of the delayed coking unit vessel when the drum is first 

vented to the atmosphere (°F). 

 Tfinal = Temperature of the delayed coking unit vessel when steam generation stops. 

Default is 212 °F. 

∆Hvap = Heat of vaporization of water (British thermal units per metric ton; Btu/mt). 

Default value at 228 °F is 2,116,000 Btu/mt (ASME, 2006). 

Many of the input variables are the same as those used in the previous model or can be estimated 

based on the parameters required to be used or reported for the previous (“initial”) DCU 

emissions model. For example, the mass of coke in the coke drum per cycle can be estimated 

based on company records of coke production or estimated based on the drum dimensions and 

drum outage as follows: 

( ) 













 ×

= × − ×

4

π D M ρ H H

2

coke bulk drum outage (Eqn. 2) 
Technical Memorandum – Revised Emission Methodology for Delayed Coking Units 

June 4, 2015 

5 

Where: 

ρbulk = Bulk coke bed density, metric tons per cubic feet (mt/ft3). Default value 

0.0191 mt/ft3

 based on particle density of petroleum coke from Perry and Green 

(1999) and assumed coke bed porosity of 0.5. 

 Hdrum = Internal height of coking unit vessel (ft). 

 Houtage = Typical distance from the top of the coking unit vessel to the top of the coke bed 

(i.e., coke drum outage) at the end of the coking cycle (ft). 

 D = Diameter of delayed coking unit vessel (ft).

Since the height and diameter of the coke drum and the coke drum outage are all current 

reporting elements, no new recordkeeping elements are needed for determining the mass of coke 

per cycle. Commenter’s on the Refinery Protocol DCU methodology suggested that the porosity 

of the coke bed was too high, but as described in the response to comment document (EPA, 

2015), this value provided a much better correlation with coke production rates than lower coke 

bed densities. 

Similarly, the mass of water in the coke drum can be estimated from the coke drum dimensions, 

the mass of coke and the height of water in the coke drum as follows:

( ) 















−

×

= × ×

particle

coke

2

water water water

ρ

M

4

π D M ρ H (Eqn. 3) 

Where: 

ρwater = Density of water at the coke drum temperature (mt/ft3). The default value for the 

density of water at 220 oF is 0.0270 mt/ft3

 (ASME, 2006). 

 Hwater = Typical distance from the bottom of the coking unit vessel to the top of the 

water level at the end of the cooling cycle just prior to atmospheric venting (ft). 

ρparticle = Particle density of petroleum coke (mt/ft3). Default value is 0.0382 mt/ft3 (Perry 

and Green, 1999). 

The height of water in the coke drum is not a current reporting requirement, but this is a 

parameter that is routinely determined by DCU owners or operators to ensure proper cooling of 

the coke drum contents and to avoid over-filling the coke drum. 

The primary difference in the current model inputs and this revised steam generation model is 

that the steam generation model relies on the initial average temperature of the coke drum vessel 

contents rather than the pressure of the coke drum vessel. The Refinery Protocol assumes that the 

average temperature of the coke drum when the drum is first vented to the atmosphere, Tinitial, is 

the average of the coke drum overhead temperature and 212 °F. While this approach can be used 

in the methodology, part 98 currently includes recordkeeping requirements for the pressure of the 

coke drum when first vented to the atmosphere. Therefore, we sought to develop a method to 
Technical Memorandum – Revised Emission Methodology for Delayed Coking Units 

June 4, 2015 

6 

estimate the average temperature of the coke drum when the drum is first vented to the 

atmosphere using this pressure of the coke drum when first vented to the atmosphere. 

For a closed system at equilibrium, steam property tables can be used to develop a correlation 

between the system pressure and the saturated steam pressure. Based on saturated steam 

properties (ASME, 2006), the following correlation was developed (and is appropriate for closed 

systems at equilibrium): 

T 0.039 P 3.13 P 212 overhead

2

initial = − overhead + + (Eqn. 4) 

Where: 

 Poverhead = The overhead coke drum pressure when the drum is first vented to the 

atmosphere, pounds per square inch gauge (psig). 

However, the system is not closed, nor is it at equilibrium. Therefore, Equation 4 is expected to 

underestimate the average temperature of the coke drum. In efforts to develop a correlation 

between the overhead pressure and the average temperature of the coke bed, detailed data on 

DCU collected by the EPA in their 2011 Petroleum Refinery Information Collection Request 

(Refinery ICR) (EPA, 2011) was used to assess and compare the two approaches (i.e., using 

overhead temperature to estimate average bed temperature or using the reported venting 

pressure). DCU that reported overhead temperatures greater than 350 °F were not used in this 

comparison because these data were expected to be either misreported or potentially impacted by 

steam purges used in the overhead line to prevent coke build up on process instrumentation. The 

final term in Equation 4 was then adjusted until the temperature based approach recommended in 

the Refinery Protocol provides the same nationwide DCU emissions as the pressure correlation 

to estimate the average coke bed temperature. Based on these results, the following correlation 

is recommended for estimating the average coke drum temperature based on the overhead 

pressure while actively venting the drum to the unit’s blow down system. 

T 0.039 P 3.13 P 220 overhead

2

initial = − overhead + + (Eqn. 5) 

Once the mass of steam generated per cycle is determined, the mass methane emissions can be 

calculated as follows. 

CH M EmF N 0.001 4 = steam × DCU × × (Eqn. 6) 

where: 

 CH4 = Annual emissions from the delayed coking unit (mt/year) 

 Msteam = Mass of steam generated and released per decoking cycle (mt/cycle). 

 EmFDCU = Methane emission factor for delayed coking units, (kilograms CH4/mt steam). 

The default value is 7.9 kg CH4/mt steam (RTI, 2015). 
Technical Memorandum – Revised Emission Methodology for Delayed Coking Units 

June 4, 2015 

7 

 N = Number of decoking cycles (or coke-cutting cycles) for all delayed coking 

unit vessels associated with the delayed coking unit during the year. 

 0.001 = Conversion factor (mt/kg). 

4. Comparison of Emission Estimation Approaches 

Most of the source test reports did not provide adequate process and coke drum vessel 

information by which to apply the emission models directly for the conditions that existed at the 

time the unit was tested. As part of the Refinery ICR (EPA, 2011), refineries had to report coke 

drum dimensions, coke drum outage, and coke drum vessel temperature and pressure when first 

venting to the atmosphere. From these data, estimates of the methane emissions could be made 

for their typical operating conditions using the emission models, and these emission estimates 

were then compared to the emissions measured during the source test. Table 1 contains a 

summary of the model emission estimates and the emissions measured from the DCU steam 

vent. As noted previously, the emissions released via the steam vent are only expected to be a 

portion of the total emissions from all steps associated with the decoking operations. Although 

the depressuring model was intended to account for both the emissions from the vent and 

subsequent coke cutting operations, the emissions estimated by this model were consistently less 

than the emissions measured from the DCU vent alone. This low bias is particularly noticeable 

when looking at the aggregate emissions across all DCU. Based on the aggregate emissions 

across the source test data, it appears that the depressuring model underestimates DCU emissions 

by a factor of 10. 

The steam generation model using the average coke drum vessel temperature calculated based on 

the ICR reported overhead temperature (Alternative 1) exhibited the most variability based on 

the range of overhead temperatures reported. Except for the test data for DCU 4, 5, and 10, it 

appears Alternative 1 appears to do a better job predicting methane emissions than Alternative 2 

(i.e., using the reported vessel pressure to estimate the average vessel temperature). The test for 

DCU 4 indicated that the venting time was much less than usual, suggesting that they may have 

cooled the coke drum more than usual (or they initiated draining immediately). In any event, the 

“usual” emissions from this unit are expected to be greater than those measured during this test, 

so the overestimates from both Alternatives 1 and 2 for this DCU are understandable and 

expected. For DCU 5, Alternatives 1 and 2 provide significantly different results. The overhead 

temperature reported for DCU 5 is very high and not at all in-line with the low reported pressure 

at which venting is initiated. Based on the average stack temperature measured during the stack 

test, it is expected that the initial overhead temperature during the source test was much less than 

the value reported in the Refinery ICR. Using the maximum measured stack temperature as the 

initial overhead temperature, the emissions estimated by Alternatives 1 and 2 would have been 

nearly identical. Thus, the very high emission estimate for Alternative 1 for DCU 5 appears to 

be an issue with the data reported in the Refinery ICR rather than an issue with the emission 

estimation approach itself. DCU 10 initiated draining immediately upon initiating venting. This 

practice is expected to divert a significant portion of the DCU emissions from the vent to other 

phases of the decoking operations; therefore, overestimates from both Alternatives 1 and 2 for 

this DCU are understandable and expected. 
Technical Memorandum – Revised Emission Methodology for Delayed Coking Units 

June 4, 2015 

8 

Table 1. Comparison of Methane Emission from Model Predictions and DCU Vent Tests 

Source 

Test 

Report 

Depressuring 

Model 

[Eqn Y18] 

(lb/cycle)a

Steam 

Generation 

Model Using 

Overhead 

TemperatureAlternative 1 

(lb/cycle)a

Steam 

Generation 

Model Using 

Vessel 

PressureAlternative 2 

(lb/cycle)a

Measured 

Emissions 

(lb/cycle)a Test/Draining Notes 

DCU 1 20.3 836 327 800 Multiple events tested; no 

draining until steam 

generation stopped; 

DCU 2 14.9 96 206 33.9 One run test; no drain info 

DCU 3 14.4 60 211 67 One run test; no drain info 

DCU 4 10.5 413 275 12.7 One run test; tester noted 

unusually short venting time; 

no drain info 

DCU 5 14.3 1,700 228 73.3 No detail; portions of source 

test were redacted (claimed 

confidential) 

DCU 6 19.2 296 296 248 Numerous events tested; 

drain 30 minutes after venting 

DCU 7 22.0 282 297 364 Numerous events tested; no 

drain info 

DCU 8 12.4 39 146 7.1 Numerous events tested; no 

drain info 

DCU 9 13.0 289 167 321 Multiple events tested; drain 1 

to 2 hours after venting 

DCU 10 32.8 1,550 690 75.3 Multiple events tested; drain 

immediately 

Total All 173.8 5,561 2,843 2,002

DCU 1,6,9 52.5 1,421 790 1,369

a

 lb/cycle = pounds per cycle 

Alternative 2 (using pressure to estimate average temperature) appears to provide the best 

prediction of DCU emissions when looking at the aggregate emissions from all DCU tested. It is 

important to remember that methane emissions from the DCU decoking operations are 

potentially released from various locations and/or times throughout the decoking process and not 

all of the emissions are released from the direct vent. Therefore, the measured emissions from 

the steam vent alone are expected to be only a fraction (albeit a significant fraction in many 

cases) of the total methane emissions from these DCU. It is interesting to compare the model 

results for those source tests that indicated that draining of the vessel was not performed until a 

set time or vessel pressure so that the majority of the decoking operations were released via the 

steam vent being measured. For these DCU, which are DCU 1, 6 and 9 in Table 1, Alternative 1 

does an excellent job of predicting DCU emissions. Alternative 2 does a reasonable job but 

appears to underestimate the methane emissions from these DCU. The depressuring model 

(Equation Y-18 in subpart Y), on the other hand, underestimates emissions for these DCU by 
Technical Memorandum – Revised Emission Methodology for Delayed Coking Units 

June 4, 2015 

9 

about a factor of 25. Since the depressuring model does not account for the physical realities of 

the DCU venting process and because it significantly underestimates the emissions from the 

DCU, the new heat balance/steam generation model should be adopted for estimating methane 

emissions from the DCU. 

5. 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. 

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. 

EPA (U.S. Environmental Protection Agency). 2015. Background Information for Final 

Emissions Factors Development for Flares and Certain Refinery Operations and Final 

Determination for No Changes to VOC Emissions Factors for Tanks and Wastewater 

Treatment Systems. Summary of Public Comments and Responses. Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. April 2015. Available at 

http://www.epa.gov/ttn/chief/consentdecree/index_consent_decree.html. 

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). 2015. Emission Estimation Protocol for Petroleum Refineries. 

Version 3. Prepared for U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. April 2015. Available at 

http://www.epa.gov/ttn/chief/efpac/protocol/.