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 acc ording to the requirements of 40 CFR part 98, subpart Y. Subpart Y includes calculation methodolo gies for a variety of emission sources, including DCU. At the time the mandatory repor ting requirements were being developed, emissions from delayed coking units were not well understood. The methodology originally established to estimate methane emissions fr om 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 “depressuriza tion” vent. These tests suggest that the simple gas expansion model tends to underestimate th e 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 quanti ties. This approach was first publically disseminated by South Coast Air Quality Manageme nt District (SC AQMD, 2013). The EPA used this approach to estimate impacts of proposed n ew 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 Protoco l”) as part of EPA’s efforts to update emissions factors for petroleum refineries. This memorandum presents this new calculation methodology fo r 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 tha t are continuous, DCU are operated in a semi-batch system. Most DCU consist of a large pro cess heater, two or more coking drums,Technical Memorandum – Revised Emission Methodology for D elayed 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 h eated to near cracking temperatures and the heavy oil is fed to one of the coking drums. As the cra cking reactions occur, coke is produced in the drum and begins to fill the drum with sponge-like solid c oke 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 pur ge organics in the coke matrix. After the coke drum is sufficiently cooled, and filled with wat er 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, t he drum is closed, and prepared to go back on-line. A typical coke drum cycle is typically 28 t o 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 pla nt, or combusted in a flare or stationary combustion device. GHG emissions arising from the combus tion of this fuel gas is considered in methodologies for flares (in subpart Y) or for statio nary combustion devices (in 40 CFR part 98 subpart C).
Near the end of the cooling process, a vent is opened on t he 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 tha t 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 e stimate 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 fi rst 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.



## ( )        
× × × × × × + × × = 001 .0 16
4 7. 14 7. 14

4 2

4 CH void CV MF MVC D f P H N CH π (Eq. Y-18)

Where:
CH 4 = Annual methane emissions from the delayed coking un it 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 de layed coking unit vessels of the

same dimensions during the year. H = Height of coking unit vessel (feet).
P CV = 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 depressuri zation gases are first routed to the atmosphere (pounds per square inch gauge, psig) 14.7 = Assumed atmospheric pressure (pounds per squ are inch, psi)
f void = 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 CH 4 (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf/ kg -mole).
MF CH4 = Mole fraction of methane in coking vessel gas (k g-mole CH 4 /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 origin ally developed considering only coke and void space and did not consider the volume of the D CU coke drum vessel filled with water. If one considers the water in the vessel when calculat ing the volumetric void fraction, f void , the gaseous void fraction will generally be much less t han the 0.6 default value. The mole fraction of methane in the coking vessel gas, MF CH4 , 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 a lso intentionally omitted the temperature term that would typically be included in an ideal g as law gaseous expansion model. This was because DCU with higher venting temperatures had hi gher emissions, but the direct ideal gas law gaseous expansion model would estimate lower mass e missions at higher gas temperatures.

New DCU Emissions Model
At pressures above atmospheric pressure, the boilin g point of water increases. Prior to venting, the pressure in the coke drum vessel will be greate r 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 fr om 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 o n the temperature and mass of coke and water in the coke drum vessel when venting first occurs a nd the pollutant emissions have been found to be strongly correlated to the quantity of steam gen erated. 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 ste am produced per cycle is:



## ( ) 

# ( ) ( )

vap final initial coke p, coke water p, water ConvLoss
steam H T T C M C M f 1 M ∆ − × × + × ×

−

= (Eqn. 1)

where:

M steam

= Mass of steam generated and released per decokin g cycle (metric tons/cycle).

f

ConvLoss = Fraction of the total heat loss that is due to c onvective heat loss from the sides

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

M water

= Mass of water in the delayed coking unit vessel at the end of the cooling cycle just prior to atmospheric venting, (mt/cycle).

C p,water

= Heat capacity of water, (British thermal units p er metric ton per degree Fahrenheit; Btu/mt-°F). Default for water at 220 °F is 2,205 Btu/mt-°F (Perry and Green, 1999).

M coke = Typical dry mass of petroleum coke in the delaye d coking unit vessel at the

end of the coking cycle (mt/cycle).

C p,coke = Heat capacity of petroleum coke, (Btu/mt-°F). De fault is 584 Btu/mt-°F (Perry

and Green, 1999).

T initial = Average temperature of the delayed coking unit v essel when the drum is first

vented to the atmosphere (°F).

T final = Temperature of the delayed coking unit vessel wh en steam generation stops.

Default is 212 °F.

∆ H vap = Heat of vaporization of water (British thermal u nits 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 u sed in the previous model or can be estimated based on the parameters required to be used or repo rted for the previous (“initial”) DCU emissions model. For example, the mass of coke in t he coke drum per cycle can be estimated based on company records of coke production or esti mated based on the drum dimensions and drum outage as follows: 

# ( )         ×

×

− × = 4 D π H H ρ M 2

outage drum bulk coke (Eqn. 2)Technical Memorandum – Revised Emission Methodology for Delayed Coking Units June 4, 2015

5 Where:

ρ bulk = Bulk coke bed density, metric tons per cubic fe et (mt/ft 3 ). Default value

0.0191 mt/ft 3 based on particle density of petroleum coke from P erry and Green (1999) and assumed coke bed porosity of 0.5.

H drum = Internal height of coking unit vessel (ft).

H outage = 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 c ycle (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 a re 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 t he response to comment document (EPA, 2015), this value provided a much better correlatio n with coke production rates than lower coke bed densities.
Similarly, the mass of water in the coke drum can b e estimated from the coke drum dimensions, the mass of coke and the height of water in the cok e drum as follows:


## ( )        

−

× × × = particle coke 2

water water water ρ M
4 D π H ρ M (Eqn. 3)

Where:

ρ water = Density of water at the coke drum temperature ( mt/ft 3 ). The default value for the

density of water at 220 oF is 0.0270 mt/ft 3 (ASME, 2006).

H water = 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 p rior to atmospheric venting (ft).

ρ particle = Particle density of petroleum coke (mt/ft 3 ). Default value is 0.0382 mt/ft 3 (Perry

and Green, 1999).
The height of water in the coke drum is not a curre nt reporting requirement, but this is a parameter that is routinely determined by DCU owner s or operators to ensure proper cooling of the coke drum contents and to avoid over-filling th e 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 initi al 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, T initial , is the average of the coke drum overhead temperature a nd 212 °F. While this approach can be used in the methodology, part 98 currently includes reco rdkeeping requirements for the pressure of the coke drum when first vented to the atmosphere. The refore, we sought to develop a method toTechnical Memorandum – Revised Emission Methodology for Delayed Coking Units June 4, 2015

6 estimate the average temperature of the coke drum w hen the drum is first vented to the atmosphere using this pressure of the coke drum whe n 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):

212 P 3.13 P 0.039 T overhead 2 overhead initial +

+

− = (Eqn. 4)

Where:

P overhead = 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 equ ilibrium. Therefore, Equation 4 is expected to underestimate the average temperature of the coke d rum. In efforts to develop a correlation between the overhead pressure and the average tempe rature of the coke bed, detailed data on DCU collected by the EPA in their 2011 Petroleum Re finery Information Collection Request (Refinery ICR) (EPA, 2011) was used to assess and c ompare the two approaches (i.e., using overhead temperature to estimate average bed temper ature 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 e ither misreported or potentially impacted by steam purges used in the overhead line to prevent c oke build up on process instrumentation. The final term in Equation 4 was then adjusted until th e 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. Base d 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 uni t’s blow down system.

220 P 3.13 P 0.039 T overhead 2 overhead initial +

+

− = (Eqn. 5)

Once the mass of steam generated per cycle is deter mined, the mass methane emissions can be calculated as follows.

0.001 N EmF M CH DCU

steam 4 ×

× × = (Eqn. 6)

where:

CH 4 = Annual emissions from the delayed coking unit (m t/year)

M steam

= Mass of steam generated and released per decokin g cycle (mt/cycle).

EmF DCU

= Methane emission factor for delayed coking units , (kilograms CH 4 /mt steam). The default value is 7.9 kg CH 4 /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 cyc les) for all delayed coking

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

0.001 = Conversion factor (mt/kg).

4. Comparison of Emission Estimation Approaches
Most of the source test reports did not provide ade quate process and coke drum vessel information by which to apply the emission models d irectly 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 ve ssel temperature and pressure when first venting to the atmosphere. From these data, estimat es of the methane emissions could be made for their typical operating conditions using the em ission 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 emi ssions 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 assoc iated 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 e stimated 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 de pressuring model underestimates DCU emissions by a factor of 10.
The steam generation model using the average coke d rum vessel temperature calculated based on the ICR reported overhead temperature (Alternative 1) exhibited the most variability based on the range of overhead temperatures reported. Excep t for the test data for DCU 4, 5, and 10, it appears Alternative 1 appears to do a better job pr edicting methane emissions than Alternative 2 (i.e., using the reported vessel pressure to estima te 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 initi ated 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 averag e stack temperature measured during the stack test, it is expected that the initial overhead temp erature 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 estimat ed by Alternatives 1 and 2 would have been nearly identical. Thus, the very high emission est imate 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 drain ing immediately upon initiating venting. This practice is expected to divert a significant portio n of the DCU emissions from the vent to other phases of the decoking operations; therefore, overe stimates 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 OverheadTemperatureAlternative 1 (lb/cycle) a Steam

Generation Model Using VesselPressureAlternative 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 t emperature) appears to provide the best prediction of DCU emissions when looking at the agg regate emissions from all DCU tested. It is important to remember that methane emissions from t he 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 v ent. Therefore, the measured emissions from the steam vent alone are expected to be only a frac tion (albeit a significant fraction in many cases) of the total methane emissions from these DC U. 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 ar e 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, un derestimates emissions for these DCU byTechnical 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 significantl y underestimates the emissions from the DCU, the new heat balance/steam generation model sh ould 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 C alendar 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 Certai n Refinery Operations and Final Determination for No Changes to VOC Emissions Facto rs for Tanks and Wastewater Treatment Systems. Summary of Public Comments and R esponses . Office of Air Quality Planning and Standards, Research Triangle Park, NC. April 2015. Available at http://www.epa.gov/ttn/chief/consentdecree/index_co nsent_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 Refineri es

. Version 3. Prepared for U.S. Environmental Protect ion Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC. April 2015. Available at http://www.epa.gov/ttn/chief/efpac/protocol/

.