Date: December 7, 2012 

To: Brenda Shine, EPA/OAQPS/SPPD 

From: Jeff Coburn 

Subject: Meeting Minutes for November 30, 2012, Meeting Between the U.S. EPA and 

Representatives from ExxonMobil 

On November 30, 2012, representatives of the U.S. Environmental Protection Agency 

(EPA) and their contractor (RTI International) participated in a meeting with representatives 

from ExxonMobil to discuss the delayed coking unit source test conducted at the ExxonMobil 

Baytown Refinery. 

Attendees 

ExxonMobil Representatives 

Sally Beckett 

Chuck Feerick 

George Graham 

Ty Hastriter 

Mitch Moloney 

Diane Otto 

U.S. EPA Representatives 

Brenda Shine 

Eric Goehl 

Andrew Bouchard 

Penny Lassiter 

RTI International (EPA contractor) 

Jeff Coburn 

Discussion Topics 

ExxonMobil representatives provided a presentation summarizing the voluntary 

emissions test conducted on the delayed coking unit (DCU) in their Baytown, TX, refinery. The 

presentation is included as Attachment 1 to this memorandum. ExxonMobil representatives 

also provided written responses to discussion topics supplied by the EPA to ExxonMobil prior to 

the meeting. The EPA discussion topics and ExxonMobil’s responses are provided as 
2

Attachment 2 to this memorandum. The meeting followed the presentation material, with 

informal questions and discussions occurring throughout the meeting. The key discussion topics 

are summarized below. 

ExxonMobil Baytown refinery was not required to test their DCU as part of the source 

testing program (“Component 4”) of the EPA’s information collection request (ICR). 

ExxonMobil voluntarily conducted the DCU source test, using the testing methods required for 

testing in response to the ICR, to better understand the emissions from the DCU. ExxonMobil 

invested considerable time and resources in order to conduct a comprehensive test. The testing 

was completed without any major testing issues beyond those inherent in the DCU vent (e.g., 

high moisture, transient flow, impossible to perform isokinetic sampling). 

The enclosed blowdown system at ExxonMobil’s Baytown refinery discharges to the wet 

gas compressor associated with the DCU’s distillation column, which directs the light gases to 

the refinery’s gas plant. The inlet operating pressure of this compressor is approximately 12 to 

13 pounds per square inch gauge (psig), so the DCU drums currently cannot be depressured to 

much below 15 psig prior to opening the steam vent to the atmosphere (depressuring at a lower 

pressure would require significant modification and investment to the unit). ExxonMobil 

representatives stated that it was common practice to initiate draining immediately after opening 

the atmospheric vent. Technical experts noted that they could actually initiate draining prior to 

opening the atmospheric vent since there is enough pressure in the system, added by additional 

steam generation, to allow draining to occur prior to opening the atmospheric vent without 

concerns of cavitation (i.e., creating a vacuum in the drum). Technical experts also noted that 

initiating draining immediately had two additional benefits. First, if draining is initiated early, 

while the pressure is still high, that helps to push the water out of the drum and they have a 

“better” (i.e., faster) drain. Second, as the water drains back through the coke bed, it often 

travels down new pathways (new cracks or fissures in the coke bed created as the coke bed 

cools) so that it can contact areas of the coke bed that were previously isolated and not 

sufficiently cooled. That is, the ExxonMobil representatives suggested that draining the coke 

drum early resulted in lower vent emissions because the coke drum was cooled more efficiently 

as a result of draining the coke drum immediately. 

ExxonMobil representatives noted that the drum was not completely empty, so steam 

could not be directed out of the bottom drain. The level indicator that reported the water level 

during the source test only viewed the top third of the coke vessel. When the indicator showed a 

water level of zero, it only indicated that the water level was below the top third of the vessel, 

not that the entire vessel has been drained. ExxonMobil representatives indicated that a “typical” 

drain would take approximately 2 hours, not the 10 to 15 minutes suggested by the top level 

indicator data included in the source test report. ExxonMobil representatives also noted that the 

testing contractors and the plant staff did not synchronize their watches, and discrepancies 

between the time the vent opened and the time testing began was likely due to different clock 

times. All efforts were taken to start sampling upon opening the vent and the sampling was 

conducted until there was no measureable gas flow (pressure in the vent equaling atmospheric 

pressure). 

Exxon Mobil representatives noted that the emissions from the DCU steam vent were 

higher than expected based on simple expansion of the gas within the DCU due to the pressure 
3

decrease (i.e., the PV=nRT estimate). The EPA agreed that simple gas expansion is not the 

source of the emissions. The EPA noted that they have revised their emission estimation method 

to project emissions based on the quantity of steam expected to be generated from the DCU, 

which would be a function of the DCU bed temperature. Given the high DCU overhead 

temperatures measured by ExxonMobil, the EPA expected high emissions from the DCU vent. 

ExxonMobil experts hypothesized that the light gases were generated from thermal cracking 

reactions that were still occurring in hot spots within the DCU coke bed, but agreed that such 

reactions should be very slow at temperatures below 400 degrees Fahrenheit (°F). 

With respect to the high overhead temperatures, ExxonMobil representatives did not 

consider this to be an accurate measure of the coke drum temperature and attributed the high 

temperatures to steam purges at the pressure relief. They also noted that the metal is hot and 

coated with coke (insulated), so the hot metal cooling slowly in the overhead lines may be 

responsible for the higher overhead temperature readings. ExxonMobil representatives stated 

that the coke bed temperature must be in the range of 250 to 270 °F based on the pressure of the 

system. When pressed regarding the fact that the system is not at equilibrium because vapors are 

constantly being removed, ExxonMobil representatives stated that this is why the bed 

temperature may be somewhat above 250 °F, the equilibrium temperature of the system at 

15 psig, but would not be that much higher than this equilibrium temperature. The stack test data 

for Run 2 supports this, but the data for Runs 1 and 3 suggest the temperature is much higher. 

The vent stack where sampling occurred does not have routine flow. While the temperature of 

the line immediately off of the DCU vessel may be cooling during the steaming process, much 

of the steam vent stack is expected to be cooler than steam vent gas (near ambient conditions 

having no flow for 24 to 28 hours prior to venting). The stack gas temperature measured in the 

steam vent stack ports reflect this, with the temperature rising through most of the sampling run. 

For Run 1, the average vent stack temperature was 320 °F, with a maximum temperature of 

338 °F (see p. 464 of the test report PDF available at 

http://www.epa.gov/ttn/atw/petref/icr4/ExxonMobilDCU.pdf). For Run 2, the average stack 

temperature was 234 °F with a maximum temperature of 260 °F; for Run 3, the average stack 

temperature was 274 °F with a maximum temperature of 294 °F. Thus, there appears to be 

significant variability in the steam vent temperature. Also, while the vent gas temperatures are 

significantly lower than the temperatures measured by the process equipment in the immediate 

DCU overhead line (lending credence to the idea that this monitor may not be accurate for 

determining the true overhead vapor temperature), it does appear that the overhead vapor 

temperature (and therefore the drum bed temperature near the top of the drum) is often hotter 

than 270 °F. 

ExxonMobil representatives noted that there is a significant temperature profile in the 

bed, with the bottom of the bed at a much lower temperature than the top of the bed, since steam 

and then water is introduced primarily from the bottom of the coke drum. As evidence of this, 

they noted that the average drain water temperature during the test was 143 to 165 °F. However, 

looking at the temperature profiles of the drain water, it is evident that the water temperature 

increased as draining continued. The testing during Run 1 lasted only 20 minutes, but for Runs 2 

and 3, the temperature of the drain water reached 212 °F within approximately 40 minutes. As 

an ExxonMobil representative indicated that a typical drain time is 2 hours, this would suggest 

that the boiling water is being drained from the DCU for approximately 1 hour. 
4

ExxonMobil representatives did revise their DCU emissions estimates (provided as part 

of Component 2 of the ICR) using a higher water temperature (200 °F). They noted that the 

Refinery Wastewater Emission Tool (RWET) does not appear to have a temperature 

dependency, which is essentially correct; the EPA noted that, in order to evaluate emissions at 

different temperatures in RWET, one needs to use the site-specific properties table in the 

“Chemical Properties” tab and enter the chemical properties at the system temperature. Based on 

ExxonMobil’s emission modeling using the EPA’s Water 9 emission model, increasing the water 

temperature from 70 °F to 200 °F increased the estimated volatile organic compound (VOC) 

emissions by approximately 75% (from 5.26 to 9.25 tons/year), with naphthalene and 2-

methylnaphthalene contributing significantly to the VOC emissions total (approximately 65%). 

ExxonMobil representatives did clarify that the polycyclic organic matter (POM) concentrations 

used in their emission model were not measured concentrations; ExxonMobil estimated the water 

concentrations based on equilibrium partitioning considerations of the gas phase concentrations 

measured during the source tests. ExxonMobil considered this to yield a conservatively high 

estimate of the pollutant concentrations in the drain water. Based on the ExxonMobil Water 9 

emission estimates, emissions of naphthalene and 2-methylnaphthalene from the drain and pit are 

more than a factor of 10 higher than the emissions from the vent, based on the ExxonMobil test 

data. The default emission factors for naphthalene and 2-methyl naphthalene from DCU vent in 

the Emission Estimation Protocol for Petroleum Refineries (see: 

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

nerie_052011.pdf) are approximately a factor of 10 higher than those determined from the 

ExxonMobil source test, but would appear to provide a reasonable estimate of the combined 

emissions from the ExxonMobil DCU when also considering the emissions from the drain/pit. 

ExxonMobil representatives then discussed the costs of retrofitting the DCU to meet a 

venting pressure of 2 or 5 psig. ExxonMobil operates 9 DCU; 4 of these DCU are in Louisiana 

and are designed to meet the 5 psig venting limit due to state requirements in Louisiana. The 

other 5 DCU operated by ExxonMobil would need to be retrofitted to meet the 2 or 5 psig limit, 

at an estimated cost of approximately $10-million per DCU. The 4 DCU in Louisiana would 

also need to be retrofitted if they were required to meet a 2 psig pressure limit at a cost of $5 to 

$10-million per DCU. At these costs and considering the low emissions from the DCU vent as 

measured by ExxonMobil, the ExxonMobil representatives did not consider that setting pressure 

limits for these DCU would result in cost-effective emissions reductions. 
Attachment 1 

Presentation Slides 

ExxonMobil Baytown Refinery Delayed Coking Unit (DCU) Emissions Test Program 
EJ!{onMobil 

Taking on the world's toughest energy challenges=' 

ExxonMobil Baytown Refinery 

Delayed Coker Unit (DCU) Emissions Test Program 

Discussion with EPA November 30, 2012 

Sally Beckett - BTRF 

Chuck Feerick- HQ SSHE 

George Graham- HQ SSHE 

Ty Hastriter - BTRF 

Mitch Moloney - EMRE 

Diane Otto - BTRF 

1 
Agenda EJf(onMobil 

Taking on the world's toughest energy challenges:' 

• Discuss ExxonMobil Baytown Refinery (BTRF) voluntary DCU test program 

• Respond to EPA's questions on the test program results 

• Summarize conclusions of the test program 

• Discuss anticipated control costs 

2 
El!(onMobil 

Seven Months of Test Planning (12/10-7/11) Taking on the world's toughest energy challenges:' 

• Selection of qualified testing company and test plan development 

-Coordination and availability of testing company and two laboratories 

-ICR test method review, selection of testing protocols, site survey, identification of 

needed facilities, operation and safety reviews 

-Fabrication of new vent pipe, scaffolding, and installation of piping and electrical 

• Pre-test Planning/Meetings 

- Review test plan 

• BTRF: Environmental, Technical, Process, and Safety 

• HQ Environmental and Technical 

- Identification of potential testing challenges 

• Velocity, moisture, and temperature profiles 

-17 test methods to be conducted simultaneously 

• Each venting cycle which is shorter than the method specified sample time (or 

insufficient to allow collection of the required sample volume) will constitute a single, 

acceptable test run 

• Requires a 1 0 person crew 

3 
Test Facilities 

• Delayed Coking Unit 

- 4 drums that operate via 2-drum pair 

• Each pair has a typical cycle time of- 28 hours 

- One drum fills while the other is de-inventoried 

D-603 

Coke Drum 

'"'"' 

D-604 

Coke Drum 

4 

EJf{onMobil 

Taking on the world's toughest energy challenges:" 

• Test Facilities 

-Vent is located -150' above ground 

• Scaffolding (-40' above deck and 20' X 1 0') 

• Personnel monitoring and special PPE 

-Multi-location for personnel/equipment 

• Scaffold at pipe level 

• In-structure 

• Ground 

- Two vent stacks 

• Tested one and other confirmed closed 

-Fabricated new 8" vent pipe for sampling 

• Twelve 3" sample ports located at optimum 

upstream and downstream locations 
Testing Challenges Elf{onMobil 

Taking on the world's toughest energy challenges:' 

• Safety 

- Elevated heights and on scaffolding 

- Potential for personnel exposure 

- Loud environment- difficult to communicate 

• Develop communication process between testing company, operations and 

Environmental 

• Batch Operation 

-Venting cycle 

• Highly variable (20 - 120 min/cycle) 

- Dependent on extent of coke bed cooling 

• Required on-call notification for testing company 

- High temperature and moisture with flow that peaks in the beginning rapidly reduces 

until flow reaches zero 

• Velocity, temperature and moisture profiling to prepare for testing 

• lsokinetic sampling impossible 

• Extremely low amount of dry gas 

5 
EJ!{onMobil Testing Challenges Taking on the world's toughest energy challenges:" 

• Operations and Sampling Program 

-Testing company notified by operations prior to opening coke 

drum vent 

• Testing equipment was already operational and sample 

valves were opened for wet chemistry as soon as vent 

stack flow rate was detected via pitot tube 

• Opened coke drum drain valve after venting process 

started consistent with industry norm 

• Clocks not synchronized before test runs 

• Test was conducted until there was no flow in the coke 

...... :..r·t -..-: 

:x~ -,," 

\\ 

\ 

i 

drum vent and not based on coke drum level indicator • 

which only measures the top 1/3 of the coke drum ----- ---~ • 

-Equipment QA/QC 

• All equipment passed required leak checks, no anomalies 

were noted 

• Total Cost - $500,000 and -1500 Man-hours 

6 

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10 
EPA's Key Observations/Concerns Elf(onMobil 

Taking on the world's toughest energy challenges."' 

• EPA expected vent emissions to be higher than reported based on the initial temperature 

and pressure of the coke drum. EPA has stated: 

- EPA Observation# 4 -"Drum overhead temperature is still very hot (well over 300°F) at end of 

venting cycle, therefore the coke remaining in the drum is also expected to be very hot and additional 

steam and pollutant emissions are expected to be generated during the cutting operation (more than 

would occur if the coke was cooled to near 212°F)." 

- EPA Observation# 2 - "Draining of the coke drum began within 1 to 2 minutes of the start of the 

testing. The drum was essentially emptied within 10-15 minutes of the start of each test (based on 

water height readings). This greatly reduces the volume of gas exiting the vent stack." 

- EPA Observation# 3 -"The water draining from the DCU appears to be superheated (based on 

overhead steam temperature). A significant amount of steam and associated contaminants in the 

water are expected to flash off as this water discharges to the pits." 

-EPA Observation# 8- "Based on how the unit is operated, only a small fraction of the emissions 

from the unit are released via the vent stack." 

• EPA concern that the emissions from the coke pit were not modeled at the proper 

conditions. EPA stated: 

-EPA Observation# 9- "If the assumption that emissions are from the quench pit, we note that the pit 

is not quiescent, and the water is probably not uniformly 115 °F, which is what you have appeared to 

have modeled. Further, how do your calculations account for emissions of 250 °F water cascading 

out of a weir into the pit?" 

7 
Response to EPA's Key Observations/Concerns EJf(onMobil 

Taking on the world's toughest energy challenges:" 

• Emissions from the coker vent are strongly a function of how much residual heat remains 

in the coke drum at the time of venting, which is set by how well the coke bed has been 

cooled during the quench cycle 

-There is residual heat which results in steam being released from the coke drum during 

venting. This steam will remove hydrocarbon from residual liquids trapped in the coke 

bed by simple mass transfer (stripping) 

-Coke bed cooling is a key aspect to reducing emissions. There are fundamental, 

intrinsic factors in how a coke bed forms that we cannot control and affect coke bed 

cooling 

-Maximizing coke drum fill with water prior to venting helps ensure a cool coke bed 

• Coke bed cooling is also enhanced by the common practice of pulling water back through 

the coke bed (draining) 

-Water finds new paths as the coke bed cracks and moves due to thermal stresses 

-Coke drum pressure drops more quickly due to the vacuum effect of the drain water 

• Consequently, by draining during venting, less hydrocarbon is stripped by the evolving 

steam (cooler bed, shorter vent time) 

8 
Elf(onMobil 

Response to EPA's Key Observations/Concerns Taking on the world's toughest energy challengeS: 

• EPA's observations that the overhead temperature is still very hot (well over 300°F} and the DCU drain 

water is hot (based on overhead steam temperature) are not correct 

- The coke drum outlet temperature is not representative of the coke bed temperature. It is more 

representative of the steam purges (PRV blowbacks) that enter the piping 

-The actual temperature at the top of the coke bed is expected to be approximately 250 to 270 °F 

- The top of the coke bed is hotter than the bottom of the coke bed (temperature gradient) 

- The drain water temperature is largely based on the cooling water inlet temperature and the extent of 

coke bed cooling prior to draining 

-Average measured drain water temperature during the test was 143- 165 °F 

• EPA's concern that emissions from the coke pit were not modeled at the proper conditions: 

- VOC emissions from the water were reported using both RWET and Water 9 models 

• VOC emissions via RWET = 0.681b/hr (2.98 tpy) 

• OriginaiiCR VOC emissions via Water 9 model = 1.20 lb/hr (5.26 tpy) based on modeled drain 

water temperature of 70 °F 

• Revised water VOC emissions via Water 9 model using 200 °F (conservative) for the water drain 

and pit temperature= 2.11 lb/hr (9.25 tpy) 

• Open roof tank modeled as quiescent unit; coke drum drain/pit as an open drain 

• Water VOC concentrations derived from vent test, based on equilibrium and solubility in water 

9 
Elf(onMobil 

Conclusions from the Test Program Taking on the world's toughest energy challenges!' 

• Exxon Mobil coker emissions test was properly conducted and yielded high 

quality data 

• Lower vent emissions reflect the extent of coke bed cooling and resultant 

short vent time 

-Vent opening pressure is a secondary determinant of vent emissions 

-Use of coke drum overhead temperature as a gauge of coke drum cooling 

is inaccurate 

• Draining during venting results in less hydrocarbon being stripped by evolving 

steam 

• Only a small fraction of VOCs were from the drain water 

-Average drain water temperature during the test was 143 - 165 °F which 

reflects the temperature of the bottom of the coke bed 

-ICR emission estimate will be revised to reflect higher drain water 

temperature 

10 
EJJ(onMobil 

Control Cost Analysis Taking on the world's toughest energy challengeS: 

• EPA has assumed a control cost of $1.5M per coker (new ejector) to 

meet either the 5 psig or the 2 psig limit 

• EPA has underestimated this cost by upwards of an order of magnitude 

• To meet 5 psig, investments needed at 5 of 9 EM cokers totaling $35-

?0M (screening level estimates). Facilities include: 

-Installing new steam ejectors, rerouting blowdown gases 

-Modifying gas compression facilities/fin fan condensers 

-Installing new liquid pumps and piping for accumulator drums 

-Safety facility system/flare gas recovery system enlargements 

• To meet 2 psig, investments needed at remaining 4 EM cokers totaling 

$22-45M 

-New liquid-ring compressors. 

11 
El!{onMobil 

Taking on Ute world's toughest;energy challen;ges! 

Back-up Information 

12 
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EJf(onMobil 

Taking on the world's toughest energy challenges:" 

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DCU Test Run #1 EJf(onMobil 

Taking on the world's toughest energy challenges:' 

DCU - Test Run #1 

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Taking on the world's toughest energy challenges:' 

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DCU Test Run #3 Elf{onMobil 

Taking on the world's toughest energy challenges:" 

DCU Test Run #3 

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16 
Attachment 2 

ExxonMobil Baytown DCU Test Report – EPA Discussion Topics and ExxonMobil 

Responses for the DCU Source Test Discussion 

November 30, 2012 

 
Exxon Mobil Baytown DCU Test Report- Exxon Mobil discussion with EPA November 30, 2012 

EPA Observations (bold)/ExxonMobil responses (italics): 

1. Testing was initiated at 1 to 2 minutes after venting was initiated (as indicated by the temperature/pressure 

readings when venting started and the sharp decrease in pressure). Vent flow rates are very high, particularly 

for the first few minutes, suggesting a considerable volume of gas was not accounted for during the test 

period. Although this is not expected to drastically alter the total emissions calculated for the vent, this initial 

should be accounted for in the mass emitted per cycle calculations. Note also, the flow rates during initial 

flow periods appear to be well above the calibrated flow range for the flow monitor. 

• Testing equipment was operational and sample valves were opened for wet chemistry as soon as vent 

stack flow rate was detected via pi tot tube. 

• All velocity equipment passed required QA/QC checks, no anomalies were noted. 

o Preliminary measurements of the vent source indicated that the gas velocity and initial pressure 

surge were well above typical conditions experienced using standard EPA Method 2 equipment 

(5-type pitot tube and 0-10' H20 manometer). The solution to measuring accurate pressure 

differentials above 10" H20 and dealing with the initial pressure surge was to employ two high 

range Dwyer Capsuhelics (0-10" H20 and 0-150 "H20} with the 5-type pitot tube. 

o The pitot tube was properly inspected (inspection sheet is presented in the report appendix) to 

assign a 0.84 coefficient while the Capsuhelics manufacturer's accuracy specifications are stated 

to be +/- 3% of full scale. It was not possible to simulate a 140" H20 pressure differential 

(highest measured pressure differential during the testing occurring during Run 1} in a wind 

tunnel calibration. N/5T traceable calibration certificates are available from the manufacturer. 

• Exxon Mobil and testing company clocks were not synchronized before test runs. 

2. Draining of the coke drum began within 1 to 2 minutes of the start of the testing. The drum was essentially 

emptied within 10- 15 minutes of the start of each test (based on water height readings). This greatly 

reduces the volume of gas exiting the vent stack. 

• The coke drum drain valve was opened after the venting process was started consistent with most cokers 

within industry. 

• The test was conducted until there was no flow in the coke drum vent and not based on the coke drum 

level indicator which only measures the top 1/3 of the coke drum. 

• Draining during venting results in less hydrocarbon being stripped by evolving steam 

o Coke bed cooling is enhanced by pulling water back through the coke drum; water finds new 

paths as the coke bed cracks and moves due to thermal stresses 

o Coke drum pressure drops more quickly due to the vacuum effect of the drain water 

3. The water draining from the DCU appears to be superheated (based on overhead steam temperature). A 

significant amount of steam and associated contaminants in the water are expected to flash off as this water 

discharges to the pits. 

1 
• The top of the coke bed is hotter than the bottom of the coke drum. The drain water temperature is 

largely based on the cooling water inlet temperature and the extent of coke bed cooling prior to 

draining. 

• Average drain water temperature during the test was 143 -165 F. 

4. The DCU drum overhead temperature is still very hot (well over 300°F) at the end of the venting cycle. 

Therefore, the coke remaining in the drum is also expected to be very hot and additional steam and pollutant 

emissions are expected to be generated during the cutting operation (more than would occur if the coke was 

cooled to near 212°F). 

• This temperature is not representative of the coke bed temperature. It is more representative of the 

steam purges (PRV blowbacks) that enter the piping. 

• The top of the coke bed is hotter than the bottom of the coke bed (temperature gradient). A liquid level 

is maintained in the drum when the drum is opened therefore, the bed temperature is cooler than 300 F. 

The average drain water temperature during the test was 143-165 F. 

5. The methane concentrations of 24 to 48 percent and the ethane concentrations of 4 to 8 percent compare 

well with dry gas concentrations measured for other cokers during other tests; we expect the TOC dilution 

probe measurement to be underestimated rather than the methane/ethane concentrations being too high in 

the bags. 

• ExxonMobil believes that the hydrocarbon measurements ore representative and consistent with other 

industry cokers within the accuracy of the test program. 

• All equipment passed required QA/QC checks, no anomalies were noted. 

6. It is unclear what is meant by the methane/ethane concentrations higher than expected based on PV=nRT 

calculations. The concentrations of all the pollutants are less than 1,000,000 ppmv on a dry basis. There 

appears to be no basis for suggesting the methane/ethane concentrations defy the laws of physics. 

• Although the coke bed is generally cool, the coke bed has residual hot spots that continue to generate 

hydrocarbons which explains why there is more hydrocarbon than expected based on the PV=nRT 

calculations. 

7. The dry gas concentrations of volatiles and semi-volatiles all appear to be within the ranges of measurements 

made at other cokers. 

• Exxon Mobil agrees that the dry gas concentrations of volatiles and semi-volatiles appear to be within the 

ranges of measurements made at other cokers. 

8. The only remarkable thing about the Baytown test is the initial temperature and pressure of the drum when 

first venting and the speed at which draining of the drum is commenced once the testing run was started. 

Emissions from the Baytown DCU are expected to be large, but based on how the unit is operated only a small 

fraction of the emissions from the unit are released via the vent stack. 

• The vent time is a function of two things (1} how long it takes to depressurize the void spaces in the coke 

drum and (2} how much residual heat is in the coke drum at the time of venting, which is set by how well 

the coke bed has been cooled during the quench cycle. 

2 
• There is residual heat which results in steam being released from the coke drum during venting. This 

steam will remove hydrocarbon from residua/liquids trapped in the coke bed by simple mass transfer 

(stripping) 

o Coke bed cooling is a key aspect to reducing emissions. There are fundamental, intrinsic factors 

in how a coke bed forms that affect coke bed cooling that we cannot control 

o M aximizing coke drum fill with water prior to venting helps ensure a cool coke bed 

• By draining during venting, less hydrocarbon is stripped by evolving steam 

o Coke bed cooling is enhanced by pulling water back through the coke drum; water finds new 

paths as the coke bed cracks and moves due to thermal stresses 

o Coke drum pressure drops quicker due to the vacuum effect of the drain water 

9. If the assumption is that emissions are from the quench pit, we note that the pit is not quiescent, and the 

water is probably is not uniformly 115 F, which is what you have appeared to have modeled. Further, how do 

your calculations account for emissions from 250 F +water cascading out of a weir into the pit? How are 

emissions of volatile compounds such as NMNE VOC and benzene calculated? We also note that your own 

calculations and sampling results indicate significant amount of semivolatile emissions of PAH (primarily 2-

methylnaphthalene), 1 to 2 TPY, orders of magnitude more than you reported for the entire site. 

• VOC emissions from the water were reported using both RWET and Water 9 models 

o VOC emissions via RWET = 0.68/b/hr {2.98 tpy) 

o Original VOC emissions vio Water 9 model= 1.20 lb/hr (5.26 tpy) based on modeled drain water 

temperature of 70 F 

o Revised water VOC emissions using 200 F for the water drain and pit temperature = 2.11/b/hr 

{9.25 tpy). Average drain water temperature during the test was 143-165 F. 

o Open roof tank modeled as quiescent unit; coke drum drain/pit as an open drain. 

o Water VOC concentrations derived f rom vent test, based on equilibrium and solubility in water. 

10. The test report indicates that oxygen concentrations were very high at the beginning of the run and about 

2% at the end of the run. Does Exxon Mobil have any explanation for this? The opposite phenomena 

would be expected. As much of the test was performed while the drum was completely drained, one 

might expect that the hot steam would rise through the vent and draw in air from the drain. This would 

not only increase the 02 concentration in the dry gas, but it would also reduce the moisture content in the 

vent gas. As neither of these appears to have occurred, it appears the steam generation rate within the 

drum must be sufficient to discharge steam from both the vent and the drain area. Can steam be seen 

coming from the drain area (as late as 10-20 minutes after the bulk of the water has drained)? If not, is 

there something in the design of the DCU vent and/or drain that limits any chimney effect or air ingress? 

• All equipment passed required leak checks, no anomalies were noted. 

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