### 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 1to 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 2to 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 cokebed 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 notedthat 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 slowlyin 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 thisequilibrium 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 testreport 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 lastedonly 20 minutes, but for Runs 2 and 3, the temperature of the drain water reached212 °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 to9.25 tons/year), with naphthalene and 2- methylnaphthalene contributing significantly to the VOC emissionstotal (approximately 65%). ExxonMobil representatives did clarify that the polycyclic organic matter (POM) concentrations used in their emission model were not measuredconcentrations; 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 naphthaleneand 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 beretrofitted 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 10 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 10') • 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 

## I**~** I -E'.'E..,.**F~\.'** TCF T..=..N3Ef..."

F1'

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 Tak ing 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 emiss ions from the coke pit were not modeled at the proper cond itions :

- 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 p it 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 conce ntrations derived from vent test , based on equilibrium and solubility in water

9

## Elf(onMobil 

# Conclusions from the Test Prog ram Taking on the world's toughest energy challenges!'


# • Exxon Mobil coker emiss i ons test was properly conducted and yielded high quality data • Lowe r vent em issions 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 fract ion 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 Tak ing 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 co kers totaling $35- ?0M (screening level estimates )
. Facil it ies in c lud e :

-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 ps ig, i nvest ments needed at re m a i ni ng 4 EM cokers tota lin g $22-45M

-New liquid-ring compressors.

11

# El!{onMobil Taking on Ute world's toughest ;energy challen;ges!



# Back-up Information

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## EJf(onMobil Taking on the world 's t oughest energy challenges:"

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# DCU Test Run #1 EJf(onMobil 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:"



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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 pitot tube.
• All velocity equipment passed required QA/QC checks, no anomalies were noted.
o Preliminary measurements ofthe 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 notpossible 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 availablefrom 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 noflow in the coke drum vent and not based on the coke drum level indicator which only measures the top 1/3 ofthe 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 ofthe 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 ofthe coke bed is hotter than the bottom ofthe coke drum. The drain water temperature is largely based on the cooling water inlet temperature and the extent ofcoke 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 ofthe coke bed temperature. It is more representative ofthe steam purges (PRV blowbacks) that enter the piping.
• The top ofthe coke bed is hotter than the bottom ofthe 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.
• ExxonMob il believes that the hydrocarbon measurements ore representative and consistent with other industry cokers within the accuracy ofthe 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 ofvolatiles and semi-volatiles appear to be within the ranges ofmeasurements 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 afunction oftwo 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 ofventing, 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 releasedfrom 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 factor s in how a coke bed forms that affect coke bed cooling that we cannot con trol 

### o M aximizing coke drum fill with water prior to venting helps ensure a cool coke bed • By draining during v enting, less hydrocarbon is stripped by ev olving steam o Coke bed cooling is enhanced by pulling water back through the coke drum; waterfinds new paths as the coke bed c racks and moves due to thermal s tress es 

### o Coke drum pressure drops quicker due t o the vacuum effect of the drain wa ter 9. If the assumption is that emissions are from the qu ench 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 c

alculations and sampling re sults indicate significant amount of semivolatile emissions of PAH (primarily 2- methyln aphthalene) , 1 to 2 TPY, orders of magnitude more than you reported for the entire site . • VOC emissions fr om the water were reported u sing bot h RW ET a nd Water 9 mod els 

### o VOC emissions via RWE T= 0. 68/b/h r { 2. 98 tpy ) o Original V OC emissions vio W ater 9 model= 1 .20 lb/hr (5.26 tpy) based on modeled drain water temperature of 70 F 

### o R e v ised water V OC em is si

ons u sing 2 00 F for th e water d rain and pit temperature 

## = 2.11/b/hr {9
.25 tpy). A v erage drain water temperature dur ing the test was 143-165 F
. 

### o O pen roof tank mod eled as quiescent unit; coke drum drain/pit as an open drain. 

### o W ater VO C concentra tions deriv edf rom v ent test, based on equilibrium and solubility in water . 10. The test report indicates that oxygen conce ntrations were very high at the beginning of the run and about 2% at the end of the run. Does Exxon Mobil have any e x planation for this? The opposite phenomena would be expected. As much of the test was performed while the drum w as 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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