Date: February 12, 2013 

To: Brenda Shine, EPA/OAQPS/SPPD 

From: Jeff Coburn 

Subject: Meeting Minutes for Meetings Between the U.S. EPA and Representatives from 

Phillips 66: May 30, 2012; November 8, 2012; December 14, 2012; and 

February 5, 2013. 

Representatives from Phillips 66 met with representatives of the U.S. Environmental 

Protection Agency (EPA) and their contractor (RTI International) on May 30, 2012, to discuss 

delayed coking unit (DCU) operations in general. On November 8, 2012, representatives of the 

EPA and RTI International participated in a meeting with representatives from Phillips 66 to 

discuss DCU operations and controls needed to achieve lower coke drum pressures. A follow-up 

conference call was held on December 14, 2012, and a final face-to-face meeting was held on 

February 5, 2013, to discuss additional information on emissions, controls, and costs associated 

with the DCU drum venting. The presentation materials discussed during the initial meetings 

were not provided to the EPA as the information had not been cleared by Phillips 66 as nonconfidential. During the February 2013 meeting, Phillips 66 provided the EPA with a nonconfidential handout that contains general meeting material covered across the meetings as well 

as a confidential handout that provided additional information that Phillips 66 considers to be 

confidential business information (CBI). The non-confidential material is provided as 

Attachment 1 to this memorandum. 

Attendees 

Phillips 66 Representatives 

John Askounis 

Tim Gettiker 

Frank Tracy 

Erin Tullos 

U.S. EPA Representatives 

Andrew Bouchard 

Eric Goehl 

Penny Lassiter 

Erika Sasser 

Brenda Shine 
2

RTI International (EPA contractor) 

Jeff Coburn 

Kristin Sroka 

Discussion Topics 

May 30, 2012 

Phillips 66 representatives presented an overview of DCU design and operations, 

including monitoring parameters. Phillips 66 representatives noted that there are two main 

suppliers of the delayed coking technology: Bechtel, which took over the ConocoPhillips 

technology licenses, and Foster Wheeler. As an initial developer of the technology and with 

eight Phillips 66 refineries utilizing this technology, Phillips 66 has significant interest in the 

EPA’s consideration to regulate the delayed coking unit under Refinery MACT 1 (40 CFR part 

63 subpart CC). Phillips 66 representatives offered to provide technical assistance to the EPA as 

they evaluate potential control strategies. 

November 8, 2012 

Phillips 66 representatives presented different blowdown system configurations for DCU 

(see Attachment 1 starting with Slide 10). Original DCU often had open blowdown systems that 

vented to the atmosphere. The blowdown systems were subsequently enclosed and vented to a 

flare. Phillips 66 representatives indicated that, to the best of their knowledge there are no DCU 

that operate with an open blowdown system and named venting of a closed blowdown system 

directly to the flare “Case 0.” In Case 0, the back pressure of the flare header system determines 

the minimum pressure that the coke drum can achieve prior to atmospheric venting. As flare gas 

recovery systems were installed, the enclosed blowdown system would essentially be discharged 

to the flare gas recovery system (“Case 1”). The flare gas recovery system (in Case 1) generally 

operates at a lower back pressure than the direct flare discharge (Case 0), so a DCU that 

discharges the blowdown system vapors to a flare with flare gas recovery system can generally 

achieve a lower drum vessel pressure before needing to vent to atmosphere. The back pressure 

of the flare gas recovery system (which affects the lowest pressure the coke drum can get to prior 

to venting to the atmosphere) is dependent on the distance of the DCU to the flare gas recovery 

system. Many newer DCU now tie the blowdown system into the overhead gas line of the DCU 

distillation column prior to the wet gas recovery compressor (Case 2), which routes the light 

gases to the facility’s gas plant. Under this configuration, the lowest pressure the coke drum can 

get to prior to venting to the atmosphere is dependent on the operating pressure of the DCU’s 

wet gas compressor; in general, this configuration (Case 2) typically has a similar back pressure 

to a system vented to a flare gas recovery system (Case 1). 

Phillips 66 representatives then discussed some methods that could be used to achieve 

lower coke drum vessel pressures prior to atmospheric venting. Two options seek to lower the 

operating pressure to the settling drum. Case 3 would be installation of a steam ejector or off-gas 

compressor to transport vapors from the blowdown system to the overhead gas line of the DCU 

distillation column prior to the wet gas recovery compressor. Case 4 would be installation of an 

off-gas compressor to transport the vapors from the blowdown system to directly to the gas plant 
3

line (downstream of the DCU distillation column overhead wet gas compressor); this option may 

be used if the wet gas compressor is already operating at or near maximum capacity. 

Phillips 66 representatives noted that the blowdown recovery system cannot be operated 

at a vacuum because air could then leak into the blowdown system, creating a potential explosion 

hazard when mixed with the light hydrocarbons in the recovered gases. Therefore, the 

blowdown settling drum is typically operated at no less than 0.5 to 1 pounds per square inch 

gauge (psig), setting a limit on the lowest pressure at which the blowdown system can operate. 

Therefore even with the addition of a Case 3 or Case 4 control system, there would need to be a 

less than a 1 psig pressure drop from the coke drum to the recovery drum in order to depressure 

the coke drum vessel to 2 psig. While this is technically possible, many DCU blowdown 

systems were not designed to minimize the pressure loss across the system, so these DCU may 

also require additional piping, valve and/or cooling system replacements/modifications in order 

to achieve a 2 psig drum pressure. These additional modifications would typically not be 

required to meet a 5 psig drum pressure. 

Phillips 66 representatives also note that a steam ejector system could be installed on 

each individual drum overhead line. This control scenario (Case 5) would help to overcome the 

need to revamp the overhead piping, valves and cooling system in order to achieve a 2 psig drum 

pressure, but this configuration would require multiple ejector system (one per drum) rather than 

a single ejector system for the set of coke drums within the DCU. 

Phillips 66 representatives presented rough (early design) cost ranges for their 13 DCU. 

Phillips 66 representatives expected that 8 of their 13 DCU could meet 5 psig without 

modification and that 5 of 13 DCU could meet 2 psig without modification. Costs for specific 

DCU were highly variable, and generally increased when trying to meet 2 psig rather than 5 psig. 

Based on these preliminary costs, Phillips 66 representatives expected that the total capital costs 

to comply with a 2 psig drum pressure limit would be approximately twice that of a 5 psig limit. 

December 14, 2012 

During this teleconference meeting, Phillips 66 representatives described their proposed 

approach for estimating emissions from their DCU. Phillips 66 collected typical 

depressurization pressures and venting times for their DCU. They also collected detailed 

information on piping configurations, valves, etc. associated with the DCU atmospheric steam 

vent. Using these data, they proposed to apply fluid flow correlations from the Crane Technical 

Paper No. 410 to estimate the total volumetric flow of steam released during different periods of 

the venting cycle. Test data collected as part of the information collection request (ICR) would 

then be used to estimate the VOC or HAP emissions based on the typical mass of these 

pollutants per mass of steam released. Similar calculations would be performed with venting 

starting at 2 or 5 psig to assess the emission reductions associated with a 2 or 5 psig pressure 

limit. EPA agreed that this sounded like a sound technical approach, but requested additional 

detail be provided about the approach and, if possible, unit specific information so the Phillips 66 

emission estimates could be compared with the EPA’s unit specific emission estimates based on 

their heat balance approach. 
4

February 5, 2013 

During this meeting, Phillips 66 representatives presented additional details of their 

approach for estimating emissions from DCU, including an example calculation (see 

Attachment 1, Slides 3 through 9). Phillips 66 representatives briefly went through the different 

DCU configurations and control methods (discussed in detail in the November 8, 2012, meeting) 

and then presented their cost impacts on a DCU specific basis for the 2 and 5 psig pressure limits 

(this information was claimed confidential and is included in the CBI handout only). As with 

their previous estimates, Phillips 66 representatives expected that 8 of their 13 DCU could meet 

5 psig without modification and that 5 of 13 DCU could meet 2 psig without modification. 

However, Phillips 66 representatives noted that that assumption is based on having a reasonable 

averaging period. Phillips 66 representatives noted that some quenching cycles may take longer 

than others based on coke morphology, channeling of quench water within the coke bed, etc. 

While Phillips 66 operates five DCU that generally vent at pressure below 2 psig, there are 

occasions when the quench cycle is completed for these DCU, and they may vent when the 

vessel pressure exceeds 2 psig. If the 2 psig limit is determined on a per venting episode basis, 

there may be additional capital costs or lost production costs associated with meeting a “never to 

be exceeded limit.” These additional costs would not be incurred if the 2 or 5 psig limit were 

determined as an average over multiple cycles. While Phillips 66 representatives stated that 

having an averaging period was important, the basis of the averaging period (e.g., using a set 

number of cycles or using a set time period) was not important. 

Based on their cost and emission estimates, Phillips 66 representatives projected the cost 

effectiveness of a pressure limit (either 2 or 5 psig) was between approximately $120,000 and 

$210,000 per ton of VOC reduced. They indicated that, although the cost-effectiveness of the 

2 psig emission limit was similar to the cost effectiveness of the 5 psig emission limit, neither 

control requirement is cost-effective, and the 2 psig limit would double the total capital costs 

associated with the DCU emissions limit. Based on the high additional costs associated with the 

2 psig venting pressure limit, Phillips 66 representatives urged the EPA to either not set a 

maximum DCU venting pressure limit (beyond the 15 psig “limit” in 40 CFR part 63, 

subpart CC) or to set a pressure limit of 5 psig (rather than 2 psig). 
5

Attachment 1 

Presentation Slides 

Coke Drum Venting 

EPA Technical Review 

February 5, 2013 

Phillips 66 
Coke Drum Venting 

. ·- ,_ 

1 
Topics 

1. Phillips 66 Coker Vent Emissions Calculations 

and Example 

2a PFDs of Possible Coke Drum Off-Gas 

Handling Solutions 

3. Scope of Possibl.e Solutions 

4. Rule Compliance Cost and Cost Effectiveness 

2 
1. Phillips 66 Coker Vent Emissions Calculations Example 

Overview 

Coke drum vent emissions are determined from: 

A. The mass of vapor released to the atmosphere during venting 

B. The concentration of VOC in the vent stream 

Details 

A. Mass of vapor released with each vent cycle is an engineering calculation 

Fluid flow calculations from Crane Technical Paper No. 410: Flow of Fluids Through · 

Valves, Fittings and Pipe 

Unique calculation for each coker 

Key Inputs 

Piping diameter and configuration to calculate equivalent pipe length 

Average vent duration 

Initial vent pressure for current operation 

Final vent pressure (atmospheric) 

Typical pressure decay curve 

Assume vent is all steam for this calculation 

B. Calculate annual VOC emissions for current vent pressures 

Apply average VOC concentration from industry reported coker vent tests to vent 

stream mass to get mass (pounds) of VOC per cycle 

Multiply by annual number of coker cycles 

3 
1. Phillips 66 Coker Vent Emissions Calculations Example 

E?<ample Refinery Calculation 

Inputs 

Drum vent inside diameter (d) = 11.938 inch = 0.9948 ft 

Vent pipe configuration: pipe segment lengths, fittings (e.g., 

elbow or tees), valves, etc. 

Vent duration = 9 minutes 

Initial vent pressure= 6.0 psig = 20.7 psia 

Final vent pressure= 0 psig = 14.7 psia (Atmospheric 

pressure at site elevation- sea level in this example) 

Coke drum vents/cycles per year = 450 

4 
1 c Phillips 66 Coker Vent Emissions Calculations Example 

Example Refinery Calculation 

Other Inputs and Assumptions 

~ 

::J 

- Total coke drum vent gas molecular weight: 18 lbs/lb-mole (99°/o steam) 

- Non-methane, non-ethane (NMNE) VOC concentration in drum vent: 

1 050 ppmv-wet as propane - based on Phillips 66 evaluation of the 

industry reported vent test results* 

- NMNE VOC molecular weight: 44 lbs/lb-mole 

- Pressure decay curve -typical based on actual refinery data 

Pressure Decay Curve 

1.2 

1.0 ·-------

0.8 ----- --·---

::l 0.6 -t--- ------""or-------~·--·-------

~ 

a.. 

0.4 

0.2 -··---

0% 20% 40% 60% 80% 

Time 

100% 

*Includes NMNE VOC concentration 

data in Hovensa, Houston Refining, 

BP, Marathon and Citgo coker vent 

test study reports 

5 
1. Phillips 66 Coker Vent Emissions Calculations 

Example Refinery Calculation 

A. Calculate mass released with each vent cycle 

Drum vent inside diameter (d) = 11.938 inch = 0.9948 ft 

Equivalent pipe length of vent (vie)= 350ft 

• The vent equivalent pipe length is calculated from the actual refinery pipe 

segment length, piping components, and valves using standard engineering 

factors found in Crane Technical Paper No. 410. 

Vent friction factor (fT) = 0.013 

• The vent friction factor (Crane, page A-26) is dependent on pipe diameter 

Resistance coefficient 

• K = (fT x vie) I dv = (0.013 x 350ft.) I 0.9948 ft. = 4.57 

• The resistance coefficient equation is from Crane, page 3-4, equation 3-15 

6 
1 a Phillips 66 Coker Vent Emissions Calculations 

Example Refinery Calculation 

A. Calculate mass released with each vent cycle (cont.) 

- Using pressure decay curve divide vent period into five slices 

- Find V1 specific volume of saturated steam at pressure from ste ~m tables 

- Calculate dp I P' 1 (vent pipe pressure drop over upstream absolute pressure) 

- Find Y, net expansion factor for compressible flow through pipe with a 

resistance coefficient K=4.57 for steam (k=1.3) from Crane chart A-22 

-

Percent Fraction V1 Y, net 

Time of vent Vent time of initial Pressure, Pressure, ft3/lb expanston 

Period time elapsed, vent psta (at next 

dP I P'1 factor 

minutes pressure pstg (P'1) (Crane A- elapsed .. whole psia) 

remammg 22) 

0 0% 0.00 1.00 6.0 20.7 20.09 0.29 0.863. 

1 25o/o 2.25 0.58 3.5 18.2 22.17 0.19 0.910 

2 50o/o 4.50 0.29 1.7 16.4 24.75 0.11 0.950 

3 75%) 6.75 0.12 0.7 15.4 26.29 0.05 0.978 

4 100% 9.00 0.00 0.0 14.7 26.80 0.00 1.000 

7 
1. Phil_lips 66 Coker Vent Emissions Calculations 

Example Refinery Calculation . 

A. Calculate mass released with each vent cycle (cont.) 

- The vent internal diameter (d) = 11.938 inches 

- ~p is the difference between the vent pressure and the atmospheric pressure, psid 

- Vent gas flow rate (lbslhr) = W = 1891 x Y x d2 x (~PI (K x V1 ))% 

• 1891 X 0.863 X (11.938)2 X (6.0 I (4.57 X 20.09)f'~ = 59,457 

• The vent gas flow rate equation is from Crane, page 3-4, equation 3-20 

- Flow at end of time period= [(Wi + Wi-1) I 2] x (Ti- Ti-1) I 60, where 

• Wi =Flow rate for time period i, Wi-1 =Flow rate for time period i-1 

• Ti =Vent time elapsed for period i, Ti-1 =Vent time elapsed for period i-1 

• 60 = minutes per hour 

V1 Y, net Flow at 

Vent time expansion W, Time ~P, ft3/lb end of Cumulative 

elapsed, factor Flow rate, Period psid (at next time Flow, lb 

minutes (Crane A- lblhr whole psia) period, lb 

22) 

0 0.00 6.00 20.09 0.863 59,457 

1 2.25 3.48 22.17 0.910 45,421 1,966 1,966 

2 4.50 1.74 24.75 0.950 31,745 1,447 3,413 

3 6.75 0.72 26.29 0.978 20,395 978 4,391 

4 9.00 0.00 26.80 1.000 0 382 4,773 

8 
1 ~ Phillips 66 Coker Vent Emissions Calculations 

Example Refinery Calculation 

B. Calculate annual VOC emissions for current vent pressures 

- Vapor released per drum vent cycle = 4, 773 lbs I 18 lbsllb-mole = 265.2 lbmoles 

- Vapor released per year = 265.2 lb-moles x 450 drum switches per year = 

119,335 lb-moles 

- NMNE VOC released per year= 119,335 lb-moles x 1050 ppmv-wet x 44 

lbsllb-mole I 1,000,000 = 5,526 lbs = 2.76 tons 

9 
2. PFDs of Possible Coke Drum Off-Gas Handling Solutions 

Case 0: .Original Closed Slowdown System connects to flare 

-Coke drum pressure set by system hyrdaulics and flare system back pressure 

- Later, flare gas recovery systems added 

To 

Val-.e 

positions 

for steam 

and water 

quench 

steps 

Vent 

Coke 

Drum 

Filling __ ~-M---1.---t..c:J--t><h 

Drum 

From Heater 

Drain 

Steam I 

Water 

Main 

Fract 

To Flare 

.------oo~·Dr-----· To Gas Plant 

Wet Gas Compressor 

"'" IV 
2. PFDs of Possible Coke Drum Off-Gas Handling Solutions 

Case 1: CBS off-gas to flare gas recovery system 

- Avoids direct connection to flare 

- Coke drum pressure set by system hyrdaulics and flare system back pressure 

Vent 

Coke 

Valve Drum 

positions 

for steam 

and water 

quench 

steps 

To 

Filling.__~_,..4--H<l-t><h Drum 

From Heater 

Drain 

Steam I 

Water 

Main 

Fract 

..-----------8 To Flare 

Gas Recovery 

To Gas Plant 

Wet Gas Compressor 

Considerations 

-Pressure drop from coke drum to settling drum 

- Flare gas recovery location, capacity, other units 

11 
2. PFDs of Possible Coke Drum Off-Gas Handling Solutions 

Case 2: CBS off-gas to main fractionator overhead 

-Avoids direct connection to flare but CBS has to operate at higher pressure 

-Coke drum pressure set by system hyrdaulics and main fractionator overhead pressure. 

Vent 

Coke 

Valve Drum 

positions 

for steam 

and water 

quench 

steps 

To 

Filling 

D rum-~-+-4------j~<l---t><:l--, 

From Heater 

Drain 

Steam I 

Water 

Main 

Fract 

Wet Gas Compressor 

Considerations 

To Flare I Flare 

Gas Recovery 

To Gas Plant 

-Pressure drop from coke drum to settling drum 

-Main fractionator overhead pressure 

12 
2. PFDs of Possible Coke Drum Off-Gas Handling Solutions 

Case 3: CBS off-gas compressed to MF overhead sysrem 

-Coke drum pressure set by system hyrdaulics and off gas compressor suction pressure. 

- A variation is to use an ejector system 

Valve 

positions 

for steam 

and water 

quench 

steps 

Vent 

Coke 

Drum 

To 

Filling+--~~,._-i--tx:~--t>c::J--. Drum 

From Heater 

Drain 

Steam I 

Water 

Main 

Fract 

~----~~-------(0 To Flare I Flare 

Gas Recovery 

Considerations 

Off Gas 

Compressor 

(Possible Alternate: 

Eiector) 

To Gas Plant 

Wet Gas Compressor 

-Pressure drop from coke drum to settling drum 

-Pressure of main fractionator overhead system may require 

multiple stages 

- Ejector aleternative adds motive steam to the system 

- MF overhead cooling water exchanger and CW system capacity 

- MF overhead sour water and plant sour water handling capacity 

-Avoid pulling vacuum on settling drum ··~ •"' 
2. PFDs of Possible Coke Drum Off-Gas Handling Solutions 

Case 4: CBS off-gas compressor discharing into Gas Plant 

-Coke drum pressure set by system hyrdaulics and off gas compressor suction pressure. 

- Ejector not likely to be feasible in this application. 

Valve 

positions 

for steam 

and water 

quench 

steps 

Vent 

Coke 

Drum 

To 

Filling 

D rum·-~-+41--j..--t><lr--l><::h 

From Heater Steam I 

Drain Water 

Main 

Fract 

n To Flare I Flare 

.---------.--...----- -\_2) Gas Recovery 

Considerations 

Off Gas 

Compressor 

Wet Gas Compressor 

To Gas Plant 

-Pressure drop from coke drum to settling drum 

-System pressure of gas plant 

'14 
2. PFDs of Possible Coke Drum Off-Gas Handling Solutions 

Case 5: Ejector on Coke Drum 

-Coke drum pressure set by ejector design. 

- Ejector not likely to be feasible in this application. 

Valve 

positions 

for end of 

water 

quench 

step 

Ejector Motive --~~----------~ Steam 

Vent 

Coke 

Drum 

To 

Filling 

· D rum -~

1 t-tJ..---1.--t><:l--t>c:h 

From Heater f 

Drain 

Main 

Fract 

Steam I 

Water 

~--------------------

Wet Gas Compressor 

Considerations 

Q To Flare I Flare 

Gas Recovery 

To Gas Plant 

-Potential large and variable steam flow rate from drum so 

ejector size and required motive steam may be large 

-System design to avoid pulling vacuum 

15 
3. Scope of Possible Solutions 

Considerations for Identifying Possible Solution I 

• Do not want to impact drum cycle time as this can reduce unit throughput 

• Pressure drop between coke drum and CBS settling drum can limit the pressure that 

can ultimately be achieved 

- Piping, valves, air coolers 

• Air cooler capacity impacts ability to depressure 

• Ejectors require motive steam 

- Limited turndown capability 

- Steam must be condensed and processed 

• Other unit constraints 

- Main fractionator overhead cooling, compression, and sour water handling capacity 

- Main fraction overhead and other system operating pressures 

• Flare system I flare gas recovery system design and constraints 

- Piping and other equipment through th·e flare gas recovery system 

• No two units are alike so we will have several different solutions 

- Unit original design I configuration I constraints 

- Coke type, cycle time, location (i.e., freeze protection requirements) 

• Additional engineering _will better define scope and cost 

16 
4. Rule Compliance Cost and Cost Effectiveness 

Cost Analysis: 

• P66 believes that industry projects required to achieve a 5 psig will range from a low of $2-10 NJM 

to a high of $25-35 MM per individual unit. 

• P66 believes that industry projects required to achieve a 2 psig standard will range from a low of 

$2-10 MM to a high of $40-60 MM per individual unit. 

• The cost to achieve 2 psig appears to be about twice that of achieving 5 psig. 

• For P66 to achieve 2 psig, about 2/3 of our units will require investment, including significant unit 

reconfigurations. 

• Timing of implementation could increase cost due to an accelerated shutdown schedule. 

Cost Effectiveness: 

• An internal P66 estimate of the cost I benefitill calculations for NMNE VOC emissions shows that 

cost effectiveness for obtaining 5 psig or 2 psig limits are well above the accepted threshold. 

• 

- In the range of $121,000- $216,000 per ton VOC to achieve 5 psi g. 

- In the range of $133,000-$207,000 per ton VOC to reduce from 5 psig to 2 psig . 

ill P66 emissions estimates were derived using a fluid-flow model developed for each P66 coker, 

utilizing VOC concentration data from industry reported coker vent tests. Annualized cost 

estimates employed EPA's depreciation schedule of 20 years with a 7% discount. 

17