Date: February 12, 2013 To: Brenda Shine, EPA/OAQPS/SPPD From: Jeff Coburn Subject: Meeting Minutes for Meetings Betweenthe 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 1to 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 Shine2 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 potentialcontrol strategies. November 8, 2012 Phillips 66 representatives presented differentblowdown 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 somemethods 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 plant3 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 ornear 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 atno 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 thisis 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 expectedthat 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 flowof 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 associatedwith 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 representativespresented 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 im pacts 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-eff ective, 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 I nputs 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: 1050 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 1 00 % *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)

.. 22) remammg 

### 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 d 2 

### 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. C alculate 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

V ent

Coke Valve D rum positions for steam and water quench steps

To**Fillin g.__~_,..4--H<l-t><h**  Drum

From HeaterD ra in Steam I Wate r 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 posit i ons for steam and water quench steps Vent

Coke Drum

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

From Heater Dra i n 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 Fillin g
· 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 wan t to i mpact 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