From: charles.p.feerick@exxonmobil.com 

To: Brenda Shine/RTP/USEPA/US@EPA, Bob Lucas/RTP/USEPA/US@EPA 

Cc: Ken Hustvedt/RTP/USEPA/US@EPA, charles.p.feerick@exxonmobil.com 

Date: 07/24/2009 02:24 PM 

Subject: Additional information on ExxonMobil Baytown flares 

Brenda and Bob, 

Thank you for meeting with me on July 9 to discuss the proposed NSPS Ja rule as it pertains to the 

requirements for flares. As we discussed at that meeting as well in our comments on the December 22, 

2009 proposal, we have three flares at our Baytown Refinery that are subject to NSPS J via a 500 lbs 

SO2/day alternative limit (based on H2S as measured by a CEMS). This alternative limit was agreed to in 

good faith by the Agency in our NSR Consent Decree, in recognition of the very poor cost effectiveness 

associated with retrofitting these flares to otherwise meet the 162 ppm H2S limit. We strongly believe that 

for these flares, this alternative limit should be incorporated into NSPS Ja as BDT. 

Attached please find additional information requested during our meeting related to these three flares. I 

hope you will find this information helpful, and please do not hesitate to contact me if you have questions. 

Thank you both again for your attention to this very important issue. 

Best Regards, 

- Chuck 

(See attached file: EM Comments on Flaring - 072409.doc) 

Chuck Feerick 

NSR CD Program Coordinator 

Downstream & Chemicals SH&E 

ExxonMobil Refining and Supply Company 

3225 Gallows Road, Room 8B2130 

Fairfax, VA 22037 

703-846-3341 Telephone 

703-980-9660 Cell phone 

703-846-5599 Facsimile 

charles.p.feerick@exxonmobil.com 
1

July 24, 2009 

Dear Brenda and Bob, 

Thank you for meeting with me on July 9 to discuss the proposed NSPS Ja rule as it 

pertains to the requirements for flares. As we discussed at that meeting as well in our 

comments on the December 22, 2009 proposal, we have three flares at our Baytown 

Refinery that are subject to NSPS J via a 500 lbs SO2/day alternative limit (based on 

H2S as measured by a CEMS, exclusive of process upset gas). This alternative limit 

was agreed to in good faith by the Agency in our NSR Consent Decree, in recognition of 

the very poor cost effectiveness associated with retrofitting these flares to otherwise 

meet the 162 ppm H2S limit. 

The three flares in question are Flares 11, 14, and 27. Flares 11 and 14 are cascaded 

with Flare 14 as the lead flare and Flare 11 serving as a backup/overflow flare. 

Consequently the routine flow to Flare 11 is very minimal, and in fact it is generally zero. 

The routine base flow to these two flares (combined) averages about 900-1000 KSCF 

per day. The total SO2 emissions based on the H2S CEMS typically ranges from about 

200 to 300 lbs/day. In 2008/1Q09 the SO2 emissions averaged about 215 lb per day, or 

about 40 tons/year. The sources of flow to these flare are provided at the end of this 

note, and are taken from Appendix G of our Consent Decree. 

The flow to Flare 27 is very low, around 145 KSCF per day on average. The SO2 

emissions based on the H2S CEMS for 2008/1H09 have averaged about 25 lbs per day. 

This equates to about 5 tons/year. The sources of flow to this flare are also provided 

below. 

We have developed some rough estimates of what it would cost to install flare gas 

recovery on these three flares. Facilities expected to be required include new 

compressors, amine absorbers, and seal drums, in addition to extensive off-sites 

equipment such as piping, electrical and power, and instrumentation. These costs are 

estimated to be about $150 million. The resultant reduction in SO2 emissions from 

these three flares is estimated at about 45 tons/year. Based on these figures, the costeffectiveness to install flare gas recovery on these flares -- even when calculated using 

the most conservative capital recovery factor (7%/20 yr) and excluding annual operating 

costs (~$6 million) -- is on the order of $300,000 per ton of SO2 which is clearly not 

consistent with what is typically considered BDT for this type of source. 

Since EPA has already agreed under the Consent Decree to the 500 lb/day SO2 limit 

(based on monitoring the H2S in the flare gas), we believe that for these three flares a 

500 lb/day SO2 limit and not the 162 ppm H2S flare gas limit is the appropriate emission 

limitation for incorporation into Subpart Ja. We believe the Agency can justify this 

position as CAA 111(a)(1) requires the Agency to take into account the cost of achieving 

reductions. As such, we believe Subpart Ja should recognize the Agency’s previous 

conclusions in this case and make available the 500 lb/day alternative limit for those 

particular flares. 

Thank you again for consideration of this important issue, and please do not hesitate to 

contact me should you have any additional questions. 

Sincerely, 
2

Chuck Feerick 

NSR CD Program Coordinator 

Downstream & Chemicals SH&E 

ExxonMobil Refining and Supply Company 

3225 Gallows Road, Room 8B2130 

Fairfax, VA 22037 

703-846-3341 Telephone 

703-980-9660 Cell phone 

703-846-5599 Facsimile 

charles.p.feerick@exxonmobil.com 

Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring 

Devices Operated by Covered Refineries 

Low Volume/Low Pressure Streams to be Routinely Combusted in Baytown Flare 11 

and/or Baytown Flare 14 

 a. Hydrocracker Unit 1 (HCU-1) 

 • S-702 (C-708 suction knock out drum) drain 

 • D-713 (C-708 1st stage discharge knock-out drum) drain 

 • D-714 (C-708 2nd stage discharge knock-out drum) drain 

 • D-770 (C-770 1st stage suction knock-out drum) drain 

 • D-771 (C-770 2nd stage suction knock-out drum) drain 

 • D-772 (C-770 3rd stage suction knock-out drum) drain 

 • D-780 (C-780 1st stage suction knock-out drum) drain 

 • D-781 (C-780 2nd stage suction knock-out drum) drain 

 • D-782 (C-780 3rd stage suction knock-out drum) drain D-780 

 • Low-point piping seal pot drains from C-770 & C-780 

 • D-773 (C-770 filter knock-out drum) drain 

 • D-783 (C-780 filter knock-out drum) drain 

 • D-771, D-772, D-781, D-782 (knock-out liquid) vents 

 • C-780 suction drain 

 • C-770 suction drain 

 • S870 hydrogen comp. coalescer drain 

• D-901 (water drain) 

• T-810 (sample point vents) 

• R-701 (sample point vent) 

• D-717A (C-701 sour seal oil drain) 

• D-717B (C-701 sour seal oil drain) 

• S-704C (C-708 peco filter) 

• D-703 (sour water sample) 

• D-715 (skim line) 

• D-905 (blend gas knock out) 

• D-906 (blowdown header low point drain) 

 b. FCCU 3 

 • C-302 (wet gas compressor) seal oil liquid collection pot drain 
3

 • C-303 (wet gas compressor) seal oil liquid collection pot drain 

 • C-301 (wet gas compressor) seal oil filtration system vent 

• D-504 C (boiler pilot gas knock out) 

• D-303 (slop drum vent) 

• D-302 (sample point vent) 

• Dopak sample points 

• D-30A F-103 (fuel gas knock out) 

• D-406 F-105 (fuel gas knock out) 

• D-1502 A, B, C (boiler fuel gas knock outs) 

 c. Hydrofining Unit 9 (HU-9) 

 • D-390 (DCU flare knock-out drum) overhead vent 

d. Equipment leaks and purges from components such as pumps, 

compressors, valves, etc. 

2. Low Volume/Low Pressure Streams to be Routinely Combusted in Baytown Flare 

27 

 a. Delayed Coker Unit (DCU) 

 • D-617 (residual flow from DCU flare knock-out drum) 

 • D-612 vent (DCU blowdown settling drum) 

 • 2 - C-601 suction lines condensible drains (during winter months) 

b. PipeStills-3/7 

• D-421 (hydrocarbon containment drum) 

• D-422 (hydrocarbon containment drum) 

c. Equipment leaks and purges from components such as pumps, 

compressors, valves, etc