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---------------------- Forwarded by Jeffrey A Shankman/HOU/ECT on 12/27/2000 10:59 AM --------------------------- From: Mark Smith @ ENRON 12/21/2000 12:09 PM To: Anthony Sexton/NA/Enron@Enron cc: john.romero@mms.gov, Russell Dyk/Corp/Enron@ENRON, Kenneth Shulklapper/HOU/ECT@ECT, Mog Heu/NA/Enron@Enron (bcc: Jeffrey A Shankman/HOU/ECT) Subject: Re: PADD V-California Gas Injection Anthony, Here is what I can add: 1. Looks like the Conventional Steam Boilers used by producers in the field (average boiler: 50 Million Btu/hr, uses 1400 mmbtu/day of gas) that have been shut-in, use approx.. 100,000- 150,000 mmbtu/day of gas (mainly, Texaco, Chevron, and independents). This number can vary depending on which majors have firm transport on the pipelines and don't have to pay spot SOCAL Border prices. This steam generation is used in either Steam Floods or Cyclic Steam Operations. 2. Crude production has probably not been affected, but if the injections stay down, you could see production start to fall off in 3 or 4 months. Crude prices in California are very weak right now (Kern River diffs are $10-13 under WTI when they normal run in the $5.80/$6.10 area). Majors that have downstream facilities have outlets for their crude and probably have no plans to cut production. Independents are seeing weakness on the buying side for the West Coast Independents and majors that normally buy their crude. It might be 2-3 months before things clean up a bit out there on the crude side. 3. Gas injection- The question here is due producers decide to risk the integrity of their reservoir's by reducing pressure and not injecting the gas. This probably would only be done for a month or two. Noone wants to damage any of their wells. This volume is not well known, but in the overall picture really shouldn't affect prices that significantly. Usually this gas is pretty sour and does not command a high price. This would also be the cheapest source or gas for producers to use (if they bought any make-up gas for their process). 4. Referring to the question #2, the majority of EOR methods used in California are Steam Floods and Cyclic Steam Processes. The oil is very heavy and needs HEAT in order to recover it out of the ground. Just injecting gas would not accomplish this. There are a lot of CO-GEN units that generate steam for most of the Majors and these are not being shut-in or slowed down. Only sustain high gas prices for 6 months would probably start affecting Crude production. Let's remember that in 1998-9 crude prices were extremely low and normal gas prices didn't change what most producers did, because if they shut-in too many wells, the production would never come back. If you have anymore questions, please let me know. Thanks Mark Anthony Sexton 12/20/2000 12:22 PM To: john.romero@mms.gov cc: Russell Dyk/Corp/Enron@ENRON, Kenneth Shulklapper/HOU/ECT@ECT, Mog Heu/NA/Enron@Enron, Mark Smith/Corp/Enron@Enron Subject: PADD V-California Gas Injection Hello, John. Again, thanks for your cooperation. Summary: A West gas trader received news from Seneca Resources stating that California crude producers that use natural gas injection (or gas lifting?) for secondary and tertiary recovery methods may stop injection and - instead - sell the gas into the market to benefit from the record high natgas prices. That being so, one wonders how much natural gas will be put back into the market and how California crude yields will be affected. Here are some specific questions that may help us: How often is natural gas used in California to enhance crude production (including gas injection/lifting, steam injection, and hot water injection)? Is this really a significant issue? What is the law concerning onshore gas injection? If the gas was bought (not produced) by the crude producer, is the crude producer obligated to recover the injected gas? If yes, must 100% of the gas be proven to be recoverable? On average, how much natgas volume is injected in an oil field to recover production? What is an approximate number of producing oil fields in California and/or PADD 5 What is the average size of these crude reservoirs? How many of these fields use natgas for enhanced oil recovery (EOR) - reiterating question #1? Is there a unit estimate of approximately how many MMBtus/Mcfs of natgas is needed to produce 1 barrel of crude onshore? How would stopping gas injection/lifting affect crude supply in California? Would crude wells be shut-in? If so, how would that affect future efforts to produce from them? Will a significant amount of crude be held from the market - especially in the PADD 5/Western region? What commodities are substitutes for natgas in secondary/tertiary EOR and how liquid are they in the West? How feasible, expeditious, and economical is it for any producing oil field to use another substance for EOR? John, I really appreciate your willingness to help unearth this information. The priority on this matter is urgent, so we would be extra grateful for a prompt response. Please do not hesitate to call me at 713-853-6304, Russell Dyk at 713-853-7332, or Ken Shulklapper at 713-853-7009 for any further questions or comments. Sincerely, Anthony
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