print
---------------------- 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