GH,
<<Interesting, this flow regime is what I intuitively would expect. It is consistent with a reservoir saturated with two dense and "immiscible" fluids. We can not, IMO, simply be dealing with a dense hydrocarbon phase saturated with a dense water phase. If reservoir fluids co-existed in this later state, then the blowout should have produced water from day one as should have BKP#1 on production test.
Do you agree ??>>
This is where I run into problems. As you said, the water should have been there immediately if it was all dense phase commigling like a bunch of ping-pong balls. It does, however, possibly indicate deep fractures that may be reaching way down to pull up water. It also lends a little credence to my Hysim model which says that water could exist as a liquid at these conditions (or aweful close to a liquid - heck what does dense phase look like any way?).
<<I had estimated 1.73 for Carneros gas and 1.85 for the Phacoides in BKP#1. I'm glad to hear that I'm at least ball park with your calc. Is yours for Carneros or Phacoides reservoir conditions ??>>
I was using the producing bottom hole pressure (14,500 psig @ 350 F) in my model. This was based on the flow test and my estimate of what that pressure was when they were producing 13 MMscfd and 3900 BWPD, 2.43" I.D. tubing.
<<I prefer to visualize two dense fluids and have trouble comprehending the "liquid water". But, admittedly, I have serious difficulty arguing for\against any fluid state at these conditions !!! <gg>>>
I come back to the water surging in during the blowout. Maybe its more dense than the HC's and actually preferentially separates (messes with my ping-pong ball model)
<<Yes, but those are VERY different conditions, John. At ELH the fluid(s) are hitting the surface choke at a higher P then you have downhole in your case history. Also, at ELH pressure should remain well above critical throughout the entire string. There should be no 3 phase considerations, anywhere in the tubing at all. It should be quite a different animal and the pressure drop per ft should not be near as severe, IMO, but who knows.>>
The well I am talking about has a SIBHP of 8400 psig. The fluids are supercritical until the pressure drops below 2400 psig. For a long time we produced with 5500 psig surface tubing pressure. Its pretty similar since I don't know how different the fluids really become once they're sqeezed this tight. This well has exactly the same water yield as it did on day one. I think the two phases are completely mixed but clearly insoluble. Maybe the water comes from below at ELH (capillary forces or big straws?)
<<Presumably BKP will have used their multirate flow test data from BKP#1 as empirical data to "calibrate" their own "pressure drop model". They should be in a far better position to size their tubing string then I am in any event.>>
IMOHO the 3-1/2" tubing is a practical choice for rig work. It may also be necessary to keep the production and drawdown at a certain level to keep the water at bay. 3-1/2" tubing may be the perfect choke to keep operators from pulling the wells too hard. Still think some special pipe with 4" I.D. would be the ultimate..but then I am always tempted to maximize production and could be looking past the water issue.
regards
J |
