Phases re-distribution during build up test.

dear all,
i am doing PBU test interpretation for well in gas cab reservoir, you can consider it as thin oil rime reservoir. during the production period GOR was high. the BU exihibit phases re-distribution pheonomena resulting in gas hump as you see.
iam using saphir, how i can include this pheonomena to be modeled and enhance my match.
regards,,,,

Dear friend
i believe that phases re-distribution pheonomena can occur during the wellbore storage period, not like it these picture. In my opinion i think the measurement wasn't done properly. Maybe there was a leaking on the wellhead ????
What is the perforation length ?Pay zone thickness ? GOR? what is the BHFP ?i suppose you have gas coning

regards

Although I can't claim to have the definitive answer on how to deal with it - not having much experience in the matter - I can address whether or not it is a WBS issue. I dont believe it is an issue only in the WBS stage..... Think of what is happening in the pipe, the gas has produced and then been shutin in the tubing at (a) lower pressure than the reservoir and (b) lower temperature (and falling now that hot gas flow has stopped) than the reservoir. Just like water condensation on the side of a cold glass, condensate will form on the tubing wall then coalesce and dribble down to the bottom, filling the bottom of the tubing up with liquid so that there is now a finite head of liquid above the transducer where at shutin it was all gas. This changing liquid density and head in the continuous phase of the tubing is I believe what is causing the phenomena you are seeing. Happy to be shown wrong - perhaps there are some more experienced well test people out there?

I really don't think that the tubing can be so cold to cause condensation..what about earth temperature gradient ? don't forget that we are talking about oil reservoir with gas cap.

first, i think is better if you QC point of pressure and after that you can regression or match to properly model. Use the correction tool.

At early time it is definitely phase segregation. In order to model it properly you must use Hegeman model for wellbore storage, check my manual here – [url]http://www.megaupload.com/?d=XSS93T0N[/url]
By the way you not properly defined infinite radial line. At later times you response became somewhat complicated. It because of radial composite response (change in mobility and saturations) and constant pressure boundary – well drainage radius probably reached fluid contact.
If you wish I can make the match for you (absolutely free ;), send your saphir file to [email]kochichiro@mail.ru[/email], I also write a little description. But I am using Ecrin 4.10.02, so I won’t be able to open newer version (4.12.--) files.

Usually the install two memory gauge downhole and one on the wellhead. Try to compare the pressures from all pressure gauges and draw them.

@kochichiro: It is very hard to do such a match if you don't have a good pressure respond. A IARF can be seen from the derivative plot, and some boundary effects but you will need some additional geology information regarding that reservoir (structural map, faults, type of rock...).. Matching is not just drawing lines :)

Well man, everyone knows that welltest is not just about lines. But two gauges is not of a good help in case of phase segregation, what is really you need is downhole shut-in tool or special test program like two-rate test or shut-in after lowest possible drawdown. The truth is that this data and build-up not a half bad, in real world welltesters always dial with such type of data. Mainstream reservoir engineers just spoiled with theoretical data from manuals and handbooks, but when the time comes to real data it is easier for them to say that this data is trash.

Also asker mentioned that reservoir has an oil rim, so it is natural to suppose that there is radial composite model with constant pressure boundary. I agree that you need more knowledge about reservoir geology, but you do not need to blindly match pressure response to reservoir geology. In many cases pressure response may provide alternative view on reservoir related problems, also it cannot be absolute answer. As I mentioned before it is just additional information from another source. I said what I am seeing from this build-up and how asker can match phase segregation. I am not saying that I am absolutely right, other peoples has they own viewpoint.

My point with two (three) pressure gauges is to compare them and see is there a pressure drop as we can see it on that picture.I agree with you regarding boundaries but how did you concluded that it is a radial composite? another question : how would you matched the derivative curve in this case? how can you explain the pressure drop on the picture?

I have same problem from my well. I got literature that if you want to match the derivative, you have to match with the second line (last period). No matter for the first period if it's not match, (better if you can match both of the period).