OPM User,
Thanks for your reply. Unfortunately, the things you are questioning tend to be
revisions I've made trying to resolve the solver issues. Water generally does
not flow in tight reservoirs. Since it has compressibility similar to the rock,
eliminating it can be a reasonable simplification. I've had good success
matching tight oil wells using RVCONST to continue some liquid production after
Sorg, and have actually observed in the field where the liquid production
evolves from a dark oil into a light/clear condensate. I extended the PVT
tables to cover the increasing pressures, hoping that the extensions would
correct the oscillations. They did not. I am unable to look at your run as it
was blocked by the administrator, but if it ran slowly with oscillations, I'm
afraid it will contain the same problems as my original runs. If you look at
the pressure grid at the end of the run, I think you'll still see the high
pressures adjacent to the high perm fracture cells that are obviously
incorrect. I appreciate the comment about the restart files, and will
definitely act on that as the files are filling up my drive! Thanks again! - NR
________________________________
From: Opm <opm-boun...@opm-project.org> on behalf of OPM User
<opmus...@gmail.com>
Sent: Sunday, March 22, 2020 12:16 AM
To: opm@opm-project.org <opm@opm-project.org>
Subject: Re: [Opm] Convergence Problems - New Shale Well Model (Resend w/o
attach)
Neale,
The email with the results has been automatically held until the list
moderator can review it for approval. So I have just sent the text
instead in this email.
OPM User
opmus...@gmail.com
------------------------------------------------------------------------
Neale,
I had a quick look at this and I'm a bit confused on what you are trying
to do, for example, why is there no water in the model? Now I understand
that you probably making changes just to get the model working, as per
the commented out keywords, so I need to get a better understanding of
what you want the final model to look like.
Note that OPM Flow does not have the same level of error checking as the
commercial simulator, but this is improving with each release, so one
needs to be more careful in checking the decks. Note that:
1.
There was a few errors on the TABDIMS keyword but that does not
effect OPM Flow as it automatically dimensions the tables as it
reads the keywords.
2.
RVCONST keyword is not needed for runs containing dry gas.
3.
On the RPTSCHED keyword BASIC is not a valid sub keyword.
4.
OPM Flow correctly reports that BASIC is not supported on the RPTRST
keyword, that means the simulator is going to write a restart record
every report time step. I don't think you want this.
I ran you model as is using 2019-10 release and it runs, it is slow with
lots of oscillating behavior messages, but it does run. The obvious
candidates for poor numerical performance are the relative permeability
curves and the PVT data. Your relative permeability curves are nice and
smooth so I don't think they are the problem. It looks as though the PVT
data set has been modified to account for high pressures, is that
correct? If so that could be part of the problem. Some times this can
result in consistencies between the oil and gas formation volume factors
and compressibilities. The commercial simulator normally gives the
dreaded "Negative Compressibility Found" warning message; however, OPM
Flow (as far as I'm aware) does not check for this. So I have another
look at the PVT. For a quick fix you good just set a lower reservoir
pressure so that you stay below the extrapolated PVT data.
Note also that these type of models with high contract permeabilities
are always challenging models to run.
I have attached results from running your case, except for the 2GB
restart files. You can load the summary data into OPM ResInsight to
review the results.
Let me know how you get on.
OPM User
opmus...@gmail.com
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