How to Quality Check a Static Model

[joshaffluence]

Can anyone help on hw to QC a static model, got a static model from a geologist and initialized but the volumes are not matching at all and have done all i know to do but i feel the problem is from d static model, hw do i QC a static model given me from a geologist

[reservoir_engineer]

Friend,
this is good and interesting subject. as reservoir engineers we got static models and caliberate it to match the observed data but the main issue if the model statically not so good so your prediction runs and scenarios will be misleading.
i think there is no ideal methods to QC the static model, that is why i apprecciate your thread to try to collect all methods and evaluate all from simulation experts.
for me i recheck the four items that geologist him self check,
1-cells bulk volume, to be sure that there is no negative bulk volumes.
2-cell angles, to avoid non -orthogonal cells, some of guys say it should always be greater than 45 degree.
3-cell inside out, to avoid twisted cells that always close to faults.
**these three items if exist in your model it cause errors in the runs.
4-property distribution with observed open hole logs, simply you can creat well section and/or function window and plot on the same track/plot interpereted log effective porosity with the model porosity distributed in the cells, it should have good match, to check scal up logs in the fine grid was good and also your upscaled grid is still in good match with logs.
5- review facies distribution as some times i saw strange unreasonable facies distribution.
the previous items are not the best procedure you can follow.
it is only what iam doing, iam sure that there are so many other better methods.
best regards,

[dronnne]

Hello,
Compare Bulk volumes, Pore volumes above/between fluid contacts. If it is ok then problem in saturation distribution - initializing.
Then:
First you should check OWC and GOC if they are the same in geo and sim models.
Then the saturation profile for wells in both models (capillary pressure, J-function?)
That will help you to identify your problem..

[reservoir_engineer]

Dear dronne,
regarding saturation distribution i don't agree with you as you should never rely on saturation distribution made by geologist simply due to two reasons:
1-geologist doesn't consider any capillary pressure data and so transition zones saturation distribution will be extremely wrong specially if you are dealing with low permeability reservoirs.
2-geologist distribute saturation in the reservoir based on petrophysical interpretation of all well logs, while log saturation in recent drilled wells affected by production from earlier drilled wells in the field, what i mean as simulation engineer you want every thing in the model to be initial as it was 1000000 years ago and then start to simulate the dynamic process of fluid flow and this is the main difference between the word static and dynamic.
for me i always take from geologist only two properties Porosity and facies distribution, permeability if NMR logs available if not i generate it using correlation from core analysis.
best regards,

[vinomarky]

The QC process is an iterative one - some issues you can spot immediately (ie volume busts), but others require some scoping runs to be done first

A few things to watch out for;
Make a KH map, by zone if sensible - and eyeball to ensure it matches conceptually with how the kh should be distributed - quite a few times I've seen bullseyes of kh just around wells, and/or massive bullseyes away from well control..... look for these anomalies and sit down with the geo to resolve.

Obviously hydrocarbon volumes etc should match, or if not, the difference should be explainable via different saturation function assumptions

Get involved with the upscaling, or at least satisfy yourself that it has been done correctly - ensure the character of the large contrast events are preserved, as these will often control model behaviour - you may have to do some sector models to satisfy yourself on this. I prefer to do the upscaling myself, but this may not be everyone's preference.

Edit: On the topic of upscaling, I would highly recommend introduce a NTG property even if one was not created initially. Use appropriate cutoff (ie perm < 1mD for oil for example) for NTG property, then zero out (set undefined) all perm/poro properties associated with NTG of 0. THEN upscale the perm, poro and NTG. The result will be upscaled perm and poro that better represents net pay and associated NTG property that addresses the volumes. Without doing this method (especially in heterogeneous formations with lots of low perm that is essentially non-contributing) you will end up with pessimistic perm & poro distributions, optimistic volumes and too much connectivity.

Once simulating -
if the well perms have been populated properly (ie tuned to SCAL and/or NMR etc) then check the PI's (or initial online rates/drawdowns) are of the right order

If you have a quite heterogeneous system (ie fluvial etc) and you cannot match the levels of depletion seen with usual tweaks, then a common problem is the geos have too much continuity/connectivity in the model - a rebuild would be required, perhaps needing to fine up the grid and use shorter influence ranges in their variograms. Less common is not enough continuity, but I guess it could occur.

Just a couple to bear in mind

[yussy]

Please how can one make kh map in petrel