negative OIIP result from MBE

dear Guys

I've question about estimating OIIP with MBE.
I already knew there is a gascap with no aquifer,
but I'v no idea OIIP, GIIP(so I need to assume m value)
So, I used gas cap drive solution but two different results make me confused.

first, when I assume m values (adjust m value ~ 0.3), OIIP was 7MMstb
(used havlena & odeh m ratio specified)
but, when I used N intercept, G slope method,
OIIP got negative value -3MMstb with OGIP 3MMscf
Can I ask the reason of two different results?
Or, any Idea to deal this problems ?
what input data should be re-checked??

Sharpjiy,

Under the conditions of a strong water drive or gas cap drive, it may not be possible to use the MBE method. In such situations, a small pressure decline takes on a magnitude comparable to the error in pressure measurements, thus bringing too high an uncertainty into the calculations.

Did you attempt a pressure match, to confirm the validity of your model? This is the first thing you should do

Negative OOIP means you may have placed to much emphasis on your early time data and most likely do not have a slope of 1 in your Havlena Odeh plot

See Craft and Hawkins "Applied Petroleum Engineering" Chapter 6

Rgrds

Chee Koh Peh

dear Chee Hoh Peh

I really appeciate your help regarding my question.
I'll check my pressure data with your comment & reference book.

I've another question calculating averaged reservoir pressure in multi-wells reservoir(All wells have a communication each other.)
I heard about the method, volume averaged pressure,
but each well production start time is different, so cumulative productions were also different.
Would you recommend me any reference books or ducuments for calculating averaged reservoir pressure, once more??

regards,
sharpjiy

Dear Sharpjiy,

See Dake - "The Practice of Reservoir Engineering", he has excellent worked examples and discusses in depth how to average reservoir pressure.

Your reservoir pressure is an average of well SIBHP, usually obtained by PTA.

Do not worry about well timing, what you need is average reservoir pressure and total fluids (gas/oil/water) produced at each average reservoir pressure point.

Rgrds

Chee Koh Peh

Take a look at this paper

http://www.pe.tamu.edu/wattenbarger/...l%20Ahmady.pdf

Also this one is good

http://www.pe.tamu.edu/wattenbarger/..._59781_leo.ppt

Dear Chee Koh Peh

Thank you for your answer, Mr. Chee.

When I was a student, I just run how to calculate reserve with MBE, or volumetric, decline curves.

But in real works, the problem was how to set input data for reserve estimation.

Calculation itself was conducted many software or other tools.

Your comments and references would be great help for me.

thank you.

regards
sharpjiy

Dear Shakespear

Thank you for your help, shakespear.
The documents you recommended were really helpful for me.
And, I was also impressed your last comment, petroleum should be used as a meterial not as a fuel.
I totally agree with you.

Regards
sharpjiy

Sharpjiy,

If you are using MB for reserves you should always cross check with the results from conventional decline curve analysis.

DCA is the most robust/defensible method of calculating reserves in fields with sufficient production history.

However the MB comes in very hand where the STOOIP/GIIP as calculated by volumetrics x recovery factor (RF) does not match the results from Np + DCA.

What the MB does, is it gives you an indication of the connected pore volume i.e. the actual producible oil/gas, which can vary considerably in volumetrics depending on the petrophysical cutoff used (i.e. Sw, porosity etc...)

Typically MB's value is early in the fields life where production data may not be sufficient for DCA.

Rgrds

Chee Koh Peh....

Chee Koh Peh, good and helpful comment. Keep it up and the younger engineers will get better.

Share is the way to Live :-)