INTERACTIVE PETROPHYSICS SOFTWARE

Hello Kokokyi

With help from you i was able to go a long way with IP. However, i have these Array Induction Imager (AIT -10,20,30,60,90) logs but really don't know how to process them for interpretation in IP.
Do you have any Ideas?
Thanks.

As I do not have the latest version of IP software, I am not sure if you can derive the true formation resistivity Rt by doing an inversion, using all these Array Induction curves with different depths of investigation. You need to check on this in the "environmental corrections" module for Schlumberger tools in IP. If that is not possible, I would recommend to use the AIT90 curve as Rt and AIT10 curve as Rxo for your calculations. Although these will be approximations, I don't think that the results will be too far off.

What is the module in IP3.6 to generate Rmf and Rm curves?

Solomon,

You can easily generate continuous Rm and Rmf curves by using the following equations in IP.

R2 = R1[(T1+6.77)/(T2+6.77)]
where R2 is either Rm or Rmf at downhole temperature T2. R1 is Rm or Rmf at surface temperature T1, at which the Rm and Rmf values were measured (usually at surface).
Temperatures T2 and T1 are in degrees Fahrenheit.

If the temperature is in Celsius (or Centigrade) units, the following equation has to be used:
R2 = R1[(T1+21.5)/(T2+21.5)]

Thank you Kokokyi,
what about hydrocarbon density?

In any deterministic petrophysical evaluation program, the hydrocarbon density is the output from the program. The assumption is that the grain density (matrix density) is known and the hydrocarbon density is unknown.
My IP program is not working at the moment. Therefore, I cannot refer to the IP parameters.

Yes, you are right.
IP will always give a range between 0.1 and 0.8, but then i have no value from any other data to calibrate it i.e core, mudlog or nearby well.
how can i go about it?

If you do not have any other data like fluid sample or pressure gradients from Wireline Formation Tester or Well Tests, you cannot calibrate the hydrocarbon density output from IP. It now becomes a judgment call, which will depened on the expertise and experiece in well log interpretation. Any software like IP is a number crunching machine, which will churn out numbers like shale volume, porosity, water saturation etc based on input parameters. All these need to be reconciled with the skill in interpretaion of well log data, especially log motif interpretation to come up with a reasonable evaluation. Of course, differentiating between gas, oil and water should be relatively straight forward, However, to pin down the exact hydrocarbon density without any other supporting hard data will be difficult.

N-Dxplot

Hi Kokoyi,
please, what do think of the attachment?

Attachments

N-Dxplot.pdf

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Without knowing the lithology of the formation, I am not sure what I am looking at.
If the formation is sandstone, it is probably water or oil bearing shaly sand.
If the formation is either limestone or dolomitic limestone (or even pure dolomite) it could be gas/light hydrocarbon bearing formation.
Therefore, first you need to identify the type of formation and then use the appropriate lithology line to determine your fluid type, estimate the crossplot porosity, compute total porosity from density log if the matrix density is known.
To use the density log for computing total porosity, you will need to correct for gas/light hydrocarbon effect. This can only be done if you know the formation lithology.