Capillary pressure is an important rock property, how it can be used to determine where does oil exist?
Suppose you have obtained representative capillary pressure (Pc) curve for your reservoir rock, and you know the free water level (FWL) (from MDT or wire line logs). Since Pc = ∆(d) g h --> h =Pc/ ∆(d) g which means instead of Pc vs Sw, you can plot 'Height above FWL' vs. Sw so that at each height you can determine water saturation. keeping in mind that at any point below FWL will have Sw=100%.
I hope this could be of any help.
"any point below FWL will have Sw=100%" says Ayman Hosny and that is true, but you can extend that rule to "any point below OWC will have Sw=100%, where OWC is the oil-water contact given by OWC = FWL - Pce/(g*∆(d)). In tight reservoirs like e.g. North Sea chalk with large entry pressures the difference between FWL and OWC may be large. The above is valid for Water wet reservoirs in drainage equilibrium.
Best regards
Niels Bech
Adding to what Ayman said, different rock classes have different Pc curves. Use the Pc for each rock class (function of porosity or permeability) and that should give you the initial fluid distribution in the reservoir.
Capillary pressure is used to determine the initial water saturation (wetting phase) in a reservoir. If you know the rock quality, namely porosity and permeability of the rock at a certain depth in the reservoir, you can use the capillary pressure (determined from the difference in densities between water and hydrocarbon and the height above the Free Water Level) to determine the initial water saturation of the reservoir at that particular depth. Saturation Height Function, based on Skelt Harrison, Leverett J funciton, etc, make use of capillary pressure and rock quality (porosity and permeability) to populate initial water sturation in static and dynamic reservoir models.
I have used various derivations of capillary pressure measurements to model water saturation above the free water level with varying degrees of success. Of course the greatest challenge is modelling the transition zone, where Sw can, in good quality reservoir, vary significantly in a few metres of the oil water contact or over greater thicknesses in lesser quality rock. Of course as noted by others entry pressures can be significant and large differences between the free water level and the oil water contact are often seen.
If one has confidence in the petrophysical evaluation of the electrical logs then a comparison of the modelled and evaluated water saturations should be attempted. This may pose a challenge in poorer quality reservoir.
As rock types can vary on a centimetre scale, it is important to understand the geology of the samples in relation to the make-up of the reservoir. Often a set of capillary pressures measurements are combined mathematically to create a J or Skelt function on the basis of a broad reservoir subdivision without any detailed knowledge of the underlying geology. This is can be an acceptable and pragmatic approach where rock types are heterogeneous even within reservoir subdivisions.
I have always adopted the routine of geologically describing the actual plugs used for measurement (not relying on contractor description) and in order to understand the applicability of the plug sample to the reservoir as a whole. This allows one to build appropriate saturation-height relationships in more homogeneous subdivisions and also remove plugs that are unrepresentative (without introducing bias) that could affect the derivation of the saturation height relationship.
homepages.see.leeds.ac.uk/~earpwjg/PG_EN/CD%20Contents/.../Chapter%204.PDF
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