This technique ONLY applies in relatively high quality reservoirs and at some distance above the oil-water contact.
In poorer quality reservoirs, saturation varies considerably higher than the minimum as we approach the oil-water contact. The more rigorous method is to convert the capillary pressure versus water saturation graph to a height above free water versus saturation graph, and use the depth dependant data set to calibrate log derived water saturation.
The water saturation for a given core plug is taken from the graph (or associated data listing) at the height above free water that is appropriate for the well in question. Notice that each cap pressure curve has an associated porosity and permeability value. Low permeability and low porosity rocks have high natural water saturation.
In fact, it is possible for a rock to be 100% wet in the middle of an oil zone merely because the porosity is too low for oil to get into the pores. No water will be produced from these intervals because the irreducible water saturation is also 100%. The cap pressure curve at top right represents such a rock - it would have to be 180 feet above free water before it could take on even 1% oil saturation. Any similar rock closer to the water zone would be 100% wet, but adjacent layers in the same reservoir could have better rock properties (higher porosity) and therefore lower water saturation.
The best way to see the relationship is to crossplot porosity vs cap pressure water saturation at some arbitrary height above free water. If a reservoir is very thick, make several crossplots at different heights. Make similar plots for the computed log analysis results and compare them to the cap pressure crossplots. Data sets must be segregated by rock type or pore geometry to be meaningful.
typical plot for a sandstone in which porosity varies with shaliness
is shown below. Notice that the data follows a good hyperbolic
trend in the higher porosity and trails downward to a lower hyperbola
as porosity decreases, indicating a different rock type or pore
geometry. The data at extreme right with high porosity is from
the water zone.
Porosity vs saturation crossplot
An overlay of cap pressure derived data (not shown) would confirm or refute the log results.
First, be sure the two data sets are from similar rock types and that only one rock type is represented on each graph. If the trend lines defined by the hyperbolas are different, you must revise the log analysis (or discount the cap pressure data as "not representative").
This may involve changing any or all of the following: Vsh, PHIe, RW, A, M, N, temperature, gas correction logic, or the saturation model. Clearly there is no unique solution and an "eyeball" best fit is all you can expect.
Some analysts have tried to create depth plots of cap press water saturation based on porosity and height above free water to compare with log analysis results. This is a very difficult and seldom proves very much. The crossplot approach is a more statistical view and easier to defend.
SATURATION - HEIGHT CURVES
values for air-brine conversion to oil-water are:
Using reservoir (oil-water) Pc
It has been traditional to look at the minimum water saturation on a
cap pressure curve and to call it irreducible water saturation (SWir).
In the above example, we don't see the minimum until 600 to 800
meters above the oil -water contact, and this reservoir is only 30
meters thick. The true irreducible water saturation is much higher
than the minimum on the graph because we are so close to the
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