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       Water Saturation Calibration          Calibrating Moveable and Residual Oil

CALIBRATING Water Saturation
Water saturation can be calibrated by comparing calculated log analysis results to capillary pressure data from special core analysis. The minimum water saturation from the cap pressure curve should agree with the log analysis, provided the cap pressure curve comes from a plug with the same porosity as the log analysis. Typical capillary pressure curves are shown below.

Capillary pressure curves
for various rock types ==>

The minimum 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 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, lower water saturation) 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.

A 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.

Water and oil saturation on conventional core analysis has little quantitative meaning when the core was drilled with water based mud. Invasion of drilling fluid makes a core look a lot like the invaded zone, and flushing of oil can be more or less complete. Bleeding oil in a core is not usually a good sign; if the zone was any good, the moveable oil should have been moved.

A change from little or no residual oil to more might indicate a gas-oil contact; from some to none may indicate an oil-water contact. The amount of residual oil can sometimes be correlated to original oil saturation. Oil saturation in a core drilled with oil based mud may be close to original oil saturation, but some oil mud systems do invade the, giving a false impression of good oil saturation.

Sample descriptions and mud logs will indicate the presence of oil or gas at certain depths in a well. This data cannot help in quantitative calibration, but is useful in targeting zones for further study.

Moveable Hydrocarbon EXAMPLE
This example shows a comparison of residual oil from core in a depleted zone (M1 interval) and in a bypassed zone (M3 interval). The Sor from core equals (1 - SW) from log analysis, so there is no moveable oil in the M1. The close match suggests that most of the saturation parameters (A, M, N, RW@FT) and porosity are reasonably well calibrated. Since the world abounds with depleted zones (most are well known to the well operators) this test should always be made to confirm SW parameters where ever core data is available.

Computed results for carbonate example. Note higher water saturation on M1 compared to M3. M3 is bypassed pay. M1 is depleted oil. Dots are core data. Note that residual oil on core in M1 matches calculated
Sor = (1 - SW). In M3, Sor on core is less than (1 - SW) from log analysis, so there is moveable oil in
 M3 interval but not in M1. Calibration to core permeability needs more work to get a decent match.

Bakken “Tight Oil” example showing core porosity (black dots), core oil saturation (red dots). core water saturation (blue dots), and permeability (red dots). Note excellent agreement between log analysis and core data. Separation between red dots and blue water saturation curve indicates significant moveable oil, even though water saturation is relatively high..
 

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