The amount of recoverable oil in an oil-water transition zone depends on the distribution of oil saturation as a function of depth, and the relationship between initial oil saturation in the transition zone (Soitz) and residual oil saturation in the transition zone (Sortz). Traditionally, it is assumed that Sortz is the same as the residual oil saturation in the oil column (Sor) above the transition zone. However, data in the literature show that residual oil saturation depends on initial oil saturation. So, residual oil saturation in the transition zone (Sortz) should be a function of initial oil saturation in the transition zone (Soitz). The relationship between Sortz and Soitz is referred to as a trapped oil relationship.

The purpose of this paper is to show recent experimental corroboration of the trapped oil relationship and to demonstrate the impact of the trapped oil relationship on reserves determination in oil-water transition zones. First, fundamental issues for appropriate selection of rock-fluid properties for characterizing transition zones are addressed. Graphical illustrations are presented to compare and contrast conventional methods for characterizing transition zones with an improved characterization method that requires additional rock-fluid property measurements.

Then, results from laboratory studies of recovery from transition zones are used to demonstrate features of the improved characterization method. These results show that oil in the transition zone is much more mobile and recoverable than is assumed by the conventional approach.

For these laboratory studies, unconsolidated packs of sand, glass beads, and plastic beads were used. The media were varied to observe the effects of wett ability and grain size on transition zone properties. It is believed that the variety of media qualitatively represent what would be observed for actual reservoir formations. Local saturations in the transition zones were correlated to gray level of video images of the surface of the packs. The laboratory methods for unconsolidated media could be extended in the future to reservoir rock (having much lower permeabilities) with centrifuge technology.

Finally, the effect of the trapped oil relationship on reserves determination is shown with an extended black oil simulation that incorporates the effects of relative permeabilities on reserves determination.


Numerical models for matching historical production and forecasting performance of hydrocarbon reservoirs rely heavily on numerous types of core measurements: porosity, absolute permeability, and formation compressibility, plus capillary pressure and relative permeabilities. Capillary pressure and relative permeability are of primary concern in this paper. Capillary pressure data translate to the hydrocarbon saturation profile as a function of height in a reservoir. Also, gradients of capillary pressures during displacement processes influence movement of fluids. Relative permeabilities provide information on fluid mobility and the amount of hydrocarbon recovery as a function of time.

Conventionally, primary drainage capillary pressure and waterflood relative permeabilities have been used to determine the depth of the lower productive limit of a transition zone, the percentage of hydrocarbon recovery, and the percentage of unrecoverable hydrocarbons from waterflooding. Here, a transition zone is defined as an interval that produces both oil and water during primary recovery. Transition zones affect

  • volumetric calculations of original oil in place,

  • simulation of oil recovery for various operational alternatives,

  • determinations of the spatial distributions of recoverable oil for well placement, completion interval determinations,

  • dimensions of the reservoir limits, and

  • the amount and distribution of unrecoverable oil by conventional methods.

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