Application of Material Balance and Volumetrics to Determine Reservoir Fluid Saturations and Fluid Contact Levels

Abstract A methodology was developed to determine residual saturations in a reservoir from fluid contact measurements and to forecast future contact movement. The methodology is based on the remaining volumes of fluid in the reservoir. At any given time, the remaining volumes of fluid (oil, gas and water) can be determined from known pore volumes, fluid contacts and saturations. The remaining fluid volumes can also be determined from material balances. The volumetric and material balance calculations are equated to solve for either the unknown saturations or the location of the fluid contacts. To apply the method, production, injection, pressure, fluid property, pore volume versus depth and initial fluid contact data are required. The methodology was demonstrated on the Westerose D-3 Pool. Residual saturations were determined to be: Swi = 6%, Sgc = 4%, Sorw = 25%, Sorg = 16%, Sgt = 23% and Sorwg = 13.5%. A history match of the historical contact levels for the Westerose Pool was obtained with an average absolute deviation of 2.0 m, which was within the measurement error. Contact movements were also forecast from 2000 to 2003. While there were no reported contact measurements in this period, the observed decline in oil rates was consistent with the predicted oil zone thickness. Introduction Reservoir simulation and analytical models require reservoir data, including: production, injection and pressure history; fluid properties; rock properties (porosity, permeability, water saturation, gross pay, net pay, top of structure); rock-fluid properties (relative permeability, capillary pressure); well locations and perforation schedules; and, contact (water-oil and gas-oil) measurements. Usually, the greatest uncertainty is in the rock properties and the rock-fluid properties. This paper focuses on rock-fluid properties; particularly, end point or residual saturations such as residual oil saturation to water displacement (Sorw), gas displacement (Sorg) and gas displacement followed by water displacement (Sorwg). These saturations limit the maximum oil recovery from a reservoir. The end point saturations are usually determined from laboratory analyses of core plugs. However, these core plugs are sometimes altered during handling, sampling and preparation. Another problem is that the best core often turns to rubble and is not retrieved. In addition, core sample size is of the order of one billionth of reservoir scale and if the reservoir is heterogeneous, a set of relative permeability curves derived from laboratory analysis may not represent the actual reservoir end point saturations. In theory, more representative field-scale saturation end points can be determined for reservoirs with fluid contacts from fluid contact movement data. Batycky et. al.(1) discussed using gas contact measurements to determine trapped gas saturations (Sgt). Their method involves equating volumetric oil- and gas-in-place to material balance oil- and gas-in-place and solving for the unknown Sgt. However, to the authors' knowledge, a generalized formulation of this method has not been developed. As well, such a method has yet to be adapted to forecast contact movement, given known residual saturations. The objectives of this paper are:to develop a method for determining residual (end point) saturations from contact measurements; and,to develop a method to forecast contact movement in a reservoir once the end point saturations are known.

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