Handling Fluid Properties in Reservoir Simulation Studies

Abstract The reservoir engineer today is able to evaluate and predict reservoir performance much more precisely through the application of multi-dimensional models to mathematically simulate reservoir behavior. The additional precision requires more attention to the handling of reservoir fluid properties than the traditional material balance studies. This paper discusses the problems involved and reviews several techniques which have been employed to achieve improved accuracy in the application of fluid properties in reservoir studies. The techniques presented attempt to consider variations in properties presented attempt to consider variations in properties spatially within the reservoir as well as variations with pressure and composition. Reservoir Bubble Point Rather than computing one point in time at which the overage reservoir pressure declines to an average reservoir bubble point pressure, model studies reflect the more realistic situation in which local areas become saturated while other areas may remain undersaturated — at least for a time. By their nature, model studies reflect this type of situation and the handling of fluid properties in the model must be appropriate to the situation. The normal concept of average reservoir saturation pressure disappears in model studies. Figure 1 shows pressure disappears in model studies. Figure 1 shows how a reservoir may be sub-divided into blocks for a two-dimensional study. The pressure and saturation and the resulting fluid flow are calculated at each block over short time steps. As an area of the reservoir becomes saturated and solution gas is released from the oil, that evolved gas may migrate away from the area where it is released. If the pressure in that area increases, even temporarily, the oil must then be treated as undersaturated. Also, the evolved gas may tend to re-saturate the oil in another area of the reservoir. The type of problem encountered in this type of situation may be illustrated by referring to Figure 2 which shows a typical formation volume factor curve. If the pressure declines in one part of the reservoir to a point well below the original bubble point, the correct formation volume factor would be determined on the "saturated oil" portion of the curve.