Compositional Numerical Modelling In Naturally Fractured Reservoirs

Abstract Recent improvements in the speed of numerical compositional simulators has made it possible to use a large number of gridblocks to model condensate reservoirs, volatile reservoirs, and gas injection projects. This paper discusses techniques for choosing pseudo components so as to use 4 – 5 pseudo components for the simulations. It also discusses the condensate dropout in the reservoir and its effect on the productivity of individual producing wells. The methods for characterizing fracture networks in a naturally fractured reservoir are presented and other parameters which affect hydrocarbon recovery are discussed as part of a parametric study. INTRODUCTION In recent years wells have been drilled to greater depths, resulting in the discovery of gas condensate reservoirs and volatile oil reservoirs at relatively high temperatures. Recently a large amount of research has been conducted to investigate productivity from these oil reservoirs. This research has investigated how to tune an equation of state so as to match the actual phase behavior which is occurring within a reservoir. Studies have reported on the effects of interfacial tension and velocity on gas-oil relative permeability curves. These studies indicate that bench type gas-oil and water-oil relative permeabilities are not applicable to predicting the performance of individual wells in gas condensate reservoirs. Well test data and recent advances in well logging procedures using well-bore imaging techniques have provided tools to better characterize the fracture system which exists in naturally fractured reservoirs. These data have been used in conjunction with stochastic models to describe the fracture network inside of these reservoirs. A parametric study using a number of variables was conducted for this paper. The results from this parametric study are useful in history matching to determine those parameters which, when adjusted, will have the greatest effect on the performance of the reservoir. This study will also suggest modifications which need to be made to numerical simulators so as to better simulate the actual mechanism which are occurring in gas condensate reservoirs. MECHANISM OF FLOW IN NATURALLY FRACTURED RESERVOIRS Fluid flow in naturally fractured reservoirs differs significantly from that in a single porosity system. The numerical simulator breaks the reservoir into two different systems, one a system of matrix blocks which mayor may not have capillary contact and a network of fractures. The simulator basically assumes that most of the flow to the wells will occur through the fracture network which contains a relatively small fluid volume, but high permeability, and that the bulk of the hydrocarbon fluids are contained within the matrix blocks. As reservoir pressure is depleted, the fluids are expelled from the blocks into the fracture system which conveys them to the producing wells. Gas condensate reservoirs initially are at pressures at or above the dewpoint. Once the pressure has been depleted below the dewpoint, liquid will condense and two phases will be present. Once these two phases are present the liquid will not flow in either the matrix or the fracture system until a critical condensate saturation is obtained.