Gas condensate reserves are increasing in size worldwide as more and more deep wells are drilled. Increased modeling efforts to optimize the performance from gas condensate reservoirs need accurate and reliable determination of condensate relative permeability curves. The use of nonrepresentative relative permeability curves may result in over/under estimates in performance predictions.
Laboratory measurement of relative permeabilities is the most common method used in relative permeability determinations. However experiments by using field representative cores and fluids at reservoir conditions are expensive and difficult to conduct. That is the reason why laboratory measured relative permeability curves are scarce and contradictory in nature.
On the other hand field automation data such as production rates and recoveries are usually available from the field. In this paper we propose a quick and reasonable method to estimate the gas and condensate relative permeabilities using this type of data. Our procedure is a modification of a method presented by Fetkovich et al. for black oil systems. Our modifications allow us to deal reasonably well with the nonuniform saturation distributions which play a unique role in the performance of gas condensate systems. The method requires flowing pressures, gas and condensate production rates and PVT properties of the condensate fluid. The new method was tested via simulation for a rich condensate fluid and it worked well in estimating the relative permeabilities. The major advantage of this approach is that the relative permeabilities calculated are representative of field performance. Hence the relative permeability curves obtained represent a naturally upscaled set of curves which can be used directly or as a guide in upscaling laboratory measurement curves.
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