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In conventional reservoir simulators, relative permeability curves are usually corrected for different values of surface tension using Coats correlation. Based on a research work in Heriot-Watt University, it was concluded that high rates near well bore in condensate reservoirs cause the enhancement of relative permeability of condensates and gas. It was also suggested to consider capillary number instead of surface tension for correction of relative permeability curves. Also, in condensate reservoirs, in contrary to
dry gas reservoir, the negative effect of inertia
(defined as skin factor) is not constant but it is a function of rate.
In order to study the above phenomenon in a reservoir scale, a fractured condensate reservoir in Nar field was selected. The modeling of reservoir fluid was first constructed using an equation of state and then, relative permeability curves were obtained and corrected for surface tension only. By the reservoir simulation using Eclipse-100, we were able to obtain a good match between pressure drop versus rate in simulation and a
pressure-flow test in one of the wells. Using
the tuned model and by changing different skin factors and drainage radii, we obtained a fairly good match in other wells, as well. Then we investigated different rates and observed no match between simulation and actual test data. Therefore, we concluded that in reservoir scale, it is necessary to correct the relative permeability curves for the effect of rate in condensate reservoirs.