Abstract

Absolute and relative permeability are key inputs into reservoir flow simulation. The other two key inputs are porosity and hydrocarbon saturation. Porosity can be, in principle, inferred from acoustic impedance if an impedance-porosity transform is available. Such transforms can be obtained from sonic, density, and porosity data at a well. Typically, a theoretical rock physics model is found to explain these data and then used to expand the impedance-porosity interpretation beyond the data range present in the well. Saturation volumes emerge from reservoir modeling itself if the initial distribution of fluids is specified. However, the permeability required to arrive at fluid distribution in the reservoir versus time and for given boundary conditions remains, by and large, unknown.

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