Plain Language Summary
The relative permeability is a crucial parameter in a system where two
fluid phases exist simultaneously. For example, in carbon capture and
storage, relative permeability is important to assess the replacement
mechanism of the existing fluid in the reservoir (wetting fluid) by the
injected CO2 (non-wetting fluid). It is also an
important parameter in enhanced oil recovery fields, as high relative
permeability of oil indicates that the oil in the reservoir can be
extracted quickly. The relative permeability is temporally and spatially
varied by reservoir conditions (e.g., temperature). But currently, in
reservoir-scale fluid flow simulation, relative permeability is assumed
to be constant regardless of the different conditions. In this study, we
conducted simulations to calculate relative permeability in various
viscosity ratio (M ) and capillary number (Ca ) conditions.
We found that relative permeability changes dramatically in differentM and Ca conditions, and we further mapped relative
permeability on the diagram between M and Ca to predict
relative permeability accurately in various reservoir conditions. Our
findings can be useful to determine the suitable fluid properties to be
used in reservoir management and to accurately estimate fluid behavior
based on reservoir-scale simulation with variant relative permeability.