Comparison of relative permeability–saturation–capillary pressure models for simulation of reservoir CO2 injection

• Six relative permeability–saturation–capillary pressure models are compared for supercritical CO2 injection into sandstone reservoirs.
• Depending on the model, large variations in plume extent and saturation distribution are predicted.
• Use of relative permeability models based on capillary pressure data or on empiricism may result in considerable uncertainty.
• The results demonstrate the permeability and porosity, relative permeability data need to be obtained.

Constitutive relations between relative permeability (kr), fluid saturation (S), and capillary pressure (Pc) determine to a large extent the distribution of brine and supercritical CO2 (scCO2) during subsurface injection operations. Published numerical multiphase simulations for brine–scCO2 systems so far have primarily used four kr − S − Pc models. For the S − Pc relations, either the Brooks–Corey (BC) or Van Genuchten (VG) equations are used. The kr − S relations are based on Mualem, Burdine, or Corey equations without the consideration of experimental data. Recently, two additional models have been proposed where the kr − S relations are obtained by fitting to experimental data using either an endpoint power law or a modified Corey approach. The six models were tested using data from four well-characterized sandstones (Berea, Paaratte, Tuscaloosa, Mt. Simon) for two radial injection test cases. The results show a large variation in plume extent and saturation distribution for each of the sandstones, depending on the used model. The VG–Mualem model predicts plumes that are considerably larger than for the other models due to the overestimation of the gas relative permeability. The predicted plume sizes are the smallest for the VG–Corey model due to the underestimation of the aqueous phase relative permeability. Of the four models that do not use fits to experimental relative permeability data, the hybrid model with Mualem aqueous phase and Corey gas phase relative permeabilities provide the best fits to the experimental data and produce results close to the model with fits to the capillary pressure and relative permeability data. The model with the endpoint power law resulted in very low, uniform gas saturations outside the dry-out zone for the Tuscaloosa sandstone, as the result of a rapidly declining aqueous phase relative permeability. This observed behavior illustrates the need to obtain reliable relative permeability relations for a potential reservoir, beyond permeability and porosity data.