Characterizing flow behavior for gas injection: Relative permeability of CO2-brine and N2-water in heterogeneous rocks

We provide a comprehensive experimental study of steady state, drainage relative permeability curves with CO2‐brine and N2‐deionized water, on a single Bentheimer sandstone core with a simple two‐layer heterogeneity. We demonstrate that, if measured in the viscous limit, relative permeability is invariant with changing reservoir conditions, and is consistent with the continuum‐scale multiphase flow theory for water wet systems. Furthermore, we show that under capillary limited conditions, the CO2‐brine system is very sensitive to heterogeneity in capillary pressure, and by performing core floods under capillary limited conditions, we produce effective relative permeability curves that are flow rate and fluid parameter dependent. We suggest that the major uncertainty in past observations of CO2‐brine relative permeability curves is due to the interaction of CO2 flow with pore space heterogeneity under capillary limited conditions and is not due to the effects of changing reservoir conditions. We show that the appropriate conditions for measuring intrinsic or effective relative permeability curves can be selected simply by scaling the driving force for flow by a quantification of capillary heterogeneity. Measuring one or two effective curves on a core with capillary heterogeneity that is representative of the reservoir will be sufficient for reservoir simulation. Key Points: Drainage relative permeability is measured for CO2‐brine and N2‐water and scaled by capillary number The CO2‐brine system is very sensitive to capillary pressure heterogeneity Reservoir characterization should be performed on heterogeneous core samples