Investigation of parameter estimation and impact of injection rate on relative permeability measurements for supercritical CO2 and water by unsteady-state method

Abstract:

CCS (Carbon dioxide Capture and Storage) is a promising option for mitigating climate changes. To predict the behavior of injected CO2 in a deep reservoir, relative permeability of supercritical CO2 and water of the reservoir rock is one of the most fundamental and influential properties. For determining the relative permeability, we employed the unsteady state method, in which the relative permeability is determined based on history matching of transient monitoring data with a multi-phase flow model. The unsteady-state method is relatively simple and short, but obviously its accuracy strongly depends on the flow model assumed in the history matching. In this study, we conducted relative permeability measurements of supercritical CO₂-water system for Berea sandstone with the unsteady-state method under a reservoir condition at a 1km depth (P= 9.5MPa, T = 44˚C). Automatic history matching was performed with an inversion simulator iTOUGH2/ECO2N for multi-phase flow system of supercritical CO₂, NaCl, and water. A sensitivity analysis of relative permeability parameters for CO₂ and water was carried out to better understand the uniqueness and the uncertainty of the optimum solution estimated by the history matching. Among the parameters of the Corey-type curve employed in this study, while the end-point permeability could be optimized in a limited range, the other parameters were correlated and their combinations were not unique. However it was found that any combination of these parameters results in nearly identical shapes of the curve in the range of CO₂ saturation in this study (0 to 60%). The optimally estimated curve from the unsteady-method was well comparable with those from the steady-state method acquired in the previous studies. Our experiment also focuses on the impact of injection rate on the estimates of relative permeability, as it is known that the injection rate could have a significant effect on fluid distribution such as viscous fingering with changes in the ratio of the viscous to the capillary forces (i.e., capillary number). It was found that the higher the injection rate, the more likely the increase of the relative permeability, suggesting that careful considerations should be given to the impact in injection rate on the estimates of relative permeability.