The impact of rock pore structure on Co2 relative permeability

Abstract

Abstract Co2 relative permeability is a critical parameter affecting many aspects of Co2 injection for Enhanced Oil recovery and Co2 storage including; injectivity and trapped phase saturation. In this study, we use measured Co2 - brine relative permeability data available in the literature to study the behaviour of the data obtained for various rocks. These measured Co2 relative permeabilities show large variations in the values of relative permeability and also in the trend of the relative permeability curves. We identify the rock internal structure or quality as a controlling factor with considerable impact on Co2 relative permeability and we offer an explanation for the observed variation in Co2 relative permeability behaviour. We use a pore network model with different pore and throat distributions to verify the effect of rock pore and throat distributions on Co2 relative permeability. Based on our definition, a normal pore-throat distributions with similar connection produces a regular Co2 relative permeability curve shape which gives a high Co2 injection rate whereas in an abnormal pore-throat distribution with dissimilar connection, it is observed that the Co2 relative permeability curve shape is almost vertical. We extended the work to the investigation of the impact of the rock internal structure on the Co2 injection characteristics particularly on Co2 injection rate. We found that normal pore-throat distributions with similar connection result in much higher Co2 injection rate than do the abnormal pore-throat distributions with dissimilar connection. The results of this study will allow us to identify rocks that would be more suitable for Co2 injection (e.g., higher injectivity requiring lower number of injection wells) on the basis of the structure and distribution of the pores inside the rock. Introduction and Objective. In most petroleum engineering literatures, the relative permeability of Co2 has been studied for each formation separately and the main factors considered to affect the Co2 relative permeability are; fluid saturation, hysteresis and interfacial tension. As for a group of formations with different rock types, the difference in Co2 relative permeability curves is mainly attributed to rock type parameters. However, it has been found that even in a set of samples extracted from different formations in the same rock type or from a single formation, there is diversity in Co2 relative permeability curves. Rock pore structure or quality has been assumed to be responsible of the observed disparity, but no detailed explanation has been offered as to how it could results in different Co2 relative permeability curves for a set of formations in the same rock type. In this work, we are introducing an improved concept of pore and throat distribution, which will be used to interpret the observed differences in Co2 relative permeabilities.