Quantification of the Impact of Pore Pressure on Relative Permeability Curves Utilizing Automated Unit with Gamma Ray Scanning Capability

Abstract

Physics of multiphase flow in porous media heavily relies on the concept of relative permeability. Moreover, relative permeability is an integral input parameter for any numerical reservoir simulation representing multiphase flow in porous media. Relative permeability curves are often used as tuning parameters to match the elements of the production history. Many times it is possible to see a single set of fixed relative permeability curves applied for the entire complex large-scale reservoir simulation. In this study, we are experimentally investigating the effect of high pressures on relative permeability curves. We are using a state-of-the-art custom-made relative permeability steady-state flow system with a gamma-ray source. The setup is capable of handling pressures from atmospheric up to 10000 psi, and temperatures up to 200 °C. For this paper, we use a model oil and brine, such as n-hexane and sodium iodide aqueous solution. The porous media is Berea sandstone rock. Such choice of simple fluids is done to avoid any secondary effects of fluid-rock interaction, such as wettability alteration, asphaltenes, and gas-dissolution. Moreover, by using simple fluids ystems we avoid fluid-fluid interactions, miscibility and interaction of phase behavior and flow. We run the relative permeability scans at fixed temperature (isotherm), and at several pressure values (isobars), such as 100, 2000, 4000 psia. The relative permeability curves are then compared to each other to examine the impact of pressure. There are two main possible outcomes for this study. First outcome is that here is no significant effect of pressure on relative permeability curves. Such outcome confirms the status quo where a fixed relative permeability curves are used for the entire simulation study. The second possible outcome of the study is that there is considerable effect of pressure on relative permeability curves. Such outcome fundamentally questions the common assumption of fixed relative permeability curves that is broadly applied in the industry. Regardless of the two main outcomes of the study, all will contribute to better understanding of the multiphase flow in porous media under high-pressure/variable pressure conditions. Moreover, we are able to observe the in-situ phase saturation propagation with radioactive scanning of the core. Such monitoring of the core simultaneously with relative permeability measurements will shed the light in the in-situ phase propagation at realistic conditions. Systematic look and the amount of data that addresses the pressure effect on the relative permeability is extremely scarce in the literature, even though the pressure varies significantly in the reservoir during the lifetime of the field. Therefore, it is essential to understand the pressure effect on the relative permeability under well controlled laboratory conditions. The outcomes of this paper may help engineers to improve design, simulation, and predictions during field developments and decision-making process.