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

Abstract

Abstract Physics of multiphase flow in porous media heavily relies on the concept of relative permeability. Moreover, relative permeability is an important input parameter for any numerical reservoir simulation representing multiphase flow in porous media. Relative permeability curves are also 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 models. In this study, we are experimentally focusing on 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 values up to 10000 psi, and temperatures up to 200 °C. For this study we limit the fluids to a model oil and brine, such as n-hexane and sodium iodide aqueous solution. Selected porous media is a core cut from Berea sandstone rock. Core dimensions are 12 inch length and 1.5 inch diameter. Such choice of simple fluids and the rock is done to avoid any secondary effects of fluid-rock interactions, such as wettability alteration, asphaltenes, and gas-dissolution, so that we can clearly identify the impact of the pressure on the outcome. Moreover, by using simple fluid systems we avoid fluid-fluid interactions, miscibility and interaction of phase behavior and flow. We run the relative permeability scans at a fixed temperature (isotherm) and at several pressure values (isobars), such as 2000, 4000, 6000, and 8000 psi. The resulting relative permeability curves are then compared to each other to examine the impact of pressure. There are two main possible outcomes for this study. The first outcome is that there is no significant effect of pressure on relative permeability curves. Such an outcome confirms the generally practiced processes, where fixed relative permeability curves are used for the entire simulation study. The second possible outcome of the study is that there is a considerable effect of pressure on relative permeability curves. Such an outcome fundamentally questions the common assumption of pressure independent relative permeability curves that is broadly applied in the industry. Regardless of the two main outcomes of the study, both will contribute to a better understanding of the multiphase flow in porous media under high-pressure/variable pressure conditions. To be able to perform the analysis more diligently, we are also observing the in-situ phase saturations by scanning the core using gamma-ray. Such monitoring of the core, simultaneous with relative permeability measurements, will improve the quantification of the in-situ phase saturations at realistic conditions. Systematic analysis of the pressure effect on 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 pressure effect on relative permeability under well controlled laboratory conditions. The outcomes of this paper may help engineers to improve their model predictions during field development and therefore decision-making processes.