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INVESTIGATION OF RELATIVE PERMEABILITY AND CAPILLARY PRESSURE ON SANDSTONE ROCK SAMPLES
Abstract
The hydrocarbon migration in a porous rock after waterflooding is a complex process. Mathematical models were developed through years to simulate the fluid flow, but input data from experimental works are needed to calibrate equations and/or trends. Routine and special laboratory analysis and measurements allow to determine the crucial input parameters. Knowledge of mineralogy, porosity, permeability, capillary pressure and relative permeability helps the reservoir engineers to predict and manage the future oil recovery. Relative permeabilities relationships as a function of fluids saturation are one of the most important parameters for describing multiphase flow processes in reservoir rocks. When direct laboratory tests are not available for investigating oil-water multi-phase flow in rocks, then indirect prediction techniques using relative permeability functions are widely used, e.g. from capillary pressure test. However, the measurement of capillary pressure is demanding and time-consuming. In this work, the measurements of drainage capillary pressure curves in conjunction with relative permeability calculation on sandstone core samples under reservoir condition were performed. State-of-the-art laboratory equipment able to work with actual reservoir fluids was used. Three experiments were conducted on Carpathian rock samples at 70пїЅC with crude oil and distilled water to eliminate influence of salinity on the results under overburden pressure of 4000 psi. Placement of semi-permeable water-wet porous plate membrane on lower end of plug guaranteed that only one phase was able to pass through each core sample end. After registration of capillary pressure points, best fitting curves were created from genetic programming (GP) and numerical integration was used in conjunction with genetic programming to generate full relative permeability curves.
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