Study on the oil-water two-phase flow characteristics of tight reservoir based on digital core technology

Abstract

Abstract Tight reservoirs are characterized by low porosity, low permeability and complex pore structures, resulting in poor waterflood recovery efficiency. Existing microscale two-phase flow studies are mostly based on two-dimensional geometric models, and the physical mechanism of fluid-solid coupling effect on flow behavior remains insufficiently understood. In this study, a three-dimensional digital core model of real tight sandstone was constructed using CT scanning and digital image processing techniques, and a phase-field mathematical model of oil-water two-phase flow considering bidirectional fluid-solid coupling was established, with its accuracy verified by classical capillary imbibition experiments (maximum relative error < 3.5%). The results show that the pore radius and throat radius of tight sandstone both follow lognormal distribution, with an average coordination number of 5.13, a fractal dimension of 2.37, and 76% of throats distributed in the 0-9 μm range. Under fluid-solid coupling, the relative permeability at the isosmotic point of the small-throat pore-type model decreases by 32.4%, significantly higher than the 18.7% decrease of the large-throat pore-fracture model. Water phase preferentially displaces oil along pore throats with low flow resistance, large pore size and spatial orientation parallel to the seepage direction. This study innovatively combines three-dimensional real digital core with bidirectional fluid-solid coupling phase-field method, quantitatively reveals the stress sensitivity difference mechanism between different pore structures, and elucidates the capillary-viscous force competition mechanism of fingering formation in tight reservoirs.