Dynamic evolution and fluid micromigration characteristics of shale reservoirs via forward modeling with physical–numerical simulation

The method of combined physical and numerical simulation effectively addresses microscale fluid migration in unconventional reservoirs. We conducted a physical simulation on artificial shales with organic-rich and organic-poor laminae. Using microcomputed tomography (CT), high-pressure mercury intrusion, and organic geochemical testing, we estimated fluid volumes within the laminae and characterized seepage pathways. Two-phase flow numerical simulations using the volume of fluid (VOF) model at a three-dimensional scale revealed that hydrocarbon generation overpressure and pore displacement pressure significantly influence fluid migration. When the vitrinite reflectance (Ro) values are between 0.8 % and 1.10 %, the overpressure in organic-rich lamina (ORL) exceeds the displacement pressure in the organic-poor lamina (OPL), leading to the micromigration of oil-dominated particles with a maximum saturation of 19.92 %. As hydrocarbon generation continues, the shale-oil reservoir becomes enriched. When Ro values range from 1.10% to 1.45 %, thermal cracking transitions the enriched shale-oil reservoir to a depleted state. At Ro values of 1.45%–2.25 %, gas-dominated flow migrates to the OPL due to oil gasification, reaching a maximum saturation of 23.38 % and forming an enriched shale gas reservoir.