Effect of dynamic displacement and imbibition on oil recovery in tight oil reservoirs: pore-scale simulation

Tight oil reservoirs are widely treated as a promising alternative for future hydrocarbon extraction due to their large reserves and high development potential. After volumetric fracturing, various reservoir spaces including hydraulic fractures, micro fractures and micro-nano pores coexist, making the oil recovery mechanism complex. However, the effect of dynamic displacement and imbibition on oil recovery in tight porous media are still lack of studies. In this study, three types of tight rock samples were imaged via high-resolution computed tomography (CT) to construct three-dimensional digital models. The dynamic displacement-imbibition process is simulated using a multiphase Shan-Chen Lattice Boltzmann model (SC-LBM) to quantify the contributions of displacement and imbibition to oil droplet mobilization. Results show that, compared with spontaneous imbibition, dynamic displacement-imbibition achieves higher oil recovery. The breakthrough of oil-water front is occurs earlier, resulting in a decrease in ultimate oil recovery. For cores with permeabilities of 8.67 mD, 6.44 mD, and 2.34 mD, the contribution of displacement to oil droplet mobilization is 52.63%, 49.52%, and 40.62%, respectively, while the contribution of imbibition is 47.37%, 50.48%, and 59.38%, respectively. Increasing the injection rate from 0.02 ml/min to 0.1 ml/min reduces ultimate recovery in Class I and Class II rocks, from 58.63% to 55.21% and from 48.85% to 46.18%, respectively, but increases it in Class III rocks, from 38.45% to 41.80%, due to variations in viscous and capillary-driven forces. Interfacial tension, oil-water viscosity ratio, and fractures strongly influence displacement-imbibition oil recovery, with differing effects on displacement and imbibition. Lower interfacial tension reduces imbibition capacity, with the average contribution of imbibition in the three rocks decreasing by 35.09%, but enhances displacement capacity. A higher viscosity ratio increases oil flow resistance, thereby reducing both recovery and the contribution of imbibition; this effect is most evident in Class II rocks, where the imbibition contribution decreases by 18.04% and recovery drops by 23.32%. The presence of micro-fractures enlarges water-matrix contact and reduces flow resistance, increasing recovery while decreasing the relative contribution of imbibition.