Abstract
Water flooding is widely used for recovering crude oil from unconventional reservoirs due to its economic feasibility. At reservoir conditions, the injected water is usually imbibed into fractured rocks, so-called spontaneous imbibition, providing a considerable driving force for enhancing oil recovery. In this work, spontaneous imbibition on a rock surface is investigated at high-pressure conditions, and its influence on tight oil recovery is revealed from a pore-scale perspective. Specifically, three typical core samples are selected and characterized to obtain their pore-size distribution by applying the NMR technique. These core samples are then saturated with crude oil and are submerged in formation water, which is filled in a high-pressure vessel. Oil recovery efficiency as well as the imbibition rate is consequently calculated for specific pores during spontaneous imbibition. Test results indicate that oil recovery from spontaneous imbibition is different in different pores depending on the petrophysical properties of the tight cores. That is, the difference in imbibition efficiency between small and large pores decreases as permeability and porosity increase in the core samples. In addition, as for core samples #1 and #2, the imbibition rate usually reaches a maximum at the initial imbibition stage. However, as for core sample #3, the maximum imbibition rate is far delayed due to high capillarity. This work may reveal the fundamental mechanism of the influence of spontaneous imbibition on a rock surface at high-pressure conditions on tight oil recovery from a pore-scale perspective.