After long-term waterflooding in offshore oilfields, the remaining oil becomes highly dispersed and discontinuous. To address the limitations of classical waterflooding theory in describing the effects of microscopic oil occurrence and stress differences on oil-phase flow, this study investigated oil–water two-phase flow during heavy-oil waterflooding using core samples from the Bohai Oilfield. The evolution of the oil-phase starting pressure gradient at different water-cut stages was measured through core two-phase steady-state displacement experiments. By combining in situ core CT scanning with pore-scale phase-field simulations, the multi-form start-up mechanisms and microscopic causes of the oil phase were clarified. The fractal characteristics of the reservoir pore structure were further incorporated to establish a calculation method for the multi-form start-up resistance of the oil phase. The results show that, as the water cut increases, the starting pressure gradient of the oil phase exhibits a nonlinear increasing trend. At a water cut of 90%, the oil-phase starting pressure gradient is approximately 7–8 times that of the pure oil phase. Meanwhile, the oil phase gradually transforms from a continuous phase to a discontinuous phase, with a smaller pore radius and a larger surface area per unit volume. Owing to the Jamin effect, capillary force exerts a stronger influence on oil-phase flow, resulting in a significant increase in the starting pressure gradient during the ultra-high water-cut stage. These findings provide a pore-scale explanation for the increase in oil-phase starting pressure gradient during ultra-high water-cut waterflooding and offer a theoretical basis for the sustainable development of mature offshore oilfields.
Sun et al. (Wed,) studied this question.