Experimental investigations on spontaneous imbibition process applied in tight conglomerate oil reservoir

In this research, experimental studies were conducted to investigate the influences of permeability and surfactant solution on varying permeability cores in the spontaneous imbibition process. Totally, four types of experiments were implemented, namely, measurements of pore-throat distribution, contact angle, interfacial tension and lower limits of pore and throat size. The experimental results reveal significant variations in pore-throat size across the cores, ranging from as low as 0.61 nm to as high as 70.58 μm in the targeted core. With increasing concentration of surfactant solution, both the contact angle and interfacial tension decreased. Compared with formation water, the contact angle decreased from 48.36° to 23.75° and interfacial tension decreased from 23.92 to 9.69 mN/m for the surfactant solution injection with the optimized concentration of 0.20%. Experiments of spontaneous imbibition indicates that the imbibition process was dominated by the initial stage across all cores. The highest imbibition efficiency occurred in macropore (>10 μm) for cores #4 and #5 with low permeability. Mesopores (1 to 10 μm) consistently showed the highest contribution to oil production, confirming their central role in the tight conglomerate reservoir. With varying injection media, the lower limits of pore and throat size was measured using Nuclear Magnetic Resonance, and significant reduction from water phase to surfactant solution phase was investigated. Therefore, the oil recovery factor can be enhanced in the surfactant solution injection process. The findings can be used to predict the effect of permeability and surfactant solution on the tight conglomerate oil recovery process.