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The core pore structure of the target shale oil block was finely characterized using scanning electron microscopy， and a microscopic numerical model of the pore-scale core was constructed to elucidate the intrinsic mechanisms and the main controlling factors of spontaneous imbibition of fracturing fluid within the complex pore space of shale. On this basis， research was conducted on spontaneous imbibition within the fracture-matrix system. The Navier-Stokes （N-S） equations were coupled with the level-set method to track changes in the oil and water interface， thus clarifying the oil and water two-phase flow characteristics and evaluating the efficiency of spontaneous imbibition under the influence of the wettability， viscosity ratio of oil and water， and interfacial tension. The research results revealed that large and small intercommunicating pores in shale form intricate microscopic displacement units under capillary action. When the rock wettability presents a water-wet state， water preferentially infiltrates from the fracture into the smaller pores， expelling oil from larger pores into the fracture， and the produced range of crude oil within the matrix pores is wider， resulting in higher spontaneous imbibition efficiency. When the rock wettability turns oil-wet， crude oil within the small pores cannot be produced during spontaneous imbibition， while the water invades from larger pores， causing crude oil to be displaced from other large pores. This results in a lower spontaneous imbibition efficiency and a small range of crude oil produced in the matrix pores. The spontaneous imbibition in the initial phase is faster but gradually slows over time. Stronger water wettability of shale indicates a lower viscosity ratio of oil and water and higher interfacial tension， resulting in a wider range of crude oil produced within the matrix pores and a cumulative efficiency of spontaneous imbibition of more than 15%.

CO2 applications for enhanced oil recovery and storage in continental shale reservoirs are promising, and there is a need to evaluate the impact of porous structure on oil–water two-phase flow under CO2 environment. In this study, first, digital cores of quartz-rich, carbonate-rich, and clay-rich shales are established using Focused Ion Beam Scanning Electron Microscopy scanning data processed through generative adversarial networks. Subsequently, the pore networks generated by digital cores are quantitatively analyzed using the generalized extreme value distribution. Finally, pore network modeling is carried out to elucidate the effect of porous structural differences on oil–water flow considering CO2 dissolution and capillary forces. The results show that quartz-rich shale, characterized by nanopore intergranular dominance and the highest pore network connectivity, demonstrates the highest relative permeability of the oil phase. Carbonate-rich shale exhibits intermediate relative permeability of oil phase, while clay-rich shale exhibits the worst. The dissolution of CO2 reduces oil–water interfacial tension and oil viscosity, enhances oil mobilization within nanopores, and notably increases the relative permeability of the oil phase. The permeability of the oil phase is governed by pore structure, displaying positive correlations with core heterogeneity, pore radius, coordination number, and throat length, and negative correlations with throat radius. [ABSTRACT FROM AUTHOR]

Based on the CO2-WAG (water-alternating-gas) flooding for conventional reservoirs, CO2-WAG huff-n-puff in shale reservoirs is proposed. To clarify the phase behavior and fluid flow of oil–CO2–water in the CO2-WAG huff-n-puff process, a series of experimental studies are conducted under different injection sequences of CO2 and water. The results show that the saturation pressure of the oil–CO2–water systems is lower than that of the oil–CO2 systems since a portion of the CO2 is dissolved in water. In addition, CO2 injection followed by water can significantly reduce the dissolution of CO2 in the water. CO2 and water preferentially flow into the macropores and bedding fractures of the oil-saturated cores at the injection stage, and the oil in mesopores and micropores reflows into macropores and bedding fractures at the soaking stage. At the depressurization production stage, the oil in mesopores and micropores is gradually extracted. Compared to water injection followed by CO2, injecting CO2 first can avoid the barrier effect caused by the subsequent injection of water and promotes oil flow into mesopores and micropores in the matrix. At the end of production, the oil recovered from water injection followed by CO2 mainly originates from macropores, while that from CO2 injection followed by water primarily comes from mesopores. [ABSTRACT FROM AUTHOR]

As the exploration and development of domestic shale gas continue, the complex incidents we encountered during drilling are also increasingly prominent. For the shale formations which is leaky and have complex lithology in South China, MPD is necessary to learn to drill through the complicated shale interval in a fast, safe and efficient manner and to break these common technical challenges of drilling. Currently, southern Yangtze region mainly develops two sets of shale formations, Silurian Longmaxi and Cambrian Niutitang. However, there are less pure shale section, complicated lithology and serious fragmentation. According to the data of shale gas drilling, the limy, silty and siliceous shale is often met during drilling, frequently accompanied with overflow and lost circulation. For the target interval with thickly developed shale bed, the density window of drilling fluid is small and the well wall is extremely unstable. According to the lithologic development of shale bed, technical characteristics of MPD, lab analysis, current MPD supporting equipment and other relevant factors, the MPD in bottom hole constant pressure method can be used to drill through the large and complicated shale interval. [ABSTRACT FROM AUTHOR]