Spontaneous imbibition in shale is commonly observed during and after hydraulic fracturing. This mechanism greatly influences hydrocarbon recovery in shale plays, therefore attracting increasing attention from researchers. The number of related publications is increasing. In this review, we summarize the recent advances in shale spontaneous imbibition from three aspects, namely, conventional spontaneous imbibition models, common experimental methods, and key mechanisms that need to be focused on. The major influencing factors on the shale imbibition process are discussed, and promising future works are presented on the basis of the merits and demerits of the recent studies. This study discusses the mechanisms of shale-liquid interaction, the complexity of multiphase flow in shale plays, and highlights the achievements and challenges in shale imbibition research.

Fully understanding the mechanism of pore-scale immiscible displacement dominated by capillary forces, especially local instabilities and their influence on flow patterns, is essential for various industrial and environmental applications such as enhanced oil recovery, ${\mathrm{CO}}_{\mathrm{2}}$ geo-sequestration and remediation of contaminated aquifers. It is well known that such immiscible displacement is extremely sensitive to the fluid properties and pore structure, especially the wetting properties of the porous medium which affect not only local interfacial instabilities at the micro-scale, but also displacement patterns at the macro-scale. In this review, local interfacial instabilities under three typical wetting conditions, namely Haines jump events during weakly-wetting drainage, snap-off events during strongly-wetting imbibition, and the co-existence of concave and convex interfaces under intermediate-wet condition, are reviewed to help understand the microscale physics and macroscopic consequences resulting in natural porous media.

Spontaneous imbibition plays an important role in many practical processes, such as oil recovery, hydrology, and environmental engineering. The past few years have witnessed a rapid development in the mechanism analysis and industry applications of spontaneous imbibition. In this paper, we focus on boundary conditions of spontaneous imbibition, which has important effects on the imbibition rate and efficiency. Various boundary conditions are first generated using different capillary model and introduced focusing on the fundamental physical mechanisms. Then, the studies of spontaneous imbibition in core scale are reviewed. The feature is discussed and the relative permeability for co- and counter-current imbibition is analyzed. The scaling of imbibition data with different boundary conditions is also presented by combination of experimental and numerical methods. An analytical model to describe spontaneous imbibition is provided at the end.

The relationship between the capillary pressure and saturation is a primary factor to describe and simulate the multiphase flow. This relationship is also fundamental to understand the characteristics of oil and gas reservoirs and make the reservoir development plan. Traditionally, the capillary pressure is measured under the equilibrium process; however, this equilibrium is hard to establish when the multiphase flow is expected in low to tight permeability porous media, and the capillary pressure is dynamic. This laboratory study conducts specially designed dynamic displacement experiments to examine the dynamic effect in capillary pressure in ultra-low permeability sandstone oil reservoirs. The dynamic capillary pressure, the dynamic relative permeabilities, the dynamic coefficient and the change rate of water saturation are obtained. Results show that the dynamic coefficient is relatively larger in ultra-low permeability reservoirs compared with that in high to low permeability reservoirs. Difference between the dynamic and the steady capillary pressures becomes more significant for less permeable porous media, with a higher dynamic coefficient and a stronger dynamic effect. Wettability advancement has been triggered during the dynamic displacement process, which is responsible for the water-wet rock before the displacement to be oil-wet during the displacement process. The difference between the dynamic and the steady relative permeabilities becomes obvious, and the dynamic effect in capillary pressure cannot be neglected when the permeability reaches ultra-low. The dynamic coefficient can reveal the shape of the displacement front.

After fracturing operations, a large amount of fracturing fluid is retained in shale fracture network, resulting in low flowback efficiency. This has been attributed to the imbibition of fracturing fluid into matrix pores. However, it is unclear how the imbibition mechanism is involved, what are its governing laws and controling parameters in fracture networks? Based on the three-dimensional water imbibition theory of matrix blocks, a fracture network model is established, and a number of dimensionless controling parameters are proposed and analyzed for flowback efficiency. The results show that the imbibition characteristics of fracturing fluid in fracture network are mainly determined by two dimensionless numbers; namely, dimensionless imbibition time, fracture width, and imbibition capacity. The dimensionless imbibition time characterizes the contact time between the fracturing fluid and shale formation, which negatively correlates to the flowback efficiency. The dimensionless fracture width is the ratio of the fracture width to the rock length, which is inversely proportional to the flowback efficiency. Smaller value of the dimensionless fracture width corresponds to larger contact area of fracturing fluid and shale, leading to a lower flowback efficiency. The dimensionless imbibition capacity depicts the capacity of shale reservoirs to imbibe fracturing fluid, which has a negative linear correlation with flowback efficiency. In addition, dimensionless time and fracture width are related to the fracturing operations, and are enhanced by increasing the shut-in periods and proppant concentration. Therefore, the flowback efficiency can be controlled by changing fracturing operations. The predictive method of the flowback efficiency established here is of great significance for reservoir damage analysis and flowback regime optimization.