Spontaneous imbibition is an essential mechanism for recovering oil from low-permeability fractured water-driven reservoirs. To accurately capture the migration interface of oil-water two-phase flow under these conditions, this study employs phase field theory coupled with Cahn-Hilliard and Navier-Stokes equations. We conduct a numerical pore-scale investigation on countercurrent imbibition in low-permeability fractured porous media. The results show that pore-scale spontaneous imbibition can be divided into four stages. In the first stage, oil-water film is formed when oil contacts with water, and this contact line moves under the action of capillary force. In the second stage, the oil film at the end of the oil cluster ruptures to form isolated oil droplets. In the third stage, these oil droplets are surrounded by water and gradually transported outward. In the final stage, oil droplets accumulate in the fractures and are collectively expelled from the matrix. In the process of oil droplet migration, the phenomenon of sticking occurs under the influence of water extrusion and the internal structure of the matrix, which leads to the formation of residual oil. The increased complexity of open boundary and fracture development strengthens the imbibition effect by elevating the degree of spontaneous imbibition pore utilization, thus improving the oil utilization efficiency. The above findings can provide a numerical modeling reference for the study of spontaneous imbibition in fractured porous media, and at the same time, has some guiding significance for the development of low-permeability reservoirs.

The recovered fracturing fluid is generally high in salinity (close to 200 kppm), which is related to the diffusion of salt ions from shale reservoir to the fracturing fluid. However, it is not clear about the diffusion capacity of salt ions in different types. In this paper, the shale, tight volcanic and sandstone are selected as comparative study and a series of tests are carried out for the porosity, permeability and mineral composition. The results show that the shale immersing in fracturing fluid will cause ions dissolution and diffusion, which will increase the salinity of the fracturing fluid. The solution salinity increases rapidly in the early stage and gradually slows down in the later stage. The salinity of the fracturing fluid has a linear relationship with the square root of time, so the slope of the curve can be used as a characteristic parameter to evaluate the ion diffusion rate. The process of dissolution and diffusion of salt ions will induce the expansion of micro-cracks, increasing the contact area between the fracturing fluid and shale and enhancing the solution salinity. The ion diffusion rate is positively related with the content of clay minerals and carbonate. The soluble ions include mainly ${\mathrm{SO}}_{\mathrm{4}}^{\mathrm{2}\mathrm{-}}$, ${\mathrm{Ca}}^{\mathrm{2}\mathrm{+}}$, ${\mathrm{Na}}^{\mathrm{+}}$ and ${\mathrm{K}}^{\mathrm{+}}$. The ${\mathrm{Na}}^{\mathrm{+}}$/ ${\mathrm{Cl}}^{\mathrm{-}}$ ratio is closely related to the content of clay minerals and carbonate minerals. It has a positive correlation with content of illite and chlorite, and a negative correlation with carbonate minerals, suggesting NaCl source from illite and chlorite. This study is significant for understanding the salinity characteristics of recovered fracturing fluid and evaluating the fracture network shape.

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.