Shale reservoir wettability is a critical parameter governing the occurrence, migration and recovery efficiency of oil and gas. This paper systematically reviews the recent advances in shale wettability assessment methods and their influencing factors. These factors are evaluated by various methods, each offering distinct advantages and limitations. The contact angle method provides rapid macroscopic wettability assessment but is constrained by the properties of mineral and fluid. Spontaneous imbibition effectively characterizes macroscopic wettability but is time-consuming owing to the inherently low porosity and permeability of shale formations. Nuclear magnetic resonance enables the dynamic monitoring of fluid distribution across multi-scale pores, whereas it is constrained by high technical complexity and cost. Numerical simulations investigate wettability from the perspectives of interfacial mechanics and at the molecular scale, while their parameterization and accuracy still depend on experimental validation. The spatial distribution of hydrophilic minerals alongside oleophilic organic matter leads to mixed-wettability states. Increased total organic carbon content enhances the oil-wetting propensity, while higher maturity further promotes the development of hydrophobic organic pores. Elevated temperature generally strengthens the water-wet characteristics, whereas increased pressure induces a preference for oil-wetting. High salinity fluids, particularly those containing divalent cations, asphaltenes and aromatic compounds, enhance oil affinity. Macroscopic wetting behavior is ultimately determined by the connectivity and relative abundance of organic versus inorganic pores. Future studies should integrate multidisciplinary approaches combining advanced experimental characterization with computational modeling to enhance dynamic wettability prediction under real reservoir conditions.

The influence of different reservoir spaces in shale reservoirs on imbibition recovery is a hot spot for improving shale oil recovery. However, the research on the influence of different chemical reagents on the recovery factor of different scale pores is limited, and the influence mechanism of shale imbibition recovery factor under the action of different media has not been systematically studied. Therefore, this study takes the Gulong shale oil reservoir as the research object, carries out imbibition experiments combined with nuclear magnetic resonance testing under different injection fluid conditions, quantifies the contribution of shale pores of different scales to imbibition recovery under different injection media conditions, and analyzes the influence of injection media types on imbibition recovery. The results show that the average contribution rate of different types of pores was in the order of interlayer clay (47.6%) > mesoscale pores (32.7%) > small pores (17.3%) > large pores (2.6%). The total imbibition recovery of shale with millimeter-scale sandy laminae was ranked as alkali solution (61.50%) > acid solution (60.92%) >GJ surfactant (39.79%)> distilled water (32.92%)>guanidine gum (30.38%), and the total imbibition recovery of laminated shale was ranked as GJ surfactant (39.1%) > slick water (38.0%) > guanidine gum (34.7%) > distilled water (29.2%).

Imbibition and huff-n-puff injection in shale reservoirs can significantly enhance oil recovery after depletion. To clarify the microscopic production characteristics and enhance the oil recovery mechanisms across different pore scales during imbibition and huff-n-puff injection, this study establishes an online physical simulation method that integrates imbibition and huff-n-puff using nuclear magnetic resonance and conducts a series of online nuclear magnetic resonance analyses under different imbibition systems. The microscopic production characteristics and dynamic development characteristics are quantitatively studied from the aspects of pore recovery and residual oil distribution. The results show that the occurrence states of pores of shale oil can be categorized into three types, including adsorption pore as the predominant type, followed by percolation pore and migration pore. When viewing the entire imbibition process comprehensively, it becomes imperative to maximize the recovery of migration pores while ensuring the recovery degree of adsorption pores. The recovery of free oil increases with the imbibition amount and the residual oil gradually shifts to adsorbed and organic matter-dominated forms, resulting in gradually decreasing recoverability. Using water-based imbibition media achieves a superior production effect for adsorbed oil in interlayered clay, whereas CO₂ imbibition media can effectively improve the recovery of organic matter through mass transfer, leading to 11.01%-23.54% enhancement in oil recovery. Leveraging the bridge flow conductivity of fractures, fluid imbibition displacement and CO₂ carrying effect emerges as a pivotal strategy for achieving optimal enhanced oil recovery.