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 imbibition process plays a crucial role in the development of shale reservoirs, particularly during the volume fracturing and water injection development phases. This process significantly influences the production capacity of shale and also serves as a essential parameter for assessing reservoir performance. Clay minerals contribute to the formation of numerous micro-pores and micro-fractures, exhibit strong plasticity and are prone to swelling. The unique structures and properties of clay minerals have a profound impact on shale imbibition. This review analyzes the effects of clay minerals on imbibition from different perspectives, finding that the effect is closely related to the total amount of clay minerals, as well as to specific mineral types and content. Clay minerals exhibit a dual impact on imbibition, which can either facilitate imbibition by promoting micro-fractures formation or hinder it by reducing pore throats and migrating to block flow paths due to swelling. While capillary action is usually considered the main mechanism for fluid displacement during the imbibition, the osmotic pressure formed by clay minerals can also serve as a driving force for imbibition, positively contributing to shale oil and gas recovery. This review aims to provide a comprehensive understanding of the role of clay minerals on the imbibition, providing a theoretical foundation and practical guidance for future research and efficient development of shale reservoirs.