Wettability plays a significant role in the exploration and development of shale oil. The wettability affects the oil enrichment and restricts the selection of fracturing fluids. Shale is composed of complex minerals and organic matter. The pores composed of inorganic minerals have water wettability, while the pores composed of organic matter show the characteristics of oil wetting. The contact angle experiment and the spontaneous imbibition experiment are the most commonly used methods for characterizing wettability. The Qingshankou Formation in the Songliao Basin has thick source rocks, which is a favorable interval for shale oil exploration and development. Strengthening the wettability research in this area is of great significance for the exploration of shale oil. The wettability of different lithofacies shale in the northern Songliao Basin is seldom characterized, and there is a lack of comparative studies on contact angle and imbibition characteristics. In view of this situation, the shale of the Qingshankou Formation in the northern Songliao Basin has been classified. This article used the method of spontaneous imbibition combined with nuclear magnetic resonance to characterize the wettability of shale and analyze the influencing factors of the wettability of different shale lithofacies. Six samples with different lithological characteristics were used for this experiment. The study found that the imbibition results of samples with different lithofacies are different. The imbibition of sandy interlayer is less affected by the direction, while the imbibition of shale is more affected by the direction. The water imbibition volume of the sample is related to the content of clay minerals. The relationship of water imbibition volume in different lithofacies samples is as follows: low organic matter laminated siliceous shale > high organic matter massive clay shale > sandy interlayer > high organic matter laminated siliceous shale > high organic matter massive siliceous shale. Excessive content of clay minerals will cause shale to absorb water and expand and block pores, which is not conducive to further water imbibition by shale. The volume of oil imbibed is related to the organic carbon content. The relationship of oil imbibition volume in different lithofacies samples is as follows: high organic matter massive clay shale > high organic matter laminated siliceous shale > sandy interlayer > low organic matter laminated siliceous shale > high organic matter massive siliceous shale. The higher the total organic carbon content, the more developed the lipophilic pore network, and the more the volume of oil imbibed by the sample.

Hybrid sedimentary rocks (HSR) are a major reservoir type in unconventional oil exploration. The reservoir characteristics and controlling factors of the oil content of HSR are not clear, restricting the understanding of the storage mechanism and sweet spots within HSR. The Lucaogou Formation in the western Jimusar Sag is taken as a case study. Starting with the classification of the lithofacies system, differences in the microscopic pore structure, oil content and controlling factors of HSR reservoirs are revealed. The results show that seven lithofacies are recognized based on mineral composition, sedimentary structure, and organic matter characteristics, exhibiting rapid vertical and horizontal changes affected by the sedimentary environment. Layered mudstone lithofacies of the shallow lake mud and massive dolomitic mudstone lithofacies of dolomitic mud flats have the worst physical properties and oil content properties. However, they do have high organic matter contents and are the main source rocks of the Lucaogou Formation. The massive argillaceous siltstone and massive argillaceous dolomite lithofacies interbed frequently. Although their physical properties are moderate, “source-reservoir integrated” unconventional oil reservoirs can be formed, due to the adjacent to the source rock. Massive dolomitic siltstone, massive siltstone, and massive silty dolomite lithofacies are developed in the middle of the Lucaogou Formation, with the highest proportion of mesopores and macropores, which is indicative of good storage properties. When these lithofacies are filled with crude oil generated from source rocks at the top and bottom of the formation, “source storage adjacent” unconventional oil reservoirs be formed. The oil content is also controlled by the pore structure and specific surface area. The proportion of macropores and mesopores is positively correlated with oil content. The oil content of the samples is very low, when the specific surface area exceeds 2 m2/g. This manuscript provides a geological basis for evaluating and establishing reasonable interpretation models of HSR sweet spots.

Wettability is a significant factor in the exploration and development of shale oil. Currently, shale wettability has yet to reach a unified understanding. The contact angle is widely used in the study of shale wettability. However, the pre-treatment of the shale profoundly affects the contact angle. In this paper, the contact angle errors introduced by the pre-treatment of samples are discussed. Shale wettability is influenced by many factors, and there is not yet a systematic study of its influencing factors. Based on the above issues, the shale of the northern Songliao Basin was taken as the subject. The wettability of the different lithofacies is characterized by an improved contact angle method. The compositional characteristics of the shales and oil in the study area were analyzed. Fresh minerals, a single component of oil, and different temperature/pressure conditions were set up to investigate the influencing factors of shale wettability. The studies show that Organic matter abundance and thermal maturity have a positive correlation with oil-wet. Siliceous minerals are positively correlated with water-wet. Carbonate and clay minerals are negatively correlated with water-wet. The mineralogical composition of the shale, the composition of the oil, the characteristics of the aqueous media, the asphaltene deposits on the surface, temperature, and pressure all impact wettability. The affinity of minerals for hydrocarbons is iron minerals > carbonate minerals > clay minerals > siliceous minerals. Minerals are more hydrophilic at low salinity conditions. The deposition of non-hydrocarbons and asphaltenes renders the surface oleophilic. Increasing temperatures will reduce the hydrophilicity of the “oil-water-rock”.