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.

Shale oil is of interest for unconventional oil and gas exploration and development and has abundant geological reserves. Shale reservoirs contain numerous nanopores. Understanding the adsorption state of shale oil in the nanopores of shale is beneficial to improve the recovery of shale oil. In this study, the adsorption properties of shale oil in kaolinite slit pores were investigated by molecular dynamics simulation. In order to study the adsorption characteristics of shale oil with different components, a single-component model from n-C8 to n-C15 was established, and a mixed model of n-C8 and n-C15 with different mass ratios represented different crude oil components. The results show that the adsorption capacity per unit area increases with the increase of the alkane carbon number. The adsorption capacity of alkanes on the surface of silicon-oxygen tetrahedron is greater than that on the surface of aluminium-oxygen octahedron. The interaction force between kaolinite and alkane surface increases with the increase of alkane carbon number. The alkane adsorption capacity of silicon-oxygen tetrahedron is stronger than that of aluminium-oxygen octahedron. Competitive adsorption also exists between alkane molecules. Alkanes with higher carbon numbers are more easily adsorbed on the surface of kaolinite. Light alkanes are more likely to exist in free form than heavy alkanes. Based on molecular simulations, we studied the adsorption capacity of alkanes with different carbon numbers and calculated the adsorption capacity per unit area in the pores. It provides a theoretical basis for the calculation of shale oil geological reserves.