The ultimate recovery of shale oil is mostly dependent upon the occurrence and content of free oil within the nano-scaled pore network of shale reservoirs. Due to the nanoporous nature of shale, quantitatively characterizing the occurrence and content of free oil in shale is a formidable undertaking. To tackle this challenge, 12 lacustrine shale samples with diverse organic matter content from the Chang7 Member in the southern Ordos Basin were selected, and the characteristics of free oil occurrence were indirectly characterized by comparing changes in pore structure before and after organic solvent extraction. The free oil enrichment in shale was assessed using the oil saturation index (OSI), corrected oil saturation index (OSI_corr), and percentage of saturated hydrocarbons. The results revealed that slit-like interparticle pores with diameters less than 30 nm are dominant in the Chang7 shale. Conceptual models for the pore structures containing free oil were established for shale with total organic carbon (TOC) content less than 9% and greater than 9%, respectively. Shale samples with TOC content less than 9% exhibit a well-developed pore network characterized by relatively larger pore volume, surface area, and heterogeneity. Conversely, shale samples with TOC content exceeding 9% display a less developed pore network characterized by relatively smaller pore volume, surface area, and heterogeneity. Larger pore volume and lower organic matter abundance favor the enrichment of free oil within the lacustrine shale pore network. This study may have significant implications for understanding oil transport in shales.

Lacustrine shale, represented by the Middle Permian Lucaogou Formation in the Jimsar Depression in the eastern Junggar Basin, has become one of the main areas of shale oil exploration in China. In this study, we used 137 samples of shale from the Lucaogou Formation, drawn from 14 wells in the Jimsar Depression, to investigate their characteristics of pyrolysis, organic carbon and soluble organic matter content, biomarkers, organic microscopic composition, and vitrinite reflectance. Basin simulation and hydrocarbon generation thermal simulation experiments were also conducted in a closed system. The results of this study indicate that the input of an algae source was dominant in the source rocks of the Lucaogou Formation, that the water in which the rocks were deposited had high salinity and strong reducibility, and that the source rocks were oil-prone. The Lucaogou source rocks generally had good hydrocarbon generation capability, but showed significant heterogeneity. At the end of the Cretaceous period, the shales in the Lucaogou Formation entered the oil-generation window as a whole. Currently, the shales of the Lucaogou Formation are generally in the high-maturity stage in the deep part of the depression, producing a large amount of high-maturity oil and condensate gas, while those in the shallow part have relatively low maturity and can only produce a large amount of conventional crude oil. The maximum crude oil generation rate of the Lucaogou Formation shale obtained from the thermal simulation results was 220.2 mg/g of the total organic carbon (TOC), and the maximum hydrocarbon expulsion efficiency was estimated to be 59.3–76.4%.