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Shale oil exploration and development have been conducted in the Permian Lucaogou Formation in the Jimusaer Sag, Junggar Basin. The upper (P 2 l 2) and lower (P 2 l 1) members of the Lucaogou Formation developed with sand layers, which are the shale oil development sections in the Lucaogou Formation. In order to clarify the enrichment law of shale oil for these members, the geological conditions of the P 2 l 2 and P 2 l 1 members were analyzed. The focus of this study were oil-bearing sandstone and mudstone samples from the Lucaogou Formation. These samples were studied by casting thin section observation, total organic carbon, pyrolysis, and gas chromatography–mass spectrometry. The results showed that the upper and lower members of the Lucaogou Formation are mainly characterized as interbedded source rock and reservoir. An oil-source correlation showed that the crude oil in the upper member mainly originated from its adjacent source rock from a deeper position through secondary migration. However, no evidence of secondary migration was observed in the crude oil in the lower member which mainly originated from the adjacent source rock. For the sandbodies in the upper member, when burial is shallower than peak oil generation, the physical properties of the middle part of the sandbody are better than the top and bottom. When burial is deeper than peak oil generation, relatively good physical properties developed in the sandstone in the vicinity the source rock. The lower member has less reservoir thickness, poorer lateral continuity and horizontal permeability than the upper member. The high-quality reservoirs are represented in a single sandbody in the lower member that is mainly developed in the middle part. After the crude oil was discharged from the source rock enters the sandbody, and long-distance lateral migration was restricted. Thus, crude oil in the lower member is enriched and accumulated in situ. • The characteristics of the source rocks and reservoir of the upper and lower members of the Lucaogou Formation are described. • The oil-source correlation in the upper and lower reservoirs of the Lucaogou Formation have been discussed. • The oil accumulation model of the upper and lower member of the Lucaogou Formation is established. [ABSTRACT FROM AUTHOR]

• Sedimentary conditions in the Lucaogou Formation source rocks are described. • The telalginite generated hydrocarbons earlier than the lamalginite. • New parameter index to identify effective source rocks is proposed. The Middle Permian Lucaogou Formation in the Jimusaer Sag is a hotspot for exploring and developing lacustrine tight oil in the Junggar Basin, NW China. In this study, we evaluated the tight oil potential from the perspective of source rock hydrocarbon generation and expulsion. Based on a detailed organic, petrological, and geochemical characterization of the target interval within the key well JHBE, kinetic experiments were performed on representative shale samples from the well JHBE and the threshold of hydrocarbon expulsion of the source rock was established. The findings of this study revealed that the Lucaogou Formation shales were deposited in a dysoxic to anoxic and clay-poor lacustrine environment with variable salinity and their organic matter (OM) was contributed from both lamalginite and telalginite with minor vitrinite and inertinite, resulting in good to excellent source rock potential. The lamalginite was deposited in water with low salinity, whereas the telalginite developed in water with relatively higher salinity. Although the greater contribution of lamalginite resulted in a higher OM content than that of telalginite, the former generated a lower amount of hydrocarbons than the latter, because telalginite is capable of generating hydrocarbons earlier than lamalginite, which is indicated by the higher HCI (Hydrocarbon index, S 1 × 100/TOC), EOM/TOC (extraction of organic matter/total organic carbon), C 29 ββ/(αα + ββ), and C 29 ααα20S/(20S + 20R) sterane values for telalginite than for lamalginite and is also evident from the difference in activation energy distributions between lamalginite and telalginite source rocks. As determined from the relationships of sterane maturity parameters C 29 ββ/(αα + ββ) and C 29 ααα20S/(20S + 20R) vs EOM/TOC ratio and HCI values, the lower C 29 ββ/(αα + ββ) and C 29 ααα20S/(20S + 20R) limits for active source rocks were approximately 0.28 and 0.44, respectively. [ABSTRACT FROM AUTHOR]