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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%. [ABSTRACT FROM AUTHOR]

Abstract Source rocks are found in the Eocene Liushagang Formation (El 1: bottom , El 2 and El 3:top members), in the Weixi'nan sag, Beibuwan Basin. The source rocks are mainly mudrocks, except El 2 , which consists of organic-rich shales at the bottom and mudrocks in the middle-upper part. Total organic carbon (TOC) and Rock-Eval analyses of 146 samples indicate that El 2 rocks have the best hydrocarbon generating potential, especially for organic-rich shales that contain up to 10% TOC with HI > 800 mg/g. The vitrinite reflectance analysis suggests that El source rocks are marginally mature to mature. Geochemical analyses were conducted on 18 El rock extracts and 18 oil samples from the WZ12 field. El 2 and El 3 source rock have similar organic facies and are distinct from El 1. El 2 and El 3 have higher C 27 βα (20R + 20S) diasteranes/C 27 αββ (20R + 20S) steranes (C 27 DiaS/C 27 S), Gammacerane/Hopane (G/H) and (C 28 + C 29) tricyclic terpane/((C 28 + C 29) tricyclic terpane + Ts) (ETR), and low C 23 tricyclic terpane/hopane (C 23 /H) and C 24 tetracyclic terpanes/C 26 tricyclic terpane (C 24 /C 26). These biomarker distributions indicate that El 2 and El 3 rocks were deposited under more alkaline-saline environment and had less import of terrestrial organic matter relative to El 1. El 2 can be distinguished from El 3 as having higher 4-methylsteranes/C 29 ααα steranes (4MSI) and G/H. WZ12 oils all exhibit similar compositions and display biomarker characteristics that correlate with the El 2 and El 3 rock extracts. 1D thermal and burial history model shows that El 2 and El 3 began to generate a great deal of hydrocarbon at ∼11.5 Ma and 23 Ma, respectively. At this stage, traps formed and faults actively extended downwards into the El 2 and likely into El 3. Oils expelled from El 2 and El 3 migrated upward into shallow intervals along faults then laterally along the structural slopes and accumulated in areas with good fault sealing primarily in the Miocene age Nx and Nj strata. Meanwhile, under the effect of overpressure in the middle of organic-rich shales, oils from El 2 may have migrated downward into reservoirs in the upper part of El 3. Lithologic traps in El 1 reservoir may be charged with relatively immature oil derived from El 1. Highlights • Source rocks in El 2 , especially organic-rich shales in the bottom of El 2 are the most important source rocks. • Sedimentary environment of different intervals of El have been distinguished. • WZ12 oils generated from oil El 2 and El 3 source rocks based on biomarkers parameters of saturated hydrocarbon. • Faults and overpressure may be responsible for the distribution of WZ12 oils. [ABSTRACT FROM AUTHOR]

In the brackish water sedimentary environment of the Junggar Basin in Xinjiang, the organic-rich shale and shale oil formation with relatively low maturity, is characterized by relatively high abundance of C 28 regular steranes. However, the biogenic source of organic matter and favorable sedimentary environment for the type of source rock has been thoroughly classified. In this paper, organic geochemical and petrological, analyses of the Lucaogou Formation shale in the Jimusaer Sag, Junggar Basin in the north of Xinjiang Uygur Autonomy Region were carried out. The source rocks in the Lucaogou Formation are mainly composed of two types of maceral including lamalginite (cyanobacteria) and telalginite (green algae), with the former predominantly fueling the high C 28 regular sterane content. Petrological, organic and inorganic geochemical analyses suggest that the lamalginite was developed in low-salinity water while the telalginite was developed in high-salinity water. Based on geochemical and organic petrological characteristics, both the lamalginite and telalginite have good hydrocarbon-generating potential, but in the lower thermal evolution stage of the Lucaogou Formation source rock, telalginite have higher hydrocarbon-generating rate. • Lamalginite (cyanobacteria) is the primary source of C 28 regular steranes. • The lamalginite (cyanobacteria) is more developed when the salinity is low and the telalginite (green algae) is more developed when the salinity is high. • In the lower thermal evolution stage of the Lucaogou Formation source rock, the lamalginite (cyanobacteria) has lower hydrocarbon-generating rate than the telalginite (green algae). [ABSTRACT FROM AUTHOR]

Shale oil generated by the lower member of the Lucaogou Formation, which was deposited under saline lacustrine conditions within the Jimusaer Sag of the Junggar Basin (NW China), is generally characterized by high density and viscosity. However, a strong spatial heterogeneity of physical properties is observed as well. In this paper, these spatial variations and their controlling mechanisms are evaluated from the perspective of the primary depositional environment, source rock thermal evolution and fractionation effects of primary migration. Based on a detailed organic petrological and geochemical characterization of the target interval within the key well JHBE, hydrous pyrolysis experiments conducted on representative source rock samples from well JHBE, as well as established methods of oil-source correlation subjected to oil samples from several regionally distributed producing shale oil wells, a predictive model of density and viscosity changes of crude oil was established. According to the findings of this study, the thermal evolution and sedimentary environment of source rocks are the main factors affecting the quality of crude oil, and the fractionation effect of primary migration has little effect. Crude oil density and viscosity at first increase up to peak oil maturity, followed by a decrease with further increasing thermal evolution of the source rock. Furthermore, if the source rocks experienced similar thermal histories, it was discovered that relatively low density and corresponding viscosity values are characteristic for crudes from source rocks which were formed in a relatively high salinity environment. In contrast, hydrocarbon generation of source rocks formed under relatively low salinity environments is slightly retarded in direct comparison, and the density and viscosity of the generated crude oil are both relatively high. This highlights that a detailed organic petrographical and geochemical evaluation of the target formation is crucial for the assessment of shale oil potential and production sweet spots in alginite-dominated lacustrine sedimentary environments. • Oil-source correlation of the lower member in the Lucaogou Formation are conducted. • Crude oil density and viscosity control by thermal evolution are discussed from a new sight. • The higher salinity is, the lower density of crude oil is. [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]