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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]

Measurements of TOC, Rock-Eval pyrolysis, carbon isotope composition, solvent extract, extract fractionation, and the gas chromatography-mass spectrum (GC-MS) of the saturated fraction were conducted on the Lower Permian Fengcheng Formation carbonate-bearing shales and argillaceous dolomites of Well FN7 in the northwestern Junggar Basin to understand the geochemistry and depositional environmental evolution of the carbonate-bearing lacustrine source rocks. The results indicate that the Fengcheng Formation carbonate-bearing shales are fair to good source rocks with Type II kerogen for generating oil and minor gas, and the argillaceous dolomites are poor source rocks. The thermal mature shales contain more residually generated hydrocarbon, whereas the argillaceous dolomites contain more migrated hydrocarbon. This property is favorable for shale oil or tight oil accumulation in the Fengcheng Formation. Biomarker analyses indicate that the Fengcheng Formation source rocks were formed in the anoxic reducing lacustrine depositional environment with a stratified water column and high salinity. The source rock organic matter has major aquatic phytoplankton and algae input and less terrestrial organic matter input. During the Fengcheng Formation period, oxidation had a weak increasing tendency and salinity had a weak decreasing tendency from the early to late periods under the background of a reducing environment. Except for poor source rocks in upper and lower parts, the good source rocks are primarily in the middle part of the Fengcheng Formation. [ABSTRACT FROM AUTHOR]

The shales in the Baijiantan Formation are considered to be an important potential source rock in the Junggar Basin. To evaluate this basin’s source-rock characteristics, 61 core samples from 14 boreholes were analyzed using total organic carbon and total sulfur analyses and Rock-Eval pyrolysis. Thirty-two core samples were analyzed using solvent extraction, column fractionation, biomarker analysis and the organic petrology of kerogen. The results suggest that the shales in the Baijiantan Formation have fair to excellent hydrocarbon generation potential, and the organic matter types include both Type II and Type III. The shales in the Baijiantan Formation are mainly oil-generating rocks, and better source rocks are mainly distributed in the middle–lower section of the Baijiantan Formation. The total organic carbon and total sulfur analyses, Rock-Eval pyrolysis, and biomarkers indicate that the shales in the Baijiantan Formation formed in a low-salinity to freshwater lacustrine sedimentary environment under reducing conditions. Biomarkers indicate that the organic matter input of the shales exhibits varying contributions from plankton, algae and terrestrial organisms. The biomarker molecular composition of the source rock is related to the organic matter source, salinity, redox conditions and maturation. [ABSTRACT FROM AUTHOR]

There are a mass of transitional types of rock including proportionally-predominated shales, secondary siliciclastic sandstones, and carbonate rocks which are in small proportion (major dolostone and minor limestone) in Lucaogou Formation of the Jimusaer Sag of Junggar Basin. These rocks were deposited in brackish lacustrine environment under alkaline to weak alkaline conditions. The various rock types were all formed in reduction environment, but there is the broadest oxidation–reduction varying condition for the shale, and environmental reductivity where dolostones deposited is stronger than that of sandstones. The organic matter in source rocks comes from either aquatic organism or terrestrial organism. As reservoir, parts of sandstones and dolostones contain more primitive solid organic matters which might act as the hydrocarbon-generating material base. Parent material types of source rocks in different lithologies are mainly mixed type of type II 2 -I and have oil-prone characteristic. In the study area, the Ro value corresponding to oil generation peak for source rock is Ro=0.9%, lower than the classic model oil peak Ro=1.0% and thermal maturity of source rocks in multifarious types fall in the stage of oil generation. Determined by relationships of TOC content vs. Bitumen/TOC and TOC content vs. HCI, the lower TOC limit for active rocks is around 1.0%, hereby, about 90% of the shales, all of the limestone, and a third of the dolostone and sandstone are active source rocks. Therefore, there are preferable oil-generating potential of lithologically different source rocks in Lucaogou Formation of the Jimusaer Sag. The shales are chiefly oil-prone source rock and parts of dolostone, sandstone and limestone also have a contribution to the oil reservoirs. [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]

The geochemical compositions of crude oils and Permian source rocks from the Mahu depression of the Junggar Basin were analyzed in this study. Based on tricyclic terpanes and isoprenoid biomarkers, three oil groups (I, II and III) can be identified that correspond to different source rock formations and organic facies. After examination of the influence of source facies and thermal maturity, and selected biomarker ratios based on carbazole isomers such as 1-MC/4-MC, 1,8-DMC/2,7-DMC and [a]/([a] + [c])-BC ratios in different oil groups, allowed us to determine the direction of hydrocarbon migration in different reservoirs. In addition, abundant oil inclusions are present with fluorescence colors ranging from yellow to blue-white. These were analyzed by FTIR to distinguish between different sources for the oils. Fluid inclusion petrography and microthermometry were also used to prove two stages of oil migration and their different sources. Taking into consideration possible migration pathways and likely driving forces, we conclude that abnormally high pressure in the Permian sequence acted as the main driving force for oil migration. The major migration pathways were vertical faults in the fault belts and slope areas, and sand bodies in the deeper areas. Group I 1 oils from P 1 f carbonate source rocks in the fault belts mainly migrated vertically through the faults and accumulated in T 1 b reservoirs in the Late Triassic, and were driven by excess formation pressure and buoyancy. Group I 2 oils in the slope areas first migrated vertically within thrust faults from P 1 f mudstone source rock in the Late Triassic, after which they migrated laterally over short distances to accumulate in T 1 b sand bodies. Group II oils from adjacent P 2 w source rocks in the center of the depression migrated mainly in the Late Jurassic, due to abnormally high pressure, and accumulated in nearby T 1 b traps. Some reservoir rocks in the slope area contain two generations of fluid inclusions, implying oil mixing from early-stage P 1 f oils and late-stage P 2 w oils, resulting in the group III oils. Combining these data from biomarkers, pyrrolic nitrogen compounds and fluid inclusions allowed us to construct models of migration and accumulation for oils in the Mahu depression. [ABSTRACT FROM AUTHOR]