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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 shale from the Cretaceous Taizhou Formation is an important source rock in the Gaoyou Sag, Northern Jiangsu Basin. Fifty-three shale core samples analyzed for total organic carbon (TOC) and Rock-Eval pyrolysis analyses were used to evaluate the geochemistry of this shale. Twenty-one samples of them were analyzed using solvent extraction, extract fractionation, Gas Chromatography-Mass Spectrometer (GC-MS) of the saturated fraction, and organic petrology analyses. Based on the test results, the shale of the Taizhou Formation contains mainly Type II-III organic matter and is chiefly oil-prone and oil-gas-prone, as a fair to good oil-source rock with a small quantity of gas-source rock. Vitrinite reflectance, Rock-Eval pyrolysis, and biomarker suggest that in this sag, the shale of the Taizhou Formation is mainly in the early mature stage and within the oil window, so the shale generates chiefly liquid oil. The Gaoyou Sag is an oil-generating sag. The saturated fraction and biomarker composition of the shale provide evidence that the Taizhou Formation shale was formed mainly in a reductive sedimentary environment with anoxic fresh to low salinity water. The organic matter came chiefly from plankton and partly from land plants and bacterial organisms. [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]

According to the geochemistry, organic petrography, stable carbon isotopic compositions and biomarker analyses of the Late Miocene Zeit Formation shale samples in the Tokar area, Red Sea Basin, the paleoenvironment and hydrocarbon-generating potential were analyzed. The Zeit Formation shales from the Wells S. Suakin-1 and Tokar-1 contain mostly Type III kerogens with minor Type II organic matter (OM), indicating more favorable gas-generating potential. OM of the shale samples from the Late Miocene Zeit Formation are predominantly of terrigenous higher plants. Kerogens from the Well Tokar-1 show abundant brown liptinites, indicating the mixed origin of planktonic/bacterial and terrigenous OM. The Late Miocene Zeit Formation was deposited in dysoxic/suboxic, reducing and salt water environments. According to the results of Tmax, Ro and biomarker maturity parameters, the most shale samples from the Zeit Formation are in early mature to mature stages. The shales from the Late Miocene Zeit Formation are generally fair to good source rock. The shales from wells Suakin-2, Talla-2 and Tokar-1 have high hydrocarbon-generating potential. • OMs from the Zeit Fm. Are predominantly of terrigenous higher plants. • Shales were deposited in dysoxic/suboxic, reducing and salt water environments. • Shales from the Zeit Formation are in early mature to mature stages. • Shales from the Zeit Formation are generally fair to good source rock. [ABSTRACT FROM AUTHOR]

The origin of crude oils and their varied geochemical features along the western and northern slope of the Mahu depression in the Junggar Basin has been controversial. Based on the molecular and isotopic geochemistry of hydrocarbons from 46 drill-stem test crude oil samples and 36 core samples, three oil groups (I, II, III) and five subgroups (I 1 , I 2 , II, III 1 and III 2 ) have been recognized and oil-source correlations have been established. The subgroup I 1 oils originated mainly from lower Permian Fengcheng (P 1 f) carbonate source rocks, subgroup I 2 from P 1 f mudstone source rock and group II oils from Middle Permian Wuerhe (P 2 w) mudstone source rock whose potential was underestimated in the past. Group III consists of mixed oils, i.e., subgroup III 1 received contributions from P 1 f carbonates and P 2 w mudstones and subgroup III 2 is a mixture of oils from P 1 f mudstones and P 2 w-generated oils. In order to determine the main source rocks, the laboratory oil mixing experiments were carried out. Tricyclic terpane biomarker parameters (TTs) were used to quantify the source contributions. Whole oil carbon isotope ratios were also used to verify the proportions of different oils in each mixture. The results show that subgroup III 1 oils have diverse mixing ratios in different reservoir, subgroup III 2 oils are mainly from P 1 f mudstones and P 2 w source rock contributes little. Finally, the accumulation process of oil fields along the northern slope of the Mahu depression was analyzed and the contributions from different sources were revealed. This study provides an effective quantitative method to identify contributions from different lacustrine source rocks to mixed oils in the Mahu depression, which could be helpful in predicting location and composition of undiscovered oils. [ABSTRACT FROM AUTHOR]