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Shales in the Carboniferous–Permian Fengcheng (FC) and Lucaogou (LCG) formations in Junggar Basin are important organic rich rocks containing significant oil resources. To evaluate the difference in sedimentary environment conditions and hydrocarbon-generating potential between the FC and LCG formations. Total organic carbon (TOC), Rock-Eval pyrolysis, solvent extraction, column fractionation, stable carbon isotope, gas chromatography-mass spectrometry (GC-MS) of saturated hydrocarbons and organic petrology from the source rocks of FC and LCG formations. were analyzed. The biomarker composition indicates that during the deposition of FC, LCG-1 to LCG-2, the sedimentary environment for the source rock formations changed with gradual decrease of salinity, from anoxic to dyoxic/suboxic in redox conditions, and from strong stratification to weakened stratification of water. The FC Formation source rock, with main telalginite (planktonic green algae), archaebacteria and minor terrestrial organic matter, deposited in the environment characterized by high salinity and strongly reducing condition. Its TOC content is relatively low with a high original hydrocarbongenerating potential of unit organic material. The LCG Formation source rock deposited in the environment with low salinity and large variations, the organic matter is mainly sourced from telalginite (planktonic green algae), lamalginite, bacteria and higher plants, resulting in strong heterogeneity of the source rock. The abundance of TOC is high, but the original hydrocarbon generation potential of unit organic matter is lower than that of FC Formation. The results provide a geochemical basis for further study of saline-brackish water sedimentary environment shales in the Junggar Basin. [ABSTRACT FROM AUTHOR]

Crude oil has been discovered in the Paleogene and Neogene units of the Weixinan Sag in the Beibu Gulf Basin. To determine the source and accumulation mode of this crude oil, 12 crude oil samples and 27 source rock samples were collected and an extensive organic geochemical analysis was conducted on them. Based on the geological conditions and the analytical results, the types, origins and accumulation patterns of crude oil in the study area were elucidated. Except for a shallowly‐buried and biodegraded crude oil deposit in Neogene rocks, the crude oil samples in the study area were normal. All of the crude oils were derived from lacustrine source rocks. According to biomarker compositions, the crude oils could be divided into two families, A and B, distinctions that were reinforced by differences in carbon isotope composition and spatial distribution. Oil‐source correlation analysis based on biomarkers revealed that Family A oils were derived from the mature oil shale at the bottom of the second member of the Liushagang Formation, while the Family B oils formed in the mature shale of the Liushagang Formation. The Family A oils, generated by oil shale, mainly migrated laterally along sand bodies and were then redistributed in adjacent reservoirs above and below the oil shale layer, as well as in shallow layers at high structural positions, occupying a wide distribution range. The Family B oils were generated by other shale units before migrating vertically along faults to form reservoirs nearby, resulting in a narrow distribution range. [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]

The origin and potential source of the presalt natural gas in the Lower Paleozoic Ordovician carbonates within the Ordos Basin, China, is heavily debated, and the causes of carbon isotope reversal are currently unclear. This study analyzes the source and origin of the presalt natural gas and determines the reasons for carbon isotope reversal. The results show that the nonhydrocarbons contain CO 2 , H 2 S, and N 2 and some gas samples have high H 2 S contents of 9.02%–23.58%. The dryness coefficient (C 1 /C 1+) of 91.06%–99.99% (ave. 98.34%) suggests that the presalt gas is mainly a dry gas with some wet gas and that it originates from a high-to over-mature source. However, the results show that the presalt natural gas is primarily a wet-gas-cracking gas, rather than a kerogen-cracking gas, with a certain amount of coal-type gas mixing and it mainly originated from oil-prone marine carbonate source rocks rather than the Permian–Carboniferous coal measures. The gas has different types of carbon isotope reversal patterns, and the δ13C 2 values become negative at Ro equ > 1.5%. The mixing between the oil-cracking and wet-gas-cracking gas at Ro equ > 1.5% results in carbon isotope reversal (δ13C 1 > δ13C 2), rather than Rayleigh and migration fractionation. The occurrence of thermochemical sulfate reduction (TSR) is supported by the high abundance of H 2 S in the presalt gas, reservoir bitumen in dissolved pores, secondary calcite with negative δ13C carbonate of −21.1‰ to −9.7‰, and diagenetic cubic pyrite. It is evident that the heavy δ13C 2 values (greater than −28‰) and the carbon isotope reversal of δ13C 2 > δ13C 3 of the presalt natural gas at Ro equ < 1.5% are related to TSR. This study also establishes a new model of the carbon isotope reversal of the natural gas, which is primarily controlled by its thermal maturity and TSR. Six carbon isotope patterns can be well explained and are supported by real gas samples from the presalt strata, and two types of carbon isotope reversal are predicted. • The presalt gas is mainly oil-derived gas and dry gas with some wet gas. • Heavy δ13C 2 values (>−28‰) and carbon isotope reversal of δ13C 2 > δ13C 3 of are caused by TSR at low maturity. • The δ13C 2 values become greatly more negative at Ro equ > 1.5%. • A new model of carbon isotope reversal is established firstly, controlled by maturity and TSR. [ABSTRACT FROM AUTHOR]