•Five kerogen molecular models within the ‘oil window’ constructed.•Jump in the structure of a Type I kerogen observed near peak oil window.•Alkyl degradation and growth in aromatic cluster number contributed to aromaticity increase.•Both aliphatic and aromatic structures generated hydrocarbons before peak oil window.Artificial maturation of Maoming oil shale kerogen (Type I) was performed at a heating rate of 5 °C/h in a closed Au tube system. Yields of pyrolysis products (C1–5, C6–14, C14+ and insoluble residue) were quantified. The insoluble kerogen residue was analyzed using Rock-Eval, elemental analysis and quantitative 13C direct polarization/magic angle spinning (DP MAS) nuclear magnetic resonance (NMR) spectroscopy. Peak oil generation was achieved at Easy %Ro 0.95. A “three-stage” relationship existed between aromaticity and Easy %Ro because of the relatively pronounced cleavage of aliphatic carbons and the formation of new aromatic structures in the kerogen residue. Five models of kerogen representing five stages in the oil window were drawn to provide a visualized kerogen structure modification with evolution. A novel jump in the structure of the kerogen residue was observed at ca. Easy %Ro 0.80–0.90, corresponding to the peak oil window. Our results suggest that aromatic carbon, replacing aliphatic carbon and becoming the dominant carbon in the residue, was the cause of the dramatic changes in the Easy %Ro interval of 0.80–0.90. Both aliphatic and aromatic structures contributed to hydrocarbon generation before peak oil generation. CH2 groups contributed most to the hydrocarbon generation potential. Me groups contributed little to hydrocarbon generation within the oil window.

•The crude oils are mixtures of different maturity oils generated from two source rocks.•The number, contributions and compositions of endmembers were estimated using chemometrics.•The general oil charge orientations were from south to north and east to west.•A model of petroleum charge, biodegradation and mixing was proposed.Forty-eight crude oil samples collected from different reservoirs in the Tahe oilfield of the Tarim Basin were investigated. Based on geochemical characteristics, it is concluded that the oil samples originated from multiple marine source rocks deposited in various sedimentary environments and subsequently altered by different levels of thermal maturation. These mixtures were de-convoluted to three endmember oils (EM1, EM2 and EM3) by alternating least squares regression using 38 concentration parameters. EM1 is the minimum contributor with an average of 13%, while EM2 and EM3 are the main contributors to the mixtures with averages of 52% and 35%, respectively. EM1 oil originated from Cambrian–Lower Ordovician source rocks in the early to peak oil window and subsequently experienced two phases of mixing and biodegradation. EM2 and EM3 oils originated from Middle–Upper Ordovician source rocks, but EM2 was generated at lower thermal maturity than EM3. The EM2 oil underwent two phases of mixing and one stage biodegradation, while the EM3 oil mixed with previous existing mixtures in the reservoirs. The final mixtures that might be affected by secondary processes, such as evaporative fractionation, are currently produced from the Tahe oilfield. The general orientation of oil filling was from south to north and east to west based on variations in the relative contributions of EMs, and the total concentrations of dibenzothiophenes and dibenzofurans in the oils. Considering the histories of sedimentary tectonic evolution, hydrocarbon generation and expulsion, and the de-convolution results, a model of three stages of oil charge and two phases of mixing and biodegradation was established for the Tahe oilfield oils.

•Experiments on the oil adsorption on minerals were carried out.•A model was developed to reconstruct the adsorption of mudstone/shale for shale oil.•The shale oil exploration risks rise at depth shallower than 3400 m.Inorganic minerals were separated from mudstone and shale to investigate their oil adsorption potential. A conceptual model was developed to reconstruct the oil adsorption capacity of underground mudrock/shale by combining adsorption and organic matter swelling data. The predictions for the free hydrocarbon oversaturation sorption zones in the Well NY1 profile were taken as a case study. The results suggest that the best depth for the shale oil prospect of the Es4s member strata lies between 3400 and 3600 m in the Dongying Depression. Hydrocarbon starvation zones occur mainly at a depth of < 3400 m, where both the maturity and the extent of oil conversion of organic matter are relatively low, while the sorption capacity of mudstone and shale rocks is by comparison high and the exploration risk is greater.

•Changes of concentrations and biomarker ratios in mixed oils investigated.•Biomarker concentrations are more suitable for chemometrics to de-convolute mixed oils than biomarker ratios.•The number, fractional contributions and compound compositions of end-members in mixtures can be calculated by ALS-C.In this study, chemometrics was used to unmix a set of oil samples that had been mixed in the laboratory using three end-member oils. It was shown that the concentrations of individual compounds in the mixed oil varied linearly with the fractional contribution of each end-member oil. However, biomarker ratios in the mixed oils varied non-linearly with the amount of each end-member oil. This study demonstrates that concentrations and ratios of biomarkers yield different results when de-convoluting mixed oils. Concentrations of biomarkers are therefore more suitable than the biomarker ratios for unmixing mixed oils. Alternating least squares of biomarker concentrations (ALS-C) provides an excellent way to calculate the number, proportions, and compound compositions of the end-members in mixed oil samples. The ALS-C results are accurate, regardless of whether end-member oils are included in the sample set. The biomarker ratios of end-member oils cannot be directly obtained by ALS, but can instead be calculated using related compound concentrations computed by ALS-C. This method should be applied and verified widely using actual geochemical data.

•Molecular geochemical characteristics of the marine oils were analyzed.•The samples were mixtures of different maturity oils from two source rocks.•The number, contributions and compositions of endmembers were calculated.•A model of petroleum charge, biodegradation and mixing was established.Geochemical characteristics of 61 crude oil samples collected from Palaeozoic reservoirs in the Tarim Basin (60 from the Tabei Uplift and one from the Tazhong Uplift) were analyzed. The samples proved to be mixed oils of different maturity from diverse source rocks. Concentrations of 40 biomarkers and carbon isotopic compositions for the whole oils were analyzed by alternating least squares (ALS) regression to de-convolute the mixtures. Three endmember (EM) oils were identified. EM1 is the minimum contributor to the mixed oils, accounting for less than 10% of most oils. EM1 originated from Cambrian–Lower Ordovician source rocks in the early to peak oil window stage and experienced two phases of mixing and biodegradation. EM2 is the secondary contributor with proportions ranging from 10% to 40% in most oil samples. EM2 originated from Middle–Upper Ordovician source rocks at the early oil generation stage and underwent two phases of mixing and one stage biodegradation in the reservoirs. EM3 is the major contributor to most samples with proportions ranging from 13% to 95%. EM3 was generated from Middle–Upper Ordovician source rocks at the late oil generation stage and mixed with earlier emplaced mixtures in the reservoirs. The final mixtures that were not biodegraded are currently exploited from Palaeozoic reservoirs in the Tabei Uplift. Biomarkers in the crude oils reveal mixed characteristics, including evidence for two phases of oil charge and severe biodegradation.

•A total of 125 source rock and oil samples were collected and analyzed using GC–MS.•PCA and multidimensional scaling were used for oil–source rock correlation.•Crude oils are mainly generated from the Xinancun-Wuyun Formation.One hundred and twenty-five rock and oil samples collected from the Fangzheng Fault Depression were analyzed by GC–MS. Principal component analysis (PCA) and multidimensional scaling (MDS) based on nine biomarker ratios were used for oil–source rock correlation in this region. The oils are characterized by a predominance of low to middle molecular weight normal alkanes (n-C12–n-C20 or n-C12–n-C25), moderate to high Pr/Ph ratios (1.44–5.3), relatively low C27/C29 regular steranes, C35/C34 hopanes and gammacerane/C31R ratios, all of which suggest relatively oxic conditions under fresh water depositional conditions with significant terrigenous organic matter input. PCA and MDS results show that the investigated oils were derived mainly from the Xinancun-Wuyun Formation and also illustrate the maturation and depositional conditions of the rocks and oils through an MDS plot. We show that MDS is a reliable, multi-parameter oil–source rock correlation method.

Pyrolysis of two kerogens isolated from the E2-3s33 and E2-3s41 source rocks in the Niuzhuang sag, Dongying Depression, Bohai Bay Basin, China, was performed in a confined system. The products were extracted with solvent and separated using micro-column chromatography into group-type fractions (saturates, aromatics, resins and asphaltenes) with the kerogen residue in each case undergoing swelling with a variety of solvents. The kinetics for generation and retention of crude oil and its group-type fractions from the kerogens were studied and the kinetic parameters applied to modeling generation and retention of crude oil and its fractions from the E2-3s33 and E2-3s41 source rocks on the basis of burial and thermal history of the Niuzhuang sag. The results show that the “normal oil” was generated at about 4.26 Ma and 24.85 Ma ago, but expelled at about 3.96 Ma and 17.46 Ma ago, respectively, from E2-3s33 and E2-3s41 source rocks. The current proportions of the expelled saturates, aromatics and NSOs are about 60%, 15% and 25%, respectively.Highlights► The kinetics for generation of oil and its fractions from kerogens were studied. ► The parameters were applied to modeling generation and retention of oil. ► The method predicted the timing of expulsion and the group-type composition.

Natural gas is dominated by low-molecular weight gaseous hydrocarbons (C1–C5) whose genetic and diagenetic information is mainly obtained from stable carbon isotope compositions. Ordos Basin is one of the largest natural gas provinces in China. By means of examining the carbon isotope compositions of the Ordos basin gases, altered patterns of the isotope-type curves due to secondary cracking, thermochemical sulphate reduction (TSR) and mixing of gases generated from different sources are recognized and discussed. A typical carbon isotope-type curve is nearly linear on the natural gas plot [Chung, H.M., Gormly, J.R., Squires, R.M., 1988. Origin of gaseous hydrocarbons in subsurface environments: theoretical considerations of carbon isotope distribution. Chemical Geology 71, 97–103]. Our results show that the isotope-type curve pattern of TSR and gas secondary cracking in coal is convex due to catalysis, while the isotope-type curve of gas secondary cracking in reservoirs is concave. The natural gas of Yulin, Suligemiao and Wushenqi gas fields is coal-derived gas; both coal-derived gas and mixed gas from oil- and gas-prone sources exist in the Ordovician reservoirs of the Jingbian gas field, depending on the borehole locations. In the Ordovician carbonate reservoirs TSR is recorded but uncommon, whereas secondary cracking in reservoirs is often observed.

Significant gas condensate as well as some black oils have been discovered in the Kuqa Depression of Tarim Basin, NW China. Dry gases with high δ13C values occur in the Kelasu structural belt, wet, isotopically light gases in the Yiqikelik belt, whereas condensates are distributed mainly in the Front Uplift area. Kinetic modeling results show that the variation of methane and ethane isotopes with increasing vitrinite reflectance is independent of heating rates for a given source rock. Two maturity trends have been observed on a C2/C1–δ13C1 plot, one for thermogenic gases associated with coal, another for oil-associated gases with minor contribution from biogenic gas. It is most likely that the gases in the Kelasu belt and Front Uplift area were derived from the Jurassic coal measures and Triassic lacustrine shales, respectively, with those in the Yiqikelik belt being the mixtures of gases from the two sources. Both Jurassic coals and Triassic lacustrine shales appear to have contributed to the gases in the Kela 2 (KL2) and Dina 2 (DN2), the two largest gas fields in the Tarim Basin.

A type Ⅱ kerogen with low thermal maturity was adopted to perform hydrocarbon generation pyrolysis experiments in a vacuum (Micro-Scale Sealed Vessel) system at the heating rates of 2 °C/h and 20 °C/h. The stable carbon isotopic compositions of gas hydrocarbons were measured to investigate their evolving characteristics and the possible reasons for isotope reversal. The δ13C values of methane became more negative with the increasing pyrolysis temperatures until it reached the lightest point, after which they became more positive. Meanwhile, the δ13C values of ethane and propane showed a positive trend with elevating pyrolysis temperatures. The carbon isotopic compositions of shale gasses were mainly determined by the type of parent organic matter, thermal evolutionary extent, and gas migration in shale systems. Our experiments and study proved that the isotope reversal shouldn't occur in a pure thermogenic gas reservoir, it must be involved with some other geochemical process/es; although mechanisms responsible for the reversal are still vague. Carbon isotopic composition of the Fayetteville and Barnett shale gas demonstrated that the isotope reversal was likely involved with water–gas reaction and Fischer-Tropsch synthesis during its generation.

Biogenic gases were reported to exhibit a “normal” carbon isotope order of δ13C1 < δ13C2 < δ13C3 < δ13C4, while abiogenic gaseous hydrocarbons in igneous rocks and meteorites exhibit a reversed distribution pattern in the order of δ13C1 > δ13C2 > δ13C3 > δ13C4. This reversed order in carbon isotope compositions is commonly thought to be unique to abiogenic gases, thus it can be a criterion for determining their origins. In this study, a closed system Fischer–Tropsch synthesis was conducted at 380 °C under 30 MPa and 390 °C under 30 MPa, 100 MPa, 200 MPa, respectively, with magnetite as a catalyst. Results of carbon isotope compositions of gaseous hydrocarbons were derived, which do not show an expected reversed order in carbon isotope composition from C1 to C3 hydrocarbons, even though features of partially reversed order in carbon isotope values, such as δ13C1 > δ13C2 < δ13C3, can still be commonly observed. This indicates that the reversed order of carbon isotope composition is not a unique criterion that can be typically used to distinguish abiogenic gases.