The dynamic paleoenvironmental conditions in lacustrine basins influence organic matter accumulation and hydrocarbon source rock development. However, the processes and mechanisms involved are diverse and complex, which limits the exploration of lacustrine shale oil to a certain extent. Here, from an integrated perspective combining sedimentary petrology and organic-inorganic geochemistry, we investigate the paleoenvironmental dynamics and its control on organic matter and shale oil enrichment in saline lacustrine, Permian Jimusar Sag. Our results indicate that the Lucaogou Formation formed in a sedimentary environment characterized by fluctuations in water salinity and the mixing of sediment from multiple sources. The lower sweet spot formed in a cold, arid, and stable climate characterized by strong evaporation, weak water circulation, high water salinity, and reducing conditions. These favorable preservation conditions primarily controlled the organic matter accumulation, with salt-tolerant planktonic algae making a greater contribution to the organic matter than in the upper sweet spot. The climatic and water conditions during deposition of the middle section were variable and the types of organic matter were diverse. The upper sweet spot was deposited during frequent climatic fluctuations, strong volcanic and hydrothermal activity, and a period of higher detrital sediment influx. High primary productivity, predominantly from bacteria and higher plants, controlled organic matter enrichment and even promoted shale oil accumulation. The water masses in upper and lower sweet spots exhibit distinct salinization mechanisms, with the former controlled primarily by hydrothermal activity and the latter by intense evaporative processes. Excellent source rocks developed in all three intervals due to both preservation and productivity. However, preservation more significantly controlled organic matter accumulation, whereas productivity was more influential in driving shale oil enrichment. These findings highlight environmental dynamics control on organic matter and even shale oil enrichment in saline lacustrine basins, which might be general throughout different ages and geographic areas.

The physical properties of coal reservoirs are crucial for evaluating deep coalbed methane (CBM) potential. The Jurassic Xishanyao and Badaowan formations in the Junggar Basin are key CBM targets, characterized by thick, stable, and widely distributed coal seams. To compare their reservoir differences, samples were collected and analyzed using coal petrography and pore structure tests. Key findings: ① Coal composition: Xishanyao formation is dominated by inertinite, followed by vitrinite, while Badaowan formation shows the opposite trend. Xishanyao has higher vitrinite reflectance. ② Depositional environment: Xishanyao formation formed in dry-humid forest swamps with herbaceous-woody plants, whereas Badaowan formation developed in shallow-deep waterlogged swamps dominated by herbaceous plants. ③ Coal quality: Both formations consist of low-rank bituminous coal with low moisture, low-medium ash, and ultra-low sulfur. ④ Pore-fracture features: Xishanyao formation exhibits balanced microporosity with good connectivity, partial mineral filling, and complex fractures. Badaowan formation has stronger heterogeneity, simpler fractures, and higher mineral filling. ⑤ The porosity of middle-low rank coal in the deep Jurassic strata of the Junggar Basin follows a “U”-shaped trend with organic matter evolution (inflection point at Ro,max=0.7%), characterized by compaction-induced porosity reduction during the relatively low-maturity stage and hydrocarbon generation-induced porosity increase during the relatively high-maturity stage, with continuous development of microfractures. Coal facies analysis indicates that high TPI, low GI, moderate GWI, and high VI promote the development of porosity in deep coal seams.

To provide a basis for investigating the resource potential and hydrocarbon accumulation patterns of the Cretaceous source rocks in the Junggar Basin, organic petrology, detailed geochemical characterization, and closed-system thermal simulation technology were employed. The study analyzed the geochemical characteristics and hydrocarbon generation potential of Cretaceous source rocks in different blocks of the basin. These source rocks showed strong heterogeneity and generally of low quality. However, high-quality source rocks were also present. Type Ⅰ and Type Ⅱ1 source rocks accounted for 39.6% of the total, and source rocks with total organic carbon (TOC) content > 1.0% accounted for 17.5%. In the Shawan, Manas and Hutubi area, located in the middle section of the southern margin of the basin, the Cretaceous source rocks had the largest sedimentary thickness, with dark mudstone thickness reaching up to 574 m and burial depth generally exceeding 6 000 m. The organic matter was mainly Type Ⅱ (89.1%), with 8.7% of the source rocks having TOC > 1.0%. Vitrinite reflectance (Ro) values ranged 0.82% to 1.01%, indicating that the source rocks were currently at the peak stage of oil generation. The source rocks had Pr/Ph values of 0.31 to 1.20 and gammacerane/C31 hopane ratios of 0.46 to 8.12, with dominant abundances of C27 and C29 regular steranes. C27, C28, and C29 regular steranes showed V-shaped distributions, indicating deposition in a strongly reducing, saline lacustrine environment. Aquatic algae were well-developed, and organic macerals developed lamalginite that emitted strong yellow fluorescence, indicating strong oil generation capacity. Cretaceous Type Ⅰ and Ⅱ1 source rocks had maximum oil generation up to 660.0 mg/g and 284.0 mg/g, respectively, with peak oil generation at Ro = 1.0%. Comprehensive study indicates that in the Shawan, Manas and Hutubi area, located in the middle section of the southern margin of the Junggar Basin, the Cretaceous source rocks are thick, rich in oil-generating lamalginite, currently at the peak stage of oil generation, and possess high oil generation capacity, making the area the most favorable target for Cretaceous-sourced oil generation.

This study investigates the effects of different types of primary organic matters on hydrocarbon generation and expulsion of source rocks. Samples representing three typical source rocks from the Lucaogou Formation in the Jimusaer Sag were collected and analyzed by hydrous pyrolysis, total organic carbon, Rock-Eval, gas chromatography-mass spectrometry, organic petrology, and scanning electron microscopy. Distinct differences in crude oil biomarkers were observed between telalginite- and lamalginite-rich source rocks. Telalginite-rich source rocks exhibit higher abundances of pristane, phytane, beta-carotane, gammacerane, and C29 regular steranes, while lamalginite-rich source rocks are characterized by enrichments of C24 tetracyclic terpane, C29 hopane, and C28 regular steranes. These biomarkers provide insights into the primary types of organic matter and their depositional environments with high water salinity of telalginite and low salinity of lamalginite. Hydrous pyrolysis results reveal that telalginite-rich source rocks demonstrate early hydrocarbon generation and a wider oil window than lamalginite-rich source rocks. Compared to lamalginite-rich source rocks, telalginite-rich source rocks produced better quality of crude oil, exhibit a smaller specific surface area of organic matter, and greater development of organic-inorganic pores, which contribute to their higher oil expulsion. These findings are helpful to the understanding of the constraints imposed by different primary organic matters on hydrocarbon generation and expulsion of the source rocks, and the insights have significant implications for exploration and development of the shale oil resources.

Due to the complexity of the lithofacies associated with shale oil in saline lacustrine basins, the differences of shale oil occurrence state and its controlling factors in different lithofacies are not completely clear. This hinders efficient shale oil exploration and development. We investigated the shale oil in the Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin, China, based mainly on sequential solvent extraction, petrological, organic geochemical, and nuclear magnetic resonance techniques. The fluidity of extractable organic matter decreased from the first extract to the fourth extract, which was caused by the gradual decrease in the contents of saturated and aromatic hydrocarbons, and gradual increase in the contents of NSO compounds and asphaltenes. The contents of free hydrocarbons (the first and second extracts) and adsorbed hydrocarbons (the third and fourth extracts) are very different among the lithofacies. The free hydrocarbon ratios in the siltstones and carbonate rocks are >70% and the main pore throats are >1 mu m in size, corresponding to the best sweet spots. The contents of free hydrocarbons in the laminated silty mudstones and shales with bedding fractures are >50%, which are also available. The free hydrocarbons in the siltstones and carbonates are saturated with migrated hydrocarbons, with the contents being more affected by the physical properties of rocks. In contrast, the free hydrocarbons in the mudstones are mainly self-generated and -stored, and their contents are controlled by total organic carbon contents and maturity. For the adsorbed hydrocarbons, the contents in all lithofacies are controlled mainly by the total organic carbon contents. The biomarker parameters record a slight increase in maturity from the fourth to the first extract. The & sum;C22-/& sum;C23+ values of n-alkanes in the third extract are the lowest, because carbonate minerals tend to capture long-chain n-alkanes. The sequential solvent extraction method provides new insights into the occurrence state and molecular geochemical characteristics of lacustrine shale oil in different lithofacies. Future exploration should focus on siltstones and carbonate rocks with a relatively high proportion of the first extract (free hydrocarbons occurring in large pores and fractures), and mudstones with a relatively high proportion of the second extract (free to adsorbed hydrocarbons occurring in matrix pores) that are suitable for hydraulic fracturing to aid production.(c) 2025 The Authors. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

Naphthenic crude oils are scarce resources of great value. Their origins are generally considered to be related to biodegradation, which consumes paraffins and enriches naphthenes. However, other possible controls on the origins of the naphthenic oils remain insufficiently clear. To fill the knowledge gap, we conducted a case study in the Junggar Basin by using comprehensive two-dimensional gas chromatography-mass spectrometry for semi-quantitative analysis of naphthenes in combination with relevant organic geochemical data, and address its global implications by synthesizing the typical naphthenic oils discovered worldwide. It was found that the occurrence of naphthenic crude oils in the basin was not caused by biodegradation alone, while sedimentary paleoenvironments and source-rock biological inputs (i.e., indicative of organofacies) are important controlling factors. Naphthenic crude oils are mainly derived from dolomitic source rocks of the Permian Fengcheng Formation in the Mahu Sag of the northwestern basin, where the average naphthene content is 43.8 %, with an average naphthene/paraffin (N/P) ratio of 1.24. Source rocks were deposited in a reducing, hypersaline and stratified alkaline lake (0.75 < pristane/phytane (Pr/Ph) < 1.46, gammacerane/C-30 alpha beta hopane > 0.23), with source-rock biological inputs being dominated by halophilic algae (steranes/hopanes > 1, C-28/C27-29-steranes > 40 %). In contrast, crude oils in the Jimusaer Sag of the southeastern basin are paraffinic-naphthenic with an average naphthene content of 24.8 % and an average N/P ratio of 0.75. Source rocks here were deposited in an anoxic-oxic lake of low salinity (1.05 < Pr/Ph < 1.59, 0.15 < gammacerane/C-30 alpha beta H < 0.18), and organic matter consists of mixed bacteria, algae, and terrigenous higher plants (steranes/hopanes < 1, C-28/C27-29-steranes < 40 %). Thermal maturity and biodegradation also control the composition of naphthenic oils. High thermal maturity promotes cracking of naphthenic groups, whereas moderate biodegradation (rank PM < 6) promotes naphthenic groups by preferentially catabolizing paraffins. Our results suggest that halophilic algae in strongly-reducing alkaline lakes provide important material for the generation of naphthenic oils in the Mahu Sag and the occurrence of naphthenic crude oils is not controlled solely by biodegradation; influencing factors are complex and vary between regions without universality. This may be the reason for their limited and sparse distribution worldwide.

Carbon isotopes have been used extensively in tracing the sources of oil. However, primary source facies and secondary alteration controls on oil isotopic compositions have not been well resolved, resulting in application uncertainties. A case study was undertaken for an alkaline lacustrine oil system in a lower Permian formation in the Junggar Basin, NW China. Results indicate that increasing maturity causes the carbon isotopic composition to become heavier for only short–middle-chain compounds, whereas source facies-related carbon assimilation controls the compositions of short-, middle-, and long-chain compounds. In particular, light-carbon assimilation during organic-matter degradation makes the isotopic composition lighter, whereas heavy carbon from the water mass makes it heavier. Accordingly, oils in this study area were divided into Type U and Type N oils based on individual compound carbon isotopic compositions, reflecting the difference in source facies in a highly saline and reducing stratified water environment. The results provide a better understanding of the controls on carbon isotopes in oil in sedimentary basins, reducing the uncertainty in oil–source correlation and addressing the origin of oil.

The alkaline lacustrine source rocks in the lower Permian Fengcheng Formation in the Mahu Sag, Junggar Basin, China, exhibit significant heterogeneity. However, most previous studies have focused on the vertical variability of the source rocks, and the lateral variability is poorly understood. This study investigated recently drilled samples of the Fengcheng Formation in the Manan area to assess the lateral variability of the source rocks. The geochemical characteristics of the Fengcheng Formation source rocks in the Manan area are variable, with low–high abundances of organic matter, which comprises types I–III kerogen that is mature to high-mature. These features differ from the typical Fengcheng Formation source rocks in the Wuxia–Fengcheng area, which have a high abundance of organic matter with substantial hydrocarbon and shale oil generation potential. Biomarker data show that the organic matter in the Fengcheng Formation source rocks in the Manan area is a mixture of higher plants, algae, and bacteria, which differs from the Wuxia–Fengcheng area where algae and bacteria are dominant. The Fengcheng Formation source rocks in the Manan area were deposited in an oxic to anoxic environment characterized by large variations in water salinity and stratification. Mudstones were deposited rather than carbonate rocks. This differs from the strongly reducing, hypersaline, and water-stratified depositional environment of the Fengcheng Formation source rocks in the Wuxia–Fengcheng area. These two areas are separated by the Dazhuluogou Fault, and there are no alkaline lacustrine deposits in the Manan area. The distribution of the alkaline lacustrine source rocks was controlled by the paleogeography and sedimentary environment, which was characterized by significant spatial heterogeneity.

Trace element tracing of oil-source rock correlations in petroliferous basins is a cutting-edge area of research in the field of petroleum geochemistry, providing an important supplement for the traditionally used organic geochemistry approach. However, the specific proxies and mechanisms are not well understood, limiting the application of the trace element approach and theoretical geochemical behavior during the oil generation, migration and accumulation. To fill the knowledge gap, based on a case study in the lower Permian Fengcheng Formation alkaline-lacustrine petroleum system, located in the northwestern Junggar Basin, Northwest China, novel trace element proxies for oil-source rock correlations was evaluated with the geochemical behavior and mechanisms being explored. Trace elements and conventional geochemistry in twenty source rock and nineteen crude oil samples were analyzed by inductively coupled plasma-mass spectrometry (ICP-MS) and gas chromatography-mass spectrometry (GC-MS) to systematically compare. Analysis of 33 commonly-detected trace elements showed that the transition metals (Ti, V, Cr, Ni, Cu, Zn, Mn, and Zr), alkaline earth metals (Sr and Ba), and nonmetallic elements (B and As) exhibit good correlations between each source rock and crude oil. However, the contents of these 12 elements exhibit changes by a factor of 0.3-1141 times from source rock to crude oil. Elements Ni, Cu, Zn and Cr are relatively enriched in crude oils, elements V, Ti, Mn and Zr are relatively enriched in source rocks, and elements B, As, Sr and Ba are not apparently enriched. This indicates that the elements contents cannot be directly used for oil-source rock correlations. Understanding the geochemical behavior and mechanisms of the differential enrichment of trace elements from source rock to crude oil is prerequisite. It is argued that the differential enrichment is mainly controlled by the geochemical partition of these elements, in the form of organic complexes (and chelates) or inorganic ions during hydrocarbon generation and accumulation. In detail, Ni and some V are chelated to organic porphyrin compounds by strong N-Ni/V bonds, which are little affected by petroleum migration and are thus relatively stable. In addition, most of the V occurs in insoluble mineral phases, and thus is preferentially enriched in source rocks during primary hydrocarbon migration. Chromium, Cu, and Zn are mainly complexed with O or S atoms in organic acids in the form of Cr-O or Cu (Zn)-S bonds. These chemical bonds are readily broken during secondary petroleum migration. Manganese, Zr, Ti, Sr, and Ba occur mainly in mineral phases in the source rocks and as ions during petroleum migration, and thus are modified by oil-rock interactions. Boron occurs mainly in mineral phases in the source rocks, but is easily complexed with organic acids, and thus undergoes limited modification due to secondary hydrocarbon migration. Arsenic occurs mainly as arsenide or arsenate ions, which are strongly affected by secondary petroleum migration. As such, Ni, V, B, Cr, Cu, Zn, and As are more reliable for oil-source rock correlations and are incorporated into four new parameters established in this study: (1) Ni contents can be used for oil-source rock correlations; (2) V/Ni and Ni/B ratios can be used to trace primary petroleum migration; and (3) a Cr-(Cu+Zn)-As ternary diagram can be used to trace secondary petroleum migration. In conclusion, trace elements in petroleum systems exhibit complex geochemical behavior during hydrocarbon generation and primary (secondary) oil migration. However, robust trace element proxies for oil-source rock correlations can be established after consideration of the geochemical behavior of each element. The proposed method is an important addition to conventional oil-source rock correlations based on organic geochemistry.

The Qingshuihe Formation in the western section of the southern margin of the Junggar Basin has excellent oil and gas exploration prospects. The systematic study of its diagenesis characteristics and pore evolution process will provide guidance for the later fine exploration and evaluation of oil and gas. Therefore, based on the analysis of ordinary thin sections, cast thin sections, whole rock X-ray diffraction, grain size, scanning electron microscopy, carbon and oxygen isotopes of carbonate cements and fluid inclusions, the diagenesis characteristics and pore evolution process of the Qingshuihe Formation in the western section of the southern margin of the Junggar Basin were systematically studied, and the differences of reservoir pore evolution process between different diagenetic facies were further discussed. The study shows that: (1)The reservoir of the Qingshuihe Formation in the studied area is dominated by glutenite. The content of rock debris is high, with an average of 65.97%, mainly tuff rock debris. The cement is mainly calcite. The average porosity of the reservoir is 6.2%, and the average permeability is 7.45×10-3 μm2. It is generally a tight reservoir of low porosity and low permeability, but high-quality reservoirs are still developed locally; (2)The reservoir burial mode of the Qingshuihe Formation in the southern margin of the Junggar Basin is characterized by long-term shallow burial and late rapid deep burial, and can be further divided into four evolutionary stages: long-term shallow burial, tectonic uplift to near surface, normal deep burial, and rapid deep burial. The diagenetic evolution of the reservoir was in early diagenetic stage A in the long-term shallow burial, tectonic uplift to near surface, and normal deep burial stages, while in the rapid deep burial stage, the reservoir was in early diagenetic stage B to middle diagenetic stage A; (3)The reservoir of the Qingshuihe Formation can be divided into four typical diagenetic facies types, namely, strong compaction facies, calcareous/iron argillaceous strong cementation facies, tuffaceous filling weak dissolution facies, and weak compaction pore development facies. The pore evolution model of the clastic rock reservoir of the Qingshuihe Formation in the southern margin of the Junggar Basin was established based on the constraints of diagenetic facies. The weak compaction pore development facies are high-quality reservoir diagenetic facies, followed by tuffaceous filling weak dissolution facies.

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.

As an important biological element, nitrogen is causally linked with organic matter accumulation, but a systematic and regular understanding has not been developed. This paper discusses this issue by taking the widely developed Permian-Paleogene terrestrial (lacustrine) hydrocarbon source rocks in China as an example. The results show that the terrestrial source rocks in China can be classified into three groups according to the nitrogen isotope (δ15N) compositions and combined with the salinity and evaporative alkali mineral characteristics: the circum-neutral group 1 (average δ15N=4.0‰±1.5‰), the circum-neutral group 2 (average δ15N=7.1‰±1.6‰), and the alkaline group (average δ15N=18.4‰±3.3‰). In the circum-neutral group with δ15N < 10‰, the δ15N of the source rocks is positively correlated with organic matter abundance, type, hydrocarbon generating capacity and shale oil potential due to the fact that higher δ15N characterizes changes in the composition of the hydrocarbon generating bio-precursors. In the alkaline group with δ15N>10‰, the organic matter types are good and shale oil potentials are higher, but the response relationship between δ15N of source rocks and organic matter accumulation is not as good as that of the circum-neutral group, reflecting that the organic matter accumulation in alkaline group is influenced by other comprehensive factors other than δ15N. Accordingly, the organic matter accumulation models of three types of lacustrine source rocks (< 5‰, 5‰-10‰, and >10‰) classified on the basis of δ15N were established. The δ15N has the potential to trace organic matter accumulation and quality of source rocks. For example, low δ15N type (δ15N < 5‰) is of poor quality and medium-high δ15N type (δ15N>5‰) is of good qualityin lacustrine source rocks. This paper enriches the biogeochemical and hydrocarbon source rock geochemical studies of nitrogen by exploring organic matter accumulation in source rocks from the new perspective of nitrogen isotope composition and nitrogen cycling.

Shale oil is becoming increasingly important in the global energy market, but its accumulation mechanism is not fully understood. We present novel and direct fluid inclusion data from the Lower Permian Fengcheng Formation, Mahu Sag, Junggar Basin, northwest China. Shortite veins in this source rock contain abundant two-phase gas-liquid hydrocarbon inclusions and coeval aqueous inclusions. The inclusions have highly variable degrees of bubble filling (5–80 vol% vapor) and homogenization temperature differences between oil and aqueous inclusions (~50 °C), which demonstrate that fluid (oil-gas-water) immiscibility occurred at high pressures. The hydrocarbon inclusions record different levels of fluid over-pressure (32.9–43.0 MPa), with a paleopressure coefficient of 1.3–1.7. Episodic fluid over-pressure release resulted in shale oil accumulation, with faults/fractures acting as important migration pathways. Oil from deeper and more mature source rocks within the Fengcheng Formation was expelled upward to the shale oil reservoir. These processes are common and important in shale oil systems. These results show that the accumulation of unconventional hydrocarbons occurs pervasively within the reservoirs, and fluid displacement is critical in exploration and exploitation.

Shale oil enrichment and accumulation in lacustrine strata is rather heterogeneous (unlike that in marine strata), which is a challenging issue to study. Here we carried out a case study in the Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin, northwestern China. Based on data from drill cores, thin sections, rock extracts, and crude oils (including well logging, petrophysics, nuclear magnetic resonance, organic geochemistry, and oil test), the differences of lithology, reservoir physical property, oil generation potential, shale oil content, and physical property and geochemistry of oil between the lower and upper sweet spots were comprehensively compared. Results show that a mixed sedimentary system comprising interbedded carbonate, siltstone, and mudstone was developed owing to terrigenous clastic sedimentation, volcanism, and carbonate deposition. The lower sweet spot has a relatively higher content of silt compared with the upper sweet spot. Due to spatial changes in the depositional environment, only the lower sweet spot occurs at the northeastern margin of the study area and only the upper sweet spot occurs at its southeastern margin, but both occur in the central part of the study area. The porosity and permeability of the sweet spots are highly heterogeneous, due to the complex sedimentary–diagenetic processes, and dissolution pores are common in the lower sweet spot. The hydrocarbon generation potential and shale oil content of the sweet spots are both excellent. Comparatively, the shale oil in the lower sweet spot has higher densities and lower wax contents than those in the upper sweet spot. Thus, the shale oil is more mobile in the upper sweet spot. This implies a high-salinity depositional environment for the lower sweet spot and the oils are generated from salt-tolerant planktonic algae. The oil saturation index (OSI) values are not entirely consistent with the test production results. This indicates that the shale oil productivity is comprehensively controlled by multiple factors, e.g., the hydrocarbon generation potential, reservoir physical properties, and shale oil mobility. These are key features that distinguish lacustrine from marine shale oil systems. The exploration and exploitation strategies of shale oil in lacustrine systems need to be carefully developed.

Lacustrine shale oil is typically heavier and more viscous than marine shale oil, impeding its exploration and exploitation. Thus, identification of its origin is key to elucidating its fluidity. Here, the middle Permian Lucaogou Formation of the Jimusar sag, Jung-gar Basin, China, was used as an example to investigate this issue. The main controlling factor for the characteristics of crude oil in the Lucaogou Formation is organic matter precursor inputs and their proportions (based on coevolution of biology and environ-ment) caused by different depositional paleoenvironments be-tween the upper and lower sections of the formation. The higher b-carotane abundance and C28/C29 sterane ratio than the average for contemporary Permian organic matter indicate that the organic matter precursor of the Lucaogou Formation was a type of salt -tolerant planktonic green algae, Dunaliella. The physical properties of crude oil from this unit (density, 0.87-0.92 g & BULL;cm 3; viscosity, 33.9-551.8 mPa.s) result from high resin and asphaltene content, typical of oils generated from Dunaliella-rich organic matter. Dur-ing deposition, higher water salinity in the lower section resulted in a higher abundance of Dunaliella. For this reason, crude oil from the lower section is heavier than that from the upper section, despite the lower section being more thermally mature. The organic matter precursor in the Lucaogou Formation resulted in high-density crude oil, which is difficult to process. However, light crude oil still exists at high-maturity stages. The understanding in this study is general for the formation of heavy oils in saline lacus-trine basins.

It is unclear whether source rocks deposited in ancient alkaline lakes undergo multiple stages of hydrocarbon generation, particularly of oils. In this study, the lower Permian Fengcheng Formation in the Junggar Basin, China, was investigated using the geochemistry of heteroatomic species, with a focus on N-containing com-pounds, by negative-ion electrospray high-resolution Fourier transform ion cyclotron resonance mass spec-trometry. The maturity parameters based on N-containing compounds (e.g., C0-5/C15-35-DBE 12 N1 and C0-5/ C15-35-DBE 15 N1) and aromatic hydrocarbons (TMNr) reveal progressive generation of mature to highly mature crude oils. The polymerization index P1 ([DBE 18 + DBE 15]/DBE 12_N1), alkylation index R1 (RC6_ 35/RC0-5), and paleo-salinity index (beta carotane/nCmax) of the Fengcheng Formation source rocks suggest that the high salinity inhibited molecular polymerization of organic matter and prolonged the oil generation peak, which produced highly mature crude oils in the late stages of hydrocarbon generation. Therefore, alkaline lacustrine source rocks undergo multiple stages of protracted oil generation, which results in a longer oil window and higher threshold for gas generation than in the case of the classic Tissot model. The results highlight the oil generation potential of deep basins containing alkaline lacustrine source rocks and highly mature organic matter, which also have a lower gas-generation potential than previously thought.

高演化有机质的生烃潜力评价与控制因素是油气地球化学研究的关键科学问题.以准噶尔盆地西北缘石炭-二叠纪不同成熟度烃源岩为例,从杂原子地球化学,特别是含氮化合物角度,应用高分辨率负离子傅里叶变换离子回旋共振质谱技术((-)ESI-FT-ICR-MS),基于分子演化模型进行了研究.结果表明,基于无荧光叶绿素代谢物(NCCs)模型的N1化合物有效记录了烃源岩生-排油过程之后残留在烃源岩中可溶有机质的特征,对有机质演化过程有重要指示意义.表征分子演化程度的聚合度(短链化、环化、芳香化)指数P1((DBE 18+DBE 15)/(DBE 12+DBE 9)_N1)和烷基化指数R1(RC6-35/RC0-5)以及经典的镜质体反射率VRo(％)和古盐度指标(β-胡萝卜烷/nCmax)揭示低盐度环境"成熟度控制"和高盐度环境"盐度-成熟度双重控制"的高演化有机质演化特征,高盐度通过抑制有机质分子聚合而延长生油高峰.结合咸化湖盆形成过程中烃源岩生烃母质组成的差异,提出其可能具有"多阶、持续、有序"的生烃模式,需要重视高演化阶段的生油潜力.

The Middle Permian Lucaogou Formation in the Jimusaer Sag is a hotspot for exploring and developing lacus-trine 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 per-formed 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, S1 x 100/TOC), EOM/TOC (extraction of organic matter/total organic carbon), C29 beta beta/(alpha alpha + beta beta), and C29 alpha alpha alpha 20S/(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 C29 beta beta/(alpha alpha + beta beta) and C29 alpha alpha alpha 20S/(20S + 20R) vs EOM/TOC ratio and HCI values, the lower C29 beta beta/(alpha alpha + beta beta) and C29 alpha alpha alpha 20S/(20S + 20R) limits for active source rocks were approximately 0.28 and 0.44, respectively.

咸化湖相沉积条件下形成的细粒沉积岩是我国页岩油勘探的热点层系.本文依据有机岩石学、扫描电镜、生烃动力学和高温高压加水热模拟实验,对准噶尔盆地吉木萨尔凹陷芦草沟组咸化湖相含有典型层状藻和结构藻的烃源岩的成烃特征进行对比研究.有机岩石学及扫描电镜观察表明两种藻类的赋存形式差异明显,结构藻的赋存形式主要为孤立分布特征,长度约为20～50 μm;层状藻垂向上呈书页状叠置,水平延伸长.生烃动力学及高温高压热模拟实验结果指示了两种有机质的成烃过程具有明显的差异性,其中结构藻为主的烃源岩在较低成熟度就可以生成一定量烃类,随着演化程度的增加,生油速率缓慢,生油范围宽;层状藻为主烃源岩的生烃特征表现为集中生烃,生油窗范围窄且主要生烃活化能较高.该认识对于有效烃源岩评价和页岩油勘探层段与甜点区的选择均具有重要的启示和指导意义.

Methane (CH4) is an important greenhouse gas, but its behavior and influencing factors over geological time scales are not sufficiently clear. This study investigated the Late Paleozoic Ice Age (LPIA), which is thought to have experienced an interval of rapid warming at ca. 304 Ma, that may have been analogous to modern warming. To explore possible causes of this warming event, we investigated ancient alkaline lakes in the Junggar Basin, northwestern China. Results show that microbial CH4 cycling here was strong, as evidenced by carbonate delta C-13 (delta C-13(carb)) values of >5 parts per thousand, similar to+0.6 parts per thousand offsets between pristane delta C-13 (delta C-13(Pr)) and phytane delta C-13 (delta C-13(Ph)) values, a 3 beta-methylhopane index of 9.5% +/- 3.0%, and highly negative delta C-13 values of hopanes (-44 parts per thousand to -61 parts per thousand). Low sulfate concentrations in the alkaline lakes made methanogenic archaea more competitive than sulfate-reducing bacteria, and the elevated levels of dissolved inorganic carbon promoted methanogenesis. Biogenic CH4 emissions from alkaline lakes, in addition to CO2, may have contributed to rapid climate warming.