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.

Most oil reservoirs that were found in the Junggar Basin are located in the Mahu sag and neighboring areas. Oil sources and classifications remain unresolved in this region. Oil source assessment can be partially inconsistent on the basis of different molecular and isotopic parameters. In the present study, classifications for the 92 studied oils from the Mahu sag and neighboring areas were performed using chemometric analysis, e.g., hierarchical cluster analysis (HCA) and principal component analysis (PCA) on the basis of integration of sixteen facies parameters. These parameters consist of isotope reversal index (RI), delta 13C of n-C25, Ph/n-C18, beta-carotane/n-C21, six terpane ratios of Ts/C23 tricyclic terpanes, Ts/ (C28+C29 tricyclic terpanes), C29 Ts/C23 tricyclic terpanes, C29Ts/(C28+C29 tricyclic terpanes), C30 diahopane/C23 tricyclic terpane and C30 diahopane/(C28+C29 tricyclic terpanes), and six ratios of polynuclear aromatic hydrocarbons (PAH) including trimethylnaphthalenes (TMNs)/(TMNs + phenanthrene (Phen)), tetramethylnaphthalenes (TeMNs)/(TeMNs + Phen), TMNs/(TMNs + methylphenanthrenes (MPs)), TeMNs/(TeMNs + MPs), TMNs/(TMNs + chrysene (Ch)) and TeMNs/(TeMNs + Ch). These sixteen parameters are mainly influenced by source facies and less influenced by maturity as demonstrated in the crossplots of these sixteen parameters versus concentrations of C30 hopane. Oil classifications are more reliable and convenient using chemometric analysis (HCA and PCA) integrating the sixteen facies parameters, compared with using crossplots of two parameters or star charts of several parameters. The 92 oils are classified into three groups using HCA and PCA, i.e., Group I, II and III. Group I and II oils are derived from source rocks within the Lower Permian Fengcheng Formation (P1f) and Middle Permian Lower Wuerhe Formation (P2w), respectively. Group III oils are mixtures of Group I and II oils. Group I consists of fifty oils mainly located at the northeastern and central areas of the Mahu sag with only three oils at the southwestern area of the Mahu sag. Group II consists of fourteen oils at the southwestern area of the Mahu sag. Group III consists of twenty-eight oils located at the southwestern and central areas of the Mahu sag. Locations of Group I, II and III oils reflect the distributions of effective source rocks containing oil-prone Type I/II kerogen within the Fengcheng (P1f) and Lower Wuerhe formations (P2w). (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-ncnd/4.0/).

The Shawan Sag is one of the most promising blocks in the western Junggar Basin for natural gas and oil exploration. To date, the research and exploration degree here is still low, and there is limited understanding of the origin and migration of natural gas and oils, which seriously restricts future exploration and development. At least three oil charging episodes and one gas charging episode could be confirmed in the reservoirs on the western slope of the Shawan Sag based on the analysis of concentrations and ratios of hopanes and steranes, diamondoids, and light hydrocarbons. The first and second charging oils originated from the peak and late oil generation window stages of Lower Permian Fengcheng Formation (P1f) source rocks, respectively. The third charging oil originated from the late oil generation window stage of source rocks of the Middle Permian lower Wuerhe Formation (P2w). Combining the carbon isotopic compositions and the gas composition, the fourth charging gas was derived from the postmature source rocks of Carboniferous(C) and Lower Permian Jiamuhe Formation (P1j) and the high-postmature source rock of Lower Permian Fengcheng Formation (P1f). The preservation conditions of nature gas in the Mesozoic (T-K) cap rocks in the Shawan Sag, as indicated by methyladamantanes (MAs)/methyldiamantanes (MDs) ratio, are better than those in the Mahu Sag. In this study, the methyladamantane maturity parameters of oils in the reservoirs were proposed to evaluate the maturity and further determine the migration direction of late-charging natural gas. The results suggest that late postmatured natural gases were charged from the southern part to the northwest of the Shawan Sag. Therefore, the southeastern direction of Well SP1 is a favorable area for natural gas exploration in the Shawan Sag. Meanwhile the northern part of the sag is favorable for the exploration of high-mature oil generated from source rocks within the Middle Permian Lower Wuerhe Formation.

AbstractDifferent from the Qaidam basin with about 320 billion m3 microbial gas, only limited microbial gases were found from the Junggar basin with similarly abundant type III kerogen. To determine whether microbial gases have not yet identified, natural gas samples from the Carboniferous to Cretaceous in the Junggar basin have been analyzed for chemical and stable isotope compositions. The results reveal some of the gases from the Mahu sag, Zhongguai, Luliang and Wu-Xia areas in the basin may have mixed with microbial gas leading to straight ethane to butane trends with a “dogleg” light methane in the Chung’s plot. Primary microbial gas from degradation of immature sedimentary organic matter is found to occur in the Mahu sag and secondary microbial gas from biodegradation of oils and propane occurred in the Zhongguai, Luliang and Beisantai areas where the associated oils were biodegraded to produce calcites with δ13C values from + 22.10‰ to + 22.16‰ or propane was biodegraded leading to its 13C enrichment. Microbial CH4 in the Mahu sag is most likely to have migrated up from the Lower Wuerhe Formation coal-bearing strata by the end of the Triassic, and secondary microbial gas in Zhongguai and Beisantan uplifts may have generated after the reservoirs were uplifted during the period of the Middle and Late Jurassic. This study suggests widespread distribution of microbial gas and shows the potential to find large microbial gas accumulation in the basin.

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.

Recently, significant oil discoveries have been made in the shallower pay zones of the Jurassic Badaowan Formation (J1b) in the Mahu Sag, Junggar Basin, Northwest China. However, little work has been done on the geochemical characteristics and origins of the oil in the J1b reservoir. This study analyzes 44 oil and 14 source rock samples from the area in order to reveal their organic geochemical characteristics and the origins of the oils. The J1b oils are characterized by a low Pr/Ph ratio and high β-carotene and gammacerane indices, which indicate that they were mainly generated from source rocks deposited in a hypersaline environment. The oils are also extremely enhanced in C29 regular steranes, possibly derived from halophilic algae. Oil-source correlation shows that the oils were derived from the Lower Permian Fengcheng Formation (P1f) source rocks, which were deposited in a strongly stratified and highly saline water column with a predominance of algal/bacterial input in the organic matter. The source rocks of the Middle Permian lower-Wuerhe Formation (P2w), which were deposited in fresh to slightly saline water conditions with a greater input of terrigenous organic matter, make only a minor contribution to the J1b oils. The reconstruction of the oil accumulation process shows that the J1b oil reservoir may have been twice charged during Late Jurassic–Early Cretaceous and the Paleogene–Neogene, respectively. A large amount volume of hydrocarbons generated in the P1f source rock and leaked from T1b oil reservoirs migrated along faults connecting source beds and shallow-buried secondary faults into Jurassic traps, resulting in large-scale accumulations in J1b. These results are crucial for understanding the petroleum system of the Mahu Sag and will provide valuable guidance for petroleum exploration in the shallower formations in the slope area of the sag.

The Hongche fault belt-Chepaizi uplift in the northwestern margin of Junggarbasin has many oil and gas reservoirs,and the physical and chemical properties and geochemical characteristics of crude oil are very complex,so the type and source of crude oil have long been controversial,which directly affects the decision of oil and gas exploration.Based on the summary of typical geochemical characteristics of crude oils and main oil source identification indexes in different ages of Junggar basin,this paper systematically analyzed and studied the geochemical characteristics and sources of the crude oils in Hongche fault belt and Chepaizi uplift,and divided the crude oils in this area into three types with single source and two types with mixed sources.Three types of single source crude oils are derived from the lacustrine source rocks of Permian,coal measure source rocks of the Middle and Lower Jurassic,lacustrine source rocks of the Paleogene Anjihaihe Formation.The two types of mixed crude oils are mixed from the biodegraded heavy oil derived from the Permian lacustrine source rocks,the normal crude oil derived from the Middle and Lower Jurassic coal measure source rocks,and the normal crude oil derived from the Paleogene lacustrine source rocks.The crude oil of the Carboniferous-Cretaceous oil reservoirs in the Hongche fault belt is mainly derived from the Permian lacustrine source rock,and the heavy oil in Chunfeng oilfield in the northeast of Chepaizi uplift is also derived from the Permian lacustrine source rock.Light crude oil in the Neogene Shawan Formation oil reservoir on the east side of Chepaizi Uplift and west side of Hongche fault belt is derived from Paleogene lacustrine source rocks.The heavy oil of the Cretaceous-Paleogene oil reservoirs in the Chunguang oilfield in the middle of Chepaizi uplift is the mixture of the Permian sourced heavy oil and the Jurassic sourced normal crude oil,and the heavy oil of Neogene Shawan Formation oil reservoir is the mixture of the Permian sourced heavy oil and the Neogene sourced normal crude oil.The light crude oil of the Carboniferous-Paleogene oil reservoir in the west of Chepaizi uplift is derived from the Middle-Lower Jurassic coal measure source rocks,while the light crude oil of the Neogene Shawan Formation oil reservoir is derived from the Paleogene lacustrine source rocks.This paper has important reference for the study of hydrocarbon accumulation and regional oil and gas exploration decision in the southern area of northwest margin of Junggar basin.

In order to clarify the reason for generally high drying coefficient of natural gas in Cainan area of the Junggar Basin and find out the law of natural gas migration and accumulation, the analysis of natural gas components and carbon isotopes, rock mineral composition in reservoir, bulk carbon and oxygen isotope of calcite, and laboratory hydrocarbon oxidation simulation experiments were carried out. The Jurassic natural gas in Cainan area is dominated by methane, with drying coefficient of generally greater than 0.95, and δ 13 C 1 value of basically greater than-32‰. Among C 7 light hydrocarbons, methylcyclohexane is dominant, with methylcyclohexane index of greater than 50%, indicating that natural gas in the study area came from high-over mature Carboniferous source rocks. Judging from natural gas migration identification index of ln（C 1 /C 2 ） with δ 13 C 1 -δ 13 C 2 , from well block Cai-47 to well block Cai-31, and then to well block Cai-003, ln（C 1 /C 2 ） values gradually increased, but δ 13 C 1 -δ 13 C 2 values did not show a trend of decreasing or increasing, indicating that migration or maturity is not the main controlling factor for the changes of natural gas composition and carbon isotope in the study area. Hydrocarbon thermal oxidation simulation experiments showed that alcohols in oil and gas were oxidized by MnO 2 to generate methane and carbon dioxide at 125 ℃, and methane could only be oxidized to generate CO 2 when the temperature reached 200 ℃,thus changing the composition of oil and gas and increasing methane content in natural gas.Using backscattered electron probe technology,it was found that there are two types of calcite in Jurassic dry gas interval in the study area. One type of calcite has a high Mn content,which can be as high as 3%. It appears bright orange and orange under cathodoluminescence. In addition,the bulk carbon isotope of calcite is negatively biased,which is 5‰-10‰ more negative than that of normal calcite. The higher content of Mn in calcite,the more negative of bulk carbon isotope,confirming that there is widespread weak oxidation of hydrocarbons in the Jurassic dry gas interval in Cainan area. Comprehensive analysis suggested that the reason for abnormally high drying coefficient of Jurassic natural gas in Cainan area is that the humic source rocks have undergone high-over mature evolution to generate natural gas that accumulated in Jurassic reservoirs rich in oxidizing minerals. Then the oxidation of hydrocarbons caused methane content in natural gas to increase further,resulting in a generally high drying coefficient of natural gas.

The formation mechanism for thermogenic gas remains unresolved. Disputes are focused on: (1) stability barrier for decomposition of oil to gas and wet gas to methane, and (2) inconsistence in dryness ratio (C1/sigma C1-5) between gases produced in pyrolysis experiments and in natural reservoirs. Here, we demonstrate the variation trend of dryness ratio (C1/sigma C1-5) with temperatures and thermal stress levels, and the correlation of dryness ratios with the yields of liquid components (sigma C8+) in confined pyrolysis experiments (gold capsules) of twenty coals. At both heating rates of 2 and 20 degrees C/h, dryness ratios of gaseous hydrocarbons at first decrease, and then increase with increasing temperatures and thermal stress levels. Dryness ratios of produced gases can be very high in the range of 66.3-95.7 wt% at initial temperature about 334 degrees C and heating rate of 20 degrees C/h, corresponding to EASY%Ro 0.56. We suggest that these gases are not the original products released from kerogen, but have been altered via wet gas incorporation to kerogen. Larger oil molecules (C8+) are more competitive in incorporating to kerogen compared with wet gases, and therefore, prohibit wet gas incorporation, leading to the observed trend of gas dryness ratios with increasing temperature and maturity and the negative correlation between dryness ratios and the yields of liquid components (sigma C8+). The conflicting results between the yields and carbon isotopes of wet gases produced in the isothermal confined pyrolysis experiments for coal plus oil can be well interpreted using the reaction mechanism that wet gases incorporate to kerogen while oil components retard this incorporation. Once free oil and wet gas molecules are reincorporated to kerogen, the bound molecules can easily decompose to smaller molecules due to substantial reduction of activation energy for carbon-carbon bond rupture. Petroleum formation from kerogen can be a recycling process: kerogen first releases oil compounds, and then free molecules reincorporate to kerogen and further decompose to smaller molecules, and finally to methane.

为研究准噶尔盆地东部石炭系优质火山岩发育规律,通过野外踏勘、岩心观察、铸体薄片鉴定、孔渗分析、测井及地震分析方法研究了火山岩储层特征及分布.结果表明:石炭系火山岩主要岩性岩相以溢流相安山岩、爆发相凝灰岩为主,其次为溢流相玄武岩、爆发相火山角砾岩;火山岩储层中气孔+溶蚀孔和溶蚀孔+裂缝型孔隙为有利的孔隙组合类型,溢流相玄武岩、安山岩和爆发相火山角砾岩储层物性最好,为优质储层发育岩性;优质火山岩储层发育受火山喷发环境、岩性岩相及后期构造改造综合控制,火山岩喷发环境决定了储集空间的发育程度与规模,水上喷发环境造成火山岩原生气孔较为发育,后期淋滤溶蚀改造较为强烈,因此水上喷发环境的火山岩储集性能要好于水下喷发环境;石炭系火山活动具有沿断裂呈串珠-中心式分布的特征,受到构造活动影响,靠近断裂的储层发育有大量的裂缝,对火山物性的改善至关重要,靠近断裂还可沟通烃源岩与储层,为后期有机酸溶蚀创造有利条件.可见准噶尔盆地东部石炭系火山岩油气勘探潜力巨大,火山岩储层中靠近断裂的水上近火山口爆发相和水下近火山口侵出相是最有利储层发育带,有利的火山岩区带主要分布在准噶尔盆地东部滴西地区、五彩湾地区和东部大井地区.

The Permian Lucaogou Formation in the Jimusar Sag in the east of the Junggar Basin is a typical continental shale oil series in China. Employing the semi-closed thermal simulation system, an experimental study on hydrocarbon generation and expulsion of shale with different source-reservoir structures was carried out to explore the efficiency and composition characteristics of hydrocarbon generation and expulsion of shale in the Permian Lucaogou Formation with different source-reservoir structures so as to provide reference for the enrichment rule of shale hydrocarbon and the fine evaluation of "sweet spots". The experimental results show that thick reservoir interbedded with thin source rock is more conducive to hydrocarbon expulsion and features the highest hydrocarbon expulsion efficiency, while thin source rock interbedded with thin reservoir features slightly lower hydrocarbon expulsion efficiency, and thick source rock interbedded with thin reservoir features the lowest hydrocarbon expulsion efficiency. When reservoir lithology is clastic rock, the hydrocarbon expulsion efficiency of thick reservoir interbedded with thin source rock, thin source rock interbedded with thin reservoir, and thick source rock interbedded with thin reservoir are 35.6%, 30.7%, and 25.6%, respectively. When reservoir lithology is carbonate rock, the hydrocarbon expulsion efficiency of these three combinations are 27.4%, 27.5%, and 12.3%, respectively. Combined with composition of expelled hydrocarbon, received hydrocarbon in reservoir, and retained hydrocarbon in source rock, it is found that received hydrocarbon in reservoir rock is mainly supplied by neighboring sources, and the farther away from source-reservoir interface, the less relevant relationship between source rock and hydrocarbon in reservoir. Hydrocarbon in reservoir is supplied by lower adjacent source rock in thick reservoir interbedded with thin source rock, and the received hydrocarbon in upper clastic reservoir is 10.7 mg/g, while received hydrocarbon in lower clastic reservoir is only 1.4 mg/g. The thick source rock interbedded with thin reservoir is mainly self-generated and self-stored, and the content of retained hydrocarbon in source rock is high, the received hydrocarbon in upper clastic reservoir is 6.0 mg/g, while retained hydrocarbon in source rock is 21.1 mg/g. Hydrocarbon in reservoir is mainly supplied by lower adjacent source rock and partly from its own source rock in thin source rock interbedded with thin reservoir. There is no significant difference between source rock and reservoir rock in the extraction family, with the content of saturated hydrocarbon in the range of 22.8%-33.0%, aromatics in the range of 6.2%-15.1%, and non-hydrocarbon and asphaltene in the range of 28.5%-41.1% and 21.0%-30.0%. Moreover, different reservoir lithology has relatively weak influence on hydrocarbon generation and expulsion efficiency, and the hydrocarbon-bearing heterogeneity is weak in thin source rock interbedded with thin reservoir. From the perspective of hydrocarbon generation and expulsion efficiency of shale with different source-reservoir structures, thick reservoir interbedded with thin source rock and thin source rock interbedded with thin reservoir are the favorable combinations for hydrocarbon exploration in the shale of the Lucaogou Formation.

Occurrence state of shale oil in saline lacustrine basins is complex, thus restricting the availability of highefficiency shale oil exploration and exploitation. To address the complexity, we conducted a study of the middle Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin, China, in a lithofacies perspective, using comprehensively multi-step Rock-Eval pyrolysis (MREP) and mineralogical, petrological, and organic geochemical methods. Results show that the low-mature to mature Lucaogou Formation in this study consists mainly of four lithofacies types, i.e., carbonate rocks, dolomitic/calcareous mudstones, silty/tuffaceous mudstones, and siltstones. The amount of free hydrocarbon (S1-1 + S1-2) and revised free hydrocarbon (S1-1 + S1-2 + S2-1) values obtained by MREP exceeds the S1 value obtained by conventional REP, which refines the evaluation of the shale oil potential. Shale oil in siltstones and carbonate rocks occurs mostly in fractures and pores in the free state, whereas the shale oil in mudstones occurs mainly in the matrix and kerogen, and on mineral surfaces in an adsorbed state. The shale oil potential of the four main lithologies is overall good, with the siltstone having the best potential (i.e., oil saturation index [OSI = S1 x 100/TOC] OSIavg = 313.22 mg HC/g TOC) and highest free hydrocarbon content ([S1-1 + S1-2]avg = 13.53 mg HC/g rock). The tuffaceous/silty mudstone has the best hydrocarbon generation potential (TOCavg = 8.01 wt%; PG = [S1 + S2]avg = 46.11 mg HC/g rock) and the highest content of adsorbed hydrocarbon (S2-1 avg = 13.78 mg HC/g rock), but the lowest shale oil potential (OSIavg = 105.78 mg HC/g TOC). The controlling factors on the free hydrocarbon content (S1-1 + S1-2) are complex but are mainly controlled by petrophysical properties. The amount of adsorbed hydrocarbon (S2-1) is controlled by the organic matter content. When a rock in the Lucaogou Formation has OSI > 100 mg HC/g TOC, the ratio of free to revised free hydrocarbon is > 50%, and the free hydrocarbon content is > 10 mg HC/g rock, the shale oil is favorable for exploration. Exploration and development of shale oil resources in saline lacustrine basins needs to consider the shale oil potential and its occurrence state and focus on sweet spots with good petrophysical properties, such as siltstones and carbonate rocks.

It remains disputed why a large amount of oil but only a limited amount of gas has been discovered in the northwestern Junggar Basin of China, although most source rocks are post-mature. Quantitative GC, GC-MS and GC-IRMS analyses were performed on 92 oils from this region to investigate gas charging and leakage of the petroleum reservoirs in the Mahu sag and nearby areas of the northwestern portion of the Junggar Basin. The 92 oils have moderate to high concentrations of C30 hopane (18-3840 ppm) and sigma C29 regular steranes (38-6100 ppm), demonstrating that these oils have normal maturities, within the oil generation window. However, these oils have high heptane and isoheptane values in the ranges of 31.1-52.2 and 0.82-7.74, respectively, and dia-mondoid (4-+ 3-methyldiamantanes) concentrations over a wide range of 1.07-22.0 ppm. These results demonstrate that the reservoirs for all the studied oils have multiple charging episodes: terpanes and steranes entered the reservoirs along with the initial oil charges from source rocks within the oil generation window while light hydrocarbons and diamondoids mainly entered the reservoirs along with the late gas and condensate charging from deep post-mature source rocks. The difference between the maximum and minimum 4-+ 3-meth-yldiamantane (4 + 3MD) concentrations (Cmax - Cmin)/Cmax is equal to 0.95. A higher ratio of (Cmax - Cmin)/Cmax (> 0.50) can be indicative of late gas and condensate charging to the reservoirs. Lower gas/oil ratios (GOR) for the reservoirs of the studied oils can be mainly ascribed to gas leakage.

通过有机岩石学和生物标志物相结合的方法,对准噶尔盆地玛湖百里大油区二叠纪碱湖的生物组成及其成藏贡献进行了研究.结果表明,碱湖风城组烃源岩生物组成总体表现为菌藻类丰度高、高等植物丰度低的特征,因此以生油为主,形成了大油区.发现了疑似类杜氏藻和蓝细菌两种特征生烃母质,除化石证据外,还揭示了生物标志物特征,前者是高的C 28 /C 29 甾烷比值和β-胡萝卜烷丰度,后者是中链单甲基烷烃的检出.生烃母质的分布与沉积环境协同演化,受控于沉积水体的盐度和分层,与类杜氏藻的丰度正相关,因此碱湖中心区发育类杜氏藻型烃源岩,边缘区发育蓝细菌型烃源岩,进而玛湖百里油区不同区域的原油聚集有差异来源,表现为“源控”特征.咸化湖盆烃源岩生烃母质组成很可能受烃源岩时代和沉积水体盐度的联合控制,而耐盐碱绿藻合成类胡萝卜素和甾醇等脂类化合物的生理机制可能影响了古绿藻演化途径.

沙湾凹陷周缘天然气混源现象普遍,前期缺少对地区的整体研究,制约了研究区天然气成藏研究.为此,系统开展了天然气地球化学特征分析,结合烃源岩热模拟技术,明确研究区中、浅层天然气的成因.研究显示,沙湾凹陷周缘中、浅层天然气以甲烷为主,干燥系数分布在0.73～1.00,δ13C1值分布在-56.0‰～-31.5‰,反映研究区成熟与高-过成熟天然气共存;δ13C2值分布在-30.4‰～-22.8 ‰,反映研究区煤型气、油型气和混合型气均有分布.结合烃源岩热解气碳同位素特征,认为研究区天然气具有4种成因类型:Ⅰ类天然气来源于佳木河组烃源岩,主要分布在红车断裂带中段白垩系,具有极重的δ13C2值,大于-25.5‰,C7轻烃中甲基环己烷含量大于50％;Ⅱ类天然气分布少,主要为原油降解次生生物气,具有异常偏负δ13C1值和极高的干燥系数;Ⅲ类天然气来源于下乌尔禾组烃源岩,主要分布在小拐地区及红车断裂带南段侏罗系,δ13C2值分布在-27.9‰～-26.4‰,具有混合型烃源岩特征;Ⅳ类天然气为下乌尔禾组烃源岩与风城组烃源岩混源,主要分布在红车断裂带南段、北段及金龙地区,以下乌尔禾组来源为主的天然气δ13C2值大于-29 ‰,以风城组来源为主的天然气δ13C2值小于-29‰.

为明确准噶尔盆地高泉背斜高探1井油藏沥青质沉淀原因，采用高温超高压模拟实验技术，探讨了不同温度、压力条件下高探1井原油沥青质沉淀过程及沉淀量，结合ICP-MS和傅里叶变换离子回旋共振质谱技术，明确了沉淀物沥青质分子组成及金属元素组成对沥青质析出的影响。研究结果显示，温度、压力和无机矿物中金属原子是高探1井沥青质沉积的外部影响因素，其中压力是最关键因素。在134℃恒温条件下，当压力降至88.9 MPa,原油中沥青质开始迅速沉淀，压力降至74.3 MPa以下时，沥青质沉淀速率明显降低，压力降至泡点压力后，沥青质又开始大量沉淀。在105℃恒温条件下，压力降至80 MPa和20 MPa时，加入无机矿物原油的沥青质沉淀量较未加无机矿物的原油同比增长了16.7%和3.8%,说明无机矿物对沥青质沉淀具有促进作用。通过分析无机矿物组分显示，沉淀物中金属元素主要有钙、钡、钠、铁等，其中钙含量最高，为4.96%,其次是钡含量为3.16%。高探1井油藏原油沥青质中富含高缩合度、多氧原子类组分，该类组分在地层条件溶解于原油中，在温度、压力下降过程中，原油溶解能力下降，高缩合度组分由于溶解性低易于从原油中沉淀出来，并且由于富含强极性多氧原子组分，易与来自地层矿物中的金属原子形成更稳定的络合物结构，两者协同作用加速了沥青质沉淀。

The co-evolution of paleo-environment and bio-precursors in alkaline lakes is of significance to understand the extreme environment system and associated enigmatic hydrocarbon potential. Here we used organic petrology and biomarker geochemistry to investigate the bio-precursors in a Permian alkaline paleo-lake in the Mahu mega-oil province within about a hundred miles of the Mahu Sag, Junggar Basin, China, and its effect on oil generation and accumulation. In general, the bio-precursors in the alkaline lacustrine source rocks of the Fengcheng Formation were mainly bacteria and algae, with a low abundance of higher plants. Therefore, these source rocks were mainly prone to oil generation. Two distinctive hydrocarbon-generating bio-precursors—Dunaliella-like algae and cyanobacteria—were identified. In addition to fossil evidence for these bio-precursors, the former results in a high C28/C29 sterane ratio and β-carotane abundance, and the latter results in the formation of medium-chain monomethyl alkanes in terms of biomarkers. The nature of the bio-precursors varied with the sedimentary paleo-environment, and was controlled by the salinity and stratification of the lake. Dunaliella-type source rocks were deposited in the central area of the alkaline lake, and cyanobacteria-type source rocks were formed around the lake margins. The crude oils in different parts of the Mahu mega-oil province within about a hundred miles have different sources. The bio-precursors in the saline lacustrine source rocks were jointly controlled by the age and water salinity of the source rocks. The physiological synthesis of carotenoids and sterols by haloalkaliphilic green algae may have affected the evolution of ancient green algae.

Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS) was employed to analyze the compositional differences of asphaltene of oil and blockage extracts of well Gaotan 1 on the southern margin of Junggar Basin. The correlation between asphaltene composition and structure and precipitation was discussed, which is important for the research of asphaltene precipitation and accumulation. Results showed that the asphaltene molecules of oil and blockage extracts of well Gaotan 1 are mainly composed of N1, N1O1, O1, O2, O3 and O4 class species. However, the degree of asphaltene condensation in blockage extract is significantly higher than that in oil, and it is enriched with O2, O3 and O4 class species. It indicates that during the flow of formation crude oil in wellbore, the precipitation of asphaltenes with different compositions has a certain selectivity. Asphaltene components with high condensation degree preferentially precipitate and deposit, forming a solid core. Among them, polyoxo-heteroatom compounds have relative strong polarity, which accelerates the precipitation of other asphaltene components in crude oil to form blockage. Asphaltene in blockage extract has a complex molecular structure and a wide range of condensation degree. The DBE values distribute between 9 and 30. Its molecular polar force parameter is larger and the distribution range is wider. Therefore, it is ideal to select a mixed solvent similar to the polar force parameter of blockage asphaltene to remove blockage.

准噶尔盆地玛湖凹陷二叠系风城组、乌尔禾组和其他不同层系原油中普遍检测出三芳甾烷(TAS)和三芳甲藻甾烷系列.基于多口井的原油和14块代表性烃源岩样品的芳烃组分色谱-质谱资料,系统分析其TAS组成特征,并将其用于油源对比研究.结果表明:TAS分布特征可以有效区分准噶尔盆地玛湖凹陷二叠系风城组烃源岩和乌尔禾组烃源岩.风城组烃源岩中TAS具有C26?20S含量低、C27?20R含量高的分布特征,并且几乎不含有三芳甲藻甾烷;而乌尔禾组烃源岩中TAS具有相反的分布特征,即C26?20S相对丰度较高,C27?20R相对丰度较低,并且具有分布完整的三芳甲藻甾烷系列.玛湖凹陷不同层系原油TAS分布特征基本一致,主要表现为C26?20S含量低,C27?20R含量高,三芳甲藻甾烷含量低或者未检测出,与风城组烃源岩分布特征相似.应用C26?20S/C28?20S TAS与C27?20R/C28?20R TAS比值和TAS三角图图版进行了原油对比分析,结果表明不同层系原油均来源于风城组烃源岩.因此,三芳甾烷及三芳甲藻甾烷系列可以作为该区油源对比的有效分子标志物.