The Kuqa Depression, a prolific hydrocarbon province in China's Tarim Basin, hosts a dual-sourcepetroleum system with Jurassic coal-bearing and Triassic lacustrine strata. However, the origins and accumulation mechanisms of hydrocarbons in the Dibei Structural Belt remain contentious, particularlyregarding contributions from Jurassic (J(2)kz, J1y) versus Triassic (T(3)h, T(2-3)k) source rocks, compoundedby ambiguities in biomarker interpretations and uncalibrated thermal models. Advanced geochemicalfingerprinting - including sterane distributions, gammacerane indices (GI; ratio of gammacerane to C30hopane), and delta & sup1;& sup3;C isotopes - was integrated with calibrated burial-thermal modeling and structural analysis,which allowed us to clarify source contributions, hydrocarbon charging history, and structural controlson accumulation. Geochemical results demonstrated that Yangxia Formation (Paleogene; a major regionalseal and secondary reservoir unit within the Kuqa Depression) oils exhibit "inverted-L" sterane patterns(C27 < C29) and delta & sup1;& sup3;C values of -26 parts per thousand to -23 parts per thousand, confirming derivation from Jurassic coal measures. Incontrast, Ahe Formation (Jurassic; a major regional sandstone reservoir unit within the Kuqa Depression)hydrocarbons displayed "V-shaped" sterane ratios (C27 > C29), delta & sup1;& sup3;C values of -32 parts per thousand to -30 parts per thousand, and elevatedGI (0.21-0.32), indicative of Triassic lacustrine sources. Notably, the identification of Triassic-sourcedhydrocarbons in deep Ahe reservoirs challenged previous Jurassic-centric models, resolving ambiguitiesthrough multiproxy integration. Burial-thermal modeling, constrained by fluid inclusion homogenizationtemperatures (80 degrees C-160 degrees C), revealed three charging phases: phase I (19-16 Ma, Jidike Fm.), phase II (16-12 Ma, Kangcun Fm.), and phase III (5-1 Ma, Kuqa Fm.), with phase III Himalayan tectonics criticallyreshaping paleo-accumulations into an inverted "gas-below-oil" stratification (phase reversal due to tectonicreorganization). Structural analysis revealed (1) two boundary-fault anticlinal traps (defined by opposednorth- and south-dipping thrust faults) with vertical gas migration in Ahe sandstones and (2) fault-sealed tightgas accumulations controlled by reservoir quality. These findings highlighted the dominant contribution ofTriassic sources to deep gas reservoirs in Dibei and underscored the importance of multiphase tectonicevolution and source-reservoir coupling. This study provided a predictive framework for hydrocarbonexploration in fold-and-thrust belts, advocating prioritized assessment of fault connectivity and Triassicsaline lacustrine source deposits.

The deep coal measure gas of the Carboniferous-Permian system in Yan'an area of Ordos Basin exhibits a complex symbiotic accumulation model and gas-water occurrence mechanism. To study the deep coal measure reservoirs pore structure characteristics, including coalbed methane (CBM) reservoirs and tight gas (TG) reservoirs, and dynamic occurrence and migration behavior of gas and water during hydrocarbon generation and expulsion, the low field nuclear magnetic resonance (LF-NMR) displacement and micro computerized tomography (mu-CT) experiments were conducted on coal and tight sandstone samples from the Permian Shanxi Formation buried at a depth of over 3000 m in Yan'an area. The results indicate that the seepage water in pores significantly decreased during the low displacement pressure stage. Beyond 7 MPa, the rate of increase in gas saturation was found to diminish, while adsorbed water variations became dominant, and gas-water seepage approached steady-state conditions. Then, the influence of pore structure of tight sandstone on critical charging pressure and steady-state pressure was studied through low speed and constant current displacement experiments. Subsequently, the anisotropy of water seepage in coal pore-fracture was visualized through single-phase water seepage simulation experiments. The Z-axis, which represented the real vertical direction of the coal sample in the formation, was the dominant seepage direction. Additionally, the heterogeneity of pore structure and gas-water dynamic distribution under displacement was quantitatively characterized based on multifractal dimension parameters. Finally, the gas-water migration mechanisms in deep coal measure reservoirs were investigated. The capillary water was displaced in a piston-like manner at low displacement pressures. As displacement pressure increased, gas gradually charged into tight sandstone, and the dominant seepage channels gradually formed. These findings provided critical insights into the characteristics of deep coal measure reservoirs and the co-production of deep coal measure gas resources.

As a new block for shale oil development in China, Mabei area has huge development potential. However, the impact of fracture network structures generated by hydraulic fracturing on oil well drainage efficiency has not been fully studied. Therefore, accurately characterizing fracture networks is crucial for improving oil well production. This study monitored the pressure data after shut-in of 7 shale oil wells in Mabei area and used the Bourdet method to plot pressure drop characteristic curves to evaluate the fracture network morphology. By integrating fracturing parameters and production test data, this study aims to provide a scientific basis for the efficient development of shale oil in this area. The study selected seven wells of shale oil in the Mabei area as research subjects. Initially, detailed monitoring of shut-in pressure data from these wells was conducted. Subsequently, pressure drop characteristic curves were plotted using the Bourdet method, which effectively reflects the morphology and characteristics of fracture networks. By analyzing the morphology and characteristics of the pressure drop derivative curves, combined with fracturing parameters (such as breakdown pressure and sand volume per meter) and production test data (such as oil breakthrough time and production rates), a comprehensive evaluation of fracture network characteristics was performed. The study focused on key parameters such as main fracture length, secondary fracture width, density, and permeability, aiming to systematically reveal the development characteristics of fracture networks. The results showed that fracture networks of shale oil in Mabei area could be classified into three types. Type I fracture networks had short main fracture lengths, medium secondary fracture widths, high density, and high permeability. The pressure drop derivative curves showed deep V-shaped characteristics leaning to lower left, indicating that this type of fractured network was dominated by conductivity and could effectively improve oil well drainage efficiency. Type Ⅱ fracture networks had medium main fracture lengths, wide secondary fracture widths, medium density, and low permeability. The pressure drop derivative curves showed shallow V-shaped characteristics leaning to upper right, indicating that this type of fractured network was mainly storage-oriented. Although their conductivity was relatively weak, they still held certain development potential. Type Ⅲ fracture networks, characterized by long main fracture lengths, narrow secondary fracture widths, low density, and medium permeability, were overall underdeveloped. Their shut-in pressure drop derivative curves lacked distinct morphological characteristics, indicating that this type of fractured network had late oil breakthrough during the production process and was unfavorable for efficient oil well development. The study also revealed an important pattern. In wells with low breakdown pressure, under the same fracturing conditions, excessively high sand volume per meter tended to lead to the formation of Type Ⅲ fracture networks. Therefore, to improve shale oil development efficiency in Mabei area, subsequent fracturing designs should focus on avoiding the formation of Type Ⅲ fracture networks. Specific measures include optimizing fracturing parameters, such as reasonably controlling sand volume per meter, to enhance the conductivity and storage capacity of fracture networks, thereby achieving efficient shale oil development. In conclusion, this study provides valuable insights into the characteristics of fracture networks in the Mabei shale oil area and offers practical recommendations for optimizing hydraulic fracturing operations to maximize well productivity. Future research can expand the sample size and incorporate numerical simulations and field experiments to further validate these findings and refine the strategies for efficient shale oil development.

The Linhe Depression in the Hetao Basin represents an important area for potential breakthroughs in hydrocarbon exploration of medium-and small-sized basins and ultra-deep strata in China.Although the Jilantai and Bayan oilfields have been discovered in recent years,multiple exploratory wells in this depression have failed to deliver expected results.The failure analysis suggests that insufficient oil sources represent a critical constraint on hydrocarbon exploration in the depression.Based on the latest exploration achievements and laboratory data,we systematically investigate the characteristics of source rocks therein and calculate their resource potential using an integrated approach that combines geological assessment,basin simulation,and resource prediction.The research results indicate that the Linhe Depression in the Hetao Basin experienced an evolutionary pattern during the Meso-Cenozoic characterized by multi-stage tectonic subsidence and staged migration of subsidence centers,with the Naoxi sub-sag acting as a long-term inherited subsidence center.The depression contains four suites of source rocks:source rocks of the Guyang,Wulate,Linhe,and Wuyuan formations.The source rocks of the Linhe Formation,among others,predominate,characterized by substantial thicknesses,extensive distribution,high organic matter abundance,and favorable kerogen types.Furthermore,these source rocks exhibit low activation energy for hydrocarbon generation,offering advantages including early maturity,early hydrocarbon expulsion,a wide oil window,and high efficiency of organic matter conversion.These characteristics and advantages are closely related to the deposition of the source rocks in a highly reducing,saline lacustrine sedimentary environment and the enrichment of algae and sulfur within organic matter.Basin simulation results identify the Pliocene-Quaternary as the major oil generation period of source rocks in the Linhe Depression,accounting for 83.1%of the total oil generated.This result aligns well with the late-stage tectonic activity and contributes to the formation of a rapid late-stage hydrocarbon accumulation model.Hydrocarbon resource evaluation indicates that the Linhe Depression has a total amount of generated oil of 31.19×109 t and petroleum resources of 2.299×109 t.Given that the current cumulative proven reserves account for merely 1.2%of the total petroleum resources,the Linhe Depression holds considerable potential for hydrocarbon exploration.Since the oil generation centers are concentrated in the Naoxi sub-sag and the central fault zone,future exploration efforts in the depression should focus on tectono-lithologic composite traps within the Linhe Formation in the central fault zone(including the Xinglong,Nalinhu,and Ulan Buh structural zones),as well as lithologic traps and shale oil in the Linhe and Wuyuan formations in the sub-sag.

This study examines the Triassic and Jurassic source rocks in the northern structural belt of the Kuqa Depression, an important petroleum region in the Tarim Basin. By integrating outcrop and drilling data for the first time, this study reveals the tectonic-sedimentary controls on hydrocarbon source rocks. Triassic source rocks are characterized by relatively higher average total organic carbon (TOC, up to ∼2.8

The Triassic marine gas reservoir in the Moxi Gas Field is one of the large gas fields initially discovered in the Sichuan Basin. However, the origin of its natural gas has long been debated. To study the genetic types and origin of natural gas, the light hydrocarbons (LHs) composition, carbon isotopes, chemical compositions, and stable carbon and hydrogen isotopic compositions were analyzed in the Triassic strata of Moxi gas field in the Sichuan Basin. The natural gases from the second member of the Jialingjiang Formation (T2j2) and the first member of the Leikoupo Formation (T2l1) have dryness coefficients higher than 0.997 and contain low content non−alkane gases such as CO2 and N2. The δ13C1 values of natural gas in the Moxi (MX) gas field range from −35.3‰ to −32.9‰, the δ13C2 values range from −34.0‰ to −30.3‰, and the δD1 values range from −144‰ to −120‰. As for light hydrocarbons composition, the C7 LHs are dominated by the methylcyclohexane (MCH), and the C6−C7 LHs have low normal alkane contents. The individual carbon isotopes of light hydrocarbons have the characteristics of δ13C > −28‰. The origin identification indicates that the natural gas in this area is oil−type gas that results from the secondary cracking of crude oil. Our results show that the natural gas in T2j2 of the MX gas field is sourced from the shale gas of the Є1q, the T2l1 gas is a mixed−source gas from different thermal evolution stages of the Є1q source rocks, shale gas and oil−cracking gas. The mixing effect is the main reason for the reversed phenomenon (δ13C1 > δ13C2).

Asphaltene deposition during petroleum production presents persistent flow assurance challenges, necessitating advanced chemical solutions. This study elucidates the molecular mechanisms underlying asphaltene dispersion using acrylamide-based polymers through an integrated computational approach. Molecular dynamics simulations, geometric analysis, and density functional theory calculations were employed to investigate polymer-asphaltene interactions at multiple scales. A novel centroid triangle analysis method was developed to quantify dispersion efficiency, revealing that polyacrylamide (PAM) and chlorinated polyacrylamide (PAM-Cl) enhance asphaltene dispersion by 67.14 % and 94.49 %, respectively, at 298 K. Electronic structure analysis demonstrates that chlorine modification in acrylamide derivatives significantly alters molecular charge distribution, enhancing electrostatic interactions while reducing van der Waals forces. Quantum chemical calculations confirm that chloroacrylamide exhibits superior molecular activity, evidenced by a reduced HOMO-LUMO gap (5.18 eV vs. 4.94 eV) and increased electronegativity (3.249 vs. 2.673) compared to unmodified acrylamide. The findings establish electrostatic interactions as the dominant mechanism in asphaltene dispersion, providing fundamental insights for rational design of next-generation asphaltene inhibitors. This work advances our understanding of structure-activity relationships in asphaltene control chemicals, offering practical solutions for mitigating deposition-related challenges in petroleum operations.

The ultra-deep (deeper than 8 000 m) petroleum in the platform-basin zones of the Tarim Basin has been found mainly in the Lower Paleozoic reservoirs located to the east of the strike-slip fault F5 in the north depression. However, the source and exploration potential of the ultra-deep petroleum in the Cambrian on the west of F5 are still unclear. Through the analysis of lithofacies and biomarkers, it is revealed that there are at least three kinds of isochronous source rocks (SRs) in the Cambrian Newfoundland Series in Tarim Basin, which were deposited in three sedimentary environments, i.e. sulfide slope, deep-water shelf and restricted bay. In 2024, Well XT-1 in the western part of northern Tarim Basin has yielded a high production of condensate from the Cambrian. In the produced oil, entire aryl-isoprenoid alkane biomarkers were detected, but triaromatic dinosterane was absent. This finding is well consistent with the geochemical characteristics of the Newfoundland sulfidized slope SRs represented by those in wells LT-1 and QT-1, suggesting that the Newfoundland SRs are the main source of the Cambrian petroleum discovered in Well XT-1. Cambrian crude oil of Well XT-1 also presents the predominance of C29 steranes and is rich in long-chain tricyclic terpanes (up to C39), which can be the indicators for effectively distinguishing lithofacies such as siliceous mudstone and carbonate rock. Combined with the analysis of hydrocarbon accumulation in respect of conduction systems including thrust fault and strike-slip fault, it is found that the area to the west of F5 is possible to receive effective supply of hydrocarbons from the Cambrian Newfoundland SRs in Manxi hydrocarbon-generation center. This finding suggests that the area to the west of F5 will be a new target of exploration in the Cambrian ultra-deep structural-lithologic reservoirs in the Tarim Basin, in addition to the Cambrian ultra-deep platform-margin facies-controlled reservoirs in the eastern part of the basin.

Abstract Downhole monitoring the production profile is crucial for the development of oil and gas reservoirs. Currently, the commonly methods for monitoring the production profile include logging tools and using tracer monitoring. The tracer monitoring method is more popular in oil field operations due to its wide applicability, simple process, low cost, low risk, and long monitoring time. However, compared to traditional logging tool monitoring methods, tracer monitoring has drawbacks such as data lag, difficulty in downhole installation, and unstable long-term effects. Bohai Oilfield has developed a new type of solid tracer and solved the problem of downhole installation by improving the structure of the downhole screen tube. This tracer uses polymer material as the skeleton. After entering the designated position, the internal tracer can slowly diffuse into the solvent through the pores in the skeleton, achieving slow release and long-term monitoring of the production profile of the oil well. In 2023, this new type was first applied in the D6 well in Bohai Sea, and a half month stable production stage liquid production profile was obtained through sampling. The monitoring results showed that: (1) Solid slow-release tracer monitoring technology can continuously obtain production layer information in complex environments and can be used for short-term rapid water exploration and long-term water production monitoring, identifying water breakthrough time and main water breakthrough location, (2) The distance between water injection well and D6 production wells is small, and the water injection volume in the injection wells is large. The tracer monitoring results show that there is a certain degree of water flooding in all 6 sections of each test layer, (3) The first test layer is the main liquid production section, the first and sixth test layers are the main oil production sections, and the first and second test layers are the main water production sections. The research results can determine the oil and water production situation of each section of oil well, identify the water breakthrough time and water outlet position, and provide a basis for the next development adjustment.

The Sichuan Basin in southern China is well-known for its large natural gas resource potential stored in Sinian-Cambrian systems. Recently, high-yield industrial gas flow has been discovered from the Dengying Formation (Sinian System) and Canglangpu Formation (Cambrian System) in the Penglai gas area, preluding the multilayer stereoscopic exploration in Sichuan Basin. However, the origin of the natural gas and its preserving mechanics is still debated, and thus, in this study the geochemical characteristics of the natural gas are systematically analyzed, based on the data from gas composition and hydrocarbon isotope of a series of local wells. On this basis, the geochemical characteristics of natural gas in different regions and layers are compared, and the reasons for these differences from the origin and influencing factors are analyzed. The results show the following: (1) The natural gas of the Penglai gas field is dry gas dominated by CH4, and the Sinian Dengying Formation gas has lower C2H6 content, larger dryness coefficient, heavier delta C-13, and lighter delta H-2(CH4) than the Cambrian gas, which is associated with the high proportion of hydrocarbons from the high-maturity Dengying source rocks. (2) The natural gas from some wells in the lower part of the structure is characterized by high H2S content and low CH4 content, and heavy delta C-13 in the components, which seems to be affected by the thermochemical sulfate reduction (TSR) effect. (3) The natural gas from the Penglai gas area has a relatively low maturity, which appears to be attributed to the continuous sealing ability of the caprock, which can preserve both the early generated gas and the late thermal-cracked gas.

Most of the natural gas hydrate sources in the world are biogenic gas, but there are still many unsolved problems in the formation process of biogenic gas. The gas source of gas hydrates in the northern South China Sea is also controversial, and the evaluation of biogas source rock in hydrate development areas lacks experimental basis and quantitative data. In order to solve these problems, this paper used the sediments obtained from the GMGS2 hydrate drilling voyage to simulate the biological gas production. Through the culture experiment, the relationship between sedimentary gas production, temperature and sediment characteristics in the hydrate development area of Dongsha Sea area was comparatively studied, and the results were compared with typical biological gas fields. The results showed that CH4 and CO2 were the main gas products, and a small amount of H2 was formed. Methane yield is closely related to temperature, and the optimal temperature range in the study area is 20°C~ 40°C. At the same time, it is found that organic carbon content (TOC) has no significant correlation with methane yield, and it is not suitable to be used as an index for the evaluation of biogas source rock. Comprehensive analysis shows that the methane production rate in the study area is relatively high and the hydrocarbon generation potential is great, which meets the gas source conditions for the formation of gas hydrate ore body. The main factors affecting biomethane yield include available organic matter, bacterial community and environmental factors.

The Kuqa depression is an important oil and gas production area in western China, and there are abundant natural gas resources in the deep and ultra‐deep tight reservoirs. In this study, the accumulation law of deep oil and gas in the Kuqa depression has been systematically discussed based on the analysis of geochemical parameters, reservoir fluid inclusions and the recovery of burial‐thermal evolution history in different structural zones. The results show that the lacustrine mudstones of the Triassic Huangshanjie and Upper Jurassic Qiakemake formations in the Kuqa depression are the main oil‐generating source rocks, and the coal‐measure source rocks of the Middle and Lower Jurassic are the main gas‐generating source rocks. The oil and gas in the northern tectonic belt originated from the Huangshanjie and Yangxia formations have the characteristics of ‘lower‐source and upper‐reservoir’ and ‘self‐generation and self‐storage’. The source rocks in the central tectonic belt are of high maturity and mainly generate natural gas, and a small amount of crude oil is derived from mudstones of the Jurassic Qiakemake Formation. The oil and gas in the southern slope belt are mainly derived from the source rocks of the Huangshanjie Formation, followed by the Jurassic source rocks. The ordered accumulation of oil and gas in the Kuqa depression is controlled by the effective spatiotemporal matching of multi‐stage tectonic evolution and hydrocarbon generation evolution of multi‐source rocks. Three spatiotemporal ordered hydrocarbon accumulation series have been proposed: early near‐source accumulation, late far and near‐source accumulation, and late upper‐near source accumulation. The piedmont belt is dominated by the near‐source continuous accumulation mode, the thrust belt is dominated by the ultra‐late upper source accumulation mode, and the slope belt is dominated by the late far‐source accumulation mode. Therefore, future exploration will focus on the tight lithologic reservoirs in the northern piedmont belt, the structural reservoirs in the central structural belt, and the unconformity hidden reservoirs in the southern slope belt.

Based on analyses of characteristics, hydrocarbon charging history and geological conditions for the formation of Sinian-Cambrian reservoirs in the north slope area of central Sichuan paleo-uplift, the natural gas origin, accumulation evolu-tion, accumulation pattern and formation conditions of large lithologic gas reservoirs have been investigated. Through com-prehensive analyses of natural gas composition, carbon and hydrogen isotopic compositions, fluid inclusions, reservoir bitu-men, and geological conditions such as lithofacies paleogeography and beach body characterization, it is concluded that: (1) The natural gas in the Sinian-Cambrian of the north slope area is mainly oil cracking gas, and different contribution ratios of mul-tiple sets of source rocks lead to different geochemical characteristics of natural gas in different reservoirs. (2) Although the both Sinian and Cambrian gas reservoirs in this area are lithologic gas reservoirs under monocline background, the former has normal-pressure and the latter has high-pressure. There are three types of source-reservoir-caprock combinations: single source with lower generation and upper reservoir, double sources with lower generation and upper reservoir or with side source and lateral reservoir, double sources with lower generation and upper reservoir or with upper generation and lower reservoir. The Permian-Triassic is the main generation period of oil, Early-Middle Jurassic is the main generation period of oil cracking gas and wet gas, and Late Jurassic-Cretaceous is the main generation period of dry gas. (3) The Sinian-Cambrian system of the north slope area has two favorable conditions for formation of large lithologic gas reservoirs, one is that the large scale beach facies reservoirs are located in the range of ancient oil reservoirs or near the source rocks, which is conducive to the "in-situ" large-scale accumulation of cracked gas in the paleo-oil reservoirs, the other is that the large scale mound-beach complex res-ervoirs and sealing layers of inter beach tight zones match effectively to form large lithologic traps under the slope background. The research results confirm that the north slope area has large multi-layer lithologic gas reservoirs with more than one trillion cubic meters of natural gas resources and great exploration potential.

The tectonic belt in northern Kuqa Depression has a long period of fault activity and multi-stage superposition, which has an important influence on hydrocarbon accumulation.Through the combination of growth index profile method, typical profile elongation (or compression ratio) method and structural equilibrium profile method, the development characteristics, active periods and hydrocarbon accumulation significance of faults in the northern Kuqa Depression are studied.The results show that there are three types of faults in the northern Kuqa Depression: early thrust fault, late thrust fault and long-term active fault.There are five periods of fault activity, which are paleogene (E), Neogene Jidike Formation (N1j), Kangcun Formation (N1k), Kuqa Formation (N2k) and Quaternary (Q) respectively.N1j, N1k and N2k are the key periods of fault activity.The fault activity will lead to the thickening of the source rocks in the Kezilenuer Formation (J2kz), which is conducive to the formation of multiple types of structural and lithologic traps.The fault active periods (N1j, N1k, N2k) match well with the main hydrocarbon generation and expulsion periods (E, N1j, N1k, N2k) of source rocks.The fault activity is beneficial to the formation and accumulation of oil and gas reservoir Yinan 2 and Tundong 2, but it also lead to the escape of oil and gas escape from Yinan 4 and Yishen 4 Wells, resulting in the destruction of reservoir forming and preservation conditions.The fingdings are of great significance to the analysis of hydrocarbon accumulation process in this area.

Because of the huge potential of hydrocarbon, the Jurassic strata in the Tugeerming area has become a significant exploration target in the Kuqa Depression of the Tarim Basin. However, accumulation characteristics and controlling factors for the Tugeerming gas reservoir need to be further developed. In the present study, the accumulation characteristics were discussed using geochemical techniques, and the controlling factors for the generation and accumulation of gas reservoir were summarized. The gas generation intensity in Tugeerming reservoir is about 20-60 x 10(8) m(3)/km(2), suggesting that source rocks could generate sufficient natural gas for the reservoir. Sandstone reservoirs with relatively good physical properties (Improved by fractures and dissolution) provide favorable condition for the gas accumulation. This oil charging period of the Early Neogene (N(1)j) and the gas charging period of the Pliocene (N(2)k) occurred in the reservoir and the periods were 23-8 Ma and 5.2-1.64 Ma, respectively. Continuous production of natural gas is beneficial to accumulation. Faults and fractures provide migration channels for oil and gas. Fractures optimize the physical properties of the reservoir. Moreover, the assemblages of source-reservoir-caprock in Tugeerming area provided good condition for hydrocarbon preservation. Tugeerming gas reservoir is defined as a structure-lithologic type, which is lower generation and upper storage mode. The conclusions are critical to further oil and gas exploration.

四川盆地结构复杂、沉积厚度大,自下而上发育多套含气层系,既有煤型气又有油型气,不同储层中天然气的组成及成熟度均存在较大差异.天然气中汞的形成与天然气的形成过程密切相关.为研究四川盆地天然气汞含量分布特征,对该盆地不同地区近120口气井开展了天然气汞含量检测,并对部分气井的天然气组成以及烷烃碳同位素进行了测定.总体上,四川盆地天然气汞含量不高,算术平均值仅为6 840 ng/m3,但天然气汞含量的分布无论在平面上还是在垂向上都是很不均匀的.在平面上,川西和川中西部地区天然气汞含量相对较高;在垂向上,天然气汞含量总体随产层深度的增加而变大,陆相储层中天然气汞含量要明显高于海相储层.四川盆地天然气汞含量分布与气源岩类型、气源岩热演化程度以及储层硫化环境有关.

通过系统分析塔里木盆地库车坳陷不同区带致密气藏的天然气地球化学特征,探讨了库车坳陷深层致密砂岩气来源.库车坳陷中段天然气对应烃源岩热演化程度高,天然气主要为高—过成熟煤型气,可能存在三叠系湖相原油裂解气;库车坳陷东部和西部天然气对应热演化程度中等,现今发现的天然气来源于侏罗系煤系(迪那气田)、三叠系湖相泥岩(迪北、博孜气田),尚未发现湖相原油裂解气.根据库车坳陷不同区带天然气地球化学特征及来源的差异,结合烃源岩热演化差异性,指出大北—克深地区侏罗系—三叠系内有效圈闭有望成为三叠系湖相原油裂解气勘探新领域,秋里塔格构造中段—西段、阿瓦特—博孜古近系膏盐之下白垩系储层内构造圈闭、北部山前带东段侏罗系内构造—岩性圈闭为高—过成熟煤型气有利勘探区域.

四川盆地川中隆起带震旦系—寒武系探明天然气储量超过万亿立方米,发现中二叠统栖霞组气藏,洗象池组、茅口组、玄武岩组、长兴组等层系获工业气流,不同层系气藏天然气地球化学特征存在明显差异.基于大量新获气井天然气组分、碳同位素、氢同位素等分析实验数据,系统研究了川中隆起带天然气成因及成藏特征,明确了下一个万亿立方米级重点勘探领域.研究结果表明:(1)震旦系、寒武系和二叠系天然气均是以烃类气体为主且干燥系数大于0.997的干气,属于原油裂解气.绝大多数二叠系天然气C2H6含量、δ13C2、δ2HCH4与源自下寒武统筇竹寺组烃源岩的寒武系天然气相似;上震旦统灯影组天然气C2H6含量低、δ13C2重、δ2HCH4轻;GS19栖霞组气藏天然气C2H6含量高、δ13C2轻、δ2HCH4轻.C2H6与δ13C2差异主要与成熟度有关,δ2HCH4主要受原始母质沉积水介质盐度影响.(2)安岳气区与太和气区聚集了不同演化阶段的原油裂解气,其中,安岳气区天然气 δ13C比太和气区重,主要聚集原油晚期阶段的裂解气,太和气区聚集早期—晚期裂解气.(3)震旦系—二叠系气藏具有单源和双源聚集模式.寒武系气藏和GS19栖霞组气藏为单源聚集模式,烃源岩分别为筇竹寺组和龙马溪组,灯影组气藏和其他二叠系气藏为双源供烃成藏模式,除均有筇竹寺组烃源岩贡献外,分别还有震旦系烃源岩和二叠系烃源岩的贡献.研究认为,不同时代烃源岩贡献比例大小是造成不同层系气藏天然气地球化学特征差异的主要原因,太和气区多层叠置连片的优质储层紧邻烃源灶或处于古油藏范围,具备万亿立方米级资源规模,勘探潜力大.

Natural gases in China are mainly coal-derived gas, with assistance from oil-typed gas. At present, many genetic identification methods, from hydrocarbon composition and isotope to light hydrocarbon and biomarker indexes, have been formed, but combined methods from non-hydrocarbon gases are lacking. Based on compositions and isotopes geochemical characteristics and the differences of non-hydrocarbon nitrogen gas in coal-derived gas and oil-typed gas, and combining the isotopic geochemical characteristics of non-hydrocarbon helium, the comprehensive identification methods of coal-derived gas and oil-typed gas for hydrocarbon gases according to the associated non-hydrocarbon gases of nitrogen and helium are established and the preliminary applications have been engaged. The main recognitions are as follows:1)Coal-derived gas generally has relatively lower nitrogen abundance, mainly distributed from 0 to 31.2% with main frequency from 0 to 2%. Oil-typed gas, on the other hand, usually has relatively higher nitrogen abundance, mainly distributed from 1.1 to 57.1% with main frequency from 2 to 16%. 2) Coal-derived gas generally has relatively heavier nitrogen isotope values, mainly distributed from -8 to 19.3‰ with main frequency from -8 to 8‰.Oil-typed gas usually has relatively lower nitrogen isotope values, mainly distributed from -10.6 to 4.6‰ with main frequency from -8 to 4‰.3)The geochemical characteristic differences of coal-derived gas and oil-typed gas are mainly due to the fact that the sapropel parent material is relatively rich in nitrogen element and rich in light δ 14 N, while the humic parent material is relatively poor in nitrogen element and rich in heavy δ 15 N. The differences on thermal maturity of source rocks, the redox conditions of source rock sedimentary environment, and the salinity of water body are also important effective factors.4)Differences on nitrogen abundances and isotopes in coal-derived gas and oil-typed gas have great significance in genetic identification. The genetic identification chart of R/Ra-δ 15 N for organic and inorganic nitrogen in natural gas and the comprehensive joint identification charts of R/Ra-δ 15 N-N 2 of nitrogen and helium for coal-derived gas and oil-typed gas have been established, and are of great reference in investigating the origins and sources of natural gas and guiding natural gas exploration in China.

The deep and ultra-deep oil and gas has been a prominent exploration direction in the field of petroleum industry in recent years. The deep oil and gas resources are mainly distributed in the carbonate rocks, clastic rocks and igneous rocks, of which the carbonate rock reservoirs account for about 40% of global oil and gas reserves for their superior reservoir properties. Currently, a number of large oil and gas fields have been discovered in the deep marine carbonate rocks in China, especially in the Sichuan and Tarim Basin, thus showing a broad oil and gas exploration potential in the deep marine carbonate rocks. In this paper, the genesis and source of deep natural gas in the Tarim and Sichuan Basin has been systematically studied. The results show that the natural gas in the deep marine carbonate rock reservoirs is not only sourced from the deep-source rocks, but the substantial crack of crude oil in the reservoir under the condition of high burial depth and high geotemperature can provide abundant natural gas sources for the deep reservoir. Accordingly, the contribution of gas from oil cracking should be concerned in evaluation on deep natural gas resources.