In recent years， deep coal-rock gas has become a research hotspot. The coal-measure strata of the Longtan Formation in the central Sichuan Basin possess favorable potential for coal-rock gas exploration and development； however， relevant research on the evaluation methods and distribution laws of coal-rock gas reservoirs in the Longtan Formation of this area remains relatively insufficient. Taking the NT1H pilot well and horizontal well in central Sichuan as the research objects， this study comprehensively evaluates the coal-rock gas reservoir performance using geological， seismic， logging， and other data， combined with methods such as scanning electron microscopy and mineral composition analysis. Meanwhile， technologies including pre-stack AVO inversion and variance-ant body attributes of near-incidence angle stack data are adopted for the fine characterization of coal seams. The research results indicate that： （1） The coal seams of Well NT1H exhibit strong gas-storing capacity and high thermal evolution degree， with well-developed high-density reticular cleat systems featuring good connectivity. The pore types include mineral pores， epigenetic pores， and primary pores， with overall good connectivity， endowing the coal seams with high-quality gas-generating potential， gas-storing potential， and a solid foundation for exploitation. （2） The low acoustic impedance zones identified by pre-stack AVO inversion can effectively indicate the distribution of thick coal seams or thin interbedded layer groups. Vertically， the coal seams in central Sichuan are mainly characterized by thin interbedding： Seams 12^#-17^# are relatively thin， while Seams 18^#-19^# are thicker， with an average thickness of 1.51-3.2 m. Planarly， controlled by micro-palaeogeomorphology， the thickness of Seams 12^#-19^# ranges from 0.5 to 6.37 m. This study clarifies the evaluation methods and distribution laws of coalbed methane reservoirs in the Longtan Formation of the study area， providing reliable practical experience and technical support for subsequent horizontal well trajectory optimization in complex areas， multi-well joint evaluation， and deep coalbed methane exploration and development.

In view of the western-central Sichuan Basin， the structural evolution， hydrocarbon source conditions， reservoir characteristics and accumulation rules of Xujiahe Formation were systematically analyzed to reveal the controlling factors of natural gas differential enrichment in the Xujiahe Formation of the Sichuan Basin and point out the favorable exploration directions for the next step. The results show that： （1）The Xujiahe Formation has experienced three tectonic movements including the Indosinian， Yanshanian and Himalayan tectonic movements， forming two groups of NW-and NE-trending fault zones， and developing three sets of source rocks in the first and second members of the Xujiahe Formation， the third member of the Xujiahe Formation， and the fifth member of the Xujiahe Formation. The large thickness of source rocks， the high abundance of organic matter， moderate thermal evolution and large gas generation intensity laid the geological foundation for the large-scale distribution of tight gas in the Xujiahe Formation. （2） The reservoir lithology of Xujiahe Formation is mainly lithic sandstone， and the reservoir space types such as intragranular dissolved pore， intergranular dissolved pore and residual intergranular pore are developed， which are fracture-pore type and pore type reservoirs. （3） The tight sandstone gas reservoir of Xujiahe Formation is mainly controlled by the coupling of source-reservoir-fault. The distribution of source rocks controls the enrichment area of tight gas and the boundary of gas reservoir. When the self-closed accumulation conditions are satisfied， the high-quality reservoir controls the degree of natural gas enrichment. The fracture can provide a channel for the vertical migration of natural gas， and its associated fractures can communicate with isolated pores to improve the seepage capacity of the reservoir to control high production. It has important guiding significance for the next exploration and deployment of natural gas in Xujiahe Formation. （4） Based on the above results， the third， fourth and fifth members of Xujiahe Formation are taken as the target intervals， and the favorable enrichment areas are optimized， which has important guiding significance for the next exploration and deployment of natural gas in Xujiahe Formation.

The Tongnanba area， which encompasses the Tongnanba Anticline and the Tongjiang Depression， is abundant in natural gas resources from the Xujiahe Formation， with proven reserves exceeding 100 billion cubic meters. Previous studies on the Tongnanba area tended to analyze it as a whole， while ignoring the differences in the characteristics of natural gas accumulation in the Tongnanba Anticline and Tongjiang Depression. The results show that the Xujiahe Formation source rocks in both the Tongnanba Anticline and Tongjiang Depression exhibit moderate-to-high organic matter abundance， belong to type Ⅱ₂-Ⅲ， and are over-mature. However， the source rocks in the depression area have a relatively greater thickness. The tight sandstone reservoirs of the Xujiahe Formation in both anticlinal and depression zones exhibit ultra-low porosity and permeability. The sandstone in the anticline area has a relatively greater thickness， and under the combined effect of faults and folds， it is more likely to form a “fault-fracture system” conducive to natural gas accumulation. The natural gas in the Xujiahe Formation of both the Tongnanba Anticline and Tongjiang Depression is a high-maturity to over-mature mixed gas derived from coal-measure source rocks of the Xujiahe Formation and the Upper Permian marine source rock. The ethane and propane carbon isotopes of natural gas in the Xujiahe Formation of the anticlinal area are relatively lighter， and commonly exhibit carbon isotopic reversal， indicating a higher proportion of marine-derived gas. In addition， systematic studies on microthermometry of fluid inclusions， tectonic burial history， thermal history and hydrocarbon generation history of source rocks indicate that there were two hydrocarbon charging episodes in the Xujiahe Formation of the Tongnanba Anticline， occurring during the Middle-Late Jurassic and Paleogene-Neogene periods， with the latter being the main charging stage. The “fault-fracture systems” formed during the Paleogene-Neogene （Himalayan period）， which are supplied by dual-source gases from the Xujiahe Formation and the Upper Permian marine source rocks， may serve as favorable exploration targets. The Xujiahe Formation in the Tongjiang Depression experienced three episodes of gas accumulation， occurring during the Late Jurassic， Late Cretaceous， and Neogene periods， wherein the Late Cretaceous was the main accumulation period. Tight reservoir “sweet spots” primarily sourced from the Xujiahe Formation source rocks， along with “fault-fracture systems” formed during the Late Cretaceous （Late Yanshanian period）， may represent more favorable exploration targets.

In recent years， China's shale oil exploration has made new breakthroughs， and has become an important replacement resource to ensure China's energy security. Shale oil mainly occurs in shale layers dominated by shale， including those in mud-shale matrix pores and clastic rock interlayers adjacent to shale. Its occurrence and distribution are governed by the evolution of the pressure field during the basin dynamic processes. This study focuses on source-reservoir separated shale formations and utilizes a formation pore thermal-pressure hydrocarbon generation and expulsion simulation experimental apparatus to systematically conduct simulation experiments on hydrocarbon generation and expulsion under source-reservoir pressure differences （referring to the pressure difference between the entire shale formation and external conventional reservoirs）. The aim is to reveal the controlling mechanism of source-reservoir pressure differences on the spatial distribution of shale oil in shale matrix pores and clastic rock interlayers， and to explore its geological implications. The results indicate： （1） The mud-shale matrix pore space is the primary reservoir for shale oil， accounting for 60%-90% of the total resource （the less accessible portion）， while the sandstone interlayers contribute 10%-40% （the more producible portion）. This ratio evolves with increasing maturity， showing a trend of decreasing matrix proportion and increasing interlayer proportion. （2） The influence of source-reservoir pressure difference on shale oil distribution exhibits significant differentiation： it primarily exerts a destructive effect on oil retained in mud-shale matrix pores， especially pronounced in the high maturity stage； in contrast， it shows a “dual-effect” on oil in sandstone interlayers-pressure differences less than 6 MPa promote enrichment through short-distance migration and charging， whereas differences greater than 6 MPa inhibit enrichment due to long-distance migration and dissipation. （3） The total oil yield is mainly controlled by the maturity and original quality of the source rock， with relatively minor influence from the source-reservoir pressure difference. However， the gas yield exhibits a strong response to pressure difference， with higher gas production rates observed under larger pressure difference during the high maturity stage. The findings of this study provide experimental evidence and theoretical support for the “source-reservoir coupling” evaluation and the selection of exploration targets in continental shale oil systems.

With the rapid advancement of AI （Artificial Intelligence） technology， its application in the field of geological exploration has demonstrated significant potential. Traditional fracture identification methods predominantly rely on geologists' expertise and manual interpretation， which are not only inefficient but also susceptible to subjective biases， thereby hindering the effective processing of large-scale datasets. To address these limitations， this study investigates the efficacy and feasibility of AI in strike-slip fault identification， using the Halahatang area of the Tarim Basin as a case study. The Halahatang area is characterized by two sets of high-angle strike-slip fault systems—NE-trending and NW-trending—that intersect in an X-shaped pattern on the horizontal plane. Leveraging preprocessed high-precision 3D seismic data， automated fracture identification and classification experiments were conducted utilizing Convolutional Neural Networks （CNN） and the U-Net architecture model. After effectively mitigating random noise interference， these algorithms achieved clear recognition of main faults， branch faults， and their structural relationships. Analysis of the experimental results demonstrates that deep learning models significantly enhance the accuracy and efficiency of strike-slip fault identification， offering a novel technological approach for geological exploration workflows.

Through the study of hydrocarbon generation potential， reservoir characteristics， gas occurrence distribution， hydrocarbon generation evolution， and sealing capacity of overlying strata of No.8 coal in Benxi Formation of Ordos Basin， the controlling factors for enrichment of coal rock gas in Ordos Basin are revealed， and the next favorable exploration direction is pointed out. Our research has shown： （1） The No.8 coal has high organic matter abundance， vitrinite-dominated macerals， high thermal maturity， high gas yield， and prolonged hydrocarbon generation period， which lays a rich material foundation for the enrichment of coal-rock gas. （2） The coal-rock reservoir has good reservoir performance， with an average porosity of 6.3% and an average permeability of 2.21×10^-3 μm². The reservoir space is dominated by organic matter micropores， accounting for about 70%. Macropores and cleat fractures are developed in large quantities， providing a large number of enrichment sites for free gas. （3） The No.8 coal has a high gas content， with an average of 18.34 m³/t. It is dominated by adsorbed gas and contains a high proportion of free gas. The difference of gas content in different regions is controlled by lithology combination mode. （4） The sealing capability of different lithologies was quantitatively evaluated. The sealing performance of coal-ash combination mode and coal-mud combination mode are the best， which was beneficial to coal-rock gas enrichment. The sealing performance of coal-sand combination mode is the worst， and some coal-rock gas diffuses into the extrinsic sandstone reservoir. An integrated “source-reservoir-seal” coupling model identifies Yulin-Zizhou and Nalinhe-Hengshan as prime targets for No.8 coal-rock gas. This has provided guidance for the prediction of geological sweet spots in China's coal-rock methane.

Previous studies on hydrocarbon charge dating in the Shaximiao Formation of Jinqiu Gas Field in the central Sichuan Basin are rather sparse and unsystematic， resulting in insufficient understanding of gas accumulation formation and adjustment process. It is of great importance to further clarify hydrocarbon charging history and to understand dynamic evolutions of gas accumulations of Jinqiu Gas Field. An integrated fluid inclusion method of petrography， micro-fluorescence spectroscopy， microthermometry， laser Raman spectroscopy， and paleo-pressure simulation has been employed， combined with the thermal/burial history simulation of typical wells and hydrocarbon generation history simulation of source rocks. The results show that oil inclusions and methane gaseous hydrocarbon inclusions occur in the Shaximiao Formation reservoirs in the study area. Those hydrocarbon inclusions are mainly distributed in healed microfractures within and cutting through quartz grains， and within quartz overgrowths and carbonate cements in the middle diagenetic stage. The aqueous inclusions， coeval with oil inclusions and gaseous hydrocarbon inclusions， have homogenization temperature ranges from 103.8 to 145.0 ℃ and from 81.3 to 149.0 ℃， respectively. Burial history modeling indicates that the reservoirs were buried to the maximum depth at the end of the Early Cretaceous followed by tectonic uplift since the Late Cretaceous to the present-day. The activity history and intensity of hydrocarbon source-related faults directly affected oil and gas supply. The reservoirs undergone two periods of hydrocarbon charge： the end of early Cretaceous to middle Paleocene （104-59 Ma）， the end of Oligocene to the present-day （24-0 Ma）. During hydrocarbon charge and accumulation， the Longquanshan fault， Jiao-1 flaut， Lianghe-1 fault and those normal faults cutting the Lower Jurassic were activated， and the gas from the Xujiahe Formation and the oil from the Lower Jurassic migrated vertically along faults and leaked into and accumulated in the Shaximiao Formation. During the first charging period， the reservoirs were medium-over pressured， and then changed to normal and abnormally low pressure state during uplift. The research results are of great significance for the tight sandstone gas exploration and deployment of the Shaximiao Formation in central Sichuan Basin

Under the global low-carbon energy transition， natural hydrogen exploration and development have emerged as a focal point in global energy competition. This paper systematically reviews the genetic mechanisms of hydrogen generation and its interactions with hydrocarbon gases in deep geological systems. Key findings include：（1） Inorganic processes dominate hydrogen generation， where serpentinization serves as a key hydrogen source due to its high efficiency and widespread distribution. Mantle degassing and basement water-rock interactions provide stable hydrogen supplies in cratonic regions. （2） Hydrogen-hydrocarbon interactions exhibit dynamic equilibrium under high-temperature/pressure conditions： External hydrogen influx reactivates secondary hydrocarbon generation in overmature source rocks， while Fischer-Tropsch synthesis drives CO₂/H₂-to-CH₄ conversion， establishing an equilibrium between hydrogen consumption and hydrocarbon enrichment. （3） Tectonic-fluid coupling systems demonstrate dual effects on gas accumulation： Deep-seated fault systems act as preferential migration pathways for hydrogen and alkane gases， yet associated hydrothermal fluid activities and caprock integrity deterioration may induce gas escape. Ductile caprocks （e.g.， evaporites） significantly enhance hydrogen retention through physical adsorption and sealing mechanisms. High-hydrogen natural gas reservoirs discovered in China's Songliao and Qaidam basins validate the co-accumulation potential in Precambrian basement margins and fault zones. Current challenges lie in three aspects： （1） Poorly constrained temperature-pressure coupling mechanisms of hydrogen isotope fractionation； （2） Lack of in-situ reaction simulation techniques for deep geological conditions； （3） Insufficient quantitative models for hydrogen generation-consumption （biotic vs. abiotic）.Future research should prioritize hydrogen source tracing techniques， develop numerical models for hydrogen-hydrocarbon interactions， and establish a dynamic evaluation framework tailored to continental sedimentary basins in China， providing theoretical and technological foundations for clean energy development.

Sulige Gas Field， the largest natural gas field in China， contains helium in its natural gas. The geochemical characteristics and helium enrichment mechanism of the helium-bearing natural gas require further investigation. Static element analysis and dynamic process dissection of the Upper Paleozoic helium reservoir in the Sulige Gas Field were carried out. By means of composition and isotope analysis of natural gas and rare gases， major and trace element analysis of rocks， and basin numerical simulation， a helium enrichment model was established. The results show that the methane content of the helium-bearing natural gas in the field ranges from 83.12% to 93.61%， with a mixture of high-maturity dry gas and mature wet gas. The average helium abundance is 0.047%， positively correlated with N₂，and exhibits a distribution pattern of higher in the west（0.05%- 0.10%） and lower in the east （0.03%-0.05%）. The Sulige Gas Field has multiple helium sources， including basement-type and sedimentary-type helium source rocks. Although the basement-type source rocks are widely developed， the lack of effective source-connecting faults results in a low helium abundance. Regions near the paleo-uplift of the basin basement with low hydrocarbon generation intensity of source rocks is favorable for helium accumulation， and the formation pressure indirectly controls helium enrichment by affecting solubility. The helium accumulation process can be divided into three stages： mainly dispersed before the Early Jurassic； controlled by the distribution of other underground fluids during the Early Jurassic-Early Cretaceous； and a groundwater dehelium accumulation model formed after the Early Cretaceous due to strata reconfiguration and fluid redistribution. This research is of great significance for the exploration and development of helium resources in China.

As a strategic resource， the efficient development of helium is crucial to national resource security. The occurrence and diffusion characteristics of helium in shale gas reservoirs underpin helium exploration and development. This study constructed molecular models of shale kerogen matrix and slit-shaped nanopores. The grand canonical Monte Carlo and molecular dynamics methods were employed to simulate the adsorption and diffusion behaviors of pure helium and helium-methane mixtures， respectively， with the effects of pressure and pore size analyzed. By quantifying different occurrence states of helium， this study unveiled the occurrence mechanisms and diffusion characteristics of helium in shale nanopores at the microscopic level. The results show that the adsorption capacity of helium in kerogen is much weaker than that of methane， with pore size having a greater influence on helium adsorption than pressure and kerogen heterogeneity. Helium mainly exists in an adsorbed state in 1 nm pores， while free states prevail in 2 nm and 4 nm pores. The small and single-atom molecular structure endows helium with strong diffusion and penetration abilities， enabling migration from the kerogen matrix to the slit-shaped pores. This study enriches the fundamental theory of helium occurrence and diffusion in shale gas reservoirs.

The Dingbian， Jingbian， and Anbian areas （collectively known as the Sanbian area） are located in the overlapping area of the Paleozoic Sulige and Jingbian gas fields within the Ordos Basin. However， exploration for Mesozoic oil here remains limited. Previous research on Mesozoic source rocks in the basin primarily focused on the interior and the southwestern/northwestern parts of the lacustrine basin， leaving the source rock development in the northern margin's Sanbian area poorly understood. Through analytical techniques such as thin-section analysis， scanning electron microscopy （SEM）， and geochemical testing， combined with core and well-log data， this study systematically analyzes the development characteristics， spatiotemporal distribution， and hydrocarbon generation potential of the Chang 7 lacustrine mudstone in this region. The analysis reveals the presence of dark mud shale with a thickness ranging from 1 to 16 m. The mudstone is rich in organic-rich laminae， primarily classified as Type I and II kerogen. Total Organic Carbon （TOC） content reaches 4%-5%， and vitrinite reflectance （R _O） ranges from 0.68% to 0.92%. Comprehensive evaluation indicates that these rocks are qualified as good to excellent source rocks with significant hydrocarbon generation potential. The discovery of the Chang 7 lacustrine mud shale in the Sanbian area extends the known area of effective source rocks northward by 2 800 km². Furthermore， reservoir formation analysis suggests that the Chang 6 to Chang 9 reservoirs benefit from a dual advantage： local vertical hydrocarbon supply from these source rocks and high-quality lateral hydrocarbon supply from the main lacustrine basin. The development of these source rocks in the region holds significant reference value for re-evaluating the extent and evolution of the Chang 7 lacustrine basin， reassessing the resource potential of the Yanchang Formation， and guiding future exploration and development efforts in this area.

To investigate the causes of the abnormal gas logging values in Well Xiangandi-1， a molecular model of the Lower Cambrian black shale in western Hunan Province was constructed using molecular simulation， and the controlling factors of its gas content were systematically studied. The results indicate that water molecules and CH₄ exhibit a pronounced competitive adsorption effect within shale pores. As water content increases from 5.5% to 20%， CH₄ adsorption decreases by 26.64%-90.04%， demonstrating that water content is one of the key factors controlling shale gas content. Geological evolution correction results reveal that two large-scale uplift and denudation events significantly disrupted the reservoir pressure-temperature conditions and sealing capacity of the Lower Cambrian black shale in western Hunan， leading to extensive gas desorption and loss. At the present burial depth of 778 m， the CH₄ content is nearly zero， consistent with the measured logging results. Moreover， although the diffusion coefficient is relatively low （-0.78 km²/Ma）， the cumulative diffusion distance during the -540 Ma geological history reaches about 421 km²， which is sufficient to cause large-scale gas loss. The development of tectonic fractures further accelerated this process. This study elucidates the microscopic mechanisms and controlling factors underlying the reduction of shale gas content in the Lower Cambrian black shale， highlights the synergistic effects of water inhibition， tectonic evolution， and long-term diffusion， and provides a new perspective for understanding deep shale gas preservation and enrichment mechanisms， as well as an important reference for unconventional natural gas potential assessment and favorable area selection.

The Triassic Yanchang Formation in the Ordos Basin， traditionally considered to exhibit a basin-wide isopachous stratigraphy， is now revealed by seismic data to display wedge-shaped thinning from the northeast to the deep lake southwest， indicating a non-isochronous framework. Integrated analysis of drilling， logging， seismic， and lithologic data shows that the Chang 7 and Chang 9 flooding surfaces serve as key isochronous markers. The depositional period of the Chang 7 basal condensed section in the southwest corresponds to the interval from the Chang 9 top to the Chang 7 base in the northeast. The widespread condensed layers in the southwest resulted from rapid lake-level rise and insufficient sediment supply， causing thin deposition or stratigraphic gaps. Three mechanisms are identified： （1） Tectonic quiescence of the Qinling Orogenic Belt. Weak initial sediment flux during tectonic transition phases led to terrigenous under compensation in the deep lake； （2） Accommodation-dominated basin dynamics. Extreme water depths created accommodation space exceeding sediment flux， compounded by hydrodynamic resistance； （3） Volcanic-induced rapid transgressions. Episodic volcanism triggered abrupt lake-level rises， disrupting synsedimentary terrestrial input. The Zircon U-Pb dating of tuffaceous layers within condensed sections reveals significant age dispersion （226-241 Ma）， confirming multistage hiatuses and diachronous deposition. These findings will enhance the basin-scale research of isochronous stratigraphy， depositional models， and source-to-reservoir configurations. This study advances lacustrine basin evolution theory and provides critical insights for hydrocarbon exploration， particularly in predicting reservoir heterogeneity and source-rock distribution in analogous continental basins.

In order to clarify the characteristics and controlling factors of tight sandstone reservoirs with early continuous deep burial and late shallow burial， taking the fourth member of the Xujiahe Formation in the Jianyang area， Sichuan Basin as an example， through a large number of core and thin section observations， as well as experimental analysis such as laser confocal microscopy， field emission scanning electron microscopy， and CT， it is proposed that under high and low temperature gradients and early continuous deep burial and late shallow burial conditions， compaction and cementation lead to reservoir densification， dissolution and fracture effectively improve reservoir properties. The research results indicate that： （1） In the Jianyang area， the sand bodies of the subaqueous distributary channels in the front edge of the braided river delta of the fourth segment are stacked and connected， with large thickness， coarse particle size， and wide distribution area， laying the foundation for the development of tight sandstone reservoirs； （2） The storage space types of the tight sandstone reservoir in the fourth section of the Jianyang area are mainly intergranular dissolution pores and intragranular dissolution pores. The reservoir has low physical properties and poor pore structure. The diagenesis of the reservoir mainly undergoes compaction， cementation， and dissolution. The compaction effect is the main reason for the densification of the Xu-4 reservoir in the Jianyang area， while the cementation effect leads to further densification of the reservoir. The network of pore and fracture systems formed by dissolution and fracture formation is the “sweet spot” distribution area of the fourth member of Xujiahe Formation tight sandstone reservoir.

The Changxing Formation in the central Sichuan Basin， located in the central isolated gentle slope platform， has developed multiple rows of high-energy reef and shoal bodies. In some local areas， dolomitized reservoirs are well developed， showing great exploration potential. However， the reservoirs have strong heterogeneity and obvious characteristics of “one reef， one reservoir”， which lead to problems such as unclear delineation of the internal boundaries of the reservoirs and ambiguous seismic response characteristics. Therefore， it is necessary to further conduct fine delineation of the boundaries of the reef and shoal bodies.In response to this， this paper starts with geological and logging data， clarifies the petrological and seismic response characteristics of the reef and shoal reservoirs in the Changxing Formation， and combines the results of forward modeling to establish a seismic identification model for the reef and shoal reservoirs. Then， by using technologies such as paleogeomorphic restoration and seismic attribute analysis， a method of delineating the internal boundaries of the reef and shoal reservoirs named the “Three Determination Method” is proposed. Finally， by comprehensively applying technologies such as seismic inversion and seismic facies analysis， the vertical and horizontal distribution characteristics of the reef and shoal reservoirs are clarified.The research shows that vertically， the reef and shoal reservoirs of the Changxing Formation in the study area are developed in the upper part of the first and second members of the Changxing Formation， with a thickness ranging from 10 to 60 m. Horizontally， they are mainly developed in the platform margin and local paleogeomorphic high parts within the platform， and the characteristics of “one reef， one reservoir” are obvious. The reef and shoal bodies in the platform margin zone with good seismic response patterns and slightly larger single areas have great exploration potential.

The Middle Permian Maokou Formation in Central Sichuan has great resource potential to form high-quality reserves of 100 billion cubic meters of natural gas. In view of the problem that the distribution characteristics and main controlling factors of gas and water in the area are not clear， the fluid geochemical characteristics are clarified by comprehensively using indoor core experimental data， logging interpretation results， three-dimensional seismic data and production performance data， the distribution characteristics of gas and water are revealed， and the geological factors affecting the distribution of gas and water are further discussed. The results show that the natural gas of Maokou Formation in Central Sichuan is mainly composed of methane， which belongs to the origin of crude oil cracking. The formation water is characterized by CaCl₂ type， and its chemical characteristics show that this area is a favorable area for oil and gas accumulation and preservation； The thickness of the gas water transition zone is closely related to the reservoir quality. The reservoir characteristics of low porosity， ultra-low permeability and strong heterogeneity lead to the wide distribution of the gas water transition zone； There are several independent gas water systems in this area， and there is no uniform gas water interface. The gas water distribution mainly has three modes：Vertical differentiation， fault diversion and heterogeneous retention， showing the characteristics of differentiated gas water production； The distribution of gas and water is controlled by many factors， such as reservoir physical properties and heterogeneity， tectonic amplitude， fault activity sequence， hydrocarbon source rock distribution and so on. It is proposed that “dominant lithofacies-local high amplitude structures-early faults-strong hydrocarbon generation”is the preferred standard for sweet spot areas. The research results can provide key theoretical basis for the evaluation of favorable exploration zones and the optimization of development well locations in Maokou Formation， and have important reference significance for the efficient exploration and development of similar low-permeability carbonate gas reservoirs.

In recent years， the deep coal rock gas in the Ordos Basin have entered the stage of large-scale commercial development. However， the rapid changes in the characteristic areas of deep coal reservoirs， as well as the large differences in fracturing construction technology and parameters， have led to significant differences in the productivity indicators of horizontal wells. The unclear main controlling factors for high production severely restrict the productivity improvement and cost reduction of deep coalbed methane wells. Therefore， this study takes the deep 8^# coal seam in Jiaxian area on the northeast edge of the Ordos Basin as an example， and combines drilling， logging， core well analysis and testing， development dynamics and other data to carry out the subdivision of the 8^# small layer and fine evaluation of the reservoir. The key geological engineering elements that affect the productivity of horizontal wells are screened， and the correlation evaluation of different geological engineering factors is carried out. The research results indicate that： （1） Proposing an initial capacity index can improve the rationality and accuracy of capacity evaluation； （2） The 8-1^# coal in Jiaxian area has developed bright coal， with the best coal quality and gas content， and more developed cleavage， making it the optimal target location for horizontal well drilling. The proportion of gas content and free gas content， the drilling encounter rate of 8-1^# coal， and the relative position of the trajectory to the coal seam top are the main geological factors controlling the high production of horizontal wells. The sand addition intensity， liquid use intensity， and the proportion of small particle sand are the main engineering factors controlling the high production of horizontal wells； This research can provide reference for the scale benefit development of deep coalbed methane in the Ordos Basin.

Helium escapes easily from gas reservoirs through diffusion， which requires caprocks with low porosity and permeability， such as gypsum and mudstone layers， for effective sealing. However， the microscopic diffusion mechanisms of helium within the pores and throats of tight caprocks， as well as the influence of lithology and associated gases， are not well understood. Using molecular dynamics simulations， we modeled the pores of caprocks with different lithologies and simulated helium adsorption， diffusion， and flow behaviors within them. The results indicate that： （1） Lower temperatures， higher gas pressures， and smaller pore sizes in caprocks reduce helium diffusion， thus improving sealing effectiveness. Under the same conditions and pore sizes， helium diffuses and flows faster in halite and kaolinite pores， followed by montmorillonite and calcite， and the slowest in gypsum pores； （2） Considering actual throat sizes in caprocks， gypsum and halite provide the best sealing for helium， followed by montmorillonite and kaolinite， with calcite being the least effective； （3） Methane and water in the gas reservoir preferentially adsorb onto pore surfaces， thereby slowing helium diffusion. This effect is more pronounced at higher concentrations， and when pore water content exceeds 90%， the diffusion coefficient of helium approaches zero. Overall， smaller pore throats， higher gas pressures， lower temperatures， and high concentrations of associated gases and water in caprock throats help reduce helium loss. Gypsum rock layers are the most effective at sealing helium， followed by mudstones， and tight carbonates are the least effective.

Tight sandstone gas reservoirs are characterized by low porosity， low permeability， and strong non-homogeneity. Fracturing is required for development， and post-fracturing production capacity is influenced by multiple factors， making accurate prediction difficult. Based on the concept of geo-engineering integration， engineering parameters， physical parameters， and logging parameters were comprehensively considered. A mutual information coefficient model was applied to identify the key factors controlling production capacity， and a Sparrow Search Algorithm （SSA） optimized Random Forest （RF） model was established for prediction. Taking the Qingshimao Gas Field as a case study， model performance was evaluated using root mean square error， mean squared error， mean absolute error， and coefficient of determination， and compared with RF models optimized by Particle Swarm Optimization （PSO） and Butterfly Optimization Algorithm （BOA）. The results show that RLLD， GR， SH， SD， VOE， and CNL are key factors， with resistivity being the most significant. Parameter tuning through SSA by adjusting population size， iteration number， and cross-validation effectively improved prediction accuracy. The proposed SSA-RF model outperforms PSO-RF and BOA-RF， providing a reliable approach for post-fracturing productivity evaluation of tight sandstone gas reservoirs.

The Ledong Diapir Zone in the Yinggehai Basin exhibits substantial exploration potential. However， this area is characterized by abundant shallow gas accumulations and well-developed faults and fractures. These features manifest seismically as blank-weak or chaotic reflection patterns， hindering the reliable interpretation of internal structures， stratigraphy， and geological bodies within the diapir zone， thereby severely constraining exploration evaluation studies. To enhance imaging within the diapir-obscured zones， delineate structural features， and identify favorable reservoirs， this study employed forward modeling to clarify the causes of seismic obscuration. A targeted approach combining multiple attenuation and energy restoration techniques was implemented for structural imaging. Furthermore， seismic response analysis for identifying structures and reservoir bodies within the diapir zone was conducted， establishing an integrated seismic-geological technical workflow for imaging， structural interpretation， and reservoir identification in diapir-obscured zones. Studies show that： （1） The primary causes for poor imaging in the diapir zone are multiples generated by shallow gas and its absorptive/scattering effects （gas shadow）. Generalized 3D Surface-Related Multiple Elimination （SRME） and a “two-step” energy restoration method can effectively suppress strong diffracted multiples， improve the signal-to-noise ratio， and recover energy within blank reflection zones. （2） The Ledong 2X diapir structure is a NW-SE trending elongated anticline， featuring two culminations （northern and southern）. The northern culmination exhibits weaker diapiric activity and minimal faulting， representing a favorable hydrocarbon accumulation site. （3） The Ledong 2X diapir zone develops turbidite sand， slope fans， and coastal sand reservoirs， exhibiting low-frequency strong amplitude seismic anomalies. In conclusion， integrated research focusing on imaging， structural analysis， and seismic reservoir characterization within the diapir-obscured zones has confirmed the presence of advantageous structures and reservoirs within the Ledong 2X diapir. This area represents a significant domain for expanding hydrocarbon reserves. The methodologies and findings presented in this study provide valuable insights for offshore hydrocarbon exploration in diapir-affected regions.

The Zigong area in the southern part of the Sichuan Basin has been affected by multi-stage and multi-directional tectonic stresses， developing natural fracture systems with multiple scales and types， which have an important impact on the enrichment， preservation and development of shale gas. By comprehensively utilizing data such as core samples， thin sections， dipole sonic logs and image logs， the types and development characteristics of natural fractures in the Long 1-1 sub-member shale reservoir in the Zigong area were quantitatively characterized. Combined with experimental analyses such as fluid inclusion analysis and acoustic emission testing， the fracture formation mechanism was clarified， and a comprehensive evaluation of fracture openness was carried out. The research results show that the Long 1-1 sub-member shale reservoir in the study area has developed structural fractures， diagenetic fractures and overpressure fractures. Among them， high-angle structural fractures in the NNE and NEE directions are dominant， with a high degree of fracture development and good effectiveness. In different tectonic units， the fracture development patterns change regularly. The shale in the Long 1-1 sub-member has experienced three stages of fracturing and three stages of cementation events. The first two stages of structural fractures have undergone multiple stages of filling and have relatively poor effectiveness； the late-stage structural fractures are hardly filled and have relatively good effectiveness. The CFF （Coulomb Failure Function） value of fractures in the study area is generally less than 0， and under the in-situ stress state， the fractures are in a stable state. From the northwest to the southeast and then to the north， the CFF value gradually increases， reflecting the gradual increase in fracture openness. Two stress mechanisms， namely normal faulting and strike-slip faulting， are mainly developed in the study area. Under different stress mechanisms， the orientations of preferentially opened fractures are different. Under the normal faulting stress mechanism， the NWW-SEE trending fractures parallel to the direction of the current maximum principal stress are preferentially opened. Under the strike-slip faulting stress mechanism， the high-angle NEE-SWW and NW-SE trending fractures with an angle of 30° to the current maximum principal stress are preferentially opened. The research results have provided a theoretical basis for the optimization of shale gas sweet spots， the prevention and control of fracture stringing and casing deformation， and the optimization of horizontal well trajectories in the study area.

Distributed acoustic sensing （DAS） technology has been widely used in dynamic monitoring of horizontal well production. However， the downhole acoustic signal is complex and interfered. At present， the understanding of the acoustic response law of gas-water two-phase flow in horizontal wells is insufficient. It is still very difficult to quantitatively diagnose the production profile of horizontal gas wells through DAS data. In this paper， through indoor physical simulation experiments， the acoustic wave profiles in the production process of horizontal wells with different production and water-gas ratio are simulated and tested. Through fast Fourier transform and digital filtering， the effective frequency amplitude characteristics of DAS data under different simulation conditions are extracted， and the acoustic wave response law of gas-water two-phase flow in horizontal wells is analyzed. The relationship chart between DAS acoustic energy and wellbore velocity is drawn， and the model library of the relationship between DAS acoustic energy and wellbore velocity in gas-water two-phase flow horizontal wells is established by data regression. The quantitative relationship between wellbore velocity and DAS response under different simulation conditions is realized， which lays a model foundation for DAS data inversion and provides a new technical idea for solving the quantitative interpretation of gas-water two-phase flow profile in horizontal wells.

Lithological classification of shale reservoirs is a crucial step in oil and gas exploration and development， directly impacting the accuracy of reservoir evaluation， fracturing design， and productivity prediction. Traditional machine learning methods often suffer from insufficient accuracy and weak generalization capability in lithology identification tasks. This study focuses on the Chang 7 Member of the Yanchang Formation in the L well area of the Ordos Basin， using logging data from 3 053 sampling points across eight wells. Pearson correlation coefficient method was employed to select six significant logging parameters， including natural gamma， acoustic travel time， spontaneous potential， well diameter， deep lateral resistivity， and shallow lateral resistivity， as response features. A Bidirectional Long Short-Term Memory （BiLSTM） network model with an attention mechanism （BiLSTM-Attention） was developed to intelligently identify lithologies of the Triassic Yanchang Formation’s terrestrial shale reservoirs. Compared with traditional supervised learning models （BiLSTM， CNN， SVM， LSTM）， experimental results show that the BiLSTM-Attention model achieves the best lithological classification performance in highly heterogeneous shale reservoirs， with an accuracy of 96.9% and a loss value of 0.09. Notably， it performs excellently in identifying thin interlayers and transitional lithology zones， with its average relative error and loss values lower than those of other comparison models. This model demonstrates better stability and reliability in lithological identification. The method provides a new approach for identifying lithologies in complex shale systems and holds good potential for application in lithological identification of highly heterogeneous unconventional reservoirs.

“Horizontal well + hydraulic fracturing” technology has become an important means for deep coalbed methane development. In view of the developed bedding in deep coal seams， the effect of bedding opening on the transportation and placement of proppant in the main hydraulic fracture and bedding remains unclear. The complex fracture with developed bedding in a deep coal seam was established. The Euler-Euler proppant transport model was used to investigate the influences of geological factors （bedding opening， number of bedding） and engineering factors （construction displacement， fracturing fluid viscosity， sand proportion and proppant particle size） on proppant transport and placement in complex fractures with developed bedding. The simulation results show that： （1） The opening of the bedding has a significant impact on the height of the stable sand dune in the hydraulic main fracture. Compared with the vertical single fracture， the maximum reduction of the characteristic length of the stable sand dune under the condition of bedding opening is 24.67%， and the maximum reduction of the characteristic area is 50.37%. （2） The influence of the number of bedding on the stable sand dune in the hydraulic main fracture is mainly manifested in the height between the lower bedding and the bottom of the hydraulic main fracture （H _LB）， and there is almost no proppant distribution in the upper bedding. （3） With the increase of construction displacement， sand proportion and proppant particle size， the time taken for the stable sand dune in the hydraulic main fracture to reach H _LB is shortened. While with the increase of bedding opening， number of bedding and fracturing fluid viscosity， the time taken for the sand dune height to reach HLB is lengthened. Compared with the vertical single fracture， under the condition of the bedding opening， the maximum reduction of the characteristic length of the stable sand dune in the hydraulic main fracture is 34.67%， the maximum reduction of the characteristic area is 49.06%. （4） Only in narrow bedding can proppant form as a stable sand dune near the entrance of the bedding. In other cases， proppant exists in suspension form in the bedding. The above research results can provide a theoretical basis for the comparison between conventional fracturing design and deep coal rock fracturing design.

In response to the issue of numerous， redundant， and complexly interpreted biomarker parameters in the field of molecular geochemistry， this paper proposes a novel comprehensive index evaluation method. Focusing on the Yanchang Formation in the Ordos Basin， the study employs factor analysis to screen out biomarker parameters most closely related to organic matter maturity， parent material type， and water salinity. Three comprehensive indices， namely Maturity Index （MI）， Parent Material Index （PMI）， and Water Salinity Index （WSI）， are constructed through linear combinations of these selected parameters. Applications of these comprehensive indices in different layers and blocks of the Yanchang Formation demonstrate their ability to represent the geochemical characteristics of organic matter more concisely and clearly， with higher accuracy and reliability compared to single parameters. Research findings based on these indices reveal that the maturity of organic matter in the Yanchang Formation gradually increases with depth， the Chang 7 oil group exhibits a significant aquatic origin of organic matter， and deeper oil groups such as Chang 9 and Chang 10 have relatively higher water salinity. Additionally， the distribution patterns of maturity， parent material type， and water salinity across different blocks on the plane are complex， indicating the diversity of geological features. The comprehensive index method proposed in this paper provides a new perspective for molecular geochemistry research and holds significant importance for oil and gas exploration under complex geological conditions.

The Fengcheng Formation in the Mahu Sag of the Junggar Basin exemplifies a typical whole petroleum system， characterized by abundant hydrocarbon resources and promising exploration potential. Previous research extensively investigated the sedimentary environment， petrology， pore structure， and physical properties of the Fengcheng Formation within the study area. However， studies on diagenetic evolutionary sequences and quantitative reservoir pore evolution remain notably limited. Integrating thin-section microscopy， scanning electron microscopy （SEM）， X-ray diffraction （XRD）， and high-pressure mercury injection data， this study conducted a refined analysis of diagenetic sequences and pore evolution in the Fengcheng Formation of the northern Mahu Sag slope. We quantitatively assessed the differential impacts of each diagenetic process on three reservoir types and examined the coupling between pore evolution and hydrocarbon accumulation processes within this whole petroleum system. Results reveal that shale oil reservoirs in the northern slope’s Fengcheng Formation predominantly comprise felsic shale， tight oil reservoirs consist mainly of felsic siltstone， and conventional oil reservoirs are primarily lithic arkose. The formation underwent a complex diagenetic process involving alternating phases of mechanical compaction， multi-stage cementation， devitrification， and multi-stage dissolution. Compaction and cementation critically degraded reservoir quality in this whole petroleum system： compaction reduced porosity by 26.67% in shale oil reservoirs， 29.41% in tight oil reservoirs， and 23.84% in conventional oil reservoirs， while cementation uniformly decreased porosity by 2.5% across all three reservoir types. Dissolution partially enhanced reservoir properties， increasing porosity by 0.78% in shale oil reservoirs， 1.75% in tight oil reservoirs， and 2.68% in conventional oil reservoirs. This research definitively establishes the diagenetic sequences and quantitative pore evolution of the whole petroleum system in the Fengcheng Formation in northern slope， providing a critical foundation for evaluating its resource potential.

To investigate the development characteristics and formation mechanisms of organic pores in continental shale， this study examines highly mature， organic-rich shale from the Jurassic Ziliujing Formation in the Sichuan Basin. Employing various experimental methods， including organic petrology， kerogen and group component carbon isotopes， argon-ion polishing-scanning electron microscopy （SEM）， and energy-dispersive X-ray spectroscopy （EDS）， we identified and classified organic matter components and organic pore types， and investigated the main controlling factors for organic pores formation in continental shale. The results indicate that： （1） The organic matter in the Ziliujing Formation shale primarily consists of primary morphologically preserved vitrinite （including fusinite/semifusinite） and secondary amorphous bituminite. Four types of higher plant debris components were identified： strip-shaped， silk shaped， branched， and block shaped. Five types of higher plant cellular structures were observed： reticular large-cavity thin-walled， reticular small-cavity thick-walled， irregular cavity， grape-cluster cavity， and tubular cavity. The bituminite components are constrained by the framework space of inorganic mineral particles and their symbiotic relationships with authigenic minerals， exhibiting four occurrence states： banded， scattered， interactive， and interpenetrating. （2） According to organic matter component types and occurrence/composite relationships with inorganic minerals， organic pores were classified into three categories comprising eight types： bituminite organic pores， bituminite-authigenic mineral composite organic pores， and vitrinite organic pores. Organic pores are commonly developed in bituminite and bituminite-authigenic mineral composites. （3） A “four-factor” controlling mechanism is proposed： （a） Organic matter component type provides the material basis for organic pore development； （b） The occurrence state of bituminite and thermal maturity are key factors controlling favorable organic pore development； （c） Hydrothermal activity promotes the development of organic pores within bituminite； （d） Preservation of cellular structures or bacterial modification facilitates organic pore development in vitrinite.

The newly discovered fault-controlled fracture-cavity hydrocarbon reservoir in the ultra-deep carbonate formations of the Shunbei-Fuman area， located within the Shuntuoguole low uplift of the Tarim Basin， represents a unique new type of oil and gas reservoir. This reservoir is controlled by strike-slip faults， mainly consisting of light oil and condensate gas， with characteristics of deep burial （over 7 300 m） and multi-stage accumulation. This study employs a fine dissection approach， based on the geological characteristics of the ultra-deep Ordovician fault-controlled fracture-cavity reservoirs in the Shunbei–Fuman area， and follows the technical specifications for calibrated units dissection. Nine key parameters are established for calibrated units analogy， including basin type， exploration area， reservoir lithology， reservoir type， pore combination， reserve abundance， resource abundance， migration-accumulation coefficient， and recovery coefficient. The evaluation results indicate that in the carbonate field of the Shuntuoguole low uplift in the Tarim Basin， the oil reserve abundance of the Ordovician fault-controlled fracture-cavity reservoirs ranges of （25-60）×10⁴ t/km²， and the gas reserve abundance ranges of （1.5-6.5）×10⁸ m³/km². Additionally， the oil resource abundance is （12.5-14.5）×10⁴ t/km²， the gas resource abundance is （0.45-1.0）×10⁸ m³/km²， the oil recovery is 12%-16%， and the gas recovery is 30%. This research conducted a detailed dissection of calibrated units and constructed key analogy parameters for fault-controlled fracture-cavity hydrocarbon reservoirs. The findings not only expand the types of calibrated units but also provide an effective reference for analogy and resource evaluation in ultra-deep carbonate rock fields within China's three major craton basins.

The H-56 block of the Daqingzi Oilfield in the Changling Sag represents a typical tight oil reservoir characterized by low porosity， complex pore structures， and strong heterogeneity. These factors exert a significant influence on the CO₂ flooding process and its efficiency. In this study， high-temperature and high-pressure micro-visualization displacement experiments using real-core models were conducted based on the petrophysical properties and pore-throat structures of the reservoir. The mechanisms of CO₂ flooding and the distribution characteristics of residual oil under different pore structures were systematically analyzed. Experimental results indicate that the reservoir cores in the study area are dominated by primary and secondary pores， with pore throats primarily exhibiting a curved-sheet morphology and intricate tortuosity， leading to distinctly hierarchical characteristics in pore-throat connectivity. Well-connected samples， characterized by well-developed and well-connected pore-throat networks， exhibited continuous and stable flow channels during CO₂ flooding. The displacement pattern was mesh-like， and the residual oil saturation was low， primarily in the form of film-like and isolated island-like residual oil， with an ultimate recovery factor of approximately 75.32%. In contrast， poorly-connected samples showed poor pore-throat connectivity and limited flow pathways， resulting in an uneven and finger-like displacement front. The residual oil mainly occurred in connected and clustered forms， and the overall recovery factor was approximately 66.98%. The study demonstrates that differences in microscopic pore-throat structures are the key controlling factors affecting CO₂ flooding efficiency and residual oil distribution. Capillary pressure， pore-throat morphology， and pore connectivity jointly determine the flow behavior of CO₂ and the mobilization efficiency of residual oil within tight sandstone reservoirs. The results provide pore-scale evidence for the evaluation of CO₂ flooding effects and the potential for remaining oil recovery in tight sandstone reservoirs.

To investigate the factors influencing gas content variations in tight reservoirs of the western Sichuan Basin， this study employed multiple fractal dimension theory alongside centrifugal-NMR experiments， high-pressure mercury intrusion porosimetry， cast thin sections， scanning electron microscopy， and X-ray diffraction. These techniques successively characterized the pore structure and gas content properties of reservoirs in southwestern and northwestern Sichuan， thereby identifying the controlling factors for gas content variability. The results demonstrate that： （1） The pore systems in western Sichuan are predominantly composed of residual intergranular pores. In the southern region， gas-poor intervals exhibit extensive carbonate cementation filling most residual intergranular pores， while in the northern region， chlorite coatings are well-developed within the pores， with gas-poor reservoirs showing significant pore blockage by chlorite. （2） The gas saturation of reservoirs in western Sichuan ranges from 38.79% to 56.88%， with the southern region showing notably lower values （38.79%） compared to the northern area. （3） In the northern reservoirs， strong compaction has led to higher porosity reduction rates and relatively smaller pore spaces， while partial blockage of smaller pores by chlorite coatings further reduces gas-bearing capacity. In contrast， the southern reservoirs exhibit strong heterogeneity in nanopores that impedes gas migration， coupled with extensive carbonate cementation in certain intervals that severely restricts secondary pore development， collectively resulting in inferior gas-bearing properties.

Conventional approaches， such as multivariate regression， empirical formulas， and petrophysical models， commonly fail to adequately capture the complex nonlinear relationships between logging curves and reservoir parameters， resulting in suboptimal accuracy for grading prediction of shale reservoirs. This study focuses on deep shales derived from the Wufeng Formation and the first sub-member of the first member of the Longmaxi Formation （marked as LMX₁ ¹） in western Chongqing area. A reservoir type identification model based on the Bayesian optimized LightGBM algorithm was developed， with the SHAP algorithm employed to quantitatively evaluate the importance of logging curves. Subsequently， the model was applied to grading evaluation of deep shale reservoirs within the target area. The results demonstrate that， compared to the regression strategy， the classification strategy achieved significant improvements in model complexity， computational efficiency， and identification performance in deep shale reservoir identification. An identification model of shale reservoir types was established using the classification scheme， yielding weighted precision and weighted recall of 89.7% and 89.6% for LightGBM algorithm， which are superior to those for RF （87.52% and 86.96%， respectively） and SVM （83.61% and 81.8%， respectively） algorithms， respectively， on the testing dataset for reservoir type identification. DEN， GR， and CNL logs proved most critical for identifying Types I and III shale reservoirs， whereas DEN， AC， and CNL logs exhibited heightened importance for the identification of Type II reservoirs. Furthermore， logging curves exert a complex nonlinear influence on model decisions. The grading evaluation results show that Type I reservoirs are predominantly developed in the upper Wufeng Formation and the first sub-layer of the LMX₁ ¹. The Bayesian optimized LightGBM algorithm facilitates efficient and precise identification of shale reservoir types， offering a novel approach for reservoir classification evaluation.

Pyrite is widely developed in organic-rich shales. The morphology of framboidal pyrite， along with the particle size characteristics of the framboids and their constituent microcrystals， serves as a reliable tracer for the sedimentary water environment. This study focuses on the pyrite within the shales of the upper Es ₄-lower Es ₃ submembers in the Dongying Depression. The morphological characteristics of pyrite were observed using optical microscopy and scanning electron microscopy， and statistical analysis of the particle sizes of framboids and internal microcrystals was performed using ImageJ software. The results indicate that the particle size distribution of framboidal pyrite in the samples can be classified into three types：Tall-type（average particle size<5 μm， standard deviation of 1-2 μm）， Broad-type （average particle size between 5 and 10 μm， standard deviation of 2-6 μm）， and Fluctuant-type （average particle size > 10 μm， standard deviation of 6-10 μm）， which reflect different formation processes of framboidal pyrite. Simultaneously， within the Tall-type and Broad-type framboidal pyrites， a negative correlation is observed between the ratio of the framboid diameter （D） to the internal microcrystal size （d） and the degree of water column euxinia. The morphology and particle size characteristics of framboidal pyrite vary across different lithofacies， revealing that the redox conditions of the sedimentary water body in the study area were significantly influenced by hydrodynamic energy and the degree of climatic aridity. Specifically： in the LF1 （Felsic claystone）， framboidal pyrite is predominantly the Fluctuant-type， with a large framboid particle size distribution； in the LF2 （Organic-rich calcareous claystone）， it is primarily the Tall-type， with D/d < 6； in the LF3 （Organic-rich dolomitic claystone）， it is mainly the Tall-type， with D/d > 6； in the LF4 （Organic-rich argillaceous limestone）， it is primarily the Tall-type， but the D/d characteristics differ among different lamina types； and in the LF5 （Organic-rich mixed rock）， framboidal pyrite is mainly the Tall-type， with D/d ranging between 5.5 and 6.2， and it contains abundant euhedral pyrite and replacement pyrite.

A number of shale gas wells have been drilled with good gas measurement in Xiaoheba Formation in Nanchuan area， Southeast Chongqing. To analyze the natural gas exploration potential of the Xiaoheba Formation， the gas accumulation conditions and accumulation models of the Xiaoheba Formation in Nanchuan area were analyzed based on outcrop， core， well logging， experimental analysis and seismic data. The results show that： （1） The Xiaoheba Formation in the Nanchuan area is a deltaic front and pre-deltaic deposit， mainly composed of siltstone and argillaceous siltstone， with a relatively large thickness. （2） The lithology is tight， showing the characteristics of strong compaction. With an average porosity of 0.84% and an average permeability of 0.1×10^-3 μm²， it is an extremely low porosity and tight reservoir. The reservoir space is dominated by micro-fractures and corrosion pores， forming a pore-fracture reservoir. The low mercury removal efficiency indicates that the reservoir has strong horizontal and vertical heterogeneity. （3） There is no obvious correlation with gas measurement and the structure. Adjacent wells on the same platform are different from gas survey locations and thickness， presenting the characteristics of fractured gas reservoirs. （4） Based on the prediction of curvature and seismic properties of the ant body， it is believed that the through-source fractures are the natural gas migration channels of the Xiaoheba Formation. （5） Due to the lateral sealing of Xiaoheba Formation and the sealing of the overlying Hanjiadian Formation， natural gas gathered in the fracture and formed a fractured reservoir accumulation model. The research results guide the Xiaoheba Formation in the upper return fracturing of the old well， which has made a breakthrough in the exploration of Xiaoheba Formation in Nanchuan area. And the research results have important guiding significance to Xiaoheba Formation in Sichuan Basin.

Reservoir research is central to the exploration and accumulation studies of shale gas. Accurately characterizing the pore structure of shale is crucial for elucidating the gas storage conditions and migration capabilities. Taking the Longmaxi Formation shale in the Luzhou area as a case study， we developed a method for quantitative characterization of shale pore structures based on gas adsorption and large-scale scanning electron microscopy （SEM）. The results indicate that： （1） The pore types within the Longmaxi Formation shale include clay mineral interlayer pores， dolomite dissolution pores， pyrite intercrystalline pores， feldspar and dolomite dissolution pores， intramineral fractures， and organic matter pores. Notably， organic matter pores account for 72.93% of the total pore area， while dissolution pores contribute about 14.04%， and intergranular pores make up approximately 13.03%； （2） Our proposed method for the quantitative characterization of shale pore structures， integrating gas adsorption and large-scale stitching SEM， demonstrates that micropores predominantly contribute to the total pore volume， with macropores and mesopores contributing similarly. This approach， which combines gas injection techniques and imaging observations， addresses the inaccuracies encountered in traditional fluid injection methods for larger meso- and macropores， offering new insights for the study of pore structures in shale and unconventional reservoirs.

The Chang 7 interlayered shale oil in the Ordos Basin possesses significant exploration potential， yet the enrichment degree varies greatly across different zones， and the understanding of regionalized reservoir controlling factors remains unclear. Through comparative analysis of reservoir-forming elements such as source rocks， reservoirs， and lithological combinations in the Chang 7 interlayered shale oil in Longdong， Northern Shaanxi， and Jiyuan areas， the controlling factors for differential accumulation of interlayered shale oil have been identified， and a differential enrichment and reservoir formation model has been established. The research results indicate that the thin mud and thick sand development in the delta front of Northern Shaanxi， coupled with limited distribution of source rocks， is the key factor contributing to the poorer enrichment of interlayered shale oil compared to Longdong. In Jiyuan， despite the maximum thickness of source rocks in the Chang 7 Member， the small scale of sandstone reservoirs and poor lateral continuity， coupled with low hydrocarbon expulsion efficiency due to the thick mud and thin sand lithological combination， result in the smallest enrichment scale of interlayered shale oil， making it a favorable area for shale-type shale oil exploration. In the Huachi-Qingcheng area of Longdong， the development of thick mud and thick sand lithological combinations， coupled with high-quality reservoirs， determines the large-scale enrichment of interlayered shale oil. The fracture development in the Heshui area provides good transport conditions for the vertical migration of shale oil， and the better physical properties of the Chang 7₁ sub-member reservoirs result in a better enrichment scale of interlayered shale oil compared to the Chang 7₂ sub-member. A “four-element” joint control differential enrichment and accumulation model has been established， which includes high-quality source rock， high-quality reservoir enrichment， lithological combination accumulation， and fracture control. It points out that the delta front ends of Longdong and Northern Shaanxi are the main target areas for interlayered shale oil exploration， and the Chang 7₃ sub-member in Jiyuan is an important area for shale-type shale oil exploration， providing theoretical support for the optimization of sweet spots and development deployment of continental shale oil.