As a clean energy source， hydrogen plays a significant role in the global energy transition. Natural hydrogen resources are widely distributed on Earth. Based on a comprehensive review of the genesis mechanisms and distribution patterns of globally discovered natural hydrogen， this paper categorizes the sources of natural hydrogen into two main types： organic and inorganic. The organic sources include microbial activity and organic matter pyrolysis， while the inorganic sources encompass various types such as deep hydrogen， water-rock reactions， Precambrian trapped hydrogen， radiogenic origins， fault activation， and Magma degassing. Given the current research status of natural hydrogen and the geological conditions of hydrogen-rich reservoirs， China's natural hydrogen resources have vast exploration prospects and significant potential. Due to the reactive chemical nature and complex formation mechanisms of natural hydrogen， research on its sources， migration， and accumulation mechanisms requires comprehensive analysis， incorporating characteristics of associated gases.

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.

Breakthrough progress has been made in the exploration of deep-seated coal-rock gas in the Carboniferous Benxi Formation in the Yichuan area of the Ordos Basin， and a number of appraisal wells have gained high-yield industrial gas flow， which confirms that the deep-seated coal rock gas resources in this area have the potential for large-scale development. However， there are fewer systematic studies on the reservoir characteristics of deep-seated coal-rock gas in this area， and the laws of reservoir characteristics are not well understood. Based on this， this study selected the No.1 coal seam of the Benxi Formation as the research object， and systematically investigated the characteristics of the coal-rock-gas reservoir of the Benxi Formation in terms of lithology， physical properties， pore-fracture development， and gas-bearing properties by synthesizing the experimental data of core observation， scanning electron microscope analysis， and physical properties testing. Research results show： （1） The coal body structure of No.8 coal of Benxi Formation is dominated by primary structural coal， the macroscopic type is dominated by bright coal and semi-bright coal， the microscopic group is dominated by specular group， the ash content is low， the average value is 12.76%， and the maximal reflectivity of specular body is from 2.04% to 2.53%， and it is dominated by anemic and anthracite， which is at the high maturity gas generation stage. （2） The reservoir type of No.8 coal in Benxi Formation is dominated by intergranular pores， cytosolic pores， cast pores， pneumatic pores and fissures， and some of the pores are filled by clay minerals or calcite， of which the fissures include macroscopic cuttings and microscopic fissures； the pore fissures are mainly micropores， followed by microcracks； the specific surface area is dominated by micropores， followed by macropores. （3） The physical properties of the No.8 coal of Benxi Formation show low porosity， with porosity ranging from 4.22% to 4.96% and averaging 4.59%； permeability ranging from 0.02×10^-3 μm² to 3.48×10^-3 μm² and averaging 1.21×10^-3 μm²， and the coal rock has good permeability in the stratigraphic state. （4） The adsorption capacity of No.8 coal of Benxi Formation is strong， with an air-dried basis Langmuir volume of 21.25–31.34 m³/t （averaging 27.61 m³/t） and a Langmuir pressure of 1.98–3.77 MPa （averaging 3.08 MPa）. The adsorption capacity of the coal rock has a negative correlation with the ash content， and a positive correlation with the maturity degree. The results not only provide quantitative evaluation indexes for the preferred selection of deep coal gas sweet spot in Yichuan area of Ordos Basin， but also reveal the new exploration direction of deep coal system unconventional gas reservoirs.

Natural hydrogen as a kind of clean energy will occupy an important position in the future energy pattern， many countries and regions in the world have carried out natural hydrogen exploration and research in different geological environments. At present， there are few related works in the field of natural hydrogen in China. In order to discuss the field and development direction of natural hydrogen exploration， this study analyzed the practical results of natural hydrogen investigation in China and the research on reservoir formation mechanism from the perspective of hydrogen system. Based on geotectonic conditions， groundwater occurrence characteristics， hydrogen source rock types and spatial and temporal distribution， the future natural hydrogen exploration potential areas in China are predicted and evaluated. The conclusions are as follows： （1） Abnormal hydrogen content has been detected in many sedimentary basins in China， with the highest concentration of 99%. Certain hydrogen content has also been found in other geological environments such as fault zones. The hydrogen is characterized by mixed sources. （2） There are various types of hydrogen source rocks in China， including ophiolite， banded iron formation （BIF）， basalt， granite and uranium ore， and they have spatial and temporal distribution characteristics. The deep faults outside the basin may release hydrogen from deep. The faults in the basin not only communicate hydrogen source and reservoir， but also form structural traps. Hydrogen-bearing reservoirs include shale， sandstone， coal and other lithologies， and their porosity and permeability characteristics are quite different. （3） Based on the comprehensive evaluation of hydrogen source rock association and groundwater conditions， it is divided into five areas， such as North China， Northeast and Northwest. Songliao Basin， Bohai Bay Basin and Junggar Basin. There are natural hydrogen prospect areas in Songliao Basin， Bohai Bay Basin， Junggar Basin and its surroundings. The natural hydrogen of ophiolite type represented by Tibet has exploration potential. It is believed that the compound superposition effect of multi-age and multi-type hydrogen source rocks and the underground water-bearing area are the important geological conditions for the formation of high content of natural hydrogen， and the influence of faults and formation rock characteristics on the occurrence of natural hydrogen should be considered in practical work.

The deep CBM （coalbed methane） industry of Chine has ushered in an important period of development opportunities， and it is imperative to accelerate the efficient development technology of horizontal wells. In this study， based on the coal characteristics and logging response， drilling parameters， the K coefficient is established from the aspects of coalification degree， physical property， structure， and gas-bearing property， and the coal reservoirs of Benxi Formation in the eastern Ordos Basin is divided into three types. The K coefficient of class I reservoir is more than 2， which is composed of cataclastic bright coal， primary bright coal and cataclastic semi-bright coal. The contribution rate per meter of the class I reservoir can reach three times that of the class III reservoir. The cataclastic structures are superior to primary structures. The cataclastic coal generally has better drill ability， permeability and gas content， which has a high proportion in the Class I reservoirs. Comprehensively considering the geological conditions such as coal thickness， the drilling encounter rate of coal， and the fracturing intensity， it is clearly that class I reservoirs are the “black gold targets” for the development of CBM in the horizontal wells and are the main cause for productivity. The 1 500 m horizontal length， 500 m class I reservoir length， 4-6 t/m sand intensity are the lower limits of the economic development with 5.5×10⁴ m³/d production. If the class I reservoir length exceeds 1 000 m， under the same horizontal length and fracturing intensity， the production of horizontal wells can economically increase with 7.0×10⁴ m³/d. Based on the geology， structure and reservoir types， this paper summarizes the coal-rock sedimentary models into three types： high coalification + gentle structure， transitional coal-rock + micro-structure， and cataclastic coal + complex structure. The first two models are suitable for large-scale deployment of cluster horizontal well groups， fully utilizing geological reserves and releasing production capacity. The model of cataclastic coal + complex structure has huge gas-bearing potential， which will be the key target for increasing the production of horizontal wells in the future.The guidance of horizontal well is a key process control for enhancing the drilling encounter rate of “black gold targets”. This paper proposes that the drilling quality of horizontal wells can be identified according to the changes of K coefficient， and the drilling decision can be adjusted in time. This technology will promote the iteration of coal guidance technology to “black gold target” guidance technology， and help the high-quality development of deep CBM.

With the great breakthrough of deep coal-rock gas exploration in central and western China， Turpan-Hami Basin， which is rich in coal resources， has been paid more and more attention. However， there is a lack of research on deep coal-rock gas in Turpan-Hami Basin， which seriously affects the exploration and implementation of coal-rock gas in the basin. Based on the distribution of coal-rock in the whole basin， combined with the analysis and comparison of maceral components and trace elements of coal-rock samples in the basin， the results show that： （1） The main layer of deep coal-rock gas exploration in the Turpan-Hami Basin is the second member of the Xishanyao Formation， especially the thick coal seam at the bottom of the second member， and the coal accumulation center is located in the northern part of the Taibei Depression. （2） Vitrinite is the main component of the maceral of the main coal seam， and the content of inertinite is high in some areas. Through the identification of the maceral facies， five types of coal facies are identified in the second member of Xishanyao Formation. （3） Based on the distribution range of trace element values of typical coal facies， the paleoenvironmental characteristics of different coal facies during the coal accumulation period are defined， and the coal facies distribution map of the main coal seam in the whole basin is established based on the distribution interval values of different sensitive trace elements. In Turpan Depression， the open water swamp phase and deep water forest swamp phase are mainly developed. （4） From the perspective of paleosedimentary environment and coal-forming plants， the hydrocarbon generation of coal rocks in different coal facies is analyzed， and it is pointed out that the coal-rocks in deep forest swamp facies and open water swamp facies have good gas potential. The research results provide effective guidance for the exploration target layer and selection zone of coal-rock gas in the Turpan-Hami Basin.

Understanding dynamic desorption characteristics and seepage mechanisms in deep coalbed methane （CBM） reservoirs is critical for optimizing drainage strategies and enabling large-scale development. Taking the coal of the Benxi Formation in Ordos Basin as the object， the dynamic production behavior is analyzed and a mathematical model for desorption of adsorbed gas from continuous coal matrix and gas-water two-phase flow in discrete fractures. The model was solved using the finite element method. Based on simulation results， gas migration patterns during drainage were analyzed and desorption characteristics in water-saturated coal and their impact on gas production were discussed. （1） The sensitive pressure， turning pressure， and starting pressure of the CBM are 1.87 MPa， 4.77 MPa， and 7.15 MPa， respectively. （2） CBM desorption continues to expand from the near-wellbore region to the reservoir boundary. After 500 days （1.4 years） of production， the entire reservoir pressure declines below the critical desorption pressure. （3） After 1 725 days （4.7 years）， desorption efficiency transitions from low-efficiency to high-efficiency desorption， and gas production shifts from free gas dominance to primarily adsorbed gas contribution. （4） Daily gas production strongly correlates with desorption behavior within 100 m of the wellbore. Stabilizing near-wellbore desorption efficiency maintains stable gas production. The conclusions will provide theoretical support for the formulation of optimization measures of drainage and production system.

The Ordos Basin is a key area for coal reservoir development in China. The deep coal reservoirs of the Benxi Formation in the northeastern part of the basin exhibit significant thickness， making them favorable targets for deep coalbed methane exploration. Through core observation， coal quality analysis， and pore structure characterization of planar samples from the No.8 coal reservoir in the Benxi Formation， this study investigates the coal quality and distribution characteristics of deep coal reservoirs， elucidates their genetic mechanisms， and provides theoretical guidance for optimizing coalbed methane exploitation. The deep coal reservoirs in the Ordos Basin show strong planar heterogeneity. From the tidal flat-swamp to the lagoon-swamp depositional systems， ash content gradually decreases， while thermal maturity， sulfur content， and vitrinite-inertinite ratio increase with increasing distance from the proximal source area within the lagoon-swamp system. This indicates that the tidal flat-swamp coal reservoirs formed in a relatively oxidized environment with substantial terrigenous clastic input， whereas the lagoon-swamp system developed under deeper water columns and more reducing conditions influenced by marine transgression-regression cycles. Pore development in the tidal flat-swamp system is inferior to that in the lagoon-swamp system， with better connectivity observed in distal areas of the latter. Micropores （predominantly 0.6 nm in diameter） dominate pore volume， followed by macropores， suggesting micropores are the primary pore type. The deep coal reservoirs are synergistically controlled by terrigenous clastic input and thermal evolution. In the tidal flat-swamp system， clay mineral infilling from clastic materials degrades reservoir quality， while in distal lagoon-swamp areas， reduced clastic influence and higher thermal maturity enhance hydrocarbon generation， promoting gas pore formation and improving reservoir properties. Consequently， the distal lagoon-swamp system represents the most favorable zone for natural gas exploration in the No.8 coal reservoir of the Benxi Formation.

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.

Against the backdrop of global efforts to address the climate crisis and the third energy structural transformation， an increasing number of countries are strategically formulating energy-saving and emission-reduction plans to reduce the production of fossil fuels such as petroleum and coal. Natural hydrogen gas， as a green and low-carbon energy source， with its high calorific value and absence of combustion pollution， has attracted attention worldwide. This paper systematically reviews the genesis mechanisms， distribution characteristics， and enrichment mechanisms of high-content （greater than 10%） natural hydrogen gas globally. The study reveals： （1） The genesis types of natural hydrogen gas are complex and diverse， and can be classified into two major categories based on their reaction mechanisms： organic genesis and inorganic genesis. Pyrolysis of organic matter， deep earth degassing and water-rock reaction are the main mechanisms of natural hydrogen generation， while biological processes and radiolysis of water play an auxiliary role in hydrogen enrichment in some specific environments. （2） The distribution range of natural hydrogen with high content is wide in the world. By comparing the formation and enrichment laws of hydrogen in different geological and tectonic environments around the world， it is found that natural hydrogen gas reservoirs with high content can exist in intra-continental rift system， Precambrian system， plate collision zone， subduction zone and their peripheral locations. （3） High-quality hydrogen source is the basis of hydrogen enrichment， and favorable migration， accumulation and preservation conditions are the key to hydrogen accumulation. Based on the concept of “source-migration-reservoir caprock” in traditional hydrocarbon accumulation theory， the dynamic accumulation model of natural hydrogen is proposed， and the formation and evolution process of underground natural hydrogen as well as the accumulation and preservation mechanism are discussed. （4） On the basis of in-depth analysis of the genetic mechanism and enrichment mechanism of natural hydrogen， the energy significance and future development trend of natural hydrogen are pointed out， in order to provide reference for promoting the transition from high carbon to low carbon and no carbon energy in the energy field.

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.

The Ma 5₄ ^1a sub⁃layer of Ordovician is a key gas-producing interval in the Ordos Basin. Through comprehensive analysis of core analysis， physical property determination， high-pressure mercury injection， nuclear magnetic resonance and dynamic production data， the characteristics of carbonate reservoirs in the target intervals were studied， and the lower limits of their physical properties were discussed， thus providing a theoretical basis for the exploration and development of carbonate gas reservoirs in the Yanchang Gas Field. The results reveal that the carbonate reservoir in the northern part of the Ma 5₄ ^1a sub⁃layer is predominantly composed of mud crystalline dolomite and fine crystalline dolomite， with a well-developed network of intercrystalline pores， dissolution pores， vuggy dissolution pores， microfractures， and dissolution fractures. The main reservoir type is characterized as a pore-fracture-pore system. The petrophysical log responses of the reservoir indicate high acoustic time differences （147-210 μs/m）， high neutron porosity （5%-18%）， low natural gamma values（8-40 API），low density（2.4-2.8 g/cm³），low effective photoelectric absorption cross-sections（2.5-4.2 b/e），and relatively low resistivity （40-800 Ω·m）. These features suggest that the reservoir is a low-porosity， low-permeability carbonate system. To further refine the understanding of its petrophysical limits， several analytical methods were employed， including empirical statistical analysis， bound water saturation assessment， mercury injection parameters， distribution function methods， and gas testing. A petrophysical model for porosity and permeability was established and validated using dynamic production data. These findings are critical for optimizing the exploration and development strategies for carbonate gas reservoirs in the region.

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.

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.

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.

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.

Deep coalbed methane （CBM） represents a critical new frontier for increasing natural gas reserves and production in China. Macrolithotypes govern the storage and production of CBM. This study focused on the No. 8 coal reservoir in the Benxi Formation of the Ordos Basin. Through vitrinite reflectance testing， maceral analysis， proximate analysis， CO₂ adsorption， low-temperature N₂ adsorption， and high-pressure mercury intrusion porosimetry， the pore structure characteristics and heterogeneity of deep coal reservoirs constrained by macrolithotypes were systematically analyzed. The study reveals that from bright to dull coal， vitrinite content decreases， ash yield increases， the specific surface area （CO₂-SSA） and pore volume （CO₂-TPV） of ultra-micropores gradually decrease， while the specific surface area （N₂-SSA） and pore volume （N₂-TPV） of micropores gradually increase， the pore volume of meso-macropores gradually decreases， and the cross-scale effects between pore structures relatively weaken. From bright coal to dull coal， the fractal dimension of ultra-micropores （D _C） gradually decreases， the surface fractal dimension of micropores and transition pores （D _N1） decreases， the pore structure fractal dimension of micropores and transition pores （D _N2） increases， and the fractal dimension of meso-macropores （D _M） is generally higher. D _C is positively correlated with vitrinite content， CO₂-TPV， and CO₂-SSA， and negatively correlated with ash yield. D _N1 is negatively correlated with inertinite content， ash yield， N₂-TPV， and N₂-SSA， while D _N2 is positively correlated with these parameters. The heterogeneity of pores at different scales is influenced by the source of organic pores， mineral filling， and complex geological conditions in deep formations across macrolithotypes. In bright and semi-bright coals， the aromatic layer stacking densification and reduced interlayer spacing caused by high coalification promote ultra-micropore development and higher D _C values. Endogenous fractures in bright and semi-bright coals provide more meso-macropore spaces. Semi-dull/dull coals dominated by durain and fusain exhibit cellular cavity pores and mineral-supported micropores with lower D _N1. Complex deep geological conditions induce pore deformation， combined with mineral filling and supplementation， resulting in higher D _N2 and D _M values.

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.

In recent years， the study of deep coal-rock gas has become a hot topic. However， research on the pore structure of deep coal-rock reservoirs in the Permian Longtan Formation in the Sichuan Basin is still relatively weak. To address this， taking the Well NT1 in the central Sichuan region as an example， deep coal-rock reservoir core samples were selected. Combined with experimental methods including coal petrophysical properties， geochemical characteristics， and pore structure analysis， it is shown that the deep coal structure in the central Sichuan region of the Sichuan Basin is primarily characterized by primary structures， with well-developed cleats， high organic matter content， good petrophysical properties， and overall superior coal quality conditions. Using a combination of micro-CT， scanning electron microscopy， gas adsorption methods， and high-pressure mercury intrusion porosimetry， a multi-scale quantitative characterization of the pore structure of deep coal-rock reservoirs was conducted. The results show that the storage space of the coal reservoir is mainly composed of pores and cleat fractures. The pores are predominantly semi-closed pores with one end sealed and the other end open. The organic pore surface area ratio is high， and micropores contribute significantly to the pore size distribution. The pore volume distribution is “dumbbell-shaped”， with micropores accounting for as much as 87% of the total pore volume and macropores accounting for 11%. The specific surface area of pores shows a "single-peak" distribution， with micropores making up 99% of the total. The development of nanoscale pores and microscale fractures in deep coal seams jointly controls the gas content characteristics of coal-rock gas. The initial findings suggest that the factors influencing gas content are primarily the coal quality and pore size distribution characteristics.

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.

The Upper Sinian Dengying Formation in the western margin of the Sichuan Basin is characterized by deep burial and relatively complete development. However， current levels of research and exploration remain low， with limited breakthroughs in oil and gas exploration to date. This study focuses on a typical outcrop profile at Yanziyan in Mianzhu， located in the northern segment of the Mianyang-Changning trough， to investigate the sedimentary sequence and reservoir characteristics of the Dengying Formation. The first member of Dengying Formation is dominated by mud-microcrystalline dolomites， while the second member of Dengying Formation is dominated by botryoidal structure， algal-laminated， and algal-striped dolomites. The major reservoirs develop within the second member of the Dengying Formation， with reservoir spaces primarily consisting of algal lattice pores， grape edge dissolution pores， caves， and fractures. Locally， bitumen is developed， reaching a thickness of up to 330 m. The Dengying Formation strata become more complete and thicker toward both northern and southern flanks of the Mianyang-Changning “inner trough zone”（Qingping and Yanziyan）. Carbon and oxygen isotopes indicate that the Dengying Formation sedimentation period was overall in a warm and humid marine tidal flat-lagoon （restricted platform） environment， mainly developing muddy limestone， bioclastic limestone， and dolomite， etc. in the gentle slope type carbonate rocks. The Dengying Formation reservoirs in the study area underwent three main evolutionary stages： the sedimentary period of the microbial reef， the near-simultaneous period of frequent exposure and dissolution， and the supergene karst period with atmospheric freshwater infiltration and dissolution. The repeated leaching and dissolution of atmospheric fresh water in the quasi-contemporaneous period are the key factors for the formation of high-quality reservoirs such as Dengying algal lamination and botryoidal structure algal dolomites. Subsequently， during the deep burial period， the dolomite reservoir of the Dengying Formation in the study area underwent at least three diagenetic fluid transformations， and during the late-stage diagenesis， quartz-rich fluid primarily transformed and filled the dissolution pores， caves， and fractures formed during the contemporaneous and supergene karst periods. The Dengying Formation profile at Yanziyan in Mianzhu， located in the favorable lower intertidal zone of the northern segment of the Mianyang-Changning trough， features thick and high-energy algal mound facies. The algal mound dolomite reservoirs are thick and exhibit good porosity and permeability. Combined with high-quality Cambrian source rocks， the middle segment of the Longmen Mountains in the northern segment of the Mianyang-Changning trough can be considered a key target area for future natural gas exploration.

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 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.

Kerogen of source rock has great potential for hydrogen production during thermal maturation evolution. At present， the characteristics of hydrogen production during the thermal evolution of kerogen are unclear， the influence mechanisms of chemical structure and pore structure of kerogen on the hydrogen production capacity are unknown， and the mechanisms of the role of water on the pyrolytic hydrogen production of kerogen need to be elucidated. In this work， the unit structures and matrix models of kerogen under dry and water-bearing conditions were constructed， and the molecular dynamics simulation method based on the ReaxFF force field was used to conduct the pyrolysis simulation of immature kerogen at elevated temperatures and kerogen at different maturity stages. The results show that： （1） During the thermal maturation process， the lower matured kerogen is more capable of producing hydrogen， and hydrogen is mainly produced in the high-temperature stage； （2） The main mode of hydrogen production during kerogen thermal evolution is the combination of hydrogen atoms from the aliphatic structures； （3） Water promotes the pyrolysis of hydrogen in the aliphatic structure of kerogen through the role of hydrogen source and the catalytic effect； （4） Hydrogen production from thermal evolution of kerogen is affected by both chemical structure and pore structure， with chemical structure having a greater influence than pore structure. The results improve the theory of hydrogen production from pyrolysis of kerogen， which can provide theoretical guidance for the exploration and development of natural hydrogen reservoirs.

Aiming at the decay and failure of long-term conductivity of propped fractures in deep coal-rock fracturing， long-term conductivity test was carried out by the FCES-100 fracture conductivity test device to evaluate the influence of coal-rock environment （comparing steel plate and coal rock）， proppant grain size （40/70 mesh and 70/140 mesh）， proppant concentration （2.5， 5， 10 kg/m²） and stress conditions （30 and 40 MPa） on the long-term conductivity law. The attenuation and prediction of long-term conductivity of propped fractures under actual production conditions were carried out， and the evaluation of the decreasing production law of deep CBM horizontal wells was carried out in combination with actual production data. The study shows that： （1） the long-term conductivity under different conditions shows a trend of rapid decline followed by slowing down with time. In the first 40 hours of the test， the decline of flow conductivity under different conditions was more than 94%， and in the second 40 hours of the test， the difference of flow conductivity under different conditions tended to stabilize. （2） When the proppant particle size is 40/70 mesh， the conductivity under the steel plate condition is larger than that under the coal rock condition， and the opposite is true when the proppant particle size is 70/140 mesh. The hydration of coal rock has a relatively large effect on the embedding of proppant. （3） The reduction of proppant particle size can effectively reduce the effect of proppant embedding on the inflow capacity. （4） The increase of proppant concentration can effectively weaken the effect due to proppant embedding under coal rock conditions. （5） The reduction of proppant particle size can shorten the failure time of inflow capacity， and too low proppant concentration can lead to the significant shortening of the failure time of inflow capacity. （6） The production decay coefficient shows a slow decline， then a rapid decline， and then a gentle decline with the increase of mining time. The error of predicting the field cumulative production data with the exponential decay law is only 2.9%. The study on the evaluation of long-term conductivity of fractured propped fractures in deep coal rocks can help the optimal design and beneficial development of fracturing for deep coalbed methane.

Currently， there is limited research on coal-rock gas in the Jurassic Kezilour Formation of the Kuqa Depression， with unclear geological characteristics and favorable accumulation models for coal-rock gas. To address these issues， this study utilized drilling， testing， and sampling data， combined with seismic data processing， well correlation analysis， sample observation， and gas experiments on core samples， to investigate the geological features of coal-rock gas， including their occurrence state and genesis types and favorable accumulation models in the coal-bearing strata of this block. The results demonstrate： （1） In the study area， the macroscopic coal types of the coal seams in the Kezilour Formation are dominated by semi-bright coals， characterized by very low ash content， medium to high volatility， and very low sulfur content. These are intermediate to low-rank coals with porosity of 6.53% and permeability of 0.68×10^-3 μm² in deeper coal seams. The pore types of coal seams are mainly mesopores， which are more conducive to the occurrence of free gas. （2） The coal-rock gas components of the Kizilnur Formation are mainly methane， with a dry coefficient of 0.95-0.99， indicating predominantly thermogenic gas with both autochthonous and external sources， occurring mainly as free gas and adsorbed gas in the coal seams. （3） The Neogene is the peak period of gas production in the Ke-4 coal seam of the Yiqikelike tectonic belt， as well as a critical period of fault activity and reservoir formation. Preservation conditions will be a key factor in the formation of coal-rock gas reservoirs. The gentle-slope zone and low-potential area formed by the structure are favorable locations for coal-rock gas exploration， and the coal thickness condition is a key factor affecting the abundance of coal-rock gas resources. Considering the lower maturity and relatively high adsorption capacity of the coal seams of Jurassic Kizilnur Formation in the Kuqa Depression， it would be more advantageous to choose high positions or gentle slope areas where thick coal seams are developed and free gas is enriched. Therefore， the northern gentle slope area with thick coal seams will be the focus of coal-rock gas exploration， while the formation mode of micro uplifts and fault-block platforms are the favorable formation modes for coal-rock gas exploration in the Kuqa Depression.

The tight sandstone of the Triassic Yanchang Formation in Ordos Basin has strong mechanical compaction and cementation， the porosity and permeability are very low， and the pore structure become an important factor affecting the reservoir velocity. Therefore， the change of pore structure will cause the change of AVO response， which causes trouble to the fluid identification. In this paper， the rock physics model of the two-dimensional regular polygon pore structure is combined with the AVO analysis method to analyze the AVO response characteristics of the key parameters of the tight sandstone reservoir in the study area. The results show that the pore shape has a significant influence on the AVO response， and the AVO response law caused by the pore shape in the reservoir containing different fluids has similar trend but different values. The comparative study of AVO attribute analysis showed that the P/G property is highly sensitive at ultra-low porosity（φ=1%），∆F is sensitive at low porosity （1%φ≤3%）， SPR×G is sensitive at medium porosity （3%φ8%）， and FF is sensitive at high porosity （φ≥8%）. The results provide theoretical support for the fluid identification using AVO attributes in the study area.

Amid the global transition to low-carbon energy systems， hydrogen energy， as a zero-carbon energy carrier， relies on underground hydrogen storage （UHS） technology for large-scale storage. This paper systematically reviews research progress on hydrogen diffusion mechanisms in UHS systems， focusing on multi-mechanism coupled diffusion theory in porous media， innovations in experimental testing methods， and cross-scale numerical simulations. The study reveals that hydrogen diffusion involves synergistic mechanisms of Fick diffusion， Knudsen diffusion， and surface diffusion. Knudsen diffusion contributes 60%-85% to mass transfer in nanopores， while surface diffusion significantly influences transport efficiency in organic/clay-rich media. Experimental findings indicate that rock type （e.g.， salt rock diffusion coefficients： 10⁻¹¹-10⁻⁹ m²/s； shale： 10⁻¹⁰- 10⁻⁸ m²/s）， pore structure， temperature-pressure conditions （a 40 °C temperature rise can increase diffusion coefficients by over 50%）， and pore water properties （5%（wt） salinity increase reduces diffusion coefficients by 12%-30%） are critical factors governing diffusion behavior. However， existing experimental methods （e.g.， hydrocarbon concentration method， desorption method） exhibit data variability spanning two orders of magnitude under high-temperature and high-pressure conditions （>100 °C，>30 MPa）. Numerical simulations remain limited in modeling multi-field coupling （thermal-hydraulic-chemical-mechanical interactions） and microbial effects. Future research should prioritize cross-scale model development， high-temperature/high-pressure in situ experimental techniques， multi-physics coupled simulations， and long-term stability assessment frameworks. Establishing standardized testing protocols and intelligent digital twin platforms will enhance the safety and efficiency optimization of UHS engineering， providing crucial theoretical support for hydrogen energy infrastructure development.

There are several sets of organic-rich shales in the Triassic of Ordos Basin， which have broad prospects for oil and gas exploration. It is of great significance to define the reservoir characteristics and main controlling factors of different shale lithofacies to study the law of shale oil enrichment and to find favorable areas. In this paper， by means of thin section observation， scanning electron microscopy， X-ray diffraction， rock pyrolysis analysis， high pressure mercury injection and nitrogen adsorption， the shale of the seventh member of Yanchang Formation （Chang 7 Member） was divided into lithofacies， and the difference of reservoir space among different lithofacies was compared to determine the dominant lithofacies and the controlling factors of pore structure. The shale of Chang 7 Member in the study area is characterized by complex lithology， developed laminae and high organic carbon content. As a whole， the shale belongs to low porosity and low permeability reservoir， and the physical properties of the reservoir are obviously different in different sedimentary environments. Therefore， based on the classification criteria of “lithology+TOC（<3%，3%-6%，>6%）+mineral composition （50% as the limit）”. The shale can be divided into seven rock facies： low organic siliceous shale （L-S）， high organic siliceous shale （H-S）， organic-rich siliceous shale （R-S）， high organic clay shale （H-C）， high organic mixed shale （H-M）， and organic-rich mixed shale（R-M）. H-S lithofacies are dominated by intergranular pores， dissolution pores and fractures， with optimal pore parameters， developed reservoir space and high oil saturation， which are the dominant lithofacies in the study area. Mineral composition， TOC and striation characteristics are the controlling factors of reservoir space， TOC plays an important role in controlling the development of shale micropores during the whole thermal evolution stage. The silty laminated reservoir has good physical properties， and the intergranular pores are well preserved by the mutual support between rigid clastic particles such as feldspar and quartz， which increases the number of large pores and is conducive to the enrichment of shale oil. The research results can provide some reference for the exploration and development of shale oil.

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.