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.

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.

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.

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 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.

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.

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

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.

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.

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.

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.

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 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 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.

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.

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.

近期勘探发现，在鄂尔多斯盆地西南缘庆阳气田天然气中发现伴生的氦气，为中氦—高氦气藏，不仅具有常规天然气藏还包括一种新型非常规气藏——铝土岩气藏。目前对于铝土岩气藏的富氦机制尚不明确。通过对鄂尔多斯盆地庆阳气田天然气进行地球化学分析测试，判识2种天然气藏中天然气及氦气的成因和来源，结合氦气成藏条件分析铝土岩气藏富氦机制，对比分析与常规富氦气藏的形成差异。结果表明：①庆阳气田铝土岩天然气中的甲烷含量与常规天然气相近，但乙烷和丙烷的含量较高。常规天然气以干气为主，而铝土岩气藏天然气整体接近湿气。②庆阳气田天然气氦含量整体较高，为中—富氦天然气藏，铝土岩气藏氦气含量均与同区域的常规天然气藏氦气含量存在差异，但铝土岩气藏天然气氦气含量整体较为一致（约为0.1%）。③庆阳气田中氦气是典型壳源成因，其常规天然气的氦气主要来源于变质岩基底，为载气长距离运移萃取氦气的富集模式。与常规天然气藏相比，铝土岩气藏的氦气发育截然不同的富集模式，铝土岩气藏中的氦气为自生自储成藏，其主要来自于富铀钍铝土岩自身的衰变释放，仅经过短距离的垂向运移进入到铝土岩储层，外源氦气较少。铝土岩气藏富氦模式的建立为氦气的勘探和开发提供了新思路。

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.

Light hydrocarbon parameters have been widely used in the exploration and development of oil and gas reservoirs. However， the component characteristics of light hydrocarbons between condensate oil and residual oil formed under different degrees of gas invasion are different. In order to verify the applicability of light hydrocarbon parameters to condensate oil， normal crude oil samples in Tazhong area of Tarim Basin were collected. Based on PVT simulation experiment， the composition of light hydrocarbon compounds was analyzed， and the distribution characteristics of C₅-C₈ light hydrocarbon components during gas invasion were analyzed. The light hydrocarbon indexes suitable for the comparison of condensate oil source and other secondary effects were selected， which provided a theoretical basis for the study of condensate oil accumulation. The results show that， controlled by carbon number， molecular weight and molecular configuration， the response of light hydrocarbon composition to gas invasion degree is different. With the increase of gas invasion degree， the relative content of n-alkanes and iso-alkanes in C₅-C₈ light hydrocarbon compounds in condensate oil products shows a downward trend， while the relative content of cycloalkanes increases， but the overall distribution of n-alkanes is still relatively dominant. The chain alkanes in C₆-C₇ light hydrocarbon compounds are obviously affected by gas invasion， while aromatic hydrocarbons and cycloalkanes are less affected by gas invasion. The relative content of dimethylcyclopentane in C₇ light hydrocarbon components did not change significantly， the relative content of methylcyclohexane increased， and the relative content of n-heptane decreased. In order to carry out the evaluation of condensate oil-source correlation and water washing effect， the parameters with variation less than 5% should be preferentially selected. In order to evaluate the degree of gas invasion suffered by condensate oil， the parameters with a variation of more than 40% should be preferentially selected. In the geological background where the degree of gas invasion is not yet clear， the common light hydrocarbon parameter system should be cautious in practical geological applications. The results further enrich and improve the content of light hydrocarbon geochemistry.

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.

Helium （He） is an indispensable strategic resource in high-tech industries， and its migration and preservation are highly dependent on the synergistic effects of carrier gases such as methane （CH₄）， carbon dioxide （CO₂）， and nitrogen （N₂）. To elucidate the microscopic coupling mechanisms and environmental dependence of He-carrier gas interactions， this study integrates quantum chemical calculations with molecular configuration screening to systematically evaluate the coupling energies and structural stability of He with various carrier molecules under both anhydrous and hydrous conditions. The results show that in anhydrous environments， the coupling affinity of He follows the order CO₂ > CH₄ > N₂ > He. Under hydrous conditions， the affinity of He for CO₂ and CH₄ decreases， while its interaction with N₂ becomes significantly more stable， accompanied by notable spatial relocation of the coupling sites. Solvation effects from water molecules enhance the He-N₂ interaction，indicating that pore water can promote the co-existence of He and N₂. In multi-molecular systems， He-H₂O complexes exhibit the highest stability， followed by He-CO₂， He-CH₄， and He-N₂. In addition， carrier molecules， due to their larger molecular sizes and the formation of molecular clusters， can cause physical obstruction in caprock pore throats， thereby improving sealing capacity and reducing He leakage. Based on these findings， this study identifies three critical microscopic contributions of carrier gases to helium accumulation， summarized as “aggregation in water， transport through fractures， and retention by caprock.” These mechanisms reveal， from a molecular perspective， the cooperative role of the He-carrier system in helium accumulation， providing a theoretical foundation for understanding accumulation mechanisms， evaluating caprock sealing efficiency， and predicting helium-rich sweet spots.

In recent years， research on helium in onshore gas reservoirs has received increasing attention both domestically and internationally， but there is relatively little research on the genesis and accumulation of helium in offshore oil and gas reservoirs. By summarizing and analyzing the helium content in oil and gas reservoirs， helium isotope ratio， associated geochemical characteristics of carbon dioxide in the Pearl River Mouth Basin， this paper discussed the origin of helium in the Pearl River Mouth Basin， and summarizes the helium accumulation model of typical high- to rich-helium gas reservoirs in this region. The research shows that the helium content of dissolved gas in the CO₂ gas cap oil layer in Enping 15-A Oilfield in the Pearl River Mouth Basin is 0.227%- 0.725%， reaching the helium-rich level. The helium content of CO₂ gas reservoir in Enping 23-E Oilfield is 0.101%， reaching the helium-high level. The helium contents of other oil and gas fields are lower than 0.03%， which are helium-poor to helium-low reservoirs. Oil and gas reservoirs with high He content in the Pearl River Mouth Basin are generally rich in CO₂， and He may be associated with CO₂. The values of ³He/⁴He are all in the range of （0.82-11.42）×10^-6， showing characteristics dominated by mantle derived factors for typical high- and rich-helium oil and gas reservoirs. Through the analysis of diagenetic sequence of oil and gas inclusions in high- to rich-helium oil and gas reservoirs and microthermometry data， it is believed that the oil and gas charging characteristics of the Zhujiang Formation in helium-rich Enping 15-A Oilfield and the Enping Formation in Enping 23-E Oilfield CO₂ gas reservoir are “two phases of oil， two phases of CO₂ and associated helium”. Volcanic activity and deep faults control the accumulation of CO₂ and helium， and two helium accumulation models have been established： deep faults to structural ridges to shallow reservoirs of the Zhujiang Formation； the controlling faults communicating with volcanic activity zones to shallow faults or volcanic vents to deep reservoirs of the Enping Formation. For the Pearl River Mouth Basin， where deep faults and tectono magmatic activities are developed， is a favorable area for the discovery of helium rich resources.

Underground hydrogen storage （UHS） is a key technology for promoting renewable energy integration， mitigating wind and solar curtailment， and stabilizing grid output. However， China currently has no operational UHS projects. Although experience from underground gas storage and carbon dioxide sequestration can be used for reference， the unique physicochemical properties of hydrogen require further investigation. Based on an extensive review of domestic and international literature， this paper summarizes the classification and development status of UHS， with a focus on research progress in hydrogen migration-diffusion mechanisms， biochemical reactions， and safety evaluation. Studies indicate that depleted oil and gas reservoirs， aquifers， and salt caverns are suitable structures for large-scale and long-term hydrogen storage. Nevertheless， challenges such as high diffusivity， geochemical reactions， microbial activity， and geomechanical risks remain， and current research in these areas is clearly inadequate. There is a need to strengthen studies on multi-process coupling mechanisms. Finally， considering geological conditions， this paper analyzes the prospects for underground hydrogen storage， showing that tight sandstone gas reservoirs alone have the potential to store at least 337 million tons of hydrogen. The findings of this study can provide critical scientific justification and engineering feasibility support for formulating China’s large-scale hydrogen storage strategy and promoting the development of major demonstration projects for UHS.

Practical studies have revealed a close association between helium-rich natural gas and regional mudstone-shale formations. However， the controlling role of regional shales in helium enrichment remains underexplored. This paper analyzes the generation， migration and accumulation relationships between helium and four regional shale units in the Sichuan Basin： The Qiongzhusi Formation， Wufeng-Longmaxi formations， Dongyuemiao Member， and Da′anzhai Member of the Ziliujing Formation. Based on it， it can be concluded that： The cumulative helium generation intensity of these shales ranges from 0.57×10⁴ to 21.31×10⁴ m³/km²， exhibiting a pronounced vertical attenuation trend.This intensity is significantly weaker than the 43.62×10⁴ m³/km² generated by basement granites. Terrestrial shale hydrocarbon generation demonstrates a helium dilution capacity exceeding 43 901.7 times， surpassing that of marine shales. Notably， the Qiongzhusi Formation exhibits the weakest hydrocarbon dilution intensity （about 267.5 times）， below the typical dilution intensity of conventional source rocks （3 000 times）. At current geological conditions， the helium dissolution capacity in shale pore water is about 30 to 76 times the historical cumulative amount of geologic helium generation， driving pressure-driven directional migration and systematic accumulation of dissolved helium in confined aquifers. Gas-bearing shale layers establish a “dual deceleration zone” through capillary sealing and hydrocarbon diffusion retardation， effectively reducing vertical helium escape rates. Spatial helium distribution in the Sichuan Basin is dominantly controlled by the Qiongzhusi mudstone/shale， indicating that helium accumulation is primarily governed by the first regional shale unit overlying the principal helium source rock. Deep-seated faults intersecting basement helium sources facilitate deep helium expulsion， enabling shallow helium-rich gas reservoir formation.

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.

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.

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.

Previous studies have discovered helium resources in the coalbed gases of the Carboniferous–Permian coal-bearing strata in areas such as Baode， Sanjiaobei-Shixi， Daning-Jixian， and Hancheng at the eastern margin of the Ordos Basin. Gas component analysis results have shown significant regional differences in the concentration of helium in coalbed gas. This paper conducts a comprehensive geological study to analyze the key geological controlling factors responsible for the differential enrichment of helium in the coalbed gases at the eastern Ordos Basin. Geochemical analysis indicates that most Carboniferous-Permian coal-bearing rocks in the Ordos Basin have high Th-U contents and helium generation potential. However， due to the generally high content of hydrocarbon gases in coal seams， indigenous ⁴He generated by in-situ decay of coal-bearing rocks without external helium supplementation is unable to form helium resources of industrial value. Baode， Sanjiaobei–Shixi， and Daning-Jixian are located in the Jinxi flexure zone with similar structural deformations， but only in the Sanjiaobei-Shixi region does the concentration of helium in coalbed gas reach industrial extraction standards， a variability possibly linked to the basement. Aeromagnetic data reveal that the Sanjiaobei-Shixi region is situated above basement gneiss rock， which has undergone prolonged decay and exhibits a high helium generation potential， serving as an important supply source of helium in the Carboniferous-Permian coalbed gases in the region. Similar to the Sanjiaobei-Shixi region， the Hancheng mining area also lies above gneiss basement rock， but the helium content in coalbed gas in the Hancheng region is significantly lower than that in the Sanjiaobei region. Seismic profiles and field observations indicate that significant deep-seated faults cutting through the Carboniferous-Permian strata are not developed in the Sanjiaobei-Shixi region， while the Hancheng region features prominent deep-seated faults， causing intense tectonic deformation and structural damage to the Carboniferous-Permian coal-bearing strata in the area. This paper proposes that the supply of external helium sources such as basement gneiss is the basis for the enrichment of helium in coalbed gas， and that later tectonic processes are essential for the modification of coal-bearing strata to ensure the enrichment of helium in coalbed gases. Later tectonic modifications should facilitate the transportation of external helium sources to the coal-bearing strata while ensuring efficient retention of helium.

This paper clarifies the helium sources and the controlling factors for the differences in helium enrichment in the Dengying Formation of the Weiyuan and Anyue gas fields through the geochemical characteristics of natural gas components， rare gas isotopes， and the proportion of water-soluble helium desorption. The results show that： （1） The average helium content in the Dengying Formation of the Weiyuan Gas Field is 0.25%， while that of the Anyue Gas Field is only 0.024%. （2） The mantle-derived helium contribution ratio in both gas fields is less than 1%， indicating a typical crustal source of helium. （3） The helium in the Dengying Formation of the Weiyuan Gas Field comes from the desorption of water-soluble helium in the basement granites， while in the Dengying Formation of the Anyue Gas Field， the helium in some wells with higher helium content （He > 0.04%） comes from the desorption of water-soluble helium in the basement metamorphic rocks， and the helium in wells with lower helium content mainly comes from the free helium in the Qiongzhusi Formation. （4） The different initial water-soluble helium concentrations in the two types of helium source rocks， granites and metamorphic rocks， are the main reasons for the differences in helium enrichment in the Dengying Formation of the two gas fields. The desorption of helium and the dilution effect of hydrocarbon gas injection during the tectonic uplift process are also the reasons for the further differences in helium enrichment in the Dengying Formation of the two regions. This study provides new ideas for the exploration of helium-rich reservoirs in ancient superimposed basins through analogy.