Pore structure characteristics are the main factor affecting shale reservoir， and its qualitative and quantitative characterization and main controlling factors are key issues in shale reservoir research. In order to explore the differences in microscopic pore structures and main controlling factors of different sedimentary microfacies of deep shale reservoir， this paper selects the Wufeng-Longmaxi formations in Well Z301 of Zigong area in southern Sichuan Basin as an example， based on systematic experiments such as core， thin section， scanning electron microscopy observations， X-ray diffraction analysis， organic geochemical analysis， N₂/CO₂ adsorption， high-pressure mercury injection， the vertical heterogeneity of pore structure in the O₃ w-S₁ l ₁ shale reservoir is analyzed. The research results indicate that the sedimentary microfacies of the O₃ w-S₁ l ₁ shale reservoir in the study area can be divided into three categories from bottom to top： strong reducing， high carbon， calcium-rich， and silicon rich deep-water continental shelves （microfacies ①）， weak reducing-medium carbon-calcium containing-silicon mud mixed-deep water continental shelves （microfacies ②）， and weak reducing-weak oxidizing-low carbon-siliceous mud-semi deep water continental shelves （microfacies ③）； among the three types of microfacies， macropores are mainly inorganic pores， while mesopores and micropores are mainly organic pores. Mesopores and micropores are also the main pore types that control the volume and specific surface area of shale pores； the development degree of different pore types varies among the three microfacies； mesopores and micropores are the most important pore type that controls reservoir physical properties and gas content； TOC and the content of clay minerals are the key factors affecting the pore structure of deep shale. Quartz has a slightly weaker controlling effect on nanoscale pores， while carbonate minerals have no significant controlling effect on nanoscale pores； the characteristics of high TOC， low clay minerals， and high brittleness minerals in microfacies ① determine that it is the most commercially valuable lithofacies for mining. The relevant conclusions can provide guidance for enriching the high-yield patterns of deep shale gas enrichment.

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.

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.

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.

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.

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.

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.

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.

In recent years， the Middle Jurassic Shaximiao Formation in the Qiulin-Jinhua and Bajiaochang structures in the central Sichuan Basin has become a hot spot of exploration. However， the origin of tight gas in the Shaximiao Formation in the study area remains unclear. In this study， the hydrocarbon generation potential of source rocks was evaluated based on total organic carbon content （TOC） and Rock-Eval pyrolysis of thirty-seven mudstone samples from the Da’anzhai Member of the Lower Jurassic Ziliujing Formation， the Lianggaoshan Formation， and the Upper Triassic Xujiahe Formation. Moreover， nineteen gas samples from the Shaximiao and Xujiahe formations were analyzed using gas chromatography and isotope ratio mass spectrometry to determine their origin. The results show that mudstones from the Da’anzhai Member and Lianggaoshan Formation are good source rocks at the mature stage， with type Ⅱ₁-Ⅱ₂ kerogen， TOC content ranging from 0.48% to 2.79% （average 1.30%）. In contrast， the mudstones of the Xujiahe Formation are mature–highly mature hydrocarbon source rocks， with type III kerogen and variable organic matter abundance. Most gas samples from the Qiulin-Jinhua areas show similar characteristics to those from the Xinchang Structure in western Sichuan Basin， indicating mature-highly mature coal-type gas sourced from the Xujiahe Formation with minor Jurassic contributions. The Bajiaochang area is dominated by mature coal-type gas and mixed gas sourced from the Xujiahe Formation and Jurassic source rocks， while the Gongshanmiao area produces oil-type gas from Jurassic sources. Regionally， Jurassic source rock contributions to Shaximiao Formation gas increase from west to central Sichuan Basin， controlling gas reservoir distribution. Coal-type gas of the Shaximiao Formation in Qiulin-Jinhua area may be transported laterally primarily from western Sichuan Basin via faults and fluvial sandstone reservoirs， supported by the similar gas maturity of gas and accumulation timing to the Shaximiao Formation reservoirs in western Sichuan Basin. In the Bajiaochang area， faults connecting the Shaximiao Formation reservoir with both the Xujiahe Formation and Jurassic source rocks are well-developed， resulting insignificantly increased proportions of mixed gas. Thus， fault-mediated vertical transmission represents a critical pathway for natural gas charging in this area.

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.

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.

In order to clarify the geochemical characteristics of Paleogene source rocks and the source of crude oil in Shunde Sag of Pearl River Mouth Basin， the geochemical characteristics of Wenchang Formation source rocks were analyzed systematically， followed by oil-source correlation by combining the total organic carbon content of source rocks， Rock-Eval pyrolysis and biomarkers of source rocks and crude oil. The abundance of organic matter in the E₂ w ₁ and E₂ w ₃ source rocks is low， and the type of organic matter is mainly type Ⅱ₂ and type Ⅱ₁.The abundance of organic matter of E₂ w ₂ source rocks is high， and the type of organic matter is mainly type I， which enters the mature stage as a whole. The medium Pr/Ph value of the source rocks of the Wenchang Formation indicates that they were deposited in a weak reduction-weak oxidation environment， and the low gammacerane value indicates that they were deposited in a freshwater environment. The C₂₇-C₂₈-C₂₉ regular steranes of the E₂ w ₁ source rocks are anti-“L” type， indicating that the source of terrestrial higher plants is dominant， while the regular steranes of the source rocks in the other layers are mainly “V” and “L” -shaped patterns， indicating the mixed source of lower aquatic organisms and terrestrial higher plants. The oil shale of E₂ w ₂ source rocks has high C₃₀ 4-methyl sterane content. E₂ e ₂ crude oil has low Pr/Ph value， low C₁₉₊₂₀TT/C₂₃TT value， C₂₇-C₂₈-C₂₉ regular steranes exhibiting a V-shaped pattern， and high abundance of C₃₀ 4-methyl steranes. The results of oil source comparison analysis show that the E₂ e ₂ crude oil comes from E₂ w ₂ source rocks.

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.

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 distribution patterns in the degree of gas invasion of oil and gas reservoirs in the Tarim Basin，geochemical analysis methods were employed to delineate the distribution characteristics of biomarkers and carbon isotope composition of individual n-alkane ratios in oil and gas reservoirs across different well areas in this paper.The results indicate significant differences in the physical properties of crude oil， the characteristics of light hydrocarbons， and the carbon isotope composition of individual n-alkanes between the TZ83 well area and the ZG43 well area. The extent of n-alkane loss， the carbon number at the breakpoint， and the content of adamantane series compounds indicate that the crude oil in the TZ83 well area exhibits relatively strong gas invasion， while the crude oil in the ZG43 well area shows relatively weak gas invasion. The study indicates that the variations in gas invasion intensity may be attributed to the differing structural positions of the well areas. The TZ83 well area is situated in the high structural zone at the intersection of the Tazhong Ⅰ fault slope fold belt and the strike-slip fault， where the underlying gas source， adjusted by faults， exerts a strong gas invasion influence， resulting in condensate oil. In contrast， the ZG43 well area is located on the platform zone of the Tazhong 10 fault belt， where the development of deep and large fault systems is less pronounced， leading to weaker gas invasion effects and the formation of waxy oil. In the shallow reservoirs， there may be undiscovered condensate oil reservoirs.

Sanhu Depression is the most important biogas-producing area of the Quaternary in Qaidam Basin， with huge natural gas resources. In order to clarify the depositional environment for the formation of mudstone reservoirs in gas reservoirs and provide a basis for reservoir sweet spot evaluation， this paper analyzes the elemental geochemical characteristics and sedimentary environment of mudstone core samples from Wells ST1 and ST2 in Sebei area of Sanhu Depression through hand specimen analysis， microscopic observation and elemental testing. The findings reveal that samples from Wells ST1 and ST2 are predominantly composed of dark mudstone and siltstone， interspersed with dolomite in block， band， and laminar forms. They contain a great number of snails and plant fragments， reflecting the sedimentary environment of shallow lakes and semi-deep lakes. It has the characteristics of low silicon， weak supersaturation of aluminum， low potassium sodium， rich in magnesium and calcium， enrichment of Ba， Sr and Rb， and loss of Zr， Hf and Ni. The ICV and CIA indices， along with Th/SC-Zr/Sc discriminant maps， suggest that the Quaternary mudstone in the Sebei area underwent only mild to moderate weathering and remained largely unaffected by sedimentary sorting or recycling processes. Parameters such as Ceanom， &U， and δCe indicate that the deposition period is the environment for the transition from reduction to oxygen deficiency. The ratios of Sr content to Th/U and V/Zr are indicative of a saline water to brackish water environment. Moreover， the MAP and LST parameters， as well as Sr/Cu， Zr/Rb ratios collectively reflect a cold and dry paleoclimatic environment with weak hydrodynamics. The high soluble organic matter content of Quaternary mudstone in the Sebei area of the Sanhu Depression， coupled with frequent changes in sedimentary water environments， has resulted in distinct vertical sand-mud interbedded characteristics， forming a favorable reservoir cap combination and facilitating the formation of mudstone biogas reservoirs.

The Upper Paleozoic tight sandstone gas in the western Ordos Basin has become a key area for the increase of natural gas reserves and production in the basin. The Taiyuan Formation， as a newly explored layer in the western Ordos Basin， has demonstrated significantly superior gas test and production performance compared to the 8th member of the Shihezi Formation and the Shanxi Formation above it. In order to clarify the natural gas enrichment law of Taiyuan Formation， the main controlling factors of natural gas enrichment in Taiyuan Formation were determined by using logging， analytical test and three-dimensional seismic data， and through the study of coal-measure source rock evaluation， sedimentary reservoir characteristics， structural characteristics， etc. Research has shown that the main hydrocarbon source rock of Upper Paleozoic Benxi Formation in the Yanchi area has a hydrocarbon generation intensity of （10-24）×10⁸ m³/km²， and the middle-eastern part of the study area has a high hydrocarbon generation intensity； a new understanding of the development of barrier coastal sedimentation in the Taiyuan Formation has been proposed for the first time. The distribution of barrier sand bars is stable， with an average thickness of 10.2 m. The reservoir is homogeneous， and the rock type is quartz sandstone， with an average porosity of 7.6% and an average permeability of 1.12×10^-3 μm²； multi-phase faults are developed， which are not penetrated to the Shiqianfeng Formation. In particular， the Hercynian faults connect the gas source rocks at the bottom， constitute a favorable migration channel for natural gas， and improve the physical properties of the reservoir； the higher the intensity of hydrocarbon generation， the more faults in Hercynian and the closer the distance， the better the physical properties of the reservoir， and the more enriched the natural gas. The research results can provide reference for natural gas exploration with the same geological characteristics in Ordos Basin.

Natural fractures play a critical role in controlling the productivity of shale oil reservoirs， and their accurate identification and characterization are essential for the optimal selection of sweet spots and efficient development of shale oil and gas. This study investigates the mixed shale oil reservoirs in the upper member of the Lower Ganchaigou Formation in the Yingxiongling area， Qaidam Basin. Core samples， thin sections， scanning electron microscopy （SEM）， and both conventional and advanced logging data were used to summarize the types and characteristics of natural fractures in the study area， and a comprehensive logging-based fracture identification model was developed. This model enables continuous fracture identification and characterization from well logs. Furthermore， by integrating fracture parameters with core experimental data， the degree of fracture development and their effectiveness were analyzed. The results show that natural fractures in the study area can be classified into three types： tectonic fractures， diagenetic fractures， and abnormal high-pressure fractures. Tectonic fractures are predominantly high-angle and highly filled， diagenetic fractures are typically low-angle horizontal with a low degrees of filling， and abnormal high-pressure fractures exhibit irregular orientations and are often filled. Fractures are most developed in the VI oil layer group of the upper member of the Lower Ganchaigou Formation， followed by the V oil layer group， with the IV oil layer group being relatively less developed. In general， low-angle unfilled fractures are the most abundant， horizontal unfilled fractures exhibit the highest developmental intensity， and high-angle unfilled fractures demonstrate the best effectiveness. The current maximum horizontal principal stress direction in the study area is NE-SW， and most unfilled fractures form angles less than 30° with this direction， which enhances their fracturing efficiency. In contrast， filled fractures have dominant orientations forming angles greater than 40° with the maximum horizontal principal stress， which reduces their fracturing efficiency. The findings of this study are expected to provide theoretical and methodological support for the identification and evaluation of natural fractures， and the optimization of sweet spots in lacustrine mixed shale oil reservoirs.

The Kuqa Depression in the Tarim Basin has developed two sets of coal bearing strata， Triassic and Jurassic. The Jurassic coal seams exhibit multi-layered characteristics， large cumulative thickness， and wide distribution area， which has the material basis for the development of coal rock gas. This study conducted a comprehensive evaluation of the Jurassic coal quality and reservoir characteristics in the northern structural belt of the Kuqa Depression through intensive core sampling， combined with rock debris data， and the use of techniques such as microscopic identification， industrial analysis， vitrinite reflectance measurement， electron microscopy scanning， conventional physical property analysis， nuclear magnetic resonance detection and CT scanning， nitrogen adsorption. The results showed that： （1） the microscopic components were mainly vitrinite， with an average content of 64.06%； coal has the characteristics of medium to high volatile matter， extra-low moisture content， and ultra-low ash content； overall， and the maturity is relatively low. （2） Various matrix pores and fractures are developed，with larger micro-fractures as the main component in the pore network， the micro-fractures are interconnected through stacking with each other.The porosity of shallow samples is 4%- 23%， with an average of 9.7% and a high proportion of mesopores and macropores. The porosity at depths >4 000 m attains 6.34%. Based on the critical depth of other basins and the relationship between the maturity and burial depth of coal rock in the coal bearing strata， the top critical burial depth for coal rock gas accumulation in this area is determined to be at least 2 500 m. On this basis， an accumulation model of coal rock gas reservoir was established， and further， in low to medium-rank coal areas， the evaluation process and method of favorable coal rock gas zones was put forward. Applied the above methods， the coal rock gas favorable zones in the area were comprehensively evaluated. On the one hand， this study provides various indicator parameters for the evaluation of coal quality in this area， and the critical burial depth， reservoir formation mode， and favorable zones provide critical guidance for the selection of target areas for coal rock gas exploration in the next step； on the other hand， the proposed comprehensive evaluation method for favorable coal rock gas zones provides technical reference for coal rock gas exploration in other basins.

Reservoir solid bitumen has been found in many petroliferous basins in the world， and it contains important information such as hydrocarbon generation， expulsion time from source rocks， and timing of paleoreservoir oil cracking. In recent years， Re-Os isotope dating is widely used in the study of solid bitumen. However， the interpretation of Re-Os isotopic ages is often ambiguous， and their geochemical significance remains unclear. This study combines isotope geochemistry and organic petrology to analyze solid bitumen from three different locations in the Upper Yangtze region. The results show that the Lower Cambrian bitumen from Songtao area has a Re-Os age of 195 ± 20 Ma， and it represents the time of bitumen solidification and the upper limit of the time when the shale of Niutitang Formation of Lower Cambrian stops hydrocarbon generation. The Dengying Formation bitumen from Jinsha area has a Re-Os age of 297 ± 20 Ma， which represents the time of bitumen solidification. The Dengying Formation bitumen from the Weiyuan Gas Field has a Re-Os age of 342.8 ± 4.7 Ma， and it also represents the time of petroleum generation. In this research， the relationship between solid bitumen Re-Os data and the thermal evolution of organic matter is discussed. It is considered that solid bitumen Re-Os data may represent the time of petroleum generation， time of hydrocarbon accumulation， and the time of bitumen solidification or the time of thermochemical sulfate reduction （TSR） completion， which ultimately depends on the genesis of solid bitumen and the homogeneity of Os in the system.

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.

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.

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 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.

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.

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

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

The Daniudi Gas Field in the northern part of the Ordos Basin in China has developed numerous small-scale strike-slip faults， but for a long time， there has been a lack of systematic structural analysis， which seriously restricts the oil and gas exploration process. Based on drilling and 3D seismic data， a strike-slip fault system was established in the Daniudi Gas Field， with the NNE trending Shibantai Fault， NNW trending Tuweihe fault， NEE trending Taigemiao Fault， and NNW trending Xiaohaotu Fault as the framework. The fault-controlled reservoir formation was discussed， and the conclusion was drawn that the strike-slip faults in the Daniudi Gas Field are mainly characterized by vertical type， flower structure， and inverted structure， with combined patterns of linear and echelon in plane distribution. The main fault exhibits vertical layering characteristics， while the Xiaohaotu fault， Shibantai fault， and Xiaohaotu strike slip fault exhibit left step segmented distribution characteristics. The Daniudi Gas Field is characterized by natural gas migration mainly from west to east， with the strike-slip fault uplift section as the oil and gas accumulation area， and the unconformity surface and fault fracture zone as the migration channels. The research results deepen the understanding of strike-slip faults in the Daniudi Gas Field and provide certain theoretical guidance for the exploration and development of Ordovician carbonate reservoirs in the study area.