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.

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

In 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.

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

The 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.

At present， all the helium used in industrial development comes from the crustal-derived helium in the helium-rich natural gas reservoir. Natural gas is the carrier of crustal-derived helium， and its generation， accumulation， and helium release are closely related to the tectonic thermal evolution of the basin. It is important to systematically evaluate the influence of tectonic thermal evolution on the helium release in a basin to clarify the enrichment of natural gas and helium. The Weihe Basin， as the first sedimentary basin with helium mining rights in China， is rich in helium gas resources. This article takes the Weihe Basin as an example to systematically simulate the tectonic and thermal evolution history of the basin. At the same time， it deeply analyzes the occurrence characteristics of hydrocarbon source rocks and helium source minerals， estimates the amount of helium resources generated and released by the main helium source minerals in the Huashan rock mass， and explores the impact of basin tectonic and thermal evolution on the enrichment of helium rich natural gas reservoirs. The aim is to provide new ideas for the establishment and improvement of a helium resource investigation and evaluation system. The results show that： （1） The crustal-derived helium gas in the Weihe Basin mainly comes from helium source minerals rich in U and Th elements such as zircon， apatite， etc.， which are relatively scattered in rocks. The temperature range （>180 ℃） where natural gas is generated in large quantities and the main helium source minerals release helium gas has a high degree of overlap. （2） After the formation of the basement， the Weihe Basin underwent Paleozoic sedimentation and was subsequently strongly uplifted and eroded. A large number of Indosinian and Yanshanian granite bodies were formed on the surface， in which helium source minerals rich in uranium and thorium elements （mainly calcite， zircon， and apatite） continuously decayed to generate helium gas and partially enclosed the helium gas in the mineral lattice. The faulting of the Cenozoic era led to rapid subsidence of the basin since approximately 40 Ma， followed by accelerated subsidence around 5 Ma， resulting in rapid warming of the strata. Natural gas was generated from Paleozoic source rocks， and helium gas generated from helium source minerals was released in a concentrated manner. The two have a spatiotemporal coupling relationship. During the migration process， natural gas continuously carries scattered helium gas into traps， thereby forming helium rich natural gas reservoirs. （3） According to the helium sealing temperature of the main helium source minerals and the characteristics of helium gas accumulation in many basins with helium rich natural gas， the helium sealing zone （<60 ℃）， partially sealing zone （60-220 ℃） and unsealing zone （>220 ℃） can be divided.

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 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.

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 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.

The Mesozoic Yanchang Formation in the Ordos Basin is characterized by multiple sets of tuff markers （K0-K9）， which serve as significant stratigraphic markers for lithostratigraphic division and correlation. In this paper， the lithology， mineral composition and microscopic characteristics of the tuff marker have been defined on the basis of core， thin section， scanning electron microscope and whole rock X-ray diffraction analysis. The thickness of tuff is identified quantitatively by logging data， basin-scale isopach maps of tuff marker bed thickness were constructed for six major intervals within the K0-K9 layers and the distribution of tuff markers in the main strata of Yanchang Formation is defined. The results indicate that the tuff markers are of the sedimentary tuff， with a rich variety of rock colors， fine sedimentary granularity， predominantly consisting of volcanic ash and dust， and are distributed in a stratified pattern with abrupt contact with the overlying and underlying rocks. The rock-forming minerals are mainly composed of quartz and clay. Microscopic observation shows that the tuff marker beds are primarily composed of basal cementation and exhibit typical tuff texture， mainly consisting of vitric fragments with low crystal fragment content. It is suggested that the formation of the tuff marker bed is influenced by both the provenance and the water depth of the lake basin， and volcanic activities during the Indosinian period continued to occur during the sedimentation period of the Yanchang Formation. The volcanic activities were most intense during the sedimentation periods of the Chang 7 and Chang 1 members， with large scale and high frequency. The research provides new approaches and evidence for regional stratigraphic correlation of the Yanchang Formation， volcanic activities， the migration and evolution of the lake basin center during the Yanchang Period. Meanwhile， they indicate the distribution range of secondary source rocks other than those in the Chang 7 Member， offering new ideas for the selection of areas for oil and gas exploration.

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 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.

Ordos Basin is the largest natural gas producing area in China. The discovery of two helium-rich natural gas fields， Dongsheng and Qingyang， shows a good helium resource prospect. Sulige Gas Field is the largest natural gas field discovered in China. In order to evaluate the helium resource prospect of the gas field， geochemical analysis of natural gas components， alkane gas， carbon isotopes of carbon dioxide， helium components and isotopes of the gas field is conducted. The geochemical characteristics of gas and helium in the Paleozoic in Sulige Gas Field have been preliminarily identified， and the main controlling factors of helium reservoir formation have been discussed. The results show that the composition of natural gas in the Upper Paleozoic is obviously different. The Upper Paleozoic natural gas has typical wet gas at mature stage and dry gas at higher than mature stage. The Lower Paleozoic natural gas is mainly dry gas with partial contribution of wet gas. The Paleozoic is dominated by thermogenic natural gas， the Upper Paleozoic is dominated by middle-late humic gas， which is coal-derived gas， mainly from Carboniferous and Permian coal measure source rocks， and the lower Paleozoic is dominated by late sapropelic dry gas and oil cracking gas. The helium content of Paleozoic natural gas is higher than that of conventional natural gas （0.03%）， which belongs to middle helium gas， and the Upper Paleozoic is higher than the Lower Paleozoic. The helium accumulation in Sulige Gas field is mainly influenced by the ancient and modern structural location， the high helium generation intensity and relatively low hydrocarbon generation intensity of helium source rocks such as U-Th rich basement granite and granite gneiss， the development of basement fault and the complex gas-water relationship， which is favorable for the helium to dissolve out of the water and enter into the natural gas 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.

Marine-terrestrial transitional shale gas is another important strategic replacement resource after the commercial development of marine shale gas. Marine-terrestrial transitional shale has the characteristics of strong heterogeneity， rapid depositional phase change， and complex lithology combination. Geological theories of marine shale gas can not be fully applied to marine-continental transitional facies， and the controlling factors of shale gas enrichment in the marine and continental transition facies are not well understood， which restricts efficient exploration and development. Taking the Shan₂ ³ sub-member shale in the Daqi area of the eastern margin of the Ordos Basin as an example， the geochemical characteristics and reservoir characteristics of shale were investigated through experiments such as microscopic analysis， gas adsorption， high-pressure mercury intrusion， breakthrough pressure， diffusion coefficient， and overburden pore permeability. This research elucidated the controlling factors of shale gas accumulation in marine-continental transitional facies. The research results indicate that the Shan₂ ³ sub-member shale in the marine-continental transitional facies exhibits high organic matter abundance， high maturity， and predominantly humic-type characteristics. The pore types are mainly dominated by inorganic mineral pores， with relatively fewer organic pores and microfractures. The conclusion suggests that the enrichment of marine-continental transitional facies shale gas is primarily controlled by a combination of organic matter abundance， pore size， lithological composition， and structural evolution. High organic matter abundance enhances the adsorption capacity of shale， providing more adsorption sites for methane gas molecules in micropores. The combination of shale-coal and shale-ash favors the in-situ enrichment of shale gas. Stable tectonics and appropriate burial depth facilitate the preservation of shale gas. Furthermore， an evolutionary model for the storage and sealing capacity of marine-continental transitional facies shale gas in the Dagang area has been established. The above findings can provide geological theoretical guidance for sweet spot prediction and rapid development of pilot test areas for marine-continental transitional facies shale gas.

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 Ordovician ultra-deep carbonate reservoirs in the Tarim Basin are rich in oil and gas resources； however， affected by multiple periods of tectonic activity and strike-slip faults， their distribution shows strong heterogeneity. In regions developing fault-controlled fractures and caves， there are uncertainties in reservoir quality evaluation methods based on physical property parameters， and methods based on geomechanical parameters show advantages. In this study， quantitative characterization of geomechanical parameters including present-day in-situ stress， natural fracture and rock elastic modulus were carried out， the carbonate fracture-cavity geological model was established， the relationship between natural fracture density， elastic modulus， horizontal minimum principal stress and horizontal stress difference was built， reservoir quality evaluation indicator was defined and calculated， and finally， reservoir quality was quantitatively evaluated. The results indicate that： （1） In the ultra-deep fault-controlled fracture-cavity carbonate reservoirs， the spatial distribution of geomechanical parameters has strong heterogeneity and is significantly affected by faults. It is segmented along the fault extension direction. The elastic modulus and natural fracture density indicate high values near the fault zone， resulting in that the present-day in-situ stresses are low values around fault zones. （2） Reservoir geomechanical parameters have a significant response to fault-controlled fracture-cavity carbonate oil and gas reservoirs. The method proposed here is effective to evaluate reservoir quality， high reservoir quality evaluation indicator is distributed around strike-slip faults and adjacent regions， e.g.， Well X3 zones. The results can provide geological reference and support for efficient exploration and profitable development of fault-controlled fracture-cavity ultra-deep carbonate reservoirs.

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.

The Ordos Basin is rich in natural gas resources， and its helium resource potential has been confirmed in the Yimeng Uplift， Weihe Basin and other regions. However， the characteristics of natural gas helium content and the main controlling factors of enrichment in other areas of the basin need to be clarified through further geological exploration and scientific research. Through the collection of natural gas samples from typical wells in the southwest of Ordos Basin， and the analysis of natural gas composition， helium isotope， major and trace elements of rocks， combined with the simulation of single well geological history， temperature and pressure evolution history， the distribution characteristics， sources and main controlling factors of helium in the Upper Paleozoic of Qingyang Gas Field in Ordos Basin were analyzed， and the helium enrichment model was established. The results show that the helium content of the Upper Paleozoic in Qingyang Gas Field is 0.068%-0.310%， and the average helium content is 0.154%， which is a medium-high helium gas reservoir. The helium distribution shows a trend of low in the north and high in the south. The helium gas in Qingyang Gas Field is a typical crust source， which mainly comes from Archean-Proterozoic basement metamorphic rock-granite series， supplemented by sedimentary helium source rock. Helium enrichment is mainly controlled by central paleo-uplift， formation temperature and formation pressure， basement fracture and tectonic movement. The central paleo-uplift makes the basement shallowly buried. The basement-type helium source rock is the main and the sedimentary-type helium source rock is supplemented to provide sufficient helium. The basement fracture provides a channel for the vertical migration of helium. Low formation pressure and high formation temperature are conducive to helium dissolution. The “seesaw” tectonic movement controls the direction of natural gas migration and accumulation， forming a multi-source helium enrichment model under the background of paleo-uplift.

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.

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.

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 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.

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.