Under the global energy transformation driven by the “dual-carbon” strategy， the Ordos Basin—a national strategic resource enrichment zone-is transitioning toward an integrated carbon-neutral energy system. This shift is critical for ensuring national energy security and promoting green development. Based on the new development phase since the “14th Five-Year Plan”， this paper re-evaluates the basin’s resources， theories and technologies， and strategic positioning from the perspectives of “Energy Power”，“Whole-Energy Integrated System” theory， and “Energy Equivalent” concept. It comprehensively analyzes the resource foundation， technological readiness， strategic orientation， and implementation pathways for the basin’s transformation from a fossil energy production base into a world-class “carbon-neutral super energy basin.” The study concludes that the Ordos Basin possesses unique advantages， including abundant fossil and renewable energy resources， excellent CO2 source-sink matching， and well-developed infrastructure. It is recognized as a “triple-super” basin， encompassing a super fossil energy basin， a super new energy basin， and a super CCUS basin. By implementing the “Seven Major Projects”-clean production of billions of tons of coal， green production of hundreds of millions of tons of oil and gas， production of associated resources such as thousands of tons of uranium， installation of hundreds of gigawatts of wind and photovoltaic power， development of hundreds of millions of square meters of clean heating， industrialization of billions of tons of CCUS/CCS， and establishment of a national energy strategic reserve and regulation hub-the basin is expected to become a world-class demonstration project of a carbon-neutral super energy basin. This initiative will integrate secure energy supply， green and low-carbon transition， and coordinated regional development， providing a systematic pathways and a leading example and demonstration for China to accelerate the building of a new-type energy system and even for the green leap forward in the transition of resource-dependent regions worldwide.
The Dingbian， Jingbian， and Anbian areas （collectively known as the Sanbian area） are located in the overlapping area of the Paleozoic Sulige and Jingbian gas fields within the Ordos Basin. However， exploration for Mesozoic oil here remains limited. Previous research on Mesozoic source rocks in the basin primarily focused on the interior and the southwestern/northwestern parts of the lacustrine basin， leaving the source rock development in the northern margin's Sanbian area poorly understood. Through analytical techniques such as thin-section analysis， scanning electron microscopy （SEM）， and geochemical testing， combined with core and well-log data， this study systematically analyzes the development characteristics， spatiotemporal distribution， and hydrocarbon generation potential of the Chang 7 lacustrine mudstone in this region. The analysis reveals the presence of dark mud shale with a thickness ranging from 1 to 16 m. The mudstone is rich in organic-rich laminae， primarily classified as Type I and II kerogen. Total Organic Carbon （TOC） content reaches 4%-5%， and vitrinite reflectance （R O） ranges from 0.68% to 0.92%. Comprehensive evaluation indicates that these rocks are qualified as good to excellent source rocks with significant hydrocarbon generation potential. The discovery of the Chang 7 lacustrine mud shale in the Sanbian area extends the known area of effective source rocks northward by 2 800 km². Furthermore， reservoir formation analysis suggests that the Chang 6 to Chang 9 reservoirs benefit from a dual advantage： local vertical hydrocarbon supply from these source rocks and high-quality lateral hydrocarbon supply from the main lacustrine basin. The development of these source rocks in the region holds significant reference value for re-evaluating the extent and evolution of the Chang 7 lacustrine basin， reassessing the resource potential of the Yanchang Formation， and guiding future exploration and development efforts in this area.
The Triassic Yanchang Formation in the Ordos Basin， traditionally considered to exhibit a basin-wide isopachous stratigraphy， is now revealed by seismic data to display wedge-shaped thinning from the northeast to the deep lake southwest， indicating a non-isochronous framework. Integrated analysis of drilling， logging， seismic， and lithologic data shows that the Chang 7 and Chang 9 flooding surfaces serve as key isochronous markers. The depositional period of the Chang 7 basal condensed section in the southwest corresponds to the interval from the Chang 9 top to the Chang 7 base in the northeast. The widespread condensed layers in the southwest resulted from rapid lake-level rise and insufficient sediment supply， causing thin deposition or stratigraphic gaps. Three mechanisms are identified： （1） Tectonic quiescence of the Qinling Orogenic Belt. Weak initial sediment flux during tectonic transition phases led to terrigenous under compensation in the deep lake； （2） Accommodation-dominated basin dynamics. Extreme water depths created accommodation space exceeding sediment flux， compounded by hydrodynamic resistance； （3） Volcanic-induced rapid transgressions. Episodic volcanism triggered abrupt lake-level rises， disrupting synsedimentary terrestrial input. The Zircon U-Pb dating of tuffaceous layers within condensed sections reveals significant age dispersion （226-241 Ma）， confirming multistage hiatuses and diachronous deposition. These findings will enhance the basin-scale research of isochronous stratigraphy， depositional models， and source-to-reservoir configurations. This study advances lacustrine basin evolution theory and provides critical insights for hydrocarbon exploration， particularly in predicting reservoir heterogeneity and source-rock distribution in analogous continental basins.
The 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.
The Changxing Formation in the central Sichuan Basin， located in the central isolated gentle slope platform， has developed multiple rows of high-energy reef and shoal bodies. In some local areas， dolomitized reservoirs are well developed， showing great exploration potential. However， the reservoirs have strong heterogeneity and obvious characteristics of “one reef， one reservoir”， which lead to problems such as unclear delineation of the internal boundaries of the reservoirs and ambiguous seismic response characteristics. Therefore， it is necessary to further conduct fine delineation of the boundaries of the reef and shoal bodies.In response to this， this paper starts with geological and logging data， clarifies the petrological and seismic response characteristics of the reef and shoal reservoirs in the Changxing Formation， and combines the results of forward modeling to establish a seismic identification model for the reef and shoal reservoirs. Then， by using technologies such as paleogeomorphic restoration and seismic attribute analysis， a method of delineating the internal boundaries of the reef and shoal reservoirs named the “Three Determination Method” is proposed. Finally， by comprehensively applying technologies such as seismic inversion and seismic facies analysis， the vertical and horizontal distribution characteristics of the reef and shoal reservoirs are clarified.The research shows that vertically， the reef and shoal reservoirs of the Changxing Formation in the study area are developed in the upper part of the first and second members of the Changxing Formation， with a thickness ranging from 10 to 60 m. Horizontally， they are mainly developed in the platform margin and local paleogeomorphic high parts within the platform， and the characteristics of “one reef， one reservoir” are obvious. The reef and shoal bodies in the platform margin zone with good seismic response patterns and slightly larger single areas have great exploration potential.
In view of the western-central Sichuan Basin， the structural evolution， hydrocarbon source conditions， reservoir characteristics and accumulation rules of Xujiahe Formation were systematically analyzed to reveal the controlling factors of natural gas differential enrichment in the Xujiahe Formation of the Sichuan Basin and point out the favorable exploration directions for the next step. The results show that： （1）The Xujiahe Formation has experienced three tectonic movements including the Indosinian， Yanshanian and Himalayan tectonic movements， forming two groups of NW-and NE-trending fault zones， and developing three sets of source rocks in the first and second members of the Xujiahe Formation， the third member of the Xujiahe Formation， and the fifth member of the Xujiahe Formation. The large thickness of source rocks， the high abundance of organic matter， moderate thermal evolution and large gas generation intensity laid the geological foundation for the large-scale distribution of tight gas in the Xujiahe Formation. （2） The reservoir lithology of Xujiahe Formation is mainly lithic sandstone， and the reservoir space types such as intragranular dissolved pore， intergranular dissolved pore and residual intergranular pore are developed， which are fracture-pore type and pore type reservoirs. （3） The tight sandstone gas reservoir of Xujiahe Formation is mainly controlled by the coupling of source-reservoir-fault. The distribution of source rocks controls the enrichment area of tight gas and the boundary of gas reservoir. When the self-closed accumulation conditions are satisfied， the high-quality reservoir controls the degree of natural gas enrichment. The fracture can provide a channel for the vertical migration of natural gas， and its associated fractures can communicate with isolated pores to improve the seepage capacity of the reservoir to control high production. It has important guiding significance for the next exploration and deployment of natural gas in Xujiahe Formation. （4） Based on the above results， the third， fourth and fifth members of Xujiahe Formation are taken as the target intervals， and the favorable enrichment areas are optimized， which has important guiding significance for the next exploration and deployment of natural gas in Xujiahe Formation.
The Tongnanba area， which encompasses the Tongnanba Anticline and the Tongjiang Depression， is abundant in natural gas resources from the Xujiahe Formation， with proven reserves exceeding 100 billion cubic meters. Previous studies on the Tongnanba area tended to analyze it as a whole， while ignoring the differences in the characteristics of natural gas accumulation in the Tongnanba Anticline and Tongjiang Depression. The results show that the Xujiahe Formation source rocks in both the Tongnanba Anticline and Tongjiang Depression exhibit moderate-to-high organic matter abundance， belong to type Ⅱ₂-Ⅲ， and are over-mature. However， the source rocks in the depression area have a relatively greater thickness. The tight sandstone reservoirs of the Xujiahe Formation in both anticlinal and depression zones exhibit ultra-low porosity and permeability. The sandstone in the anticline area has a relatively greater thickness， and under the combined effect of faults and folds， it is more likely to form a “fault-fracture system” conducive to natural gas accumulation. The natural gas in the Xujiahe Formation of both the Tongnanba Anticline and Tongjiang Depression is a high-maturity to over-mature mixed gas derived from coal-measure source rocks of the Xujiahe Formation and the Upper Permian marine source rock. The ethane and propane carbon isotopes of natural gas in the Xujiahe Formation of the anticlinal area are relatively lighter， and commonly exhibit carbon isotopic reversal， indicating a higher proportion of marine-derived gas. In addition， systematic studies on microthermometry of fluid inclusions， tectonic burial history， thermal history and hydrocarbon generation history of source rocks indicate that there were two hydrocarbon charging episodes in the Xujiahe Formation of the Tongnanba Anticline， occurring during the Middle-Late Jurassic and Paleogene-Neogene periods， with the latter being the main charging stage. The “fault-fracture systems” formed during the Paleogene-Neogene （Himalayan period）， which are supplied by dual-source gases from the Xujiahe Formation and the Upper Permian marine source rocks， may serve as favorable exploration targets. The Xujiahe Formation in the Tongjiang Depression experienced three episodes of gas accumulation， occurring during the Late Jurassic， Late Cretaceous， and Neogene periods， wherein the Late Cretaceous was the main accumulation period. Tight reservoir “sweet spots” primarily sourced from the Xujiahe Formation source rocks， along with “fault-fracture systems” formed during the Late Cretaceous （Late Yanshanian period）， may represent more favorable exploration targets.
In recent years， 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.
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.
“Horizontal well + hydraulic fracturing” technology has become an important means for deep coalbed methane development. In view of the developed bedding in deep coal seams， the effect of bedding opening on the transportation and placement of proppant in the main hydraulic fracture and bedding remains unclear. The complex fracture with developed bedding in a deep coal seam was established. The Euler-Euler proppant transport model was used to investigate the influences of geological factors （bedding opening， number of bedding） and engineering factors （construction displacement， fracturing fluid viscosity， sand proportion and proppant particle size） on proppant transport and placement in complex fractures with developed bedding. The simulation results show that： （1） The opening of the bedding has a significant impact on the height of the stable sand dune in the hydraulic main fracture. Compared with the vertical single fracture， the maximum reduction of the characteristic length of the stable sand dune under the condition of bedding opening is 24.67%， and the maximum reduction of the characteristic area is 50.37%. （2） The influence of the number of bedding on the stable sand dune in the hydraulic main fracture is mainly manifested in the height between the lower bedding and the bottom of the hydraulic main fracture （H LB）， and there is almost no proppant distribution in the upper bedding. （3） With the increase of construction displacement， sand proportion and proppant particle size， the time taken for the stable sand dune in the hydraulic main fracture to reach H LB is shortened. While with the increase of bedding opening， number of bedding and fracturing fluid viscosity， the time taken for the sand dune height to reach HLB is lengthened. Compared with the vertical single fracture， under the condition of the bedding opening， the maximum reduction of the characteristic length of the stable sand dune in the hydraulic main fracture is 34.67%， the maximum reduction of the characteristic area is 49.06%. （4） Only in narrow bedding can proppant form as a stable sand dune near the entrance of the bedding. In other cases， proppant exists in suspension form in the bedding. The above research results can provide a theoretical basis for the comparison between conventional fracturing design and deep coal rock fracturing design.
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.
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.
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.
Lithological classification of shale reservoirs is a crucial step in oil and gas exploration and development， directly impacting the accuracy of reservoir evaluation， fracturing design， and productivity prediction. Traditional machine learning methods often suffer from insufficient accuracy and weak generalization capability in lithology identification tasks. This study focuses on the Chang 7 Member of the Yanchang Formation in the L well area of the Ordos Basin， using logging data from 3 053 sampling points across eight wells. Pearson correlation coefficient method was employed to select six significant logging parameters， including natural gamma， acoustic travel time， spontaneous potential， well diameter， deep lateral resistivity， and shallow lateral resistivity， as response features. A Bidirectional Long Short-Term Memory （BiLSTM） network model with an attention mechanism （BiLSTM-Attention） was developed to intelligently identify lithologies of the Triassic Yanchang Formation’s terrestrial shale reservoirs. Compared with traditional supervised learning models （BiLSTM， CNN， SVM， LSTM）， experimental results show that the BiLSTM-Attention model achieves the best lithological classification performance in highly heterogeneous shale reservoirs， with an accuracy of 96.9% and a loss value of 0.09. Notably， it performs excellently in identifying thin interlayers and transitional lithology zones， with its average relative error and loss values lower than those of other comparison models. This model demonstrates better stability and reliability in lithological identification. The method provides a new approach for identifying lithologies in complex shale systems and holds good potential for application in lithological identification of highly heterogeneous unconventional reservoirs.
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