There is a lack of systematic understanding of coal-forming environment classification and its controls on coal petrographic characteristics, a coal-forming mire classification scheme applicable to petroleum geology is proposed based on modern ecological peatland frameworks. The formation, evolutionary processes, and diagnostic criteria of coal-forming environments are systematically clarified. The results show that: (1) modern peatlands can be classified according to hydrological conditions, vegetation types, and geomorphic settings, and coal-forming mires can be divided into lowmoor, mesomoor, and highmoor peat mires based on geomorphology; (2) initiation of coal-forming environments includes three modes: subaqueous peat infilling, autochthonous peat accumulation in wetlands, and mire development in arid regions; (3) peat accumulation is jointly controlled by plant production and decomposition, hydrological disturbances, and sediment input, and the peat-to-coal thickness ratio varies with coalification; (4) diagnostic criteria for lowmoor, mesomoor, and highmoor peat mires are established using ash yield, gamma-ray log responses, and vitrinite/inertinite ratios; and (5) transgression-regression processes exert a key control on peat mire evolution, directly influencing peat thickness and continuity, while the evolution of lowmoor, mesomoor, and highmoor mires governs coal maceral assemblages and thereby affects hydrocarbon generation potential and reservoir properties of coals. The coal-forming environment classification and identification system developed in this study effectively reveals the vertical heterogeneity of coals in the Ordos Basin, providing theoretical and practical guidance for efficient exploration and development of coal rock gas.

The compound system of polyacrylamide hydrogels and surfactant solutions are used for enhanced oil recovery (EOR). The polyacrylamide hydrogels are injected into block high-permeability zones firstly, followed by a low-cost sacrificial agent, then an oil-displacing surfactant, and finally an aqueous polymer solution containing diethanolamine, to enhance oil production. The hydrogels are selected through oscillatory rheometry, while the surfactant is optimized after optical imaging analysis. The EOR performance of the compound system is evaluated through core flooding experiments and reservoir numerical simulation. Specifically, the properly cross-linked polyacrylamide hydrogel can be selected using its elastic modulus as a quantitative parameter while accounting for pore structure. The sacrificial agent is used to block active adsorption sites in the rock matrix before mobilizing more crude oil with a nonionic-anionic surfactant system. The addition of the mild organic alkali (diethanolamine) into the polymer slug reduces surfactant adsorption and improves sweep efficiency, thereby enhancing the oil-washing effect. Flooding experimental results show that the sequential injection of hydrogel and surfactant compositions prolongs the period of increasing pressure gradient during subsequent waterflooding and significantly boosts oil production, achieving a 21-percentage-point increase in oil displacement efficiency. Numerical simulation for the target reservoir in the West Siberian oil province confirms the effectiveness, projecting a maximum cumulative oil increase of 6 851 t over three years.

Based on new understandings of the whole petroleum system theory for coal measures, and utilizing data from coal-rock gas wells and other oil and gas wells in numerous pilot test areas for key parameter validation, this study conducted a national resource assessment of coal-rock gas widely developed in marine-continental transitional and continental strata in major petroliferous basins like Ordos, Sichuan and Junggar in China. The main achievements and understandings were obtained as follows. (1) A resource evaluation methodology for coal-rock gas was established, incorporating varying geological/data conditions. (2) Key parameter thresholds for deep coal-rock gas resource evaluation were defined, including the upper limits of burial depth (1 500, 2 000, 2 500 m), lower limit of reservoir thickness (1 m), and lower limits of gas content in medium-low rank and medium-high rank coals (2, 10 m³/t), depending on varying geological conditions across basins. (3) Methods for determining key parameters such as gas content, porosity, and technical recovery factor were developed using the basic data from coal-rock gas experiments/tests and logging. (4) Evaluation results indicate that the geological resources of coal-rock gas in the 14 major basins of onshore China amount to 55.11×10¹² m³. Resources at depths of 1 500-3 000, 3 000-5 000, 5 000-6 000 m account for 50.29%, 43.11%, 6.59% of the total, respectively. Resource classification shows that Class I, II, and III resources constitute 21.79%, 32.76%, 45.44%, with the estimated Class I and II recoverable resources of approximately 13.23×10¹² m³. (5) The Ordos Basin remains the most favorable province, while the Sichuan, Junggar and Tarim basins are the promising targets, for future exploration and development of coal-rock gas in the country. Other basins including Bohai Bay, Qaidam, Tuha, Songliao and Hailar are considered as prospective options. Coal-rock gas production is expected to reach 500×10⁸ m³ annually within the next 10-15 years, positioning it as a major contributor to the natural gas production growth of China and a crucial alternative resource for ensuring the national gas supply.

To clarify the main enrichment-controlling factors and accumulation mechanisms of shale gas in the Permian Dalong Formation within the Western Hubei-Eastern Chongqing complex structural zone, this study systematically reveals the enrichment patterns and accumulation model through analysis of typical drilling data, geochemical testing, scanning electron microscopy (SEM), methane isothermal adsorption experiments, numerical simulations, and research on tectonic evolution and preservation condition. The results are obtained mainly in two aspects. First, the enrichment of shale gas in the Dalong Formation is synergistically controlled by four factors, i.e. rift troughs controlling shale development, provenance controlling reservoir, temperature and pressure controlling gas occurrence, and structure controlling enrichment. The geometry and scale of rift troughs (Chengkou-Western Hubei, and Kaijiang-Liangping) determine the development of organic-rich shale (average TOC >6%, thickness of 15-50 m). Multi-source materials lead to strong heterogeneity of the reservoir, with endogenous minerals as the main component (accounting for 74.31%), and the pores are mainly organic matter pores (micropores and mesopores accounting for 93.4%). The formation temperature and pressure conditions control the occurrence state of shale gas, with adsorbed gas (>50%) dominantly in 500-2 750 m depth, while free gas (>50%) prevailing in >2 750 m depth. The uplift, erosion, and fault systems associated with the Yanshanian tectonic activity result in differential enrichment of shale gas, with three structural styles—broad gentle anticlines, residual synclines, and low gentle slopes—exhibiting relatively high shale gas enrichment. Second, the self-sealing mechanism of medium-shallow shale gas in the Western Hubei-Eastern Chongqing complex structural zone is revealed. Specifically, the Dalong Formation shale aquifer forms a lateral seal for shale gas in the downdip direction via water films and capillary forces, and it combines with the overlying Daye Formation limestone and underlying Xiayao Formation tight layers to establish a syncline/monoclinal self-sealing accumulation model. The geological insights, such as “four-factor synergistic control” and self-sealing accumulation model, provide a dynamic coupling evaluation framework for shale gas in complex structural zones, promoting the transition of shale gas exploration and evaluation from static descriptions to integrated reservoir-tectonic-fluid analysis.

This study reviews the recent progress and trends of carbon capture, utilization and storage (CCUS) technologies, with a particular focus on related policy orientations, technological status, and representative projects across North America, Europe, the Middle East, and China. The technical connotations of CCUS are elucidated, and the existing issues and challenges are identified from the perspectives of technology, economics, safety and system integration. The CO₂ capture technologies are relatively mature; the emergence of novel processes such as direct air capture (DAC) and advanced materials such as metal-organic frameworks (MOFs) offer new choices for efficient capture, but issues related to high energy consumption and operational costs remain unresolved. The CO₂ geological utilization has developed earlier, where breakthroughs rely on effective source matching, enhanced miscibility and increased swept volume. The CO₂ chemical utilization exhibits broad market potential for producing high value-added products, and the development of catalytic systems with high conversion efficiency and low cost is identified as the core challenge. For CO₂ storage, diverse geological bodies provide vast theoretical capacities on both land and offshore worldwide, but subsidy policies and carbon market regulation are required to offset the limited economic returns of storage technologies. This study highlights several frontier technologies, including low-concentration CO₂ capture, CO₂-enhanced oil recovery (EOR), CO₂-based green fuel synthesis, microbial CO₂ conversion, CO₂ mineralization and hydrogen production, and CO₂ cushion gas replacement in underground gas storage (UGS). Through cost-effective innovation, regional pipeline network development, flexible technology integration, coordinated macro-policy regulation, and cross-disciplinary collaboration, CCUS can achieve a transformative scale-up from million-ton and ten-million-ton capacities to the hundred-million-ton level, contributing to the achievement of the carbon neutrality goals of China.

Through systematic investigation of deep coal-rock gas in the Ordos Basin, NW China, this work analysed the thickness distribution of the entire Upper Paleozoic coal-rock intervals, quantified the resource potential of representative areas (a 12 000 km² rectangular block in the eastern Ordos Basin roughly centered on Yulin City), clarified the occurrence characteristics of coal-rock gas, and identified key development indicators for gas wells, thereby defining the direction for iterative optimization of key technologies. (1) The total coal-rock gas in-place of the Upper Paleozoic coal seams 1^#-10^# in the reserve evaluation region is assessed at 5.66×10¹² m³, of which coal seam 8^#, currently the main target interval, contains about 3.08×10¹² m³, accounting for roughly 54% of the total. (2) Deep coal-rock gas is characterized by a high ratio of free gas. Under the conditions of 2 000 m burial depth, 6.35% porosity, 95% free gas saturation, and 22.13 m³/t total gas content, the free gas content of the reservoir is estimated to be ca. 40% of the total gas. (3) Three productivity evaluation models (triangular, convex, concave) are developed for horizontal wells, of which the triangular model can serve as the reference model for predicting the estimated ultimate recovery (EUR) throughout the lifecycle of coal-rock gas wells. Using the triangular model with a 7 m coal thickness, 1 500 m effective lateral length and 400 m well spacing, the average single-well EUR is determined to be 4 621.28×10⁴ m³. (4) Development of the coal seam 8^# should employ horizontal wells with pressure-controlled production. Meanwhile, it can be further optimized by adopting the cost-effective strategies of the Sulige Gas Field in the Ordos Basin, China. (5) To achieve cost-effective development and increase primary recovery factor, key technologies must undergo continuous iteration and upgrading, focusing on accelerating drilling, extending effective lateral lengths, high-intensity reservoir stimulation, and well-pattern optimization.

Four types of volcanic rock samples, i.e. breccia, andesite, tuff, and dacite, selected from the Carboniferous in the Junggar Basin were characterized through experiments such as X-ray diffraction (XRD), scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR) for identifying the acid imbibition and ion diffusion behaviors during fracture acidizing in volcanic rock reservoirs. The results demonstrate that the invaded acid dissolves the minerals and alters the pore structure in the reservoir. Moreover, volcanic rocks of different lithologies exhibit substantial variations in their acidification and dissolution effects. Specifically, breccia and andesite, which contain abundant calcite and other soluble minerals, show markedly improved pore connectivity after acidizing. In addition, pronounced differences are observed between the acid-induced dissolution responses of oil-rich and water-rich pores within volcanic rocks. In water-rich pores, acid-induced dissolution is dominated by H⁺ diffusion, whereas in oil-rich pores, imbibition-driven dissolution is the primary mechanism. The hydrated hydrogen-ion network formed in water-rich pores enhances H⁺ diffusion, facilitating uniform dissolution across pore scales. As a result, the pore structure becomes more homogenized, leading to a reduction in fractal dimension. In oil-rich pores, acid imbibition driven by capillary force is the predominant mechanism, enabling small pores to be dissolved preferentially, followed by medium to large pores. Consequently, the overall extent of acid erosion remains limited, and pore heterogeneity persists at a high level. Both the acid-imbibition and ion-diffusion processes exhibit a three-stage evolution: linear-transitional-stable. In the linear stage, the acid imbibition and H⁺ diffusion distances scale proportionally with t^0.5. In the transitional stage, the H⁺ diffusion rate decreases due to pore-throat blockage induced by the hydration and precipitation of clay minerals. Concurrently, acid imbibition and mineral dissolution enhance the fluid flow capacity, partially offsetting the attenuation of capillary force, and sustaining the increase in imbibition rate. In the stable stage, both acid imbibition and ion diffusion approach equilibrium.

Outcrop coal samples from the Shizhuang South Block of the Qinshui Basin, Shanxi Province, China, were subjected to true triaxial hydraulic fracturing experiments. Combined with CT scanning and three-dimensional fracture reconstruction, the study examined fracture propagation patterns and bedding activation behaviors under variable pumping-rate fracturing in coal reservoirs. Results indicate that the variable pumping-rate fracturing technique effectively overcomes the strong arresting effect of coal bedding. Hydraulic fractures are initiated at multiple weak points along bedding planes, leading to multi-point fracture initiation and competitive propagation of fractures toward the far field, thereby generating a more three-dimensional and complex fracture network. The geometry and aperture of the induced fracture network are primarily controlled by the ramp-up rate of injection flowrate. A gradual ramp-up favors the development of a more complex fracture network, though at the expense of lower breakdown pressure, insufficient initiation, and narrower apertures. In contrast, a rapid ramp-up produces wider fractures and larger propped lengths, but results in more pronounced aperture fluctuations. For coal reservoirs with relatively high rock strength, a moderately higher ramp-up rate is recommended to avoid excessively narrow fractures and potential proppant bridging. Furthermore, different coal lithotypes necessitate tailored ramp-up strategies to optimize fracture morphology and stimulation effectiveness.

Focusing on the chronological issues related to the matching relationship between the strike-slip fault activity and the stages of hydrocarbon generation, reservoir formation, and hydrocarbon accumulation, this study aims to quantitatively constrain the tectonic-burial history, reservoir porosity evolution history, and hydrocarbon accumulation history by determining the isotopic ages and temperatures of multiphase calcites (particularly the calcites which contain hydrocarbon-bearing fluid inclusions) and quartzs filling the fractures in the Ordovician strata within the platform-basin area of Tarim Basin. Three major findings have been obtained. (1) According to the tectonic-burial history restored under the constraint of the isotopic ages and temperatures, the platform-basin area of the Tarim Basin experienced a continuous burial process during the Cambrian-Ordovician period, with only a minor uplift at the end of the Silurian. Overall, the area was characterized by continuous hydrocarbon generation and a gradual increase in vitrinite reflectance (R_o). (2) While mechanical compaction and pressure-solution during burial progressively reduced the matrix porosity, the strike-slip fault activity during the Middle Caledonian II and III episodes induced physical fragmentation, which created extensive interbreccia pores, fault cavities, and structural fractures as seepage pathways for surface runoff, and, in conjunction with interlayer karstification, led to the development of widespread dissolution vugs. This represents the main phase for the formation of fracture-vug system in the Ordovician limestone, providing effective storage space for hydrocarbons generated during the Late Caledonian and subsequent periods. (3) The Ordovician fault-karst limestone reservoirs underwent four stages of hydrocarbon accumulation: low-medium maturity liquid hydrocarbons during the Middle-Late Caledonian, medium-high maturity liquid hydrocarbons during the Middle-Late Hercynian, high maturity liquid hydrocarbons during the Indosinian, and high-over maturity gas during the Middle Yanshanian. Variations in hydrocarbon accumulation among different strike-slip faults or different segments of the same fault are controlled by differences in source rock maturity across structural units, as well as by the timing of fault activity and fault-related connectivity to hydrocarbon sources. This research also establishes a geochronological framework for investigating strike-slip fault-controlled reservoir formation and hydrocarbon accumulation, facilitating a more accurate determination of the reservoir formation and hydrocarbon accumulation phases, and providing critical insights for evaluating hydrocarbon enrichment zones in fault-controlled reservoirs.

Under the guidance of the whole petroleum system theory, using seismic, drilling and laboratory analysis data, and combined with the practical achievements of oil and gas exploration, the distribution patterns of different types of natural gas in the deep-water area of the Qiongdongnan Basin of China were systematically reviewed, the orderly symbiosis mechanisms and hydrocarbon accumulation processes of diverse gas reservoirs were analyzed, and a composite whole petroleum system model for the deep-water and strongly active basins in the northern South China Sea was constructed. In the deep-water area of the Qiongdongnan Basin, there are three sets of source rocks, namely the Eocene, the Oligocene, and the Upper Miocene-Quaternary, and three whole petroleum systems can be accordingly classified. The source rocks have the characteristics of multilayers, multiple types, and multiple hydrocarbon generation centers. The Eocene lacustrine source rocks, Oligocene marine and continental source rocks, and Pliocene-Quaternary marine source rocks form multiple hydrocarbon generation centers, which are orderly distributed from east to west. The reservoirs are characterized by multiple geological ages, multiple rock types, and multiple hydrodynamic influences, and exist as a reservoir composite superposition pattern with basement buried hill-lower traction flow-upper gravity flow vertically in the deep-water area. Fluid activities within the basins are controlled by free dynamic fields, confined dynamic fields, and bound dynamic fields. The coupling of source rocks, reservoirs and dynamic fields in the whole petroleum system causes natural gas to present an orderly distribution of shale gas (speculated)-tight gas-conventional gas-ultra-shallow gas-hydrate from bottom to top. The research results have verified the adaptability of the whole petroleum system theory in the deep-water area of the Qiongdongnan Basin, providing a theoretical support for the exploration of complex oil and gas resources in the deep-water area, and are expected to effectively guide the distribution prediction and exploration of different types of petroleum resources in deep-water areas.

A temperature-sensitive mud cake remover (G315) was developed using ethyl lactate as the primary component. Based on this, a temperature-sensitive acidic completion fluid (CF-G315) was formulated. Core evaluation tests, mud cake dissolution tests and corrosion tests were conducted to analyze the mud cake removal performance of G315, and the removal efficiency of CF-G315, its ability to modify the near-wellbore reservoirs, corrosion to casing and hydrolysis performance. Results indicate that ethyl lactate in G315 exhibits weak acidity at room temperature and decomposes into lactic acid under high temperatures. The lactic acid reacts with the calcium carbonate in the mud cake, generating bubbles that dislodge the cake and form soluble salts that are subsequently removed by fluid flow, thereby ensuring effective mud cake clearance. CF-G315 removes mud cake efficiently and enhances near-wellbore reservoir permeability. It demonstrates low corrosivity and environmental compatibility, contributing to equipment safety, simplified operational procedures, and reduced operational risks. CF-G315 is promising for application in scenarios such as horizontal wells, open-hole completions, and gravel pack completions.

Based on the data of reservoir rock cores and 3D seismic inversion for reservoir, a comprehensive analysis was conducted using in-situ U-Pb dating of calcite cements, fluid inclusions, and geochemical data of fractured-vuggy reservoirs to investigate the controls on the formation of reservoirs along the ultra-deep strike-slip fault zone in the depression, northern Tarim Basin, and establish the reservoir development model. The results show that the Middle Ordovician Yijianfang Formation contains tight matrix reservoirs and strike-slip faults with small displacement but relatively wide damage zone, forming a series of fault-fracture and fault-karst reservoirs which distribute contiguously along the fault zone. Strike-slip faulting occurred during the deposition of the Yijianfang Formation, giving rise to penecontemporaneous atmospheric freshwater dissolved pores/vugs. The U-Pb ages of 440-468 Ma obtained from calcite cements in the fractures/vugs indicate that the reservoirs along the strike-slip fault zone were formed in middle to late Ordovician. Data of reservoir fluid inclusions, trace elements, and C/O/Sr isotopes suggest that the fracture/vug cementation and filling took place in a penecontemporaneous to shallow burial environment dominated by atmospheric freshwater. On the basis of intra-platform shoal deposits, strike-slip faulting coupled with dissolution is identified as the primary control on reservoir formation and spatial distribution, and a penecontemporaneous-shallow burial strike-slip fault-controlled reservoir development model is thus proposed. Comprehensive analysis indicates that large-scale fault-fracture and fault-karst reservoirs can develop along ultra-deep strike-slip fault zone in intracratonic depression, with their scales and distribution scope controlled by the coupling of microfacies, fracturing, and dissolution processes in the penecontemporaneous-shallow burial environment.

Based on the survey of saline lacustrine shales in the Permian Lucaogou Formation and Fengcheng Formation in the Junggar Basin, it is found that the sweet intervals of these shale oil strata are enriched with lithium—an underexplored resource with significant potential. The sedimentary environment, depositional process, and geochemical characteristics of these intervals were analyzed, indicating that lithium enrichment in saline lacustrine shale is controlled by multiple factors during deposition and diagenesis. The salinity of lake water during sedimentation plays a key role in lithium accumulation, while clastic input reduces its concentration, and diagenesis further affects its distribution. To assess the potential for lithium co-production in shale oil development, future research should focus on the distribution of lithium and hydrocarbons in lacustrine shales and the economic feasibility of an “oil-lithium integrated sweet spot”. Furthermore, efficient lithium extraction and environmental protection technologies need to be explored to optimize resource development. Saline lacustrine shale oil development not only ensures stable oil and gas supplies but also, if lithium co-production is realized, could enhance China’s lithium security, contributing significantly to the country’s energy transformation.

Based on the self-developed high-stress solid-fluid-thermal coupling permeability experimental system and the in-situ rock THMC-CT coupling testing system, multi-scale research approaches were employed to investigate the permeability evolution of deep continental shale under coupled high-temperature and high-stress conditions, the quantitative characterization and dynamic evolution of pore-fracture structures under in-situ high-temperature environments, and the evolutionary mechanisms governing the macro-micro responses of shale permeability, thermal oil generation, and pore-fracture structures. The results show that: (1) The permeability evolution of continental shale under thermo-pressure coupling exhibits distinct three-stage characteristics: the low permeability stage (25-350 ℃), the rapid permeability increase stage (350-450 ℃), and the permeability decline stage (450-600 ℃). (2) Under in-situ constant stress and elevated temperature conditions, the fractures in continental shale undergo two expansion phases (25-300 ℃, 350-450 ℃) and two closure phases (300-350 ℃, 450-550 ℃), following a dynamic evolution pattern. The three-stage permeability evolution under thermo- pressure coupling in continental shale was validated. The main response mechanisms are as follows: (1) At 350 ℃, the permeability decreases due to the filling of pores and fractures by heavy, immobile liquid hydrocarbons retained within the rock. (2) In the temperature range of 350 ℃ to 450 ℃, thermal fracturing and the pyrolysis of organic matter significantly increase the number, aperture, and connectivity of pores and fractures at different scales, leading to a substantial enhancement in permeability. (3) At temperatures above 450 ℃, illitization of clay minerals causes the collapse of the rock framework. As a result, the rock deformation transitions from brittle to plastic behavior, leading to a marked decrease in permeability. The research findings provide important theoretical foundations and engineering technological parameters for commercial development of underground in-situ shale oil conversion.

Using the latest global datasets of hydrocarbon fields and reservoirs, this study systematically investigates the characteristics of differential hydrocarbon enrichment and its primary controlling factors in the southern Tethys realm within the context of Tethys tectonic evolution. The results indicate that although the southern Tethys realm comprises only one-third of the Tethys realm in areal extent, it hosts nearly 80% of its total hydrocarbon reserves, exhibiting a markedly uneven distribution pattern. Specifically, the Middle East sub-segment is identified as the core enrichment area, with the Arabian Basin serving as a typical example. Through tectonic subdivision, classification of sedimentary basins, analysis of source rock distribution and reservoir-seal assemblages, as well as an integrated investigation of the relationship between succeeding paleo-uplifts and hydrocarbon richness, the study demonstrates that the superimposition patterns of prototype basins, the scale and distribution of source rocks, the compatibility of reservoir-seal assemblages, and the basement paleo-uplifts are the key factors governing hydrocarbon enrichment in the southern Tethys realm. The findings of this study provide valuable references for deeper understanding of hydrocarbon accumulation patterns in the central and northern Tethys realms and even other global regions with similar geological settings, and offer a scientific basis for selection of favorable play fairways in the southern Tethys realm.

Low-salinity fracturing fluids tend to induce ion migration, alter wettability, and cause fluctuations in gas desorption efficiency when penetrating deep coal seams. Taking the No. 8 coal from the Daning-Jixian block in the Ordos Basin as a representative example, this study employs physical simulation experiments to reveal the coupled control mechanism of salinity gradient on the ion-coal matrix-gas/water interfacial system and its key role in the imbibition-desorption process. The results show that increasing ionic concentration enhances the hydrophobicity of coal, with multivalent ions exhibiting particularly significant effects. The imbibition and ion diffusion occur in opposite directions, with imbibition equilibrium being achieved earlier than ionic equilibrium. Water-coal interactions induce both mineral dissolution and secondary precipitation. When a low-salinity fracturing fluid is injected into a high-salinity reservoir, the osmotic-pressure difference drives imbibition, promotes CH₄ desorption, but results in higher fluid loss. Conversely, injecting high-salinity fracturing fluid into a low-salinity reservoir creates a reverse osmotic gradient that suppresses leak-off while improving flowback efficiency. Based on these findings, a high-low salinity sequential injection strategy is proposed for deep coal seams: high-salinity fluid is first injected to form stable fracture networks, followed by low-salinity fluid to enlarge the imbibition zone and enhance CH₄ desorption and diffusion. In addition, moderate well soaking is recommended to increase the imbibition volume, thereby achieving multiple positive effects such as maintaining reservoir pressure, preserving formation energy, and promoting imbibition-driven displacement.

The well deployment under the guidance of the ramp model in the Ordovician Yingshan Formation in the Gucheng area of the Tarim Basin focuses on the inner ramp in the western part of the study area, which results in a low drilling success rate and an exploration predicament. To address these issues, this study focused on reconstructing sedimentary models and the adjustment strategies for oil and gas exploration. The carbonate sedimentary model of the Yingshan Formation was re-evaluated using the data of seismic interpretation, core observations, thin-section analyses, carbon isotope composition, well logging, detrital zircon U-Pb dating, and carbonate mineral U-Pb dating. Then, the favorable sedimentary facies belts were delineated, and updated prospective exploration targets were proposed. The results demonstrate that the sedimentary model of the Yingshan Formation in the Gucheng area is characterized as a rimmed platform system, exhibiting an orderly west-to-east sedimentary sequence transition from restricted/open platform environments through the platform margin and slope settings, ultimately grading into basinal deposits. The platform margin, distinguished by thick successions of grain shoals overlain by interlayered karst zones. It is the most favorable distribution area for large-scale reservoirs. Guided by this revised sedimentary model, Well Gutan-1 was successful drilled within the outer platform margin, encountering over 90% high-energy grain shoal facies with well-developed porous and fractured-vuggy reservoirs. Through oil testing, it has successfully obtained industrial oil and gas flow. It is confirmed that the platform margin is the priority area for oil and gas exploration in the Ordovician System of the Gucheng area, thereby effectively ending the prolonged exploration stagnation in the Yingshan Formation of the Gucheng area.

Taking the shale of the second member of the Paleogene Funing Formation (Ef₂) in the Qintong Sag, Subei Basin, as an example, this study integrates in-situ observation methods such as rock sectioning, optical/electron microscopy, and laser confocal microscopy, assisted by Wood's alloy injection and other techniques, to systematically investigate lamina types and combinations, pore-fracture units and fracture systems, hydrocarbon occurrence, and shale oil enrichment patterns. The following results are obtained. (1) Three basic lamina types, i.e. felsic, clay-rich, and carbonate, are identified in the study area. Their combinations are controlled by the interplay of climate, hydrodynamics, and tectonics, with vertical distribution influenced by lake-level fluctuations and event sedimentation. (2) Reservoir space is controlled by lithological composition, predominantly comprising intergranular pores and fractures within felsic laminae and intercrystalline pores and fractures within clay-rich laminae, which together with dissolution pores and organic-matter pores form a matrix pore-fracture system. This system, combined with bedding fractures, structural fractures, and overpressure fractures, constitutes a hierarchical and three-dimensional transport network. (3) The “felsic + clay-rich + organic-rich” lamina combination exhibits an optimal pore-fracture configuration, serving as the preferred shale oil reservoir unit, continuously distributed in sub-members I-II. (4) A “hierarchical migration-dynamic sealing” in-source enrichment model is established. Specifically, hydrocarbon generation in clay-rich laminae creates overpressure, driving migration through nanoscale pore-fracture networks and forming localized accumulations; subsequent fracture formation from overpressure breaches lamina interfaces, allowing hydrocarbons to migrate under capillary pressure into micrometer-scale porous domains in felsic laminae; structural fractures connect multiple laminae to form a 3D seepage system, while cementation bands associated with micro-faults and lamina interfaces provide dynamic sealing. Ultimately, shale oil accumulates in source via the coupling of pores, fractures, and laminae.

The faults and associated fracture zones in the tight sandstone reservoirs of the fifth member of the Triassic Xujiahe Formation (Xu-5 Member) in the Wubaochang area, northeastern Sichuan Basin, play a critical role in controlling gas well productivity. To delineate the distribution patterns of faults and associated fracture zones in this area, a transfer-trained convolutional neural network (CNN) model and an XGBoost-based intelligent seismic attribute fusion method were employed to identify faults and fracture zones, respectively, enabling precise characterization of their spatial distribution. The faults in the Wubaochang area are classified into first- to fourth-order structures, with the average fracture zone width on the hanging wall exceeding that of the footwall, demonstrating a strong positive correlation between fracture zone width and fault displacement. The study area is subdivided into three distinct deformation regions (southern, central, and northern regions) featuring five fault structural styles (imbricate thrust, imbricate-backthrust, duplex, composite syncline imbricate-backthrust, and composite anticline imbricate-backthrust) and four corresponding fracture zone development patterns (imbricate thrust, imbricate-backthrust, composite syncline imbricate-backthrust, and composite anticline imbricate-backthrust). Based on the controlling effects of faults on gas enrichment, the dual-source hydrocarbon-generating zones are interpreted to be predominantly distributed in the northern and central regions, while the southwestern and southeastern sectors are identified as fault-induced gas-escape zones. By integrating the distribution of favorable reservoir development areas and fracture zones, two classes of gas enrichment zones (ClassⅠand Ⅱ) are delineated. ClassⅠzones are primarily distributed in the northern region and the transitional zone from the southern to central regions, whereas Class Ⅱ zones are concentrated in the central region. ClassⅠzones exhibit dual-source hydrocarbon-generation conditions, larger-scale fracture zone development, and higher favorability compared to Class Ⅱ zones. Analysis of local stress fields and drilling fluid loss data indicates that within ClassⅠzones, fault-controlled fold-related fracture zones demonstrate higher effectiveness, whereas fault-controlled fracture zones dominate in Class Ⅱ zones. A high-productivity gas well model for the Wubaochang area is proposed, emphasizing “dual-source faults controlling enrichment, effective fracture zones controlling high production, and high matrix porosity ensuring sustained production”. Targeted drilling directions for different favorable zones are further optimized based on this model.

The traditional binary hydrocarbon-generation patterns are inadequate for accurately evaluating the hydrocarbon-generation potential of different types of source rocks in the Permian Pusige Formation in the piedmont southwestern Tarim Basin, especially the resource potential of light oil and condensate. In this study, we selected the Pusige Formation source rocks from the piedmont southwestern Tarim Basin to conduct closed gold tube pyrolysis experiments, recovered the hydrocarbon-generation process under geological conditions using the method of hydrocarbon-generation kinetics, and established multi-component hydrocarbon-generation patterns of source rocks with three quality levels. The results show that the total hydrocarbon yields of good (TOC = 1.35%), fair (TOC = 0.70%), and poor (TOC = 0.24%) source rocks are 648 mg/gTOC, 236 mg/gTOC, and 108 mg/gTOC, respectively. The good source rock shows more concentrate oil-generation process, while fair source rock has stronger dry gas potential in high-maturity stage. Furthermore, based on the characteristics of hydrocarbon generation, the Pusige Formation source rocks can be divided into immature, and heavy hydrocarbon, light hydrocarbon, wet gas, and dry gas generation stages. The proposed multi-component hydrocarbon-generation patterns are used to evaluate the hydrocarbon-generation potential and resources of different reservoirs. The resources of heavy oil, light oil, wet gas, and dry gas generated by the Pusige Formation source rocks in the study area are estimated to be 225×10⁸ t, 150×10⁸ t, 3×10¹² m³, and 6×10¹² m³, respectively. Our results indicate that the Pusige Formation source rocks in the piedmont southwestern Tarim Basin exhibit great hydrocarbon-generation potential, providing the material foundation for forming large oil and gas fields. This area rich in light resources is promising for future petroleum exploration, and it is expected to become a national resource strategic base in China.

Based on the investigation of sedimentary filling characteristics and pool-forming factors of the Mesozoic in the Ordos Basin, the whole petroleum system in the Mesozoic is divided, the migration & accumulation characteristics and main controlling factors of conventional-unconventional hydrocarbons are analyzed, and the whole petroleum system model is established. First, the Mesozoic develops whole petroleum system specialized by continuous and orderly accumulations, with more unconventional resources than conventional resources, in which high-quality source rocks of Chang 7 member serve as the core and low-permeability unconventional oil reservoirs are dominant. It can be divided into four hydrocarbon accumulation domains, including intra-source retained hydrocarbon accumulation domain, near-source tight hydrocarbon accumulation domain, far-source conventional hydrocarbon accumulation domain, and transitional hydrocarbon accumulation domain. Second, the sedimentary filling core is the oil-rich core of the whole petroleum system. From the core to the periphery, the reservoir type evolves as shale oil → tight oil → conventional oil, the accumulation power is dominated by overpressure drive → buoyancy or overpressure and capillary force, the reservoir scale changes from extensive billions of tons to a dispersed hundreds thousands-million tons, and the gas-oil ratio and methane content decrease. Third, the sedimentary structure provides the material basis and spatial framework for the whole petroleum system, the superimposed sand body, fault and unconformity control the dominant migration pathway of hydrocarbons in the far-source conventional hydrocarbon accumulation domain and the transitional hydrocarbon accumulation domain, the quality of source rocks and the micro-nano pore throat-fracture network play the key roles in the intra-source accumulation of shale oil, and the hydrocarbon migration and accumulation process is mainly controlled by intense expulsion of hydrocarbon under overpressure in the pool-forming stage and the in-situ re-enrichment under negative pressure in post-pool-forming stage. The long-term preservation of the system depends on the coordination among three factors (stable geological structure, multi-cycle sedimentary textures, and dual self-sealing). Fourth, the whole petroleum system model is defined as four domains, overpressure + negative pressure drive, and dual self-sealing.

To reveal the complex crude oil-CO₂ interaction mechanism and oil mobilization behavior during CO₂ huff-n-puff in shale-type shale oil reservoirs, CO₂ huff-n-puff experiments with on-line nuclear magnetic resonance monitoring were conducted on Gulong shale cores, combined with the prediction model of CO₂ dynamic diffusion coefficient, the flow mechanism and factors influencing oil mobilization during CO₂ huff and puff in Gulong shale oil reservoir is studied, and the diffusion and mass transfer behavior of CO₂ is investigated in shale. The results show that at the injection stage, CO₂ invades into macropores near the injection end, and drives part of the crude oil to small pores in the deep part of the core. At the shut-in stage, the crude oil gradually reflows to macropores near the injection end and is redistributed in the core. At the production stage, the oil mobilization zone is gradually expanded from the production end (injection end) to the deep part of the core. The contribution ratio of produced oil from large and small pores is about 8:3 after production. The diffusion coefficient of CO₂ in shale porous media gradually decreases with the advance of diffusion front at shut-in stage. The better the porosity and permeability of core samples, the higher the CO₂ concentration at diffusion front, the greater the CO₂ diffusion coefficient, and the slower the diffusion decline rate is. Increasing the huff and puff cycles could effectively enhance oil displacement efficiency, though its impact on the crude oil mobilization zone remains insignificant. The crude oil in small pores of the small layer with undeveloped laminae is difficult to be produced during CO₂ huff and puff, and the oil recovery is only 12.72 %. The crude oil in macro- and small pores of the small layer with developed laminae can be effectively mobilized during CO₂ huff and puff, and the oil recovery can reach 39.11%.

Particle image velocimetry technology was employed to investigate the planar three-dimensional velocity field and the mechanisms of proppant entry into branch fractures in a 90° intersecting fracture configuration of “vertical main fracture-vertical branch fracture”. This study analyzed the effects of pumping rate, fracturing fluid viscosity, proppant particle size, and fracture width on the transport behavior of proppant into branch fractures. Based on the deflection behavior of proppant, the main fractures can be divided into five regions: pre-entry transition, pre-entry stabilization, deflection entry at the fracture mouth, rear absorption entry, and movement away from the fracture mouth. Proppant primarily deflects into the branch fracture at the fracture mouth, with a small portion drawn in from the rear of the intersection. Increasing the pumping rate, reducing the proppant particle size, and widening the branch fracture are conducive to promoting proppant deflection into the branch. With increasing fracturing fluid viscosity, the ability of proppant to enter the branch fracture first improves and then declines, indicating that excessively high viscosity is unfavorable for proppant entry into the branch. During field operations, a high pumping rate and micro- to small-sized proppant can be used in the early stage to ensure effective placement in the branch fractures, followed by medium- to large-sized proppant to ensure adequate placement in the main fracture and enhance the overall conductivity of the fracture network.

Based on the Low Frequency Distributed Acoustic Sensing (LF-DAS) fiber optic monitoring and downhole hawk-eye imaging results, the fluid and proppant distribution and perforation erosion of all clusters during hydraulic fracturing were evaluated, and then a fully coupled wellbore-perforation-fracture numerical model was established to simulate the whole process of slurry migration and analyze key influencing factors. The results show that the proppant and fracturing fluid exhibit divergent flow pathways during multi-staged, multi-cluster fracturing in horizontal wells, resulting in significant heterogeneity in the fluid-proppant distribution among clusters. Perforation erosion is prevalent, and perforation erosion and proppant distribution have phase bias. Notably, the trajectory of proppant transport is controlled by the combined effects of inertia of particle migration and gravity settlement. The inertial effect is dominant at the wellbore heel, where the fluid flow rate is high, hindering particles turning into perforations and causing uneven proppant distribution among clusters. On the other hand, gravity settlement is more pronounced toward the wellbore toe, where the fluid flow rate is low, leading to enhanced phase-bias of slurry distribution and perforation distribution/erosion. Increasing the pumping rate reduces the influence of gravity settlement, mitigating the phase bias of proppant distribution and perforation erosion. However, the large pumping rate limits the proppant distribution efficiency near the heel clusters, and more proppants accumulate towards the toe clusters. High-viscosity fluids improve particle suspension, achieving more uniform proppant distribution within wellbore and fractures. Larger particle sizes exacerbate proppant distribution differences among clusters and perforations, limiting the proppant placement range within fractures.

In the ultra-deep strata of the Tarim Basin, the vertical growth process of strike-slip faults remains unclear, and the vertical distribution of fractured-cavity carbonate reservoirs is complex. This paper investigates the vertical growth process of strike-slip faults through field outcrop observations in the Keping area, interpretation of seismic data from the Fuman oilfield, and physical simulation experiments. The result are obtained mainly in four aspects. First, field outcrops and ultra-deep seismic profiles indicate a three-layer structure within the strike-slip fault, consisting of fault core, fracture zone, and primary rock. The fault core can be classified into three parts vertically: fracture-cavity unit, fault clay, and breccia zone. The distribution of fracture-cavity units demonstrates a distinct pattern of vertical stratification, owing to the structural characteristics and growth process of the slip-strike fault. Second, the ultra-deep seismic profiles show multiple fracture-vuy units in the strike-slip fault zone. These units can be classified into four types: top fractured, middle connected, deep terminated, and intra-layer fractured. Third, physical simulation experiments and ultra-deep seismic data interpretation reveal that the strike-slip faults have evolved vertically in three stages: segmental rupture, vertical growth, and connection and extension. The particle image velocimetry (PIV) detection demonstrates that the initial fracture of the fault zone occurred at the top or bottom and then evolved into cavities gradually along with the fault growth, accompanied by the emergence of new fractures in the middle part of the strata, which subsequently connected with the deep and shallow cavities to form a complete fault zone. Fourth, the ultra-deep carbonate strata primarily develop three types of fractured-cavity reservoirs: large and deep fault, flower-shaped fracture, and staggered overlap. The first two types are larger in size with better reservoir conditions, suggesting a significant exploration potential.

Lacustrine shale oil in China exhibits a huge resource potential but a highly heterogeneous distribution. Deciphering its intra-source micro-migration and enrichment mechanisms is crucial for accurately predicting geological sweet spots. Taking the Chang7₃ submember of the Yanchang Formation in the Ordos Basin as an example, we integrated high-resolution scanning electron microscopy (SEM), optical microscopy, laser Raman spectroscopy, rock pyrolysis, and organic solvent extraction experiments to identify solid bitumen of varying origins, obtain direct evidence of intra-source micro-migration of shale oil, and establish the coupling between the shale nano/micro-fabric and the oil generation, micro-migration and accumulation. The results show that the Chang7₃ shale with rich alginite in laminae has the highest hydrocarbon generation potential but a low thermal transformation ratio. Frequent alternations of micron-scale argillaceous-felsic laminae enhance expulsion efficiency, yielding consistent aromaticity between in-situ and migrated solid bitumen. Argillaceous laminae rich in terrestrial organic matter (OM) and clay minerals exhibit lower hydrocarbon generation threshold but stronger hydrocarbon retention capacity, with a certain amount of light oil/bitumen preserved to differentiate the chemical structure of in-situ versus migrated bitumen. Tuffaceous and sandy laminae contain abundant felsic minerals and migrated solid bitumen. Tuffaceous laminae develop high-angle microfractures under shale overpressure, facilitating oil charging into rigid mineral intergranular pores of sandy laminae. Fractionation during micro-migration progressively decreases the aromaticity of solid bitumen from shale, through tuffaceous and argillaceous, to sandy laminae, while increasing light hydrocarbon components and enhancing OM-hosted pore development. The intra-source micro-migration and enrichment of the Chang7₃ shale oil result from synergistic organic-inorganic diagenesis, with compositional fractionation being a key mechanism for forming laminated sweet spots.

Based on the coalbed methane (CBM)/coal-rock gas (CRG) geological, geophysical, and experimental testing data from the Daji block in the Ordos Basin, the coal-forming and hydrocarbon generation & accumulation characteristics across different zones were dissected, and the key factors controlling the differential CBM/CRG enrichment were identified. The No. 8 coal seam of the Carboniferous Benxi Formation in the Daji block is 8-10 m thick, typically overlain by limestone. The primary hydrocarbon generation phase occurred during the Early Cretaceous. Based on the differences in tectonic evolution and CRG occurrence, and with the maximum vitrinite reflectance of 2.0% and burial depth of 1 800 m as boundaries, the study area is divided into deeply buried and deeply preserved, deeply buried and shallowly preserved, and shallowly buried and shallowly preserved zones. The deeply buried and deeply preserved zone contains gas content of 22-35 m³/t, adsorbed gas saturation of 95%-100%, and formation water with total dissolved solid (TDS) ˃50 000 mg/L. This zone features structural stability and strong sealing capacity, with high gas production rates. The deeply buried and shallowly preserved zone contains gas content of 16-20 m³/t, adsorbed gas saturation of 80%-95%, and formation water with TDS of 5 000-50 000 mg/L. This zone exhibits localized structural modification and hydrodynamic sealing, with moderate gas production rate. The shallowly buried and shallowly preserved zone contains gas content of 8-16 m³/t, adsorbed gas saturation of 50%-70%, and formation water with TDS <5 000 mg/L. This zone experienced intense uplift, resulting in poor sealing and secondary alteration of the primary gas reservoir, with partial adsorbed gas loss, and low gas production rate. Based on these findings, a depositional unification and structural divergence model is proposed, that is, although coal seams across the basin experienced broadly similar depositional and tectonic histories, differences in tectonic intensity have led to spatial heterogeneity in the maximum burial depth (i.e., thermal maturity of coal) and current structural configuration (i.e., gas content and occurrence state). The research results provide valuable guidance for advancing the theoretical understanding of CBM/CRG enrichment and for improving exploration and development practices.

The Mid-Permian geomorphic transition in the Sichuan Basin is critical for understanding the development of large-scale reservoir facies belts in the Maokou Formation. This study reconstructed the paleo-uplift and depression differentiation patterns within the sequence stratigraphic framework of the Maokou Formation and investigated its tectono-sedimentary mechanisms based on analysis of outcrops, loggings and seismic data. The results show that the Maokou Formation comprises two third-order sequences (SQ1 and SQ2), six fourth-order sequences (SSQ1-SSQ6), and four distinct slope-break zones developing progressively from north to south. Slope-break zones I-III in the northern basin, controlled by synsedimentary normal faults, exhibited a NE-trending linear distribution and gradual southeastward migration. In contrast, slope-break zone IV in the southern basin displayed an arcuate distribution along the Emeishan Large Igneous Province (ELIP). The evolutions of these multistage slop-break zones governed the Middle Permian paleogeomorphic transformations from a giant, north-dipping gentle slope (higher in the southwest than in the northeast) in the early-stage (SSQ1-SSQ2) to a platform (south)-basin (north) pattern in the middle-stage (SSQ3-SSQ5), culminating a further depression zone in the southwestern basin to construct a paleo-uplift sandwiched by two depressions during the late-stage (SSQ6). The developments of paleogeomorphy reflected the combined control by the rapid subduction of the Paleo-Tethyan Mianlue Ocean and the episodic eruptions of the Emeishan mantle plume (or hot spots), which jointly facilitated the formation of extensive high-energy shoal facies belts along slope-break zones and around paleo-volcanic uplifts.

Based on previously published data from natural gas samples across spring water systems and sedimentary basins (e.g. Songliao, Bohai Bay, Sanshui, Sichuan, Ordos, Tarim, and Yingqiong), this paper systematically compares the geochemical and isotopic characteristics of abiogenic versus biogenic gases. Emphasis is placed on the diagnostic signatures of abiogenic alkane gases in terms of gas composition, and carbon, hydrogen and helium isotopes. The main findings are as follows. (1) In hydrothermal spring systems, abiogenic alkane gases are extremely scarce. Methane concentrations are typically less than 1%, with almost no detectable C₂₊ hydrocarbons. The gas is dominantly composed of CO₂, while N₂ is the major component in a few samples. (2) Abiogenic alkane gases display distinct isotopic signatures, including enriched methane carbon isotopes (δ¹³C₁>-25‰ generally), complete carbon isotopic reversal (δ¹³C₁>δ¹³C₂>δ¹³C₃>δ¹³C₄), and enriched helium isotope (R/R_a>0.5, CH₄/³He<10¹⁰ generally). (3) The hydrogen isotopic composition of abiogenic alkane gases may be characterized by a positive sequence (δD₁<δD₂<δD₃), or a complete reversal (δD₁>δD₂>δD₃), or a V-shaped distribution (δD₁>δD₂<δD₃). The hydrogen isotopic compositions of methane generally show limited variation (about 9‰), possibly due to isotopic exchange with formation water. (4) In identifying gas origin, CH₄/³He-R/R_a and δ¹³C_CO2-R/R_a charts are more effective than CO₂/³He-R/R_a chart. These new geological insights provide theoretical clues and diagnostic charts for genetic identification of natural gas and further research on abiogenic gases.

Currently, unconventional reservoirs are characterized by low single well-controlled reserves, high initial production, and fast production decline. This paper sorts out the problems of energy dispersion and limited length and height of main hydraulic fractures induced in staged multi-cluster fracturing, and proposes an innovative concept of “energy-focused fracturing (EFF)”. The technical connotation, theoretical model, and core techniques of EFF are systematically examined, and the implementation path of this technology is determined. The EFF technology incorporates the techniques such as geology-engineering integrated design, perforation optimization design, fracturing process design, and drainage engineering control. It transforms the numerous, short and dense artificial fractures to limited, long and sparse fractures. It focuses on fracturing energy, and aims to improve the fracture length, height and lateral width, and the proppant long-distance transportation capacity, thus enhancing the single well-controlled reserves and development effect. The EFF technology has been successfully applied in the carbonate reservoirs in the Yangshuiwu buried hill, shallow coalbed methane reservoirs, and coal-rock gas reservoirs in China, demonstrating the technology’s promising application. It is concluded that the EFF technology can significantly increase the single well production and estimated ultimate recovery (EUR), and will be helpful for efficiently developing low-permeability, unconventional and low-grade resources in China.

Guided by the fundamental principles of the whole petroleum system, the controls of tectonism, sedimentation, and diagenesis on hydrocarbon accumulation in a fault basin is studied using the data of petroleum geology and exploration of the second member of the Paleogene Kongdian Formation (Kong-2 Member) in the Cangdong Sag, Bohai Bay Basin, China. It is clarified that the circle structure and circle effects are the marked features of a continental fault petroleum basin, and they govern the orderly distribution of conventional and unconventional hydrocarbons in the whole petroleum systems of the fault basin. Tectonic circle zones control sedimentary circle zones, while sedimentary circle zones and diagenetic circle zones control the spatial distribution of favorable reservoirs, thereby determining the hydrocarbon accumulation orderly distribution of reservoir types in various circles. A model for the integrated, systematic aggregation of conventional and unconventional hydrocarbons under a multi-circle structure of the whole petroleum system of continental fault basin has been developed. It reveals that each sub-basin of the fault basin is an independent whole petroleum system and circle system, which encompasses multiple orderly circles of conventional and unconventional hydrocarbons controlled by the same source kitchen. From the outer circle to the middle circle and then to the inner circle, there is an orderly transition from structural and stratigraphic reservoirs, to lithological and structural-lithological reservoirs, and finally to tight oil/gas and shale oil/gas enrichment zones. The significant feature of the whole petroleum system is the orderly control of hydrocarbons by multi-circle stratigraphic coupling, with the integrated, orderly distribution of conventional and unconventional reserves being the inevitable result of the multi-layered interaction within the whole petroleum system. This concept of multi-circle stratigraphic coupling for the orderly, integrated accumulation of conventional and unconventional hydrocarbons has guided significant breakthroughs in the overall, three-dimensional exploration and shale oil exploration in the Cangdong Sag.

Accurate identification of natural gas origin is fundamental to exploration deployment and resource potential assessment. Since the 1970s, Academician Dai Jinxing has developed a comprehensive system for natural gas origin determination, grounded in geochemical theory and practice, and based on the integrated analysis of stable isotopes, molecular composition, light hydrocarbon fingerprints, and geological context. This paper systematically reviews the core framework established by him and his team, focusing on the conceptual design and technical pathways of key diagnostic diagrams such as δ¹³C₁-C₁/(C₂+C₃), δ¹³C₁-δ¹³C₂-δ¹³C₃, δ¹³C-CO₂ versus CO₂ content, and the C₇ light hydrocarbon triangular plot. We evaluate the applicability and innovation of these tools in distinguishing between oil-type gas, coal-derived gas, biogenic gas, and abiogenic gas, as well as in identifying mixed-source gases and multiphase charging systems. The findings suggest that this diagnostic system has significantly advanced natural gas geochemical interpretation in China, shifting from single-indicator analyses to multi-parameter integration and from qualitative assessments to systematic graphical identification, and has also exerted considerable influence on international research in natural gas geochemistry. This review aims to provide a structured overview of the development trajectory of natural gas origin discrimination methodologies and offer a scientific foundation for the academic evaluation and practical application of related achievements.

Taking the Wangfu Rift in the Songliao Basin as an example, on the basis of seismic interpretation and drilling data analysis, the distribution of the basement faults was clarified, the fault activity periods of the coal-bearing formations were determined, and the fault systems were divided. Combined with the coal seam thickness and actual gas indication in logging, the controls of fault systems in the rift basin on the spatial distribution of coal and the occurrence of coal-rock gas were identified. The results show that the Wangfu Rift is an asymmetrical graben formed under the control of basement reactivated strike-slip T-rupture, and contains coal-bearing formations and five sub-types of fault systems under three types. The horizontal extension strength, vertical activity strength and tectono-sedimentary filling difference of basement faults control vertical stratigraphic sequences, accumulation intensity, and accumulation frequency of coal seam in rift basin. The structural transfer zone formed during the segmented reactivation and growth of the basement faults control the injection location of steep slope exogenous clasts. The filling effect induced by igneous intrusion accelerates the sediment filling process in the rift lacustrine area. The structural transfer zone and igneous intrusion together determine the preferential accumulation location of coal seams in the plane. The faults reactivated at the basement and newly formed during the rifting phase serve as pathways connecting to the gas source, affecting the enrichment degree of coal-rock gas. The vertical sealing of the faults was evaluated by using shale smear factor (SSF), and the evaluation criteria was established. It is indicated that the SSF is below 1.1 in major coal areas, indicating favorable preservation conditions for coal-rock gas. Based on the influence factors such as fault activity, segmentation and sealing, the coal-rock gas accumulation model of rift basin was established.

In the late 1970s, the theory of coal-formed gas began to take root, sprout, develop, and improve in China. After decades of development, a complete theoretical system was finally formed. The theory of coal-formed gas points out that coal measures are good gas source rocks, with gas as the main hydrocarbon generated and oil as the auxiliary. It has opened up a new exploration idea using coal-bearing humic organic matter as the gas source, transforming the theoretical guidance for natural gas exploration in China from “monism” (i.e. oil-type gas) to “dualism” (i.e. coal-formed gas and oil-type gas) and uncovering a new field of natural gas exploration. Before the establishment of the coal-formed gas theory, China was a gas-poor country with low proven reserves (merely 2 264.33×10⁸ m³) and production (137.3×10⁸ m³/a), corresponding to a per capita annual consumption of only 14.37 m³. Guided by the theory of coal-formed gas, China’s natural gas industry has developed rapidly. By the end of 2023, China registered a cumulative proven gas geological reserves of 20.90×10¹² m³, an annual gas production of 2 343×10⁸ m³, and a per capita domestic gas consumption reaching 167.36 m³. The cumulative proven geological reserves and production of natural gas were dominated by coal-formed gas. Owing to this advancement, China has transformed from a gas-poor country to the fourth largest gas producer in the world. The coal-formed gas theory and the tremendous achievements made in natural gas exploration in China under its guidance have been highly praised by renowned scholars globally.

Based on the comprehensive analysis of data from petrology, well logging, seismic surveys, paleontology, and geochemistry, a detailed research was conducted on the tectonic-sedimentary setting, and paleoenvironmental and paleoclimatic conditions of the source rocks in the second member of the Eocene Wenchang Formation (Wen 2 Member) in the Shunde North Sag at the southwestern margin of the Pearl River Mouth Basin. The Wen 2 Member hosts excellent, thick lacustrine oil shales with strong longitudinal heterogeneity and an average total organic carbon (TOC) content of over 4.9%. The Wen 2 Member can be divided into three units (I, II, III) from bottom to top. Unit I features excellent source rocks with Type I organic matters (average TOC of 5.9%) primarily sourced from lake organic organisms; Unit II hosts source rocks dominated by Type II₂ organic matters (average TOC of 2.2%), which are originated from mixed sources dominated by terrestrial input. Unit III contains good to excellent source rocks dominated by Type II₁ organic matters (average TOC of 4.9%), which are mainly contributed by lake organisms and partially by terrestrial input. Under the background of rapid subsidence and limited source supply during strong fault depression, excellent source rocks were developed in Wen 2 Member in the Shunde North Sag under the coordinated control of warm and humid climate, volcanic activity, and deep-water reducing conditions. During the deposition of Unit I, the warm and humid climate and volcanic activity promoted the proliferation of lake algaes, primarily Granodiscus, resulting in high initial productivity, and deep-water reducing conditions enabled satisfactory preservation. These factors jointly controlled the development and occurrence of excellent source rocks. During the deposition of Unit II, a transition from warm to cool and semi-arid paleoclimatic conditions led to a decrease in lake algaes and initial productivity. Additionally, enhanced terrestrial input and shallow-water, weakly oxidizing water conditions caused a significant dilution and decomposition of organic matters, degrading the quality of source rocks. During the deposition of Unit III, when the paleoclimatic conditions are cool and humid, Pediastrum and Botryococcus began to thrive, leading to an increase in productivity. Meanwhile, the reducing environment of semi-deep water facilitated the preservation of excellent source rocks, albeit slightly inferior to those in Unit I. The study results clarify the differential origins and development models of various source rocks in the Shunde Sag, offering valuable guidance for evaluating source rocks and selecting petroleum exploration targets in similar marginal sags.

Based on the basic data of drilling, logging, testing and geological experiments, the geological characteristics of the Permian Dalong Formation marine shales in the Sichuan Basin and the factors controlling shale gas enrichment and high yield in these shales are studied. The results are obtained in four aspects. First, the high-quality shale of the Dalong Formation was formed after the deposition of the Wujiaping Formation, and it is mainly developed in the Kaijiang-Liangping trough in the northern part of Sichuan Basin, where deep-water continental shelf facies and deep-water reduction environment where siliceous organisms flourished have formed the black siliceous shale rich in organic matter. Second, the Dalong Formation shale contains both organic and inorganic pores, with stratification of alternating brittle and plastic minerals, which was stacked with severe compaction to enlarge the fractures, thereby improving the permeability. In addition to organic pores, a large number of inorganic pores are developed even in the ultra-deep (˃4 500 m) layers, contributing a total porosity of more than 5% and a permeability of 0.2×10^-3 μm², which significantly expands the accommodation space for shale gas. Third, the limestone at the roof and floor of the Dalong Formation acted as a seal in the early burial and hydrocarbon generation stage, providing favorable conditions for the continuous hydrocarbon generation and rich gas preservation in shale interval. In the later reservoir stimulation process, it was beneficial to the lateral extension of the fractures, so as to achieve the optimal stimulation performance and increase the well-controlled resources. Combining the geological, engineering and economic conditions, the favorable area with depth <5 500 m is determined to be 1 800 km², with resources of 5 400×10⁸ m³. Fourth, the shale reservoirs of the Dalong Formation are thin but rich in shale gas. The syncline zone far away from the main faults in the high and steep tectonic zone, eastern Sichuan Basin, with depth <5 500 m, is the most favorable target for producing the Permian shale gas under the current engineering and technical conditions. It mainly includes the Nanya syncline, Tanmuchang syncline, and Liangping syncline.

The Carter model is used to characterize the dynamic behaviors of fracture growth and fracturing fluid leakoff. A thermo-fluid coupling forward model is built considering the fluid flow and heat transfer in wellbore, fracture and reservoir. The influences of fracturing parameters and fracture parameters on the responses of distributed temperature sensing (DTS) are analyzed, and a diagnosis method of fracture parameters is presented based on the simulated annealing algorithm. A field case study is introduced to verify the model’s reliability. The results show that typical V-shaped characteristics can be observed from DTS responses in the multi-cluster fracturing process, with locations corresponding to the created hydraulic fractures. The V-shape depth is shallower for a higher injection rate and longer fracturing and shut-in time. Also, the V-shape is wider for a higher fracture-surface leakoff coefficient, longer fracturing time, and smaller fracture width. Additionally, the cooling effect near the wellbore continues to spread into the reservoir during the shut-in period, causing the DTS temperature to decrease instead of rise. Real-time monitoring and interpretation of DTS temperature data can help understand the fracture propagation during fracturing operation, so that immediate measures can be taken to improve the fracturing performance.

In order to identify the development characteristics of fracture network in tight conglomerate reservoir of Mahu after hydraulic fracturing, a hydraulic fracturing test site was set up in the second and third members of Triassic Baikouquan Formation (T₁b₂ and T₁b₃) in Ma-131 well area, which learned from the successful experience of hydraulic fracturing test sites in North America (HFTS-1). Twelve horizontal wells and a high-angle cored well MaJ02 were drilled. The occurrence, connection, propagation law and major controlling factors of hydraulic fractures were analyzed by comparing results of CT scans, imaging logs, direct observation of cores from Well MaJ02, and the tracer monitoring data. Results indicate that: (1) Two types of fractures have developed by hydraulic fracturing, i.e. tensile fractures and shear fractures. Tensile fractures are approximately parallel to the direction of the maximum horizontal principal stress, and propagate less than 50 m from the perforation cluster. Shear fractures are distributed among tensile fractures and mainly in the strike-slip mode due to the induced stress field among tensile fractures, and some of them are in conjugated pairs. Overall, tensile fractures alternate with shear fractures, with shear fractures dominated and activated after tensile ones. (2) Tracer monitoring results showed an obvious difference in fracturing and fluid production among different fracturing stages in horizontal wells. Some hydraulic fractures with length exceeding the well spacing gradually close during the fluid production process due to interwell communication. (3) Density of hydraulic fractures is mainly affected by the lithology and fracturing parameters, which is smaller in the mudstone than the conglomerate. Larger fracturing scale and smaller cluster spacing lead to a higher fracture density, which are important directions to improve the well productivity.

Based on the test and experimental data from exploration well cores in the central-eastern Ordos Basin, combined with structural, depth and fluid geochemistry analyses, this study reveals the fluid characteristics, gas accumulation control factors and accumulation modes in coal reservoirs. The study indicates findings in two aspects. First, the 1 500-1 800 m interval represents the critical transition zone between shallow-medium open fluid system and deep closed fluid system. Reservoirs below 1 500 m reflect intense water invasion, with discrete pressure gradient distribution, and the presence of methane mixed with varying degrees of secondary biogenic gas, and they generally exhibit high water saturation and adsorbed gas undersaturation. Reservoirs deeper than 1 800 m, with extremely low permeability, are self-sealed, and contains closed fluid systems formed jointly by the hydrodynamic lateral blocking and tight caprock confinement. Within these systems, surface runoff infiltration is weak, the degree of secondary fluid transformation is minimal, and the pressure gradient is relatively uniform. The adsorbed gas saturation exceeds 100% in most seams, and the free gas content primarily ranges from 1 to 8 m³/t (˃10 m³/t in some seams). Second, the gas enrichment in deep coals is primarily controlled by coal quality, reservoir-caprock assemblage, and structural position governed storage, wettability and sealing properties, under the constraints of the underground temperature and pressure conditions. High-rank, low-ash yield coals with limestone and mudstone caprocks show superior gas accumulation potential. Positive structural highs and negative structural lows are favorable sites for gas enrichment, while slope belts of fold limbs exhibit relatively lower gas content. This research enhances understanding of gas accumulation mechanisms in coal reservoirs and provides effective guidance for precise zone evaluation and innovation of adaptive stimulation technologies for deep resources.

Static adsorption and dynamic damage experiments were carried out on typical No.8 deep coal rock in the Ordos Basin to evaluate the adsorption capacity of hydroxypropyl guar gum and polyacrylamide as fracturing fluid thickeners on deep coal rock surface and the permeability damage caused by adsorption. The adsorption morphology of the thickener was quantitatively characterized by atomic force microscopy, and the main controlling factors of the thickener adsorption were analyzed. Meanwhile, the adsorption mechanism of the thickener was revealed by Zeta potential, Fourier infrared spectroscopy and X-ray photoelectron spectroscopy. The results show that the adsorption capacity of hydroxypropyl guar gum on deep coal surface is 3.86 mg/g, and the permeability of coal rock after adsorption decreases by 35.24%-37.01%. The adsorption capacity of polyacrylamide is 3.29 mg/g, and the permeability of coal rock after adsorption decreases by 14.31%-21.93%. The thickness of the thickener adsorption layer is positively correlated with the mass fraction of thickener and negatively correlated with temperature, and a decrease in pH will reduce the thickness of the hydroxypropyl guar gum adsorption layer and make the distribution frequency of the thickness of the polyacrylamide adsorption layer more concentrated. Functional group condensation and intermolecular force are the chemical and physical forces for adsorbing fracturing fluid thickener in deep coal rock. Optimization of thickener mass fraction, chemical modification of thickener molecular, oxidative thermal degradation of polymer and addition of desorption agent can reduce the potential damages on micro-nano pores and cracks in coal rock.