By summarizing the characteristics of the global energy structure and China’s energy resource endowment, this study analyzes the historical context and opportunities for China to build an “energy powerhouse”, and proposes pathways and measures for its realization. It is indicated that the energy resource endowment in China is characterized by abundant coal, limited oil and gas, and vast renewable potential, coupled with an energy consumption structure characterized by high coal consumption, low oil and gas consumption, and rapidly growing renewable energy use. The “whole-energy system” approach that integrates multi-energy complementarity, green development, stable supply, smart utilization and carbon neutrality is an effective solution to addressing energy transition and energy independence. To build an “energy powerhouse”, China can follow the approach of the steady and orderly low-carbon development of fossil fuels, the safe and scaled development of new energy, the integrated development of a carbon-neutral “whole-energy system”, and the shared development of the “Belt and Road” energy corridor. The construction of an “energy powerhouse” should follow a “three-phase” strategic pathway: from 2025 to 2030, achieving peak primary energy consumption and “carbon peaking”; from 2031 to 2050, energy production will achieve parity with consumption for the first time, striving for “energy independence”; and from 2051 to 2060, aiming for “carbon neutrality”, and establishing an “energy powerhouse”. Building an “energy powerhouse” will fundamentally safeguard national energy security, advance the achievement of carbon neutrality goals, provide Chinese solutions for global energy transition and green Earth construction, and support the modernization and great rejuvenation of the Chinese nation.

Static adsorption and dynamic damage experiments were carried out on typical 8^# deep coal rock of the Carboniferous Benxi Formation in the Ordos Basin, NW China, 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 polyacrylamide adsorption layer more concentrated. Functional group condensation and intermolecular force are 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.

Based on the observation and analysis of cores and thin sections, and combined with cathodoluminescence, laser Raman, fluid inclusions, and in-situ LA-ICP-MS U-Pb dating, the genetic mechanism and petroleum geological significance of calcite veins in shales of the Cretaceous Qingshankou Formation in the Songliao Basin were investigated. Macroscopically, the calcite veins are bedding parallel, and show lenticular, S-shaped, cone-in-cone and pinnate structures. Microscopically, they can be divided into syntaxial blocky or columnar calcite veins and antitaxial fibrous calcite veins. The aqueous fluid inclusions in blocky calcite veins have a homogenization temperature of 132.5-145.1 °C, the in-situ U-Pb dating age of blocky calcite veins is (69.9±5.2) Ma, suggesting that the middle maturity period of source rocks and the conventional oil formation period in the Qingshankou Formation are the sedimentary period of Mingshui Formation in Late Cretaceous. The aqueous fluid inclusions in fibrous calcite veins with the homogenization temperature of 141.2-157.4 °C, yields the U-Pb age of (44.7±6.9) Ma, indicating that the middle-high maturity period of source rocks and the Gulong shale oil formation period in the Qingshankou Formation are the sedimentary period of Paleocene Yi'an Formaiton. The syntaxial blocky or columnar calcite veins were formed sensitively to the diagenetic evolution and hydrocarbon generation, mainly in three stages (fracture opening, vein-forming fluid filling, and vein growth). Tectonic extrusion activities and fluid overpressure are induction factors for the formation of fractures, and vein-forming fluid flows mainly as diffusion in a short distance. These veins generally follow a competitive growth mode. The antitaxial fibrous calcite veins were formed under the driving of the force of crystallization in a non-competitive growth environment. It is considered that the calcite veins in organic-rich shale of the Qingshankou Formation in the study area has important implications for local tectonic activities, fluid overpressure, hydrocarbon generation and expulsion, and diagenesis-hydrocarbon accumulation dating of the Songliao Basin.

Based on recent advancements in shale oil exploration within the Ordos Basin, this study presents a comprehensive investigation of the paleoenvironment, lithofacies assemblages and distribution, depositional mechanisms, and reservoir characteristics of shale oil of fine-grained sediment deposition in continental freshwater lacustrine basins, with a focus on the Chang 7₃ sub-member of Triassic Yanchang Formation. The research integrates a variety of exploration data, including field outcrops, drilling, logging, core samples, geochemical analyses, and flume simulation. The study indicates that: (1) The paleoenvironment of the Chang 7₃ deposition is characterized by a warm and humid climate, frequent monsoon events, and a large water depth of freshwater lacustrine basin. The paleogeomorphology exhibits an asymmetrical pattern, with steep slopes in the southwest and gentle slopes in the northeast, which can be subdivided into microgeomorphological units, including depressions and ridges in lakebed, as well as ancient channels. (2) The Chang 7₃ sub-member is characterized by a diverse array of fine-grained sediments, including very fine sandstone, siltstone, mudstone and tuff. These sediments are primarily distributed in thin interbedded and laminated arrangements vertically. The overall grain size of the sandstone predominantly falls below 62.5 μm, with individual layer thicknesses of 0.05-0.64 m. The deposits contain intact plant fragments and display various sedimentary structure, such as wavy bedding, inverse-to-normal grading sequence, and climbing ripple bedding, which indicating a depositional origin associated with density flows. (3) Flume simulation experiments have successfully replicated the transport processes and sedimentary characteristics associated with density flows. The initial phase is characterized by a density-velocity differential, resulting in a thicker, coarser sediment layer at the flow front, while the upper layers are thinner and finer in grain size. During the mid-phase, sliding water effects cause the fluid front to rise and facilitate rapid forward transport. This process generates multiple “new fronts”, enabling the long-distance transport of fine-grained sandstones, such as siltstone and argillaceous siltstone, into the center of the lake basin. (4) A sedimentary model primarily controlled by hyperpynal flows was established for the southwestern part of the basin, highlighting that the frequent occurrence of flood events and the steep slope topography in this area are primary controlling factors for the development of hyperpynal flows. (5) Sandstone and mudstone in the Chang 7₃ sub-member exhibit micro-and nano-scale pore-throat systems, shale oil is present in various lithologies, while the content of movable oil varies considerably, with sandstone exhibiting the highest content of movable oil. (6) The fine-grained sediment complexes formed by multiple episodes of sandstones and mudstones associated with density flow in the Chang 7₃ formation exhibit characteristics of “overall oil-bearing with differential storage capacity”. The combination of mudstone with low total organic carbon content (TOC) and siltstone is identified as the most favorable exploration target at present.

Based on the oil and gas exploration in western depression of the Qaidam Basin, NW China, combined with the geochemical, seismic, logging and drilling data, the basic geological conditions, oil and gas distribution characteristics, reservoir-forming dynamics, and hydrocarbon accumulation model of the Paleogene whole petroleum system (WPS) in the western depression of the Qaidam Basin are systematically studied. A globally unique ultra-thick mountain-style WPS is found in the western depression of the Qaidam Basin. Around the source rocks of the upper member of the Paleogene Lower Ganchaigou Formation, the structural reservoir, lithological reservoir, shale oil and shale gas are laterally distributed in an orderly manner and vertically overlapped from the edge to the central part of the lake basin. The Paleogene WPS in the western depression of the Qaidam Basin is believed unique in three aspects. First, the source rocks with low organic matter abundance are characterized by low carbon and rich hydrogen, showing a strong hydrocarbon generating capacity per unit mass of organic carbon. Second, the saline lake basinal deposits are ultra-thick, with mixed deposits dominating the center of the depression, and strong vertical and lateral heterogeneity of lithofacies and storage spaces. Third, the strong transformation induced by strike-slip compression during the Himalayan resulted in the heterogeneous enrichment of oil and gas in the mountain-style WPS. As a result of the coordinated evolution of source-reservoir-caprock assemblage and conducting system, the Paleogene WPS has the characteristics of “whole process” hydrocarbon generation of source rocks which are low-carbon and hydrogen-rich, “whole depression” ultra-thick reservoir sedimentation, “all direction” hydrocarbon adjustment by strike-slip compressional fault, and “whole succession” distribution of conventional and unconventional oil and gas. Due to the severe Himalayan tectonic movement, the western depression of the Qaidam Basin evolved from depression to uplift. Shale oil is widely distributed in the central lacustrine basin. In the sedimentary system thicker than 2 000 m, oil and gas are continuous in the laminated limy-dolomites within the source rocks and the alga limestones neighboring the source kitchen, with intercrystalline pores, lamina fractures in dolomites and fault-dissolution bodies serving as the effective storage space. All these findings are helpful to supplement and expand the WPS theory in the continental lake basins in China, and provide theoretical guidance and technical support for oil and gas exploration in the Qaidam Basin.

Based on the basic data of drilling, logging, testing and geological experiments, the geological characteristics of the Permian Dalong Formation marine shales in the northern Sichuan Basin and the factors controlling shale gas enrichment and high yield 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 Permian Wujiaping Formation, and it is developed in the Kaijiang-Liangping trough in the northern part of Sichuan Basin, where deep-water continental shelf facies and deep-water reduction environment with thriving siliceous organisms have formed the black siliceous shale rich in organic matter. Second, the Dalong Formation shale contains both organic and inorganic pores, with stratification of alternated brittle and plastic minerals. In addition to organic pores, a large number of inorganic pores are developed even in ultra-deep (deeper than 4 500 m) layers, contributing a total porosity of more than 5%, which significantly expands the storage space for shale gas. Third, the limestone at the roof and floor of the Dalong Formation acted as seal rock 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 less than 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 less than 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.

In addition to the organic matter type, abundance, thermal maturity, and shale reservoir space, the preservation conditions of source rocks play a key factor in affecting the quantity and quality of retained hydrocarbons in source rocks of lacustrine shale, yet this aspect has received little attention. This paper, based on the case analysis, explores how preservation conditions influence the enrichment of mobile hydrocarbons in shale oil. Research showns that good preservation conditions play three key roles. (1) Ensure the retention of sufficient light hydrocarbons (C₁-C₁₃), medium hydrocarbons (C₁₄-C₂₅) and small molecular aromatics (including 1-2 benzene rings) in the formation, which enhances the fluidity and flow of shale oil; (2) Maintain a high energy field (abnormally high pressure), thus facilitating the maximum outflow of shale oil; (3) Ensure that the retained hydrocarbons have the miscible flow condition of multi-component hydrocarbons (light hydrocarbons, medium hydrocarbons, heavy hydrocarbons, and heteroatomic compounds), so that the heavy hydrocarbons (∑C₂₅₊) and heavy components (non-hydrocarbons and asphaltenes) have improved fluidity and maximum flow capacity. In conclusion, in addition to the advantages of organic matter type, abundance, thermal maturity, and reservoir space, good preservation conditions of shale layers are essential for the formation of economically viable shale oil reservoirs, which should be incorporated into the evaluation criteria of shale oil-rich areas/segments and considered a necessary factor when selecting favorable exploration targets.

The gas-liquid countercurrent flow pattern is complex and the bubble migration velocity is difficult to predict in the process of bullheading well killing. The experiment on bubble migration in gas-liquid countercurrent flow in annulus is carried out under different working conditions to reveal how the wellbore inclination angle, liquid phase property and countercurrent liquid velocity affect the bubble deformation and bubble migration trajectory/velocity, and to establish a bubble migration velocity prediction model. The bubbles in the countercurrent flow mainly migrate in two modes: free rising of isolated bubbles, and interactive rising of multiple bubbles. The bubbles migrate by an S-shaped trajectory in the countercurrent flow. With the increase of countercurrent liquid velocity, the lateral oscillation of bubbles is intensified. The increases of wellbore inclination angle, liquid density and liquid viscosity make the bubble migration trajectory gradually to be linear. The bubble is generally ellipsoidal during its rising. The wellbore inclination angle has little effect on the degree of bubble deformation. The bubbles are ellipsoidal during rising, with little influence of wellbore inclination angle on bubble deformation. With the increase of liquid viscosity and density, the aspect ratio of the bubble decreases. As the wellbore inclination angle increases, the bubble migration velocity gradually decreases. As the liquid viscosity increases, the bubble migration velocity decreases. As the liquid density increases, the bubble migration velocity increases slightly. The established bubble migration velocity prediction model yields errors within ±15%, and demonstrates broad applicability across a wide range of operating conditions.

This paper introduces a deep learning workflow to predict phase distributions within complex geometries during two-phase capillary-dominated drainage. We utilize subsamples from Computerized Tomography (CT) images of rocks and incorporate pixel size, interfacial tension, contact angle, and pressure as inputs. First, an efficient morphology-based simulator creates a diverse dataset of phase distributions. Then, two commonly used convolutional and recurrent neural networks are explored and their deficiencies are highlighted, particularly in capturing phase connectivity. Subsequently, we develop a Higher-Dimensional Vision Transformer (HD-ViT) that drains pores solely based on their size, with phase connectivity enforced as a post-processing step. This enables inference for images of varying sizes, resolutions, and inlet-outlet setup. After training on a massive dataset of over 9.5 million instances, HD-ViT achieves excellent performance. We demonstrate the accuracy and speed advantage of the model on new and larger sandstone and carbonate images. We further evaluate HD-ViT against experimental fluid distribution images and the corresponding Lattice-Boltzmann simulations, producing similar outcomes in a matter of seconds. In the end, we train and validate a 3D version of the model.

Significant exploration progress has been made in ultra-deep clastic rocks in the Kuqa Depression, Tarim Basin, over recent years. A new round of comprehensive geological research has formed four new understandings: (1) Establish structural model consisting of multi-detachment composite, multi-stage structural superposition and multi-layer deformation. Multi-stage structural traps are overlapped vertically, and a series of structural traps are discovered in underlying ultra-deep layers. (2) Five sets of high-quality large-scale source rocks of three types of organic phases are developed in the Triassic and Jurassic systems, and forming a good combination of source-reservoir-cap rocks in ultra-deep layers with three sets of large-scale regional reservoir and cap rocks. (3) The formation of large oil and gas fields is controlled by four factors which are source, reservoir, cap rocks and fault. Based on the spatial configuration relationship of these four factors, a new three-dimensional reservoir formation model for ultra-deep clastic rocks in the Kuqa Depression has been established. (4) The next key exploration fields for ultra-deep clastic rocks in the Kuqa Depression include conventional and unconventional oil and gas. The conventional oil and gas fields include the deep multi-layer oil-gas accumulation zone in Kelasu, tight sandstone gas of Jurassic Ahe Formation in the northern structural zone, multi-target layer lithological oil and gas reservoirs in Zhongqiu-Dina structural zone, lithologic-stratigraphic and buried hill composite reservoirs in south slope and other favorable areas. Unconventional oil and gas fields include deep coal rock gas of Jurassic Kezilenuer and Yangxia formations, Triassic Tariqike Formation and Middle-Lower Jurassic and Upper Triassic continental shale gas. The achievements have important reference significance for enriching the theory of ultra-deep clastic rock oil and gas exploration and guiding the future oil and gas exploration deployment.

This paper investigates the macroscopic and microscopic characteristics of viscosity reduction and quality improvement of heavy oil in a supercritical water environment through laboratory experiments and testing. The effect of three reaction parameters, i.e. reaction temperature, reaction time and oil-water ratio, is analyzed on the product and their correlation with viscosity. The results show that the flow state of heavy oil is significantly improved with a viscosity reduction of 99.4% in average after the reaction in the supercritical water. Excessively high reaction temperature leads to a higher content of resins and asphaltenes, with significantly increasing production of coke. The optimal temperature ranges in 380-420 °C. Prolonged reaction time could continuously increase the yield of light oil, but it will also results in the growth of resins and asphaltenes, with the optimal reaction time of 150 min. Reducing the oil-water ratio helps improve the diffusion environment within the reaction system and reduce the content of resins and asphaltenes, but it will increase the cost of heavy oil treatment. An oil-water ratio of 1︰2 is considered as optimum to balance the quality improvement, viscosity reduction and reaction economics. The correlation of the three reaction parameters relative to the oil sample viscosity is ranked as temperature, time and oil-water ratio. Among the four fractions of heavy oil, the viscosity is dominated by asphaltene content, followed by aromatic content and less affected by resins and saturates contents.

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 coring well MaJ02 were drilled. The orientation, 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 combined with 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 perforation clusters. 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 indicate that communication between wells was prevalent in the early stage of production, and the static pressure in the fracture gradually decreased and the connectivity between wells reduced as production progressed. (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 experimental results of casting thin section, low temperature nitrogen adsorption, high pressure mercury injection, nuclear magnetic resonance T₂ spectrum, contact angle and oil-water interfacial tension, the relationship between pore throat structure and crude oil mobility characteristics of full particle sequence reservoirs in the Lower Permian Fengcheng Formation of Mahu Sag, Junggar Basin, are revealed. (1) With the decrease of reservoir particle size, the volume of pores connected by large throats and the volume of large pores show a decreasing trend, and the distribution and peak ranges of throat and pore radius shift to smaller size in an orderly manner. The upper limits of throat radius, porosity and permeability of unconventional reservoirs in Fengcheng Formation are approximately 0.7 μm, 8% and 0.1×10^?3 μm², respectively. (2) As the reservoir particle size decreases, the distribution and peak ranges of pores hosting retained oil and movable oil are shifted to a smaller size in an orderly manner. With the increase of driving pressure, the amount of retained and movable oil of the larger particle reservoir samples shows a more obvious trend of decreasing and increasing, respectively. (3) With the increase of throat radius, the driving pressure of reservoir with different particle levels presents three stages, namely rapid decrease, slow decrease and stabilization. The oil driving pressures of various reservoirs and the differences of them decrease with the increase of temperature and obviously decrease with the increase of throat radius. According to the above experimental analysis, it is concluded that the deep shale oil of Fengcheng Formation in Mahu Sag has great potential for production under geological conditions.

By comprehensively considering the influences of temperature and pressure on fluid density in high temperature and high pressure (HTHP) wells in deepwater fractured formations and the effects of formation fracture deformation on well shut-in afterflow, this study couples the shut-in temperature field model, fracture deformation model, and gas flow model to establish a wellbore pressure calculation model incorporating thermo-hydro-mechanical coupling effects. The research analyzes the governing patterns of geothermal gradient, bottomhole pressure difference, drilling fluid pit gain, and kick index on casing head pressure, and establishes a shut-in pressure determination chart for HPHT wells based on coupled model calculation results. The study results show: geothermal gradient, bottomhole pressure difference, and drilling fluid pit gain exhibit positive correlations with casing head pressure; higher kick indices accelerate pressure rising rates while maintaining a constant maximum casing pressure; validation against field case data demonstrates over 95% accuracy in predicting wellbore pressure recovery after shut-in, with the pressure determination chart achieving 97.2% accuracy in target casing head pressure prediction and 98.3% accuracy in target shut-in time. This method enables accurate acquisition of formation pressure after HPHT well shut-in, providing reliable technical support for subsequent well control measures and ensuring safe and efficient development of deepwater and deep hydrocarbon reservoirs.

Based on the tectonic genesis and seismic data of fault-controlled fractured-vuggy reservoirs, the typical fractured-vuggy structure features were analyzed. A 3D large-scale visual physical model of “tree-like” fractured-vuggy structure was designed and made. The experiments of bottom-water flooding and multi-media synergistic oil displacement after bottom-water flooding were conducted with different production rates and different well-reservoir configuration relationships. The formation mechanisms and distribution rules of residual oil during bottom-water flooding under such fractured-vuggy structure were revealed. The producing characteristics of residual oil under different production methods after bottom-water flooding were discovered. The results show that the remaining oil in "tree-like" fractured-vuggy structure after bottom-water flooding mainly include the remaining oil of non-well controlled fault zones and the attic remaining oil at the top of well controlled fault zones. There exists obvious water channeling of bottom-water along the fault at high production rate, but intermittent drainage can effectively weaken the interference effect between fault zones to inhibit water channeling. Compared with the vertical well, horizontal well can reduce the difference in flow conductivity between fault zones and show better resistance to water channeling. The closer the horizontal well locates to the upper part of the “canopy”, the higher the oil recovery is at the bottom-water flooding stage. However, comprehensive consideration of the bottom-water flooding and subsequent gas injection development, the total recovery is higher when the horizontal well locates in the middle part of the “canopy” and drills through a large number of fault zones. After bottom water flooding, the effect of gas huff and puff is better than that of gas flooding, and the effect of gas huff and puff with large slug is better than that of small slug. Because such development method can effectively develop the remaining oil of non-well controlled fault zones and the attic remaining oil at the top of well controlled fault zones transversely connected with oil wells, thus greatly improving the oil recovery.

Considering the three typical phase-change related rock mechanics phenomena during drilling and production in oil and gas reservoirs, which include phase change of solid alkane-related mixtures upon heating, sand liquefaction induced by sudden pressure release of the over-pressured sand body, and formation collapse due to gasification of pore fillings from pressure reduction, this study first systematically analyzes the progress of theoretical understanding, experimental methods, and mathematical representation, then discusses the engineering application scenarios corresponding to the three phenomena and reveals the mechanical principles and application effectiveness. Based on these research efforts, the study further discusses the significant challenges, potential developmental trends, and research approaches that require urgent exploration. The findings disclose that various phase-related rock mechanics phenomena require specific experimental and mathematical methods that can produce multi-field coupling mechanical mechanisms, which will eventually instruct the control on resource exploitation, evaluation on disaster level, and analysis of formation stability. To meet the development needs of the principle, future research efforts should focus on mining more phase-change related rock mechanics phenomena during oil and gas resources exploitation, developing novel experimental equipment, and using techniques of artificial intelligence and digital twins to implement real-time simulation and dynamic visualization of phase-change related rock mechanics.

Based on petroleum exploration and new progress of oil and gas geology study in the Qiongdongnan Basin, combined with seismic, logging, drilling, core, sidewall coring, geochemistry data, a systematic study is conducted on the source, reservoir-cap conditions, trap types, migration and accumulation characteristics, enrichment mechanisms, and reservoir formation models of ultra-deep water and ultra-shallow natural gas, taking the Lingshui 36-1 gas field as an example. (1) The genetic types of the ultra-deep water and ultra-shallow natural gas in the Qiongdongnan Basin include thermogenic gas and biogenic gas, and dominated by thermogenic gas. (2) The reservoirs are mainly composed of the Quaternary deep-water submarine fan sandstone. (3) The types of cap rocks include deep-sea mudstone, mass transport deposits mudstone, and hydrate-bearing formations. (4) The types of traps are mainly lithological, and also include structural- lithological traps. (5) The migration channels include vertical transport channels such as faults, gas chimneys, fracture zones, and lateral transport layers such as large sand bodies and unconformity surfaces, forming a single or composite transport framework. A new natural gas accumulation model is proposed for ultra-deep water and ultra-shallow layers, that is, dual source hydrocarbon supply, gas chimney and submarine fan composite migration, deep-sea mudstone-mass transport deposits mudstone-hydrate-bearing strata ternary sealing, late dynamic accumulation, and large-scale enrichment at ridges. The new understanding obtained from the research has reference and enlightening significance for the next step of deepwater and ultra-shallow layers, as well as oil and gas exploration in related fields or regions.

Based on drilling and logging data, as well as geological experiments, the geological characteristics and factors controlling high-yield and enrichment of hydrocarbons in ultra-deep clastic rocks in the Linhe Depression, Hetao Basin, are studied. The results are obtained in four aspects. First, the inland saline lacustrine high-quality source rocks developed in the Paleogene in the Linhe Depression have the characteristics of early maturity, early expulsion, high hydrocarbon yield, and continuous and efficient hydrocarbon generation, providing an important resource basis for the formation of ultra-high pressure and high-yield reservoirs. Second, the weak compaction, early charging, and weak cementation for pore-preserving, together with the ultra-high pressure for pore-preserving and fracture expansion to improve the permeability, leads to the development of high-quality reservoirs with medium porosity (greater than 15%) and medium permeability (up to 226×10^?3 μm²) in the ultra-deep strata (deeper than 6 500 m), which represents a greatly expanded space for oil and gas exploration. Third, the Linhe Formation adjacent to the trough exhibits a low net-to-gross (NTG) and good reservoir-caprock assemblage, and it is overlaid by very thick high-quality mudstone caprock, which are conducive to the continuous and efficient hydrocarbon generation and pressurization and the formation of ultra-high pressure oil and gas reservoirs. Fourth, the most favorable targets for ultra-deep exploration are the zones adjacent to the hydrocarbon generating center of the Paleogene Linhe Formation and with good tectonic setting and structural traps, mainly including the Xinglong faulted structural zone and the Nalinhu faulted buried-hill zone. The significant breakthrough of ultra-deep oil and gas exploration in the Linhe Depression reveals the good potential of ultra-deep clastic rocks in this area, and provides valuable reference for oil and gas exploration of ultra-deep clastic rocks in other areas.

This study took the Gulong Shale in the Upper Cretaceous Qingshankou Formation of the Songliao Basin, NE China, as an example. Through paleolake-level reconstruction and comprehensive analyses on types of lamina, vertical associations of lithofacies, as well as stages and controlling factors of sedimentary evolution, the cyclic changes of waters, paleoclimate, and continental clastic supply intensity in the lake basin during the deposition of the Qingshankou Formation were discussed. The impacts of lithofacies compositions/structures on oil-bearing property, the relation between reservoir performance and lithofacies compositions/structures, the differences of lithofacies in mechanical properties, and the shale oil occurrence and movability in different lithofacies were investigated. The insights of this study provide a significant guideline for evaluation of shale oil enrichment layers/zones. The non-marine shale sedimentology is expected to evolve into an interdisciplinary science on the basis of sedimentary petrology and petroleum geology, which reveals the physical, chemical and biological actions, and the distribution characteristics and evolution patterns of minerals, organic matter, pores, fluid, and phases, in the transportation, sedimentation, water-rock interaction, diagenesis and evolution processes. Such research will focus on eight aspects: lithofacies and organic matter distribution prediction under a sequence stratigraphic framework for non-marine shale strata; lithofacies paleogeography of shale strata based on the forward modeling of sedimentation; origins of non-marine shale lamina and log-based identification of lamina combinations; source of organic matter in shale and its enrichment process; non-marine shale lithofacies classification by rigid particles + plastic components + pore-fracture system; multi-field coupling organic-inorganic interaction mechanism in shale diagenesis; new methods and intelligent core technology for shale reservoir multi-scale characterization; and quantitative evaluation and intelligent analysis system of shale reservoir heterogeneity.

By reviewing the research progress and exploration practices of shale gas geology in China, analyzing and summarizing the geological characteristics, enrichment laws, and resource potential of different types of shale gas, the following understandings have been obtained: (1) Marine, transitional, and lacustrine shales in China are distributed from old to new in geological age, and the complexity of tectonic reworking and hydrocarbon generation evolution processes gradually decreases. (2) The sedimentary environment controls the type of source-reservoir configuration, which is the basis of “hydrocarbon generation and reservoir formation”. The types of source-reservoir configuration in marine and lacustrine shales are mainly source-reservoir integration, with occasional source-reservoir separation. The configuration types of transitional shale are mainly source-reservoir integration and source-reservoir symbiosis. (3) The resistance of rigid minerals to compression for pore preservation and the overpressure facilitate the enrichment of source-reservoir integrated shale gas. Good source reservoir coupling and preservation conditions are crucial for the shale gas enrichment of source-reservoir symbiosis and source-reservoir separation types. (4) Marine shale remains the main battlefield for increasing shale gas reserves and production in China, while transitional and lacustrine shales are expected to become important replacement areas. It is recommended to carry out the shale gas exploration at three levels: Accelerate the exploration of Silurian, Cambrian, and Permian marine shales in the Upper-Middle Yangtze region; make key exploration breakthroughs in ultra-deep marine shales of the Upper-Middle Yangtze region, the new Ordovician marine shale strata in the North China region, the transitional shales of the Carboniferous and Permian, as well as the Mesozoic lacustrine shale gas in basins such as Sichuan, Ordos and Songliao; explore and prepare for new shale gas exploration areas such as South China and Northwest China, providing technology and resource reserves for the sustainable development of shale gas in China.

A flexible sidetracking stimulation technology of horizontal wells is formed to develop the lateral deep remaining oil and gas resources of the low-permeability mature oilfields. This technology first uses the flexible sidetracking tool to achieve low-cost sidetracking in the old wellbore, and then uses the hydraulic jet technology to induce multiple fractures to fracture. Finally, the bullhead fracturing of multi-cluster temporary plugging for the sidetracking hole is carried out by running the tubing string, to realize the efficient development of the remaining reserves among the wells. The flexible sidetracking stimulation technology involves flexible sidetracking horizontal wells drilling and sidetracking horizontal well fracturing. The flexible sidetracking horizontal well drilling includes three aspects: flexible drill pipe structure and material optimization, drilling technology, and sealed coring tool. The sidetracking horizontal well fracturing includes two aspects: fracturing scheme optimization, fracturing tools and implementation process optimization. The technology has been conducted several rounds of field tests in the Ansai Oilfield of Changqing, China. The results show that by changing well type and reducing row spacing of oil and water wells, the pressure displacement system can be well established to achieve effective pressure transmission and to achieve the purpose of increasing liquid production in low-yield and low-efficiency wells. It is verified that the flexible sidetracking stimulation technology can provide favorable support for accurately developing remaining reserves in low-permeability reservoirs.

Using gas and rock samples from major petroliferous basins in the world, the helium content, composition, isotopic compositions and the U and Th contents in rocks are analyzed to clarify the helium enrichment mechanism and distribution pattern and the exploration ideas for helium-rich gas reservoirs. It is believed that the formation of helium-rich gas reservoirs depends on the amount of helium supplied to the reservoir and the degree of helium dilution by natural gas, and that the reservoir-forming process can be summarized as "multi-source helium supply, main-source helium enrichment, helium-nitrogen coupling, and homogeneous symbiosis". Helium mainly comes from the radioactive decay of U and Th in rocks. All rocks contain trace amounts of U and Th, so they are effective helium sources. Especially, large-scale ancient basement dominated by granite or metamorphic rocks is the main helium source. The helium generated by the decay of U and Th in the ancient basement in a long geologic history, together with the nitrogen generated by the cracking of the inorganic nitrogenous compounds in the basement rocks, is dissolved in the water and preserved. With the tectonic uplift, the ground water is transported upward along the fracture to the gas reservoirs, with helium and nitrogen released. Thus, the reservoirs are enriched with both helium and nitrogen, which present a clear concomitant and coupling relationship. In tensional basins in eastern China, where tectonic activities are strong, a certain proportion of mantle-derived helium is mixed in the natural gas. The helium-rich gas reservoirs are mostly located in normal or low-pressure zones above ancient basement with fracture communication, which later experience substantial tectonic uplift and present relatively weak seal, low intensity of natural gas charging, and active groundwater. Helium exploration should focus on gas reservoirs with fractures connecting ancient basement, large tectonic uplift, relatively weak sealing capacity, insufficient natural gas charging intensity, and rich ancient formation water, depending on the characteristics of helium enrichment, beyond the traditional idea of searching for natural gas sweetspots and high-yield giant gas fields simultaneously.

To address the challenges associated with existing separated zone oil production technologies, such as incompatibility with pump inspection operations, short effective working life, and poor communication reliability, an innovative electromagnetic coupling intelligent zonal oil production technology has been proposed. The core and accessory tools have been developed and applied in field tests. This technology employs a pipe string structure incorporation a release sub, which separates the production and allocation pipe strings. When the two strings are docked downhole, electromagnetic coupling enables close-range wireless transmission of electrical power and signals between the strings, powering multiple downhole intelligent production allocators (IPAs) and enabling two-way communication. Core tools adapted to the complex working conditions downhole were developed, including downhole electricity & signal transmission equipment based on electromagnetic coupling (EST), IPAs, and ground communication controllers (GCCs). Accessory tools, including large-diameter release sub anchor and cable-crossing packers, have also been technically finalized. Field tests conducted on ten wells in Daqing Oilfield demonstrated that the downhole docking of the two strings was convenient and reliable, and the EST worked stably. Real-time monitoring of flow rate, pressure and temperature in separate layers and regulation of zonal fluid production were also achieved. This technology has enhanced reservoir understanding and achieved practical production results of increased oil output with reduced water cut.

China has abundant resources of hot dry rocks. However, due to the fact that the evaluation methods for favorable areas are mainly qualitative, and the evaluation indicators and standards are inconsistent, which restrict the evaluation efficiency and exploration process of dry hot rocks. This paper is based on the understanding of the geologic features and genesis mechanisms of hot dry rocks in China and abroad. By integrating the main controlling factors of hot dry rock formation, and using index grading and quantification, the fuzzy hierarchical comprehensive method is applied to establish an evaluation system and standards for favorable areas of hot dry rocks. The evaluation system is based on four indicators: heat source, thermal channel, thermal reservoir and cap rock. It includes 11 evaluation parameters, including time of magmatic/volcanic activity, depth of molten mass or magma chamber, distribution of discordogenic faults, burial depth of thermal reservoir, cap rock type and thickness, surface thermal anomaly, heat flow, geothermal gradient, Moho depth, Curie depth, Earthquake magnitude and focal depth. Each parameter is divided into 3 levels. Applying this evaluation system to assess hot dry rock in central Inner Mongolia revealed that Class I favorable zones cover approximately 494 km², while Class II favorable zones span about 5.7×10⁴ km². The Jirgalangtu Sag and Honghaershute Sag in the Erlian Basin, along with Reshuitang Town in Keshiketeng Banner, Reshui Town in Ningcheng County, and Reshuitang Town in Aohan Banner of Chifeng City, are identified as Class I favorable zones for hot dry rock resources. These areas are characterized by high-temperature subsurface molten bodies or magma chambers serving as high-quality heat sources, shallow thermal reservoir depths, and overlying thick sedimentary rock layers acting as caprock. The establishment and application of the evaluation system for favorable areas of hot dry rock are expected to provide new approaches and scientific basis for guiding the practice of selecting hot dry rock areas in China.

This study comprehensively uses various methods such as production dynamic analysis, fluid inclusion thermometry and carbon-oxygen isotopic compositions testing, based on outcrop, core, well-logging, 3D seismic, geochemistry experiment and production test data, to systematically explore the control mechanisms of structure and fluid on the scale, quality, effectiveness and connectivity of ultra-deep fault-controlled carbonate fractured-vuggy reservoirs in the Tarim Basin. The results show that reservoir scale is influenced by strike-slip fault scale, structural position, and mechanical stratigraphy. Larger faults tend to correspond to larger reservoir scales. The reservoir scale of contractional overlaps is larger than that of extensional overlaps, while pure strike-slip segments are small. The reservoir scale is enhanced at fault intersection, bend, and tip segments. Vertically, the heterogeneity of reservoir development is controlled by mechanical stratigraphy, with strata of higher brittleness indices being more conducive to the development of fractured-vuggy reservoirs. Multiple phases of strike-slip fault activity and fluid alterations contribute to fractured-vuggy reservoir effectiveness evolution and heterogeneity. Meteoric water activity during the Late Caledonian to Early Hercynian period was the primary phase of fractured-vuggy reservoir formation. Hydrothermal activity in the Late Hercynian period further intensified the heterogeneity of effective reservoir space distribution. The study also reveals that fractured-vuggy reservoir connectivity is influenced by strike-slip fault structural position and present in-situ stress field. The reservoir connectivity of extensional overlaps is larger than that of pure strike-slip segments, while contractional overlaps show worse reservoir connectivity. Additionally, fractured-vuggy reservoirs controlled by strike-slip faults that are nearly parallel to the present in-situ stress direction exhibit excellent connectivity. Overall, high-quality reservoirs are distributed at the fault intersection of extensional overlaps, the central zones of contractional overlaps, pinnate fault zones at intersection, bend, and tip segments of pure strike-slip segments. Vertically, they are concentrated in mechanical stratigraphy with high brittleness indices.

Based on the comprehensive analysis of data from petrology and mineralogy, well logging, seismic surveys, paleontology, and geochemistry, a detailed research was conducted on paleoenvironmental and paleoclimatic conditions, and modeling of the source rocks in the second member of the Eocene Wenchang Formation (Wen 2 Member) in the Northern Shunde Subsag at the southwestern margin of the Pearl River Mouth Basin. The Wen 2 Member hosts excellent, thick lacustrine source rocks 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 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 intense rifting period in the Eocene, excellent source rocks were developed in Wen 2 Member in the Northern Shunde Subsag 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 of organic matters. 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.

This paper proposes a novel intelligent method for defining and solving the reservoir performance prediction problem within a manifold space, fully considering geological uncertainty and the characteristics of reservoirs performance under time-varying well control conditions, creating a surrogate model for reservoir performance prediction based on Conditional Evolutionary Generative Adversarial Networks (CE-GAN). The CE-GAN leverages conditional evolution in the feature space to direct the evolution of the generative network in previously uncontrollable directions, and transforms the problem of reservoir performance prediction into an image evolution problem based on permeability distribution, initial reservoir performance and time-varying well control, thereby enabling fast and accurate reservoir performance prediction under time-varying well control conditions. The experimental results in basic (egg model) and actual water-flooding reservoirs show that the model predictions align well with numerical simulations. In the basic reservoir model validation, the median relative residuals for pressure and oil saturation are 0.5% and 9.0%, respectively. In the actual reservoir model validation, the median relative residuals for both pressure and oil saturation are 4.0%. Regarding time efficiency, the surrogate model after training achieves approximately 160-fold and 280-fold increases in computational speed for the basic and actual reservoir models, respectively, compared with traditional numerical simulations. The reservoir performance prediction surrogate model based on the CE-GAN can effectively enhance the efficiency of production optimization.

The Bohai Bay Basin, as a super oil-rich basin in the world, is characterized by cyclic evolution and complex regional tectonic stress field, and its lifecycle tectonic evolution controls the formation of regional source rocks. The main pre-Cenozoic stratigraphic system and lithological distribution are determined through geological mapping, and the dynamics of the pre-Cenozoic geotectonic evolution of the Bohai Bay Basin are investigated systematically using the newly acquired high-quality seismic data and the latest exploration results in the study area. The North China Craton where the Bohai Bay Basin is located in rests at the intersection of three tectonic domains: the Paleo-Asian Ocean, the Tethys Ocean, and the Pacific Ocean. It has experienced the alternation and superposition of tectonic cycles of different periods, directions and natures, and experienced five stages of the tectonic evolution and sedimentary building, i.e. Middle-Late Proterozoic continental rift trough, Early Paleozoic marginal-craton depression carbonate building, Late Paleozoic marine-continental transitional intracraton depression, Mesozoic intracontinental strike-slip-extensional tectonics, and Cenozoic intracontinental rifting. The cyclic evolution of the basin, especially the multi-stage compression, strike-slip and extensional tectonics processes in the Hercynian, Indosinian, Yanshan and Himalayan since the Late Paleozoic, controlled the development, reconstruction and preservation of several sets of high-quality source rocks, represented by the Late Paleozoic Carboniferous-Permian coal-measure source rocks and the Paleogene world-class extra-high-quality lacustrine source rocks, which provided an important guarantee for the hydrocarbon accumulation in the super oil-rich basin.

Coal measures are significant hydrocarbon source rocks and reservoirs in petroliferous basins. Many large gas fields and coalbed methane fields globally are originated from coal-measure source rocks or accumulated in coal rocks. Inspired by the discovery of shale oil and gas, and guided by “the overall exploration concept of considering coal rock as reservoir”, breakthroughs in the exploration and development of coal-rock gas have been achieved in deep coal seams with favorable preservation conditions, thereby opening up a new development frontier for the unconventional gas in coal-rock reservoirs. Based on the data from exploration and development practices, a systematic study on the accumulation mechanism of coal-rock gas has been conducted. The mechanisms of “three fields” controlling coal-rock gas accumulation are revealed. It is confirmed that the coal-rock gas is different from CBM in accumulation process. The whole petroleum systems in the Carboniferous-Permian transitional facies coal measures of the eastern margin of the Ordos Basin and in the Jurassic continental facies coal measures of the Junggar Basin are characterized, and the key research directions for further developing the whole petroleum system theory of coal measures are proposed. Coal rocks, compared to shale, possess intense hydrocarbon generation potential, strong adsorption capacity, dual-medium reservoir properties, and partial or weak oil and gas self-sealing capacity. Additionally, unlike other unconventional gas such as shale gas and tight gas, coal-rock gas exhibits more complex accumulation characteristics, and its accumulation requires a certain coal-rock play form lithological and structural traps. Coal-rock gas also has the characteristics of conventional fractured gas reservoirs. Compared with the basic theory and model of the whole petroleum system established based on detrital rock formations, coal measures have distinct characteristics and differences in coal-rock reservoirs and source-reservoir coupling. The whole petroleum system of coal measures is composed of various types of coal-measure hydrocarbon plays with coal (and dark shale) in coal measures as source rock and reservoir, and with adjacent tight layers as reservoirs or cap or transport layers. Under the action of source-reservoir coupling, coal-rock gas is accumulated in coal-rock reservoirs with good preservation conditions, tight oil/gas is accumulated in tight layers, conventional oil/gas is accumulated in traps far away from sources, and coalbed methane is accumulated in coal-rock reservoirs damaged by later geological processes. The proposed whole petroleum system of coal measures represents a novel type of whole petroleum system.

Natural gas hydrate (NGH), as a widely recognized clean energy, has shown a significant resource potential. However, due to the lack of a unified evaluation methodology and the difficult determination of key parameters, the evaluation results of global NGH resource are greatly different. This paper establishes a quantitative relationship between NGH resource potential and conventional oil and gas resource and a NGH resource evaluation model based on the whole petroleum system (WPS) and through the analysis of dynamic field controlling hydrocarbon accumulation. The global NGH initially in-place and recoverable resources are inverted through the Monte Carlo simulation, and verified by using the volume analogy method based on drilling results and the trend analysis method of previous evaluation results. The proposed evaluation model considers two genetic mechanisms of natural gas (biological degradation and thermal degradation), surface volume conversion factor difference between conventional natural gas and NGH, and the impacts of differences in favorable distribution area and thickness and in other aspects on the results of NGH resource evaluation. The study shows that the global NGH initially in-place and recoverable resources are 99×10¹² m³ and 30×10¹² m³, with averages of 214×10¹² m³ and 68×10¹² m³, respectively, less than 5% of the total conventional oil and gas resources, and they can be used as a supplement for the future energy of the world. The proposed NGH resource evaluation model creates a new option of evaluation method and technology, and generates reliable data of NGH resource according to the reliability comprehensive analysis and test, providing a parameter basis for subsequent NGH exploration and development.

To reveal the enrichment conditions and resource potential of coal-rock gas in the Ordos Basin, this paper presents a systematic research on the sedimentary environment, distribution, physical properties, reservoir characteristics, gas-bearing characteristics and gas accumulation play of deep coals. The results show that thick coals are widely distributed in the Carboniferous-Permian of the Ordos Basin. The main coal seams Carboniferous 5^# and Permian 8^# in the Carboniferous-Permian have strong hydrocarbon generation capacity and high thermal evolution degree, which provide abundant materials for the formation of coal-rock gas. Deep coal reservoirs have good physical properties, especially porosity and permeability. Coal seams Carboniferous 5^# and Permian 8^# exhibit the average porosity of 4.1% and 6.4%, and the average permeability of 8.7×10^-3 μm² and 15.7×10^-3 μm², respectively. Cleats and fissures are developed in the coals, and together with the micropores, constitute the main storage space. With the increase of evolution degree, the micropore volume tends to increase. The development degree of cleats and fissures has a great impact on permeability. The coal reservoirs and their industrial compositions exhibit significantly heterogeneous distribution in the vertical direction. The bright coal seam, which is in the middle and upper section, less affected by ash filling compared with the lower section, and contains well-developed pores and fissures, is a high-quality reservoir interval. The deep coals present good gas-bearing characteristics in Ordos Basin, with the gas content of 7.5-20.0 m³/t, and the proportion of free gas (greater than 10%, mostly 11.0%-55.1%) in coal-rock gas significantly higher than that in shallow coals. The enrichment degree of free gas in deep coals is controlled by the number of macropores and microfractures. The coal rock pressure testing shows that the coal-limestone and coal-mudstone combinations for gas accumulation have good sealing capacity, and the mudstone/limestone (roof)-coal-mudstone (floor) combination generally indicates high coal-rock gas values. The coal-rock gas resources in the Ordos Basin were preliminarily estimated by the volume method to be 22.38×10¹² m³, and the main coal-rock gas prospects in the Ordos Basin were defined. In the central-east of the Ordos Basin, Wushenqi, Hengshan-Suide, Yan'an, Zichang, and Yichuan are coal-rock gas prospects for the coal seam #8 of the Benxi Formation, and Linxian West, Mizhi, Yichuan-Huangling, Yulin, and Wushenqi-Hengshan are coal-rock gas prospects for the coal seam #5 of the Shanxi Formation, which are expected to become new areas for increased gas reserves and production.

Based on the oil and gas exploration in the Sichuan Basin, combined with data such as seismic, logging and geochemistry, the basic geological conditions, hydrocarbon types, hydrocarbon distribution characteristics, source- reservoir relationship and accumulation model of the Upper Triassic-Jurassic continental whole petroleum system in the basin are systematically analyzed. The continental whole petroleum system in the Sichuan Basin develops multiple sets of gas-bearing strata, forming a whole petroleum system centered on the Triassic Xujiahe Formation source rocks. The thick and high-quality source rocks in the Upper Triassic Xujiahe Formation provide sufficient gas source basis for the continental whole petroleum system in the basin. The development of conventional-unconventional reservoirs provides favorable space for hydrocarbon accumulation. The coupling of faults and sandbodies provides a high-quality transport system for gas migration. Source rocks and reservoirs are overlapped vertically, and there are obvious differences in sedimentary environment, reservoir lithology and physical properties, which lead to the orderly development of inner-source shale gas, near-source tight gas, and far-source tight-conventional gas in the Upper Triassic-Jurassic, from bottom to top. The orderly change of geological conditions such as burial depth, reservoir physical properties, formation pressure and hydrocarbon generation intensity in zones controlled the formation of the whole petroleum system consisting of structural gas reservoir in thrust zone, shale gas-tight gas reservoir in depression zone, tight gas reservoir in slope zone, and tight gas-conventional gas reservoir in uplift zone on the plane. Based on the theory and concept of the whole petroleum system, the continental shale gas and tight gas resources in the Sichuan Basin have great potential, especially in the central and western parts with abundant unconventional resources.

By systematically reviewing the development status of global carbon dioxide capture, utilization and storage (CCUS) cluster, and comparing domestic and international CCUS industrial models and successful experiences, this study explores the challenges and strategies for the scaled development of the CCUS industry of China. Globally, the CCUS industry has entered a phase of scaled and clustered development. North America has established a system of key technologies in large-scale CO₂ capture, long-distance pipeline transmission, pipeline network optimization, and large-scale CO₂ flooding for enhanced oil recovery (CO₂-EOR), with relatively mature cluster development and a gradual shift in industrial model from CO₂-EOR to geological storage. The CCUS industry of China has developed rapidly across all segments but remains in the early stage of cluster development, facing challenges such as absent business model, insufficient policy support, and technological gaps in core areas. China needs to improve the policy support system to boost enterprises participation across the entire industrial chain, strengthen top-level design and medium- to long-term planning to accelerate demonstration projects construction for whole-process CCUS clusters, advance for a full-chain technological system, including low-cost capture, pipeline optimization and EOR/storage integration technologies, and strengthen personnel training, strengthen discipline construction and university-enterprise research cooperation.

Existing sandstone rock structure evaluation methods rely on visual inspection, with low efficiency, semi-quantitative analysis of roundness, and inability to perform classified statistics in particle size analysis. This study presents an intelligent evaluation method for sandstone rock structure based on the Segment Anything Model (SAM). By developing a lightweight SAM fine-tuning method with rank-decomposition matrix adapters, a multispectral rock particle segmentation model named CoreSAM is constructed, which achieves rock particle edge extraction and type identification. Building upon this, we propose a comprehensive quantitative evaluation system for rock structure, assessing parameters including particle size, sorting, roundness, particle contact and cementation types. The experimental results demonstrate that CoreSAM outperforms existing methods in rock particle segmentation accuracy while showing excellent generalization across different image types such as CT scans and core photographs. The proposed method enables full-sample, classified particle size analysis and quantitative characterization of parameters like roundness, advancing reservoir evaluation towards more precise, quantitative, intuitive, and comprehensive development.

To address the challenges in studying the pore formation and evolution processes, and unclear preservation mechanisms of deep to ultra-deep carbonate rocks, a high-temperature and high-pressure visualization simulation experimental device was developed for ultra-deep carbonate reservoirs. Carbonate rock samples from the Sichuan Basin and Tarim Basin were used to simulate the dissolution-precipitation process of deep to ultra-deep carbonate reservoirs in an analogous geological setting. This unit comprises four core modules: an ultra-high temperature, high pressure triaxial stress core holder module (temperature higher than 300 °C, pressure higher than 150 MPa), a multi-stage continuous flow module with temperature-pressure regulation, an ultra-high temperature-pressure sapphire window cell and an in-situ high-temperature-pressure fluid property measurement module and real-time ultra-high temperature-pressure permeability detection module. The new experimental device was used for simulation experiment, the geological insights were obtained in three aspects. First, the pore-throat structure of carbonate is controlled by lithology and initial pore-throat structure, and fluid type, concentration and dissolution duration determine the degree of dissolution. The dissolution process exhibits two evolution patterns. The dissolution scale is positively correlated to the temperature and pressure, and the pore-forming peak period aligns well with the hydrocarbon generation peak period. Second, the dissolution potential of dolomite in an open flow system is greater than that of limestone, and secondary dissolved pores formed continuously are controlled by the type and concentration of acidic fluids and the initial physical properties. These pores predominantly distribute along pre-existing pore/fracture zones. Third, in a nearly closed diagenetic system, after the chemical reaction between acidic fluids and carbonate rock reaches saturation and dynamic equilibrium, the pore structure no longer changes, keeping pre-existing pores well-preserved. These findings have important guiding significance for the evaluation of pore-throat structure and development potential of deep to ultra-deep carbonate reservoirs, and the prediction of main controlling factors and distribution of high-quality carbonate reservoirs.

By conducting organic geochemical analysis of the samples taken from the drilled wells in Baiyun Sag of Pearl River Mouth Basin, China, the development characteristics of hydrocarbon source rocks in the sag are clarified. Reconstruct the current geothermal field of the sag and restore the tectonic-thermal evolution process to predict the type, scale, and distribution of resources in Baiyun Sag through thermal pressure simulation experiments and numerical simulation. The Baiyun Sag is characterized by the development of Paleogene shallow lacustrine source rocks, which are deposited in a slightly oxidizing environment. The source rocks are mainly composed of terrestrial higher plants, with algae making a certain contribution, and are oil and gas source rocks. Current geothermal field of the sag was reconstructed, in which the range of geothermal gradients is (3.5-5.2) °C/100 m, showing an overall increasing trend from northwest to southeast, with significant differences in geothermal gradients across different sub-sags. Baiyun Sag has undergone two distinct periods of extensional process, the Eocene and Miocene, since the Cenozoic era. These two periods of heating and warming events have been identified, accelerating the maturation and evolution of source rocks. The main body of ancient basal heat flow value reached its highest at 13.82 Ma. The basin modelling results show that the maturity of source rocks is significantly higher in Baiyun main sub-sag than that in other sub-sags. The Eocene Wenchang Formation is currently in the stage of high maturity to over maturity, while the Eocene Enping Formation has reached the stage of maturity to high maturity. The rock thermal simulation experiment shows that the shallow lacustrine mudstone of the Wenchang Formation has a good potential of generating gas from kerogen cracking with high gas yield and long period of gas window. Shallow lacustrine mudstone of the Enping Formation has a good ability to generate light oil, and has ability to generate kerogen cracking gas in the late stage. The gas yield of shallow lacustrine mudstone of the Enping Formation is less than that of shallow lacustrine mudstone of the Wenchang Formation and the delta coal-bearing mudstone of the Enping Formation. The numerical simulation results indicate that the source rocks of Baiyun main sub-sag generate hydrocarbons earlier and have significantly higher hydrocarbon generation intensity than other sub-sags, with an average of about 1 200×10⁴ t/km². Oil and gas resources were mainly distributed in Baiyun main sub-sag and the main source rocks are distributed in the 3^rd and 4^th members of Wenchang Formation. Four favorable zones are selected for the division and evaluation of migration and aggregation units: No. ① Panyu 30 nose-shaped structural belt, No. ③ Liuhua 29 nose-shaped uplift belt and Liwan 3 nose-shaped uplift belt, No. ② gentle slope belt of Baiyun east sag, and No. ⑧ Baiyun 1 low-uplift.

A large language model (LLM) is constructed to address the sophisticated demands of data retrieval and analysis, detailed well profiling, computation of key technical indicators, and the solutions to complex problems in reservoir performance analysis (RPA). The LLM is constructed for RPA scenarios with incremental pre-training, fine-tuning, and functional subsystems coupling. Functional subsystem and efficient coupling methods are proposed based on named entity recognition (NER), tool invocation, and Text-to-SQL construction, all aimed at resolving pivotal challenges in developing the specific application of LLMs for RDA. This study conducted a detailed accuracy test on feature extraction models, tool classification models, data retrieval models and analysis recommendation models. The results indicate that these models have demonstrated good performance in various key aspects of reservoir dynamic analysis. The research takes some injection and production well groups in the PK3 Block of the Daqing Oilfield as an example for testing. Testing results show that our model has significant potential and practical value in assisting reservoir engineers with RDA. The research results provide a powerful support to the application of LLM in reservoir performance analysis.

Wells CXD1 and CX2 have uncovered high-concentration potassium-and lithium-containing brines and substantial layers of halite-type polyhalite potash deposits within the 4th and 5th members of the Triassic Jialingjiang Formation and the 1st Member of Leikoupo Formation (Jia 4 Member, Jia 5 Member, and Lei 1 Member) in the Puguang area, Sichuan Basin. These discoveries mark significant breakthroughs in the exploration of deep marine potassium and lithium resources within the Sichuan Basin. Utilizing the concept of “gas-potassium-lithium integrated exploration” and incorporating drilling, logging, seismic, and geochemical data, we have investigated the geological and enrichment conditions, as well as the metallogenic model of potassium-rich and lithium-rich brines and halite-type polyhalite. First, the sedimentary systems of gypsum-dolomite flats, salt lakes and evaporated flats were developed in Jia 4 Member, Jia 5 Member, and the 1st member of Leikoupo Formation (Lei 1 Member) in northeastern Sichuan Basin, forming three large-scale salt-gathering and potassium formation centers in Puguang, Tongnanba and Yuanba, and developing reservoirs with potassium-rich and lithium-rich brines, which are favorable for the deposition of potassium and lithium resources in both solid or liquid phases. Second, the soluble halite-type polyhalite has a large thickness and wide distribution, and the reservoir brine has a high content of K⁺ and Li⁺. A solid-liquid superimposed “three-story structure” (with the lower thin-layer of brine reservoir in lower part of Jia 4 Member and Jia 5 Member, middle layer of halite-type polyhalite potash depositS, upper layer of potassium-rich and lithium-rich brine reservoir in Lei 1 Member) is formed. Third, the ternary enrichment and mineralization patterns for potassium and lithium resources were determined. Vertical superposition of polyhalite and green bean rocks is the mineral material basis of potassium-lithium resources featuring “dual-source replenishment and proximal-source release”, with primary seawater and gypsum dehydration as the main sources of deep brines, while multi-stage tectonic modification is the key to the enrichment of halite-type polyhalite and potassium-lithium brines. Fourth, the ore-forming process has gone through four stages: salt-gathering and potassium-lithium accumulation period, initial water-rock reaction period, transformation and aggregation period, and enrichment and finalization period. During this process, the halite-type polyhalite layer in Jia 4 Member and Jia 5 Member is the main target for potassium solution mining, while the brine layer in Lei 1 Member is the focus of comprehensive potassium-lithium exploration and development.

This paper discusses the characteristics and formation mechanism of thin dolomite reservoirs in the lower submember of the second member of the Permian Maokou Formation (lower Mao 2 Member) in the Wusheng-Tongnan area of the Sichuan Basin, SW China, through comprehensive analysis of geological, geophysical and geochemical data. The reservoir rocks of the lower Mao 2 Member are dominated by porphyritic vuggy dolomite and calcareous dolomite or dolomitic limestone, which have typical karst characteristics of early diagenetic stage. The dolomites at the edge of the karst system and in the fillings have dissolved estuaries, and the dolomite breccia has micrite envelope and rim cement at the edge, indicating that dolomitization is earlier than the early diagenetic karstification. The shoal facies laminated dolomite is primarily formed by the seepage reflux dolomitization of moderate-salinity seawater. The key factors of reservoir formation are the bioclastic shoal deposition superimposed with seepgae reflux dolomitization and the karstification of early diagenetic stage, which are locally reformed by fractures and hydrothermal processes. The development of dolomite vuggy reservoir is closely related to the upward-shallowing sequence, and mainly occurs in the late highstand of the fourth-order cycle. Moreover, the size of dolomite is closely related to formation thickness, and it is concentrated in the formation thickness conversion area, followed by the thinner area. According to the understanding of insufficient accommodation space in the geomorphic highland and the migration of granular shoal to geomorphic lowland in the late highstand of the third-order cycle, it is proposed that the large-scale shoal-controlled dolomite reservoirs are distributed along structural highs and slopes, and the reservoir-forming model with shoal, dolomitization and karstification jointly controlled by the microgeomorphy and sea-level fluctuation in the sedimentary period is established. On this basis, the paleogeomorphology in the lower Mao 2 Member is restored using well-seismic data, and the reservoir distribution is predicted. The prediction results have been verified by the latest results of exploration wells and tests, which provide an important reference for the prediction of thin dolomite reservoirs under similar geological setting.

The basic geological characteristics of the Qiongzhusi Formation reservoirs and conditions for shale gas enrichment and high-yield were studied by using methods such as mineral scanning, organic and inorganic geochemistry, breakthrough pressure, and triaxial mechanics testing based on the core, logging, seismic and production data. (1) Both types of silty shale, rich in organic matter in deep water and low in organic matter in shallow water, have good gas bearing properties. (2) The brittle mineral composition of shale is characterized by comparable feldspar and quartz content. (3) The pores are mainly inorganic pores with a small amount of organic pores. Pore development primarily hinges on a synergy between felsic minerals and total organic carbon content (TOC). (4) Dominated by Type I organic matters, the hydrocarbon generating organisms are algae and acritarch, with high maturity and high hydrocarbon generation potential. (5) Deep-and shallow-water shale gas exhibit in-situ and mixed gas generation characteristics, respectively. (6) The basic law of shale gas enrichment in the Qiongzhusi Formation was proposed as “TOC controlled accumulation and inorganic pore controlled enrichment”, which includes the in-situ enrichment model of “three highs and one over” (high TOC, high felsic mineral content, high inorganic pore content, overpressured formation) for organic rich shale represented by Well ZY2, and the in-situ + carrier-bed enrichment model of “two highs, one medium and one low” (high felsic content, high formation pressure, medium inorganic pore content, low TOC) for organic-poor shale gas represented by Well JS103. It is a new type of shale gas that is different from the Longmaxi Formation, enriching the formation mechanism of deep and ultra-deep shale gas. The deployment of multiple exploration wells has achieved significant breakthroughs in shale gas exploration.