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.

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 parameters and standards are inconsistent, which restrict the evaluation efficiency and exploration process of dry hot rocks. This paper is based on the understandings of 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 parameter 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 mainly based on four indicators: heat source, thermal channel, thermal reservoir and cap rock. It includes 11 evaluation parameters, including magma and volcanic activity time, depth of molten body or magma chamber, distribution of deep faults, burial depth of thermal reservoirs, cap rock conditions, surface thermal anomalies, geothermal flow, geothermal gradient, Moho depth, burial depth, seismic level, and focal depth. Each parameter is divided into 3 levels. Applying this evaluation system to assess favorable zones for 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 Depression and Honghaershute Depression 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 heat 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.

In recent years, wells Pengshen 10, Heshen 9, Tongshen 17 and Zhengyang 1 in the Sichuan Basin have confirmed the presence of a set of porous reef-beach reservoirs in the Upper Permian Changxing Formation, which breaks the traditional view that deep and ultra-deep carbonate oil and gas are mainly distributed in porous dolomite reservoirs and karst fracture-cavity limestone reservoirs. Through core and thin section observations, reservoir geochemical analysis, and well-seismic based reservoir identification and tracking, this study provides insights in four aspects. (1) Porous reef-beach limestone reservoirs are developed in the Changxing Formation in deep-buried layers. The reservoir space is mainly composed of intergranular (dissolved) pores, framework pores, biological cavity pores, mold pores and dissolution pores, which are formed in sedimentary and early surface environments. (2) The intermittently distributed porous reef-beach complexes are surrounded by relatively dense micrite limestone, which leads to the formation of local abnormal overpressure inside the reef-beach complexes under the deep ultra-high temperature. (3) The floor of the Changxing Formation reservoir is composed with interbedded tight mudstone and limestone of the Upper Permian Wujiaping Formation, and the floor is the tight micrite limestone interbedded with mudstone of the first member of Lower Triassic Feixianguan Formation. Under the clamping of dense roof and floor, the abnormal overpressure in the Changxing Formation is formed. Abnormal overpressure is the key to maintain the pores formed in the sedimentary and surface periods in deep-buried layers. (4) Based on the identification of roof, floor and reef-beach complexes, the favorable reef-beach limestone reservoir distribution area of 10.3×10⁴ km² is predicted by well-seismic combination. These insights lay the theoretical foundation for the development of deep porous limestone reservoirs, expand the new field of exploration of deep-buried limestone reservoirs in the Sichuan Basin, and have important reference value for the exploration of deep-buried limestone reservoirs in other basins.

To address the challenges of existing separated zone oil production technologies, which include 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 and developed. This technology employs a release-sub-involved pipe string structure that separates the production and allocation pipe strings. Once the two strings are docked downhole, the principle of electromagnetic coupling is used to achieve close-range wireless transmission of electrical power and signals between the strings, powering multiple downhole intelligent production allocators (IPAs) and enabling two-way communication between ground and downhole. The core tools including downhole electricity & signal transmission equipment based on electromagnetic coupling (EST), IPAs, and ground communication controller (GCC), and accessory tools including large-diameter release sub anchor and cable-crossing packers, have been developed to meet the complex downhole conditions. Field tests on ten wells in the 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 of separate layer and regulation of zonal fluid production were achieved, enhancing reservoir understanding, and achieving practical production results of increased oil output and reduced water content.

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 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 experiment. 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. This can be further 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 0.062 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 the density flows was established for the southwestern part of the basin, highlighting that the frequent occurrence of flood events and the steep topography in this area are the primary controlling factors for the development of density flows; (5) Sandstone and mudstone in the Chang 7₃ sub-member exhibit micro- and nano-scale pore-throat systems, with varying oil-bearing properties across different lithologies and significant differences in mobile oil content. (6) It was determined that 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.

A flexible sidetracking stimulation technology of horizontal wells is formed to develop the 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 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 and sidetracking horizontal well fracturing. The flexible sidetracking horizontal well 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. At the same time, it is verified that the flexible sidetracking stimulation technology can provide favorable support for accurately developing remaining reserves in low-permeability or ultra-low-permeability reservoirs.

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 analytical 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 significantly improved with a viscosity reduction of 99.4% in average after the reaction in 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 °C-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 minutes. 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 and less affected by resins and saturates contents.

Considering the three typical phase-change 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 flow 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 numerical 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, 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.

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 to protect pores, 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 terrestrial shales are expected to become important replacement areas. In the future, 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 the ultra-deep marine shales of the Upper-Middle Yangtze region, the new marine strata in the North China region, the transitional shales between 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.

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 radius 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 show 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 driving pressure decreases with the increase of temperature, obviously decreases with the increase of throat radius, and increases with the increase of reservoir particle size. The difference of driving pressure of crude oil in reservoir with different particle levels decreases with the increase of temperature, and decreases 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.

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 cavernous 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 estuarines, and the dolomite breccia has micrite sheath and rim cement at the edge, indicating that dolomitization is earlier than the early diagenetic karst. The beach facies laminated dolomite is primarily formed by the osmotic reflux dolomitization of moderate-salinity seawater. The key factors of reservoir formation are the clastic beach deposition superimposed with osmotic reflux dolomitization and the karstification of early diagenetic stage, which are locally reformed by fractures and hydrothermal processes. The development of dolomite porous-vuggy reservoir is closely related to the upward-shallowing sequence, and mainly occurs in the upper 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 small thickness area. According to the understanding of insufficient accommodation space in the geomorphic highland and the migration of granular beach to geomorphic lowland in the upper highstand of the third-order cycle, it is proposed that the large-scale beach-controlled dolomite reservoirs are distributed along the high rim slope, and the reservoir-forming model with beach, 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. The research results provide an important reference for the prediction of thin dolomite reservoirs under similar geological setting.

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 continental 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. The following findings are obtained: (1) Optimal preservation conditions 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) Good preservation conditions also maintain a high energy field (abnormally high pressure), facilitating the maximum outflow of shale oil; (3) Good preservation conditions 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.

Using the ultra-low permeability reservoirs in the L block of the Jiangsu oilfield as an example, a series of experiments, including slim tube displacement experiments of CO₂-oil system, injection capacity experiments, and high-temperature, high-pressure online nuclear magnetic resonance displacement experiments, are conducted to reveal the oil/gas mass transfer pattern and oil production mechanisms during CO₂ flooding in ultra-low permeability reservoirs. The impacts of CO₂ storage pore range and miscibility on oil production and CO₂ storage characteristics during CO₂ flooding are clarified. Crude oil expansion and viscosity reduction are the main mechanisms for improving recovery in the CO₂ displacement stage. After CO₂ breakthrough, the extraction of light components from the crude oil further enhances oil recovery. During CO₂ flooding, the contribution of crude oil in large pores to the enhanced recovery exceeds 46%, while crude oil in medium pores serves as a reserve for incremental recovery. After CO₂ breakthrough, a small portion of the crude oil is extracted and carried into nano-scale pores by CO₂, becoming residual oil that is hard to recover. As the miscibility increases, the CO₂ front moves more stably and sweeps a larger area, leading to increased CO₂ storage range and volume. The CO₂ full-storage stage contributes the most to the overall CO₂ storage volume. In the CO₂ escape stage, the storage mechanism involves partial in-situ storage of crude oil within the initial pore range and the CO₂ carrying crude oil into smaller pores to increase the volume of stored CO₂. In the CO₂ leakage stage, as crude oil is produced, a significant amount of CO₂ leaks out, causing a sharp decline in the storage efficiency.

Considering the interactions between fluid molecules and pore walls, variations in critical properties, capillary forces, and the influence of the adsorbed phase, this study investigates the phase behavior of the CO₂-shale oil within nanopores by utilizing a modified Peng-Robinson (PR) equation of state alongside a three-phase (gas-liquid-adsorbed) equilibrium calculation method. The results reveal that nano-confinement effects of the pores lead to a decrease in both critical temperature and critical pressure of fluids as pore size diminishes. Specifically, CO₂ acts to inhibit the reduction of the system’s critical temperature while promoting the decrease in critical pressure. Furthermore, an increase in the mole fraction of CO₂ causes the system’s critical point to shift leftward and reduces the area of the phase envelope. In the shale reservoirs of Block A in Gulong of Daqing, China, pronounced nano-confinement effects are observed. At a pore diameter of 10 nm, reservoir fluids progressively exhibit characteristics typical of condensate gas reservoirs. Notably, the liquid-phase CO₂ content in 10 nm pores increases by 20.0% compared to 100 nm pores, while the gas-phase CO₂ content decreases by 10.8%. These findings indicate that nano-confinement effects enhance CO₂ mass transfer within nanopores, thereby facilitating CO₂ sequestration and improving microscopic oil recovery.

Wells CXD1 and CX2 revealed high-concentration potassium- (K) and lithium- (Li) containing brines and thick layers of halite-type polyhalite potash deposit in the 4th and 5th members of Triassic Jialingjiang Formation (Jia 4 Member and Jia 5 Member) in Puguang area, Sichuan Basin, achieving breakthroughs in the exploration of deep marine potassium and lithium resources in the Sichuan Basin. Following the concept of “gas-potassium-lithium integrated exploration” and using the drilling, logging, seismic and geochemical data, we studied the geological and enrichment conditions, metallogenic model of potassium-rich and lithium-rich brines and halite-type polyhalite. First, the sedimentary system of gypsum-dolomite flats, salt lake and evaporated flat are 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 + Jia 5 Member, middle layer of halite-type polyhalite potash deposit, upper layer of potassium-rich and lithium-rich brine reservoir in Lei 1 Member) is formed, laying the foundation for the development and utilization of marine deep potassium-lithium resources in China. Third, the ternary enrichment and mineralization model for potassium and lithium resources was established: vertical superposition of polyhalite and green bean rocks are mineral material basis of potassium-lithium resources featuring “dual-source replenishment and proximal-source release”, and primary seawater and gypsum dehydration are the main sources of deep brines, while multi-stage tectonic modification is 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.

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 organic phase types 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 the 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 and shale gas. The achievements have important reference significance for enriching the theory of ultra-deep clastic rock oil and gas exploration and guiding the next oil and gas exploration deployment.

By considering the thermo-poroelastic effects of rock, the constitutive relationship of fatigue deterioration under cyclic loading, elastic-brittle failure criteria, and wellbore stress superposition effects, a thermal-hydraulic-mechanical-fatigue damage coupled model for fracture propagation during soft hydraulic fracturing in hot dry rock (HDR) was established and validated. Based on this model, numerical simulations were conducted to investigate the fracture initiation and propagation characteristics in HDR under the combined effects of different temperatures and cyclic loading. The results are obtained in three aspects. First, cyclic injection, fluid infiltration, pore pressure accumulation, and rock strength deterioration collectively induce fatigue damage of rocks during soft hydraulic fracturing. Second, the fracture propagation pattern of soft fracturing in HDR is jointly controlled by temperature difference and cyclic loading. A larger temperature difference generates stronger thermal stress, facilitating the formation of complex fracture networks. As cyclic loading decreases, the influence range of thermal stress expands. When the cyclic loading is 90%p_b and 80%p_b (where p_b is the breakdown pressure during conventional hydraulic fracturing), the stimulated reservoir area increases by 88.33% and 120%, respectively, compared to conventional hydraulic fracturing (with an injection temperature of 25 ℃). Third, as cyclic loading is further reduced, the reservoir stimulation efficiency diminishes. When the cyclic loading decreases to 70%p_b, the fluid pressure cannot reach the minimum breakdown pressure of the rock, resulting in no macroscopic hydraulic fractures.

The basic geological characteristics of the Qiongzhusi Formation reservoir and high-yield conditions for shale gas enrichment 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 has the characteristic of equivalent content of feldspar and quartz. (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 dubious sources, with high maturity and high hydrocarbon generation potential. (5) Deep- and shallow-water shale gas exhibit in-situ and mixed characteristics, respectively. (6) The basic law of shale gas enrichment in the Qiongzhusi Formation was proposed as “TOC controlled storage 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 “three highs, one medium and one low” (high felsic content, high formation pressure, medium inorganic pore content, low TOC) for low organic 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.

Two etching models, the spherical-rod standard pore channel and the pore structure, were used to conduct displacement experiments in the water-gas dispersion system to observe the morphological changes and movement characteristics of microbubbles. Additionally, numerical simulation methods were employed for quantitative analysis of experimental phenomena and oil displacement mechanisms. In the experiment, it was observed that microbubble clusters can disrupt the pressure equilibrium state of fluids within the transverse pores, and enhancing the overall fluid flow; bubbles exhibit a unique expansion-contraction vibration phenomenon during the seepage process, which is nearly unobservable in water flooding and gas flooding processes. Bubble vibration can accelerate the adsorption and expansion of oil droplets, and promote the emulsification of crude oil, thereby improving microscopic oil displacement efficiency. Combining experimental data with numerical simulation analysis of bubble vibration effects, it was found that microbubble vibrations exhibit characteristics of a sine function, and the energy release process follows an exponential decay pattern; compared to the gas drive front interface, microbubbles exhibit a significant “rigidity” characteristic; the energy released by microbubble vibrations alters the stability of the seepage flow field, resulting in significant changes to the flow lines; during the oil displacement process, the vast number of microbubbles can fully exert their vibrational effects, facilitating the migration of residual oil and validating the mechanism of the water-gas dispersion system enhancing microscopic oil displacement efficiency.

The thermal flux curve of phase-transition fluid (PF) was tested using differential scanning calorimetry (DSC), based on which a reaction kinetics model was established to reflect the relationship between phase transition conversion rate, temperature and time. A temperature field model for fractures and rock matrix considering phase transition heat was then constructed, and its reliability was verified using previously established temperature field models. Additionally, the new model was used to study the effects of different injection parameters and phase-transition fracturing performance parameters on the temperature variations in fractures and matrix. The study indicates that, at different positions and times, the cooling effect of the injected cold fluid and the exothermic effect during the phase transition alternately dominate the temperature within the fracture. At the initial stage of fracturing fluid injection, the temperature within the fracture is high, and the phase transition rate is rapid, resulting in a significant impact of exothermic phase transition on the reservoir rock temperature. In the later stage of injection, the fracture temperature decreases, the phase transition exothermic rate slows, and the cooling effect of the fracturing fluid on the reservoir rock intensifies. Phase transition heat significantly affects the temperature of the fracture. Compared to cases where phase transition heat is not considered, when it is taken into account, the temperature within the fracture increases to varying degrees at the end of fluid injection. As the phase transition heat increases from 20 J/g to 60 J/g, the maximum temperature rise in the fracture increases from 2.1 ℃ to 6.2 ℃. The phase transition heat and PF volume fraction are positively correlated with fracture temperature changes, while specific heat capacity is negatively correlated with temperature changes. With increasing injection time, the temperature and phase transition rate at the fracture opening gradually decrease, and the location of the maximum phase transition rate and temperature difference gradually shifts from the fracture opening to about 10 m from the opening.

The saline lacustrine hybrid sedimentary rocks are complex in lithology and unknown for their sedimentary mechanisms. The hybrid sedimentary rocks samples from the Neogene upper Ganchaigou Formation to lower Youshashan Formation (N₁-N₂¹) in the Fengxi area, the Qaidam Basin, were investigated through core-log and petrology-geochemistry cross-analysis by using the core, casting thin section, scanning electron microscope, X-ray diffraction, logging, and carbon/oxygen isotope data. The results indicate that the hybrid sedimentary rocks in the Fengxi area were deposited in a shallow lake environment far from the source, or occasionally in a semi-deep lake environment, with 5 lithofacies types and 6 microfacies types recognized. Stable carbon and oxygen isotopes reveal that the formation of sedimentary cycles is controlled by a climate-driven compensation-undercompensation cyclic mechanism. A sedimentary cycle model of hybrid sedimentary rocks in an arid and saline setting is proposed. According to this model, in the compensation period, the lake level rises sharply, and microfacies such as mud flat, sand-mud flat and beach are developed, with physical subsidence as the dominant sedimentary mechanism; in the undercompensation period, the lake level falls slowly, and microfacies such as lime-mud flat, lime-dolomite flat and algal mound/mat are developed, with chemical-biological process as the dominant sedimentary mechanism. Unlike marine carbonate rock formed during transgression, lacustrine carbonate rock is mainly formed along with regression. In the saline lacustrine sedimentary system, the facies change is not interpreted by the accommodation believed traditionally, but controlled by the temporary fluctuation of lake water chemistry caused by climate change. The research results update the interpreted high-resolution sequence model and genesis of hybrid sedimentary rocks in the saline lacustrine basin and provide a valuable guidance for exploring unconventional hydrocarbons of saline lacustrine facies.

This paper presents an analysis of four aspects, including the distribution and production of global oil and gas fields, the distribution and changes of remaining recoverable reserves, the differences in oil and gas production between regions/countries, and the development potentials of oil and gas fields unproduced and to be produced in 2023. On this basis, the situation and characteristics of global oil and gas development are expounded, and the trend of global oil and gas development is forecasted. In 2023, oil and gas fields were widely distributed around the world, with an expanding upstream production landscape; Oil and gas reserves increased year-on-year, driven by significant contributions from new discoveries and reserve revisions; The overall oil and gas production grew continuously, with notable contributions from new projects coming online and capacity expansion efforts; and The oil and gas fields unproduced or to be produced, especially large onshore conventional oil fields and economically challenging offshore gas fields, host abundant reserves. From the perspectives of reshaping oil and gas production areas due to the pandemic and Russia-Ukraine conflicts, geopolitical crises, capital expenditure structures in exploration and development, and the proactive layout of associated resources, the trend of global oil and gas development in 2023 was analyzed systematically. The enlightenment and suggestions in four aspects are proposed for Chinese oil companies to focus on core businesses and clarify development strategies in the post-pandemic era and the context of energy transition: The global oil and gas landscape is undergoing profound adjustments, and it is essential to grasp development trends, especially in core businesses; Upstream business exhibits a strong potential, and emerging business is considered as a replacement; The prospects for tight/shale oil and gas are promising, and new pathways to ensure national energy security are explored; Cutting-edge breakthroughs are achieved in emerging industries of strategic importance, and a comprehensive energy collaboration system for supply security is established.

The high temperature and high pressure visualization PVT experiments of different gas media-crude oil were carried using the interface disappearance method. The experiments show that there are two miscible temperature domains in the miscibility of CO₂-crude oil during heating process under constant pressure. Under the experiment pressure of 15 MPa, when the temperature is less than 140 °C, the miscible zone shows liquid phase characteristics, and increasing the temperature inhibits the miscible process; when the temperature is greater than 230 °C, the miscible zone tends to gas phase characteristics, and increasing the temperature is conducive to the miscibility formation. Under a certain pressure, with the increase of temperature, the miscibility of flue gas/nitrogen and crude oil is realized. When the temperature is low, the effect of CO₂ on promoting miscibility is obvious, and the order of miscible temperature of gas medium and crude oil is N₂ > flue gas > CO₂; however, when the temperature is high, the effect of CO₂ on promoting miscibility gradually decreases, and the miscible temperature of N₂ and crude oil is close to that of flue gas. The miscibility is dominated by the distillation and volatilization of light components of crude oil. There are many light hydrocarbon components in the gas phase at phase equilibrium, and the miscible zone is characterized by gas phase.

Based on the data of 3D seismic survey, drilling, sidewall coring, thin sections and tests, this paper systematically discusses the necessary conditions for the formation of buried-hills, reservoirs, and accumulations in the large oil and gas fields in deep to ultra-deep composite buried hills in the Bohai Sea through the analysis of the Meso-Cenozoic geotectonic dynamics, buried-hill reservoir characteristics, and differential enrichment patterns of oil and gas in the buried hills, as well as case study of typical reservoirs. The key findings are as follows. First, the double-episode destruction of the North China Craton in the Yanshanian and Himalayan served as the primary tectonic driver for the development of deep to ultra-deep composite buried hills in the Bohai Sea. Jointly controlled by the destruction of the North China Craton and the activity of the Tanlu Fault, the destruction center migrated and converged episodically from the margins of the Bohai Bay Basin towards the Bozhong Depression, resulting in an orderly mountain-building process within the basin and subsequently two development zones for composite buried hills, i.e. the middle and inner rim zones within the Bozhong Depression. Second, under the coupling of favorable lithologies and multi-stage structures, the middle and inner rim zones are conducive to the formation of reservoirs in fluid dissolution-pore/fracture zones underlying the weathering crust. Third, during the Episode II craton destruction, the middle and inner rim zones subsided intensely, along which massive hydrocarbons were generated, resulting in the overpressure, and then migrated to and accumulated in the composite buried hills. The lower parts and interiors of these buried hills still possess excellent conditions for hydrocarbon accumulation. These findings promote a shift in buried hill exploration to three-dimensional exploration of composite buried hills. It is emphasized that the deep to ultra-deep composite buried hill interiors in the middle rim zone and the multi-stage volcanic edifices in the inner rim zone of the depression represent important successor areas for future exploration in the Bohai Sea.

Through investigating the Triassic Yanchang Formation in the Ordos Basin, black carbon has been found for the first time in the seventh member of the Middle Triassic Yanchang Formation (Chang 7 Member). This study fills the gap in black carbon record in the Middle Triassic in terrestrial basins in in the East Tethys, and suggests that the oxygen content in the East Tethys during the Middle Triassic was beyond 15% and that plants had recovered from the Late Permian mass extinction. The results show that the distribution of black carbon in the Chang 7 Member is heterogeneous in the basin. In the southeastern part, the black carbon content is the highest (possibly ˃6%) in shale, with the proportion in TOC up to 20%, which is lower than 10% in the northwestern and northeastern parts. It is intriguing that the proportion of black carbon in the organic matter can reach to this high level during the Middle Triassic when black carbon was stunted. Therefore, it is postulated that black carbon could account for great proportion in organic matter after vegetation on land in the Silurian. The traditional practice needs to be caution when TOC is set as a critical proxy in source rock evaluation and shale oil and gas sweet spot screening. Source rock bearing high TOC but high proportion in black carbon may not be good target for unconventional oil and gas exploitation, while shale bearing low TOC with low or no black carbon may become promising option. The TOC in the source rock can be fractioned into black carbon (w_b), active carbon (w_a), residual carbon (w_r), and maturated oil carbon (w_o). TOC subtract w_b or TOC-w_b is recommended for evaluation of source rock, w_a for screening the in-situ recovery area of low to medium maturity shale oil, and w_o of matured shale oil for appraisal of the favorable exploration area of medium to high matured shale oil. These results allow for the quantitative evaluation of organic matter composition of shale, hydrocarbon generation potential, maturation stage, and expulsion and retention of shale oil, and also guide the reconstruction of paleoclimate in the source rock development period and the shale oil and gas sweet spot screening.

Taking the Ordos Basin as an example, this paper proposed that the construction of an energy super basin should follow the principle of “more energy, less carbon, and better energy structure”. The modeling workflow of energy super basin was built. Based on the resources/reserves, development status and infrastructures of the Ordos Basin, the development potential of the basin was evaluated, the uncertainties in the construction of energy super basin were analyzed, and the future vision and realization path of the Ordos Energy Super Basin were recommended. This study demonstrates that the Ordos Basin has the advantages of abundant sources, perfect infrastructures, well-matched carbon source and sink, small population density, and proximity to the energy consumption areas. These characteristics ensure that the Ordos Basin is a good candidate of the energy super basin. It is expected that the energy supply of the Ordos Basin in 2050 will reach 23×10⁸ tons of standard coal, and the proportion of fossil fuels in energy supply will decrease to 41%. The carbon emissions will decrease by 20×10⁸ tons of carbon dioxide equivalent compared to the emissions in 2023. The future construction of the basin should focus on the generation and storage of renewable energy. The carbon capture, utilization and storage technology requires breakthrough innovation.

The shales in the ancient Qiongzhusi Formation in the Sichuan Basin are characterized by large burial depth and high maturity, but unknown for shale gas enrichment pattern. Through detailed characterization of the depositional environment of the Deyang-Anyue aulacogen and the Leshan-Longnüsi paleouplift, thermal simulation experiments, and analysis of the main controlling factors of shale gas enrichment, the aulacogen-uplift enrichment pattern is proposed. It is revealed that the Deyang-Anyue aulacogen controls the depositional environment of the Qiongzhusi Formation, where high-quality sedimentary facies and thick strata are observed, and the Leshan-Longnüsi paleouplift controls the maturity evolution of the shale in the Qiongzhusi Formation, with the uplift located in a high position and exhibiting a moderate degree of thermal evolution and a high resistivity. The aulacogen-uplift overlap area is conducive to the enrichment of shale gas during the deposition, oil generation, gas generation, and adjustment stages, and has a joint control on the development of reservoirs, resulting in multiple reservoirs of high quality and large thickness. Based on the aulacogen-uplift enrichment pattern and combinations, four types of shale gas play are identified, and the sweet spot evaluation criteria for the Qiongzhusi Formation is established. Accordingly, a sweet spot area of 8 200 km² in the aulacogen is determined, successfully guiding the deployment of Well Zi 201 with a high-yield industrial gas flow of 73.88×10⁴ m³/d. The study insights provide an important basis for the development of deep Cambrian shale gas.

Based on commercial databases from S&P Global and Rystad Energy and public information from oil companies around the world, a systematic analysis has been conducted on the global hydrocarbon exploration investment, award of exploration blocks, exploratory drilling, new conventional oil and gas discoveries, and exploration of associated resources in 2023. The results show that, in 2023, the global hydrocarbon exploration investment increased steadily and the total number and area of awarded exploration blocks increased significantly, but the increase in drilling costs led to a decline in the number of exploration wells for conventional oil and gas resources around the world. The decline in the number and success rate of high-impact exploration wells directly affected the quantity of additional oil and gas reserves discovered globally in 2023. In recent years, the deepwater areas of passive margin basins have been the major targets for seeking medium- and large-sized conventional oil and gas fields. In 2023, however, the newly discovered onshore reserves were equivalent to the newly discovered offshore reserves, and fine exploration in mature blocks achieved significant results. Oil companies continued to plan and perform unconventional oil and gas exploration activities and accelerated access to mineral resources such as natural hydrogen and helium and other emerging industries. For Chinese oil companies international exploration business, it is recommended to: (1) continue the upstream investment to strengthen upstream services for consolidating the strategic position of oil and gas resources; (2) uphold oil and gas exploration activities by further deploying exploration activities in the deepwater areas of passive margin basins, deeply exploring mature basins, closely following hotspot basins, and gaining access to frontier basins; (3) follow the principle of integrated development to plan the exploration of associated resources while exploiting conventional and unconventional resources; and (4) make technological innovations to develop and improve core technologies and promote the application of artificial intelligence.

With the continuous discovery of unconventional oil and gas, traditional petroleum system theories and methods can no longer adapt to the research of all underground oil and gas resources. Traditional petroleum system theories emphasize the restoration of the accumulation process from “source” to “trap”. The main oil and gas resources in the concept are conventional oil and gas, lacking the concept and research of unconventional oil and gas enrichment mechanism. The whole petroleum system is developed from the traditional petroleum system. Compared with the petroleum system, the whole petroleum system adds the research content of unconventional oil and gas. Although the study of the whole petroleum system is still in three aspects: geological elements, dynamic evolution and oil and gas distribution, its research ideas and research contents are very different, mainly including the following three aspects. (1) In terms of geological elements, the traditional petroleum system mainly studies the characteristics of source rocks and hydrocarbon generation evolution, and the reservoir properties, traps, migration and preservation conditions of conventional oil and gas. On the basis of the above research, the whole petroleum system has increased the quantitative evaluation of retained hydrocarbons, unconventional reservoir characterization, source reservoir configuration and other research contents. (2) In terms of dynamic evolution, the petroleum system mainly studies the matching between the evolution of conventional oil and gas source rocks and the formation period of traps, that is, the critical moment of oil and gas accumulation, while the whole petroleum system has increased the research content of the matching of unconventional reservoir densification and oil and gas charging, and the later transformation of unconventional oil and gas reservoirs. (3) In terms of oil and gas distribution, the petroleum system takes buoyancy accumulation mechanism as the core to study the migration, accumulation and distribution of conventional oil and gas. The whole petroleum system adds unconventional oil and gas self-sealing accumulation mechanism and conventional-unconventional oil and gas distribution sequence, so as to determine the oil and gas distribution characteristics of the whole petroleum system.

Considering the adsorption loss of the hydraulic fracturing assisted oil displacement (HFAD) agent in the matrix, a method is proposed to characterize the dynamic saturation adsorption capacity of the HFAD agent with pressure differential and permeability. On this basis, coupled with the viscosity-concentration relationship of the HFAD agent, a non-linear seepage model of HFAD was established, taking into account the adsorption effect of high pressure drops, and the influencing factors were analyzed. The findings indicate that the replenishment of formation energy associated with HFAD technology is predominantly influenced by matrix permeability, fracture length and the initial concentration of the HFAD agent. The effect of replenishment of formation energy is positively correlated with matrix permeability and fracture length, and negatively correlated with the initial concentration of the HFAD agent. The initial concentration and injection amount of the high-pressure HFAD agent can enhance the concentration of the HFAD agent in the matrix and improve the efficiency of oil washing. However, a longer fracture is not conducive to maintaining the high concentration of the HFAD agent in the matrix. Furthermore, the fracture length and pump displacement are the direct factors affecting the fluid flow velocity in the matrix subsequent to HFAD. These factors can be utilized to control the location of the displacement phase front, and thus affect the swept area of HFAD. A reasonable selection of the aforementioned parameters can effectively supplement the formation energy, expand the swept volume of the HFAD agent, improve the recovery efficiency of HFAD, and reduce the development cost.

Based on 2D and 3D seismic data and well logging data, this paper studies the distribution of well-seismic stratigraphic filling and shoal controlled reservoirs of Upper Cambrian Xixiangchi Formation in the south slope of Leshan-Longnüsi paleouplift in the Sichuan Basin, to reveal the genetic relationship between stratigraphic filling, paleogeomorphology and large-scale grain shoal. (1) The Xixiangchi Formation in the study area is overlapped and filled gradually to the Leshan-Longnüsi paleouplift, but gets thin sharply due to truncation only near the denudation pinch-out line of the paleouplift. Therefore, 2 overlap slope break belts and 1 erosion slope break belt are identified, and the Xixiangchi Formation is divided into 4 members from bottom to top. (2) The filling pattern of the overlapping at the base and erosion at the top indicates that the thickness of Xixiangchi Formation can reflect the pre-depositional paleogeomorphology, and reveals that the study area has a monoclinal geomorphic feature of plunging to southeast and being controlled by multistage slope break belts. (3) The large-scale grain shoals and shoal controlled reservoirs are developed longitudinally in the third and fourth member of the Xixiangchi Formation, and laterally in the vicinity of the multistage overlap slope break belts. (4) Overlap slope break belts are closely related to northwest trending reverse faults. The northwest to southeast compressive stress formed by the convergence of the western margin of South China Plate with the Himalayas landmass of the Qiangtang-Tethyan realm in the middle and late Cambrian led to the rapid uplift of the northwest margin of the Yangtze Plate and the expansion to the southeast, forming a gradually plunging multistage slope break paleogeomorphology. Combined with oil and gas test results, it is predicted that the favorable exploration zone of the grain shoal controlled reservoirs can cover an area of 3340 km².

The depositional facies types of the fourth member of the Middle Triassic Leokoupo Formation (Lei-4 Member) in western Sichuan Basin are examined through the methods of sedimentology, lithology and the mineral composition interpretation, as well as the special lithofacies indicators such as microbialite, anhydrite-halite succession and tempestites, using the data of about 400 boreholes and 11 outcrop sections. The distribution evolution characteristics and its hydrocarbon significances of the paleo-bay facies have been discussed further. The Lei-4 Member in western Sichuan Basin has an ocean-bay-flat depositional model, with the presence of evaporated tidal flat, restricted tidal flat and paleo-bay facies from east to west. The subfacies such as bay margin, subtidal bay and bay slope are recognized within the paleo-bay, with microbial reef and grain bank microfacies in the bay margin, microbial dolomitic flat, deep-water spongy reef and hydrostatic mudstone microfacies in the subtidal bay, and tempestites and collapsed deposits in the upper bay slope. The bay margin covered the Guangyuan-Zitong-Dujiangyan area in the period of the first submember of the Lei-4 Member (Lei-4-1), regressed westward into the Shangsi-Jiangyou-Dujiangyan area in the period of Lei-4-2, and expanded to the Jiange-Zitong-Langzhong-Wusheng-Yanting-Chengdu area in the northern part of central Sichuan Basin in the period of Lei-4-3 along with a small-scale transgression. The topographic pattern of “one high and two lows” is confirmed in the Lei-4 Member, corresponding to a configuration of source rocks and reservoir rocks that are alternated horizontally and superimposed vertically. Two efficient source-reservoir configuration models, i.e. side source & side reservoir, and self-generating & self-storing, are available with the microbial reef and grain bank reservoirs at the bay margin and the high-quality source rocks within the sags on both sides of the bay. The research findings will inevitably open up a new situation for the hydrocarbon exploration in the Leikoupo Formation.

The researches on the geological theory of coal-formed gas are reviewed, the contribution of coal-formed gas to China's natural gas reserves and production and to the development of natural gas in major gas-producing basins are analyzed, and the key favorable exploration zones for coal-formed gas in China are comprehensively evaluated. The following results are obtained. First, coal measures are good gas source rocks, and hydrocarbon generation from coal measure was dominated by gas generation, followed by oil. Second, a natural gas genetic identification index system based on stable isotopes, light hydrocarbon components, and biomarkers is established. Third, the quantitative and semi-quantitative factors controlling the formation of large gas fields, represented by the indicator of gas generation intensity greater than 20×10⁸ m³/km², are identified to guide the discovery of large gas fields in China. Fourth, coal-formed gas is the major contributor to China's current natural gas reserves and production, both accounting for over 55%. The high proportion of coal-formed gas has enabled the Tarim, Sichuan, and Ordos basins to be the major gas production areas in China. Fifth, deep coal rock gas is an important option for future exploration of coal-formed gas, and key zones include the Carboniferous Benxi Formation in the Wushenqi-Mizhi area of the Ordos Basin, the Permian Longtan Formation in central-southern Sichuan Basin, the Jurassic Xishanyao Formation in the southern margin and Luliang uplift of the Junggar Basin, Sixth, tight gas is the main area for increasing reserves and production, and the favorable exploration zones include the Carboniferous-Permian in southern Ordos Basin and the Bohai Bay Bain, and the Triassic Xujiahe Formation in the transition zone between central and western Sichuan Basin. Seventh, the Jurassic in the southern margin of the Junggar Basin is a key favorable exploration zone for subsequent investigation of conventional coal-formed gas. These insights have valuable theoretical and practical significance for further developing and improving the theory of coal-formed gas, and guiding the exploration of coal-formed gas fields in China.

Considering the demands, situations, and trends in respect to global climate change, carbon neutrality, and energy transition, the achievements and implications of the global green energy transition and China’s new energy revolution are summarized, and the “energy triangle” theory is proposed. The research indicates that the energy technology revolution is driving a dual transformation in global energy: the black “shale oil and gas revolution” in North America and the green “new energy revolution” in China. China’s green energy revolution has achieved significant milestones in wind, solar, and hydrogen storage technologies, leading the world in photovoltaic and wind power. The country has developed the world’s largest, most comprehensive, and competitive new energy innovation, industrial, and value chains, along with the largest clean power supply system globally. New quality productivity represents green productivity. China’s green “new energy revolution” has accelerated the transformation of its energy structure and the global shift towards clean energy, promoting a new win-win model for the global green and low-carbon transition. The “energy triangle” theory in the context of new quality productivity interprets the relationship and development between energy security, economy and greenness, carbon neutrality goal, and green energy transition. Compared to the global energy resource endowment, China’s energy resources are characterized by abundant coal, limited oil and gas, and unlimited wind and photovoltaic energy. Moving forward, China's energy strategies will focus on the advancement of technologies to clean coal for carbon emission reduction, increase gas output while stabilizing oil production, increase green energy while enhancing new energy, and achieve intelligent integration. Vigorously developing new energy is an essential step in maintaining China’s energy security, and establishing a carbon-neutral “super energy system” is a necessary choice. It is crucial to enhance China’s international competitiveness in new energy development, promote high-quality energy productivity, support the country’s transition to an “energy power,” and strive for “energy independence.”

Based on petroleum exploration and new progress of oil and gas geology study in the Qiongdongnan Basin, combined with seismic, drilling, logging, core wall, 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 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. (2) The reservoirs are mainly composed of deep-water gravity flow sedimentary submarine fan sandstone. (3) The types of cap rocks include deep-sea mudstone, mass flow mudstone, and hydrate bearing formations. (4) The types of traps are mainly lithological, and also include structural, lithological, and structural 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 submarine fan composite migration, late dynamic accumulation, deep-sea mud mass flow hydrate-bearing strata ternary sealing, and large-scale enrichment at ridges of the Quaternary submarine fan. The new understanding obtained from the research has reference and enlightening significance for the next step of deepwater and ultra-shallow layers exploration, as well as oil and gas exploration in related fields or regions.

This study integrates field outcrop profiles, drilling cores, 2D seismic profiles, and 3D seismic data of key areas to analyze the Triassic tectonic-sequence stratigraphy in the Kuqa foreland basin, and investigates the impact of episodic thrust structures on sedimentary evolution and source rock distribution. (1) The Kuqa foreland basin has experienced stages of initial strong, weakened activities, relaxation and inactivity of episodic thrusting, resulting the identification of 4 second-order sequences (Ehebulake Formation, Karamay Formation, Huangshanjie Formation, Taliqike Formation) and 11 third-order sequences (SQ1-SQ11). Each sequence or secondary sequence displays a “coarse at the bottom and fine at the top” pattern due to the influence of secondary episodic thrust activity. (2) The episodic thrusting is closely linked to regional sequence patterns, deposition and source rock formation and distribution. The sedimentary evolution in the Triassic period progresses from fan delta to braided river delta, lake, braided river delta, and meandering river delta, corresponding to the initial strong (Ehebulake Formation), weakened (Karamay Formation), relaxation (Huangshanjie Formation), and inactivity (Taliqike Formation) of episodic thrusting. The development stage of thick, coarse-grained sandy conglomerate reservoirs aligns with the strong to weakened thrust activities, while the source rock formation period coincides with the relaxation to inactivity stages. (3) Controlled by the intensity and stages of episodic thrust activity, the nearly EW trending thrust fault not only significantly thickened the footwall source rock during the Huangshanjie Formation, becoming the development center of Triassic source rock, but also experienced multiple overthrust nappes in the soft stratum of the source rock, showing “stacked style” distribution. (4) The deep layers of the Kuqa foreland basin have the foundation and conditions necessary for the formation of substantial gas reservoirs, capable of forming various types of reservoirs such as self-generating and self-storing lithology, lower generating and upper storing fault-lithology, and stratigraphic unconformity. This area holds significant importance for future gas exploration efforts aimed at enhancing storage and production capabilities.

Based on the analyses of the core, cast thin section, physical property, CT, wireline loggings, well tests and seismic data, taking the Lower Cretaceous Yamama Formation in Oilfield A of the Central Arabian Basin as an example, the sedimentation and diagenesis characteristics and favorable reservoir distribution in semi-restricted carbonate ramp are clarified. The results show that semi-restricted carbonate ramp is enriched with Algae, Benthic foraminifera, Bivalve, Bacinella, and peloids, and is characterized by diverse low-energy and shallow-water lithofacies. The depositional environment of the Yamama Formation at early stage is dominated by open shelf, and then is dominated by large scale lagoon, locally being grain shoal, patchy reef, back shoal and tidal flat. There are three sequences in the Yamama Formation, namely I, II, and III, from bottom to top. During the regression cycle, the sequence I is dominated by cementation, the sequence II by dissolution, and the sequence III by alternating cementation and dissolution. The reservoirs are composed of packstone, wackstone and bindstone, with varying lithological sequence laterally which is difficult to be correlated. The reservoirs are porous, with the space contributed by micropores, moldic pores, and skeletal pores, as well as less primary intergranular pores, corresponding to medium- and micro-throats. The physical properties generally exhibit low to medium porosity, and low to ultra-low permeability. The medium-high permeability reservoirs are underdeveloped. It is found that the development of favorable reservoir in semi-restricted carbonate ramp are controlled by high-energy sedimentation locally, soluble bioclastic enrichment, and intense dissolution. Local high-energy grain shoals and patchy reef contain primary intergranular pores with no intense cementation, and they are important facies of favorable reservoirs in semi-restricted carbonate ramp. Low- to medium-energy facies such as lagoon and back shoal are rich in soluble bioclastics such as Algae and Bacinella. The bioclastics were intensely dissolved, forming a large number of moldic pores and skeletal pores, which effectively improved the reservoir physical properties, thus facilitating the formation of large-scale favorable reservoirs. The favorable reservoirs of the Yamama Formation in Oilfield A are mainly distributed in the north-central anticline axis of YA member and YB member.

The application framework leveraging large language models (LLMs) is explored to address the sophisticated demands of data retrieval and analysis, detailed well profiling, computation of key technical indicators, and the development of solutions in reservoir dynamic analysis (RDA). This framework encompasses a large language foundation model augmented with incremental pre-training, fine-tuning, and subsystems coupling. Key innovations in specialized fine-tuning technologies include named entity recognition (NER) based on prompt engineering, classification-based 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 real block of the PK3 Fault Block transition zone 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.