The types and configurations of source-reservoir coupling can be identified based on the shale oil and gas source-reservoir coupling, which provides a basis for the determination of ideas about shale oil and gas exploration and the efficient exploration and development of shale oil and gas. However, until now, shale oil and gas have not introduced by any scholars into a unified evaluation system for the classification of source-reservoir coupling types, which to some extent restricts the exploration and development process of shale oil and gas. In view of this, based on analyzing the source-reservoir configuration characteristics of typical marine and terrestrial shale oil and gas reservoirs in China, the source-reservoir coupling relationship of shale oil and gas is divided into three categories. Moreover, this study makes clear the geological connotations of different source-reservoir coupling types and their mechanisms controlling oil and gas enrichment, and proposes an efficient exploration approach based on the overall evaluation of shale oil and gas in China. The research results suggest that the source-reservoir coupling types of shale oil and gas can be divided into three categories: source-reservoir separation, source-reservoir coexistence, and source-reservoir integration. Specifically, the migration distance of source-reservoir separation hydrocarbons is above meter scale, and the near-source oil and gas forms sweet spots, represented by the Lower Cambrian Qiongzhusi Formation in Sichuan Basin, the first and second submembers of Member 7 of Triassic Yanchang Formation in Ordos Basin, and the Permian Lucaogou Formation in Jimusar sag of Junggar Basin. The source-reservoir coexistence is characterized with the multi-source supply of hydrocarbons and the coexistence of source and reservoir, of which hydrocarbons are migrated into the nearby advantageous reservoirs to make them oil-bearing as a whole, represented by the Member 2 of Permian Wujiaping Formation in Sichuan Basin, the Jurassic Lianggaoshan Formation in Sichuan Basin, and the Member 4 of Paleogene Shahejie Formation in Jiyang depression of Bohai Bay Basin. The source-reservoir integration indicates that the source rock and reservoir are in the same stratum, and hydrocarbons undergo micro migration within the stratum, represented by the Ordovician Wufeng Formation and Silurian Longmaxi Formation in Sichuan Basin and the Cretaceous Qingshankou Formation in Songliao Basin. Sedimentary environment, biogenic silica, thermal maturity, and hydrocarbon generation/expulsion efficiency are the core elements that affect the shale oil and gas source-reservoir configuration and furtherly control the enrichment of shale oil and gas. Taking the typical shale oil and gas reservoirs in China as an example, the paper furtherly clarifies the exploration levels and ideas under the vertical multi-type source-reservoir coupling configuration at different levels of maturity. The research results are beneficial for quickly identifying and optimizing favorable intervals of shale oil and gas, providing an important scientific basis for the efficient exploration and development of shale oil and gas in China.

As the super and most petroliferous basin in China, Songliao Basin has achieved strategic breakthroughs in the exploration and evaluation of Gulong shale oil, of which the potential and scale of resources remain unclear. Based on the extensive geochemical data including total organic carbon (TOC), rock pyrolysis, vitrinite reflectance and pressure-reserved core, in combination with logging and production data, a systematic evaluation was conducted on various types of shale oil, primarily in Qijia-Gulong sag. A classification scheme using organic matter maturity and reservoir type as key indicators was developed for shale oil in Songliao Basin. As a result, grading standards for shale oil were established based on the key parameters such as TOC content, oil content, effective porosity, and oil saturation. A shale oil resource evaluation method was created, involving the key technologies such as precise evaluation of oil content, light hydrocarbon recovery and calibration of recoverable coefficient. Based on dynamic production data, the geological resource potential of shale oil under current technological conditions was assessed, achieving the predictive analysis of resource recoverability. The comprehensive evaluation indicates that Qijia-Gulong sag contains medium- to high-maturity shale oil resources of 107.73×10 ⁸t (including 42.08×10 ⁸t of Class Ⅰ resources and 33.67×10 ⁸t of Class Ⅱ resources), with technically recoverable resources exceeding 8×10 ⁸t. Additionally, the geological resources of dissolved gas are estimated to be 1.75×10 ¹²m ³, and the technically recoverable resources amount to 0.13×10 ¹²m ³. The resource evaluation results suggest that the favorable shale oil resources in Songliao Basin are mainly distributed in Qijia-Gulong sag, as being the essential strategic replacement resource. With future advancements in development technologies, the recoverable potential of shale oil is expected to increase significantly.

The Cambrian Qiongzhusi Formation is one of the earliest series of strata for shale gas exploration and research in China. In the early stage, due to unclear understandings of the overall geological cognition and limited technological conditions, a number of wells were only deployed in the Weiyuan anticline and Changning anticline with a burial depth less than 3 500 m and a relatively gentle structure. The production rate of the wells is low, indicating a failure in the large-scale commercial development. Recently, major exploration breakthroughs have been made in Well Zi201 and Well Weiye1H, marking significant progress in geological cognition of the deep shale gas in Qiongzhusi Formation of the Deyang-Anyue aulacogen. The sedimentary environment of Qiongzhusi Formation is controlled by the aulacogen. The deep-water siliceous argillaceous shelf facies in the trough and deep-water silty argillaceous shelf facies on the slope of the trough edge are the dominant sedimentary facies zones, which are conducive to the enrichment and accumulation of shale gas. Vertically, Qiongzhusi Formation has developed multiple sets of shale reservoirs, mainly consisting of the 1st, 3rd, 5th, and 7th substrata. In particular, the 5th substratum is a key breakthrough layer with the total organic carbon content of 2.7% to 3.1%, porosity of 4.2% to 4.9%, brittle mineral content of 69.5% to 76.5%, gas content of 7.8 m ³/t to 9.5 m ³/t, and moderate maturity of 3.0% to 3.5%. The 3rd substratum is a potential exploration stratum. Qiongzhusi Formation is expected to realize multi-interval three-dimensional development. The bottom margin of the Cambrian System has a simple structure in the middle section of the aulacogen, lacking of obvious major faults. The pressure coefficient of Qiongzhusi Formation is generally above 1.8, and the preservation conditions are favorable. The aulacogen provides sufficient sedimentary space and material basis, as a result of which the shale in Qiongzhusi Formation is rich in hydrocarbon sources and has achieved a high volume of gas production; the existence of Leshan-Longnüsi paleo-uplift prevents the shale in Qiongzhusi Formation from excessive thermal evolution. A "aulacogen-paleouplift" shale gas enrichment model has been established, and it has been determined that the favorable exploration area of Qiongzhusi Formation is 4 400 km ² and the resources amounts to 2×10 ¹²m ³. The exploration breakthrough of shale gas in Qiongzhusi Formation has opened up another new field for achieving a trillion of cubic meters of reserves and a billion of cubic meters of production. Next, the geological-engineering integrated high-yield model of Well Zi201 will be promoted and applied to the exploration and development fields of marine deep and ultra-deep shale gas in the entire Upper Yangtze area of southern China.

Six sets of high-quality source rocks have been identified globally, with three of them in the pre-Mesozoic strata serving as the primary source rocks for ancient oil and gas reservoirs. Ancient oil and gas reservoirs from the pre-Mesozoic strata exhibit five key characteristics. (1) The predominant basin types include foreland, passive continental margin, and cratonic basins. (2) Their primary type of oil and gas resources remains conventional, although shale oil and gas is developing rapidly. (3) Their oil and gas accumulations are primarily concentrated in the Permian, Devonian, Carboniferous, and Ordovician. (4) Their reservoir lithology is primarily composed of limestones, sandstones, shales, and dolomites. (5) Their burial depth is predominantly within the middle to shallow layers, indicating significant potential for deep plays. The substantial discoveries of ancient oil and gas plays demonstrate enrichment in four fields: the periphery of cratons, carbonate reservoirs, shale oil and shale gas reservoirs, and basement reservoirs. After analyzing the major discoveries in key areas, it is revealed that high-quality source-reservoir-seal combinations form readily in the peripheral regions of cratons that were historically located within low-latitude intertropical convergence zones. Global significant events have played a crucial role in shaping the development of source rocks and the enrichment of shale oil and gas. Within the temporal framework of these significant global events, potential plays can be optimized in advance by reconstructing the paleo-positions of accumulation elements. Based on independent evaluations of recoverable oil and gas reserves and yet-to-be-discovered resources, it is evident that conventional oil and gas exploration should focus on the Arabian Basin, Zagros Basin, Tarim Basin, and other basins. Basement rocks and residual strata are also important potential exploration areas. For shale oil and shale gas exploration, the focus should be on the Devonian Domanik shale in the Timan-Pechora and the Volga-Ural basins in Russia, the Silurian hot shale in the Arabian Basin in the Middle East, the Silurian and Devonian plays in the Ghadames Basin in the North Africa, and several sets of shales in the Sichuan and Junggar basins in China.

The Whole Petroleum System theory establishes the unified accumulation mechanism, enrichment regularity and geodynamic control conditions of conventional and unconventional oil and gas. Tight oil and gas are crucial components of the Whole Petroleum System. This paper reviews the development history of tight oil and gas, looks forward to the resource prospect of tight oil and gas, describes the geological characteristics of typical tight oil and gas reservoirs in China, and reveals the accumulation mechanism and enrichment regularity of tight oil and gas from the perspective of the Whole Petroleum System theory. The research results are as follows. (1) China’s tight oil and gas resources have broad prospects and great development potential, and great achievements have been made in the field of exploration and development, but there are still great challenges in the future, including geological theory, engineering technology and enhanced oil recovery technology. (2) Both physical property and accumulation process of tight oil and gas reservoir are between those of conventional oil-gas and shale oil-gas. The complex capillary network composed of pore throats within the tight reservoir is the key to the self-containment of tight oil and gas. (3) Oil and gas resources in different petroliferous basins in China show distinct differential enrichment characteristics. The Ordos Basin is a super tight oil and gas enrichment basin. (4) Based on the source-reservoir coupling relationship, tight oil and gas reservoirs can be classified into far-source type, near-source type, and intra-source type.

A new wave of technological revolution and industrial transformation is rapidly advancing against the backdrop of global climate change, the consensus on carbon neutrality, and the imperative for energy transition. The emerging industries of new energy has become a key development focus for nations worldwide. Emerging industries symbolize the trajectory of future technological and industrial advancement. The emerging industries is growing under the leadership of established sectors innovately, while nurturing future industries and serving as a crucial direction for the development of new quality productive forces. New energy stands as a pivotal strategic emerging industry, playing a paramount role within China’s energy strategies of "cleaning up coal, stabilizing oil production, enhancing gas utilization, strengthening new energy development, promoting multi-energy complementarity, and advancing intelligent collaboration". Fueled by advancements in manufacturing, infrastructure and intelligentization capabilities, the existing energy system relied on underground resource endowments is shifting to a novel energy system grounded in technological innovation. The advancement of new quality productive forces promotes the high-quality development of emerging industries in the field of new energy. Through the synergy of technological innovation and the dual carbon goals, the "four-wheel drive" of technology innovation and carbon emissions reduction leading the way, and energy economy and security propelling the progress, will successfully resolve the "impossible triangle" contradiction that has been troubling the energy field. This transition steers towards the transformation of the energy landscape from the fossil fuel-dominated "impossible triangle" to the new energy-driven "achievable triangle", enriches and develops the "energy triangle" theory. Through a series of measures such as constructing innovation platforms, driving technological innovation, fostering collaborative innovation, developing talent teams, and constructing industrial supply chains, a group of technology leaders emerge, which will accelerate the formation of new quality productive forces in emerging industries of new energy. This effort holds the promise of transforming fossil fuels such as coal and oil into more chemical material-oriented resources, striving for new energy to achieve "technological independence", and helping China achieve "energy independence".

In 2024, according to the exploration idea of "fracture-cavity gas reservoirs formed after fracture reconstruction of carbonate rock", three exploration wells were deployed in the Ordovician subsalt area of Ordos Basin to test gas and obtain high-yield industrial gas flow, revealing good exploration potential for the subsalt fracture-cavity gas reservoirs. However, the high-yield and enrichment regularity and comprehensive prediction model of fracture-cavity gas reservoirs are still unclear, making it difficult to determine favorable zones and achieve drilling targets. Therefore, based on cores, thin sections, seismic data, logging data, and production performances, this paper investigates the basic geological conditions and high-yield and enrichment mechanism of the Ordovician subsalt fracture-cavity gas reservoir in Ordos Basin. The results show as follows. (1)The subsalt fracture-cavity gas reservoirs have dual source hydrocarbon supply conditions of the Upper Paleozoic coal measures and Lower Paleozoic marine source rocks, of which the latter are the main source rocks, with the maximum hydrocarbon generation intensity of 1.2×10 ⁸m ³/km ² and sufficient hydrocarbon supply capacity. (2)The reservoir spaces of the subsalt fracture-cavity units are mainly composed of fractures and dissolution pores developed along the fracture zone, mixed with a small amount of matrix intergranular pores. The average porosity can reach more than 10 %, and the average permeability can reach up to 10 mD, demonstrating good reservoir performance. (3)The subsalt faults and associated fracture systems can not only improve the physical properties of dolomite reservoirs and form fracture-cavities with good reservoir performance, but also communicate source rocks with reservoirs, thus providing effective channels for oil and gas to accumulate in fracture-cavity reservoirs. (4)The thick layer of gypsum-salt rock developed in the 6th submember of Member 5 of Majiagou Formation serves as the regional cap rock for the fracture-cavity gas reservoir. The gypsum-salt rock developed in the 10th submember of Member 5 of Majiagou Formation, as well as the Member 3 of Majiagou Formation, serves as the cap rock overlying on the gas reservoir. Moreover, the tight carbonate rocks around the fracture-cavities form lateral sealing, and those good preservation conditions are conducive to natural gas enrichment and formation of fracture-cavity gas reservoirs. Through comprehensive evaluation, it has been preliminarily determined that the favorable exploration area for the Ordovician subsalt fracture-cavity gas reservoirs is about 2.5×10 ⁴km ², and the estimated natural gas reserves can reach 5000×10 ⁸m ³, indicating great exploration potential. It is an important direction and real target for exploration of the Ordovician subsalt natural gas.

A study is performed on the reservoir-controlling of strike-slip faults in deep marine carbonate rocks (>4 500 m) in Sichuan Basin, which is of important significance for the efficient exploration and development of gas reservoirs in tight carbonate rocks. Through the analyses of gas reservoirs as well as static and seismic data, investigations are carried out on the temporal and spatial relationship between strike-slip fault and hydrocarbon accumulation, as well as the controlling effects of strike-slip fault on the gas migration, trap and enrichment. The results show that the pre-Mesozoic strike-slip fault system is dispersively distributed and widely developed in the central Sichuan Basin, which had destructive effect on hydrocarbon accumulation in the Caledonian period. However, the petroleum accumulation conditions were superior in the Indonian-Yanshanian period, thus forming the pre-Mesozoic multi-layer superimposed hydrocarbon accumulation system controlled by strike-slip faults. The strike-slip faults constitute the pre-Mesozoic vertical-lateral oil/gas transport system throughout the central Sichuan Basin. The strike-slip fault system has formed two kinds of migration modes, including the near-source lateral fault-controlled petroleum migration in the Upper Sinian-Lower Cambrian carbonate reservoirs, and the far-source vertical petroleum migration of the Middle Permian carbonate reservoirs. This has led to subsequent differentiation in stratified and zonal oil/gas accumulation. In the tight carbonate rocks, the effective structural-lithologic traps are developed under the joint action of high energy microfacies and strike-slip faults, and the both also play a role of controlling the effectiveness of traps, thus forming the gas reservoiring mode of "small gas reservoir but large field" along the strike-slip fault zones. The strike-slip faults control the distribution of the high porosity and high permeability "sweet spots" fracture-vug reservoirs and high-yield wells, which can increase the reserves, and control the hydrocarbon enrichment. The results reveal that there is a pre-Mesozoic deep carbonate strike-slip fault-controlled gas-rich system in the central Sichuan Basin, with the ternary coupling factors of "source-fault-reservoir" that control the gas accumulation; there are differences in controlling gas migration, trapping and enrichment by strike-slip faults; the strike-slip fault-controlled "sweet spot" gas reservoir is a new favorable field for exploration and development of deep carbonate rocks.

The water-flooding oilfield in Bohai Bay is dominated by the unconsolidated sandstone with high porosity and high permeability. As a result, the heterogeneity is further intensified from the stage of strong injection and production in long subsection to the high water cut stage. This leads to a series of problems, such as the difficulty in exploiting more sub-layers by water flooding and conventional polymer flooding and continuously and effectively expanding the swept volume. According to the differences in flooding control strength in chemical system, polymer gel, elastic dispersion fluid and polymer were defined as being of strong, medium and weak flooding control system. Based on the dynamic change rules of flow resistance during continuous chemical flooding (continuous injection in a single slug system), in combination with a test on the effective injection pressure of heterogeneous cores, a study was performed on the dynamic characteristics of expanding the swept volume by discontinuous chemical flooding (hereinafter referred to as DCF), composed of strong, medium, and weak flooding control systems. Then, the microscopic mechanism of the expanded swept volume was revealed by microfluidic experiment. The discontinuous chemical flooding slug combined injection mode was optimized by the parallel-cores flooding experiment. Finally, the feasibility of enhanced oil recovery by discontinuous chemical flooding was verified by field tests in offshore oilfields. The results show that the total mobility of oil and water phases during the continuous chemical flooding process is increased, the proportion of the total mobility of the high-permeability area in heterogeneous core is also increased, and the ability of expanding swept volume is restricted. Therefore, DCF substitution model for the slug combinations of different pharmaceutical systems can be used to effectively solve the problem of insufficient, excessive or uneven resistance increasing capacity from single slug injection. In addition, microfluidic experiments show that the "strong-weak" and "weak-strong" combinations of DCF can expand the swept volume by 29.2 % and 14.0 % as compare with the single continuous injection mode, respectively. Core flooding experiments show that the "medium-strong-weak-strong-weak" combination of DCF has a better EOR effect and can further improve oil recovery by 4.41 % as compared with continuous polymer flooding. Thus, it can be seen that effective control of injection and production pressure difference and continuous expansion of microscopic heterogeneous remaining oil are the main mechanisms of EOR by non-continuous chemical flooding. The pilot test of DCF in 2 wells of BZ oilfield in Bohai Bay shows that the water cut of the flooding response well is reduced by up to 14 %, and the oil production is increased to 6.97×10 ⁴t, indicating a good effect of controlling water control and increasing oil production.

Industrial oil flow has been discovered in hydrocarhon exploration from the Permian to the Jurassic in the central Mahu sag, showing promising indications of oil and gas. However, the level of overall exploration in the study area remains relatively low. In addition, there is a notable absence of systematic research on the geological conditions for hydrocarbon enrichment, accumulation mode and primary controlling factors. A deep understanding of accumulation conditions and the distribution of favorable zones within the central Mahu sag is crucial to improving the efficiency of hydrocarbon exploration efforts. Based on recent data from core, logging, well tie and seismic profiles, and microscopic rock thin section observation, this paper investigates the characteristics of source rocks in the central Mahu sag, as well as the sedimentary characteristics and reservoir-controlling factors of key target strata, including the Permian Xiawuerhe Formation, Triassic Baikouquan Formation and Baijiantan Formation, and Jurassic Badaowan Formation. On this basis, this study determines the locations of multi-layered oil-gas target strata and identifies three-dimensional accumulation modes, thus providing a forward-looking prediction for the next phase of exploration. The study indicates that a widespread strike-slip fault system facilitates communication with the underlying Permian source rocks. Thus, oil and gas can be transported vertically and laterally to the Permian Xiawuerhe Formation and Triassic Bakouquan Formation through faults and unconformities, and further to shallow formations through faults for oil-gas accumulations. The extensive hydrocarbon accumulation in Mahu sag lies in the good reservoir-cap assemblage of widespread fan delta front facies mud-poor gravel reservoirs and retrogradational fan delta facies sediments with the late massive set of mudstone in Xiawuerhe Formation and Bakouquan Formation. The shallow oil-gas accumulation is associated with the favorable reservoir-cap assemblage of the thin-bedded glutenite reservoirs with massive mudstone in Baijiantan Formation and Badaowan Formation. A comprehensive analysis suggests that the fan delta front facies sandbodies of the Xiawuerhe Formation and the upper submember of Member 1 of the Baikouquan Formation in the central Mahu sag can develop high-quality reservoirs, and possess conditions for the large-scale development of stratigraphic traps. Moreover, braided fluvial delta front facies thin-bedded glutenites of the Member 2 of Baijiantan Formation and the Member 1 of Badaowan Formation in the central Mahu sag can develop high-quality reservoirs and provide favorable conditions for the formation of lithological traps. All the above are key strata for further oil-gas exploration in the central Mahu sag.

Geological modeling and numerical reservoir simulation are considered as important tools for modern reservoir research and management, and it is of great significance to promote the development and application of modeling and numerical simulation integration technique for efficient exploitation of oil and gas reservoirs. This paper briefly elaborates the formation, development and deep integration of the modeling and numerical simulation disciplines, and also analyzes the connotations of modeling and numerical simulation integration in terms of concept, process, algorithm and application, as well the development trends for key techniques of modeling and numerical simulation integration. At present, geological modeling technique needs to be further explored in terms of seismic multi-information drive, multi-point new statistical algorithm, geological process simulation and artificial intelligence technology; numerical simulation technique should focus more on in-depth studies of multi-phase, multi-component and multi-field coupling, physicochemical porous flow, whole-reservoir integration simulation and AI-based automatic history matching. Main methods for achieving modeling and numerical simulation integration are proposed, including building an integrated software platform, establishing standard procedures and standards, giving play to demonstrative and leading roles and fostering versatile talents. Moreover, it is considered that multi-dimensional and multi-scale data assimilation, construction of big reservoir development model and digital twin will be the future development trends for integrated modeling and numerical simulation.

Millimeter-scale fine evaluation of shale reservoir performance and oil-bearing property is of great significance for studying the enrichment characteristics of shale oil. This study targets at the medium to high maturity shale in Member 1 of Qingshankou Formation in Gulong sag of Songliao Basin. A series of analytical experiments were carried out, including micro-X-ray fluorescence spectroscopy, rock thin section observation, low-temperature nitrogen adsorption, high-pressure mercury injection, rock pyrolysis, as well as measurement of total organic carbon content. The results show that calcite+clay mineral lamina, clay mineral lamina, calcite lamina, felsic lamina, clay mineral layer, pyrite layer, and dolomite+clay mineral layer are mainly developed in the laminated and layered shale in key exploration sections of the study area. The combination of clay minerals and organic matter can always form organic-clay complexes, and the interaction between the both results in the formation of clay mineral lamina/layer and calcite/dolomite+ clay mineral lamina/layer with larger pore volume and specific surface area, when compared with calcite, felsic, and pyrite lamina/layer. It is verified that clay mineral and organic matter content are the main factors affecting shale reservoir shale reservoir performance and oil-bearing property in the study area. It is suggested that the shale strata rich in organic matter and clay mineral should be the preferred target for exploration.

The platform area of Tarim Basin possesses a vast hydrocarbon resource potential in deep to ultra-deep reservoirs. Tarim Basin has experienced a complex of hydrocarbon accumulation in the Ordovician Yijianfang Formation and Yingshan Formation in Fuman oilfield. Meanwhile, there is a significant difference in the planar distribution of hydrocarbon phases. Based on micro-area U-Pb isotope dating of carbonate cement and crude oil inclusions as well as carbonate veins, this study has determined three stages of fracture-cave type vein filling in reservoirs of Fuman oilfield, three stages of crude oil charging and one stage of natural gas charging. Specifically, the Stage-1 of crude oil charging occurred during the Middle Caledonian Period (473.3-447.4 Ma), the Stage-2 spanned from the Middle Devonian to the Late Devonian Period (348.2-273.9 Ma), the Stage-3 occurred during the Early Indosinian to Yanshanian Period (217.6-205.2 Ma), and the natural gas charging occurred on a large scale during the Late Yanshanian to Himalayan (90-20 Ma). The three stages of fracture-cave type vein filling correspond to the three stages of crude oil charging and tectonic activity. There are differences in the maturity and type of paleo oils charged in the southern and northern parts of Fuman oilfield, which are primarily influenced by variations in the thermal evolution of source rocks in the Cambrian Yuertusi Formation in different areas of the oilfield. The evolutionary processes of the Cambrian source rocks and the timing of tectonic activities in the platform area exhibit temporal and spatial correlations with the four phases of hydrocarbon charging. These research findings contribute to an enhanced understanding of the hydrocarbon accumulation mechanism and hydrocarbon enrichment regularity of deep to ultra-deep carbonate reservoirs.

Core analysis can provide support for studying the history of hydrocarbon generation, reservoir formation, and petroleum accumulation, improving oil and gas recovery rates, and searching for large-scale high-quality reserves. With the hydrocarbon exploration and development shifting towards deep and unconventional fields, the reservoirs are highly heterogeneous, and so the previous single-point analysis based on core can no longer meet the needs. It is necessary to comprehensively analyze the multi-scale images and experimental data of cores. Moreover, core analysis has developed from conventional manual description to the current digital core technology, and further towards the intelligent recognition of cores. Firstly, the paper comprehensively summarizes the current research status of core image analysis at home and abroad, and then proposes the definition and connotation of intelligent recognition technology for cores; next, the intelligent recognition of cores has been elaborated based on the case study of how to reconstruct the high-resolution CT images of full-diameter pore structure using micro-nano CT images; finally, the application of intelligent recognition technology for cores in reservoir evaluation, fracturing scheme design, and micro-seepage mechanism research is prospected. The proposal of intelligent recognition technology for cores reflects that artificial intelligence technology has begun to upgrade and develop synchronously in the oil and gas field, i.e., from the primary stage of intelligentization and speed and efficiency improvement of single-point business to a higher stage of multi-scale and multi-modal data fusion, application of large model technology in vertical fields, as well as high-quality development.

This study focuses on the Lucagou Formation of Jimusaer sag in Junggar Basin. Based on the lithological and reservoir pore characteristics, the migration and enrichment mechanisms of shale oil were determined using geochemical analysis data. The analysis of biomarkers shows that the lower section of sweet spots and the central thick mudstone interval of Lucagou Formation are independent petroleum systems without the occurrence of mixed shale oil source in the longitudinal direction, and the crude oil in reservoir sandbodies is derived from adjacent hydrocarbon source rocks, and characterized with near-source migration and in-situ accumulation, displaying a self-generation, self-reservoir and near-source accumulation model. Besides originating from nearby hydrocarbon source rocks, the shale oil in the upper section of sweet spots is mainly derived from deep hydrocarbon source rocks, and characterized with lateral migration and enrichment of shale oil, displaying a mixed accumulation model based on long-distance lateral migration and vertical near-source migration. The analyses of well profiles, rock thin sections, and high-pressure mercury injection experiments show that the upper section of sweet spots has the characteristics of low crude oil density, large reservoir thickness (single sandbody with the thickness of more than 1.6 m), well-developed intergranular pores, and good horizontal permeability, providing favorable conditions for the lateral migration of shale oil. By contrast, the crude oil density is higher, the reservoir thickness is thinner, and intergranular pores are not well developed in the central mudstone interval and the lower section of sweet spots, which is unfavorable for the lateral migration and enrichment of shale oil. The research results have identified two favorable depth intervals for the development of sweet spots of shale oil in the upper section of Lucagou Formation, i.e., the shallow depth section with high porosity and the deep depth section with developed secondary dissolution pores. The lateral migration distances of shale oil during enrichment in these two sections are 7300 m and 4100 m respectively. The shale oil enrichment in the lower section of sweet spots and the central thick mudstone interval needs to consider the hydrocarbon generation intensity and expulsion amount of adjacent source rocks. The favorable exploration interval in the lower section of sweet spots is below the peak oil generation depth (over 3 300 m). The research results have certain guiding significance for the discovery of interbedded shale oil sweet spots and the shale oil exploitation.

The continental lacustrine shale is developed in Nenjiang Formation of Songliao Basin, and characterized with wide distribution area, good quality of source rocks and large-scale potential shale oil resources. Previous studies mainly focused on the medium-high mature shale reservoirs of Qingshankou Formation, and rare attention is paid on the medium-low mature lacustrine shale in Nenjiang Formation. Based on whole-rock mineral analysis, organic geochemical analysis, as well as test data of field emission scanning electron microscopy and nitrogen adsorption, in combination with the regional tectonic background and sedimentary characteristics, the paper comprehensively analyzes the distribution of shale and the characteristics of source rocks, shale oil content and reservoir property of Nenjiang Formation, and discovers the geological characteristics and resource potential of shale oil in Nenjiang Formation. The results show that the shale is widely developed in Member 1 and 2 of Nenjiang Formation, with large thickness and stable distribution. Vertically, there are three sets of shale reservoirs with high organic matter in Nenjiang Formation, dominated by the organic matter of Type I and II ₁ in the medium-low mature stage. The nano-scale reservoir space of shale is dominated by intergranular pores, intragranular pores and pyrite intercrystalline pores, and the pore size is mainly distributed in the range of 64 nm to 128 nm. The paleoenvironment provides a material basis for the development of organic matter, and the enrichment of shale oil is jointly controlled by the coupling of high quality source rocks and multi-type nano-level reservoir space. The comprehensive evaluation shows that the best sweet spots are developed in Member 2 of Nenjiang Formation, followed by the middle section of Member 1 of Nenjiang Formation. The oil resources are preliminarily estimated to be more than 100×10 ⁸t. Well NY1H in Nenjiang Formation was deployed and drilled in 2021 by Daqing Oilfield Company Limited, with a cumulative oil production of 2 160 t, achieving stable production of medium-low mature shale oil in Nenjiang Formation, which confirmed that Nenjiang Formation has a good resource base of shale oil and utilization potential.

Due to the estimated reserves of natural gas hydrates in the South China Sea reaching up to 800×10 ⁸t oil equivalent, the Chinese government is actively encouraging the industrialization of these resources. This contrasts sharply with the decreasing theoretical research and financial investment in natural gas hydrates by foreign countries. Given the significant disparity in enthusiasm for natural gas hydrate research between China and other countries, as well as the risks and challenges associated with advancing the industrial development of natural gas hydrate resources in the South China Sea, this study integrates the latest global and South China Sea resource potential assessments. A comparative analysis is conducted on the differences in resource potential evaluations and perceptions between domestic and international scholars, and the underlying reasons for these differences. The latest evaluation results indicate that the global recoverable resources of natural gas hydrates have a mode value of 300×10 ⁸t oil equivalent and an average value of 680×10 ⁸t oil equivalent. For the South China Sea, the mode value of recoverable natural gas hydrate resources is 10×10 ⁸t of oil equivalent, and the average value is 26×10 ⁸t oil equivalent. The average value of recoverable resources in the South China Sea is less than 5 % and 20 % of the total conventional oil and gas resources globally and in the South China Sea, respectively. Thus, the estimated 800×10 ⁸ tons of oil equivalent in the South China Sea does not represent the actual recoverable resources but rather 30 to 80 times greater, which cannot be used for production guidance and strategic development research. The lack of uniformity in the concept and characterization methods of natural gas hydrate resources is one of the fundamental reasons for differences in understanding their development prospects. The current promotion of industrializing natural gas hydrate resources in the South China Sea faces risks and challenges in five aspects:small scale of recoverable resources, immature key technologies, weak market competitiveness, high commercial investment risks, and inconsistency with the national "dual-carbon" goals for large-scale development. Therefore, accelerating the industrialization of natural gas hydrate resources in the South China Sea requires in-depth research in four aspects:enhancing technological capabilities to increase recoverable resources, reducing extraction costs to expand the effective resource range, deepening geological assessments to clarify resource distribution characteristics, and conducting comprehensive geological surveys of various oil and gas resources to improve integrated development efficiency. With technological progress, natural gas hydrate resources are bound to be developed and utilized on a large scale, thus continued support and encouragement for relevant research and exploration are necessary.

This paper presents the current development state of shale oil and gas in home and abroad and systematically reviews the new technologies, equipment, materials, and software in the fields of shale oil and gas drilling, completion, and fracturing engineering, which are developed by China National Petroleum Corporation(CNPC) based on adhering to a problem-oriented approach tailored to the geological characteristics of China’s continental shale oil and gas. Through comparing these technologies with the overall shale oil and gas engineering technologies in North American, the paper summarizes the issues and challenges faced by shale oil and gas development in CNPC, and then proposes development recommendations for a "Chinese version" of shale oil and gas engineering technology. These recommendations focus on continuously advancing the research and application of key technologies and equipment, accelerating the research and development of new-generation directional drilling tools, carrying out ahead of time the research and development of in-situ conversion technologies for medium- to low-maturity shale oil, and vigorously promoting digital transformation and intelligent development. The goal is to enhance the support provided by engineering technology for shale oil and gas resource development and strengthen its role in ensuring national energy security.

Sepiolite-containing succession are developed in the cyclothems composed of limestones and argillaceous limestones in the first Member of Middle Permian Maokou Formation in Sichuan Basin. This paper investigates the paleoenvironment and sedimentary patterns of the sepiolite-containing succession in the first Member of Maokou Formation and reveals their sedimentary geological significances based on analyses such as identification of rock thin section, observations of scanning electron microscopy, determination of major/trace elements and carbon/oxygen isotopes. The research results indicate that there are four types of sepiolites in the first Member of Maokou Formation, namely lenticular, stellate, lamellar and bioclastic sepiolites. Among them, lenticular and stellate sepiolites are mainly developed in limestones, lamellar sepiolite is developed in argillaceous limestones, and bioclastic sepiolite is developed in both limestone and argillaceous limestone. During the limestone deposition, the ancient seawater temperature ( T ₁) restored using oxygen isotopes (δ ¹⁸O) is concentrated between 3.71 ℃ and 12.45 ℃, while the ancient seawater temperature ( T ₂) restored using the Mg/Ca ratio is concentrated between 13.78 ℃ and 14.20 ℃. The Sr/Ba ratios of the limestones are concentrated between 16.57 and 659.18, with the average paleosalinity of 131.97, average Sr/Cu ratio of 2 175.43, average V/(V+Ni) ratio of 0.9044, and average Ni/Co ratio of 14.32, indicating an cool water sedimentary environment with high salinity, drought, and oxygen-deficiency. During the deposition of argillaceous limestone, T ₁ is concentrated between 6.98 ℃ and 14.48 ℃, T ₂ is in the range of 13.80 ℃ to 15.14 ℃, the Sr/Ba ratio ranges from 77.34 to 819.59, and the average paleosalinity, Sr/Cu ratio, V/(V+Ni) ratio and Ni/Co ratio is 131.76, 1511.73, 0.912 2 and 16.42 respectively, reflecting a cool-water sedimentary environment with relatively low salinity, humidity and oxygen-deficiency. In the cool-water environment ( T ₁<12 ℃) with poor aluminum (Al) and rich magnesium (Mg), the silicon(Si)-rich fluid connected by faults forms a large number of sepiolite deposits in low subsags under the drive of gravity and concentration potentials. As the burial depth increases, sepiolites undergo different diageneses, forming a mineral combination sequence of sepiolite, talc, dolomite and quartz. The sedimentary pattern of sepiolite-containing succession in the first Member of Maokou Formation is described as follows. During the deposition period of limestone, the low seawater temperature was low, small amount of fresh water and terrestrial inputs, high salinity of seawater and less siliceous fluids resulted in the deposition of lenticular and stellate sepiolites. During the deposition period of argillaceous limestones, the increase of seawater temperature, increase of fresh water and terrigenous inputs, decrease of salinity, frequent volcanic activities and intrusion of siliceous fluids resulted in the deposition of lamellar sepiolites. The thickness distribution characteristics of sepiolite-containing succession reveal that Maokou Formation in the Sichuan Basin has a sedimentary pattern of "two platforms with one sag". The sepiolite-containing succession are thick in C-shaped Tongjiang-Changshou sag.