Based on the development practice of volumetric fracturing in shale oil horizontal wells in Ordos Basin, and the method of combining laboratory research and field production data analysis, the paper systematically summarizes the overall production decline law of shale oil horizontal wells and differences in the estimated ultimate recovery (EUR)of single well in different types of reservoirs, as well as the variation patterns of water content, salinity, pressure, gas-oil ratio and liquid production in horizontal well intervals during different development stages. On this basis, a production system featuring "reasonable shut-in periods to promote reservoir equilibrium, controlled flowback for sand control in early stage, and pressure-stabilized production to preserve reservoir energy" has been developed, along with a suit of remediation technologies and processes including "sand washing, wax removal, scale removal, gas content control, and eccentric wear prevention". Under the primary energy replenishment development in shale oil horizontal wells, Type Ⅰ and Ⅱ ₁ reservoirs demonstrate the average estimated ultimate recovery (EUR)of over 3.0×10 ⁴ t and approximately 2.4×10 ⁴ t per well, respectively, achieving economically viable large-scale development. Besides, in response to the problem of low single-well production in mid-to-late development stages of shale oil horizontal wells and the demand for enhanced oil recovery (EOR), the method of refracturing in existing horizontal wells in mature areas to create new fractures is proposed to increase EUR and EOR of single well, which is built based on preliminary field implementation analysis in combination with numerical simulation studies on reservoirs, and is predicted to increase the recovery rate by more than 5 %.

In 2023, a major breakthrough was achieved in exploration of the Member 2 of Maokou Formation in Longnüsi area of central Sichuan Basin. The proven reserves submitted to Ministry of Natural Resources of the People’s Republic of China exceeded 460×10 ⁸m ³, marking the first large-scale gas reservoir discovered in the 60-year exploration history of Maokou Formation in Sichuan Basin. As of 2024, PetroChina Company Limited has proven geological reserves of natural gas exceeding 1 500×10 ⁸m ³ in Maokou Formation of central Sichuan Basin, making the Maokou Formation an important new field for increasing reserves and production in the Sichuan Basin. The main understandings obtained are as follows. (1) It is innovatively proposed that the paleo-uplift of central Sichuan Basin has a significant controlling effect on the differentiation of ancient landforms in the early sedimentary period of the Member 2 of Maokou Formation. The slope break zone developed at the edge of the paleo-uplift is a favorable area for the development of high-energy shoals. The shoal thickness is large in Longnüsi-Hechuan-Nanchong area, which is a favorable breakthrough area for exploration. (2) The high-energy shoal facies in Longnüsi area of central Sichuan Basin has undergone multiple dolomitization processes such as early exposure, dissolution and shallow burial, resulting in the formation of high-quality dolomite reservoirs in the Member 2 of Maokou Formation and providing reservoir space conditions for large-scale accumulation. The lower submember of Member 2 of Maokou Formation in the study area develops fracture-pore type high-quality reservoirs, with thickness from 5 m to 30 m, core porosity from 2 % to 8 %, and permeability from 0.01 mD to 1.00 mD. (3) The large-scale hydrocarbon accumulation in Maokou Formation of the Longnüsi area was mainly controlled by multi-source relay hydrocarbon supply, early reservoir formation and trap formation. High-quality source rocks from the Cambrian Qiongzhusi Formation, the Silurian Longmaxi Formation, and the Member 1 of Permian Maokou Formation successively played an important role in sustained hydrocarbon supply after maturation, providing four-stage continuous oil and gas charging from Middle Triassic to Late Cretaceous in Maokou Formation. Early-stage hydrocarbon accumulation occurred in high-energy shoal facies reservoirs, which were laterally sealed by tight limestone, forming early lithologic traps favorable for the formation of large-scale gas reservoirs. (4) The Longnüsi-Hechuan-Nanchong area is the most favorable exploration area for the lower submember of Member 2 of Maokou Formation. The Ya’an-Dujiangyan area in western Sichuan Basin, the Yanting area in northern Sichuan Basin, and the Luzhou area in southern Sichuan Basin have similar sedimentary backgrounds and favorable accumulation conditions, and are potential favorable areas for the next exploration.

Numerical simulation technologies faces new challenges from the development of ultra-low permeability and tight oil reservoirs by large-scale fracturing and water/chemical injection for enhanced recovery. A discrete fracture model is used to characterize the complex fracture network; on this basis, a multiphase and multicomponent flow mathematical model has been established when considering reservoir stress sensitivity and nonlinear flow characteristics, and coupling the machanisms of the surfactants/salts adsorption and diffusion effects and their impacts on capillary pressure, relative permeability curves, and osmotic pressure variations. The explicit characterization of fractures is achieved using an adaptive grid refinement method, and the mode is solved by the finite volume method. The simulation results of the "vertical well injection with fractured horizontal well production" test model are consistent with the results from commercial software. The multiphase and multicomponent flow model established based on the discrete fracture model can successfully simulate the development of ultra-low permeability and tight oil reservoirs under the influence of complex fracture networks. The results show that when the matrix and fractures exhibit high stress sensitivity, a significant drop in reservoir pressure will lead to a substantial decline in well productivity. The development of ultra-low permeability and tight oil reservoirs has to consider the nonlinear flow characteristics of reservoirs, so as to accurately evaluate the development range and well productivity. To appropriately reduce the oil-water interfacial tension through surfactant addition can improve the energy-enhanced imbibition efficiency. The osmotic pressure effect induced by low salinity can improve the energy-enhanced imbibition to a certain extent, whereas the incremental oil recovery is limited.

Coal-rock gas is a new type of natural gas discovered in recent years, generally buried deeper, and some scholars also call it as deep coalbed methane. The exploration and development of this type of natural gas has made rapid progress, with significantly increasing production. Preliminary research indicates that deep coal-rock gas differs significantly from traditional coalbed methane, shale gas, tight gas, and other gas reservoirs in terms of reservoir characteristics and development methods, and has the potential to become a strategic replacement resource for natural gas in China. Therefore, a new round of national science and technology major projects for oil-gas exploration and development will focus on a series of scientific and technological breakthroughs in deep coal-rock gas. Based on systematical analysis, this paper summarizes the three major scientific challenges and ten key research directions for coal-rock gas exploration and development as follows. (1)The key fundamental geological issues are the accumulation mechanism of coal-rock gas and the construction of coal-measure whole petroleum system. The main research directions include the whole process mechanism of hydrocarbon generation/expulsion and enrichment lower limit of coal rocks, sedimentation and source-reservoir coupling effect of coal measures, multiple reservoir types and structures of coal rocks, and coal-measure whole petroleum system and oil-gas distribution. (2)The key fundamental development issues are the flow mechanism and migration regularities of fluid in coal beds. The main research direction include the occurrence state and migration mechanism of coal-rock gas, controlling factors of fluid co-production in coal reservoirs, and stereo development models of complex fluid systems in multiple (thin)reservoirs. (3)The key fundamental engineering issues are the mechanical characteristics and fracture propagation regularities of coal-rocks. The main research directions include the mechanical characteristics and fracturing mechanism of coal rocks, the interaction mechanism between coal rock and fracturing media, and the instability mechanism of coal reservoirs. The analysis of the above-mentioned major scientific issues and key research directions will provide important support for the efficient exploration and development of deep coal-rock gas, and lay the foundation for improving the geological theory of coal-rock gas with Chinese characteristics and coal measure whole petroleum system.

A great breakthrough has been made in the exploration and development of coalbed methane in Ordos Basin. To futher clarify the geological regularities governing deep coalbed methane enrichment, a systematic analysis was conducted on the hydrocarbon generation mechanism, hydrocarbon accumulation evolution, lithological assemblages, and differential migration-accumulation characteristics of the No.8 coal seam of Carboniferous Benxi Formation. Moreover, the exploration prospects of coalbed methane and favorable areas for next hydrocarbon exploration were also pointed out. The results show as follows. (1)The No.8 coal seam of Benxi Formation is mainly deposited in swamps covered with mixed vegetation and water, and has been stably developed in the basin. It exhibits the hydrocarbon generation and evolution characteristics of "high gas generation intensity and long duration", and lays a material foundation for coalbed methane accumulation. (2)Deep coal reservoirs are characterized with dumbbell-shaped pore size distribution, of which the reservoir spaces mainly consist of organic matter pores such as cell tissue pores and bubble pores, as well as a large number of well-developed cleavage-fracture networks. Micropores account for more than 60 % of the total porosity, and the pore size distribution is obviously affected by reservoir maturity. The study has clarified the four-stage evolution mechanism of coal reservoirs. (3)Deep coal reservoirs have abundant gas, with the average gas content of 21.7 m ³/t, and the free gas content of 24.48 % on average. The adsorbed gas occurs mainly in micropores, and free gas is stored in macropores and fractures. (4)The lithological assemblages control the three-dimensional differential migration and accumulation of coalbed methane. The coal-mudstone assemblage and the coal-limestone assemblage show good sealing properties, which are conducive to the in-situ retention and enrichment of coalbed methane. On this basis, the paper establishes a deep coalbed methane accumulation mode of "continuous hydrocarbon generation, source-reservoir-accumulation integration, three-dimensional hydrocarbon expulsion, and differential enrichment". Based on the geological characteristics of deep coalbed methane, three favorable exploration areas have been determined in the study area. Additionally, the paper establishes a comprehensive theoretical and technical system encompassing gas enrichment geological theory, geophysical exploration and prediction, full through-type fracture network fracturing technology, and efficient development of geological engineering, which lays a solid foundation for the effective utilization of deep coalbed methane. This understanding is expected to provide significant references for pioneering large-scale exploration and development of deep coalbed methane, promoting exploration breakthroughs in coal reservoirs of other basins in China, and leading the rapid development of the deep coalbed methane industry.

For the current deep shale reservoirs in southeastern Sichuan, the variables such as geostress magnitude, orientation and structure are complex and changeable, and their changing laws are still unclear, thus severely restricting the deployment, implementation, and production efficiency of shale gas exploration and development. This study targets at Longmaxi Formation in key blocks of southeastern Sichuan Basin. Based on the core analyses and the multi-source and multi-dimensional stress responses data from wells, as well as geomechanical analyses and numerical simulations, the study identifies the key geological processes causing geostress disturbances, reveals the mechanical mechanisms and patterns of stress variations and further clarifies their impacts on shale gas enrichment and high production. Results indicate that the southeastern Sichuan Basin can be divided into five regions according to the current geostress, and the stress machanism is mainly presented as strike-slip stress regime. However, in complex marginal zones, the stress mechanism transitions from reverse faulting at shallow depths to strike-slip or normal faulting at greater depths. Folds and faults are identified as the critical external factors causing stress field deflections. Above the neutral surface of the folds at the first and second submembers of Member 1 of Longmaxi Formation, the stress orientation deflects along the fold axis, with the deflection angle controlled by the mechanical properties and deformation intensity of the rock layers, and stress magnitudes decrease. Below the neutral surface, the opposite trend from stress magnitudes and orientation is observed. Moreover, the stress orientation deflects along the fault strike as the distance from the fault decreases, with the stress magnitude decreasing and the differential stress between principal directions increasing. Pore pressure variations mainly influence the minimum horizontal principal stress, with the deflection angles reaching up to 35°. Vertically, as influenced by lithological disturbances, stress values are low for siliceous shales from Wufeng Formation to the first sub-layer of the third submember of Member 1 of Longmaxi Formation, and these weak-stress layers are favorable for fracturing. Comprehensive analysis suggests that below the neutral surface, syncline zones or areas near low-level (Grade Ⅳ or below)NE-trending faults exhibit good fracture sealing and high gas content. The tensile stress disturbance areas exhibit low stress magnitudes and small differential stresses, facilitating the formation of complex fracture networks with high fracture heights and high production rates. These areas are highlighted as priority zones for future shale gas exploration and development. The research results are expected to provide important insights and guidance for the accurate evaluation of geostress fields and optimal selection of sweet spots in deep and structurally complex shale reservoirs.

The research of Whole Petroleum System (WPS) theory, emerging as a frontier field in the petroleum and natural gas geology at present, has attracted extensive attention from both the petroleum industry and academic community since its proposal. Expanding beyond the traditional concepts of petroleum systems, the research of WPS theory involves the geological regularities and resource development of unconventional oil and gas, representing an evolution and development of the petroleum system theory. This paper elucidates the fundamental principles of WPS theory, and summarizes the research progress during its development, including:(1) research advances and exploration practices of the Permian WPS in Junggar Basin; (2) the differential enrichment in the sequential distribution pattern of conventional and unconventional oil and gas, as well as the hydrocarbon accumulation and enrichment mechanism controlled by "source-reservoir coupling"; (3) hydrocarbon migration models in WPS; (4) analysis of WPS in sedimentary basins with the development of multiple sets of source rocks; (5) research and development of the new-generation basin modeling technology and genesis-based hydrocarbon resource appraisal methods on the basis of WPS theory.

Intelligent drill bits are one of the core components of future intelligent drilling systems. By integrating sensors capable of stable performance under high-temperature and high-pressure conditions, adaptive control algorithms, and optimized drill bit structures, these advanced drill bits enable real-time downhole condition monitoring, dynamic adjustment, and precise execution, thereby improving drilling efficiency. As oil and gas exploration expands to ultra-deep formations and complex, unconventional reservoirs, drill bits face increasingly harsh geological conditions. Traditional drill bits, under high-temperature and high-pressure environments and complex geological settings, suffer from challenges such as rapid wear, short service life, and high drilling costs that urgently demand the development and application of high-performance drilling technology. This further highlights the importance of intelligent drill bits as a pivotal future direction for improving drilling speed and efficiency. By systematically summarizing and analyzing the current research, core technologies, and product advancements in intelligent drill bits, such as multi-parameter sensing technology capable of withstanding extreme downhole environments, machine learning- and deep learning-based adaptive control algorithms, and progress in drill bit structure and control mechanisms, this work reveals the potential of intelligent drill bits in modern drilling operations. Typical case studies from both domestic and international projects demonstrate the advantages of intelligent drill bits in enhancing rate of penetration, extending bit life, and reducing unplanned downtime. Looking ahead, research on intelligent drill bits will move toward higher autonomy, broader adaptability, and deeper integration with digital platforms. They are poised to play an even greater role within the intelligent drilling technology framework.

Marine carbonate rocks are an important part of onshore oil-gas exploration in China. A series of exploration breakthroughs have been made in recent years, which play an important role in ensuring energy security. Based on the recent achievements of petroleum exploration in the three craton basins of China, this paper systematically reviews the latest advances in the theory and technology of marine petroleum accumulation in China, and forms the following understandings and advances. (1)Significant achievements have been made in marine oil and gas exploration in three major cratons. For example, two ultra-deep fault-controlled giant oil-gas fields with 1 billion tons of geological reserves have been discovered in in Fuman and Shunbei areas of Tarim Basin, the trillion cubic meters of large gas field has been initially established in the northern slope of central Sichuan Basin, and several new exploration zones have been discovered in the dolomites from the Ordovician pre-salt submember 6 of Member 5 of Majiagou Formation to Member 4 of Majiagou Formation in Ordos Basin. (2)A series of important advances have been made in reservoir prediction and reservoir tracing. For example, the study of Mg isotope tracing dolomitization process has promoted the development of genetic mechanism analysis of dolomite. By analyzing the spatial characteristics and retention mechanism of carbonate reservoirs such as deep fault solution, it is clear that the lower limit of exploration depth of carbonate cavern reservoir is far beyond the drilling depth. Advances in fault solution characterization, reef bank characterization, reservoir transparency and constant volume characterization have promoted efficient exploration and significantly improved drilling success. (3)Remarkable progress has been made in hydrocarbon accumulation process and fluid tracing. For example, technological innovations such as light hydrocarbons, isotopes and biomarkers have been used to improve the effectiveness of hydrocarbon source correlation. Important progress has been made in the dating techniques of accumulation with various methods, which can effectively guide the determination of favorable accumulation areas. With the development of hydrocarbon reservoir evolution and reconstruction technology, the marine carbonate reservoir formation process under complex tectonic background has been transformed from qualitative analysis to quantitative study. (4)By systematically analyzeing the accumulation law and main controlling factors of marine carbonate oil and gas in China, it is clear that marine oil and gas reservoirs in China are characterized by large area distribution, large amplitude of oil and gas column, high production well controlled by source rock and large-scale reservoir, oil and gas richment controlled by strike-slip fault, and ultra-long life of hydrocarbon reservoirs. (5)The deep and ultra-deep resource potential of marine basins in China is huge, with the potential development of 5 trillion cubic meter gas fields and 1 billion-ton oilfield. The development of marine oil and gas theory enriches the accumulation theory of small craton basins, promotes the progress of petroleum geology theory, and plays an important role in the practice of oil and gas exploration.

Continental shale oil reservoirs in China are characterized with abundant clay minerals, well-developed laminae, and complex and diverse lithologies. The crude oil is accumulated in organic pores, inorganic pores, and bedding fractures, featuring multi-scale distributions. Therefore, it is very difficult to accurately characterize the flow mechanism of shale oil reservoirs and precisely predict their apparent permeability. Based on the nano-confinement effects and different flow boundary conditions, flow velocity equations were derived for organic pores, inorganic pores, and micro-fractures. Meanwhile, considering the distribution characteristics and arrangement-combination patterns of pores and fractures, a comprehensive apparent permeability prediction model for the fractured continental shale reservoirs was established. Taking the Jiyang depression shale oil reservoir as a case study, a systematical analysis was conducted on the effects of pore-fracture combination patterns, total organic carbon (TOC)content, nano-confinement effects, and fracture distribution characteristics on the apparent permeability of shale reservoirs. The results show that in continental shale oil, the low-velocity nonlinear flow behavior is mainly controlled by the liquid-solid interfacial slippage effects and adsorption boundary layer effects. The slippage effects in organic pores help increase the flow velocity, whereas the adsorption boundary layer effects in inorganic pores play a role in flow inhibition. The arrangement patterns of pores and fractures exert significant influences on the apparent permeability, with particularly pronounced nonlinear characteristics observed in serial arrangement, indicating the great impact of TOC content on flow behavior. Furthermore, under low-pressure gradient conditions, macropores such as inorganic pores and micro-fractures are the main flow channels, and the apparent permeability of micro-fractures increases nonlinearly with the increase in fracture density. The increase in fracture aperture significantly enhances its permeability, especially in laminated shale reservoirs.

With the continuous advancement of oil and gas exploration, the reserves of medium-shallow reservoirs are gradually decreasing, as a result of which deep-layer oil and gas development has become a critical strategic direction for China’s energy succession. However, deep drilling operations are subjected to the high-temperature and ultra-high-temperature environments, which can induce failures in drilling fluids, drilling tools, and logging-while-drilling equipment, thereby severely compromising operational safety and efficiency. To address the multiple challenges posed by high temperatures, wellbore cooling technology has emerged as a focal point in the research and development of deep drilling technologies. By lowering the borehole temperature, this technology can improve drilling fluid performance, ensure equipment stability and extend service life of critical components. This review summarizes latest advancements in the research of wellbore cooling, involving drilling fluid cooling technologies, wellbore thermal insulation techniques, and drill pipe thermal insulation technologies, and further systematically analyzes their working principles, application scenarios, cooling effects and mechanisms. Additionally, the challenges and future development directions of these technologies are explored in depth, aiming to provide technical references for safe and efficient deep drilling operations and support the sustainable development of deep oil and gas resources.

Oil and gas resources are abundant in the southern margin of Junggar Basin with multi-layered geological structures and complicated and variable structural styles, which features the most complex petroleum geological conditions and the most tortuous exploration history. In recent years, with the improvement of the geological theories, the progress of seismic and drilling technologies, and the shift of exploration strategies for hydrocarbon exploration of ultra-deep clastic rocks in the foreland at the southern margin of Junggar Basin, a large gas area of ultra-deep clastic rocks has been discovered in the middle section of the southern margin of Junggar Basin. Exploration practices and researches show as follows. (1)Five sets of source rocks, i.e., the Permian, Triassic, Jurassic, Cretaceous, and Paleogene, are developed in the southern margin of Junggar Basin. Among them, the Jurassic and Permian as the main source rocks have entered the stage of large-scale gas generation and possess the material basis for the formation of large and medium-sized gas fields. (2)The lower assemblage has developed multiple sets of large-scale reservoirs such as the Cretaceous Qingshuihe Formation, and the Jurassic Kalazha Formation, Toutunhe Formation, Sangonghe Formation, and Badaowan Formation. The superimposition of pore-type and multi-scale fracture-type reservoirs forms a large-span fracture body, providing reservoir conditions for high natural gas production. (3)The regional thick quilt-like ultra-high pressure mudstone caprock of the Cretaceous Tugulu Group has good preservation conditions, which is the key to natural gas accumulation. (4)The large-scale anticlinal structural trap group distributed in rows has developed in a belt-like pattern. According to the superposition pattern of structures, the southern margin of Junggar Basin can be divided into three rows of tectonic belts (thrust belt, detachment fold belt and frontal slope belt), including seven structural belts (buried structural belt, Dongwan structural belt, Wuchang transfer belt, Huomatu structural belt, Du’an structural belt, Hutubi structural belt and Fangcaohu structural belt). It is clear that Dongwan structural belt, Hutubi structural belt, Wuchang transfer belt and buried structural belts are most favorable anticlines for natural gas preservation. During exploration of the southern margin of Junggar Basin, a sequence of techniques such as high-precision seismic acquisition, full-depth modeling and migration imaging, and fine description of traps for the "double complex" structures (complex surface and subsurface structures)in the ultra-deep piedmont has been established, as well as the key supporting technologies involving fine evaluation of ultra-deep, ultra-high pressure and ultra-high temperature clastic rock reservoirs, optimal fast drilling and completion, and safety testing. The breakthrough of natural gas exploration in the middle section of the southern margin of Junggar Basin has effectively promoted the exploration and development of natural gas in ultra-deep clastic rocks, thus enriching the petroleum geological theories of continental ultra-deep clastic rocks.

The ultra-deep Mesozoic volcanic trap group in the surrounding area of Bozhong sag has great exploration potential for forming large and medium-scale volcanic oi-gas reservoirs. In recent years, both Well BZ8-3S-A and Well BZ8-3S-B deployed in the Bozhong8-3 South structure in the southwest low uplift zone of the sag have achieved high-yield oil-gas flow from volcanic reservoirs. This breakthrough marks the new exploration progress of large and medium-scale volcanic hydrocarbon reservoirs in the deep subsags of Bohai Sea. Based on the analysis of the core, thin section and source rock, in combination with well logging and seismic interpretation data, the paper systematically investigates the formation conditions and accumulation characteristics of large-scale volcanic oil-gas reservoirs in Bozhong sag, and also explores the seismic prediction methods of favorable volcanic reservoirs. The Mesozoic Yixian Formation volcanic rocks in Bohai Sea consist of 4 eruption cycles, and the large-scale acidic volcanic reservoir represented by the Bozhong8-3 South structure are mainly constructed by the third eruption cycle. The Bozhong8-3 South structure exhibits favorable hydrocarbon accumulation conditions as below. (1) The Mesozoic volcanic buried-hill reservoir is adjacent to three sets of high-quality Paleogene source rocks in the Member 1 and 3 of Shahejie Formation and Dongying Formation, which provide superior oil-gas supply conditions. (2) Four laterally stacked large acid volcanic edifices suffer from the strong superimposed transformation of weathering, tectonic activities and fluid flows, forming large-scale volcanic rock reservoirs. (3) There is a multi-dimensional hydrocarbon charging mode based on the combination of the lateral direct source-reservoir contact and unconformity migration, and the source rock formations with an overpressure coefficient of 1.5 to 1.8 can not only provide sufficient hydrocarbon migration driving force, but also enhance the sealing capacity of the mudstone overlying volcanic rocks. (4) The Bozhong8-3 South structure develops massive condensate-rich gas reservoirs with large gas-bearing formation thickness, high gas column height, high temperature and high pressure, late to ultra-late accumulation. Through the analysis of the seismic response characteristics of the drilled wells, the maximum amplitude and arc length attributes were optimized to predict the distribution patterns of weathering crust. Additionally, the multi-attribute cluster analysis was applied to predict reservoir development zones. On this basis, a seismic prediction technology was established for large-scale favorable volcanic reservoirs in the Bozhong8-3 South structure. The research methods and understandings are of important significance for guiding the exploration of ultra-deep volcanic reservoirs in Bohai Sea.

The cumulative hydrocarbon production in the oilfields in the eastern South China Sea has achieved nearly 400 million tons of oil equivalent over the years, making outstanding contributions to China’s energy security and economic construction. However, after more than 40 years of exploration and development, the remaining potential of conventional oil and gas is exhausted, and the deep oil and gas have become strategic replacements for guaranteeing sustainable reserves and production. This study focuses on the key issues encountered by oil and gas exploration in deep formations, such as basin formation, hydrocarbon generation, reservoir formation, and hydrocarbon accumulation. Using three-dimensional seismic, drilling data, and core analysis results, the hydrocarbon accumulation conditions in deep to ultra-deep reservoirs were systematically investigated from multiple perspectives, including the formation mechanism of hydrocarbon-rich sags/subsags, development mechanism of effective reservoirs, and hydrocarbon enrichment patterns. This provides new geological insights as below. (1)The composite continental-margin magmatic arcs control the formation and evolution of large lake basins. (2)Potassium-rich fluid transformation controls the development of effective reservoirs. (3)Seal and migration mechanism of transtensional fault systems controls hydrocarbon migration, accumulation, and enrichment. These findings guided the integrated evaluation and cluster drilling of the Huizhou 19-6 structure, leading to the discovery of billion-ton-scale oilfield in deep to ultra-deep clastic formations in China’s offshore area. The discovery of the Huizhou 19-6 structural oilfield further reveals that deep oil and gas of the Pearl River Mouth Basin are important replacements for the future growth of hydrocarbon reserves and production, demonstrating the huge exploration potential of deep to ultra-deep reservoirs in the offshore high-geothermal, highly tectonically active composite continental-margin basins, which provides important reference and inspiration for the exploration of petroliferous basins with similar structural settings.

Xihu sag in the East China Sea Basin is the largest hydrocarbon-bearing sag in China's offshore area, and is also one of the main battlefields for offshore natural gas exploration and development in China. In the past five years, based on the "positive rhythm channel sand dessert" seismic prediction while drilling monitoring technology, "permeability classification-dessert thickness ratio" high-efficiency well type design and productivity evaluation technology, and oil-based mud long open hole productivity release technology, the geological-engineering integration technology system innovation and effective practice have been carried out. Xihu sag has obtained commercial gas flow in many low-ultra-low permeability fields, showing good potential for low-ultra-low permeability natural gas storage and production. Based on the analysis of core, mud logging, logging, seismic and other geological data and the exploration and development practice of typical gas reservoirs, the accumulation characteristics and resource potential of low permeability and ultra-low permeability natural gas reservoirs in Xihu sag are systematically analyzed. The Eocene Pinghu Formation in the Xihu sag develops two types of source rocks:the delta-tidal flat facies coal measure source rock in the slope zone and the tidal flat-lagoon facies sapropelic humic source rock in the sag area, showing a full-sag distribution pattern. The tidal flat sedimentary system of Pinghu Formation has the near-source enrichment conditions of natural gas with "self-generation, self-storage and self-cover", and the natural gas accumulation conditions are superior. Controlled by the structural pattern of "east-west zoning and north-south block", three new models of differential enrichment of natural gas are developed in the central anticline belt of Xihu sag. The lithologic oil and gas reservoirs of Pinghu Formation in the western slope zone have the oil and gas distribution law of "vertical superposition and horizontal connection". The large-scale structural traps in the north of the central anticline belt, the lithologic traps in the wing of the central and southern anticlines, the deep Pinghu Formation in the south and the near-sag areas in the western slope belt are the key exploration directions for the low-permeability and ultra-low-permeability gas reservoirs in Xihu sag. The natural gas resources exceed 500 billion cubic meters.

In the study of enhanced oil recovery (EOR)in reservoirs, conventional simulation methods typically use core flooding techniques as evaluation tools. However, the inability to directly observe the internal flow process within the core makes it difficult to clarify the microscopic oil displacement characteristics at the pore scale, thereby limiting the in-depth investigation of the mechanism of efficient reservoir exploitation. This paper reviews the current flow visualization technologies for investigating microscopic mechanisms in reservoirs, and elaborates on the fabrication methods and application scopes of various models. The quartz-glass microscopic flow model, which enables micron-scale pore simulation and possesses the advantages of high-temperature and high-pressure resistance, has become the preferred method for visualizing microscopic flow in reservoirs. Additionally, the paper summarizes the applications of the model in various types of tertiary oil recovery technologies, such as gas flooding and chemical flooding tertiary oil recovery. To simulate real reservoir environments and meet the demands for studying the micro- and nano-scale flow mechanisms of oil reservoirs, future improvements in the quartz-glass microscopic flow model are proposed from three perspectives:external coordination and configuration, in-situ pore wall property restoration (including clay minerals and wettability), and dual upgrades in terms of scale and dimension.

China has achieved major breakthroughs in the exploration of deep coal-rock gas, marking a strategic shift from traditional shallow coalbed methane to deep coal-rock gas. As a high-quality source rock, coal-rock is characterized by high organic matter abundance, continuous gas generation throughout its entire evolution process, and strong storage capacity, which is conducive to the formation of coal-rock gas reservoir where adsorbed and free gases coexist. Based on the new theory of "whole petroleum system of coal measures", this paper reveals the accumulation mechanism and resource potential of coal-rock gas. The preliminary evaluations indicate that the deep coal-rock gas resources with a burial depth greater than 1 500 meters exceed 100×10 ¹²m ³ in China, approximately twice that of conventional natural gas resources, providing a resource foundation for the formation of super-large gas fields. In Daji block of Ordos Basin, large-scale development has been achieved through the application of horizontal well and volumetric fracturing technologies, with an average daily production of 12×10 ⁴m ³ per well and cumulative proven reserves of 1 452×10 ⁸m ³, demonstrating promising development prospects. At present, China has established a series of key technological systems, including experimental testing, optimized drilling and completion, fracturing stimulation, and volume development, which support the efficient extraction of coal-rock gas. However, challenges still exist in coal-rock gas development, such as incomplete theoretical system, unclear sedimentary evolution mechanisms, and insufficient research on accumulation mechanisms. To address these issues, it is suggested to systematically conduct nationwide resource assessments, strengthen exploration in key areas, optimize mining right management, and promote theoretical innovation and demonstration applications. These efforts will provide strategic support for increasing natural gas reserves and production and enhancing China’s energy self-sufficiency capacity.

The Permian Fengcheng Formation in the Well Pen-1 West sag of Junggar Basin is one of the key strata for natural gas exploration. Previous source-proximal exploration led to occasional modest-scale breakthroughs. In 2023, the Well WT1 deployed in the Mosuwan uplift achieved high-yield industrial gas flow, thus confirming the exploration potential of Fengcheng Formation. This provides a basis for identifying new gas replacement plays, and is of great theoretical and practical significance. To further advance exploration, a study was carried out to investigate the gas accumulation elements and mechanisms using high-precision seismic data and exploration drilling results from multiple wells. The study shows as follows. (1) Glutenite reservoirs are developed in Member 3 of Fengcheng Formation in the source-proximal uplift area of the Well Pen-1 West sag. In the in-source slope area, the Member 2 and Member 1 of Fengcheng Formation are developed. The Member 2 of Fengcheng Formation is primarily composed of mudstone, as the primary hydrocarbon source rock, and the Member 1 of Fengcheng Formation is dominated by lowstand sandstone and dolomitic sandstone. (2) In the in-source slope area of the Well Pen-1 West sag, Fengcheng Formation develops retrogradational braided river delta sedimentary reservoirs, conventional stratigraphic-lithologic gas reservoirs in the source-proximal zone under the background of sedimentary overlap, and continuous tight sandstone gas reservoirs in the source rock. Exploration in the Well Pen-1 West sag has been extended into the in-source slope area, identifying a favorable exploration zone of exceeding 3 000 km ². With the natural gas resource potential exceeding 400 billion cubic meters, this area is expected to become one of the primary targets for natural gas exploration and development in Junggar Basin.

After more than 60 years of exploration, the Member 2 of Shahejie Formation in Zhanhua sag of Bohai Bay Basin, has formed an exploration situation of "widely containing oil and making breakthroughs in many aspects". At present, due to the Member 2 of Shahejie Formation developed in a transitional stage from rift to depression (rift-depression transition period), under the influence of complex basin structure, the sedimentary characteristics, main controlling factors, and exploration potential of beach- bars are still unclear. Based on geological data of drilling, logging and coring, the paper investigates the depositional features, sedimentary facies distribution patterns, controlling factors, and exploration potential of beach-bars in the Member 2 of Shahejie Formation of Zhanhua sag. The research results show as follows. (1)Three types of sedimentary facies, i.e., sandstone beach-bar, carbonate beach-bar, as well as mix beach-bar, have been identified in the Member 2 of Shahejie Formation. Vertically, the scale of all three beach-bar types gradually increases from the fourth sand group to the first sand group. Laterally, sandstone beach-bar facies are distributed near the lake shoreline, carbonate beach-bar facies are adjacet to the plunging structural belt in Bonan subsag, and the mix beach-bar facies are distributed across both the plunging structural belt and its flanks in Bonan subsag. (2)The development of beach-bar is mainly controlled by windfield, sediment source, and basin structure. Specifically, the windfield-controlled hydrodynamic zones of lake basin play a role in controlling the types, orientation and location of beach-bar. Sandstone beach-bar is developed in the breaker zone with the strongest hydrodynamic energy, while both carbonate and mix beach-bars are developed in the surfzone with strong water body energy. The sediment source influences the development scale and type of beach-bar. Large-scale sandstone beach-bar is developed in the area with sufficient provenance, while carbonate and mix beach-bars are developed in the area with poor provenance. The unique basin structure formed during the transition period has a controlling effect on the types and distributions of beach-bars. Sandstone, carbonate, and mix beach-bars are developed in structural high. (3)The Member 2 of Shahejie Formation reservoir exhibits high porosity and low permeability. The sand bodies with the layer thicknesses of 2 m to 6 m are favorable exploration targets in the study area. A total of 28 favorable sand bodies have been identified, and the favorable exploration area is predicted to be 300.24 km ². The research results are expected to provide a theoretical basis for oil and gas exploration under similar geological backgrounds.

Convective heating technology is one of the key feasible technologies in the in-situ retorting of oil shale. The use of steam as a heat-carrying fluid has been shown to have significant advantages in terms of technical process and economy. In deep high-stress environments, low-pressure high-temperature steam can be transformed into near/supercritical water. In this study, experiments were performed on oil shale pyrolysis through anhydrous conduction heating and near/supercritical water heating. Combined with micro-CT scanning, triaxial permeability tests, and uniaxial compression mechanical tests, an in-depth comparative study was conducted on the evolution of microscopic pore and fracture structures of oil shale as well as the macroscopic permeability and mechanical changes under different pyrolysis environments, thus explaining the differential mechanisms of macro and micro oil shale characteristics induced by different pyrolysis conditions. The porosity and fracture development degree of oil shale under near/supercritical water pyrolysis conditions are much higher than those under anhydrous pyrolysis condition, with the porosity differences of nearly ten times. The maximum crack width is increased from around 30 μm to about 150 μm under near/supercritical water conditions. The changes in minerals after near/supercritical water pyrolysis significantly affect the microscopic structure of oil shale, forming numerous micro-nano pores between the illite-smectite mixed layers. Under different stress and pore pressure conditions, the permeability achieved by anhydrous pyrolysis is below 0.04 mD, while the permeability under near/supercritical water conditions reaches 0.1-0.7 mD, differing by nearly 20 to 50 times. By contrast, supercritical water has stronger permeability, heat transfer capacity, solubility, and carrying capacity. In the supercritical water pyrolysis environment, oil shale forms numerous fractures along parallel beddings and interlaminar cross fractures connecting beddings, shown as more complex microscopic structures and smoother flow channels. The compressive strength of oil shale under near/supercritical water conditions is significantly lower than that in an anhydrous environment at the same temperature. The participation of near/supercritical water accelerates the decomposition of organic matter, causing oil shale to delaminate at a lower temperature. The results provide a theoretical basis for the convective heating exploitation of deep oil shale and other organic-rich rocks.