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 %.

The Member 6 of Triassic Yanchang Formation is one of the key contributors to the oil reserves and crude oil production in Ordos Basin, and it is also the earliest oil production reservoir in the continental areas of China. This study aims at revealing the formation mechanism and distribution pattern of tight oil in the Member 6 of Yanchang Formation. Based on analyzing the data of drilling, mud logging, well logging, and core samples from 1 505 prospecting wells in southeastern Ordos Basin, the paper systematically studies the formation mechanism and enrichment laws of tight oil in the Member 6 of Yanchang Formation, and presents three palaeo-geomorphic units, including steep and gentle paleoslopes, and paleolake bottoms, as well as more than ten types of secondary palaeo-geomorphic units. Based on the comprehensive analysis of palaeo-geomorphology and hydrocarbon accumulation conditions, in combination with the physical simulation experiments of crude oil migration and accumulation, four typical accumulation assemblages have been identified, i.e., the dual-source hydrocarbon supply with the medium to poor reservoirs at the end of distributary channels on gentle slopes, the single-source hydrocarbon supply with the poor to medium reservoirs under scattered gravity flow at the lake bottom, the dual-source hydrocarbon supply with the medium to good reservoir assemblages under gravity flow at the bottom of steep slopes, and the single-source hydrocarbon supply with the damaged and adjusted good to medium reservoirs on steep slopes. The genesis mechanism and accumulation process of tight oil reservoirs in delta front and gravity flow are revealed. Then it is clarified that the scale of high-quality reservoirs in near-source effective traps is the key to the enrichment and high yield of tight oil. Further, the paper proposes the differential distribution and accumulation mode of tight oil be controlled by the heterogeneous source-reservoir-cap assemblages under diverse paleogeomorphology setting, improves the hydrocarbon exploration strategies applied in typical oilfields, and puts forwards the unconventional oil exploration strategies such as the expanding exploration along the bottom of steep slopes, three-dimensional exploration at the lake bottom, detailed exploration of multiple wells in gentle slopes, and effective traps exploration in the structurally adjusted areas of steep slopes. Finally, the research focuses on exploring the four basic geological conditions for the formation of large-scale continental tight oil fields, i.e., tectonic action, provenance, paleo-geomorphic units, and preservation condition. In the Member 6 of Yanchang Formation in southeastern Ordos Basin, the cumulative geological reserves of tight oil amount to 1.885 522×10 ⁸t, the cumulative crude oil production in the past three years is 16.72×10 ⁴t, and the first 100 million-ton-level integrated tight oil field, i.e., Huangling oilfield, has been discovered and established. It is expected that the research results have a positive impact on the development of geological theories in terms of unconventional petroleum accumulation, as well as the exploration and development practices in the terrestrial lacustrine basin of China.

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.

Hybrid thermal-chemical recovery process is a typical follow-up technology applied in the later stage of steam recovery process in heavy oil reservoirs. During the hydrocarbon development process, the displacement and flow of the hybrid thermal system in porous media involve complex physical and chemical mechanisms, generally exhibiting highly non-isothermal and nonlinear laws, which is difficult to be characterized. Based on comprehensively considering the effect of the hybrid thermal system on reservoir rock and fluid properties, the paper establishes a non-isothermal phase field-controlled mathematical model for hybrid thermal-chemical recovery process in heavy oil reservoirs. Moreover, a regular porous media model and a porous media model reflecting the pore-throat characteristics of real rock samples have been constructed to simulate the displacement and flow characteristics of three different systems in porous media. The simulation results were validated against the results from microfluidic chip experiments. Focusing on the hybrid thermal recovery by CO ₂-chemical agent as a representative case, it was finally clarified the effects of injected fluid temperature, rock wettability, interfacial tension, and gas-liquid ratio on the displacement and flow laws during hybrid thermal-chemical recovery process. Results show that the oil-water emulsification effect is the most typical mechanism for hybrid thermal-chemical recovery process, which has a significant influence on displacement and flow characteristics in porous media. Compared to the thermal injection recovery, hybrid thermal-chemical recovery process can effectively activate oil films on pore walls and expand the swept area . Specifically, the total swept area for the hybrid thermal recovery using CO ₂-chemical agent is increased by approximately 12.5 % , and the average reservoir temperature is increased by nearly 15 ℃. The sweep efficiency of the hybrid thermal system can be significantly enhanced by increasing the injection temperature and gas-liquid ratio of the system while reducing contact angle and interfacial tension, among which the contact angle and interfacial tension have more significant effects.

A major breakthrough has been made in exploration of deep coalbed methane (CBM) in recent years, leading the CBM industry to enter its best period in history. However, the rapid expansion of the industrial scale still faces many problems and challenges. To promote the comprehensive upgrade of deep CBM exploration and development, implement the development strategies for large-scale CBM industry, guarantee energy security, and achieve the "dual carbon" target, a systematic analysis was conducted on the current status, theoretical and technical progress, industry upgrading strategy, and challenges in the deep CBM industry. The study suggests that the connotation of upgrading the deep CBM industry can be summarized in four aspects, i.e., theoretical and technical maturity, improved development efficiency, strong investor confidence, and rapid scale expansion. The basic conditions for industry upgrading include six aspects, i.e., policy support and guidance, technological innovation and breakthroughs, infrastructure construction and improvement, talent training and introduction, coordinated development of industrial chains, safe production and environmental protection. For deep CBM industry upgrading, the study proposes a "Eight-in-One" technological, economic, and management system integrating exploration and development, geology and engineering, theories and technologies, underground and ground surface, research and production, investment and profitability, big data and artificial intelligence, as well as strategy and tactics. By integrating exploration and development with geology and engineering, it is feasible to achieve an integration of theoretical research and technological innovation, promote the rapid transformation of scientific research achievements and their applications in production, improve the whole technological level, and enhance technological innovative ability. Through the integration of underground and ground surface development, the coordinated development of underground resources and ground facilities can be achieved to ensure safety operation and environmental protection throughout the entire process. By integrating investment efficiency, big data and artificial intelligence, resource allocation can be optimized and development costs are reduced. Through practical applications, the CBM exploration and development efficiency has been significantly improved; an operation mechanism has been formed through government organization under the leadship of enterprises. A set of coordinated and mutually supporting strategic development goals and corresponding strategies have been formulated and implemented, achieving remarkable effects. To achieve the goal of deep CBM industrial upgrading in the future, it is required to strengthen five aspects and implement three programs, i.e., to strengthen the technological innovation and R & D investment, cooperation and coordination between upstream and downstream of the industrial chain, safety and environmental protection management, international cooperation and exchange, as well as policy support and guidance; adhering to the implementation of "technological innovation as the main body, resource, technology, talent, policy and investment as a whole, as well as coordinated and innovative development" in a coordinated and cooperative manner, to effectively implement the "deep coal seam gas revolution" project, gradually implement the "Eight-in-One" strategic system, and promote industrial upgrading and development.

Hydrocarbon exploration has been carried out in the lower assemblage (P and F formations) of the western Bongor Basin for many years without breakthrough. Through in-depth studies of the hydrocarbon accumulation patterns in western Bongor Basin, Well D-2 was deployed and drilled by China National Petroleum Corporation in 2024; oil reservoirs were encountered during drilling in the lower assemblage of Bongor Basin, and the well production during well testing exceeded 200 tons per day, thus determining the exploration potential in the study area. To better summarize this discovery and guide further exploration, a systematic study, which is based on analysis of regional geological setting and exploration history, has been conducted on the tectonic evolution, stratigraphy, sedimentation, and source-reservoir-seal assemblages of the western Bongor Basin. On this basis, the hydrocarbon accumulation models and exploration deployment strategies have been clarified. The results show as follows. (1) The lower assemblage of Bongor Basin developed in the fault depression period. Thick lacustrine mudstones and near-source deltaic sand bodies were developed in the deep depression area, forming favorable lithological combinations. (2) The thick lacustrine mudstones of P and M formations, with high total organic carbon content and good organic matter type, have already entered into the oil generation window. They served as not only the excellent source rocks but also regional seals in western Bongor Basin. (3) Due to tectonic inversion, uplift and denudation during late stages, the deltaic sand bodies of P Formation had a certain porosity despite large burial depths, thus being considered as good reservoirs. The underlying buried hills experienced long-term structural fracture, weathering and denudation, and formed composite reservoirs with the sandstones of P Formation. (4) The Bongor Basin underwent multiple stages of tectonic evolution and inversion, leading to extensive fault development, which allowed oil and gas to migrate along the faults and accumulate in both upper and lower assemblages and buried hills. (5) Based on the characteristics of reservoirs in the lower assemblage, a comprehensive three-dimensional exploration deployment strategy was recommended to explore both shallow and deep formations, structural and non-structural traps, which can achieve breakthroughs in exploration of new strata and new fields. (6) The quartz sandstone above the basement is speculated to be a set of older formation than P Formation, and widely developed in western Bongor Basin, indicating good hydrocarbon accumulation conditions. The exploration breakthrough of Well D-2 has confirmed the resource potential in western Bongor Basin and exploited new reservoirs in Bongor Basin. Moreover, the three-dimensional exploration deployment strategy can provide guidance for oversea risk exploration in the future.

In 2023, a major breakthrough of hydrocarbon exploration had been made in Triassic Yanchang Formation of Hongde area, southwestern Ordos Basin, where Hongde oilfield was discovered with 100-million-ton crude oil reserves. To clarify the geological characteristics and accumulation conditions of Yanchang Formation in Hongde area, the factors and patterns of hydrocarbon accumulation were systematically sorted out by integrating core, well logging, 3D seismic and analytical test data. Moreover, the key technologies for hydrocarbon exploration and development were summarized. The research results show that the braided river delta plain subfacies with distributary channel sand bodies are developed in the Member 8 of Yanchang Formation (Chang 8) in Hongde area, where the reservoirs have large thickness and good physical properties, demonstrating excellent conditions for oil accumulation. The source rock in the Member 7 of Yanchang Formation (Chang 7) in Hongde area is characterized with thin layer, and its total organic carbon (TOC) content is 1.16 % on average, thus indicating a low potential for supplying hydrocarbons. The crude oil in Chang 8 of Hongde area is mainly originated from the high-quality source rock of Chang 7 near the center of lake basin in the eastern part of Ordos Basin. The oil migrates laterally through the three-dimensional transport system composed of faults, fractures and high-quality reservoir sandbodies developed in Yanshanian period, and accumulates in the high parts of paleo-structures. Horizontally, the structural and structural-lithologic reservoirs developed in the west of Hongde area are characterized with the hydrocarbon accumulation mode of "lateral migration and accumulation, reservoirs controlled by fault and uplift, and enrichment characteristics controlled by physical properties of reservoirs". In contrast, the large scale of lithologic reservoirs are developed in the east of Hongde area, with the characteristic of being close to source rocks. During the petroleum exploration and development in Hongde area, the study establishes a series of key technologies focusing on 3D seismic processing and interpretation of depth migration, evaluation of reservoir fluid properties based on the integration of well logging and mud logging, and fracturing transformation for fracture controlling and reservoir stimulation. Those technologies have provided strong supports for new oil and gas discoveries. The breakthrough of Hongde oilfield proves that the area far from the oil source of Tianhuan depression still has the potential for large-scale accumulation. The western margin of Ordos Basin is expected to further implement the petroleum geological reserves of more than 2×10 ⁸t, which is a key field for expanding the extra-source oil and gas exploration.

Sanmenxia Basin is a Mesozoic-Cenozoic fault basin located on the western Henan uplift in the southern margin of the North China block. No petroleum resources and effective source rocks were discovered during previous exploration activities. In recent years, non-profit oil and gas surveys have confirmed the presence of the Paleogene source rocks in the southern margin of the basin and have gained new insights into oil and gas accumulation. To verify the hydrocarbon potential of the basin, Well Yuxiadi 1 was drilled at Hanguguan structural belt. Drilling data of Paleogene Xiao’an Formation reveal that the porosity ranges from 13.43 % to 20.60 %, and the permeability varies from 35.1 mD to 215.5 mD. The drill stem test (DST) results of the lower oil layer of Xiaoan Formation demonstrate a wellhead oil production of 17.52 m ³ under 24-hour intermittent flow conditions (water-free). Through formation testing by layer, combined with mechanical pumping production, the upper, middle, and lower oil layers of Xiaoan Formation have achieved the stable daily oil production of 4.79 m ³, 6.79 m ³, and 15.83 m ³ (water-free), respectively. These results indicate that the Hanguguan structural belt develops the water-free wax-bearing light oil reservoirs characterized with medium-high temperature, medium porosity, medium permeability, medium-shallow depth, and normal pressure. A comprehensive research shows that the oil source of Well Yuxiadi 1 may be derived from the lower Member of Xiaoan Formation and the upper Member of Podi Formation, the mudstone in Liulinhe Formation and its overlying strata serve as regional cap rocks, and normal faults act as the primary hydrocarbon transportation system. Sanmenxia Basin develops four sets of potential source-reservoir-cap assemblages, and it is inferred that its hydrocarbons have the characteristics of "short-distance migration, multiple hydrocarbon accumulation types, and forming reservoir in late stage", and the main accumulation stage is in the Himalayan period. The oil and gas breakthrough in Sanmenxia Basin signifies the emergence of a new petroliferous basin, which is expected to re-attract attention from the industry on medium- to small-sized basins, such as Southern North China Basin and Weihe Basin. This is of certain reference value and guiding significance to the exploration of oil and gas resources in these basins.

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.

In the context of "carbon peaking and carbon neutrality", ammonia has zero-carbon energy properties as well as easier storage and transportation, higher energy density, higher safety and more complete infrastructure than hydrogen. Coupled with advances in ammonia production, storage and transportation and application technologies, as well as its economic competitiveness in the whole industry chain, various countries have been attracted to the development and utilization of ammonia as an energy source. China National Petroleum Corporation (CNPC)possesses complete ammonia synthesis technologies as well as relevant storage and transportation facilities, and has the fundamental advantages in both ammonia production by renewable energy and application of ammonia fuel in the marine field. A deep analysis was performed on CNPC’s development pathways for the production of blue and green ammonia in the upstream sectors, the low-cost ammonia storage and transportation in the midstream sectors as well as the application pathways for ammonia in the downstream sectors as hydrogen carrier, fuel for combustion and raw materials for ammonia cells. It is proposed that there are three development stages for CNPC’s ammonia energy industry:(1)strategic planning during 2024-2025; (2)steady progress during 2026-2035; (3)large-scale development during 2036-2050. CNPC will explore three major businesses, i.e., ammonia production, ammonia storage and transportation and ammonia energy application. It will focus on five key technologies:(1)energy-saving blue ammonia production process technology; (2)flexible ammonia synthesis technology based on renewable energy; (3)low-temperature and low-pressure ammonia decomposition for hydrogen production; (4)key technology for ammonia combustion; (5)key technology for ammonia fuel cells. In addition, it will also build five demonstration projects:(1)industrialization demonstration of blue ammonia production; (2)industrialization demonstration of renewable energy electrolysis for hydrogen production followed by low-temperature and low-pressure ammonia synthesis; (3)industrialization demonstration of 10 000-ton ammonia decomposition for hydrogen production; (4)industrialization demonstration of heavy oil thermal recovery with ammonia-assisted combustion; (5)industrialization demonstration for co-generation of heat and power by ammonia fuel cell. Realizing high-quality development of the ammonia energy industry can contribute petroleum resources to the construction of China’s new energy system.

Significant breakthroughs have been made in exploration of deep coalbed methane (CBM) in China, demonstrating promising prospects for future development. However, due to the complex geological conditions and the high difficulty in CBM development, the existing basic theoretical researches cannot fully explain the deep-seated issues such as the enrichment mechanism and development prospects of CBM. The research progress of global CBM exploration and development shows that the enrichment and accumulation conditions for CBM in deep reservoirs are superior to those in shallow layers. However, the deepening research on deep CBM faces a series of challenges, including multiple genetic types with unclear genetic relationship, undetermined mechanism and key controlling factors of deep CBM accumulation, lack of discrimination criteria for enrichment modes and critical accumulation conditions of CBM, difficulties in predicting and evaluating high-yield sweet spots and fully applying the exploration experience of deep CBM in the eastern Ordos Basin to other regions. To solve the problems, the Whole Petroleum System (WPS) theory and the hydrocarbon accumulation model with dynamic field are introduced to expound the differences, correlations, and united symbiotic relationships between conventional and unconventional coal-formed gas reservoirs in petroliferous basin, in an attempt to provide new theoretical and methodological guidance for the prediction and evaluation of high-yield and rich CBM areas. The preliminary research results on CBM in major petroliferous basins of China indicate that during the evolution process of the Coalbed Whole Petroleum System (CWPS), the free hydrocarbon dynamic field is conducive to the enrichment and accumulation of CBM in an adsorbed state, whereas the confined hydrocarbon dynamic field is conducive to the enrichment of free gas in coal seams. In the free hydrocarbon dynamic field of coal seams, the amount of adsorbed gases increased with the increasing of burial depth and decreased after reaching a peak, while the free gas content has begun to increase. In the confined hydrocarbon dynamic field, the amount of gas trapped in coal seams in a free state continues to increase with the increasing of burial depth, and then decreases until it tends to disappear after reaching its peak. Vertically, the lower part of the free hydrocarbon dynamic field and the upper part of the confined hydrocarbon dynamic field (organic matter accumulation degree ranges from 0.50 % to 2.75 % ) are most favorable for multiphase enrichment and high production of CBM. The buried depths of the high heat flow basins of the eastern China, medium heat flow basins of the central China, and low heat flow basins of the western China are from 1 000 m to 3 600 m, 1 500 m to 7 500 m, and 3 000 m to 8 500 m, respectively. In these favorable fields, the total amount of coal resources is about 80 596×10 ⁸t, and the in-situ and recoverable resources of CBM are 115.91×10 ¹²m ³ and 56.5×10 ¹²m ³ respectively, showing broad prospects for development.

Coupled thermo-hydro-mechanical flows in complex fractured rock occur widely in unconventional and deep reservoir development scenarios. Coupled simulations of complex fracture networks will produce huge computational cost. Parallel computing technology is the effective method to achieve high-resolution simulations of complex discrete fractures. In this paper, massively parallel numerical simulation technology for thermo-hydro-mechanical coupling using general embedded discrete fracture model on unstructured grids is introduced. Firstly, a parallel solution of embedded discrete fracture model is achieved based on the domain decomposition method; and the way to decompose two independent matrix and fracture systems is introduced for unstructured grids. the existing embedded discrete fracture model by using two independent matrix and facture grid systems, and this approach significantly enhance the simulation ability of the EDFM for a complex 3D discrete fractures system. Secondly, for the thermo-hydro-mechanical coupling problem, the finite volume method is adopted to discretize compositional flow, heat transform and poro-mechanical equations uniformly, a parallel sequential implicit method is employed to solve the nonlinear coupling problem. Finally, this simulator is validated against two analytical model, and it is used for a multi-layer shale gas reservoir three-dimensional simulation and a deep high-temperature fractured reservoir simulation, and the parallel computational performance and scalability are analyzed at different parallel scales. The proposed methods can achieve high-resolution simulations of discrete fracture networks in practical engineering, and we obtain a great parallel performance and scalability at different scales, this simulator can be an efficient tool for the design and analysis of energy development in fractured rocks.

Wushi oilfield is a Cenozoic complex fault block oilfield developed in the eastern part of Wushi sag in Beibuwan Basin. It is also the third largest oil production base in the western part of the South China Sea, with the total proven reserves of 100 million tons and daily production of more than 1 000 m ³. By reviewing the exploration and development history of Wushi oilfield, this paper systematically summarizes the geological conditions and characteristics for hydrocarbon accumulation, and key exploration and development technologies of the oilfield. On this basis, the following achievements and understandings are obtained. (1)The organic-rich lacustrine shale and oil shale of Liushagang Formation, which are widely distributed in the eastern part of Wushi sag, have laid a good material foundation for the formation of oil field. (2)Owing to the multi-source, multi-period and multi-stage tectonic-sedimentary evolution, many sets of favorable reservoir-cap assemblages are formed in the sag. (3)Several sets of regional stable mudstone caprocks were developed in the whole area during the lacustrine transgression period, providing favorable conditions for oil and gas preservation. (4)Multi-level oil source faults, sand body, structural ridges and unconformity surface constitute favorable hydrocarbon migration pathways. (5)Based on the dynamic and static accumulation factors, three typical hydrocarbon accumultion patterns are clarified in Wushi oilfield, including the lateral step-type in slope zone, three-dimensional composite type in uplift zone of the sag, and pumping type with fault-sand coupling in steep slope zone. (6)A series of supporting technologies with a focus on the high-resolution seismic data acquisition and processing technology, fine interpretation and evaluation technology for complex fault blocks, fine carving technology for large-scale reservoirs, and water flooding compatibility evaluation technology for offshore waterflooding oil fields have been established, which provide a technical guarantee for efficient exploration and production as well as capacity construction in Wushi oilfield. The research results are expected to provide some guidance and reference for the exploration and development of similar reservoirs in other basins at home and abroad.

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.

In the drilling process of deepwater and deep oil and gas, there is a high demand for real-time calculation of the wellbore temperature field. Therefore, a high-precision and high-efficiency wellbore temperature field solution method is the key to accurately calculate fluid properties and precisely guarantee the safety of wellbore flow. In this study, a wellbore temperature field model is embedded into the neural network in the form of loss function, and the optimization method of self-adaptive weight and self-adaptive learning rate is used to improve the training efficiency. Further, the paper establishes a method for solving the wellbore temperature field driven by physical information neural network, and analyzes the transient changes in wellbore temperature during drilling and gas well testing. The results show that during drilling, the average errors of drill pipe temperature and annular temperature are 0.847 % and 0.725 % , respectively, and those of bottom hole temperature and wellhead temperature are 0.162 % and 1.047 % , respectively, from which it can be seen that the computational efficiency is improved by about 150 times when compared with the finite difference algorithm. Compared with the field measurments, the average errors of the predicted solution driven by the physical information neutral network and the finite difference numerical solution are 2.16 % and 2.27 % , respectively, and the model accuracy can be improved by avoiding the truncation errors in partial differential equations. During the gas well testing for two days, the inferred time for the risk of natural gas hydrate formation is 0.728 1 s, and this method can be applied to quickly predict the hydrate formation areas. In conclusion, the proposed solution method can not only ensure the calculation accuracy, but also significantly improve the computational speed.

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.

The flow field and pressure field of low-permeability reservoirs are changed by dynamic fractures, significantly affecting the swept volume of water flooding. Comprehensively using the data of imaging logging, core analysis, rock mechanics experiments, production performance, and dynamic monitoring, the paper analyzes the characteristics and controlling factors of dynamic fractures in four typical ultra-low permeability reservoirs in the Ordos Basin, including Jing’an, Ansai, Xifeng, and Huaqing. Based on their geneses, dynamic fractures can be classified into two types, i.e., being formed by exceeding the rock formation’s fracture pressure and activated by natural fractures. According to impacts on the water cut of oil wells, they can be divided into unidirectional and multidirectional dynamic fractures. The evolution of dynamic fractures undergoes four stages:rapid growth to a certain scale, a fixed length, and a maximum length, and contraction stage; the extension direction of fractures is primarily controlled by the current maximum horizontal principal stress direction. The development intensity of dynamic fractures is influenced by factors such as matrix permeability, natural fractures, rock brittleness index, as well as development technology policies. The lower matrix permeability, more developed natural fractures, higher brittleness index, and stronger water injection development technology policies are easier for the formation of dynamic fractures, and the transition from unidirectional to multidirectional fractures. Dynamic fractures significantly affect the water cut increase regularity of oil wells and the distribution of remaining oil.