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

The production optimization in the closed-loop reservoir management is generally empirical, and challenged by the issues such as low precision, low efficiency, and difficulty in solving constrained optimization problems. This paper outlines the main principles, advantages and disadvantages of commonly used production optimization methods/models, and then proposes an intelligent integrated production optimization method for waterflooding reservoirs that considers efficiency and precision, real-time and long-term effects, and the interaction and synergy between a variety of optimization models. This method integrates multiple optimization methods/models, such as reservoir performance analysis, reduced-physics models, and reservoir numerical models, with these model results and insights organically coupled to facilitate model construction and matching. This proposed method is elucidated and verified by field examples. The findings indicate that the optimal production optimization model varies depending on the specific application scenario. Reduced-physics models are conducive to short-term real-time optimization, whereas the simulator-based surrogate optimization and streamline-based simulation optimization methods are more suitable for long-term optimization strategy formulation, both of which need to be implemented under reasonable constraints from the perspective of reservoir engineering in order to be of practical value.

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

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

To improve the accuracy and generalization of well logging curve reconstruction, this paper proposes an artificial intelligence large language model “Gaia” and conducts model evaluation experiments. By fine-tuning the pre-trained large language model, the Gaia significantly improved its ability in extracting sequential patterns and spatial features from well-log curves. Leveraging the adapter method for fine-tuning, this model required training only about 1/70 of its original parameters, greatly improving training efficiency. Comparative experiments, ablation experiments, and generalization experiments were designed and conducted using well-log data from 250 wells. In the comparative experiment, the Gaia model was benchmarked against cutting-edge small deep learning models and conventional large language models, demonstrating that the Gaia model reduced the mean absolute error (MAE) by at least 20%. In the ablation experiments, the synergistic effect of the Gaia model's multiple components was validated, with its MAE being at least 30% lower than that of single-component models. In the generalization experiments, the superior performance of the Gaia model in blind-well predictions was further confirmed. Compared to traditional models, the Gaia model is significantly superior in accuracy and generalization for logging curve reconstruction, fully showcasing the potential of large language models in the field of well-logging. This provides a new approach for future intelligent logging data processing.

Conventional borehole image log interpretation of linear fractures on volcanic rocks, represented as sinusoids on unwrapped cylinder projections, is relatively straight-forward, however, interpreting non-linear rock structures and complex facies geometries can be more challenging. To characterize diverse volcanic paleoenvironments related to the formation of the South American continent, this study presents a new methodology based on image logs, petrography, seismic data, and outcrop analogues. The presented methodology used pseudo-boreholes images generated from outcrop photographs with typical igneous rock features worldwide simulating 2D unwrapped cylinder projections of a 31 cm (12.25 in) diameter well. These synthetic images and standard outcrop photographs were used to define morphological patterns of igneous structures and facies for comparison with wireline borehole image logs from subsurface volcanic and subvolcanic units, providing a “visual scale” for geological evaluation of volcanic facies, significantly enhancing the identification efficiency and reliability of complex geological structures. Our analysis focused on various scales of columnar jointing and pillow lava lobes with additional examples including pahoehoe lava, ignimbrite, hyaloclastite, and various intrusive features in Campos, Santos, and Parnaíba basins in Brazil. This approach increases confidence in the interpretation of subvolcanic, subaerial, and subaqueous deposits. The image log interpretation combined with regional geological knowledge has enabled paleoenvironmental insights into the rift magmatism system related to the breakup of Gondwana with associated implications for hydrocarbon exploration.

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

The formation water sample in oil and gas fields may be polluted in processes of testing, trial production, collection, storage, transportation and analysis, making the properties of formation water not be reflected truly. This paper discusses identification methods and the data credibility evaluation method for formation water in oil and gas fields of petroliferous basins within China. The results of the study show that: (1) the identification methods of formation water include the basic methods of single factors such as physical characteristics, water composition characteristics, water type characteristics, and characteristic coefficients, as well as the comprehensive evaluation method of data credibility proposed on this basis, which mainly relies on the correlation analysis sodium chloride coefficient and desulfurization coefficient and combines geological background evaluation; (2) The basic identifying methods for formation water enable the preliminary identification of hydrochemical data and the preliminary screening of data on site, the proposed comprehensive method realizes the evaluation by classifying the CaCl₂-type water into types A-I to A-VI and the NaHCO₃-type water into types B-I to B-IV, so that researchers can make in-depth evaluation on the credibility of hydrochemical data and analysis of influencing factors; (3) When the basic methods are used to identify the formation water, the formation water containing anions such as CO₃^2-, OH^- and NO₃^-, or the formation water with the sodium chloride coefficient and desulphurization coefficient not matching the geological setting, are all invaded with surface water or polluted by working fluid; (4) When the comprehensive method is used, the data credibility of A-I, A-II, B-I and B-II formation water can be evaluated effectively and accurately only if the geological setting analysis in respect of the factors such as formation environment, sampling conditions, condensate water, acid fluid, leaching of ancient weathering crust, and ancient atmospheric fresh water, is combined, although such formation water is believed with high credibility.

Based on the analysis of surface geological survey, exploratory well, gravity-magnetic-electric and seismic data, and through mapping the sedimentary basin and its peripheral orogenic belts together, this paper explores systematically the boundary, distribution, geological structure, and tectonic attributes of the Ordos prototype basin in the geological historical periods. The results show that the Ordos block is bounded to the west by the Engorwusu Fault Zone, to the east by the Taihangshan Mountain Piedmont Fault Zone, to the north by the Solonker-Xilamuron Suture Zone, and to the south by the Shangnan-Danfeng Suture Zone. The Ordos Basin boundary was the plate tectonic boundary during the Middle Proterozoic to Paleozoic, and the intra-continental deformation boundary in the Meso-Cenozoic. The basin survived as a marine cratonic basin covering the entire Ordos block during the Middle Proterozoic to Ordovician, a marine-continental transitional depression basin enclosed by an island arc uplift belt at the plate margin during the Carboniferous to Permian, a unified intra-continental lacustrine depression basin in the Triassic, and an intra-continental cratonic basin circled by a rift system in the Cenozoic. The basin scope has been decreasing till the present. The large, widespread prototype basin controlled the exploration area far beyond the present-day sedimentary basin boundary, with multiple target plays vertically. The Ordos Basin has the characteristics of a whole petroleum (or deposition) system. The Middle Proterozoic wide-rift system as a typical basin under the overlying Phanerozoic basin and the Cambrian-Ordovician passive margin basin and intra-cratonic depression in the deep-sited basin will be the important successions for oil and gas exploration in the coming years.

Based on the basic data of drilling, logging, testing and geological experiments, the geological characteristics of the Permian Dalong Formation marine shales in the northern Sichuan Basin and the factors controlling shale gas enrichment and high yield are studied. The results are obtained in four aspects. First, the high-quality shale of the Dalong Formation was formed after the deposition of the Permian Wujiaping Formation, and it is developed in the Kaijiang-Liangping trough in the northern part of Sichuan Basin, where deep-water continental shelf facies and deep-water reduction environment with thriving siliceous organisms have formed the black siliceous shale rich in organic matter. Second, the Dalong Formation shale contains both organic and inorganic pores, with stratification of alternated brittle and plastic minerals. In addition to organic pores, a large number of inorganic pores are developed even in ultra-deep (deeper than 4 500 m) layers, contributing a total porosity of more than 5%, which significantly expands the storage space for shale gas. Third, the limestone at the roof and floor of the Dalong Formation acted as seal rock in the early burial and hydrocarbon generation stage, providing favorable conditions for the continuous hydrocarbon generation and rich gas preservation in shale interval. In the later reservoir stimulation process, it was beneficial to the lateral extension of the fractures, so as to achieve the optimal stimulation performance and increase the well-controlled resources. Combining the geological, engineering and economic conditions, the favorable area with depth less than 5 500 m is determined to be 1 800 km², with resources of 5 400×10⁸ m³. Fourth, the shale reservoirs of the Dalong Formation are thin but rich in shale gas. The syncline zone far away from the main faults in the high and steep tectonic zone, eastern Sichuan Basin, with depth less than 5 500 m, is the most favorable target for producing the Permian shale gas under the current engineering and technical conditions. It mainly includes the Nanya syncline, Tanmuchang syncline and Liangping syncline.

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

Based on the comprehensive analysis of data from petrology and mineralogy, well logging, seismic surveys, paleontology, and geochemistry, a detailed research was conducted on paleoenvironmental and paleoclimatic conditions, and modeling of the source rocks in the second member of the Eocene Wenchang Formation (Wen 2 Member) in the Northern Shunde Subsag at the southwestern margin of the Pearl River Mouth Basin. The Wen 2 Member hosts excellent, thick lacustrine source rocks with strong longitudinal heterogeneity and an average total organic carbon (TOC) content of over 4.9%. The Wen 2 Member can be divided into three units (I, II, III) from bottom to top. Unit I features excellent source rocks with Type I organic matters (average TOC of 5.9%) primarily sourced from lake organisms; Unit II hosts source rocks dominated by Type II₂ organic matters (average TOC of 2.2%), which are originated from mixed sources dominated by terrestrial input. Unit III contains good to excellent source rocks dominated by Type II₁ organic matters (average TOC of 4.9%), which are mainly contributed by lake organisms and partially by terrestrial input. Under the background of rapid subsidence and limited source supply during intense rifting period in the Eocene, excellent source rocks were developed in Wen 2 Member in the Northern Shunde Subsag under the coordinated control of warm and humid climate, volcanic activity, and deep-water reducing conditions. During the deposition of Unit I, the warm and humid climate and volcanic activity promoted the proliferation of lake algaes, primarily Granodiscus, resulting in high initial productivity, and deep-water reducing conditions enabled satisfactory preservation of organic matters. These factors jointly controlled the development and occurrence of excellent source rocks. During the deposition of Unit II, a transition from warm to cool and semi-arid paleoclimatic conditions led to a decrease in lake algaes and initial productivity. Additionally, enhanced terrestrial input and shallow-water, weakly oxidizing water conditions caused a significant dilution and decomposition of organic matters, degrading the quality of source rocks. During the deposition of Unit III, when the paleoclimatic conditions are cool and humid, Pediastrum and Botryococcus began to thrive, leading to an increase in productivity. Meanwhile, the reducing environment of semi-deep water facilitated the preservation of excellent source rocks, albeit slightly inferior to those in Unit I. The study results clarify the differential origins and development models of various source rocks in the Shunde Sag, offering valuable guidance for evaluating source rocks and selecting petroleum exploration targets in similar marginal sags.

Based on development practices of Gulong shale oil and a series of experiments on interactions between CO₂ and the rocks and fluids of shale oil reservoirs, the application and adaptability of CO₂ pre-fracturing to the Gulong shale oil reservoirs are systematically evaluated. The pilot tests indicate that compared to wells with conventional fracturing, the wells with CO₂ pre-fracturing demonstrate four significant characteristics: high but rapidly declined initial production, low cumulative production, high and unstable gas-oil ratio, and non-competitive liquid production. These characteristics are attributed to two facts. First, pre-fracturing with CO₂ inhibits the cross-layer extension of the main fractures in the Gulong shale oil reservoirs, reduces the stimulated reservoir volume, weakens the fracture conductivity, and decreases the matrix permeability and porosity, ultimately impeding the engineering performance. Second, due to the confinement effect, pre-fracturing with CO₂ increases the saturation pressure difference between the fracture-macropore system and the matrix micropore system, leading to continuous gas production and light hydrocarbon evaporation in the fracture-macropore system, and difficult extraction of crude oil in the matrix-micropore system, which affects the stable production. Under the superposition of various characteristics of Gulong shale oil reservoirs, pre-fracturing with CO₂ has some negative impacts on reservoir stimulation (fracture extension and fracture conductivity), matrix seepage, and fluid phase and production, which restrict the application performance of CO₂ pre-fracturing in the Gulong shale oil reservoirs.

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

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

Lacustrine rift basins in China are characterized by pronounced structural segmentation, strong sedimentary heterogeneity, extensive fault-fracture development, and significant variability in thermal maturity and mobility of shale oil. This study reviews the current status of exploration and development of shale oil in such basins and examines theoretical frameworks such as “binary enrichment” and source-reservoir configuration, with a focus on five key subjects: (1) sedimentation-diagenesis coupling mechanisms of fine-grained shale reservoir formation; (2) dynamic diagenetic evolution and hydrocarbon occurrence mechanisms of organic-rich shale; (3) dominant controls and evaluation methods for shale oil enrichment; (4) fracturing mechanisms of organic-rich shale and simulation of artificial fracture networks; and (5) flow mechanisms and effective development strategies for shale oil. Integrated analysis suggests that two major scientific challenges must be addressed: the coupled evolution of fine-grained sedimentation, differential diagenesis, and hydrocarbon generation under tectonic influence and its control on shale oil occurrence and enrichment; and multi-scale, multiphase flow mechanisms and three-dimensional development strategies for lacustrine shale oil in complex fault blocks. In response to current exploration and development bottlenecks, future research will be conducted primarily to: (1) deeply understand organic-inorganic interactions and reservoir formation mechanisms in organic-rich shales, and clarify the influence of high-frequency sequence evolution and diagenetic fluids on reservoir space; (2) elucidate the dynamic processes of hydrocarbon generation, expulsion, and retention across different lithofacies, and quantify their relationship with thermal maturity, including the conditions for the formation of self-sealing systems; (3) develop a geologically adaptive, data- and intelligence-driven shale oil classification and grading evaluation system of shale oil; (4) reveal artificial fracture propagation pattern and optimize physical field coupled fracturing technologies for complex lithofacies assemblages; and (5) overcome challenges in multi-scale geological modeling and multiphase flow characterization, and establish advanced numerical simulation methodologies.

The Carter model is used to characterize the dynamic behaviors of fracture growth and fracturing fluid leakoff. A thermo-fluid coupling temperature response forward model is built considering the fluid flow and heat transfer in wellbore, fracture and reservoir. The influences of fracturing parameters and fracture parameters on the responses of distributed temperature sensing (DTS) are analyzed, and a diagnosis method of fracture parameters is presented based on the simulated annealing algorithm. A field case study is introduced to verify the model’s reliability. Typical V-shaped characteristics can be observed from the DTS responses in the multi-cluster fracturing process, with locations corresponding to the hydraulic fractures. The V-shape depth is shallower for a higher injection rate and longer fracturing and shut-in time. Also, the V-shape is wider for a higher fracture-surface leakoff coefficient, longer fracturing time and smaller fracture width. Additionally, the cooling effect near the wellbore continues to spread into the reservoir during the shut-in period, causing the DTS temperature to decrease instead of rise. Real-time monitoring and interpretation of DTS temperature data can help understand the fracture propagation during fracturing operation, so that immediate measures can be taken to improve the fracturing performance.

The presence of clay coatings on the surfaces of quartz grains can play a pivotal role in determining the porosity and permeability of sandstone reservoirs, thus directly impacting their reservoir quality. This study employs a multiphase-field model of syntaxial quartz cementation to explore the effects of clay coatings on quartz cement volumes, porosity, permeability, and their interrelations in sandstone formations. To generate various patterns of clay coatings on quartz grains within three-dimensional (3D) digital sandstone grain packs, a pre-processing toolchain is developed. Through numerical simulation experiments involving syntaxial overgrowth cementation on both single crystals and multigrain packs, the main coating parameters controlling quartz cement volume are elucidated. Such parameters include the growth of exposed pyramidal faces, lateral encasement, coating coverage, and coating pattern, etc. The coating pattern has a remarkable impact on cementation, with the layered coatings corresponding to fast cement growth rates. The coating coverage is positively correlated with the porosity and permeability of sandstone. The cement growth rate of quartz crystals is the lowest in the vertical orientation, and in the middle to late stages of evolution, it is faster in the diagonal orientation than in the horizontal orientation. Through comparing the simulated results of dynamic evolution process with the actual features, it is found that the simulated coating patterns after 20 d and 40 d show clear similarities with natural samples, proving the validity of the proposed three-dimensional numerical modeling of coatings. The methodology and findings presented contribute to improved reservoir characterization and predictive modeling of sandstone formations.

Taking the Wangfu fault depression in the Songliao Basin as an example, on the basis of seismic interpretation and drilling data analysis, the distribution of the basement faults was clarified, the fault activity periods of the coal-bearing formations were determined, and the fault systems were divided. Combined with the coal seam thickness and actual gas indication in logging, the controls of fault systems in the rift basin on the spatial distribution of coal and the occurrence of coal-rock gas were identified. The results show that the Wangfu fault depression is an asymmetrical graben formed under the control of basement reactivated strike-slip T-rupture, and contains coal-bearing formations and five sub-types of fault systems under three types. The horizontal extension strength, vertical activity strength and tectono-sedimentary filling difference of basement faults control vertical stratigraphic sequences, accumulation intensity, and accumulation frequency of coal seam in rift basin. The structural transfer zone formed during the segmented reactivation and growth of the basement faults controls the injection location of steep slope exogenous clasts. The filling effect induced by igneous intrusion accelerates the sediment filling process in the rift lacustrine area. The structural transfer zone and igneous intrusion together determine the preferential accumulation location of coal seams in the plane. The faults reactivated at the basement and newly formed during the rifting phase serve as pathways connecting to the gas source, affecting the enrichment degree of coal-rock gas. The vertical sealing of the faults was evaluated by using shale smear factor (SSF), and the evaluation criterion was established. It is indicated that the SSF is below 1.1 in major coal areas, indicating favorable preservation conditions for coal-rock gas. Based on the influence factors such as fault activity, segmentation and sealing, the coal-rock gas accumulation model of rift basin was established.

The lamina (combination) types, reservoir characteristics and shale oil occurrence states of organic-rich shale in the Triassic Yanchang Formation Chang 7₃ sub-member in the Ordos Basin were systematically investigated to reveal the main controlling factors of shale oil occurrence under different lamina combinations. The differential enrichment mechanisms and patterns of shale oil were discussed using the shale oil micro-migration characterization and evaluation methods from the perspectives of relay hydrocarbon supply, stepwise migration, and multi-stage differentiation. The results are obtained in five aspects. First, Chang 7₃ shale mainly develops five types of lamina combination, i.e. non-laminated shale, sandy laminated shale, tuffaceous laminated shale, mixed laminated shale, and organic-rich laminated shale. Second, shales with different lamina combinations are obviously different in the reservoir space. Specifically, shales with sandy laminae and tuffaceous laminae have a large number of intergranular pores, dissolution pores and hydrocarbon generation-induced fractures. The multi-scale pore and fracture system constitutes the main place for liquid hydrocarbon occurrence. Third, the occurrence and distribution of shale oil in shale with different lamina combinations are jointly controlled by organic matter abundance, reservoir property, thermal evolution degree, mineral composition and laminae scale. The micro-nano-scale pore-fracture networks within shales containing rigid laminae, particularly sandy and tuffaceous laminations, primarily contain free-state light hydrocarbon components. In contrast, adsorption-phase heavy hydrocarbon components predominantly occupy surfaces of organic matter assemblages, clay mineral matrices, and framework mineral particulates. Fourth, there is obvious shale oil micro-migration between shales with different lamina combinations in Chang 7₃. Generally, such micro-migration is stepwise in a sequence of organic-rich laminated shale → tuffaceous laminated shale → mixed laminated shale → sandy lamiated shale → non-laminated shale. Fifth, the relay hydrocarbon supply of organic matter under the control of the spatial superposition of shales with various laminae, the stepwise migration via multi-scale pore and fracture network, and the multi-differentiation in shales with different lamina combinations under the control of organic-inorganic interactions fundamentally decide the differences of shale oil components between shales with different lamina combinations.

Based on the data of drilling, logging, experiment and gas testing in the Nanchuan area, southeastern Sichuan Basin, the hydrocarbon generation potential, gas genesis, occurrence state, migration, preservation conditions, pore and fracture features and accumulation evolution of the first member of Permian Maokou Formation (Mao 1 Member) are systematically studied, and the main controlling factors of unconventional gas enrichment and high production in marlstone assemblage of Mao 1 Member are discussed. (1) The enrichment and high yield of unconventional natural gas in the Mao 1 Member are controlled by three factors: carbon-rich fabric controlling hydrocarbon generation potential, good preservation controlling enrichment, and natural fracture controlling production. (2) The carbonate rocks of Mao 1 Member with carbon rich fabric have significant gas potential, exhibiting characteristics of self-generation and self-storage, which lays the material foundation for natural gas accumulation. (3) The occurrence state of natural gas is mainly free gas, which is prone to lateral migration, and good storage conditions are the key to natural gas enrichment. Positive structure is more conducive to natural gas accumulation, and a good compartment is created jointly by the self-sealing property of the Mao 1 Member and its top and bottom sealing property in monoclinal area, which is favorable for gas accumulation by retention. (4) Natural fractures are the main reservoir space and flow channel, and the more developed natural fractures are, the more conducive to the formation of high-quality porous-fractured reservoirs and the accumulation of natural gas, which is the core of controlling production. (5) The accumulation model of unconventional natural gas is proposed as “self-generation and self-storage, preservation controlling richness, and fractures controlling production”. (6) Identifying fracture development areas with good preservation conditions is the key to successful exploration, and implementing horizontal well staged acidizing and fracturing is an important means to increase production and efficiency. The study results are of referential significance for further understanding the natural gas enrichment in the Mao 1 Member and guiding the efficient exploration and development of new types of unconventional natural gas.

The ultra-deep (deeper than 8 000 m) petroleum in the platform-basin zones of the Tarim Basin has been found mainly in the Lower Paleozoic reservoirs located to the east of the strike-slip fault F5 in the north depression. However, the source and exploration potential of the ultra-deep petroleum in the Cambrian on the west of F5 are still unclear. Through the analysis of lithofacies and biomarkers, it is revealed that there are at least three kinds of isochronous source rocks (SRs) in the Cambrian Newfoundland Series in Tarim Basin, which were deposited in three sedimentary environments, i.e. sulfide slope, deep-water shelf and restricted bay. In 2024, Well XT-1 in the western part of northern Tarim Basin has yielded a high production of condensate from the Cambrian. In the produced oil, entire aryl-isoprenoid alkane biomarkers were detected, but triaromatic dinosterane was absent. This finding is well consistent with the geochemical characteristics of the Newfoundland sulfidized slope SRs represented by those in wells LT-1 and QT-1, suggesting that the Newfoundland SRs are the main source of the Cambrian petroleum discovered in Well XT-1. Cambrian crude oil of Well XT-1 also presents the predominance of C₂₉ steranes and is rich in long-chain tricyclic terpanes (up to C₃₉), which can be the indicators for effectively distinguishing lithofacies such as siliceous mudstone and carbonate rock. Combined with the analysis of hydrocarbon accumulation in respect of conduction systems including thrust fault and strike-slip fault, it is found that the area to the west of F5 is possible to receive effective supply of hydrocarbons from the Cambrian Newfoundland SRs in Manxi hydrocarbon-generation center. This finding suggests that the area to the west of F5 will be a new target of exploration in the Cambrian ultra-deep structural-lithologic reservoirs in the Tarim Basin, in addition to the Cambrian ultra-deep platform-margin facies-controlled reservoirs in the eastern part of the basin.

Based on the test and experimental data from exploration well cores of the Upper Paleozoic in the central-eastern Ordos Basin, combined with structural, burial depth and fluid geochemistry analyses, this study reveals the fluid characteristics, gas accumulation control factors and accumulation modes in the Upper Paleozoic coal reservoirs. The study indicates findings in two aspects. First, the 1 500-1 800 m interval represents the critical transition zone between open fluid system in shallow-medium depths and closed fluid system in deep depths. The reservoirs above 1 500 m reflect intense water invasion, with discrete pressure gradient distribution, and the presence of methane mixed with varying degrees of secondary biogenic gas, and they generally exhibit high water saturation and adsorbed gas undersaturation. The reservoirs deeper than 1 800 m, with extremely low permeability, are self-sealed, and contains closed fluid systems formed jointly by the hydrodynamic lateral blocking and tight caprock confinement. Within these systems, surface runoff infiltration is weak, the degree of secondary fluid transformation is minimal, and the pressure gradient is relatively uniform. The adsorbed gas saturation exceeds 100% in most seams, and the free gas content primarily ranges from 1 m³/t to 8 m³/t (greater than 10 m³/t in some seams). Second, the gas accumulation in deep coals is primarily controlled by coal quality, reservoir-caprock assemblage, and structural position governed storage, wettability and sealing properties, under the constraints of the underground temperature and pressure conditions. High-rank, low-ash yield coals with limestone and mudstone caprocks show superior gas accumulation potential. Positive structural highs and wide and gentle negative structural lows are favorable sites for gas enrichment, while slope belts of fold limbs exhibit relatively lower gas content. This research enhances understanding of gas accumulation mechanisms in coal reservoirs and provides effective parameter reference for precise zone evaluation and innovation of adaptive stimulation technologies for deep resources.

The Mesozoic volcanic rocks of the Bodong Low Uplift in the Bohai Bay Basin have been studied and explored for years. In 2024, the LK7-A well drilled in this region tested high-yield oil and gas flows from volcanic weathered crust. These volcanic rocks need to be further investigated in terms of distribution patterns, conditions for forming high-quality reservoirs, and main factors controlling hydrocarbon accumulation. Based on the logging, geochemical and mineralogical data from wells newly drilled to the Mesozoic volcanic rocks in the basin, and high-resolution 3D seismic data, a comprehensive study was conducted for this area. The research findings are as follows. First, the volcanic rocks in the LK7-A structure are adakites with a large source area depth, and the deep and large faults have provided channels for the emplacement of intermediate-acidic volcanic rocks. Second, volcanic rock reservoirs are mainly distributed in tectonic breccias and intermediate-acidic lavas, and they are dominantly fractured-porous reservoirs, with high-porosity and low-permeability or medium-porosity and low-permeability. Third, the dominant lithologies/lithofacies is the basic condition for forming large-scale volcanic rock reservoirs. Structural fractures and late-stage strong weathering are crucial mechanisms for the formation scale of reservoirs in the Mesozoic volcanic rocks. Fourth, the Bodong Low Uplift exhibits strong hydrocarbon charging by two sags and overpressure mudstone capping, which are favorable for forming high-abundance oil and gas reservoirs. The Mesozoic volcanic buried hills in the study area reflect good trap geometry, providing favorable conditions for large-scale reservoir formation, and also excellent migration and accumulation conditions. Areas with long-term exposure of intermediate-acidic volcanic rocks, particularly in active structural regions, are the key targets for future exploration.

Based on the coalbed methane (CBM)/coal-rock gas (CRG) geological, geophysical, and experimental testing data from the Daji block in the Ordos Basin, the coal-forming and hydrocarbon generation & accumulation characteristics across different zones were dissected, and the key factors controlling the differential CBM/CRG enrichment were identified. The No. 8 coal seam of the Carboniferous Benxi Formation in the Daji block is 8-10 m thick, typically overlain by limestone. The primary hydrocarbon generation phase occurred during the Early Cretaceous. Based on the differences in tectonic evolution and CRG occurrence, and with the maximum vitrinite reflectance of 2.0% and burial depth of 1 800 m as boundaries, the study area is divided into deeply buried and deeply preserved, deeply buried and shallowly preserved, and shallowly buried and shallowly preserved zones. The deeply buried and deeply preserved zone contains gas content of 22-35 m³/t, adsorbed gas saturation of 95%-100%, and formation water with total dissolved solid (TDS) higher than 50 000 mg/L. This zone features structural stability and strong sealing capacity, with high gas production rates. The deeply buried and shallowly preserved zone contains gas content of 16-20 m³/t, adsorbed gas saturation of 80%-95%, and formation water with TDS of 5 000-50 000 mg/L. This zone exhibits localized structural modification and hydrodynamic sealing, with moderate gas production rate. The shallowly buried and shallowly preserved zone contains gas content of 8-16 m³/t, adsorbed gas saturation of 50%-70%, and formation water with TDS lower than 5 000 mg/L. This zone experienced intense uplift, resulting in poor sealing and secondary alteration of the primary gas reservoir, with partial adsorbed gas loss, and low gas production rate. A depositional unification and structural divergence model is proposed, that is, although coal seams across the basin experienced broadly similar depositional and tectonic histories, differences in tectonic intensity have led to spatial heterogeneity in the maximum burial depth (i.e., thermal maturity of coal) and current burial depth and occurrence of CRG (i.e., gas content and occurrence state). The research results provide valuable guidance for advancing the theoretical understanding of CBM/CRG enrichment and for improving exploration and development practices.

This study introduces a novel methodology and makes case studies for anomaly detection in multivariate oil production time-series data, utilizing a supervised Transformer algorithm to identify spurious events related to interval control valves (ICVs) in intelligent well completions (IWC). Transformer algorithms present significant advantages in time-series anomaly detection, primarily due to their ability to handle data drift and capture complex patterns effectively. Their self-attention mechanism allows these models to adapt to shifts in data distribution over time, ensuring resilience against changes that can occur in time-series data. Additionally, Transformers excel at identifying intricate temporal dependencies and long-range interactions, which are often challenging for traditional models. Field tests conducted in the ultradeep water subsea wells of the Santos Basin further validate the model’s capability for early anomaly identification of ICVs, minimizing non-productive time and safeguarding well integrity. The model achieved an accuracy of 0.954 4, a balanced accuracy of 0.969 4 and an F1-Score of 0.957 4, representing significant improvements over previous literature models.

The core sampling experiments were conducted after hydraulic fracturing in the three-dimensional development zone of Fuling shale gas. Six coring wells of different well types were systematically designed. Based on the integrated engineering technology of post-fracturing drilling, coring and monitoring of shale and the analysis of fracture source tracing, the evaluation of the fracture network after fracturing in the three-dimensional development of shale gas was conducted. The data of core fractures after fracturing indicate that three major types of fractures are formed after fracturing: natural fractures, hydraulic fractures, and fractures induced by external mechanical force, which are further classified into six subcategories: natural structural fractures, natural bedding fractures, hydraulic fractures, hydraulically activated fractures, drilling induced fractures, and fractures induced by core transportation. The forms of the artificial fracture network after fracturing are complex. Hydraulic fractures and hydraulically activated fractures interweave with each other, presenting eight forms of artificial fracture networks, among which the “一”-shaped fracture is the most common, accounting for approximately 70% of the total fractures. When the distance to the fractured wellbore is less than 35 m, the density of the artificial fracture network is relatively high; when it is 35-100 m, the density is lower; and when it is beyond 100 m, the density gradually increases. The results of the fracture tracing in the core sampling area confirm that the current fracturing technology can essentially achieve the differential transformation of the reservoir in the main area of Jiaoshiba block in Fuling. The three-layer three-dimensional development model can efficiently utilize shale gas reserves, although there is still room for improvement in the complexity and propagation uniformity of fractures. It is necessary to further optimize technologies such as close-cutting combined with temporary blocking and deflection within fractures or at fracture mouths, as well as limited flow perforation techniques, to promote the balanced initiation and extension of fractures.

During drilling operations, the low resolution of seismic data often limits the accurate characterization of small-scale geological bodies near the borehole and ahead of the drill bit. This study investigates high-resolution seismic data processing technologies and methods tailored for drilling scenarios. The high-resolution processing of seismic data is divided into three stages: pre-drilling processing, post-drilling correction, and while-drilling updating. By integrating seismic data from different stages, spatial ranges, and frequencies, together with information from drilled wells and while-drilling data, and applying artificial intelligence modeling techniques, a progressive high-resolution processing technology of seismic data based on multi-source information fusion is developed, which performs simple and efficient seismic information updates during drilling. Case studies show that, with the gradual integration of multi-source information, the resolution and accuracy of seismic data are significantly improved, and thin-bed weak reflections are more clearly imaged. The updated seismic information while-drilling demonstrates high value in predicting geological bodies ahead of the drill bit. Validation using logging, mud logging, and drilling engineering data ensures the fidelity of the processing results of high-resolution seismic data. This provides clearer and more accurate stratigraphic information for drilling operations, enhancing both drilling safety and efficiency.

Based on a large amount of basic research and experimental analysis data from Shengli Oilfield, Bohai Bay Basin, guided by the theory of whole petroleum system, the distribution of sedimentary systems, the distribution and hydrocarbon generation and expulsion process of source rocks, the variation of reservoir properties, and the control of fracture systems on hydrocarbon accumulation in the Paleogene of the Jiyang Depression, Boahai Bay Basin, were systematically analyzed, and the geological characteristics of the whole petroleum system in the rift basin were identified. Taking the Dongying Sag as an example, combined with the distribution of discovered conventional, tight, and shale oil/gas, a hydrocarbon accumulation model of the fault-controlled whole petroleum system in rift basin was proposed, and the distribution patterns of conventional and unconventional oil and gas reservoirs in large geological bodies horizontally and vertically were clarified. The research results show that paleoclimate and tectonic cycles control the orderly distribution of the Paleogene sedimentary system in the Jiyang Depression, the multi-stage source rocks provide sufficient material basis for in-situ shale oil/gas accumulation and other hydrocarbon migration and accumulation, the changes in reservoir properties control the dynamic threshold of hydrocarbon accumulation, and the combination of faults and fractures at different stages controls hydrocarbon migration and accumulation, and in-situ retention and accumulation of shale oil/gas, making the whole petroleum system in the rift basin associated, segmented and abrupt. The above elements are configured to form a composite whole petroleum system controlled by faults in the Paleogene of the Jiyang Depression. Moreover, under the control of hydrocarbon accumulation dynamics, a whole petroleum system can be divided into conventional subsystem and unconventional subsystem, with shale oil, tight oil and conventional oil in an orderly distribution in horizontal and vertical directions. This systematic understanding is referential for analyzing the whole petroleum system in continental rift basins in eastern China.

Based on the technological demands for significantly enhancing oil recovery and long-term CO₂ sequestration in the lacustrine oil reservoirs of China, this study systematically reviews the progress and practices of CO₂ flooding and storage technologies in recent years. It addresses the key technological needs and challenges faced in scaling up the application of CO₂ flooding and storage to mature, developed oil fields, and analyzes future development directions. During the pilot test phase (2006-2019), continuous development and application practices led to the establishment of the first-generation CO₂ flooding and storage technology system for lacustrine reservoirs. In the industrialization phase (since 2020), significant advances and insights have been achieved in terms of confined phase behavior, storage mechanisms, reservoir engineering, sweep control, engineering process and storage monitoring, enabling the maturation of the second-generation CO₂ flooding and storage theories and technologies to effectively support the demonstration projects of Carbon Capture, Utilization and Storage (CCUS). To overcome key technical issues such as low miscibility, difficulty in gas channeling control, high process requirements, limited application scenarios, and coordination challenges in CO₂ flooding and storage, and to support the large-scale application of CCUS, it is necessary to strengthen research on key technologies for establishing the third-generation CO₂ flooding and storage technological system incorporating miscibility enhancement and transformation, comprehensive regulation for sweep enhancement, whole-process engineering techniques and equipment, long-term storage monitoring safety, and synergistic optimization of flooding and storage.

To address the issue that traditional finite element methods cannot fully consider the semi-infinite earth strata and have lower solution accuracy, a new equivalent force model for induced deformation during oil and gas reservoir development is derived from the perspective of semi-infinite strata. A brand-new volume boundary element numerical method solution has been developed and verified and tested. The influences of internal flow and flow boundary of the reservoir on strata deformation are equivalent to the impacts on strata deformation when external forces act at the interior and boundary of the reservoir, respectively. Calculation methods for the flow equivalent force and boundary equivalent force are provided. The deformation solution at any point in the strata can be obtained through the convolution of flow equivalent forces, boundary equivalent forces and Green’s functions. After discretization, the deformation solution at any point in the strata can be obtained by multiplying the grid boundary equivalent forces, grid flow equivalent forces with their corresponding grid boundary sources and grid volume sources respectively, and then summing them up. This numerical method is termed the Volumetric Boundary Element Method(VBEM). Compared with traditional commercial simulators, VBEM fully considers the effects of reservoir flow boundaries, pore pressure gradient fields within the reservoir, and fluid mass changes within pores on formation deformation. It eliminates the need for meshing outside the reservoir, achieves significantly improved solution accuracy, and provides a new technical framework for simulating deformation induced by reservoir development.

Taking the Lower Silurian Longmaxi Formation shale in the Sichuan Basin as an example, this study employs atomic force microscopy-based infrared (AFM-IR) spectroscopy to analyze the submicron-scale molecular functional groups of different types and occurrences of organic matter. Combined with the quantitative evaluation of pore development via scanning electron microscopy (SEM), the response of organic pore formation and evolution mechanisms to chemical composition and structural evolution of organic matter in overmature marine shale is investigated. The results indicate that the AFM-IR spectra of graptolite periderms and pyrobitumen in shale are dominated by the stretching vibrations of conjugated C=C bonds in aromatic compounds at approximately 1 600 cm^-1, with weak absorption peaks near 1 375, 1 450 and 1 720 cm^-1, corresponding to aliphatic chains and carbonyl/carboxyl functional groups. Overall, the AFM-IR structural indices (A and C factors) of organic matter show a strong correlation with visible porosity in shales of equivalent maturity. Lower A and C factor values correlate with enhanced development of organic pores, which is associated with the detachment of more aliphatic chains and oxygen-containing functional groups during thermal evolution. Pyrobitumen-clay mineral composites generally exhibit superior pore development, likely attributable to clay mineral dehydration participating in hydrocarbon generation reactions that promote the removal of more functional groups. Additionally, hydrocarbon generation within organic-clay composites during high-over mature stages may induce volumetric expansion, resulting in microfracturing and hydrocarbon expulsion. The associated higher hydrocarbon expulsion rates promote the formation of larger pores and fracture-shaped pores along the flake-shaped clay minerals. This study highlights that the research of submicron-scale molecular functional groups provides a deeper understanding of organic matter evolution and pores development mechanisms in overmature shales, thereby offering critical theoretical parameters for reservoir evaluation in shale oil and gas exploration.

Taking the natural gas reservoirs of the Sinian Dengying Formation on the east and west sides (Gaoshiti-Moxi area and north slope of central Sichuan paleo-uplift on the east; Weiyuan and Well Datan-1 block on the west) of the Deyang-Anyue rift trough in the Sichuan Basin, China, as the research object, the geochemical parameters (component, isotopic composition) of natural gas from the Dengying Formation in different areas are compared, and then the differences in geochemical characteristics of Dengying natural gas on the east and west sides of the Deyang-Anyue rift trough and their genesis are clarified. First, the Dengying gas reservoirs on both sides of the rift trough are predominantly composed of oil-cracking gas with high maturity, which is typical dry gas. Second, severely modified by thermochemical sulfate reduction (TSR) reaction, the Dengying gas reservoirs on the east side exhibit high H₂S and CO₂ contents, with an elevated δ¹³C₂ value (average value higher than -29‰). The Dengying gas reservoirs in the Weiyuan area are less affected by TSR modification, though the δ¹³C₁ values are slightly greater than that of the reservoirs on the east side with partial reversal of carbon isotope composition, likely due to the water-soluble gas precipitation and accumulation mechanism. The Dengying gas reservoir of Well Datan-1 shows no influence from TSR. Third, the Dengying gas reservoirs reflect high helium contents (significantly higher than that on the east side) in the Weiyuan and Datan-1 areas on the west side, which is supposed to attribute to the widespread granites in basement and efficient vertical transport along faults. Fourth, controlled by the paleo-salinity of water medium in the depositional period of the source rock, the δ²H_CH4 values of the Dengying gas reservoirs on the west side are slightly lighter than those on the east side. Fifth, the Dengying natural gas in the Datan-1 area is contributed by the source rocks of the Sinian Doushantuo Formation and the third member of the Dengying Formation, in addition to the Cambrian Qiongzhusi Formation.

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

By integrating core observations, logging data and seismic interpretation, this study takes the massive Cretaceous carbonates in the M block of the Santos Basin, Brazil, as an example to establish the sequence filling pattern of fault-bounded isolated platforms in rift lake basins, reveal the control mechanisms of shoal-body development and reservoir formation, and reconstruct the evolutionary history of lithofacies paleogeography. The following results are obtained. (1) Three tertiary sequences (SQ1-SQ3) are identified in the Lower Cretaceous Itapema-Barra Velha of the M block. During the depositional period of SQ1, the rift basement faults controlled the stratigraphic distribution pattern of thick on both sides and thin in the middle. The strata overlapped to uplift in the early stage. During the depositional period of SQ2-SQ3, the synsedimentary faults controlled the paleogeomorphic reworking process with subsidence in the northwest and uplifting in the northeast, accompanied with the relative fall of lake level. (2) The Lower Cretaceous in the M block was deposited in a littoral-shallow lake, with the lithofacies paleogeographic pattern transiting from the inner clastic shoals and outer shelly shoals in SQ1 to the alternation of mounds and shoals in SQ2-SQ3. (3) Under the joint control of relative lake-level fluctuation, synsedimentary faults and volcanic activity, the shelly shoals in SQ1 tend to accumulated vertically in the raised area, and the mound-shoal complex in SQ2-SQ3 tends to migrate laterally towards the slope-break belt due to the reduction of accommodation space. (4) The evolution pattern of high-energy mounds and shoals, which were vertically accumulated in the early stage and laterally migrated in the later stage, controlled the transformation of high-quality reservoirs from “centralized” to “ring shaped” distribution. The research findings clarify the sedimentary patterns of mounds and shoals and the distribution of favorable reservoirs in the fault-controlled lacustrine isolated platform, providing support for the deepwater hydrocarbon exploration in the subsalt carbonate rocks in the Santos Basin.

Based on large-field rock thin section scanning, high-resolution field emission-scanning electron microscopy (FE-SEM), fluorescence spectroscopy, and rock pyrolysis experiments of the Mesoproterozoic Jixianian Hongshuizhuang Formation shale samples from the Yanliao Basin in northern China, combined with sedimentary forward modeling, a systematic petrological and organic geochemical study was conducted on the reservoir quality, oil-bearing potential, distribution, and resource potential of the Hongshuizhuang Formation shale in Well Yuanji-2. The results indicate that: (1) The original organic carbon content of the Hongshuizhuang Formation shale averages up to 6.24%, and the original hydrocarbon generation potential is as high as 44.09 mg/g, demonstrating a strong oil generation potential. (2) The rock type is primarily siliceous shale containing low clay mineral content, characterized by the development of shale bedding fractures and organic shrinkage fractures, resulting in good compressibility and reservoir quality. (3) The fifth and fourth members of the Hongshuizhuang Formation serve as shale oil sweet spots, contributing more than 60% of shale oil production with their total thickness as only 40% of the target formation. (4) The Kuancheng-Laozhuanghu area is the most prospective shale oil exploration option in the Yanliao Basin and covers approximately 7 200 km². Its original total hydrocarbon generation potential reaches about 74.11 billion tons, with current estimated retained shale oil resources exceeding 1.148 billion tons (lower limit) - comparable to the geological resources of the Permian Lucaogou Formation shale oil in the Jimsar Sag of the Junggar Basin. These findings demonstrate the robust exploration potential of the Hongshuizhuang Formation shale oil in the Yanliao Basin.

In 2023, the China National Petroleum Corporation (CNPC) has successfully drilled a 10 000-m ultra-deep well - TK-1 in the Tarim Basin, NW China. This pioneering project has achieved dual breakthroughs in ten-thousand-meter ultra-deep earth science research and hydrocarbon exploration while driving technological advancements in ultra-deep well drilling engineering. The successful completion of TK-1 has yielded transformative geological discoveries. For the first time in exploration history, comprehensive data including cores, well logs, fluids, temperature and pressure were obtained from 10 000-meter depths. These findings conclusively demonstrate the existence of effective source rocks, carbonate reservoirs, and producible conventional hydrocarbons at such extreme depths - fundamentally challenging established petroleum geology paradigms. The results not only confirm the enormous hydrocarbon potential of ultra-deep formations in the Tarim Basin but also identify the most promising exploration targets. From an engineering perspective, the project has established four groundbreaking technological systems: safe drilling in complex pressure systems of ultra-deep wells, optimized and fast drilling in complex and difficult-to-drill formations of ultra-deep wells, wellbore quality control under harsh conditions in ultra-deep wells, and data acquisition in ultra-deep, ultra-high-temperature complex formations. Additionally, ten key tools for ultra-deep well drilling and completion engineering were developed, enabling the successful completion of Asia's first and the world's second-deepest vertical well. This achievement has significantly advanced the understanding of geological conditions at depths exceeding 10 000 m and positioned China as one of the few countries with core technologies for ultra-deep well drilling.

This study systematically reviews the development history and key technological breakthroughs of large gas fields in the Ordos Basin, and summarizes the development models of three gas reservoir types, low-permeability carbonate, low-permeability sandstone and tight sandstone, as well as the progress in deep coal-rock gas development. The current challenges and future development directions are also discussed. Mature development models have been formed for the three representative types of gas reservoirs in the Ordos Basin: (1) Low-permeability carbonate reservoir development model featuring groove fine-scale characterization and three-dimensional vertical succession between Upper and Lower Paleozoic formations. (2) Low-permeability sandstone reservoir development model emphasizing horizontal well pressure-depletion production and vertical well pressure-controlled production. (3) Tight sandstone gas reservoir development model focusing on single-well productivity enhancement and well placement optimization. In deep coal-rock gas development, significant progress has been achieved in reservoir evaluation, sweet spot prediction, and geosteering of horizontal wells. The three types of reservoirs have entered the mid-to-late stages of the development, when the main challenge lies in accurately characterizing residual gas, evaluating secondary gas-bearing layers, and developing precise potential-tapping strategies. In contrast, for the early-stage development of deep coal-rock gas, continuous technological upgrades and cost reduction are essential to achieving economically viable large-scale development. Four key directions of future research and technological breakthroughs are proposed: (1) Utilizing dual-porosity (fracture-matrix) modeling techniques in low-permeability carbonate reservoirs to delineate the volume and distribution of remaining gas in secondary pay zones, supporting well pattern optimization and production enhancement of existing wells. (2) Integrating well-log and seismic data to characterize reservoir spatial distribution of successive strata, enhancing drilling success rates in low-permeability sandstone reservoirs. (3) Utilizing the advantages of horizontal wells to penetrate effective reservoirs laterally, achieving meter-scale quantification of small-scale single sand bodies in tight gas reservoirs, and applying high-resolution 3D geological models to clarify the distribution of remaining gas and guide well placement optimization. (4) Further strengthening the evaluation of deep coal-rock gas in terms of resource potential, well type and pattern, reservoir stimulation, single-well performance, and economic viability.

Taking the GY8HC well in the Gulong Sag of the Songliao Basin, NE China, as an example, this study utilized high-precision zircon U-Pb ages from volcanic ashes and AstroBayes method to estimate sedimentation rates. Through spectral analysis of high-resolution total organic carbon content (TOC), laboratory-measured free hydrocarbons (S₁), hydrocarbons formed during pyrolysis (S₂), and mineral contents, the enrichment characteristics and controlling factors of shale oil in an overmature area were investigated. The results indicate that: (1) TOC, S₁, and S₂ associated with shale oil enrichment exhibit a significant 173×10³ a obliquity amplitude modulation cycle; (2) Quartz and illite/smectite mixed-layer contents related to lithological composition show a significant 405×10³ a long eccentricity cycle; (3) Comparative studies with the high-maturity GY3HC well and moderate-maturity ZY1 well reveal distinct in-situ enrichment characteristics of shale oil in the overmature Qingshankou Formation, with a significant positive correlation to TOC, indicating that high TOC is a key factor for shale oil enrichment in overmature areas; (4) The sedimentary thickness of 12-13 m corresponding to the 173×10³ a cycle can serve as the sweet spot interval height for shale oil development in the study area, falling within the optimal fracture height range (10-15 m) generated during hydraulic fracturing of the Qingshankou shale. Orbitally forced climate changes not only controlled the sedimentary rhythms of organic carbon burial and lithological composition in the Songliao Basin but also influenced the enrichment characteristics and sweet spot distribution of Gulong shale oil.

For deep prospects in the foreland thrust belt, southern Junggar Basin, NW China, there are uncertainties in factors controlling the structural deformation, distribution of paleo-structures and detachment layers, and distribution of major hydrocarbon source rocks. Based on the latest 3D seismic, gravity-magnetic, and drilling data, together with the results of previous structural physical simulation and discrete element numerical simulation experiments, the spatial distribution of pre-existing paleo-structures and detachment layers in deep strata of southern Junggar Basin were systematically characterized, the structural deformation characteristics and formation mechanisms were analyzed, the distribution patterns of multiple hydrocarbon source rock suites were clarified, and hydrocarbon accumulation features in key zones were reassessed. The exploration targets in deep lower assemblages with possibility of breakthrough were expected. Key results are obtained in three aspects. First, structural deformation is controlled by two-stage paleo-structures and three detachment layers with distinct lateral variations: the Jurassic layer (moderate thickness, wide distribution), the Cretaceous layer (thickest but weak detachment), and the Paleogene layer (thin but long-distance lateral thrusting). Accordingly, a four-layer composite deformation sequence was identified, and the structural genetic model with paleo-bulge controlling zonation by segments laterally and multiple detachment layers controlling sequence vertically. Second, the Permian source rocks show a distribution pattern with narrow trough (west), multiple sags (central), and broad basin (east), which is depicted by combining high-precision gravity-magnetic data and time-frequency electromagnetic data for the first time, and the Jurassic source rocks feature thicker mudstones in the west and rich coals in the east according to the reassessment. Third, two petroleum systems and a four-layer composite hydrocarbon accumulation model are established depending on the structural deformation strength, trap effectiveness and source-trap configuration. The southern Junggar Basin is divided into three segments with ten zones, and a hierarchical exploration strategy is proposed for deep lower assemblages in this region, that is, focusing on five priority zones, expanding to three potential areas, and challenging two high-risk targets.