This paper presents a multi-agent system centered on large language models for well log interpretation and constructs a digital twin architecture across three dimensions: agents, tools, and environment. At the agent level, a role-based architecture is established to decompose the complex interpretation workflow into independent subtasks, enabling structured transfer of expert knowledge. At the tool level, petrophysical formulas and machine learning algorithms are encapsulated to form a physics-data dual-path hybrid reasoning mechanism; at the environment level, a standardized digital twin space is established based on the Model Context Protocol to achieve closed-loop control of the entire workflow. Engineers can drive the system through natural language commands to complete the full interpretation process from data loading and parameter calculation to reservoir classification, realizing end-to-end automation from raw data to interpretation conclusions. In tests on 100 field wells, the system generates key interpretation parameters that are highly consistent with expert results, exhibiting stable recognition capability for complex reservoir types. This study demonstrates that this human-AI collaborative working mode significantly enhances the standardization and efficiency of well log interpretation, providing reusable technical reference for intelligent transformation of highly specialized industrial processes.

Under the guidance of the whole petroleum system (WPS) concept, the Jurassic coal-measure source rocks, source-reservoir- caprock conditions, and configurations of various hydrocarbon accumulations in the Junggar Basin were systematically investigated to reveal the hydrocarbon accumulation characteristics and exploration targets of the Jurassic coal-measure WPS. The following research insights are obtained. First, the coal rocks of the Jurassic Badaowan and Xishanyao formations, together with the mudstones of the Sangonghe Formation, constitute a unified source kitchen characterized by large thickness, high thermal evolution degree, and sustained gas-generation capability. This kitchen provides an ample source for the synergistic accumulation of conventional oil and gas, coal-rock gas, and tight sandstone gas. Second, multi-phase fluvial-deltaic sedimentation has developed thick conventional sandstones, tight sandstones, and coal rocks as diverse types of reservoirs in the basin, offering various storage spaces for hydrocarbon accumulation, while regionally extensive thick mudstones ensure effective sealing of deep gas reservoirs. Third, within the unified petroleum system, multi-phase detachment and superimposed structures control hydrocarbon migration pathways and accumulation units, resulting in a sequential distribution of reservoirs from structural highs to deep sags. Specifically, at the southern margin, deep conventional natural gas and deep coal-rock gas are endowed in the central segment, while oil and gas coexist in the eastern and western segments; in the basin hinterland, coal-rock gas generated from old strata and stored in young strata is confirmed in the Dinan-Baijiahai area, while coal-rock gas generated and stored in the same set of strata is discovered in the Qigu area; in the slope and structurally complex zones, tight sandstone gas of the Badaowan Formation is found.

This paper systematically investigates the numerical simulation model construction and methods for hot dry rock geothermal resource development. It highlights the mechanisms and characterization differences of thermal-hydraulic-mechanical-chemical (THMC) coupling across various stages of development and utilization. The technical features and applicable scenarios of typical numerical simulation methods, as well as the application potential and advantages of emerging technologies such as intelligent algorithms in numerical simulation for hot dry rock geothermal development, are comprehensively reviewed. In addition, the functional characteristics and engineering application cases of mainstream geothermal numerical simulation software in China and abroad are summarized. On this basis, the core challenges for existing techniques are identified, and future development directions are proposed. At present, numerical simulation for hot dry rock geothermal resource development still faces several challenges, including insufficient accuracy in characterizing complex reservoir structures, incomplete representation of multi-physics field coupling mechanisms, limited cross-scale simulation capability, inadequate adaptability of software to diverse scenarios, and insufficient support from field monitoring and fundamental data. In the future, numerical simulation technologies for hot dry rock geothermal resource development should advance theoretical and technical research in full-chain integrated modeling, refined characterization of multi-physics field coupling, deep integration of intelligent algorithms with numerical simulation, and establishment of an independent and controllable software ecosystem, thereby providing theoretical and technical support for the sustainable and efficient development of hot dry rock geothermal resources in China.

Based on the post-frac core evaluation results for shale gas reservoirs in the Jiaoshiba block of the Fuling gas field, a simulation method for tensile-shear composite fracture networks and a multi-scale characterization method for residual gas were developed. The types and distribution characteristics of residual shale gas were clarified, and an efficient flow field with coordinated “artificial well pattern-induced fracture network-natural fracture network” was established. Strategies for residual gas recovery was proposed, and the expected technologies for efficient development of shale gas reservoirs were recommended. The induced fractures in shale exhibit features such as single overall morphology, clustered non-uniform distribution, branching dendritic extension, and limited propped area. Residual gas can be classified into four types: gas uncontrolled by well pattern, gas insufficiently swept by inter-well fractures, gas unevenly swept by inter-layer fractures, and gas unswept between clusters. For purpose of residual gas recovery and enhanced gas recovery, an efficient flow field with coordinated “artificial well pattern-induced fracture network-natural fracture network” can be constructed through drilling infill wells, sidetracking in old wells, differential trajectory design, and precision fracturing design. Future efficient development of shale gas is expected to be achieved by improving accurate reservoir characterization, advancing coordinated 3D development technologies, iteratively optimizing technologies for enhanced shale gas recovery, and deepening the synergy between conventional and unconventional development methods. These efforts are believed to drive high-quality advancement of China’s shale gas development technology.

The whole petroleum system (WPS) theory represents a significant innovation proposed to address the limitations of the classical petroleum system theory. The successful application of this theory has propelled China's oil and gas exploration toward a new paradigm characterized by “all stratigraphic sequences, all resource types, and all exploration domains.” Based on a review of the fundamental principles of this theory, this study provides a comprehensive analysis of 25 relevant cases from 12 basins in China. It is indicated that there exists an orderly distribution of three fluid dynamic fields in a whole petroleum system, i.e., free dynamic field, restricted dynamic field and confined dynamic field. Hydrocarbon accumulation in a restricted dynamic field primarily relies on capillary force and viscous force; however, long-term effectiveness still depends on sealing capacity and regional boundary conditions. The superposition of hydrocarbon generation from source rocks with different kerogen types or lithologies results in a broader hydrocarbon generation window, and earlier and longer hydrocarbon generation, than the traditional Tissot model, demonstrating a whole-process hydrocarbon generation across all kerogen types. The distribution and physical properties of reservoirs are generally controlled by sedimentary facies and diagensis. From basin margin to sag center, sediment grains generally present reservoir-forming features of all facies belts and all grain-size grades. A typical whole petroleum system generally follows a full-sequence, three-dimensional accumulation pattern described as “three zones laterally, three layers vertically”. Laterally, along the basin margin → slope area → sag center, conventional oil and gas reservoirs, tight oil and gas reservoirs, and shale oil and gas reservoirs develop sequentially corresponding to the intervals of major source rocks. Vertically, in addition to shale/coal-rock oil and gas reservoirs within these intervals, tight/conventional reservoirs are also found above and below the source beds. Within the accumulation framework of the whole petroleum system, underexplored areas that have not yet achieved breakthroughs represent important potential domains for future oil and gas discoveries.

Based on the molecular structure transitions, hydrocarbon composition, and reservoir characteristics changes during coal evolution, combined with the production characteristics of coalbed methane/coal-rock gas, the generation stages and accumulation types of coalbed methane/coal-rock gas are discussed. The generation of coalbed methane/coal-rock gas can be divided into five stages: low-coal-rank biogenic gas generation stage (R_o < 0.5%), mid-coal-rank transitional gas generation stage (0.5% ≤ R_o < 0.8%), mid-coal- rank mature gas generation stage (0.8% ≤ R_o < 1.3%), mid-coal-rank high-maturity gas generation stage (1.3% ≤ R_o < 2.0%), and high-coal-rank overmature gas generation stage (R_o ≥ 2.0%). Based on the burial depth and genesis, coalbed methane/coal-rock gas is divided into three types: shallow coalbed methane, deep coal-rock gas, and exogenous coal-rock gas. By the hydrocarbon generation evolution stage of coal rock, deep coal-rock gas is further classified into: mid-coal-rank low-maturity coal-rock gas, mid-coal-rank mature coal-rock gas, mid-coal-rank high-maturity coal-rock gas, and high-coal-rank overmature coal-rock gas. Coalbed methane→coal-rock gas represents a complete dynamic evolution sequence from shallow to deep. Coals reflect a hydrocarbon generation evolution sequence of “biogenic gas→transitional gas→wet gas→dry gas”, and reservoirs undergo a formation process of “primary pores→cleat development→peak organic matter pores→densification and fracturing + fracture opening”. The occurrence state gradually shifts from “absolute dominance of adsorbed gas” to “continuous increase in free gas proportion”, and the development modes also transform from “long-term drainage and depressurization for desorption” to “high gas production upon well opening”. In addition, exogenous coal-rock gas refers to the natural gas from external sources, especially in the underlying strata. This type of coal-rock gas corresponds to low-rank coals with reservoir properties, where gas was accumulated under the control of tectonics, and free gas takes a high proprotion. A high initial production has been observed.

Aiming at the problems of the poor understanding of enrichment factors, unclear exploration targets, and challenging selection of favorable areas for medium- and low-rank coal-rock gas (coalbed methane) resources in Xinjiang, this paper, based on the coal-measure whole petroleum system theory, examines the main controlling factors of coal rock gas (coalbed methane) enrichment and further discusses the exploration targets and favorable areas, through extensive coal petrology and coal quality analysis, gas content measurements, and well-seismic data interpretation. The study shows that the insufficient thermal evolution, with vitrinite reflectance (R_o) commonly below 0.8%, is the primary factor responsible for the marked discrepancy between actual gas content and hydrocarbon generation potential in basins such as the Junggar Basin. In addition, the coal-forming age and maceral composition characteristics also exert important controls on gas content. Accordingly, two exploration strategies are proposed: seeking relatively higher coal ranks and elevated geothermal gradients, and targeting older (especially Paleozoic) coal-measure strata. Further, five major exploration targets are identified: (1) post-coalification high geothermal gradient zone; (2) early deep burial and late uplift tectonic belt; (3) Upper Paleozoic coal measures with high thermal maturity; (4) coal seams with high vitrinite content; and (5) coordinated development area of the coal-measure whole petroleum system. Depending on the distribution of coal-measure strata, structural characteristics, and coal rock properties of various basins in Xinjiang, three practical exploration areas are defined: the southern piedmont structural belt and stable central region of the Junggar Basin, the Wenjisang structural belt and the Hongtai slope of the Tuha Basin, and the northern Kuqa structural belt of the Tarim Basin. Additionally, six peripheral strategic replacement areas are identified: Heshituoluogai, Yili, Yanqi, Santanghu, Kupu, and Fujin Basins. The study provides a scientific basis for selecting favorable zones to advance the effective exploration and large-scale development of coal-rock gas (coalbed methane) resources in Xinjiang.

This paper systematically reviews the development stages and status of key oil production engineering domains, including injection-production engineering, artificial lift, reservoir stimulation, and workover operations. On this basis, the major challenges for oil production engineering are identified in four aspects: intelligent endpoint devices and process integration, extreme-environment operations, and collaborative operational constraints; AI-driven data and modeling complexities, and advanced structural and functional material requirements; and the need for geoscience-engineering integration in reservoir characterization, operational efficiency, and green development. Centered on multidisciplinary integration, the concept of the Oil Production Engineering Agent is introduced as a miniaturized, intelligent, integrated hardware-software system designed for extreme downhole environments, incorporating power supply, communication, sensing, computation, and actuation modules to enable environmental perception, autonomous decision-making, and adaptive control. The characteristics of various agent types, including those for injection-production, lift, fracturing, and workover, are analyzed, with key research directions identified in miniaturized self-powered energy management, reliable communication in high-interference environments, highly integrated multi-parameter sensing with long-term drift self-calibration, and high-reliability microsystem integration manufacturing. AI-driven decision optimization remains the core feature, requiring advances in data acquisition, governance, and fusion architectures, alongside algorithmic improvements in model performance and deployment compatibility. Additionally, advanced structural and functional materials support agent construction and extreme-environment adaptability, while geoscience-engineering integration continues to expand the functional scope of oil production engineering.

The temperature-pressure history of the organic-rich shale in the Cretaceous Qingshankou Formation in the northern Songliao Basin was reconstructed through comprehensive analyses, including field tests, paleo-heat flow recovery, overpressure evolution, and geochemistry. The formation and evolution process of the Gulong shale oil was reproduced, and its enrichment patterns were clarified. Because of tectonic thermal events and movements at the end of the Cretaceous Mingshui Formation deposition, the evolution of organic matter thermal maturity in the first member of Qingshankou Formation (Qing-1 Member) exhibited distinct stages, which can be divided into the Cretaceous rapid evolution stage and the Paleogene-Neogene slow evolution and stabilization stage. High paleogeotemperature drove secondary cracking of retained oil in the Qing-1 Member, forming light shale oil in the Gulong Sag. This sag experienced three phases of overpressure during the late Nenjiang Formation and late Mingshui Formation of the Cretaceous, and the Neogene. The first two phases were related to the oil generation peak and secondary cracking in the sag, respectively, while the third phase resulted from the inheritance of earlier overpressure, as well as sustained hydrocarbon cracking and heat-induced fluid volume expansion. Crude oil is distributed orderly in the northern Songliao Basin. Conventional oil reservoirs such as Saertu and Putaohua contain high contents of non-hydrocarbon compound, and they are believed to have formed by hydrocarbon charging as a result of the first phase of overpressure. Tight oils in the Fuyu and Gaotaizi reservoirs, most similar to shale oil in the Qing-1 Member in terms of composition and physical properties, are characterized by high content of saturated hydrocarbons, with their hydrocarbon charging and accumulation related to the second phase of overpressure. Paleo-heat flow impacted by tectothermal events is determined to be the main driving factor for the staged hydrocarbon generation of organic matter in the Qingshankou Formation. The Qingshankou shale with high thermal conductivity and the Nenjiang shale with low thermal conductivity constitutes a thermal structure with lower conducting and upper sealing. This structure has prolonged secondary cracking of hydrocarbons, widened the liquid hydrocarbon window, and helped self-sealing enrichment of the Gulong light shale oil by virtue of the third phase of overpressure.

Considering the complex occurrence environment and significant compositional variation of continental shale oil, as well as the uncertainties in its mobility and producible amount, this study employs geochemical analysis and production monitoring to investigate the “component flow” behavior of shale oil during production from the Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin. It is clarified that the miscibility of different hydrocarbon components and non-hydrocarbon substances improves the flowability of multi-component hydrocarbons and non-hydrocarbons, thereby effectively enhancing the production of mobile hydrocarbons from shale oil. Research indicates that the “lower sweet spot” has a relatively high content of light and medium hydrocarbon components and strong formation energy, resulting in higher density and viscosity of the produced crude oil, which can be regarded as evidence of “component flow” of retained hydrocarbons. The “upper sweet spot” exhibits two scenarios. In areas far from faults with good preservation conditions, the high content of light and medium components in retained hydrocarbons and a high formation pressure coefficient make component flow more likely to occur. Consequently, the produced crude oil has a higher specific gravity, and the estimated ultimate recovery (EUR) per well is also higher. In areas near faults with poor preservation conditions, although the produced crude oil has a light specific gravity, the EUR per well is relatively low, indicating that the conditions for component flow of retained hydrocarbons underground have deteriorated. The study also demonstrates that preservation conditions (preventing light hydrocarbon escape and maintaining formation energy) and production strategies (controlling production pressure differential and maintaining stable operations) are important factors in regulating the occurrence and continuity of “component flow” to maximize EUR per well. These new insights can be applied to the evaluation of economically productive “sweet spots” and provide guidance for achieving optimal EUR per well in shale oil production.

Given the stringent requirements for friction reducers in terms of long-distance friction reduction, efficient proppant transport, temperature resistance and viscosity enhancement in deep oil and gas fracturing development, an aqueous two-phase high-viscosity friction reducer ANSD-PADA suitable for deep reservoir fracturing was prepared by introducing nanomaterial ANSD and through the aqueous two-phase polymerization. Its mechanisms of temperature resistance, viscosity enhancement, and friction reduction were explored by means of fluorescence spectroscopy, microscopic morphology observation, nanomechanical testing and other analytical methods, and field tests were also carried out. The introduction of hydrophobic monomer N-(3-dimethylaminopropyl)methacrylamide enables PADA (a self-synthesized hydrophobic terpolymer) molecules to entangle, associate and self-assemble into a honeycomb-like network structure under the action of supramolecular forces including van der Waals force, electrostatic repulsion and hydrophobic interaction. This structure further increases the hydrodynamic volume, thereby significantly improving the viscosity-enhancing performance of the product. ANSD fills the pores of the polymer network structure, effectively strengthening the network skeleton and association junctions, and remarkably improving the temperature resistance of the system. The friction reducer retains a friction reduction rate of 73.36% at 130 °C, with a temperature resistance up to 150 °C, and it has demonstrated encouraging results in the pilot site at Well XX-HF targeting deep shale oil reservoirs on the northern slope zone of the Gaoyou Sag, Subei Basin, China.

Through systematic comparison of the geological characteristics, resource distribution, and exploration & development status of global marine and lacustrine shale oil, this paper deeply analyzes the key theoretical and technical issues that restrict the development of lacustrine shale oil in China. It points out that the basic theoretical research areas, such as the enrichment and accumulation mechanisms of shale oil with different lithological combinations, and the multi-scale and multiphase flow mechanisms in nanoscale confined spaces, are relatively weak; the accuracy of sweet spot prediction cannot effectively guide the selection of target layers and the positioning of horizontal well trajectories, and there are fewer geology-engineering integration practices. All these factors severely restrict the large-scale utilization of shale oil resources. Focusing on the progress in the study of lacustrine shale oil in the Songliao Basin, Ordos Basin, Junggar Basin, and Bohai Bay Basin, this paper systematically analyzes six bottleneck issues (genetic models of fine-grained sedimentary rocks, types and distribution of hydrocarbon-generating organic matter, hydrocarbon generation-expulsion models and potential, types and performance of reservoir spaces, parameter selection and evaluation techniques for of sweet spots, and productivity laws and enhanced oil recovery), progress in theoretical and technological research, examples, and directions for tackling key issues. It identifies six major challenges confronting China’s shale oil revolution: hydrocarbon accumulation mechanisms, sweet spot identification, seepage law, fracturing modification, drainage and production technology, and recovery enhancement. To address these, the study proposes to establish a shale oil classification scheme based on source-reservoir configuration, to promote the refined development model of “geology-engineering-geology spiral integration”, and build an efficient shale oil development technology system tailored to China’s continental geological conditions, providing theoretical and technical support for achieving large-scale and beneficial development.

To address the challenges of connectivity characterization, dynamic prediction efficiency, and real-time optimization in complex reservoir injection-production systems, this study proposes a physics- and deep learning-integrated intelligent injection-production modeling framework based on the graph connection element method. The method adopts the connection element method as the physical foundation and constructs a non-Euclidean graph representation to describe interwell connectivity, enabling characterization of the physical topology and dynamic interactions within the well pattern system. By incorporating an adaptive attention mechanism into a graph convolutional network and embedding time-dependent node attributes, a physics-consistent reservoir performance prediction model is developed. Furthermore, a hybrid optimization strategy integrating differential evolution and particle swarm optimization is employed to establish an economically constrained intelligent optimization framework. Based on rapid prediction of injection and production behaviors, the proposed approach enables optimization of operational parameters and maximization of exploitation economics. Field applications demonstrate that the proposed intelligent injection-production model based on graph connection element accurately reproduces water-cut behavior of producers and provides quantitative uncertainty estimation. It achieves rapid history matching and dynamic response forecasting for complex reservoir injection-production systems, exhibiting high accuracy and stability. Moreover, it enables global optimization of production strategies under economic constraints, demonstrating strong engineering applicability and scalability.

Global deep Earth exploration and ultra-deep oil and gas exploration (below 6 000 m) have attracted increasing attention, with a growing number of major oil and gas discoveries. This article systematically reviews the discovery history of ultra-deep oil and gas exploration since 1937, dividing it into four major stages: onshore ultra-deep exploration and local breakthrough (1937-1982), shallow- water-dominated ultra-deep exploration and sporadic discoveries (1983-1997), onshore and offshore large-scale ultra-deep discoveries (1998-2018), and onshore extra-deep exploration and new breakthrough (since 2019). By the end of 2025, a total of 1 348 exploratory wells with a depth of more than 6 000 m have been drilled worldwide. A total of 305 ultra-deep oil and gas fields have been discovered in 29 basins across 20 countries, with recoverable reserves equivalent to 63.21×10⁸ t, accounting for only 0.9% of the global total reserves and indicating enormous exploration potential. The discovered resources are highly concentrated in the Tethys and South Gondwana petroleum domains, dominated by passive continental margin basins with a proportion of 71.25%. Reservoirs are mainly composed of Meso-Cenozoic carbonate rocks and clastic rocks. Studies show that three types of advantageous basins, including cratonic basins, passive continental margin basins and foreland basins, have their own characteristics in terms of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation. The global ultra-deep oil and gas exploration degree is extremely low, and there may exist another “golden zone” for hydrocarbon accumulation with huge resource potential. In the future, it is necessary to strengthen research on the mechanisms of hydrocarbon generation and accumulation as well as resource assessment in ultra-deep strata, and carry out integrated evaluation combining geology, engineering and intelligent technology. Internationally, efforts should be focused on new ultra-deep project evaluation and oil and gas cooperation in hydrocarbon-rich regions such as the two sides of the Atlantic, the Middle East, Central Asia-Russia and Australia. With the accelerated exploration of extra-deep oil and gas in China, a new peak of reserve growth is forthcoming.

To accurately evaluate the storage capacity of shale oil reservoirs under in-situ temperature and pressure conditions, we constructed a new model for determining the porosity under formation conditions, developed a HTHP shale porosity measurement system capable of operating at an overburden pressure of 70 MPa, a pore-fluid pressure of 40 MPa, and a temperature of 120°C, and established an integrated workflow for restoring in-situ porosity in clay-rich lacustrine shale oil reservoirs. This technology system was applied to the Upper Cretaceous Gulong shales in the Songliao Basin. The results show that the in-situ porosity in shale oil reservoirs is consistently higher than that measured at normal pressure on surface. The restored porosity increases by 3.17-4.00 percentage points for ordinary shale, 1.58-1.60 percentage points for silty shale, and 1.12-1.58 percentage points for carbonates. The restored porosity increase grows regularly with burial depth, temperature, pore pressure, and pressure coefficient, reflecting the elastic dilation of clay- and organic-associated nanopores and the widening of overpressure-supported microfractures in the Gulong shales. Core depressurization was found to collapse these pressure-supported pores, causing conventional helium and surface NMR measurements to systematically underestimate storage capacity, particularly in deep, clay-rich, overpressured intervals. For reserve estimation, use of ambient-condition porosity may introduce significant underestimation of original oil in place (OOIP). For clay-rich Gulong shales, it is recommended to apply a correction factor of 3-4 percentage points to the surface-measured porosity (or surface porosity) for ordinary shale, and about 1.6 percentage points for silty shale, while only a minor correction is needed for carbonates. In-situ porosity should thus be incorporated into OOIP calculations and parameterized using clay content, TOC, pressure coefficient, and burial depth. Operationally, production from clay-rich, overpressured intervals should be implemented under controlled pressure, in order to avoid elastic closure of native microfractures and preserve reservoir deliverability.

Based on China’s latest exploration and development achievements, production performance data of over 7 000 horizontal wells, and the Unconventional Oil & Gas Digital-Intelligent Platform (UOG), and by integrating statistical analysis and machine learning prediction techniques, this study systematically compares four types of unconventional natural gas (tight gas, shale gas, shallow coalbed methane, and medium-deep coal-rock gas) in the country, from the aspects of resource characteristics, key technologies, development indicators, and prospects. The results show that China holds a substantial quantity of unconventional natural gas, especially shale gas and medium-deep coal-rock gas which boast prominent resource advantages and present a large-scale “continuous” spatial distribution. More than 75% of high-quality resources are concentrated in the Ordos and Sichuan Basins. A type-adaptive key technical system has been established, incoprating extensive recovery of tight gas by virtue of “well pattern optimization + low-cost fracturing”, commercial development of shale gas relying on “geological-engineering dual sweet spot evaluation + super fracture network fracturing”, stable production of shallow-medium coalbed methane through “precision drainage and depressurization”, and breakthroughs in pilot technologies such as pressure-controlled development and energy-gathered fracturing for horizontal wells of medium-deep coal-rock gas. The four types of unconventional natural gas vary significantly in development indicators. Tight gas, shale gas and medium-deep coal-rock gas reach peak production 10-30 days after gas breakthrough, showing the characteristics of high initial production followed by rapid decline (with a first-year decline rate of 30%-51%). Specfically, shale gas horizontal wells have the highest average daily production in the first year (7.28×10⁴ m³/d) and single-well EUR (8 255×10⁴ m³). Shallow coalbed methane reaches peak production about 240 days after gas breakthrough, presenting a trend of slow rise-gentle decline, with the lowest single-well indicators. At present, the development of unconventional natural gas is faced with four major constraints including complex geology, technical bottlenecks, environmental restrictions and imperfect policies. Thus, it is necessary to address the predicament through multi-dimensional coordination in terms of resources, technology, environmental protection, and policies.

Centering on the critical bottlenecks in the development of shale oil in the Jiyang Depression, Shengli Oilfield, key scientific and engineering issues are proposed in aspects such as the storage space and occurrence state of shale oil, the formation mechanism of multi-scale flow spaces, the mobilization mechanism of crude oil in pores and fractures, and enhanced oil recovery (EOR) mechanisms during the late stage of elastic development. The research progress and mechanistic insights in recent years are reviewed with respect to experimental techniques, characteristics of pore-fracture structure and fluid occurrence, fracture evolution mechanisms, shale oil flow mechanisms, and EOR techniques. Through improving the experimental methods, optimize the testing conditions, and develop new technologies, we deeply understand the occurrence state, storage space and flow pattern of shale oil, and reveal the distribution pattern of “oil-bearing in all pore sizes and oil-rich in large pores” and the differences in fluid phase states under the confinement effect of nano-scale pores in shales of the Jiyang Depression; depict the characteristics of “restricted vertical expansion and complex fracture network” of induced fractures and the dynamic evolution of fracture networks during the fracturing-soaking-production process; establish a “easy flow-slow flow-stagnant flow” three-zone model and the elastic drive + imbibition drive synergistic energy replenishment mechanism; and carry out high-pressure injection to further enhance the mass transfer and diffusion capacity of CO₂ within the shale pore-fracture system, and compete for the desorption of alkanes to improve the mobilization degree of shale oil. The research achievements provide crucial support for the formation of the theory of continental shale oil development and the construction of the technical system. The future research efforts will focus on mine-scale multi-field coupling physical simulation equipment, microscopic to macroscopic cross-scale experimental methods, pore/fracture fine characterization and post-fracturing core fracture description technologies, multi-media fluid-solid coupling numerical simulation algorithms, and low-cost EOR and low-quality shale oil in-situ upgrading technologies, in order to promote the large-scale and profitable development of shale oil in the Jiyang Depression.

To address the challenges of complex fluvial sandbody distribution and difficult remaining oil recovery in mature continental oilfields, this study focuses on key issues such as ambiguous narrow-channel boundaries and subdivision of multi-stage superimposed sandbodies. Taking the Upper Cretaceous continental sandstone in the Sazhong Oilfield of the Daqing Placanticline as an example, a technical system integrating azimuth-preserved high-resolution processing, multi-attribute fusion, and variable-scale inversion was developed to establish a complete workflow from seismic processing to reservoir prediction and remaining oil recovery. The following results are obtained. First, the OVT seismic processing technology is extended, for the first time, from fracture imaging to sandbody prediction, in order to address the weak seismic responses from boundaries of narrow and thin sandbodies. A geology-oriented OVT partitioning method is developed to significantly improve the imaging accuracy, enabling identification of channel sandbodies as narrow as 50 m. Second, an amplitude-coherence dual-attribute fusion method is proposed for predicting narrow channel boundaries between wells. Constrained by a sedimentary unit-level sequence chronostratigraphic framework, this method accurately delineates 800-2 000 m long subaqueous distributary channels with bifurcation-convergence features. Third, considering the superimposition of multi-stage channels, a three-level variable-scale stratigraphic model (sandstone groups: 8-10 m; sublayers: 4-5 m; sedimentary units: 2-5 m) is constructed to overcome single-scale modeling limitations, successfully characterizing key sedimentary features like meandering river “cut-offs” through 3D inversion. Based on these advances, a direct link between seismic prediction and remaining oil recovery is established. Horizontal wells deployed using narrow-channel predictions encountered oil-bearing sandstones in the horizontal section by 97%, and achieved initial daily production of 12.5 t per well. Precise identification of individual channel boundaries within 17 composite sandbodies guided recovery processes in 135 wells, yielding an average daily increase of 2.8 t per well and a cumulative increase of 136 000 tons.

The forward model of optical fiber strain induced by fractures, together with the associated model resolution matrix, is used to demonstrate the interpretability of fracture parameters once the fracture intersects the fiber. A regularized inversion framework for fracture parameters is established to evaluate the influence of measured data quality on the accuracy of iterative regularized inversion. An interpretation approach for both fracture width and height is proposed, and the synthetic forward data with measurement error and field examples are employed to validate the accuracy of the simultaneous inversion of fracture width and height. The results indicate that, after the fracture contacts the fiber, the strain response is strongly sensitive only to the fracture parameters at the intersection location, whereas the interpretability of parameters at other locations remains limited. The iterative regularized inversion method effectively suppresses the impact of measurement error and exhibits high computational efficiency, showing clear advantages for inversion applications. When incorporating the first-order regularization with a Neumann boundary constraint on the tip width, the inverted fracture-width distribution becomes highly sensitive to fracture height; thus, combined with a bisection strategy, simultaneous inversion of fracture width and height can be achieved. Examination using the model resolution matrix, noisy synthetic data, and field data confirms that the iterative regularized inversion model for fracture width and height provides high interpretive accuracy and can be applied to the calculation and analysis of fracture width, fracture height, net pressure and other parameters.

Based on the survey of saline lacustrine shales in the Permian Lucaogou Formation and Fengcheng Formation in the Junggar Basin, it is found that the sweet intervals of these shale oil strata are enriched with lithium—an underexplored resource with significant potential. The sedimentary environment, depositional process, and geochemical characteristics of these intervals were analyzed, indicating that lithium enrichment in saline lacustrine shale is controlled by multiple factors during deposition and diagenesis. The salinity of lake water during sedimentation plays a key role in lithium accumulation, while clastic input reduces its concentration, and diagenesis further affects its distribution. To assess the potential for lithium co-production in shale oil development, future research should focus on the distribution of lithium and hydrocarbons in lacustrine shales and the economic feasibility of an “oil-lithium integrated sweet spot”. Furthermore, efficient lithium extraction and environmental protection technologies need to be explored to optimize resource development. Saline lacustrine shale oil development not only ensures stable oil and gas supplies but also, if lithium co-production is realized, could enhance China’s lithium security, contributing significantly to the country’s energy transformation.

The well deployment under the guidance of the ramp model in the Ordovician Yingshan Formation in the Gucheng area of the Tarim Basin focuses on the inner ramp in the western part of the study area, which results in a low drilling success rate and an exploration predicament. To address these issues, this study focused on reconstructing sedimentary models and the adjustment strategies for oil and gas exploration. The carbonate sedimentary model of the Yingshan Formation was re-evaluated using the data of seismic interpretation, core observations, thin-section analyses, carbon isotope composition, well logging, detrital zircon U-Pb dating, and carbonate mineral U-Pb dating. Then, the favorable sedimentary facies belts were delineated, and updated prospective exploration targets were proposed. The results demonstrate that the sedimentary model of the Yingshan Formation in the Gucheng area is characterized as a rimmed platform system, exhibiting an orderly west-to-east sedimentary sequence transition from restricted/open platform environments through the platform margin and slope settings, ultimately grading into basinal deposits. The platform margin, distinguished by thick successions of grain shoals overlain by interlayered karst zones. It is the most favorable distribution area for large-scale reservoirs. Guided by this revised sedimentary model, Well Gutan-1 was successful drilled within the outer platform margin, encountering over 90% high-energy grain shoal facies with well-developed porous and fractured-vuggy reservoirs. Through oil testing, it has successfully obtained industrial oil and gas flow. It is confirmed that the platform margin is the priority area for oil and gas exploration in the Ordovician System of the Gucheng area, thereby effectively ending the prolonged exploration stagnation in the Yingshan Formation of the Gucheng area.

The faults and associated fracture zones in the tight sandstone reservoirs of the fifth member of the Triassic Xujiahe Formation (Xu-5 Member) in the Wubaochang area, northeastern Sichuan Basin, play a critical role in controlling gas well productivity. To delineate the distribution patterns of faults and associated fracture zones in this area, a transfer-trained convolutional neural network (CNN) model and an XGBoost-based intelligent seismic attribute fusion method were employed to identify faults and fracture zones, respectively, enabling precise characterization of their spatial distribution. The faults in the Wubaochang area are classified into first- to fourth-order structures, with the average fracture zone width on the hanging wall exceeding that of the footwall, demonstrating a strong positive correlation between fracture zone width and fault displacement. The study area is subdivided into three distinct deformation regions (southern, central, and northern regions) featuring five fault structural styles (imbricate thrust, imbricate-backthrust, duplex, composite syncline imbricate-backthrust, and composite anticline imbricate-backthrust) and four corresponding fracture zone development patterns (imbricate thrust, imbricate-backthrust, composite syncline imbricate-backthrust, and composite anticline imbricate-backthrust). Based on the controlling effects of faults on gas enrichment, the dual-source hydrocarbon-generating zones are interpreted to be predominantly distributed in the northern and central regions, while the southwestern and southeastern sectors are identified as fault-induced gas-escape zones. By integrating the distribution of favorable reservoir development areas and fracture zones, two classes of gas enrichment zones (ClassⅠand Ⅱ) are delineated. ClassⅠzones are primarily distributed in the northern region and the transitional zone from the southern to central regions, whereas Class Ⅱ zones are concentrated in the central region. ClassⅠzones exhibit dual-source hydrocarbon-generation conditions, larger-scale fracture zone development, and higher favorability compared to Class Ⅱ zones. Analysis of local stress fields and drilling fluid loss data indicates that within ClassⅠzones, fault-controlled fold-related fracture zones demonstrate higher effectiveness, whereas fault-controlled fracture zones dominate in Class Ⅱ zones. A high-productivity gas well model for the Wubaochang area is proposed, emphasizing “dual-source faults controlling enrichment, effective fracture zones controlling high production, and high matrix porosity ensuring sustained production”. Targeted drilling directions for different favorable zones are further optimized based on this model.

Based on the investigation of sedimentary filling characteristics and pool-forming factors of the Mesozoic in the Ordos Basin, the whole petroleum system in the Mesozoic is divided, the migration & accumulation characteristics and main controlling factors of conventional-unconventional hydrocarbons are analyzed, and the whole petroleum system model is established. First, the Mesozoic develops whole petroleum system specialized by continuous and orderly accumulations, with more unconventional resources than conventional resources, in which high-quality source rocks of Chang 7 member serve as the core and low-permeability unconventional oil reservoirs are dominant. It can be divided into four hydrocarbon accumulation domains, including intra-source retained hydrocarbon accumulation domain, near-source tight hydrocarbon accumulation domain, far-source conventional hydrocarbon accumulation domain, and transitional hydrocarbon accumulation domain. Second, the sedimentary filling core is the oil-rich core of the whole petroleum system. From the core to the periphery, the reservoir type evolves as shale oil → tight oil → conventional oil, the accumulation power is dominated by overpressure drive → buoyancy or overpressure and capillary force, the reservoir scale changes from extensive billions of tons to a dispersed hundreds thousands-million tons, and the gas-oil ratio and methane content decrease. Third, the sedimentary structure provides the material basis and spatial framework for the whole petroleum system, the superimposed sand body, fault and unconformity control the dominant migration pathway of hydrocarbons in the far-source conventional hydrocarbon accumulation domain and the transitional hydrocarbon accumulation domain, the quality of source rocks and the micro-nano pore throat-fracture network play the key roles in the intra-source accumulation of shale oil, and the hydrocarbon migration and accumulation process is mainly controlled by intense expulsion of hydrocarbon under overpressure in the pool-forming stage and the in-situ re-enrichment under negative pressure in post-pool-forming stage. The long-term preservation of the system depends on the coordination among three factors (stable geological structure, multi-cycle sedimentary textures, and dual self-sealing). Fourth, the whole petroleum system model is defined as four domains, overpressure + negative pressure drive, and dual self-sealing.

Particle image velocimetry technology was employed to investigate the planar three-dimensional velocity field and the mechanisms of proppant entry into branch fractures in a 90° intersecting fracture configuration of “vertical main fracture-vertical branch fracture”. This study analyzed the effects of pumping rate, fracturing fluid viscosity, proppant particle size, and fracture width on the transport behavior of proppant into branch fractures. Based on the deflection behavior of proppant, the main fractures can be divided into five regions: pre-entry transition, pre-entry stabilization, deflection entry at the fracture mouth, rear absorption entry, and movement away from the fracture mouth. Proppant primarily deflects into the branch fracture at the fracture mouth, with a small portion drawn in from the rear of the intersection. Increasing the pumping rate, reducing the proppant particle size, and widening the branch fracture are conducive to promoting proppant deflection into the branch. With increasing fracturing fluid viscosity, the ability of proppant to enter the branch fracture first improves and then declines, indicating that excessively high viscosity is unfavorable for proppant entry into the branch. During field operations, a high pumping rate and micro- to small-sized proppant can be used in the early stage to ensure effective placement in the branch fractures, followed by medium- to large-sized proppant to ensure adequate placement in the main fracture and enhance the overall conductivity of the fracture network.

Based on the Low Frequency Distributed Acoustic Sensing (LF-DAS) fiber optic monitoring and downhole hawk-eye imaging results, the fluid and proppant distribution and perforation erosion of all clusters during hydraulic fracturing were evaluated, and then a fully coupled wellbore-perforation-fracture numerical model was established to simulate the whole process of slurry migration and analyze key influencing factors. The results show that the proppant and fracturing fluid exhibit divergent flow pathways during multi-staged, multi-cluster fracturing in horizontal wells, resulting in significant heterogeneity in the fluid-proppant distribution among clusters. Perforation erosion is prevalent, and perforation erosion and proppant distribution have phase bias. Notably, the trajectory of proppant transport is controlled by the combined effects of inertia of particle migration and gravity settlement. The inertial effect is dominant at the wellbore heel, where the fluid flow rate is high, hindering particles turning into perforations and causing uneven proppant distribution among clusters. On the other hand, gravity settlement is more pronounced toward the wellbore toe, where the fluid flow rate is low, leading to enhanced phase-bias of slurry distribution and perforation distribution/erosion. Increasing the pumping rate reduces the influence of gravity settlement, mitigating the phase bias of proppant distribution and perforation erosion. However, the large pumping rate limits the proppant distribution efficiency near the heel clusters, and more proppants accumulate towards the toe clusters. High-viscosity fluids improve particle suspension, achieving more uniform proppant distribution within wellbore and fractures. Larger particle sizes exacerbate proppant distribution differences among clusters and perforations, limiting the proppant placement range within fractures.

In the ultra-deep strata of the Tarim Basin, the vertical growth process of strike-slip faults remains unclear, and the vertical distribution of fractured-cavity carbonate reservoirs is complex. This paper investigates the vertical growth process of strike-slip faults through field outcrop observations in the Keping area, interpretation of seismic data from the Fuman oilfield, and physical simulation experiments. The result are obtained mainly in four aspects. First, field outcrops and ultra-deep seismic profiles indicate a three-layer structure within the strike-slip fault, consisting of fault core, fracture zone, and primary rock. The fault core can be classified into three parts vertically: fracture-cavity unit, fault clay, and breccia zone. The distribution of fracture-cavity units demonstrates a distinct pattern of vertical stratification, owing to the structural characteristics and growth process of the slip-strike fault. Second, the ultra-deep seismic profiles show multiple fracture-vuy units in the strike-slip fault zone. These units can be classified into four types: top fractured, middle connected, deep terminated, and intra-layer fractured. Third, physical simulation experiments and ultra-deep seismic data interpretation reveal that the strike-slip faults have evolved vertically in three stages: segmental rupture, vertical growth, and connection and extension. The particle image velocimetry (PIV) detection demonstrates that the initial fracture of the fault zone occurred at the top or bottom and then evolved into cavities gradually along with the fault growth, accompanied by the emergence of new fractures in the middle part of the strata, which subsequently connected with the deep and shallow cavities to form a complete fault zone. Fourth, the ultra-deep carbonate strata primarily develop three types of fractured-cavity reservoirs: large and deep fault, flower-shaped fracture, and staggered overlap. The first two types are larger in size with better reservoir conditions, suggesting a significant exploration potential.

Lacustrine shale oil in China exhibits a huge resource potential but a highly heterogeneous distribution. Deciphering its intra-source micro-migration and enrichment mechanisms is crucial for accurately predicting geological sweet spots. Taking the Chang7₃ submember of the Yanchang Formation in the Ordos Basin as an example, we integrated high-resolution scanning electron microscopy (SEM), optical microscopy, laser Raman spectroscopy, rock pyrolysis, and organic solvent extraction experiments to identify solid bitumen of varying origins, obtain direct evidence of intra-source micro-migration of shale oil, and establish the coupling between the shale nano/micro-fabric and the oil generation, micro-migration and accumulation. The results show that the Chang7₃ shale with rich alginite in laminae has the highest hydrocarbon generation potential but a low thermal transformation ratio. Frequent alternations of micron-scale argillaceous-felsic laminae enhance expulsion efficiency, yielding consistent aromaticity between in-situ and migrated solid bitumen. Argillaceous laminae rich in terrestrial organic matter (OM) and clay minerals exhibit lower hydrocarbon generation threshold but stronger hydrocarbon retention capacity, with a certain amount of light oil/bitumen preserved to differentiate the chemical structure of in-situ versus migrated bitumen. Tuffaceous and sandy laminae contain abundant felsic minerals and migrated solid bitumen. Tuffaceous laminae develop high-angle microfractures under shale overpressure, facilitating oil charging into rigid mineral intergranular pores of sandy laminae. Fractionation during micro-migration progressively decreases the aromaticity of solid bitumen from shale, through tuffaceous and argillaceous, to sandy laminae, while increasing light hydrocarbon components and enhancing OM-hosted pore development. The intra-source micro-migration and enrichment of the Chang7₃ shale oil result from synergistic organic-inorganic diagenesis, with compositional fractionation being a key mechanism for forming laminated sweet spots.

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) ˃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 <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. Based on these findings, 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 structural configuration (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.

The Mid-Permian geomorphic transition in the Sichuan Basin is critical for understanding the development of large-scale reservoir facies belts in the Maokou Formation. This study reconstructed the paleo-uplift and depression differentiation patterns within the sequence stratigraphic framework of the Maokou Formation and investigated its tectono-sedimentary mechanisms based on analysis of outcrops, loggings and seismic data. The results show that the Maokou Formation comprises two third-order sequences (SQ1 and SQ2), six fourth-order sequences (SSQ1-SSQ6), and four distinct slope-break zones developing progressively from north to south. Slope-break zones I-III in the northern basin, controlled by synsedimentary normal faults, exhibited a NE-trending linear distribution and gradual southeastward migration. In contrast, slope-break zone IV in the southern basin displayed an arcuate distribution along the Emeishan Large Igneous Province (ELIP). The evolutions of these multistage slop-break zones governed the Middle Permian paleogeomorphic transformations from a giant, north-dipping gentle slope (higher in the southwest than in the northeast) in the early-stage (SSQ1-SSQ2) to a platform (south)-basin (north) pattern in the middle-stage (SSQ3-SSQ5), culminating a further depression zone in the southwestern basin to construct a paleo-uplift sandwiched by two depressions during the late-stage (SSQ6). The developments of paleogeomorphy reflected the combined control by the rapid subduction of the Paleo-Tethyan Mianlue Ocean and the episodic eruptions of the Emeishan mantle plume (or hot spots), which jointly facilitated the formation of extensive high-energy shoal facies belts along slope-break zones and around paleo-volcanic uplifts.

Based on previously published data from natural gas samples across spring water systems and sedimentary basins (e.g. Songliao, Bohai Bay, Sanshui, Sichuan, Ordos, Tarim, and Yingqiong), this paper systematically compares the geochemical and isotopic characteristics of abiogenic versus biogenic gases. Emphasis is placed on the diagnostic signatures of abiogenic alkane gases in terms of gas composition, and carbon, hydrogen and helium isotopes. The main findings are as follows. (1) In hydrothermal spring systems, abiogenic alkane gases are extremely scarce. Methane concentrations are typically less than 1%, with almost no detectable C₂₊ hydrocarbons. The gas is dominantly composed of CO₂, while N₂ is the major component in a few samples. (2) Abiogenic alkane gases display distinct isotopic signatures, including enriched methane carbon isotopes (δ¹³C₁>-25‰ generally), complete carbon isotopic reversal (δ¹³C₁>δ¹³C₂>δ¹³C₃>δ¹³C₄), and enriched helium isotope (R/R_a>0.5, CH₄/³He<10¹⁰ generally). (3) The hydrogen isotopic composition of abiogenic alkane gases may be characterized by a positive sequence (δD₁<δD₂<δD₃), or a complete reversal (δD₁>δD₂>δD₃), or a V-shaped distribution (δD₁>δD₂<δD₃). The hydrogen isotopic compositions of methane generally show limited variation (about 9‰), possibly due to isotopic exchange with formation water. (4) In identifying gas origin, CH₄/³He-R/R_a and δ¹³C_CO2-R/R_a charts are more effective than CO₂/³He-R/R_a chart. These new geological insights provide theoretical clues and diagnostic charts for genetic identification of natural gas and further research on abiogenic gases.

Currently, unconventional reservoirs are characterized by low single well-controlled reserves, high initial production, and fast production decline. This paper sorts out the problems of energy dispersion and limited length and height of main hydraulic fractures induced in staged multi-cluster fracturing, and proposes an innovative concept of “energy-focused fracturing (EFF)”. The technical connotation, theoretical model, and core techniques of EFF are systematically examined, and the implementation path of this technology is determined. The EFF technology incorporates the techniques such as geology-engineering integrated design, perforation optimization design, fracturing process design, and drainage engineering control. It transforms the numerous, short and dense artificial fractures to limited, long and sparse fractures. It focuses on fracturing energy, and aims to improve the fracture length, height and lateral width, and the proppant long-distance transportation capacity, thus enhancing the single well-controlled reserves and development effect. The EFF technology has been successfully applied in the carbonate reservoirs in the Yangshuiwu buried hill, shallow coalbed methane reservoirs, and coal-rock gas reservoirs in China, demonstrating the technology’s promising application. It is concluded that the EFF technology can significantly increase the single well production and estimated ultimate recovery (EUR), and will be helpful for efficiently developing low-permeability, unconventional and low-grade resources in China.

Guided by the fundamental principles of the whole petroleum system, the controls of tectonism, sedimentation, and diagenesis on hydrocarbon accumulation in a fault basin is studied using the data of petroleum geology and exploration of the second member of the Paleogene Kongdian Formation (Kong-2 Member) in the Cangdong Sag, Bohai Bay Basin, China. It is clarified that the circle structure and circle effects are the marked features of a continental fault petroleum basin, and they govern the orderly distribution of conventional and unconventional hydrocarbons in the whole petroleum systems of the fault basin. Tectonic circle zones control sedimentary circle zones, while sedimentary circle zones and diagenetic circle zones control the spatial distribution of favorable reservoirs, thereby determining the hydrocarbon accumulation orderly distribution of reservoir types in various circles. A model for the integrated, systematic aggregation of conventional and unconventional hydrocarbons under a multi-circle structure of the whole petroleum system of continental fault basin has been developed. It reveals that each sub-basin of the fault basin is an independent whole petroleum system and circle system, which encompasses multiple orderly circles of conventional and unconventional hydrocarbons controlled by the same source kitchen. From the outer circle to the middle circle and then to the inner circle, there is an orderly transition from structural and stratigraphic reservoirs, to lithological and structural-lithological reservoirs, and finally to tight oil/gas and shale oil/gas enrichment zones. The significant feature of the whole petroleum system is the orderly control of hydrocarbons by multi-circle stratigraphic coupling, with the integrated, orderly distribution of conventional and unconventional reserves being the inevitable result of the multi-layered interaction within the whole petroleum system. This concept of multi-circle stratigraphic coupling for the orderly, integrated accumulation of conventional and unconventional hydrocarbons has guided significant breakthroughs in the overall, three-dimensional exploration and shale oil exploration in the Cangdong Sag.

Accurate identification of natural gas origin is fundamental to exploration deployment and resource potential assessment. Since the 1970s, Academician Dai Jinxing has developed a comprehensive system for natural gas origin determination, grounded in geochemical theory and practice, and based on the integrated analysis of stable isotopes, molecular composition, light hydrocarbon fingerprints, and geological context. This paper systematically reviews the core framework established by him and his team, focusing on the conceptual design and technical pathways of key diagnostic diagrams such as δ¹³C₁-C₁/(C₂+C₃), δ¹³C₁-δ¹³C₂-δ¹³C₃, δ¹³C-CO₂ versus CO₂ content, and the C₇ light hydrocarbon triangular plot. We evaluate the applicability and innovation of these tools in distinguishing between oil-type gas, coal-derived gas, biogenic gas, and abiogenic gas, as well as in identifying mixed-source gases and multiphase charging systems. The findings suggest that this diagnostic system has significantly advanced natural gas geochemical interpretation in China, shifting from single-indicator analyses to multi-parameter integration and from qualitative assessments to systematic graphical identification, and has also exerted considerable influence on international research in natural gas geochemistry. This review aims to provide a structured overview of the development trajectory of natural gas origin discrimination methodologies and offer a scientific foundation for the academic evaluation and practical application of related achievements.

Taking the Wangfu Rift 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 Rift 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 control 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 criteria 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.

In the late 1970s, the theory of coal-formed gas began to take root, sprout, develop, and improve in China. After decades of development, a complete theoretical system was finally formed. The theory of coal-formed gas points out that coal measures are good gas source rocks, with gas as the main hydrocarbon generated and oil as the auxiliary. It has opened up a new exploration idea using coal-bearing humic organic matter as the gas source, transforming the theoretical guidance for natural gas exploration in China from “monism” (i.e. oil-type gas) to “dualism” (i.e. coal-formed gas and oil-type gas) and uncovering a new field of natural gas exploration. Before the establishment of the coal-formed gas theory, China was a gas-poor country with low proven reserves (merely 2 264.33×10⁸ m³) and production (137.3×10⁸ m³/a), corresponding to a per capita annual consumption of only 14.37 m³. Guided by the theory of coal-formed gas, China’s natural gas industry has developed rapidly. By the end of 2023, China registered a cumulative proven gas geological reserves of 20.90×10¹² m³, an annual gas production of 2 343×10⁸ m³, and a per capita domestic gas consumption reaching 167.36 m³. The cumulative proven geological reserves and production of natural gas were dominated by coal-formed gas. Owing to this advancement, China has transformed from a gas-poor country to the fourth largest gas producer in the world. The coal-formed gas theory and the tremendous achievements made in natural gas exploration in China under its guidance have been highly praised by renowned scholars globally.

Based on the comprehensive analysis of data from petrology, well logging, seismic surveys, paleontology, and geochemistry, a detailed research was conducted on the tectonic-sedimentary setting, and paleoenvironmental and paleoclimatic conditions of the source rocks in the second member of the Eocene Wenchang Formation (Wen 2 Member) in the Shunde North Sag at the southwestern margin of the Pearl River Mouth Basin. The Wen 2 Member hosts excellent, thick lacustrine oil shales 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 organic 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 strong fault depression, excellent source rocks were developed in Wen 2 Member in the Shunde North Sag 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. 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 the basic data of drilling, logging, testing and geological experiments, the geological characteristics of the Permian Dalong Formation marine shales in the Sichuan Basin and the factors controlling shale gas enrichment and high yield in these shales 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 Wujiaping Formation, and it is mainly developed in the Kaijiang-Liangping trough in the northern part of Sichuan Basin, where deep-water continental shelf facies and deep-water reduction environment where siliceous organisms flourished have formed the black siliceous shale rich in organic matter. Second, the Dalong Formation shale contains both organic and inorganic pores, with stratification of alternating brittle and plastic minerals, which was stacked with severe compaction to enlarge the fractures, thereby improving the permeability. In addition to organic pores, a large number of inorganic pores are developed even in the ultra-deep (˃4 500 m) layers, contributing a total porosity of more than 5% and a permeability of 0.2×10^-3 μm², which significantly expands the accommodation space for shale gas. Third, the limestone at the roof and floor of the Dalong Formation acted as a seal 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 <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 <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.

The Carter model is used to characterize the dynamic behaviors of fracture growth and fracturing fluid leakoff. A thermo-fluid coupling 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. The results show that typical V-shaped characteristics can be observed from DTS responses in the multi-cluster fracturing process, with locations corresponding to the created 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.

In order to identify the development characteristics of fracture network in tight conglomerate reservoir of Mahu after hydraulic fracturing, a hydraulic fracturing test site was set up in the second and third members of Triassic Baikouquan Formation (T₁b₂ and T₁b₃) in Ma-131 well area, which learned from the successful experience of hydraulic fracturing test sites in North America (HFTS-1). Twelve horizontal wells and a high-angle cored well MaJ02 were drilled. The occurrence, connection, propagation law and major controlling factors of hydraulic fractures were analyzed by comparing results of CT scans, imaging logs, direct observation of cores from Well MaJ02, and the tracer monitoring data. Results indicate that: (1) Two types of fractures have developed by hydraulic fracturing, i.e. tensile fractures and shear fractures. Tensile fractures are approximately parallel to the direction of the maximum horizontal principal stress, and propagate less than 50 m from the perforation cluster. Shear fractures are distributed among tensile fractures and mainly in the strike-slip mode due to the induced stress field among tensile fractures, and some of them are in conjugated pairs. Overall, tensile fractures alternate with shear fractures, with shear fractures dominated and activated after tensile ones. (2) Tracer monitoring results showed an obvious difference in fracturing and fluid production among different fracturing stages in horizontal wells. Some hydraulic fractures with length exceeding the well spacing gradually close during the fluid production process due to interwell communication. (3) Density of hydraulic fractures is mainly affected by the lithology and fracturing parameters, which is smaller in the mudstone than the conglomerate. Larger fracturing scale and smaller cluster spacing lead to a higher fracture density, which are important directions to improve the well productivity.

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