To address the limitation of conventional macroscopic wettability measurements in characterizing pore-scale wettability distributions in shale, a quantitative method for microscopic wettability characterization was developed. The method improves the conventional Amott approach by integrating nuclear magnetic resonance and high-pressure mercury intrusion porosimetry. Fluid distributions during spontaneous and pressurized imbibition in oil-water and oil-fracturing-fluid systems were measured, and a calculation model for the pore-size-dependent microscopic wettability index was established. The average microscopic wettability index derived from the proposed method agrees well with those obtained from gravimetric and macroscopic NMR measurements, validating the reliability of the method and revealing mixed-wettability characteristics that may be obscured by macroscopic averaging. The method was applied to interbedded, laminated, and mud-laminated shale cores from Well H181-1 in the Chang 7 Member of the Triassic Yanchang Formation, Ordos Basin. The results show that the original macroscopic wettability of the shale is generally neutral to oil-wet, whereas the overall water-wetness of all three core types increases markedly after fracturing-fluid interaction. However, the pore-scale wettability responses vary significantly among the three shale types. In the interbedded shale, local oil-wetness increases in small pores,whereas the intermediate and large pores generally become more water-wet. In the laminated shale, water-wetness increases markedly in small pores, the intermediate pores exhibit heterogeneous responses, and water-wetness decreases in large pores. In the mud-laminated shale, the small and intermediate pores shift toward more water-wet conditions, whereas the large pores exhibit heterogeneous wettability changes. These results clarify the pore-scale wettability distribution characteristics of shale reservoirs and provide a theoretical basis for fracturing-fluid selection, stimulation-parameter optimization, and enhanced oil recovery.

The concept of integrated source-to-sink system (IS2S) is proposed to systematically integrate fine-grained (<62.5 μm) clastic sediments into the source-to-sink framework, bridge the long-standing separation between coarse- and fine-grained sediment research, and unravel the complete sediment-routing system and multi-factor coupling along the source-to-sink pathway. The concept is based on multi-proxy provenance analysis and a comparison of marine and continental sedimentary records. The IS2S framework extends source-to-sink analysis from coarse-grained clasts to the full gravel-to-clay grain-size spectrum of terrigenous clastic sediments, places chemical weathering on an equal footing with physical denudation as a primary control, and unifies characterization of the dynamically coupled clastic and associated dissolved/colloidal fluxes within the same framework. Chemically and biogenically induced precipitates are explicitly treated as independent, parallel pathways outside the clastic grain-size spectrum. The framework further recognizes that coarse-grained sediment deposition is governed mainly by topographic gradients and tractive currents, whereas fine-grained sediment deposition is dominated by suspended transport and flocculated settling. Although terrigenous coarse- and fine-grained clasts share a common provenance, they differ markedly in transport and depositional mechanisms. Compared with coarse-grained source-to-sink systems, fine-grained systems are still constrained by non-unique provenance proxies, complex bottom-current reworking, and marked differences between marine and continental settings. The IS2S is intended primarily to characterize syndepositional sediment composition and depositional-body architecture, and can provide sedimentological constraints on quantitative provenance analysis of fine-grained sediments and on modeling the spatial co-occurrence of conventional and unconventional hydrocarbon accumulations.

Taking the shale of Cretaceous Qingshankou Formation in Songliao Basin as an example, this study adopts experimental methods including X-ray diffraction analysis, field emission electron microscopy, atomic force microscopy, two-dimensional nuclear magnetic resonance, combined with the test of pressure-preserved sealed core ultra-low temperature frozen samples, to discuss the coupling relationship between the diagenetic evolution of organic-clay complex and the “four properties” of shale, i.e., reservoir property, oil-bearing property, mobility and fracability. (1) The oil content of organo-clay complex initially increases and then decreases with increasing diagenesis, with the maximum oil content exceeding twice that of the corresponding bulk shale, indicating a significant contribution to shale oil production. The decrease in oil content of organo-clay complex during the middle diagenetic stage B suggests that a portion of the crude oil has micro-migrated into other shale pores for storage. (2) The BET specific surface area and pore volume of organo-clay complex show a trend of first increasing and then decreasing with diagenetic evolution, reaching maximum values of 65 m²/g and 0.15 cm³/g, respectively, at the end of the middle diagenetic stage A₁. From middle diagenetic stage A₂ to middle diagenetic stage B, volume shrinkage of the organo-clay complex generates abundant organo-clay complex pores and bedding-parallel fractures, resulting in an increase in effective porosity of the shale from 5% to 10% or so. (3) The transformation of clay minerals within the organo-clay complex and the formation of authigenic minerals such as quartz lead to improved shale fracability. In the middle diagenetic stage B, the shale exhibits an elastic modulus greater than 20 GPa, a Poisson’s ratio less than 0.2, and a brittleness index greater than 65%. (4) Both the organo-clay complex and the bulk shale show increasing free oil content with progressive diagenesis, indicating improved shale oil mobility. During the middle diagenetic stages A₂ and B, dehydration of clay minerals results in an increase in pore water content of the shale, reaching a maximum of 11.8 mg/g, which suggests alterations in the wettability of shale flow pathways that are favorable for water-oil displacement and imbibition during hydraulic fracturing. Integrating the shale oil enrichment model and the coupling relationships among the “four properties” parameters, three types of shale oil “sweet spot” zones (intervals) are categorized. The findings of this study hold significant theoretical implications for the exploration evaluation and development practice of continental high-clay-content shale oil.

Based on seismic, drilling, and outcrop data, fault geometry-kinematics analysis and balanced-section restoration were used to define the architecture and boundaries of the Awati Sag, Northern Depression, Tarim Basin, reconstruct its structural evolution history, and identify its hydrocarbon accumulation controls. The Awati Sag presents a framework of wedge-shaped structure with larger thickness in the west than in the east, as a result of multi-stage differential reactivation of the South Kalayuergun, Shajingzi, and Aqia-Tumuxiuke faults. Internally, conjugate and strike-slip fault systems form a multi-stage, vertically differentiated, heterogeneous 3D deformation network with a composite structural style. Its structural evolution history includes two stages: a pre-sag stage, and a sag stage. The former stage can be divided into five sub-stages: the Jinningian rifting center, the Early-Middle Caledonian intracratonic depression, the Middle-Late Caledonian post-uplift of the peripheral foreland basin, the Early-Middle Hercynian northwestern Tarim paleo-uplift, and the Late Hercynian rifting center, while the later stage into 3 sub-stages: the Indosinian embryonic sag, the Yanshanian paleo-uplift slope, and the Himalayan final shaping. Principal source rocks are the high-quality marine Cambrian Yuertusi and Ordovician Saergan formations, supplemented by the Ordovician Yingan Formation and Permian-Triassic coal measures and dark mudstones. Thermal evolution shows the characteristics of long-term shallow burial followed by rapid deep burial. Within the total petroleum system, near-source fractured-vuggy/tight sandstone and far-source structural-lithologic reservoirs form a composite play, with in-source shale oil/gas as a potential target. The eastern slope has the greatest exploration potential.

To address the requirements for comprehensive analysis of multi-source geological information and intelligent decision-making in shale oil exploration and development, this paper proposes a methodology for constructing a domain-specific large language model (LLM) for the shale oil field, along with methods for building and evaluating an LLM-based intelligent agent for shale oil seismic processing and interpretation. Utilizing Qwen2.5-72B and Qwen3-32B as foundation models, we integrated publicly available shale oil literature with domain knowledge graphs to construct a specialized corpus comprising 21 billion tokens. Leveraging expert annotations and model generation, we compiled 58,000 high-quality domain-specific question-answer pairs to form the supervised fine-tuning dataset. We propose a multi-stage, efficient domain-adaptation training framework for shale-oil large language models (LLMs). Domain knowledge is injected via task-aware expanded continual pre-training; supervised fine-tuning is then performed by combining Quantized Low-Rank Adaptation (QLoRA) with context-parallel algorithms. Direct Preference Optimization (DPO) and Group Relative Policy Optimization (GRPO) are employed to align disciplinary preferences and strengthen reasoning capabilities. Furthermore, a reflective retrieval-augmented generation (RAG) framework is constructed to improve the accuracy and interpretability of model outputs. Building on the LLM, we curate a specialized toolkit from open-source geoscience tools and conduct tool-use-oriented supervised fine-tuning to enhance the model’s tool-calling capability while effectively mitigating hallucinations during tool invocation. Leveraging the Model Context Protocol (MCP), we deploy an intelligent scheduling service that deeply integrates such core functionalities as seismic data processing, seismic interpretation, visualization and report generation, and construct an LLM-driven agent for shale-oil seismic processing and interpretation. Experimental evaluations demonstrate that the shale-oil LLM significantly outperforms general-purpose base models in professional question answering and has superior domain-adaptation performance. After tool-use supervised fine-tuning, its tool-calling capability is substantially improved compared with open-source base models.

This study integrates modern and ancient sedimentological analogs, as well as surface and subsurface geological analyses, using outcrops, modern sediments, cores, well logs, seismic data, production data, and laboratory test data to comprehensively investigate the geologic age and distribution the Kalazha Formation in the southern Junggar Basin, and its relationship with the Qingshuihe Formation. The results are obtained in four aspects. First, the Kalazha Formation comprises a series of sandy and gravelly distributive fluvial systems (DFSs) in the piedmont zone of the southern Junngar Basin. These systems vary in scale and sedimentary facies, including coarse-grained alluvial fan, fluvial fan, sandy fluvial mega-fan, and their relative (fan) deltas. The Kalazha Formation is widely distributed across the southern Junggar Basin, forming apron-like bodies along the basin margin, with thickness decreasing from south to north and from east to west. The Kalazha Formation is also well developed in the western part of the southern Junggar Basin. Third, the Kalazha Formation conglomerates and the Qingshuihe Formation sand-mudstones are alternating and superimposed vertically near the piedmont outcrop, exhibiting continuous deposition and a conformable contact. Laterally, they represent contemporaneous difference facies. Towards the basin center, the Kalazha Formation conglomerates gradually thin, pinch out, and transition to the fine-grained deposits of the Qingshuihe Formation and the Tugulu Group. Four, the stratigraphic affiliation of the Kalazha Formation is related to the Jurassic-Cretaceous boundary in the southern margin of the Junggar Basin. However, the delineation of this boundary remains uncertain. It is suggested that more biostratigraphic and chronostratigraphic data be accumulated. Drilling results confirm that the Kalazha Formation has the basic conditions to contribute high-quality hydrocarbon reservoirs. Future research should strengthen quantitative characterization of sedimentary systems in this interval and pay attention to the associated lithofacies paleogeographic changes during the Jurassic-Cretaceous transition, thereby providing more evidence for hydrocarbon exploration.

Taking the Permian clastic buried-hill reservoirs in the Jiyang Depression, Bohai Bay Basin, China, as the research object, core samples, thin-section observations and experimental/test data were utilized to investigate reservoir characteristics and diagenetic fluid types/assemblages, and identify the reservoir-controlling factors. On this basis, a reservoir-controlling model was established. The results show that four types of diagenetic fluids are developed in the clastic buried-hill reservoirs, namely alkaline water associated with tuffaceous alteration, meteoric fresh water, hydrothermal fluid, and organic acid. Fluid assemblages vary distinctly among different buried-hill reservoirs. The Gubei buried-hill is characterized by the assemblage of meteoric fresh water + volcanic hydrothermal fluid + organic acid. The Gaoqing buried-hill and the Yihezhuang-Dawangzhuang area both develop the assemblage of alkaline water associated with tuffaceous alteration + meteoric fresh water (relatively weak) + organic acid. Among these fluids, meteoric fresh water and organic acid exert constructive modification on reservoir quality. Reservoirs are synergistically controlled by multiple factors such as fault-related fractures, weathering crust, soluble sedimentary components, and diagenetic fluids. The established “three-element and six-factor” reservoir-controlling model yields predictions that display a significant positive correlation with measured reservoir physical properties. Sand bodies with coarse grains, large thickness and abundant tuffaceous components formed during the sedimentary period provide the material basis for high-quality reservoir formation. Meteoric fresh water dissolves soluble components within reservoirs during the uplifting stage, whereas organic acid improves reservoir quality via further dissolution during the burial stage. The proposed model supplies new geological theoretical support for the prediction of clastic buried-hill reservoirs.

Application of CO₂ pre-fracturing to displace the shale oil of the Permian Fengcheng Formation in the Mahu Sag, the Junggar Basin, suffers from gas channeling, asphaltene precipitation, emulsification and viscosity increase of crude oil under fracturing impact, and low utilization rate of CO₂. To address these problems, a high-temperature and high-pressure visual silicon tube experimental system was used, together with Raman-infrared microscope and stereoscope, to study the interaction between CO₂ and crude oil in fractures and microfissures, and to reveal the influence mechanism of solubilizer on the dissolution characteristics, foam oil behavior and flow stability of CO₂-crude oil system. The results show that, during displacement at higher pressure, the solubilizer can greatly reduce the start-up pressure and oil-water interfacial tension of CO₂-crude oil system, enhance the dissolution and retention capacity of CO₂ in crude oil, form a stable and fine foam oil structure, inhibit bubble aggregation and delay gas release, thereby delaying the process of gas channeling, and improving the sweep and oil displacement efficiency of CO₂. The effect is better when the mass fraction of solubilizer is 1.0%. During production at lower pressure, the solubilizer can inhibit the precipitation of resin and asphaltene by means of peptization, thus reducing the risk of plugging near wellbore and in pore throat, and improving the mobility of crude oil in hydraulic fractures. The field data confirm that the solubilizer performs well in increasing production, and it provides a technical option for the efficient development of shale oil in the Mahu Sag.

Focusing on Shunbeilong 2, a well with commercial oil/gas flow from the Ordovician Penglaiba Formation in the dome structure in the Shunbei area in the Tarim Basin of China, the drilling, logging, testing and thin-section data were integrated for petrologic analysis, microscopic temperature measurement of fluid inclusions, C/O isotope analysis, trace element analysis, and U-Pb dating. The pore space, fluid properties/origin, and controlling factors of the Penglaiba Formation reservoirs were delineated, together with their genetic mechanisms. Finally, a reservoir development model was established. The results indicate that the Penglaiba Formation dolomite reservoirs are distributed in the form of thin interbeds and quasi-layers, with the pore space consisting of fabric-selective vugs which are superimposed by reticular fractures. Image logging data reveal a weak correlation between vug intervals and fracture intervals, demonstrating that vugs were formed primarily under the control of high-frequency sequence boundaries. The matrix is predominantly composed of medium-to-coarse crystalline dolomite, with minor fine crystalline dolomite and late calcite cements. The U-Pb age of medium-to-coarse crystalline dolomite is dated to 464±14 Ma; this dolomite shares inherited seawater-derived dolomitizing fluid signatures with fine crystalline dolomite and vug-filling dolomite cements. The homogenization temperatures of fluid inclusions hosted in secondary quartz and late calcite are concentrated at 150 ℃-160 ℃ and 130 ℃-140 ℃, respectively, and the in-situ U-Pb age of late calcite yields 450±3.4 Ma. It is proposed that the Penglaiba Formation dolomite reservoirs have evolved in four stages: selective dissolution controlled by high-frequency sequence boundaries during the penecontemporaneous period; dolomitization under shallow burial conditions; hydrothermal fluid modification of carbonate rocks along fault-fracture systems; and reworking by superimposed reticular fractures.

The current status of volume fracturing technology is reviewed for continental shale oil reservoirs in China. Considering the limited hydraulic fracture propagation and proppant transport under the prevailing “long-fracture” volume fracturing model in horizontal wells, a new “wide-short fracture” volume fracturing model is proposed to fully stimulate the reservoir in the near-wellbore zone, in accordance with four principles: multi-cluster fracture placement, balanced fracture propagation, appropriate treatment scale, and economics-based parameter selection. Beyond the energy allocation pattern in current fracturing practices, the new model is designed logically to concentrate fracturing energy in the near-wellbore zone region. This redistribution enables balanced propagation of multiple fractures and full-domain propping, thereby enhancing the connectivity between the fracture system and the oil-bearing matrix, expanding the fracture-controlled reservoir volume, and achieving coordinated reservoir control by wells and fractures. Five core elements underpin the proposed fracturing design: refined geological modelling of the in-situ stress field; techniques for controlling balanced fracture propagation; high-density perforating with uniform entry-hole diameters; techniques for full-domain propping of complex fracture systems; and a framework for jointly optimizing well patterns and well spacing. Comparative numerical model predictions for different fracturing models indicate that the proposed model can substantially increase both total ultimate recoverable reserves and the ultimate oil recovery factor at the well-pad scale in continental shale oil reservoirs. These findings can provide a theoretical basis and engineering support for the large-scale, cost-effective development of continental shale oil reservoirs in China.

Dolomite reservoirs are important targets for oil and gas production. However, the correlation among types, spatial distribution, geometric configurations, and seismic responses of large-scale dolomite reservoirs remains unclear, hindering the reservoir prediction and hydrocarbon exploration. This study establishes a database of Neoproterozoic-Lower Paleozoic dolomite reservoirs in the Tarim Basin and conducts comparative and analogical analyses between basin data and global data, in order to investigate the coupling among formation mechanisms, spatial distribution, internal configurations, and seismic responses of large-scale dolomite reservoirs. The database includes data from 16 oil and gas fields/reservoirs in the Tarim Basin, data from some regional exploration wells that encountered dolomite reservoirs but have not revealed oil and discoveries, as well as data from typical global dolomite hydrocarbon reservoirs. The analysis results indicate that the dolomite reservoirs are governed by the superimposition of multiple factors, but their spatial distribution and geometric configurations are primarily decided by three mechanisms: sedimentation, karstification, and tectonism. Accordingly, the dolomite reservoirs are classified into sedimentary, karst, and tectonic types. Through reservoir configurations analysis and global comparison, ten subtypes of dolomite reservoirs are identified. Finally, the patterns of coupling among types, spatial distribution, geometric configurations, and seismic responses of dolomite reservoirs are clarified, and the geological models and seismic identification markers for each subtype are established, providing reference for geological survey and practical exploration of oil and gas in dolomite reservoirs.

The Sinian Dengying Formation in central Sichuan Basin is characterized by complex hydrocarbon accumulation processes, significant uncertainties regarding the timing of paleo-oil reservoir formation, and a limited availability of absolute age data. In this study, petrographic observations, fluid inclusion analysis, carbonate U-Pb dating, and paleo-oil-water interface reconstruction were integrated to decipher the diagenetic-hydrocarbon accumulation evolution sequence of the Dengying Formation reservoirs in central Sichuan Basin and to precisely clarify the formation timing of paleo-oil reservoirs. The results reveal that the first-stage paleo-oil reservoirs with a limited scale were formed in the Late Cambrian-Early Ordovician, and the second-stage large-scale paleo-oil reservoirs were formed during the Middle Triassic, approximately 30 million years earlier than the previously proposed Late Triassic. The paleo-uplift of the Dengying Formation was more extensive during the Middle Triassic than in the Late Triassic, which controlled a broader distribution of paleo-oil reservoirs. These paleo-oil reservoirs exhibited features of widespread contiguous oil-bearing, quasi-continuous distribution, and relative enrichment in structural highs, providing liquid hydrocarbon precursors for the subsequent development of large-scale oil-cracking gas reservoirs. The findings improve our understanding of natural gas exploration potential for the Sinian strata in the Sichuan Basin and suggest favorable gas exploration prospects for structural-lithologic traps within the Central Sichuan paleo-uplift and its peripheral areas.

Under the dual constraints of carbon neutrality and energy security, this study systematically examines the background, advantages, initiatives, and strategic significance of integrated development of oil and gas industry with new energy, based on resource endowment in China characterized by abundant coal, limited oil and gas, and vast renewable energy potential, together with its high dependence on imported oil and gas. Furthermore, the principle of “inexhaustible energy” is revealed according to three global energy development laws: succession, decarbonization and inexhaustibility. The oil and gas industry possesses inherent advantages such as integrated source-grid-load-storage (SGLS) systems, on-site consumption of renewable resources in oil and gas fields, flexible peak-shaving through natural gas-fired power generation, and the evolution of conventional oil and gas fields toward multi-energy systems encompassing power generation, geothermal energy, hydrogen production and carbon management. These advantages provide a solid foundation for deep coupling between fossil fuels and renewable energy. In terms of implementation, a comprehensive integration framework covering upstream and downstream sectors is established and advanced through three successive stages: the clean substitution and demonstration breakthrough stage, the strategic replacement and large-scale integration stage, and the green transition and carbon neutrality realization stage. Strategically, the integrated development can enhance national energy self-sufficiency and system resilience, accelerate deep decarbonization of the oil and gas industry and its transition toward integrated energy services, provide a Chinese solution for the smart integration of oil, gas and new energy, and strengthen the influence of China in global green energy governance. The integrated development of oil, gas, and new energy represents an indispensable pathway toward safeguarding national energy security, fulfilling China’s dual-carbon goals, and building an energy powerhouse.

This study compares the apparent hydrogen diffusion characteristics of typical rocks, their controlling factors, and the sealing performance of different caprocks. A two-chamber gas diffusion apparatus was used to determine the apparent diffusion coefficient (D_app) of 25 sedimentary, igneous, and metamorphic rock samples under isobaric conditions at 0.1 MPa. Representative samples were further tested for the effects of temperature, effective stress, water content, and counter-diffusing gas composition, followed by one-dimensional diffusion simulations using the measured parameters. The results show that: (1) At an effective stress of 1 MPa, D_app ranges from 2.54×10^-9 to 358.43×10^-9 m²/s, with most values between 10×10^-9 and 100×10^-9 m²/s, and is positively correlated with porosity. Hydrogen diffusion is relatively high in sandstones, coals, and some high-porosity shales and carbonate rocks. The tested basalt, granite, and diabase samples show low to moderate diffusion, whereas the tested serpentinite and salt rock samples exhibit lower diffusion. (2) Increasing temperature from 278.15 to 318.15 K increases D_app by 11.9%-34.4%. Increasing effective stress causes an exponential decrease in D_app, with stress sensitivity decreasing in the order of salt rock, serpentinite, diabase, shale, sandstone, and limestone. Increasing water content markedly suppresses hydrogen diffusion. (3) Compared with N₂, CH₄ causes only minor changes in D_app, whereas CO₂ reduces D_app by an average of 8.6%. (4) Increasing caprock thickness and water content reduces hydrogen diffusion and loss. Among the selected caprock samples, dry salt rock shows the strongest sealing performance, while shale performs no worse than diabase at comparable water contents. Overall, apparent hydrogen diffusion coefficient is jointly controlled by porosity, pore-throat structure, connectivity, effective stress, and water content. Caprock sealing evaluation should therefore consider lithology, thickness, effective connectivity, and in-situ water conditions.

To systematically examine the paradigm shift of sedimentary paleogeography research driven by artificial intelligence, and clarify the technical integration pathways and core challenges, this study combines theoretical analysis and typical case analysis to summarize the multi-dimensional characteristics of the paradigm shift and explore a new framework for intelligent paleogeographic reconstruction. The results show that the paradigm of sedimentary paleogeography research is undergoing a systematic transformation across four dimensions: the data foundation shifts from experience-driven to data-driven, the cognitive mode from qualitative description to quantitative characterization, the prediction target from static representation to dynamic prediction, and the decision-making mode from single-discipline analysis to systematic decision-making. Accordingly, a comparative framework of traditional empirical, digital, and intelligent paradigms is constructed. In three key aspects, i.e. paleogeographic reconstruction, sedimentary process simulation, and reservoir parameter prediction, the methods such as knowledge graphs, physics-informed neural networks, and ensemble learning have demonstrated significant integration effectiveness. Furthermore, a technical workflow framework for intelligent paleogeographic reconstruction is proposed, encompassing core modules including multi-source data fusion, knowledge graph constraints, machine learning prediction, expert validation, and feedback iteration. This work provides a systematic theoretical reference and technical pathway for the digital-intelligence transformation of sedimentary paleogeography.

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.

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.