A three-dimensional multiphase particle-in-cell (MP-PIC) method was adopted to establish a liquid-solid two-phase flow model accounting for complex fracture networks. The model was validated using physical experimental data. On this basis, the main factors influencing proppant transport in fracture network were analyzed. The study shows that proppant transport in fracture network can be divided into three stages: initial filling, dominant channel formation and fracture network extension. These correspond to three transport patterns: patch-like accumulation near the wellbore, preferential placement along main fractures, and improved planar placement as fluid flows into branch fractures. Higher proppant density, lower fracturing fluid viscosity, lower injection rate, and larger proppant grain size result in shorter proppant transport distance and smaller planar placement coefficient. The use of low-density, small-diameter proppant combined with high-viscosity fracturing fluid and appropriately increased injection rate can effectively enlarge the stimulated volume. A smaller angle between the main fracture and branch fractures leads to longer proppant banks, broader coverage, more uniform distribution, and better stimulation performance in branch fractures. In contrast, a larger angle increases the likelihood of proppant accumulation near the branch fracture entrance and reduces the planar placement coefficient.

Based on the plate tectonics theory, the sedimentary environment of paleotectonics along the passive continental margins on both sides of the South Atlantic Ocean was reconstructed using the paleomagnetic, regional geological, and seismic data, and the intrinsic relationships of hydrocarbon distribution in the passive continental margin basins and the differential hydrocarbon accumulation patterns were analyzed. Results show that basins on both sides of the South Atlantic experienced two major extensional phases—rift and depression—and four evolutionary stages: the Early Cretaceous Berriasian-Barremian intracontinental rift stage, the Early Cretaceous Aptian-Albian intercontinental rift to initial drift transition stage, the Late Cretaceous-Paleogene drift-related marine transgressive depression stage, and the Neogene-Quaternary drift-related marine regressive depression stage. According to basin architecture and superposition style, the passive-margin basins are classified into two principal types: rift-continental marginal depression composite and continental marginal depression-dominated. The basins in the study area were further divided into six types based on the development degree of salt tectonics and the type of dominant sand bodies, i.e. salt-free rift-continental marginal gravity-flow composite type, salt-free rift-continental marginal delta composite type, salt-bearing rift-continental marginal gravity flow composite type, delta-dominated salt-bearing rift-continental marginal delta composite type, gravity-flow-dominated continental marginal depression type, and delta-dominated continental marginal depression type. The salt-free rift-continental marginal gravity flow and delta composite basins are mainly distributed in the southern segment. The salt-bearing rift-continental marginal gravity flow and delta composite basins are mainly distributed in the central segment. The gravity-flow-dominated continental marginal depression basins are mainy distributed in the northern segment. The delta-dominated passive-margin depression basins are distributed in three segments from north to south. In different types of basins, distinctive depositional systems and source-reservoir-caprock assemblages were formed in each upper/lower structure layer. The superimposition and evolution of multi-phase prototype basins result in the orderly hydrocarbon accumulation vertically and laterally, which are “segmented along-strike, zoned across-strike, and layered vertically”.

Based on the data of regional geology, seismic, drilling, logging and production performance obtained from 94 major petroliferous basins worldwide, the global coal resources were screened and statistically analyzed. Then, using established definition methods and evaluation criteria for coal-rock gas in China, and by analogy with the tectono-sedimentary and burial-thermal evolution conditions of coal rocks in sedimentary basins within China, the geological resource potential of global coal-rock gas was estimated mainly by the volume method, partly by the volumetric method in selected regions. According to the evaluation indicator system comprising 14 parameters under 5 categories and the associated scoring criteria, the target basins were ranked, and the future research targets for these basins were proposed. The results reveal that, globally, coal rocks are primarily formed in four types of swamp environments within four categories of prototype basins, and distributed across five major coal-forming periods and eight coal-accumulation belts. The total geological coal resources are estimated at approximately 42×10¹² t, including 22×10¹² t in the strata deeper than 1 500 m. The global geological coal-rock gas resources in deep strata are roughly 232×10¹² m³, of which over 90% are endowed in Russia, Canada, the United States, China and Australia, with China contributing 24%. The top 10 basins by coal-rock gas resource endowment, i.e. Alberta, Kuznetsk, Ordos, East Siberian, Bowen, West Siberian, Sichuan, South Turgay, Lena-Vilyuy and Tarim, collectively hold 75% of the global total. The Permian, Cretaceous, Carboniferous, Jurassic, and Paleogene-Neogene account for 32%, 30%, 18%, 10%, and 7% of total coal-rock gas resources, respectively. The 10 most practical basins for future coal-rock gas exploration and development are identified as Alberta, Ordos, Kuznetsk, San Juan, Sichuan, East Siberian, Rocky Mountain, Bowen, Junggar and Qinshui. Propelled by successful development practices in China, coal-rock gas is now entering a phase of theoretical breakthrough, technological innovation, and rapid production growth, positioning it to spearhead the next wave of the global unconventional oil and gas revolution.

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 investigate the fracture initiation and propagation behavior of fractures in tight sandstone under the shaped-charge impulse of supercritical CO₂ (SCCO₂), laboratory fracturing experiments were conducted using a true-triaxial-like SCCO₂ shaped-charge impulse fracturing system. Computed tomography (CT) scanning and three-dimensional fracture reconstruction were employed to elucidate the effects of shaped-charge pressure, pore pressure, and in-situ stress on fracture characteristics. In addition, nuclear magnetic resonance (NMR) T₂ spectra were used to assess the internal damage induced by SCCO₂ shaped-charge impulse fracturing. The results indicate that, compared with conventional hydraulic fracturing and SCCO₂ quasi-static fracturing, SCCO₂ shaped-charge impulse fracturing facilitates multidirectional fracture initiation and the formation of complex fracture networks. Increasing shaped-charge pressure more readily activates bedding-plane weaknesses, with main and subsidiary fractures interweaving into a dense fracture network. Under the same impulse intensity, elevated pore pressure reduces the effective normal stress and alters stress-wave scattering paths, thereby inducing more branch fractures and enhancing fracture complexity. An increase in differential in-situ stress promotes fracture propagation along the direction of the maximum principal stress, reduces branching, and simplifies fracture morphology. With increasing SCCO₂ shaped-charge pressure, pore volume and connectivity generally increase: small-to-medium pores primarily respond through increased abundance and enhanced connectivity; when the shaped-charge pressure rises to 40-45 MPa, crack coalescence generates larger pores and fissures, which play a dominant role in improving flow pathways and effective storage space, ultimately forming a multiscale pore-fracture network.

For the next exploration direction and integrated evaluation and optimization of targets for the northern continental margin of the South China Sea, this paper proposes the concept of the “total natural gas play system” based on the principles of systems theory. Integrating over 60 years of exploration achievements in the four major basins, the paper studies the basic geological conditions, hydrocarbon accumulation models and distribution characteristics of the system. With the core principle of “source-heat controlling hydrocarbons and play-stratigraphy controlling accumulation”, it analyzes the distribution law of natural gas reservoirs covering “intra-sag, sag margin, extra-sag” and multi-stratigraphic sequences. The study shows that under the joint control of source and heat, the northern continental margin of the South China Sea can be divided into two major gas areas: the southern area dominated by coal-type gas and the northern area dominated by oil-type gas, with the former as the main body. Based on the distribution location of gas-generating sags, the total gas plays are classified into three types: intra-sag, sag margin and extra-sag. In the oil-type gas area of the northern coastal zone, the proportion of intra-sag natural gas plays is relatively high; in the coal-type gas area of the southern offshore zone, the proportions of intra-sag plays and sag margin natural gas plays are relatively large; while the scale of gas accumulation in the extra-sag plays is relatively small. Finally, it is clearly pointed out that the southern offshore zone is the main direction for the next natural gas exploration in the northern South China Sea. Specifically, in the offshore zone, the intra-sag play and middle-deep layers of the sag margin play in the Yingzhong Sag should be focused for the Yinggehai Basin; the intra-sag play and sag margin play in the central depression are targets for the Qiongdongnan Basin; the middle-deep layers of the intra-sag play are targets for the Baiyun Sag of the Pearl River Mouth Basin. Furthermore, in the northern depression zone of the Pearl River Mouth Basin within the coastal zone, the main exploration directions include the middle-deep layers of the intra-sag play in the Huizhou Sag and the middle-deep layers of the intra-sag play in the Enping Sag; in the Beibu Gulf Basin, the main directions are the middle-deep layers of the intra-sag play in the Weixinan Sag and the middle-deep layers of the intra-sag play in the Haizhong Sag.

In the Jimusaer Sag of the Junggar Basin, crude oils from the upper and lower sweet-spot intervals of the Permian Lucaogou Formation display a pronounced “light-heavy reversal” in oil properties that is inconsistent with conventional interpretations based solely on source-rock thermal maturity, indicating a fundamental mismatch between oil composition and maturity indicators. To resolve this anomaly, this study integrates geological, geochemical, and petrophysical datasets and systematically evaluates the combined roles of thermal evolution, organic facies, wettability, abnormal overpressure, and migration-related fractionation on shale oil composition. On this basis, a “segmented charging-cumulative charging” model is proposed and validated to explain compositional heterogeneity in lacustrine shale oils. The results demonstrate that crude-oil properties are jointly controlled by the extent of biomarker depletion, the temporal evolution of hydrocarbon charging, and the openness of the source-reservoir system, rather than by thermal maturity or organic facies alone. The upper sweet-spot interval is interpreted to have functioned as a semi-open system during early stages, in which hydrocarbon generation and expulsion were broadly synchronous, leading to preferential loss of early-generated, biomarker-rich heavy components, whereas progressive shale densification at later stages promoted the retention of highly mature, light hydrocarbons. In contrast, the lower sweet-spot interval represents a relatively closed system, where hydrocarbons generated during multiple stages continuously accumulated and were preserved as mixed charges; superposition of multi-phase fluids progressively weakened sterane isomerization signals, rendering them unreliable indicators of individual charging events or final thermal maturity. This charging behavior provides a reasonable explanation for anomalously low or distorted biomarker parameters observed in intervals of low or similar maturity. Overall, the proposed charging model reconciles the observed reversal in crude-oil properties and, by shifting the interpretive focus from static maturity assessment to charging dynamics, offers a new theoretical basis for understanding lacustrine shale oil accumulation processes, and guiding sweet-spot selection and exploration-development strategies.

GANSim is a generative adversarial networks (GANs)-based direct conditional geomodelling framework. To extend GANSim to multi-scenario, non-stationary reservoir geomodelling, and to address its tendency to overlook single-grid well conditioning data that can cause local facies disconnections around wells, an enhanced GANSim framework is proposed. The effectiveness of the enhanced GANSim is validated using a 3D multi-scenario, non-stationary turbidite reservoir as an example. For reservoirs that may involve multiple geological scenarios, two GANSim geomodelling workflows are proposed: (1) training a comprehensive GANSim model that covers all possible geological scenarios; and (2) first performing geological scenario falsification and then training GANSim models only for the unfalsified scenarios. On this basis, a local discriminator architecture is designed to improve facies continuity around wells. The modelling results show that both workflows can generate non-stationary facies models that conform to expected geological patterns and honor conditioning data, and the facies discontinuity issue around wells is effectively resolved. Compared with multipoint geostatistical methods (SNESIM), GANSim exhibits superior capability in reproducing reservoir geological patterns and modelling efficiency. Although GANSim requires a longer training time, once training is completed, it can be applied to geomodelling reservoirs of arbitrary scale with similar geological structures, achieving modelling speeds approximately 1000 times faster than SNESIM.

Taking the underground shale of the Silurian Longmaxi Formation in southern Sichuan Basin as the research object, stress-sensitive experiments on self-supporting fractures and micro-visualization experiments on gas-water flow were conducted under simulated reservoir conditions to understand the mechanism of microscopic gas-water flow during the fracture closure process and discuss its engineering applications. The results show that as the effective stress gradually increases from 5MPa to 60MPa with an increment of 5 MPa per step, the self-supporting fracture closure exhibits a two-stage characteristic of being fast in the early stage and slow in the later stage, with the inflection point stress ranging from 30 MPa to 35 MPa, and the closure degree of 47%-76%. The effective stress increase gradient gradually rose from 5 MPa per step to 20 MPa per step, and the early fracture closure accelerated, with the maximum closure degree increased by 8.6%. As the fracture width reduced from 500 μm to 50 μm, the gas phase shifted from continuous to discontinuous flow, and the proportion of the critical gas phase flow to maintain the continuous gas phase flow increased. In the early stage of fracture closure (fracture width >300 μm), the continuous gas phase flow is controlled by the fracture width - the larger the fracture width, the smaller the proportion of the critical gas phase flow to maintain the continuous gas phase flow. In the late stage of fracture closure (fracture width <300 μm), as the fractures continue to close, the dominant role of the surface roughness of the fractures becomes stronger, and the proportion of the critical gas phase flow to maintain the continuous gas phase flow exceeds 70%. It suggests that a reasonable pressure control during stable production and pressure reduction in the early stage (the peak pressure drop at the wellhead is less than 30 MPa) to delay the self-supporting fracture closure is conducive to the stable and increased production of gas wells.

In-situ heating conversion is the most practical extraction method for lacustrine low-to-medium maturity shale oil. However, the energy output-input ratio (E_out/E_in) must exceed the economic threshold to achieve commercial development. This paper systematically investigates the mechanism of super-rich accumulation of organic matter in continental shale, sweet spot evaluation, optimal heating windows, and appropriate well types and patterns from the perspectives of enhancing energy output and reducing energy input. (1) The super-rich accumulation of organic matter in lacustrine shale is primarily controlled by the intensity, frequency, and preservation of external material inputs, and is related to moderate volcanic and hydrothermal activities, marine transgressions, and radioactive materials, with organic matter abundance ≥6%. (2) The quality of organic-rich intervals is related to the type of source material and hydrocarbon generation potential. The in-situ conversion-derived hydrocarbon quality index (HQI) is established, and the zones exhibiting HQI ˃450 are defined as sweet spots. (3) Considering the characteristics of the organic matter conversion material field and seepage field, the temperature interval 300 °C-370 °C is recommended as the optimal heating window for the Chang 7₃ sub-member in the Ordos Basin. Based on the advantages of thermal conductivity, permeability, and hydrocarbon expulsion efficiency along the bedding direction during shale heating, the “horizontal well heating + vertical well development” scheme is proposed, which has demonstrated significant enhancement in both recovery factor and energy output-input ratio, making it the optimal in-situ conversion process. The research findings provide a theoretical and technical foundation for the economical and efficient development of low- to medium-maturity shale oil.

This paper proposes an approach to determing the optimal cluster spacing for volume fracturing in shale oil reservoirs based on three scales, i.e. microscopic capillary displacement, large-scale core imbibition, and macroscopic reservoir NMR logging. Through water flooding experiments using capillary with different diameters and lengths, and large-scale core counter-current and dynamic imbibition tests, and combing with the NMR logging data of fractured wells, a graded optimization criterion for cluster spacing is established. The proposed approach was tested in the shale oil reservoir in the seventh member of the Triassic Yanchang Formation (Change 7 Member), the Ordos Basin. The following findings are obtained. First, in the Chang 7 reservoir, oil in pores smaller than 8 μm requires a threshold pressure, and for 2-8 μm pores, the movable drainage distance under a pressure difference of 27 MPa ranges from 0.7 to 4.6 m. Second, the large-scale core imbibition tests show a counter-current imbibition distance of only 10 cm, but a dynamic imbibition distance up to 30 cm. Third, in-situ NMR logging results verified that the post-fracturing matrix drainage radius around fractures is 0-4 m, which is consistent with the capillary water flooding experiments and large-scale core imbibition tests. The main pore-size range (2-8 μm) of the Chang 7 reservoir corresponds to a permeability interval of (0.1-0.4)×10^-3 μm². Accordingly, a graded optimization criterion for cluster spacing is proposed as follows: for reservoirs with permeability <0.20×10^-3 μm², the cluster spacing should be reduced to <4.2 m; for reservoirs with permeability of (0.2-0.4)×10^-3 μm², the cluster spacing should be designed as 4.2-9.2 m. Field application on a pilot platform, where the cluster spacing was reduced to 4.0-6.0 m, yielded an increased initial oil production by approximately 36.6% over a 100-m horizontal reservoir section as compared with untested similar platforms.

Through tracing the background and customary usage of classification of fine-grained sedimentary rocks and terminology, and comparing current “sedimentary petrology” textbooks, this paper proposes a classification scheme for fine-grained sedimentary rocks and clarifies related terminology. The comprehensive analysis indicates that the classification of clastic rocks, volcanic clastic rocks, chemical rocks, and biogenic (carbonate) rocks is unified, and the definitions of terms such as lamination, bedding and beds are consistent. However, there is a disagreement on the definition of “mud”. European and American scholars commonly use the term “mud”, which includes silt and clay (particle size <0.062 5 mm). Chinese scholars equate the term “mud” to “clay” (particle size <0.0039 mm or <0.01 mm). Combined with the discussion on terms such as sedimentary structures (bedding, lamination, and fissility), shale, mudstone, mudrocks/argillaceous rocks, and mudshale, it is recommended to use “fine-grained sedimentary rocks” as the general term for all sedimentary rocks composed of fine-grained materials (particle size <0.062 5 mm), including claystone/mudrocks and siltstone. Claystone/mudrocks are further classified into argillaceous (or clayey) mudstone/shale, calcareous mudstone/shale, siliceous mudstone/shale, silty mudstone/shale, and silt-containing mudstone/shale. Argillaceous (or clayey) mudstone/shale emphasizes a content of clay minerals or clay-sized particles exceeding 50%. Other mudstones/shales emphasize a content of particles (particle size <0.062 5 mm) exceeding 50%. The commonly referred term "shale" should not include siltstone. It is necessary to establish a good and widely accepted classification scheme for fine-grained sedimentary rocks in the future. An integrated shale microfacies research at the thin-section scale should be carried out, and combined with well logging data interpretation and seismic attribute analysis, a geological model of lithology/lithofacies will be iteratively upgraded to accurately determine sweet layer, locate target layer, and evaluate favorable area. Thus, a “fine-grained sedimentology” is developed.

Using platform-target compatibility, collision pressure, trajectory complexity, and total drilling footage as objective functions, and comprehensively considering constraints such as platform layout area, drilling extension limits, underground target distribution, and trajectory collision risks, a model of platform location-wellbore trajectory collaborative optimization for a complex-structure well factory is developed. A hybrid heuristic algorithm is proposed by combining an improved sparrow search algorithm (ISSA) for optimizing platform parameters in the outer layer and a directed artificial bee colony algorithm (DABC) for optimizing trajectory parameters in the inner layer. This ISSA-DABC interaction facilitates the resolution of the collaborative optimization problem. The ISSA-DABC provides an effective solution to the platform-trajectory collaborative optimization problem for complex-structure well factories and overcomes the tendency of the traditional platform-trajectory stepwise optimization workflow to become trapped in local optima and yield inconsistent designs. The ISSA-DABC achieves a strong global search capability, fast convergence, and good robustness, can simultaneously satisfy multiple engineering constraints on drilling footage, trajectory complexity, and collision risk, and enables automated, workflow-wide generation of constraint-compliant, near-globally optimal platform-trajectory configurations. Field applications further demonstrate that ISSA-DABC significantly reduces the objective function value and collision risk, yielding more rational platform layouts and well factory design parameters.

In recent years, the concurrent exploration of shale oil wells in the Gulong Sag of the Songliao Basin has uncovered promising hydrocarbon shows in the Fuyu reservoir of the Lower Cretaceous Quantou Formation, indicating favorable exploration prospects. To assess the hydrocarbon exploration potential of the Fuyu reservoir, this study systematically analyzes the main controlling factors for hydrocarbon accumulation, including source rock conditions, reservoir characteristics, and migration capacity, in the deep area of the Gulong Sag, using seismic, drilling, and core data, and thus reveals the hydrocarbon enrichment mechanism and accumulation model. The results indicate that the source rocks in the first member of Cretaceous Qingshankou Formation (Qing-1 Member) in the Gulong Sag are widely distributed, characterized by high quality, large area, high maturity, and high hydrocarbon generation intensity, providing an ample oil source for the Fuyu reservoir. The Fuyu reservoir in the Gulong Sag features multi-phase channel sand bodies and beach-bar sands that are laterally superimposed and vertically stacked, forming large-scale sand-rich reservoir assemblages, which provide the storage space for tight oil enrichment. Influenced by overpressure pore preservation and dissolution-enhanced porosity, the porosity of the Fuyu reservoir can reach up to 13%, meeting the reservoir conditions necessary for large-scale tight oil enrichment. The episodic opening of hydrocarbon-source connected faults during the hydrocarbon expulsion period, combined with source-reservoir pressure differentials, drives the efficient charging and enrichment of hydrocarbons into the underlying tight reservoirs. The hydrocarbon accumulation model of the Fuyu reservoir is summarized as “source-reservoir juxtaposition, overpressure charging, lateral source-reservoir connection + vertical fault-directed bidirectional hydrocarbon supply, continuous sand body distribution, and large-scale enrichment in fault-horst belts”. A new insight for the deep area of the Gulong Sag is proposed as being sand-rich, having superior reservoirs, and being oil-rich. This insight guided the deployment of a risk exploration well HT1H, which achieved a high-yield industrial oil flow rate of 43.32 m³/d during testing, discovering light tight oil with low density and low viscosity. Through horizontal well volumetric fracturing treatment, Well HT1H achieved the first high-yield breakthrough of tight oil in the deep area of the Gulong Sag, confirming the presence of geological conditions for large-scale hydrocarbon accumulation in this area. This expands the potential for hundred-million-ton tight oil resource additions in the Songliao Basin and deepens the theoretical understanding of continental tight oil accumulation.

Traditional source-to-sink analyses cannot effectively characterize deep-time sedimentary processes involving multiple sediment sources and the spatial-temporal evolution of contributions from different sources. In this study, a dynamic, quantitative source-to-sink analysis approach using stratigraphic forward modeling (SFM) is proposed, and it is applied to the Paleogene Enping Formation in the Baiyun Sag, the Pearl River Mouth Basin. The model’s built-in spatio-temporal provenance tagging assigns a unique time-source label to sediments from each provenance, making each source’s contribution identifiably "labeled" in the simulated formation, and thus enabling a direct precise tracking and high temporal-spatial resolution quantification of such contributions. Five pseudo-wells (from proximal to distal locations) in the Baiyun Sag were analyzed. The simulation results quantitatively represent the varied proportion of each source’s contribution at different locations and in different periods and verify the proposed approach's operability and accuracy. The simulated 3D deposit distribution shows a high agreement with the measured stratigraphic data, validating the model’s reliability. Results reveal significant spatio-temporal changes in the Enping sedimentary system. In the late stage of Enping Formation deposition, a distal source supply from the northern part of the sag became dominant, the depocenter migrated northward to the deepwater area, and large-scale deltaic sand bodies extensively progradating into the sag were formed. The modeled 3D deposit distribution indicates that extensive high-quality reservoir sandstones are likely present across the deepwater area of the Baiyun Sag, which are identified as key exploration targets. Compared to traditional static approaches, the SFM-based dynamic simulation markedly enhances the spatio-temporal resolution of source-to-sink analysis and quantitatively captures the sedimentary system’s responses to tectonic activity, base-level fluctuations and other external drivers. The proposed approach provides a novel quantitative framework for investigating complex, deep-time, multi-source, systems, and offers an effective tool for reservoir prediction and exploration planning in under-explored deepwater areas.

Two types of ultra-high-temperature resistant water-based drilling fluid additives were designed and developed: an ultra-high- temperature resistant salt-tolerant polymer loss control agent, and an ultra-high-temperature resistant micro-nano sealing agent. An ultra-high-temperature resistant water-based drilling fluid system meeting the requirements of ultra-deep well drilling was established. Laboratory test and field application were employed for performance evaluation. The ultra-high-temperature and high-salt resistant polymer fluid loss reducer exhibits a mesh-like membrane structure with numerous cross-linking points, and its high-temperature and high-pressure (HTHP) loss was 28.2 mL after aging at 220 °C under saturated salt conditions. The ultra-high-temperature resistant micro-nano sealing agent adaptively filled mud cake pores/fractures through deformation, reducing the fluid loss. At elevated temperatures, it transitioned to a viscoelastic state to effectively cement the wellbore rock, enhancing wall stability. The ultra-high-temperature resistant water-based drilling fluid system with a density of 1.6 g/cm³ exhibits excellent rheological properties at high temperature and high pressure. Its HTHP fluid loss at 220 °C was only 9.6 mL. It maintains a stable performance under high-temperature and high-salt conditions, with a sedimentation factor below 0.52 after holding at high temperature for 7 d, and generates no H₂S gas after aging, demonstrating good lubricity and safety. This drilling fluid system has been successfully applied in the first 10 000-meter ultra-deep well of China, TK1, in Tarim Oilfield, ensuring the well's successful drilling to a depth of 10 910 meters.

Based on data from drilling, logging, seismic surveys, and test analyses, a systematic study was conducted on the petroleum geological characteristics and hydrocarbon accumulation features/models of the Triassic Jiucaiyuan Formation in the Fukang Sag of the Junggar Basin. The favorable exploration targets were clarified. The results are obtained in six aspects. First, the saline lacustrine, highly mature, high-quality source rocks developed in the Permian Lucaogou Formation in the Fukang Sag are characterized by continuous and efficient hydrocarbon expulsion over multiple stages, providing a critical material foundation for large-scale hydrocarbon accumulation in the Jiucaiyuan Formation. Second, the lower part of the Jiucaiyuan Formation is a braided river delta sedimentary system, with widely developed channel sandbodies and well-preserved intergranular pores and fractures, providing good reservoir conditions. Third, the middle and upper parts of the Jiucaiyuan Formation contain thick, high-quality mudstone caprocks, creating excellent sealing conditions for hydrocarbon preservation. Source-connected faults and associated fracture systems serve as effective pathways for hydrocarbon migration and accumulation. Under continuous and efficient hydrocarbon generation and pressurization conditions, favorable conditions exist for the formation of ultra-high pressure oil and gas reservoirs. Fourth, the effective spatial configuration of various accumulation elements contributes a hydrocarbon accumulation model characterized by “lower generation, upper accumulation, fault transportation, sandbody-fracture storage, and overpressure-driven enrichment”, resulting in the current structural-lithologic reservoirs within the Jiucaiyuan Formation. Fifth, the most favorable exploration targets are areas adjacent to the hydrocarbon generation center of the Lucaogou Formation, with superior structural settings and well-developed faults and sandbodies, corresponding to the prospective trap area of 263 km² and the possible resources amounting to 1.68×10⁸ t. Sixth, the zones with efficient coupling of five elements (source, fault, sandbody, fracture, and pressure) are recommended as preferential targets for seeking additional large-scale petroleum discoveries in the Jiucaiyuan Formation. The renewed major breakthrough in the Triassic petroleum exploration in the Fukang Sag has underscored its significant potential and promising prospects for large-scale exploration. The resulting study is expected to promote a composite multi-play exploration pattern in the eastern part of the Junggar Basin and provide an important guidance for oil and gas exploration in analogous regions.

This paper systematically analyzes the reservoir-forming characteristics and shale oil types in four major hydrocarbon- generating sags (Qingxi, Ying’er, Huahai, and Shida) of the Jiuquan Basin, based on the data of experiments for microscopic and geochemical analysis of reservoirs. Specifically, the hydrothermal alteration-induced reservoir-forming model and its reservoir- controlling effect in the Qingxi Sag are discussed, and the exploration potential of shale oil in these four sags are evaluated. The research results are obtained in two aspects. First, the Qingxi Sag is widely developed with mud shale, dolomitic shale, and laminated argillaceous dolomite in the Cretaceous, which can be defined as mixed shale as a whole. The source rocks in this area are of good quality and high maturity, formed in a saline water sedimentary environment, and rich in dolomite, with a strong hydrocarbon generation capacity and excellent oil generation conditions. The reservoir space has been significantly modified by hydrothermal process, with well-developed dissolution pores and microfractures, recording favorable reservoir conditions for shale oil enrichment. Overall, this sag has large reservoir thickness and large resource volume, making it the most realistic shale oil exploration target in the Jiuquan Basin. However, it faces challenges such as great burial depth (4 500 m) and strong tectonic stress. Second, the Ying'er, Huahai, and Shida Sags do not have mixed shale setting for oil accumulation, and all feature sand-mud interbeds consisting of fan delta front thin sandbodies and lacustrine mud shale in the Cretaceous, indicating relatively good source rock quality and favorable conditions for interbedded-type shale oil accumulation. Nonetheless, the source rocks are insufficient in thermal evolution degree and unevenly distributed, and favorable shale oil resources are mainly endowed near the center of the sags. Reservoirs are primarily composed of siltstone to fine sandstone, suggesting relatively good reservoir conditions, generally with small burial depth (3 000-4 000 m) and the possibility of local sweet spots. It is noted that the Ying’er Sag has already produced low-mature to mature oil, allowing it to be a near-term realistic shale oil exploration target.

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.

There is a lack of systematic understanding of coal-forming environment classification and its controls on coal petrographic characteristics, a coal-forming mire classification scheme applicable to petroleum geology is proposed based on modern ecological peatland frameworks. The formation, evolutionary processes, and diagnostic criteria of coal-forming environments are systematically clarified. The results show that: (1) modern peatlands can be classified according to hydrological conditions, vegetation types, and geomorphic settings, and coal-forming mires can be divided into lowmoor, mesomoor, and highmoor peat mires based on geomorphology; (2) initiation of coal-forming environments includes three modes: subaqueous peat infilling, autochthonous peat accumulation in wetlands, and mire development in arid regions; (3) peat accumulation is jointly controlled by plant production and decomposition, hydrological disturbances, and sediment input, and the peat-to-coal thickness ratio varies with coalification; (4) diagnostic criteria for lowmoor, mesomoor, and highmoor peat mires are established using ash yield, gamma-ray log responses, and vitrinite/inertinite ratios; and (5) transgression-regression processes exert a key control on peat mire evolution, directly influencing peat thickness and continuity, while the evolution of lowmoor, mesomoor, and highmoor mires governs coal maceral assemblages and thereby affects hydrocarbon generation potential and reservoir properties of coals. The coal-forming environment classification and identification system developed in this study effectively reveals the vertical heterogeneity of coals in the Ordos Basin, providing theoretical and practical guidance for efficient exploration and development of coal rock gas.

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.