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

Based on drilling, mud logging, core, seismic and imaging logging data, this paper studies the identification and evolution process of negative inversion structures in the Carboniferous buried hills in the No. 1 and No. 2 fault zones of Weixinan Sag, Beibu Gulf Basin, China, and reveals the controls of these structures on high-quality reservoirs. The No. 2 fault zone develops significant negative inversion structures in the Carboniferous buried hills, as a result of multi-stage transformations of compressive-tensile stress fields in the period from the Late Hercynian to the Himalayan. The Hercynian carbonates laid the material basis for the formation of high-quality reservoirs. The negative inversion structures mainly control the development of high-quality reservoirs in buried hills through: (1) creating large-scale fractures to increase reservoir space and improve oil-gas flow pathways; (2) regulating stratigraphic differential denudation to highlight dominant lithology for later reservoir transformation; (3) shaping the paleogeomorphological highlands to provide favorable conditions for superficial karstification. The negative inversion structures form a high-quality, composite reservoir space with the synergistic existence of superficial dissolution fractures/cavities and burial-enhanced karst systems through the coupling of fracture network creation, formation denudation screening and multi-stage karst transformation. The research results have guided the breakthrough of the first exploratory well with a daily oil production over 1 000 m³ in carbonate buried-hill reservoir in the Beibu Gulf Basin, and provide referential geological basis for finding more reserves and achieving higher production in the Carboniferous buried hills in the Weixinan Sag.

Based on the petroleum exploration in the Cretaceous Qingshankou Formation, northern Songliao Basin, NE China, integrated with seismic, drilling and logging data, this study investigates the characteristics and genetic mechanisms of orderly distribution and the differential enrichment patterns of conventional and unconventional hydrocarbons in the formation. Key findings involve five aspects. First, the conventional and unconventional hydrocarbons coexist orderly. Laterally, conventional oil, tight oil, and shale oil form a pattern of orderly accumulation from basin margins to the center. Vertically, shale oil, tight oil, and conventional oil develop progressively upward. Second, the coupled tectonic-sedimentary processes govern sedimentary facies differentiation and diagenesis, influencing reservoir physical properties and lithology, thereby controlling the orderly distribution of conventional and unconventional hydrocarbons in space. Third, the coupling of source rock hydrocarbon generation evolution, fault sealing capacity, and reservoir densification determines the orderly coexistence pattern of conventional and unconventional hydrocarbons. Fourth, sequential variations in reservoir physical properties generate distinct dynamic fields that regulate hydrocarbon orderly accumulation. Fifth, enrichment controls are different depending on hydrocarbon types: buoyancy-driven, fault-transport, sandbody-connected, and trap-concentrated, for above-source conventional oil; overpressure-driven, fault-transport, multi-stacked sandbodies, and quasi-continuous distribution for near-source tight oil and gas; self-sourced reservoirs, retention through self-sealing, in-situ accumulation or micro-migration driven by hydrocarbon-generation overpressure for inner-source shale oil. From exploration practices, these findings will effectively guide the integrated deployment and three-dimensional exploration of conventional and unconventional hydrocarbon resources in the Qingshankou Formation, northern Songliao Basin.

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 whole petroleum system developed in the Mesozoic takes the high-quality source rocks of the 7^th member of the Triassic Yanchang Formation as the core and mainly consists of low-permeability and unconventional oil and gas reservoirs. 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, which together form a continuous, symbiotic, and orderly accumulation entity wherein unconventional resources significantly outweigh conventional ones in proportion. Second, the spatial core area of sedimentary filling 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 → buoyancy or overpressure and capillary force, the accumulation scale changes from extensive hundreds of millions of tons to a isolated hundreds of thousands-million of tons, and the gas-oil ratio and methane content decrease. Third, the sedimentary filling system provides the material basis and spatial framework for the whole petroleum system, the superimposed sand body, fault and unconformity constitute the dominant migration pathway of hydrocarbons in the far-source conventional hydrocarbon accumulation domain and the transitional hydrocarbon accumulation domain, the high-quality source rocks provide a solid resource basis for shale oil, and the micro-nano pore throat-fracture network constitute unconventional accumulation space. 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 controlled by underpressure in post-pool-forming stage. The oil-gas enrichment and long-term preservation depends on the coordination among three factors (stable geological structure, multi-cycle sedimentation, and dual self-sealing). Fourth, the whole petroleum system model is defined as four domains, overpressure + underpressure drive, and dual self-sealing.

To address the discrepancies between well and seismic data in stratigraphic correlation of the Triassic Yanchang Formation in the Ordos Basin, NW China, traditional stratigraphic classification schemes, the latest 3D seismic and drilling data, and reservoir sections are thoroughly investigated. Guided by the theory of sequence stratigraphy, the progradational sequence stratigraphic framework of the Yanchang Formation is systematically constructed to elucidate new deposition mechanisms in the depressed lacustrine basin, and it has been successfully applied to the exploration and development practices in the Qingcheng Oilfield. Key findings are obtained in three aspects. First, the seismic progradational reflections, marker tuff beds, and condensed sections of flooding surfaces in the Yanchang Formation are consistent and isochronous. Using flooding surface markers as a reference, a progradational sequence stratigraphic architecture is reconstructed for the middle-upper part of Yanchang Formation, and divided into seven clinoform units (CF1-CF7). Second, progradation predominantly occurs in semi-deep to deep lake environments, with the depositional center not always coinciding with the thickest strata. The lacustrine basin underwent an evolution of “oscillatory regression-progradational infilling- multi-phase superimposition”. Third, the case study of Qingcheng Oilfield reveals that the major pay zones consist of “isochronous but heterochronous” gravity-flow sandstone complexes. Guided by the progradational sequence stratigraphic architecture, horizontal well oil-layer penetration rates remain above 82%. The progradational sequence stratigraphic architecture and associated geological insights are more consistent with the sedimentary infilling mechanisms of large-scale continental depressed lacustrine basins and actual drilling results. The research results provide crucial theoretical and technical support for subsequent refined exploration and development of the Yanchang Formation, and are expected to offer a reference for research and production practice in similar continental lacustrine basins.

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, Tarim Basim, NW China, and structural physical simulation experiments. The results 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-cavity 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, structural 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 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: flower-shaped fracture, large and deep fault and staggered overlap. The first two types are larger in size with better reservoir conditions, suggesting a significant exploration potential.

The occurrence types and controlling factors of organic matter in the sepiolite-containing successions of the first member of Mid-Permian Maokou Formation (Mao-1 Member for short) in the Eastern Sichuan Basin, SW China, have been investigated through outcrop section measurement, core observation, thin section identification, argon ion polishing-field scanning electron microscopy, energy spectrum analysis, X-ray diffraction, total organic carbon content (TOC), major and trace element analysis. Finally, the symbiotic adsorption model of sepiolite for organic matter enrichment has been established. The results show that the sepiolite-containing successions of the Mao-1 Member are composed of the rhythmite of mudstone, argillaceous limestone and limestone, with five depositional intervals vertically and the organic matter mostly developed in the mudstone and argillaceous limestone layers within the lower three intervals. The organic matter occurrence types are mostly layered or nodular in macro to meso-scale, blocky-vein-like under a microscope, but scattered, interstitial or adsorbed at a mesoscopic scale. It underwent transition processes from lower to higher salinity, from oxygen-poor and anoxic reduction to oxygen-poor and localized oxygen enrichment on the palaeo-environment of the Mao-1 Member. The first two intervals of the early depositional phase of Mao-1 Member constitute the cyclothems of mudstone, argillaceous limestone and limestone and quantities of fibrous-feathered sepiolite settle down within the Tongjiang-Changshou sag with continuous patchy organic matter from adsorption of alginate by sepiolite in intercrystalline, bedding surfaces and interlayer pores. The third and fourth intervals in the mid-depositional phase are mostly composed of the mudstone and argillaceous limestone alternations with the continuous patchy or banded organic matter in the surface and inter-crystalline pores of fibrous, feathered and flaky sepiolite. And the fifth interval in the late depositional phase of the Mao-1 Member comprises the cyclothems of extremely thin layered argillaceous limestone and thick-layered limestone with the fibrous sepiolite depositing in the argillaceous limestone and irregular organic matter dispersing around the sepiolite. Therefore, the symbiotic adsorption between organic matter and sepiolite effectively enhances the preservation efficiency of organic matter and improves the source rock quality of the Mao-1 Member, which enhances our understanding on the enrichment model of the depositional organic matter.

Taking the shale oil of the first member of the Cretaceous Qingshankou Formation of Changling Sag in southern Songliao Basin as an example, this paper establishes a saturation model of lacustrine shale oil considering the influence of organic matter on clay-bound water conductivity. Based on the fluid characterization results of sealed samples and two-dimensional nuclear magnetic resonance, the differential influence of organic matter on clay-bound water conductivity was quantitatively revealed, and the conductivity mechanism and rock-electrical relationships of lacustrine shale were systematically analyzed. The results show that there are two conductive networks for lacustrine shales, i.e. the matrix free water and the clay-bound water. The bound water cementation index m_sh was introduced to reflect the impact of organic matter on clay-bound water conductivity, and it is positively correlated with the effective porosity. When there is sufficient rigid framework support and well-developed pores, organic matter is more likely to fill or adsorb onto clay interlayers. This reduces the ion exchange capacity of the electrical double layer, leading to an increase in m_sh and a decrease in the conductivity of clay-bound water. The overall conductivity of shale is controlled by the clay-bound water conductivity, and the relative contributions of the mentioned two conductive networks to formation conductivity are affected by the effective porosity and m_sh. The larger the effective porosity and m_sh, the more the contribution of the matrix free water to formation conductivity. According to the experimental results, the proposed saturation model yields a significantly higher interpretation accuracy in oil saturation than the Archie model and the Total-shale model.

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

Guided by the analysis of source-to-sink system, this study investigates the Paleogene Oligocene Lingshui Formation in the Qiongdongnan Basin by comparing the geological characterizes in land and sea areas and integrating outcrop, core, drilling, logging and 3D seismic data, to systematically analyze the characteristics of the source, transport pathway, and sink during the deposition of Lingshui Formation, and reveal the patterns, controlling factors and petroleum geologic significance of the source-to-sink systems. The results are obtained in five aspects. First, during the fault-depression transition, the Qiongdongnan Basin received sediments from the provenances presenting as segments in east-west and zones in north-south, primarily with the Indosinian granites in the Shenhu Uplift in the east and the Yanshanian granites in the west. Overall, the sources are young in the southern and northern parts and old in the interior of the basin. Second, three types of sediment transport pathways are identified: paleo-valleys, fault troughs and trough-valley transitional zones. Third, based on differences in sediment supply modes, the unique source-to-sink systems during the fault-depression transition in marine rift basins are categorized into three types: exogenous, endogenous and composite. Fourth, the characteristics of these source-to-sink systems are primarily controlled by provenance, paleogeomorphology, and sea-level changes. Provenance lithology and scale dictated the composition and volume of sedimentary deposits. Paleogeomorphology influenced erosion intensity in the provenance and the development of paleodrainage systems, thereby affecting the distribution and types of sedimentary systems. Additionally, sea-level changes decided the extent of the provenance, but also regulated the sediment distribution patterns through oceanic processes such as waves and tides. Fifth, the exogenous source-to-sink systems may form large-scale reservoir bodies, the endogenous systems develop secondary pores due to presence of soluble minerals, and the composite systems demonstrate reservoir properties varying from area to area.

To clarify the mechanism of differential enrichment of intrasource shale oil, taking the third of seventh member of the Triassic Yanchang Formation (Chang 7₃ submember for short) in the Ordos Basin, NW China 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 intrasource micro-migration of shale oil, and establish the coupling between the shale nano/micro-fabric and the oil generation, migration and accumulation. The Chang 7₃ 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 the hydrocarbon expulsion efficiency, yielding consistent aromaticity between in-situ and migrated solid bitumen. Mudstone 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 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 aromatization of solid bitumen from shale, through tuffaceous and mudstone, to sandy laminae, while increasing light hydrocarbon components and enhancing OM-hosted pore development. The intrasource micro-migration and enrichment of the Chang 7₃ shale oil result from synergistic organic-inorganic diagenesis, with crude oil component fractionation being a key mechanism for forming sweet spots in laminated shale oil reservoirs.

Existing imaging techniques cannot simultaneously achieve high resolution and a wide field of view, and manual multi-mineral segmentation in shale lacks precision. To address these limitations, we propose a comprehensive framework based on generative adversarial network (GAN) for characterizing pore structure properties of shale, which incorporates image augmentation, super-resolution reconstruction, and multi-mineral auto-segmentation. Using real 2D and 3D shale images, the framework was assessed through correlation function, entropy, porosity, pore size distribution, and permeability. The application results show that this framework enables the enhancement of 3D low-resolution digital cores by a scale factor of 8, without paired shale images, effectively reconstructing the unresolved fine-scale pores under a low resolution, rather than merely denoising, deblurring, and edge clarification. The trained GAN-based segmentation model effectively improves manual multi-mineral segmentation results, resulting in a strong resemblance to real samples in terms of pore size distribution and permeability. This framework significantly improves the characterization of complex shale microstructures and can be expanded to other heterogeneous porous media, such as carbonate, coal, and tight sandstone reservoirs.

Based on the waterflooding development in carbonate reservoirs in the Middle East, this study analyzes the geological characteristics and waterflooding behaviors/patterns of different types of high permeability zones (HPZs), and proposes rational waterflooding strategies and modes. Four types of HPZs, i.e. sedimentation-dominated, sedimentation-diagenesis coupling, biogenic and composite, are identified in the carbonate reservoirs in the Middle East. Based on their distribution patterns, flow mechanisms, and waterflooding behaviors/patterns, five waterflooding modes are established: (1) the mode with stepwise-infilled areal vertical well pattern, for composite HFZs in patchy distribution; (2) the mode with regular row vertical well pattern for Type I channel “network” HFZs (with dominant water flow pathways at the base), and the mode with irregular differentiated vertical well pattern for Type II channel “network” HFZs (where multi-stage superimposition leads to “layered flooding”), for sedimentation-diagenesis coupling HFZs; (3) the mode with row horizontal wells through bottom injection and top production, for biogenic HFZs characterized by thin, contiguous distribution and rapid advancing of injected water along a 工-shaped path; and (4) the mode with progressive waterflooding through edge water injection via vertical well and oil production via horizontal well, for sedimentation-dominated HFZs characterized by thick, contiguous distribution and flood first in upper anti-rhythmic reservoirs. Development practices demonstrate that the proposed waterflooding modes are efficient in the highly heterogeneous carbonate reservoirs in the Middle East, with balanced employment of reserves in the adjacent reservoirs and enhanced oil recovery.

This study focuses on the hydrated ion bridge (HIB) effect at the oil-rock interface in low- to ultra-low-permeability oil reservoirs. It systematically summarizes the research methodologies, formation mechanisms, interaction strength, and disruption mechanisms of HIB, and discusses the influencing mechanisms of HIB on the occurrence state and mobility of crude oil. On this basis, the key challenges inherent in the current HIB research are analyzed, and prospective directions for future development are proposed. Currently, research in this field primarily relies on experimental characterization techniques and molecular simulation methods. The microscopic interactions involved in HIB formation mainly include electrostatic interactions, hydrogen bonds and van der Waals forces. Notably, the hydrogen bonds between polar molecules in crude oil and hydrated ions serve as the primary sites for disrupting the HIB effect. The interaction strength of HIB is collectively modulated by ion type and concentration, reservoir solution environment, mineral type of reservoir rocks, and polar components in crude oil, which subsequently influence the occurrence state and mobility of crude oil. Systematic challenges persist in HIB-related research across three dimensions: research methodologies, scale integration and geological complexity. Specifically, the dynamic evolution mechanism of HIB remains inadequately elucidated; a discontinuity exists in the connection of spatiotemporal cross-scale modeling and prediction; and the reproducibility of actual geological environments in experimental settings is insufficient. Future research may pursue breakthroughs in the following three aspects: (1) developing in-situ dynamic experimental characterization techniques and machine learning-augmented simulation strategies; (2) establishing a framework for cross-scale model fusion and upscaling prediction; and (3) conducting in-depth studies on HIB under the coupled effects of complex mineral systems and multi-physical fields.

Given that a large amount of crude oil remains on the surface of rocks and is difficult to produce after conventional waterflooding, a new superwetting oil displacement system incorporating the synergy between a hydroxyl anion compound (1OH-1C) and an extended surfactant (S-C₁₃PO₁₃S) was designed. The interfacial tension, contact angle and emulsification performance of the system were measured. The oil displacement effects and improved oil recovery (IOR) mechanisms of 1OH-1C, S-C₁₃PO₁₃S and their compound system were investigated by microscopic visualization oil displacement experiments and core displacement experiments. The results show that 1OH-1C creates a superwetting interface and electrostatic separation pressure on the solid surface, which destroys the strong interactions between crude oil and quartz to peel off the oil film. S-C₁₃PO₁₃S has low interfacial tension, which can promote the flow of remaining oil and emulsify it into oil-in-water emulsions. The compound system of 1OH-1C and S-C₁₃PO₁₃S has both superwettability and low IFT, which can effectively improve oil recovery through a synergistic effect. The oil displacement experiment of low-permeability natural core shows that the compound solution can increase the oil recovery by 16.4 percentage points after waterflooding. This new high-efficiency system is promising for greatly improving oil recovery in low-permeability reservoirs.

Taking deep coal-rock gas in the Yulin and Daning-Jixian areas of the Ordos Basin, NW China, as the research object, full-diameter coal rock samples with different cleat/fracture development degrees from the Carboniferous Benxi Formation were selected to conduct physical simulation and isotope monitoring experiments of the full-life-cycle depletion development of coal-rock gas. Based on the experimental results, a dual-medium carbon isotope fractionation (CIF) model coupling cleats/fractures and matrix pores was constructed, and an evaluation method for free gas production patterns was established to elucidate the carbon isotope fractionation mechanism and adsorbed/free gas production characteristics during deep coal-rock gas development. The results show that the deep coal-rock gas development process exhibits a three-stage carbon isotope fractionation pattern: “Stable (I) → Decrease (II) → Increase (III)”. A rapid decline in boundary pressure in stage Ⅲ leads to fluctuations in isotope value, characterized by a “rapid decrease followed by continued increase”, with free gas being produced first and long-term supply of adsorbed gas. The CIF model can effectively match measured gas pressure, cumulative gas production, and δ¹³C₁ value of produced gas. During the first two stages of isotope fractionation, free gas dominated cumulative production. During the mid-late stages of slow depletion production, the staged pressure control development method can effectively increase the gas recovery. The production of adsorbed gas is primarily controlled by the rock's adsorption capacity and the presence of secondary flow channels. Effectively enhancing the recovery of adsorbed gas during the late stage remains crucial for maintaining stable production and improving the ultimate recovery factor of deep coal-rock gas.

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

Stereoscopic particle image velocimetry technology was employed to investigate the planar three-dimensional velocity field and the process of proppant entry into branch fractures in a fracture configuration of “vertical main fracture - vertical branch fracture” intersecting at a 90° angle. 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, the fluid and sand 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 sand-carrying fluid migration and analyze key influencing factors. 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 sand inflow ratio have phase bias. 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 sand distribution among clusters. The 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 erosion. Increasing the pumping rate reduces the influence of gravity settlement, mitigating the phase bias of sand inflow and perforation erosion. However, the large pumping rate limits the sand inflow efficiency near the heel clusters, and more proppants accumulate towards the toe clusters. High-viscosity fluids improve particle suspension, achieving more uniform proppant placement within wellbore and fractures. Larger particle sizes exacerbate sand inflow differences among clusters and perforations, limiting the proppant placement range within fractures.

In overpressure reservoirs, natural gas often coexists in a three-phase mixed form of continuous free state, dispersed free state and water-saturated dissolved state. However, the latter two have not received sufficient attention. In response to this situation, based on detailed characterization of typical overpressure dissolved gas in the Yinggehai-Qiongdongnan basin and the experiment results of natural gas dissolution with high-temperature and overpressure, the concept of “overpressure-dissolved gas” was proposed and its basic features, formation conditions and resource potential were summarized. It refers to the natural gas present in the gas-water transitional zone and the saturated dissolved gas zone within the overpressure reservoirs. The formation of overpressure-dissolved gas requires two basic conditions: the pressure coefficient typically greater than 1.5, and a relatively high gas saturation in the reservoir (10%-35%). Overpressure-dissolved gas exists in the strata from shallow to deep with a multi-stage superimposed pattern; there are at least four combination types: overpressure-dissolved gas with multiple gas caps, overpressure-dissolved gas with single gas cap, gas-bearing water layer without gas cap, and dissolved gas-bearing water layer without gas cap. The basic geological elements required for the formation of overpressure-dissolved gas include the gas source, reservoir, cap rock, gas-water transitional zone and overpressure body. The conditions of gas source, reservoir and cap rock determine the scale of the overpressure-dissolved gas zone. High temperature, high pressure and low-permeability reservoirs control the solubility of natural gas and the thickness of the gas-water transitional zone. The physical properties of sandstone determine the combination types of overpressure-dissolved gas. Changes in pressure control the transformation of different existing states of overpressure-dissolved gas. The overpressure-dissolved gas in the Yinggehai-Qiongdongnan Basin has considerable huge resource potential. Once breakthrough is achieved in this area, it will usher in a new era of natural gas exploration in the overpressured basin.

To understand the applicability of high-temperature preformed particle gel (HT-PPG) for control of short-circuiting in enhanced geothermal systems (EGSs), core flooding experiments were conducted on fractured granite cores under varying fracture widths, gel particle sizes and swelling ratios. Key parameters such as injection pressure, water breakthrough pressure, and residual resistance factor were measured to evaluate HT-PPG performance. The gel exhibited strong injectability, entering granite fractures at pressure gradients as low as 0.656 MPa/m; HT-PPG yields a superior sealing performance by significantly reducing the permeability; and dehydration occurs during HT-PPG propagation, with a dehydration ratio ranging from 4.71% to 11.36%. This study reveals that HT-PPG can be injected into geothermal formations with minimal pressure yet provides strong resistance to breakthrough once in place. This balance of injectability and sealing strength makes HT-PPG effective for addressing thermal short-circuiting in EGS reservoirs.