In alignment with China’s national deep-earth exploration strategy, China National Petroleum Corporation (CNPC) has successfully drilled a record-breaking 10,000-meter ultra-deep well - TK-1 in the Tarim Basin. This pioneering project has achieved dual breakthroughs in ultra-deep earth science research and hydrocarbon exploration while driving technological advancements ten-thousand-meters deep well drilling engineering. The successful completion of TK-1 has yielded transformative geological discoveries. For the first time in global 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 active source rocks, porous 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 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 meters and positioned China as one of the few countries with core technologies for ultra-deep well drilling.

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 using 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, 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.

Taking the GY8HC well in the Gulong Sag of the Songliao Basin as an example, this study utilized high-precision zircon U-Pb ages from volcanic ash and two astronomical cycle quality assessment methods (TimeOpt and AstroBayes) to estimate sedimentation rates. Through spectral analysis of high-resolution total organic carbon (TOC) content, laboratory-measured free hydrocarbons (S₁), hydrocarbons form 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 may have 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.

Existing imaging techniques cannot simultaneously achieve high resolution and a wide field of view, and manual multi-mineral phase segmentation in shale is inadequate in precision. To address these limitations, we propose a comprehensive framework based on generative adversarial network (GAN) for predicting pore structure properties of shale, which incorporates image augmentation, super-resolution reconstruction, and multi-mineral phase 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 phase 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 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.

Based on drilling, mud logging, core, seismic and imaging logging data, this paper studies the negative inversion structures in the Carboniferous buried hills in the No. 1 and No. 2 fault zones of Weixinan Sag, the Beibeu Gulf Basin, 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 formation of high-quality reservoirs. The negative inversion structures mainly control the development of high-quality reservoirs in buried hills through: (1) triggering the large-scale creation of fractures to increase reservoir space and improve 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; and (4) driving deep fluid to migrate upwards by virtue of negative inversion faulting activities to strengthen the transformation by buried karsitification. 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 1,000-ton well in carbonate buried-hill reservoir in the Beibuwan Basin, and provide referential geological parameters for finding more reserves and achieving higher production in the Carboniferous buried hills in the Weixinan Sag.

To reveal the complex crude oil-CO₂ interaction mechanism and oil mobilization behavior during CO₂ huff-n-puff in shale-type shale oil reservoirs, CO₂ huff-n-puff experiments with on-line nuclear magnetic resonance monitoring were conducted on Gulong shale cores, combined with the prediction model of CO₂ dynamic diffusion coefficient, the flow mechanism and factors influencing oil mobilization during CO₂ huff and puff in Gulong shale oil reservoir is studied, and the diffusion and mass transfer behavior of CO₂ is investigated in shale. The results show that at the injection stage, CO₂ invades into macropores near the injection end, and drives part of the crude oil to small pores in the deep part of the core. At the shut-in stage, the crude oil gradually reflows to macropores near the injection end and is redistributed in the core. At the production stage, the oil mobilization zone is gradually expanded from the production end (injection end) to the deep part of the core. The contribution ratio of produced oil from large and small pores is about 8:3 after production. The diffusion coefficient of CO₂ in shale porous media gradually decreases with the advance of diffusion front at shut-in stage. The better the porosity and permeability of core samples, the higher the CO₂ concentration at diffusion front, the greater the CO₂ diffusion coefficient, and the slower the diffusion decline rate is. Increasing the huff and puff cycles could effectively enhance oil displacement efficiency, though its impact on the crude oil mobilization zone remains insignificant. The crude oil in small pores of the small layer with undeveloped laminae is difficult to be produced during CO₂ huff and puff, and the oil recovery is only 12.72 %. The crude oil in macro- and small pores of the small layer with developed laminae can be effectively mobilized during CO₂ huff and puff, and the oil recovery can reach 39.11%.

Taking deep coal-rock gas in the Yulin and Daning-Jixian areas of the Ordos Basin 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 coalbed methane. Based on the experimental results of the full-lifec-ycle physical simulation of coal-rock gas well depletion development and isotopic monitoring, a dual-medium 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 characteristic 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, 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 ultimate recovery factor of deep coal-rock gas.

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 years of exploration practice and the experiment results of natural gas dissolution with high-temperature and overpressure, the concept of “overpressure-dissolved gas” was proposed. 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 is usually greater than 1.5, and there is a large amount of formation water with a high gas saturation (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-water transitional layer without gas cap, and saturated dissolved gas 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.

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 Eastern Sichuan Basin have been investigated through outcrop section measurement, core observation, thin section identification, argon ion polishing-field scanning electron microscope, energy spectrum analysis, X-ray diffraction, total organic carbon content (TOC), major and trace elements analysis. And finally the symbiotic adsorption model of sepiolite for organic matter enrichment has been established. The results show that the sepiolite-containing successions of Mao-1 Member are composed of the cyclothems of mudstone, argillaceous limestone and limestone, with five depositional intervals vertically and the organic matter mostly develops 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, intersertal 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.

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.

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 depositional mechanisms in the depressed lake 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 bentonite 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 lake basin underwent an evolution in multiple phases of "oscillatory regression-progradational infilling". 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 lacustrine depressed lake 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.

Based on the practices of petroleum exploration in the Qingshankou Formation, northern Songliao Basin, 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, conventional and unconventional hydrocarbons coexist orderly. Laterally, conventional oil, tight oil, and shale oil form sequential reservoirs from basin margins to the center. Vertically, shale oil, tight oil, and conventional oil develop progressively upward. Second, 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 migration and accumulation patterns. Fifth, enrichment controls are different depending on hydrocarbon types: buoyancy-driven, fault-conducted, sandbody-adjusted, and trap-concentrated, for above-source conventional oil; overpressure-driven, fault-conducted, multi-stacked sandbodies, and quasi-continuous distribution for near-source tight oil; self-sourced reservoirs, retention through self-sealing, in-situ accumulation or micro-migration driven by hydrocarbon-generation overpressure for inner-source shale oil. 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.

Continental 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 lacustrine shale oil. This study reviews the current status of exploration and development of shale oil in such basins. It 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, 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 in structurally complex continental shale reservoirs. 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 quantitative classification and grading evaluation system; (4) optimize artificial fracture propagation mechanisms and multi-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. Considering the challenges such as strong reservoir heterogeneity and high development costs, interdisciplinary research will be required to achieve theoretical breakthroughs and technological iterations, thereby enabling efficient shale oil development in continental rift 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, 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.

Taking the shale oil of the first member of the Cretaceous Qinglong Formation in southern Songliao Basin as an example, this paper establishes a saturation model of lacustrine shale oil considering the influence of organic matter (OM) on clay-bound water conductivity. The model parameters were calibrated based on the fluid characterization results of sealed samples and two-dimensional nuclear magnetic resonance, the differential influence of OM on clay-bound water conductivity was then 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 OM 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, OM 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 or m_sh. The larger the effective porosity or m_sh, the more the contribution of the matrix free water to formation conductivity. According to the experiments on sealed core samples, the proposed saturation model yields a significantly higher interpretation accuracy than the Archie model and the Total-shale model.

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.

Guided by the coupling 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 rifting-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: ancient valleys, fault troughs, and transitional zones. Third, based on differences in sediment supply mechanisms, the unique source-to-sink systems during the rifting-depression transition in marine rift basins are categorized into three types: exogenous, endogenous, and composite. Fourth, the patterns of these source-to-sink systems are primarily controlled by provenance, paleogeomorphology, and sea-level changes. Provenance composition and scale dictated the lithology 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 accumulations, the endogenous systems develop secondary pores due to presence of soluble minerals, and the composite systems demonstrate reservoir properties varying from area to area.

Due to the strong interaction between crude oil and rock, a large amount of crude oil remains on the surface of rocks after conventional water/chemical flooding. In this paper, a new superwetting oil displacement system incorporating the synergy between hydroxyl anion compound (1OH-1C) and extended surfactant (S-C₁₃PO₁₃S) was designed. The interfacial tension (IFT), 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 produces 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 IFT, which can promote the flow of remaining oil and emulsify it into oil-in-water (O/W) 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% OOIP after water flooding. This new high-efficiency system is promising for greatly improving oil recovery in low-permeability reservoirs.

基于板块构造理论,综合利用古地磁、地质及地震等资料,恢复南大西洋东西两侧被动大陆边缘原型盆地形成演化过程,依据盆地结构及沉积充填差异,将研究区被动大陆边缘盆地群进一步划分为“三段”“四类”盆地,即南段无盐断坳型、中段含盐断坳型和北段无盐坳陷型及三角洲改造型4类盆地,揭示出南大西洋两岸盆地群均经历了早期陆内裂谷、过渡期陆间裂谷及漂移拗陷期被动大陆边缘3个阶段,其中少数三角洲改造型盆地自中新世以来发育高建设性三角洲。各盆地每个原型阶段都能形成独特的沉积体系及生储盖成藏组合,从而控制了油气纵向上的有序聚集。南段“无盐断坳型”盆地,来源于陆内-陆间裂谷层系的油气被上部拗陷期海相页岩优质区域盖层有效封堵,富集于裂谷层系顶部构造-地层型圈闭之中;源于坳陷层系下部的油气富集在与之紧邻的斜坡扇/海底扇群中。中段为裂谷坳陷层系都比较发育的“含盐断坳型”盆地,以过渡期陆间裂谷蒸发盐岩充填为特征,盐下裂谷期湖相和盐上漂移期海相页岩均可形成有效烃源岩,海相页岩及盐岩作为优质盖层,形成盐下碳酸盐岩、盐上重力流扇体碎屑岩型大油气田。北段为“无盐坳陷型”盆地,以裂谷层系分布范围小、坳陷沉积范围广且厚度大为特征,源于坳陷层系下部海相页岩中的油气直接充注于该套层系内部裙边状分布的重力流复合扇体之中,形成漂移期重力流扇体群碎屑岩型大油气田。另外,研究区还发育三角洲改造型被动大陆边缘盆地,纵向分层、横向分带,由陆向海序次形成4大环状构造带：生长断裂带-塑性底辟带-逆冲褶皱带-缓坡带,均有望形成大油气田。

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

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

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

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

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

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

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

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

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

Based on the basic data of drilling, logging, testing and geological experiments, the geological characteristics of the Permian Dalong Formation marine shales in the Sichuan Basin and the factors controlling shale gas enrichment and high yield in these shales are studied. The results are obtained in four aspects. First, the high-quality shale of the Dalong Formation was formed after the deposition of the Wujiaping Formation, and it is mainly developed in the Kaijiang-Liangping trough in the northern part of Sichuan Basin, where deep-water continental shelf facies and deep-water reduction environment where siliceous organisms flourished have formed the black siliceous shale rich in organic matter. Second, the Dalong Formation shale contains both organic and inorganic pores, with stratification of alternating brittle and plastic minerals, which was stacked with severe compaction to enlarge the fractures, thereby improving the permeability. In addition to organic pores, a large number of inorganic pores are developed even in the ultra-deep (˃4 500 m) layers, contributing a total porosity of more than 5% and a permeability of 0.2×10^-3 μm², which significantly expands the accommodation space for shale gas. Third, the limestone at the roof and floor of the Dalong Formation acted as a seal in the early burial and hydrocarbon generation stage, providing favorable conditions for the continuous hydrocarbon generation and rich gas preservation in shale interval. In the later reservoir stimulation process, it was beneficial to the lateral extension of the fractures, so as to achieve the optimal stimulation performance and increase the well-controlled resources. Combining the geological, engineering and economic conditions, the favorable area with depth <5 500 m is determined to be 1 800 km², with resources of 5 400×10⁸ m³. Fourth, the shale reservoirs of the Dalong Formation are thin but rich in shale gas. The syncline zone far away from the main faults in the high and steep tectonic zone, eastern Sichuan Basin, with depth <5 500 m, is the most favorable target for producing the Permian shale gas under the current engineering and technical conditions. It mainly includes the Nanya syncline, Tanmuchang syncline, and Liangping syncline.

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

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

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

Static adsorption and dynamic damage experiments were carried out on typical No.8 deep coal rock in the Ordos Basin to evaluate the adsorption capacity of hydroxypropyl guar gum and polyacrylamide as fracturing fluid thickeners on deep coal rock surface and the permeability damage caused by adsorption. The adsorption morphology of the thickener was quantitatively characterized by atomic force microscopy, and the main controlling factors of the thickener adsorption were analyzed. Meanwhile, the adsorption mechanism of the thickener was revealed by Zeta potential, Fourier infrared spectroscopy and X-ray photoelectron spectroscopy. The results show that the adsorption capacity of hydroxypropyl guar gum on deep coal surface is 3.86 mg/g, and the permeability of coal rock after adsorption decreases by 35.24%-37.01%. The adsorption capacity of polyacrylamide is 3.29 mg/g, and the permeability of coal rock after adsorption decreases by 14.31%-21.93%. The thickness of the thickener adsorption layer is positively correlated with the mass fraction of thickener and negatively correlated with temperature, and a decrease in pH will reduce the thickness of the hydroxypropyl guar gum adsorption layer and make the distribution frequency of the thickness of the polyacrylamide adsorption layer more concentrated. Functional group condensation and intermolecular force are the chemical and physical forces for adsorbing fracturing fluid thickener in deep coal rock. Optimization of thickener mass fraction, chemical modification of thickener molecular, oxidative thermal degradation of polymer and addition of desorption agent can reduce the potential damages on micro-nano pores and cracks in coal rock.

Based on recent advancements in shale oil exploration within the Ordos Basin, this study presents a comprehensive investigation of the paleoenvironment, lithofacies assemblages and distribution, depositional mechanisms, and reservoir characteristics of shale oil in continental freshwater lacustrine basins, with a focus on the Chang 7₃ sub-member of Triassic Yanchang Formation. The research integrates a variety of exploration data, including field outcrops, drilling, logging, core samples, geochemical analyses, and flume simulation experiment. The study indicates that: (1) The paleoenvironment of the Chang 7₃ deposition is characterized by a warm and humid climate, frequent monsoon events, and a large water depth of freshwater lacustrine basin. The paleogeomorphology exhibits an asymmetrical pattern, with steep slopes in the southwest and gentle slopes in the northeast. This can be further subdivided into microgeomorphological units, including depressions and ridges in lakebed, as well as ancient channels; (2) The Chang 7₃ sub-member is characterized by a diverse array of fine-grained sediments, including very fine sandstone, siltstone, mudstone, and tuff. These sediments are primarily distributed in thin interbedded and laminated arrangements vertically. The overall grain size of the sandstone predominantly falls below 0.062 5 μm, with individual layer thicknesses of 0.05-0.64 m. The deposits contain intact plant fragments and display various sedimentary structure, such as wavy bedding, inverse-to-normal grading sequence, and climbing ripple bedding, which indicating a depositional origin associated with density flows; (3) Flume simulation experiments have successfully replicated the transport processes and sedimentary characteristics associated with density flows. The initial phase is characterized by a density-velocity differential, resulting in a thicker, coarser sediment layer at the flow front, while the upper layers are thinner and finer in grain size. During the mid-phase, sliding water effects cause the fluid front to rise and facilitate rapid forward transport. This process generates multiple “new fronts”, enabling the long-distance transport of fine-grained sandstones, such as siltstone and argillaceous siltstone, into the center of the lake basin; (4) A sedimentary model primarily controlled by the density flows was established for the southwestern part of the basin, highlighting that the frequent occurrence of flood events and the steep topography in this area are the primary controlling factors for the development of density flows; (5) Sandstone and mudstone in the Chang 7₃ sub-member exhibit micro- and nano-scale pore-throat systems, with varying oil-bearing properties across different lithologies and significant differences in mobile oil content. (6) It was determined that the fine-grained sediment complexes formed by multiple episodes of sandstones and mudstones associated with density flow in the Chang 7₃ formation exhibit characteristics of “overall oil-bearing with differential storage capacity”. The combination of mudstone with low total organic carbon content (TOC) and siltstone is identified as the most favorable exploration target at present.

This paper investigates the macroscopic and microscopic characteristics of viscosity reduction and quality improvement of heavy oil in a supercritical water environment through laboratory experiments and analytical testing. The effect of three reaction parameters, i.e. reaction temperature, reaction time and oil-water ratio, is analyzed on the product and their correlation with viscosity. The results show that the flow state of heavy oil significantly improved with a viscosity reduction of 99.4% in average after the reaction in supercritical water. Excessively high reaction temperature leads to a higher content of resins and asphaltenes, with significantly increasing production of coke. The optimal temperature ranges in 380 °C-420 °C. Prolonged reaction time could continuously increase the yield of light oil, but it will also results in the growth of resins and asphaltenes, with the optimal reaction time of 150 minutes. Reducing the oil-water ratio helps improve the diffusion environment within the reaction system and reduce the content of resins and asphaltenes, but it will increase the cost of heavy oil treatment. An oil-water ratio of 1:2 is considered as optimum to balance the quality improvement, viscosity reduction, and reaction economics. The correlation of the three reaction parameters relative to the oil sample viscosity is ranked as temperature, time, and oil-water ratio. Among the four fractions of heavy oil, the viscosity is dominated by asphaltene content and less affected by resins and saturates contents.

Through investigating the Triassic Yanchang Formation in the Ordos Basin, black carbon has been found for the first time in the seventh member of the Middle Triassic Yanchang Formation (Chang 7 Member). This study fills the gap in black carbon record in the Middle Triassic in terrestrial basins in in the East Tethys, and suggests that the oxygen content in the East Tethys during the Middle Triassic was beyond 15% and that plants had recovered from the Late Permian mass extinction. The results show that the distribution of black carbon in the Chang 7 Member is heterogeneous in the basin. In the southeastern part, the black carbon content is the highest (possibly ˃6%) in shale, with the proportion in TOC up to 20%, which is lower than 10% in the northwestern and northeastern parts. It is intriguing that the proportion of black carbon in the organic matter can reach to this high level during the Middle Triassic when black carbon was stunted. Therefore, it is postulated that black carbon could account for great proportion in organic matter after vegetation on land in the Silurian. The traditional practice needs to be caution when TOC is set as a critical proxy in source rock evaluation and shale oil and gas sweet spot screening. Source rock bearing high TOC but high proportion in black carbon may not be good target for unconventional oil and gas exploitation, while shale bearing low TOC with low or no black carbon may become promising option. The TOC in the source rock can be fractioned into black carbon (w_b), active carbon (w_a), residual carbon (w_r), and maturated oil carbon (w_o). TOC subtract w_b or TOC-w_b is recommended for evaluation of source rock, w_a for screening the in-situ recovery area of low to medium maturity shale oil, and w_o of matured shale oil for appraisal of the favorable exploration area of medium to high matured shale oil. These results allow for the quantitative evaluation of organic matter composition of shale, hydrocarbon generation potential, maturation stage, and expulsion and retention of shale oil, and also guide the reconstruction of paleoclimate in the source rock development period and the shale oil and gas sweet spot screening.

The depositional facies types of the fourth member of the Middle Triassic Leokoupo Formation (Lei-4 Member) in western Sichuan Basin are examined through the methods of sedimentology, lithology and the mineral composition interpretation, as well as the special lithofacies indicators such as microbialite, anhydrite-halite succession and tempestites, using the data of about 400 boreholes and 11 outcrop sections. The distribution evolution characteristics and its hydrocarbon significances of the paleo-bay facies have been discussed further. The Lei-4 Member in western Sichuan Basin has an ocean-bay-flat depositional model, with the presence of evaporated tidal flat, restricted tidal flat and paleo-bay facies from east to west. The subfacies such as bay margin, subtidal bay and bay slope are recognized within the paleo-bay, with microbial reef and grain bank microfacies in the bay margin, microbial dolomitic flat, deep-water spongy reef and hydrostatic mudstone microfacies in the subtidal bay, and tempestites and collapsed deposits in the upper bay slope. The bay margin covered the Guangyuan-Zitong-Dujiangyan area in the period of the first submember of the Lei-4 Member (Lei-4-1), regressed westward into the Shangsi-Jiangyou-Dujiangyan area in the period of Lei-4-2, and expanded to the Jiange-Zitong-Langzhong-Wusheng-Yanting-Chengdu area in the northern part of central Sichuan Basin in the period of Lei-4-3 along with a small-scale transgression. The topographic pattern of “one high and two lows” is confirmed in the Lei-4 Member, corresponding to a configuration of source rocks and reservoir rocks that are alternated horizontally and superimposed vertically. Two efficient source-reservoir configuration models, i.e. side source & side reservoir, and self-generating & self-storing, are available with the microbial reef and grain bank reservoirs at the bay margin and the high-quality source rocks within the sags on both sides of the bay. The research findings will inevitably open up a new situation for the hydrocarbon exploration in the Leikoupo Formation.

Based on 2D and 3D seismic data and well logging data, this paper studies the distribution of well-seismic stratigraphic filling and shoal controlled reservoirs of Upper Cambrian Xixiangchi Formation in the south slope of Leshan-Longnüsi paleouplift in the Sichuan Basin, to reveal the genetic relationship between stratigraphic filling, paleogeomorphology and large-scale grain shoal. (1) The Xixiangchi Formation in the study area is overlapped and filled gradually to the Leshan-Longnüsi paleouplift, but gets thin sharply due to truncation only near the denudation pinch-out line of the paleouplift. Therefore, 2 overlap slope break belts and 1 erosion slope break belt are identified, and the Xixiangchi Formation is divided into 4 members from bottom to top. (2) The filling pattern of the overlapping at the base and erosion at the top indicates that the thickness of Xixiangchi Formation can reflect the pre-depositional paleogeomorphology, and reveals that the study area has a monoclinal geomorphic feature of plunging to southeast and being controlled by multistage slope break belts. (3) The large-scale grain shoals and shoal controlled reservoirs are developed longitudinally in the third and fourth member of the Xixiangchi Formation, and laterally in the vicinity of the multistage overlap slope break belts. (4) Overlap slope break belts are closely related to northwest trending reverse faults. The northwest to southeast compressive stress formed by the convergence of the western margin of South China Plate with the Himalayas landmass of the Qiangtang-Tethyan realm in the middle and late Cambrian led to the rapid uplift of the northwest margin of the Yangtze Plate and the expansion to the southeast, forming a gradually plunging multistage slope break paleogeomorphology. Combined with oil and gas test results, it is predicted that the favorable exploration zone of the grain shoal controlled reservoirs can cover an area of 3340 km².