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

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

The concurrent exploration of shale oil wells in the Gulong Sag of the Songliao Basin has uncovered promising hydrocarbon shows in the Fuyu pay zone of the Lower Cretaceous Quantou Formation. To assess the hydrocarbon exploration potential of the Fuyu pay zone, this study systematically analyzes the main controlling factors for hydrocarbon accumulation, including source rock conditions, reservoir characteristics and migration capacity, in the deep area of the Gulong Sag, using seismic, drilling and core data, and reveals the hydrocarbon enrichment mechanism and accumulation model. The results indicate that the source rocks in the first member of Cretaceous Qingshankou Formation (Qing-1 Member) in the Gulong Sag are widely distributed, characterized by high quality, large area, high maturity and high hydrocarbon generation intensity, providing an ample oil source for the Fuyu pay zone. The Fuyu pay zone in the Gulong Sag features multi-phase channel sand bodies and beach-bar sands that are laterally superimposed and vertically stacked, forming large-scale sand-rich reservoir assemblages, which provide the storage space for tight oil enrichment. Influenced by overpressure pore preservation and dissolution-enhanced porosity, the porosity of the Fuyu pay zone can reach up to 13%, meeting the reservoir conditions necessary for large-scale tight oil enrichment. The episodic opening of hydrocarbon-source connected faults during the hydrocarbon expulsion period, combined with source-reservoir pressure differentials, drives the efficient charging and enrichment of hydrocarbons into the underlying tight reservoirs. The hydrocarbon accumulation model of the Fuyu pay zone is summarized as “source-reservoir juxtaposition, overpressure charging, lateral source-reservoir connection + vertical fault-directed bidirectional hydrocarbon supply, continuous sand body distribution, and large-scale enrichment in fault-horst belts”. A new insight for the deep area of the Gulong Sag is proposed as being sand-rich, having superior reservoirs, and being oil-rich. This insight guided the deployment of three risk exploration wells. The Well HT1H achieved a high-yield industrial oil flow rate of 35.27 t/d during testing, discovering light tight oil with low density and low viscosity. Through horizontal well volumetric fracturing treatment, the Well HT1H achieved the first high-yield breakthrough of tight oil in the deep area of the Gulong Sag, confirming the presence of geological conditions for large-scale hydrocarbon accumulation in this area. This expands the potential for hundred-million-ton tight oil resource additions in the Songliao Basin and deepens the theoretical understanding of continental tight oil accumulation.

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

Through tracing the background and customary usage of classification of fine-grained sedimentary rocks and terminology, and comparing current “sedimentary petrology” textbooks and monographs, this paper proposes a classification scheme for fine-grained sedimentary rocks and clarifies related terminology. The comprehensive analysis indicates that the classification of clastic rocks, volcanic clastic rocks, chemical rocks, and biogenic (carbonate) rocks is unified, and the definitions of terms such as lamination, bedding and beds are consistent. However, there is a disagreement on the definition of “mud”. European and American scholars commonly use the term “mud” to include silt and clay (particle size less than 0.062 5 mm). Chinese scholars equate the term “mud” to “clay” (particle size less than 0.003 9 mm or less than 0.01 mm). Combined with the discussion on terms such as sedimentary structures (bedding, lamination and lamellation), shale, mudstone, mudrocks/argillaceous rocks and mud shale, it is recommended to use “fine-grained sedimentary rocks” as the general term for all sedimentary rocks composed of fine-grained materials with particle size less than 0.062 5 mm, including claystone/mudrocks and siltstone. Claystone/mudrocks are further classified into argillaceous (or clayey) mudstone/shale, calcareous mudstone/shale, siliceous mudstone/shale, silty mudstone/shale and silt-containing mudstone/shale. Argillaceous (or clayey) mudstone/shale emphasizes a content of clay minerals or clay-sized particles exceeding 50%. Other mudstones/shales emphasize a content of particles (particle size less than 0.062 5 mm) exceeding 50%. The commonly referred term “shale” should not include siltstone. It is necessary to establish a reasonable, standardized, and applicable classification scheme for fine-grained sedimentary rocks in the future. An integrated shale microfacies research at the thin-section scale should be carried out, and combined with well logging data interpretation and seismic attribute analysis, a geological model of lithology/lithofacies will be iteratively upgraded to accurately determine sweet layer, locate target layer, and evaluate favorable area.

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

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

To address the challenges of complex fluvial sandbody distribution and difficult remaining oil recovery in mature continental oilfields, this study focuses on key issues in reservoir identification such as ambiguous narrow-channel boundaries and subdivision of multi-stage superimposed sandbodies. Taking the Upper Cretaceous continental sandstone in the Sazhong Oilfield of the Daqing Placanticline as an example, a technical system integrating OVT high-resolution processing, multi-attribute fusion, and varible-scale inversion was developed to establish a complete workflow from seismic processing to reservoir prediction and remaining oil recovery. The following results are obtained. First, the Offset Vector Tile (OVT) seismic processing technology is extended, for the first time, from fracture imaging to sandbody prediction, in order to address the weak seismic responses from boundaries of narrow and thin sandbodies. A geology-oriented OVT partitioning method is developed to significantly improve the imaging accuracy, enabling identification of channel sandbodies as narrow as 50 m. Second, an amplitude-coherence dual-attribute fusion method is proposed for predicting narrow channel boundaries between wells. Constrained by a sedimentary unit-level sequence chronostratigraphic framework, this method accurately delineates 800-2 000 m long subaqueous distributary channels with bifurcation-convergence features. Third, considering the superimposition of multi-stage channels, a three-level variable-scale stratigraphic model (sandstone groups, sublayers, sedimentary units) is constructed to overcome single-scale modeling limitations, successfully characterizing key sedimentary features like meandering river “cut-offs” through 3D seismic inversion. Based on these advances, a direct link between seismic prediction and remaining oil recovery is established. The horizontal wells deployed using narrow-channel predictions encountered oil-bearing sandstones in the horizontal section by 97%, and achieved initial daily production of 12.5 t per well. Precise identification of individual channel boundaries within 17 composite sandbodies guided recovery processes in 135 wells, yielding an average daily increase of 2.8 t per well and a cumulative increase of 13.6×10⁴ t.

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

This paper systematically analyzes the reservoir-forming characteristics and cretaceous shale oil types in four major hydrocarbon-generating sags (Qingxi, Ying’er, Huahai, and Shida) of the Jiuquan Basin, based on the data of experiments for microscopic and geochemical analysis of reservoirs. The hydrothermal alteration-induced reservoir-forming model and its reservoir-controlling effect in the Qingxi Sag are discussed, and the exploration potential of shale oil in these four sags are evaluated. (1) The Qingxi Sag is widely developed with mud shale, dolomitic shale, and laminated argillaceous dolomite in the Cretaceous, which can be defined as mixed shale as a whole. The source rocks in this area are of good quality and high maturity, formed in a saline water sedimentary environment, and rich in dolomite, with a strong hydrocarbon generation capacity and excellent oil generation conditions. The reservoir space has been significantly modified by hydrothermal process, with well-developed dissolution pores and microfractures, recording favorable reservoir conditions for shale oil enrichment. Overall, this sag has large reservoir thickness and large resource volume, making it the most realistic shale oil exploration target in the Jiuquan Basin. However, it faces challenges such as great burial depth (deeper than 4 500 m) and strong tectonic stress. (2) The Ying’er, Huahai, and Shida sags all feature sand-mud interbeds consisting of fan delta front thin sandbodies and lacustrine mud shale in the Cretaceous, having good source rock quality and favorable conditions for interbedded-type shale oil accumulation. The source rocks are insufficient in thermal evolution degree and unevenly distributed, and favorable shale oil resources are mainly endowed near the center of the sags. Reservoirs are primarily composed of siltstone to fine sandstone, suggesting relatively good reservoir conditions, generally with small burial depth (3 000-4 000 m) and the possibility of local sweet spots. It is noted that the Ying’er Sag has already produced low-mature to mature oil, qualifying it as a near-term realistic shale oil exploration area.

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

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

Taking the underground shale of the Silurian Longmaxi Formation in southern Sichuan Basin as the research object, stress-sensitive experiments on self-supporting fractures and micro-visualization experiments on gas-water flow were conducted under simulated reservoir conditions to study the mechanism of microscopic gas-water flow during the fracture closure process and discuss its engineering applications. The results show that as the effective stress gradually increased from 5 MPa to 60 MPa with an increment of 5 MPa per step, the self-supporting fracture closure exhibited a two-stage characteristic of being fast in the early stage and slow in the later stage, with the inflection point stress ranging from 32 MPa to 35 MPa, and the closure degree of 47%-76%. The effective stress increase gradually rose from 5 MPa per step to 20 MPa per step, and the early fracture closure accelerated, with the maximum closure degree increasing by 8.6%. As the fracture width decreased from 500 μm to 50 μm, the gas-phase shifted from continuous to discontinuous flow, and the proportion of the critical gas-phase flow to maintain the continuous gas-phase flow increased. In the early stage of fracture closure (fracture width greater than 300 μm), the continuous gas-phase flow is controlled by the fracture width - the larger the fracture width, the smaller the proportion of the critical gas-phase flow to maintain the continuous gas-phase flow. In the late stage of fracture closure (fracture width less than 300 μm), as the fractures continue to close, the dominant role of the surface roughness of the fractures becomes stronger, and the proportion of the critical gas-phase flow to maintain the continuous gas-phase flow exceeds 70%. A reasonable pressure control during stable production and pressure reduction in the early stage (the peak pressure drop at the wellhead is less than 32 MPa) to delay the self-supporting fracture closure is conducive to the stable and increased production of gas wells.

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

GANSim is a generative adversarial networks (GANs)-based geomodelling framework with direct conditioning capabilities. To extend GANSim for geomodelling of multi-scenario and non-stationary reservoirs, and to address its tendency to overlook single-pixel well facies conditioning data that can cause local facies disconnections around wells, an enhanced GANSim framework is proposed. The effectiveness of the enhanced GANSim is validated using a 3D multi-scenario, non-stationary turbidite fan reservoir. For reservoirs that may involve multiple geological scenarios, two GANSim geomodelling workflows are proposed: (1) training a comprehensive GANSim model that covers all possible geological scenarios; and (2) first performing geological scenario falsification and then training GANSim models only for the unfalsified scenarios. On this basis, a local discriminator architecture is designed to improve facies continuity around wells. The modelling results show that both workflows can generate non-stationary facies models that conform to expected geological patterns and honor conditioning data, and the facies discontinuity issue around wells is effectively resolved. Compared with multipoint geostatistical methods(SNESIM), GANSim exhibits superior capability in reproducing geological patterns and modelling efficiency. Although GANSim requires a long training time, once training is completed, it can be applied to geomodelling reservoirs of arbitrary scale with similar geological structures, achieving modelling speeds approximately 1 000 times faster than SNESIM.

Two types of ultra-high-temperature resistant water-based drilling fluid additives were designed and developed: an ultra-high-temperature resistant salt-tolerant polymer fluid loss reducer, and an ultra-high-temperature resistant micro-nano plugging agent. An ultra-high-temperature resistant water-based drilling fluid system meeting the requirements of ultra-deep well drilling was established. Laboratory test and field application were employed for performance evaluation. The ultra-high-temperature and high-salt resistant polymer fluid loss reducer exhibits a mesh-like membrane structure with numerous cross-linking points, and its high-temperature and high-pressure (HTHP) loss was 28.2 mL after aging at 220 °C under saturated salt conditions. The ultra-high-temperature resistant micro-nano plugging agent adaptively filled mud cake pores/fractures through deformation, thus reducing the fluid loss. At elevated temperatures, it transitioned to a viscoelastic state to effectively cement the rock on wellbore wall and enhanced wall stability. The ultra-high-temperature resistant water-based drilling fluid system with a density of 1.6 g/cm³ exhibits excellent rheological properties at high temperature and high pressure. Its HTHP fluid loss at 220 °C was only 9.6 mL. It maintains a stable performance under high-temperature and high-salt conditions, with a sedimentation factor below 0.52 after holding at high temperature for 7 d, and generates no H₂S gas after aging, demonstrating good lubricity and safety. This drilling fluid system has been successfully applied in the 10 000-meter ultra-deep well of China, Shenditake 1, in Tarim Oilfield, ensuring the well's successful drilling to a depth of 10 910 m.

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

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

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

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