This study reviews the recent progress and trends of carbon capture, utilization and storage (CCUS) technologies, with a particular focus on related policy orientations, technological status, and representative projects across North America, Europe, the Middle East, and China. The technical connotations of CCUS are elucidated, and the existing issues and challenges are identified from the perspectives of technology, economics, safety and system integration. The CO₂ capture technologies are relatively mature; the emergence of novel processes such as direct air capture (DAC) and advanced materials such as metal-organic frameworks (MOFs) offer new choices for efficient capture, but issues related to high energy consumption and operational costs remain unresolved. The CO₂ geological utilization has developed earlier, where breakthroughs rely on effective source matching, enhanced miscibility and increased swept volume. The CO₂ chemical utilization exhibits broad market potential for producing high value-added products, and the development of catalytic systems with high conversion efficiency and low cost is identified as the core challenge. For CO₂ storage, diverse geological bodies provide vast theoretical capacities on both land and offshore worldwide, but subsidy policies and carbon market regulation are required to offset the limited economic returns of storage technologies. This study highlights several frontier technologies, including low-concentration CO₂ capture, CO₂-enhanced oil recovery (EOR), CO₂-based green fuel synthesis, microbial CO₂ conversion, CO₂ mineralization and hydrogen production, and CO₂ cushion gas replacement in underground gas storage (UGS). Through cost-effective innovation, regional pipeline network development, flexible technology integration, coordinated macro-policy regulation, and cross-disciplinary collaboration, CCUS can achieve a transformative scale-up from million-ton and ten-million-ton capacities to the hundred-million-ton level, contributing to the achievement of the carbon neutrality goals of China.

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.

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.

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.

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

Under the guidance of the whole petroleum system theory, using seismic, drilling and laboratory analysis data, and combined with the practical achievements of oil and gas exploration, the distribution patterns of different types of natural gas in the deep-water area of the Qiongdongnan Basin of China were systematically reviewed, the orderly symbiosis mechanisms and hydrocarbon accumulation processes of diverse gas reservoirs were analyzed, and a composite whole petroleum system model for the deep-water strongly active basins in the northern South China Sea was constructed. In the deep-water area of the Qiongdongnan Basin, there are three sets of source rocks, namely the Eocene, the Oligocene, and the upper Miocene-Quaternary, and three whole petroleum systems can be accordingly classified. The source rocks have the characteristics of multilayers, multiple types, and multiple hydrocarbon generation centers. The Eocene lacustrine source rocks, Oligocene marine and continental dual-origin source rocks, and upper Miocene-Quaternary marine source rocks form multiple hydrocarbon generation centers, which are orderly distributed from east to west. The reservoirs are characterized by multiple geological ages, multiple rock types, and multiple hydrodynamic influences, and exist as a reservoir composite superposition pattern with basement buried hill-lower traction flow sandbody-upper gravity flow sandbody vertically in the deep-water area. Fluid activities within the basin are controlled by free dynamic fields, confined dynamic fields, and bound dynamic fields. The natural gas in the whole petroleum system presents an orderly distribution of shale gas (speculated)-tight gas-conventional gas-ultra-shallow gas-hydrate from bottom to top. The research results have verified the adaptability of the whole petroleum system theory in the deep-water area of the Qiongdongnan Basin, providing a theoretical support for the exploration of complex oil and gas resources in the deep-water area, and are expected to effectively guide the distribution prediction and exploration of different types of petroleum resources in deep-water areas.

Two types of ultra-high-temperature resistant water-based drilling fluid additives were designed and developed: an ultra-high-temperature resistant salt-tolerant polymer 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.

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 seismic data, well log data, and analyses of hydrocarbon accumulation elements in typical oil and gas fields, this study systematically investigates the tectonic differentiation and its control on hydrocarbon accumulation in four major Cenozoic petroliferous basins (Beibuwan, Pearl River Mouth, Qiongdongnan and Yinggehai) of the northern South China Sea. The results show that the tectonic evolution in the study area exhibits a significant differentiation characterized by “east-west staging and north-south zonation”, with major subsidence events occurred progressively later from west to east and from north to south, allowing the basins to be classified into two types: passive continental margin basins and transform continental margin basins. This tectonic differentiation governs hydrocarbon accumulation through a “triple-control” mechanism: subsidence-thermal evolution divergence controls source rock type and maturation; tectonic-depositional cycle coupling controls reservoir/trap type and reservoir-caprock assemblage; and structural configurations control hydrocarbon accumulation, preservation and enrichment patterns. Moderate heat flow on the northern shelf favors oil generation from the Paleogene lacustrine source rocks, while high geothermal gradients in the southern deep-water area promote late-stage rapid gas generation from coal measures, forming the resource distribution framework with “oil in the north and gas in the south”; Tectonic-depositional coupling regulates reservoir distribution and reservoir-caprock assemblage effectiveness, with the rift-stage faulting inducing isolated lacustrine delta reservoirs, the southward shift of subsidence during the rift-drift transition giving rise to extensive marine delta sandstones, the detachment faults in deep-water areas governing the development of canyon channels, and regional transgressive mudstones and overpressure mudstones serving as key caprocks; Structural styles dictate accumulation models, including primary oil reservoirs characterized by the association of weakly reworked traps and regional seals, deep-water gas reservoirs characterized by shelf-break controlled sand and high heat flow-driven gas migration, composite gas reservoirs characterized by transfer zone controlled reservoirs and overpressure mudstone sealing, and late-stage rapid hydrocarbon accumulation characterized by strike-slip stress transition and diapir conduit. Analysis of hydrocarbon accumulation in typical oil and gas fields validates these cognitions, revealing the comprehensive control of tectonic evolution on source rock maturation, reservoir distribution, trap types and preservation conditions. Based on these findings, it is recommended to differentiate exploration strategies by areas and layers, with focus on structural-lithological traps under high heat flow setting in deep-water areas and primary oil reservoirs with weak reworking in shallow-water areas.

This paper systematically reviews the advances in shale oil and gas drilling fluid technology, provides an in-depth analysis of the critical bottlenecks in each technology and explores their future development directions. Several technologies have been developed for shale oil and gas: water-based drilling fluids with a core emphasis on sealing, inhibition and lubrication; oil-based drilling fluids centered around wellbore strengthening, low-oil-water-ratio emulsions, and synthetic-based systems; drilling fluids for reservoir protection based on clay-free, under-balanced, and interfacial modification; as well as lost circulation control technologies founded on bridging, gelling, responsive, and composite mechanisms. A comprehensive analysis indicates that existing technologies are still plagued by several bottlenecks, including inadequate high-temperature and contamination resistance, prohibitive costs, and poor formation adaptability. Drilling operations still face severe challenges such as wellbore instability, reservoir damage and severe fluid losses. Accordingly, the following prospects for future shale oil and gas drilling fluid technology are proposed: (1) Water-based drilling fluids require a focus on the synergistic effects of nanoscale plugging and chemical inhibition, the development of smart responsive lubricants, and enhanced resistance to high temperatures and acid gas contamination. (2) Oil-based drilling fluids should achieve breakthroughs in novel emulsifiers for cost-effectiveness and high-temperature resistance, alongside intensified research efforts in environmentally friendly technologies. (3) Reservoir protective drilling fluids necessitate the development of a real-time prediction and diagnosis expert system for formation damage, coupled with the advancement and application of high-temperature resistant additives and intelligent integrated pressure control equipment. (4) Lost circulation control technologies should be dedicated to developing smart responsive plugging materials and strengthening their compatibility with fracture networks.

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.

This paper systematically reviews the development history and generational characteristics of multi-stage fracturing technology in horizontal wells and defines the connotation and essence of the new-generation volume stimulation technology, as represented by eXtreme Limited Entry (XLE). The research indicates that classical fracturing theory remains the cornerstone for optimizing stimulation designs. Optimization based on fracture units is fundamental for achieving “perfect fracturing”, while “proppant loading intensity” serves merely as a statistical parameter and therefore cannot be used to evaluate fracturing effectiveness. Consequently, expanding the stimulated volume is identified as the key to achieving optimal stimulation results. Regarding limited entry perforation strategies, the study clarifies that all clusters initiation can be achieved when the total perforation friction exceeds the horizontal in-situ stress difference among clusters. Furthermore, XLE requires a total perforation friction greater than 10 MPa, superimposed on the treating pressure at wellhead after all clusters initiation, to ensure even fluid distribution across all fractures. Based on the characteristics of “fracture swarms” observed in cores from hydraulic fracturing test sites (HFTS), it is revealed that creating a single principal fracture is critical for effective fracture propagation. Drawing on the rheological characteristics of proppant settling in slickwater and learnings from North American HFTSs, three novel viewpoints on modern fracturing are proposed: Slickwater fracturing relies on velocity for proppant transport, and subsequently injected proppant travels the furthest, suggesting that “CounterProp” is the future direction of fracturing technology; High-viscosity slickwater struggles to achieve effective proppant transport; The proppant settling mode determines that the dynamic fracture width during the treatment is effectively equal to the propped fracture width. Finally, the technical connotation and implementation pathway for “whole-domain propped” treatment are presented, and a future development vision for Autonomous Intelligent Fracturing (AIF) is proposed.

Starting from the first principle thinking, this study systematically reviews the development mechanisms of gas reservoirs and proposes the development concept of “full life cycle enhanced gas recovery (EGR)”. Following the principles of scientificity, practicality and comparability, a generational classification system for EGR technologies is established. The research indicates that the properties of natural gas dictate a development mechanism primarily driven by pressure depletion to release the elastic expansion energy of gas. This leads to a development model centered on primary depletion, supplemented by limited adjustments in late stages. Early development essentially lies in well pattern optimization and risk pre-control, while late development focuses on targeted local adjustments and integrated collaborative control. Primary gas recovery, relying on natural energy depletion, achieves a recovery factor of 25%-55%. Secondary gas recovery, through active regulation of the reservoir pressure field via techniques like blockage removal, and injection-production optimization, can enhance the recovery factor by 10-15 percentage points. Tertiary gas recovery, employing multiple mechanisms to alter the reservoir’s physical and chemical fields synergistically, offers a potential further increase of 5-10 percentage points. Currently, primary recovery technologies are mature and well-established. Synergistic optimization of well patterns and fracture networks enables effective production from gas-drive reservoirs, while optimized development strategies facilitate orderly production from water-drive gas reservoirs. Secondary recovery technologies, in the field pilot stage currently, adopt active measures like enhanced water drainage, water shutoff, and gas injection to effectively control water influx and release trapped gas. Tertiary recovery remains largely in the laboratory or pilot test stage. Future efforts should focus on cross-generational technologies, such as “primary + secondary” and “primary + tertiary” combinations, to continuously improve recovery factors throughout the full lifecycle of gas reservoirs.

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

Based on new understandings of the whole petroleum system theory for coal measures, and utilizing data from coal-rock gas wells and other oil and gas wells in numerous pilot test areas for key parameter validation, this study conducted a national resource assessment of coal-rock gas widely developed in marine-continental transitional and continental strata in major petroliferous basins like Ordos, Sichuan and Junggar in China. The main achievements and understandings were obtained as follows. (1) A resource evaluation methodology for coal-rock gas was established, incorporating varying geological/data conditions. (2) Key parameter thresholds for deep coal-rock gas resource evaluation were defined, including the upper limits of critical depth (1 500, 2 000, 2 500 m), lower limit of reservoir thickness (1 m), and lower limits of gas content in medium-low rank and medium-high rank coals (2, 10 m³/t), depending on varying geological conditions across basins. (3) Methods for determining key parameters such as gas content, porosity, and technical recovery factor were developed using the basic data from coal-rock gas experiments/tests and logging. (4) Evaluation results indicate that the geological resources of coal-rock gas in the 14 major basins of onshore China amount to 55.11×10¹² m³. Resources at depths of 1 500-3 000, 3 000-5 000, 5 000-6 000 m account for 50.29%, 43.11%, 6.60% of the total, respectively. Resource classification shows that Class I, II, and III resources constitute 21.80%, 32.76%, 45.44%, with the Class I and II technically recoverable resources of approximately 13.23×10¹² m³. (5) The Ordos Basin remains the most favorable province, while the Sichuan, Junggar and Tarim basins are the promising targets, for future exploration and development of coal-rock gas in the country. Other basins including Bohai Bay, Qaidam, Tuha, Songliao and Hailar are considered as prospective options. Coal-rock gas production is expected to reach 500×10⁸ m³ annually within the next 10-15 years, positioning it as a major contributor to the natural gas production growth of China and a crucial alternative resource for ensuring the national gas supply.

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.

Based on data from drilling, logging, seismic surveys and tests, a systematic study was conducted on the petroleum geological characteristics and hydrocarbon accumulation features/models of the Triassic Jiucaiyuan Formation in the eastern Fukang Sag of the Junggar Basin. The favorable exploration targets were identified. First, the highly mature, high-quality saline lacustrine source rocks developed in the Permian Lucaogou Formation in the eastern Fukang Sag are characterized by continuous and efficient hydrocarbon expulsion over multiple stages, providing a critical material foundation for large-scale hydrocarbon accumulation in the Jiucaiyuan Formation. Second, the Jiucaiyuan Formation, a dual source-sink system, represents a distal, large-scale braided river delta sand bodies originated from the Karamaili Mountain, with well-preserved intergranular pores and fractures, providing good reservoir conditions. Third, the middle and upper parts of the Jiucaiyuan Formation contain thick, high-quality mudstone caprocks. Source-connected faults and associated fracture systems serve as effective pathways for hydrocarbon migration and accumulation. The continuous hydrocarbon generation and pressurization conditions are favorable for the formation of ultra-high-pressure oil and gas reservoirs. Fourth, the effective spatial configuration of various accumulation elements constitutes a hydrocarbon accumulation model characterized by “lower generation, upper accumulation, fault transportation, sandbody-fracture storage, and overpressure-driven enrichment”, resulting in the current structural-lithologic reservoirs within the Jiucaiyuan Formation. Fifth, the most favorable exploration targets in Fudong are areas adjacent to the hydrocarbon generation center of the Lucaogou Formation, with superior structural settings and superimposed development of faults and sandbodies, corresponding to the prospective trap area of 263 km² and the possible resources amounting to 1.68×10⁸ t. Sixth, the zones with efficient coupling of five elements (source, fault, sandbody, fracture and pressure) are recommended as preferential targets for seeking additional large-scale petroleum discoveries in the Jiucaiyuan Formation. The renewed major breakthrough in the Triassic petroleum exploration in the Fukang Sag, represented by a high oil flow rate of 56.16 m³/d at Well Fukang-2 during test, has underscored its significant potential and promising prospects for large-scale exploration. The research findings on hydrocarbon accumulation are expected to promote a multi-layer three-dimensional exploration pattern in the eastern part of the Junggar Basin and have an important strategic significance for oil and gas exploration in the Triassic across the basin.

Global deep Earth exploration and ultra-deep oil and gas exploration (deeper than 6 000 m) have attracted increasing attention, with a growing number of major oil and gas discoveries. This article systematically reviews the discovery history of ultra-deep oil and gas exploration since 1937, dividing it into four major stages: onshore ultra-deep exploration and local breakthrough (1937-1982), shallow- water-dominated ultra-deep exploration and sporadic discoveries (1983-1997), onshore and offshore large-scale ultra-deep discoveries (1998-2018), and onshore over-8 000-m exploration and new breakthrough (since 2019). By the end of 2025, a total of 1 348 exploratory wells with a depth of more than 6 000 m have been drilled worldwide. A total of 305 ultra-deep oil and gas fields have been discovered in 29 basins across 20 countries, with recoverable reserves equivalent to 63.21×10⁸ t, accounting for only 0.9% of the global total reserves and indicating enormous exploration potential. The discovered reserves are highly concentrated in the Tethys and South Gondwana petroleum realms, dominated by passive continental margin basins with a proportion of 71.25%. Reservoirs are mainly composed of Meso-Cenozoic carbonate rocks and clastic rocks. Studies show that three types of advantageous basins, including cratonic basins, passive continental margin basins and foreland basins, have their own characteristics in terms of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation. The global ultra-deep oil and gas exploration degree is extremely low, and there may exist another “golden zone” for hydrocarbon accumulation with huge resource potential. In the future, it is necessary to strengthen research on the mechanisms of hydrocarbon generation and accumulation as well as resource assessment in ultra-deep strata, and carry out integrated evaluation combining geology, engineering and intelligent technology. Internationally, efforts should be focused on new ultra-deep project evaluation and oil and gas cooperation in hydrocarbon-rich regions such as the both sides of the Atlantic, the Middle East, Central Asia-Russia and Australia. With the accelerated exploration of over-8 000-m oil and gas in China, a new peak of reserve growth is forthcoming.

This study establishes a one-way finite element method-discrete element method (FEM-DEM) coupling numerical framework to dynamically simulate the thermal damage and crack evolution of heterogeneous granite under plasma jet, and to identify the thermo-mechanical cracking mechanisms. The finite element method is used to build a Gaussian rotating conical heat source to compute the transient temperature field. The temperature is then mapped onto a heterogeneous DEM model reconstructed from real mineral grain boundaries. The model incorporates temperature-dependent bond strength degradation and temperature-threshold-triggered fracture criterion to capture the crack evolution process. Validation against experiments shows errors of less than 7% for temperature, 6% for pit morphology, and 11% for crack inclination, suggesting the reliability and accuracy of the model. Simulation reveals the crack evolution in three stages: crack initiation, rapid propagation and stable extension. The dominance of tensile failure and presence of significantly more cracks within grain than at grain boundary indicate that intragranular cracking driven by thermal strain mismatch is the primary pattern of plasma thermal cracking. When the plasma current exceeds 200 A, the damage factor increases sharply and nonlinearly, indicating the existence of a current threshold where the rate of thermal stress accumulation exceeds the rate of stress relaxation. Higher initial rock temperature intensifies thermal damage and shifts the failure mode from tensile-dominated to tensile-shear composite, while confining pressure suppresses axial crack propagation but exacerbates the near-surface thermal spalling effect.

This study investigates the strong heterogeneity and complex internal architecture of carbonate reservoirs, using the Cretaceous Main Mishrif Formation in the Middle East as an example. A multi-scale characterization of sedimentary architecture is conducted based on reservoir genetic analysis. Quantitative calibration of well logs with core thin sections enables semi-quantitative evaluation of dissolution intensity in non-cored intervals. Within a coupled depositional-diagenetic framework, reservoir classification is established with depositional-diagenetic facies as the linking framework, allowing delineation of their spatial distribution and connectivity. The results show that three types of architectural units are developed in the Main Mishrif Formation, including tidal channels, bioclastic shoals, and tidal bioclastic deltas, which exhibit fining-upward, coarsening-upward, and coarsening-upward-fining-upward successions, respectively. These units form two composite stacking patterns, namely the “encapsulated” pattern and the “upper-lower” pattern. A dissolution intensity index is defined based on thin-section analysis, and a log-based prediction model is developed using principal component analysis and multivariate regression. Dissolution in the MB2 sub-member is controlled by third-order sequence boundaries, with strong dissolution occurring from MC1-1 to MB2-1, forming high-permeability zones across architectural units. In contrast, dissolution in the MB1 sub-member is controlled by high-frequency sequences, with stronger dissolution in the upper intervals, favoring the development of high-permeability zones. By combining depositional and dissolution characteristics, a total of 21 depositional-diagenetic facies are identified, and the distributions of high-permeability zones, high-quality, moderate, and poor reservoirs, as well as interlayers are systematically characterized. These findings provide a geological basis for stratified reservoir development, well pattern optimization, and remaining oil recovery in carbonate reservoirs, and are promising for the characterization of giant thick carbonate reservoirs in the Middle East and Central Asia.

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.

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.

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.

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.

Based on drilling core, thin section, physical property and logging data, taking the second member of the Ordovician Majiagou Formation (Ma 2 Member) in the Ordos Basin as an example, this paper discusses the reservoir types, distribution and forming mechanisms of the carbonate-evaporite paragenetic system. The results are obtained in three aspects. First, the Ma 2 Member was deposited in an onlapping pattern toward the Central Paleouplift and is in unconformable contact with the underlying Cambrian around the paleouplift. From the paleouplift to the eastern depression, sedimentary environments such as tidal flat, grain shoal and lagoon, as well as five types of carbonate-evaporite paragenetic sequences, developed in turn. Second, dolomicrite, silt-crystalline dolomite and grain dolomite reservoirs are developed in the Ma 2 Member. According to sedimentary and diagenetic differences, they are further subdivided into four types of reservoir rocks, including mottled silt-crystalline dolomite, grain dolomite, burrow-bearing micritic (silt-crystalline) dolomite, and gypsum-mold-pore-bearing dolomicrite. Among them, grain dolomite reservoirs have superior physical properties and high development frequency, representing the high-quality reservoirs in the study area. Vertically, the reservoirs are mainly developed in the middle and upper parts of high-frequency cycles; laterally, they show a pattern of distribution along sags and around structural highs ("along sags and around highs"), characterized by multi-stage superposition and lateral migration. Third, based on the understanding of the sedimentary geomorphic pattern and onlap sedimentary filling model, combined with the lithology, lithofacies distribution and evolution of reservoir rocks, and considering the penecontemporaneous dissolution and dolomitization under high-frequency periodic sea-level cycles, a four-element reservoir-controlling differentiation model of slope geomorphology, particle shoal, dissolution and dolomitization ("slope-shoal-dissolution-dolomitization") has been established.. The research results can provide a basis for evaluating the exploration potential of hydrocarbon replacement areas in the deep Ma 2 Member of the basin.

The Paleogene Liushagang Formation in the Wushi Sag of the Beibuwan Basin is characterized by dispersed hydrocarbon distribution, small-scale residual exploration targets and large burial depth. Based on data from drilling, laboratory experiments, and geophysic analysis, this study systematically investigates the hydrocarbon accumulation conditions and enrichment patterns in the Liushagang Formation. The key findings are obtained in five aspects. First, the structural evolution of the sag involved three distinct stages: early faulting, mid-stage detachment deformation and late adjustment, governed by an “extension-detachment-strike-slip” composite fault system that controlled basin subsidence, depocenter migration and sedimentary environment evolution. Second, three principal source rock intervals in the Eocene Liushagang Formation, concentrated in the southern East Sub-sag under the control of the No. 7 Fault Zone, are characterized by considerable thickness and high quality, with the oil shale in the lower part of the second member of Liushagang Formation (lower Liu-2 Member) being the most prolific, providing a robust resource foundation in the sag. Third, four reservoir-seal assemblages are identified, corresponding to three hydrocarbon migration systems: direct source-reservoir contact, fault-sandbody coupling, and fault-structural ridge-sandbody stepwise composite networks. Fourth, three accumulation models are established: “young source, old reservoir” with lateral stepwise migration, “self-sourced and self-stored” intra-source enrichment, and “lower source-upper reservoir” with vertical migration. Fifth, exploration priorities are further delineated, highlighting deep fault-block traps in the central zone of the East Sub-sag, intrasag lithologic traps, and bedrock buried-hill targets with direct source-reservoir connectivity, all demonstrating significant resource potential.

Through systematic investigation of deep coal-rock gas in the Ordos Basin, NW China, this work analysed the thickness distribution of the entire Upper Paleozoic coal-rock intervals, quantified the resource potential of representative areas (a 12 000 km² rectangular block in the eastern Ordos Basin roughly centered on Yulin City), clarified the occurrence characteristics of coal-rock gas, and identified key development indicators for gas wells, thereby defining the direction for iterative optimization of key technologies. (1) The total coal-rock gas in-place of the Upper Paleozoic coal seams 1^#-10^# in the resource evaluation region is assessed at 5.66×10¹² m³, of which coal seam 8^#, currently the main target interval, contains about 3.08×10¹² m³, accounting for roughly 54% of the total. (2) Deep coal-rock gas is characterized by a high ratio of free gas. Under the conditions of 2 000 m burial depth, 6.35% porosity, 95% free gas saturation, and 22.13 m³/t total gas content, the free gas content of the reservoir is estimated to be ca. 40% of the total gas. (3) Three productivity evaluation models (triangular, convex, concave) are developed for horizontal wells, of which the triangular model can serve as the reference model for predicting the estimated ultimate recovery (EUR) throughout the lifecycle of coal-rock gas wells. Using the triangular model with a 7 m coal thickness, 1 500 m effective lateral length and 400 m well spacing, the average single-well EUR is determined to be 4 621.28×10⁴ m³. (4) Development of the coal seam 8^# should employ horizontal wells with pressure-controlled production. Meanwhile, it can be further optimized by adopting the cost-effective strategies of Sulige Gas Field in the Ordos Basin, China. (5) To achieve cost-effective development and increase primary recovery factor, key technologies must undergo continuous iteration and upgrading, focusing on accelerating drilling, extending effective lateral lengths, high-intensity reservoir stimulation, and well-pattern optimization.

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.

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.

Taking the Middle-Upper Cambrian Xixiangchi Group in the central-southern Sichuan Basin as an example, this study investigates the sedimentary characteristics and evolutionary history of tempestites using field outcrop, core, thin-section and logging data, and elucidates the patterns and processes by which storms have reworked grain shoal reservoirs in carbonate platforms, thereby identifying the zones with favorable reservoirs. The results indicate that: (1) The Xixiangchi Group develops massive storm deposits, with five intervals occurred in a complete storm sedimentary sequence; Xixiangchi Group exhibits six typical storm depositional sequences, with storm-related grain shoals developed in settings such as mixed tidal flats, intra-platform depressions, and margins of the intra-platform depressions. (2) During the deposition of the Xixiangchi Group, storm activities were mainly in the southeastern, central and southwestern parts of the Sichuan Basin. Overall, storm action showed an initial increase followed by a decrease. (3) The impact of storms on the reworking of grain shoal reservoirs varies across different facies zones. The intra-platform depression margins, influenced by storm centers, experienced strong reworking, leading to the vertical stacking of storm-related grain shoals and normal grain shoals, which expands the scale of the shoal complex. Furthermore, storms enhance the penecontemporaneous dissolution, favoring the development of large-scale high-quality reservoirs. The intra-platform depressions and mixed tidal flats, controlled by the storm centers, were weakly modified, possibly inducing scattered storm-related grain shoals under low-energy conditions. The degree of karst modification is generally low, and local conditions are favorable for reservoir development. (4) The Dazu-Hechuan-Guang’an area, strongly reworked by storm activities, exhibits a large scale of storm-related grain shoals with good physical properties, providing favorable conditions for the development of contiguous, high-quality grain shoal reservoirs, so it can be regarded as a key target for subsequent exploration of the Xixiangchi Group.

Considering the complex occurrence environment and significant compositional variation of continental shale oil, as well as the uncertainties in its mobility and producible amount, this study employs geochemical analysis and production monitoring to investigate the “component flow” phenomenon of shale oil during production from the Permian Lucaogou Formation in the Jimsar Sag, Junggar Basin. It is clarified that the miscibility of different hydrocarbon components and non-hydrocarbon substances improves the flowability of multi-component hydrocarbons and non-hydrocarbons, thereby effectively enhancing the production of shale oil. Research indicates that the “lower sweet spot” has a relatively high content of light and medium hydrocarbon components and strong formation energy compared to the “upper sweet spot” of Lucaogou Formation, resulting in higher density and viscosity of the produced crude oil, which can be regarded as evidence of “component flow” of retained hydrocarbons. The “upper sweet spot” exhibits two scenarios. In areas far from faults with good preservation conditions, the high content of light and medium components in retained hydrocarbons and a high formation pressure coefficient make component flow more likely to occur. Consequently, the produced crude oil has a higher density, and the estimated ultimate recovery (EUR) per well is also higher. In areas near faults with poor preservation conditions, although the produced crude oil has a light density, the EUR per well is relatively low, indicating that the conditions for component flow of retained hydrocarbons underground have deteriorated. The study also demonstrates that preservation conditions (preventing light hydrocarbon escape and maintaining formation energy) and production strategies (controlling production pressure differential and maintaining stable operations) are important factors in regulating the occurrence and continuity of “component flow” to maximize EUR per well. These new insights can be applied to the evaluation of economically productive “sweet spots” and provide guidance for achieving optimal EUR per well in shale oil production.

The compound system of polyacrylamide hydrogels and surfactant solutions are used for enhanced oil recovery (EOR). The polyacrylamide hydrogels are injected into block high-permeability zones firstly, followed by a low-cost sacrificial agent, then an oil-displacing surfactant, and finally an aqueous polymer solution containing diethanolamine, to enhance oil production. The hydrogels are selected through oscillatory rheometry, while the surfactant is optimized after optical imaging analysis. The EOR performance of the compound system is evaluated through core flooding experiments and reservoir numerical simulation. Specifically, the properly cross-linked polyacrylamide hydrogel can be selected using its elastic modulus as a quantitative parameter while accounting for pore structure. The sacrificial agent is used to block active adsorption sites in the rock matrix before mobilizing more crude oil with a nonionic-anionic surfactant system. The addition of the mild organic alkali (diethanolamine) into the polymer slug reduces surfactant adsorption and improves sweep efficiency, thereby enhancing the oil-washing effect. Flooding experimental results show that the sequential injection of hydrogel and surfactant compositions prolongs the period of increasing pressure gradient during subsequent waterflooding and significantly boosts oil production, achieving a 21-percentage-point increase in oil displacement efficiency. Numerical simulation for the target reservoir in the West Siberian oil province confirms the effectiveness, projecting a maximum cumulative oil increase of 6 851 t over three years.

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

Traditional wellbore detection technologies face limitations such as low detection efficiency, poor accuracy, unsuitability for unconventional oil/gas well fracturing operations, and incomplete coverage of wellbore damage as well as integrity assessment. This paper introduces a phased array electromagnetic wellbore detection technology. The theoretical principles, instrument design, and technical connotation of this technology are systematically elaborated. Field applications, including casing damage and corrosion detection in old wells in Xinjiang Oilfield, China, and fracturing-induced casing deformation detection in platform wells targeting deep shale gas in Southwest Oil & Gas Field and deep shale oil in Dagang Oilfield, China, are analyzed to evaluate the proposed technology’s performance in inspecting metal casing strings. Results demonstrate that the phased array electromagnetic wellbore detection technology provides high measurement accuracy, broad applicability, ease of operation and high scalability. The technology achieves a resolution of 10 mm for non-penetrating damage detection, 0.5 mm for inner diameter measurement of oil casing, and 0.3 mm for wall thickness assessment. It maintains stable performance in high-temperature (no more than 175 °C) and high-pressure (no more than 140 MPa) environments, and effectively addresses current exploration and production requirements by providing comprehensive and accurate wellbore integrity data for downhole operations.

This paper proposes a multi-agent system centered on large language models to address the issues that traditional well log interpretation relies on expert experience and poses great difficulty in multi-disciplinary collaboration and constructs a digital twin architecture across three dimensions of agents, tools and environment. At the agent level, a role-based architecture is established to decompose the complex log interpretation workflow into independent subtasks, enabling structured transfer of expert knowledge. At the tool level, petrophysical formulas and machine learning algorithms are encapsulated to form a physics-data dual-path hybrid reasoning mechanism; at the environment level, a standardized digital twin space is established based on the Model Context Protocol to achieve closed-loop control of the entire workflow. Engineers can drive the system through natural language commands to complete the full log interpretation process from data loading and parameter calculation to reservoir classification, realizing end-to-end automation from raw data to interpretation conclusions. In tests on 100 field wells, the system generates key interpretation parameters that are highly consistent with expert results, exhibiting stable recognition capability for complex reservoir types. This study demonstrates that this human-machine collaborative working mode significantly enhances the standardization and efficiency of well log interpretation, providing technical reference for intelligent transformation of highly specialized industrial processes.

Given the absence of a prediction method for proppant embedment depth in artificial fractures of hydrate reservoirs, this study employs a hypoplastic constitutive model to quantitatively evaluate the impact of hydrate saturation on the mechanical parameters of the sediments. By integrating the load distribution at the proppant-sediment interface with their respective deformation characteristics, a computational model is developed to determine the proppant embedment depth across three distinct stages: elastic, elastoplastic and fully plastic. Based on the established model, the influences of hydrate saturation, proppant particle size, proppant arrangement pattern, and closure pressure on the proppant embedment depth are analyzed. The results demonstrate that the proppant embedment depth in fractures of hydrate reservoirs increases with greater closure pressure and larger proppant particle sizes, while it decreases with higher hydrate saturation and increased proppant areal packing density. At a constant closure pressure, the proppant embedment depth exhibits a nonlinear relationship with hydrate saturation, proppant particle size, and proppant areal packing density, with this nonlinearity becoming more pronounced at elevated closure pressures.

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.

Using the latest global datasets of hydrocarbon fields and reservoirs, this study systematically investigates the characteristics of differential hydrocarbon enrichment and its primary controlling factors in the southern Tethys Domain within the context of Tethys tectonic evolution. The results indicate that although the southern Tethys Domain comprises only one-third of the Tethys Domain in areal extent, it hosts nearly 80% of its total hydrocarbon reserves, exhibiting a markedly uneven distribution pattern. Specifically, the Middle East sub-segment is identified as the core enrichment area, with the Arabian Basin serving as a typical example. Through tectonic subdivision, classification of sedimentary basins, analysis of source rock distribution and reservoir-seal assemblages, as well as an integrated investigation of the relationship between succeeding paleo-uplifts and hydrocarbon enrichment, the study demonstrates that the superimposition patterns of prototype basins, the scale and distribution of source rocks, the effectiveness of reservoir-seal assemblages, and the basement paleo-uplifts are the key factors governing hydrocarbon enrichment in the southern Tethys Domain. The findings of this study provide valuable references for deeper understanding of hydrocarbon accumulation patterns in the central and northern Tethys Domain and even other global regions with similar geological settings, and offer a scientific basis for selection of favorable play fairways in the southern Tethys Domain.

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.

In response to the unsatisfactory water injection performance in Qinghai Oilfield caused by complex reservoir geological conditions, the fourth-generation cable-controlled zonal water injection technology was innovatively upgraded. An integrated fine water injection technology system was established, integrating fine reservoir characterization, intelligent zonal water injection with precise monitoring, and remote dynamic regulation. Through the design of high-temperature-resistant measurement and control circuits and the development of low-flow downhole flow measurement technology, a small-diameter cable-controlled water distributor suitable for complex conditions characterized by high temperature, high pressure, and high salinity was developed. In addition, a remote monitoring and management system for zonal water injection was established, enabling real-time monitoring of production parameters and dynamic regulation of injection rates throughout the entire layered water injection process. The technology system has been applied in the Huatugou and Yingdong demonstration areas. The intelligent zonal water injection can effectively improve the injection profile, enhance waterflood sweep efficiency, control the natural production decline rate of well groups, increase the qualification rate of zonal water injection, and slow down the rise of water cut. Economic evaluation results show that, compared with conventional zonal water injection technology, the proposed intelligent zonal fine water injection method demonstrates significant advantages in reducing operational costs and improving development efficiency. The results indicate that the upgraded fourth-generation cable-controlled zonal water injection technology can significantly improve waterflood performance and provides a replicable and scalable engineering solution for fine water injection and efficient, stable production in complex fault-block reservoirs.