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 analysis of surface geological survey, exploratory well, gravity-magnetic-electric and seismic data, and through mapping the sedimentary basin and its peripheral orogenic belts together, this paper explores systematically the boundary, distribution, geological structure, and tectonic attributes of the Ordos prototype basin in the geological historical periods. The results show that the Ordos block is bounded to the west by the Engorwusu Fault Zone, to the east by the Taihangshan Mountain Piedmont Fault Zone, to the north by the Solonker-Xilamuron Suture Zone, and to the south by the Shangnan-Danfeng Suture Zone. The Ordos Basin boundary was the plate tectonic boundary during the Middle Proterozoic to Paleozoic, and the intra-continental deformation boundary in the Meso-Cenozoic. The basin survived as a marine cratonic basin covering the entire Ordos block during the Middle Proterozoic to Ordovician, a marine-continental transitional depression basin enclosed by an island arc uplift belt at the plate margin during the Carboniferous to Permian, a unified intra-continental lacustrine depression basin in the Triassic, and an intra-continental cratonic basin circled by a rift system in the Cenozoic. The basin scope has been decreasing till the present. The large, widespread prototype basin controlled the exploration area far beyond the present-day sedimentary basin boundary, with multiple target plays vertically. The Ordos Basin has the characteristics of a whole petroleum (or deposition) system. The Middle Proterozoic wide-rift system as a typical basin under the overlying Phanerozoic basin and the Cambrian-Ordovician passive margin basin and intra-cratonic depression in the deep-sited basin will be the important successions for oil and gas exploration in the coming years.

This study introduces a novel methodology and makes case studies for anomaly detection in multivariate oil production time-series data, utilizing a supervised Transformer algorithm to identify spurious events related to interval control valves (ICVs) in intelligent well completions (IWC). Transformer algorithms present significant advantages in time-series anomaly detection, primarily due to their ability to handle data drift and capture complex patterns effectively. Their self-attention mechanism allows these models to adapt to shifts in data distribution over time, ensuring resilience against changes that can occur in time-series data. Additionally, Transformers excel at identifying intricate temporal dependencies and long-range interactions, which are often challenging for traditional models. Field tests conducted in the ultradeep water subsea wells of the Santos Basin further validate the model’s capability for early anomaly identification of ICVs, minimizing non-productive time and safeguarding well integrity. The model achieved an accuracy of 0.954 4, a balanced accuracy of 0.969 4 and an F1-Score of 0.957 4, representing significant improvements over previous literature models.

Based on the technological demands for significantly enhancing oil recovery and long-term CO₂ sequestration in the lacustrine oil reservoirs of China, this study systematically reviews the progress and practices of CO₂ flooding and storage technologies in recent years. It addresses the key technological needs and challenges faced in scaling up the application of CO₂ flooding and storage to mature, developed oil fields, and analyzes future development directions. During the pilot test phase (2006-2019), continuous development and application practices led to the establishment of the first-generation CO₂ flooding and storage technology system for lacustrine reservoirs. In the industrialization phase (since 2020), significant advances and insights have been achieved in terms of confined phase behavior, storage mechanisms, reservoir engineering, sweep control, engineering process and storage monitoring, enabling the maturation of the second-generation CO₂ flooding and storage theories and technologies to effectively support the demonstration projects of Carbon Capture, Utilization and Storage (CCUS). To overcome key technical issues such as low miscibility, difficulty in gas channeling control, high process requirements, limited application scenarios, and coordination challenges in CO₂ flooding and storage, and to support the large-scale application of CCUS, it is necessary to strengthen research on key technologies for establishing the third-generation CO₂ flooding and storage technological system incorporating miscibility enhancement and transformation, comprehensive regulation for sweep enhancement, whole-process engineering techniques and equipment, long-term storage monitoring safety, and synergistic optimization of flooding and storage.

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

Based on 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.

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

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.

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.

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.

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.

By integrating core observations, logging data and seismic interpretation, this study takes the massive Cretaceous carbonates in the M block of the Santos Basin, Brazil, as an example to establish the sequence filling pattern of fault-bounded isolated platforms in rift lake basins, reveal the control mechanisms of shoal-body development and reservoir formation, and reconstruct the evolutionary history of lithofacies paleogeography. The following results are obtained. (1) Three tertiary sequences (SQ1-SQ3) are identified in the Lower Cretaceous Itapema-Barra Velha of the M block. During the depositional period of SQ1, the rift basement faults controlled the stratigraphic distribution pattern of thick on both sides and thin in the middle. The strata overlapped to uplift in the early stage. During the depositional period of SQ2-SQ3, the synsedimentary faults controlled the paleogeomorphic reworking process with subsidence in the northwest and uplifting in the northeast, accompanied with the relative fall of lake level. (2) The Lower Cretaceous in the M block was deposited in a littoral-shallow lake, with the lithofacies paleogeographic pattern transiting from the inner clastic shoals and outer shelly shoals in SQ1 to the alternation of mounds and shoals in SQ2-SQ3. (3) Under the joint control of relative lake-level fluctuation, synsedimentary faults and volcanic activity, the shelly shoals in SQ1 tend to accumulated vertically in the raised area, and the mound-shoal complex in SQ2-SQ3 tends to migrate laterally towards the slope-break belt due to the reduction of accommodation space. (4) The evolution pattern of high-energy mounds and shoals, which were vertically accumulated in the early stage and laterally migrated in the later stage, controlled the transformation of high-quality reservoirs from “centralized” to “ring shaped” distribution. The research findings clarify the sedimentary patterns of mounds and shoals and the distribution of favorable reservoirs in the fault-controlled lacustrine isolated platform, providing support for the deepwater hydrocarbon exploration in the subsalt carbonate rocks in the Santos Basin.

There are various types of natural gas resources in coal measures, making them major targets for natural gas exploration and development in China. In view of the particularity of the whole petroleum system of coal measures and the reservoir-forming evolution of natural gas in coal, this study reveals the formation, enrichment characteristics and distribution laws of coal-rock gas by systematically reviewing the main types and geological characteristics of natural gas in the whole petroleum system of coal measures. First, natural gas in the whole petroleum system of coal measures is divided into two types, conventional gas and unconventional gas, according to its occurrence characteristics and accumulation mechanism, and into six types, distal detrital rock gas, special rock gas, distal/proximal tight sandstone gas, inner-source tight sandstone gas, shale gas, and coal-rock gas, according to its source and reservoir lithology. The natural gas present in coal-rock reservoirs is collectively referred to as coal-rock gas. Existing data indicate significant differences in the geological characteristics of coal-rock gas exploration and development between shallow and deep layers in the same area, with the transition depth boundary generally 1500-2 000 m. Based on the current understanding of coal-rock gas and respecting the historical usage conventions of coalbed methane terminology, coal-rock gas can be divided into deep coal-rock gas and shallow coalbed methane according to burial depth. Second, according to the research concept of “full-process reservoir formation” in the theory of the whole petroleum system of coal measures, based on the formation and evolution of typical coal-rock gas reservoirs, coal-rock gas is further divided into four types: primary coal-rock gas, regenerated coal-rock gas, residual coal-rock gas, and bio coal-rock gas. The first two belong to deep coal-rock gas, while the latter two belong to shallow coal-rock gas. Third, research on the coal-rock gas reservoir formation and evolution shows that shallow coal-rock gas is mainly residual coal-rock gas or bio coal-rock gas formed after geological transformation of primary coal-rock gas, with the reservoir characteristics such as low reservoir pressure, low gas saturation, adsorbed gas in dominance, and gas production by drainage and depressurization, while deep coal-rock gas is mainly primary coal-rock gas and regenerated coal-rock gas, with the reservoir characteristics such as high reservoir pressure, high gas saturation, abundant free gas, and no or little water. In particular, the primary coal-rock gas is wide in distribution, large in resource quantity, and good in reservoir quality, making it the most favorable type of coal-rock gas for exploration and development.

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.

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.

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 a set of high-resolution 3D seismic data from the northern continental margin of the South China Sea, the lithospheric structure, thinning mechanisms and related syn-rift tectonic deformation response processes in the crustal necking zone in the deepwater area of the Pearl River Mouth Basin were systematically analyzed, and the petroleum geological significance was discussed. The necking zone investigated in the study is located in the Baiyun Sag and Kaiping Sag in the deepwater area of the Pearl River Mouth Basin. These areas show extreme crustal thinned geometries of central thinning and flank thickening, characterized by multi-level and multi-dipping detachment fault systems. The necking zone exhibits pronounced lateral heterogeneity in structural architectures, which can be classified into four types of thinned crustal architectures, i.e. the wedge-shaped extremely thinned crustal architecture in the Baiyun Main Sub-sag, dumbbell-shaped moderately thinned crustal architecture in the Baiyun West Sub-sag, box-shaped weakly thinned crustal architecture in eastern Baiyun Sag, and metamorphic core complex weakly thinned crustal architecture in the Kaiping Sag. This shows great variations in the degree and style of crustal thinning, types of detachment faults, distribution of syn-rift sedimentary sequences, and intensity of magmatism. The thinning of the necking zone is controlled by the heterogeneous rheological stratification of lithosphere, intensity of mantle-derived magmatism, and deformation modes of detachment faults. The syn-rift tectonic deformation of the necking zone evolved through three phases, i.e. uniform stretching during the early Wenchang Formation deposition period, necking during the late Wenchang Formation deposition period, and hyperextension during the Enping Formation deposition period. The crustal thinning extent and architectural differentiation in these phases were primarily controlled by three distinct mechanisms, i.e. the pure shear deformation activation of pre-existing thrust faults, the simple shear deformation of crust-mantle and inter-crust detachment faults, and differential coupling of lower crustal flow and ductile domes with main detachment faults. The hydrocarbon accumulation and enrichment in the necking zone exhibit marked spatial heterogeneity. Four distinct crustal thinned architecture-hydrocarbon accumulation models were identified in this study. The hydrocarbon accumulations in the shallow part exhibit significant correlations with their deep crustal thinned architectures. The unique lithospheric structure and deformation process predominantly control the favorable hydrocarbon accumulation zones with excellent source-fault-ridge-sand configurations, which is critical to reservoir-forming. The most promising exploration targets are mainly identified on the uplift zones and their seaward-dipping flanks associated with the middle and lower crustal domes. This research provides additional insights into lithospheric thinning-breakup process at intermediate continental margins of marine sedimentary basins, being significant for guiding the deepwater petroleum exploration in the Pearl River Mouth Basin.

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.

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.

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.

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.

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.

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 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.

Based on the finite-discrete element method, a three-dimensional numerical model for axial impact rock breaking was established and validated. A computational method for energy conversion during impact rock breaking was proposed, and the effects of conical tooth forward rake angle, rock temperature, and impact velocity on rock breaking characteristics and energy transfer laws were analyzed. The results show that during single impact rock breaking with conical tooth bits, merely 7.52% to 12.51% of the energy is utilized for rock breaking, while a significant 57.26% to 78.10% is dissipated as frictional loss. An insufficient forward rake angle increases tooth penetration depth and frictional loss, whereas an excessive forward rake angle reduces penetration capability, causing bit rebound and greater energy absorption by the drill rod. Thus, an optimal forward rake angle exists. Regarding environmental factors, high temperatures significantly enhance impact-induced rock breaking. Thermal damage from high temperatures reduces rock strength and inhibits its energy absorption. Finally, higher impact velocities intensify rock damage, yet excessively high velocities increase frictional loss and reduce the proportion of energy absorbed by the rock, thereby failing to substantially improve rock breaking efficiency. An optimal impact velocity exists.

Based on the achievements and research advances in oil and gas exploration in the Persian Gulf Basin, this study analyzes the orderliness of oil and gas distribution and main controlling factors of hydrocarbon accumulation with reservoir-forming assemblage as the unit. In the Persian Gulf Basin, the hydrocarbon-generating centers of source rocks of different geological ages and the hydrocarbon rich zones migrate in a clockwise direction around the Ghawar Oilfield in the Central Arabian Subbasin. Horizontally, the overall distribution pattern is orderly, showing “oil in the west and gas in the east”, and “large oil and gas fields dense in the basin center and sparse at the basin edges”. Vertically, the extents of petroleum system compounding and sources mixing increase from west to east, the pattern of tectonic strength (weak in the west and strong in the east) forming the distribution characteristics of “gas rich in the Paleozoic, oil rich in the Mesozoic, and both oil and gas rich in the Cenozoic”. The large scale accumulation and orderly distribution of oil and gas in the Persian Gulf Basin are controlled by three factors: (1) Multiple sets of giant hydrocarbon kitchens provide a resource base for near-source reservoir-forming assemblages. The short-distance lateral migration determines the oil and gas enrichment in and around the distribution area of effective source rocks. (2) The anhydrite caprocks in the platform area are thin but have experienced weak late-stage tectonic activities. Their good sealing performance makes it difficult for oil and gas to migrate vertically to shallow layers through them. The thrust faults and high-angle fractures formed by intense tectonic activities of the Zagros Orogenic Belt connect multiple source-reservoir assemblages. However, the Neogene Gachsaran Formation gypsum-salt rocks are thick and highly plastic, generally with good sealing performance, so large-scale oil and gas accumulations are still formed beneath the salt; (3) Each set of reservoir-forming assemblages is well matched in time and space in terms of the development of source rocks and reservoir-caprock assemblages, the maturation and hydrocarbon generation of source rocks, and the formation of traps, thus resulting in abundant multi layer hydrocarbon accumulations. At present, the Persian Gulf Basin is still in the stage of structural trap exploration. The pre-salt prospective traps in effective hydrocarbon kitchens remain the first choice. The areas with significant changes in Mesozoic sedimentary facies have the conditions to form large scale lithologic oil and gas reservoirs. The deep Paleozoic conventional oil and gas reservoirs and the Lower Silurian Qusaiba Member shale gas have great exploration potential and are expected to become important reserve growth areas in the future.

By integrating laboratory physical modeling experiments with machine learning-based analysis of dominant factors, this study explored the feasibility of pulse hydraulic fracturing (PHF) in deep coal rocks and revealed the fracture propagation patterns and the mechanisms of pulsating loading in the process. The results show that PHF induces fatigue damage in coal matrix, significantly reducing breakdown pressure and increasing fracture network volume. Lower vertical stress differential coefficient (less than 0.31), lower peak pressure ratio (less than 0.9), higher horizontal stress differential coefficient (greater than 0.13), higher pulse amplitude ratio (greater than or equal to 0.5) and higher pulse frequency (greater than or equal to 3 Hz) effectively decrease the breakdown pressure. Conversely, higher vertical stress differential coefficient (greater than or equal to 0.31), higher pulse amplitude ratio (greater than or equal to 0.5), lower horizontal stress differential coefficient (less than or equal to 0.13), lower peak pressure ratio (less than 0.9), and lower pulse frequency (less than 3 Hz) promote the formation of a complex fracture network. Vertical stress and peak pressure are the most critical geological and engineering parameters affecting the stimulation effectiveness of PHF. The dominant mechanism varies with coal rank due to differences in geomechanical characteristics and natural fracture development. Low-rank coal primarily exhibits matrix strength degradation. High-rank coal mainly involves the activation of natural fractures and bedding planes. Medium-rank coal shows a coexistence of matrix strength degradation and micro-fracture connectivity. The PHF forms complex fracture networks through the dual mechanism of matrix strength degradation and fracture network connectivity enhancement.

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.

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.

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.

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 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.

The faults and associated fracture zones in the tight sandstone reservoirs of the fifth member of the Triassic Xujiahe Formation (Xu-5 Member) in the Wubaochang area, northeastern Sichuan Basin, play a critical role in controlling gas well productivity. To delineate the distribution patterns of the faults and associated fracture zones in this area, a transfer-trained convolutional neural network (CNN) model and an XGBoost (eXtreme Gradient Boosting)-based intelligent seismic attribute fusion method were employed to identify faults and fracture zones, respectively, enabling precise characterization of their spatial distribution. The faults in the Wubaochang area are classified into first- to fourth-order structures, with the average fracture zone width on the hanging wall exceeding that of the footwall, demonstrating a strong positive correlation between fracture zone width and fault displacement. The study area is divided into three distinct deformation regions (southern, central and northern regions) featuring five fault structural styles (duplex, duplex-backthrust, imbricate thrust, synclinorium imbricate-backthrust, and anticlinorium imbricate-backthrust) and four corresponding fracture zone development patterns (duplex, duplex-backthrust, synclinorium imbricate-backthrust, and anticlinorium imbricate-backthrust). Based on the controlling effects of faults on gas enrichment, the dual-source hydrocarbon-supply zones are interpreted to be distributed in the northern and central regions, while the southern region is identified as gas-escape zones. By integrating the distribution of favorable reservoir development areas and fracture zones, two classes of gas enrichment zones (Class I and II) are delineated. Class I zones are primarily distributed in the northern region and the transitional zone from the southern to central regions, whereas Class II zones are concentrated in the central region. Class I zones exhibit dual-source hydrocarbon-supply conditions, larger-scale fracture zone development, and higher favorability compared to Class II zones. According to the defined gas accumulation effectiveness in different types of fracture zones, a high-productivity gas well model for the Wubaochang area is proposed, emphasizing “dual-source faults controlling enrichment, effective fracture zones controlling high production, and high matrix porosity ensuring sustained production”. Targeted drilling directions for different favorable zones are further optimized based on this model.

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.

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.

Taking the second member of the Xujiahe Formation of the Upper Triassic in the Xinchang structural belt as an example, based on data such as logging, production, seismic interpretation and test, a systematic analysis was conducted on the structural characteristics and evolution, reservoir diagenesis and densification processes, and types and stages of faults/fractures, and revealing the multi-stage and multi-factor dynamic coupled enrichment mechanisms of tight gas reservoirs. (1) In the early Yanshan period, the paleo-structural traps were formed with low-medium maturity hydrocarbons accumulating in structural highs driven by buoyancy since reservoirs were not fully densified in this stage, demonstrating paleo-structure control on traps and early hydrocarbon accumulation. (2) In the middle-late Yanshan period, the source rocks became mature to generate and expel a large quantity of hydrocarbons. Grain size and type of sandstone controlled the time of reservoir densification, which restricted the scale of hydrocarbon charging, allowing for only a small-scale migration through sand bodies near the fault/fracture or less-densified matrix reservoirs. (3) During the Himalayan period, the source rocks reached overmaturity, and the residual oil cracking gas was efficiently transported along the late-stage faults/fractures. Wells with high production capacity were mainly located in Type I and II fault/fracture zones comprising the late-stage north-south trending fourth-order faults and the late-stage fractures. The productivity of the wells was controlled by the transformation of the late-stage faults/fractures. (4) The Xinchang structural belt underwent three stages of tectonic evolution, two stages of reservoir formation, and three stages of fault/fractures development. Hydrocarbons mainly accumulated in the paleo-structure highs. After reservoir densification and late fault/fracture adjustment, a complex gas-water distribution pattern was formed. Thus, it is summarized as the model of “near-source and low-abundance hydrocarbon charging in the early stage, and differential enrichment of natural gas under the joint control of fault-fold-fracture complex, high-quality reservoirs and structural highs in the late stage”. Faults/fractures with well-coupled fault-fold-fracture-pore are favorable exploration targets with high exploration effectiveness.

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.

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.

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.

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.