The production optimization in the closed-loop reservoir management is generally empirical, and challenged by the issues such as low precision, low efficiency, and difficulty in solving constrained optimization problems. This paper outlines the main principles, advantages and disadvantages of commonly used production optimization methods/models, and then proposes an intelligent integrated production optimization method for waterflooding reservoirs that considers efficiency and precision, real-time and long-term effects, and the interaction and synergy between a variety of optimization models. This method integrates multiple optimization methods/models, such as reservoir performance analysis, reduced-physics models, and reservoir numerical models, with these model results and insights organically coupled to facilitate model construction and matching. This proposed method is elucidated and verified by field examples. The findings indicate that the optimal production optimization model varies depending on the specific application scenario. Reduced-physics models are conducive to short-term real-time optimization, whereas the simulator-based surrogate optimization and streamline-based simulation optimization methods are more suitable for long-term optimization strategy formulation, both of which need to be implemented under reasonable constraints from the perspective of reservoir engineering in order to be of practical value.

To improve the accuracy and generalization of well logging curve reconstruction, this paper proposes an artificial intelligence large language model “Gaia” and conducts model evaluation experiments. By fine-tuning the pre-trained large language model, the Gaia significantly improved its ability in extracting sequential patterns and spatial features from well-log curves. Leveraging the adapter method for fine-tuning, this model required training only about 1/70 of its original parameters, greatly improving training efficiency. Comparative experiments, ablation experiments, and generalization experiments were designed and conducted using well-log data from 250 wells. In the comparative experiment, the Gaia model was benchmarked against cutting-edge small deep learning models and conventional large language models, demonstrating that the Gaia model reduced the mean absolute error (MAE) by at least 20%. In the ablation experiments, the synergistic effect of the Gaia model's multiple components was validated, with its MAE being at least 30% lower than that of single-component models. In the generalization experiments, the superior performance of the Gaia model in blind-well predictions was further confirmed. Compared to traditional models, the Gaia model is significantly superior in accuracy and generalization for logging curve reconstruction, fully showcasing the potential of large language models in the field of well-logging. This provides a new approach for future intelligent logging data processing.

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.

Conventional borehole image log interpretation of linear fractures on volcanic rocks, represented as sinusoids on unwrapped cylinder projections, is relatively straight-forward, however, interpreting non-linear rock structures and complex facies geometries can be more challenging. To characterize diverse volcanic paleoenvironments related to the formation of the South American continent, this study presents a new methodology based on image logs, petrography, seismic data, and outcrop analogues. The presented methodology used pseudo-boreholes images generated from outcrop photographs with typical igneous rock features worldwide simulating 2D unwrapped cylinder projections of a 31 cm (12.25 in) diameter well. These synthetic images and standard outcrop photographs were used to define morphological patterns of igneous structures and facies for comparison with wireline borehole image logs from subsurface volcanic and subvolcanic units, providing a “visual scale” for geological evaluation of volcanic facies, significantly enhancing the identification efficiency and reliability of complex geological structures. Our analysis focused on various scales of columnar jointing and pillow lava lobes with additional examples including pahoehoe lava, ignimbrite, hyaloclastite, and various intrusive features in Campos, Santos, and Parnaíba basins in Brazil. This approach increases confidence in the interpretation of subvolcanic, subaerial, and subaqueous deposits. The image log interpretation combined with regional geological knowledge has enabled paleoenvironmental insights into the rift magmatism system related to the breakup of Gondwana with associated implications for hydrocarbon exploration.

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.

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.

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.

The presence of clay coatings on the surfaces of quartz grains can play a pivotal role in determining the porosity and permeability of sandstone reservoirs, thus directly impacting their reservoir quality. This study employs a multiphase-field model of syntaxial quartz cementation to explore the effects of clay coatings on quartz cement volumes, porosity, permeability, and their interrelations in sandstone formations. To generate various patterns of clay coatings on quartz grains within three-dimensional (3D) digital sandstone grain packs, a pre-processing toolchain is developed. Through numerical simulation experiments involving syntaxial overgrowth cementation on both single crystals and multigrain packs, the main coating parameters controlling quartz cement volume are elucidated. Such parameters include the growth of exposed pyramidal faces, lateral encasement, coating coverage, and coating pattern, etc. The coating pattern has a remarkable impact on cementation, with the layered coatings corresponding to fast cement growth rates. The coating coverage is positively correlated with the porosity and permeability of sandstone. The cement growth rate of quartz crystals is the lowest in the vertical orientation, and in the middle to late stages of evolution, it is faster in the diagonal orientation than in the horizontal orientation. Through comparing the simulated results of dynamic evolution process with the actual features, it is found that the simulated coating patterns after 20 d and 40 d show clear similarities with natural samples, proving the validity of the proposed three-dimensional numerical modeling of coatings. The methodology and findings presented contribute to improved reservoir characterization and predictive modeling of sandstone formations.

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.

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

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.

The core sampling experiments were conducted after hydraulic fracturing in the three-dimensional development zone of Fuling shale gas. Six coring wells of different well types were systematically designed. Based on the integrated engineering technology of post-fracturing drilling, coring and monitoring of shale and the analysis of fracture source tracing, the evaluation of the fracture network after fracturing in the three-dimensional development of shale gas was conducted. The data of core fractures after fracturing indicate that three major types of fractures are formed after fracturing: natural fractures, hydraulic fractures, and fractures induced by external mechanical force, which are further classified into six subcategories: natural structural fractures, natural bedding fractures, hydraulic fractures, hydraulically activated fractures, drilling induced fractures, and fractures induced by core transportation. The forms of the artificial fracture network after fracturing are complex. Hydraulic fractures and hydraulically activated fractures interweave with each other, presenting eight forms of artificial fracture networks, among which the “一”-shaped fracture is the most common, accounting for approximately 70% of the total fractures. When the distance to the fractured wellbore is less than 35 m, the density of the artificial fracture network is relatively high; when it is 35-100 m, the density is lower; and when it is beyond 100 m, the density gradually increases. The results of the fracture tracing in the core sampling area confirm that the current fracturing technology can essentially achieve the differential transformation of the reservoir in the main area of Jiaoshiba block in Fuling. The three-layer three-dimensional development model can efficiently utilize shale gas reserves, although there is still room for improvement in the complexity and propagation uniformity of fractures. It is necessary to further optimize technologies such as close-cutting combined with temporary blocking and deflection within fractures or at fracture mouths, as well as limited flow perforation techniques, to promote the balanced initiation and extension of fractures.

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.

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.

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.

The Mesozoic volcanic rocks of the Bodong Low Uplift in the Bohai Bay Basin have been studied and explored for years. In 2024, the LK7-A well drilled in this region tested high-yield oil and gas flows from volcanic weathered crust. These volcanic rocks need to be further investigated in terms of distribution patterns, conditions for forming high-quality reservoirs, and main factors controlling hydrocarbon accumulation. Based on the logging, geochemical and mineralogical data from wells newly drilled to the Mesozoic volcanic rocks in the basin, and high-resolution 3D seismic data, a comprehensive study was conducted for this area. The research findings are as follows. First, the volcanic rocks in the LK7-A structure are adakites with a large source area depth, and the deep and large faults have provided channels for the emplacement of intermediate-acidic volcanic rocks. Second, volcanic rock reservoirs are mainly distributed in tectonic breccias and intermediate-acidic lavas, and they are dominantly fractured-porous reservoirs, with high-porosity and low-permeability or medium-porosity and low-permeability. Third, the dominant lithologies/lithofacies is the basic condition for forming large-scale volcanic rock reservoirs. Structural fractures and late-stage strong weathering are crucial mechanisms for the formation scale of reservoirs in the Mesozoic volcanic rocks. Fourth, the Bodong Low Uplift exhibits strong hydrocarbon charging by two sags and overpressure mudstone capping, which are favorable for forming high-abundance oil and gas reservoirs. The Mesozoic volcanic buried hills in the study area reflect good trap geometry, providing favorable conditions for large-scale reservoir formation, and also excellent migration and accumulation conditions. Areas with long-term exposure of intermediate-acidic volcanic rocks, particularly in active structural regions, are the key targets for future exploration.

During drilling operations, the low resolution of seismic data often limits the accurate characterization of small-scale geological bodies near the borehole and ahead of the drill bit. This study investigates high-resolution seismic data processing technologies and methods tailored for drilling scenarios. The high-resolution processing of seismic data is divided into three stages: pre-drilling processing, post-drilling correction, and while-drilling updating. By integrating seismic data from different stages, spatial ranges, and frequencies, together with information from drilled wells and while-drilling data, and applying artificial intelligence modeling techniques, a progressive high-resolution processing technology of seismic data based on multi-source information fusion is developed, which performs simple and efficient seismic information updates during drilling. Case studies show that, with the gradual integration of multi-source information, the resolution and accuracy of seismic data are significantly improved, and thin-bed weak reflections are more clearly imaged. The updated seismic information while-drilling demonstrates high value in predicting geological bodies ahead of the drill bit. Validation using logging, mud logging, and drilling engineering data ensures the fidelity of the processing results of high-resolution seismic data. This provides clearer and more accurate stratigraphic information for drilling operations, enhancing both drilling safety and efficiency.

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.

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.

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 a large amount of basic research and experimental analysis data from Shengli Oilfield, Bohai Bay Basin, guided by the theory of whole petroleum system, the distribution of sedimentary systems, the distribution and hydrocarbon generation and expulsion process of source rocks, the variation of reservoir properties, and the control of fracture systems on hydrocarbon accumulation in the Paleogene of the Jiyang Depression, Boahai Bay Basin, were systematically analyzed, and the geological characteristics of the whole petroleum system in the rift basin were identified. Taking the Dongying Sag as an example, combined with the distribution of discovered conventional, tight, and shale oil/gas, a hydrocarbon accumulation model of the fault-controlled whole petroleum system in rift basin was proposed, and the distribution patterns of conventional and unconventional oil and gas reservoirs in large geological bodies horizontally and vertically were clarified. The research results show that paleoclimate and tectonic cycles control the orderly distribution of the Paleogene sedimentary system in the Jiyang Depression, the multi-stage source rocks provide sufficient material basis for in-situ shale oil/gas accumulation and other hydrocarbon migration and accumulation, the changes in reservoir properties control the dynamic threshold of hydrocarbon accumulation, and the combination of faults and fractures at different stages controls hydrocarbon migration and accumulation, and in-situ retention and accumulation of shale oil/gas, making the whole petroleum system in the rift basin associated, segmented and abrupt. The above elements are configured to form a composite whole petroleum system controlled by faults in the Paleogene of the Jiyang Depression. Moreover, under the control of hydrocarbon accumulation dynamics, a whole petroleum system can be divided into conventional subsystem and unconventional subsystem, with shale oil, tight oil and conventional oil in an orderly distribution in horizontal and vertical directions. This systematic understanding is referential for analyzing the whole petroleum system in continental rift basins in eastern China.

This study systematically reviews the development history and key technological breakthroughs of large gas fields in the Ordos Basin, and summarizes the development models of three gas reservoir types, low-permeability carbonate, low-permeability sandstone and tight sandstone, as well as the progress in deep coal-rock gas development. The current challenges and future development directions are also discussed. Mature development models have been formed for the three representative types of gas reservoirs in the Ordos Basin: (1) Low-permeability carbonate reservoir development model featuring groove fine-scale characterization and three-dimensional vertical succession between Upper and Lower Paleozoic formations. (2) Low-permeability sandstone reservoir development model emphasizing horizontal well pressure-depletion production and vertical well pressure-controlled production. (3) Tight sandstone gas reservoir development model focusing on single-well productivity enhancement and well placement optimization. In deep coal-rock gas development, significant progress has been achieved in reservoir evaluation, sweet spot prediction, and geosteering of horizontal wells. The three types of reservoirs have entered the mid-to-late stages of the development, when the main challenge lies in accurately characterizing residual gas, evaluating secondary gas-bearing layers, and developing precise potential-tapping strategies. In contrast, for the early-stage development of deep coal-rock gas, continuous technological upgrades and cost reduction are essential to achieving economically viable large-scale development. Four key directions of future research and technological breakthroughs are proposed: (1) Utilizing dual-porosity (fracture-matrix) modeling techniques in low-permeability carbonate reservoirs to delineate the volume and distribution of remaining gas in secondary pay zones, supporting well pattern optimization and production enhancement of existing wells. (2) Integrating well-log and seismic data to characterize reservoir spatial distribution of successive strata, enhancing drilling success rates in low-permeability sandstone reservoirs. (3) Utilizing the advantages of horizontal wells to penetrate effective reservoirs laterally, achieving meter-scale quantification of small-scale single sand bodies in tight gas reservoirs, and applying high-resolution 3D geological models to clarify the distribution of remaining gas and guide well placement optimization. (4) Further strengthening the evaluation of deep coal-rock gas in terms of resource potential, well type and pattern, reservoir stimulation, single-well performance, and economic viability.

Based on large-field rock thin section scanning, high-resolution field emission-scanning electron microscopy (FE-SEM), fluorescence spectroscopy, and rock pyrolysis experiments of the Mesoproterozoic Jixianian Hongshuizhuang Formation shale samples from the Yanliao Basin in northern China, combined with sedimentary forward modeling, a systematic petrological and organic geochemical study was conducted on the reservoir quality, oil-bearing potential, distribution, and resource potential of the Hongshuizhuang Formation shale in Well Yuanji-2. The results indicate that: (1) The original organic carbon content of the Hongshuizhuang Formation shale averages up to 6.24%, and the original hydrocarbon generation potential is as high as 44.09 mg/g, demonstrating a strong oil generation potential. (2) The rock type is primarily siliceous shale containing low clay mineral content, characterized by the development of shale bedding fractures and organic shrinkage fractures, resulting in good compressibility and reservoir quality. (3) The fifth and fourth members of the Hongshuizhuang Formation serve as shale oil sweet spots, contributing more than 60% of shale oil production with their total thickness as only 40% of the target formation. (4) The Kuancheng-Laozhuanghu area is the most prospective shale oil exploration option in the Yanliao Basin and covers approximately 7 200 km². Its original total hydrocarbon generation potential reaches about 74.11 billion tons, with current estimated retained shale oil resources exceeding 1.148 billion tons (lower limit) - comparable to the geological resources of the Permian Lucaogou Formation shale oil in the Jimsar Sag of the Junggar Basin. These findings demonstrate the robust exploration potential of the Hongshuizhuang Formation shale oil in the Yanliao Basin.

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.

For shale oil reservoirs in the Jimsar Sag of Junggar Basin, the fracturing treatments are challenged by poor prediction accuracy and difficulty in parameter optimization. This paper presents a fracturing parameter intelligent optimization technique for shale oil reservoirs and verifies it by field application. A self-governing database capable of automatic capture, storage, calls and analysis is established. With this database, 22 geological and engineering variables are selected for correlation analysis. A separated fracturing effect prediction model is proposed, with the fracturing learning curve decomposed into two parts: (1) overall trend, which is predicted by the algorithm combining the convolutional neural network with the characteristics of local connection and parameter sharing and the gated recurrent unit that can solve the gradient disappearance; and (2) local fluctuation, which is predicted by integrating the adaptive boosting algorithm to dynamically adjust the random forest weight. A policy gradient-genetic-particle swarm algorithm is designed, which can adaptively adjust the inertia weights and learning factors in the iterative process, significantly improving the optimization ability of the optimization strategy. The fracturing effect prediction and optimization strategy are combined to realize the intelligent optimization of fracturing parameters. The field application verifies that the proposed technique significantly improves the fracturing effects of oil wells, and it has good practicability.

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.

For deep prospects in the foreland thrust belt, southern Junggar Basin, NW China, there are uncertainties in factors controlling the structural deformation, distribution of paleo-structures and detachment layers, and distribution of major hydrocarbon source rocks. Based on the latest 3D seismic, gravity-magnetic, and drilling data, together with the results of previous structural physical simulation and discrete element numerical simulation experiments, the spatial distribution of pre-existing paleo-structures and detachment layers in deep strata of southern Junggar Basin were systematically characterized, the structural deformation characteristics and formation mechanisms were analyzed, the distribution patterns of multiple hydrocarbon source rock suites were clarified, and hydrocarbon accumulation features in key zones were reassessed. The exploration targets in deep lower assemblages with possibility of breakthrough were expected. Key results are obtained in three aspects. First, structural deformation is controlled by two-stage paleo-structures and three detachment layers with distinct lateral variations: the Jurassic layer (moderate thickness, wide distribution), the Cretaceous layer (thickest but weak detachment), and the Paleogene layer (thin but long-distance lateral thrusting). Accordingly, a four-layer composite deformation sequence was identified, and the structural genetic model with paleo-bulge controlling zonation by segments laterally and multiple detachment layers controlling sequence vertically. Second, the Permian source rocks show a distribution pattern with narrow trough (west), multiple sags (central), and broad basin (east), which is depicted by combining high-precision gravity-magnetic data and time-frequency electromagnetic data for the first time, and the Jurassic source rocks feature thicker mudstones in the west and rich coals in the east according to the reassessment. Third, two petroleum systems and a four-layer composite hydrocarbon accumulation model are established depending on the structural deformation strength, trap effectiveness and source-trap configuration. The southern Junggar Basin is divided into three segments with ten zones, and a hierarchical exploration strategy is proposed for deep lower assemblages in this region, that is, focusing on five priority zones, expanding to three potential areas, and challenging two high-risk targets.

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.

To optimize the bit selection for large-diameter wellbore in the upper section of an ultra-deep well S-1, a full-well dynamic model integrating drill string vibration and bit rock-breaking was established and then verified using measured vibration data of drilling tools and actual rate of penetration (ROP) from Well HT-1 in northern Sichuan Basin. This model was employed to calculate and analyze drill string dynamic characteristics during large-diameter wellbore drilling in the Jurassic Penglaizhen Formation of Well S-1, followed by bit optimization. Research results show that during the drilling in Penglaizhen Formation of Well S-1, considering both the ROP of six candidate bits and the lateral/axial/torsional vibration characteristics of downhole tools, the six-blade dual-row cutter bit with the fastest ROP (average 7.12 m/h) was optimally selected. When using this bit, the downhole tool vibration levels remained at medium-low values. Field data showed over 90% consistency between actual ROP data and dynamic model calculation results after bit placement, demonstrating that the model can be used for bit program screening.

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.

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.

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.

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.

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 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.

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.

This study takes shale samples from the Jiaoshiba block in the Fuling shale gas field of the Sichuan Basin, and uses the true triaxial testing system to conduct a series of mechanical experiments under deep shale reservoir conditions after shale hydration. Stress-strain data and mechanical parameters of shale after hydration under high temperature and high pressure were obtained to investigate the effects of reservoir temperature, hydration time and horizontal stress difference on the mechanical strength of shale after hydration. By using nonlinear regression and interpolation methods, a prediction model for the mechanical strength of shale after hydration was constructed, and the mechanical strength chart of deep shale under high stress difference was plotted. First, higher hydration temperature, longer hydration reaction time, and greater horizontal stress difference cause shale to enter the yield stage earlier during the compression process after hydration and to exhibit more prominent plastic characteristics, lower peak strength, peak strain, residual strength and elastic modulus, and higher Poisson’s ratio. Second, the longer the hydration time, the smaller the impact of hydration temperature on the mechanical strength of deep shale is. As the horizontal stress difference increases, the peak strength and residual strength weaken intensely, and the peak strain, elastic modulus and Poisson’s ratio deteriorate slowly. Third, the mechanical strength of shale decreases significantly in the first 5 days of hydration, but gradually stabilizes as the hydration time increases. Fourth, the visual mechanical strength chart helps to understand the post-fracturing dynamics in deep shale gas reservoir fracturing site and adjust the drainage and production plan in time.

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

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.