Current studies predominantly focus on macroscopic tectonic evolution, addressing the scientific challenges of insufficient understanding of the distribution and evolution of bedrock in source areas and unclear mechanisms of proximal sediment supply within regional provenance system research. However, research on the fine classification of bedrock types within source areas and their dynamic linkages with the 'source- to-sink' system remains notably inadequate. Based on high-resolution 3D seismic data, drilling and logging information, this study provides a new case for understanding the distribution patterns and evolution of bedrock in the source area of the 'source-sink' system, as well as a reference for studying depressions that supply sediments in close proximity. Our study demonstrates the following: (1) The Enping-Yangjiang low uplift area encompasses three bedrock types-granite, volcanic and sedimentary rocks-each corresponding to distinct seismic facies (SF1-SF3). Granite basement is directly intersected by multiple wells; sedimentary rocks exhibit stratified reflection characteristics; whereas volcanic rocks are characterised by a strong reflection envelope with weak, chaotic internal reflections. (2) The distribution of bedrock shows significant zoning. Jurassic granite dominates the main body, sedimentary rocks are concentrated in the northern arcuate fault zone, volcanic rocks are distributed in the southwest and there is a mixed zone of sedimentary and volcanic rocks in the southeast. (3) Governed by diverse tectonic systems, the evolution of bedrock has undergone three stages: compressional uplift during the Late Jurassic-Early Cretaceous, extensional processes in the Late Cretaceous and re-compressional uplift during the Late Cretaceous-Paleogene. This study clarifies the geological attributes of the Enping-Yangjiang low uplift area as a hub for proximal sediment supply, with its bedrock distribution pattern and evolutionary stage directly regulating the composition and structure of sediments in surrounding depressions. It provides a replicable research paradigm of 'source area characterisation-sink area response' for provenance analysis in rift basins and has significant guiding implications for predicting hydrocarbon accumulation patterns under similar tectonic settings.

Deep tight sandstone reservoirs in the thrust-fold belt of the Kuqa depression, Tarim Basin, host substantial oil and gas resources. Structural fractures are the dominant reservoir space and seepage pathways in these tight reservoirs, yet their multi-periodic development and strong heterogeneity caused by multi-stage tectonic compression make accurate quantitative prediction extremely difficult. This study aims to establish a quantitative prediction method for multi-period tight sandstone fractures based on the minimum energy dissipation theory, targeting the Bozi Gas Field in the Kuqa depression. We first constructed a fine 3D geological model based on tectonic, drilling and logging data, then simulated the paleotectonic stress fields of key fracture-forming periods via 3D finite element analysis, and finally built a quantitative fracture parameter model of Bozi Gas Field by integrating the minimum energy dissipation theory with key fracture-controlling factors (thrust-fold structure, faults and lithology). The results show that the overlying thrust structure is the dominant control on the paleotectonic stress field distribution under intense tectonic compression, and the simulated fracture linear density shows a strong positive correlation with FMI logging interpretation results. The simulation result fully verifies the high accuracy and reliability of the method. This method provides critical guidance for tight gas exploration and development in the Kuqa depression, and a reference for fracture prediction in similar thrust-fold belts globally.

This study addresses the critical issue of lost circulation during drilling operations, particularly in fractured reservoirs within the Bozhong Sag of the Bohai Bay Basin. Lost circulation, defined as the leakage of drilling fluids into formation fractures due to pressure differentials, poses significant challenges for wellbore stability and oil and gas exploration. The research leverages the principle of minimum energy dissipation combined with classical mechanics to develop a unified theoretical framework for predicting fracture development and linear density characterization in deep tight sandstone reservoirs. Through constructing paleo-tectonic and geomechanical models, finite element simulations were performed to simulate the paleotectonic stress field, enabling quantitative predictions of structural fractures. Key findings indicate that the proposed rock strength criterion ensures the condition of minimum energy dissipation rate is met throughout the entire rock deformation process, offering enhanced universal applicability compared to traditional criteria. Notably, the model accurately predicted spatial distributions of fractures, verified by core data showing a correlation coefficient of over 0.85 with measured fracture densities. This work innovates by integrating the minimum energy dissipation principle with classical mechanics for fracture prediction, providing a more robust approach to addressing lost circulation issues. It advances upon previous efforts by improving the accuracy and reliability of fracture prediction in complex geological settings, crucial for mitigating risks and enhancing operational efficiency in drilling engineering.

Fracture systems are critical for understanding fluid flow heterogeneity in carbonate reservoirs, yet subsurface data limitations often hinder detailed characterization. This study presents a prototype geological model (PGM) for multi-stage fracture-karst evolution analysis in the Yijianfang (YJF) outcrop in Northwest Tarim Basin, integrating digital outcrop modeling, geomechanical simulations, isotopic analyses, Discrete Fracture Network (DFN) modeling, and flow modeling. Using unmanned aerial vehicle (UAV) scanning technology, a highresolution digital outcrop model (DOM) was established to characterize fracture networks. Fractures were classified into four fracture sets based on strike, cross-cutting relationships, and carbon-oxygen-strontium isotope dating, which were developed in Middle Caledonian, Late Caledonian-Early Hercynian, Late HercynianIndosinian, and Himalayan. Using a geomechanics-based tectonic stress field simulations, spatial distribution predictions for different stages of fracture formation in the study area were conducted. Based on the fracture prediction results, a multi-scale, multi-stage discrete fracture network modeling method was used to build a prototype geological model of outcrop fractures. Fluid flow simulations using the cubic law and Oda method revealed that fracture permeability (5-26 mD) correlates with cave development, with NW-SE and E-W trending caves controlled by 330 degrees and 270 degrees fractures, respectively. This study establishes a robust PGM methodology, demonstrating that fracture-karst evolution is governed by tectonic movement history and lithological heterogeneity. The model provides a predictive framework for characterization and prediction of karst fracture-cave reservoirs, particularly for linking fracture networks to fluid flow and karstification processes.

This research introduces an innovative fractal–fractional synergy framework for multiscale analysis of stress field dynamics in geo-energy systems. By integrating fractional calculus with multiscale fractal dimension analysis, we develop a coupled approach examining stress redistribution patterns across different geological scales. The methodology combines fractal characterization of rock mechanical parameters with fractional-order stress gradient modeling, validated through integrated analysis of core testing, well logging, and seismic inversion data. Our fractal–fractional operators enable simultaneous characterization of stress memory effects and scale-invariant fracture propagation patterns. Key insights reveal the following: (1) Non-monotonic variations in rock mechanical properties (fractal dimension D = 2.31–2.67) correlate with oil–water ratio changes, exhibiting fractional-order transitional behavior. (2) Critical stress thresholds (12.19–25 MPa) for fracture activation follow fractional power-law relationships with fracture orientation deviations. (3) Fracture network evolution demonstrates dual-scale dynamics—microscale tip propagation governed by fractional stress singularities (order α = 0.63–0.78) and macroscale expansion obeying fractal growth patterns (Hurst exponent H = 0.71 ± 0.05). (4) Multiscale modeling reveals anisotropic development with fractal dimension increasing by 18–22% during multi-well fracturing operations. The fractal–fractional formalism successfully resolves the stress-shadow paradox while quantifying water channeling risks through fractional connectivity metrics. This work establishes a novel paradigm for coupled geomechanical–fluid dynamics analysis in complex reservoir systems.

In recent years, the exploration and development of oil and gas reservoirs in the Bohai Sea have gained significant attention. However, the high cost of offshore drilling and the occurrence of frequent lost circulation accidents have resulted in substantial economic losses. Therefore, it is crucial to effectively predict and assess the risk of lost circulation in the Bozhong Depression. This study focuses on the analysis of lost circulation characteristics, identifying fracture characteristics as the most influential factors. Geomechanical methods were employed to characterize fracture parameters in the study area, enabling the prediction of lost circulation. A three-dimensional heterogeneous rock mechanical parameter model, incorporating lithology and faults, was constructed based on rock mechanics experiments, logging, and seismic data. Structural evolution analysis and acoustic emission experiments were conducted to determine the main period of fracture development. The Ansys software's finite element simulation platform facilitated the simulation of the paleo-stress field in the study area. By applying the principles of geomechanics, a calculation formula for fracture parameters was derived, and the spatial distribution of fracture parameters in the study area was quantitatively characterized using the results of the paleo-stress field simulation. Taking into account the lost circulation points of drilled wells, fracture parameters, current stress field, lithology, and other factors contributing to lost circulation, a leakage risk threshold area for fracture parameters was proposed. The predictions of lost circulation were validated using verification wells, demonstrating good agreement with actual drilling conditions. This approach provides valuable insights for mitigating lost circulation during drilling, reducing drilling cycles, and minimizing economic losses.

Shahejie Formation of Boxing Subsag in Dongying Sag is rich in hydrocarbon resources and holds significant exploration potential. However， the complex geological structure， rapid lateral lithological changes in lacustrine shales， strong reservoir heterogeneity， and significant burial depth pose substantial challenges. Multiple fault zones significantly affect the spatial distribution of the in-situ stress field， leading to frequent drilling issues such as collapse and fluid invasion. Additionally， during reservoir fracturing operations， the interference between wellbore fracture networks and difficulties in fracturing key intervals directly hinder hydrocarbon exploration and development of Boxing Subsag. The Upper Submember of the 4th Member of the Eocene Shahejie Formation （Es4U） to the Lower Submember of the 3rd Member of the Eocene Shahejie Formation（Es3L） （Es4U-Es3L） were taken as research objects， and mechanical experiments， logging interpretation， and seismic attribute analysis were integrated to construct a heterogeneous rock mechanics parameter model and determine the in-situ stress state of individual wells. Based on the finite element geomechanical model， the study employed elastoplastic finite element numerical simulations to characterize the in-situ stress field spatially and analyze the controlling factors and mechanisms of in-situ stress field distribution differences. Results indicate that the central-western part of Boxing Subsag has experienced prolonged structural activity， with major faults exhibiting extension and strike-slip characteristics. The overall trend of structural activity is from the south to the north and from the subsag center towards major faults. The overall in-situ stress state of the Es4U-Es3L falls into Class I but varies with depth in some areas. The maximum horizontal principal stress shows an NE-WN extension of high， low， and high-value variation. High in-situ stress zones are mainly concentrated near the Gaoqing-Pingnan fault corner， dominated by nearly EW-trending horizontal compression. The main controlling factors for in-situ stress field distribution include reservoir lithology， structural morphology， and faults. Reservoir lithology results in uneven distribution of in-situ stress due to different mechanical properties of rock， and structural morphology influences in-situ stress properties. Faults lead to chaotic in-situ stress directions， with stress concentrations at fault tips and bends.

The deeply buried Ordovician carbonates in the Tarim Basin exhibit complex fracture superposition due to polyphase tectonics, challenging prediction due to sparse well data and deep reservoir heterogeneity. This study presents an innovative fracture prediction framework for deep carbonates by integrating damage deformation mechanisms. A confining pressure-dependent fracture predictive model was established via triaxial tests, acoustic emission monitoring, and modified Mohr-Coulomb criteria, explicitly incorporating damage deformation effects on fracture parameters. Through failure tests and numerical simulation on pre-fractured rock samples, a multistage fracture superposition algorithm was established to account for fracture accumulation from distinct tectonic events, applied to the A Oilfield in the Northern Tarim Basin for practical validation. By commencing with detailed fault interpretation in the A Oilfield, we reconstructed tectonic evolution characteristics and identified three major fracture-forming periods through integrated analysis. By integrating rock mechanics experiments, logging data, and seismic data, geomechanical models corresponding to different tectonic phases were constructed were constructed and utilized in stress field simulations, enabling dynamic integration of multi-stage stress field simulations and fracture parameter superposition analysis. The model predicts fracture linear density (0.1-1.5 m-1) and aperture (0.5-2.75 mm) with 80 % consistency with FMI interpretations, outperforming traditional brittle models. For the A Oilfield, the results of fracture prediction directly guide the identification of high-potential exploration zones, as well as the evaluation of effective reservoirs. This study provides a mechanistic approach for deep carbonate fracture prediction, aiming to address the limitations of traditional models that overlook confining pressure effects and damage deformation. This approach not only enhances reservoir description accuracy in the A Oilfield but also offers a practical reference for similar deep carbonate basins worldwide.

This study delves into the geomechanical responses of different sedimentary hydrodynamic cycles in deep tight sandstone formations. Employing core observation and thin section analysis, we quantitatively identified and characterized bedding planes, sedimentary microfacies, and tectonic fractures. Then, the intricate relationships between various architectural interfaces and geomechanical parameters were elucidated. Subsequently, utilizing finite element numerical simulation software, in situ stress and fracture parameters were derived. By identifying a fracture facies zone correlated with the sedimentary hydrodynamic cycle and production data, our findings unveil several key insights: (1) Geomechanical parameters (Young’s modulus, Poisson’s ratio, brittleness index) exhibited noteworthy variations within the T3x2−5 sand group, indicative of weak elasticity and robust plasticity. (2) The effective distance, influenced by diverse reservoir architecture interfaces, displayed variability, with each transition between peak-valley-peak or valley-peak-valley pinpointed as a distinct sedimentary hydrodynamic cycle. (3) In environments characterized by strong sedimentary hydrodynamics (between two level 3 architecture interfaces), fractures with larger strike angles and lower dip angles were observed to be more prevalent. (4) Three significant fracture faces—level I, level II, and level III—were discerned within the study area. Notably, reservoirs associated with level III exhibited characteristics suggestive of medium porosity and permeability, indicative of a gas layer. By thoroughly understanding the geomechanical response characteristics of formations such as the Xujiahe Formation, it is possible to guide the exploration and development of energy resources such as oil and natural gas. This helps to improve the efficiency and safety of resource extraction, promoting the sustainable utilization of energy.

This study aims to elucidate the dynamic evolution mechanism of the fracturing fracture system during the exploration and development of complex oil and gas reservoirs.By integrating methods of rock mechanical testing,logging calculation,and seismic inversion technology,we obtained the current in-situ stress characteristics of a single well and rock mechanical parameters.Simultaneously,significant controlling factors of rock mechanical properties were analyzed.Subsequently,by coupling hydraulic fracturing physical experiments with finite element numerical simulation,three different fracturing models were configured:single-cluster,double-cluster,and triple-cluster perforations.Combined with acoustic emission technology,the fracture initiation mode and evolution characteristics during the loading process were determined.The results indicate the following findings:(1)The extension direction and length of the fracture are significantly controlled by the direction of the maximum horizontal principal stress.(2)Areas with poor cementation and compactness exhibit complex fracture morphology,prone to generating network fractures.(3)The interlayer development of fracturing fractures is controlled by the strata occurrence.(4)Increasing the displacement of fracturing fluid enlarges the fracturing fracture length and height.This research provides theoretical support and effective guidance for hydraulic fracturing design in tight oil and gas reservoirs.

This study endeavors to formulate a comprehensive methodology for establishing a Geological Knowledge Base (GKB) tailored to fracture-cavity reservoir outcrops within the North Tarim Basin. The acquisition of quantitative geological parameters was accomplished through diverse means such as outcrop observations, thin section studies, unmanned aerial vehicle scanning, and high-resolution cameras. Subsequently, a three-dimensional digital outcrop model was generated, and the parameters were standardized. An assessment of traditional geological knowledge was conducted to delineate the knowledge framework, content, and system of the GKB. The basic parameter knowledge was extracted using multiscale fine characterization techniques, including core statistics, field observations, and microscopic thin section analysis. Key mechanism knowledge was identified by integrating trace elements from filling, isotope geochemical tests, and water-rock simulation experiments. Significant representational knowledge was then extracted by employing various methods such as multiple linear regression, neural network technology, and discriminant classification. Subsequently, an analogy study was performed on the karst fracture-cavity system (KFCS) in both outcrop and underground reservoir settings. The results underscored several key findings: (1) Utilization of a diverse range of techniques, including outcrop observations, core statistics, unmanned aerial vehicle scanning, high-resolution cameras, thin section analysis, and electron scanning imaging, enabled the acquisition and standardization of data. This facilitated effective management and integration of geological parameter data from multiple sources and scales. (2) The GKB for fracture-cavity reservoir outcrops, encompassing basic parameter knowledge, key mechanism knowledge, and significant representational knowledge, provides robust data support and systematic geological insights for the intricate and in-depth examination of the genetic mechanisms of fracture-cavity reservoirs. (3) The developmental characteristics of fracture-cavities in karst outcrops offer effective, efficient, and accurate guidance for fracture-cavity research in underground karst reservoirs. The outlined construction method of the outcrop geological knowledge base is applicable to various fracture-cavity reservoirs in different layers and regions worldwide.

A fault accommodation zone is a type of structure that is defined as regulating displacement and strain between faults structure. Increasing numbers of fault accommodation zones are being identified in graben basins, indicating the potential exploration target and petroleum accumulation areas. This study aims to analyze the formation mechanism and development of fault accommodation zones under combined stress by a numerical simulation method considering geomechanical modeling. Using three-dimensional (3-D) seismic interpretation and fractal dimension method, exampled with the Dongxin fault zone, the fault activity and fault combination pattern were conducted to quantitatively characterize the activity difference in fault accommodation zones. Combined with mechanical experiment test, a geomehcanical model was established for fault accommodation zones in a graben basin. Integrating the paleostress numerical simulations and structural physical simulation experiment, the developmental characteristics and genetic mechanism of fault accommodation zones were summarized. Influenced by multi movements and combined stresses, three significant tectonic evolution stages of the Dongxing Fault Zone (DXFZ) were distinguished: During the Es3 sedimentary period, the large difference in the stress, strain, and rupture distribution in various faults were significant, and this stage was the key generation period for the prototype of the DXFZ, including the FAZ between large-scale faults. During the Es2 sedimentary period, the EW-trending symmetric with opposite dipping normal faults and the NE-SW trending faults with large scale were furtherly developed. The junction area of two secondary normal faults were prone to be ruptured, performing significant period for inheriting and developing characteristics of fault accommodation zones. During the Es1 sedimentary period, the high-order faults in the DXFZ exhibited the obvious fault depressions and strike-slip activity, and the fault accommodation zones were furtherly inherited and developed. This stage was the molded and formative period of the FAZ, the low-order faults, and the depression in the DXFZ.

Natural fractures are critical for shale oil and gas enrichment and development. Due to the extremely high heterogeneity of shale, the factors controlling the formation of internal fractures, especially horizontal fractures, remain controversial. In this study, we integrate thin section analysis and micro-computed tomography (CT) data from several lacustrine shale samples from the third member (Es3) of the Shahejie Formation, Qikou Sag, Bohai Bay Basin, to assess the fractures in detail. The goal is to reveal the development characteristics, controlling factors, and geological significance for evaluating sweet spots in a shale oil play. The fractures in the Es3 contain high-angle structural and horizontal bed-parallel fractures that are mostly shear and extensional. Various factors influence fracture development, including lithofacies, mineral composition, organic matter content, and the number of laminae. Structural fractures occur predominantly in siltstone, whereas bed-parallel fractures are abundant in laminated shale and layered mudstone. A higher quartz content results in higher shale brittleness, causing fractures, whereas the transformation between clay minerals contributes to the development of bed-parallel fractures. Excess pore pressure due to hydrocarbon generation and expulsion during thermal advance can cause the formation of bed-parallel fractures. The density of the bed-parallel and structural fractures increases with the lamina density, and the bed-parallel fractures are more sensitive to the number of laminae. The fractures are critical storage spaces and flow conduits and are indicative of sweet spots. The laminated shale in the Es3 with a high organic matter content contains natural fractures and is an organic-rich, liquid-rich, self-sourced shale play. Conversely, the siltstone, massive mudstone, and argillaceous carbonate lithofacies contain lower amounts of organic matter and do not have bed-parallel fractures. However, good reservoirs can form in these areas when structural fractures are present and the source, and storage spaces are separated.

Objective The Sikeshu Sag of the southern Junggar Basin is tectonically located in the western thrust belt of the North Tianshan Mountains. The basin has undergone multiple stages and multidirectional tectonic movements since the Palaeozoic. Clarifying the structural characteristics and evolutionary process of the structural system in the study area is critical for petroleum exploration and development in such petroliferous basins. Methods Utilizing the seismic data interpretation and the outcrop geological investigation of the Sikeshu Sag, spatial-temporal variations in the structural patterns and stress fields were revealed, and a tectonic evolution model was established. Results This study indicates that the compressional inversion and strike-slip structures were widely developed in the deep-buried layers of the Sikeshu Sag, but the thrust and decollement structures were more prevail in the shallow layers of the Sikeshu Sag. According to the structural style, the Sikeshu Sag can be divided into the southern compressional fault-fold belt, central strike-slip compressive-torsional belt, and northern uplift belt. The Sikeshu Sag experienced two periods of strong tectonic uplift, corresponding to the peak period of two stages of fault activity. The tectonic environment and stress field conditions underwent multiple changes: the NNW-SSE extension driven by the back-arc rifting during the late Carboniferous to early-middle Permian, the rift-depression transition triggered by the NNW-SSE extrusion of the Zaire orogenic movement during the late Permian to Triassic, the regional depression induced by the NNW-SSE extrusion of the peripheral orogenic belt and Chepaizi uplift during the late Jurassic to Palaeogene, and the reactivation of foreland caused by NS extrusion of North Tianshan Mountains during the Neogene. Conclusion This study explores the tectonic evolution of the Sikeshu Sag under multiphase stress fields, which favors the better understanding of the overall tectonic pattern changes in similar petroliferous basins and provides new insights for the next steps of petroleum exploration in the study area.

In this paper, a multi-state dependent constitutive model is proposed to describe the complex mechanical behaviors of gas hydrate-bearing sediments (GHBS). Based on the concepts of superloading and subloading, the single superloading surface is reconstructed to form a double superloading surface for characterizing the two state variables of ‘cementation structure’ and ‘filling structure’, which makes it possible to describe the two different enhancement mechanisms of hydrate in host sediment. In addition, a new concept of ‘equivalent GH saturation’ is proposed and introduced into the evolution rules of the two state variables, which can not only reasonably describe the influence of hydrate saturation, but also naturally consider the influence of temperature and pore pressure conditions. The proposed model employs only eight mechanical parameters, five of which are the same as those in the Cam-clay model, and the other three can be experimentally determined. Through the calculation of element tests under different initial conditions, it is confirmed that the multi-state dependent model proposed here inherits and expands the advantages of the concepts of superloading and subloading, and can reasonably describe the complex mechanical behaviors of GHBS, especially considering its influencing factors (effective confining pressure, void ratio, hydrate saturation, temperature and pore pressure).

Due to strong reservoir heterogeneity and low-resolution limit of geophysical data, it is difficult to predict fractures in ultra-deep reservoirs by conventional methods. In this research, we established a novel geomechanical model for prediction of fracture distribution in brittle reservoirs, especially for ultra-deep tight sandstone reservoirs. Methodologically, we intended to introduce the minimum energy dissipation principle considering time variable, combined with the generalized Hooke’s law containing damage variable, and obtained the energy dissipation rate expression corresponding to the energy dissipation process of brittle rocks. Combined with the three-shear energy yield criterion, the Lagrangian multiplier was introduced to deduce and construct the constitutive model and the failure criterion of rocks under the framework of the theory of minimum energy dissipation. Based on the law of conservation of energy, the stress-energy coupling characterization model of fracture density parameter was derived. Finally, all the improved geomechanical equations were incorporated into a finite element software to quantitatively simulate the distributions of tectonic stress filed and fractures based on paleo-structure restoration of Keshen anticline during the middle and late Himalayan periods. Its predictions agreed well with measured fracture density from reservoir cores and image logs.

Structural fractures are key factors that influence natural gas migration and accumulation within ultra-deep tight reservoirs. To obtain a quantitative forecast of the development and distribution of reservoir fractures in the Keshen gas reservoir, we analyzed the characteristics of the region's structural evolution and paleo-tectonic stress field settings. A reasonable geological model of the research area was built based on an interpretation of the geological structure, a test for rock mechanics, and an experiment on acoustic emission. Thereafter, a 3-D paleo-tectonic stress field during the mid-late Himalayan movement was simulated using the finite element method. By introducing the principle of minimum energy dissipation, which to our knowledge, was done for the first time in the field, mechanical constitutive models, rock failure criteria, and fracture parameter calculation models were derived and used to determine the quantitative development of fractures and predict zones prone to fracture development. The fracture distribution in the ultra-deep Keshen gas reservoir is mainly controlled by folds, buried depth, faults, and lithology. Interestingly, even in the strong tectonic compression movement, the stress field was not continuously transmitted forward but showed fluctuation or cyclicity, indicating that fractures might have occurred at each time stage. The predicted areas with developed fractures were consistent with wells having high fracture linear density (i.e., measured results) and in locations with high-producing gas wells. We believe that the novel method in this study can be of great significance to fracture research in other ultra-deep petroliferous basins.

Objective Large deep carbonate reservoirs have been developed in the Tarim Platform area. Structural fractures are important seepage paths and reservoir spaces for deep carbonate reservoirs. Due to the strong heterogeneity of reservoirs, which is influenced by multiple geological factors, there is no effective technical method to solve the problem of quantitatively characterizing multiscale fractures in reservoirs. Methods In this study, digital outcrop technology was used to establish a 3D digital model of the outcrop area, and on this basis, outcrop fracture identification and quantitative description of fracture parameters were carried out. Emphatically, based on the outcrop fracture results, different modelling methods have been adopted for the development of multiscale fractures. Large-scale fractures were modelled via the deterministic modelling method. Optimal fusion modelling methods based on fractal dimension theory were used for medium-scale fractures. Due to the complex problem of small-scale fracture modelling, three significant models were distinguished via the multisource information fusion method: the fault strike model, the distance from fault model and a stratigraphic curvature model.A comprehensive development probability body of small-scale fractures was established. Construction of a small-scale fracture model based on collaborative simulation of multiple data points was constrained by the comprehensive probability volume. Consequently, restricted by the established comprehensive probability volume, a small-scale fracture model was constructed based on collaborative simulations of multiple sets of data. Finally, under the same grid system, a prototype geological model of the outcrop was obtained by superimposing the multiscale fracture model and the structural model. Results The results of the outcrop prototype geological model were applied to fracture modelling of underground reservoirs in the Yueman area of the Tarim Basin. The primary modelling parameters, such as fracture occurrence and density, and the main controlling factors of fracture development were described at multiple scales. By integrating the analysis results of the well point fractures, a reservoir multiscale fracture network model was constructed, which agreed well with the fracture interpretation and production data from a single well. Conclusion The results showed that outcrop prototype geological model can provide important research ideas and a geological basis for subsurface reservoir fracture modelling.

In recent years, volcanic reservoirs in the Bohai Sea have become the focus of oil and gas exploration and development. Volcanic activity during the Cenozoic provided favorable conditions for the development of hy-drocarbon traps. These volcanics also result in difficulties during the drilling and development of oil and gas fields. Furthermore, the high-temperature magma induced thermal expansion in the surrounding rocks, which changed the local stress field and affected the fracture distribution characteristics of the surrounding strata. The complexity of the fracture distribution makes predicting lost circulation difficult and causes substantial economic losses. Therefore, it is necessary to characterize the volcanic perimeter expansion-type fractures effectively. The distribution of volcanic rocks is identified through logging and seismic data, with perimeter fracture develop-ment characteristics being analyzed. The temperature conditions of the volcanic activity were determined through core mineral analysis and thin section observation. Based on the laws of energy conservation and geomechanics, the principle of thermal coupling was applied to quantitatively predict the thermal expansion fractures caused by volcanic activity using a finite element numerical simulation method. To determine the extent of volcanic influence on lost circulation, and the development characteristics of fractures under the in-fluence of these rocks were analyzed. The results provide an important reference for drilling and volcanic reservoir prediction in the Bohai Basin and guide for elsewhere.