Intraplate small-displacement strike-slip faults cannot be identified accurately and quantitatively analyzed quantitatively by conventional techniques. To clarify the tectonic characteristics and deformation process of intraplate small-displacement strike-slip faults, taking the Fuman Oilfield in the northern Tarim Basin as an example, structural physical simulation experiments were designed based on the geological conditions of the study area. Laser scanning was adopted to elaborately and quantitatively analyze the deformation features and differences of the strike-slip faults at each evolutionary stage. This study indicates that the deformation of the FI17 fault zone in the Fuman Oilfield evolves in four stages: diffuse deformation, R-shear fracture, branched fault interconnection, and through-going principal displacement zone (PDZ). During the evolution of the strike-slip fault zone, en echelon anticlines serve as a diagnostic marker for R-shear fracture, and their relief amplitude represents a vital parameter to classify evolutionary stages. A “Net Deformation Magnitude” method is proposed, which can effectively remove post-tectonic stratigraphic deformations irrelevant to strike-slip-related folds and extract fold geometries and uplift amplitudes solely generated by strike-slip faulting. This method further enables quantitative characterization of along-strike heterogeneities in deformation intensity and connectivity of strike-slip fault zones, thereby realizing integrated seismic-geological interpretation. A case study of the Fuman Oilfield demonstrates that the FI17 fault zone is currently in the branched fault interconnection stage, characterized by alternating through-going and disconnected segments along its strike. The findings establish a geological model for the refined interpretation of intraplate small-displacement strike-slip faults. Furthermore, the newly recognized fault-karst traps associated with R-shear fractures are expected to become promising new targets for hydrocarbon exploration.

Faults in porous sandstone were previously considered ill-suited for sealing hydrocarbons, which resulted in many promising fault-related hydrocarbon exploration targets being overlooked. This study investigates the sealing properties of faults within porous sandstone in the Bozhong subbasin using well drilling data and repeat formation test pressure measurements from both sides of the faults. The results demonstrate that the faults in the porous sandstone could seal hydrocarbons, with the maximum sealable hydrocarbon column height reaching 83 m and the buoyancy pressure reaching 0.223 MPa. Owing to the low clay content (<10%), high porosity (>15%), and moderate burial depth (1-3 km) of the host rock, cataclasis associated with fault deformation may generate low-permeability cataclasite, which is regarded as the most probable sealing mechanism for faults in porous sandstone. Increased effective fault normal stress during fault movements intensifies sandstone grain cataclasis, further reducing fault permeability and enhancing the fault sealing capacity. A positive correlation was identified between fault sealable buoyancy pressure and effective fault normal stress. These findings highlight the importance of considering stress effects, in addition to clay content, when evaluating the sealing capacity of faults in sand-mudstone sequences. Neglecting the role of stress may lead to underestimation of the fault sealing potential, particularly for faults in porous sandstones. More research is needed to evaluate the sealing capacity of faults in porous sandstone. In addition, data sharing and cooperation between industry and academia should be encouraged so that, in the long run, workflows can be developed specifically for faults in porous sandstones.

This study focuses on continental shale oil reservoirs, an essential component of the global energy portfolio, with the aim of investigating the controlling factors of fracture occurrence and characteristics, emphasizing the integrated effects of in-situ stresses, geomechanical attributes, and structural discontinuities. Fractures in continental shale are important since they play a critical role as migration pathways, storage spaces, and major contributors to hydrocarbon production. Herein, outcrops were investigated in details, employing field measurements (e.g., Schmidt hammer for rock competence) and structural analysis, where faults and associated fractures (e.g., geometry, spacing, density, and type) were characterized. This integrated, joint analysis approach enables us to decipher the coupled controls on fracturing. The results show that fractures can be classified into bed-internal, bed-confined, and throughgoing fractures, with significant differences in their patterns and attributes across various structural positions. It was found that mechanical stratigraphy plays a principal role in controlling fracture scale and intensity. Moreover, fractures are nearly evenly spaced within mechanical layers where they are more developed in thin and competent layers. Furthermore, the fracture density in fault damage zones is found higher than in the host rock, while the width and fracture intensity of the hanging wall damage zone is greater than those of the footwall, a direct indicator of asymmetric stress distribution during faulting. Critically, the study reveals that fracture patterns within fault zones are not solely a function of faulting but arise from the interplay between fault zone architecture and the mechanical stratigraphy they intersect. This is evidenced by variations in damage zone width across different mechanical layers and by localized high-density clusters (''outliers'') related to minor faults. Through this comprehensive analysis, the most significant finding is the quantitative characterization of this bidirectional interaction, demonstrating how pre-existing mechanical heterogeneity modulates fault-related fracture networks. Collectively, the results from this study provide a predictive framework for natural fracture networks that is grounded in the coupled mechanical-structural heterogeneity, offering specific guidance for optimizing well placement to target high-intensity fracture corridors and informing hydraulic fracturing design by accounting for the complex mechanical and structural heterogeneities documented herein.

Shale has strong compositional and structural heterogeneity, and its molecular structure model accuracy is a bottleneck which limited the molecular simulation results. To improve reproducibility of three-dimensional (3D) intact shale model and enhance the reliability of molecular simulation results. The chemical composition of the carbon skeleton, functional groups, and chemical bonds in organic matter (OM) were quantitatively characterized through a combination of methods including 13C nuclear magnetic resonance (NMR), Fourier transform infrared spectroscopy (FT-IR), and X-ray photoelectron spectroscopy (XPS). The two-dimensional (2D) OM structure was reconstructed according to above experimental results in software ACD/C + H NMR, until the iterative validation of 13C NMR profiles was successfully obtained. Then, the 3D OM structure was reconstructed in software Material Studio (MS) based on the reconstructed 2D structure after geometric optimization and anneal. It is a 3.23 × 3.23 × 3.23 nm (α = β = γ = 90°) cell with a molecular formula of C1900H1340O240N100 and relative molecular mass of 29 380. Density and porosity of experimental and calculated results were compared to validate its precision, the results exhibit low relative errors of 2.0

As a key unconventional energy source, shale gas extraction depends on hydraulic fracturing, with fracture toughness determining crack initiation and propagation. Size variations in specimens directly influence toughness and failure modes. Mode-I fracture toughness tests were conducted on Arrester-oriented shale NSCB specimens (25, 50, 75 and 100 mm) in diameter. DIC (Digital image correlation) and AE (Acoustic Emission) monitoring method were employed to track fracture initiation and propagation and a size effect model for shale mode I fracture toughness was developed. The results show that the load-displacement curve of shale NSCB specimens varies with the increase of sample size. Small-sized samples exhibit a two-stage behavior, transitioning from linear elasticity to failure. In contrast, larger samples demonstrate a three-stage behavior, including compaction, linear elasticity, and failure. When the diameter of the specimens increases from 25 mm to 100 mm, the average peak load increases from 0.57 kN to 5.86 kN. The corresponding average fracture toughness increases from 0.96 MPa m1/2 to 1.22 MPa m1/2. Initially, the horizontal strain field is uniform in all sizes. During the linear-elastic stage, strain localizes at the pre-crack tip; at peak load the band expands, with larger specimens releasing more energy. AE shows rising ring-down counts but falling hit counts as diameter grows; higher energy yet fewer high-amplitude events indicate distributed micro-cracking dominates in large specimens. Using Bazant's size effect model and RILEM's methodology, fracture process zone lengths and fracture toughness were quantified. Results enhance understanding of Arrester shale mechanics and guide hydraulic-fracture design.

This study presents a systematic 3D physical simulation investigation of CO2 injection parameter sensitivity in deep saline aquifers, focusing on the synergistic effects of well type, injection rate, and geological barriers. Experiments conducted in a custom high-temperature, high-pressure 3D simulator with integrated resistivity tomography quantitatively tracked CO2 saturation evolution under controlled scenarios. Results indicate that horizontal wells increase dissolution trapping by 6.8% (absolute) relative to vertical wells under the tested conditions, an effect attributed to enhanced CO2-brine interfacial contact. Injection rate governs the trade-off between storage efficiency and operational safety: high-rate injection (4 mL/min) accelerates dissolution trapping to 26.6% but elevates near-wellbore pressure to an estimated level approaching the material's fracture threshold, suggesting a potential caprock fracturing risk under similar downhole conditions; low-rate injection (1 mL/min) promotes uniform plume distribution and enhances residual trapping, contributing to long-term storage stability. In this model, low-permeability barriers (1 × 10−5 mD) create hydraulically isolated pressure compartments that completely block vertical migration, enhancing local storage security, whereas moderate-permeability barriers (0.1 mD) permit partial breakthrough and cross-layer pressure communication. These findings provide a systematic 3D experimental dataset that illustrates multi-parameter synergy in CO2 storage under the specific conditions of a small closed-boundary laboratory model. For homogeneous reservoirs, the “horizontal well + medium-low injection rate” configuration performed best among the tested configurations in this specific closed-boundary laboratory model. Field-scale validation under open-aquifer conditions is required before any direct application.

The sealing capacity of fault zones, which fundamentally influences hydrocarbon migration and entrapment, is predominantly governed by their internal architecture. In sand-clay sequences, this capacity typically correlates positively with clay content. However, in the study area-the X492 trap bounding fault in the Huimin depression, Bohai Bay Basin of China, demonstrates effective sealing despite occurring in sand-rich sequences and having limited displacement. The reservoir description results showed that the height of the oil column sealed by this bounding fault reaches 30 m, and the clay content within the fault zone, as indicated by the Shale Gouge Ratio, is generally below 15%. To determine the cause, we studied the subcore of the fault zone surrounding the trap through observation and description. Core-based analysis of fault rocks reveals a sand-mud mixture with a mud-encased texture. Dense networks of deformation bands and laminated phyllosilicate fabrics, approximately 1 mm thick, display high continuity and no evidence of hydrocarbon invasion. Laboratory measurements show these fault rocks are clay-dominated with minimal carbonate cement (<5%). Thin-section and micro-CT analyses indicate that deformation bands and phyllosilicate layers reduce grain size by 0-2 orders of magnitude and porosity by 10-20% relative to the host rock, significantly degrading petrophysical properties. This millimeter-scale microstructure is interpreted as the key mechanism for subsurface fluid sealing. This study conducts an analysis based on the above and presents a discussion on the potential sealing mechanism of the bounding fault of a trap, proposing a sealing model for low-displacement faults developed in high net/gross sand ratio sequences. This study demonstrates that in specific scenarios, low-displacement faults possess sealing capabilities and exploration potential.

During the injection and withdrawal of natural gas, faults may cause lateral leakage, resulting in the loss or migration of natural gas out of the gas storage area. Therefore, the lateral sealing property of faults is crucial for the safe operation of gas storage facilities. This paper uses the L gas storage reservoir as a case study to conduct a statistical analysis of the fault dip, reservoir thickness, and overburden thickness within the faulted structure. It integrates a fault sealing triangle diagram derived from logging data to ascertain that the gas storage facility in this study primarily depends on lithological contact sealing and fault rock sealing mechanisms. Furthermore, it evaluates the sealing capacity of these confining faults and develops a quantitative model for assessing their lateral sealing capacity based on an anatomical examination of the original gas reservoir. Through the analysis of dynamic development data for the safe operation of gas storage facilities, pressure variations on both sides of the faults during different injection and production phases were systematically identified. The pressure differential at the end of production was selected, and a numerical simulation incorporating time effects was conducted to assess the dynamic sealing capacity of the fault. A model representing fault sealing capability based on this dynamic development data was established, which elucidates the sealing mechanisms present on either side of the fault across various periods and identifies factors (fluid pressure, tectonic stress, changes in fluid properties) contributing to pressure differentials. The model demonstrates 89% prediction accuracy through machine learning-assisted history matching of 12 injection-production cycles, significantly outperforming conventional methods by 32%. Additionally, the study discusses discrepancies in lateral sealing capacities among different stages and clarifies the fundamental reasons behind variations in pressure differences over time. These findings provide a robust theoretical foundation for assessing sealing capabilities in gas storage facilities during subsequent development phases.

Long-term CO2 storage security and efficiency in deep saline aquifers are governed by coupled thermal-hydraulic-mechanical-chemical (THMC) processes. This study develops and validates a fully coupled THMC model by integrating COMSOL (mechanical), TOUGHREACT (thermal-hydraulic-chemical), and a MATLAB-based data exchange interface to address gaps in current simulation capabilities. The framework enables efficient bidirectional coupling and iterative solving across all four physical fields, and is validated against high-temperature, high-pressure 3 dimensional (D) experimental data, accurately replicating CO2 plume migration, pressure changes, and key mineral reactions. Field-scale results show that reservoir mineralogy controls sequestration mechanisms: feldspar-rich sandstone has greater mineral trapping potential than carbonate reservoirs. Silicate mineral dissolution (e.g., K-feldspar, albite) releases cations (Ca2+, Mg2+, Fe2+), promoting precipitation of stable carbonates like ankerite and dawsonite for permanent CO2 storage. Rapid pH buffering from carbonate dissolution in carbonate rocks inhibits further CO2 dissolution and mineralization. The chemo-hydraulic coupling is identified as the dominant mechanism controlling the evolution of reservoir properties. Modest mineral precipitation near the wellbore leads to minor porosity and permeability reductions of approximately 1% and 1.8%, suggesting a mild near-well self-sealing tendency that may locally enhance containment, though it could slightly reduce long-term injectivity, a key factor in injection strategy optimization. Under conventional injection pressures, the mechanical response (poroelastic effect) has negligible impact on porosity and permeability changes compared to chemical alterations. This study provides a robust numerical tool and key theoretical insights for CO2 storage site selection, injection optimization, and long-term safety assessment.

This study investigates the quantitative relationship between fracture geometry, topological connectivity, and the long-term heat extraction performance of Enhanced Geothermal Systems (EGS). A discrete fracture network (DFN) is constructed using the Monte Carlo method, and a topology-based connectivity coefficient (CL) is proposed as a bridge to evaluate reservoir efficiency. A two-dimensional thermo-hydraulic (TH) coupling model is established to analyze the systemic impact of various fracture distribution patterns. Results indicate that the inter-set intersection angle significantly influences the network connectivity, with CL reaching a peak value at approximately 70 degrees. For the investigated reservoir scale, an inter-set angle of 90 degrees is recommended to balance production temperature. Fracture length serves as a primary control for the percolation threshold; lengths below 200 m result in a disconnected network, whereas an optimal length of 300 m is identified under current conditions to ensure sustained thermal recovery. Furthermore, while higher fracture count improves thermal output, overly connected networks can lead to rapid reservoir cooling and premature thermal breakthrough. Under the investigated parameters, a count of 100 fractures achieves a favorable compromise between thermal performance and reservoir longevity. These findings provide a topological framework for the design and optimization of fractured EGS reservoirs.

Ultra-deep sandstone reservoirs are characterized by poor petrophysical properties. Identifying effective reservoir rocks and evaluating reservoir quality are key but challenging aspects in the exploration and development of ultra-deep hydrocarbon reservoirs. Adopting the Cretaceous Bashijiqike Formation of the Keshen gas field in the Tarim Basin with burial depths exceeding 8000 m as an example, we evaluated the quality of this ultra-deep tight sandstone reservoir by classifying petrofacies and analyzing the diagenetic evolution of different petrofacies. We revealed that although the petrophysical properties of ultra-deep reservoirs are poor, effective reservoir rocks with relatively high porosities and permeabilities can still develop locally. According to the detrital mineralogy and texture, diagenesis, and pore system, we classified sandstone into effective petrofacies (ductile lithic-lean sandstone) and tight petrofacies (ductile lithic-rich sandstone and tightly carbonate-cemented sandstone), which underwent differential diagenetic evolution processes. Such processes significantly influence the quality of ultra-deep tight sandstone reservoirs. High contents of ductile grains and carbonate cement explained the low reservoir quality. The ductile lithic-rich sandstone was relatively fine-grained and contained a high content of ductile grains, which, owing to mechanical compaction during early burial, were compacted and largely occupied the pore space, yielding a low reservoir quality. The carbonate-cemented sandstone pores were filled with large amounts of carbonate cements during early diagenesis, resulting in a low reservoir quality. The ductile lithic-lean sandstone was relatively coarse-grained, contained a high content of rigid grains, and exhibited moderate compaction, with relatively well-developed primary pores and secondary dissolution pores. This sandstone exhibited the highest reservoir quality and represents an effective reservoir rock type in ultra-deep tight sandstone reservoirs. This study provides new insights for the evaluation of the effective properties of ultra-deep tight sandstone reservoirs. (c) 2026 China University of Geosciences (Beijing) and Peking University. Published by Elsevier B.V. on behalf of China University of Geosciences (Beijing). Thi s is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

The temperature-pressure history of the organic-rich shale in the Cretaceous Qingshankou Formation in the northern Songliao Basin was reconstructed through comprehensive analyses, including field tests, paleo-heat flow reconstruction, overpressure evolution and geochemistry. The formation and evolution process of the Gulong shale oil was reproduced, and its enrichment patterns were clarified. Influenced by tectothermal events and tectonic movements at the end of the Cretaceous Mingshui Formation deposition, the evolution of organic matter thermal maturity in the first member of Qingshankou Formation (Qing-1 Member) exhibited distinct stages, which can be divided into the Cretaceous rapid evolution stage and the Paleogene-Neogene slow evolution and stabilization stage. High paleogeotemperature drove secondary cracking of retained oil in the Qing-1 Member, forming light shale oil in the Gulong Sag. This sag experienced three phases of overpressure during the late depositional stage of the Nenjiang Formation and late depositional stage of the Mingshui Formation of the Cretaceous, and the Neogene. The first two phases were related to the oil generation peak and secondary cracking in the sag, respectively, while the third phase resulted from the inheritance of earlier overpressure, as well as sustained hydrocarbon cracking and heat-induced fluid volume expansion. Crude oil is distributed orderly in the northern Songliao Basin. Conventional oil reservoirs such as Saertu and Putaohua contain high contents of non-hydrocarbon compounds, and they are believed to have formed by hydrocarbon charging as a result of the first phase of overpressure. Tight oils in the Fuyu and Gaotaizi reservoirs, most similar to shale oil in the Qing-1 Member in terms of composition and physical properties, are characterized by high content of saturated hydrocarbons, with their hydrocarbon charging and accumulation related to the second phase of overpressure. High paleo-heat flow generated by tectothermal events is determined to be the main driving factor for the staged hydrocarbon generation of organic matter in the Qingshankou Formation. The shale of Qing-1 Member with high thermal conductivity and the Cretaceous Nenjiang shale with low thermal conductivity constitute a thermal structure with lower conducting and upper sealing. This structure has prolonged secondary cracking of hydrocarbons, widened the liquid hydrocarbon window, and helped self-sealing enrichment of the Gulong light shale oil by virtue of the third phase of overpressure.

During natural gas injection and withdrawal, faults may cause lateral leakage, leading to gas loss or migration. Thus, fault lateral sealing is critical for safe gas storage operation. This study uses the L gas reservoir as a case to analyze fault dip, reservoir thickness, and overburden thickness. Logging data are integrated into the fault-sealing triangle diagram, confirming that lithological contact and fault rock sealing dominate in this reservoir. A quantitative model evaluates fault lateral sealing capacity based on the original gas reservoir's anatomy. Dynamic development data reveal pressure variations across fault sides during injection-production phases. A numerical simulation incorporating time effects assesses dynamic sealing capacity, with end-of-production pressure differentials selected for analysis. The fault-sealing model developed from this data explains sealing mechanisms and factors (fluid pressure, tectonic stress, fluid property changes) influencing pressure differences. Machine learning-assisted history matching of 12 injection-production cycles achieves 89

Deformation bands are a type of local strain concentration structure that develops in porous rocks, and they play an important role in the fluid dynamics of underground reservoirs. Although field outcrop observations can provide important information for revealing the geometry and distribution characteristics of deformation bands, capturing the dynamic processes and controlling mechanisms of deformation band formation and evolution is difficult. In recent years, laboratory-scale physical simulations have become key methods for studying the formation processes of deformation bands by precisely controlling stress, displacement, and material properties to reproduce the evolution path. In this study, the shear experiment methods, quantitative structural analysis techniques, and numerical simulation strategies that are widely used in the current research on deformation bands are systematically reviewed and evaluated. Physical simulation methods, such as ring shear, direct shear, triaxial shear, and sandbox experiments, and porosity and permeability measurement methods, which are based on computed tomography (CT) scans and image processing, are assessed in this paper. Furthermore, the ways that experimental data are used in the construction of parameters of discrete element and continuum models are discussed, as are modeling practices at the core and regional scales. Finally, the main challenges are summarized, including in situ permeability testing for consolidated rocks, the imperfection of quantitative structure analysis technologies, the difficulty in simulating the effects of cement, and the bottleneck in cross-scale modeling, and key directions for future research are proposed. The aim of this review is to establish a research framework that integrates experiments, calculations, and observations to provide theoretical and methodological support for an in-depth understanding of the formation mechanism of deformation bands and their control on underground fluid migration.

The hot dry rock (HDR) heat extraction process is a typical multi-physical field coupling phenomenon, where efficiency depends not only on the intrinsic properties of individual physical fields but also on their synergistic coordination. To address this, the Field Synergy Principle (FSP) is introduced to analyze the heat extraction process between the HDR reservoir and the working fluid. Based on the coupled temperature-seepage numerical simulation, an evaluation system for heat extraction performance is established, with the Reynolds number, Prandtl number, field synergy number Fc, and field synergy angle as key parameters. The mechanism underlying the differential heat extraction performance of various self-supported fracture types is systematically analyzed, and an optimized fracture configuration scheme for enhanced heat extraction is proposed. The results demonstrate that the field synergy effect is significantly stronger at the fracture entrance and in the central region; however, it deteriorates progressively near the fracture wall, where the angle between the velocity vector and temperature gradient is substantially larger. The field synergy number Fc of the rough fractures is consistently slightly higher than that of the smooth fractures. This study provides theoretical guidance for the optimized design and efficient development of HDR fracturing reservoirs.

Far-field temporary plugging fracturing can enhance fracture complexity and improve reservoir stimulation effectiveness, making it a powerful technique for the efficient development of unconventional oil and gas. Existing numerical methods face significant challenges in simulating the mechanical process of plugging the fracture tip and forcing the formation of new fractures. Numerical studies on far-field temporary plugging fracturing are rarely published, which constrains the application and development of this technique. This work developed a user subroutine to define field variable (USDFLD) to identify and control the rock properties at the fracture tip. It also established a numerical model for far-field temporary plugging fracturing based on the cohesive zone method (CZM). The model successfully achieved effective temporary plugging of propagating fractures, and its validity was verified through laboratory experiments. The results indicate that when the fracture tip encounters a temporary plugging body, fracture growth ceases and the pressure inside the fracture rises. The fracture width first increases until a new fracture forms, after which it gradually decreases. As the temporary plugging distance increases, the rate of internal pressure rise after contacting the temporary plugging body slows down. The farther the temporary plugging body is positioned, the greater the fracture width that can form during plugging. Implementing temporary plugging at a greater distance from the fracture tip is more beneficial for enhancing fracturing effectiveness. During Hydraulic fracture propagation, fractures may directly cross natural fractures. Implementing temporary plugging fracturing can activate structural weak planes that were not opened before plugging, thereby expanding the stimulated reservoir volume. On this basis, secondary temporary plugging further promotes the formation of new fracture paths and a more complex fracture network. The research provides a new tool for optimizing far-field temporary plugging fracturing design.

To overcome the limitations of conventional dynamic-static parameter conversion methods characterized by low accuracy and destructive core dependency, this study presents a novel non-destructive approach for high-precision dynamic-static mechanical parameter conversion based on acoustic wave propagation characteristics. Considering that the acoustic wave wavelength is much smaller than the measurement scale of the rock body, a stratified mechanical model for heterogeneous rocks was constructed. The bulk density and reciprocal of wave velocity for each sub-sample layer of the rock sample are set to follow normal distributions, with the variance and expected values of these distributions determined by experimental measurements of wave velocity and bulk density in macroscopic rock samples. Under these constraints, target values of layer parameters are determined through a statistical search algorithm, establishing the dynamic-static mechanical parameter conversion model. Taking Bozhong Oilfield reservoir cores as an example, mechanical and acoustic experiments demonstrate that static parameters obtained with the new method show close agreement with test values, yielding average deviations of 0.048 for Young's modulus and 0.066 for Poisson's ratio. Compared with conventional methods, the dynamic-static conversion relationship developed through this new method proves more effective and accurate in estimating stratum static mechanical parameters when applied to well logging interpretation data. The new method enhances core utilization while maintaining accuracy, offering a cost-efficient solution for reservoir mechanical characterization.

A failure of classical seal bore production packers for packer challenging wells, may lead inefficient, expensive operations, and also significant environmental risk. In response to these challenges, a low-cost and highefficiency ball plugging injection process has been proposed and developed, which primarily utilizes the motion and plugging capabilities of custom made balls to control the flow control of injected fluids across different formations, and its key technologies involved in the pitching, plugging-selection, and recovery process. The plugging balls were subjected to a rigorous manufacturing and performance inspection to ensure high strength and no deformation for the downhole operational environment. Motion characteristics and plugging mechanism of the plugging balls were revealed through calibrated mathematical modelling. Dimensionless analysis based on the Stokes number and Elasticity number was introduced to distinguish plugging, competition, and offside. An experimental rig has been developed and experimental studies have been conducted to determine process parameters and verifying mathematical predictions. Temperature sensitivity analysis was performed to assess the effect of elastic modulus reduction on plugging stability. The research findings from the modelling calibrated by the laboratory experiments were implemented successfully in the oilfield setting showing potentials in Enhanced Oil Recovery (EOR) of this technology.

CO2 injection in shale oil reservoirs has emerged as a promising technique for simultaneously achieving CO2 geological storage and enhancing shale oil recovery. This study investigates the potential of CO2 injection into shale oil reservoirs with natural fractures for carbon storage and enhanced oil recovery through a combination of experimental and numerical simulations. It focuses on the synergistic effects on carbon storage capacity and oil recovery efficiency. A series of CO2 injection experiments using online NMR T2 and stratified T2 technology were conducted to validate the feasibility of carbon storage and oil recovery in shale oil reservoirs. The shale samples consist of three distinct pore space systems: kerogen, inorganic matrix, and shale bedding fractures. A coupled multiscale-multiphase simulation model was developed to facilitate a comprehensive analysis of the underlying mechanisms. In the model, kerogen, inorganic matrix, and shale bedding fractures are defined as triple-continuum media. The model integrates the mechanisms of molecular diffusion, adsorption, and viscous flow to accurately represent the mass transport processes during CO2 injection in shale oil reservoirs. Within this framework, a series of mass transport partial differential equations were derived to describe the CO2 injection process. The finite element method was used to numerically solve these equations, and the proposed model was validated against experimental results. Sensitivity analyses yielded the following results: (1) The shale bedding fractures are not only key reservoir spaces for shale oil but also the key mass transfer channels for shale oil and CO2 during CO2 injection. Increasing the permeability of the shale bedding fractures can significantly improve oil recovery efficiency and CO2 adsorption amount. (2) The kerogen content and organic porosity have a significant impact on CO2 adsorption amount and shale oil recovery factor, respectively. (3) High production pressure is essential for maximizing carbon storage capacity. Simultaneously, increasing injection pressure can effectively enhance carbon storage and shale oil recovery.

This paper proposes a method for estimating the height of a type I capillary barrier based on the concept of hydraulic flow units. It was noted in the work that taking into account capillary effects in the formation is relevant and in demand when performing work on estimating reserves, designing a development system and planning various geological and technical measures. In this case, it becomes necessary to study the heterogeneity of the reservoir properties due to the presence of different-pore facies in the formation and leading to the formation of capillary barriers of different heights. The Hydraulic Flow Unit (HFU) concept is one of the approaches used to study the heterogeneity of the geological structure of pay zones by reservoir properties. It is noted that using the concept of hydraulic flow units allows you to detail the filtration properties of the formation. Consequently, the reliability of the forecast of the distribution of current mobile oil reserves and the boundaries of the oil potential contour is increased. Therefore, based on the parameters Hydraulic Flow Unit and Flow Zone Indicators, it becomes possible to study the size of capillary barriers of the first kind.The analytical conclusion of the formula for dependence of capillary barrier dimensions (height) on the RQI parameter (reservoir quality index) is presented in detail. Based on this relationship, a method is proposed for estimating the height of a capillary barrier of the first kind based on the concept of hydraulic flow units. This requires procedures such as calculating the RQI parameter, estimating the constant value of the A0 using the given formula in the text of the work, and estimating the height of the capillary barrier.Various oil fields of Western Siberia, Ural-Volga region and Western Kazakhstan are considered in approbation of proposed method. The capillary barrier height and the RQI parameter have their own analytical relationships for each study object. Based on this, it is concluded that the corresponding analytical dependencies of the change in the capillary barrier height and the RQI parameter for various geological and field conditions of the study objects have been established.