Search Results (1,180)

To elucidate the development control factors, diagenetic evolution, and pore evolution of oil and gas reservoirs of the Huagang Formation in the East China Sea Shelf Basin Central Anticlinal Belt, this study involved geological analyses, including thin-section petrography, scanning electron microscopy (SEM), mineral analysis via TESCAN Integrated Mineral Analyzer (TIMA), X-ray diffraction (XRD), and petrophysical measurements. We investigated the reservoir characteristics and primary diagenetic processes of the Huagang Formation reservoirs using logging and nuclear magnetic resonance (NMR) data, identified provenance differences between the north-central (FN) and south-central (FS) areas, divided diagenetic environments, established distinct diagenetic sequences, and uncovered high-quality reservoir pore evolution patterns. The results showed that the provenance in the FN area of the Central Anticlinal Belt is primarily acidic igneous rocks, which exhibits low resistance to compaction but is susceptible to dissolution modification, and the “high-dissolution zone” developed at burial depths of 3600–3900 m constitutes the primary high-quality reservoir; the provenance in the FS area is a mixture of medium- and high-grade metamorphic rocks and acidic igneous rocks, which exhibits stronger resistance to compaction, but dissolution zones are poorly developed. The Huagang Formation has experienced multiple diagenetic processes, such as compaction, cementation, and dissolution. During destructive diagenesis, the average reduction in pore volume due to compaction accounts for 76% (FN area) and 81% (FS area), while cementation accounts for 18% (FN area) and 12% (FS area). Vertically, 3900 m and 4000 m are the boundaries between the acidic zone and acid-alkaline transition zone of the Huagang Formation in the FN and FS areas, respectively, and the whole Huagang Formation is considered within the meso-diagenetic A2 stage. The pore evolution is closely related to diagenesis. The porosity of the sandstones in the Upper Member of the Huagang Formation in the FN area changes from 37.5% to 10.62%, and the porosity of the sand-stones in the Lower Member of the Huagang Formation in the FS area changes from 36.5% to 8.90%. The results of this study provide a reference for the study of differential diagenetic evolution of sandstones in the Xihu Sag and the exploration of deep high-quality reservoirs. Full article

Studying sedimentary distribution in water reservoirs is essential to understand the depositional processes and develop sustainable environmental management strategies. Characterization of deposited sediments provides information about the sources of particulate matter, transport patterns and predominant deposition mechanisms in different compartments of the reservoir. This study aimed to evaluate active deposition processes and to improve the understanding of sedimentation in water reservoirs. In this case, the Espora hydroelectric power plant, located on the Corrente River, southwestern Goiás, Brazil, was employed as a model environment. Sediment cores were collected at 29 points along the reservoir, covering different aquatic compartments. Particle-size analysis of the sediments was performed based on established methodologies using textural classification to identify sedimentary facies. The results indicated the predominance of stream deposits (sandy material) in areas where water flow velocity was higher, and bed deposits, composed predominantly of clays and silts, in regions of lower water flow velocity and greater depth. Full article

China has abundant deep coalbed methane (CBM) resources; however, high temperature, stress, and reservoir pressure complicate the gas adsorption–desorption–diffusion–seepage processes, severely restricting the development of deep CBM. Through experimental research on adsorption, desorption, diffusion, and seepage behaviors of various coal samples, the control mechanisms of deep coal reservoir properties on CBM production in the Linxing–Shenfu region have been revealed. The results indicate that CBM adsorption and desorption characteristics are jointly controlled by coal rank, ash yield, temperature. and pressure. Among the above conditions, coal rank and pressure exhibit positive effects, while ash yield and temperature show inhibitory effects. Analysis of desorption efficiency based on the Langmuir model further identifies sensitive desorption and rapid desorption stages as key phases for enhancing productivity. Moreover, the gas diffusion mechanism is dynamically evolving, with Knudsen diffusion and Fick diffusion being the main modes during high ground pressure stages, gradually transitioning to the coexistence of Knudsen, transition, and Fick diffusions as pressure decreases. Concurrently, gas–water seepage experiments demonstrate that increasing temperature will reduce the irreducible water saturation and enhance the relative permeability of the gas. Since irreducible water saturation is negatively correlated with relative permeability of gas, the relative permeability of the gas phase, cross-point saturation, and the range of the two-phase co-seepage zone all significantly increases with the increase in temperature. The findings systematically elucidate the regulatory mechanisms of deep coal reservoir properties in the process of “adsorption–desorption–diffusion–seepage,” providing critical theoretical support for optimizing development strategies and enhancing the efficiency of deep CBM development. Full article

Shale pores and throats are key factors controlling the enrichment and development efficiency of shale oil and gas. However, the characteristics and formation mechanisms of shale pores and throats remain unclear. Taking the Permian continental shales in the Mahu Sag of the Junggar Basin as an example, this paper studies the formation mechanisms of pores and throats in shales of different lithofacies through a series of experiments, such as high-pressure mercury injection and scanning electron microscopy. The results show that the Permian continental shales in the Junggar Basin are mainly composed of five lithofacies: rich siliceous shale (RSS), calcareous–siliceous shale (CSS), argillaceous–siliceous shale (ASS), siliceous–calcareous shale (SCS), and mixed-composition shale (MCS). The pores in shale are dominated by intergranular and intragranular pores. The intergranular pores are mainly primary pores and secondary dissolution pores. The primary pores are mainly slit-like and polygonal, with diameters between 40 and 1000 nm. The secondary dissolution pores formed by dissolution are irregular with serrated edges, and their diameters range from 0.1 to 10 μm. The throats are mainly pore-constriction throats and knot-like throats, with few vessel-like throats, overall exhibiting characteristics of nanometer-scale width. The mineral composition has a significant influence on the development of pores and throats. Siliceous minerals promote the development of macropores, and carbonate minerals promote the development of mesopores. Clay minerals inhibit pore development. Diagenesis regulates the development of pores and throats through mechanical compaction, cementation, and dissolution. Compaction leads to a reduction in porosity, and cementation has varying effects on the preservation of pores and throats. Dissolution is the main factor for increased pores and throats. These findings provide a lithofacies-based geological framework for evaluating effective porosity, seepage capacity, and shale oil development potential in continental shale reservoirs. Full article

The sustainability of reservoir resettlement depends on the synergistic development of resettlers’ livelihoods and host regions; however, existing studies lack an integrated analytical framework. Combining the Sustainable Livelihoods Framework with synergistic development theory, this study establishes a dual-system evaluation model comprising the Regional Development Support (RDS) and Resettlers’ Livelihood Development (RLD) indices. Using survey data from 289 households across 10 counties in Zhejiang’s QC Reservoir project, we apply composite weighting, coupling coordination modeling, and spatial analysis to evaluate the levels of synergistic development and examine spatial patterns. The findings reveal that (1) there is significant gradient differentiation in the Synergistic Development Index (SDI), with scores ranging from 0.134 to 0.738; (2) spatial autocorrelation is weak (Moran’s I = −0.089), reflecting industrial heterogeneity; and (3) four distinct coordination types are identified, with employment–industry mismatch and ecological constraints being the primary limiting factors. This study provides a diagnostic framework for assessing resettlement outcomes and offers guidance for formulating differentiated policy interventions. Full article

Accurate identification of lithology is considered very important in oil and gas exploration because it has a direct impact on the evaluation and development planning of any reservoir. In complex reservoirs where extreme class imbalance occurs, as critical minority lithologies cover less than 5%, the identification accuracy is severely constrained. Recent deep learning methods include convolutional neural networks, recurrent architectures, and transformer-based models that have achieved substantial improvements over traditional machine learning approaches in identifying lithology. These methods demonstrate great performance in catching spatial patterns and sequential dependencies from well log data, and they show great recognition accuracy, up to 85–88%, in the case of a moderate imbalance scenario. However, when these methods are extended to complex reservoirs under extreme class imbalance, the following three major limitations have been identified: (1) single-scale architectures, such as CNNs or standard Transformers, cannot capture thin-layer details less than 0.5 m and regional geological trends larger than 2 m simultaneously; (2) generic imbalance handling techniques, including focal loss alone or basic SMOTE, prove to be insufficient for extreme ratios larger than 50:1; and (3) conventional Transformers lack depth-dependent attention mechanisms incorporating stratigraphic continuity principles. This paper is dedicated to proposing a geological-constrained multi-scale Transformer framework tailored for 1D well-log sequences under extreme imbalance larger than 50:1. The systematic approach addresses the extreme imbalance by deep-feature fusion and advanced class-rebalancing strategies. Accordingly, this framework integrates multi-scale convolutional feature extraction using 1 × 3, 1 × 5, 1 × 7 kernels, hierarchical attention mechanisms with depth-aware position encoding based on Walther’s Law to model long-range dependencies, and adaptive three-stage class-rebalancing through SMOTE–Tomek hybrid resampling, focal loss, and CReST self-training. The experimental validation based on 32,847 logging samples demonstrates significant improvements: overall accuracy reaches 90.3% with minority class F1 scores improving by 20–25% percentage points (argillaceous siltstone 73.5%, calcareous sandstone 68.2%, coal seams 65.8%), and G-mean of 0.804 confirming the balanced recognition. Of note, the framework maintains stable performance even when there is extreme class imbalance at a ratio of up to 100:1 with minority class F1 scores above 64%, representing a two-fold improvement over the state-of-the-art methods, where former Transformer-based approaches degrade below. This paper provides the fundamental technical development for the intelligent transformation of oil and gas exploration, with extensive application prospects. Full article

In the context of energy structure transition, Enhanced Geothermal Systems (EGSs) represent a core technology for developing hot dry rock (HDR) resources. However, the ultra-long-term natural recovery patterns of reservoir temperature after heat extraction cessation remain unclear, hindering sustainable lifecycle assessment of the system. This study establishes a dual-well EGS numerical model based on the finite element method to simulate the impact mechanisms of flow rate, injection temperature, initial reservoir temperature, and well spacing on natural reservoir temperature compensation during a 1000-year shut-in period following 40 years of heat extraction. Results indicate that reservoir temperature fails to recover to its initial state after shut-in, with final recovery rates ranging from 60.63% to 89.51% of the initial temperature. Each parameter exerts nonlinear control over recovery: lower flow rates yield higher final recovery temperatures (87.62% at 20 kg/s versus 60.63% at 100 kg/s); increased injection temperature from 10 °C to 70 °C reduces the absolute recovery magnitude from 10.65 °C to 7.05 °C but raises the final recovery rate from 78.16% to 86.07%; higher initial reservoir temperatures from 100 °C to 260 °C significantly enhance absolute recovery temperatures from 79.48 °C to 199.58 °C; reduced well spacing from 500 m to 100 m improves final recovery rates from 72.77% to 89.51%. After shut-in in dual-well EGS, the vertical fracture configuration recovered to 78.16% of the initial temperature, the horizontal fracture to 74.39%, and the no-fracture configuration only to 67.87%. Due to optimal heat flow and thermal compensation efficiency, vertical fractures exhibit the best recovery performance, while the no-fracture configuration shows the worst. This study reveals the dynamic mechanism of heat recovery dominated by heat conduction in surrounding rocks, establishes a long-term temperature recovery evaluation framework for EGS, and provides novel scientific evidence and perspectives for the sustainable development and research of geothermal systems. Full article

To address the problem of wellbore instability in the development of deep coalbed methane reservoirs in Daniudi gas field, this study takes the coal seam cores from Member 1 of the Taiyuan Formation at a depth of approximately 2880 m as the research object. Through CT scanning, scanning electron microscopy (SEM), mineralogical analysis, laboratory mechanical tests, and drilling fluid interaction experiments, the study investigated the coal seam fabric characteristics, mechanical response, anisotropy, and the interaction between drilling fluids and the formation. Based on the double-weak-plane criterion, a wellbore collapse prediction model was established, and instability risk assessment under multi-factor coupling conditions was carried out. Experimental and computational results indicate that the deep coal seam exhibits significant heterogeneity in fabric structure, the clay minerals show low swelling potential, and the bright coal and semi-bright coal are prone to instability due to their dual pore structures. The average uniaxial compressive strength (UCS) of the coal cores is 16.3 MPa, which is weaker than that of the roof, floor, and dirt band. The coal also exhibits anisotropy, with the lowest strength occurring when the loading direction forms an angle of 30–60° with the weak planes, corresponding to 67.5% of the intrinsic compressive strength. Immersion in drilling fluid causes the coal rock strength to decay in a pattern of “rapid decline in the initial stage—gradual decrease in the middle stage—stabilization in the later stage.” After 24 h, the strength is only 55–65% of that in the dry state. Due to its excellent plugging and inhibition performance, HX-Coalmud drilling fluid delays strength loss more effectively than the strongly inhibitive composite salt drilling fluid. The wellbore instability risk assessment indicates that as the drilling time is extended, the collapse pressure rises significantly. After 7 and 20 days of contact between the wellbore and drilling fluid, the equivalent collapse pressure density increases by 0.08–0.15 g/cm³ and 0.13–0.20 g/cm³, respectively. Therefore, homogeneous isotropic models tend to underestimate the risk of wellbore collapse. The findings can provide theoretical and technical support for the safe drilling of deep coalbed methane in Daniudi gas field. Full article

Systemic lupus erythematosus (SLE) is a complex autoimmune disease characterized by autoantibody production and the formation of immune complexes (ICs), which lead to widespread inflammation and tissue damage. Neutrophil extracellular traps (NETs), web-like structures composed of DNA, histones, and antimicrobial proteins released by activated neutrophils, play a crucial role in innate immunity by defending against pathogens. However, excessive NET formation and ineffective clearance of these structures contribute to the development of SLE. This review explores the mechanisms behind NET formation in SLE, their relationship with oxidative stress, and the potential role of antioxidants in treatment. Research indicates that SLE patients exhibit two key abnormalities: excessive NET formation and impaired NET clearance. Excessive NET formation is driven by proinflammatory low-density granulocytes (LDGs) and immune complexes (ICs). Impaired NET clearance stems from reduced DNase1/DNase1L3 activity or anti-nuclease autoantibodies. These two abnormalities lead to elevated circulating NETs. These NETs act as autoantigen reservoirs, forming pathogenic NET–ICs that amplify autoimmune responses. Oxidative stress drives NET formation by activating NADPH oxidase. In contrast, various antioxidants, including enzymatic and non-enzymatic types, can inhibit NET formation via scavenging reactive oxygen species (ROS) and blocking NADPH oxidase activation. Preclinical studies show that antioxidants such as curcumin, resveratrol, and mitochondrial-targeted MitoQ reduce NET formation and ameliorate lupus nephritis; clinical trials confirm that curcumin and N-acetylcysteine (NAC) lower SLE disease activity and reduce proteinuria, supporting their role as safe adjuvant therapies. However, high-dose vitamin E may exacerbate autoimmunity, highlighting the need for dose optimization. Future research should aim to clarify the mechanisms underlying NET formation in SLE and to optimize new antioxidant therapies, including assessments of their long-term efficacy and safety. Full article

This paper presents a comprehensive study on the feasibility and implications of a CO₂ injection simulation in the Syderiai deep saline aquifer of Lithuania, focusing on leakage, geo-mechanical aspects, and geo-chemical aspects. The Syderiai aquifer, characterized by its sandstone formation covered by shaly rocks, is considered a potential site for CO₂ geological storage in Lithuania. Using 3D mechanistic models developed in T-navigator software, we conducted extensive simulations to analyze CO₂ storage behavior and associated impacts. The leakage study examines various scenarios to assess the impact of fracture permeability, layer-wise heterogeneity, and fracture position on CO₂ injection and leakage volumes. Results indicate that while fracture permeability influences CO₂ migration dynamics, its impact on both free and dissolved CO₂ leakage volumes is minimal, highlighting that leakage behavior is more dependent on the presence of fractures than their permeability. Geo-mechanical analysis reveals the effects of CO₂ injection on the bulk modulus and shear modulus of sandstone and shale formations, highlighting changes in compaction and cementation. The geo-chemical study was performed using TOUGHREACT software V4.13-OMP to investigate the distribution of pH, porosity change, and free CO₂ over 1000-years following 10-year CO₂ injection. Results demonstrate the acidifying effect of CO₂ injection and its implications for the caprock–reservoir interface over time. The findings offer valuable perspectives on the feasibility and consequences of CO₂ geological storage in the Syderiai deep saline aquifer, highlighting the importance of incorporating leakage, geo-mechanical aspects, and geo-chemical aspects for implementing efficient CO₂ storage. Full article

A central challenge in tight fault-depression reservoirs is understanding how three-dimensional fracture structures control gas storage and flow. This study introduces a data-driven, geologically informed framework that integrates structural-mechanical coupling to decipher fracture networks within the Shahezi Formation. Our model, based on rock failure criteria, achieves quantitative fracture prediction across one-dimensional to three-dimensional scales. This capability overcomes the limitations inherent in single-method approaches for tight, fracture-dominated reservoirs. By synthesizing sedimentary facies-controlled reservoir modeling, sweet-spot inversion, and geo-engineering integration, we establish a predictive system for accurate reservoir assessment. The continental clastic Shahezi Formation is typified by secondary fractures. This study utilizes leverage small-scale data (core, thin section, log) to quantify key parameters (fracture density, aperture), enabling a systematic analysis of fracture typology, heterogeneity, and controls. Building on this foundation, and spatially constrained by large-scale datasets (seismic interpretation, stress-field simulations), we developed a robust fracture development model for deep tight reservoirs. Stress-field modeling delineated fracture-prone zones, where a discrete fracture network (DFN) model was built to characterize 3D fracture geometry and connectivity. Integrating simulated fracture size and aperture-derived permeability allowed us to quantify fracture contribution to total permeability, ultimately mapping favorable targets. The results identify favorable zones primarily in the western sector of the study area, forming an NS-trending, belt-like distribution. They are mainly concentrated around the wells Changshen-4, Changshen-40, and Changshen-41. This distribution is clearly controlled by the Qianshenzijing Fault. Full article

High-pressure water injection (HPWI) refers to injecting water into the formation under conditions where the injection pressure is higher than or close to the formation fracture pressure. This technique can effectively improve the water absorption capacity of low-permeability reservoirs and maintain the formation pressure above the bubble point. It is a key technology for solving the problem of “difficult injection and difficult recovery” in low-permeability reservoirs, thereby achieving increased injection and enhanced production. However, due to the lack of a unified understanding of the mechanisms of dynamic micro-fractures and the mechanism of pore volume expansion and permeability enhancement during HPWI, the technology has not been widely promoted and applied. Based on an in-depth analysis of the mechanism of high-pressure water injection and by building a geological model for an actual oilfield development block, the “compaction–expansion” theory of rocks is used to characterize the variation in reservoir properties with pore pressure. This model is used to simulate the reservoir’s pore volume expansion and permeability enhancement effects during high-pressure water injection. The research results show the following: (1) HPWI can increase the effective distance of injected water by changing the permeability of the affected area. (2) During HPWI, the effective areas in the reservoir are divided into three regions: the enhanced-permeability zone (EPZ), the swept zone without permeability enhancement, and the unswept zone. Moreover, the EPZ expands significantly with higher injection pressure, rate, and volume. However, the degree of reservoir heterogeneity will significantly affect the effect of HPWI. (3) Simulation of two production modes—“HPWI–well soaking–oil production” and “simultaneous HPWI and oil production”—shows that under the first production mode, the degree of uniformity of the production wells’ response is higher. However, in the production wells in the EPZ, after a certain stage, an overall water flooding phenomenon occurs. In the second mode, the production wells in the water channeling direction show an alternating and rapid water-flooding phenomenon, while the production wells in the non-water channeling areas are hardly affected. Meanwhile, for local production wells with poor effectiveness of high-pressure water injection, hydraulic fracturing can be used as a pilot or remedial measure to achieve pressure-induced effectiveness and improve the sweep efficiency of the injected water. The results of this study explain the mechanisms of volume expansion and permeability enhancement during high-pressure water injection, providing guiding significance for the on-site application and promotion of high-pressure water injection technology in low-permeability reservoirs. Full article

Lacustrine shale oil in the Chang 7 Member of the Ordos Basin is controlled by a multi-scale pore–throat system in which oil occurrence, spontaneous imbibition, and pore-structure evolution are tightly coupled. In this study, nitrogen adsorption and micro-computed tomography (μCT) were employed to characterize pore-size distribution and connectivity, whereas nuclear magnetic resonance (NMR) T₂ relaxation was utilized to classify oil occurrence states, and X-ray diffraction (XRD) and total organic carbon (TOC) analyses were performed to determine mineralogical and organic compositions. Spontaneous imbibition experiments were conducted at 60 °C and subsequently extended to temperature–pressure sequence tests. The Chang 7 shale exhibits a stratified pore system in which micropores, mesopores, and macropores jointly define a three-tier “micropore adsorption–mesopore confinement–macropore mobility” pattern. As pore size and connectivity increase, the equilibrium imbibed mass and initial imbibition rate both rise, while enhanced wettability (contact angle decreasing from 81.2° to 58.7°) further strengthens capillary uptake. Temperature elevation promotes imbibition, whereas increasing confining pressure suppresses it, revealing a “thermal enhancement–pressure suppression” behavior. μCT-based network analysis shows that imbibition activates previously ineffective pore–throat elements, increasing coordination number and connectivity and reducing tortuosity, which collectively represents a capillary-driven structural reconfiguration of the pore network. When connectivity exceeds a threshold of about 0.70, the flow regime shifts from interface-dominated to channel-dominated. Building on these observations, a multi-scalecoupling framework and a three-stage synergistic mechanism of “pore-throat activation–energy conversion–structural reconstruction” are established. These results provide a quantitative basis for predicting imbibition efficiency and optimizing capillary-driven development strategies in deep shale oil reservoirs. Full article

Cancer remains one of the leading causes of death worldwide, and resistance to conventional therapies underscores the need for the discovery of novel antitumor agents. The ongoing search for novel natural sources offers promising avenues for discovering unique anticancer compounds with new mechanisms of action. One of these natural sources is represented by fungi, a prolific group of endophytic and non-endophytic eukaryotes able to produce bioactive secondary metabolites, many of which exhibit potent antitumor properties. These natural compounds display diverse chemical structures including polyketides, terpenoids, alkaloids, amino acid-derived compounds, phenols, etc. Their mechanisms of action are equally varied, ranging from induction of apoptosis and cell cycle arrest to inhibition of angiogenesis and metastasis. In this review we describe some potential antitumor compounds of fungal origin, together with the characteristics and biosynthesis of three representative types of antitumor compounds produced by filamentous fungi: squalene-derived sterol-type antitumor agents, prenylated diketopiperazine antitumor metabolites and meroterpenoid antitumor compounds. The ongoing scientific debate regarding the presence of paclitaxel biosynthetic genes in fungi is also discussed. As drug resistance remains a challenge in cancer therapy, fungal compounds offer a valuable reservoir for the development of new chemotherapeutic agents with novel modes of action. Full article

The topological structure of fracture networks fundamentally controls the mechanical behavior and fluid-driven failure of brittle materials. However, a systematic understanding of how topology dictates hydraulic fracture propagation remains limited. This study conducted experimental investigations on granite specimens containing 10 different topological fracture structures using a self-developed visual hydraulic fracturing test system and an improved Digital Image Correlation (DIC) method. It systematically revealed the macroscopic control laws of topological nodes on crack initiation, propagation path, and peak pressure. The experimental results indicate that hydraulic crack initiation follows the “proximal-to-loading-end priority” rule. Macroscopically, the breakdown pressure shows a significant negative correlation with topological parameters (number of nodes, number of branches, normalized total fracture length). However, specific configurations (e.g., X-shaped nodes) can exhibit a configuration-strengthening effect due to dispersed stress concentration, leading to a higher breakdown pressure than simpler topological configurations. Discrete Element Method (DEM) simulations revealed the underlying mechanical essence at the meso-scale: the topological structure governs crack initiation behavior and initiation pressure by regulating the distribution of force chains and the mode of stress concentration within the rock mass. These findings advance the fundamental understanding of fracture–topology–property relationships in rock masses and provide insights for optimizing fluid-driven fracturing processes in engineered materials and reservoirs. Full article