Search Results (3,605)

Conventional depletion development and waterflooding are often ineffective in tight oil reservoirs because of their ultra-low permeability, complex fracture–matrix architecture, and limited fluid mobility. Although inter-fracture CO₂ flooding has demonstrated considerable potential for enhanced oil recovery (EOR), the coupled effects of key operational parameters on reservoir pressure evolution, fracture–matrix mass transfer, and oil mobilization remain inadequately understood. In this study, a multi-component compositional simulation model, constrained by detailed geological characterization and calibrated through production history matching of the Yuan 284 block in the Changqing Oilfield, was developed to systematically evaluate the effects of CO₂ injection rate, injection–production time ratio, and shut-in duration on recovery performance and reservoir response. The results show that increasing the CO₂ injection rate from 1000 to 50,000 m³/d improves the recovery factor from 40.49% to 49.90%; however, the incremental recovery gain decreases markedly beyond 30,000 m³/d, which is aggravated by enhanced gas channeling through high-conductivity fracture pathways. Analysis of the injection–production time ratio indicates that an optimal ratio of 0.50 provides the best balance between reservoir energy replenishment and oil displacement efficiency, whereas excessively small ratios result in insufficient pressure support and reduced recovery. In contrast, extending the shut-in duration consistently lowers recovery performance by weakening fracture–matrix mass transfer and promoting pressure dissipation, demonstrating that immediate production following injection is more effective than prolonged soaking under the investigated conditions. The optimized operating scheme yields a recovery factor of 48.87%, substantially exceeding the representative waterflooding recovery level of 35.20%. These findings clarify the mechanisms controlling pressure maintenance, CO₂ utilization efficiency, and volumetric sweep during inter-fracture asynchronous CO₂ flooding, and provide both theoretical insights and practical guidance for the efficient development of ultra-low-permeability fractured tight oil reservoirs. Full article

Deep high-temperature and high-pressure (HTHP) oil reservoirs have limited experimental MMP data, large differences between reservoir and saturation pressures, low gas–oil ratios, and pressure-sensitive CO₂–oil phase behavior, which make both minimum miscibility pressure (MMP) prediction and miscibility-mechanism identification challenging. To address these gaps, this study determines the MMP of a CO₂–oil system by integrating slim-tube experiments, empirical formula methods, the Multiple Mixed-Cell (MMC) method, the Method of Characteristics (MOC), compositional numerical simulation, and three intelligent algorithm models (GWO-RBF, GWO-LSSVM, and GWO-SVM). The slim-tube MMP of 44.13 MPa at 140 °C is used as the experimental reference for comparing prediction errors, whereas PVTsim and literature data are used for consistency checks and model benchmarking. The results show that when the injected CO₂ mole fraction exceeds 0.88, the formation oil under original reservoir conditions cannot achieve first-contact miscibility with CO₂, and the maximum dissolved CO₂–oil molar ratio is 7.3:1. Supercritical CO₂ forms dual displacement mechanisms, including front-end vaporizing miscible drive and rear-end condensing miscible drive, but the dominant mechanism for this CO₂–oil system is vaporizing miscible drive. During the vaporizing gas drive, the CO₂ + N₂ + C₁ content in the liquid phase increases from less than 60% to nearly 90%, indicating significant CO₂ dissolution into oil and associated density and viscosity reduction; meanwhile, the C₇₊ content in the gas phase increases to nearly 10%, indicating extraction of heavy components. Relative to the slim-tube reference at 140 °C, the deviations of MMC, GWO-SVM, GWO-LSSVM, compositional numerical simulation, GWO-RBF, MOC, and empirical formula methods are 2.97%, 3.08%, 3.40%, 4.24%, 4.26%, 11.62%, and 19.74%, respectively. The MMC method is the most suitable approach for this specific HTHP oil system, while intelligent algorithms should be regarded as supplementary predictors whose reliability depends on training-domain coverage and independent validation. Full article

Background/Objectives: Ischemic stroke remains a major global health challenge, yet therapeutic options are severely restricted by narrow treatment windows and the risk of hemorrhagic transformation. Natural small molecules represent a valuable reservoir for discovering novel neuroprotective leads with favorable safety profiles. Cinchonidine, a natural quinoline alkaloid, has shown anti-inflammatory and cytoprotective properties, but its potential in treating ischemic stroke is largely unexplored. This study aimed to evaluate the neurovascular protective effects and hemostatic safety of cinchonidine in preclinical stroke models. Methods: We evaluated cinchonidine using a mouse model of middle cerebral artery occlusion (MCAO) and in vitro oxygen–glucose deprivation (OGD) models in cerebral endothelial cells (CECs) and Neuro2A cells. Infarct volume, brain edema, and neurological recovery were assessed. Blood–brain barrier (BBB) integrity was measured via Evans blue extravasation. Mechanistic markers, including microglial activation, pro-inflammatory mediators (iNOS, COX-2), and apoptosis-related signaling, were examined. Additionally, cinchonidine’s effect on platelet aggregation was also tested. Results: Cinchonidine significantly reduced infarct volume and brain edema while improving neurological functional recovery. It effectively preserved BBB integrity and enhanced cell viability under OGD conditions. Furthermore, cinchonidine suppressed microglial activation and decreased the expression of pro-inflammatory mediators. These protective effects were associated with the modulation of apoptotic signaling pathways. These protective effects were accompanied by reduced p53-associated stress signaling in endothelial cells and ischemic brain tissue. Importantly, cinchonidine did not significantly interfere with platelet aggregation, suggesting a potentially favorable hemostatic profile. Conclusions: Cinchonidine attenuates ischemic brain injury and is associated with endothelial protection, preservation of BBB integrity, and modulation of inflammatory and apoptotic responses. As a natural lead compound that does not compromise hemostasis, cinchonidine represents a promising lead compound for further development as a neurovascular protective strategy in ischemic stroke. Full article

Hydro-dominant distribution grids with high penetrations of distributed photovoltaic (PV) generation exhibit a clear operational asymmetry. PV output changes rapidly at the minute scale, whereas hydropower regulation is constrained by reservoir water balance, turbine ramping capability, and hydraulic safety limits. During high-inflow periods, mandatory hydropower generation further reduces the downward regulation margin and restricts midday PV accommodation. To address this issue, this paper develops an asymmetry-aware adaptive bi-level planning framework for photovoltaic hosting capacity (PVHC) assessment. A db4 discrete wavelet transform is used to decompose PV output into low-frequency energy trends and high-frequency fluctuation components. The upper layer performs hourly economic dispatch while maintaining reservoir water balance, and the lower layer conducts minute-level constrained tracking under ramping and vibration-zone avoidance constraints. A bisection-type capacity-search procedure is then used to identify the PVHC boundary by jointly checking curtailment, ramping, frequency proxy, voltage, line-loading, point-of-common-coupling exchange, and vibration-zone residence constraints. Case studies based on a 15 min PV dataset from a 30 MW station, hydropower operation records, and a modified 15-node feeder in Southwest China show that hydrological asymmetry materially affects PV accommodation. The obtained PVHC ranges from 53.17 MW under the most restrictive high-proxy condition to 65.33 MW under low-proxy operation. Compared with the no-coordination case, representative-month PVHC increases from 49.80 MW to 65.33 MW, while the simulated residence time within the predefined vibration-prone zone decreases from 447 min to 0 min. These results indicate that PVHC evaluation in hydro-dominant feeders should jointly consider electrical constraints, hydrological asymmetry, and hydraulic safety limits. Full article

During hydraulic fracturing, the extensive use of slickwater and post-fracturing shut-in (soaking) processes take advantage of spontaneous imbibition to displace crude oil. While nano-flooding agents are known to reduce interfacial tension (IFT) and alter wettability, a critical challenge lies in distinguishing between deep but inefficient displacement and shallow but highly efficient sweep. This study investigates the pore-scale mobilization and penetration depth of a nano-flooding agent in tight conglomerate reservoirs and focuses on the recovery per unit imbibition depth as a novel metric for evaluating the displacement efficiency. The nano-agent demonstrated excellent performance, reducing oil–water IFT to 0.141 mN/m and reversing wettability from oil-wet (148.7°) to water-wet (39.5°). Experiments revealed that the diffusion rate of the nano-agent decreases with pore size, suggesting a limited transport in confined space. Under reservoir conditions (80 °C), spontaneous imbibition in tight cores was highly permeability-dependent. High-permeability cores achieved a recovery rate of up to 44.6%, whereas low-permeability cores reached only about 12%. This work highlights that penetration depth alone does not necessarily indicate high recovery. The medium-permeability core exhibited a lower final penetration depth than the low-permeability core but achieved a much higher total recovery due to superior efficiency per unit depth, suggesting that in tight reservoirs, a shallow but highly efficient displacement mechanism can outperform a deep but inefficient one. Full article

The Tajik Basin is located on the eastern edge of the Central Asian segment of the Tethyan tectonic domain. The basin underwent intense tectonic transformation during the Himalayan period, resulting in complex structural styles, unclear original sedimentary characteristics and oil and gas geological conditions, and a complex process of oil and gas accumulation, which restricts the further evaluation of the basin’s exploration potential. Studying the Tajik Basin in the macro background of the Tethys tectonic domain, the tectonic sedimentary evolution of the Tethys tectonic domain has a significant effect on the basin’s tectonic evolution, sedimentary characteristics, and oil and gas accumulation conditions. The Tajik Basin has gone through four stages of tectonic evolution: the Late Permian to Triassic was the stage of back arc foreland basin; the Jurassic period was the stage of back arc extensional faulting depression; the Cretaceous–Paleogene period was the stage of depression basins; and the Neogene is the stage of the regenerated foreland basins. Through field geological surveys and analysis of outcrop samples, it has been determined that the Tajik Basin has developed three sets of source rocks: the Middle and Lower Jurassic, Cretaceous, and Paleogene. Among them, the organic matter abundance of the Middle and Lower Jurassic is relatively high, most of them are in the mature stage, and they are primarily gas-generating source rocks. The Cretaceous and Paleogene source rocks are mainly oil generating and in a low-mature state. There are four sets of reservoirs developed in the Tajik Basin: Middle-Upper Jurassic carbonate rocks, Lower Cretaceous clastic rocks, Upper Cretaceous carbonate rocks and Paleogene carbonate rocks. Comprehensive research shows that the Tajik Basin mainly develops three types of oil and gas reservoirs: Jurassic carbonate gas reservoirs, distributed in the southwestern Gissar Uplift and Surhan Depression in the western part of the basin; Paleogene carbonate reservoirs, distributed in the southern Vakhsh Depression and the eastern Kuliabu Depression; and multi layer–multi lithology oil and gas reservoirs, distributed in the northern Dushanbe Depression. The primary controlling factor for the three types of oil and gas reservoirs is tectonic movement, which forms traps and simultaneously reshapes the reservoirs, ultimately leading to effective accumulation of oil and gas. The distribution of oil and gas in the Tajik Basin is characterized by “west gas and east oil, west more and east less, west pre-salt and east post-salt, and pre-salt gas and post-salt oil”. Affected by the regional tectonic movements of the Tethys rich oil and gas tectonic domain, the basin has high-quality hydrocarbon source rocks, reservoirs, and cap rock conditions. The pre-salt Jurassic has the potential to form large natural gas reservoirs, while the post-salt Cretaceous and Paleogene still have further potential for exploration. Full article

Particle-laden flow through rough confined fractures is controlled by the coupled evolution of particle packing, load-bearing contacts, and rough-wall flow channels. In this study, conductivity experiments were performed on rough split-core fractures prepared from downhole tight-sandstone cores from the Tarim Basin, China, to examine how proppant size mixing and placement sequence regulate flow capacity under closure. Single-size 40/70 and 70/140 proppants and mixed-size systems with different size ratios were tested under staged and uniformly mixed placement schemes. Two equivalent placement levels, denoted as 1 mm and 2 mm, were considered. Three-dimensional laser scanning before and after conductivity testing was used to quantify rough-wall morphology using $R_a$, $R_q$, and $R_z$. The results show that fracture conductivity decreased with increasing closure pressure for all particle systems, indicating progressive narrowing and rearrangement of preferential flow channels. Coarse-particle-dominated systems consistently retained higher conductivity, with an overall ranking of 40/70 > 3:1 > 1:1 > 1:3 > 70/140 at both placement levels. Increasing the placement level from 1 mm to 2 mm markedly enhanced conductivity, especially for systems rich in 40/70 proppant. Staged placement yielded higher conductivity than uniformly mixed placement for the 3:1 and 1:1 systems, but this effect was negligible for the fine-particle-dominated 1:3 system. Post-test roughness changes indicate that sparse placement induced competing smoothing and roughening, whereas sufficient placement caused systematic roughening after closure. The proposed morphology-aware experimental workflow provides a laboratory-scale basis for interpreting the coupled evolution of fracture conductivity and rough-wall morphology in propped rough fractures. Although the workflow can be extended to other lithologies and fracture systems, quantitative field-scale prediction requires further calibration with larger datasets and reservoir-specific conditions. Full article

Background: Although chronic venous insufficiency is often treated as a localized problem, it is a systemic condition that can negatively affect cardiac hemodynamics. This study investigates the associated effects of eliminating the pathologic venous reservoir on right ventricular (RV) functions, systolic pulmonary artery pressure (sPAP), and inferior vena cava (IVC) diameter in patients undergoing endovenous radiofrequency ablation (RFA) for severe great saphenous vein (GSV) insufficiency. Methods: This retrospective observational study included 154 patients who presented between September 2023 and May 2025 with GSV insufficiency (CEAP C3-C4b) and underwent endovenous RFA. Patients with major cardiopulmonary diseases were strictly excluded. Preoperative and 6-month postoperative transthoracic echocardiography records were analyzed to evaluate RV diastolic diameter, tricuspid annular plane systolic excursion (TAPSE), sPAP, the TAPSE/sPAP ratio, and IVC diameter. Results: At 6 months post-RFA, compared to preoperative values, a significant decrease was detected in the mean sPAP (14.7 ± 2.5 vs. 11.8 ± 1.8 mmHg, p < 0.001) and IVC diameter (2.1 ± 0.2 vs. 1.9 ± 0.2 cm, p < 0.001). Furthermore, significant improvements were observed in TAPSE (20.0 ± 2.0 vs. 21.5 ± 1.8 mm, p < 0.001) and the TAPSE/sPAP ratio (1.36 ± 0.15 vs. 1.82 ± 0.18 mm/mmHg, p < 0.001). Conclusions: Endovenous RFA is associated with favorable changes in right heart parameters. Eliminating pathologic extremity blood pooling may optimize venous return kinetics and subclinically improve right ventricular–pulmonary arterial coupling. Full article

Natural fractures can significantly affect fluid seepage behavior and development performance in tight formations. However, the optimal configurations and performance of oriented horizontal wells under various natural fracture scenarios remain insufficiently understood. Numerical simulation models for a fractured horizontal well in a five-spot well pattern were established based on the embedded discrete fracture model (EDFM) to consider the coupled effects of hydraulic fractures and natural fractures. Optimization analyses were performed under different natural fracture conditions, with cumulative oil production used as the main evaluation criterion. The results indicate that natural fractures play a significant role in determining the optimal horizontal well orientation. For reservoirs without natural fractures and those with low- to medium-density single-set natural fractures, the optimal horizontal well orientation is perpendicular to the maximum horizontal stress direction. In contrast, for high-density single-set natural fracture systems, a slight rotation of the horizontal wellbore improves cumulative oil production, with an optimal orientation angle of approximately 15° identified in this work. For conjugate fracture networks, the influence of well orientation becomes more significant, and the optimal orientation angle varies with fracture density, ranging from 15° to 45°. This study indicates that the horizontal wellbore trajectory design may highly rely on the characteristics of natural fractures. Therefore, thorough and accurate characterization of natural fractures should be conducted before optimizing the orientation of fractured horizontal wells. The findings of this work provide theoretical guidance for the placement of fractured horizontal wellbores in naturally fractured tight formations. Full article

The integration of high-penetration renewable energy creates new requirements for cross-timescale peak shaving and for system robustness under extreme meteorological conditions. This study develops a dual-timescale capacity allocation method for pumped hydro storage (PHS), combining 8760 h chronological production simulation with monthly typical-day retrospective analysis. The model represents the operating limits of conventional units, nuclear power, hydropower, wind power, photovoltaic generation, tie-line exchange, and PHS energy shifting. On this basis, a stepwise capacity-sensitivity framework is established to minimize annualized comprehensive system cost while controlling renewable energy curtailment within a predefined planning threshold, rather than treating zero curtailment as an unconditional monthly hard constraint. Using long-term planning data from a coastal provincial power grid in southeastern China, the study compares the 2035 and 2040 planning scenarios. The results show that isolated typical-day models tend to overestimate PHS requirements because they disconnect chronological continuity and cross-day reservoir buffering. In 2035, the system presents a two-level seasonal capacity structure: 15,000 MW can support normalized operation in stable months, whereas the rigid boundary rises to 19,000 MW under extreme autumn high-wind conditions. In 2040, wind and photovoltaic capacity increase by approximately 20.01 GW compared with 2035, deepening low-net-load valleys and compressing seasonal regulation margins. Under the assumed planning boundary, the recommended PHS capacity converges to 23,000 MW. The proposed framework provides a practical reference for flexible resource planning in coastal power grids with deep renewable energy integration. Full article

Water blockage severely restricts gas transport in deep shale reservoirs, while effective mitigation requires a precise balance of multiple operational variables. This study utilizes core-flooding experiments to optimize the treatment processes of an amphiphobic fluorinated copolymer, focusing on the coupled roles of surfactant concentration, injected volume, and shut-in duration. The results show that permeability damage decreases rapidly with surfactant concentration, optimizing at 0.5 wt.%. Conversely, excessive liquid retention beyond a critical injection threshold of 1.0 PV triggers secondary water-blocking. Extending the shut-in duration to 8 days facilitates surfactant redistribution and interfacial equilibrium, gradually reversing rock wettability to a stable amphiphobic state. Crucially, the concurrent reduction in interfacial tension markedly lowers capillary resistance, allowing trapped water to detach and flow back under significantly lower driving pressures. This optimization effectively minimizes the energetic barrier for fluid displacement and creates a gas-preferential flow environment. The proposed laboratory operational window balances surfactant dosage, injection volume, and shut-in duration under the tested conditions, providing an experimental reference for optimizing post-fracturing cleanup, controlling liquid retention, and improving early-time gas flowback in shale gas reservoirs. Full article

Serratia marcescens has emerged as an important opportunistic pathogen in intensive care units (ICUs), where critically ill patients, invasive devices, antimicrobial exposure, and complex environmental reservoirs create favorable conditions for colonization, infection, and recurrent outbreaks. This narrative review synthesizes evidence from the past decade regarding the clinical and molecular epidemiology, environmental persistence, device-associated transmission, biofilm-mediated resistance, and infection-control strategies of S. marcescens in ICU settings. The literature was reviewed using an integrative approach informed by Ferrari’s narrative review framework, with thematic synthesis across clinical, microbiological, environmental, and genomic domains. Recent evidence indicates that ICU-associated S. marcescens infections frequently involve respiratory tract colonization, ventilator-associated pneumonia, bloodstream infection, urinary tract infection, and device-related transmission. Hospital water systems, sink drains, wet surfaces, ventilator circuits, reusable equipment, and contaminated antiseptic or liquid products may serve as persistent reservoirs, particularly when biofilm formation supports long-term survival and recurrent dissemination. At the molecular level, S. marcescens demonstrates substantial genomic diversity, intrinsic and acquired antimicrobial resistance, inducible AmpC β-lactamase activity, efflux-mediated tolerance, and plasmid-associated resistance gene transfer. This review particularly emphasizes the molecular determinants that enable S. marcescens to persist in ICU ecosystems, including AmpC-mediated β-lactam resistance, efflux-associated tolerance, quorum-sensing-regulated biofilm formation, plasmid-mediated horizontal gene transfer, and WGS-defined clonal transmission. Whole-genome sequencing, rapid molecular diagnostics, active surveillance, environmental sampling, and integrated infection-control bundles have become increasingly important for distinguishing clonal outbreaks from endemic transmission and guiding timely interventions. Emerging perspectives emphasize the need to combine antimicrobial stewardship, environmental engineering, respiratory-care auditing, anti-biofilm strategies, and AI-assisted real-time surveillance into adaptive ICU infection-control frameworks. Overall, S. marcescens should be regarded not merely as an episodic outbreak organism, but as a highly adaptable ICU-associated pathogen requiring multidisciplinary prevention strategies. Full article

During horizontal drilling in coal-rock gas reservoirs, the particle size distribution (PSD) of drilled cuttings directly affects drilling efficiency, hole cleaning, and wellbore stability. However, the evolution of cuttings PSD and its controlling mechanisms during coal-rock fragmentation remain insufficiently understood. In this study, a drill bit–coal-rock interaction model was established using the discrete element method (DEM) and calibrated against uniaxial compression experiments. The effects of weight on bit (WOB), rotational speed, and depth of cut (DOC) on cuttings PSD were quantitatively investigated. The results show that the relative influence on the maximum cutting size followed the order of DOC > WOB > rotational speed, whereas the influence on the average cutting size followed the order of rotational speed > WOB > DOC. Increasing DOC from 0.5 mm to 1.5 mm increased the maximum cutting size from 11.6 mm to 29.4 mm. Increasing WOB promoted the generation of medium- and large-sized cuttings, thereby increasing hole-cleaning requirements. Meanwhile, increasing rotational speed from 40 rpm to 90 rpm reduced the average cutting size and shifted the dominant cutting fraction from 4–6 mm to 1–4 mm. DEM observations reveal that cutting PSD evolution is jointly controlled by primary brittle fracture and secondary particle breakage through a five-stage fragmentation process involving stress concentration, microcrack initiation, crack propagation and coalescence, fragment detachment, and secondary fragmentation. Field validation using 146 cutting samples demonstrated the applicability of the proposed optimization strategy. Under the investigated drilling conditions, a DOC of approximately 0.5 mm and a rotational speed of 70–90 rpm were found to effectively limit oversized cutting generation. These findings improve the mechanistic understanding of cutting PSD evolution and provide practical guidance for drilling parameter optimization and hole-cleaning management in coal-rock gas horizontal wells. Full article

Predicting landslide displacement is important for geological-hazard early warning. In reservoir areas, displacement evolution is affected by rainfall, reservoir water level, vegetation variation, and the intrinsic non-stationarity of the displacement sequence, which makes accurate prediction difficult for conventional single-sequence models. To address this problem, this study proposes a residual-increment-oriented landslide displacement prediction framework that fuses multi-source monitoring variables. The displacement sequence is first processed into trend and periodic-related fluctuation representations, and the residual increment is used as the prediction target. Rainfall, reservoir water level, and the normalized difference vegetation index (NDVI) are incorporated as external monitoring variables. A cross-branch attention mechanism models interactions among heterogeneous feature branches, and a sparse MoE-based fusion module is introduced to adaptively adjust branch contributions under different deformation conditions. The model predicts the displacement residual increment, from which the final displacement is reconstructed. A case study using the Baishui River (Baishuihe) landslide monitoring dataset was conducted, together with additional validation on the related Bazimen Z110 landslide monitoring dataset and comparisons against conventional recurrent, convolutional, statistical, and Transformer-based baselines. The results show that the proposed model achieves lower RMSE and MAE than the compared methods on the tested datasets. These findings suggest that residual-increment modeling, multi-source monitoring variables, and condition-dependent branch fusion can improve short-term displacement prediction for the tested reservoir-area landslide cases. Full article

Deep and ultra-deep carbonate reservoirs commonly experience fracture closure and conductivity reduction under high-temperature and high-stress conditions. In this study, triaxial creep tests were conducted on unacid-etched and acid-etched carbonate cores under different stress levels to investigate their time-dependent deformation behavior and the influence of acid etching on rock rheology. The results indicate that carbonate rocks exhibit pronounced creep behavior, including instantaneous elastic deformation, primary creep, and steady-state creep. Acid etching significantly altered the creep characteristics and rheological parameters of carbonate rocks, leading to distinct time-dependent deformation responses compared with the unacid-etched core. The Burgers constitutive model was employed to characterize the creep behavior, and all fitting correlation coefficients exceeded 0.9. Finite element simulations based on the fitted parameters successfully reproduced the experimental creep curves, verifying the reliability of the constitutive model. This study provides a theoretical and numerical basis for evaluating the long-term deformation behavior of acid-etched carbonate rocks and its implications for fracture closure and conductivity evolution. Full article