Search Results (54)

Geological storage of carbon dioxide (CO₂) in deep-sea formations represents a pivotal strategy for mitigating atmospheric CO₂ levels, where storage security and efficacy are fundamentally governed by the pore-scale seepage behavior of CO₂. However, the microscopic displacement mechanisms of CO₂–water two-phase flow under the characteristic high-pressure, low-temperature conditions of the deep sea remain inadequately understood. This study employed a self-developed high-pressure microfluidic experimental platform (0–30 MPa, 4–50 °C) to systematically investigate the CO₂ displacement process in porous media. The effects of injection rate (0.001–5 mL/min) and system pressure (1, 5, and 10 MPa) on displacement patterns, front stability, and final saturation were quantified. The results demonstrate that injection rate is the primary controller of displacement stability: high rates (≥0.1 mL/min) induce viscous fingering and lower final saturation, whereas low rates (≤0.05 mL/min) promote stable, piston-like displacement. Crucially, elevated pressure exerts a profound stabilizing effect, effectively suppressing fingering instabilities and enhancing final gas saturation (up to 0.544 at 10 MPa). This work elucidates the synergistic regulatory mechanism between injection rate and confining pressure, providing essential pore-scale experimental evidence for optimizing injection parameters to achieve efficient and secure CO₂ storage in deep-sea reservoirs. Full article

Fracturing is the dominant stimulation technique for low-porosity, low-permeability dolomite gas reservoirs, yet the lack of systematic laboratory research on multistage alternating acid etching mechanisms restricts field construction parameter optimization. Targeting the low-permeability Xixiangchi Formation dolomite reservoir in the eastern Sichuan Basin, this work develops a high-temperature, high-pressure core acid etching system coupled with 3D surface scanning. A reliable lab-to-field parameter conversion is established based on the Reynolds and Froude similarity criteria. Four-factor three-level orthogonal tests are conducted to quantify the impacts of pad fluid-to-acid viscosity ratio, total acid volume, pumping rate, and alternating injection stages on JRC-characterized wall roughness and fracture conductivity. The results show an identical factor dominance ranking for both indicators: viscosity ratio > pumping rate > injection stages > total acid volume. The optimal stimulation scheme is determined as a 50:1 viscosity ratio, 120 mL total acid volume, 12.54 mL/min laboratory pumping rate (equivalent to 8 m³/min in field operations), and 3 alternating injection stages. An elevated viscosity ratio intensifies viscous fingering, induces heterogeneous dolomite dissolution, and forms abundant irregular asperities on fracture surfaces. These self-supporting rough structures sustain stable seepage channels and markedly improve conductivity, verifying the positive roughness-conductivity correlation and revealing the core mechanism of heterogeneous etching-driven conductivity enhancement. The findings provide direct experimental support and parameter guidance for multistage alternating acid fracturing design in the Xixiangchi Formation and analogous tight dolomite reservoirs. Full article

Multiphase flow involving fluids and particles is inherently complex due to the coupled effects of viscosity, capillary forces, and particle-scale friction. The fluids exhibit viscous behavior, which manifests as instabilities at the interface; changes in fluid viscosity also significantly affect the interface. In this study, we injected aqueous solutions of varying viscosities into a layer of dry, hydrophobic particles. As the viscous and frictional forces changed, we observed alterations in the number and width of the finger-like invasion patterns. When the pressure gradient exceeds a critical threshold, the finger-like structures expand radially outward. The fractal dimension of the invasion patterns was calculated using the standard box-counting method applied to binarized invasion masks, allowing the space-filling degree and morphological transition of the patterns to be quantified under different particle layer filling ratios, injection rates, particle sizes, and liquid viscosities. Full article

Vibration-assisted water flooding (VA-WF) can improve sweep efficiency. However, unclear macro-scale mechanisms limit its wider adoption in heavy oil reservoirs. This study combines previous sandpack experiments with two-dimensional Volume-of-Fluid (VOF) simulations to show how vibrations reshape permeability fields and, in turn, pressure and production behaviour. Heavy oil sandpacks were water-flooded under conditions of no vibration and 2 Hz and 5 Hz axial excitation. Measured injection pressure histories and oil production were used to calibrate a VOF model in which absolute permeability follows a log-normal distribution with directional anisotropy. Only when axial and radial permeabilities were assigned a negative local correlation did the model reproduce key observations: secondary pressure spikes, irregular viscous-fingering morphologies, delayed production drops, and variability in cumulative recovery. Parameter sweeps quantify the sensitivity of VA-WF performance to the variance and correlation of the permeability field, and multiple runs estimate the variability in outcomes introduced by stochastic heterogeneity. This study proposes a transferable workflow—comprising sample testing, parameter inference, and probabilistic simulation—to screen excitation conditions and forecast VA-WF performance prior to field implementation, enabling operators to optimize vibration frequency based on reservoir-specific permeability characteristics and to anticipate production variability under uncertainty. These results highlight the dominant factors affecting swept volume and oil recovery, supporting data-driven decision making in VA-WF projects. Full article

This paper presents the design, modeling, and experimental validation of a capacitive tactile sensor specifically conceived to sense shear-driven contact dynamics in robotic manipulation. The proposed device is a layered flexible capacitive structure, in which controlled tangential interactions are induced. The electrode design maximizes sensitivity to shear motion and promotes an isotropic response with respect to slip direction, thereby addressing two key limitations that affect the majority of existing slip-sensing technologies. An analytical model was developed to describe the essential relationship between shear-induced displacements and the electrical response, providing insight into the design parameters and supporting the selection of geometry and materials. To test the sensor in real conditions, a dedicated capacitive readout circuit based on high-frequency excitation and synchronous demodulation was developed to robustly acquire capacitance variations while rejecting static offsets and parasitic effects. Several formulations for the interposed dielectric layer material were investigated, including viscous fluids and composite mixtures with high-permittivity nanoparticles, with the aim of improving electrical sensitivity while preserving mechanical stability. Experimental results obtained under controlled loading and sliding conditions demonstrate that the sensor is highly sensitive to changes in contact state and tangential interaction dynamics. The sensor responded consistently to both load-induced shear and slip-related phenomena, enabling the reliable monitoring of contact dynamics rather than binary slip detection. A proof-of-concept integration into a robotic finger confirms the suitability of the proposed approach for grasp monitoring. Full article

Tight oil reservoirs are widely recognized as a critical successor in global unconventional energy development and are generally characterized by distinct geological features, including fine pore throats, pronounced heterogeneity, and a high concentration of clay minerals (e.g., montmorillonite and mixed-layer illite/smectite). Severe hydration, swelling, and fines migration are readily induced during water injection or conventional water-based fluid operations, thereby resulting in irreversible impairment of reservoir permeability. Despite the excellent injectivity and capacity for viscosity reduction associated with CO₂ flooding, sweep efficiency is severely compromised by viscous fingering and gas channeling, which are induced by the inherent low viscosity of the gas. While CO₂ foam technology is widely acknowledged as a pivotal solution for addressing mobility control challenges, its implementation is hindered by a primary technical bottleneck: the incompatibility between traditional water-based foam systems and strongly water-sensitive reservoirs. A dual challenge comprising water injectivity constraints and gas channeling is presented by strongly water-sensitive tight oil reservoirs. To address these impediments, three emerging low-damage CO₂ foam systems are critically evaluated in this review. First, the synergistic mechanisms of novel quaternary ammonium salts and polymers in inhibiting clay hydration and enhancing foam stability within modified water-based systems are elucidated. Next, the physical isolation strategy of substituting the water phase with a non-aqueous phase (oil/organic solvent) in organic emulsion systems is analyzed, highlighting advantages in wettability alteration and the mitigation of water blocking. Finally, the prospect of waterless operations using CO₂-soluble foam systems—wherein supercritical CO₂ is utilized as a surfactant carrier to generate foam or viscosify fluids via in situ formation water—is discussed. It is revealed by comparative analysis that: (1) Modified water-based systems are identified as the most economically viable option for reservoirs with moderate water sensitivity, wherein cationic stabilizers are utilized to inhibit hydration; (2) Superior wettability alteration and the elimination of aqueous phase damage are provided by organic emulsion systems, rendering them ideal for ultra-sensitive, high-value reservoirs, despite higher solvent costs; (3) CO₂-soluble systems are recognized as the future direction for “waterless” flooding, specifically tailored for ultra-tight formations (<0.1 mD) where injectivity is critical. Current challenges, such as surfactant solubility, high-temperature stability, and cost control, are identified through a comparative analysis of these three systems with respect to structure-activity relationships, rheological properties, damage control capabilities, and economic feasibility. What is more, an outlook is provided on the molecular design of future environmentally sustainable, cost-effective CO₂-philic materials and smart injection strategies. Consequently, theoretical foundations and technical support are established for the efficient exploitation of strongly water-sensitive tight oil reservoirs. By bridging the gap between reservoir damage control and mobility enhancement, this study identifies viable strategies for enhanced oil recovery. Crucially, it supports carbon neutrality and sustainable energy targets via CCUS integration. Full article

Low gas recovery in the Sebei-2 gas field is linked to residual gas trapping under water encroachment. This study investigates the pore-scale trapping behaviour of residual gas in three types of layer: conventional, low-resistivity, and low-acoustic high-resistivity. High-fidelity pore structures were reconstructed by integrating mercury intrusion porosimetry with thin-section data and microfluidic models were designed using the Quartet Structure Generation Set method and fabricated by wet etching. Visualized displacement experiments were performed under different wettability conditions and water invasion rates, and image analysis was used to quantify the distribution of trapped gas. Results show that the low-resistivity gas layer exhibits the highest residual gas saturation (30.57%), followed by the low-acoustic high-resistivity gas layer (20.20%), while the conventional gas layer has the lowest (15.29%). These values correspond to apparent pore-scale gas recoveries of about 48.95%, 65.01%, and 72.14% for the low-resistivity, low-acoustic high-resistivity and conventional gas layers, respectively. In hydrophilic systems, wetting-film thickening and flow diversion are the main trapping processes, whereas in hydrophobic systems, flow diversion dominates and residual gas decreases markedly. Increasing the water invasion rate reduces trapped gas in the conventional and low-resistivity layers, whereas in the strongly heterogeneous low-acoustic high-resistivity layer, higher invasion intensity strengthens preferential channelling/viscous fingering, leading to a non-monotonic residual gas response. These findings clarify the differentiated pore-scale trapping mechanisms of gas under water encroachment and highlight that mitigating water film-controlled trapping in low-resistivity layers and flow diversion trapping in low-acoustic high-resistivity layers is essential for mobilizing trapped gas, improving dynamic reserves, and ultimately enhancing the economic recovery of water-bearing gas reservoirs similar to the Sebei-2 gas field. Full article

The investigation of fluid flow channeling and viscous fingering during immiscible two-phase displacement in subsurface porous media is crucial for optimizing CO₂ geological sequestration and improving hydrocarbon recovery. In this study, we develop a pore-scale numerical framework for unsteady state immiscible displacement based on a body-centered cubic percolation network, which explicitly captures the coupled effects of pore-scale heterogeneity, capillary number, and unfavorable viscosity ratio on flow channeling and viscous fingering. The simulations reveal that viscous fingering and flow channeling preferentially occur along overlapping high conductivity pathways that conform to the minimum energy dissipation principle. Along these preferential routes, the local balance between viscous and capillary forces governs the stability of the two-phase interface and gives rise to distinct patterns and intensities of viscous fingering in the invading phase. Building on these insights, we establish a theoretical framework that quantifies how the critical pore radius and capillary number control the onset and growth of interfacial instabilities during immiscible displacement. The model demonstrates that lowering the injection rate, and hence, the effective capillary number, suppresses viscous fingering, leading to more stable displacement fronts. These findings provide practical guidance for the design of injection schemes, helping to enhance oil and gas recovery and improve the storage efficiency and security of CO₂ geological sequestration projects. Full article

Large-scale storage solutions play a critical role in the ongoing energy transition, with Underground Hydrogen Storage (UHS) emerging as a possible option. UHS can benefit from existing natural gas storage expertise; however, key differences in hydrogen’s behavior compared to CH₄ must be characterized at the pore scale to optimize the design and the management of these systems. This work investigates two-phase (gas–water) flow behavior using microfluidic devices mimicking reservoir rocks’ pore structure. Microfluidic tests provide a systematic side-by-side comparison of H₂–water and CH₄–water displacement under the same pore-network geometries, wettability, and flow conditions, focusing on the drainage phase. While all experiments fall within the transitional flow regime between capillary and viscous fingering, clear quantitative differences between H₂ and CH₄ emerge. Indeed, the results show that hydrogen’s lower viscosity enhances capillary fingering and snap-off events, while methane exhibits more stable viscous-dominated behavior. Both gases show rapid breakthrough; however, H₂’s flow instability—especially at low capillary numbers (Ca)—leads to spontaneous water imbibition, suggesting stronger capillary forces. Relative permeability endpoints are evaluated when steady state conditions are reached: they show dependence on Ca, not just saturation, aligning with recent scaling laws. Despite H₂ showing a different displacement regime, closer to capillary fingering, H₂ mobility remains comparable to CH₄. These findings highlight differences in flow behavior between H₂ and CH₄, emphasizing the need for tailored strategies for UHS to manage trapping and optimize recovery. Full article

CO₂ miscible flooding provides dual advantages in enhancing oil recovery and facilitating geological sequestration, and has become a key technical approach for developing low-permeability oil reservoirs and carbon emission reduction. The pore-scale flow mechanisms governing CO₂ behavior during miscible flooding are crucial for achieving efficient oil recovery and secure geological storage of CO₂. In this study, pore-scale two-phase flow simulations of CO₂ miscible flooding in porous media are performed using a coupled laminar-flow and diluted-species-transport framework. The model captures the effects of diffusion, concentration distribution, and pore structure on the behavior of CO₂ miscible displacement. The results indicate that: (1) during miscible flooding, CO₂ preferentially displaces oil in larger pore throats and subsequently invades smaller throats, significantly improving the mobilization of oil trapped in small pores; (2) increasing the injection velocity accelerates the displacement front and improves oil utilization in dead-end and trailing regions, but a “velocity saturation effect” is observed—when the inject velocity exceeds 0.02 m/s, the displacement pattern stabilizes and further gains in ultimate recovery become limited; (3) higher injected CO₂ concentration accelerates CO₂ accumulation within the pores, enlarges the miscible sweep area, promotes a more uniform concentration field, leads to a smoother displacement front, and reduces high-gradient regions, thereby suppressing local instabilities, and improves displacement efficiency, although its effect on overall recovery remains modest; (4) CO₂ dynamic viscosity strongly influences flow stability: low-viscosity conditions promote viscous fingering and severe local bypassing, whereas higher viscosity stabilizes flow but increases injection pressure drop and energy consumption, indicating a necessary trade-off between flow stability and operational efficiency. Full article

Viscous fingering is an interfacial instability that occurs when multiple fluids displace each other. This research focuses on the interface instability during immiscible displacement of shear-thinning fluids by CO₂. By controlling velocity and applying heat to the upper and lower walls, the influence of velocity and temperature on viscous fingering during CO₂ displacement is investigated. Moreover, by modifying the geometric conditions of the classical Hele-Shaw cells (HSCs), a novel analytical framework for viscous fingering is proposed. The primary methodology involves implementing a minute depth gradient distribution within the HSC, coupled with the Volume of Fluid (VOF) multiphase model, which systematically reveals the dynamic suppression mechanism of shear-thinning effects on viscous finger bifurcation. The results indicate that temperature elevation leads to increased sweep efficiency, reduced residual non-Newtonian fluid in the displaced zone, and enhanced displacement efficiency. Furthermore, increased velocity leads to reduced sweep efficiency. However, at lower velocities, displacement efficiency remains relatively low due to limited sweep coverage. The direction and magnitude of the depth gradient significantly govern the morphology and extension length of viscous fingering. Both positive and negative depth gradients promote fingering development on their respective sides, as the gradient establishes anisotropic permeability that prioritizes flow pathways in specific orientations, thereby intensifying finger propagation. Full article

Polymer flooding is a widely used enhanced oil recovery (EOR) method for improving energy efficiency and reducing the carbon footprint of oil production. Optimizing polymer concentration is critical for maximizing recovery while minimizing economic and environmental costs. Here, we present a systematic experimental study which shows that even very low concentrations of polymers yield relatively high recovery rates at adverse mobility ratios (230 cP oil). A series of core flood experiments were conducted on Bentheimer sandstone rock, with polymer concentrations ranging from 40 ppm (1.35 cP) to 600 ppm (10.0 cP). Beyond a mobility ratio threshold, increasing polymer concentration did not significantly enhance recovery. This plateau in performance was attributed to the persistence of viscous fingering and oil crossflow into pre-established water channels. The study suggests that low concentrations of polymer may mobilize oil at high mobility ratios by making use of the pre-established water channels as transport paths for the oil and that the rheology of the polymer enhances this effect. These findings enable reductions in the polymer concentration in fields with adverse mobility ratios, leading to substantial reductions in chemical usage, energy consumption, and environmental impact of the extraction process. Full article

CO₂ displacement is a key technique that was examined through numerical methods in a 3D Hele–Shaw cell, with CO₂ as the displacing phase and shear-thinning fluids as the displaced phase. Without interfacial tension effects, the displacement shows branching patterns forming two vertically symmetric fingers, regardless of whether the displacing fluid is air or CO₂. Under CO₂ displacement, viscous fingering propagates farther and achieves higher displacement efficiency than air. Compared with air displacement, the finger advancing distance increases by 0.0035 m, and the displacement efficiency is 15.2% higher than that of air displacement. Shear-thinning behavior significantly influences the process; stronger shear thinning enhances interfacial stability and suppresses fingering. As the power-law index n increases (reducing shear thinning), the fingering length extends. Variations in interfacial tension reveal it notably affects fingering initiation and velocity in CO₂ displacement of non-Newtonian fluids, but has a weaker impact on fingering formation. Interfacial tension suppresses short-wavelength perturbations, critical to interface stability, jet breakup, and flows, informing applications like foam-assisted oil recovery and microfluidics. Full article

Acid fracturing is a crucial method for reservoir reconstruction in carbonate reservoirs, and the propagation pattern of acid-etched fractures plays a key role in determining the scope of reservoir enhancement and post-fracturing productivity. However, large-scale physical simulations directly using acid solutions in fracturing experiments are limited, and the fracture propagation patterns under acid fracturing remain unclear. To address this gap, in this study, we collected carbonate rock samples from the Majiagou Formation in the Daniudi area, preparing large-scale fracturing specimens with side lengths of 30 cm. The propagation of acid fracturing fractures was investigated using self-developed true-triaxial acid fracturing equipment. Based on post-fracturing fracture morphology and pressure curves, the effects of fracturing fluid type, injection rate, injection mode, and natural fractures (NFs) on acid fracturing fracture propagation were analyzed. The experimental results showed that the acid solution effectively weakens the mechanical properties of the open-hole section, creating multiple mechanical weak points and promoting the initiation of fractures. Pre-fracturing treatment with low-viscosity acid can significantly enhance fracture complexity near the wellbore and expand the near-well stimulation zone. Lowering the injection rate increases the acid solution’s filtration loss into natural fractures, weakening the cementation strength of these fractures and encouraging the formation of complex fracture networks. Furthermore, employing a multi-stage alternating injection of high-viscosity and low-viscosity acids can reduce fracture temperature and acid filtration loss while also enhancing differential etching through viscous fingering. This approach improves the conductivity and conductivity retention of the acid-etched fractures. The results of this study can provide a reference for the acid fracturing stimulation of fractured carbonate reservoirs. Full article

The present study aimed to develop a novel temperature and pressure-controlled hybrid system (Cent-Hydro) for large-scale nanofiber production. Nanofibers from a hydrophilic carrier matrix were prepared using the Cent-Hydro system. This study explores the effect of increasing working temperature on the surface tension and viscosity of polymer solutions. The Cent-Hydro system was calibrated through the process of jet formation, and spinning parameters were identified for the jet path. The formation of fingers in front of the thin liquid occurred due to Rayleigh–Taylor instability, and a lower concentration of polymer solution favoured the development of thinner and longer fingers. The critical angular velocity and initial velocity for jet formation were obtained when the balance between surface tension, centrifugal force, and viscous force was achieved. The effect of increasing rotational speed and working temperature on finger velocity and length was experimentally evaluated, concluding that an increase in working temperature increases finger velocity and length. Additionally, the effect of increasing rotational speed, polymer concentration, and working temperature on the diameter of the nanofiber was evaluated. Overall, the Cent-Hydro system presents a compelling proposition for large-scale nanofiber production, offering distinct advantages over conventional methods and paving the way for advancements in various applications. Full article