Search Results (156)

For casing damage phenomena including casing corrosion, rupture, and seal failure that frequently occur in carbon capture, utilization, and storage (CCUS) injection-production wells under long-term gas injection and pressure fluctuations, combined with the characteristics of ultra-fine cement slurry such as concentrated hydration heat release and vulnerability to acidic environment corrosion, this study synthesized tartaric acid-intercalated Mg-Al layered double hydroxides (TA-LDHs) through ion-exchange reaction as a functional retarder, and focused on screening the water–cement ratio as well as the dosages of fluid loss additive and dispersant suitable for CCUS working conditions. The results demonstrate that at a water–cement ratio of 0.7 with 1.5% fluid loss additive TSJ-1, 0.4% dispersant FSJ-1, and 0.2% TA-LDHs retarder, the cement slurry presents excellent rheological properties, a short thickening transition time, and remarkable resistance to acidic environment erosion. Plugging performance evaluations reveal that under simulated formation water conditions, the system maintains a breakthrough pressure gradient above 90.5 MPa·m⁻¹ and a plugging efficiency of more than 99%, and after 30 days of curing, its compressive strength reaches 29 MPa while the plugging efficiency is improved to 99.37%. Furthermore, after exposure to CO₂-saturated simulated formation brine at 80 °C and 20 MPa for 30 days, the TA-LDHs-modified cement exhibited a compressive strength of 27.0 MPa and a strength retention of 93.1%, while its permeability increased by only 23.1%. In comparison, the compressive strength retention of the control cement was 80.8%, and its permeability increased by 138.5%. These results indicate that the TA-LDHs-modified ultra-fine cement possesses favorable plugging performance and improved resistance to CO₂-induced degradation, showing potential for casing damage remediation in CCUS wells. Full article

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

In slurry shield tunneling, inefficient control of slurry permeability in sandy formations can cause excessive slurry loss, increased material consumption, reduced bentonite reuse, and compromised tunnel-face stability. To address these challenges and enhance material efficiency, this study investigates slurry infiltration and bentonite particle deposition mechanisms in saturated sandy soils. Based on deposited-particle mass conservation and slurry volume conservation coupled with excess pore-water pressure, a mathematical model is established to capture the evolution of slurry rheological properties and soil pore characteristics during infiltration. Through multilayer infiltration column experiments, a multiple regression formula for the filtration coefficient is established, considering the spatiotemporal variability of slurry and soil properties. Furthermore, a dynamic penetration criterion for slurry particles is proposed and verified through single-soil infiltration tests. Results demonstrate that most bentonite particles deposit on the soil surface, with only a minimal fraction migrating into deeper pores until reaching shear stress equilibrium. The maximum infiltration distance is positively correlated with soil particle size but negatively correlated with slurry mass concentration. Increasing the slurry mass concentration or shear strength promotes the development of a well-structured filter cake and infiltration zone. These findings provide a theoretical framework for precisely regulating slurry permeability, thereby minimizing material waste and supporting sustainable shield tunneling operations. Full article

Thermal–gas–chemical treatment (TGCT) using activated aluminum alloys is a promising near-wellbore stimulation method for high-viscosity oil reservoirs, combining localized heat generation, hydrogen release, pressure increase, and chemical activation of the treated zone. This study evaluates the potential of TGCT for the Karazhanbas field using laboratory core flooding experiments and reservoir-scale scenario analysis. Experiments were conducted on unconsolidated core models saturated with high-viscosity oil. Treatment with activated aluminum alloy and formation water generated up to 2600 mL of gas but did not increase oil displacement efficiency. In contrast, the system containing activated aluminum alloy, 3 wt.% HCl, and 2 wt.% surfactant intensified the reaction, promoted gas–liquid foam formation, increased electrical resistivity to 5000 Ω·m, and improved oil displacement efficiency from 0.37 to 0.61. The additional oil recovery reached 16.8 mL, corresponding to a relative increase of approximately 65%. Reservoir-scale scenario calculations showed a heterogeneous production response, with maximum oil production rate increases ranging from 0.03 to 3.27 m³/day, depending on well conditions. The results indicate that TGCT efficiency is controlled by the combined thermal, gas, and chemical effects rather than gas generation alone. Field-scale implementation requires the calibration of the treatment radius, effect duration, temperature response, gas saturation, permeability alteration, and well-specific reservoir conditions. Full article

Shale oil is a vital unconventional resource. Large-scale hydraulic fracturing serves as the core technology for the efficient development of shale oil reservoirs. Well testing can be applied to characterize the reservoir parameters of fractured shale formations. Nevertheless, conventional well testing approaches fail to account for numerous discrete fractures and complex formation geometries. Based on the embedded discrete fracture model (EDFM)—an effective tool for simulating flow in discrete fractures—this work proposes a numerical well testing approach for horizontal wells in hydraulically fractured shale reservoirs. The effects of fracture permeability, number of fracture clusters, matrix permeability, and water saturation on well testing curves are also investigated. The results showed that the parameters such as the main fracture permeability, the number of fracture clusters, and the matrix permeability all have significant effects on the well test curves. When the permeability of main fractures exceeds 20D, radial flow characteristics appear in Stage V. For the distance between fracturing intervals and pressure monitoring points within 0 m to 200 m, it imposes the most significant impact on Stage I and Stage II. The half-length of main fractures, the SRV extent in the Y-direction, and boundary conditions mainly affect Stage VI and Stage VII. Full article

Depleted hydrocarbon reservoirs (DHRs), particularly depleted gas reservoirs (DGRs), are increasingly regarded as promising candidates for geologic carbon storage (GCS). However, their low abandonment pressure poses significant thermo-hydraulic challenges during the injection of cold, high-pressure CO₂. In such non-isothermal conditions, complex processes may occur, including Joule–Thomson (J-T) cooling, hydrate formation, salt precipitation, and thermal fracturing, all of which may affect storage performance. This study presents an integrated assessment of the impact of CO₂ injection into DGRs on the three key pillars of GCS: capacity, injectivity, and containment. The analysis integrates laboratory experiments conducted at our institute, simplified analytics and numerical simulations to assess the governing physical mechanisms. The findings indicate that the cold CO₂ injection can enhance effective storage capacity during the injection phase. This is attributed to the increase in fluid density and the delay in pressure buildup. However, the post-injection thermal equilibrium may result in pressure rebound. The CO₂ injectivity has been demonstrated to be significantly impacted by the near-wellbore thermal effects. While thermo-induced fracturing may enhance injectivity, it poses potential risks to wellbore and caprock integrity. The process of hydrate formation depends on the local temperature and petrophysical conditions, with dynamic factors further reducing the likelihood of pore plugging. Salt precipitation has been found to be less critical under typical DGR conditions with low initial water saturation, although having the potential to become significant in the presence of water influx and/or cyclic injection. The findings provide a technical basis for enhancing the engineering design, accelerating the certification process, and ensuring the safe operation of future GCS projects in DGRs. Full article

Hydrogen (H₂) storage in subsurface formations has recently gained attention as a promising large-scale energy storage solution. Although previous studies have revealed distinct displacement behaviors between H₂ and other gases such as nitrogen (N₂) and carbon dioxide (CO₂) in high-permeability sandstones, the mechanisms governing H₂ migration in tight formations remain largely unexplored. To provide experimental observations that may help improve the understanding of H₂ migration in tight reservoirs, we conducted H₂ flooding experiments on a tight sandstone sample from the Ordos Basin under pore fluid pressures of 0.5, 1, and 2 MPa. Dynamic core flooding processes were monitored using a low-field nuclear magnetic resonance (NMR) analysis system. The capillary number (Nc) in this work ranged from 1.7 × 10⁻⁹ to 3.4 × 10⁻⁹, indicating a capillarity-dominated flow. H₂ saturation in the tight sandstone increased from 41.9% to 53.3% and then to 57.7% with increasing pore fluid pressure. Under a pore fluid pressure of 0.5 MPa, H₂ initially displaced water in small pores (T₂ < 10.5 ms), leading to prolonged fluctuations in water content over 136 min before significant displacement occurred in large pores (10.5 ms < T₂ < 6579.3 ms). In contrast, at a pore fluid pressure of 2 MPa, the water in large pores was more significantly impacted, with a marked decrease in water saturation observed after 8 min of flooding. These findings provide direct experimental evidence of pressure-dependent and pore-scale selective displacement patterns of H₂ in tight sandstone, offering new insights into the fluid dynamics that control hydrogen injectivity and storage efficiency in low-permeability reservoirs. Full article

Addressing the problem of limited methane (CH₄) recovery degree under different production conditions in a target low-permeability carbonate gas reservoir, this study intends to further investigate the effect of carbon dioxide (CO₂) injection on enhanced gas recovery (EGR). A group of long-core physical simulation experiments of CO₂ injection for EGR was adopted. Field injection–production parameters were converted to laboratory conditions through similarity criteria to simulate the actual production process of gas wells. Systematic experiments on CH₄ depletion and CO₂ displacement were carried out under different irreducible water saturation, gas injection timing pressure and injection rates. The influence laws of each key parameter on the CO₂ breakthrough time and CH₄ recovery degree were analyzed emphatically, and the optimal injection–production scheme was obtained. For the target low-permeability carbonate gas reservoir (permeability < 1 mD), the optimal CO₂ injection scheme is as follows: for layers with medium to high irreducible water saturation (≥40%), CO₂ injection at a rate of 36,000 m³/d per well after the end of stable production (formation pressure > 7.38 MPa) can increase the CH₄ recovery degree by 3–5%. This study provides experimental support for the optimization of CO₂ injection schemes for enhanced recovery in gas reservoirs and the adjustment of gas reservoir development strategies under different irreducible water saturation conditions. Full article

The widely applied empirical Darcy’s law in geotechnical engineering faces significant challenges in describing low-velocity flow processes in low-permeability porous media such as tight sandstones containing irreducible water. A deep understanding of low-velocity non-Darcy two-phase flow behavior in low-permeability porous media is essential for evaluating the development of ultra-low-permeability reservoirs. In this study, seven low-permeability three-dimensional digital cores with distinct pore structures were constructed based on realistic ultra-low-permeability sandstones. Using the lattice Boltzmann method, pore-scale investigations of water displacing oil were conducted. Low-velocity two-phase flow behavior under varying wettability conditions, pore structures, and fluid viscosities was simulated. The underlying mechanisms of low-velocity non-Darcy flow in ultra-low-permeability sandstones were examined, leading to a modified low-velocity non-Darcy flow equation. This improved model was subsequently applied to numerical simulations of ultra-low-permeability reservoirs. The results demonstrate that non-Darcy effects manifest primarily as nonlinearities in seepage curves, representing a marked departure from conventional Darcy’s law. Low-velocity non-Darcy (LVND) flow is predominantly constrained by the influence of complex pore-throat structures and capillary forces on fluid distribution. The dynamic equilibrium among capillary forces arising from residual water saturation, viscous forces, and pressure gradients constitutes the fundamental mechanism governing the onset of LVND flow. Enhanced nonlinear behavior is observed with increasing viscosity of the invading phase and elevated capillary forces. Substantial discrepancies in reservoir production dynamics are identified between LVND and classical Darcian regimes. Through pore-scale numerical simulations, this study systematically elucidates LVND behavior during bi-phasic flow in low-permeability porous media, while identifying critical controlling factors. These findings provide scientific rationale and technical support for addressing geological engineering challenges in tight sandstone formations. Full article

A large number of low-resistivity and low-permeability reservoirs have been discovered in the deep Paleogene strata of the Wenchang Sag. These reservoirs are characterized by complex porosity–permeability relationships and difficulties in fluid property identification, which restrict the progress of exploration and development operations. However, existing reservoir studies mostly focus on either low-permeability or low-resistivity reservoirs, with relatively few investigations targeting this specific type. Using petrological analysis and physical property testing as the main methods, combined with sedimentary and diagenetic studies, this paper examines the characteristics and genesis of low-resistivity and low-permeability reservoirs in the Paleogene of the Wenchang Sag. The results show that the Paleogene reservoirs are dominated by lithic quartz sandstones, with secondary pores as the main reservoir space, consisting of medium–small pores and fine throats. Samples of the same grain size exhibit a favorable porosity–permeability correlation. Based on capillary pressure curve morphology, the reservoirs can be classified into three types: high mercury intrusion saturation with low displacement pressure, medium mercury intrusion saturation with medium displacement pressure, and medium mercury intrusion saturation with medium–high displacement pressure. The low porosity and permeability are mainly attributed to the fact that the reservoir rocks are primarily deposited in near-source braided fluvial delta underwater distributary channels, resulting in low compositional and textural maturity of sandstones. Strong compaction resistance leads to a significant reduction in primary pores during burial, and intergranular cement filling further deteriorates physical properties. On the other hand, rapid lithological changes and complex pore structures give rise to abundant isolated pores and poor connectivity, leading to high irreducible water saturation. Coupled with high formation water salinity, these factors collectively give rise to low-resistivity reservoirs in the study area. This study clarifies the formation mechanism of low-permeability and low-resistivity reservoirs in the Paleogene of the Wenchang Sag, providing guidance for reservoir evaluation in subsequent oil and gas exploration and serving as a reference for analogous areas. Full article

The present work investigated the thermodynamic behaviors of oxygen in a liquid Fe–Ti alloy over a wide Ti concentration range of 11.6–71.2 wt% at 1873 K by integrating equilibrium experiments with thermodynamic modeling. To prevent excessive oxidation during the equilibrium experiments, the liquid alloys were equilibrated in a purified Ar atmosphere with an oxygen partial pressure below ~10⁻²⁰ atm. Two quenching methods—furnace quenching with He gas injection and water quenching via quartz tube suction—were employed to evaluate the effect of cooling rate on total oxygen measurements. While He gas quenching led to higher measured oxygen contents owing to the formation of secondary Ti oxides, the quartz tube suction quenching method consistently yielded significantly lower oxygen values. The dissolved oxygen content increased with increasing Ti content. Electron probe microanalysis identified TiO as a stable equilibrium oxide phase above 11.6 wt% Ti, which was characterized as a face-centered cubic (FCC) rock-salt structure via electron backscatter diffraction analysis. Based on these results, a thermodynamic assessment of oxygen behavior in a liquid Fe–Ti alloy in equilibrium with TiO was performed for the first time using a modified quasichemical model. Consequently, the present model successfully reproduced the Ti–O relationship in the liquid Fe–Ti alloy across both the high-Ti concentration region saturated with TiO and the low-Ti concentration region saturated with Ti₂O₃ and Ti₃O₅. Full article

The Jimusar shale reservoir exhibits extremely low permeability, classified as an ultra-low porosity and ultra-low permeability formation. Crude oil mobility is poor, and the reservoir demonstrates significant heterogeneity. Conventional horizontal well fracturing development fails to meet requirements, facing issues such as pronounced energy depletion in the formation, unclear oil–water distribution, and changes in formation stress direction. Based on the reservoir properties of the Jimusar shale oil reservoir, this paper establishes a fracture propagation model for horizontal wellbore hydraulic fracturing and a reservoir numerical model. It simulates the evolution of pressure fields, stress fields, and seepage fields at different time points during the fracturing and production phases of horizontal wells. Results indicate the following: (1) When fracturing fluid is injected into the formation, oil saturation around fractures rapidly decreases. During the initial production phase, oil saturation around fractures increases due to the recovery of some fracturing fluid and the sorption effect between fracturing fluid and crude oil. (2) Formation pressure around horizontal wells significantly increases upon fracturing fluid injection. The dual effects of fracture opening and fluid injection cause stress to rise near fractures. During production, both formation pressure and stress decrease near the wellbore, with greater pressure reduction in the near-wellbore zone than in the far-wellbore zone. However, formation stress decreases less near the wellbore due to stress concentration effects from fracture opening, resulting in a smaller reduction than in the far-wellbore zone. (3) The formation surrounding the fracture undergoes dual influences from fracture opening and fracturing fluid injection, causing deflection in the direction of near-wellbore stress. During the initial production phase, the impact of stress deflection gradually diminishes with ongoing production. However, after prolonged production, the deflection of formation stress intensifies. The conclusion states that this understanding clarifies the multi-field evolution patterns in fracturing production for horizontal well clusters, providing theoretical guidance for subsequent shale development processes. Full article

Rain erosion is a critical issue for the development of wind power generation because it limits the lifetime of wind turbine blades. To clarify the erosion initiation mechanism in wind turbine blades of metallic material, pit formation and erosion initiation on a smooth wet wall of aluminum materials A3003 and annealed A5052 were investigated; water droplets were impinged on the wall using a pulsed-jet tester; and combined theoretical and numerical studies were performed by considering the influence of the water film on the wall. Although the theoretical and numerical impact pressures were much lower than the offset yield strength of the materials, random pit formation and erosion initiation were observed on the target material. To clarify the reason for this, the occurrence of cavitation erosion was investigated based on the numerical pressure distribution of a droplet impacting a wet wall. The numerical results showed that the pressures in the droplet center and water film became lower than the saturated vapor pressure, suggesting the occurrence of cavitation erosion. Furthermore, a similar pit formation and erosion initiation were observed on the wall material in the acoustic cavitation test under the cavitation erosion condition. These results indicate that the pit formation could have been caused by the high impact pressure caused by the micro-jet mechanism that occurs when a droplet impacts the wet wall. This could potentially explain the mechanism of the more severe erosion in the actual wind turbine blade than was expected. Full article

The configurational stability and mobilizable oil release behavior of a multiscale gel–particle cooperative nested system within tight sandstone pore structures were systematically investigated. Scanning electron microscopy (SEM), atomic force microscopy (AFM), and μCT-based three-dimensional reconstruction were employed to characterize the multiscale structural features of the system. Interfacial regulation behavior was analyzed using contact angle measurements, oil–water interfacial tension (IFT), and zeta potential tests, while core flooding experiments were conducted to evaluate seepage response and oil displacement performance. The results indicate that particle reinforcement transforms the gel pore walls from a weakly rough interface into a strongly rough and mechanically interlocked structure, with the root-mean-square surface roughness increasing from 23.6 nm to 71.4 nm. μCT quantitative analysis shows that the pore volume fraction increases from 38.6% to 52.4%, and the connectivity ratio rises from 41.2% to 68.5, leading to the formation of a more continuous pore–throat network. Interfacial property measurements reveal that the rock surface contact angle decreases from 116.3° to 60.5°, and the oil–water interfacial tension is reduced from 27 mN·m⁻¹ to 3–5 mN·m⁻¹. Meanwhile, the system–rock interface exhibits a stronger overall negative surface charge. During displacement experiments, the pressure differential at 3.0 pore volumes (PV) is only 17.0 kPa, significantly lower than that of the control gel (26.2 kPa). The oil recovery is increased to 44.8%, while the residual oil saturation decreases from 0.46 to 0.32, and the displacement efficiency improves from 36.1% to 55.6%. These results demonstrate that the multiscale gel–particle cooperative nested system establishes a stable, regulated seepage configuration in tight sandstone and enables sustained mobilization of trapped oil under relatively low-pressure gradients through the coupled regulation of wettability, interfacial tension, and interfacial electrostatics. This study elucidates a coupled mechanism of configurational stability–flow channel redistribution–continuous oil mobilization and provides a new material design and regulation strategy for efficient recovery of residual oil in tight reservoirs. Full article

Humic substances (HSs) pose a significant challenge to safe drinking-water production due to their ubiquity, limited removal by conventional methods, and their role in forming toxic disinfection by-products, reinforcing the need for more efficient, energy-favorable, and scalable treatment technologies. This study developed and evaluated a compact hydrodynamic cavitation (HC) system that simultaneously induces coagulation and generates microbubbles for flotation-based HS removal. For the first time, HC is explored as a multifunctional unit capable of integrating rapid mixing, coagulant destabilization, and flotation within a single device. Optimal coagulation conditions were established at pH 5.0 and 9.5 mg L⁻¹ of ferric chloride. Process optimization using a Rotated Central Composite Design demonstrated that inlet pressure, flotation time, and initial HS concentration were the dominant operational factors, enabling the HC system to achieve a maximum removal efficiency of 81.9%. Five Venturi geometries with divergent angles of 4°, 8°, 11°, 14°, and 90° were investigated, with the 8° Venturi exhibiting superior performance due to stable microbubble formation and effective coagulant dispersion, as confirmed by CFD analyses. Comparative tests with a conventional Flotest unit showed that achieving similar efficiencies required at least 30% saturated water. In contrast, the HC system delivered equivalent removal in continuous flow without external air saturation. These findings demonstrate the potential of HC as an integrated coagulation–flotation core and highlight its promise as a compact, energy-efficient, and scalable technology for natural organic matter removal in water treatment. Full article