Search Results (150)

Low-salinity water flooding is a commonly used method to enhance oil recovery. At the microscopic scale, changes in pore structure and the distribution of remaining oil are critical to the effectiveness of water flooding. However, current research on the relationship between pore structure and remaining oil distribution is relatively limited. Therefore, this study employed micro-CT technology to analyze changes in pore structure and the distribution characteristics of remaining oil in sandstone cores during the water flooding process. Micron CT technology provides non-destructive, high-resolution three-dimensional imaging, clearly revealing the dynamic changes in the oil-water interface and remaining oil. The experiments included water saturation, oil saturation, and multi-stage water displacement processes in sandstone cores with different permeability values. The results show that the oil saturation in the rock core decreases during water flooding, and the morphology of remaining oil changes with increasing water flooding volume: cluster-like remaining oil decreases rapidly, while porous and membrane-like remaining oil gradually transforms, and columnar and droplet-like remaining oil increases under specific conditions. The study results indicate that at 1 PV flooding volume, the crude oil recovery rate reaches 57.56%; at 5 PV, the recovery rate increases to 64.00%; and at 100 PV, the recovery rate reaches 75.53%. This indicates that water flooding significantly improves recovery rates by enhancing wettability and capillary forces. Meanwhile, pore connectivity decreases, and particle migration becomes prominent, especially for particles smaller than 20 μm. These changes have significant impacts on remaining oil distribution and recovery rates. This study provides microscopic evidence for optimizing reservoir development strategies and holds important implications for enhancing recovery rates in mature oilfields. Full article

During water flooding processes, the high viscosity of heavy oil and significant reservoir heterogeneity often lead to severe water channeling and low sweep efficiency. Addressing the limitations of traditional hydrophobically associating polymer-based profile-control agents—such as significant adsorption loss, mechanical degradation during reservoir migration, resulting in a limited effective radius and short functional duration—this study developed a polymeric graded profile-control agent suitable for highly heterogeneous conditions. The physicochemical properties of the system were comprehensively evaluated through systematic testing of its apparent viscosity, salt tolerance, and anti-aging performance. The microscopic oil displacement mechanisms in porous media were elucidated by combining CT scanning and microfluidic visual displacement experiments. Experimental results indicate that the agent exhibits significant hydrophobic association behavior, with a critical association concentration of 1370 mg·L⁻¹, and demonstrates a “low viscosity at low temperature, high viscosity at high temperature” rheological characteristic. At a concentration of 3000 mg·L⁻¹, the apparent viscosity of the solution is 348 mPa·s at 30 °C, rising significantly to 1221 mPa·s at 70 °C. It possesses a salinity tolerance of up to 50,000 mg·L⁻¹, and a viscosity retention rate of 95.4% after 90 days of high-temperature aging, indicating good injectivity, reservoir compatibility, and thermal stability. Furthermore, within a concentration range of 500–3000 mg·L⁻¹, the agent can effectively emulsify Gudao heavy oil, forming O/W emulsion droplets with sizes ranging from 40 to 80 μm, enabling effective plugging of pore throats of corresponding sizes. CT scanning and microfluidic displacement experiments further reveal that the agent possesses a graded control function: in the near-wellbore high-concentration zone, it primarily relies on its aqueous phase viscosity-increasing capability to control the mobility ratio; upon entering the deep reservoir low-concentration zone, it utilizes “emulsion plugging” to achieve fluid diversion, thereby expanding the sweep volume and extending the effective treatment period. This research outcome provides a new technical pathway for the efficient development of highly heterogeneous heavy oil reservoirs. Full article

Long-term water flooding development has exacerbated reservoir heterogeneity, and traditional polymer gels are unable to simultaneously meet the requirements of high injectability and strong plugging strength. If the viscosity of the polymer is high, its injectability will be poor; on the contrary the viscosity is low, the plugging strength will be poor, which severely restricts the oil recovery effect. This study synthesized an NBAP through free radical polymerization followed by a substitution reaction, and a plugging system (NBAP-B1) was subsequently formed by combining the polymer with a Cr³⁺ crosslinking agent. Rheological experiments demonstrated that the system exhibited significant shear thinning behavior, as well as excellent temperature and salt resistance. Gelation experiments indicated that the NBAP-B1 system featured controllable gelation time (20~150 h) and high gelation strength (J grade), along with excellent resistance to both high temperature and high salinity. Microscopic analysis revealed that the gel formed by NBAP-B1 possessed a dense and uniform three-dimensional network structure. Injection and plugging experiments demonstrated that NBAP-B1 exhibited optimal injectability and outstanding plugging performance. Additionally, profile control and displacement tests revealed a 18.37% enhancement in oil recovery efficiency by water flooding after the application of NBAP-B1 for conformance control. Collectively, these results demonstrate that the NBAP exhibits significantly superior performance compared to single component systems. It combines excellent injectability with high strength plugging capability, offering an effective approach for enhancing oil recovery in low permeability reservoirs. Full article

In low-permeability reservoirs, studying reservoir sensitivity is crucial for optimizing water flooding, as it identifies detrimental mineral-fluid interactions that can cause formation damage and reduce injection efficiency. However, existing diagnostic methods for sensitivity-induced damage rely on post-facto pressure monitoring and lack a quantitative relationship between sensitivity factors and water injectivity impairment. Furthermore, correlating microscale interactions with macroscopic injectivity parameters remains challenging, causing current models to inadequately represent actual injection behavior. This study combines microscopic techniques (e.g., SEM, XRD, NMR) with macroscopic core flooding experiments under various sensitivity-inducing conditions to analyze the influence of reservoir mineral composition on flow capacity, evaluate formation sensitivity, and assess the dynamic impact on water injectivity. The quantitative relationship between clay minerals and injectivity impairment in low-permeability reservoirs is also investigated. The results indicate that flow capacity is predominantly governed by the type and content of sensitive minerals. In water-sensitive reservoirs, water injection induces clay swelling and migration, leading to flow path reconfiguration and water-blocking effects. In salt-sensitive formations, high-salinity water promotes salt precipitation within pore throats, reducing permeability. In velocity-sensitive formations, fine particle migration causes flow resistance to initially increase slightly and then gradually decline with continued injection. Acidizing generally enhances pore connectivity but induces pore-throat plugging in chlorite-rich reservoirs. Alkaline fluids can exacerbate heterogeneity and generate precipitates, though appropriate concentrations may improve connectivity. Under low effective stress, rock dilation increases porosity and permeability, while elevated stress causes compaction, increasing flow impedance. Full article

This study investigates groundwater salinization in a section of a coastal aquifer in Rio Grande do Norte, Brazil, using frequency-domain electromagnetic (FDEM) measurements. With the global expansion of shrimp farming in ecologically sensitive coastal regions, there is an urgent need to assess associated risks and promote sustainable management practices. A key concern is the prolonged flooding of shrimp ponds, which accelerates saltwater infiltration into surrounding areas. To better delineate salinization plumes, we analyzed direct groundwater salinity measurements from 14 wells combined with 315 subsurface apparent conductivity measurements obtained using the FDEM method. Correlating these datasets improved the accuracy of salinity mapping, as evidenced by reduced variance in kriging interpolation. By integrating hydrogeological, hydrogeochemical, and geophysical approaches, this study provides a comprehensive characterization of groundwater salinity in the study area. Hydrogeological investigations delineated aquifer properties and flow dynamics; hydrogeochemical analyses identified salinity levels and water quality indicators; and geophysical surveys provided spatially extensive conductivity measurements essential for detecting and mapping saline intrusions. The combined insights from these methodologies enable a more precise assessment of salinity sources and support the development of more effective groundwater management strategies. Our findings demonstrate the effectiveness of integrating geophysical surveys with hydrogeological and hydrogeochemical data, confirming that shrimp farm ponds are a significant source of groundwater contamination. This combined methodology offers a low-impact, cost-effective approach that can be applied to other coastal regions facing similar environmental challenges. Full article

Low-Salinity Water Flooding (LSWF) has gained attention for its cost-effectiveness and environmental advantages, yet its underlying mechanisms remain not fully understood. Oil recovery in LSWF is primarily governed by interfacial dynamics and formation wettability. This research investigates the effects of seawater dilution in carbonate reservoirs through laboratory analyses and displacement experiments. Results show that oil recovery efficiency is largely driven by rock–fluid interactions rather than fluid–fluid interactions, with optimal brine concentrations enhancing wettability alteration, boundary flexibility, and mineral leaching. These findings highlight the importance of considering both fluid–rock interactions and mineral reactivity, rather than attributing recovery to a single mechanism. Molecular dynamics simulations further supported the experimental observations. Overall, the study emphasizes that early and well-designed low-salinity injection strategies can maximize LSWF performance. The results elucidate the key interaction mechanisms between surfactants and the various components of heavy oil through atomic-scale precision modeling and dynamic process tracking. These simulations clarify, at the microscopic level, the differences in displacement dynamics and efficiency of organic solvent systems toward different hydrocarbon components. Full article

Temperature is a key factor in regulating interfacial behaviors and enhancing oil recovery during low-salinity water flooding in tight sandstone reservoirs. This study systematically investigates the synergistic mechanisms of temperature and salinity on ion exchange, wettability alteration, interfacial tension, and crude oil desorption. The experimental results show that elevated temperature significantly strengthens the oil–water–rock interactions induced by low-salinity water, thereby improving oil recovery. At 70 °C, the release of divalent cations such as Ca²⁺ and Mg²⁺ from the rock surface is notably enhanced. Simultaneously, the increase in interfacial electrostatic repulsion is evidenced by a shift in the rock–brine zeta potential from −3.14 mV to −6.26 mV. This promotes the desorption of polar components, such as asphaltenes, from the rock surface, leading to a significant change in wettability. The wettability alteration index increases to 0.4647, indicating a strong water-wet condition. Additionally, the reduction in oil–water interfacial zeta potential and the enhancement in interfacial viscoelasticity contribute to a further decrease in interfacial tension. Under conditions of 0.6 PW salinity and 70 °C, non-isothermal core flooding experiments demonstrate that rock–fluid interactions are the dominant mechanism responsible for enhanced oil recovery. By applying a staged injection strategy, where 0.6 PW is followed by 0.4 PW, the oil recovery reaches 34.89%, which is significantly higher than that achieved with high-salinity water flooding. This study provides critical mechanistic insights and optimized injection strategies for the development of high-temperature tight sandstone reservoirs using low-temperature waterflooding. Full article

A CO₂-responsive TMPDA–SDS–SiO₂ gel system was developed and evaluated through formulation optimization, structural characterization, rheological testing, and core flooding experiments. The optimal formulation was identified as 7.39 wt% SDS, 1.69 wt% TMPDA, and 0.1 wt% SiO₂, achieving post-CO₂ viscosities above 10³–10⁴ mPa·s. Spectroscopic and microscopic analyses confirmed that CO₂ protonates TMPDA amine groups to form carbamate/bicarbonate species, which drive the micellar transformation into a wormlike network, thereby enhancing gelation and viscosity. Rheological tests showed severe shear-thinning behavior, excellent shear recovery, and reversible viscosity changes under alternating CO₂/N₂ injection. The gel demonstrated rapid responsiveness, reaching stable viscosities within 8 min, and maintained good performance after 60 days of thermal aging at 90 °C and in high-salinity brines. Plugging tests in sand-packed tubes revealed that a permeability reduction of 98.9% could be achieved at 0.15 PV injection. In heterogeneous parallel core flooding experiments, the gel preferentially reduced high-permeability channel conductivity, improved sweep efficiency in low-permeability zones, and increased incremental oil recovery by 14.28–34.38% depending on the permeability contrast. These findings indicate that the CO₂-responsive TMPDA–SDS–SiO₂ gel system offers promising potential as a novel smart blocking gel system for improving the effectiveness of CO₂ flooding in heterogeneous reservoirs. Full article

Low-salinity waterflooding (LSWF) enhances oil recovery at low cost in carbonate reservoirs, but its effectiveness requires the precise control of injected water chemistry and interaction with reservoir minerals. This study specifically investigates carbonated low-salinity waterflooding (CLSWF), where dissolved ${\mathrm{CO}}_2$ modulates geochemical processes. This study develops an integrated transport model coupling geochemical surface complexation modeling (SCM) with multiphase compositional dynamics to quantify wettability alteration during CLSWF. The framework combines PHREEQC-based equilibrium calculations of the Total Bond Product (TBP)—a wettability indicator derived from oil–calcite ionic bridging—with Corey-type relative permeability interpolation, resolved via COMSOL Multiphysics. Core flooding simulations, compared with experimental data from calcite systems at 100 ${}^{\circ }\mathrm{C}$ and 220 bar, reveal that magnesium ([${\mathrm{Mg}}^{2+}$]) and sulfate ([${\mathrm{SO}}_4^{2-}$]) concentrations modulate the TBP, reducing oil–rock adhesion under controlled low-salinity conditions. Parametric analysis demonstrates that acidic crude oils (TAN higher than 1 $\mathrm{m}$$\mathrm{g}$ KOH/$\mathrm{g}$) exhibit TBP values approximately $2.5 \mathrm{times}$ higher than those of sweet crudes, due to carboxylate–calcite bridging, while pH elevation (higher than 7.5) amplifies wettability shifts by promoting deprotonated ${\mathrm{-COO}}^{-}$ interactions. The model further identifies synergistic effects between ([${\mathrm{Mg}}^{2+}$]) (ranging from 50 to 200 mmol/kgw) and ([${\mathrm{SO}}_4^{2-}$]) (higher than 500 mmol/kgw), which reduce (${\mathrm{Ca}}^{2+}$)-mediated oil adhesion through competitive mineral surface binding. By correlating TBP with fractional flow dynamics, this framework could support the optimization of injection strategies in carbonate reservoirs, suggesting that ion-specific adjustments are more effective than bulk salinity reduction. Full article

To address the issues of poor thermal stability, inadequate salt tolerance, and environmental risks in conventional gel systems for the development of high-temperature, high-salinity heterogeneous reservoirs, a triple-synergy gel system comprising anionic polyacrylamide (APAM), polyethyleneimine (PEI), and phenolic resin (SMP) was developed in this study. The optimal synthesis parameters—APAM of 180 mg/L, PEI:SMP = 3:1, salinity of 150,000 ppm, and temperature of 110 °C—were determined via response surface methodology, and a time–viscosity model was established. Compared with existing binary systems, the proposed gel exhibited a mass retention rate of 93.48% at 110 °C, a uniform porous structure (pore size of 2–8 μm), and structural stability under high salinity (150,000 ppm). Nuclear magnetic resonance displacement tests showed that the utilization efficiency of crude oil in 0.1–1 μm micropores increased to 21.32%. Parallel dual-core flooding experiments further confirmed the selective plugging capability in heterogeneous systems with a permeability contrast of 10:1: The high-permeability layer (500 mD) achieved a plugging rate of 98.7%, while the recovery factor of the low-permeability layer increased by 13.6%. This gel system provides a green and efficient profile control solution for deep, high-temperature, high-salinity reservoirs. Full article

Waterflooding, a key method for secondary hydrocarbon recovery, has been employed since the early 20th century. Over time, the role of water chemistry and ions in recovery has been studied extensively. Low-salinity water (LSW) injection, a common technique since the 1930s, improves oil recovery by altering the wettability of reservoir rocks and reducing residual oil saturation. Recent developments emphasize the integration of LSW with various recovery methods such as CO₂ injections, surfactants, alkali, polymers, and nanoparticles (NPs). This article offers a comprehensive perspective on how LSW injection is combined with these enhanced oil recovery (EOR) techniques, with a focus on improving oil displacement and recovery efficiency. Surfactants enhance the effectiveness of LSW by lowering interfacial tension (IFT) and improving wettability, while ASP flooding helps reduce surfactant loss and promotes in situ soap formation. Polymer injections boost oil recovery by increasing fluid viscosity and improving sweep efficiency. Nevertheless, challenges such as fine migration and unstable flow persist, requiring additional optimization. The combination of LSW with nanoparticles has shown potential in modifying wettability, adjusting viscosity, and stabilizing emulsions through careful concentration management to prevent or reduce formation damage. Finally, building on discussions around the underlying mechanisms involved in improved oil recovery and the challenges associated with each approach, this article highlights their prospects for future research and field implementation. By combining LSW with advanced EOR techniques, the oil industry can improve recovery efficiency while addressing both environmental and operational challenges. Full article

Urban estuarine environments face increasing water safety risks due to microbial contamination from combined sewer overflows (CSOs), particularly during heavy rainfall events. In megacities like Tokyo, where waterfronts are widely used for recreation, such contamination poses significant public health risks. The challenge is compounded by the variability in both intensity and spatial distribution of rainfall across the catchment, combined with complex tidal dynamics making effective water quality management difficult. To address this challenge, we conducted a series of hydrodynamic–microbial fate simulations to examine the spatial and vertical behavior of Escherichia coli (E. coli) under different rainfall–tide conditions. Focusing on the Sumida River estuary, rainfall data from eight drainage areas were classified into six event types using cluster analysis. Two contrasting events were selected for detailed analysis: a light rainfall (G2, 15 mm over 13 h) and an intense event (G6, 272 mm over 34 h). Vertical water quality profiling was performed along an 8.5 km transect from the Kanda–Sumida River confluence to the Tokyo Bay Tunnel, illustrating E. coli and salinity. The results showed that the rainfall intensity and tidal phase at the event onset are critical in shaping both the magnitude and vertical distribution of microbial contamination. The intense event (G6) led to deep microbial intrusion (up to 6–7 m) and major salinity disruption, while the lighter event (G2) showed surface-layer confinement. Salinity gradients were more strongly affected during G6, indicating freshwater intrusion. Tidal phase also influenced transport: the flood-high condition retained E. coli, whereas ebb-low tides facilitated downstream flushing. These findings highlight the influence of rainfall intensity and tidal timing on microbial distribution and support the use of vertical profiling in estuarine water quality management. They also support the development of dynamic, event-based water quality risk assessment tools. With appropriate local calibration, the modeling framework is transferable to other urban estuarine systems to support proactive and adaptive water quality management. Full article

As conventional waterflooding enters mid-to-late stages, chemical enhanced oil recovery (EOR) technologies such as polymer–surfactant binary flooding have emerged to address declining recovery rates. This study systematically investigates the synergistic effects of polymer–surfactant binary formulations through core-flooding experiments under varying concentrations, injection volumes, and salinity conditions. The optimal formulation, identified as 0.5% surfactant and 0.15% polymer, achieves a maximum incremental oil recovery of 42.19% with an interfacial tension (IFT) reduction to 0.007 mN/m. A 0.5 pore volume (PV) injection volume balances sweep efficiency and economic viability, while sequential slug design with surfactant concentration gradients demonstrates superior displacement efficacy compared with fixed-concentration injection. Salinity sensitivity analysis reveals that high total dissolved solids (TDS) significantly degrade viscosity, whereas low TDS leads to higher viscosity but only marginally enhances the recovery. These findings provide experimental evidence for optimizing polymer–surfactant flooding strategies in field applications, offering insights into balancing viscosity control, interfacial tension reduction, and operational feasibility. Full article

Soil saline–alkaline stress and water stress, exacerbated by anthropogenic activities and climate change, are major drivers of wetland vegetation degradation, severely affecting the function of wetland ecosystems. In this study, we conducted a simulation experiment with three water levels and four saline–alkaline concentration levels as stress factors to assess eight key functional traits of Phragmites australis and Bolboschoenus planiculmis, dominant species in the salt marsh wetlands in the western region of Jilin province, China. The study aimed to evaluate how these factors influence the functional traits of P. australis and B. planiculmis. Our results showed that the leaf area, root biomass, and clonal biomass of P. australis significantly increased, and the leaf area of B. planiculmis significantly decreased under low and medium saline–alkaline concentration treatments, while the plant height, ramet number, and aboveground biomass of P. australis and the root biomass, clonal biomass, and clonal/belowground biomass ratio of B. planiculmis were significantly reduced and the ratio of belowground to aboveground biomass of B. planiculmis significantly increased under high saline–alkaline concentration treatment. The combination of drought conditions with medium and high saline–alkaline treatments significantly reduced leaf area, ramet number, and clonal biomass in both species. The interaction between flooding water level and medium and high saline–alkaline treatments significantly suppressed the plant height, root biomass, and aboveground biomass of both species, with the number of ramets having the greatest contribution. These findings suggest that the effects of water levels and saline–alkaline stress on the functional traits of P. australis and B. planiculmis are species-specific, and the ramet number–plant height–root biomass (RHR) strategy may serve as an adaptive mechanism for wetland clones to environmental changes. This strategy could be useful for predicting plant productivity in saline–alkaline wetlands. Full article

In the development of high-temperature and high-salinity oil fields, biopolymer scleroglucan flooding technology faces significant challenges. Traditional scleroglucan products exhibit poor injectability and high extraction costs. This study investigated the application potential of the original fermentation broth of exopolysaccharides (EPS) produced by microorganisms in a simulated high-temperature and high-salinity oil reservoir environment. The polysaccharide was identified as scleroglucan through IR and NMR analysis. Its stability and rheological properties were comprehensively evaluated under extreme conditions, including temperatures up to 150 °C, pH levels ranging from 1 to 13, and salinities up to 22 × 10⁴ mg/L. The results demonstrated that EPS maintained excellent viscosity and stability, particularly at 76.6 °C and 22 × 10⁴ mg/L salinity, where its viscosity remained above 80% for 35 days. This highlights its significant viscoelasticity and stability in high-temperature and high-salinity oil reservoirs. Additionally, this study, for the first time, examined the rheological properties of the original fermentation broth of scleroglucan, specifically assessing its injectability and enhanced oil recovery (EOR) performance in a simulated Middle Eastern high-temperature, high-salinity, medium-low permeability reservoir environment. The findings revealed an effective EOR exceeding 15%, confirming the feasibility of using the original fermentation broth as a biopolymer for enhancing oil recovery in extreme reservoir conditions. Based on these experimental results, it is concluded that the original fermentation broth of Athelia rolfsii exhibits superior performance under high-temperature and high-salinity conditions in medium–low permeability reservoirs, offering a promising strategy for future biopolymer flooding in oil field development. Full article