A controllable particle size mono-dispersing nanofluid system has been developed to address the challenges of low porosity and low-permeability in low to ultra-low-permeability reservoirs. This system combines high dispersion stability with enhanced oil recovery performance, and its effectiveness in improving recovery rates in low-permeability reservoirs, where conventional chemical flooding is ineffective, has been well demonstrated. Using the in situ method to prepare monodispersed nano-silica particles, the effects of the water concentration, ammonia concentration, and silica precursor concentration on the morphology, particle size, and formation time of the silica spherical particles were analyzed. Building on this foundation, a partially hydrophobic modified nano-silica oil displacement fluid was synthesized in situ. The system’s dispersion stability, ability to reduce oil-water interfacial tension, and capacity to alter rock wettability were evaluated. Core physical models were used to evaluate the oil displacement efficiency and the permeability applicability limits of the self-dispersing nano-silica oil displacement system. The experiments confirmed that the particle size distribution of the self-dispersing nano-silica oil displacement system can be controlled within a range of 10 nm to 300 nm. The nanofluids exhibited excellent stability, effectively altering the rock wettability from oil-wet to water-wet and reducing the oil-water interfacial tension to approximately 10⁻¹ mN/m. The nano-displacement system increased the recovery rate of the low permeability reservoirs by more than 17%. The in situ modification method used to prepare these self-dispersing nanoparticles provides valuable insights for synergistic enhancement of recovery when combined with other systems, such as surfactants and CO₂. This approach also opens up new possibilities and drives further development in the field of nano-enhanced oil recovery chemistry.

High-gravity rotating packed beds enhance mass transfer via high-gravity fields, where the flow and viscosity distribution of polymer solutions govern dissolution efficiency and equipment compactness. Understanding these behaviors is essential for optimizing polymer dissolution in offshore polymer flooding, yet experimental methods are hindered by poor light transmittance and observational blind spots, making it difficult to capture the dynamic dispersion and evolution of polymer solutions within the wire mesh packing. To address this issue, a two-dimensional computational model was constructed by combining the VOF multiphase model with the Carreau–Yassuda viscosity model, accounting for the shear-thinning characteristics and viscosity variations of the polymer solution. The effects of zero-shear viscosity, rotational speed, and inlet velocity on flow morphology, aggregation, and apparent viscosity distribution were systematically examined. Results show the following: (1) Increasing rotational speed from 300 to 900 rpm promotes the transition from film-dominated to droplet-dominated flow, increasing zero-shear viscosity from 59 to 348 mPa·s suppresses dispersion and forms coexisting films and droplets, and increasing inlet velocity from 1.74 to 3.17 m/s drives the transition from droplet-dominated to film-dominated flow. (2) Increasing rotational speed reduces apparent viscosity by up to 30% and improves distribution uniformity, with a turning point near 1000 rpm; inlet velocity has limited effects, with radial distribution higher in the inner region. (3) The Carreau–Yassuda model reveals a shear-thinning effect, where high rotational speed mitigates the influence of high zero-shear viscosity, and the combination of high rotational speed and high inlet velocity synergistically enhances dispersion. These findings provide a theoretical basis for optimizing polymer dissolution in high-gravity carbon capture processes.

This study aims to investigate the interfacial tension, emulsion stability, and the impact on oil displacement effectiveness of mixed systems containing nonionic surfactants and amphoteric surfactants at different ratios. To achieve this, three different emulsion stability formulations were prepared by mixing betaine and nonionic surfactants in ratios of 1:1, 3:2, and 3:1 respectively. By adjusting the proportions of betaine and nonionic surfactants, variations in interfacial tension and emulsion formation among the three mixed systems were studied to analyze the mechanism of interaction between betaine and nonionic surfactants and evaluate their effects on crude oil displacement and enhanced oil recovery in reservoirs. Subsequently, microscopic and macroscopic oil displacement experiments were conducted on the three mixed systems, along with experiments on emulsion flow resistance. The aim was to verify the oil displacement effectiveness of different mixed systems and further understand their potential applications in reservoirs. By comprehensively analyzing the experimental results, optimal ratios and conditions for the mixed systems were determined. The experimental results indicate that the emulsification system formed by mixing betaine and nonionic surfactants at a ratio of 3:1 achieves molecular synergies through electrostatic interactions and mixed adsorption with betaine, resulting in a compact arrangement of interface membranes and demonstrating a synergistic effect in reducing interfacial tension to an ultra-low value of 10 -4 mN/m. Additionally, as the proportion of betaine surfactant increases, the viscosity of the aqueous phase liquid film increases, the rate of thinning of the liquid film slows down, the rate of water release slows down, and the stability of the emulsion increases. Microscopic oil displacement experiments verified that the three mixed systems increase oil washing efficiency through low interfacial tension and emulsification stripping action, thereby increasing the oil displacement mechanism's coefficient. Emulsion flow resistance experiments demonstrated that as the proportion of betaine surfactant increases, the system exhibits better plugging ability. However, macroscopic oil displacement experiments revealed differences in compatibility between different emulsion stability solutions and rocks with different permeabilities. The mixed system of betaine and nonionic surfactants at a ratio of 3:1 exhibits the best emulsification plugging ability in rocks with a permeability of 109mD, while the 1:1 mixed system performs best in rocks with a permeability of 12mD. This holds significant theoretical and practical significance for reservoir development and enhanced production.