Foam has been successfully used to improve mobility control in the process of enhanced oil recovery, yet the instability of foam limits its application. Modified nanoparticles with varying wettability were prepared by reacting 3-methacryloxypropyltrimethoxysilane (KH570) with spherical SiO₂ nanoparticles in this study. Fourier transform infrared (FTIR) spectra and the measured contact angles were used to characterize the surface properties of the modified SiO₂ particles, and the foam stabilization effects of wettability SiO₂ were compared. Pore-scale visualization experiments were conducted using a 2D micromodel to identify the prevailing enhanced oil recovery (EOR) mechanisms of modified nano SiO₂-Sodium alpha-olefin Sulfonate (AOS) foam flooding. The results indicate that modified SiO₂ effectively improves foam stability by adsorbing on the bubble surface and forming a mesh-like structure. The optimum contact angle of the particles is approximately 60°, resulting in a significant increase in drainage half-life by 29.4% compared to foam stabilized only by AOS. Additionally, Foam stabilized by modified SiO₂ demonstrates superior dynamic stability and deformation resistance. The modified SiO₂ stabilized foam exhibits enhanced interfacial viscoelasticity and plugging and profile control performance, surpassing AOS foam in displacing more residual oil in dead-end pores. The oil recovery of the micro model was determined by ImageJ software. KH570@SiO₂ (0.2wt%)-AOS (0.2wt%) foam flooding increased the recovery by 8.7% compared to AOS (0.2wt%) foam flooding.

Xtacking™ is a novel 3D (three-dimensional) NAND flash architecture, in which memory cells and peripheral circuits are bonded by millions of pairs of small-pitch metal vias. Consequently, its bonding interface reliability attracts great interest. In this paper, we conducted reliability test of Xtacking™ bonding interface in both test structure level and product level. In test structure level reliability test, the bonding layer showed stable electrical properties and bonding interface after ultra-long time thermal or humidity stress (e.g., 7000hrs), which is much longer than common industry requirement (e.g., 1000hrs). Furthermore, the double cantilever beam test following long time temperature cycling and package level electromigration test also demonstrated good strength and stability of bonding interface. In product level reliability test, no function failure or scanning acoustic microscope image abnormality was observed after thermal or humidity stress, which further proves the excellent reliability of the bonding interface in actual product. Thus Xtacking ™ architecture achieved robust and reliable bonding interface with millions of pairs of small-pitch metal vias.

Na₂CO₃ was used together with surfactant and polymer to form the Alkaline/Surfactant/Polymer (ASP) flooding system. Interfacial tension (IFT) and emulsification of Dagang oil and chemical solutions were studied in the paper. The experiment results show that the ASP system can form super-low interfacial tension with crude oil and emulsified phase. The stability of the emulsion is enhanced by the Na₂CO₃, surfactant, and the soap generated at oil/water contact. Six core flooding experiments are conducted in order to investigate the influence of Na₂CO₃ concentration on oil recovery. The results show the maximum oil recovery can be obtained with 0.3 wt% surfactant, 0.6 wt% Na₂CO₃, and 2000 mg/L polymer. In a heterogeneous reservoir, the ASP flooding could not enhance the oil recovery by reducing IFT until it reaches the critical viscosity, which indicates expanding the sweep volume is the premise for reducing IFT to enhance oil recovery. Reducing or removing the alkali from ASP system to achieve high viscosity will reduce oil recovery because of the declination of oil displacement efficiency. Weak base ASP alkali can ensure that the whole system with sufficient viscosity can start the medium and low permeability layers and enhance oil recovery even if the IFT only reaches 10⁻² mN/m.

This study aims to analyze the influence of viscosity and interfacial tension (IFT) on the recovery in heterogeneous reservoir and determines the main controlling factors of the polymer-surfactant (SP) flooding. The influence of the salinity and shearing action on the polymer viscosity and effects of the surfactant concentration on the IFT and emulsion behavior between chemical agent and oil were studied through the static and flooding experiments. The results show that increasing the concentration of polymer GF-11 (HPAM) can reduce the influence of the salinity and GF-11 has high shear-resistance property. In the condition of the Jilin Oilfield, the oil/water IFT can reach 10⁻³ mN/m when the surfactant concentration is 0.3 wt%. The lower the IFT is, the easier the emulsion of SP and oil is formed. Seven flooding experiments are conducted with the SP system. The results show that the recovery can be improved for 5.02%–15.98% under the synergistic effect of the polymer and surfactant. In the heterogeneous reservoir, the contribution of oil recovery is less than that of the sweep volume.

Nanoparticles (NPs) have shown great potential in stabilizing foam for enhanced oil recovery (EOR). However, conventional NPs are difficult to recover and may contaminate produced oil, increasing operational costs. In contrast, superparamagnetic Fe₃O₄ NPs can be efficiently recovered using external magnetic fields, offering a sustainable solution for foam stabilization. In this study, Fe₃O₄ NPs were coated with SiO₂ using tetraethyl orthosilicate (TEOS) and further modified with dodecyltrimethoxysilane to enhance their hydrophobicity. The modification effects were characterized, and the optimal foam-stabilizing Fe₃O₄@SiO₂ NPs were found to have a contact angle of 77.01°. The foam system formed with α-olefin sulfonate (0.2 wt%) as the foaming agent and the optimal modified NPs exhibited a drainage half-life of 452 s. After foam-stabilization experiments, the NPs were recovered and reused, with the results indicating that three recovery cycles were optimal. Finally, visual microscopic displacement experiments demonstrated that the foam stabilized by modified NPs effectively mobilized clustered, membranous, and dead-end residual oil, increasing the recovery rate by 17.01% compared with unmodified NPs. This study identifies key areas for future investigation into the application of magnetic nanoparticles for enhanced oil recovery.

Structures of pore-throat and permeability alteration caused by precipitation and the dissolution of rock matrix are serious problems during CO₂ flooding into reservoirs for enhanced oil recovery (EOR). Experiments were conducted under pressure boost and reduction conditions, which simulate CO₂-brine scaling in different parts of the reservoir during CO₂ flooding. And experiments on the dissolution and scaling of CO₂-brine-rock were carried out. The results show that the pH of brine with CO₂ under high pressure is small, and no precipitation is formed, so there is no precipitation generated near the gas injection well. Pressure drops sharply near the production well, CO₂ dissolved in the formation fluid escapes in large quantities, pH increases, carbonate precipitates are generated, so inorganic scale is formed near the production well. The increase of permeability of core saturated high scale-forming ions is smaller than that of saturated no scale-forming ions brine after CO₂ flooding. The accumulation and attachment of salt crystals were found in some large pores of the core with scale-forming ions water after CO₂ flooding. The ratio of medium size pores decreased, while that of large and small pores increases, and the pore radius distribution differentiates toward polarization.