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.

The adsorption of polymer microspheres in a stratum can directly affect its action mode and performance in the actual application process. Understanding the adsorption pattern of polymer microspheres and their adsorption mechanism can facilitate optimization of the application mode and enhance the use efficiency. Ultraviolet spectrophotometry was employed to measure the static adsorption characteristics of polymer microspheres (PMS) on the surface of quartz sand. The PMS adsorption capacity on the surface of quartz sand increased with increasing concentration. When the concentration was 1000 mg/L, the static equilibrium adsorption capacity was 402 μg/g, and monolayer adsorption was dominant. The effect of the contact time on the adsorption was investigated, and the fitting was performed using the isothermal adsorption thermodynamic equilibrium model and the adsorption kinetic model. The adsorption of 800 mg/L PMS tended to equilibrate after 0.8 h of adsorption on the surface of quartz sand, and the adsorption of 1400 mg/L PMS tended to equilibrate after 1 h of adsorption on the surface of quartz sand. Good fitting results of the kinetic adsorption process were obtained using the pseudo-first-order (PFO) model, pseudo-second-order (PSO) model, Elovich model, and mixed-order (MO) model. The effects of the temperature, particle size of the quartz sand, solid–liquid ratio, and salinity on the adsorption of PMS on the surface of quartz sand were examined. The PMS adsorption capacity on the surface of quartz sand decreased with increasing environmental temperature. The adsorption of PMS at the solid–liquid interface was an exothermic process, and the enthalpy of adsorption was negative. As the mass of the quartz sand in the solid–liquid ratio increased, the adsorption capacity decreased; a low salinity and neutral pH were conducive to the adsorption of PMS on the surface of quartz sand.

In the field of enhanced oil recovery in low-permeability reservoirs, the application of nanomaterials has attracted widespread attention. However, conventional nanomaterials exhibit issues such as large particle size and poor dispersion stability. This study selected SiO₂ nanoparticles with a particle size of 10 nm and combined them with 12 types of commonly used oilfield surfactants. After aging at 120 °C for 48 h, using dispersion stability and interfacial tension (IFT) as evaluation criteria, hexadecyltrimethylammonium bromide (CTAB) was ultimately identified as the optimal modifier. The structure and morphology of the SiO₂ particles were characterized in detail using X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FT-IR), and transmission electron microscopy (TEM). The system evaluated the dispersion stability of nanofluids before and after modification, as well as the interfacial properties (IFT reduced to the 10⁻¹ mN/m range) and wettability (oil-wet surfaces reversed to strongly water-wet, with contact angles decreasing to 30°) of nanofluids with different modification degrees. Considering economic factors, the modified nano-SiO₂ system with a ratio of 1:0.5 was selected. Microvisualization experiments revealed that the modified nanoscale system achieves residual oil displacement through three mechanisms: emulsification (reducing residual oil droplet size to enhance mobility), wetting reversal (lowering contact angle to weaken adhesion), and structural separation pressure (counteracting capillary forces to destabilize residual oil). Displacement experiments reveal that in rock cores with permeability ranging from 1 to 100 mD, the modified system exhibits a recovery rate trend that initially increases and then decreases. Nevertheless, it consistently enhances recovery rates, maintaining them above 12%, demonstrating strong application potential.

Large-scale volumetric fracturing is generally used during shale gas development. The return rate of fracturing fluid is low, and a large amount of slickwater is retained in the reservoir. The adsorption and desorption of partially hydrolyzed polyacrylamide (HPAM), an additive commonly used in slickwater, on the surface of shale was studied using Longmaxi shale from the Sichuan Basin. The experimental results showed that the mass ratio of the HPAM solution to shale reached saturation adsorption at 20:1 when the concentration of HPAM solution was 1000 mg/L and 25:1 when the concentration of HPAM solution was 500 mg/L. The mass ratio of the HPAM solution to shale was fixed at 25:1, and the adsorption equilibrium was reached at a HPAM concentration of 1000 mg/L when the aqueous solution temperature was 30 °C and 800 mg/L when the aqueous solution temperature was 60 °C. The Langmuir adsorption model yielded a better fit than the Freundlich adsorption model. The adsorption equilibrium time at 30 °C was at 60 min for a HPAM concentration of 500 mg/L, while for a concentration of 1000 mg/L, it was at 90 min. The adsorption equilibrium time at 60 °C was 40 min for a HPAM concentration of 500 mg/L, whereas it was 60 min for a HPAM concentration at 1000 mg/L. The pseudo-second order (PSO) kinetics model yielded better fits than the pseudo-first order (PFO) kinetics model. The adsorption of HPAM on shale was strong, and the adsorbed HPAM resembled cobwebs adhering to the shale surface. HPAM on the surface of shale after adsorption was able to resist the desorption capacity of water. However, when the amount of adsorbed HPAM on shale increased significantly, the amount of residual HPAM on the surface of the shale decreased rapidly during desorption in deionized water. The desorption of HPAM on the shale surface followed a modified desorption model. The higher the concentration of HPAM adsorbed on the shale surface was, the easier it was to desorb and the easier it was to be removed from the shale.

Large-scale volumetric fracturing is generally used during shale gas development. The return rate of fracturing fluid is low, and a large amount of slickwater will be retained in the reservoir. The adsorption and desorption of partially hydrolyzed polyacrylamide (HPAM), an additive commonly used in slickwater, on the surface of shale was studied using Longmaxi Shale from the Sichuan Basin. The experimental results showed that the mass ratio of the HPAM solution to shale reached saturation adsorption at 20:1 when the concentration of HPAM solution was 1000 mg/L and 25:1 when the concentration of HPAM solution was 500 mg/L. The mass ratio of the HPAM solution to shale was fixed at 25:1, and the adsorption equilibrium was reached at a HPAM concentration of 1000 mg/L when the aqueous solution temperature was 30°C and 800 mg/L when the aqueous solution temperature was 60°C. The Langmuir adsorption model yielded a better fit than the Freundlich adsorption model. The adsorption equilibrium time at 30°C was at 60 min for a HPAM concentration of 500 mg/L, while for a concentration of 1000 mg/L, it was at 90 min. The adsorption equilibrium time at 60°C was 40 min for a HPAM concentration of 500 mg/L, whereas it was 60 min for a HPAM concentration at 1000 mg/L. The pseudo-second order kinetics model yielded better fits than the pseudo-first order kinetics model. The adsorption of HPAM on shale was strong, and the adsorbed HPAM resembled cobwebs adhering to the shale surface. HPAM on the surface of shale after adsorption could resist the desorption capacity of water. However, when the amount of adsorbed HPAM on shale increased significantly, the amount of residual HPAM on the surface of the shale decreased rapidly during desorption in deionized water. The desorption of HPAM on the shale surface followed a modified desorption model. The higher the concentration of HPAM adsorbed on the shale surface was, the easier it was to desorb, the easier it was to be removed from the shale.