Pore-to-core evaluation of silica nanofluid-assisted CO₂ storage using surrogate fluids in sandstone systems

Residual brine trapping and limited pore-scale accessibility are key factors that determine the efficiency of geological CO₂ storage in saline aquifers and depleted reservoirs. Nanofluid-assisted injection is considered a promising enhancement strategy. However, the mechanisms governing its use and scalability across different length scales remain unclear. This paper presents a pore-to-core experimental investigation that combines microfluidic visualization and core-flooding experiments using surrogate supercritical CO₂ (scCO₂) fluids and silica SiO₂ nanofluids in sandstones with contrasting permeability values under controlled wettability conditions. Microfluidic visualization experiments are conducted using a surrogate CO₂–brine system (Isopar M and a glycerol–water mixture) under ambient conditions. At the pore scale, despite negligible changes in the interfacial tension, nanofluid injection reduced trapped brine and increased the accessible pore volume by approximately 10% in strongly water-wet systems, indicating the importance of interfacial flow modification. In intermediate-wet systems, nanofluids further enhanced bypass trapping and the hysteresis-driven immobilization of surrogate scCO₂, leading to significant storage gains of up to 16%. These pore-scale trends were reflected at the core scale, where nanofluid-assisted injection resulted in a modest enhancement of 4% in high-permeability sandstone and a pronounced improvement of 22% in low-permeability cores, suggesting localized flow-path adjustment. Overall, the observed enhancement was driven by wettability and permeability, rather than a single mechanism. These findings are limited to controlled surrogate-fluid and ambient-condition experiments. The obtained insights can contribute to future work on high-pressure and high-temperature validation with real scCO₂ and formation brines.