Injecting CO2 into water-disposal wells is a promising strategy for geological carbon storage. However, this process can destabilize asphaltenes in residual oil blobs—primarily of the emulsified type – trapped within trapped in the porous rock, leading to precipitation that threatens storage integrity and operational safety. This study introduces a novel high-pressure laboratory apparatus and protocol designed to directly quantify asphaltene precipitation during CO2 injection into oil-in-water emulsions, which represent water-flooded formations. The system operates at reservoir-relevant conditions (up to 11,000 psi and 210 °C) and utilizes in situ near-infrared (NIR) light transmission to monitor asphaltene precipitation in real-time. Additionally, this research investigates the behavior of the oil-in-water emulsion (EM) phase as the medium hosting CO2 gas under different conditions. Quantitative results, expressed as the percentage reduction in NIR transmission, showed that asphaltene precipitation was minimized to 0.8% under optimal conditions (2DSW, 120 °C, 50 mol% CO2), compared to a peak of 25.1% in the worst-case scenario (FW, 30 °C, 35 mol% CO2). Regarding the CO2 injection rate, less asphaltene precipitation occurred at higher injection rates. In this case, crude oil vaporized in the EM phase at high CO2 injection rates (above 35 mol%), resulting in fewer crude oil droplets available to interact with CO2. Notably, EMs prepared with twice-diluted seawater (2DSW) exhibited the least asphaltene precipitation, a finding strongly correlated with lower oil/water interfacial tension. Overall, the developed protocol provides a critical tool for screening and de-risking CO2 storage sites in water-disposal zones by enabling accurate prediction of asphaltene-related damage.
