CO2–water–rock reaction transport via simulation study of nanoparticles-CO2 flooding and storage

Abstract

Carbon dioxide (CO2) sequestration for sustainable enhanced oil recovery and reducing greenhouse gas emissions, still faces various challenges. The process performance can improve via injection of nanoparticles into CO2 (NPs-CO2). However, the migration laws of the mixed NPs-CO2 fluid in the reservoir condition, while experiencing a chemical reaction, are still unclear. In this study, a mass transfer model of NPs-CO2 nanofluid is established by combining the migration law of NPs-CO2 fluid and the micro-pore structure change of porous media under CO2–water–rock reaction conditions. Numerical simulation was performed to analyze the CO2 and reservoir formation geochemical reaction via three-dimensional stratigraphic model. Also, the influence of rock microstructure heterogeneity on migration of NPs-CO2 brine fluid and the miscibility were investigated. The physical properties of reservoir were improved as the porosity of the rock increased from 6.43% to 25.84% after 100 years. It was also noted that the average permeability (from 0.013 mD to 0.017 mD) was directly proportional to porosity at various reservoir locations. Results also indicated that due to the CO2–water–rock reaction, porosity, permeability, heterogeneity of the reservoir was generally increasing, which lead to selective migration of NPs-CO2. The local accumulation of NPs-CO2 in detached pores will slightly weaken the original oil displacement efficiency. The density difference between NPs-CO2 and formation water can promote the miscibility of NPs-CO2-brine fluid and can inhibit the acid fluid under buoyancy. The upward diffusion was moved to the cap layer and prevents the chemical reaction of the rocks, that leads to the permanent storage of greenhouse gases.