Use of low- and high-IFT fluid systems in experimental and numerical modelling of systems that mimic CO2 storage in deep saline formations

Storage of CO2 in deep saline formations is currently the most promising option for mitigating the impact of climatic changes. Therefore, it is important to understand flow processes and distribution of forces acting on injected CO2. To demonstrate the influence of gravitational, viscous, and capillary forces on the flow of CO2, special experiments were designed. Laboratory experiments and numerical simulations were performed, where fluid representing CO2 was injected into a 2D porous medium saturated with fluid representing brine. Two sets of fluids characterised by different interfacial tension (IFT) were tested. Results demonstrate that at increasing injection rate viscous forces become stronger, leading to a higher total displacement of brine. Such performance is preferred at field scale, since it facilitates dissolution and residual trapping of CO2. Gravity effects were more pronounced in cases with low injection rates and high permeability and are demonstrated by lower volumes of the in-situ fluid displacement. Therefore, reservoirs giving low influence of gravity forces are more suitable for CO2 storage. The high-IFT fluid system had an IFT corresponding to the value of CO2-brine systems at possible reservoir conditions. However, the fluid flow in the laboratory model was dominated by capillary forces. This kind of behaviour is less likely to be observed at field scale as it is a result of the much smaller volume of porous system used in the laboratory compared to the volume at the field scale. The low-IFT fluid system resembled better field scale flow behaviour. The laboratory experiments were also modelled using a numerical reservoir simulation software. While modelling of observations from high-IFT system was challenging, simulations for low-IFT displacements showed accurate reflection of experiments.