Impact of pore-scale heterogeneity on continuum-scale multiphase flow properties: Insights from Indiana limestone

Microscale heterogeneity in porous media can influence larger-scale multiphase flow behaviour, particularly in the context of CO 2 storage. We conducted a multiphase steady-state flooding experiments on Indiana limestone, a carbonate with millimetre-scale heterogeneity, at two flow rates with capillary numbers of N c = 5 × 10 −8 and 1 × 10 −7 . Micro-CT at a 4.9 µm resolution was used to image nitrogen–brine displacement: the analysis included the whole sample and six representative sub-volumes from distinct regions. The analysis shows that doubling the capillary number produced a more homogeneous saturation profile, reflecting the greater influence of viscous forces even within a predominantly capillary-controlled regime. Moreover, the relative permeabilities shifted upward and to higher brine saturation with decreasing flow rate; this indicated that the non-wetting phase benefits from enhanced connectivity through preferential pathways. As the flow rate increases, however, viscous forces begin to override local capillary entry barriers, enabling the non-wetting phase to invade smaller and previously uninvaded pores. The sub-volume analysis showed two distinct regions with different entry pressures: the regions with higher entry pressure exhibit a higher gas invasion at the higher flow rate, whereas low capillary entry pressure regions showed minimal change. These observations show that modest increases in capillary number can change relative permeability, saturation, and trapping. This underlines the need to represent capillary heterogeneity when upscaling flow properties for reservoir-scale simulation of subsurface CO₂ storage. Relative permeability models that neglect sub-grid variability may bias simulated plume migration and trapping efficiency, and therefore the inferred storage performance.