The characterisation of multiphase flow properties is essential for predicting large-scale fluid behaviour in the subsurface. Insufficient representation of small-scale heterogeneities has been identified as a major gap in conventional reservoir simulation workflows. Capillary heterogeneity has an important impact on small-scale flow and is one of the leading causes of anisotropy and flow rate dependency in relative permeability. We evaluate the workflow developed by Jackson et al. (2018) for use on rocks with complex heterogeneities. The workflow characterises capillary heterogeneity at the millimetre scale. The method is a numerical history match of a coreflood experiment with the 3D saturation distribution as a matching target and the capillary pressure characteristics as a fitting parameter. Coreflood experimental datasets of five rock cores with distinct heterogeneities were analysed: two sandstones and three carbonates. The sandstones exhibit laminar heterogeneities. The carbonates have isotropic heterogeneities at a range of length scales. We found that the success of the workflow is primarily governed by the extent to which heterogeneous structures are resolved in the X-ray imagery. The performance of the characterisation workflow systematically improved with increasing characteristic length scales of heterogeneities. Using the validated models, we investigated the flow rate dependency of the upscaled relative permeability. The findings showed that the isotropic heterogeneity in the carbonate samples resulted in non-monotonic behaviour; initially the relative permeability increased, and then subsequently decreased with increasing flow rate. The work underscores the importance of capturing small-scale heterogeneities in characterising subsurface fluid flows, as well as the challenges in doing so.