  This study refutes the premise that the distribution of flow speeds in
complex porous media can be described by a simple function such as a normal or
exponential variation. In many complex porous media, including those relevant
for subsurface storage and recovery applications, a separation of scales exists
between larger inter-granular pores and micro-porosity inside the grains,
leading to different flow signatures that need to be described by multimodal
functions with distinct flow field characteristics. We demonstrate this finding
by devising a novel methodology to simulate fluid flow in carbonate rock based
on a representation of the pore space obtained by differential X-ray imaging.
The permeability assignment in the micro-porous space is estimated from the
pore size inferred from mercury injection porosimetry. Model predictions
considering micro-porosity agree well with experimentally measured porosities
and permeabilities. The micro-porosity can contribute significantly to the
overall permeability, particularly in the more heterogeneous media.
