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This thesis handles relatively novel and promising techniques (X-ray radiography, X-ray micro-tomography and numerical simulation at micro-scale) to investigate physical phenomena typical of immiscible displacements in porous media and estimate the related parameters of interest. In particular, we deal with reservoir rock samples focusing on two key hydraulic properties, relative permeability and capillary pressure, which are very useful in petro-physics for macro-scale reservoir simulations and are routinely measured by means of costly and invasive laboratory tests. This research work provides new methodologies able to support the traditional procedures. It exploits the capability of X-ray radiography and X-ray micro-tomography to inspect a porous sample and furnish a truthful view of the pore space internal structure. The planar and volumetric attenuation maps of the dry sample are used for quantitative morphological measurements (porosity, pore size), whereas the corresponding maps of the sample undergone displacement allow us to derive the fluid saturation maps, the saturation profiles and visualize the fluid distributions within the pores. From the reconstructed pore space, it is possible to extract a computational domain suitable for single-phase and two-phase flow simulations. Relative permeability and capillary pressure curves are numerically estimated, following the steady-state protocol, and compared to experimental results. On the other hand, starting from a microscopic approach, we manage to calculate the local capillary pressure of isolated oil blobs trapped in the pores at the end of an imbibition, by exploiting the Young-Laplace?s theory and our curvature estimates. Some preliminary tests are also performed to verify the influence that the variability of the contact angle between the immiscible fluids could have on the process evolution. The model is validated in a simple geometry and, further, applied to a complex porous domain. |
