We present experimental investigations of multi-phase (two-phase (oil/water, oil/gas) and three-phase (oil/water/gas)) relative permeabilities performed on laboratory scale rock cores. Two- and three-phase relative permeabilities data were obtained on two core samples (a Sand-pack and a Berea sandstone) by way of a Steady-State (SS) technique. Spatial and temporal dynamics of in-situ saturations along core samples were directly measured through an X-Ray absorption technology. The latter rendered detailed distributions of (section-averaged) fluid flow phases through the medium, which can then be employed for the characterization of relative permeabilities. The technique also enabled us to clearly identify the occurrence of end-effects during the experiments and to quantify the reliability of corrective strategies. For the oil/water settings we considered low and high viscosity oil, our findings supporting the observation that relative permeability to oil and water was sensitive to oil viscosity. Three-phase experiments were performed by following an IDI (Imbibition-Drainage-Imbibition) saturation path. The complete experimental data-base is here illustrated and juxtaposed to results obtained by the implementation of simple and commonly employed three-phase relative permeability models. In the three-phase setting, water and gas relative permeabilities display an approximately linear dependence on the logarithm of their own saturation. Consistent with the observation that oil behaves as an intermediate phase in our system, three-phase oil relative permeabilities lie in between those of their two-phase counterparts. Our data-set stands as a reliable reference for further model development and testing, as only a limited quantity of three-phase data are currently available.
Journal of Petroleum Science and Engineering – Elsevier
Published: Sep 1, 2016
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