Abstract
The transport of fluids through a permeable rock can follow complex paths depending on the complexity of pore size distributions and connectivity. Understanding the contribution of individual pores to total flow helps to build representative relative permeability models for reservoir simulation of secondary and tertiary recovery applications. Whether or not micropores contribute to the flow will eventually affect the shape of the relative permeability curve of the two-phase flow. In addition, it affects the extent of the mixing zone during fluid displacement for any miscible enhanced oil recovery (EOR) processes.
Through a single-phase dispersion test, mimicking miscible displacement with continuous nuclear magnetic resonance (NMR) T2 distribution measurements, fluid displacements relative to pore type were directly observed and quantified. The displacement data was modeled using the classical convective-dispersive model.
Results illustrate that the micropores of the selected bimodal carbonate samples are preferentially connected and the micropores in M_1 petrophysical rock type (PRT) effectively contribute to the displacement/flow mechanism in these rocks. In addition, the experimental results from single-phase study suggests the contribution of micropores to the total displacment in the M_1 PRT should not be ignored when modeling relative permeability for reservoir simulation. The results from modeling the miscible fluid displacement data using the classical convective-dispersive model showed that micro- and macropores in M and M_1 PRTs communicate in parallel and in serial. This result should be accounted for designing any types of miscible and surfactant flooding for reservoirs with these PRTsas they are relevant to the extent of the mixing zone relative to pore types.
