Factors Influencing Unsteady Relative Permeability of a Mixed-Wet Reservoir Rock

Summary Capillarity, viscous fingering, and heterogeneity influence the flow in a core plug and hence affect the relative permeability determined from an unsteady test. Several unsteady water/oil relative permeability tests were carried out in a mixed-wet core while in-situ 3D saturation distribution was monitored by a computerized-tomography (CT) scanner. Results illustrate that, in the early part of the Johnson-Bossler-Naumann (JBN) method, relative permeability is dominated by fingering and heterogeneity effects. The later part of this method (> 1 PV), however, represents the relative permeability of the end-face saturation and is influenced by the capillary number and throughput. Thus, laboratory results must be scaled to the field on the basis of the flow parameters: end-effect, capillary, instability, and heterogeneity numbers.