Understanding the interplay of foam and nonaqueous phases in porous media is key to improving the design of foam for enhanced oil recovery and remediation of aquifers and soils. A widely used implicit‐texture foam model predicts phenomena analogous to cusp catastrophe theory: The surface describing foam apparent viscosity as a function of fractional flows folds backwards on itself. Thus, there are multiple steady states fitting the same injection condition J defined by the injected fractional flows. Numerical simulations suggest the stable injection state among multiple possible states but do not explain the reason. We address the issue of multiple steady states from the perspective of wave propagation, using three‐phase fractional‐flow theory. The wave‐curve method is applied to solve the two conservation equations for composition paths and wave speeds in 1‐D foam‐oil flow. There is a composition path from each possible injection state J to the initial state I satisfying the conservation equations. The stable displacement is the one with wave speeds (characteristic velocities) all positive along the path from J to I. In all cases presented, two of the paths feature negative wave velocity at J; such a solution does not correspond to the physical injection conditions. A stable displacement is achieved by either the upper, strong‐foam state, or lower, collapsed‐foam state but never the intermediate, unstable state. Which state makes the displacement depends on the initial state of a reservoir. The dependence of the choice of the displacing state on initial state is captured by a boundary curve.

A new capillary number (N_ca) definition is proposed for 2‐D etched micromodels. We derive the new definition from a force balance on a nonwetting ganglion trapped by capillarity. It incorporates the impact of pore microstructure on mobilization. The geometrical factors introduced can be estimated directly from image analysis of the pore network etched in the micromodel, without conducting flow experiments. The improved fit of the new N_ca to published data supports its validity. The new definition yields a consistent trend in the capillary‐desaturation curve. The conventional N_ca definitions proposed for porous rock give a large scatter in the capillary‐desaturation curve for data in micromodels. This is due to the different type of flow in micromodels, as 2‐D networks, relative to 3‐D geological porous media. In particular, permeability is dominated by channel depth in micromodels with shallow depth of etching, and generally, there is no simultaneous multiphase flow under capillary‐dominated conditions. Applying the conventional definitions to results in micromodels may lead to misleading conclusions for fluid transport in geological formations.