The problems associated with many gas injection projects are the inefficient gas utilization, poor sweep efficiency and low incremental oil recovery due to viscous instabilities (channeling or fingering) and gravity segregation. These are caused by rock heterogeneity as well as the low density and viscosity of the injected gas. To mitigate these drawbacks foam can be injected into the oil reservoir by co-injection of surfactant solution and gas, or by surfactant-alternating-gas (SAG) mode. When the foam films are created in-situ, the flow of gas is hindered and gas can sweep the pores that would not be reached in the absence of foam – better vertical and areal sweep. The efficiency of the displacement process in foam-assisted gas flood depends largely on the longevity of the created foam films, and ratio of film destabilization and re-generation rates. Experimental studies have demonstrated the detrimental impact of oil on foam stability. This paper reviews the mechanisms and theories (disjoining pressure, coalescence and drainage, entering and spreading of oil, oil emulsification, pinch-off, etc) suggested in the literature to explain the impact of oil on foam stability in the bulk and porous media. Moreover, we describe the existing approaches for foam modeling in porous media and the ways these models use to describe the oil effect on foam propagation in porous media. Further, we present various ideas on an improvement of foam stability and longevity in the presence of oil. The outstanding questions regarding foam-oil interactions are pointed out.

We review challenges to accurate simulation of foam enhanced oil recovery, with a focus on numerical issues. Foam responds in an abrupt, nonlinear way to changes in water saturation, surfactant concentration, and oil saturation, in ways that cause fluxes to fluctuate in time and space. As the grid is refined these effects have smaller impact on the overall process but execution of the simulation slows. In addition, in simulations of foam with oil, consecutive grid blocks can lie on opposite sides of a strong foam/weak foam boundary on the composition diagram. Because by definition foam is an interaction between gas and water, the naming of phases (gas or oil) in a compositional simulation of a miscible EOR process can have significant effect on the simulation of a foam flood. Numerical dispersion of surfactant concentration is a problem, but attempts to minimize its effect can lead to other numerical artifacts. Because foam is so sensitive to water saturation and capillary pressure, capillary effects are important, especially in finely laminated formations. "Population-balance" foam simulators, which represent the complex dynamics of bubble creation and destruction along with the effect of foam on gas mobility, face additional challenges with instability and slow run times, especially for models that represent the multiple steady states seen in the laboratory. We collect and review the various numerical challenges to foam simulation. Some of these problems are largely cosmetic, giving for instance fluctuating fluxes and pressure gradient but no significant effect on final recovery. Others do severely influence the whole progress of the flood. We discuss the origin of the challenges, how to recognize them, how they can be mitigated, and whether they arise from a correct representation of foam physics or the unintended result of attempts to solve other numerical problems.

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.

The propagation of foam in an oil reservoir depends on the creation and stability of the foam in the reservoir, specifically the creation and stability of foam films, or lamellae. As the foam propagates far from in injection well, superficial velocity and pressure gradient decrease with distance from the well. Experimental (Friedmann et al., 1994) and theoretical (Ashoori et al., 2011) studies relate concerns about foam propagation at low superficial velocity to the minimum velocity or pressure gradient for foam generation near the well (Rossen and Gauglitz, 1990; Gauglitz et al., 2002). The objective of this work is to measure the impact of surfactant concentration and gas fractional flow on foam generation. Theory (Rossen and Gauglitz, 1990; Kam and Rossen, 2003) relates foam generation to gas fractional flow and, indirectly, to the stability of foam films, or lamellae, which in turn depends on surfactant concentration (Apaydin and Kovscek, 2001). However, the link between foam generation and surfactant concentration has not been established experimentally. In our experiments, nitrogen foam is generated in a core of Bentheimer sandstone. The foam-generation experiments consist of measuring the minimum velocity for foam generation as a function of gas fractional flow at three surfactant concentrations well above the critical micelle concentration. Experimental results show that the minimum velocity for foam generation decreases with increasing liquid fraction, as shown by previous foam generation studies (Rossen and Gauglitz, 1990; Friedmann et al., 1991). Additionally, our results show that this velocity decreases with increasing surfactant concentration, far above the CMC. We also propose a workflow for screening out the experimental artefacts that can distort the trigger velocity.