Foam increases sweep efficiency during gas injection in enhanced oil recovery processes. Surfactant alternating gas (SAG) is the preferred method to inject foam for both operational and injectivity reasons. Dynamic SAG corefloods are unreliable for direct scaleup to the field because of core-scale artifacts. In this study, we report fit and scaleup local-equilibrium (LE) data at very-low injected-liquid fractions in a Bentheimer core for different surfactant concentrations and total superficial velocities. We fit LE data to an implicit-texture foam model for scaleup to a dynamic foam process on the field scale using fractional-flow theory. We apply different parameter-fitting methods (least-squares fit to entire foam-quality scan and the method of Rossen and Boeije 2015) and compare their fits to data and predictions for scaleup. We also test the implications of complete foam collapse at irreducible water saturation for injectivity. Each set of data predicts a shock front with sufficient mobility control at the leading edge of the foam bank. Mobility control improves with increasing surfactant concentration. In every case, scaleup injectivity is much better than with coinjection of gas and liquid. The results also illustrate how the foam model without the constraint of foam collapse at irreducible water saturation (Namdar Zanganeh et al. 2014) can greatly underestimate injectivity for strong foams. For the first time, we examine how the method of fitting the parameters to coreflood data affects the resulting scaleup to field behavior. The method of Rossen and Boeije (2015) does not give a unique parameter fit, but the predicted mobility at the foam front is roughly the same in all cases. However, predicted injectivity does vary somewhat among the parameter fits. Gas injection in a SAG process depends especially on behavior at low injected-water fraction and whether foam collapses at the irreducible water saturation, which may not be apparent from a conventional scan of foam mobility as a function of gas fraction in the injected foam. In two of the five cases examined, this method of fitting the whole scan gives a poor fit for the shock in gas injection in SAG. We also test the sensitivity of the scaleup to the relative permeability krw(Sw) function assumed in the fit to data. There are many issues involved in scaleup of laboratory data to field performance: reservoir heterogeneity, gravity, interactions between foam and oil, and so on. This study addresses the best way to fit model parameters without oil for a given permeability, an essential first step in scaleup before considering these additional complications.@en

Foam can improve sweep efficiency in gas-injection-enhanced oil recovery. Surfactant-alternating-gas (SAG) is a favored method of foam injection. Laboratory data indicate that foam can be non-Newtonian at low water fractional flow f_w, and therefore during gas injection in a SAG process. We investigate the implications of this finding for mobility control and injectivity, by extending fractional-flow theory to gas injection in a non-Newtonian SAG process in radial flow. We make most of the standard assumptions of fractional-flow theory (incompressible phases, one-dimensional displacement through a homogeneous reservoir, instantaneous attainment of local equilibrium), excluding Newtonian mobilities. For this initial study, we ignore the effect of changing or non-uniform oil saturation on foam. Non-Newtonian behavior at low f_w implies that the limiting water saturation for foam stability varies as superficial velocity decreases with radial distance from the well. We discretize the domain radially and perform Buckley–Leverett analysis on each narrow increment in radius. Solution characteristics move outward with fixed f_w. We base the foam model parameters and non-Newtonian behavior on laboratory data in the absence of oil. We compare results to mobility and injectivity determined by conventional simulation, where grid resolution is usually limited. For shear-thinning foam, mobility control improves as the foam front propagates from the well, but injectivity declines somewhat with time. This change in mobility ratio is not that at steady state at fixed water fractional flow in the laboratory, however, because the shock front in a non-Newtonian SAG process does not propagate at fixed fractional flow (though individual characteristics do). Moreover, the shock front is not governed by the conventional condition of tangency to the fractional-flow curve, though it continually approaches this condition. Injectivity benefits from the increased mobility of shear-thinning foam near the well. The foam front, which maintains a constant dimensionless velocity for Newtonian foam, decelerates somewhat with time for shear-thinning foam. For shear-thickening foam, mobility control deteriorates as the foam front advances, though injectivity improves somewhat with time. Overall, however, injectivity suffers from reduced foam mobility at high superficial velocity near the well. The foam front accelerates somewhat with time. Conventional simulators cannot adequately represent these effects, or estimate injectivity accurately, in the absence of extraordinarily fine grid resolution near the injection well.

@en

Foam is able to increase gas’s sweep efficiency in Enhanced-Oil-Recovery applications. A surfactant-alternating-gas, or SAG, process is usually preferred for placing foam in the reservoir. During a SAG process, foam is generated away from the wellbore, offering both good injectivity and good mobility control at the leading edge of the foam bank. Scale-up of laboratory data for SAG to field applications remains a challenge. Direct scale-up of dynamic SAG coreflood results is unreliable because of the dominance of core-scale artifacts. Steady-state coreflood data can be scaled up using fractional-flow theory (Kibodeaux and Rossen, 1997; Rossen and Boeije, 2015). However, about half the published laboratory studies of foam fractional-flow curves report non-monotonic behavior, where at some point liquid saturation Sw increases with decreasing liquid fractional flow fw. Rossen and Bruining (2007) warn that such behavior would result in foam collapse during injection of the gas slug in a SAG process at the field scale. Here we report and analyse a series of steady-state and dynamic coreflood experiments to investigate the occurrence of non-monotonic fractional-flow behavior. These corefloods vary surfactant concentration, injected gas fraction (foam quality) and total superficial velocity and are supported by CT measurements. The CT data confirm that in these cases, as foam weakens with decreasing fw, liquid saturation increases, confirming the non-monotonic fw(Sw) behaviour. In our results, every case of non-monotonic fractional-flow behavior begins with propagation of foam from the inlet, followed by eruption of a much-stronger foam at the outlet of the core and backwards propagation of the stronger foam state to the inlet, similar to behavior reported by Apaydin and Kovscek (2001) and Simjoo et al. (2013). This suggests that there may be more than one stable local-equilibrium (LE) foam state. The initial creation of the stronger foam near the outlet is at least in part due to the capillary end effect. It is thus not clear which LE foam state controls behaviour in a SAG process in the field. In our results, the subsequent transition from a stronger- to a weaker-foam state, leading to non-monotonic fw(Sw) behavior, coincides with conditions for weaker foam (lower surfactant concentration, lower fw) and less-vigorous foam generation (lower superficial velocity); this agrees with the theory of foam propagation of Ashoori et al. (2012). We discuss the implications of these findings, if confirmed to apply generally, for design of SAG foam processes. @en

Foam increases sweep efficiency during gas injection in enhanced oil recovery (EOR) processes by reducing gas mobility. In fact, foam is the only EOR technology that is able to fight against both gravity segregation and geological heterogeneity. Surfactant Alternating Gas, or SAG, is the preferred method to place foam into the reservoir for both operational and injectivity reasons. For example, this method of injection avoids the difficulties of having foam in the injection lines. Injecting foam in this manner also offers better injectivity than in foam-injection processes in which pregenerated foam is injected into the reservoir.@en