We present a CT coreflood study of foam, both pre-generated and generated in-situ, displacing oil, as a function of oil type and saturation. Foam generation and propagation are reflected through sectional pressure measurements. Dual-energy CT imaging monitors in-time phase saturations. With an oil less harmful to foam (hexadecane), injection with and without pre-generation of foam exhibits similarities: propagation of a foam bank through a core and later refinement of foam texture. In contrast, with an oil destabilizing to foam (with 20 wt% oleic acid in the hexadecane), pre-generation of foam behaves very differently from co-injection, suggesting very-different effects on foam generation and propagation. Without pre-generation, strong-foam generation is very difficult even at residual oil saturation (about 0.1); generation finally starts from the outlet (likely a result of the capillary-end effect). This strong-foam state propagates upstream very slowly. Pre-generated foam shows two stages of propagation, both from the inlet to outlet. First, weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. This dependence on injection method with harmful oil is not represented in currently applied foam models, which need further improvements for reliable prediction of foam for enhanced oil recovery.@en

Surfactant-alternating-gas (SAG) is a favored method of foam injection, which has been proved as an efficient way for enhancing oil recovery. However, foam flow is extremely complicated, and there are still unsolved problems for foam application. One is liquid injectivity. Our previous studies suggest that the injectivity in a SAG process is determined by propagation of several banks near the injection well that are not represented by current foam models. Uniform bank properties were assumed. However, in a companion paper, our experimental results show that the dimensionless propagation velocity and the total mobility of banks during the liquid-injection period depends on superficial velocity. Shearing-thinning behavior is observed. In radial flow, the superficial velocity varies with distance from the well. In this study, we scale-up the experimental results using a radial bank-propagation model. The comparison of liquid injectivity estimated from conventional foam simulators (Peaceman equation) and the bank-propagation model show that the conventional foam models cannot represent the effect of the superficial-velocity-dependent fluid properties during liquid injection in a SAG process. The shear-thinning behavior can lead to much better liquid injectivity than expected, which should be accounted for in a field application of a SAG foam process.@en

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. @en

We present a comparative study of foam coreflood experiments with various surfactant concentrations. Plots of apparent viscosity vs. injected gas fraction were obtained for surfactant concentrations at the critical micelle concentration and above. Bulk foam stability was measured for all concentrations and compared with the coreflood results. There were different responses to surfactant concentration in bulk and in corefloods. The coreflood results were matched with an implicit-texture foam model, and the dependency of the model parameters on the surfactant concentration is discussed. Fitting the data requires relating the surfactant concentration to the dry-out function or the limiting capillary pressure. @en

tAqueous foams play an important role in many industrial processes, from ore separation by froth flotationto enhanced oil recovery (EOR). In the latter case, the foam is used as a means of increasing the sweepefficiency through the oil bearing rock – the complex, structure dependent, flow behavior of the foammeans that it has improved penetration of lower permeability regions than would be obtained with aNewtonian fluid. An understanding of how foam behaves when flowing through a rock is therefore of greatimportance when selecting suitable surfactants for EOR processes. Previous tests have suggested thatthere is no reliable correlation between bulk foam behavior and foam behavior in a rock core, especially inthe presence of oil. We present a comparative study of bulk stability tests and core floods with foam, bothwith and without oil. Core-flood tests were conducted in rock cores with a diameter of 1 cm, significantlysmaller than typical cores. Apparent viscosity/injected gas fraction response curves were obtained, bothwith and without oil in the system.The current work finds that, in the absence of oil, there is a positive correlation between bulk foamstability and core-flood performance. Bulk foam experiments can therefore be a useful screening tool togive a good indication of the surfactant performance in the core flood. However, in the presence of oil,although there was a general trend of increasing maximum apparent viscosity with increasing bulk foamstability, no strong correlation was found between bulk foam stability and the performance in the corefor the experiments performed.@en

Surfactant-alternating-gas (SAG) is a preferred method of foam injection, which is a promising means of enhanced oil recovery. Liquid injectivity in a SAG process is commonly problematic. Our previous studies suggest that the liquid injectivity can be better than expected due to the existence of a collapsed-foam region formed during the gas-injection period ahead of the liquid-injection period. A single superficial velocity was used in those studies to examine the flow behavior during gas- and liquid-injection periods, separately. However, in radial flow from an injection well, superficial velocity decreases with distance from the injection well. Understanding the effect of superficial velocity on gas and liquid injectivities is important, but remains unexplored. In this study, we first examine gas injection at different superficial velocities following foam injection. We then study the effect of liquid superficial velocity on the liquid injectivity following a similar volume of gas injection. Our results show that during a prolonged period of gas injection following foam, the propagation velocity and the total mobility of the collapsed-foam bank are not significantly affected by the gas superficial velocity. During liquid injection after a period of gas injection, the dimensionless propagation velocities and the total mobilities of the forced-imbibition bank and the gas-dissolution bank follow a power-law dependence on the liquid superficial velocity. Liquid fingering through the weakened-foam region shows strongly shear-thinning behavior. It is also observed from X-ray computer-tomography experiments that the liquid fingers are wider if the liquid superficial velocity is greater. The impact of the shear-thinning behavior on the estimation of liquid injectivity in a field application is the subject of a companion paper.@en

We present a set of steady-state foam-flood experimental data for four sandstones with different permeabilities, ranging between 6 and 1900 mD, and with similar porosity. We derive permeability-dependent foam parameters with two modelling approaches, those of Boeije and Rossen (2015a) and a non-linear least-square minimization approach (Eftekhari et al., 2015). The two approaches can yield significantly different foam parameters. Thus, we critically assess their ability in deriving reliable foam parameter estimates. In particular, the way the two approaches treat shear-thinning foam behaviour and foam coalescence is discussed. The foam parameter set acquired from the latter approach is further used as input in foam diversion calculations: this serves to evaluate mobility predictions in non-communicating reservoir layers. This study aims to provide a framework to integrate experimental work, modelling and simple qualitative diversion calculations to provide a background for the upscaling of foam studies, with particular focus on heterogeneous systems.@en

We present a set of steady-state foam-flood experimental data for four sandstones with different permeabilities, ranging between 6 and 1900 mD, and with similar porosity. We derive permeability-dependent foam parameters with two modelling approaches, those of Boeije and Rossen (2015a) and a non-linear least-square minimization approach (Eftekhari et al., 2015). The two approaches can yield significantly different foam parameters. Thus, we critically assess their ability in deriving reliable foam parameter estimates. In particular, the way the two approaches treat shear-thinning foam behaviour and foam coalescence is discussed. The foam parameter set acquired from the latter approach is further used as input in foam diversion calculations: this serves to evaluate mobility predictions in non-communicating reservoir layers. This study aims to provide a framework to integrate experimental work, modelling and simple qualitative diversion calculations to provide a background for the upscaling of foam studies, with particular focus on heterogeneous systems.@en

The effectiveness of foam for mobility control in the presence of oil is key to foam EOR. A fundamental property of foam EOR is the existence of two steady-state flow regimes: the high-quality regime and the low-quality regime. Experimental studies have sought to understand the effect of oil on foam through its effect on these two regimes. Here we explore the existence of multiple steady states for one widely used foam model. The widely used STARS foam model includes two algorithms for the effect of oil on foam: in the "wet-foam" model, oil changes the mobility of full-strength foam in the low-quality regime; in the "dry-out" model, oil alters the limiting water saturation at which foam collapses. We examine their effect on the two flow regimes, using Corey relative permeabilities for oil. Specifically, we plot the pressure-gradient contours that define the two flow regimes as a function of superficial velocities of water, gas and oil and show how oil shifts behavior in the regimes. There are two ways to study the effect of oil on steady-state foam: 1) at fixed oil saturation. This is the way a simulator represents the effect, but it is difficult if not impossible to fix this condition in a laboratory coreflood. 2) at fixed superficial velocities. In both kinds of plots, the wet-foam model shifts behavior in the low-quality regime with no direct effect on the high-quality regime. The dry-out model shifts behavior in the high-quality regime but not the low-quality regime. At fixed superficial velocities, both models predict multiple steady states at some injection conditions. We investigate these states using a simple 1D simulator with and without incorporating capillary diffusion. The steady-state attained after injection depends on the initial state. In some cases, it appears that the steady state at intermediate pressure gradient is inherently unstable as represented in the model. In some cases introduction of capillary diffusion is required to attain a uniform steady-state in the medium. The existence of multiple steady states, with the middle one unstable, is reminiscent of c Foam can divert flow from higher- to lower-permeability layers and thereby improve vertical conformance in gas-injection enhanced oil recovery. Recently, Kapetas et al. (2015) measured foam properties in cores from four sandstone formations ranging in permeability from 6 to 1900 md, and presented parameter values for foam model fit to those data. Permeability affects both the mobility reduction of wet foam in the "low-quality" foam regime and the limiting capillary pressure at which foam collapses. Kapetas et al. showed how foam would divert injection between layers of these formations if all layers were full of foam injected at a given quality (gas fractional flow). Here we examine the effects of injection method on diversion in a dynamic foam process using fractional-flow modeling and the model parameters derived by Kapetas et al. Like them, we consider a hypothetical reservoir containing non-communicating layers with the properties of the four formations in their study. The effectiveness of diversion varies greatly with injection method. In a SAG (surfactant-alternatinggas) process, diversion of the first slug of gas depends on foam behavior at very high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This of course favors diversion away from high-permeability layers that receive a large surfactant slug, but there is an optimum surfactant slug size: too little surfactant and diversion from high-permeability layers is not effective; too much and mobility is reduced in lowpermeability layers, too. For a SAG process, it is very important to determine if foam collapses completely at irreducible water saturation. In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with time of injection. Injectivity is extremely poor with foam injection, but is not necessarily worse than waterflood in some effective SAG foam processes atastrophe theory and of studies of foam generation without oil. @en

The effectiveness of foam for mobility control in the presence of oil is key to foam EOR. A fundamental property of foam EOR is the existence of two steady-state flow regimes: the high-quality regime and the low-quality regime. Experimental studies have sought to understand the effect of oil on foam through its effect on these two regimes. Here we explore the existence of multiple steady states for one widely used foam model. The widely used STARS foam model includes two algorithms for the effect of oil on foam: in the "wet-foam" model, oil changes the mobility of full-strength foam in the low-quality regime; in the "dry-out" model, oil alters the limiting water saturation at which foam collapses. We examine their effect on the two flow regimes, using Corey relative permeabilities for oil. Specifically, we plot the pressure-gradient contours that define the two flow regimes as a function of superficial velocities of water, gas and oil and show how oil shifts behavior in the regimes. There are two ways to study the effect of oil on steady-state foam: 1) at fixed oil saturation. This is the way a simulator represents the effect, but it is difficult if not impossible to fix this condition in a laboratory coreflood. 2) at fixed superficial velocities. In both kinds of plots, the wet-foam model shifts behavior in the low-quality regime with no direct effect on the high-quality regime. The dry-out model shifts behavior in the high-quality regime but not the low-quality regime. At fixed superficial velocities, both models predict multiple steady states at some injection conditions. We investigate these states using a simple 1D simulator with and without incorporating capillary diffusion. The steady-state attained after injection depends on the initial state. In some cases, it appears that the steady state at intermediate pressure gradient is inherently unstable as represented in the model. In some cases introduction of capillary diffusion is required to attain a uniform steady-state in the medium. The existence of multiple steady states, with the middle one unstable, is reminiscent of c Foam can divert flow from higher- to lower-permeability layers and thereby improve vertical conformance in gas-injection enhanced oil recovery. Recently, Kapetas et al. (2015) measured foam properties in cores from four sandstone formations ranging in permeability from 6 to 1900 md, and presented parameter values for foam model fit to those data. Permeability affects both the mobility reduction of wet foam in the "low-quality" foam regime and the limiting capillary pressure at which foam collapses. Kapetas et al. showed how foam would divert injection between layers of these formations if all layers were full of foam injected at a given quality (gas fractional flow). Here we examine the effects of injection method on diversion in a dynamic foam process using fractional-flow modeling and the model parameters derived by Kapetas et al. Like them, we consider a hypothetical reservoir containing non-communicating layers with the properties of the four formations in their study. The effectiveness of diversion varies greatly with injection method. In a SAG (surfactant-alternatinggas) process, diversion of the first slug of gas depends on foam behavior at very high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This of course favors diversion away from high-permeability layers that receive a large surfactant slug, but there is an optimum surfactant slug size: too little surfactant and diversion from high-permeability layers is not effective; too much and mobility is reduced in lowpermeability layers, too. For a SAG process, it is very important to determine if foam collapses completely at irreducible water saturation. In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with time of injection. Injectivity is extremely poor with foam injection, but is not necessarily worse than waterflood in some effective SAG foam processes atastrophe theory and of studies of foam generation without oil. @en

A surfactant alternating gas (SAG) process is often the injection method for foam, on the basis of its improved injectivity over direct foam injection. In a previous study, we reported coreflood experiments on liquid injectivity after foam flooding and liquid injectivity after injection of a gas slug following steady-state foam. Results showed that a period of gas injection is important for the subsequent liquid injectivity. However, the effects of multiple gas and liquid slugs were not explored. In this paper, we present a coreflood study of injectivities of multiple gas and liquid slugs in an SAG process in a field core. Nitrogen and surfactant solution are either coinjected or injected separately into the sandstone core sample. The experiments are conducted at an elevated temperature of 90℃ with a backpressure of 40 bar. Differential pressures are measured to quantify gas and liquid injectivities. Computed tomography (CT) scanning is applied to relate water saturation to mobility. During the injection of a large gas slug following foam, a bank in which foam completely collapses or greatly weakens forms near the inlet and propagates slowly downstream. During the subsequent period of liquid injection, liquid flows through the collapsed-foam bank much more easily than further downstream. Beyond the collapsed-foam region, liquid first imbibes into the whole cross section. In this region, liquid flows mainly through a finger of high liquid saturation. Our CT results suggest a revision of our earlier interpretation; the process of gas dissolution does not merely follow fingering but is evidently directly involved in the fingering process. Our results suggest that, in radial flow, the small region of foam collapse very near the well greatly improves injectivity. The subsequent gas and liquid slugs behave near the wellbore, affecting injectivity, in a way similar to the first slugs. Thus, the behavior and modeling of the first gas slug and first subsequent liquid slug is representative of near-well behavior in an SAG process. The trends observed in our previous work are reproduced in a low-permeability field core.@en

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 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 Kovcsek, 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 foamgeneration experiments consist of measuring the critical 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 critical velocity 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 the critical velocity decreases with increasing surfactant concentration, far above the CMC. We also propose a workflow for screening out the experimental artifacts that can distort the trigger velocity.@en

Foam structure evolves with time due to gas diffusion between bubbles (coarsening). In a bulk foam, coarsening behaviour is well defined, but there is less understanding of coarsening in confined geometries such as porous media. Previous predictions suggest that coarsening will cause foam lamellae to move to low energy configurations in the pore throats, resulting in greater capillary resistance when restarting flow. Foam coarsening experiments were conducted in both a model-porous-media micromodel and in a sandstone core. In both cases, foam was generated by coinjecting surfactant solution and nitrogen. Once steady state flow had been achieved, the injection was stopped and the system sealed off. In the micromodel, the foam coarsening was recorded using time-lapse photography. In the core flood, the additional driving pressure required to reinitiate flow after coarsening was measured. In the micromodel the bubbles coarsened rapidly to the pore size. At the completion of coarsening the lamellae were located in minimum energy configurations in the pore throats. The wall effect meant that the coarsening did not conform to the unconstricted growth laws. The coreflood tests also showed coarsening to be a rapid process. The additional driving pressure to restart flow reached a maximum after just 2 minutes.@en

Gas trapping is an important mechanism in both Water or Surfactant Alternating Gas (WAG/SAG) and foam injection processes in porous media. Foams for enhanced oil recovery (EOR) can increase sweep efficiency as they decrease the gas relative permeability, and this is mainly due to gas trapping. However, gas trapping mechanisms are poorly understood. Some studies have been performed during corefloods, but little work has been carried out to describe the bubble trapping behaviour at the pore scale. We have carried out foam flow tests in a micromodel etched with an irregular hexagonal pattern. Image analysis of the foam flow allowed the bubble centres to be tracked and local velocities to be obtained. It was found that the flow in the micromodel is dominated by intermittency and localized zones of trapped gas. The quantity of trapped gas was measured both by considering the fraction of bubbles that were trapped (via velocity thresholding) and by measuring the area fraction containing immobile gas (via image analysis). A decrease in the quantity of trapped gas was observed for both increasing total velocity and increasing foam quality. Calculations of the gas relative permeability were made with the Brooks Corey equation, using the measured trapped gas saturations. The results showed a decrease in gas relative permeabilities, and gas mobility, for increasing fractions of trapped gas. It is suggested that the shear thinning behaviour of foam could be coupled to the saturation of trapped gas.@en

Aqueous foams play an important role in many industrial processes, from ore separation by froth flotation to enhanced oil recovery (EOR), where the foam is used as a means of increasing sweep efficiency through oil-bearing rock. The complex, structure-dependent, flow behavior of the foam gives improved penetration of lower-permeability regions. Foam is stabilized by surfactant molecules, and the foam strength is influenced by the surfactant concentration in the water phase. It is therefore of great importance to understand the effect of surfactant concentration on foam processes. Implicit Texture (IT) foam models eg STARS account for the surfactant effect with functions that depend on surfactant concentration in the water and a few other parameters. However, there is no evidence that these functions are able to capture adequately the effect of surfactant concentration effect. We present a comparative study of foam core-flood experiments with various surfactant concentrations. Core-flood tests were conducted in rock cores with a diameter of 1 cm and length of 17cm, significantly smaller than typical cores. Plots of apparent viscosity vs. injected gas fraction were obtained for surfactant concentrations at the critical micellar concentration (CMC) and above. Bulk foam stability and surface tension were measured for all concentrations, in order to define the CMC and to compare with coreflood results. The experimental results have been matched with the STARS IT foam model and the dependency of model parameters on the surfactant concentration is discussed. This work found that the IT model is not able to predict the decrease of the foam strength with decreasing surfactant concentration. Instead, the study shows that the effect of surfactant concentration can be correlated with the dry-out function of the IT model, and specifically to the limiting capillary pressure.@en

Aqueous foams play an important role in many industrial processes, from ore separation by froth flotation to enhanced oil recovery (EOR), where the foam is used as a means of increasing sweep efficiency through oil-bearing rock. The complex, structure-dependent, flow behavior of the foam gives improved penetration of lower-permeability regions. Foam is stabilized by surfactant molecules, and the foam strength is influenced by the surfactant concentration in the water phase. It is therefore of great importance to understand the effect of surfactant concentration on foam processes. Implicit Texture (IT) foam models eg STARS account for the surfactant effect with functions that depend on surfactant concentration in the water and a few other parameters. However, there is no evidence that these functions are able to capture adequately the effect of surfactant concentration effect. We present a comparative study of foam core-flood experiments with various surfactant concentrations. Core-flood tests were conducted in rock cores with a diameter of 1 cm and length of 17cm, significantly smaller than typical cores. Plots of apparent viscosity vs. injected gas fraction were obtained for surfactant concentrations at the critical micellar concentration (CMC) and above. Bulk foam stability and surface tension were measured for all concentrations, in order to define the CMC and to compare with coreflood results. The experimental results have been matched with the STARS IT foam model and the dependency of model parameters on the surfactant concentration is discussed. This work found that the IT model is not able to predict the decrease of the foam strength with decreasing surfactant concentration. Instead, the study shows that the effect of surfactant concentration can be correlated with the dry-out function of the IT model, and specifically to the limiting capillary pressure.@en