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.

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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.

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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.

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Gas injection was introduced to the petroleum industry in the early 1950s. Nevertheless, the process efficiency is impacted by the low density and viscosity of the gas, which decrease sweep efficiency. Foam for Enhanced Oil Recovery (EOR) can overcome the downside of the viscous fingering by increasing the apparent viscosity of the gas. Importantly, the structure of the foam evolves with time due to gas diffusion between bubbles (coarsening). In a bulk foam, the coarsening behaviour is well defined, but there is a lack of understanding of coarsening behaviour in confined geometries, especially in porous media. Nonnekes et al [2014] predicted numerically and analytically that coarsening will cause the foam lamellae to move to low energy configurations in the pore throats, resulting in greater capillary resistance when trying to restart flow. This study describes foam coarsening in a porous medium and the implications for foam propagation. Foam coarsening experiments have been conducted in both a micromodel and in a rock core. The micromodel is etched with an irregular hexagonal pattern, with a Gaussian distribution of pore diameters. Foam was generated by coinjecting surfactant solution and nitrogen gas into the micromodel. Once steady state flow had been achieved, the flow was stopped. The coarsening behaviour of the foam was recorded using time-lapse photography. The core flood coarsening experiments were carried out using a Bentheimer Sandstone core. Foam was produced by coinjecting surfactant solution and nitrogen at the base of the core. Once a steady state flow was achieved, the flow was stopped and the core sealed off. When flow restarted, the additional driving pressure required to reinitiate flow was measured, and this could be attributed to the stable configuration of the coarsened foam. The microfluidic results found that the bubbles coarsened rapidly (t < 10 minutes) to the size of the pores. At the completion of coarsening the majority of the lamellae were located in the pore throats with minimum length. Because of the effect of the walls, the behaviour did not conform to the unconstricted coarsening growth laws. Furthermore, results on coreflood showed that coarsening is a rapid process, in agreement with microfluidic results. An increase in the additional pressure required to re-initiate flow was observed for the first 1 – 5 minutes of flow stoppages, while the pressure peaks did not increase for durations above 5 min. The implications of this behaviour for the field scale are also discussed. @en

Foams for enhanced oil recovery can increase sweep efficiency, as they decrease the gas relative permeability, 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. Microfluidic experiments are a useful tool for studying the foam flow behavior at the pore scale. We have carried out foam flow tests in a model porous media glass micromodel. Image analysis of the foam flow allowed local velocities to be obtained. 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 trapped gas fraction was observed both for increasing total velocity and for 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 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

We report a simulation study of surfactant-alternating-gas (SAG) foam injection into a waterflooded oil reservoir. We show the effects of oil, and of SAG cycle size and number on sweep efficiency, and the longterm impact of a single surfactant slug on the areal sweep efficiency of a gas-flood. Shan and Rossen (2004) show that a single-cycle SAG flood with fixed injection pressure can effectively overcome gravity override in a homogeneous reservoir with a uniform residual oil saturation. A single cycle works better than multiple cycles. We show that the presence of mobile oil can invalidate this model, but not simply because oil weakens or destroys foam. If foam is weakened by oil, moderately but uniformly, vertical sweep efficiency can still be good. Of course if oil kills foam nearly completely, gravity override occurs. In our simulations, foam collapses where oil saturation is above a certain threshold value greater than waterflood residual. Oil mobilized by the foam bank flows downward. This can lead to an oil bank at the bottom of the reservoir, and in single-cycle SAG this oil bank is not displaced by foam if its oil saturation is sufficient to destroy foam. Meanwhile, gas flows upward and the low-mobility front advances rapidly across the top of the reservoir, leading to an override zone. It is the non-uniformity of the resulting oil saturation and gas mobility that invalidates Shan and Rossen's model in this case. Instead there is an oil-rich zone at the bottom of the reservoir, foam above the oil-rich zone, and a foam-free override zone above the foam. In this case, if foam is injected in several relatively small slugs, oil production can be better than that with fewer relatively large slugs. We also illustrate the impact of injecting a single surfactant slug on the areal sweep efficiency of a long-term gas-flood. By injecting a surfactant slug prior to the gas slug, stronger foam can form in parts of the reservoir with a lower oil saturation. Foam then diverts gas flow to oil-rich areas in the reservoir, in our case the bottom of the reservoir. In a conventional gas flood gas flows primarily across the top of the reservoir with poor sweep efficiency. By injecting a single surfactant slug ahead of gas, higher oil recovery can be achieved at the same injected PV of gas. @en

Gas injection was introduced to the petroleum industry in the early 1950s. Nevertheless, the process efficiency is impacted by the low density and viscosity of the gas, which decrease sweep efficiency. Foam for Enhanced Oil Recovery (EOR) can overcome the downside of the viscous fingering by increasing the apparent viscosity of the Foam EOR improves the sweep efficiency by reducing gas mobility and creating a stable displacement front. In the field application, the surfactant concentration and flow rate vary in the reservoir, influencing dramatically the foam mobility. However, the variations of surfactant concentration and flow rate do not relate monotonously to the foam properties. In some cases, the foam properties depends on the history of the flow, i.e., a hysteresis effect. But hysteresis in foam flood has not been well characterized and understood. This study aims to understand hysteresis behavior of foam in porous media. To this end two series of experiments have been conducted: 1) Hysteresis behavior due to flow rate variations and 2) Hysteresis behavior due to surfactant concentration variations. In the flow rate experiments, several shear-thinning experiments at different volume fractions of gas (foam quality) are conducted in order to understand the effect of gas fraction and total velocity on foam generation mechanisms. In the surfactant concentration experiment, experiments have been performed at different surfactant concentrations and at different volume fractions of gas (foam quality). Results showed that a transition from weak to strong foam is more pronounced in high-quality regimes (gas fractional flow above 90%) than low-quality regimes (gas fractional flow below 80%). Remarkably, no hysteresis behavior has been observed in low-quality regimes, while hysteresis behavior occurred in high quality regimes. Furthermore, the effect of surfactant concentration on hysteresis behavior has been also investigated at high- and low-quality regimes. Contrary to some previous works, hysteresis behavior does not occur for surfactant variation. Remarkably, the apparent viscosity remains almost constant in lowquality regime for different surfactant concentrations. These results have important implications of the injection strategy and the economics of foam EOR. The surfactant concentration could be decreased and less gas could be injected, and in the same time, the foam performance could be maintained. gas. Importantly, the structure of the foam evolves with time due to gas diffusion between bubbles (coarsening). In a bulk foam, the coarsening behaviour is well defined, but there is a lack of understanding of coarsening behaviour in confined geometries, especially in porous media. Nonnekes et al [2014] predicted numerically and analytically that coarsening will cause the foam lamellae to move to low energy configurations in the pore throats, resulting in greater capillary resistance when trying to restart flow. This study describes foam coarsening in a porous medium and the implications for foam propagation. Foam coarsening experiments have been conducted in both a micromodel and in a rock core. The micromodel is etched with an irregular hexagonal pattern, with a Gaussian distribution of pore diameters. Foam was generated by coinjecting surfactant solution and nitrogen gas into the micromodel. Once steady state flow had been achieved, the flow was stopped. The coarsening behaviour of the foam was recorded using time-lapse photography. The core flood coarsening experiments were carried out using a Bentheimer Sandstone core. Foam was produced by coinjecting surfactant solution and nitrogen at the base of the core. Once a steady state flow was achieved, the flow was stopped and the core sealed off. When flow restarted, the additional driving pressure required to reinitiate flow was measured, and this could be attributed to the stable configuration of the coarsened foam. The microfluidic results found that the bubbles coarsened rapidly (t < 10 minutes) to the size of the pores. At the completion of coarsening the majority of the lamellae were located in the pore throats with minimum length. Because of the effect of the walls, the behaviour did not conform to the unconstricted coarsening growth laws. Furthermore, results on coreflood showed that coarsening is a rapid process, in agreement with microfluidic results. An increase in the additional pressure required to re-initiate flow was observed for the first 1 – 5 minutes of flow stoppages, while the pressure peaks did not increase for durations above 5 min. The implications of this behaviour for the field scale are also discussed. @en

Foam flow in porous media without oil shows two regimes, depending on foam quality (gas fractional flow). Complexity and limited data on foam-oil interactions in porous media greatly restrict understanding of foam in contact with oil. Distinguishing which regimes are affected by oil is key to modelling the effect of oil on foam. We report steady-state corefloods to investigate the effect of oil on foam through its effect on the two flow regimes. We fit parameters of the widely used STARS foam model to data for foam-oil concurrent flow. This research provides a practical approach and initial data for simulating foam EOR in the presence of oil. To ensure steady state, oil is co-injected with foam at a fixed ratio of oil (Uo) to water (Uw) superficial velocities in a Bentheimer sandstone core. Model oils used here consist of two components: hexadecane, which is benign to foam stability, and oleic acid, which can destroy foam. Varying the concentration of oleic acid in the model oil allows one to examine the effect of oil composition on steady-state foam flow. Experimental results show that oil impacts both high- and low-quality regimes, with the high-quality regime more vulnerable to oil. In particular, oil increases the limiting water saturation (Sw^∗) in the high-quality regime and also lessens gas mobility reduction in the low-quality regime. The high-quality regime is strongly shear-thinning in the presence of oil. Pressure gradient (p) in the low-quality regime, in some cases, decreases with increasing Uw at fixed gas superficial velocity (Ug), either with or without oil. This may reflect either an effect of oil, if oil is present, or easier flow of bubbles under wetter conditions. Increasing oleic acid concentration extends the high-quality regime to lower foam qualities, indicating more difficulty in stabilizing foam. Thus oil composition plays as significant a role as oil saturation. A model fit assuming a fixed Sw∗ and including shear-thinning in the low-quality regime doesn't represent each regime when the oil effect is strong enough. In such cases, fitting Sw∗ to each p contour and excluding shear-thinning in the low-quality regime yields a better match to data. The dependency of Sw∗ on oil saturation is not yet clear owing to absence of oil-saturation data in this study. Furthermore, none of the current foam simulation models can capture the upward-tilting p contours in the low-quality regime.

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Foam can potentially solve the associated problems with gas injection by reducing the mobility of the injected gas leading to a more stable displacement front. It is known that under immiscible conditions, the presence of oil can be detrimental for foam stability through several mechanisms. Under miscible conditions, there is no separate oil or gas phase; instead, CO2 and oil mix in different proportions forming a phase with varying composition at the proximity of the displacement front. There are then two fundamental questions, which arise from addition of surfactant to the system: (1) what is the nature of the “mixed phase” in the presence of the surfactant, and (2) how do the properties of this mixture change with compositional variations? This study reports the results of core-flood experiments conducted using CO2 and decane (nC10) as the model oil under miscible conditions. Surfactant and a mixture of CO2-decane were co-injected with variations of CO2 molar fractions, mixture volume fractions and total flow rates. We found that separate injection of CO2 or oil with the surfactant solution into the cores creates in-situ fluids that exhibit both low-quality (increasing viscosity with decreasing fraction of surfactant) and high-quality (decreasing viscosity with decreasing fraction of surfactant) regimes. However, upon simultaneous injection of CO2 and oil with the surfactant solution and depending on the molar fraction of CO2 in CO2- decane mixture (xCO2), three distinct regimes were observed. In Regime 1 (xCO2>0.8) the apparent viscosity of the in-situ fluid was the highest and increased with increasing xCO2. In Regime 2 (xCO2<2) the apparent viscosity increased with decreasing xCO2. In Regime 3 (0.2< xCO2<0.8) the apparent viscosity of the fluid remained relatively low and insensitive to the value of xCO2. Shear-thinning rheology was observed in all three regimes: supercritical CO2 foam (xCO2 =1), decane emulsion (xCO2 = 0), as well as CO2-decane-surfactant floods. Moreover, in Regime 1 and Regime 2, there is a transition at shear rates from 10 s-1 to 100 s-1, where the apparent viscosity increases by one order of magnitude. In Regime 3, however, this transition is not observed. Finally, we found that the current implicit-texture foam model cannot simulate our experimental data. @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.

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Foam can be used for gas mobility control in different subsurface applications. The success of foam-injection process depends on foam-generation and propagation rate inside the porous medium. In some cases, foam properties depend on the history of the flow or concentration of the surfactant, i.e., the hysteresis effect. Foam may show hysteresis behavior by exhibiting multiple states at the same injection conditions, where coarse-textured foam is converted into strong foam with fine texture at a critical injection velocity or pressure gradient. This study aims to investigate the effects of injection velocity and surfactant concentration on foam generation and hysteresis behavior as a function of foam quality. We find that the transition from coarse-foam to strong-foam (i.e., the minimum pressure gradient for foam generation) is almost independent of flowrate, surfactant concentration, and foam quality. Moreover, the hysteresis behavior in foam generation occurs only at high-quality regimes and when the pressure gradient is below a certain value regardless of the total flow rate and surfactant concentration. We also observe that the rheological behavior of foam is strongly dependent on liquid velocity.

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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

Foam can increase sweep efficiency within a porous medium, which is useful for oil-recovery processes[1]. The flow of foam in porous media is a complex process that depends on properties like permeability, porosity and surface chemistry, but also temperature. Although the surface activity of surfactants as a function of temperature is well described at the liquid/liquid or liquid/ gas interface, data on the effect of temperature on foam stability is limited, especially in porous media. In this work, we tested a surfactant (AOS) at different temperatures, from 20°C to 80°C, in a sandstone porous medium with co-injection of foam. The pressure gradient, or equivalently the apparent viscosity, was measured in steady-state experiments. The core-flood experiments showed that the apparent viscosity of the foam decreased by 50% when the temperature increased to 80°C. This effect correlates with the lower surface tension at higher temperatures. These results are compared to bulk foam experiments, which show that at elevated temperatures foam decays and coalesces faster. This effect, however, can be attributed to the faster drainage at high temperature, as a response to the reduction in liquid viscosity, and greater film permeability leading to faster coarsening. Our results using the STARS foam model show that one cannot fit foam-model parameters to data at one temperature and apply the model at other temperatures, even if one accounts for the change in fluid properties (surface tension and liquid viscosity) with temperature. Experiments show an increase in gas mobility in the low-quality foam regime with increasing temperature that is inversely proportional to the decrease in gas-water surface tension. In the high-quality regime, results suggest that the water saturation at which foam collapses fmdry increases and Pc * decreases with increasing temperature. @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

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

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