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

As foam is injected into an oil reservoir, the region near an injector can become oil-free due to the relatively high capillary number. Foam created in this region encounters oil further out in the reservoir. The impact of oil on foam in porous media is usually investigated by co-injecting surfactant, gas and oil, or by injecting pre-generated foam into an oil-saturated core. However, the former experiment does not give information on the impact of oil on pre-generated foam, and with the latter experiment one cannot easily obtain data at different oil fractional flows, necessary to model the impact of oil on pre-generated foam. Here we present a novel but relatively simple experimental technique for investigating the effect of oil on pre-generated foam in porous media. This allows one to compare the effects of oil on pre-generated foam and on foam generation without the experimental complications involved in using two separate porous media. We co-inject surfactant solution and gas into a relative narrow core (1 cm diameter), and inject oil into the core some distance downstream from the inlet through ports in the side of the core. The relatively narrow core allows rapid contact between the injected crude oil and pre-generated foam in a porous medium much larger than pore dimensions. By injecting the three phases into the core we investigate the flow behaviour of foam with oil at fixed fractional flows of all three phases. We illustrate the technique with a study of the effect of one crude oil with two surfactants. With this system, there is a progressive decrease in the apparent viscosity of the foam after encountering oil. Foams with a higher gas fraction experiences a more-significant weakening by oil over the length of the core than foams with a lower gas fraction. By the end of the core, the apparent viscosities of foam with a higher gas fraction approach values observed with three-phase co-injection. We present a novel, but relatively simple method to investigate the change of foam mobility as it encounters oil in a porous medium, at controlled fractional flows. We show that in our case the apparent viscosity of foam with oil can decrease by more than a factor of four over a distance of 15 cm, indicating that foam and oil reach steady-state (as observed with three-phase co-injection) almost instantaneously compared to the length of a reservoir-simulation grid-block.

@en

Dispersed and solubilized oil can impact bulk foam stability differently. Though aromatic components are more soluble in water than straight-chain aliphatic components, solubilized aromatics do not necessarily impact the stability of foam in bulk or porous media, whereas straight-chain aliphatic components can have a detrimental impact (Bergeron et al., 1993; Lee et al., 2013). However, to our knowledge there is no published research on the impact of a solubilized crude oil on foam, as distinct from a separate oil phase, in a porous medium. To investigate whether the behaviour of steady-state foam with crude oil can be explained by solubilized oil components, we perform foam-flooding experiments with surfactant solution previously equilibrated with crude oil. Furthermore, we conduct foam-flooding experiments with hexane solubilized in the surfactant solution, to determine whether straight-chain aliphatic components can explain the behaviour of the solubilized crude oil on steady-state foam mobility, in the same way that they impact bulk foam in the literature. The impact of crude oil, as a separate, dispersed oleic phase, is studied here by co-injection of crude oil, surfactant solution and gas in core-floods, focusing on steady-state mobility, captured by the pressure gradient within the core. In our experiments crude oil, as a separate oleic phase, reduces the pressure gradient within the core up to a factor of twenty compared to the case without oil. Nonetheless, this pressure gradient is about a factor three greater than we observe by co-injecting crude oil, water without surfactant, and gas. With a simplified model we fit our three-phase co-injection experimental data by increasing the viscosity of both the gas and water, indicating that some weak foam and emulsion is generated. Neither effect by itself can fit the data. In contrast, with crude oil or hexane solubilized in the surfactant solution, the pressure gradient is of the same order of magnitude as for co-injection gas and surfactant with or without solubilized oil. These results indicate that solubilized crude oil does not reduce foam mobility as much as does the crude oil as a separate oleic phase. Furthermore, the effect of solubilized crude on foam is not due only to straight-chain aliphatic components such as hexane: our experiment with solubilized hexane showed a less-significant impact on foam mobility. The major result of our work is that we find that both gas and oil mobility are reduced when co-injecting oil, gas and surfactant solution in a porous medium. Another result is that the solubilized crude oil slightly reduces foam mobility, but does not explain the much-larger detrimental impact of crude oil in a separate phase on foam in a porous media.@en

As foam is injected into an oil reservoir, the region near an injector can become oil-free due to the relatively high capillary number. Foam created in this region encounters oil further out in the reservoir. The impact of oil on foam in porous media is usually investigated by co-injecting surfactant, gas and oil, or by injecting pre-generated foam into an oil-saturated core. However, the former experiment does not give information on the impact of oil on pre-generated foam, and from the latter experiment one cannot easily obtain data at different oil fractional flows, necessary to model the impact of oil on pre-generated foam. Here the impact of crude oil on pre-generated foam is studied by co-injecting surfactant solution and gas into a relative narrow core (0.01 m diameter), and injecting oil into the porous medium some distance downstream from the inlet, through ports in the side of the porous medium. By injecting the three phases into the core we investigate the flow behaviour of foam with oil at fixed fractional flows of all three phases. The relatively narrow core allows rapid contact between the injected crude oil and pre-generated foam. We observe a progressive decrease in the apparent viscosity of the foam after encountering oil. Foams with a higher gas fraction experience a more significant weakening by oil over the length of the core than foams with a lower gas fraction. By the end of the core, the apparent viscosities of foam with a higher gas fraction approach values observed with three-phase co-injection. Foam made with surfactant pre-equilibrated with the crude oil propagated for a shorter distance in presence of oil than foam made with surfactant that hasn’t contacted oil before. We present a novel, but relatively simple method to investigate the change of foam mobility as it encounters oil in a porous medium, at controlled fractional flows of all phases. We show that in our case the apparent viscosity of foam with oil can decrease by more than a factor of four over a distance of 0.15 m, indicating that foam and oil reach steady-state (as observed with three-phase co-injection) almost instantaneously compared to the length of a reservoir-simulation grid-block.@en

Surfactant-alternating-gas (SAG) is a favored method of foam injection, in part because of excellent gas injectivity. However, liquid injectivity is usually very poor in SAG. We report a core-flood study of liquid injectivity under conditions like those near an injection well in SAG application in the field, i.e., after a prolonged period of gas injection following foam. We inject foam [gas (nitrogen) and surfactant solution] into a 17-cm-long Berea core at temperature of 90 °C with 40 bar back pressure. Pressure differences are measured and supplemented with CT scans to relate water saturation to mobilities. Liquid injectivity directly following foam is very poor. During prolonged gas injection following foam, a collapsed-foam region forms near the inlet and slowly propagates downstream, in which water saturation is reduced. This decline in liquid saturation reflects in part liquid evaporation, also pressure-driven flow and capillary effects on the core scale. In the collapsed-foam region, liquid mobility during subsequent liquid injection is much greater than downstream, and liquid sweeps the entire core cross section rather than a single finger. Mobility in the region of liquid fingering is insensitive to the quality of foam injected before gas and the duration of the period of gas injection. This implies that at the start of liquid injection in a SAG process in the field, there is a small region very near the well, crucial to injectivity, substantially different from that further out, and not described by current foam models. The results can guide the development of a model for liquid injectivity based on radial propagation of the various banks seen in the experiments.@en

Surfactant-alternating-gas (SAG) is often the injection method for foam enhanced oil recovery (EOR) in order to improve injectivity. However, liquid injectivity can be very poor once foam is created in the near-wellbore region. In a previous study, we reported core-flood experiments on liquid injectivity after foam flooding and liquid injectivity after a period of gas injection following foam. Results showed the importance of the gas slug to 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 a SAG process. We inject nitrogen foam, gas and surfactant solution into a sandstone core sample. The experiments are conducted at a temperature of 90°C with 40-bar back pressure. Pressure differences are measured to quantify the injectivity and supplemented with CT scans to relate water saturation to mobility. We find that during prolonged gas injection in the first gas slug following foam, a collapsed-foam region forms near the inlet due to the interplay of evaporation, capillary pressure and pressure-driven flow. This region slowly propagates downstream. During subsequent liquid injection, liquid mobility is much greater in the collapsed-foam region than downstream, and liquid sweeps the entire core cross section there rather than a single finger. In the region beyond the collapsed-foam region, liquid fingers through foam. Liquid flow converges from the entire cross section to the finger through the region of trapped gas. During injection of the second gas slug, the liquid finger disappears quickly as gas flows in, and strong foam forms from the very beginning. A collapsed-foam region then forms near the inlet and slowly propagates downstream with a propagation velocity and mobility similar to that in the first gas slug. Behavior of the second liquid slug is likewise similar to that of the first liquid slug. Our results suggest that, in radial flow, the small region of foam collapse very near the well is crucial to injectivity because of its high mobility. The subsequent gas and liquid slugs behave like the first slugs. The behavior of the first gas slug and subsequent liquid slug is thus representative of near-well behavior in a SAG process.@en

Foam can be applied to enhance oil recovery from a reservoir. Currently, to understand and model the behavior of foam in an oil reservoir, experiments need to be conducted in the presence of the specific crude oil, and extrapolating from one crude oil to another is not possible. It is therefore desirable to model the impact of a crude oil on foam solely based on the crude-oil composition. This would allow one to efficiently screen reservoirs for foam application. Here we investigate the behavior of foam in the presence of a crude oil and in the presence of mixtures of pure components, which we choose based on the gas chromatography analysis of the crude oil as well as its total acid number and total base number. To analyze the impact of an oil mixture on bulk foam we shake test tubes with surfactant solution and either a mixture of pure oil components or crude oil and analyze foam height and liquid height over time. We also conduct experiments in a porous medium, where we coinject mixtures of pure components, surfactant solution, and gas. We fix the oil injection rate and vary the ratio of the gas to surfactant solution. We use the following organic compounds (OC) to represent the crude oil: toluene (an aromatic), oleic acid (an organic acid), octanol (an organic base), methylcyclohexane (a cycloalkane), dimethyl sulfoxide (an organosulfur), n-octane, and hexadecane. However, when one or all of the first components is added to a 50/50 (vol %) mixture of n-octane and hexadecane, in proportions similar to their presence in the crude oil, the impact of the oil mixture on foam (both in bulk and in porous media) is only slightly different from the impact of the n-octane and hexadecane mixture. We formed a “synthetic” crude oil, with its composition mimicking the composition of a crude oil and its total acid/base number. Although the pure OC and synthetic crude oil weaken foam in bulk and in porous media, their impact on foam was less severe than the impact of the crude oil on the foam. Based on the composition of an oil mixture and the impact of its components, separately, on foam, it is not clear how to predict the impact of the oil mixture on foam in bulk or porous medium. However, in our case we find a good correlation between the foam apparent viscosity in porous media and the product of the bulk foam half-life and initial volume. One implication is that if either the half-life or initial volume of bulk foam is poor, the foam performs poorly in the porous medium.@en

Dispersed and solubilized oil can impact bulk foam stability differently. Though aromatic components are more soluble in water than straight-chain aliphatic components, solubilized aromatics do not necessarily impact bulk foam stability, whereas straight-chain aliphatic components can have a detrimental impact (Lee et al., “Stability of Aqueous Foams in the Presence of Oil: On the Importance of Dispersed vs Solubilized Oil”, Ind. Eng. Chem. Res., 52,pp. 66−72, 2013). However, to our knowledge there is no research on the impact of solubilized oil on foam in porous media. The impact of the crude oil, as a separate oleic phase, was studied by co-injection of crude oil, surfactant solution and gas in coreflood, on steady-state mobility, captured by the pressure drop across the core. To investigate if the behaviour of steady-state foam with dispersed crude oil can be explained by the solubilized oil components, we perform foam-flooding experiments with surfactant solution previously equilibrated with crude oil. Furthermore, we conduct foam-flooding experiments with solubilized hexane in surfactant solution, to determine if the straight-chain aliphatic components can explain the behaviour of the solubilized crude oil on steady-state foam mobility as it impacts bulk foam in the literature. The crude oil , as a separate oleic phase, reduces the pressure gradient across the core by a factor of twenty compared to the case without oil. Nonetheless, this pressure gradient was about a factor three higher than we observed by co-injecting crude oil, water without surfactant, and gas, which indicates that some weak foam and emulsion was generated by co-injecting surfactant, crude oil, and gas. In contrast, with solubilized crude oil and with solubilized hexane, the pressure gradient is in the same order of magnitude for co-injection gas and surfactant with and without solubilized oil. These results indicate that solubilized crude oil cannot explain the impact of the crude oil as a separate oleic phase on foam mobility in our case. Furthermore, the impact of solubilized crude oil on steady-state foam mobility cannot be explained as the effect of a solubilized straight-chain aliphatic component such as hexane. The major result of our work is that the impact of solubilized crude oil on foam does not explain the detrimental impact of crude oil in a separate oleic phase on foam in a porous media. Another result is that though co-injected water, gas and crude oil might not generate strong foam, it can result in somewhat higher pressure gradients with surfactant in the aqueous phase than without surfactant. This is possibly caused by smaller oil droplets in presence of surfactant and a weak foam.@en