The novel enhanced oil recovery (EOR) technique combining the reduction of oil/water (o/w) interfacial tensions (IFT) to ultralow values and generation of a foam drive for mobility control is known as foam-assisted chemical flooding (FACF). We present a well-controlled laboratory study on the feasibility of FACF at reservoir conditions. Two specially selected chemical surfactants were screened on their stability in sea water at 90 °C. The ability of both surfactants to generate stable foam in bulk was studied in the presence and absence of crude oil. It led to the composition of the foam drive formulation for drive mobility control. Phase behavior scan studies, for the two crude oil/surfactant/brine systems, yielded the design of the chemical slug capable of mobilizing residual oil by drastically lowering the o/w IFT. Core-flood experiments were performed in Bentheimer sandstones previously brought to a residual oil to waterflood of 0.33 ± 0.02. A surfactant slug at under-optimum (o/w IFT of 10^-2 mN/m) or optimum (o/w IFT of 10^-3 mN/m) salinity was injected for mobilizing residual oil. It resulted in the formation of an unstable oil bank because of dominant gravitational forces at both salinities. Next, a foam drive was generated either in situ, by co-injecting nitrogen gas and surfactant solution, or pregenerated ex situ and then injected to displace the oil bank. We found that (i) the presence of the crude oil used in this work has a detrimental effect on foam stability in bulk and foam strength in Bentheimer sandstones, (ii) optimum salinity FACF was able to increase the ultimate oil recovery with 5% of the oil in place (OIP) after water flooding compared with under-optimum FACF, and (iii) injection of pregenerated drive foam increased its ultimate oil recovery by 13% of the OIP after water flooding compared to in situ drive foam generation at optimum salinity.

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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

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

Foam reduces gas mobility and can improve sweep efficiency in an enhanced-oil-recovery (EOR) process. Previous studies show that foam can be generated in porous media by exceeding a critical velocity or pressure gradient. This requirement is typically met only near the wellbore, and it is uncertain whether foam can propagate several tens of meters away from wells as the local pressure gradient and superficial velocity decreases. Theoretical studies show that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability. In this study, we validate theoretical predictions through a variety of experimental evidence. Coreflood experiments involving simultaneous injection of gas and surfactant solution at field-like velocities are presented. We use model consolidated porous media made out of sintered glass, with a well-characterized permeability transition in each core. The change in permeability in these artificial cores is analogous to sharp, small-scale heterogeneities, such as laminations and cross laminations. Pressure gradient is measured across several sections of the core to identify foam-generation events and the subsequent propagation of foam. X-ray computed tomography (CT) provides dynamic images of the coreflood with an indication of foam presence through phase saturations. We investigate the effects of the magnitude of permeability contrast on foam generation and mobilization. Experiments demonstrate foam generation during simultaneous flow of gas and surfactant solution across a sharp increase in permeability, at field-like velocities. The experimental observations also validate theoretical predictions of the permeability contrast required for foam generation by “snap-off” to occur at a certain gas fractional flow. Pressure-gradient measurements across different sections of the core indicate the presence or absence of foam and the onset of foam generation at the permeability change. There is no foam present in the system before generation at the boundary. CT measurements help visualize foam generation and propagation in terms of a region of high gas saturation developing at the permeability transition and moving downstream. If coarse foam is formed upstream, then it is transformed into stronger foam at the transition. Significant fluctuations are observed in the pressure gradient across the permeability transition, suggesting intermittent plugging and mobilization of flow there. This is the first CT-assisted experimental study of foam generation by snap-off only, at a sharp permeability increase in a consolidated medium. The results of experiments reported in this paper have important consequences for a foam application in highly heterogeneous or layered formations. Not including the effect of heterogeneities on gas mobility reduction in the presence of surfactant could underestimate the efficiency of the displacement process.@en

A laboratory study of principal immiscible gas flooding schemes is reported. Very well-controlled experiments on continuous gas injection, water-alternating-gas (WAG) and alkaline–surfactant–foam (ASF) flooding were conducted. The merits of WAG and ASF compared to continuous gas injection were examined. The impact of ultra-low oil–water (o/w) interfacial tension (IFT), an essential feature of the ASF scheme along with foaming, on oil mobilisation and displacement of residual oil to waterflood was also assessed. Incremental oil recoveries and related displacement mechanisms by ASF and WAG compared to continuous gas injection were investigated by conducting CT-scanned core-flood experiments using n-hexadecane and Bentheimer sandstone cores. Ultimate oil recoveries for WAG and ASF at under-optimum salinity (o/w IFT of 10⁻¹ mN/m) were found to be similar [60 ± 5% of the oil initially in place (OIIP)]. However, ultimate oil recovery for ASF at (near-)optimum salinity (o/w IFT of 10⁻² mN/m) reached 74 ± 8% of the OIIP. Results support the idea that WAG increases oil recovery over continuous gas injection by drastically increasing the trapped gas saturation at the end of the first few WAG cycles. ASF flooding was able to enhance oil recovery over WAG by effectively lowering o/w IFT (< 10⁻¹ mN/m) for oil mobilisation. ASF at (near-)optimum salinity increased clean oil fraction in the production stream over under-optimum salinity ASF.

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Foam reduces gas mobility and can help improve sweep efficiency in an enhanced oil recovery process. For the latter, long-distance foam propagation is crucial. In steady gas-liquid flow, foam is generated in homogeneous porous media by exceeding a critical pressure gradient, which normally only happens near the wellbore. Away from wells, these requirements may not be met, and foam propagation is uncertain. It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability. This could dominate foam generation away from wells in layered or laminated geological formations and can improve the chances of success of a foam application. The objective of this study is to validate theoretical explanations through experimental evidence and to quantify the effect of permeability contrast, velocity and fractional flow on this process. In this study, we validate theoretical predictions through a variety of experimental evidence. Coreflood experiments involving co-injection of gas and surfactant solution at field-like velocities were performed. Layered, consolidated and well-characterized sintered glass cores were used as the porous media. The permeability change in each core was analogous to sharp, small-scale heterogeneities such as laminations and cross-laminations. The experiments were carefully designed not to allow foam generation by mechanisms other than snap-off at the permeability boundary in the core. Local pressure gradient was measured at various locations and was used to identify foam generation and subsequent propagation through the porous medium. Additionally, X-ray computed tomography (CT) was employed to detect changes in phase saturation that accompany foam generation and subsequent propagation downstream. CT-based saturations measurements were also used to qualitatively chart the reduction in capillary pressure across the sharp permeability jump, supporting theoretical explanations behind this process. The effect of permeability contrast, superficial velocity and flowing gas fraction on this process was also investigated. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous theory (Rossen, 1999). Conditions for propagation of foam were explored by successively performing experiments at lower velocities and higher gas fractional flows. Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate - probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and greater permeability contrasts. @en

Foam reduces gas mobility and can improve sweep efficiency in an enhanced-oil-recovery process. Previous studies show that foam can be generated in porous media by exceeding a critical velocity or pressure gradient. Such pressure gradients are typically encountered only near a well and therefore, it is uncertain whether foam can propagate far from wells. Theoretical studies show that foam can be generated independent of pressure gradient during flow across an abrupt increase in permeability. In subsurface flow, such sharp permeability changes occur across different length scales. Laminations and cross-laminations, for example, are commonly found small-scale features, whereas unconformities, including layer boundaries and erosional surfaces, are field-scale features that are associated with sharp permeability contrasts across them. In this study, we validate theoretical predictions of foam generation through a variety of experimental evidence. We perform coreflood experiments involving simultaneous injection of gas and surfactant solution at field-like velocities into a model consolidated porous medium made of sintered glass. The core has a well-characterized, sharp permeability transition achieved by sintering glass of different grain sizes. Pressure gradient is measured across several sections of the core to identify foam-generation events and the subsequent propagation of foam. X-ray computerized tomography (CT) provides dynamic images of the coreflood in the form of phase saturations as they develop through the experiment. We investigate the effects of the magnitude of the permeability change and injected gas fractional flow on foam generation and mobilization.@en