Modeling foam flow through porous media in the presence of oil is essential for various foam-assisted enhanced oil recovery (EOR) processes. We performed an in-depth literature review of foam-oil interactions and related foam modeling techniques, and demonstrated the feasibility of an improved bubble populationbalance model in this paper. We reviewed both theoretical and experimental aspects of foam-oil interactions and identified the key parameters that control the stability of foam lamellae with oil in porous media. Upon reviewing existing modeling methods for foam flow in the presence of oil, we proposed a unified population-balance model that can simulate foam flow both with and without oil in standard finite-difference reservoir simulators. Steadystate foam apparent viscosity as a function of foam quality was used to evaluate the model performance and sensitivity at various oil saturations and fluid velocities. Our literature review suggests that, among various potential foam-oil interaction mechanisms, the pseudo-emulsion-film (gas/aqueous/oil asymmetric film) stability has a major impact on the foam-film stability when oil is present.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Jian, Guoqing (Rice University) | Ma, Kun (Total) | Mateen, Khalid (Total) | Ren, Guangwei (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Biswal, Sibani (Rice University) | Hirasaki, George (Rice University)
The high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-mD formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions.
The low-IFT foam process was investigated through core flooding experiments in homogenous and fractured oil-wet cores with sub-10-mD matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer (AOS C14-16) were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the core flooding experiments.
Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-mD matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-mD matrix permeability achieved 64% incremental oil recovery compared to water flooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluids flow in it. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids, such as mineral dissolution and the exchange of Calcium and Magnesium, were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It therefore may cause injectivity and phase trapping issues especially in the homogenous limestone.
Results in this work demonstrated that despite the challenges associated with limestone dissolution, a low-IFT foam process can remarkably extend chemical EOR in fractured oil-wet tight reservoirs with matrix permeability as low as 5 mD.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Jian, Guoqing (Rice University) | Ma, Kun (Total E&P) | Mateen, Khalid (Total E&P) | Ren, Guangwei (Total E&P) | Bourdarot, Gilles (Total E&P) | Morel, Danielle (Total E&P) | Bourrel, Maurice (Total E&P) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George (Rice University)
Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This paper describes the use of a low-interfacial-tension (low-IFT) foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding.
A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. The optimized formulation simultaneously can generate IFT of 10-2 mN/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. Coreflood results also indicate that the low-IFT foam diverts primarily the aqueous surfactant solution into the matrix because of (1) mobility reduction caused by foam in the fracture, (2) significantly lower capillary entry pressure for surfactant solution compared with gas, and (3) increasing the water relative permeability in the matrix by decreasing the residual oil. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs.
Higher stability of the bulk and dynamic foam with polymer addition to the aqueous phase has been demonstrated experimentally. Recent experiments indicated that the efficacy of polymer enhanced foam (PEF) is dependent on polymer type and surfactant-polymer interaction. However, numerical modeling of PEF flow in porous media has been relatively less well understood due to the additional complexity. In this work, we propose modifications to the population-balance foam model for PEF modeling, and their successful use in matching the experimental results.
The population-balance model proposed by Chen and co-workers has been used as development platform. Upon reviewing various aspects in the physics of foam generation, coalescence and mobility reduction in porous media with the addition of polymer, a modified population-balance model was proposed with new parameters pertaining to the polymer effect on the net foam generation and the limiting capillary pressure. The new model was implemented and used to history match foam coreflood experiments with and without polymer.
In addition to the foam apparent viscosity increase due to higher viscosity of the aqueous phase, polymer also impacts foamability and foam stability of bulk foam as indicated in the literature. Our modified population-balance model introduce the viscosity terms in foam generation and coalescence coefficients to account for postulated positive impact on reducing liquid drainage and foam coalescence and negative impact on the characteristic time needed for bubble snap-off in porous media. Additionally, a modification in the limiting capillary pressure was proposed in the new model to include the polymer effect based on our analysis of the disjoining pressure. Two new model parameters are proposed and implemented accordingly. The new foam model succeeded in history-matching the anionic-surfactant-based and nonionic-surfactant-based PEF corefloods with different types of polymers through tuning the two new model parameters. The simulations also captured the transient increasing of the pressure drops induced by polymer transport and adsorption. The proposed model can be used to provide meaningful values of the model parameters that were able to explain the physical mechanisms behind the PEF floods and to guide future experimental design to further constraint the choices of model parameters.
This work provided new methodology to model PEF flow in porous media using the mechanistic population-balance approach for the first time. With proper calibrations of the parameters proposed in the model, the new model can therefore be used to simulate PEF EOR processes to describe the combined effect of foam and polymer on the mobility control of the injectants.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Ma, Kun (Total) | Mateen, Khalid (Total) | Ren, Guangwei (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George (Rice University)
Oil recovery in many carbonate reservoirs is challenging due to unfavorable conditions such as oil-wet surface wettability, high reservoir heterogeneity and high brine salinity. We present the feasibility and injection strategy investigation of ultralow-interfacial-tension (ultralow-IFT) foam in a high temperature (above 80°C), ultra-high formation salinity (above 23% TDS) fractured carbonate reservoir.
Because a salinity gradient is generated between injection sea water (4.2% TDS) and formation brine (23% TDS), a frontal-dilution map was created to simulate frontal displacement processes and thereafter used to optimize surfactant formulations. IFT measurements and bulk foam tests were also conducted to study the salinity gradient effect to ultralow-IFT foam performance. Ultralow-IFT foam injection strategies were investigated through a series of core flood experiments in both homogenous and fractured core systems with initial two-phase saturation. The representative fractured system included a well-defined fracture by splitting core sample lengthwise and controllable initial oil/brine saturation in the matrix by closing the fracture with a rubber sheet at high confining pressure.
The surfactant formulation showed ultra-low IFT (10-2-10-3 mN/m magnitude) at the displacement front and good foamability at under-optimum conditions. Both ultralow-IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow-IFT foam flooding achieved over 60% incremental oil recovery compared to water flooding in oil-wet fractured systems due to the selective diversion of ultralow-IFT foam. This effect resulted in crossflow near foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high-salinity brine flowed back to the fracture ahead of the front. The crossflow of oil/high-salinity brine from the matrix to the fracture was found to make it challenging for foam propagation in the fractured system by forming Winsor II condition near foam front and hence killing the existing foam.
Results in this work demonstrated the feasibility of ultralow-IFT foam in high temperature, ultra-high salinity fractured carbonate reservoirs and investigated the injection strategy to enhance the low-IFT foam performance. The ultralow-IFT formulation helped mobilize the residual oil for better displacement efficiency. The selective diversion of foam makes it a good candidate as a mobility control agent in fractured system for better sweep efficiency.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Ma, Kun (Total) | Mateen, Khalid (Total) | Ren, Guangwei (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Bourrel, Maurice (Total) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George (Rice University)
Oil recovery in highly heterogeneous carbonate reservoirs is typically inefficient because of the high permeable fracture networks and unfavorable capillary force resulting from oil-wet matrix. Foam as a mobility control agent has been proposed to mitigate reservoir heterogeneity by diverting injected fluids from the highly permeable fractured zones into the low permeable unswept rock matrix, hence improving the sweep efficiency. This paper presents the use of a low-interfacial-tension foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. The novel formulation providesboth mobility control and oil-water interfacial tension (IFT) reduction to overcome the unfavorable capillary forces preventingdisplacing fluids from entering oil-filled matrix. Thus, as expected, the combination of these two effects significantly improves oil recovery compared to either foam or surfactant flooding.
In this research, the three-component surfactant formulation was tailored by phase behavior tests in seawater with crude oil from a targeted reservoir. The optimized formulation can simultaneously generate 10−2 mN/m IFT and strong foam in porous media with oil present, as demonstrated by IFT measurements and foam floodingtests. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting core lengthwise and precisely controlled of aperture by applying specific confining pressure. The foam flooding experiments reveal that the low-IFT foaming formulation in an oil-wet fractured Edward Brown dolomite recovers about 72% of oil while water flooding only recovers less than 2%,and it is more efficient than foam flooding lacking low oil-water IFT property.The core flood test results also indicate that low-IFT foam diverts mostly surfactant solution into matrix because of (1) the mobility reduction due to foam in the fracture network, (2) significantly lower capillary entry pressure for surfactant solution compared to gas and (3) the increase of mobility to water in the matrix by the low oil-water IFT displacing residual oil in the matrix. This selective diversion effect of the novel foaming system allows to carry out the surfactant flooding at low IFT condition in the low permeability matrix to recover the trapped oil, which is otherwise impossible with simple surfactant or high-IFT foam flooding in highly heterogeneous or fractured reservoirs.
A correct understanding of foam generation, coalescence and transport at achievable reservoir flow rates has been a key issue for its applications in enhanced oil recovery processes. Use of foam models to simulate foam flow in the reservoir requires establishing of the parameters in the lab. This is generally done at relatively high flow rates in a so-called strong-foam state, which covers both high- and low-quality foam regimes that are used to fit foam modeling parameters. In the reservoir, because of the in situ velocities changing between near and far from the wellbore, there is a need for the foam model to be able to predict the foam behavior at two different foam states with high and low velocities, respectively. Depending upon the petrophysical properties of the reservoir, one may not generate and transport strong foam at the low-velocities away from the well.
Bubble population-balance models are considered a useful tool to understand foam flow through porous media by addressing the phenomenon from the first principle of physics. We investigated the capability of available population-balance models to simulate these two foam states over a wide range of velocities. Using an example case, the same set of data was fit to two well-known models at relatively high flow rates. Both models fit the steady-state data at high-flow rates reasonably well through proper tuning of the parameters. One foam model, reported by Afsharpoor and co-workers in 2010, predicted a weak-foam state with much lower apparent viscosity at low flow rates; however, the other model, reported by Chen and co-workers in 2010, predicted much higher pressure gradient at low flow rates with the same set of relative permeability and capillary pressure curves, due to the shear-thinning effect and the foam generation effect in the absence of a minimum pressure gradient (MPG). We observed significantly different foam rheology above the MPG: shear-thinning behavior when the foam texture reaches the maximum and Newtonian behavior when the foam texture is below the maximum. Below the MPG, a shear-thickening behavior, with an abrupt change at the boundary, was predicted by Afsharpoor model as was earlier observed in several experiments reported in the literature. The sensitivity of MPG to the corresponding critical velocity in Afsharpoor model is also studied in this work.
The data acquired in steady-state experiments have to be in the strong-foam state in order to estimate correct parameters in the model to simulate foam behavior in high- and low-quality regimes. However, if the experimental data acquired at low fluid velocities is available and indicates a weak-foam state at low velocities, one can use Afsharpoor model to predict this weak-foam state away from the well. Note that the findings are limited to steady-state foam flows in relatively homogeneous systems, while transient foam modeling and the impact of heterogeneity / pore-network distribution are yet to be investigated.
Nguyen, N. (The University of Texas at Austin) | Ren, Guangwei (Total E&P USA) | Mateen, K. (Total E&P USA) | Cordelier, P. R. (Total CSTJF) | Morel, D. C. (Total S.A.) | Nguyen, Quoc P. (The University of Texas at Austin)
The work presented in this paper evaluates the potential of Low-Tension Gas (LTG) as an alternative to polymer flood for displacing the surfactant slug in a chemical EOR process in ultra-high salinity (above 189,000 ppm TDS), high temperature (above 85°C) sandstone reservoirs. The LTG process involves the use of surfactant and gas to achieve the mobility control required to displace the micro-emulsions and the crude oil. The optimal formulation of surfactants is identified to obtain good oil/water microemulsion phase behavior and desirable high optimum salinity. The latter feature allows the LTG process to work with a wide variation of injection brine salinity or in-situ salinity gradient. The optimal injection strategies are then determined through a series of oil recovery core floods with co-injection of gas and the surfactant solution. Tertiary recovery of up to 90% of the residual OIP was achieved for cores with 150–400md air permeability. The high optimum salinity that is closest to the formation brine salinity was found to give the highest incremental oil recoveries. Macroscopic stability of displacement fronts was studied via pressure derived mobility ratios. Approximate parity of relative mobility of injected fluids was observed with respect to relative mobility of displaced water at true residual oil saturation and interpreted relative mobility of a formed oil bank. These results indicate that in-situ foam propagation was present which enabled mobility control, and that stable displacement of in-situ fluids was achieved during flooding. By replacing polymer with foam, chemical EOR methods can be expanded into formations where the use of polymer is impractical.
Foam, a dispersion of gas in liquid, has been investigated as a tool for gas-mobility and conformance control in porous media for a variety of applications since the late 1950s. These applications include enhanced oil recovery, matrix-acidization treatments, gas-leakage prevention, as well as contaminated-aquifer remediation. To understand the complex physics of foam in porous media and to implement foam processes in a more-controllable way, various foam-modeling techniques were developed in the past 3 decades. This paper reviews modeling approaches obtained from different publications for describing foam flow through porous media. Specifically, we tabulate models on the basis of their respective characteristics, including implicit-texture as well as mechanistic population-balance foam models. In various population-balance models, how foam texture is obtained and how gas mobility is altered as a function of foam texture, among other variables, are presented and compared. It is generally understood that both the gas relative permeability and viscosity vary in the reduction of gas mobility through foam generation in porous media. However, because the two parameters appear together in the Darcy equation, different approaches were taken to alter the mobility in the various models: only reduction of gas relative permeability, increasing of effective gas viscosity, or a combination of both. The applicability and limitations of each approach are discussed. How various foam-generation mechanisms play a role in the foam-generation function in mechanistic models is also discussed in this review, which is indispensable to reconcile the findings from different publications. Additionally, other foam-modeling methods, such as the approaches using the fractional-flow theory and those that use percolation theory, are also reviewed in this work. Several challenges for foam modeling, including model selection and enhancement, fitting parameters to data, modeling oil effect on foam behavior, and scaling up of foam models, are also discussed at the end of this paper.
Foam, a dispersion of gas in liquid, has been investigated as a tool for gas mobility and conformance control in porous media for a variety of applications since late 1950s. These applications include enhanced oil recovery, matrix acidization treatments, gas leakage prevention, as well as contaminated aquifer remediation. In order to understand the complex physics of foam in porous media and to implement foam processes in a more controllable way, various foam modeling techniques have been developed in the past three decades.
This paper reviews modeling approaches obtained from different publications for describing foam flow through porous media. Specifically, we tabulate models based on their respective characteristics, including empirical and semi-empirical as well as mechanistic population-balance foam models. In population-balance models, how different formulations alter gas mobility as a function of foam texture, among other variables, and how foam texture is obtained are presented and compared. It is generally understood that both the relative permeability and the gas viscosity vary in the reduction of gas mobility through foam generation in porous media. However, as the two parameters appear together in the Darcy’s equation, different approaches have been taken to alter the mobility in the various models: only reduction of gas relative permeability to account for the trapped gas effect, increasing only the effective gas viscosity to account for the flowing resistance of moving lamellae, or a combination of both of them. The applicability and limitations of each approach will be discussed. How various foam generation mechanisms play a role in the foam generation function in mechanistic models is also discussed in this review, which is indispensable to reconcile the findings from different publications. Additionally, other foam modeling methods, such as the approaches using the fractional flow theory and those using the percolation theory, are also reviewed in this work. Several challenges for foam modeling, including model selection and enhancement, fitting parameters to data, modeling oil effect on foam behavior, and upscaling of foam models are also discussed.