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.
Dupuis, Guillaume (SNF) | Antignard, Sebastien (SNF) | Giovannetti, Bruno (SNF) | Gaillard, Nicolas (SNF) | Jouenne, Stephane (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Zaitoun, Alain (Poweltec)
A great number of Middle East fields have too harsh reservoir conditions (high temperature, high salinity) for conventional EOR polymers used as mobility control agents. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable.
At temperatures above 70°C, acrylamide moieties hydrolyze to acrylate groups which ultimately may lead to precipitation and total loss of viscosifying power. Thermal stability can be improved by incorporating specific monomers such as ATBS or NVP. However, their polymerization reactivity can cause some compositional drift and limit their molecular weight / viscosifying power. Compared to HPAM, they will require a higher dosage and higher cost.
In this study, we present thermal stability and propagation behavior of a new class of synthetic polymers with high thermal stability. In harsh conditions of Middle East brines, with salinity ranging from sea water to 220 g/L TDS, they present excellent thermal stability until temperature as high as 140°C. Adsorption and mobility reduction were evaluated through coreflood experiments using carbonate cores and Clashach sandstone cores, with permeability ranging between 100mD and 700mD. Mobility and permeability reductions indicate a good propagation in both types of rocks.
The development of this new polymer is a major breakthrough to overcome the current limits of polymer EOR applications in harsh reservoir conditions. Moreover, molecular weights can be tailored from low to high molecular weights depending on reservoir permeability. Further work is needed to evaluate resistance to mechanical degradation, salt tolerance and adsorption in carbonates and sandstones.
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.
Morel, Danielle (Total SA) | Al-Amrie, Omar (Total ABK) | Delattre, Eric (Total ABK) | Cordelier, Philippe (Total SA) | Greder, Hugues (Total SA) | Rivero, Mayela (Total US) | Romero, Carolina (Total SA) | Bursaux, Romain (Total SA) | Peltier, Sophie (Total SA) | Levitt, David (TOTAL SA, ADMA)
In 2014, Total performed a surfactant-polymer one spot pilot offshore to test the effectiveness of inhouse developed surfactant molecules to mobilize trapped oil. This paper describes the deployment of this pilot, as a key step of the derisking roadmap of chemical EOR under the harsh salinity and temperature conditions of Middle East carbonates. During several years of R&D and focused studies on this field of the Emirates, a surfactant polymer formulation has been developed able to achieve very low residual oil saturation at core level. The question of testing the formulation in the field has been addressed in parallel to the laboratory work, through extensive surface and subsurface integrated studies, in order to define which type of pilot would be the more suitable.
The paper addresses several aspects: Pilot type selection from a geosciences point of view and versus objectives and information provided: where, how many wells, time response, cost Monitoring needs: base line establishment, injection and production follow up, Surface issues related to the pilot in this offshore context: injection and production top side facilities Chemical logistics when part of the formulation is a R&D chemical, to be manufactured on purpose, and imported in due time, including the choice of premix versus on line mixing products Management of a pilot as a project but still with the specificities of derisking and qualifying a technology on a mature field (from preliminary study to project execution) Offshore concerns, with the added difficulty of a H2S environment
Pilot type selection from a geosciences point of view and versus objectives and information provided: where, how many wells, time response, cost
Monitoring needs: base line establishment, injection and production follow up,
Surface issues related to the pilot in this offshore context: injection and production top side facilities
Chemical logistics when part of the formulation is a R&D chemical, to be manufactured on purpose, and imported in due time, including the choice of premix versus on line mixing products
Management of a pilot as a project but still with the specificities of derisking and qualifying a technology on a mature field (from preliminary study to project execution)
Offshore concerns, with the added difficulty of a H2S environment
After a cautious analysis of the pros and cons, a one spot pilot has been sanctioned. The design of the pilot versus effective realization is provided, together with the decision tree that was constructed in order to face any operational issue. The paper emphasizes how a strong project management, and headquarters/operational team collaboration allowed completing a safe and successful pilot, ultimately achieving ultra low residual oil at the one spot scale.
The success of a pilot project is conditioned to the strict application of a rigorous methodology of study, validation, and execution, like any development project
In 2014, TOTAL performed two Single Well Tracer Tests (SWTT) to evaluate the remaining oil saturation in an offshore high temperature, high salinity carbonate reservoir. The SWTT method has proved to be a reliable way, when carefully programmed, to measure a representative remaining oil saturation without being impacted by near wellbore effects. The objective of these measurements was to evaluate the efficiency of a single well chemical EOR (CEOR) pilot by measuring oil desaturation.
Extensive in-house laboratory work was carried out by TOTAL to lay the foundation for the pre and post CEOR pilot SWTTs. A specific tracer injection skid was internally developed to ease the operations. Specific numerical work was performed to achieve robust designs and interpretations. These simulations, carried out in-house, took into account all major uncertainties highlighted by experimental work. Detailed results from the SWTT preparation phase will be described in the paper.
Results from the baseline SWTT interpretation evidenced excellent quality tracer profiles from the first test and high remaining oil saturation, improving our knowledge on the flooding pattern of this reservoir. Results from the post EOR SWTT showed again a clear response of a remarkable decrease in remaining oil saturation, proving the efficiency of the chemical formulation provided by TOTAL and the envisaged recovery mechanism. Interpretation of these Single Well Tracer Tests also allowed us to evidence a much lower than anticipated reservoir dispersion. These findings highlight the potential of EOR implementations in these carbonate formations.
Lessons learned from these two offshore SWTTs are discussed in this paper, such as the need for specific preparation to tackle the complexity of a high temperature high salinity carbonate reservoir in presence of H2S. TOTAL has shown that such operations can be performed in a strict timeframe while adhering to company safety rules. Careful interpretation of such results is mandatory to validate the success of the single well chemical EOR pilot.