Strong Foam Research Articles

Low-IFT Foaming System for Enhanced Oil Recovery in Highly Heterogeneous/Fractured Oil-Wet Carbonate Reservoirs

Summary 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.

Investigating Supercritical CO2 Foam Propagation Distance: Conversion from Strong Foam to Weak Foam vs. Gravity Segregation

This study investigates how to determine the optimal supercritical CO2 foam injection strategies, in terms of total injection rate (or injection pressure, equivalently) and injection foam quality, to place injected foams deep and far into the reservoir. Two different mechanisms that limit field foam propagation, such as “conversion from strong foam to weak foam” and “gravity segregation,” are examined separately, and the results are combined together. The first is performed by using a mechanistic foam model based on bubble population balance, while the second is conducted by an analytical model (called Stone and Jenkins model) and reservoir simulations with a commercial software (CMG-STARS). Note that the gas-phase mobility, required as a key input parameter for gravity segregation simulations, is calibrated by the mechanistic model, which is a significant advance in this study. The results from both mechanisms show in general that foam propagation distance increases with increasing injection pressure or rate (which is often limited by the formation fracturing pressure) and increases with decreasing foam quality down to a certain threshold foam quality below which the distance is not sensitive to foam quality any longer. It is found that the mobilization pressure gradient (i.e., the pressure gradient above which foam films are mobilized to create a population of bubbles) plays a key role to determine the distance. Therefore, the injection of supercritical CO2 foams with lower mobilization pressure gradient should be more favored in field applications. As a step prior to real-world reservoir applications, this study deals with a relatively ideal reservoir (i.e., large homogeneous cylindrical reservoir) focusing on the steady state after foam treatment in the absence of oil.

Foaming Behavior of CO2-Soluble, Viscoelastic Surfactant

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190302, “Foaming Behavior of CO2-Soluble Viscoelastic Surfactant in Homogeneous Porous Media,” by Galang Ramadhan, The University of Texas at Austin; George Hirasaki, SPE, Rice University; and Quoc P. Nguyen, SPE, The University of Texas, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. Aqueous foam has been demonstrated to have promise in conformance-control applications. This paper explores the foaming behavior of a CO2-soluble, cationic, amine-based surfactant. A distinguishing feature of this surfactant is its ability to dissolve in supercritical CO2 and to form wormlike micelles (WLMs) at elevated salinity. The presence of WLMs leads to an increase in viscosity of the aqueous surfactant solution. This paper investigates how the presence of WLM structures affects transient foam behavior in a homogeneous porous media (sandpack). Introduction Aqueous foam is a dispersion of a gas in an aqueous phase with a surface-active agent (surfactant) to lower the interfacial tension between the two phases. Foam functions as an effective mobility-control agent because of its high apparent viscosity in porous media. Foam’s mobility in porous media is also influenced by the media’s relative permeability. In porous media, foam’s ability to flow from one pore to another is heavily dependent upon overcoming the capillary forces imposed by the pore-throat constrictions. Because of this yield-stress requirement, a large portion of a foam system in a porous media is not mobile. This fraction of trapped foam could occupy up to 65% of total pore volume, depending on foam-injection quality, injection velocity, and porous-media morphology. Trapped foam severely reduces the effective permeability of gas moving through a porous media by reducing the number of conduits through which the foam can flow. Addition of Polymer and Polymer-Like Structures The addition of polymer to a surfactant solution typically increases a foam’s apparent viscosity. From the perspective of foam generation, the addition of polymer to a surfactant solution seems to decrease the rate of foam-generation events. With the addition of liquid-phase-viscosifying polymer, a greater pressure gradient needs to be applied to reach the onset of strong foam generation. The higher pressure-gradient requirement could translate to fewer foam-generation events and potentially limit the foam generation to the near-injection-well region. From the perspective of foam stability, addition of polymer seems to reduce the occurrence of lamellae destruction. Immediately after the formation of fresh foam bubbles, the lamellae are subjected to disturbance forces that reduce the thickness of the lamellae’s liquid phase (film). The thinning process continues until the film reaches a critical thickness at which the lamella is not stable and tends to coalesce. Polymer improves the stability of thick foam film by increasing its viscosity and reducing the rate of film drainage.

Modeling foam flow at achievable flow rates in the subterranean formation using the population-balance approach and implications for experimental design

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.

Destabilization, Propagation, and Generation of Surfactant-Stabilized Foam during Crude Oil Displacement in Heterogeneous Model Porous Media.

Foam flooding in porous media is of increasing interest due to its numerous applications such as enhanced oil recovery, aquifer remediation, and hydraulic fracturing. However, the mechanisms of oil-foam interactions have yet to be fully understood at the pore level. Here, we present three characteristic zones identified in experiments involving the displacement of crude oil from model porous media via surfactant-stabilized foam, and we describe a series of pore-level dynamics in these zones which were not observed in experiments involving paraffin oil. In the displacement front zone, foam coalesces upon initial contact with crude oil, which is known to destabilize the liquid lamellae of the foam. Directly upstream, a transition zone occurs where surface wettability is altered from oil-wet to water-wet. After this transition takes place, a strong foam bank zone exists where foam is generated within the porous media. We visualized each zone using a microfluidic platform, and we discuss the unique physicochemical phenomena that define each zone. In our analysis, we also provide an updated mechanistic understanding of the "smart rheology" of foam which builds upon simple "phase separation" observations in the literature.

Comparative study of ultra-lightweight pulp foams obtained from various fibers and reinforced by MFC

A range of cellulose-based, ultra-lightweight pulp foams with different morphologies were prepared and reinforced with microfibrillated cellulose (MFC). By careful design of the pulp foam forming process, free-standing ultra-lightweight pulp foams were obtained through high velocity mixing and air/oven drying from cellulose fiber in the presence of surfactant, MFC, and retention aid. The effects of different types of fibers and surfactants on the air uptake volumes and mechanical properties of the foam were systematically investigated. The structures characterized using an optical microscope and scanning electron microscope (SEM) showed that the foam was composed of wood fibers into two- or three-dimensional microstructures within random orientations surrounding gas bubbles. The results indicated that in spite of the strength of the foam could be manipulated by varying the surfactants and processing parameters, the addition of MFC indeed improved strength of pulp foams further. The process developed in this work provides a cost effective approach to fabricate the strong and ultra-lightweight pulp foam, with a density lower than 0.02g/cm3, using a standard handsheet former.

Investigation of Chemical-Foam Design as a Novel Approach toward Immiscible Foam Flooding for Enhanced Oil Recovery.

Strong foam can be generated in porous media containing oil, resulting in incremental oil recovery; however, oil recovery factor is restricted. A large fraction of oil recovered by foam flooding forms an oil-in-water emulsion, so that costly methods may need to be used to separate the oil. Moreover, strong foam could create a large pressure gradient, which may cause fractures in the reservoir. This study presents a novel chemical-foam flooding process for enhanced oil recovery (EOR) from water-flooded reservoirs. The presented method involved the use of chemically designed foam to mobilize the remaining oil after water flooding and then to displace the mobilized oil to the production well. A blend of two anionic surfactant formulations was formulated for this method: (a) IOS, for achieving ultralow interfacial tension (IFT), and (b) AOS, for generating a strong foam. Experiments were performed using Bentheimer sandstone cores, where X-ray CT images were taken during foam generation to find the stability of the advancing front of foam propagation and to map the gas saturation for both the transient and the steady-state flow regimes. Then the proposed chemical-foam strategy for incremental oil recovery was tested through the coinjection of immiscible nitrogen gas and surfactant solutions with three different formulation properties in terms of IFT reduction and foaming strength capability. The discovered optimal formulation contains a foaming agent surfactant, a low IFT surfactant, and a cosolvent, which has a high foam stability and a considerably low IFT (1.6 × 10–2 mN/m). Coinjection resulted in higher oil recovery and much less MRF than the same process with only using a foaming agent. The oil displacement experiment revealed that coinjection of gas with a blend of surfactants, containing a cosolvent, can recover a significant amount of oil (33% OIIP) over water flooding with a larger amount of clean oil and less emulsion.

The effect of nanoparticle aggregation on surfactant foam stability

The combination of nanoparticles (NPs) and surfactant may offer a novel technique of generating stronger foams for gas mobility control. This study evaluates the potential of silica NPs to enhance the foam stability of three nonionic surfactants. Results showed that the concentration of surfactant and NPs is a crucial parameter for foam stability and that there is certain concentrations for strong foam generation. A balance in concentration between the nonionic surfactants and the NPs can enhance the foam stability as a result of forming flocs in solutions. At fixed surfactant concentration, the addition of NPs at low to intermediate concentrations can produce a more stable foam compared to the surfactant. The production of small population of flocs as a result of mixing the surfactant and NPs can enhance the foam stability by providing a barrier between the gas bubbles and delaying the coalescence of bubbles. Moreover, these flocs can increase the solution viscosity and, therefore, slow the drainage rate of thin aqueous film (lamellae). The measurements of foam half-life, bubble size, and mobility tests confirmed this conclusion. However, the addition of more solid particles or surfactant might have a negative impact on foam stability and reduce the maximum capillary pressure of coalescence as a result of forming extensive aggregates.

Light and Strong Hierarchical Porous SiC Foam for Efficient Electromagnetic Interference Shielding and Thermal Insulation at Elevated Temperatures.

A novel light but strong SiC foam with hierarchical porous architecture was fabricated by using dough as raw material via carbonization followed by carbothermal reduction with silicon source. A significant synergistic effect is achieved by embedding meso- and nanopores in a microsized porous skeleton, which endows the SiC foam with high-performance electromagnetic interference (EMI) shielding, thermal insulation, and mechanical properties. The microsized skeleton withstands high stress. The meso- and nanosized pores enhance multiple reflection of the incident electromagnetic waves and elongate the path of heat transfer. For the hierarchical porous SiC foam with 72.8% porosity, EMI shielding can be higher than 20 dB, and specific EMI effectiveness exceeds 24.8 dB·cm3·g-1 at a frequency of 11 GHz at 25-600 °C, which is 3 times higher than that of dense SiC ceramic. The thermal conductivity reaches as low as 0.02 W·m-1·K-1, which is comparable to that of aerogel. The compressive strength is as high as 9.8 MPa. Given the chemical and high-temperature stability of SiC, the fabricated SiC foam is a promising candidate for modern aircraft and automobile applications.

Experimental Study of Hysteresis behavior of Foam Generation in Porous Media

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.

Intermittent large amplitude internal waves observed in Port Susan, Puget Sound

A previously unreported internal tidal bore, which evolves into solitary internal wave packets, was observed in Port Susan, Puget Sound, and the timing, speed, and amplitude of the waves were measured by CTD and visual observation. Acoustic Doppler current profiler (ADCP) measurements were attempted, but unsuccessful. The waves appear to be generated with the ebb flow along the tidal flats of the Stillaguamish River, and the speed and width of the resulting waves can be predicted from second-order KdV theory. Their eventual dissipation may contribute significantly to surface mixing locally, particularly in comparison with the local dissipation due to the tides. Visually the waves appear in fair weather as a strong foam front, which is less visible the farther they propagate.

Foam Diversion in Heterogeneous Reservoirs: Effect of Permeability and Injection Method

SummaryFoam can divert flow from higher- to lower-permeability layers and thereby improve the injection profile in gas-injection enhanced oil recovery (EOR). This paper compares two methods of foam injection, surfactant-alternating-gas (SAG) and coinjection of gas and surfactant solution, in their abilities to improve injection profiles in heterogeneous reservoirs. We examine the effects of these two injection methods on diversion by use of fractional-flow modeling. The foam-model parameters for four sandstone formations ranging in permeability from 6 to 1,900 md presented by Kapetas et al. (2015) are used to represent a hypothetical reservoir containing four noncommunicating layers.Permeability affects both the mobility reduction of wet foam in the low-quality-foam regime and the limiting capillary pressure at which foam collapses. The effectiveness of diversion varies greatly with the injection method. In a SAG 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. (2015). Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This favors diversion away from high-permeability layers that receive a large surfactant slug. However, there is an optimum surfactant-slug size: Too little surfactant and diversion from high-permeability layers is not effective, whereas with too much, mobility is reduced in low-permeability layers. For a SAG process, injectivity and diversion depend critically on whether 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 injection time. Injectivity is extremely poor with foam injection for these extremely strong foams, but for some SAG foam processes with effective diversion it is better than injectivity in a waterflood.

Understanding aqueous foam with novel CO2-soluble surfactants for controlling CO2 vertical sweep in sandstone reservoirs

The ability of a novel nonionic CO2-soluble surfactant to propagate foam in porous media was compared with that of a conventional anionic surfactant (aqueous soluble only) through core floods with Berea sandstone cores. Both simultaneous and alternating injections have been tested. The novel foam outperforms the conventional one with respect to faster foam propagation and higher desaturation rate. Furthermore, the novel injection strategy, CO2 continuous injection with dissolved CO2-soluble surfactant, has been tested in the laboratory. Strong foam presented without delay. It is the first time the measured surfactant properties have been used to model foam transport on a field scale to extend our findings with the presence of gravity segregation. Different injection strategies have been tested under both constant rate and pressure constraints. It was showed that novel foam outperforms the conventional one in every scenario with much higher sweep efficiency and injectivity as well as more even pressure redistribution. Also, for this novel foam, it is not necessary that constant pressure injection is better, which has been concluded in previous literature for conventional foam. Furthermore, the novel injection strategy, CO2 continuous injection with dissolved CO2-soluble surfactant, gave the best performance, which could lower the injection and water treatment cost.

Foam Generation Hysteresis in Porous Media: Experiments and New Insights

Foam application in subsurface processes including environmental remediation, geological carbon-sequestration, and gas-injection enhanced oil recovery (EOR) has the potential to enhance contamination remediation, secure \(\hbox {CO}_{2}\) storage, and improve oil recovery, respectively. Nanoparticles are a promising alternative to surfactants in creating foam in harsh environments. We conducted \(\hbox {CO}_{2}\)-in-brine foam generation experiments in Boise sandstones with surface-treated silica nanoparticle in high-salinity conditions. All the experiments were conducted at the fixed \(\hbox {CO}_{2}\) volume fraction and fixed flow rate which changed in steps. The steady-state foam apparent viscosity was measured as a function of injection velocity. The foam flowing through the cores showed higher apparent viscosity as the flow rate increased from low to medium and high velocities. At very high velocities, once foam bubbles were finely textured, the foam apparent viscosity was governed by foam rheology rather than foam creation. A noticeable hysteresis occurred when the flow velocity was initially increased and then decreased, implying multiple (coarse and strong) foam states at the same superficial velocity. A normalized generation function was combined with CMG-STARS foam model to cover full spectrum of foam behavior in the experiments. The new model successfully captures foam generation and hysteresis trends in presented experiments in this study and data from the literature. The results indicate once foam is generated in porous media, it is possible to maintain strong foam at low injection rates. This makes foam more feasible in field applications where foam generation is limited by high injection rates that may only exist near the injection well.

Foamability of fatty acid solutions and surfactant transfer between foam and solution phases

The foaming properties of aqueous solutions of fatty acids with different hydrocarbon chain lengths - hexanoate, laurate, and oleate - were assessed through measurements of foam volume and growth rate under continuous aeration. Simultaneous measurements of the partition of each surfactant between the bulk solution and foam phases were also carried out. Although bubble size measurements in bulk solution pointed towards quite similar gas dispersing abilities of the tested surfactants, their foamabilities under the same conditions were remarkably enhanced with increasing chain length of the hydrocarbon tail. Shorter chain surfactants - hexanoate and laurate - generated wet foams and the accumulation of these surfactants in the foam phase was very low, indicative of a low adsorption density of the reagents at the gas-liquid interface. In contrast, sodium oleate produced stable dry foams, and the amount of oleate transferred to the foam was much higher. The formation of these different types of foam was attributed to the higher adsorption of oleate at the gas-liquid interface compared to the lower adsorption of hexanoate or laurate, and to different mechanisms of foam stabilization. Regardless of the interfacial mechanism of the foaming action of the tested surfactants, it was generally found that strong foaming was possible only from surfactant solutions whose bulk concentration was higher than the critical coalescence concentration of a given surfactant. It was concluded that bubbles entering the foam phase from the bulk solution phase must already be stable against coalescence to induce foam formation and impart stability to the entire foam column. Foaming was observed only in true solutions of the tested surfactants, while precipitation of colloidal acid species completely depressed foam formation.

Solution-Processed Ultraelastic and Strong Air-Bubbled Graphene Foams.

Solution-processed ultraelastic graphene foams are prepared via a convenient air-bubble-promoted synthesis. These foams can dissipate external compression through the ordered interconnecting graphene network between the bubbles without causing a local fracture and thus reliably show compressive stress of 5.4 MPa at a very high strain of 99%, setting a new benchmark for solution-processed graphene foams.

Dimensionality-Dependent Foam Rheological Properties: How To Go From Linear to Radial Geometry for Foam Modeling and Simulation

Summary Numerous laboratory and field tests reveal that foam can effectively control gas mobility and improve sweep efficiency, if correctly designed. It is believed that there is a significant gap between small laboratory-scale experiments and large field-scale tests because of two main reasons: (1) Typical laboratory flow tests are conducted in linear systems, whereas field-scale foam enhanced-oil-recovery (EOR) processes are performed in radial (or spherical partly) systems and (2) through the complicated in-situ lamella creation/coalescence mechanisms and non-Newtonian behavior, foam rheology depends on the geometry and dimensionality. As a result, it is still an open question as to how to translate laboratory-measured data to field-scale treatments. Motivated by earlier studies of Kovscek et al. (1994, 1997), this study investigates how such dimensionality-dependent foam rheological properties are affected by different injection conditions on small and large scales, with a mechanistic foam-modeling technique. Complex foam-flow characteristics such as three foam states (weak-foam, strong-foam, and intermediate states) and two steady-state strong-foam regimes (high-quality regime and low-quality regime) lie in the heart of this analysis. The calculation results from small radial and spherical systems showed that (1) for strong foams in the low-quality regime injected, foam mobility decreased [or mobility reduction factor (MRF) increased] significantly with distance showing a good sweep efficiency; (2) for strong foams in the high-quality regime, the situation became more complicated—near the well, foam mobility decreased, but away from the well, foam mobility increased with distance, which eventually gave a relatively low sweep efficiency; and (3) for weak foams injected, foam mobility increased with distance showing a poor sweep efficiency. The results implied that the use of a fixed value of MRF, which is a common practice in field-scale reservoir simulations, might lead to a significant error. When the method was applied to a larger scale, it was shown that strong foams could propagate deeper into the reservoir at higher injection rate, higher injection pressure, and at lower injection foam quality. Foam-propagation distance was very sensitive to these injection conditions for strong foams in the high-quality regime, but much less sensitive for strong foams in the low-quality regime.

Size-dependent properties of silica nanoparticles for Pickering stabilization of emulsions and foams

Nanoparticles are a promising alternative to surfactants to stabilize emulsions or foams in enhanced oil recovery (EOR) processes due to their effectiveness in very harsh environments found in many of the oilfields around the world. While the size-dependent properties of nanoparticles have been extensively studied in the area of optics or cellular uptake, little is known on the effects of nanoparticle size on emulsion/foam generation, especially for EOR applications. In this study, silica nanoparticles with four different sizes (5, 12, 25, and 80 nm nominal diameter) but with the same surface treatment were employed to test their emulsion or foam generation behavior in high-salinity conditions. The decane-in-brine emulsion generated by sonication or flowing through sandpack showed smaller droplet size and higher apparent viscosity as the nanoparticle size decreased. Similarly, the CO2-in-brine foam generation in sandstone or sandpacks was also significantly affected by the nanoparticle size, exhibiting higher apparent foam viscosity as the nanoparticle size decreased. In case of foam generation in sandstone cores with 5 nm nanoparticles, a noticeable hysteresis occurred when the flow velocity was initially increased and then decreased, implying a strong foam generation initially; and then the trapping of the generated foam in the rock pores, as the flow velocity decreased. On the other hand, weak foams stabilized with larger nanoparticles indicated a rapid coalescence of bubbles which prevented foam generation. Overall, stable emulsions/foams were achievable by the smaller particles as a result of greater diffusivity and/or higher number concentration, thus allowing more nanoparticles with higher surface area to volume ratio to be adsorbed at the fluid/fluid interfaces of the emulsion/foam dispersion.

Foams Stabilized by In-Situ Surface-Activated Nanoparticles in Bulk and Porous Media

Summary Foams for subsurface applications are traditionally stabilized by surfactants. The goal of this work is to study foam stabilization by nanoparticles—in particular, by in-situ surface-hydrophobization of hydrophilic nanoparticles. The interfacial properties of the nanoparticles were modulated by the attachment of short-chain surface modifiers (alkyl gallates) that render them partially hydrophobic, but still fully dispersible in water. First, static foams were generated with nanoparticles with varying concentrations of surface modifiers. The decay of foam height with time was measured, and half-lives were determined. Optical micrographs of foam stabilized by surface-modified nanoparticles (SMNPs) and surfactant were recorded. Second, aqueous foams were created in-situ by coinjecting the SMNP solutions with nitrogen gas through a Berea sandstone core at a fixed quality. Pressure drop across the core was measured to estimate the achieved resistance factor. These pressure-drop results were then compared with those of a typical surfactant (alpha olefin sulfonate, alkyl polyglucoside) under similar conditions. Finally, oil-displacement experiments were conducted in Berea cores with surfactant and SMNP solutions as foaming agents (coinjection with nitrogen gas). A Bartsch shake test revealed the strong foaming tendency of SMNPs even with a very low initial surface-modifier concentration (0.05 wt%), whereas hydrophilic nanoparticles alone could not stabilize foam. The bubble texture of foam stabilized by SMNPs was finer than that with surfactants, indicating a stronger foam. As the degree of surface coating increased, the resistance factor of SMNP foam in a Berea core increased significantly. The corefloods in the sandstone cores with a reservoir crude oil showed that immiscible foams with SMNP solution can recover a significant amount of oil (20.6% of original oil in place) over waterfloods.

Surfactant foam technology for in situ removal of heavy chlorinated compounds-DNAPLs

The use of surfactant foam for the remediation of a saturated soil contaminated with a dense non-aqueous phase liquid (DNAPL) was investigated at bench-scale. Despite the presence of the DNAPL, high foam stability was obtained for a mixture of cocamidopropyl betaïne and dodecylsulfate at 0.05%. Foams were assessed in different injection conditions and were compared to commonly used remediation methods. Strong foams improved significantly the DNAPL recovery yield, which amounted up to 98%, owing to the propagation of a flat foam front, with low dissolution (<0.5gl−1) and surfactant consumption (<10gkg−1 DNAPL recovered). The effects of important parameters (gas to liquid ratio, injection velocity, gas nature) and methods for foam production on pressure gradient (∇P), remediation efficiency and surfactant consumption were investigated. Even for low injection velocities (4×10−4ms−1), capillary numbers were high enough (∼8×10−3) to push the DNAPL efficiently. DNAPL lowered ∇P for foam propagation because of its destabilising effect. The use of CO2 as gas reduced the ∇Ps for foam propagation by 35%. ∇P were also decreased by 25% for gas to liquid ratios lower than 75%, whereas, DNAPL removal remained high. This technology should lower spreading risks and treatment costs.