Cores, surfactant adsorption

Another method is based on the evaporation of a w/o microemulsion carrying a water-soluble solubilizate inside the micellar core [221,222], The contemporaneous evaporation of the volatile components (water and organic solvent) leads to an increase in the concentration of micelles and of the solubilizate in the micellar core. Above a threshold value of the solubilizate concentration, it starts to crystallize in confined space. Nanoparticle coalescence could be hindered by surfactant adsorption and nanoparticle dispersion within the surfactant matrix. 

Figure 5. Normalized surfactant concentration from a core flow adsorption test.

Adsorption of surfactant on reservoir rock can be determined by static tests (batch equilibrium tests on crushed core grains) and dynamic tests (core flood) in the laboratory. The units of surfactant adsorption in the laboratory can be mass of surfactant adsorbed per unit mass of rock (mg/g rock), mass per unit pore volume (mg/mL PV), moles per unit surface area (peq/m ), and moles per unit mass of rock (peq/g rock). The units used in field applications could be volume of surfactant adsorbed per unit pore volume (mL/mL PV) or mass per unit pore volume (mg/mL PV). Some unit conversions follow ... 

This value seems to be on the higher side of the typical values of surfactant adsorption on Berea sandstone cores Green and Willhite (1998) summarized... 

Surfactant adsorption is strongly affected by the redox condition of the system. Laboratory cores typically have been exposed to oxygen and are in an aerobic state. Wang (1993) showed that the surfactant adsorption in anaerobic conditions was lower than that in aerobic conditions. Most of the data collected... 

Surfactant adsorption is reversible with salinity, however, and it decreases with decreasing salinity (Somasundaran and Hanna, 1977). Hurd (1969) patented a method of desorbing and reusing surfactant by flooding a saline surfactant solution using less saline water. Figure 7.48 shows the surfactant history at the effluent end of a core flood (fraction of injected surfactant concentration... 

For all these cases, the total amount of each chemical was the same. The core flood results are shown in Figure 13.21. We can see that the incremental oil recovery factors over waterflooding in Schemes 2 and 4 were obviously higher than that in Scheme 1. The alkali and surfactant concentration gradients from high to low can overcome the negative effects at the displacement front caused by dilution, alkali consumption, and surfactant adsorption. 

More recently Smith (8), and Hill and Lake (14) studied cation exchange as it affected the behavior of micellar slugs in typical reservoir cores. These authors found that cation exchange in cores was quite complex, but that calcium and magnesium could, for all practical purposes, be treated as a single species. Moreover, they found that pre-flushing of a core reduced surfactant losses in most cases. Hill and Lake found that surfactant adsorption in cores was reduced by dissolution of carbonate minerals and by converting the clays to their sodium form. 

This section discusses the adsorption behavior of a number of foamforming surfactants under a wide variety of conditions. Surfactant adsorption data that appear in the petroleum literature are often difficult to compare because they are measured by different methods (batch or coreflood experiments), and experimental conditions may vary widely and are frequently not completely specified. The data discussed in this section, which are taken from references 7—12, 34, and 82 and some unpublished results, constitute the most extensive set of adsorption data for commercial foam-forming surfactants that were measured in a consistent manner by performing core-floods. 

Figure 10. Example of experimental and simulated effluent concentrations from a core-flood and the surfactant adsorption isotherm calculated from the best-fit adsorption model parameters.

Figure 20 contains adsorption levels measured in the water-wet and mixed-wet sandstones in the absence and in the presence of residual oil. Similar trends are observed for the anionic and the amphoteric surfactant. Adsorption levels in the water-wet cores are essentially the same in the absence of oil and in the presence of any of the three oils. In a water-wet system, the solid surfaces are surrounded by water films. As long as water-wet conditions prevail, the aqueous surfactant solution is in contact... 

Figure 20. Surfactant adsorption levels, expressed as packing densities on the solid surface, in clean and wettability-modified Berea cores containing different oils.

In the mixed-wettability cores, adsorption is affected only slightly by the presence of oil. The compensating effects of a decrease in the accessible solid—water interface and an increase in oil—water interface could be the reason for the relatively small effect. The most notable effect of the asphaltene treatment is the substantially higher adsorption density on the more oil-wet rock. Surfactant adsorption is higher on hydrophobic surfaces than it is on hydrophilic surfaces, a finding that is consistent with literature data. 

In addition to w/c microemulsions, o/c microemulsions may be formed for systems with strong surfactant adsorption. The area occupied by PFPE-C00 NH4 at the interface between 600 molecular weight polyethylene glycol (PEG) md CO2 is 440 per molecule based upon measurement of the interfacial tension versus surfactant concentration [21]. This surface coverage is sufficient for microemulsion formation as was verified with phase behavior measurements. Only 0.55 wt% of 600 molecular weight polyethylene glycol is soluble in CO2 at 45 °C and 300 bar. With the addition of 4wt% PFPE-C00 NH4 surfactant, up to 1.8 wt% is solubilized. The additional PEG resides in the core of the microemulsion droplets, consistent with the prediction from the adsorption measurement. 

Surfactant adsorption on the reservoir surface is another important factor to be considered when using foams in EOR processes is discussed in [258]. Adsorption experiments with surfactants of different structures were performed on cores of a number of materials (quartz, sandstones, kaolin, calcite and others), both clean and modified (impregnated) with hydrocarbons of various structure ( light oil, high-viscosity oil, asphaltenes). Minimum adsorption, as well as maximum oil recovery based was observed when using amphoteric surfactants as well as surfactant mixtures, e.g. diphenyl ether disulfonate - a-olefin sulfonate (DPES-AOS). 

Three types of interaction mechanisms are known between the micelle and the analyte as shown in Figure 3.3 (1) incorporation of the analyte into the hydrophobic core, (2) adsorption of the analyte on the surface or on the palisade layer, and (3) incorporation of the analyte as a cosurfactant. Highly hydrophobic and nonpolar analytes such as aromatic hydrocarbons will be incorporated into the core of the micelle. The selectivity may not be very different among long alkyl-chain surfactants for this class of analyte but the distribution coefficient will be increased with longer alkyl-chain surfactants. Thus, selectivity will not be altered significantly for nonpolar hydrophobic analytes, even when different surfactants are used. However, bile salts may provide substantially different selectivity in comparison with long-alkyl chain surfactants, even for nonpolar hydrophobic analytes. 

The two main properties of surfactant molecules are micelle formation and adsorption at interfaces. In Micellar Liquid Chromatography (MLC), the micelle formation property is linked to the mobile phase. Micelles play the role of the organic modifier in RPLC. Nonpolar solutes partition themselves between the micelle apolar core and the apolar bonded stationary phase. This partitioning will be the subject of Chapter 5. The surfactant adsorption property is linked to the stationary phase. A significant number of surfactant molecules may adsorb on the stationary phase surface changing its properties. The study of such adsorption and its associated problems is the main subject of this chapter. 

Clearly, the Knox plot study points out that surfactant adsorption on the stationary phase is responsible for the bulk of efficiency loss observed using micellar phases. A slow solute exchange between the micelle apolar core and the aqueous phase is another possible explanation for MLC efficiency loss. 

P. H. Krumrine subsequent to this symposium, which are summarized in Table 9, show a 75% decrease in surfactant adsorption in Berea cores when no oil is present. Another factor, which may be of importance, is the lower interfacial tension values obtained between the crude oil and the surfactant solution. The data in Table 10 show that the addition of 1.0% by weight of 3.22 ratio sodium silicate solution (37.6% solids) produced a significant reduction in interfacial tension values compared to the values measured with surfactant alone. 

A later study [66] focused on the nonequilibrium adsorption of C9-Ph-(E0)e-S03Na, 88 mol% sulfonate and 12 mol% unconverted nonionic surfactant, with a polymer, xanthan, onto oil-containing sandstone cores from the North Sea. Addition of the polymer reduced the surfactant adsorption by 80% relative to adsorption without xanthan, yet there was no complex formation between the surfactant and the xanthan. This study reflects one of the current trends of using systems containing surfactant-polymer mixtures and emphasizes the need for system specific adsorption studies in EOR applications. 

A more recent study [70] examined the effects of the polymer on surfactant adsorption in a low tension polymer water flood (LTPWF). The surfactant was alkylpropoxyethoxy sulfate, Ci2-i5-(PO)4-(EO)2-0S03 Na, and the polymers were xanthan and a copolymer of acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate (AN 125 from Floerger). The solid materials were sandstone cores from a North Sea oil reservoir, Berea, and Bentheim cores. For these systems the xanthan caused a 20% reduction in the adsorption of the surfactant. It was also observed that surfactant adsorption appeared to increase as the water... 

Thus, to sum up, the polymer may decrease the adsorption of surfactant in reservoir rock of high clay content, approximately 20 wt%. In cores of low clay content, approximately 5 wt%, the polymer will probably have negligible effect on the surfactant adsorption onto the rock. 

Adsorption Anaerobic/Aerobic. A very interesting paper, suggesting that surfactant adsorption onto reservoir rock is related to the reduction/oxidation potential of the system, was presented by Wang [46] using the PO-EO sulfates from in the Loudon field test. Conventional laboratory core floods consistently resulted in higher surfactant adsorp-... 

The simulations for this long core experiment, at 95% quality, focused on testing the validity of instantaneous foam generation assumed in STARS, provided sufficient surfactant and gas co-exist. Therefore, the foam front in the STARS model advances as the surfactant front advances, taking into account surfactant adsorption. 

Surfactant Adsorption. Surfactant adsorption was measured by flooding one core under the same conditions as used in the MRF measurements. 

In the experiments in Ref. [589], 100 mM electrolyte is present, which leads to k" 1 nm, and the midplane potential is 0.7, so that exp(-d> ,/2) 0.705. Then, Equation 4.243 reduces to 0 < / < 4.4 nm. This range of h values includes the range of thicknesses, where the hydration force is operative. In the experiments in Ref. [589], the hydration repulsion appears in the interval 0 < / < 3.71 nm irrespective of the kind of counterion (Li+, Na+, or Cs+). Note that in Figure 4.38 the data are plotted versus the total film thickness, h, which includes not only the water core, but also the two surfactant adsorption layers at the film surfaces. 

Surfactant adsorption onto the core surfaces is evaluated in terms of estimation of material loss in the rock during fluid flow. Previous knowledge of the surfactants phase behavior is required, since it is necessary to ensure that the extracting mixture will remain stable within the ranges of water content and salinity levels observed during operation. 

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