Single-Walled-Carbon-Nanotube (SWNT)-Silica nanohybrid particles are a very promising material that could be used in a near future for enhanced oil recovery because of their interfacial activity. The mechanism used to recover additional oil in this case would be to deliver catalytically active nanohybrid particles to the O/W interface, where they would react with and modify the oil properties to mobilize the oil in the reservoir. To demonstrate the basic principle, aqueous nanohybrid particle dispersions were evaluated by looking at the effect of pH, salt, surfactant and polymer. The results showed that pH and salt did not have significant effect on the dispersion stability of nanohybrid particles. Although surfactant could improve the dispersion stability, it reduced the interfacial activity of the nanohybrid particles, causing them to stay in the aqueous phase. The best nanohybrid particle dispersion stability was found upon polymer addition, where the dispersions were stable for more than a week even at low polymer concentration (50 ppm).After the best conditions for dispersions stability were determined, one-dimensional-sand-pack studies were performed to evaluate the flow of the nanohybrid particles through porous media. The results showed that the most of the nanohybrid particles could pass through a column packed with glass beads while a measurable fraction of the particles were retained in the column packed with crushed Berea. When the columns contained a residual saturation of decane, additional nanohybrid particles were retained at the oil/water interface in both media (glass bead and crushed Berea sand packs). The sand pack studies showed that not only can the nanohybrid particles flow through porous media, but also about half of the particles injected will go the O/W interface when the porous medium contains a residual saturation of hydrocarbon, where they could be used to support a catalytic conversion of components of the oil.
In this study, fatty acids with carbon chains ranging in length from 3 to 8 (propyl to octyl) were used in place of alcohols to form microemulsion systems. The microemulsion systems contained sodium dodecyl sulfate (SDS), hexane, fatty acid, water, and NaCl. The phase behavior of these systems was examined using salinity scans at 25°C. The results showed that propanoic and butanoic acids promoted the formation of clear isotropic microemulsions, whereas the other fatty acids promoted a gel formation. High hexane solubilization was obtained with all of the systems. The optimum solubilization parameter (SP*) and optimum salinity (S*) decreased with increasing SDS concentration. With increasing fatty acid chain length, S* decreased but SP* increased. Conductivity measurements showed that, during the salinity scan, the conductivity of the systems was relatively unchanged, gradually decreased, or was a maximum at a given value. Interfacial tension (IFT) measurements showed that ultralow IFT were realized between microemulsion and oil phases using the fatty acids and that SP* and IFT were inversely related. The results of this study confirm that microemulsions can be formulated without alcohols through replacement of the alcohols with the appropriate fatty acids.Paper no. S1300 in JSD 6, 15-24 (January 2003).
Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+, Mg2+, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 3 pore volumes of surfactant-only system, experimental results show the oil recovery ranging from 45 % to 70% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 102,300 mg/L total dissolved solids (TDS). The aim of ongoing test is to confirm the effectiveness of the high-salinity surfactant-only formulation (0.46 wt% of surfactant). In this effort, we plan to conduct multiple single-well tests at different wells to minimize the design risks involved for the surfactant pilot test. A pilot test at a sandstone reservoir is scheduled to be performed in July of 2013 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.
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