The morphology of surfactants physically adsorbed on the surface of carbon nanotubes (CNTs) has a significant impact on the dispersion of CNTs in the solution. The adsorption of the surfactants alfoterra 123-8s (AF) and tergitol 15-s-40 (TG) on CNTs was investigated with dissipative particle dynamics (DPD) simulations, as well as the behavior of the binary surfactant system with CNTs. Properties of surfactants (i.e., critical micelle concentration, aggregation number, shape and size of micelle, and diffusivity) in water were determined to validate the simulation model. Results indicated that the assembly of surfactants (AF and TG) on CNTs depends on the interaction of the surfactant tail and the CNT surface, where surfactants formed mainly hemimicellar structures. For surfactants in solution, most micelles had spherical shape. The particles formed by the CNT and the adsorbed surfactant became hydrophilic, due to the outward orientation of the head groups of the surfactants that formed monolayer adsorption. In the binary surfactant system, the presence of TG on the CNT surface provided a considerable hydrophilic steric effect, due to the EO groups of TG molecules. It was also seen that the adsorption of AF was more favorable than TG on the CNT surface. Diffusion coefficients for the surfactants in the bulk and surface diffusion on the CNT were calculated. These results are applicable, in a qualitative sense, to the more general case of adsorption of surfactants on the hydrophobic surface of cylindrically shaped nanoscale objects.

The adsorption of anionic, cationic, and nonionic surfactants was measured on high-surface area silica and alumina nanoparticles when in the presence of the proposed polyelectrolyte sacrificial agents. Surfactant adsorption was characterized using two types of adsorption isotherms: one with constant polymer concentration and varying surfactant concentration, and another with a varying polymer concentration and constant surfactant concentration. Polystyrenesulfonate and Polydiallyl dimethylammonium chloride were tested as potential sacrificial agents on alumina and silica, respectively. Each surfactant/polymer system was allowed to reach equilibrium and supernatant surfactant concentrations were measured. This information was then plotted in order to determine what, if any, effect the proposed sacrificial agent had on the equilibrium adsorption. Results indicate that both of these polymers can have a large effect on total surfactant adsorption at a variety of surfactant concentrations.

In situ CO2 enhanced oil recovery (ICE) shows great potential for increasing oil field tertiary recovery. Instead of injecting liquid CO2 directly into the oil reservoir, a solution of a CO2-generating agent is injected to deliver CO2 to the targeted zone. Urea is an attractive gas-generating agent for ICE because it has both low price and exceptional stability in brine with elevated divalent cation concentrations. Besides CO2, urea thermal hydrolysis releases NH3(aq). Both molecules have positive impacts on the tertiary recovery, such as oil swelling, oil viscosity reduction, brine alkalinity increase, and sand surface wettability reversal. Thermal hydrolysis of urea is rapid at 120 °C, but the reaction rate decreases exponentially at lower temperatures. This work compares tertiary recovery from urea hydrolysis at 120 and 80 °C with and without a homogeneous catalyst (NaOH) for the purpose of examining the feasibility of urea-ICE for low-temperature reservoirs. The tertiary recovery was studied and optimized with data from 11 one-dimensional sand pack tests at varying conditions. Since urea hydrolysis produces a reaction intermediate, ammonium carbamate, which is known to precipitate in the presence of divalent cations, brines with elevated calcium concentrations were studied to examine the divalent cation stability of the proposed system. The optimization work included tests with urea concentrations varying from 1 to 35 wt % and different injection strategies and flow rates (0.03–0.3 mL/min). Tertiary oil recovery results of this study show that there are two different optimal concentrations of urea, one that maximizes the volume of tertiary oil produced and another that minimizes the cost per barrel of tertiary oil produced. The urea consumption of the proposed ICE can be as low as 34 kg/barrel with 2.5 wt % chemical slug, and the tertiary recovery can be as high as 48.3% with 10 wt % chemical injection. The optimal injection strategy was strongly dependent on chemical residence time because the tertiary recovery mechanisms vary with the injected concentrations. The aqueous effluent showed increasing solution pH, approaching pH 10. Based on an high-performance liquid chromatography analysis of the aqueous effluent, the mass balance of different tests was calculated. No adverse effect on tertiary recovery was observed in simulated seawater brines, with up to 1 wt % dissolved divalent salts. At higher levels of divalent ions (Ca2+ 7000 ppm) in a so-called API brine, lower tertiary recovery was observed but there was no evidence of formation damage and tubing blockage. In this work, the proposed ICE system showed superior tertiary recovery performance (48.3%) compared to the most recent efforts by our group (29.5%) as well as similar ICE systems (2.4–18.8%) proposed by others. Results illustrate the economic feasibility and the divalent cation tolerance of the urea-ICE process.

Carbon nanotubes (CNTs) exhibit promising properties for potential applications in oil and gas reservoirs. CNTs can be used as delivery vehicles for contrast agents or catalyst nanoparticles deep inside the reservoir. Dispersing 100 ppm of CNTs in deionized water is easily achieved by sonication of CNTs using properly selected surfactant or polymer solutions. These surfactants and polymers are non-covalently adsorbed to the nanotube surface, inducing dispersion stability. In oil reservoirs, high salinity is the norm; therefore, because the electrostatic double layer is compressed as a result of the high ionic strength found in a typical reservoir brine, colloid CNT dispersions lose stability and CNTs flocculate and precipitate. To maintain a stable colloidal dispersion of CNTs, a dispersant with functionality providing steric repulsion between the dispersed tubes is needed to prevent aggregation. In this work, suspensions of multi-walled carbon nanotubes (MWNTs) were generated using two polymers, gum arabic (GA) and hydroxyethyl cellulose (HEC-10), in 10% API brine (8 wt % NaCl and 2 wt % CaCl 2 ). GA was used as a primary dispersant, which is able to debundle the tube aggregates. After the first sonication with GA, the secondary dispersant, HEC-10, is added to provide the steric repulsion needed to keep the tubes dispersed in high-salinity brines. Polymer adsorption to the nanotube surface was observed using scanning electron microscopy. Focusing the electron beam for an extended period of time induced damage to the polymer layer around the individual nanotubes, leaving the tubes intact, as clear evidence of polymer adsorption. Adsorption experiments showed low to negligible adsorption of MWNTs to crushed Berea sand at 80 °C in both 10 and 20% brines. Dispersion injection in column and coreflooding tests showed successful propagation of CNT dispersions through porous media, with total nanoparticle recovery exceeding 80% in reservoir rock. This work demonstrates the potential of using polymer-stabilized carbon nanoparticle dispersions in a range of applications to advance current oilfield technology.

Multiwalled carbon nanotubes (MWNTs) exhibit promising properties for potential applications in oil production. Because of their substantial surface area, they could be used as carriers for catalysts or chemicals into subsurface oil and gas zones to change the properties of reservoir fluids or rock. A prerequisite for utilizing the MWNT in reservoir applications is to generate stable aqueous-phase dispersions that are well-dispersed and able to propagate successfully through the reservoir medium. In this study, different types of surfactants were investigated for their ability to disperse MWNTs in high-ionic-strength solutions typical of oil reservoirs up to 10% American Petroleum Institute (API) brine (8 wt % NaCl and 2 wt % CaCl 2 ). Stable nanotube dispersions in deionized water were achieved with the anionic surfactants evaluated. Compression of the electrical double layer, however, at high ionic strength, e.g., >3 wt % electrolytes, led to rapid aggregation of the anionic surfactant-aided nanotube dispersion. This study showed that by dispersing nanotubes in nonionic surfactant such as alkylphenol polyethoxylates with a large number of ethylene oxide (EO) groups, stable MWNT dispersions were obtained in 10 wt % brine. In the sandpack column test, a binary surfactant formulation, which consisted of a nonionic surfactant and an anionic surfactant in the proper ratios, exhibited an excellent capability to propagate MWNT, with 96% of the injected nanotubes recovered in the effluent. The adsorption density of surfactants onto MWNT was determined to be 9 molecules/nm 2 from the shift of the CMC value in the surface tension measurement. This study reveals that steric repulsion between the nanotubes could eliminate the aggregation of dispersed MWNT under the high-electrolyte-concentration condition, whereas nanotube−nanotube and nanotube−sand surface electrical repulsion could assist in the transport of the MWNT dispersion through porous media.