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The existence of ellipsoidal micelles in aqueous solution has been debated in the literature. Although a number of experimental studies suggest that certain surfactants form ellipsoidal micelles, many theoretical studies have claimed that micelles with an ellipsoidal shape cannot exist. To shed light on this topic, in this paper, we develop a curvature-corrected, molecular-thermodynamic model for the free energy of micellization of nonionic surfactant biaxial ellipsoidal micelles. We subsequently use this model to evaluate the feasibility of forming ellipsoidal micelles, compared to forming spherical, spherocylindrical, and discoidal micelles, and conclude that ellipsoidal micelles can exist in solution. Utilizing the model developed here, we also establish theoretical limits on the size of the ellipsoidal micelles. These limits depend solely on the chemical structure of the surfactant molecule.

Wells are considered to be high-risk pathways for fluid leakage from geologic CO storage reservoirs, because breaches in this engineered system have the potential to connect the reservoir to groundwater resources and the atmosphere. Given these concerns, a few studies have assessed leakage risk by evaluating regulatory records, often self-reported, documenting leakage in gas fields. Leakage is thought to be governed largely by initial well-construction quality and the method of well abandonment. The geologic carbon storage community has raised further concerns because acidic fluids in the CO storage reservoir, alkaline cement meant to isolate the reservoir fluids from the overlying strata, and steel casings in wells are inherently reactive systems. This is of particular concern for storage of CO in depleted oil and gas reservoirs with numerous legacy wells engineered to variable standards. Research suggests that leakage risks are not as great as initially perceived because chemical and mechanical alteration of cement has the capacity to seal damaged zones. Our work centers on defining the coupled chemical and mechanical processes governing flow in damaged zones in wells. We have developed process-based models, constrained by experiments, to better understand and forecast leakage risk. Leakage pathways can be sealed by precipitation of carbonate minerals in the fractures and deformation of the reacted cement. High reactivity of cement hydroxides releases excess calcium that can precipitate as carbonate solids in the fracture network under low brine flow rates. If the flow is fast, then the brine remains undersaturated with respect to the solubility of calcium carbonate minerals, and zones depleted in calcium hydroxides, enriched in calcium carbonate precipitates, and made of amorphous silicates leached of original cement minerals are formed. Under confining pressure, the reacted cement is compressed, which reduces permeability and lowers leakage risks. The broader context of this paper is to use our experimentally calibrated chemical, mechanical, and transport model to illustrate when, where, and in what conditions fracture pathways seal in CO storage wells, to reduce their risk to groundwater resources. We do this by defining the amount of cement and the time required to effectively seal the leakage pathways associated with peak and postinjection overpressures, within the context of oil and gas industry standards for leak detection, mitigation, and repairs. Our simulations suggest that for many damage scenarios chemical and mechanical processes lower leakage risk by reducing or sealing fracture pathways. Leakage risk would remain high in wells with a large amount of damage, modeled here as wide fracture apertures, where fast flowing fluids are too dilute for carbonate precipitation and subsurface stress does not compress the altered cement. Fracture sealing is more likely as reservoir pressures decrease during the postinjection phase where lower fluxes aid chemical alteration and mechanical deformation of cement....