Master of Science / Department of Geology / Saugata Datta / With the ever-rising atmospheric concentrations of CO₂ there arises a need to either reduce emissions or develop technology to store or utilize the gas. Geologic carbon storage is a potential solution to this global problem. This work is a part of the U.S. Department of Energy small-scale pilot studies investigating different areas for carbon storage within North America, with Kansas being one of them. This project is investigating the feasibility for CO₂ storage within the hyper-saline Arbuckle aquifer in Kansas. The study incorporates the investigation of three wells that have been drilled to basement; one well used as a western calibration study (Cutter), and the other two as injection and monitoring wells (Wellington 1-28 and 1-32). Future injection will occur at the Wellington field within the Arbuckle aquifer at a depth of 4,900-5,050 ft. This current research transects the need to understand the lateral connectivity of the aquifers, with Cutter being the focus of this study. Three zones are of interest: the Mississippian pay zone, a potential baffle zone, and the Arbuckle injection zone. Cored rock analyses and analyzed formation water chemistry determined that at Wellington there exists a zone that separated the vertical hydrologic flow units within the Arbuckle. This potential low porosity baffle zone within the Arbuckle could help impede the vertical migration of the buoyant CO₂ gas after injection. Geochemical analysis from formation water within Cutter indicates no vertical separation of the hydrologic units and instead shows a well-mixed zone. The lateral distance between Cutter and Wellington is approximately 217 miles. A well-mixed zone would allow the CO₂ plume to migrate vertically and potentially into potable water sources. Formation brine from Cutter was co-injected with supercritical CO₂ into a cored rock from within the Arbuckle (7,098 ft.). Results show that the injected CO₂ preferentially preferred a flow pathway between the chert nodules and dolomite. Post reaction formation chemistry of the brine showed the greatest reactivity occurring with redox sensitive species. Reactivity of these species could indicate that they will only be reactive on the CO₂ plumes front, and show little to no reactivity within the plume.

Even in times of renewable energy revolution fossil fuels will play a major role in energy supply, transportation, and chemical industry. Therefore, increasing demand for crude oil will still have to be met in the next decades by developing new oil re-serves. To cope with this challenge, companies and researchers are constantly seeking for new methods to increase the recovery factor of oil fields. For that reason, many enhanced oil recovery (EOR) methods have been developed and applied in the field. EOR methods alter the physico-chemical conditions inside the reservoir. One possibility to achieve this is to inject an aqueous solution containing special chemicals into the oil-bearing zone. Polymers, for example, increase the viscosity of the injected water and hence improve the displacement of the oil to the production well. The injection of surfactant solutions results in reduced capillary forces, which retain the oil in the pores of the reservoir. Some surfactants form viscoelastic solutions under certain conditions. The possibil-ity to apply those solutions for enhanced oil recovery has been investigated by some authors in the last years in low salinity brines. Reservoir brines, however, often contain high salt concentrations, which have detrimental effects on the properties of many chemical solutions applied for EOR operations. The Triphenoxymethane derivatives, which were the subject of study in this thesis, form viscoelastic solutions even in highly saline brines. The aim of this thesis was to investigate the efficiency and the mode-of-action of this new class of chemical EOR molecules with respect to oil mobilization in porous media.

Even in times of renewable energy revolution fossil fuels will play a major role in energy supply, transportation, and chemical industry. Therefore, increasing demand for crude oil will still have to be met in the next decades by developing new oil re-serves. To cope with this challenge, companies and researchers are constantly seeking for new methods to increase the recovery factor of oil fields. For that reason, many enhanced oil recovery (EOR) methods have been developed and applied in the field. EOR methods alter the physico-chemical conditions inside the reservoir. One possibility to achieve this is to inject an aqueous solution containing special chemicals into the oil-bearing zone. Polymers, for example, increase the viscosity of the injected water and hence improve the displacement of the oil to the production well. The injection of surfactant solutions results in reduced capillary forces, which retain the oil in the pores of the reservoir. Some surfactants form viscoelastic solutions under certain conditions. The possibil-ity to apply those solutions for enhanced oil recovery has been investigated by some authors in the last years in low salinity brines. Reservoir brines, however, often contain high salt concentrations, which have detrimental effects on the properties of many chemical solutions applied for EOR operations. The Triphenoxymethane derivatives, which were the subject of study in this thesis, form viscoelastic solutions even in highly saline brines. The aim of this thesis was to investigate the efficiency and the mode-of-action of this new class of chemical EOR molecules with respect to oil mobilization in porous media.