Date of Award

January 2025

Document Type

Dissertation

Degree Name

Doctor of Philosophy (PhD)

Department

Geology

First Advisor

Sven Egenhoff

Second Advisor

Paul Ullmann

Abstract

This dissertation comprises three major chapters (Chapters 2, 3, and 4) that investigate the potential for CO2 sequestration in the Williston Basin. The following are abstracts that emerged from three major chapters:Chapter 2 Carbon dioxide (CO2) dissolution in formation brine, known as solubility trapping, is one of the most secure and permanent trapping mechanisms for CO2 sequestration. More solubility trapping means a greater CO2 storage capacity and less supercritical CO2 being buoyant, which drives upward and occupies the pore space, potentially reducing the plume extent. The solubility of CO2 in the brine depends on several factors, including pressure, temperature, salinity, and the composition of the CO2 stream. Depending on the type of capture technology, the purity of CO2 can significantly impact actual capture costs. To balance CO2 capture cost, considering a CO2 stream with impurities could be cost-effective if it is proven to have no adverse effect on storage capacity. The Energy & Environmental Research Center (EERC) team, supported by the State Energy Research Center (SERC), focused on evaluating the effects of impurities (N2/O2) on CO2 dissolution in a nonpetroleum, high-salinity, thick, clastic CO2 storage reservoir located in Williston Basin, North Dakota. This project comprised controlled laboratory experiments and numerical modeling to develop a conceptual model and understand CO2 stream phase behavior and its dissolution in its pure (100% CO2) and impure states (Mix 1- 10% N2 & Mix 2- 8% N2 + 2% O2) under high temperature (60°C) and pressure (≤204 atm equivalent to 3000 psi), mimicking the reservoir conditions needed for CO2 sequestration. CO2 solubility in deionized (DI) water and brine increases with pressure. The increase in CO2 solubility with pressure became less as the pressure increased. Total dissolved solids with varying concentrations (28,000–111,000 ppm) in the formation fluid reduced CO2 solubility in brine compared to that in DI water. Despite a reduced CO2 mass fraction in the impure CO2 stream with 10% N2, the % CO2 dissolved increased by a maximum of 3.5%. The density of the CO2 stream decreased with impurities, which increased the molar volume of the gas mixture. Changes in density and molar volume collectively increase the buoyancy of the CO2 stream, which enhances the flow of the CO2 plume, increasing the area of the storage site. The combined effect of reduced mass fraction and a decrease in density due to the presence of impurities contributes to reducing the storage capacity. Maximum reduction in storage capacity was observed at a pressure of 120 atm for Mix 1 (32%) and Mix 2 (27%), respectively. While the presence of N2 in the CO2 stream had a positive effect by enhancing CO2 dissolution, the net effect is negative on reservoir storage capacity due to the change in the physical properties of the CO2 stream resulting from impurities. Chapter 3 Caprock integrity is an integral part of CCS deployment and a prerequisite for safe and long-term confinement of CO2 within the storage system. The efficacy of the cap rock over long period is dictated by its thickness, ductility, presence of microfracture and its density, mineralogical and petrophysical properties (porosity and permeability) that control its ability to inhibit upward migration of CO2 into shallow underground sources of drinking water (USDW) and eventually be back into the atmosphere. The 3rd chapter of this dissertation investigates the diffusive loss of dissolved CO2 through the water-saturated pore space of the Opeche/Spearfish Formation of Williston Basin and its effect on caprock integrity using pure and varying concentrations of impurities in the CO2 stream. Due to CO2 leakage, caprock up to 1 meter from the CO2-caprock interface is affected by CO2-saturated brine and subsequent mineral dissolution and precipitation. With pure CO2, a decrease in porosity is evident. However, with impurities, caprock up to 1 meter, experiences an initial increase in porosity as it is first exposed to CO2, but porosity decreases to nearly its initial condition after a few years of injection. Results from numerical simulations suggest that the geochemical change from exposure to the CO2 stream is minimal and will not cause substantive deterioration of the Opeche/Spearfish cap rock. Chapter 4 The Bakken CO2 EOR and Storage project explores injecting CO2 into hydraulically fractured horizontal wells to enhance oil recovery while storing CO2 underground, thereby reducing carbon emissions from oil production. The upper Bakken Formation is primarily organic-rich siliciclastic mudstones, with higher amounts of detrital and biogenic quartz in the lower part. The fractures in the upper Bakken shale occur in a trough considered tectonically quiet. The occurrence of these fractures follows known tectonic lineaments, and therefore, the fractures are believed to reflect synsedimentary (with respect to the formation) or very early diagenetic tectonic activity, only recorded in the radiolarian beds. These fractures might contribute to the fluid pathway through the hydraulically fractured Bakken Formation when considering CO2 EOR. Therefore, understanding the origin and distribution of these fractures is critical when considering CO2 EOR. This study, therefore, explores the apparent contradiction between the presence of tectonically active structures and tectonically induced fractures and the reaction of black shales to synsedimentary (or very early post-sedimentary) tectonic influences. In general, fractures occur only near tectonic features; if they occur in areas where no tectonic faults or folds are known, they likely react to some unknown tectonic feature in the subsurface. Even though the fractures are now filled with cement, they must have originally formed as open features, and the infill postdated their formation. Their intense folding suggests that they formed very early in the diagenesis process. These cracks are thought to reflect basement structures that most likely naturally fractured the upper Bakken shale and potentially over- and underlying units. Their occurrence is, therefore, crucial for interpreting fluid pathways, be it for CO2 sequestration or hydrocarbon location purposes.

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