Date of Award

December 2015

Degree Type


Degree Name

Master of Science



First Advisor

Weon Shik Han

Committee Members

Shangping Xu, Kue-Young Kim


CO2 Sequestration, Design of Experiments, Injectivity, Risk Analysis, Uncertainty Quantification


Carbon Capture and Geologic Storage is a viable technology to reduce the concentration of CO2 emitted to the atmosphere, however there remains challenges and risks associated with implementing this technology. One of the challenges, and the focus of Chapter 2, is maintaining the injectivity of the reservoir throughout the entire injection period of a project. While potential risks include the pressurization of the reservoir and the leakage of CO2 and/or brine out of the storage reservoir which is the focus of Chapter 3. A consequence of injecting dry-supercritical CO2 is that it results in salt precipitation in the near well region of the reservoir which consequently reduces the permeability of this region; having adverse effects on the well injecitivity and pressure build-up. This work evaluated the salt precipitation, brine flux patterns, and pressure build-up for two well constructions, (1) a partially perforated (4 injection intervals) and (2) fully perforated throughout the storage reservoir. Both well designs showed non-localized salt precipitation in low-k formations and localized precipitation in high-k formations. It was also found that two distinct brine flux patterns occurred; under low-k conditions the brine flux was outward and parallel to CO2 migration and precipitation became limited. However, under high-k conditions there developed back flow of the brine which amplified salt precipitation. When this process occurred the permeability reduction was orders of magnitude greater than when non-localized salt precipitation occurred. This reduction resulted in pressure build-up in the near well region. Optimal injection conditions were found to be in reservoirs of mid-range permeability; which allowed for adequate pressure dissipation and minimized salt precipitation.

Once the injection is initiated there is a corresponding injection-induced pressurization of the reservoir which is typically monitored by an array of pressure sensors located within the storage reservoir as well as the surrounding formations. The monitoring of pressure build-up can provide explicit information on the reservoir security and integrity. Chapter 3 within this work evaluated pressurization of a CO2 reservoir system in the presence of leakage pathways as well as exploring the effects of compartmentalization of the reservoir utilizing surrogate modeling techniques (e.g. Design of Experiments (DoE) and Response Surface Methodology (RSM)). Two simulation models were developed (1) an idealized scenario for the evaluation of multiple DoE methods, and (2) a complex scenario implementing the best performing DoE method to investigate pressurization of the reservoir system. The evaluation of scenario 1, determined that the Central Composite design would be implemented in the complex scenario. The complex scenario evaluated 5 uncertain factors: the permeabilities of the reservoir, seal, leakage pathway and fault, and the location of the pathway. A total of 36 response surface equations (RSEs) were developed for the complex scenario with an average R2 of 0.94 and a NRMSE of 0.060. Sensitivity to the input factors were dynamic through space and time. At the earliest time the impact of the reservoir permeability was dominant, whereas the fault permeability became dominant for later times (>0.5 years). The RSEs were implemented in a Monte Carlo Analysis to analyze leakage and pressurization risks. At the earliest time the permeability of the leakage pathway had a sufficiently high influence on the above-zone pressure allowing for adequate determination of leakage risk. At later times (>0.5 years) that fault permeability became dominate inhibiting the determination of leakage risk while allowing for sufficient determination of pressurization risk.