Larter, Stephen RDong, MingzheTawiah, Paul2023-02-112021-11-16Tawiah, P. (2021). CO2 Injectivity Under Varying Thermal Conditions in Deep Saline Geologic CO2 Storage Reservoir Systems (Doctoral thesis, University of Calgary, Calgary, Canada). Retrieved from https://prism.ucalgary.ca.http://hdl.handle.net/1880/115839https://dx.doi.org/10.11575/PRISM/40733CO2 injectivity is critical to achieving the rapidly-scaled and significant rates of CO2 injection into subsurface geologic reservoirs for Carbon Capture & Storage (CCS) as an important greenhouse gas (GHG) emissions reduction technology. In this research, the influence of injected CO2 bottomhole temperature (BHT) variability on CO2 injectivity has been investigated at the field-scale using field performance observations and data analysis of a large-scale (>1Mtpa injected CO2) commercial CCS operation, the Quest CCS site, and lab-scale experimental CO2 corefloods at varying equilibrium temperatures. The results of this study indicate that CO2 injectivity exhibits an inverse relationship with CO2 BHT. A 10oC decrease in CO2 BHT causes CO2 injectivity to increase by 10% for a constant continuous mass rate of CO2 injection into a deep saline aquifer, where the temperature difference (?T) between the CO2 BHT and the reservoir fluctuates between 27oC (summer) and 40oC (winter). Neither CO2 kinematic viscosity changes alone with temperature or CO2 physico-chemical reactions with in-situ reservoir fluids under non-isothermal conditions can explain the inverse relationship between seasonally cyclical CO2 BHT and injectivity. Non-isothermal cyclic CO2/brine drainage-imbibition can change CO2/brine two-phase flow characteristics. CO2 drainage endpoint phase mobility increases as temperature increases, but the mobility increases cannot explain the inverse relationship between CO2 BHT and injectivity. CO2 endpoint relative permeability contributes marginally to the CO2 phase mobility changes with temperature. Thermo-geomechanical mechanisms linked to continuous injection of “colder” CO2 at BHTs lower than the average deep saline aquifer reservoir temperatures, can induce thermal stimulation of existing natural fractures around the vicinity of the CO2 injector well through thermoelastic effects. Thermoelasticity enhances CO2 injectivity as the CO2 BHT decreases, even when bottomhole injection pressures (BHIPs) are considerably (tens of MPa) below the fracture pressure of the reservoir rocks. CO2 phase mobility changes with BHT and thermally induced stimulation mechanisms act contemporaneously and in opposite directions to influence injectivity. Thermal stimulation effects on CO2 injectivity can be more dominant than CO2 phase mobility effects, implying a need to distinguish thermoelasticity from poroelastic effects in CO2 injection regulatory requirements for improved injection efficiency in geologic CO2 storage while maintaining permanent storage security.enUniversity of Calgary graduate students retain copyright ownership and moral rights for their thesis. You may use this material in any way that is permitted by the Copyright Act or through licensing that has been assigned to the document. For uses that are not allowable under copyright legislation or licensing, you are required to seek permission.CO2 StorageCarbon Capture and StorageCCSCO2 InjectivityNon-isothermal injectivitythermal effectsCO2 phase mobilitythermal stimulationGeologydoctoral thesis