CO₂ trapping mechanisms assessment using numerical and analytical methods

Carbon capture and storage (CCS) is a proven technique for reducing greenhouse gas emissions and climate change. Although monitoring shows that CO₂ can be safely stored underground, CO₂ leakage is still of concern. Therefore, understanding and forecasting the CO₂ distribution over a geological time is necessary to assess the storage performance and related risks. To understand the CO₂ distribution during or/and after a CCS process, four main trapping mechanisms have been introduced: stratigraphic (structural) trapping, residual trapping, solubility trapping, and mineral trapping. The relative contribution of each mechanism in CO₂ sequestration is expected to change over time as CO₂ migrates and reacts with formation rock and fluids. Although structural trapping is the most active trapping mechanism after CO₂ injection, some of the structurally trapped CO₂ dissolves into water with the rest becoming residual over time. Both the residual and dissolved CO₂ then react with rock and trap some of the CO₂, the process of which is recognized as part of mineral trapping. The relative contribution of different trapping mechanisms depends on different parameters, such as the type of geologic sink (i.e., saline aquifers, hydrocarbon reservoirs), and the properties of the reservoir fluids contained. Additionally, in the case of CO₂-EOR/storage the importance of different trapping mechanisms may change depending on the CO₂ injection strategy (e.g., water alternating gas, WAG; continuous gas injection, CGI; water curtain injection, WCI). In this dissertation, I investigate the CO₂ trapping mechanisms in two CCS processes: CO₂-EOR/storage and CO₂ injection in dipping aquifers. First, I investigate the CO₂ trapping mechanisms during and after a CO₂-EOR process using reservoir simulation. The main purpose is to answer questions associated with the relationship between EOR operational strategies and CO₂ utilization ratios, and to understand the impact of the different CO₂ trapping mechanisms on this relationship. To answer these questions, I integrate three main elements of field assessment: physical field characterization, production and pressure history, and reservoir simulation. I use this method to model and compare two fields that represent two different reservoir settings: Cranfield (representative of the U.S. Gulf Coast sandstone reservoirs) and SACROC (representative of the Permian Basin carbonate reservoirs). CGI is the original operating strategy in Cranfield and WAG is the original operating strategy applied in the SACROC unit. Second, I investigate the impact of relative permeability on the trapping mechanisms in a CO₂-EOR process using fractional flow analysis and reservoir simulation. I use the fractional flow theory for miscible displacement to analytically and graphically analyze the distribution of CO₂ trappings. I use the Cranfield model to show the impact of relative permeability on field predictions. I discuss the relative permeability impact on four different CO₂ injection schemes: continuous gas injection (CGI), water alternating gas injection (WAG), water curtain injection (WCI), and WCI+WAG. Third, I introduce a mathematical model, derived from force balance, to predict CO₂ plume migration in dipping aquifers. This model calculates the down and up-dip extension of CO₂ plume in the absence of trapping mechanisms. The force balance shows that there is a point in the down-dip flow where buoyancy and viscous forces are equal and the plume cannot extend further. However, in the up-dip flow, where the direction of viscous and buoyancy forces are the same, the plume migrates upward for an unlimited time. I validate the mathematical model against numerical simulation results. I introduce an effective relative permeability correlation to capture the competition between water and CO₂. I adjust the permeability of the aquifer to validate the mathematical model against heterogeneous cases. The results show that the heterogeneity-induced error is small if we use the near well-bore average permeability. I also investigate the effect of local capillary trapping on the plume shape. Using numerical simulation, I apply capillary trapping and show how capillary forces prevent the buoyant CO₂ from migrating up-dip.