Simulation of CO2 injection in a cylindrical rock sample

Simulation of CO2 injection in a cylindrical roCarbon Capture Storage (CCS) is a strategy to reduce anthropogenic CO2 emissions in order to mitigate climate change. Because of their widespread occurrence, huge potential capacity, and independence from previous hydrocarbon extraction, deep saline aquifers stand out among the other geological choices as one of the most attractive storage sites. After being injected into these formations, CO₂ interacts with the porous medium saturated with brine through a variety of processes, such as residual, solubility, structural, and ultimately mineral entrapment. To understand fundamental displacement mechanisms of CO2 in brine saturated porous media, pore- and plug- scale studies must be performed, nevertheless reservoir-scale models are crucial for long-term forecasts. Laboratory plug experiments combined with numerical simulation establish a connection between field-scale storage performance and microscopic displacement mechanisms For the purpose of replicating laboratory-scale CO2 injection studies three-dimensional cylindrical rock plug was modeled and simulated in tNavigator® (Rock Flow Dynamics), a high-performance numerical software for reservoir modeling and simulation. A cylindrical domain was defined using an ACTNUM mask created by a MATLAB code, which was also used to create a 3-D map of normally distributed heterogeneous petrophysical properties. The CO2STORE module was employed to simulate multiphase flow (CO2-brine) under laboratory conditions. Particular attention was posed on boundary conditions, which were set to replicate the experimental laboratory setup. Since pressure boundary conditions are not explicitly allowed in the simulator, a set of fictitious wells was defined on both top (inlet) and bottom (outlet) surfaces. Injection rate at the inlet wells and production rate at the outlet wells are regulated by bottom hole pressure control. Furthermore, a maximum injection rate is imposed on the group of inlet wells. Different scenarios were considered: homogeneous plug, heterogeneous plug with random porosity, heterogeneous plus with random permeability and heterogeneous plug with combined random porosity and permeability values. Quantifying the quantity of CO2 trapped in the porous media because of residual saturation and dissolution into brine was given particular attention. The findings show that regional variation in porosity and permeability greatly affects the transient behavior of CO₂–brine displacement, even though all four scenarios eventually achieve the same steady-state injection and production conditions. Heterogeneous cases consistently demonstrated slower collapse of water relative permeability, delayed brine removal, and earlier gas breakthrough, demonstrating that pore-scale heterogeneity enhances residual water retention and speeds up CO₂ invasion. While the combined heterogeneity scenario resulted in the most delayed water desaturation. The thesis is organized so that it progresses from context to simulation. Prior to focusing on plug-scale experiments, the discussion first examines the various geological storage options and places CO₂ storage in the context of the larger climate challenge. The modeling process, including grid construction, property assignment, and well configuration, is then thoroughly explained. The outcomes of the simulation are then summarized, with a focus on trapping mechanisms and displacement dynamics. Their implications for scaling from plug to reservoir are discussed, and ck sample