Cost and risk reduction of geologic carbon sequestration using flue gas injection

ABSTRACT: We explore the impacts of flue gas injection as an alternative to CO₂ injection for geologic carbon sequestration (GCS) and enhanced oil recovery (EOR). To address the increase in pressure-driven risks with increased injection volumes, we create a model comparing subsurface behavior when injecting pure CO₂ versus an equal volume of CO₂ in flue gas. Pressure buildup from injecting 1 million tons per year (Mtpa) of CO₂ through one well versus injecting 5 Mtpa CO₂-N₂ through five wells drilled in a two-one-two well pattern is compared. Pressure throughout the reservoir is measured over a range of project variables, including a range of CO₂-N₂ compositions. Permeability is varied from approximately 10^-14 to 10^-12 m² (10 to 1,000 mD). We vary the spacing between wells from 100 m to 5,000 m and measure the change in reservoir pressure using a layer cake reservoir model for 20 years of injection followed by 10 years of pressure relaxation. Compared to the single injector case, the area of pressure elevation is approximately five times larger for the five-injector scenario. However, the magnitude of pressure buildup is significantly mitigated as spacing between wells increases. Results show that pressures decrease exponentially with increased well spacing and increased permeability.