Quantifying Thermally Driven Fracture Geometry During CO2 Storage

The desired lifetime for CO2 injection for sequestration is several decades at a high injection rate ( up to 10 bbl/min or 2,400 tons/day per injector). Government regulations and geomechanical design constraints may impose a limit on the injection rate such that, for example, the bottomhole pressure remains less than 90% of the hydraulic fracture pressure. Despite injecting below the critical fracture pressure, fractures can nevertheless initiate and propagate due to a thermoelastic stress reduction caused by cool CO2 encountering hot reservoir rock. Here we develop a numerical model to calculate whether mechanical and thermal equilibrium between the injected CO2 and the reservoir evolves, such that fracture growth ceases. When such a condition exists, the model predicts the corresponding fracture geometry and time to reach that state. The critical pressure for fracture propagation depends on the thermoelastic stress, a function of rock properties and the temperature difference between the injected fluid and the reservoir (Delta T). Fractures will propagate as long as the thermoelastic stress and the fluid pressure at the fracture tip exceed a threshold; we calculate the extent of a fracture such that the tip pressure falls below the thermoelastically modified fracture propagation pressure. Fracture growth is strongly dependent upon the formation permeability, the level of injection pressure above fracture propagation pressure, and Delta T. Published by Elsevier Ltd.