Commercial CO2 geologic storage will require large injection rates and will favor pipeline transport of CO2 as a dense (liquid) phase. Thus the temperature of CO2 entering a storage formation may be significantly lower than the formation temperature. This difference in temperature introduces a thermo-elastic stress that reduces the critical pressure required for initiation of fractures. The initiation of fractures poses a potentially serious risk for CO2 leakage to upper formations or surface.
We present a simple model to predict the range of bottomhole fluid temperatures, and thus the range of thermo-elastic stresses, for different operating conditions. The operators and regulators can estimate the safe injection rate range based on the model to avoid injection-induced fracture initiation around an injection well. Different injection strategies are considered in this work. The effect of Joule-Thomson cooling across the perforations is investigated and found to be small. We also evaluate the sensitivity of safe injection rate to formation permeability, heat transfer coefficient, geothermal gradient, and surface temperatures of injection fluid and well. Results from this study provide a guide for risk assessment and form a basis for investigating the extension of initiated fractures.