Influence of thermo-elastic stress on fracture initiation during CO2 injection and storage

During large-scale storage, 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 and propagation of fractures from injection wells are primary considerations during project risk assessment. The nominal fracture gradient does not account for thermo-elastic effects. Consequently, nominally safe injection rates could nevertheless create fractures. This work describes a model with which operators and regulators can estimate the safe injection pressure range to avoid fracture initiation at an injection well. We design a simple model for heat transfer in the wellbore and use it to predict the range of bottom hole fluid temperature, and hence the range of thermo-elastic stress, for different storage strategies. We use the model to evaluate the sensitivity of thermo-elastic stress to thermal and operating parameters, then relate the thermo-elastic stress to the critical pressure for fracture initiation. A dimensionless group is introduced to describe the influence of injection rate and heat transfer between wellbore fluid and surrounding formation. Commercial software (PROSPER) is used to verify the simple heat transfer model in different injection strategies. The model offers several insights into risk mitigation. The range of wellbore heat transfer coefficients for which thermo-elastic effects are small provides a performance target for wellbore construction and completion materials, should an operator wish to reduce fracturing risk in this manner. Thermo-elastic stress in shale is typically larger than in sandstone. Thus injection into a storage formation near its overlying seal could lead to fracturing the seal even when the storage formation remains intact. The thermoelastic effect is more significant in shallow formations because the difference between formation and bottomhole temperature changes slowly at greater depths. Thus achieving commercial storage rates without inducing fractures will be easier in deeper formations. The safe injection rate does not increase in proportion to an increase in formation permeability because the influence of thermo-elastic stress is greater in high permeability formation. These observations suggest that further work should be undertaken to determine the extent to which fractures propagate, once initiated.