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Abstract
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.

Introduction
Risk assessment is necessary and significant before and during geological storage of CO2. One of the most important CO2 storage risks is leakage from the storage formation into the surrounding environment. Fractures in the sealing cap rock are one of the primary potential leakage conduits. To avoid leakage, the evaluation of the conditions for initiation and propagation of fractures is an essential component of project risk assessment (Fig. 1).

The pore-pressure criterion for fracture initiation is familiar from the theory and practice of well construction and of well stimulation. But because temperature differences contribute to rock stresses, the thermal conditions of the formation and the injected fluid are also crucial factors controlling the initiation and propagation of fractures (Perkins and Gonzalez, 1985; Settari, 1988; Detienne et al., 1998; Suri and Sharma, 2007; Hustedt et al., 2008). This has been established in long-term waterfloods, for example. In commercial injection and storage projects, the bottomhole temperature of CO2 can be significantly lower than the temperature of the formation receiving the CO2. The difference in temperature induces thermoelastic stress in those rocks, which decreases the critical pressure required for fracture initiation (Perkins and Gonzalez, 1985), and hence decreases the maximum safe injection rate. Consequently, operating at the injection rate calculated to be safe with nominal fracture gradient (which considers only the pore-pressure criterion) can cause fracture initiation and propagation in storage aquifer and possibly in the sealing cap rock.

We design a simple analytical model to describe heat transfer between the CO2 in the wellbore and its surroundings and use it to predict the temperature of CO2 when it reaches the bottom of the well. After obtaining the temperature of bottomhole CO2, we calculate the thermo-elastic stress and finally determine the critical pressure required for fracture initiation. By setting the bottomhole pressure equal to the critical pressure for fracturing, we estimate the maximum safe injection rate.
Different injection strategies are described in terms of the injection rate , the temperature of the CO2 at the wellhead Twh, and the heat transfer coefficient U, as these are the factors under at least some degree of control by the operator. The value of Twh will depend on the CO2 source; CO2 from a pipeline is likely to be cool, while CO2 direct from capture and compression is likely to be warm. The value of U, closely related to the construction and completion materials of wellbore, determines for the radial flux of heat through the tubing containing CO2, and the successive annuli of completion fluid, casing, mud, cement etc. to the surrounding formation (Fig. 1). The results described later in this paper suggest that it may be of interest to consider materials that would increase U and thereby reduce the risk of thermally induced fracturing.