SPE International Conference on CO2 Capture, Storage, and Utilization,
10-12 November 2010,
New Orleans, Louisiana, USA
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.
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.