The fracturing of any component of the CO2 storage system is generally viewed as a liability to be avoided. Yet in large-scale CCS, injection-induced fracturing of the storage reservoir is almost a certainty, even when operators keep injection pressures below the nominal fracture gradient. Models and field data indicate that pipeline-delivered CO2 will still be relatively cool when it enters the reservoir. The consequent thermoelastic stress reduces the fluid pressure needed to fracture the reservoir, so much so that commercial injection rates will not be possible if fracturing is prohibited. Simple models show that the CO2 does not warm significantly within the fracture, but the injection-induced fracture nevertheless propagates only a finite distance into the storage reservoir because friction within the fracture reduces the fluid pressure at the fracture tip. This prediction is consistent with field observations of injectivity. Such self-limiting propagation is useful for increasing the rate of storage and need not jeopardize the containment of the CO2, especially if injection is coupled with pressure management via extraction wells. We present field data from water flooded oil reservoirs that support this assertion.


Geological CO2 sequestration (GCS) in deep saline aquifer is one of the most promising techniques for reducing greenhouse gas emissions, but its potential strongly depends on large injection rates, long term storage security and low-cost operations [1]. An important regulation of GCS could be the constraint on the injection pressure to be below the formation breakdown pressure [2]. Yet even if the pressure constraint is met, injection-induced fractures can still occur in the storage reservoir. One reason is the reduction of tangential stress caused by injecting cool fluid into a warm reservoir [3-5]. When the temperature of injection fluid is significantly lower than the formation temperature at the bottomhole of injection well, the superposition of thermoelastic stress greatly reduces the tangential stress around the wellbore, allowing initiation of a tensile fracture at fluid pressures below nominal fracture pressure [6].

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