Injection of CO2 into a geological formation results in hydrodynamic effects as wells as pore pressure changes, which in turn affects the stress state. During the injection phase of a CO2 storage project, the increase in pressure changes the effective stress and may lead to rock deformation, which may result in shear slip or tensile opening of pre-existing faults, or creation of new fractures. Therefore, modelling the geomechanical properties of the reservoir along with the fluid transport is vital for the safe storage of CO2. The reservoir pressure starts to decrease when CO2 injection ceases. The reservoir is considered to be secure against geomechanical failure as the pressure decays towards a stable condition. Compression of both the injected and in-situ fluids and expansion of the pore space may lead to ground lift and, in some cases, seismicity. The reservoir properties (e.g. permeability) may also be affected. The development of a static 3D geologic model, the careful assessment of the stress field and coupled modelling of pore pressure and stress changes, help the assessment of possible fault/fracture development and surface heave. The data required for coupled geomechanical and flow modelling include rock compressibility, Young's modulus, Poisson's ratio, compressive strength, and formation fracture pressure. The coupled geomechanical and flow simulations should be used to assess the likelihood of potential leakage and rates relative to key risks, such as CO2 entry into the caprock

Simulation of CO2 storage in an underground formation requires a complex multi-disciplinary effort, with the analysis of a number of interacting processes, including multi-phase flow and transport, geochemistry and geomechanics.

Injection of a large volume of fluid in the subsurface over a period can have geomechanical as well as hydrodynamic effects. During the injection phase of a CO2 storage project, the (average) pore pressure in the storage formation would increase with continuous CO2 injection. Spatially, the pressure increase would be highest at the injection well. Changes in the pore pressure will in turn alter the stress state. The associated changes in the effective stress (total stress minus the product of pore pressure and the Biot constant) cause rock to deform. If the injection-induced pressure increase is too large, shear slip or tensile opening of pre-existing fault(s) in the storage reservoir/caprock may occur, or new fractures may be created. This may cause a previously sealing fault to become conductive, and thus potentially compromise the caprock seal. Induced shear-stress changes may also induce micro-seismicity and even earthquakes of moderate local magnitudes (Bachu, 2008). For example, in Germany earthquakes up to magnitudes of 2.6 to 2.8, triggered by natural gas production, have been reported (Chadwick et al., 2008).

The injected fluids are accommodated in the subsurface through local displacement of resident fluids (water, oil or gas), compression of both the injected and in situ fluids, and expansion of the pore space that sometimes may lead to ground heaving (Bachu, 2008). Fractured and faulted reservoirs are generally highly compacted and, thus, severely affected by stress changes induced by reservoir thermal variations (e.g. cold CO2 injection).

Storage reservoir pressure will start to subside when CO2 injection ceases. The risk of leakage is expected to decrease as the pressure decays towards a stable condition. When the reservoir pressure reduces to this stable level, the reservoir is considered secure against geomechanical failure due to the internal forces (Chalaturnyk et al., 2005).

Geomechanical data, among other properties, are required under the EU CCS Directive (2009) during the storage site characterisation stage in order to evaluate the geomechanical effects of CO2 injection. Knowledge of the elastic properties of the storage formation/caprock, pre-existing fault strength properties, if any, in situ stress state, etc. allow the estimation of the fracturing pressure and, therefore, the determination of the upper limit of injection pressure. They also help to assess and predict the reservoir behaviour with respect to its overall capacity and avoid critical pressure build-up.

CO2 transport model simulations provide the information necessary to determine whether there is potential CO2 leakage through the caprock. Three key areas of simulation - focusing on faults andfFractures, subsurface behaviour and fate of CO2, and geomechanical/mechanical/flow models - show that numerical modelling is critical to CO2 storage evaluation and risk. Monitoring programs or computer simulations can be used to determine whether hydraulic fracturing would pose a risk to the confining layer, based on site-specific information.

Gaus, 2010 stated that the coupling of geomechanical codes with coupled flow-transport codes remains a further challenge, although it is much-needed in order to assess the interplay between the two phenomena. This does not only require code development, but also the availability of the necessary datasets to feed into these codes and the correct treatment of uncertainties, since both geomechanical and geochemical processes are defined by highly uncertain parameters.


in depth

5.1 Geomechanical terms and processes in CO2 storage

Stress is a measure of the amount of force exerted per unit area. There are 9 stress components....

5.2 Geomechanical site characterisation

Sufficiently representative and detailed characterisation of potential storage sites is essential for accurate simulatio...

5.3 Case studies and need for geomechanical coupled simulations

It is a priori necessary to predict that a potential storage site has a good sealing capacity, so that the injected CO2 ...

5.4 Methods of coupling flow and geomechanics

In conventional fluid flow formulations, the pore volume variation only depends on the pore volume compressibility coeff...

5.5 Conclusions

Injection of CO2 in a geological medium results in pore pressure changes, which in turn affects the stress-state....