3D geomechanical modelling for CO2 geologic storage in the Dogger carbonates of the Paris Basin

CO2 injection into a depleted hydrocarbon field or aquifer may give rise to a variety of coupled physical and chemical processes. During CO2 injection, the increase in pore pressure can induce reservoir expansion. As a result the in situ stress field may change in and around the reservoir. The geomechanical behaviour induced by oil production followed by CO2 injections into an oil field reservoir in the Paris Basin has been numerically modelled. This paper deals with an evaluation of the induced deformations and in situ stress changes, and their potential effects on faults, using a 3D geomechanical model. The geomechanical analysis of the reservoir–caprock system was carried out as a feasibility study using pressure information in a “one way” coupling, where pressures issued from reservoir simulations were integrated as input for a geomechanical model. The results show that under specific assumptions the mechanical effects of CO2 injection do not affect the mechanical stability of the reservoir–caprock system. The ground vertical movement at the surface ranges from −2 mm during oil production to +2.5 mm during CO2 injection. Furthermore, the changes in in situ stresses predicted under specific assumptions by geomechanical modelling are not significant enough to jeopardize the mechanical stability of the reservoir and caprock. The stress changes issued from the 3D geomechanical modelling are also combined with a Mohr–Coulomb analysis to determine the fault slip tendency. By integrating the stress changes issued from the geomechanical modelling into the fault stability analysis, the critical pore pressure for fault reactivation is higher than calculated for the fault stability analysis considering constant horizontal stresses.