Bifrost Project: Assessment of the CO2 Storage Complex Integrity from Coupled 3D Geomechanical Modelling

Abstract The Bifrost project will transport and store CO2 in a geological formation offshore Denmark: from the CO2 being captured on land to the transportation offshore via specialized shipping or existing pipelines – and finally injected into the depleted gas reservoir. Situated 3650 meters below the surface, the depleted sandstone reservoir is highly suitable for permanently and safely storing CO2 thanks to its good containment and strong shale seal. TotalEnergies with its oil and gas industry’s solid offshore experience and its embedded safety culture as lead-operator of Danish Underground Consortium (TotalEnergies, Nordsøfonden and BlueNord) and DTU Offshore Technology Center have the responsibility to ensure that establishing CCS solutions in the Danish North Sea is safe and sustainable for both the environment, people and the climate. Geomechanics plays a critical role in the assessment of the integrity of the complex storage for a safe and sustainable CO2 storage. CO2 leakage can occur mainly through destabilized faults/fractures and caprock induced fracturing depending on variations of in-situ stresses, pressures, temperatures in the reservoir and caprock and injection patterns over production/injection timescale. Intact rock of discontinuity failure may be expected in tensile or shear mode in response to the stress variations induced by pressure and temperature changes within the reservoir and caprock. A coupled numerical geomechanical modelling of the field has been generated to assess the impact of depletion in the field and subsequent injection of CO2. The 3D modelling allows to capture the effects of the regional tectonics, the geometry of the field, the faults, and the injection pattern on the stress distribution across the storage complex. The impact of the pressure and temperature changes on the reservoir, the caprock and the faults were simulated through different scenarios. Results of the simulations were also translated into induced seismicity during CO2 injection and ground deformation (compaction/subsidence). The work performed enabled to define the maximum injection pressure for CO2 injectors considering the entire storage complex including the Middle Jurassic reservoir sandstone, intermediate Upper Jurassic caprock shale and the base of the Upper Cretaceous chalk forming the ultimate caprock. The stress calibration includes the LOT/FIT data available from wells, log data, core data and thorough literature review from the area. A particular attention was paid to the structural interpretation including key horizons and faults. Usually restricted to the reservoir level it has been extended to account for the full volume of the storage complex that includes the overburden. Geomechanical simulations were performed using a one-coupling method associating a reservoir flow model, matching the historical production period. Key pressure and temperatures time-steps were defined to generate historical pressure changes in the reservoir during production and expected pressure and temperature changes during the CO2 injection period. 3D geomechanical simulations were performed on various scenarios to reflect the changes induced in the reservoir and caprock during depletion and injection. The arching affect during depletion and during injection was quantified to define a minimum fracturing limit and maximum injection pressure. The results of the simulation have been analysed and are summarized below. Evaluation of the ground deformation (compaction/subsidence) between -16 and -36cm at seabed posing no threat to surface facilities.Seal efficiency of the cap rock The FCP (or Shmin) at the base of the cap rock was evaluated to be safely above the pore pressure and we see no tensile failure potential in the cap rock. On the other hand, the simulations showed a probability of Thermal Induced Fractures in the reservoir due to the cooling effect. Evaluation of fault stability Localized areas of plastic shear strain were predicted in the reservoir model due to the temperature effects and these levels of small scale strain related to displacement are limited to the reservoir and only in areas where faults are present in the cold zone. By avoiding the faulted areas, this risk can be further minimised. Overall, it is very unlikely that a loss of integrity of the storage complex through fault reactivation will occur. Evaluation of induced seismicity with CO2 injection The simulations showed fault slip during depletion of 5 to 10cm which were probably aseismic due to high shale content. Contrastingly, the smaller intra-reservoir faults composition of high friction sands does create the possibility of a single slip no greater than 5mm and associated magnitude event of 1.4 during the CO2 injection phase. This is due to the temperature effects in case injection occurs in the vicinity of these faults.