A workflow for estimating injection pressure limits for CO2 storage: A reservoir-geomechanical analysis of a candidate site in the German North Sea sector

Geological carbon capture and storage (CCS) in saline formations is seen as a plausible short-term solution to reduce atmospheric carbon dioxide (CO₂) concentrations and mitigate climate change. Besides storage capacity, largely determined by pore space within a geological trap, the maximum allowable pressure in the storage formation represents a major limitation for geological CO₂ storage. This study, therefore, addresses the hydromechanical aspects of geological CO₂ storage by developing an integrated workflow to determine site-specific injection pressure limits and applying it to a potential storage site in the German North Sea sector. The workflow ensures consistency between reservoir flow and geomechanical models by automatically extracting near-wellbore geomechanical domains from the large-scale model. For a vertical well, the site-specific injection pressure limit is estimated at 17.9 MPa/km, governed by tensile failure in the storage formation. Within the cap rock, the limit increases to 28.6 MPa/km, providing a large margin of safety and enabling higher injection rates. A horizontal well configuration yields a slightly higher limit of 19.7 MPa/km, due to the larger well-reservoir contact area and improved pressure dissipation. The derived pressure limits are subsequently implemented in a large-scale dynamic simulation to verify workflow performance and assess formation integrity. Results indicate that injection rates of approximately 1.7 Mt CO₂ per year per vertical well can be sustained over 30 years, with reservoir overpressure and the corresponding stress states strongly dependent on the hydraulic setting of the reservoir. Importantly, injection-induced stresses and thus the probability of fracture formation decreases rapidly after CO₂ injection ends.