Offshore carbon dioxide storage in the German North Sea: Lessons from capacity assessment

Geological storage of CO₂ offers a promising solution for reducing atmospheric emissions and mitigating anthropogenic climate change. The feasibility of a storage site and the efficiency of injection strategies depend on geological settings, coupled with techno-economic and socio-political considerations. A site-specific approach is crucial, as storage dynamics vary significantly across different geological structures, such as anticlines or stratigraphic traps with features like pinch-outs. This study evaluates one of two potential CO₂ storage site candidates within the German North Sea, investigated as part of the GEOSTOR project, targeting the Triassic Middle Buntsandstein unit as storage formation. The study site, located approximately 130 km from onshore hub in the central German North Sea, is characterised by a 40-50 m thick basal Volpriehausen sandstone. Within the storage structure, an anticline site formed by salt tectonics, several suitable sub-traps are identified using a spill-point analysis. The site is intersected by faults with dip angles of 43°-63°, predominantly striking NE-SW.

Dynamic capacity assessment is conducted using the open-source OPM Flow simulator, with an injection target of 10 Mt/y for 30 years. A maximum allowable pressure limit derived from geomechanical modelling is applied. The model is parameterised using regional correlation models, as well as petrophysical data from legacy well logs. The reservoir model includes CO₂ dissolution, hysteresis of relative permeability, as well as thermal effects associated with injecting cold supercritical CO₂. The fault system geometry and displacement features are fully represented in the reservoir model but were numerically deactivated for flow and transport processes, as no parameterisation could be obtained.

Results indicate that the target injection rate is achievable using five vertical wells located down-dip of the structure, or alternatively two horizontal wells. Approximately 40% of the estimated static capacity can be utilised under technically feasible injection settings. After 100 years post-injection, about 50% of the injected CO₂ remains in free-phase form above the spill point, with the remaining part trapped as residual phase or dissolved in the formation brine. Hydraulic pressure changes extend tens of kilometers from the injection points. The southern boundary of the model, defined as hydraulically closed due to formation erosion, prevents pressure changes from extending into the Dutch subsurface, located approximately 30 km from the model’s southern edge. However, fault systems in the southern model domain, which intersect both the injection reservoir and overburden formations, could potentially cause vertical pressure changes and brine displacement from the German to the Dutch sector, raising cross-border aspects of CCS. The presence of a legacy well at the formation crest point requires further considerations concerning its sealing performance, as pressure increases during injection phase may reach 50 bar.