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Abstract

Modelling fluid–rock interactions induced by CO2 is a key issue when evaluating the technical feasibility and long-term safety assessment of CO2 storage projects in deep formations. The German R&D programme CLEAN (CO2 Large-Scale Enhanced Gas Recovery in the Altmark Natural Gas Field) investigated the almost depleted onshore gas reservoir located in the Rotliegend sandstone at over 3,000-m depth. The high salinity of the formation fluids and the elevated temperature in the reservoir exceed the validity limits of commonly available thermodynamic databases needed for predictive geochemical modelling. In particular, it is shown that the activity model of Pitzer has to be applied, even if necessary input data for this model are incomplete or inconsistent for complex systems and for the considered temperatures. Simulations based on Debye- Hu¨ckel activity model lead to severe, systematic discrepancies already in the simple proposed reference case where experimental data could be used for comparison. A simplified geochemical model, consistent with the average measured composition of formation fluids and the prevailing mineralogical assemblage of the host rock, identifies the mineral phases most likely to be considered at equilibrium with the formation fluid. The simulated reactions due to CO2 injection, under the hypothesis of local thermodynamical equilibrium, result in a moderate reactivity of the system, with the dissolution of anhydrite cementation and haematite being the most relevant expected mineral reactions. This is compensated, at equilibrium, by the precipitation of new carbonates, like calcite and siderite, for an overall very small loss of porous space. The simulated rather small effect of mineral alteration is also due to the scarce amount of water available for reactions in the reservoir. The results of the model are qualitatively in line with observations from batch experiments and from natural analogues.