Supplementary files for: Assessment of formation brine salinity, pressure and temperature in selected structures in eastern Denmark and implications for CO2 storage

CO2 storage presents new risks and challenges, where the properties of formation water play an important role. These challenges include reduced injectivity and storage capacity due to salt precipitation, viscous fingering caused by viscosity contrasts between CO2 and brine and diminished CO2 solubility in formation waters. Understanding these factors and developing predictive models for pressure distribution are essential for successful CO2 storage projects. This study presents salinity (Cl and total dissolved solids), density, temperature, pressure, halite (NaCl) saturation, CO2 solubility and viscosity of formation waters across five CO2 storage sites in Denmark (Stenlille, Gassum, Rødby, Lisa and Inez), covering eight reservoirs (one in the Frederikshavn Formation, four in the Gassum Formation and three in the Bunter Sandstone and Skagerrak Formations). Salinity assessments are based on existing brine data or, where unavailable, a reference salinity model developed from a water chemistry database with 77 analyses from 28 wells in the Danish Basin and adjacent regions. The model was created using Partial Least Squares regression, accounting for local geological developments and subsurface salts. We report high chloride levels (182 000–202 000 mg/L) and densities (1.21–1.23 kg/L) in the Bunter Sandstone and Skagerrak Formations, while the Gassum and Frederikshavn Formations are undersaturated with halite, exhibiting lower chloride levels (99 000–148 000 mg/L) and densities (1.11–1.17 kg/L). These differences suggest a higher risk of mineral precipitation due to brine evaporation in dry CO2, and a higher risk of density override due to significant density contrast, which will hamper filling efficiency in older reservoirs. Modelling shows that CO2 solubility reaches 33.9 g CO2/L, with a 37% reduction due to chemical and pressure–temperature variations. Conceptual fluid flow modelling is recommended to further assess brine–rock–CO2 interactions. The salinity model has implications for geothermal reservoir assessment and can be applied regionally.