The Longyearbyen CO2 Lab of Svalbard, Norway was established to estimate the potential for geological carbon sequestration at Spitsbergen. Several monitoring wells were drilled in and around the planned CO2 injection site. These revealed a Triassic to Cretaceous stratigraphy consisting of (from top to bottom) a zone of permafrost, the aquifer, the caprock shale, and the upper, middle and lower reservoir. This paper uses two tools to investigate fluid communication within and between these entities: 87 Sr/ 86 Sr of formation waters extracted from cores using the residual salt analysis (RSA) method, and the δ 13 C of gases, principally methane and CO2, degassed from core samples. The Sr RSA data reveal that the upper reservoir rocks have very constant formation water 87 Sr/ 86 Sr in wells several kilometres apart, suggesting good lateral communication on a geological timescale. However, there is a distinct barrier to vertical communication within the middle reservoir, indicated by a step change in 87 Sr/ 86 Sr, corresponding to thin but presumably laterally extensive (>1.5 km) lagoonal mudrocks. The aquifer, which shows a gradient in 87 Sr/ 86 Sr, is also interpreted to have some degree of vertical internal communication on a geological time scale. The caprock shale shows large-scale (over 350 m) smooth vertical gradient in 87 Sr/ 86 Sr. This is indicative of an ongoing mixing process between high-87 Sr/ 86 Sr waters within the caprock and lower-87 Sr/ 86 Sr waters in the underlying reservoir. Diffusion and flow modelling of the Sr data suggest that at some time in the past shale, fluid transport properties were enhanced by the formation of temporary pressure escape features (fractures or chimneys) during deep burial and uplift or cycles of glaciation. Nevertheless, the smooth compositional gradient in the caprock indicates that fluid mixing has subsequently taken place slowly, dominated by diffusion. This 3 interpretation is supported by the gas isotope data, where systematic variations in gas δ 13 C values also indicate slow and incomplete diffusional fluid mixing. These are positive indicators for caprock effectiveness during a CO2 injection project.

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Capturing CO2 from point sources and storing it into geologic formations is a potential option to allaying the CO2 level in the atmosphere. In order to evaluate the effect of geological storage of CO2 on rock-water interaction, batch experiments were performed on sandstone samples taken from the Altmark reservoir, Germany, under insitu conditions of 125°C and 50 bar CO2 partial pressure. Two sets of experiments were performed on pulverized sample material placed inside a closed batch reactor in a) CO2 saturated and b) CO2 free environment for 5, 9 and 14 days. A 3M NaCl brine was used in both cases to mimic the reservoir formation water. For the "CO2 free" environment, Ar was used as a pressure medium. The sandstone was mainly composed of quartz, feldspars, anhydrite, calcite, illite and chlorite minerals. Chemical analyses of the liquid phase suggested dissolution of both calcite and anhydrite in both cases. However, dissolution of calcite was more pronounced in the presence of CO2. In addition, the presence of CO2 enhanced dissolution of feldspar minerals. Solid phase analysis by X-ray diffraction and Mössbauer spectroscopy did not show any secondary mineral precipitation. Moreover, Mössbauer analysis did not show any evidence of significant changes in redox conditions. Calculations of total dissolved solids concentrations indicated that the extent of mineral dissolution was enhanced by a factor of approximately 1.5 during the injection of CO2, which might improve the injectivity and storage capacity of the targeted reservoir. The experimental data provide a basis for numerical simulations to evaluate the effect of injected CO2 on long term geochemical alteration at reservoir scale

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