The Longyearbyen CO2 Lab: Fluid communication in reservoir and caprock

Abstract The Longyearbyen CO 2 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 CO 2 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 CO 2 , degassed from core samples. The Sr RSA data reveal that the upper reservoir rocks have very constant formation water 87 Sr/ 86 Sr (0.7130) 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 (0.7130–0.7112), 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 (0.7200-0.7130). 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 interpretation is supported by the gas isotope data, where systematic variations in gas δ 13 C (-50‰ to −32‰) values also indicate slow and incomplete diffusional fluid mixing. These are positive indicators for caprock effectiveness during a CO 2 injection project.