Sequestration of CO2 in a saline aquifer is currently being evaluated as a possible way to handle CO2 emitted from a coal-fueled power plant in Svalbard. The chosen reservoir is a 300-m thick, laterally extensive, shallow marine formation of late Triassic-mid Jurassic age, located below Longyearbyen in Svalbard. The reservoir consists of 300 m of alternating sandstone and shale and is sealed by 400 m of shale.
Experimental and numerical studies have been performed to evaluate CO2 storage capacity. A total of 51 samples of core material from one well (Dh4) were collected and tested to find the potential units for CO2 injection. Analysis of the results shows that the permeability is generally less than 2 millidarcies and the capillary entry pressure is high. This poses a serious challenge with respect to achieving practical levels of injectivity and injection pressure. For further investigation, two 32-cm-long sandstone samples from the depth 675 m (Sample 1) and 679 m (Sample 2) were selected for laboratory core flooding experiments at reservoir conditions. This review presents the experimental protocol and detailed CO2-brine drainage and imbibition relative permeability data for these two different samples of rock. Capillary pressure measurements and simulation of the transient process was used to support the interpolation of the experimental flooding data.
Initial x-ray computed tomography scan showed no sign of fractures inside the cores, whereas after the core flooding experiment, there were visible fractures especially in Sample 1. Scanning electron microscopy analysis showed a high proportion of diagenetic iron-minerals in the sandstones like Fe-chlorite, Fe-carbonate (FeCO3), and pyrite (FeS2). A brownish output flow was seen in the sample with highest porosity and permeability. Dissolution of CO2 in the brine forms a weak acid that reacts with iron-minerals (e.g. siderite) to form iron-hydroxides. Severe hysteresis effects on one of the samples most likely resulted from changes in the rock composition.