Sequestration of carbon dioxide in a saline aquifer is currently being evaluated as a possible way to handle carbon dioxide emitted from a coal-fuelled 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 capped by 400 meter shale.Experimental and numerical studies have been performed to evaluate CO 2 storage capacity and long term behaviour of the injected CO 2 in rock pore space. Laboratory core flooding experiments were conducted during which air was injected into brine saturated cores at standard conditions. Analysis of the results shows that the permeability is generally less than 2 millidarcies and the capillary entry pressure is high. For most samples, no gas flow was detected in the presence of brine, when employing a reasonable pressure gradient. This poses a serious challenge with respect to achieving viable levels of injectivity and injection pressure.A conceptual numerical simulation of CO 2 injection into a segment of the planned reservoir was performed using commercial reservoir simulation software and available petrophysical data. The results show that injection using vertical wells yields the same injectivity but more increases in field pressure compare to injection through horizontal wells. In order to keep induced pressure below top-seal fracturation pressure and preventing the fast propagation and migration of CO 2 plume, slow injection through several horizontal wells into the lower part of the "high" permeability beds appears to offer the best solution.The high capillary pressure causes slow migration of the CO 2 plume, and regional groundwater flow provides fresh brine for CO 2 dissolution. In our simulations, half of the CO 2 was dissolved in brine and the other half dispersed within a radius of 1000 meter from the wells after 4000 years. Dissolution of CO 2 in brine and lateral convective mixing from CO 2 saturated brine to surrounding fresh brine are the dominant mechanisms for CO 2 storage in this specific site and this guarantees that the CO 2 plume will be stationary for thousands of years.

Sequestration of carbon dioxide in a saline aquifer into shallow marine formation of Jurassic sandstones in Svalbard has been studied on unfractured cores and by using a simplified set of geological boundary conditions. In this paper, the feasibility of storing CO 2 in a fracture and matrix system in a low permeable formation is studied by performing a series of laboratory experiments under different stress conditions. Laboratory core flooding experiments were conducted on two alternative fractured and unfractured cores. Water and nitrogen were injected into brine saturated cores at the reservoir conditions. The result shows that core plugs are very tight and the liquid permeability even for fractured core is less than 1 millidarcy. Under increased acting stress from 10 to 180 bar, the effective permeability of fractured core is reduced by 73 percent and fluid flow occurs through both fracture and matrix.A conceptual, generic and simple 3D numerical model using commercial reservoir simulation software and available petrophysical data was used to study the CO 2 injection through fracture at different overburden pressure. The effect of different overburden pressures were applied by using respective permeabilities in simulation model. Mean pressure along the cores was used to match simulation predictions with experiments results. The result shows that even though the system is water-wet, and matrix has a very high capillary pressure, CO 2 flows through both fracture and matrix. The amount of CO 2 that flows through the fracture is high and is reduced by increasing overburden pressure. The quantity of dissolved CO 2 in brine phase reduces by decreasing overburden pressure and increasing permeability. The faster the CO 2 is flowing through the fracture less time is available for CO 2 to trap as residual phase and dissolve in brine. In dipping fractured saline aquifer, CO 2 plume movement in updip direction is accelerated by decreased overburden pressure and increased permeability.