Longyearbyen (UNIS) CO2 Lab
Primary research area:
Secondary research area:
Snorre Olaussen(1), Alvar Braathen(1,2), Kim Senger(1), Srikumar Roy(1,5), & some current staff members of UNIS
(1)University Centre in Svalbard (UNIS), (2)University of Oslo, (3)NTNU, (4)University of Bergen, (5)University College Dublin, NORSAR, SINTEF, IFE, NGI, Equinor, CIPR, NGU, ConocoPhillips, Store Norske
Carbon capture, Geological storage
Climate change, decarbonisation
The Longyearbyen CO2 Lab of Svalbard, Norway, is one of the demonstration projects currently carried out worldwide with the purpose to learn more about the CO2 behaviour in high-pressure conditions and to assess the storage and sealing capacity of local subsurface rock successions. A coal-burning, single power plant in Longyearbyen provides both electricity and hot water, and supports the city’s entire house-warming system of radiators. The aim of this project has been to evaluate the feasibility of safe carbon dioxide (CO2) storage in an Artic environment by capturing CO2 from the thermal power plant and study the feasibility of safe CO2 storage in the subsurface of Longyearbyen in Svalbard.
Project activity included the drilling and logging of slim-hole cored wells, acquisition of new seismic sections, and a wide range of laboratory and field studies. The targeted reservoir is a marginal-marine sandstone succession of the Upper Triassic−Middle Jurassic Kap Toscana Group at ≥670 m depth, overlain by thick Upper Jurassic shales and younger shale-rich formations. The reservoir has a sandstone net/ gross of 25−30% and is intruded by thin dolerite sills and dykes. The reservoir and cap-rock succession rises at 1−3° towards the surface and crops out 14−20 km to the northeast of Longyearbyen in the inner Isfjorden area – where acoustic and multibeam echosounder data were acquired for a marine baseline study.
The reservoir shows considerable underpressure, in the lower part equal to c. 30% of hydrostatic pressure, which indicates good initial sealing conditions. Core samples indicate a ‘tight’ reservoir, with sandstones of moderate porosity (5−18%) and low permeability (max. 1−2 mD). Rock fractures are important for fluid flow.
Water-injection tests have indicated good injectivity in the lower part of the reservoir succession (870−970 m depth). The relatively more porous and permeable upper part (670−870 m depth) has only been partly tested. The injectivity increases with the increasing pressure, which suggests that the fractures gradually open and grow under injection. Reservoir pressure compartments indicate bedding-parallel permeability barriers, although these may gradually yield under a growing cumulative pressure. The seafloor and its subsurface conditions are analysed and interpreted, where the targeted aquifer and organic-rich top-seal shales sub-crop in the inner Isfjorden region, as part of the marine baseline study for the CO2 project.
Carbon capture storage; leakage risks; storage capability; injectivity; monitoring