--> Abstract: Theoretical Storage Capacity Assessment of an Unconventional CO2 Storage Site in the High Arctic, Svalbard, NO, by Kim Senger; #90177 (2013)

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Theoretical Storage Capacity Assessment of an Unconventional CO2 Storage Site in the High Arctic, Svalbard, NO

Kim Senger

Carbon dioxide (CO2) may be injected into a Late Triassic to Middle Jurassic, tight, naturally fractured siliciclastic reservoir on Svalbard, Arctic NO. Reservoir characterization is based on cores and logs from eight boreholes, supplemented by extensive outcrop data from exposed parts of the reservoir located approximately 15 km to the north-east of the planned injection site. Water injection tests have confirmed injectivity in two levels of the target reservoir, suggesting a fracture-dominated fluid flow system in the lower part (870-970 m) and a matrix-dominated system in the upper part (672-700 m). Borehole pressure data show a sub-hydrostatic pressure regime indicating compartmentalization of the reservoir, possibly by igneous intrusions, sub-seismic faults, lateral facies changes or a combination thereof. Furthermore, pressure responses during testing suggest this may lead to dynamic phase transitions of injected CO2, with both supercritical and gas-phase CO2 stable at different stages. In order to determine the feasibility of storing CO2 produced from the local coal-fuelled power plant, with annual CO2 emissions of ca. 60.000 tons, a stochastic Monte-Carlo type volumetric calculation was undertaken and an estimation of potential storage capacity is presented. A modified version of the well-known hydrocarbon resource-assessment formula was applied using the GeoX software, taking the fluid properties of CO2 and the reservoir pressure build-up during injection into account. A reasonable range of values was assigned for each critical input parameter, including areal extent, reservoir thickness, net-to-gross ratio, porosity, gas saturation, fluid expansion factor and the storage efficiency factor. The porosity contribution from the natural fracture network was modeled separately. A sensitivity study illustrates that fracture density and fracture aperture define the overall fracture porosity, with other factors (orientation, length) defining the permeability field. Based on this first-order calculation we present initial probable ranges of pore volume and equivalent CO2 storage capacity in gaseous and supercritical form. The results suggest that the fracture network, while critical for permeability and injectivity of the target reservoir, only contributes < 2% of the pore volume for CO2 storage. Furthermore, we suggest that the accessible pore volume may be on the order of 915-1600 million m3. This would be sufficient to hold 430-732 million tons of supercritical CO2, but large uncertainty exists regarding likely regional gas saturation and the storage efficiency factor. Outcrop-based reservoir models are used to constrain these parameters.

AAPG Search and Discovery Article #90177©3P Arctic, Polar Petroleum Potential Conference & Exhibition, Stavanger, Norway, October 15-18, 2013