Towards simulation of CO2 flow through a naturally fractured reservoir, Spitsbergen,
Svalbard
Kim Senger1,2, Kei Ogata3, Jan Tveranger1, Alvar Braathen2,3
1
Centre for Integrated Petroleum Research (CIPR), Uni Research, Allégaten 41, 5020, Bergen, Norway
(kim.senger@uni.no, jan.tveranger@uni.no)
2
Department of Earth Science, University of Bergen, Allégaten 41, 5020, Bergen, Norway
3
University Centre on Svalbard (UNIS), PO box 56, 9171, Longyearbyen, Norway (kei.ogata@unis.no,
alvar.braathen@unis.no)
As part of the Longyearbyen CO2 laboratory (http://co2-ccs.unis.no), CO2 will be injected into
a Triassic, clastic sequence of the Kapp Toscana Group. The chosen injection site in this
reservoir is logistically easily accessible, located some 900 m below the high arctic
community of Longyearbyen, yet poses several challenges, including a high degree of natural
fracturing and the presence of igneous bodies. Cores from the reservoir were retrieved from
two boreholes, DH2 and DH4; the reservoir rocks can also be examined at outcrops some
16km away. Plug measurements from the DH4 core exhibit moderate to low porosity (8-14%)
and permeability values of less than 1 mD. Nevertheless, two water injection tests conducted
in August-September 2010 in the lowermost 100 m of the well revealed good injectivity
potential, with total flow capacity of approximately 45 md·m. Fractures appear to be the
critical factor allowing injection into the tight reservoir.
High fracture frequencies were registered in the drill cores, as well as on televiewer data. Both
vertical and horizontal fractures were mapped in the core. Fracture frequencies peak in a subhorizontal thrust fault zone within the overlying Agardfjellet Formation. Further, peaks in
fracture frequencies are related to distinct stratigraphic intervals.
Here we present initial results from modeling the fracture network within the reservoir, based
on borehole data (manual logging, televiewer) and limited outcrop studies. A sensitivity
matrix of simulation cases is set up to account for the relative contributions of key parameters,
including fracture length, fracture orientation and fracture fill on injection performance. The
relative contribution of near-horizontal and steeply-dipping fractures is also examined.
The sensitivity matrix will be used to target key fracture variables for additional field data
collection in the summer of 2011.