Influence of relative permeability on injection pressure and plume configuration during CO2 injections in a mafic reservoir

Carbon capture and sequestration projects have traditionally targeted deep sedimentary basins; however, mafic reservoirs may also be attractive targets for CO2 disposal on the basis of permanent mineral trapping over relatively short time scales (10(1) to 10(2) yr). Nevertheless, CCS development in mafic reservoirs is hampered by substantial uncertainty in fracture-controlled reservoir characteristics, particularly with respect to the effects of multi-phase fluid flow, e.g., relative permeability and capillary pressure. The present study quantifies uncertainty surrounding relative permeability effects in a basalt reservoir by developing a numerical modeling experiment on the basis of site characterization data from the Slack Canyon #2 flow top, which is one of three flow tops comprising the injection zone at the Wallula Basalt Sequestration Pilot Project in southeast Washington State. This numerical modeling experiment controls for the effects of curvature in the relative permeability models by performing an ensemble of 399 CO2 injection simulations with constant geometry and reservoir properties, while systematically varying the phase interference parameter (lambda) and residual CO2 saturation (S-gr), which govern wetting and non wetting phase relative permeability, respectively. The relative permeability parameter space is defined by selecting combinations of lambda and S-gr that cover a wide range of experimental laboratory measurements. For each simulation, CO2 is injected into the reservoir for 10 years at a constant rate of 2.78 kg s(-1) (87,856 metric tons (MT) yr(-1)), which is 10% of the annual injection rate proposed for one injection scenario at the Wallula Site. Results from the ensemble of simulations show that relative permeability alone can account for >50 MPa of variability in the injection pressure and a two-fold difference in lateral CO2 plume migration. Additionally, this work shows that curvature in the wetting phase relative permeability model is the stronger influence on reservoir pressure accumulation, while curvature in the non-wetting phase relative permeability model strongly governs CO2 plume geometry. (C) 2015 Elsevier Ltd. All rights reserved.