Speaker
Description
Geologic carbon sequestration (GCS) as a greenhouse gas mitigation method is reliant on the long-term retention of carbon dioxide within reservoir storage zones. During the subsurface migration of carbon dioxide in highly homogeneous formations, fluids tend to quickly migrate upwards and accumulate at the top of the storage interval. These accumulations are therefore dependent on the surface between the reservoir and the overlying, impermeable zones, i.e. caprocks. This setting leads to capacity being largely dictated by the presence and nature of the structural features of the reservoirs. In the industrial development of GCS, large volumes of CO2 must be injected to make an impact, and the requirement of structural traps may be limiting or prohibitively costly. On the other hand, highly heterogeneous systems often possess stratigraphic features within the reservoir which impede this vertical migration resulting in higher residual trapping and potentially more laterally compact CO2 plumes. These formations may be preferential and expand the set of possible storage locations. At the reservoir scale, the stratigraphic heterogeneity that leads to this phenomenon can be characterized through anisotropic relative permeability input curves reservoir models. These models can then be used as predictive tools showing the CO2 migration dynamics in these heterogeneous formations.
To test this problem, we employed GEOS, a reservoir simulation software package that we expanded to include directional relative permeability hysteresis. We treat relative permeability as a tensor giving us the ability to input different flow properties for different directions. Depending on the level of heterogeneity, different input curves are used for the horizontal and vertical directions aligning with the principal axes of variation. To focus on industrial field development, we created a synthetic, commercial-scale (approximately 14 km by 14 km by 200 m) geologic reservoir model based on a real geologic basin. A series of CO2 injection flow simulations were executed on this model. The simplest model only includes heterogeneity for porosity and permeability through standard geostatistical well-log derived spatial distribution. Increasingly sophisticated physics models were included to represent heterogeneous and anisotropy using different capillary pressure and relative permeability models. The most complex uses an advanced rock-type model characterization for relative permeability anisotropy and hysteretic anisotropy properties that are representative of the geology’s heterogeneity. The results of these simulations and the implications for either ignoring or including these effects are discussed. Results show significant differences in predicted trapping, mobility, and displacement (CO2 plume footprint). Therefore, when modeling these heterogeneous reservoirs, it may be critical to adopt similar anisotropic models.
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