  Depleted oil fields in the Gulf of Suez (Egypt) can serve as geothermal
reservoirs for power generation using a CO2-Plume Geothermal (CPG) system,
while geologically sequestering CO2. This entails the injection of a
substantial amount of CO2 into the highly permeable brine-saturated Nubian
Sandstone. Numerical models of two-phase flow processes are indispensable for
predicting the CO2-plume migration at a representative geological scale. Such
models require reliable constitutive relationships, including relative
permeability and capillary pressure curves. In this study, quasi-static
pore-network modelling has been used to simulate the equilibrium positions of
fluid-fluid interfaces, and thus determine the capillary pressure and relative
permeability curves. Three-dimensional images with a voxel size of 0.65 micro
m3 of a Nubian Sandstone rock sample have been obtained using Synchrotron
Radiation X-ray Tomographic Microscopy. From the images, topological properties
of pores/throats were constructed. Using a pore-network model, we performed a
sequential primary drainage-main imbibition cycle of quasi-static invasion in
order to quantify (1) the CO2 and brine relative permeability curves, (2) the
effect of initial wetting-phase saturation (i.e. the saturation at the point of
reversal from drainage to imbibition) on the residual-trapping potential, and
(3) study the relative permeability-saturation hysteresis. The results improve
our understanding of the potential magnitude of capillary trapping in Nubian
Sandstone, essential for future field-scale simulations. Further, an initial
basin-scale assessment of CO2 storage capacity, which incorporates capillary
trapping, yields a range of 14-49 GtCO2 in Nubian Sandstone, Gulf of Suez
Basin.
