Carbon capture and storage, that is the collection of carbon dioxide (CO2) from power
plants and its injection underground, is an important technology for reducing CO2 emissions
to the atmosphere and hence, mitigating climate change. A key aspect of CO2 storage
is the injection rate into the subsurface, which is limited by the pressure at which formation
starts to fracture. Hence, it is vital to assess all of the relevant processes that may
contribute to the pressure increase in the aquifer during CO2 injection.
The central aim of this study is to analyse the ability of the near-well region of a saline
formation to conduct fluids, using a set of analytical solutions that enable quick and reliable
assessment of CO2 injectivity. In this research, the near-well fluid flow was assumed to be
a function of the non-Darcy flow parameter as defined by the Forchheimer equation. For
the analysis of single-phase flow problems, the analytical solution for the Forchheimer flow
in closed domains was derived and an alternative method for applying analytical solutions
associated with a single well to multiple well systems was proposed. The CO2 injection
process was modelled as a two-phase system where the non-Darcy flow was assumed for
the gas phase only, including a novel representation of the spatially varying fractional flow
function. The solution for immiscible flow was further developed to model compositional
displacements, which enabled analysis of the porosity reduction due to salt precipitation in
a near-well region. Finally, the effects of gas compressibility were examined by integrating
the analytical model with an iterative algorithm for correcting gas properties.
Results showed that in low permeability formations when CO2 is injected at high
rates non-Darcy flow conditions are more favourable for CO2 storage than linear flow
due to better displacement efficiency. This, however, came at the cost of increased well
pressures. More favourable estimations of the pressure buildup were obtained when CO2
compressibility was taken into account because reservoir pressures were reduced due to
the change in the gas phase properties. The non-Darcy flow resulted in a significant
reduction in solid salt saturation values, with a positive effect on CO2 injectivity. In the
examples shown, non-Darcy flow conditions may lead to significantly different pressure and
saturation distributions in the near-well region, with potentially important implications for
CO2 injectivity.