Simulation of altering residual water saturation near wellbore for CO2 injectivity

Abstract:

Volumetric CO₂ storage capacity in brine aquifers is one of the most important factor for large scale CCS projects. The maximum sustainable injection rate or the injectivity is another important criterion which is dependent on many reservoir specific properties including permeability, porosity, formation thickness, areal extent, pressure and relative permeability. Among those parameters, we focused on the residual wetting phase saturation expressed in relative permeability curve. From previous experiments, residual brine saturation is typically between 0.4 and 0.6. Higher displacement efficiency cannot be expected with those values because the displacement efficiency is inversely proportional to the residual oil saturation. Also, it is natural that the end-point relative permeability for CO₂ should be low. The reason is that the high CO₂-brine interfacial tension disturbs CO₂ invasion into small pores. In this study, chemical flooding was assumed with surfactants or intermediate fluid which is miscible with both water and CO₂ to reduce the interfacial tension. We didn’t use the chemicals to improve the displacement efficiency all over the field but intend to improve the injectivity at least near the wellbore region swept by the chemicals. Once lower residual brine saturation was achieved, the higher CO₂ saturation could be maintained and the better CO₂ injectivity was shown. Injection tests using a commercial model showed that the increase of the injectivity was not very high but the enhancement was meaningful.