Near-Wellbore Damage Associated with Formation Dry-Out and Fines Migration During CO2 Injection

Abstract

Abstract One of the key parameters for subsurface CO2 storage in well injectivity. There are multiple factors that can affect injection rate including formation dry-out, fines migration, and salt precipitation that can increase or decrease the injectivity. In this study, we experimentally investigated the cumulative effect of rock drying-out and fines migration on well injectivity for a formation in the Cooper – Eromanga Basin, South Australia. Four core plugs with a range of clay content and permeability were chosen from the formation. Each core was fully saturated with artificially made formation water to measure initial permeability. The core samples were then subjected to a constant flow of gas (air or CO2) at reservoir pressure for up to 185,000 PVI. The effluent fluid was sampled continuously to measure the concentration of solid particles produced from the core during gas injection. The tests were followed by injection of formation water to eliminate the salt precipitation effect and then DI water to identify the maximum possible formation damage in each core sample. Overall injectivity increased significantly during continuous injection of CO2or air into fully saturated core samples despite permeability damage due to fines migration. Fines migration was observed during gas injection, resulting in a pressure drop increase across the cores and fine release at the core outlet. 30-60% reduction of core permeabilities were observed during connate water evaporation. The damaging effect of fines migration on injection rate was negligible compared to 4-30 times pressure drop decrease due to reduction in liquid saturation.