Joule Thomson Cooling Effects on Rock Dry-Out, Salt Precipitation and Fines Migration During CO2 Storage in Depleted Oil and Gas Reservoir: Laboratory Investigation

Effective geological carbon storage critically relies on maintaining CO2 injectivity in depleted reservoirs. However, injectivity is often compromised by formation damage mechanisms such as salt precipitation and fines migration, especially under high-temperature and variable injection rate conditions. This study investigates the interplay between brine evaporation, salt deposition, and fines mobilization during CO2 gas injection into various sandstone core samples, mimicking actual reservoir temperatures and pressure. In addition, reservoir cooling effect due to Joule-Thomson cooling was investigated. Laboratory core-flood experiments were conducted across different injection rates and temperatures to quantify changes in gas and brine permeabilities, as well as the production of fines during both brine displacement and evaporation phases. Results show that higher-permeability cores dry out more rapidly, while lower injection rates promote brine evaporation and subsequent salt precipitation, leading to significant injectivity losses up to 88% in the most affected samples. Fines migration was found to persist throughout both the displacement and drying-out phases, contributing more to brine permeability impairment, whereas salt precipitation predominantly reduces gas permeability. Elevated injection rates mitigated salt-related damage by achieving full brine displacement but did not eliminate fines migration. These findings provide new insights into the complex mechanisms governing injectivity decline and offer guidance for optimizing CO2 injection strategies in depleted oil and gas reservoirs.