CO2-brine primary displacement mechanisms: salt precipitation as a result of supercritical gas injection

Geological storage of CO2 is currently considered the most promising large-scale option to avoid emissions by industrial activities. Oil and gas reservoirs and the more abundant saline aquifers are regarded as suitable subsurface storage containers. The injection of dry or under-saturated supercritical (sc) CO2 into water-bearing formations leads to the formation of a so-called dry-out zone due to evaporation of the resident brine into the injected fluid and, hence, potential precipitation of formerly dissolved brine constituents. If minerals precipitate within the pore space of a rock formation, porosity and, as a consequence, permeability are adversely affected, which potentially impairs injectivity. Even though injectivity impairment poses operational and financial challenges, major research questions remain open; what is the size of the affected zone itself? What is the impact of capillarity on the fluid transport therein? Current reservoir simulation tools lack in the description of mutual mass transfer of the involved fluid phases, which may lead to a significant misinterpretation in terms of salt precipitation and the consequential clogging of the pore space. We developed a novel reservoir simulation module based on DuMuX capable of describing both evaporation and reaction kinetics. Besides that, we designed and assembled a meter-scale core-flooding unit to experimentally derive the size and extend of the zone of attraction. A major achievement was the experimental investigation of the dry-out zone and transport phenomena therein. The ultimate goal of this study was to calibrate the numerical code with the experimentally derived data to limit the future need for costly and time-intensive experimental studies. In this PhD thesis, the responsible evaporation of brine and fluid transport mechanisms are outlined and discussed, as well as the potential reduction of the formation permeability and with it the injectivity. Moreover, we will give insights into the implementation of the mass transfer between the fluid phases involved and the numerical model itself. A remaining important question is the zone of counter-current flow in the direction of the wellbore, which determines the amount of salt that potentially precipitates in the near-wellbore area and the accompanied porosity reduction. We approach this question with numerical simulations to determine the size of the zone affected by the undersaturated CO2. The modified saturation profile in this zone allows for salt to be transported toward the injector. We investigate the major parameters governing this zone and the fluid transport therein.