Fluid-flow and geochemical simulations of CO2 storage in a depleted gas reservoir: identification of the key parameters

Carbon capture and storage (CCS) is one of the methods for the reduction of anthropogenic CO2 emissions. Deep saline aquifers, and depleted oil and gas fields are all potential storage sites but they differ substantially for the quantity of CO2 they can accommodate, and for the knowledge level and uncertainties characterizing them. Typically, depleted fields have a relatively limited capacity but they have been thoroughly investigated and information about their geological structure and rock properties are already available before conversion into a storage facility. Deep aquifers are potentially able to host very large CO2 quantities but they are mostly unexplored traps and require significant investments to assess their suitability as safe CO2 storage sites. This is the main reason why depleted fields are considered a very interesting option for CO2 storage. Along this line, this research was aimed at investigating the significance of modelling and quantifying the physical and chemical CO2 trapping mechanisms taking place in a depleted gas reservoir where CO2 is injected for geological storage. The study was carried out with the aid of a commercial software specifically developed to model the CO2 flow and the geochemical reactions in underground formations. The software is GEM, offered by the company Computer Modelling Group. First, the simulation objectives were established, namely the investigation of the impact of each trapping mechanism of the stored CO2 in a gas reservoir as a function of the rock – fluid interaction properties. A simplified reservoir geometry was assumed to avoid dependence of the results from a specific shape or layering of the geological formation. The data for characterizing the reservoir were mainly taken from the literature, based on published case histories describing in detail reservoirs successfully converted into CO2 storages. To have the most efficient storage, the pressure and temperature conditions were chosen so that CO2 remains in the reservoir in the supercritical phase. After generating the reference model, two gas production scenarios were simulated to mimic the reservoir depletion. Then CO2 was injected. The simulation time was much longer than the injection period so as to investigate the changes in the CO2 distribution as a free fluid, as a trapped fluid, and as a mineral over time. The initial simulations only included structural trapping, then solubility trapping, capillary trapping, and mineral trapping were progressively added in the simulations to investigate the impact of each process on the CO2 fate. The results not only emphasized the importance of considering the geochemical trapping processes while designing and developing a CO2 storage project but also highlighted which parameters have the largest impact on the modeled trapping mechanisms. This aspect is particularly relevant and of practical application when defining the laboratory experiments needed to characterize the system. Results confirmed that the rock relative mineral volume fractions and the relative permeability curves are key information to be determined. Furthermore, it was found that water vaporization has a significant influence on the amount of mineral precipitate. Specifically, a large increase in the mineral precipitate was observed when water vaporization was modeled, which is a plus since mineral trapping is considered the safest trapping mechanism.