Experimental investigation of CO₂-brine-calcite interactions under reservoir conditions

Deep geological formations such as saline aquifers and depleted oil and gas fields are potential sites for CO₂ geological storage. The local host rock in these formations can have significant quantities of calcite present, such as in limestone or where carbonate formations have overlying chalk intervals. Therefore, the objective of this work is to understand how CO₂-saturated brine interacts with calcite under reservoir conditions. Hydrothermal experiments were carried out over a 6 month period to assess the potential for calcite to buffer brine and promote mineral carbonation over time. In addition, as the system had yet to reach equilibrium at 6 months, geochemical modelling using PHREEQC was performed to calculate the equilibrium state. The dissolution and precipitation of minerals were investigated to determine the effect that these processes have on the properties of the rock, such as porosity. The addition of calcite to the brine resulted in a significant increase in brine pH from 2.03 to 5.72. However, once CO₂ had been injected there was only a slight initial increase in pH, and therefore, the buffering effect of calcite is not sufficient to promote mineral carbonation. The formation of anhydrite, celestite and hematite was observed after 3 months, although dissolution and precipitation were still taking place after 6 months. The PHREEQC modelling conducted estimated an overall decrease in mineral volume of 2.3%, leading to an increase in porosity that is dependent on the SO₄ ^{2 −} concentration in the original brine. Therefore, brine composition needs to be considered when injecting CO₂ into reservoirs containing calcite bearing rock.