Impact of NO2 co-Injection on Geological Carbon Sequestration

Geological carbon sequestration is a promising technology for large scale CO₂ mitigation, especially from the point sources like power plants. The captured flue gas streams often contains small amount of impurities such as Sulphur oxides (SO_x) and Nitrogen Oxides (NO_x). In this paper, the objective is to study the impact of NO₂ co-injection on geological carbon sequestration in a deep saline carbonate formation. The objective of this research is accomplished by estimating the impact of NO₂ on following parameters a) changes in pH of the brine-rock-CO₂ system b) changes in mineralogy or porosity of the formation c) changes in solubility of CO₂ in brine or solubility trapping.

TOUGHREACT 3.3 (developed by Lawrence Berkeley National Laboratory, Berkeley) has been used to simulate the brine-rock-CO₂-NO₂ system. The mineralogy of the carbonate formation is based on the Dollar Bay formation in South Florida basin. The simulated domain is comprised of 11 carbonate layers varying in terms of porosity, permeability, thickness and composition of carbonate minerals (mainly calcite and dolomite). Three different NO₂ mass fractions 0.15%, 1%, and 2% were co-injected with CO₂.

Results from the study suggests that co-injecting NO₂ acidifies the system to greater extent as compared to pure CO₂ injection. Higher degree of acidification causes more dissolution of carbonate minerals, leading to higher changes in porosity across the layers in case of NO₂ co-injection (magnitude in order of 10^-3), compared to pure CO₂ injection (magnitude in order of 10^-4). Solubility of CO₂ remained largely unaffected with concentration of dissolved CO₂ for all four cases were evaluated around 50 g/kg of water. Based on the study, it can be concluded that co-injecting NO₂ can be a feasible option for geological carbon sequestration as it may render economic benefits by cutting the process cost associated with reducing NO_x concentration in the emission streams.