Permanent underground storage of carbon dioxide (CO2) has been proposed as a potential mitigator for greenhouse gases in the atmosphere. In such underground reservoirs, CO2 is trapped through a complex combination of physical and chemical processes. Also, injected CO2 in contact with subsurface water can decrease the cement strength, deteriorating wellbore integrity. Current industry programs, such as reservoir simulators and wellbore-cementing programs, provide powerful models for the physical processes. This paper discusses a model for the remaining geochemical processes. This model is designed for implementation in existing industry programs, enabling the industry, while planning carbon capture and sequestration (CCS) projects, to take advantage of experience acquired throughout many years.
A self-contained solution procedure has been developed to solve geochemical equilibrium calculations. The equilibrium within the brine phase is computed with activity coefficients calculated by use of either the general Helgeson-Kirkham-Flowers (HKF) electrolyte model, or the more-accurate Pitzer ion model. A correlation from open literature has been selected to calculate the equilibrium between CO2 and brine phases. Once equilibrium is established, the model calculates precipitation or dissolution rates for common minerals. The solution procedure has been designed for optimum balance between robustness and calculation speed while solving the nonlinear geochemical equilibrium problem. A novel initialization scheme and a three-pass solution procedure are introduced. During Pass 1, activity coefficients are set to unity while a nonlinear minimization algorithm is used to locate the neighborhood of the equilibrium solution; in Pass 2, the first pass is repeated with the activity coefficients being calculated by use of the selected model. Finally, during the final pass, the solution is refined to the desired accuracy by the use of a nonlinear solver.
The solution model fits observed data. The CO2 solubility and brine phase pH can be computed for temperatures between 300K (80°F) and 478K (400°F), pressures up to 414 bar (6,000 psia), and brine strengths up to 6 mol NaCl/kg H2O. The more than 50 primary and secondary mineral species in the database represent common carbonate and clastic formation components. Temperature-dependent dissolution and mineralization rates can be predicted at similar conditions.
As the industry plans CCS projects, it must document projections of formation and well integrity during the project lifetime. The solution procedure is suitable for inclusion in various oil and gas industry models, including cementing simulators or reservoir simulators, to model CCS in subsurface aquifers and enhanced oil recovery (EOR). This paper provides guidance on how the algorithms should be implemented within reservoir simulators.