Reactive transport modeling of carbon dioxide sequestration via bicarbonate brine injection in the Rose Run sandstone formation: A comparison with traditional CCS
Abstract
One by-product of the Calera process to make building materials from CO2 is a bicarbonate solution that contains a variable fraction of the CO2 captured from flue gas. Injection of this fluid into the subsurface has advantages over CO2 injection in terms of technical risks, environmental issues, cost, safety, and public acceptance. With bicarbonate injection, there is no need of a cap-rock, as the solution is non-volatile, and will not be buoyant because it is of comparable density to the host fluids. Although a bicarbonate fluid has less CO2 mass per unit volume than supercritical CO2 (in our example, 34 times less), a large injection zone footprint is not a strong disadvantage because detailed site characterization, in particular of cap-rock integrity, is less critical. Moreover, the amount of CO2 that needs trapping is reduced by an amount equal to the carbon in the mineralized cement by-product. Bicarbonate injection can be carried out in relatively shallow aquifers, which reduces the pumping energy needed for emplacement. In terms of desirable long-term CO2 trapping mechanisms, bicarbonate injection greatly accelerates solubility and mineral trapping into hours and days as compared to decades or more for liquid CO2 injection. Thus, bicarbonate injection is a practical demonstration of fluid mixing at field scale. To assess the potential for geological storage of CO2 in American Electric Power’s (AEP) Mountaineer site, 1D reactive transport models have been constructed to compare bicarbonate with CO2 injection and upscale the mixing problem from batch experiments to the field. For CO2 injection, CO2 forms a completely dried-out zone near the borehole, which may result in halite efflorescence and may be a concern for well-bore injectivity. Simulations predict that after 10,000 years, the CO2 partial pressure remains above 200 bars, and the solution pH remains below 5 within a one kilometer radius of the wellbore. Consequently, the dissolved CO2 is about 1 molal and mineral trapping is minimal. The predicted porosity change is insignificant. For bicarbonate injection, the pH rises to about 9, and decreases to about 8 at 10,000 years. CO2 partial pressure remains at less than 1 bar. The predicted porosity increase is about 0.5% at 10,000 years. Bicarbonate remains the dominant carbon species and carbonate mineral precipitation is less than 0.1% by volume.
- Publication:
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AGU Fall Meeting Abstracts
- Pub Date:
- December 2010
- Bibcode:
- 2010AGUFM.H51C0892L
- Keywords:
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- 1009 GEOCHEMISTRY / Geochemical modeling;
- 1012 GEOCHEMISTRY / Reactions and phase equilibria;
- 1832 HYDROLOGY / Groundwater transport