John Kaszuba, PhD , University of Wyoming
Geologic sequestration of CO2 generated by coal-fired power plants is a critical component of Carbon Capture and Storage (CCS) (Pacala and Socolow, 2004). In addition to CO2, coal combustion generates SOx, NOx, and other constituents. Purity requirements for CO2 injected into a geologic reservoir are being debated worldwide and have yet to be established (Gale, 2009). Conventional CO2 separation technologies that can be retrofitted to existing power plants yield CO2 that is greater than 90% pure (Rao and Rubin, 2002). However, these technologies impose large parasitic energy costs of 30 to 40% of the net power plant output. In addition, even just a few tenths of a percent of the common impurities (e.g., SOx and NOx) will influence the geochemistry of a water-rock system. Novel technologies such as oxy-fuel combustion and integrated gasification combined cycle (IGCC) power plants dramatically reduce parasitic energy costs but also produce higher levels of impurities in the combustion products. In either case, any industrial process is susceptible to off-normal occurrences and accidents that may inadvertently introduce impurities into the CO2 that is injected into the geologic storage reservoir.
Geologic sequestration of CO2 that contains impurities is known as co-sequestration, a term first used with reference to co-injected CO2 and H2S (Williams, 2002). The geochemical effects of co-injected impurities on a geologic storage reservoir and its caprock are largely unknown. The essential problem facing geologic carbon-sulfur co-sequestration is that SO2, the most abundant constituent in SOx, is very reactive in water-rock systems. We are undertaking a series of hydrothermal experiments to evaluate CO2-SO2-brine-rock reactions and processes in saline reservoirs. Our results will help to determine the viability of co-sequestering sulfur with carbon and bring the management and storage of carbon emissions closer to a practical reality.
Our experiments emulate actual carbonate and siliclastic formations, the Madison Limestone and Weber Sandstone, respectively. Both formations are viable sequestration targets (Surdam and Zhao, 2007). In southwest Wyoming these formations also house natural accumulations of CO2. These two "natural analogs" have stored supercritical CO2 for geologic time scales. Experimental work developed in the context of these naturally occurring fluid-rock systems helps clarify long-term storage behavior of reactive carbon and sulfur in anthropogenic systems.
The Weber Sandstone is an anhydrite and dolomite cemented, pyrite-bearing, arkosic sandstone housing a Na-SO4 brine (I = 0.4 molal, pH = 8.0). The Madison Limestone is a dolostone that also contains calcite, anhydrite, and accessory pyrite and silicate minerals. It houses a Na-Cl-SO42- brine (I = 0.5 molal). Hydrothermal experiments emulate both formations by reacting synthetic rock and brine at in-situ conditions (110°C and 25 MPa) for approximately 2000 hours. Supercritical CO2 containing 500 ppm SO2 is then injected and the experiments continued for an additional 500 to 1100 hours. Parallel experiments are performed without SO2 to provide a basis of understanding for the interaction of SO2 with supercritical CO2-brine-rock systems.
Synthesis and interpretation of the Madison Limestone experiments are nearly complete and represent the culmination of one MS student's graduate research. The results of the Weber Sandstone experiments are being processed and represent a significant component of a second MS student's graduate research. PRF funds are being leveraged with other funding sources for this work. The following are highlights of this research.
1) The dolomite-calcite-anhydrite mineral assemblage and reaction textures produced in supercritical CO2-brine-rock experiments are consistent with mineral assemblages and textures present in the natural CO2 reservoir of the Madison Limestone on the Moxa Arch. These results are consistent with a thermodynamic assessment for the Madison Limestone-brine system performed by Kaszuba et al. (2011).
2) Injection of supercritical CO2 into the Madison Limestone experiments decreases pH, increases Eh, and drives reaction pathways along the pyrite-anhydrite saturation boundary of an Eh-pH diagram. The bulk mineralogy present in the experiment, and by analogy in the natural system, does not change in response to emplacement of supercritical CO2. Minerals are instead dissolved, mobilized and re-precipitated. Mineral dissolution and re-precipitation textures observed in the Madison Limestone in southwest Wyoming could be records of the emplacement of CO2 as opposed to infiltration of aqueous fluids or diagenetic changes.
3) Published geochemical modeling studies hypothesize that co-injected SO2 will disproportionate into H2S and H2SO4, decreasing pH in formation waters at least one unit more than acidification by CO2 alone. Injection of supercritical CO2 into Madison Limestone and Weber Sandstone experiments decreases in-situ pH between 2.5 and 3.5 units. Co-injection of supercritical CO2 + SO2 yields pH values that closely track SO2-absent experiments, never differing by more than 0.1 pH units. Thus, supercritical CO2 and reservoir rock determine pH, co-injected SO2 does not generate extreme pH.
4) Anhydrite precipitates in response to injection of supercritical CO2 ± SO2 and provides a mineral trap for sulfur in a carbon-sulfur co-sequestration scenario. Anhydrite precipitation decreases aqueous sulfate activity, ultimately leading to carbonate re-precipitation and thus mineralization of carbon.
5) Equilibrium laboratory experiments can predict the long-term fate of reactive carbon in a natural carbon dioxide reservoir as well as a sequestration scenario, even if equilibrium is not achieved on the laboratory scale.
Gale, J., 2009. Impure thoughts. Int. J. Greenhouse Gas Control 3, 1-2.
Kaszuba, J. P., Navarre-Sitchler, A., Thyne, G., Chopping, C., and Meuzelaard, T., 2011. Supercritical carbon dioxide and sulfur in the Madison Limestone: A natural analogue in Southwest Wyoming for geologic carbon-sulfur co-sequestration. Earth Planet. Sci. Lett. 309, 131–140.
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Rao, A.B., and Rubin, E.S., 2002. A technical, economic, and environmental assessment of amine-based CO2 capture technology for power plant greenhouse gas control. Environ. Sci. Technol. 36, 4467-4475.
Surdam, R.C., and Zhao, Z., 2007. The Rock Springs Uplift: An outstanding geological CO2 sequestration site in southwest Wyoming. Wyoming Geological Survey, WSGS-2007-CGRD-02.
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