How big of a problem is the presence of impurities in the CO2 stream destined to be stored underground? Of course the type of contaminant and its concentration are key factors. The possible effects are field-specific and depend on the mineralogical composition of the rocks. They can vary from dissolution creating micro-voids, to mineralization which fills-up the pore-space. Although the potential mechanisms through which certain impurities could affect storage capacity or integrity are well understood, simulating the exact conditions of a storage complex and the gradual accumulation of impurities in the laboratory pose significant problems.
CO2 streams from all capture processes will contain variable levels of impurities, sometimes referred to as ‘co-components’ or ‘contaminants’. The impurities in CO2 streams originate from the source of CO2, for instance a power plant or a cement kiln. They can include nitrogen (N2), oxygen (O2) and water (H2O), but also air pollutants such as sulphur (S) and nitrogen oxides (SOx and NOx), particulates, hydrochloric acid (HCl), hydrogen fluoride (HF), mercury (Hg), other metals and trace organic and inorganic contaminants. The removal of certain contaminants may be required for health, safety and environmental protection reasons, but also to ensure efficient transport and storage.
Research on the effects of these impurities on the integrity of geological storage formations is limited. Most CO2-rock interactions have been investigated with laboratory experiments using pure CO2. Only a small number of laboratories world-wide are able physically simulate the affects of sulphur oxides and acids at high pressure and temperature over geological time frames, and a lack of understanding of the kinetics of diffusion and chemical reactions limits the reliability of modelling. Nevertheless, two broad categories of possible impacts on CO2 storage processes can be identified.
First, the presence of non-condensable gases such as hydrogen (H2), argon (Ar), N2 and O2 can significantly reduce the density of the CO2 stream. In particular, captured CO2 streams from oxyfuel capture technologies can contain relatively large percentages of non-condensable gases, up to approximately 10% depending on the conditioning processes deployed at the installation. Specifically for storage, the low density of the injected CO2 stream would lead to the inefficient utilisation of pore space, reducing the amount of CO2 that can be stored at a particular storage location. Therefore, there are economic reasons to partially remove certain contaminants in the CO2 stream.
Second, the presence of certain impurities such as hydrogen sulphide (H2S), NOx and SOx can reduce the pH of the formation water and consequently affect porosity and permeability of the cap rock. The presence of SO2 and the formation of sulphuric acid, has the most potent effect at reducing the pH of the in-situ water. The extent of the drop in pH results in an acidified radial zone of approximately 200m around the injection point, whereby the dissolution of carbonate material takes place. At the periphery of the acidified zone where the pH rises, the precipitation of secondary minerals is observed. The precipitation of such minerals is higher in the cases where CO2 is co-injected with SO2. It has been observed that after approximately 100 years, sufficient precipitation of secondary minerals may take place that can induce changes in porosity and permeability (1, 2). This process could lead to the long-term stabilisation of the injected CO2, and thereby improve the integrity of the storage complex. No current scientific literature indicates the co-injection of SO2 or H2S leading to short-term (<10 years) porosity reduction that could hinder injectivity.
What should policymakers do? In terms of setting limits on impurities for storage purposes, the literature points towards a maximum permissible amount of non-condensable gases in the CO2 stream of 4% by volume (3, 4). This figure is understood to reflect an optimum balance between gas conditioning costs and the costs of compression. Concerning the potential for impurities to induce changes in the porosity and injectivity of a storage site, there are no indications that the amounts expected in captured CO2 streams will reduce the efficiency or integrity of storage.
December 2nd, 2011
1 Knauss, K., Johnson, J.W., Steefel, C.I., 2005. Evaluation of the impact of CO2, co-contaminant gas, aqueous fluid and reservoir-rock interactions on the geologic sequestration of CO2. Chemical Geology 217, 339-350.
2 Xu T, Apps JA Pruess K and Yamamoto H., 2007. Numerical modelling of injection and mineral trapping of CO2 with H2S and SO2 in a sandstone formation. Chemical Geology 242, 319-346.
3 Visser, de, E., Hendriks, C., Barrio, M., Molnvik, M., de Koijer, G., Liljemark, S. and le Gallo, Y., 2008. Dynamis CO2 quality recommendations. International journal of greenhouse gas control 2, 478-484.
4 Yan, J., Anheden, M. and Bernstone, C. (2009). Impacts of non-condensable components on CO2 compression/purification, pipeline transport and geological storage. Proceedings of the 1st IEA Oxyfuel Combustion Conference. Cottbus, September 8-11, 2009.
Tom Mikunda is a researcher at the Energy research Centre of the Netherlands (ECN). Since joining ECN in 2009, Tom has participated in a wide range of projects related to CCS, including CO2 transportation, CO2 storage, public perception and regulatory issues. Tom is currently coordinating the research activities on the legal and regulatory aspects of CCS within the Dutch national CCS R&D programme CATO2.