Vol 2 Chapter 16: Materials Selection for Capture, Compression, Transport and Injection of CO2
Marion Seiersten and Kjell Ove Kongshaug
Abstract: The principal alternative for long-distance transportation of CO2 from source to storage site is in pipelines. To a large extent pipelines can be made in carbon steel as pure, dry CO2 is essentially non-corrosive. More corrosion-resistant materials or corrosion inhibition must be considered when the CO2 contains water that condenses out during transportation. This will occur where it is impossible to dry CO2 to a dew point well below the ambient temperature. Water-saturated CO2 is corrosive when water precipitates, but experiments show that corrosion rates at high CO2 pressures in systems containing only water or water/MEG (monoethylene glycol) mixtures are considerably lower than predicted by corrosion models. This applies particularly at low temperatures that are typical for sub-sea pipelines in northern waters. In our previous study, it has been demonstrated that 20 ppm CO2 corrosion inhibitor is sufficient to lower the corrosion rate below 0.1 mm/y at temperatures up to 30 8C and CO2 pressures up to 72 bar. The present study focuses on determining the corrosion rate as function of CO2 pressure up to 80 bar. The results are compared to existing corrosion models that have been developed to cover a pressure range relevant for oil and gas transportation, i.e. pressures up to 20 bar. The objective of the present study was to verify or extend the use of corrosion models at CO2 pressure above 20 bar. The experiments show that the models overestimate the corrosion rate when they are used above their CO2 partial pressure input limit. At low temperature the models predict more than 10 times the measured corrosion rate. Furthermore, the results indicate that the corrosion rate has a maximum as function of CO2 pressure at 40 and 50 8C. The maximum is at 30–50 bar depending on temperature. Part of the present study was devoted to determine the solubility of water in CO2 containing up to 5% CH4 at high pressure. The results show that CH4 lowers the water solubility and hence increases the risk of free water in liquid or supercritical CO2.
Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO2 Capture
Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA
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