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Inspectioneering Journal

99 Diseases of Pressure Equipment: Carbon Dioxide and Condensate Corrosion

By John Reynolds at Intertek. This article appears in the May/June 2005 issue of Inspectioneering Journal

Carbon dioxide (CO2) corrosion is most typically found in boiler condensate return systems that are not adequately treated with corrosion inhibitors (typically amines). Dissolved CO2 in condensate forms carbonic acid (H2CO3) which corrodes steels and low alloys to form a iron carbonate scale. In quiescent solutions, the iron carbonate is actually protective, but as velocity and turbulence increase, the softscale is easily scoured off the surface of the steel to expose the underlying metal to high rates of corrosion. As with the case of BFW corrosion, water analysis is the best way to detect condensate problems that may lead to leaks in condensate return systems. Radiography or ultrasonic thickness measurements on the bottom of condensate piping and on the back side of elbows or other areas of higher velocity and/or turbulence may also detect localized thinning typical of condensate corrosion. Where corrosion inhibition fails to control steam condensate corrosion, selected upgrading to 304 SS is very effective in minimizing corrosion, as long as you don’t get into a chloride cracking regime.

CO2 corrosion is also a problem in oil and gas production flow lines and several petrochemical process systems where carbon dioxide laden condensate forms (also called dew point corrosion), especially in steam methane reformers (hydrogen plants, also known as SMRs). In SMRs, high velocity, hotshift gases, containing significant quantities of CO2 and condensing steam impinge on heat exchanger tube sheets, channels, and knockout pots. Once again, upgrading various affected components to 304 SS is effective in minimizing corrosion.

Do you know where the potential for CO2 corrosion exists in your plants and are you controlling the processor steam condensate effectively, continuously to minimize leaks?


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