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AM-15-70 Predicting Corrosion Rates in Amine and Sour Water Systems
R. Scott Alvis Optimized Gas Treating, Inc. Houston, TX Nathan Hatcher Optimized Gas Treating, Inc. Buda, TX Clayton E Jones Optimized Gas Treating, Inc. Buda, TX
Format:
Electronic (digital download/no shipping)
Associate Member, International Member, Petrochemical Member, Refining Member -
$0.00
Government, NonMember -
$35.00
Description:
Corrosion is a ubiquitous problem in the petroleum refining and natural gas industries, in syngas plants, in processing opportunity crudes, unconventional gases such as shale and coal seam gas, and in numerous other treating applications. The primary impurities removed in the treating process are the acid gases carbon dioxide and hydrogen sulphide. The corrosion of equipment and piping is an inevitable consequence of removing these very gases with amines, and of handling sour water. There are also corrosive impurities such as HCN and oxygen typically associated with gas from cokers and FCC units, and others that are produced in the amine system itself, mostly heat stable salts (HSSs) derived from HCN. Corrosion rates are affected by the nature of the corrosive agent, temperature, fluid velocity, the presence of solids, and the metallurgy involved[1]. To prevent equipment failures, mitigate risk, select optimal materials, and project the impact of processing certain crudes, one must be able to predict corrosion rates pertinent to the particular processing conditions. This article describes the underpinnings of a chemistrybased predictive corrosion model built on both public and much proprietary corrosion rate data. The model includes dependence on ionic solution composition (speciation), fluid velocity, temperature, HSSs, and metallurgy.
Product Details:
Product ID: | AM-15-70 |
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Publication Year: | 2015 |