Crude Unit Overhead Corrosion

Introduction

The overhead of a crude unit can be subjected to a multitude of corrosives species.

Hydrochloric acid, formed from the hydrolysis of calcium and magnesium chlorides, is the principal strong acid responsible for corrosion in crude unit overhead.
Carbon dioxide is released from crudes typically produced in CO2 flooded fields and crudes that contain a high content of naphthenic acid.
Low molecular fatty acids such as formic, acetic, propionic and butanoic acids are released from crudes with a high content of naphthenic acid.
Hydrogen sulfide, released from sour crudes, increase significantly corrosion of crude unit overhead.
Sulfuric and sulfurous acids, formed by either oxidation of H2S or direct condensation of SO2 and SO3, also increase corrosion.

Mitigation of this type of corrosion is performed by process changes, materials upgrading, design changes, and injection of chemicals such as neutralizers and corrosion inhibitors. Process changes include any action to remove or at least reduce the amount of acid gas present and to prevent accumulation of water on the tower trays. Material upgrading include lining of distillation tower tops with alloys resistant to hydrochloric acid. Design changes are used to prevent the accumulation of water. They include coalescers and water draws. The application of chemicals include the injection of a neutralizer to increase the pH and a corrosion inhibitor. The presence of many weak acids such as fatty acids and CO2 can buffer the environment and require a higher use of neutralizers. Excess of neutralizer may cause plugging of trays and corrosion under the salt deposits. Unfortunately, no experience on the use of dew point probes is available. A dew point probe is typically placed in a location at least 100F above the calculated dew point temperature. The probe elements are then cooled internally by cold air injection and the temperature at which the first liquid drop forms is determined for the actual conditions in the tower. The injection point and the amount of chemicals used depend on the knowledge of the temperature in the tower where condensation start. With the number of corrosive species present, calculated dew point may be much lower than the actual dew point.

References

Merrick, R.D. and T. Auerbach, “Crude Unit Overhead Corrosion Control”, Materials Performance, September 1983, Page 15.
French, E.C. and W.F. Fahey, “Water Soluble Filming Inhibitor System for Corrosion Control in Crude Unit Overheads”, Materials Performance, September 1983, Page 9.
Rue, J.R. and D.P. Naeger, “Cold Tower Aqueous Corrosion: Causes and Control”, CORROSION/90, Paper # 211, NACE, Houston, Texas, 1990.
French, E.C. and W.F. Fahey, “HCl not Sole Culprit in Crude Overhead Corrosion”, Oil & Gas Journal, May 28, 1979, Page 67.
Cox, W.M, W.Y. Mok and R.G. Miller,” Corrosion Monitoring in Refinery Overheads”, CORROSION/90, Paper # 200, NACE, Houston, Texas, 1990.
Borgard, B.G., S.A. Bieber and J.B. Harrell, ” Control of CO2 Corrosion in Refinery Crude Unit Atmospheric Tower Overhead Vapor Condensing Systems”, CORROSION/93, Paper # 633, NACE, Houston, Texas, 1993.
Rue, J.R. and D.P. Naeger, “Advances in Crude Unit Corrosion Control”, CORROSION/87, Paper # 199, NACE, Houston, Texas, 1987.
Edmonson, J.G. and S.E. Lehrer, ” Advances in Neutralizing Amine Technology”, CORROSION/94, Paper # 514, NACE, Houston, Texas, 1994.
Fearnside, P., R.B. Lessard and D.L. Stonecipher, “Advances in Continuous Monitoring for Improved Corrosion Control”, CORROSION/94, Paper # 516, NACE, Houston, Texas, 1994.
Hausler, R.H. and N.D. Coble, “Crude Unit Overhead Corrosion”, Hydrocarbon Processing, May 1972, Page 108.
Lindley, W.A. and R.C.Strong, “Selective Neutralization of Overhead Crude-Unit Corrosion by SOx is Identified and Controlled”, Oil & Gas Journal, June 16, 1986, Page 112.
Schutt, H.U. and R.J. Horvath, “Crude Column Overhead Corrosion Problems Caused by Oxidized Sulfur Species”, CORROSION/87, Paper # 198, NACE, Houston, Texas, 1987.