99 Diseases of Pressure Equipment: High Temperature Sulfidation Corrosion

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By John Reynolds at Intertek, and John Reynolds at Intertek. This article appears in the July/August 2004 issue of Inspectioneering Journal

High temperature sulfidation is probably the most common high temperature corrosion nemesis in the refining industry, since there are very few “sweet” refineries still in operation. Sulfidation corrosion typically is of concern in sour oil services starting at temperatures in the 500F (260C) range. Up to that point, carbon steels are often acceptable, except in the most highly sour environments. In this case, “sour” means hydrogen sulfide (or other active sulfur compounds) containing oils. And while the corrosion rates for sulfidation are “fairly” predictable and “fairly” general, in “sour oil boiling and cat cracking” operations, corrosion rates are much less predictable, occur at higher rates and are more localized when sulfidation occurs in hydroprocess operations. As is the case with oxidation, alloying with chromium enhances resistance to sulfidation, almost in direct proportion to the chromium content when hydrogen is not present. With hydrogen present, the lower chromium alloys are of less use in resisting sulfidation. The 300 series austenitic stainless steels (containing 18%+ chromium) have substantial resistance to sulfidation and are often the material of choice under the more harsh sulfidation conditions, corroding at only 1-2 mpy even up to ~750F (~400C) when hydrogen is not present; though their susceptibility to chloride cracking at lower temperatures when moisture is present means that austenitic stainless steels are no panacea for sour oil process equipment.

Most of the industry failures from sulfidation occur for one of three reasons:

  1. Lack of adequate PMI - which means that an inadvertent substitution of carbon steel or lower chromium alloy causes a piping component to fail prematurely and unexpectedly. This has been a repetitive problem in the refining industry, and one that I will address at the upcoming API/NPRA Operating Practices Symposium on October 14 at the Anaheim Hilton.
  2. The second reason is closely related to the first reason, and results when piping systems have a mixture of higher silicon containing steels (ie silicon-killed) and lower silicon containing steels (non-killed). Silicon content imparts significant resistance to sulfidation corrosion for carbon steels in the 500-650F (260-342C) range. Over the long haul, silicon containing fittings and pipe will corrode at significantly lower rates, such that if you do not have thickness monitoring locations (TML) on each of the low silicon containing components, you may be at risk of an unexpected sulfidation failure.
  3. And the third reason: Process Creep - the gradual increase over time in hydrogen sulfide content of process streams introduced by changing feedstocks. This situationresults in increasing corrosion rates from sulfidation that may be unknown to the inspection folks that think that the long term corrosion rates that they have been measuring for many years are still applicable, when they may not be. This situation can be avoided with better management of change (MOC) that effectively communicates increasing sulfur components in feedstocks to the inspection group, so that inspection intervals can be adjusted appropriately.

Do you have adequate PMI & MOC work processes at your facility so that your management will not be surprised by a premature and unexpected piping failure from high temperature sulfidation? Does your RBI team consider the possibility of PMI issues (including low silicon content steels) contributing to the risk of failure in your hot oil systems? Does your PHA team consider the risk of process creep increasing the potential hazard of an incident in your hot oil systems?

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