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Corrosion in the Refinery

By: Norm Lieberman, Process Engineering Consultant, New Orleans, LA


My major problem as an operating supervisor in Texas City was corrosion. The common origins of corrosion in an aqueous phase in refinery and process plant applications are HCl, CO2, and SO3. I have not included H2S in this list because H2S, when not interacting with any of the above three molecules, is not particularly corrosive. Also, the above three acids are not corrosive either, unless an aqueous phase (water) is present.

One of the main products of corrosion has never been seen and can only be observed indirectly. That is ionic hydrogen—or a proton. It is these protons that are the culprit of the most dangerous aspect of corrosion. That being “hydrogen-assisted stress corrosion cracking.”


This is the corrosion mechanism that is most familiar to refinery process engineers:

The end products of the above, being an iron sulfide black sludge and a hydrogen ion, cause hydrogen-assisted stress corrosion cracking.

Most of the corrosion products I encountered in my time in Texas City were a black, slippery, finely divided powder. The black powder would, upon drying, autoignite. It burned with a pale blue flame, not visible in sunlight, which emitted a white vapor that made me choke. That is sulfur dioxide (SO2).

Analysis indicated this black powder was iron sulfide (FeHS) or pyrophoric iron. A rather surprising observation, as hydrogen sulfide, which is a weak acid, is not particularly corrosive at moderate temperatures. Why then, I wondered, was there all this corrosion to piping, vessels, and heat exchangers, operating at less than 200°F, due to hydrogen sulfide (H2S)? The source of my corrosion problem was not so much H2S as the real agent of corrosion—rather, it was hydrochloric acid.

Origin of HCl in Refineries

I have always considered hydrochloric acid to be a rather evil molecule. In process units, it originates in two benign ways: from sea water and to promote improved octane in gasoline.

Sea water consists of 97% water and 3% salts. The salts are mainly these three:

The NaCl is pretty much removed in the crude unit desalter, as is much of the CaCl2. The MgCl2 (magnesium chloride) is less soluble in the desalter wash water, and hence 30–40% escapes from the desalter.

At 500°F or hotter, the MgCl2 will dissociate into:

The second origin of HCl encountered in a refinery is manmade. We inject chlorides into the hydrogen recycle gas on naphtha reformers, to enhance gasoline octane. The chlorides react with the recycle hydrogen to produce:

Both of the above reactions produce small amounts of hydrochloric acid. HCl is completely non-corrosive, as long as it is dry. However, should the HCl—which is a very strong acid—become wet, it becomes terribly corrosive to carbon steel piping, vessels, and heat exchanger tubes. The result of this corrosive reaction is:

The hydrogen is produced initially as a hydrogen ion. These protons (H+) actually dissolve into the surrounding metal walls. They get trapped at imperfections in the metallic structures, combine to form molecular hydrogen (H2), and in so doing, create localized hydrogen pressures or stresses inside a metal wall. This is the origin of hydrogen-assisted stress corrosion cracking, which is a leading cause of vessel failure and death and disaster in refineries and chemical plants.

Fe(Cl)2 is water-soluble. As the HCl produced is present in only a few ppm, it does not directly result in very much metal loss, except when aided by H2S in its evil effects.

HCl is a very strong acid. H2S is a much weaker, less reactive acid. Ordinarily, a weak acid like H2S could never displace from its salt (i.e., FeCl2) a strong acid like HCl. However, the concentration of H2S is typically 10,000 times greater in a refinery environment than that of HCl. Thus, the following unfortunate reaction will take place:

Again, this reaction can only proceed in an aqueous phase. The resulting iron sulfide, which is insoluble in water, is that black, thin powder we find all over the plant. The HCl so liberated from the iron sulfide goes on to destroy a new molecule of iron.

It’s rather like hydrochloric acid is a “catalyst for corrosion,” when mixed with water and high concentrations of hydrogen sulfide.

Preventing Corrosion

In refineries, most of the corrosion with the origin I have just described can be mitigated by improved desalter operation to enhance the Mg(Cl)2 extraction. In order of importance, here are steps to minimize MgCl2 escape from the desalter:

  1. Double desalting.
  2. Inject all wash water upstream of the first preheat exchanger.
  3. Use 6 wt% or more water on crude; 4% is too little.
  4. For heavier crudes, use desalter temperatures of 280°–300°F. For lighter crude, use 250°F–270°F.
  5. If the sour water stripper bottoms is used as desalter wash water, keep NH3 concentration at less than 20 ppm.
  6. Control desalter pH to 6.5–7.5.
  7. Continuous use of water recirculation through bottom mud wash nozzles to reduce solids buildup is helpful, but promotes sludge carryover to the exchanger train downstream of the desalter.
  8. Add 50% of chemical demulsifiers to the unit charge tank, and add the rest to the desalter itself.
  9. Use a conductivity probe to monitor the oil-to-emulsion interface levels.
  10. BS&W should be NMT 0.2–0.3 wt.% in the desalter crude effluent stream.

This excerpt is taken from Norm Lieberman’s new book, Process Operations: Lessons Learned in a Nontechnical Language

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Note: The views, thoughts, and opinions expressed in the content above belong solely to the author and do not necessarily reflect the opinions and beliefs of Refining Community or its parent company, CRU Group. 

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