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H2S Corrosion



H2S, polysulfides, and sulfur Information

The maximum concentration of H2S in water is 400 ppm. Wells with large amounts of H2S are usually labeled sour; however wells with only 10 ppm or above can be labeled sour. Partial pressures of only 0.05 H2 S are considered corrosive.

The primary problem in the presence of H2S is metal embrittlement, caused by penetration of H2 in metal. The attack mechanism is complex, with many postulated routes. May involve SH- ion, since it is the only dissolved sulfur ion.

Hydrogen sulfide is a weak acid when dissolved in water, and can act as a catalyst in the absorption of atomic hydrogen in steel, promoting sulfide stress cracking (SSC) in high strength steels. Polysulfides and sulfanes (free acid forms of polysulfides) may be formed when hydrogen sulfide reacts with elemental sulfur. These sulfanes are produced along with other gaseous constituents. As pressure decreases up the production tubing, the sulfanes dissociate and elemental sulfur precipitates, which can cause plugging.

Iron sulfides are often formed from corrosion reactions, and can be important in corrosion control, especially at lower temperatures and low H2 S partial pressures, where a protective film often forms. However, in order for this protective film to form, the absence of oxygen and chloride salts is required.

In environments with hydrogen sulfide (H2S) corrosion, the most common types include uniform corrosion, pitting corrosion, corrosion fatigue, sulfide stress cracking, hydrogen blistering, hydrogen embrittlement, and stepwise cracking. For more on the theory and mechanisms for each corrosion type, go to the theory page.

Corrosion products include black or blue-black iron sulfides, pyrite, greigite, mackinwaite, kansite, iron oxide (Fe3O4), magnetite, sulfur (S), and sulfur dioxide (SO2 ).

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Where Found

H2S corrosion can be found in production wells, flowlines, and during drilling. Areas where H2 S corrosion is common include sucker rods

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Prevention / Mitigation

To reduce or prevent corrosion in an H2S environment:
Drilling - High pH, zinc treatments
Production - corrosion inhibitors
Flowlines - Corrosion inhibitors, H2 S scavengers

Predicting corrosion

Sour gas wells may be corrosive if the pH is 6.5 or less, and H2 S concentration is 250 ppm or more.

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Pictures - Click on thumbnail to see larger picture

Signs of hydrogen sulfide corrosion include shallow round pits with etched bottoms.


H2S Attack on sucker rods followed by corrosion fatigue break, caused by alternating stresses.




Sulfide stress cracking occurs when H2 S corrosion is accelerated by stresses.


Hydrogen embrittlement fractures are caused by hydrogen entering the metal and concentrating internally in high-stress areas, making the metal very brittle. Hydrogen induced cracking can also occur if the metal is subjected to cyclic stresses or tensile stress.

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Petroleum Recovery Research Center, Socorro, NM-87801