Sweet and sour corrosion: What is sweet and sour corrosion?

Sweet and sour corrosion

Corrosion primarily caused by dissolved CO2 is commonly called sweet corrosion, whereas corrosion due to the combined presence of dissolved CO2 and H2S is referred to as sour corrosion. A rule-of-thumb distinction between the two is that sweet corrosion occurs where the partial pressure of CO2 is more than 500 times the partial pressure of H2S, giving iron carbonate as the primary corrosion product. With a CO2 to H2S partial pressure ratio of less than 20, sour corrosion, with a primary corrosion product of iron sulphide will occur. Between these two limits, a complicated mixed CO2 / H2S corrosion regime predominates.

Corrosion in sour or mixed sweet/sour regimes is difficult to predict. The complex interaction of iron sulphide corrosion product films and process parameters, such as flow rate, flow regime, solids, etc., can cause large changes to the character of the sulphide film, and the level of protection it provides. Where the film fails, or is damaged, high localized-corrosion rates can occur. Corrosion in very sour regimes where the CO2 / H2S ratio is significantly less than 20:1 is likely to develop a stable iron sulphide film that should provide a low general corrosion rate, but pitting failure is still possible, particularly where the chloride content is high and where there is elemental sulphur and organic acids.

The CO2 / H2S ratio for each of the four composition cases is mostly in the order of 20:1 or below. This means that the H2S is likely to stabilize the corrosion product film and reduce the general corrosion rate, possibly to very low levels, but there will be a tendency for failure by localized pitting, particularly if the water phase contains elemental sulphur and/or high chlorides.
The threat of mixed CO2 / H2S corrosion is considered as high risk if not properly mitigated. It can cause uniform corrosion, pitting corrosion that could cause metal loss and may affect the integrity of the facilities. In order to mitigate the mixed CO2 / H2S corrosion, sufficient corrosion allowance shall be provided for carbon steel based on service life corrosion.

If corrosion rates for carbon steel are not acceptable or economically viable, consideration may be given to:
  • The use of internal coating for vessels / equipment, either with or without internal cathodic protection from sacrificial anodes

  • The use of corrosion resistant alloys (CRAs). CRAs may be considered in either solid form or as internal cladding. CRA must provide suitable corrosion and chloride stress corrosion cracking (CSCC) resistance to the process and/or external environment.

Mixed CO2 / H2S Corrosion

CO2 Corrosion
Mixed CO2 / H2S Corrosion
H2S Corrosion
CO2 : H2S Ratio
> 500:1
500:1 to 20:1
< 20:1
Principal Corrosion Product
Mixed FeCO3 / FeS
FenSm (Various Crystallographic Structures)
Mode of failure
General and localized
(Rupture & Pinhole Leak)
General and localized
(Rupture & Pinhole Leak)
(Pinhole Leak)
Top-of-the-Line Corrosion
Caused by high moisture condensation rates in wet gas pipelines and in stratified flow regimes for multiphase pipelines
Not observed unless excessive methanol is injected
Not observed unless excessive methanol is injected
Corrosion sensitivity:
• Higher liquid velocity
• Chloride
• Elemental Sulphur
• Settled solids /sands

• Increase
• Modest increase
• N/A
• Modest increase

• Mixed Effects
• Increase
• Increase
• Increase

• Increase (if FeS scale Removed
• Increase
• Increase
• Increas

H2S Corrosion: SSCC and HIC

Sour service is defined as exposure to oilfield environments that contain sufficient H2S to cause cracking of materials by the mechanisms addressed by ISO 15156.

In accordance with NACE MR0175 / ISO 15156, the service conditions for all equipment items in contact with the process fluids in gas systems are rated as sour if:

         There is free water present as a liquid
         The total pressure is at or above 65 psia (448kPa)
         The partial pressure of hydrogen sulphide is equal to or greater than 0.05 psia (0.345 kPa).

The presence of H2S can cause sulphide stress cracking, hydrogen embrittlement, or other hydrogen related damage mechanisms. The severity of the sour environment, determined in accordance with NACE MR0175/ISO 15156.

Sulphide stress cracking will not occur in a dry environment, but cracking can occur very quickly and consideration must be given to the chance of process upsets that can give rise to free water. All metallic materials that exceed the H2S partial pressure for sour service must conform to the requirements of NACE MR0175 / ISO 15156, third edition (2015).

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