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
|
Parameter
|
CO2
Corrosion
|
Mixed CO2 / H2S Corrosion
|
H2S Corrosion
|
|
CO2 : H2S Ratio
|
> 500:1
|
500:1 to
20:1
|
< 20:1
|
|
Principal
Corrosion Product
|
FeCO3
|
Mixed FeCO3 / FeS
|
FenSm (Various
Crystallographic Structures)
|
|
Mode of
failure
|
General
and localized
(Rupture
& Pinhole Leak)
|
General
and localized
(Rupture
& Pinhole Leak)
|
Localized
(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
|
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).