Corrosion generally involves carbon dioxide (CO2), sweet corrosion, or hydrogen sulphide (H2S), sour corrosion. In both cases, water must be present for corrosion to occur.
The problems can be minimised through the circulation of corrosion inhibiting chemicals or the selection of corrosion resistant alloys. The primary factors that affect the severity of corrosion are the gas partial pressure, temperature, pH, chloride concentration and flow velocity.
Sweet corrosion
Sweet corrosion is caused by CO2 which dissolves in the water phase to produce carbonic acid. This lowers the pH, resulting in a highly corrosive environment.
If the predicted corrosion rate is determined to be too severe for carbon steel (with inhibition) then 13% Cr stainless steel will probably be adequate for most sweet service applications, as long as the operating temperature is below 150°C.
Sour corrosion
Sour corrosion is caused by the presence of H2S and water, even in trace quantities. Careful material selection must be made in H2S environment, as the corrosion process may lead to failure by cracking.
The hydrogen atoms resulting from the corrosion process can diffuse into the metal causing a significant reduction in ductility. This is called hydrogen embrittlement.
The maximum susceptibility of steel to hydrogen embrittlement problems is at room temperature. Above 80°C the degree of embrittlement becomes small.
Two types of cracking:
a. Sulphide stress corrosion cracking
SSCC can occur when a metal is subjected to a tensile stress while in contact with H2S dissolved in water. Cracking can occur suddenly and can lead to an unacceptable release of toxic fluids. A guidance document issued by NACE (National Association of Corrosion Engineers in Houston, USA), referred to as MR-01-75, is the basic code of conduct to which most oil companies adhere.
b. Hydrogen induced cracking
In most steels which have been rolled into plate to be made into vessels and pipe, non-metallic inclusions are rolled out into thin sharp-edged platelets which can act as sites for the accumulation of gaseous hydrogen. This accumulation of hydrogen can lead to the development of cracks even if no external load is present.
Oxygen corrosion
In aerated environments, oxygen reduction can occur in the presence of water, resulting in the corrosion of steel. In water injectors, the level of dissolved oxygen should be below 5 to prevent this form of metal attack and reduce the amount of corrosion deposits injected into the formation. Reducing oxygen to this level is extremely difficult and the use of GRE or polyethylene (PE) lined pipe should be considered for these systems.
Corrosion management
The data collected during inspection and corrosion monitoring activities are a major asset. Commercial software packages can provide a framework for the uniform storage of corrosion-related inspection data for all equipment.
The most cost effective way to handle carbon dioxide problem is using 13% chrome N-80 tubing equipped with premium connections.
Sweet gas fields can be divided into three groups:
- CO2 partial pressure under 2 psia - No corrosion protection is used with no evidence of downhole corrosion.
- CO2 partial pressure 5 to 20 psia - Most fields in this group used inhibitor batch treatment since start-up. Corrosion failures have occurred in unprotected wells and there is some evidence of corrosion despite regular nhibitor treatment.
- CO2 partial pressure over 20 psia - There were many instances of corrosion pitting rates greater than 10 millimetres per year and documented cases of corrosion failures with monthly inhibitor batch treatment. Many operators use stainless steel production tubing to avoid corrosion.
Corrosion control alternatives
- Monitor only
- Stainless steel tubing
- Partial stainless steel
- Inhibitor batch treatment
- Inhibitor squeeze treatment
- Continuous inhibitor injection via annulus
- Continuous inhibitor injection via capillary