Damage Mechanisms and Corrosion Inhibition in Oil and Gas Industries

The damage mechanisms for static equipment is refining and petrochemical plants may largely defined as two categories:

1. Aqueous corrosion
2. Dry corrosion

Although this is a very controversial, it is practical to demonstrate in scope of of corrosion inhibition as a corrosion management practice.
Aqueous corrosion is a electrochemical corrosion process, in which the presence of liquid water phase is essential. The upper limit temperature is about 230^oC. The common types of aqueous of corrosion are:

1. General /uniform corrosion , e.g. CO₂ corrosion, aqueous H₂S corrosion
2. Galvanic corrosion
3. Corrosion caused by dissolved oxygen
4. Microbiologically Induced Corrosion (MIC)
5. Corrosion Under Insulation (CUI)
6. Cavitation
7. Flow Assisted Corrosion (FAC)
8. Corrosion fatigue
9. Caustic corrosion
10. Dealloying
11. Erosion
12. Environment assisted cracking

Dry corrosion is usually referred to damage mechanism at elevated temperature, in which presence of free water is not essential. The common type of dry corrosion are:

1. Oxidation
2. Sulfidation
3. Carbonisation/Decatbonisation
4. Iron Dusting
5. Fuel ash corrosion
6. Nitriding
7. High temperature hydrogen attack.

The corrosion inhibition (chemical treatment) is often utilised for aqueous corrosion. The electrochemical process may be efficiently controlled by the use of passivating, neutrualising or adsorption type of corrosion inhibitors. The corrosion inhibitors offers little solution for dry corrosion at elevated temperature. The materials selection and metallurgical approaches are usually the primary mitigation for these metal degradation mechanisms. For example, filming forming corrosion inhibitors have their upper limit at about 230~260^oC. In practical, the fouling issue becomes a serious concern in the range of 150~370^oC, in which antifoulant dosing has to be considered.