Internal Corrosion
Internal corrosion affects pipelines, tanks, vessels, and process equipment. The main mechanisms are CO2 (sweet) corrosion, H2S (sour) corrosion, oxygen corrosion, microbiologically influenced corrosion (MIC), and erosion-corrosion from flow. Candidates must connect the mechanism to the environment and the control method.
Understand key drivers. CO2 corrosion produces iron carbonate scales that can be protective depending on pH, temperature, and flow. H2S can form iron sulfide films and cause sulfide stress cracking in susceptible steels; sour service requires hardness and material controls. Oxygen corrosion is severe and often localized; deaeration and oxygen scavengers are common controls. MIC is associated with bacteria such as sulfate-reducing bacteria (SRB), often in stagnant or low-flow areas, and is detected through monitoring.
Traps: assuming a corrosion inhibitor works without considering partitioning and flow regime; ignoring water wetting (corrosion requires an aqueous phase contacting the metal); and forgetting that stagnant conditions promote under-deposit and MIC attack. Also watch the difference between general and localized internal attack.
Worked example: A wet gas line has partial pressure of CO2 of 0.5 bar. At higher CO2 partial pressure, corrosion risk rises; if the calculated uninhibited rate exceeds the allowable rate, specify a corrosion-resistant alloy or a chemical inhibition program with monitoring. Rule of thumb: CO2 partial pressure above roughly 0.2 bar generally flags sweet-corrosion concern; validate with a proper model.
Understand monitoring: coupons, ER/LPR probes, fluid sampling, and inspection (UT, ILI).