Internal Corrosion of a Wet Sour Gas Gathering Line
A 6-inch carbon steel gathering line carries wet sour gas from three wells to a central processing facility. Operating pressure is 30 bar, temperature 40 °C, and the gas contains 1.2 mol% H2S and 4 mol% CO2. Produced water is present intermittently, with chloride around 25,000 mg/L and pH 5.5. The line has been in service 8 years with no internal inspection beyond annual pig runs. Recent pig returns show increasing black powder and the operator suspects internal corrosion. There is no corrosion inhibitor injection currently. The line is not piggable in the last 2 km due to tight bends.
1. Assess the internal corrosion threat and identify the dominant mechanisms in this line.
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The line is a wet sour gas system with CO2 and H2S, so multiple mechanisms are active:
- CO2 corrosion (sweet corrosion): 4 mol% CO2 at 30 bar gives a significant CO2 partial pressure; with intermittent water wetting, mesa attack and localized pitting are likely, especially at low pH (5.5).
- H2S effects: 1.2 mol% H2S promotes iron sulfide scale formation, which can be protective but is often brittle and can spall, leading to under-deposit and localized corrosion. H2S also raises SSC risk in the steel.
- Chloride-assisted localized attack: 25,000 mg/L chloride increases pitting susceptibility.
- Black powder in pig returns is consistent with iron sulfide/iron carbonate corrosion products, confirming active corrosion.
- Non-piggable last 2 km means no mechanical cleaning and likely under-deposit corrosion and water holdup at tight bends.
The dominant mechanisms are CO2/H2S localized corrosion and under-deposit attack, worst in the non-piggable section.
2. The operator proposes simply adding a corrosion inhibitor injection point at the inlet. Evaluate whether this is sufficient.
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Inlet inhibitor injection alone is insufficient and potentially misleading:
- Inhibitor distribution: In a 6-inch line with intermittent wetting and tight bends, inhibitor may not reach the non-piggable last 2 km, especially where water holdup occurs. Film-forming inhibitors need continuous wetting and sufficient concentration.
- No pigging in last 2 km: Without mechanical cleaning, deposits and corrosion products will accumulate, and inhibitor cannot protect under deposits.
- Inhibitor selection: Must be qualified for wet sour service (H2S/CO2) and compatible with the chloride level; poor selection can cause foaming or emulsion issues.
- Monitoring: Without corrosion monitoring (coupons, ER probes, or sampling), effectiveness cannot be verified.
A defensible program includes inhibitor injection with distribution verification, batch treatment for the non-piggable section, and a monitoring plan.
3. Propose an internal corrosion management program for this line, including how to address the non-piggable section.
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A defensible program:
- Inspection and baseline: Run intelligent pigging (UT or MFL) on the piggable section; for the non-piggable 2 km, use guided-wave or tethered UT or install corrosion coupons/ER probes at accessible points.
- Chemical treatment: Continuous corrosion inhibitor injection at the inlet, with batch treatment (pig-batched inhibitor slugs) for the non-piggable section; qualify inhibitor for wet sour service.
- Monitoring: Coupons, ER probes, water chemistry sampling (pH, chloride, iron), and periodic pig returns analysis.
- Pigging program: Regular pigging of the piggable section to control deposits; consider foam or gel pigs for the non-piggable section.
- Mitigation for non-piggable section: Evaluate replacement with a piggable route, installation of internal coating, or chemical batch treatment with monitoring.
- Risk assessment: Update the corrosion risk assessment and inspection intervals based on findings.