Sour Gas Line: Metallurgy and Chemical Treatment Under Constraint
A 6-inch carbon steel (API 5L X65) sour gas gathering line transports 12 MMscfd of gas at 850 psig and 120°F. Gas analysis: 4.5 mol% H2S, 2.0 mol% CO2, 0.5 mol% water vapor, balance methane. The line is 8 miles long, buried, and has no upstream dehydration. Corrosion coupons installed 6 months ago show uniform corrosion at 12 mpy and localized pitting up to 40 mpy. The operator wants to extend the line's life by at least 10 years without replacing pipe. Options under consideration: (A) continuous injection of a film-forming amine corrosion inhibitor at 50 ppm, (B) batch treatment with a different inhibitor every 3 months, (C) increasing gas velocity to sweep liquids, or (D) adding a dehydration unit upstream. Budget is limited; the line must remain in service.
1. Evaluate the likelihood and type of wet H2S cracking and recommend which option(s) should be prioritized to mitigate both general and localized corrosion, justifying with calculations and industry criteria.
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First, assess cracking risk. With 4.5 mol% H2S and 850 psig, the H2S partial pressure is 0.045 × 850 = 38.25 psia. This exceeds the 0.05 psia threshold for sour service per NACE MR0175/ISO 15156, so the line is in sour service. However, carbon steel X65 may be acceptable if hardness and stress are controlled, but the presence of free water and high H2S partial pressure raises susceptibility to sulfide stress cracking (SSC) and hydrogen-induced cracking (HIC). The 12 mpy uniform corrosion indicates active wet H2S corrosion; pitting at 40 mpy suggests localized attack likely due to under-deposit or flow-induced effects. Without dehydration, water condenses, creating wet conditions. Option D (dehydration) would eliminate free water, but capital cost and footprint may be high. Option A (continuous inhibitor) can reduce corrosion if properly applied, but inhibitor efficiency must be >90% to bring 12 mpy to <1.2 mpy; however, pitting may not be controlled. Option B (batch) may be less effective for a long line with liquid holdup. Option C (velocity increase) could increase erosion-corrosion and is not recommended. A combined approach: implement continuous inhibitor with a qualified product (e.g., per NACE SP0198) and monitor with coupons and probes; also evaluate dehydration as a long-term solution. Immediate action: reduce H2S partial pressure by dehydration or dilution, but that is not feasible short-term. Therefore, prioritize A with careful monitoring, and plan for D in the next capital cycle. Also, consider internal coating as an alternative, but not listed. The key is to control water wetting and inhibitor availability.
2. If continuous inhibitor is chosen, what key parameters must be monitored to ensure effectiveness, and what would trigger a change in treatment?
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Key monitoring parameters: (1) corrosion rate from coupons and electrical resistance probes (target <1 mpy), (2) inhibitor residual concentration in the water phase (target >10 ppm for film persistency), (3) water chemistry (pH, iron count, chlorides) to detect changes, (4) pigging frequency to manage solids and distribute inhibitor, (5) bacterial activity (SRB) if water accumulates. Trigger for change: if corrosion rate exceeds 2 mpy for two consecutive months, or pitting is observed on coupons, or inhibitor residual falls below target, then re-evaluate inhibitor type or dose, consider batch treatment in conjunction, or accelerate dehydration. Also, if H2S partial pressure increases due to reservoir changes, reassess cracking risk.