Amine corrosion control

Amine systems are central to modern gas processing, enabling the removal of acid gases such as hydrogen sulfide (H₂S), carbon dioxide (CO₂), and mercaptans to meet product requirements, as well as to refineries cleaning off-gases to achieve environmental requirements. Despite decades of operating experience and established design practices, amine units continue to account for a disproportionate share of corrosion-related failures, with significant metal loss often only identified during routine inspections.

Amines themselves are not inherently corrosive; corrosion is driven by the acid gases and contaminants absorbed during service, combined with elevated temperatures, high velocities, and process upsets. Mechanisms such as acid gas breakout, heat stable amine salts (HSAS) formation, wet H₂S conditions, and oxygen ingress can destabilise protective films and promote localised attack, particularly in thermally and hydraulically stressed areas such as regenerator reboilers, stripper bottoms, and inlet zones.

This article examines why amine vessel corrosion persists, identifies where damage most commonly occurs within amine units, and discusses practical mitigation strategies based on field experience and long-term inspection data.

Fundamentals of amine system corrosion

Corrosion behaviour in amine service is controlled by the chemical and thermal conditions established as the solvent circulates through the process. Key contributors to corrosion in amine systems include:

Acid gas breakout

Acid gas breakout occurs when absorbed CO₂ and H₂S flash out of solution due to elevated temperatures, high velocities, or local pressure reductions. This results in localised acid attack, particularly at inlets, tray levels, and reboiler return zones.

High temperatures

Corrosion rates increase significantly with temperature. In rich amine service, temperatures above approximately 220°F (104°C) can lead to severe localised corrosion, especially in regenerator bottoms and reboilers where thermal loading is highest.

Organic linings and coating systems are sometimes considered for corrosion protection in amine service; however, their performance is often limited by operating and maintenance conditions. Elevated process temperatures can exceed the thermal stability limits of many organic materials. In addition, steam-out procedures commonly used during shutdowns and cleaning cycles can lead to softening, blistering, loss of adhesion, or complete failure of organic systems. As a result, organic linings may deteriorate or disbond over time, creating under-film corrosion risks and complicating inspection and repair.

HSAS

HSAS are formed through reactions between the amine and contaminant acids introduced via feed impurities, degradation, or oxygen ingress. HSAS accumulate in the system, lower solution pH, increase conductivity, and destabilise protective surface films.

Wet H₂S environments

While low H₂S concentrations can support the formation of protective sulfide films, elevated H₂S levels promote highly aggressive corrosion mechanisms, including hydrogen-induced cracking (HIC) under certain conditions.

Contaminants and oxygen ingress

Solid particulates contribute to erosion-corrosion in high-velocity regions, while oxygen accelerates amine degradation and HSAS formation, compounding corrosion risk even at low ingress levels.

Despite these challenges, carbon steel remains widely used in amine systems due to its cost-effectiveness and acceptable performance within defined operating limits. However, when these limits are exceeded, corrosion rates can increase rapidly, highlighting the importance of understanding local operating conditions and their impact on materials performance.

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Read the article online at: https://www.hydrocarbonengineering.com/special-reports/27032026/amine-corrosion-control/