Amine Corrosion Causes

 Amine solutions, in their pure and properly maintained state, are not particularly aggressive toward carbon steel. The corrosivity that leads to equipment damage is almost always a result of contamination, degradation, or operating conditions outside design intent. Most amine system corrosion follows one of three pathways: acid gas-driven attack in rich amine service, oxygen-driven attack throughout the loop, or heat stable salt-driven attack in hot lean sections.

These mechanisms often act together. A unit with oxygen ingress will develop heat stable salts, which then accelerate acid gas-driven corrosion in the regenerator. Addressing one mechanism without understanding the others is one of the most common reasons corrosion programs fail.

 Oxygen Ingress

Oxygen is one of the most aggressive contributors to amine system corrosion. It directly oxidizes carbon steel, accelerates amine degradation, and produces organic acids that form heat stable salts. The result is a compounding problem: oxygen creates HSS, which then drives further corrosion long after the oxygen exposure has ended.

Common entry points include unblanketed storage tanks, leaking pump seals, sample points, vacuum sections of the loop, and poorly maintained valve packing. Even trace oxygen exposure, if sustained over time, can produce measurable damage. Plants that prioritize oxygen control consistently see lower corrosion rates and longer equipment life. For more on this relationship, link to the internal article on Heat Stable Salts in Amine Systems.

Acid Gas Loading

CO2 and H2S are the gases the amine unit is designed to absorb, but they also drive corrosion under certain conditions. Rich amine, the solution leaving the contactor loaded with acid gas, is significantly more corrosive than lean amine, particularly at elevated temperatures. CO2 corrosion can produce iron carbonate scales, while H2S corrosion can produce iron sulfide. In CO2-rich service especially, rich amine velocities and turbulence become critical design factors because high-velocity zones in piping and exchangers can strip protective films and expose fresh metal.

The most aggressive conditions occur when rich amine is heated, such as in the lean-rich exchanger and regenerator inlet. Acid gas flashing in these locations produces localized two-phase flow that mechanically and chemically attacks the surface.

Heat Stable Salts

Heat stable salts dramatically increase the corrosivity of the amine solution by lowering pH, increasing ionic strength, and chelating iron from carbon steel surfaces. Some HSS species, particularly thiocyanate and certain organic acid anions, are especially aggressive toward steel. When total HSS climbs above roughly 2 wt% on a free amine basis, corrosion rates typically accelerate sharply, even if other parameters remain unchanged.

The hot lean amine sections of the unit, including the regenerator bottom, reboiler tubes, and lean amine return, are most affected because elevated temperature amplifies the corrosivity of HSS-laden solution. Plants seeing iron levels above 10–20 ppm in circulating amine should treat HSS analysis as a priority, not an afterthought.

Amine Degradation Products

Beyond HSS, amine solutions develop a range of heavier degradation compounds over time, including bicine, HEED, and various dimers and oligomers. Some of these compounds are mildly corrosive on their own, but their larger impact is operational: they raise viscosity, foul exchanger surfaces, and reduce stripping efficiency. Reduced stripping forces operators to push higher reboiler temperatures, which then accelerates further degradation. The cycle compounds quickly 

if it is not interrupted by reclamation.

Poor Filtration and Solids

Suspended solids in circulating amine, typically iron sulfide, corrosion byproducts, and particulate carryover, contribute to corrosion through three main mechanisms. They mechanically erode protective oxide and sulfide films, creating localized fresh-metal sites. They settle in low-flow areas and create under-deposit corrosion cells, where the chemistry beneath the deposit becomes much more aggressive than the bulk fluid. They also provide nucleation sites that accelerate foaming, which in turn creates operating conditions favorable to further attack.

A properly maintained 10-micron mechanical filter on the lean amine side, combined with activated carbon for organic contaminants, is foundational to corrosion control. A bypassed or fouled filter is one of the fastest paths to elevated iron levels.

 Not all parts of an amine unit corrode at the same rate. The areas most consistently affected include:

• The regenerator and reboiler. High temperatures, stripping vapor, and concentrated HSS make this the most aggressive zone in most units. Reboiler tube failures are among the most common single-point corrosion failures.
• The lean-rich exchanger. Both sides of the exchanger see corrosion: the rich side from acid gas flashing, the lean side from hot HSS-laden solution. Tube leaks here are particularly problematic because they cross-contaminate the streams.
• Rich amine piping. High flow velocities and acid gas content make rich amine lines vulnerable to flow-accelerated corrosion, especially at elbows, tees, and downstream of orifices and control valves.
• Regenerator overhead system. The overhead condenser and accumulator see hot, water-saturated acid gas and are vulnerable to acid condensation corrosion. Material selection in this zone is critical.
• Reflux piping. The reflux water returning to the regenerator can become highly acidic, particularly if HSS partition into the reflux loop, leading to localized attack.

 Recognizing corrosion early is critical because most failure modes accelerate once protective films are compromised. Operators should monitor for:

• A steady increase in iron, nickel, or chromium content in circulating amine.
• Coupon weight loss exceeding industry guidelines; in amine service, 5 mpy is often considered an upper acceptable limit, with target rates well below that.
• Visible thinning, blistering, or pitting during inspection.
• Increasing leak frequency at flanges, valve bonnets, and weld joints.
• Black, particulate-laden amine indicating high iron sulfide content.
• Reduced equipment service life compared to design expectations.
• Rising makeup water consumption that may suggest leaks.

The challenge is that many of these symptoms develop gradually. By the time leaks appear, significant material loss has already occurred. That is why a systematic monitoring program, not reactive inspection, is the foundation of effective corrosion management.

 Before implementing mitigation, the actual driving mechanism must be identified. A complete diagnostic workup includes:

Corrosion Coupon Monitoring

Coupons placed at critical locations, such as rich amine, lean amine, and reboiler return, provide direct measurement of corrosion rates. Coupons should be inspected and analyzed at consistent intervals, typically quarterly, and trended over time.

Online Corrosion Monitoring

Linear polarization resistance and electrical resistance probes can provide real-time corrosion rate data, which is valuable for catching upset conditions before they cause damage.

Iron and Metals Analysis in Solvent

Trending iron, nickel, and chromium concentrations in circulating amine indicates active material loss and helps localize where the loss is occurring.

Full Solvent Analysis

Amine strength, HSS speciation through ion chromatography, degradation products, and suspended solids all contribute to the picture. Without this data, corrosion mitigation becomes guesswork.

Equipment Inspection

Ultrasonic thickness measurements, visual inspection of internals during turnaround, and targeted radiography of high-risk welds provide ground truth on actual material condition.

Once the data is in, the goal is to match the corrosion pattern to a mechanism. Uniform thinning across hot lean sections points to HSS. Localized attack at flow disturbances points to flow-accelerated corrosion. Random pitting throughout the system points to oxygen and chloride contamination. Each pattern leads to a different intervention.

 Oxygen Control

Because oxygen drives both direct corrosion and HSS formation, oxygen exclusion delivers the highest leverage of any single intervention. Nitrogen blanketing on storage tanks, mechanical seal upgrades on circulation pumps, sample point design improvements, and routine leak surveys are all part of a complete oxygen control program.

HSS Management

Keeping HSS below operational thresholds, typically under 2 wt%, substantially reduces corrosivity. This requires routine sampling, trending, and a defined reclamation strategy when levels approach the action threshold. Reactive reclamation after corrosion damage has already occurred is far more expensive than preventive reclamation. Foaming events, which often accompany high HSS, are addressed in the internal article on Amine Foaming Causes and Troubleshooting.

Filtration and Solids Control

A well-maintained mechanical filter and activated carbon system removes both particulates and organic contaminants. Filter elements should be replaced based on differential pressure and a defined schedule, not only when they fail. Activated carbon should be replaced before breakthrough, with bed condition verified periodically.

Material Selection and Upgrades

In high-risk locations, material upgrades from carbon steel to 304/316L stainless steel, duplex stainless, or specialty alloys can substantially extend service life. Common candidates include reboiler tubes, regenerator overhead piping, and lean-rich exchanger internals. Material selection decisions should be data-driven and based on actual corrosion patterns observed in the unit.

Operating Condition Optimization

Maintaining design-target temperatures, acid gas loadings, and circulation rates all contribute to corrosion control. Excessive reboiler temperatures, over-circulation, and operation outside design loading windows all accelerate corrosion. Routine review of operating parameters against design intent is a low-cost intervention with meaningful payback.

Corrosion Inhibitors

In specific applications, corrosion inhibitor injection can supplement other controls, but inhibitors are not a substitute for managing root causes. Inhibitor selection requires careful evaluation of compatibility with the amine, downstream impacts, and long-term solvent quality. Used incorrectly, inhibitors can themselves contribute to foaming and contamination.

• Treating corrosion as a maintenance problem rather than a chemistry and operations problem.
• Ignoring gradual increases in iron content in circulating amine.
• Failing to monitor and control oxygen ingress.
• Delaying reclamation until corrosion damage is already evident.
• Using corrosion inhibitors to mask underlying contamination instead of addressing root causes.
• Skipping speciation analysis and treating all HSS as equivalent.

 Routine corrosion monitoring and basic mitigation can be managed in-house by experienced operations and maintenance teams. However, when corrosion is severe, persistent, or accompanied by multiple operational symptoms such as foaming, capacity loss, or unexplained iron levels, a specialized assessment is warranted. Detailed system inspections, lab-scale corrosion testing, and engineering evaluation can isolate causes that are not visible in routine data.

 Nexo Solutions provides comprehensive amine system corrosion diagnostics and mitigation engineering across gas processing, LNG, and refinery operations. Our capabilities include corrosion monitoring program design, advanced solvent analysis and HSS speciation, root cause investigations, material selection consulting, system optimization studies, and onsite testing and troubleshooting.

If your unit is showing signs of accelerated corrosion, or if you want to build a preventive monitoring program before damage emerges, our team can help.

Contact Nexo Solutions to discuss your amine system corrosion management strategy.