Amine System Corrosion Fundamentals

1. Corrosion Mechanisms in Amine Systems

Corrosion in amine gas treating systems is driven by the presence of dissolved acid gases—hydrogen sulfide (H₂S) and carbon dioxide (CO₂)—in the amine solution. The rich amine stream, which carries absorbed acid gases from the absorber to the regenerator, is particularly aggressive because the acid gas loading creates a corrosive environment that attacks carbon steel piping, vessels, and heat exchanger surfaces.

The severity of corrosion depends on several interrelated factors: acid gas loading, amine type and concentration, solution temperature, flow velocity, and the presence of amine degradation products. Understanding each mechanism is essential for developing an effective corrosion management program per API 945 guidelines.

Acid Gas Corrosion

The primary corrosion mechanism in amine systems is acid gas attack on carbon steel. When CO₂ dissolves in the aqueous amine solution, it forms carbonic acid (H₂CO₃), which dissociates to release hydrogen ions that attack the steel surface. CO₂ corrosion becomes increasingly aggressive at temperatures above 180°F, which is why the hottest parts of the amine circuit—the reboiler, regenerator, and hot side of the lean/rich exchanger—experience the highest corrosion rates.

H₂S corrosion produces iron sulfide (FeS) as a corrosion product. Unlike the porous and non-protective iron carbonate scale from CO₂ corrosion, iron sulfide can form a semi-protective film on the steel surface. However, this film is fragile and can be dislodged by high flow velocities, turbulence, or thermal cycling, exposing fresh metal to continued attack.

Amine Degradation and Heat-Stable Salts

Amine degradation products, particularly heat-stable salts (HSS), are a major contributor to accelerated corrosion. HSS are acidic in nature and reduce the pH of the amine solution, increasing the corrosivity of the circulating solvent. Even moderate HSS accumulation (3–5 wt%) can double or triple corrosion rates compared to a clean amine solution.

Velocity-Assisted Corrosion

High amine velocities strip away protective corrosion product films, continuously exposing fresh metal to the corrosive solution. This erosion-corrosion mechanism is particularly damaging in rich amine piping, where velocities exceeding 5 ft/s in carbon steel lines can cause rapid metal loss. Elbows, tees, and downstream of control valves are especially vulnerable due to turbulent flow patterns.

Corrosion Locations in Amine Unit

The highest-risk locations share common characteristics: elevated temperature, high acid gas loading in the amine, and turbulent flow conditions. Corrosion management efforts should focus on these critical areas, with more frequent inspection intervals and consideration of upgraded metallurgy where carbon steel proves inadequate.

2. Material Selection

Proper material selection is the most effective long-term strategy for managing corrosion in amine systems. While carbon steel is the standard construction material for most amine service, certain high-temperature and high-velocity locations require upgraded metallurgy to achieve acceptable service life. API 945 provides comprehensive guidance on material selection for amine units, and NACE MR0175/ISO 15156 establishes requirements for materials in sour (H₂S-containing) service.

Carbon Steel

Carbon steel (SA-106 Gr. B for piping, SA-516 Gr. 70 for vessels) is the workhorse material for amine service and is adequate for the majority of the amine circuit when proper operating practices are maintained. Carbon steel relies on the formation of a protective iron sulfide film to limit corrosion rates to acceptable levels (typically <5 mpy). The key requirements for successful carbon steel service include: maintaining amine velocity below recommended limits, controlling HSS levels, and ensuring proper solution chemistry.

Stainless Steel 304/316

Austenitic stainless steels are used in locations where carbon steel corrosion rates are unacceptable. Type 304 stainless steel provides good resistance to general amine corrosion and is commonly used for regenerator overhead condensers and reflux piping. Type 316 stainless steel offers additional resistance to pitting and is preferred for reboiler tubes and high-velocity areas where chloride contamination may be present.

Stainless Steel 316L

The low-carbon variant (316L) is the preferred choice when the acid gas contains more than 15% CO₂, when HSS levels are chronically elevated, or when welded construction requires resistance to sensitization and intergranular corrosion. The lower carbon content (<0.03%) eliminates the need for post-weld solution annealing in most applications.

High-Alloy Materials

For extreme service conditions—hot rich amine above 250°F, very high acid gas loadings, or aggressive degradation product environments—nickel alloys such as Alloy 825 (UNS N08825) or Alloy 625 (UNS N06625) may be required. These alloys provide excellent resistance to both general corrosion and stress corrosion cracking but carry significantly higher material costs.

NACE MR0175 / ISO 15156 Requirements

All materials in amine service that may be exposed to wet H₂S must comply with NACE MR0175/ISO 15156 to prevent sulfide stress cracking (SSC), hydrogen-induced cracking (HIC), and stress-oriented hydrogen-induced cracking (SOHIC). Key requirements include:

• Hardness limits: Carbon steel weldments must not exceed HRC 22 (approximately 248 HB) in the base metal, heat-affected zone, and weld metal
• Post-weld heat treatment (PWHT): Required for all carbon steel weldments in amine service per API 945 to reduce residual stresses and hardness; typically performed at 1,100–1,250°F for a minimum of 1 hour per inch of thickness
• HIC-resistant steel: For vessels and piping in rich amine service, HIC-tested plate (per NACE TM0284) with through-thickness testing is recommended
• Prohibited materials: Non-stress-relieved carbon steel welds, high-strength bolting (>HRC 22 for sour service), and free-machining steels

Material Selection Guide by Location

Material upgrades should be evaluated on a life-cycle cost basis. While stainless steel has a higher initial cost (typically 3–5 times carbon steel), the elimination of frequent repairs, reduced inspection costs, and improved reliability often justify the investment in critical service locations.

3. Amine Degradation and Heat-Stable Salts

Amine degradation is an unavoidable consequence of continuous operation in gas treating service. All amines undergo thermal, oxidative, and CO₂-induced degradation that produces non-regenerable compounds collectively known as heat-stable salts (HSS). These degradation products accumulate in the circulating amine solution over time and are a primary driver of accelerated corrosion, foaming, and reduced treating capacity.

Thermal Degradation

Thermal degradation occurs when the amine is heated above its stability threshold. Each amine type has a characteristic maximum operating temperature beyond which degradation accelerates rapidly:

• MEA (monoethanolamine): Stable to approximately 250°F; forms HEED (hydroxyethyl ethylenediamine) and other polymeric products
• DEA (diethanolamine): Stable to approximately 280°F; forms HEOD (bishydroxyethyl oxazolidone), which is both corrosive and a foaming agent
• MDEA (methyldiethanolamine): Stable to approximately 260°F; degrades more slowly than primary and secondary amines due to its tertiary structure

Reboiler temperature is the most critical control parameter for limiting thermal degradation. Localized hot spots on reboiler tubes (caused by fouling, low liquid level, or excessive heat flux) can produce film temperatures well above the bulk amine temperature, accelerating degradation even when the bulk temperature appears acceptable.

Oxidative Degradation

Dissolved oxygen is extremely destructive to amine solvents. Even trace amounts of oxygen (as low as 0.1 ppm) react with the amine molecule to produce organic acids—primarily formic acid, acetic acid, and oxalic acid—which immediately form heat-stable salts with the amine. Sources of oxygen ingress include:

• Inadequate nitrogen blanketing on amine storage and surge tanks
• Seal leaks on amine circulation pumps (especially packing-style seals)
• Inlet gas containing dissolved oxygen (common in tail gas treating and biogas applications)
• Makeup water that has not been properly deaerated

CO₂-Induced Degradation

CO₂ reacts irreversibly with primary and secondary amines to form stable degradation products. MEA reacts with CO₂ to form HEED (hydroxyethyl ethylenediamine) and oxazolidone compounds. DEA forms HEOD (bishydroxyethyl oxazolidone), THEED (trihydroxyethyl ethylenediamine), and other polymerized products. MDEA, as a tertiary amine, does not form carbamates with CO₂ and is therefore much more resistant to CO₂-induced degradation.

Impact of Heat-Stable Salts

Heat-stable salts are called “heat-stable” because they cannot be regenerated (reversed) by the normal reboiler temperature in the regenerator. Once formed, they remain in the circulating amine solution and accumulate over time. The consequences of elevated HSS include:

• Increased corrosion: HSS lower the solution pH and increase the availability of hydrogen ions at the steel surface
• Increased foaming: Degradation products act as surfactants that stabilize foam in the absorber and regenerator
• Reduced treating capacity: HSS tie up amine molecules, reducing the effective amine concentration available for acid gas absorption
• Higher amine losses: Degradation products increase amine volatility losses from the regenerator overhead

The target for total HSS concentration is less than 2% by weight of the circulating solution. Concentrations above 5% typically require reclaiming action (thermal reclaiming, vacuum distillation, or ion exchange) to restore solution quality.

Heat-Stable Salt Types

A comprehensive amine analysis program should include quarterly (or monthly for problematic units) testing for individual HSS species by ion chromatography. Tracking individual anion concentrations over time reveals the dominant degradation pathway and guides corrective action—for example, elevated formate and acetate point to oxygen ingress, while elevated thiosulfate indicates inadequate oxygen exclusion in the presence of H₂S.

4. Corrosion Monitoring and Inspection

An effective corrosion monitoring program combines real-time process measurements with periodic inspection techniques to detect corrosion early, track trends over time, and trigger corrective action before equipment integrity is compromised. API 945 recommends a multi-method approach that integrates both direct measurement of metal loss and indirect indicators of corrosive conditions.

Corrosion Coupons

Corrosion coupons are the most widely used and cost-effective method for measuring corrosion rates in amine systems. Pre-weighed metal coupons (typically carbon steel, matching the piping metallurgy) are inserted into the process stream at key locations using retractable coupon holders. After a standard exposure period of 90 days, the coupons are retrieved, cleaned, and reweighed to determine the weight loss, which is converted to a corrosion rate in mils per year (mpy). Coupons should be installed in the rich amine line, the lean amine line, the regenerator overhead, and the reboiler outlet as a minimum.

Electrical Resistance (ER) Probes

ER probes provide real-time corrosion rate measurement by tracking changes in the electrical resistance of a thin metal element exposed to the process fluid. As the element corrodes and thins, its resistance increases in proportion to the metal loss. ER probes offer faster response than corrosion coupons (days rather than months) and can detect corrosion rate excursions quickly enough to trigger immediate corrective action. They are most valuable in the rich amine circuit where corrosion rates can change rapidly with process upsets.

Ultrasonic Thickness (UT) Surveys

Periodic UT thickness surveys establish the baseline wall thickness of piping and vessels and track metal loss over time. Measurements should be taken at predetermined thickness monitoring locations (TMLs) selected based on the expected corrosion pattern: downstream of elbows, at pipe supports, at injection points, and at locations identified as high-risk by process analysis. Baseline surveys should be performed at commissioning, with subsequent surveys at intervals determined by the measured corrosion rate and the remaining corrosion allowance.

Process Chemistry Monitoring

Indirect corrosion indicators provide early warning of developing corrosive conditions before significant metal loss occurs:

• Iron counts: Dissolved iron in the lean amine solution is a direct measure of corrosion activity. The target is less than 5 ppm total iron; levels above 20 ppm indicate active corrosion requiring immediate investigation.
• Lean amine pH: Normal lean amine pH is 10.5–11.5. A declining pH trend indicates HSS accumulation and increasing corrosivity.
• HSS concentration: Total HSS should be maintained below 2 wt%. Trending individual HSS anions identifies the degradation mechanism.
• Amine strength: Declining amine concentration (without proportional makeup) suggests excessive degradation losses.

Corrosion Monitoring Methods

The most effective corrosion management programs integrate all of these monitoring techniques into a unified tracking system. Plotting corrosion coupon rates, iron counts, HSS levels, and UT readings on the same timeline reveals correlations between process upsets and metal loss, enabling data-driven decisions about material upgrades, operating parameter changes, and reclaiming schedules.

5. Mitigation Strategies

Effective corrosion mitigation in amine systems requires a comprehensive approach that addresses the root causes of corrosion rather than simply treating symptoms. The following strategies, applied in combination, can reduce corrosion rates to acceptable levels (<5 mpy) and extend equipment service life significantly.

Temperature Control

Maintaining reboiler temperature below the amine degradation threshold is the single most important mitigation measure. The reboiler steam temperature or fired-heater duty should be set to achieve adequate regeneration without exceeding the thermal stability limit of the amine. For MDEA systems, the reboiler temperature should not exceed 260°F; for DEA, 280°F; and for MEA, 250°F. Regular reboiler tube cleaning prevents fouling-induced hot spots that create localized over-temperature conditions.

Velocity Limits

Controlling amine velocity in carbon steel piping is critical to preserving the protective corrosion product film. Recommended maximum velocities are:

• Rich amine: ≤5 ft/s in carbon steel piping (3–4 ft/s preferred)
• Lean amine: ≤7 ft/s in carbon steel piping
• Stainless steel piping: Up to 10 ft/s is acceptable for both lean and rich service

If existing piping exceeds these limits, options include re-routing to larger-diameter piping, installing stainless steel at the most turbulent locations (elbows, tees, control valve downstream piping), or reducing circulation rate through process optimization.

Oxygen Exclusion

Preventing oxygen ingress is essential to minimizing oxidative degradation and the formation of organic acid HSS. Key oxygen exclusion measures include:

• Nitrogen blanketing: All amine storage tanks, surge drums, and the regenerator overhead accumulator should be nitrogen-blanketed to prevent air contact with the amine surface
• Mechanical seal upgrades: Replace packing-style pump seals with tandem mechanical seals using a nitrogen or inert gas seal flush to eliminate oxygen ingress at the pump
• Deaerated makeup water: Makeup water should be deaerated or nitrogen-sparged to remove dissolved oxygen before addition to the amine system
• Oxygen scavengers: Chemical scavengers (sodium sulfite or hydrazine) can be used as a secondary measure, though they contribute their own degradation byproducts and should not replace proper exclusion practices

Filtration

Proper filtration removes suspended solids (iron sulfide particles, pipeline scale, well debris) and dissolved contaminants that contribute to corrosion and foaming:

• Mechanical filtration: Full-flow or slip-stream cartridge or bag filters (10–25 micron nominal) on the lean amine stream remove particulate solids. Filter at least 10–20% of the total circulation rate on a continuous slip-stream basis.
• Activated carbon filtration: A carbon bed downstream of the mechanical filter adsorbs dissolved hydrocarbons, surfactants, and degradation products that cause foaming. Carbon beds should be sized for 15–20 minutes of contact time and replaced when breakthrough is detected.

Reclaiming

When HSS levels exceed 5 wt%, active reclaiming is required to restore amine solution quality. Three reclaiming technologies are commonly used:

• Thermal reclaiming: Applicable to MEA and DGA systems; the amine is boiled overhead in a reclaimer vessel, leaving degradation products behind as a waste residue
• Vacuum distillation: Used for MDEA and DEA systems; operates at reduced pressure to lower the boiling point and prevent further thermal degradation during reclaiming
• Ion exchange: Strong-base anion exchange resins remove HSS anions from a slip stream of the circulating amine; does not remove non-ionic degradation products

Neutralization

Addition of caustic soda (NaOH) to the amine solution neutralizes HSS and restores the solution pH. However, this is a temporary measure: the neutralized salts remain in solution and contribute to increased total dissolved solids. Neutralization should be used only as a bridge until reclaiming can be performed, and the total sodium concentration should not exceed 0.5 wt% to avoid additional corrosion issues.

Corrosion Mitigation Checklist

The most successful amine corrosion management programs treat corrosion control as a continuous operational discipline rather than a one-time engineering exercise. Regular amine analysis, proactive filtration and reclaiming, strict oxygen exclusion, and targeted metallurgy upgrades at the highest-risk locations form the foundation of reliable, long-term amine unit operation with minimal corrosion-related downtime.

References

1. API Recommended Practice 945 — Avoiding Environmental Cracking in Amine Units, 3rd Edition
2. NACE MR0175 / ISO 15156 — Petroleum and Natural Gas Industries: Materials for Use in H₂S-Containing Environments
3. GPSA, Chapter 21 — Gas Treating
4. NACE International Publication 34109 — Review of Operating Experience with Amine Units
5. API 571 — Damage Mechanisms Affecting Fixed Equipment in the Refining Industry