The amine unit’s corrosive secret — and the refinery playbook to stop it

Amine solutions aren’t “acidic” on paper. Yet refineries know the corrosion story is written by dissolved CO₂/H₂S and the amine degradation products those gases spawn. Acid gases lay down weakly protective carbonate/sulfide films on steel (FeCO₃/FeS), but high flow and reboiler agitation break those films again and again, exposing fresh metal and driving rapid loss (scribd.com).

In high‑CO₂ “sweet” service, carbon steel corrosion has been documented at several mm/year — that’s hundreds of mpy (mils per year, a common corrosion rate unit) — unless a protective sulfide film forms; even a few percent H₂S (≈H₂S/CO₂ ≥1/20) changes the picture (digitalrefining.com). When amines absorb CO₂/H₂S or degrade, solutions become more corrosive (lower pH, higher conductivity). Heat‑stable salts (HSS) built from degraded amine chemistry dramatically increase corrosion; in one study, adding oxalate, malonate, or formate to MEA (monoethanolamine) sharply raised carbon‑steel attack, with oxalate most aggressive (pubs.acs.org). HSS also dissolve or undermine any protective carbonate films (scribd.com).

The result is a combined CO₂/H₂S wet‑corrosion plus amine‑related attack, with alloy steels exposed to sulfide cracking modes (HIC/SSC, hydrogen‑induced and sulfide stress cracking) and degraded solutions picking up iron in the hundreds of mg/L (digitalrefining.com).

Corrosion mechanisms and failure modes

Acid‑gas films (FeCO₃/FeS) are inherently fragile under high shear and agitation, particularly around reboilers, where localized turbulence and hot surfaces repeatedly strip the protective layer (scribd.com). In CO₂‑rich feeds, maintaining an H₂S/CO₂ ratio around ≥0.05 (≈1/20) is associated with forming a more protective sulfide film; without it, sweet service can exceed 1 mm/yr metal loss (digitalrefining.com).

Degradation products accumulate as HSS — non‑regenerable salts that raise conductivity, drop pH, dissolve protective layers, and markedly accelerate attack. Laboratory work on 5 M MEA at moderate temperatures underscored oxalate, formate, acetate, malonate, and related species as especially aggressive (pubs.acs.org), aligning with field reports of significant iron pickup in degraded solvents (digitalrefining.com).

Specialized inhibitors and film‑forming strategies

Refiners increasingly deploy filming amines and specialty organics that adsorb onto carbon steel, creating hydrophobic barriers. Long‑chain aliphatic amines such as oleylamine have shown >95% inhibition at just 100 ppm in sour CO₂/H₂S brine (researchgate.net). Custom acrylate‑based polymers can cut carbon‑steel corrosion by ~84% at ≥100 ppm, dropping rates from ~88 mpy to 1.4 mpy under sour‑brine conditions (pubs.acs.org).

Inhibitors are typically continuously injected at 0.1–1% v/v into the rich‑amine or regenerator recycle to maintain monolayer coverage. Common types include long‑chain amines/imidazolines (e.g., oleoyl imidazoline and alkyl tertiary amine derivatives that adsorb strongly as film barriers; see researchgate.net and researchgate.net), neutralizing amines for condensate loops (less common inside amine circuits, more in boilers), and polymeric inhibitors (polyaspartates, acrylate copolymers) that chelate/seal the surface. Selection focuses on amine compatibility, low foaming, and minimal solvent loss; vendor programs often report 50–95% rate reduction at proper dose.

One Saudi Aramco acryloyl copolymer raised polarization resistance by 6× and reduced current density by 84% in testing (pubs.acs.org). For context, without inhibitor, carbon steel in rich amine often runs in the tens of mpy or higher. Plants verify results with corrosion coupons or probes, targeting <5–10 mpy in service (researchgate.net). Programs are commonly delivered as corrosion inhibitors and metered with a dedicated dosing pump for steady coverage.

Operating window and process control

Reboiler temperature control matters. Excess superheat above ~140°C accelerates thermal degradation and HSS formation; running at the minimum strip temperature, often 120–130°C for MDEA (a tertiary amine solvent used in gas treating), limits acid byproducts (scribd.com).

Acid‑gas composition is another anchor. Maintaining sufficient H₂S in CO₂‑containing feeds (≈H₂S/CO₂ ≥1/20) supports a protective sulfide film; in pure CO₂ service, steels have suffered >1 mm/yr attack (digitalrefining.com). Many operators monitor H₂S/CO₂ ratios (≥0.05) and pH, and may treat upstream with scavengers as part of the gas‑quality strategy.

Hydraulics and fouling drive localized risk. Absorbers and reboilers are designed to limit high‑velocity scour; square‑pitch tube bundles ease cleaning and reduce flow‑accelerated corrosion (scribd.com). Foaming control — including foam fractionation and antifoam — keeps entrained water and acids from concentrating on hot steel surfaces; many programs incorporate a targeted antifoam to stabilize operation.

Utilities and lean‑amine quality round out the picture. Clean steam, preheated feeds to minimize cold spots, and low‑O₂/low‑solids makeup are standard. Oxygen scavenging can help (e.g., an inline copper bed), although oxygen was less critical at low acid loading in MDEA regenerator studies (researchgate.net); some facilities deploy oxygen/H₂S scavengers in related circuits to manage contaminants.

Monitoring closes the loop. Plants track corrosion (electrochemical probes, coupons) and solution chemistry (pH, amine strength, iron). Rapid iron increases or rates trending above ~5 mpy trigger maintenance or inhibitor dose‑ups (researchgate.net). In one field case, lowering regenerator temperature by 10–20°C and adding inhibitor cut coupon corrosion from ~10 mpy to 3 mpy — the site target was <5 mpy (researchgate.net).

Heat‑stable salt (HSS) management

HSS are highly corrosive, non‑regenerable salts formed by irreversible reactions between amines and strong acids or contaminants (e.g., O₂, SO₂, HOCN) or entrained from sour feeds. Even small concentrations increase aggressiveness and iron solubility (scribd.com; pubs.acs.org). Studies show that adding ≈0.5–1 wt% of formate, oxalate, or acetate in MEA significantly raises carbon‑steel corrosion rates (pubs.acs.org). Uncontrolled HSS also lowers acid‑gas capacity and promotes foaming and amine fouling, cutting throughput (researchgate.net).

Designers aim to keep common HSS (acetate, formate, glycolate, malonate, etc.) low, often <500–1000 mg KOH/L equivalent. Tactics include routine blowdown/purge — bleeding a fraction of rich amine and replacing with fresh lean solvent — with heavy‑duty units purging about 1–5% of circulation daily. Solvent reclamation via ion exchange or distillation can remove 70–95% of accumulated HSS when well operated (researchgate.net); many facilities use an ion‑exchange system as part of their reclaiming train.

Periodic base treatment (e.g., NaOH, K₂CO₃) neutralizes heat‑stable acids so organic salts precipitate (as carbonates) and are filtered out. Keeping HSS to minimal concentrations prevents the lab‑observed accelerants — in 5 M MEA at 80°C, oxalate/formate were especially aggressive — and many units lock targets near zero (pubs.acs.org).

What the data say

Across studies and field surveys, acid gases and HSS are the consistent drivers of amine‑unit corrosion (scribd.com; researchgate.net; researchgate.net). Modern inhibitors — from aliphatic amines to polymers — routinely deliver >80% corrosion reduction when properly dosed (pubs.acs.org; researchgate.net), especially when paired with reboiler control below ~140°C and attention to gas ratios (digitalrefining.com) and rigorous HSS management (researchgate.net; pubs.acs.org). That combined discipline is how carbon steel reaches its intended lifetime — and how unplanned downtime and maintenance costs stay off the books.