5.1 Amine Corrosion & Carbon Dioxide (CO2) Sweet Corrosion

Acid Gas Treating and Sweet Corrosion Fundamentals

Acid gas removal and carbon dioxide processing are core operations across petroleum refining, petrochemical synthesis, and natural gas production. In these systems, equipment integrity is governed by the chemical interactions of weak acid gases—principally hydrogen sulfide ($\text{H}_2\text{S}$) and carbon dioxide ($\text{CO}_2$)—with aqueous carrier solvents or condensed moisture films.

This section addresses two primary process-specific degradation mechanisms defined in API RP 571:

1. Amine Corrosion (API RP 571 Section 3.2): Degradation of carbon steel and alloys in alkanolamine treating units used to sweeten hydrocarbon gases and liquids.
2. Carbon Dioxide (CO2) Sweet Corrosion (API RP 571 Section 3.18): Metal loss of carbon and low-alloy steels in production wells, gathering pipelines, and overhead systems caused by dissolved wet $\text{CO}_2$.

Both mechanisms involve weak acid electrochemistry, but their driving forces, morphology, temperature dependencies, and metallurgical solutions exhibit critical distinctions that are heavily emphasized in plant inspection and API-571 certification examinations.

---

Amine Corrosion (API RP 571 Section 3.2)

Description and Mechanism

Amine treating units utilize aqueous solutions of alkanolamines to remove acid gases ($\text{H}_2\text{S}$ and $\text{CO}_2$) from sour hydrocarbon gas and liquid streams via reversible chemical absorption. Common commercial amines include:

• MEA: Monoethanolamine (primary amine)
• DEA: Diethanolamine (secondary amine)
• DGA: Diglycolamine / 2-(2-aminoethoxy)ethanol (primary amine)
• MDEA: Methyldiethanolamine (tertiary amine, selective for $\text{H}_2\text{S}$ in the presence of $\text{CO}_2$)
• Formulated / Hindered Amines: Specialty blended solvents containing kinetic activators (e.g., piperazine) to accelerate $\text{CO}_2$ mass transfer.

Pure, unreacted alkanolamine solutions are non-corrosive to carbon steel across standard operating temperatures. Corrosion in amine treating units is an active electrochemical thinning mechanism caused by:

1. Dissolved Acid Gases: High concentrations of dissolved $\text{CO}_2$ and $\text{H}_2\text{S}$ in the solvent.
2. Amine Degradation Products: High-temperature thermal degradation and oxidative breakdown products, such as bicine ($N,N$-bis(2-hydroxyethyl)glycine), hydroxyethyl ethylenediamine (HEED), and oxazolidones.
3. Heat-Stable Amine Salts (HSAS): Non-regenerable salts formed when amines react with strong organic or inorganic acid anions (formate, acetate, glycolate, oxalate, thiosulfate, thiocyanate, and chloride).
4. Thermal Desorption Stresses: Evolution of dissolved acid gas bubbles at hot metal surfaces during reboiling and regeneration.

Lean vs. Rich Amine Chemistry

The treating circuit operates as a closed loop consisting of an absorber (contactor) and a stripper (regenerator):

• Lean Amine: Regenerated amine returning from the stripper bottom to the absorber. Acid gases have been stripped out. Lean amine is generally mildly corrosive to non-corrosive to carbon steel unless contaminated with excessive HSAS, oxygen, or thermal degradation products.
• Rich Amine: Loaded solvent leaving the bottom of the absorber containing high concentrations of absorbed $\text{H}_2\text{S}$ and $\text{CO}_2$. Rich amine is highly corrosive to carbon steel, particularly when heated above 220 °F (104 °C) prior to entering the regenerator.

In rich systems removing primarily $\text{H}_2\text{S}$, a semi-protective black iron sulfide ($\text{FeS}$, mackinawite) film forms on carbon steel surfaces:

$\text{Fe} + \text{H}_2\text{S} \xrightarrow{\text{Amine}} \text{FeS} + \text{H}_2$

However, in $\text{CO}_2$-rich amine systems (or systems with a very high $\text{CO}_2 / \text{H}_2\text{S}$ ratio), iron carbonate ($\text{FeCO}_3$) cannot form a stable, adherent barrier at high velocities, and the protective $\text{FeS}$ film is either absent or continually destabilized. When the rich solvent is heated in lean/rich exchangers and regenerator reboilers, dissolved $\text{CO}_2$ flashes out of solution, generating intense local turbulence, two-phase acid gas impingement, and severe carbonic acid attack.

Critical Factors Influencing Amine Corrosion

1. Amine Solvent Type and Corrosivity Ranking:

   • MEA: The most corrosive alkanolamine. MEA binds strongly to acid gases, requiring high regeneration energy and elevated reboiler temperatures, while forming corrosive degradation products (HEED). Operating concentrations are typically limited to 15 to 20 wt%.
   • DGA: Moderately corrosive. Operated at higher concentrations (50 to 60 wt%), requiring careful monitoring of degradation products (BHT).
   • DEA: Moderately to mildly corrosive. Widely used at 25 to 35 wt% concentration. Exhibits lower degradation rates and lower reboiler vapor flashing aggressiveness than MEA.
   • MDEA and Formulated Amines: Least corrosive to carbon steel under clean conditions. MDEA binds $\text{CO}_2$ weakly as a bicarbonate salt rather than a carbamate, requiring lower regeneration heat and operating at 40 to 50 wt% with minimal thermal degradation.

2. Acid Gas Loading Limits:

   • Acid gas loading is expressed as moles of total acid gas per mole of active amine (mol/mol). Exceeding critical rich loading thresholds destroys passivity on carbon steel:
     • MEA: Rich loading must not exceed 0.30 to 0.35 mol/mol on carbon steel.
     • DEA: Rich loading is typically limited to 0.40 to 0.45 mol/mol.
     • MDEA: Rich loading can operate up to 0.45 to 0.55 mol/mol (and even higher in proprietary formulations with specialized corrosion inhibitors).

3. Operating Temperature Thresholds:

   • Corrosion rates increase exponentially with temperature:
     • Below 140 °F (60 °C) (absorber conditions), corrosion rates on carbon steel are negligible (<2 mils/year / 0.05 mm/yr).
     • Above 220 °F (104 °C) (rich amine flash drums, lean/rich exchanger hot passes, stripper feed line), corrosion accelerates dramatically.
     • In reboilers and regenerator bottoms (240 °F to 265 °F / 116 °C to 129 °C), carbon steel suffers severe attack unless upgraded or inhibited. Skin temperatures on reboiler tubes must be strictly limited by keeping steam supply temperatures below 285 °F to 300 °F (140 °C to 149 °C) to prevent local boiling film dry-out and thermal solvent decomposition.

4. Fluid Velocity and Mechanical Shear:

   • Carbon steel depends on a fragile, loosely adherent surface film. High fluid shear or local turbulence strips this film, causing rapid flow-induced corrosion:
     • Carbon Steel Velocity Limit in Rich Amine: Strictly restricted to 3.0 to 6.0 ft/s (0.9 to 1.8 m/s).
     • Carbon Steel Velocity in Lean Amine: RP 571 cites about 20 ft/s (6 m/s) as a typical upper limit.
     • 300-Series Stainless Steel: Tolerates velocities in excess of 20 to 30 ft/s (6.1 to 9.1 m/s) without protective film loss.

5. Heat-Stable Amine Salts (HSAS) and Degradation Products:

   • Oxygen ingress (from storage tank breathing, pump seal leaks, or aerated feedstocks) oxidizes amines to organic acids (formic, acetic, glycolic, oxalic acids). These react with free amine to form HSAS.
   • HSAS Operating Threshold: Total HSAS should be maintained below 2.0 wt% to 5.0 wt% (or <10% of total solvent concentration). HSAS lowers system pH, dramatically increases solution electrical conductivity, and complexes protective iron ions.
   • Bicine: A cyclic amino acid degradation product that acts as a powerful iron chelator. Bicine actively extracts iron from steel surfaces even in alkaline solutions, causing severe uniform thinning and pitting.

Affected Equipment and Units

• Rich Amine Piping: Downstream of lean/rich exchangers, control valves, orifice plates, and piping elbows.
• Lean/Rich Heat Exchangers: Rich-side tube bundles, shell nozzles, and channel heads.
• Amine Regenerators (Strippers): Column shell in the lower stripping section, chimney trays, packing support grids, and tray valves/caps.
• Reboilers: Bundle tubes (steam or hot oil heated), shell side vapor spaces, and reboiler vapor return lines where flashing acid gas disengages.
• Regenerator Overhead Condensers and Reflux Accumulators: Condensing water containing residual acid gas and vaporized amine creates an acidic condensate environment.

Morphology of Amine Corrosion

• Uniform Thinning: Occurs on carbon steel in hot rich amine service when velocity is moderate.
• Localized Erosion-Corrosion and Grooving: Smooth, rounded depressions, horseshoe-shaped pits, or bright metal washouts immediately downstream of flow disruptions, pump impellers, thermowell nozzles, and throttling valves.
• Crucial Distinction from Amine SCC (API RP 571 Section 3.3):
  • Amine Corrosion (Section 3.2) is an active wall-loss mechanism (thinning/grooving) driven by acid gases, temperature, HSAS, and velocity.
  • Amine Stress Corrosion Cracking (Section 3.3) is an environmental cracking mechanism affecting non-stress-relieved carbon steel welds in both lean and rich amine service, driven by tensile stress and alkaline amine chemistry without requiring wall loss.

Prevention and Mitigation Strategies

1. Metallurgical Upgrades:
   • 300-Series Austenitic Stainless Steel (Type 304L, 316L, 316Ti): Highly resistant to amine corrosion and routinely used where carbon steel corrodes (reboilers, regenerators, hot lean/rich exchanger tubes, and hot rich amine piping). Standard industry practice specifies 304L/316L for reboiler tube bundles, regenerator trays/packing, clad column shells in the bottom third, and hot rich amine transfer lines.
   • Nickel Alloys: Solid or clad Alloy 625 or Alloy 825 utilized in severe high-temperature reboiler shells and aggressive reclaiming equipment.
2. Filtration and Solvent Reclaiming:
   • Mechanical Filtration: 10-micron cartridge filters on lean or rich streams removing particulate iron sulfides.
   • Activated Carbon Beds: Treating a 10% to 20% slipstream to adsorb heavy hydrocarbons, surfactants, and organic degradation products.
   • Thermal Reclaimers / Slipstream Ion Exchange: Vacuum distillation thermal reclaimers (for MEA/DGA) or ion exchange resin systems and electrodialysis units (for MDEA/DEA) to continuously strip out Heat-Stable Amine Salts and maintain HSAS < 2.0 wt%.
3. Oxygen Exclusion:
   • Installing automated nitrogen blanketing on amine storage tanks, surge vessels, and sump systems to eliminate oxidative degradation and bicine formation.
4. Process and Velocity Controls:
   • Sizing piping to maintain rich amine velocities below 3.0 to 6.0 ft/s on carbon steel; using long-radius (3D or 5D) elbows and sweep tees.
   • Limiting reboiler steam heating bundle surface temperatures below 285 °F to 300 °F to avoid local solvent skin boiling.
   • Continuous injection of specialized proprietary filming amine inhibitors or passivating chemistry.

Inspection and NDE Techniques

• Ultrasonic Thickness Testing (UT): Automated scanning UT (AUT) and manual grid UT on hot rich amine piping, elbow extrados, and vessel shells.
• Profile Radiography (PRT): Primary non-invasive method for detecting localized internal wall thinning, flow grooving, and step-changes at piping nozzles and small-bore branches without insulation removal.
• Internal Visual Testing (VT): Turnaround inspection of regenerator column internals, demister pads, reboiler shell baffles, and tube bundles for washout grooves and scale detachment.
• Laboratory Solvent Analysis: Regular tracking of rich/lean acid gas loading, amine concentration, dissolved iron content (spikes indicate active corrosion), HSAS concentration, and bicine levels.

---

Carbon Dioxide (CO2) Sweet Corrosion (API RP 571 Section 3.18)

Description and Mechanism

Carbon dioxide ($\text{CO}_2$) corrosion—historically termed sweet corrosion because it occurs in the absence of hydrogen sulfide ($\text{H}_2\text{S}$)—is an aggressive degradation mechanism affecting carbon steel and low-alloy steels in oil and gas production wells, gathering flowlines, multiphase pipelines, offshore risers, gas treating facilities, and boiler condensate return lines.

Completely dry gaseous or supercritical $\text{CO}_2$ is non-corrosive to carbon steel. However, when $\text{CO}_2$ dissolves in free water (formation water, condensed steam, or condensation in gas pipelines), it hydrates to form aqueous carbonic acid ($\text{H}_2\text{CO}_3$):

$\text{CO}_2\text{ (g)} + \text{H}_2\text{O} \rightleftharpoons \text{CO}_2\text{ (aq)}$ $\text{CO}_2\text{ (aq)} + \text{H}_2\text{O} \rightleftharpoons \text{H}_2\text{CO}_3$ $\text{H}_2\text{CO}_3 \rightleftharpoons \text{H}^+ + \text{HCO}_3^- \rightleftharpoons 2\text{H}^+ + \text{CO}_3^{2-}$

Why Carbonic Acid Corrodes Faster Than Strong Mineral Acids

A critical exam concept in API-571 is the electrochemical behavior of carbonic acid compared to strong mineral acids (such as $\text{HCl}$ or $\text{H}_2\text{SO}_4$). At an identical pH (for example, pH 4.0), carbonic acid corrodes carbon steel at a rate 5 to 10 times higher than hydrochloric acid.

This occurs because $\text{H}_2\text{CO}_3$ is a weak, partially dissociated acid that provides a massive chemical buffer reservoir. In addition to the reduction of dissociated hydrogen ions ($\text{H}^+$), undissociated carbonic acid molecules adsorb directly onto the metallic iron cathode and undergo direct electrochemical reduction:

$\text{Anodic Reaction: } \text{Fe} \rightarrow \text{Fe}^{2+} + 2e^{-}$ $\text{Cathodic Reduction of Hydrogen Ions: } 2\text{H}^+ + 2e^{-} \rightarrow \text{H}_2$ $\text{Direct Cathodic Reduction of Carbonic Acid: } 2\text{H}_2\text{CO}_3 + 2e^{-} \rightarrow \text{H}_2 + 2\text{HCO}_3^-$ $\text{Overall Corrosion Reaction: } \text{Fe} + \text{CO}_2 + \text{H}_2\text{O} \rightarrow \text{FeCO}_3\text{ (siderite)} + \text{H}_2$

Because the direct reduction of $\text{H}_2\text{CO}_3$ bypasses the mass-transfer diffusion limit of hydrogen ions, the corrosion rate remains exceptionally high even as pH climbs toward neutral.

Siderite (FeCO3) Scale Kinetics and Scaling Regimes

The corrosion rate of carbon steel in sweet systems is entirely dictated by whether a stable, crystalline iron carbonate ($\text{FeCO}_3$, siderite) protective scale can nucleate and adhere to the steel surface:

1. Non-Scaling Regime (Low Temperatures < 140 °F / 60 °C):

   • $\text{FeCO}_3$ exhibits retrograde solubility (it is more soluble at lower temperatures and less soluble at higher temperatures).
   • Below 140 °F (60 °C), the solubility of $\text{FeCO}_3$ is high. The solution cannot easily reach supersaturation at the pipe wall. No protective scale forms. The steel experiences continuous, uniform, active thinning governed by classical de Waard-Milliams kinetics.

2. Scaling Regime (Elevated Temperatures > 140 °F to 160 °F / 60 °C to 71 °C):

   • Above 140 °F to 160 °F, $\text{FeCO}_3$ solubility drops sharply. If local water chemistry achieves supersaturation ($[\text{Fe}^{2+}][\text{CO}_3^{2-}] > K_{sp}$), dense, protective, crystalline siderite precipitates onto the steel surface.
   • Under stagnant or low-velocity laminar flow, this adherent siderite scale acts as a physical barrier to mass transport, driving baseline corrosion rates down from hundreds of mils per year to <2 to 5 mils/year.

3. Localized Scale Breakdown and Mesa Attack:

   • Siderite scale is mechanically brittle and poorly adherent under high fluid shear. When fluid velocity, turbulence, or multiphase slug flow disrupts the scale, bare steel is exposed.
   • An intense galvanic macro-cell is established between the small bare metal crater (anode) and the large surrounding intact siderite scale (cathode). The bare steel dissolves at catastrophic rates (often >250 to 500 mils/year / 6.4 to 12.7 mm/yr), carving distinctive flat-bottomed, sharp-sided trenches known as mesa attack.

Fluid Flow (Turbulent Multiphase Shear Strip)
  ═══════════════════════════════════════════════════════════════
         Intact FeCO3 Scale             Intact FeCO3 Scale
         (Large Cathode)                (Large Cathode)
        ┌─────────────────┐            ┌─────────────────┐
        │                 │            │                 │
  ──────┘                 └────────────┘                 └──────
  Steel Base Metal        │  Mesa Pit  │
                          │ (Small     │
                          │  Anode)    │
                          └────────────┘

Critical Environmental Factors

1. CO2 Partial Pressure ($p_{\text{CO}_2}$):

   • Calculated using Dalton's Law: $p_{\text{CO}_2} = y_{\text{CO}_2} \times P_{\text{total}}$ (where $y_{\text{CO}_2}$ is mole fraction and $P_{\text{total}}$ is total system pressure).
   • Industry rule-of-thumb guidelines classify sweet corrosivity:
     • $p_{\text{CO}_2} < 3\text{ psia (0.02 MPa)}$: Generally non-corrosive; corrosion mitigation is rarely required for carbon steel.
     • $p_{\text{CO}_2} = 3\text{ to }30\text{ psia (0.02 to 0.2 MPa)}$: Moderately corrosive; corrosion can occur depending on temperature and water cut; monitoring or inhibition recommended.
     • $p_{\text{CO}_2} > 30\text{ psia (0.2 MPa)}$: Severe sweet corrosion anticipated; continuous chemical inhibition or corrosion-resistant alloy (CRA) metallurgy mandatory.

2. Water Wetting and Water Cut:

   • Sweet corrosion cannot occur without liquid water directly contacting the metallic pipe wall.
   • In oil pipelines, if water cut is low (<20% to 30%) and fluid velocity is high, water is completely entrained as an emulsion within the continuous oil phase, preventing pipe wall contact (water wetting).
   • At higher water cuts, low velocities, or stratified flow, water separates out along the bottom of the line (water dropout), causing severe bottom-of-line sweet corrosion.
   • In gas systems, top-of-line corrosion (TLC) occurs when hot wet gas cools, condensing distilled water droplets on the uninsulated upper 12 o'clock pipe roof where continuous liquid-phase inhibitors cannot reach.

3. Presence of Trace Hydrogen Sulfide ($\text{H}_2\text{S}$):

   • Even minute concentrations of $\text{H}_2\text{S}$ (as low as 10 to 50 ppm in gas) dramatically alter sweet corrosion. $\text{H}_2\text{S}$ preferentially reacts with iron to precipitate insoluble iron sulfide ($\text{FeS}$), which can suppress $\text{FeCO}_3$ formation and transition the system into sour corrosion or wet $\text{H}_2\text{S}$ cracking regimes.

4. Flow Velocity and Turbulence:

   • High velocity prevents scale precipitation, strips protective inhibitors, and scours siderite films, triggering mesa attack.

Morphology of CO2 Corrosion

• Uniform Metal Loss: Found under low-temperature, non-scaling conditions with moderate turbulence.
• Mesa Attack: The classic, unmistakable morphology of sweet corrosion. Consists of broad, flat-bottomed, steep-walled, scalloped depressions or flat-topped plateaus resembling mesa geological formations.
• Pitting and Grooving: Under-deposit pitting beneath loose sand or corrosion debris, and continuous longitudinal bottom-of-line grooving in multiphase pipelines.

Prevention and Mitigation Strategies

1. Metallurgical Upgrades:
   • 13Cr Martensitic Stainless Steels (e.g., AISI 420 / UNS S42000, Modified 13Cr): Standard industry metallurgy for downhole tubing, wellhead valves, and Christmas trees in sweet production. Forms a passive chromium-rich film that is highly resistant to carbonic acid attack within the temperature and chloride limits set by the operator's materials guidance. API RP 571 notes that increasing chromium gives little benefit against CO2 corrosion until at least about 12% Cr is reached, while 300 series SS are highly resistant.
   • 22Cr Duplex Stainless Steel (UNS S31803 / S32205): Specified for subsea flowlines, manifold piping, and topsides processing when both high $\text{CO}_2$ and high formation chlorides are present.
   • 316L Austenitic Stainless Steel: Utilized for gas plant vessels, overhead condenser tubes, and clad piping.
2. Chemical Corrosion Inhibition:
   • Continuous injection of surface-active filming amine or imidazoline-based corrosion inhibitors. Inhibitor molecules form an adsorbed hydrophobic hydrocarbon barrier layer on the steel surface.
   • Batch inhibition scraping (slugging) using pipeline inspection gauges (pigs) in multiphase pipelines.
3. pH Stabilization:
   • In wet gas pipelines, injecting monoethylene glycol (MEG) or triethylene glycol (TEG) for hydrate control combined with pH-stabilizing bases (MDEA, $\text{NaOH}$, or $\text{NaHCO}_3$) to elevate aqueous pH above 6.0–6.5, forcing iron carbonate supersaturation.
4. Hydraulic and Pipeline Design:
   • Running routine maintenance cleaning pigs to remove stagnant water pockets and unadherent solids.
   • Insulating pipelines to prevent Top-of-Line condensation.