Amine Corrosion in Carbon Steel

• Amine corrosion primarily affects carbon steel in amine treating processes.
• The corrosion is caused by dissolved acid gases, heat stable amine salts (HSAS), amine degradation products, and other contaminants, not the amine itself.
• Stress Corrosion Cracking (SCC) of carbon steel in amine services is covered in section 3.3.

Affected Materials

• Carbon steel is the primary material affected by amine corrosion.
• 300 series stainless steel and other stainless steel grades exhibit greater resistance to amine corrosion.

Critical Factors

• Design and operating practices, amine type, contaminants, temperature, and velocity influence corrosion.
• Proper design and operation are critical; most problems are linked to faulty design, poor operating practices, or solution contamination.
• Alkanolamine systems' aggressiveness from most to least: MEA, DGA, DIPA, DEA, and MDEA.
• Lean amine solutions are generally not corrosive due to low conductivity and a high pH.
• Heat stable salts above 2 % can significantly increase corrosion in hot lean amine.
• Oxygen in-leakage leads to high corrosion rates and contributes to heat stable salt formation.
• Overstripped lean amine solutions can be corrosive without adequate H2S to maintain the protective iron sulfide film.
• Temperatures above 220 °F (105 °C) can cause acid gas flashing and severe localized corrosion.
• High velocities and turbulence cause localized thickness losses; velocities are generally limited to 3-6 fps for rich amine and about 20 fps for lean amine.

Affected Units or Equipment

• Amine units remove H2S, CO2, and mercaptans from process streams in crude, coker, FCC, hydrogen-reforming, hydroprocessing, and tail gas units.
• The regenerator reboiler and its lines, along with the regenerator itself, are high-risk corrosion areas due to temperature and turbulence.
• Excessive regeneration in the reboiler (>5 %) can cause acid gas corrosion in the reboiler, vapor return line, and bottom of the regenerator.
• Ammonia, H2S, and HCN accelerate corrosion in the regenerator overhead condenser, outlet piping, reflux piping, valves, and pumps.
• Other problem areas: rich amine side of lean/rich exchangers, hot lean/rich amine piping, stripper overhead condenser piping, amine solution pumps, and reclaimers.
• In amine absorber systems, corrosion is likely at amine or acid gas impingement points and downstream of pressure letdown valves.

Appearance or Morphology of Damage

• Carbon and low-alloy steels mainly experience uniform thinning in localized areas or localized under-deposit attack.
• Low process stream velocity leads to more uniform, widespread thinning, while high velocity causes localized metal loss.
• Welds can be preferentially attacked.

Prevention/Mitigation

• Proper operation of the amine system, with focus on acid gas loading levels, is the most effective control.
• Process temperature should stay within limits to avoid corrosive amine degradation products.
• Control reboiler rate and temperature to maintain proper regenerator temperatures.
• Prevent heat stable salts from building up to unacceptable levels.
• The system design should control local pressure drop to minimize flashing; upgrade to corrosion-resistant alloys where flashing is unavoidable.
• Prevent air ingress into the system to avoid corrosive heat stable salt formation; use oxygen-free inert gas blanketing for storage tanks and surge vessels.
• Remove solids and hydrocarbons from the amine solution through filtration and process control.
• Corrosion inhibitors may be needed.

Inspection and Monitoring

• Visual inspection (VT) of internal surfaces is effective in identifying localized corrosion, especially at flow impingement areas, turbulent flow areas, liquid/vapor interfaces, and welds/HAZs; use a pit gauge with visual examination to measure metal loss.
• External ultrasonic testing (UT) maps component thickness to find thin regions.
• Profile radiographic testing (RT) identifies localized attack, especially at welds/HAZs and turbulent locations.
• UT with VT, laser scanning, structured white light imaging, and/or pit gauges determines the extent of metal loss.
• Permanently mounted thickness monitoring sensors can be used.
• Monitor amine degradation product levels; increased iron content indicates increased degradation products.
• Fouling of exchangers and filters can indicate corrosion problems.