Description of Damage:

Carbon dioxide (CO2) corrosion is a type of corrosion that can occur in Stainless Steel, Carbon Steel and other materials when they are exposed to a CO2-containing environment. CO2 corrosion can occur in both the presence and absence of oxygen.

In the presence of oxygen, CO2 corrosion can occur through a process known as "uniform corrosion," which is characterized by the uniform corrosion of the surface of the material. This type of corrosion can occur when CO2 reacts with water to form carbonic acid (H2CO3), which can attack the surface of the material.

In the absence of oxygen, CO2 corrosion can occur through a process known as "localized corrosion," which is characterized by the corrosion of specific areas of the material, such as crevices, welds, and under deposits. This type of corrosion can occur when CO2 reacts with water to form a hydrogen carbonate (bicarbonate) solution, which can attack the surface of the material in specific areas.

Affected Materials:

  • Carbon steel and low-alloy steels are affected.
  • Type 300 series austenitic Stainless Steel is highly resistant to CO2 corrosion.
  • Type 410 martensitic Stainless Steel (11.5 % chromium content) is resistant to CO2 corrosion.
  • Increasing the level of chromium in steels offers no major improvement in resistance until a minimum of 12 % Cr is reached.

Critical Factors:

  • Liquid water Content: Corrosion occurs in the liquid water phase, often at locations where CO2 condenses from the vapor phase
  • Partial pressure of CO2: increasing partial pressures of CO2 increases rates of corrosion, because pH is reduced.
  • pH: Lower the pH higher the rate of corrosion.
  • Temperature: Increasing temperatures increase corrosion rate up to the point where CO2 is driven off
  • Oxygen contamination: accelerate corrosion rates. Oxygen should be less than 10 ppb to avoid accelerating corrosion
  • Velocity: and turbulence can cause accelerated, localized corrosion.

Affected Units or Equipment:

  • Boiler Feed Water Unit and Condensate Systems
  • Overhead systems of regenerators in CO2 removal plants
  • Along the bottom surface of a pipe if there is a separate water phase or along the top
  • surface of a pipe if condensation in wet gas systems occurs.
  • Overhead systems of crude towers where stripping steam is commonly used (when dew point is reached)
  • Accelerated in downstream of control valves, and changes in piping direction (e.g. at elbows and tees) or piping diameter (i.e. at reducers) where flow velocity and turbulence is high.
  • Locations where a cooling effect can cause condensation and resultant CO2 (carbonic acid) corrosion:

      • where insulation is damaged
      • where portions of blind flanged nozzles extend beyond insulation and thus cool below the dew point
      • where pipe supports attach to piping

  •  Effluent gas streams off the shift converters in hydrogen plants when the effluent stream drops below the dew point at approximately 300 °F (150 °C).

Inspection:

  • Visual Inspection (VI) , Ultrasonic Testing (UT), Radiographic Testing (RT) and preferably Profile Radiography Testing (PRT) can be used for general loss and local loss in thickness where water wetting is anticipated.
      • The use of remote video probes can be effective for locations with limited or no direct line-of-sight (e.g. in boiler tubes).
  • Corrosion of welds may require Shearwave Ultrasonic Testing (SWUT)/Phased Array Ultrasonic Testing (PAUT) (using angle beam UT technique) or Radiographic Testing (RT).

 Monitoring:

  • Permanently mounted thickness monitoring sensors can be used.
  • Monitor water analyses (pH, Fe, O2, etc.) to determine changes in operating conditions.

Appearance or Morphology of Damage:

  • Carbon steel is affected by localized general thinning or pitting corrosion. It may suffer deep pitting, grooving, or smooth “wash out” in areas of turbulence.
  • Corrosion generally occurs or is worse in areas of turbulence and impingement. 
  • It can be sometimes seen at the root of piping welds.
  • Corrosion may initiate where water first condenses.
  • It can be most severe at water/vapor interfaces.
  • The appearance can differ depending on the unit and equipment in which it occurs (steam and condensate systems vs H2 manufacturing units vs crude tower overheads vs CO2 removal plants vs oilfield production equipment). 
  • Contributing to the differences in appearance are the type of water (BFW or steam condensate vs untreated fresh water vs salt water or brine) and the other species in the water, e.g. oxygen, H2S, and other acids and salts.

  • It may appear as a number of flat-bottomed pits, sometimes called “mesa”-type pitting.

Prevention/Mitigation:

  • In steam condensate systems:
    • Corrosion inhibitors and Vapor phase inhibitors are required to protect against condensing steam.
    • Increasing condensate pH above 6 can reduce corrosion.
    • Corrosion cab be managed by improving the operating conditions or water treatment program.
  • Ensure good condition of insulation and jacketing to prevent undesired cooling and condensation.

  • Internal coatings can be effective where the design and environment permit.

Related Mechanisms:

  1. Boiler water condensate corrosion 
  2. Carbonate cracking

Summary:


Procedure: