Chloride Stress Corrosion Cracking

For Chloride Stress Corrosion Cracking (SCC) to occur, one of the following criteria has to take place:

  • Chloride content
  • Oxygen level
  • pH level
  • Temperature
  • Deterioration of materials’ surface
  • Weld crevice
  • Metals cross-contaminant
  • Cyclic conditions

To minimize Chloride Stress Corrosion Cracking, consider the followings in your design:

  • Keep the system / equipment dry to avoid SCC
  • Keep the Oxygen and pH content at a controlled environment to decrease Chloride SCC
  • Keep the temperature low to decrease Chloride SCC
  • Use coating with Thermal Sprayed Aluminum when piping or vessels are insulated
  • Stress Relieve Heat Treat (partial heat treatment if the equipment or structure is too large to perform at once) to reduce residual stress from welding during fabrication and repair

Sulfide Stress Corrosion Cracking

Following are the parameters affect sulfide stress corrosion cracking:

  • Metallurgy
    • Chemical composition
    • Method of manufacturing
    • Strength
    • Hardness and local variations
    • Amount of cold work and Heat-Treatment
    • Micro-structural uniformity
    • Grain size
    • Cleanliness of the material
  • H2S partial pressure (use equivalent concentration in water phase)
  • Chloride ion concentration (water phase)
  • pH
  • Presence of oxidants such as sulfur
  • Presence of non production fluids
  • Temperature
  • Total tensile stress
  • Exposure time

Sulfide stress corrosion cracking occurs in presence of Hydrogen Sulfide. Gas phase water needs to be there as well even in a trace amount.

Sulfide Stress Corrosion Cracking often happens in the Oil & Gas industry (sour environments) as there are natural gas and crude oil being present.

Changing any of the followings can reduce Sulfide Stress Corrosion Cracking:

  • pH level
  • Concentration of Hydrogen Sulfide
  • Temperature

Sulfide stress corrosion cracking is worst in the temperature range between 60-100°C.

Equipment including nuts and bolts in the H2S environments (i.e. Sour Service, Fuel Gas System) should consider the followings:

  • Using Super Duplex material
  • Using 3rd party verification of metallurgy and mechanical properties
  • PMI (Positive Material Identification) Testing upon arrival at the facilities

In addition, consider the following materials when selecting/designing equipment:

  • S41425: used in slightly sour oil and gas
  • S31254, N08904
  • S31654, S31266, S34565, N08926, N08367
  • N07718, N09925

and few others but each one is dependent upon temperatures and environments when designing.

Refer to NACE MR0175/ISO 15156 for more information.

Type Examples Advantages Disadvantages
Ferritic 410S, 430, 446 Low cost, moderate corrosion resistance & good formability Limited corrosion resistance, formabilty & elevated temperature strength compared to austenitics
Austenitic 304, 316 Widely available, good general corrosion resistance, good cryogenic toughness. Excellent formability & weldability Work hardening can limit formability & machinability. Limited resistance to stress corrosion cracking
Duplex 1.4462 Good stress corrosion cracking resistance, good mechanical strength in annealed condition Application temperature range more restricted than austenitics
Martensitic 420, 431 Hardenable by heat treatment Corrosion resistance compared to austenitics & formability compared to ferritics limited. Weldability is limited.
Precipitation Hardening 17/4PH Hardenable by heat treatment, but with better corrosion resistance than martensitics Limited availability, corrosion resistance, formability & weldability restricted compared to austenitics

If the above conditions are present, it will still take some period of time for the Sulfide Stress Corrosion Cracking to occur. This depends on the following factors:

  • Stress Level – higher the stress, lower the time to failure
  • Hardness of the steel – higher the hardness, lower the time to failure
  • Hydrogen Sulfide concentration – higher the concentration, lower the time to failure
  • pH of the fluid – lower the pH, lower the time to failure.
  • Temperature – at ambient conditions, lower the time to failure, above 150ºF the chances of failure decreases.

Hydrogen Induced Stress Cracking for Duplex Stainless Steel in subsea use

Duplex Stainless Steels (22Cr duplex and 25Cr super duplex) are susceptible to hydrogen induced stress cracking (HISC) under cathodic protection (CP). Industry subsea failures have resulted from HISC under load-control scenarios where local strain levels exceed a critical strain threshold. Load-control situations occur in the absence of restraints on continuous material straining, such as for thermal growth and free spans. Residual stress levels from fabrication and installation, coating system integrity, and defective material microstructures contribute to initiation of HISC.

In order to avoid CP-induced HISC in subsea use of 22Cr duplex and 25Cr super duplex, design conditions should include each of the following mitigators:

  • Avoidance of all possible load-control scenarios on duplex components
  • Use of finite element models that limit local strains to less than 0.50 percent
  • Control of peak loading to less than 80 percent of the nominal material yield strength

Further, coatings should be applied to all subsea duplex materials. The required coating system should be durable, of high dielectric properties, and capable of shielding critical areas of the duplex material from CP. The coating system should consist of a corrosion protection undercoat and a thick film insulation coating. The undercoat should be fusion bonded epoxy for flowlines or a three layer epoxy for fabricated components. The thick film insulation coating should be either syntactic polyurethane foam or other insulating material such as polypropylene.