Over 98% of pipelines are buried. No matter how well these pipelines are designed, constructed and protected, once in place they are subjected to environmental abuse, external damage, coating disbondments, inherent mill defects, soil movements or instability and third party damage. In pipelines this occurs due to a combination of appropriate environment, stresses (absolute hoop and/or tensile, fluctuating stress) and material (steel type, amount of inclusions, surface roughness.)

Environment is a critical causal factor in SCC. High-pH SCC failures of underground pipelines have occurred in a wide variety of soils, covering a range in color, texture, and pH. No single characteristic has been found to be common to all of the soil samples. Similarly, the compositions of the water extracts from the soils have not shown any more consistency than the physical descriptions of the soils. On several occasions, small quantities of electrolytes have been obtained from beneath disbonded coatings near locations where stress corrosion cracks were detected. The principle components of the electrolytes were carbonate and bicarbonate ions and it is now recognized that a concentrated carbonate-bicarbonate environment is responsible for this form of cracking. Much of this early research focused on the anions present in the soils and electrolytes. In addition to an appropriate coating failure, the local soil, temperature, water availability, and bacterial activity have a critical impact on SCC susceptibility. Coating types such as coal tar, asphalt and polyethylene tapes have demonstrated susceptibility to SCC. Fusion bonded epoxy hasn't shown susceptibility to SCC.

Loading is the next most important parameter on SCC. Cyclic loading is considered a very important factor; or the crack tip strain rate defines the extent of corrosion or hydrogen ingress into the material. There has been no systematic effect of yield strength on SCC susceptibility. Certain types of ERW pipe have been found to be systematically susceptible to SCC. Non-metallic inclusions have also had limited correlation to SCC initiation.

SCC propensity

There are two types of SCC normally found on pipelines, and known as high pH (9 to 13) and near-neutral pH SCC (5 to 7). The high pH SCC caused numerous failures in USA in the early 1960's and 1970's, whereas near-neutral pH SCC failures were recorded in Canada during the mid 1980's to early 1990's. The SCC failures have continued throughout the world including Australia, Russia, Saudi Arabia, South America and other parts of the world.

High pH SCC
This is a classical SCC, which was originally noted in gas transmission pipelines. It is normally found within 20 kilometers downstream of the compressor station. High pH SCC normally occurs in a relatively narrow cathodic potential range (-600 to -750 mV Cu/CuSO4) in the presence of a carbonate/bicarbonate environment in a pH window from 9 to 13. Temperatures greater than 40 degrees C are necessary for high pH SCC susceptibility; growth rates decrease exponentially with temperature.

Intergranular cracking mode generally represents high pH SCC. A thin oxide layer is formed in the concentrated carbonate-bicarbonate environment, which around the crack surfaces provides protection. However, due to changes in loading or cyclic loading there is crack tip strain resulting in breakage of oxide film. This results in crack extension due to corrosion. Because of such a stringent environmental requirement for SCC initiation, this is not as prevalent as the near-neutral pH SCC. This type of SCC has been primarily noted in gas transmission lines (temperature.)

High pH SCC Integrity Management Strategy
Evaluate and establish extent of SCC susceptibility.
Ensure that the material, coating and other operational conditions are conducive for SCC.
Utilize over the ditch coatings survey to identify locations of holiday & match them with high stress levels (60% specified minimum yield strength (SMYS))
Additionally match it with high temperature locations.
Finally if there is an inspection run match the corrosion locations with coating failure if these exist; especially with minor corrosion.
Excavate to identify susceptibility (should also be conducted as part of due diligence during corrosion management.)

If SCC susceptible
Quantify life cycle of the pipeline; conduct fracture mechanics calculations to estimate where in the system an SCC rupture is likely using excavation results.
Utilizing this as a basis, a next step involves further evaluation of the degree of SCC. (In-line inspection) or hydrostatic test may be warranted.
If inspection tools don't exist (diameter or piggability) an appropriately defined hydrostatic test program may be effective.
If inspection tool options are viable; circumferential MFL tools may be a screening option, depending on crack opening; or ultrasonic tools may be a more permanent option as a true alternative to hydrostatic testing.
Longer term mitigation will have to include temperature reduction (if possible.)

If SCC not found but still parameters indicate susceptibility.
Continue monitoring for SCC while managing integrity for other issues such as corrosion.

Near-neutral pH SCC
This type of transgranular cracking mode of SCC was initially noted in Canada, and has been observed by operators in the US. The environment primarily responsible is diluted groundwater containing dissolved CO2. The CO2 originates (like in high pH) from the decay of organic matter. Cracking is further exacerbated by the presence of sulfate reducing bacteria. This occurs primarily due to disbonded coatings, which shields the cathodic current that could reach the pipe surface. There is a free corrosion condition below the coating that results in an environment with a pH around 5 to 7.

A cyclical load is critical for crack initiation and growth. There are field data that indicate that with a decreasing stress ratio there is an increased propensity for cracking. Hydrogen is considered a key player in this SCC mechanism, where it reduces the cohesive strength at the crack tip. Attempts have been made to relate soil and drainage type with SCC susceptibility, however limited correlation's have been noted.

There has been no correlation to a clear threshold for SCC initiation or growth. The morphology of the cracks are wide with evidence of substantial corrosion on the crack side wall.

Near-neutral pH SCC management
Evaluate and establish extent of SCC susceptibility – ensure the material and coating parameters indicate susceptibility to SCC.
Utilize corrosion inspection survey to identify areas of corrosion linearity or small pitting corrosion locations to identify sites for SCC susceptibility.
Identify locations of high cyclical pressure combined with a high operating pressure.
Excavate at many of these locations to develop extent of SCC on the pipeline system.
Additional parameters such as soil and drainage can be considered for SCC susceptibility, but should be used with caution. For example, both very poor and well drained soils have shown susceptibility to SCC.

If SCC susceptible, and extent is not low – quantify life of the pipeline, utilizing fracture mechanics models and excavation data.
Utilizing this as a basis, identify the time period available for mitigating the problem. If the time period is small, then hydrostatic testing may represent the best short term approach to this problem.
If the time period available is high or there is no immediate danger (< 1year) to the pipeline, then options such as inline inspection can be considered. The circumferential MFL is a good screening tool for SCC, but the ultrasonic shear wave tools are highly reliable for SCC. A regular inspection and rehabilitation may prove to be a long term solution to managing SCC. If no inspection option is available, then the regular hydrostatic testing is the only option to mitigate failure from SCC.

If SCC susceptible, but the extent of SCC is very low.
Continue to monitor and validate the conclusion as part of an overall integrity management program.