Page 273 - Challenges in Corrosion Costs Causes Consequences and Control(2015)

CORROSION OF UNDERGROUND GAS AND LIQUID TRANSMISSION PIPELINES 251

of corrosion defects is high or the potential exists for continued increase in dig/repair
frequency, the affected pipe section may require repair or replacement.

4.11.6 Aging Coating

Maintaining the required level of CP is of concern because of the cost. An increased
number of coating defects requires an increased amount of CP current. The increase in
CP current is accomplished by increasing the current output of the impressed-current
rectifiers, installing impressed-current rectifiers at more locations along the pipeline
or installing additional sacrificial anodes. Coating defects can be identified by con-
ventional potential surveys or by specific coating defect surveys and verified by direct
visual inspection also known as a dig program. Under certain conditions, coatings fail
in a manner that makes assessment of the corrosion condition of the pipe through con-
ventional surveying methods difficult. Aging coating and the associated increase in
coating defects can make the continuous need for CP upgrading uneconomical.

4.11.7 Stress Corrosion Cracking (SCC)
This form is defined as the brittle fracture of a normally ductile metal by the conjoint
action of a specific corrosive environment and a tensile stress. On underground
pipelines, SCC affects only the external surface of the pipe that is exposed to
soil/ground water at locations where the coating is disbonded. The primary compo-
nent of the tensile stress on an underground pipeline is in the hoop direction and
results from the operating pressure. Residual stresses from fabrication, installation,
and damage in service contribute to the total stress. Individual cracks initiate in the
longitudinal direction on the outside surface of the pipe. The cracks typically occur
in colonies that may contain hundreds or thousands of individual cracks. Over a
period of time, the cracks in the colonies interlink and may cause leaks or rupture
once a critical-size flaw is achieved. Figure 4.10 shows an SCC hydrostatic test
failure on a high-pressure gas pipeline.
The two basic types of SCC identified on underground pipelines are: high pH
cracking (pH of 9–10), which propagates intergranularly, and “near-neutral pH”
cracking, which propagates intergranularly. Near-neutral pH SCC (<pH 8) is most
commonly found on pipelines with polyethylene tape coatings that shield the CP
current. The environment that develops under the tape coating and causes this
form of cracking is dilute carbonic acid. Carbon dioxide from the decay of organic
material in the soil dissolves in the electrolyte beneath the disbonded coating to form
the carbonic acid solution. High pH SCC is most commonly found on pipelines with
asphalt or coal tar coatings. The high pH environment is a carbonate–bicarbonate
solution that develops because of the presence of carbon dioxide in the groundwater
and the CP system.
The presence of extensive SCC may necessitate replacement or rehabilitation
of a pipeline. Because SCC is dependent on unique environmental conditions, a
large-scale recoating program may protect against these environmental conditions