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November 17 - November 28, 2014

How do you gauge the remaining service life of an aging FBE system on a buried transmission pipeline?

Selected Answers

From Lydia Frenzel of Advisory Council on November 25, 2014:
I just got back from a Crude Pipeline Asset Integrity Congress. The pipeline is buried. You can't get to the coating without digging up the pipe. So the industry relies on smart pigs, looking for corrosion problems, and doesn't have a good handle for external coating issues which range from tree root damage, to pinholes, to cathodic disbondment, to resting on rocks that cause damage. I was showing in-the ditch (in situ) examination where the pipeline is uncovered. When the old coating was removed, some of the pipe was still in very good condition; some had extensive pitting and active anodic cells. However, the pipeline industry in the US just opens small bell holes and examines the pipeline, let's say, 100 feet at a time. They almost never uncover a buried pipeline, even if aged. I don't have a good answer because I didn't hear anyone talk about a smart pipe-pig that could measure discontinuities or pinholes or blisters in the external or internal coating. This question is about remaining LIFE, so one would think that a comparison was in order. This question was discussed: when to start a base-line study for the pipeline. Answer: the first month as it is being put down. Of course, ac and dc corrosion is playing a part under the coating.They had a lot of data collection; none as far as I could tell related to the coatings.

From Barry Turner of Axson Coatings on November 25, 2014:
It is difficult to be precise when answering this question. FBE-coated pipelines have been in service for many years in all parts of the world and are operating at different temperatures, so there is a good track record on which to base a general assumption. Being more scientific about it, one of the first  signs of degradation is visual. FBE generally fails by blistering due to water penetration or thermal degradation, as evidenced by visible discoloration or even charring because the operating temperature was high (depending on cured Tg) and oxygen content in the soil.

Older FBE-coated pipelines may suffer problems, particularly at girth welds, due to the older coating technologies used at the time. It may be that tests such as cross cut adhesion or impact will show some deviation from the original specification also. In the end, however, estimating remaining lifetime is a very difficult question that is probably left to experience and reference to similar pipelines already in service.

From Warren Brand of Chicago Corrosion Group on November 24, 2014:
My understanding of fusion bonded epoxy is, that, well, it is an epoxy. Due to the fact that it is buried, it is not exposed to one of epoxies' most nefarious enemies, UV. If we were hired to run this problem, we would look at the original specifications of the material and conduct various tests to determine how closely the old material compared to the original specifications. We would compare hardness, adhesion, and likely do some other tests as well, such as a solvent wipe, although, from doing this type of work for a really, really long time, the appearance of the FBE would likely provide a very good idea of its condition. If it looks good, that's a very good indication that there has been no degradation of the material. I've heard that epoxies, over time, tend to embrittle. I'm not sure how, and if, this applies to FBEs.

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Tagged categories: Asia Pacific; Condition assessment; EMEA (Europe, Middle East and Africa); Fusion bonded epoxy; Latin America; North America; Pipeline; Quality Control

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