Derating MAOP of a corroded subsea pipeline or offshore platform pipes

[NATIVES]

Can anyone please state your experience to derate MAOP of a corroded pipeline using ASME 31G? Is the result obtained by using B31G reliable? Any good or bad experience? What is the difference bwteen B31G, B31G modified, and RSTRNG method? Any advantage o using one method over the other one? How prevalent is it offshore pipeline system, specially Gulf of Mexico Area? Can anyone point me towards right direction to get more info. Thanks.

 

[brimmer]

Your question requires too much info to answer all in one, but here is some basic info, very simplified explanation.

B31G is the most conservative, assumes a rectangular flaw (max depth and length)
Modified B31G is less conservative and more accurate for predicting burst pressure than B31G, assumes a modified shape at the ends of the feature
RStreng is the least conservative and most accurate of the three for predicting burst pressure, and takes into account the actual direct shape of the feature (you need actual measurements of the feature at some interval rather than just the max depth and length like to other two methods)

The technical differences in the equations describing shape and stresses taken into account I'll let you read about. There has been validation testing of each, RStreng is the most accurate of these three for a "normal" corrosion feature. However, all three methods have been shown to be conservative (generally speaking), which isn't a bad thing, as you would want some conservatism built into the calculations. In some cases the shape of the corrosion will help determine which method you might use, as for example very ling corrosion can cause issues for one of the methods.

If I was using any of the 3 methods for a de-rate, I would choose RStreng, as it gives the closest results to actual burst pressure, and takes into account actual shapes and depths of the feature, rather than just max depth and length. How prevalent in GOM? Don't know, but these are the most common methods in North America to assess corrosion, every pipeline operator I've encountered uses them.

As far as de-rating a pipeline due to features that might be below or near the MAOP, your company hopefully has an overall strategy for this. I will take a temporary de-rate before I can repair a defect, but this would not be an acceptable long term solution (unless the pipeline is very very near end of life), it is a strategy used for safety margin until repairs can be made. Remember that corrosion tends to continue to grow, so if you de-rate a line based on a burst pressure calculated today, the feature usually continues to grow and you would have to continue de-rating your line based on some growth rate and re-calculation of burst pressure, with some sort of safety margin added.

There is lots of info online, attached is one example. There is lots of info and differences in the public domain.

 

[NATIVES]

Thanks for the response!