CVN Test Temperature for API 5L B31.4 pipe 1

[IFRs]

For API 5L pipe X42 to X60 used for both an above and below ground B31.4 pipeline facility being purchased to PSL-2 what should the CVN test temperature be specified as? I am not an expert in such things but had expected the design temperature of minus 20 F but find plus 32 F on the drawings. I need help understanding the logic before I parade my ignorance to the EOR. Many thanks in advance...

 

[SJones]

That's a bit rich after 9 items of supposition earlier on. Good quality control procedures don't cover for an incorrect material. It's not 'fun', it's called process safety, mechanical integrity, good design and appreciating materials behaviour. It's not a question of identifying failures; it's a question of preventing them. There are plenty of examples of pressure equipment brittle fracture failures to warrant analogy with a pig trap.

Steve Jones
Materials & Corrosion Engineer

http://www.linkedin.com/pub/8/83b/b04

 

[BigInch]

Then I'm sure you won't have any trouble finding a pig trap among them.

"People will work for you with blood and sweat and tears if they work for what they believe in......" - Simon Sinek

 

[SJones]

It will probably be that one in Hibbing.

Steve Jones
Materials & Corrosion Engineer

http://www.linkedin.com/pub/8/83b/b04

 

[BigInch]

I won't be holding my breath waiting for that to happen. That one's been there since 1982.
There's several more in the colder elevations of the Rockies. Others in Montana, North Dakota, South Dakota, Colorado, Nebraska, Iowa, Illinois, Kansas, up-state New York; those are only the ones I've installed in reasonably cold temperatures, and gas pipelines as well. I doubt that anybody could possibly even count all the launchers and receivers in only the colder areas of the US. If they were as risky as you think they are, we'd all have heard about them a long, long time ago.

"People will work for you with blood and sweat and tears if they work for what they believe in......" - Simon Sinek

 

[SJones]

That's what all the pipeline owners who suffered mechanical failures as per the attached probably thought. I don't think that pipelines are risky when they have been designed correctly and the materials specified properly. The originating post for this thread suggests that neither was going to happen before the poster came on here.

Steve Jones
Materials & Corrosion Engineer

http://www.linkedin.com/pub/8/83b/b04

 

[BigInch]

No doc there. But I check the DOT incidence reports ... at least once a year.

Don't get me wrong, as I have no problem with specifying neither the appropriate materials, or extra requirements for them when such are warranted.

Well yes, but after he got the specific answer and code reference that he needed to define the appropriate CNV temperature, there was no reason to suspect that the design temperature problem, if there actually was one, would not be worked out too. Even if not, he still had what I thought was the appropriate temperature for the CNV. Furthermore, the code allows for a difference between design temperature and CNV temperature when it says take "the lowest" of the two, so even now I have no reason to suspect that anything about this might be anything less than Kosher.

"People will work for you with blood and sweat and tears if they work for what they believe in......" - Simon Sinek

 

[SJones]

The document was this one:

http://www.ogp.org.uk/pubs/434-04.pdf

At the very least, the Charpy test temperature has to be at or below the minimum expected metal temperature. So, that is fixed. However, when the pipe is much thicker than the thickness of the Charpy test piece, there will be a question about the validity of the test temperature remaining the same. It follows from simple fracture considerations: increased thickness leads to higher constraint which lowers fracture toughness. Lowering the test temperature still further compensates for the relative thickness differential, as seen (quite rightly) in DNV-OS-F101 for example. Some people, take the alternative approach which is to load up the Charpy energy acceptance criteria instead for thicker walled pipe. Which then leads on to the related question: is the B31.4 acceptance criterion of 27 Joules enough under any circumstances? Again, simple fracture considerations would suggest not. Brittle fracture is a function of stress, defect configuration and fracture toughness. The higher the stress, the higher the required fracture toughness for the same defect size. So, with designs based on a fraction of SMYS, how can it be that from X42 up to X120 say, the Charpy acceptance criteria can still be the same even though the stresses in the pipe wall are going up for the same design factor? API Spec 5L has a go at trying to address the issue, but strangely throws the curve ball of a diameter variable into the mix. It also states in a note, that according to itself, the values 'provide sufficient fracture-initiation resistance for most pipeline designs.' Personally, I prefer the straight SMYS (MPa)/10 approach of DNV.

In summary, there's a bit more to just picking a temperature.

Steve Jones
Materials & Corrosion Engineer

http://www.linkedin.com/pub/8/83b/b04

 

[BigInch]

"Provides sufficient fracture-initiation resistance for most pipeline designs." Yes. That's exactly what I was trying to say. There is a significant experience base upon which the ASME and API codes are founded that compensate for a lot of the mechanics and physics that we have yet to understand completely. That quote is obviously part of that experience base.

As I have heard, the diameter glitch is a leftover from manufacturing capabilities at the time the requirements became part of the code. The other is that just inserting the requirement for toughness, no matter what the value required was, had a marked improvement in the quality of steel being delivered since.

I could agree that at times there may be more to it than just picking a temperature. On the North Slope and in Siberia, I would be inclined to do extensive tests and at 10C lower than min temperature in service. At other times, picking a reasonable temperature is all you need.



"People will work for you with blood and sweat and tears if they work for what they believe in......" - Simon Sinek

 

[SJones]

Forgive me if I sound cynical, but as a former representative of the Netherlands for drafting ISO 3183, under the guise of one Dutch-British supermajor oil company, how these phrases generally come about is as follows:

The oil company end user representatives gang up on one side wanting high Charpy requirements, amongst many other things, whilst the pipe manufacturers gang up on the other wanting lower requirements. The arguments go round and round until, eventually, it gets down to a case of 'accept our stance or we advise our national bodies to vote negative.' At which point, the oil companies cave in and say 'OK have it your way - we will just write a tougher company spec anyway.' The pipe manufacturers then work in phrases like "provides sufficient fracture-initiation resistance for most pipeline designs" so that they don't get pestered with onerous toughness requirements from those who might not know any better.

Fracture is reasonably well understood these days to know that a blanket approach from X42 to X70, and X80 to X120 doesn't work.

The only thing that is 'saving' us is that steelmaking and NDT are so much better these days unless you happen to use substandard suppliers like the Keystone Pipeline perhaps.

Steve Jones
Materials & Corrosion Engineer

http://www.linkedin.com/pub/8/83b/b04

 

[BigInch]

Absolutely correct. Personally I don't extrapolate anything past X60, nor do I push anything I don't have experience with. It is important to remember that codes are minimum requirements.

I'm willing to concede that X70 may have its uses. X80 with a thin wall I believe is sometimes problematic to transport and install. I can't imagine yet how X120 pipe thin wall, large diameter is going to be transported by ship, rail, or down a right of way, never mind actually being lowered in and buried, assuming it can be field welded. I think it will be a long time before higher pipeline pressures arrive, forcing the thickness up to where X++ can be handled without excessive worry. Maybe the higher pressures will allow smaller diameters, but I doubt it. Seems like diameters just keep on getting larger and larger. Maybe the risk of damage during installation will make the contractors with lower risk appetites think about not bidding.

I don't like the 0.80 gas PL design factor very much either. I think it will be too much for the operators to take care of it with such thin walls. Like if it gets to the point where you have to add as much corrosion allowance as you have wall thickness needed for stress, that's going to be a problem.

While the traditional suppliers have improved, some of the low bidders can still throw some out some big trouble.

BTW your caps key seems to be stuck

"People will work for you with blood and sweat and tears if they work for what they believe in......" - Simon Sinek

 

[IFRs]

Sirs - I've been on the road the last few days and have been following your posts on a small phone screen. I finally have an internet connection and a keyboard. First, I'd like to thank both of you for the informative and enlightening discussion. I come from an API 650 committee background where toughness is carefully evaluated, we consider thickness, material grade and condition as well as temperature. Charpy tests are always done at the minimum design temperature which is always the lowest one-day mean plus 15 Deg F. I am peripherally involved in a B31.4 pipeline project and asked the owner and their engineers for an explanation of how the minimum design temperature and Charpy test temperature were determined and if they were related. I did not receive what I considered good explanation from them and so I purchased and skim-read API 5L, 49CFR195, B31.4 among others and found no real definitive explanation, at least not as crisp and clear as the API 650 code. For this project, the minimum design temperature has been chosen to be -20 DegF and the Charpy test temperature has been chosen to be +32 DegF ( not by me - I'm just trying to understand ). This B31.4 project has mostly below ground pipeline with some above ground facility piping including pig traps and launchers. The materials top out at 0.500 inch API 5L X70 underground and the above-ground pipe tops out at 0.750 inch thick and X-52. The location is the upper mid west where the lowest one-day mean is -15 DegF. From your discussion, it appears that - 20 DegF is an acceptable MDMT for the above ground piping and + 32 DegF is acceptable for the CVT temperature. The basis for this appears to be that API 5L uses generally ductile materials, the experience has been good over a long time, the materials are generally relatively thin and the stresses are relatively low. I guess I was expecting a more definitive criteria based on a set of curves for acceptable material thicknesses versus temperature based on their grade or condition or group, etc. Again, thanks for your time and efforts, I will re-read the entire thread again for better comprehension...

 

[BigInch]

"Test temperature shall be the lower of 32F (0C), or the lowest expected metal temperature during service..."

As I read that, B31.4, ss423.2.3, 32F would ONLY be acceptable if 32F is lower than the expected metal temperature while in service. IN other words, service temperatures below 32 would have to be impossible.

"People will work for you with blood and sweat and tears if they work for what they believe in......" - Simon Sinek

 

[IFRs]

What I sent to the owner last week was: "Is there a reasonable expectation that the metal temperature of a component would be below 32 Deg F under normal operations? If so, those components should be tested at the expected metal temperature or lower." They will likely go to the EOR with the question.