I'm trying to get a feel for what those in the oil & gas/chemical/industrial industries are doing in terms of pipe stress performed on piping connected to pressure vessels and exchangers. If you read ASCE 7, it is clear to me that the intent that piping attachments to all these pieces of equipment shall be analyzed to handle the movements in table 15.7-1 times Cd. This is very similar to API 650 Annex E seismic analysis. However, outside of API 650 Annex E tanks, is anyone running this 15.7.4 flexibility analysis on standard pressure vessels, exchangers, etc?
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Pipe Stress - ASCE 7 section 15.7.4
- Thread starter JoeSeag
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What is ASCE 7?
API addresses some equipment related to the general petroleum industry and drilling equipment, 650 as you mention and API 2 for offshore structures, among many others.
Pipe stress in the petroleum, chemical plant and pipelines generally comply with ASME codes in the USA and many other countries.
A quick summary of our typical practices are found here....also note the additional links within.
ASME Piping seismic design code is B31E - 2008. This Standard establishes a method for the seismic design of above-ground, metallic piping systems in the scope of the ASME B31 Code for Pressure Piping (B31.1, B31.3, B31.4, B31.5, B31.8, B31.9, B31.11).
Pressure vessels are designed in accordance with ASME BPV (Boiler and Pressure Vessel) codes.
Of course these are only for pipe and vessel design. If you are looking to design the foundations, or structural concrete supporting buildings, frames and floors, then ACI Codes apply. Attached structural items made with steel, or steel structures supporting elevated vessels, then its ASCE 7.
--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
API addresses some equipment related to the general petroleum industry and drilling equipment, 650 as you mention and API 2 for offshore structures, among many others.
Pipe stress in the petroleum, chemical plant and pipelines generally comply with ASME codes in the USA and many other countries.
A quick summary of our typical practices are found here....also note the additional links within.
ASME Piping seismic design code is B31E - 2008. This Standard establishes a method for the seismic design of above-ground, metallic piping systems in the scope of the ASME B31 Code for Pressure Piping (B31.1, B31.3, B31.4, B31.5, B31.8, B31.9, B31.11).
Pressure vessels are designed in accordance with ASME BPV (Boiler and Pressure Vessel) codes.
Of course these are only for pipe and vessel design. If you are looking to design the foundations, or structural concrete supporting buildings, frames and floors, then ACI Codes apply. Attached structural items made with steel, or steel structures supporting elevated vessels, then its ASCE 7.
--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
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- #3
ASCE 7 is the code for "Minimum Design Loads and Associated Criteria for Buildings and Other Structures" adopted as law directly or indirectly via IBC in just about all states in the US. I've attached one of the applicable snapshots. It has specific direction for piping connected to vessels and tanks and what needs to be verified for seismic review. I understand all the reference you posted; those are very standard resources for analysis. This ASCE 7 requirement is a topic I cannot find discussion on and the fact that it is adopted as law in states has me wondering what others in the industry are doing, if anything at all.
My (admittedly vague) understanding is ASCE 7 is related the structure(s) involved with tanks and piping. So I run my pipe stress analysis and determine loads and support locations. The structural engineer is involved on the other side to ensure the structures are adequate per ASCE 7 and other codes.
To my quick skim, section 15.7.4 is just another statement that your structure needs to consider earthquakes and other occasional loads, similar to the B31.3 statements for the process piping side of things.
To my quick skim, section 15.7.4 is just another statement that your structure needs to consider earthquakes and other occasional loads, similar to the B31.3 statements for the process piping side of things.
In the oil & gas/chemical/industrial industries piping stress analysis is performed in accordance with the requirements of B31 piping codes. Typically B31.3 is used for process plant piping. A computer program analysis is performed such as Caesar II.
B31 codes specify requirements for wind and earthquake loads to be included in the piping analysis. It's been a while since I looked at B31.3 so I am not sure if it specifies exactly what methods to use for the analysis of these loads or leaves it up to the engineer. However most analysis that I have performed use ASCE 7 methods for determining loads on piping from wind and earthquake. There is a subprogram spreadsheet in Caesar you fill in with all of the design parameters found in ASCE 7 and the program uses this to compute the loading on the piping and resulting stresses in the piping.
From the loading on the piping in combination with the thermal expansion and other loadings, the loadings of the piping on the vessel nozzles can be determined. However movements of the vessel at the nozzle connection are usually determined independently from tables in ASCE 7 as I recall. I forgot how exactly we used to determine movements at nozzles under earthquake loading but I believe it was base on using an equivalent earthquake load based on the g acceleration and then determing how much a vessel will deflect along its length. These methods are found in pressure vessel handbooks. Other than that I imagine the tables in ASCE 7 could be used but I do not know how conservative they are.
From the loadings calculated on the nozzles we would then calculate the stresses in the vessel wall per methods such as WRC 107/297. Caesar also has a subprogram that makes this analyis also as part of the piping streas analysis.
B31 codes specify requirements for wind and earthquake loads to be included in the piping analysis. It's been a while since I looked at B31.3 so I am not sure if it specifies exactly what methods to use for the analysis of these loads or leaves it up to the engineer. However most analysis that I have performed use ASCE 7 methods for determining loads on piping from wind and earthquake. There is a subprogram spreadsheet in Caesar you fill in with all of the design parameters found in ASCE 7 and the program uses this to compute the loading on the piping and resulting stresses in the piping.
From the loading on the piping in combination with the thermal expansion and other loadings, the loadings of the piping on the vessel nozzles can be determined. However movements of the vessel at the nozzle connection are usually determined independently from tables in ASCE 7 as I recall. I forgot how exactly we used to determine movements at nozzles under earthquake loading but I believe it was base on using an equivalent earthquake load based on the g acceleration and then determing how much a vessel will deflect along its length. These methods are found in pressure vessel handbooks. Other than that I imagine the tables in ASCE 7 could be used but I do not know how conservative they are.
From the loadings calculated on the nozzles we would then calculate the stresses in the vessel wall per methods such as WRC 107/297. Caesar also has a subprogram that makes this analyis also as part of the piping streas analysis.
Don’t use B31E. ASCE 7-16 loads in paragraph 13 something is indeed a good way to go. Feels strange that a European pipe stressed should tell this to an American. Refer to B31.3 para 301.5.3.
Once I’m back in the office tomorrow I’ll up the reference ms from the applicable section in chapter 13. There’s a dedicated table for all piping parameters.
Huub
- You never get what you expect, you only get what you inspect.
Once I’m back in the office tomorrow I’ll up the reference ms from the applicable section in chapter 13. There’s a dedicated table for all piping parameters.
Huub
- You never get what you expect, you only get what you inspect.
B31E isn't referenced in B31.3. B31.3 references ASCE 7,however its not explicitly limited to the application of ASCE 7 only (see the use of may);
This means B31E may be used/applicable as well, however discussions found (e.g. here on eng-tips) indicate that the method may not be conservative. Situations that Ive seen so far (i.e. in AutoPIPE, since AP has included a B31E check per default now![[thumbsdown]](/data/assets/smilies/thumbsdown.gif "[thumbsdown] [thumbsdown]")
) is that the allowable can become way too high.
Huub
- You never get what you expect, you only get what you inspect.
This means B31E may be used/applicable as well, however discussions found (e.g. here on eng-tips) indicate that the method may not be conservative. Situations that Ive seen so far (i.e. in AutoPIPE, since AP has included a B31E check per default now
) is that the allowable can become way too high.Huub
- You never get what you expect, you only get what you inspect.
- Thread starter
- #9
This discussion is veering off topic a bit. It wasn't intended to discuss seismic accelerations on the piping itself. I think that is a standard analysis performed using different strategies. I use ASCE7 chapter 13 within Caesar for that analysis and that topic is very well understood in my opinion. What my original question is about specifically is in regards to ASCE 7 chapter 15 (SEISMIC DESIGN REQUIREMENTS FOR NONBUILDING STRUCTURES). Section 15.7 is specific to tank and vessels. ASCE appears to take the stance that in a seismic event, one of the most common weakest links is the piping to equipment connection. It appears that the way they want to eliminate this failure potential is by applying rules to the piping (which to me was surprising to find such black and white verbiage on piping design outside of the normal ASME 31 codes). It state within 15.7.4 (Flexibility of Piping Attachments) that piping shall be designed to inherently absorb a tabulated amount of movement in all 6 directions at the equipment nozzle connection without overstress and also a second review to apply even greater tabulated 6 displacements to confirm the piping doesn't rupture (but is allowed to yield). This forces a good amount of flexibility to be included in piping between the nozzle and the first support away from the nozzle. This adds a substantial amount of added analysis above what is typically performed per ASME 31. But if you look at new installations all over the place, there's no way most of these designs are passing the requirements of ASCE7 15.7.4 and I've not seen discussion on this topic in the 20yrs in my career. Hence I am trying to understand if perhaps I am looking at this entirely wrong as I will the first to admit I am not an ASCE 7 expert, especially chapter 15 no matter how many times I've read it. Much appreciation on this topic everyone.
XL
Yes. That agrees with the quote from B31E I posted above. It says "or", so either may be used.
But how is the allowable stress affected by B31E? B31E only specifically mentions a limit on longitudinal stress, PD/4t + (Msustained + Mseismic)/Z <= minimum of (2.4 x S, 1.5 x Sy, or 60ksi)
Other stress limits appear to be similar to 31.3, .1, .4 and .8.
But since B31E is an "or" situation, at worse it is essentially just another design case, Seismic Design Condition 2, and the designer could choose to design to the more severe Condition 1, if his conservative judgement prevailed, or the lesser, if the pipes were not critical or hazardous services.
I don't see where there is a problem. B31 specific stresses retain their individual requirements, so you still cannot ignore those and you can include B31E as an additional case, if stresses are higher,
Is that not correct?
--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
Yes. That agrees with the quote from B31E I posted above. It says "or", so either may be used.
But how is the allowable stress affected by B31E? B31E only specifically mentions a limit on longitudinal stress, PD/4t + (Msustained + Mseismic)/Z <= minimum of (2.4 x S, 1.5 x Sy, or 60ksi)
Other stress limits appear to be similar to 31.3, .1, .4 and .8.
But since B31E is an "or" situation, at worse it is essentially just another design case, Seismic Design Condition 2, and the designer could choose to design to the more severe Condition 1, if his conservative judgement prevailed, or the lesser, if the pipes were not critical or hazardous services.
I don't see where there is a problem. B31 specific stresses retain their individual requirements, so you still cannot ignore those and you can include B31E as an additional case, if stresses are higher,
Is that not correct?
--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
I usually do not see problems with typical pipe to vessel or tank nozzles connections. I have never seen where arbitrary displacements of pipe at nozzles were considered. In practical cases, there are probably few situations where that actually could happen. The usual cases are where piping is actually supported off the vessel itself in the vicinity of nozzles, if not at other locations along their route to those nozzles. In that case there is no possibility that seismic movement of pipe will be different from the seismic movement of the nozzle itself. As for tanks, most pipe of significant size such that differential stiffness might cause differential movements at nozzles, the pipe attaches to points of a tank that are not typically subject to high Seismic movements; being generally located near the foundations where sway of the tank or vessel structure will be minimal if anything. I just don't see where or how differential Seismic movements between pipe and tank or vessel nozzles are supposed to happen. In most all cases they are going to move together. There is simply no way that they won't. They are usually directly coupled. If a horizontal pipe connects two vertical vessels together at height, yes, there is potential for differential movements, but that rarely happens. In those cases where you have problem configurations, the problem is easily recognised by an experienced engineer, or gets red flagged by Caesar anyway, if it is a real problem that actually creates overstresses. There is no need to specify that pipe connecting to nozzles will be subject to any arbitrary movements when we know exactly what differential movements will actually occur and what stresses are generated in the process. In cases where pipe and structure are analyzed separately, potential differential, out of phase, seismic movements are typically considered. The vessel fabricator can supply seismic movement characteristics. The structural engineer checks those calculations before designing the foundations. The pipe stress engineer checks the pipe movements at the nozzle points. My general opinion is, in petrochem and petroleum, power gen related work, in most all cases, temperature differentials cause much more problems than seismic loads ever will. If you have enough flexibility for temperature changes, you have more than enough for seismic concerns.
--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
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- #12
1503-44, while I agree with much of what you say, that is not how the ASCE7 chapter 15 is written based on my understanding. And being that it is adopted as law, one could not justify feelings on the matter as an excuse to not perform very clear directions provided by code in court of law. That is why I'm hoping someone can make arguments backed by evidence provided by verbiage in the code that proves my understanding incorrect. I'm hoping to be wrong on the matter, I just can't find actual justification in the code to do that. I too think this is over-reaching in design. But I can tell you after doing many of these analysis on tanks and vessels, this in fact quite often heavily drives design vs thermal expansion of piping. The commentary for 15.7.4 sheds a bit more light and I can wrap my head around needing to do API 650 Annex E analysis on large field erected storage tanks, but to apply these same requirements on ALL vessels of any kind is quite a different story! But that is how I understand the intent of ASCE7 chapter 15. Please read this chapter on your own and I would love for some other thoughts on the text that is written.
I agree with 1503 about arbitrary displacements of nozzles. Considering the forces and issues associated with ACTUAL vessel movements, I can't imagine the piping modifications needed to accommodate something as arbitrary as an additional 4" of displacement. Sure, in an ideal world we could throw an expansion joint at every nozzle to cover this arbitrary movement and the owner would keep up with it and maintain it. But that's not how it works in reality.
In my opinion the statement at the beginning of 15.7.4 is doing a lot of heavy lifting - "unless otherwise calculated use the minimum displacemetns in Table 15.7-1". Sure thing, I've got better info and I'm going to ignore those comical values.
In my opinion the statement at the beginning of 15.7.4 is doing a lot of heavy lifting - "unless otherwise calculated use the minimum displacemetns in Table 15.7-1". Sure thing, I've got better info and I'm going to ignore those comical values.
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- #14
RVAmeche, I again am not in disagreement with you. I would be interested in knowing your thoughts for calculating displacements other than table 15.7-1, again from a point of substance and technical backing that would hold up in court of law. I think there's consensus that the requirements spelled out in ASCE7 chapter 15 don't pass the gut feel test and are impractically overbearing, but unfortunately its published and adopted by law.
For pipe design purposes, 31E says "OR". 31E does not require that the ASCE given displacement condition must be the pipe design condition. That gives the piping design engineer the justification in court to say that he used the alternate, calculated criteria and that it was reasonable and justified by his expert opinions backed by his experience, which BTW are not "feelings".
--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
In any case flexibility is not usually difficult to provide, providing that the piping engineer was thinking about that during his layout. What I see more times than I should is a long run of pipe going straight into a valve bolted onto a tank nozzle. It's not that difficult to put in a 90 or two, both horizontal or one vertical to get the required flexibility. I see long runs of pipeline running straight into a pig receiver at the center of a gas processing plant, then a huge pipe anchor block trying to stop the thermal movement, even at ambient temperature ranges. No bends, Nothing. Headers straight into the pump house. Those usually don't even work thermally in seismic zone 0. I think the general stress problem isn't so much seismic, it's much more attributable to inexperienced pipe layout artists. Once that gets into the plot plan, it's difficult to shake it out. As I said, in most cases, seismic amounts to getting the sideway under control with proper spacing between supports. The seismic stresses themselves are hardly ever a controlling case, unless you are in a really high seismic zone. Getting thermal under control, is the biggest headache.
--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
A few points
Seismic anchor movement (SAM) needs to be considered. Vessels, tanks, buildings etc do move around in EQ and the piping and the connected pipe needs to allow for this. A model of the structure is required to find the SAM. For large vessels it could be rotation of foundation giving the SAM.
B31E does have higher allowance stress combinations, but the accelerations (1/Rp) used in the model are higher.
Pressure equipment design codes are poor match with seismic design codes for buildings. Not so bad for ASCE 7 and B31E where they talk the same language. A problem out side of USA where the local seismic design codes for structures has a different approach and terminology.
Seismic anchor movement (SAM) needs to be considered. Vessels, tanks, buildings etc do move around in EQ and the piping and the connected pipe needs to allow for this. A model of the structure is required to find the SAM. For large vessels it could be rotation of foundation giving the SAM.
B31E does have higher allowance stress combinations, but the accelerations (1/Rp) used in the model are higher.
Pressure equipment design codes are poor match with seismic design codes for buildings. Not so bad for ASCE 7 and B31E where they talk the same language. A problem out side of USA where the local seismic design codes for structures has a different approach and terminology.
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