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Heat Exchanger Adjoining Pipework During Tube Rupture - Api 521 4.4.1

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#1 BH17


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Posted 04 January 2022 - 08:47 AM


During commissioning of our newly constructed plant we discovered a design flaw in some of our heat exchangers that have cooling water on the low pressure side (DP of the CW network = 10 barg, hydrotest = 15 barg) and syngas on the high pressure side (ca. 140 bar).

The design pressure of the LP side of the exchangers has been upgraded to the 2/3rds rule, the low pressure side exchanger nozzles have also been upgraded - which is pretty typical. However, the connected piping has maintained the original hydrotest pressure of 15 barg.

PSVs have also been situated at quite a far distance from the exchanger (on the return side only) and although they have been sized to relieve the critical vapour flow through a full tube break they haven't considered the initial liquid slug they would need to push out prior to relieving the gas i.e. their response time will be slow. Finally, no transient analysis was conducted which is a code requirement if selecting to deal with tube rupture in this way.


What we have done since discovering this:

First we commissioned a transient analysis on the current as-built and potential re-designs. Our re-designs are very limited due to the project phase - some of the conclusions and constraints are listed for info below:

1. Report shows that the current design will have a pressure spike in the cooling water network that far exceeds the pipework's hydrotest pressure (40ish bar) at the two isolation valves either side of the exchanger. (pipework is 150# carbon steel).

2. We cannot upgrade the entire CW network to a higher design pressure as 95% of it is underground, its already been commissioned and so the cost is astronomical. We can't redo the hydrotest pressure of this pipework either (to the ASME16.5 limits for 150# carbon steel piping - roughly 19 bargx1.5) on the section we can't upgrade as this is also extremely difficult and costly at this stage.

3. We can upgrade the pipework up to the isolation valves (to 300# or above) and we can also add fast acting bursting discs either side of the exchanger. 



Points 2 and 3 have meant that we had to consider a design in which we extended the pipework length on return and supply sides of the low pressure side the exchanger before hitting the isolation valves on either side. The idea being that the length of pipe dissipates the pressure spike such that once it gets to the 150# isolation valves it is at or lower than the 15 barg hydrotest pressure. 


API 521 states the following:

"The user may choose a pressure other than the corrected hydrotest pressure, given that a proper detailed mechanical analysis is performed showing that a loss of containment is unlikely.” 


My questions are based around this statement. First, what does the statement in API actually mean? - does anyone have experience of interpreting this? Does it mean that we could select a higher pressure than the hydrotest pressure we have already conducted (and that we cannot re-test) without proving it if we add some mechanical analysis checks?

We have already resigned ourselves to the fact we need additional upgraded pipework to dissipate the pressure spike (in addition to the two bursting discs), my concern is that when the new as-built is remodelled we might still be slightly over the 15 barg hydrotest pressure. I was looking at this and considering whether is could be a sort of get-out clause.

Secondly, what would be the mechanical analysis checks to convince ourselves a loss of containment (LOC) cannot happen?


Apologies for the crude accompanying sketch, its the best i could do whilst in transit - it has a mistake on the isolation valves, these are to be retained as 150# so the spec break is on the wrong side. Also ignore the restriction orifices, these are not there or part of the final design.


Attached Files

#2 latexman


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Posted 04 January 2022 - 09:57 AM

Look in for a clue, "The use of maximum possible system pressure instead of design pressure may be considered as the design pressure of the high-pressure side on a case-by-case basis where there is a substantial difference in the design and operating pressures for the highpressure side of the exchanger.  Leakage or failure of external gaskets may be a tolerable risk in some services (e.g. cooling water)  but not in others (e.g. hydrocarbon, corrosive, toxic services) because of potential impacts of a release."

Section is on specific types of heat exchangers that are not shell and tube types, however a system pressure analysis on a system with shell and tube exchanger(s) would be just as meaningful, and using the maximum possible system pressure instead of design pressure for shell and tube exchangers is what they are referring to.  And, your case is cooling water, so can a leak or failure into that be tolerated?  Or, can it be modified so it is tolerable?  Can a small leak be detected and alarmed prior to a bigger, non-tolerable event?  It's up to you and your team.
Just remember:
  • Tube failures are rare.
  • When the high pressure is on the shell side rather than the tube side, like in your case, a total failure is much less likely. Tubes will normally collapse rather than split open. 
With test pressures at 1.5X design pressure, my company considers loss of containment at 2X.
Keep working it.  Is your metallergy inherently resistant to any possible corrosion at operating temperatures?  Is there any chlorides in the syngas or CW?  Any potential of stress cracking?  Can you step up the methods and frequency of inspection to detect issues?  Any vibration issues?
This is a tough one.

#3 BH17


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Posted 05 January 2022 - 08:03 AM

Thanks for your prompt and informative response Latexman. Yes it's certainly a messy and costly one.

At my previous company we had a similar rule of thumb to yours which was 1.5xtest pressure for LOC, 1.1-1.5xtest pressure for flange leaks etc. So maybe this is the get out of jail card we need - the current surge analysis report already shows that we are near the 1.5xtest pressure without any significant increase in pipe length. We are adding a significant amount of extra piping to try and meet the 15 barg based on extrapolation of this report so even if we don't quite reach 15 barg at the isolation valve we should be well within this rule of thumb.


We can certainly tolerate some leakage of the syngas into the cooling water network and this seems to be in line with the API statement about selecting a higher than hydrotested pressure i.e. up to the ASME flange limit or similar so perhaps we can accept a higher pressure without actually conducting a new hydrotest. We already have a vent at the end of the cooling water network (closed circuit) which has been sized using a rule of thumb for exchanger pinhole leak. This is vented to safe location but its possible to add a sample take-off here to add some monitoring protection - unfortunately this wouldn't allow us to pinpoint which exchanger is leaking but at the very least we can check the all the critical exchangers on a turnaround. For the other concerns re: metallurgy/SCC etc. - i don't think we have much of an issue as our cooling water chloride spec is extremely low (exact number i can't remember and don't have access currently), pH <8. The piping is carbon steel so any embrittlement issues from hydrogen leaking through should be minimal - admittedly this sort of stuff is not my background but i can certainly get a metallurgist to confirm these things. As we are yet to start this part of the plant up (don't want to put syngas in until we resolve the issue) i can't comment on vibration.


Thanks for your thoughts, its given me some more ways forward!

#4 Bobby Strain

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Posted 05 January 2022 - 03:13 PM

What does your insurance carrier require? Or you local inspectors/regulators? You probably need to do more research. This situation has been around for a very long time.



#5 breizh


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Posted 08 January 2022 - 02:11 AM


As Bobby is pointing out you need to stick to regulation and code . You must have your equipment designed for what it is supposed to do . 

In other words you need to get all the certificates including nameplate attached to the equipment with the operating condition prior to use.


Good luck


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