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Heat Exchanger-tube Rupture-downstream Equipment


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#1 vvsastry66

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Posted 01 September 2008 - 10:36 PM

Can any one tell me if we apply 10/13 rule for tube rupture case of shell&tube heat exchanger, upto what extent, the low pressure side, to be designed for 10/13 of high pressure side des. pres. Is it enough, if we do it upto first isolation valve? why?

sastry

#2 JoeWong

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Posted 10 September 2008 - 12:07 PM

QUOTE (vvsastry66 @ Sep 1 2008, 10:36 PM) <{POST_SNAPBACK}>
Can any one tell me if we apply 10/13 rule for tube rupture case of shell&tube heat exchanger, upto what extent, the low pressure side, to be designed for 10/13 of high pressure side des. pres. Is it enough, if we do it upto first isolation valve? why?

sastry


No. Including low pressure side piping that potentially blocked in.

#3 djack77494

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Posted 11 September 2008 - 08:52 AM

QUOTE (vvsastry66 @ Sep 1 2008, 10:36 PM) <{POST_SNAPBACK}>
upto what extent, the low pressure side, to be designed for 10/13 of high pressure side des. pres.


sastry,
The idea is that the low pressure side of the exchanger has already been proven to operate at the full high pressure side design pressure. By proven I mean that the l.p. side of the exchanger is actually pressure tested at ~13/10 * its own design pressure as part of code requirements. So it makes sense to say that it can handle this pressure, at least as a short term excursion.

Regarding what else to include and how to handle it, you should view the piping as having potential exposure to the full 13/10 * connected exchanger design pressure. Since this scenario only occurs during a tube rupture, it is VERY unlikely. Our practice is to assign it to the minimum short term excursion catagory; i.e. a 10 hour/event, 100 hour/year as permitted in B31.3. This usually makes the defining of where this applies to be a moot point.

#4 JoeWong

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Posted 11 September 2008 - 09:09 AM

Doug,

Interesting !
I always wanna to seek the way out from this scenario to save cost...

Can you advise the way to justify / qualify this particular case into minimum short term excursion catagory as permitted in B31.3. ?

#5 djack77494

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Posted 14 September 2008 - 12:43 PM

QUOTE (JoeWong @ Sep 11 2008, 05:09 AM) <{POST_SNAPBACK}>
Can you advise the way to justify / qualify this particular case into minimum short term excursion catagory as permitted in B31.3. ?


JoeWong,
We are speaking here ONLY of the tube rupture scenario for a shell & tube heat exchanger.

Clients I have worked with are often very reluctant to accept potentially hazardous scenarios as existing for only short term durations. Thus many will resist any suggestions that a condition should only exist very infrequently and/or over a short time period. Usually I don't push the point, although the added cost can be significant.

Despite this, most clients WILL accept the fact that a heat exchanger tube rupture is a very rare occurance. A complete break in a tube with one side having an appreciably higher pressure fluid than the other side would be readily detected and rapidly mitigated. This makes such good logical sense that even extremely risk adverse clients generally accept this reasoning. The logical conclusion is that this scenario fits within te B31.3 definition of a 10/100 short term excursion.
Doug

#6 JoeWong

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Posted 15 September 2008 - 03:07 PM

Thanks...

#7 fallah

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Posted 17 September 2008 - 02:10 AM

QUOTE (djack77494 @ Sep 11 2008, 08:52 AM) <{POST_SNAPBACK}>
QUOTE (vvsastry66 @ Sep 1 2008, 10:36 PM) <{POST_SNAPBACK}>
upto what extent, the low pressure side, to be designed for 10/13 of high pressure side des. pres.


sastry,
The idea is that the low pressure side of the exchanger has already been proven to operate at the full high pressure side design pressure. By proven I mean that the l.p. side of the exchanger is actually pressure tested at ~13/10 * its own design pressure as part of code requirements. So it makes sense to say that it can handle this pressure, at least as a short term excursion.

Regarding what else to include and how to handle it, you should view the piping as having potential exposure to the full 13/10 * connected exchanger design pressure. Since this scenario only occurs during a tube rupture, it is VERY unlikely. Our practice is to assign it to the minimum short term excursion catagory; i.e. a 10 hour/event, 100 hour/year as permitted in B31.3. This usually makes the defining of where this applies to be a moot point.

You concluded that the tube side and associated piping is enough to be designed at 10/13 of shell side design pressure?

#8 vvsastry66

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Posted 17 September 2008 - 04:57 AM

Dear Friends,

Thanks everyone for your valuable replies.

1.0 Can we conclude that if there is no possibility of downstream valves to be blocked, is it enough to design (10/13) upto first isolation valve of exchanger?

2.0 Even if there is blocked outlet valve possibility, as per B31.3, of low probability, upto first isolation valve is enough?

3.0 Alternatively, can we provide a PSV on tube side, set at lowest pressure in the piping loop. This way we need not design tube side for 10/13 pressure.

Sastry


QUOTE (fallah @ Sep 17 2008, 03:10 AM) <{POST_SNAPBACK}>
QUOTE (djack77494 @ Sep 11 2008, 08:52 AM) <{POST_SNAPBACK}>
QUOTE (vvsastry66 @ Sep 1 2008, 10:36 PM) <{POST_SNAPBACK}>
upto what extent, the low pressure side, to be designed for 10/13 of high pressure side des. pres.


sastry,
The idea is that the low pressure side of the exchanger has already been proven to operate at the full high pressure side design pressure. By proven I mean that the l.p. side of the exchanger is actually pressure tested at ~13/10 * its own design pressure as part of code requirements. So it makes sense to say that it can handle this pressure, at least as a short term excursion.

Regarding what else to include and how to handle it, you should view the piping as having potential exposure to the full 13/10 * connected exchanger design pressure. Since this scenario only occurs during a tube rupture, it is VERY unlikely. Our practice is to assign it to the minimum short term excursion catagory; i.e. a 10 hour/event, 100 hour/year as permitted in B31.3. This usually makes the defining of where this applies to be a moot point.

You concluded that the tube side and associated piping is enough to be designed at 10/13 of shell side design pressure?


#9 Shailesh Paranjpe

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Posted 17 September 2008 - 09:53 AM

QUOTE (vvsastry66 @ Sep 1 2008, 10:36 PM) <{POST_SNAPBACK}>
Can any one tell me if we apply 10/13 rule for tube rupture case of shell&tube heat exchanger, upto what extent, the low pressure side, to be designed for 10/13 of high pressure side des. pres. Is it enough, if we do it upto first isolation valve? why?

sastry

The Good Engineering practise is to design the low pressure side upto first isolation valve on the Low pressure side. The 10/13 exchangers typically may have utility on the lower pressure side, in which case, once the process breakthrough into utility headers is detected, the impact can be minimized by closing the Low pressure side isolation valve. Considering this, the upstream of isolation valve on the low pressure side must be designed for the highest pressure on the High Pressure side.

#10 djack77494

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Posted 17 September 2008 - 04:54 PM

QUOTE (Shailesh Paranjpe @ Sep 17 2008, 05:53 AM) <{POST_SNAPBACK}>
the upstream of isolation valve on the low pressure side must be designed for the highest pressure on the High Pressure side.


I cannot concur with this statement and it was definitely NOT the point I was trying to make. My point was that it should be perfectly acceptable to all to design the low pressure side of the heat exchanger, including connecting piping to the first isolation valve, for the "normal" low design pressure. This is assuming that that design pressure is >= the high pressure design pressure * 10/13.

I want to affirm fallah's question about concluding the tube side could be designed for 10/13 * shellside design pressure. Also, while I find the statements of vvsastry66 a little hard to follow, I believe that all three of his statements are correct. In statement #1, if you cannot block in the low pressure side, then you needn't even design for 10/13 provided that the always open and available inlet and outlet piping are sufficient to prevent overpressure. I accept statements 2 & 3 as is.

#11 JoeWong

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Posted 18 September 2008 - 01:44 AM

Whenever a tube rupture occurred, gas in High Pressure Side (HPS) flowing liquid in Low Pressure Side (LPS), there is momentary surge. Then this momentary surge would possibly lead to instantaneous peak pressure possibly exceeded the Maximum Allowable Working Pressure (MAWP) of the HX LPS. Here, i mentioned possibly. It is very difficult to quantify this surge pressure. It subject to where the tube rupture occurred, does it impinging the shell wall, can resonance occurred, etc. A blocked in condition increase the possibility...

Then fluid from HPS side will flow into LPS. If you have blocked in event, then the pressure in LPS will build-up to equalize the pressure in the HPS and LPS. The MAWP @ MOP (maximum operating temperature) shall be good for this equalized pressure. Upto the blocked in battery limit, this condition shall be kept.

If you are definitely sure blocked in event is NOT possible, then fluid from HPS flow into the LPS . The story doesn't stop here... Fluid in HPS (in compressible) may expand. Large flow passing the burst tube... Both expansion and large flow discharge into LPS network and release some way (please analyze the LPS). A high back pressure may occur at the HX end due to large flow and expansion. So this back pressure might exceed the piping MAWP...

Apart, there are still problem with the discharge handling...

Above complicated situation lead to some engineers ask a question. Probability of specific event. Smart engineer argued that low probability event... Don't have to consider.

  • How to qualify this "low probability event" ?
  • The deviation in ASME is Accumulated hour through-out the equipment life. That means it includes momentary peak pressure due to ALL possible scenario since it is fabricated i.e. hydraulic test, surge pressure created during commissioning, maintenance, start-up, etc. How to quantify all these data ?
  • Can i use this "low probability event" statement and apply throughout the plant or even other plant ? If this stands, then API Std 521 can drop the tube rupture scenario from the list...


Personally, the spirit should be "take maximum effort to minimize the risk but not find some confusing or avoidance argument"...

This does not answer your questions but hope it give you (or reader) some ideas...




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