Tubeside Rupture Protection 1

[maddocks]

I am designing propane subcoolers with low pressure liquid propane on the shellside and high pressure ethane rich liquid LPG on the tubeside. I have several options:

- one is to simply design the shellside up to 2/3 of the tubeside design pressure and avoid the tube rupture problem. That is, to raise the MAWP from 320 to 471 Psig.

- the other is to attempt to predict fluid properties for flashing ethane rich liquid at 320 Psig (shellside MAWP) as it exits from a tube rupture. The tubeside design is 707 Psig.

Can anyone provide some guidance for tube rupture PSV sizing in a liquid/liquid hydrocarbon exchanger where the relieving fluid will be flashing at the relieving pressure? Interestingly enough, the LPG mixture also goes cryogenic across the PSV which is another issue.

regards,
Jim

 

[TD2K]

Do a keyword search for "Heat Xchanger tube rupture" where this was discussed.

It's also thread798-21481 (sorry, haven't figured out how to paste this in as a clickable link).

 

[grt12]

A couple of points to note:
1. ASME has been modified so that it is no longer a 2/3 rule - the hydrotest pressure has been changed from 1.5 times MAWP to 1.3 times.
2. For tube rupture in this case, if flashing is occurring across the tube break then the relief rate may be too high for a PSV to handle (the volumetric rate if liquid releif would have to equal the volumetric gas flow and this leads to very large relief valves). The other problem is that relief valves cannot nornally respond fast enough to the transient pressure surge and a rupture disc may be required for this protection.
3. There is a good paper on tube rupture relief published in Hydrocarbon processing in February 1992 by Mr. Wong.

 

[maddocks]

My understanding is that the change to 1.3 X MAWP can only be applied via Code cases with a release from the end user. If we choose to continue with the more traditional 1.5X rule, can I continue to use the 2/3 rule for not requiring a PSV?

 

[TD2K]

Maddocks, your understanding is also my understanding. Given that, you can continue to use the 2/3 rule (or the corresponding fraction if you elect to hydrotest at 1.3x design) if the exchanger is hydrotested to 1.5x design.

Note that the entire piping envelope associated with the low pressure side of that exchanger also has to meet this criteria. You can not ignore the fact if the associated piping and/or other equipment would be pressured over its hydrotest pressure by simply stopping at the exchanger's flange face because the low pressure side meets the 2/3 rule.

The intent behind the 2/3 rule is that in the event of a tube rupture (a pretty rare event) the equipment would not be pressurized over the pressure it was hydrotested at (and hopefully still capable of holding). So, if you elect to hydrotest the vessel originally at 1.3x design, you can still avoid a PSV sized for a tube rupture but not to as high a pressure as for 1.5x hydrotest condition.