PSV's Tubeside and Shellside

[maddocks]

I am designing a gas chiller with sour natural gas in the tubeside (DP: 455 Psig) and boiling propane on the shellside (DP: 225 Psig).

Q1: Since the 455 is more than 1.3X the 225, at first glance it would seem that I need a tube rupture PSV. However, API-521 has a statement about using tubeside operating pressure instead of design - my op is only 166 Psig. Do I still need provision for a tube rupture PSV? Since the chiller is outside and propane filled, I will probably have to do a firesize on this as well.

Q2: Due to compressor controls, the tubeside can be isolated with auto-closing block valves. Do I need to consider a tubeside fire case even though the bundle is submerged in liquid boiling propane? If it is blocked in and begins to warm up, the pressure will rise.

Help?

 

[pleckner]

Q1: Just for information, you only need to consider the design ratio of 1.3 if the equipment was tested at 130% of the design pressure. Nothing says that one cannot still test the equipment at 150% of design pressure and many still do, especially if they test the equipment along with the connected piping.

Second, the statement in API RP520, Fourth Ed. March 1997 (wow, are they ever so overdue for a revision!!) mentions that this should be on a case-by-case basis and says there should be a SUBSTANTIAL differece between the maximum operating pressure and the design pressure of the HIGH PRESSURE SIDE (paragraph 3.18.2). Then you COULD consider that maxium high pressure side operating pressure to be functionally the high pressure side design pressure. (That word "substantial" is wide open to interpretation, isn't it?) So, you have to feel real comfortable that your 166 psig is indeed the maximum pressure the high pressure side will ever see for you to meet the conditions to eliminate a tube rupture scenario from your relief considerations. In my opinion, for your system I wouldn't.

Also note that when using the exclustion rules, you must consider the low pressure side SYSTEM design pressure, not just the heat exchanger component. For example, if my tube side is the low pressure side and designed within the exclusion rule but the tube side is associated with a vessel (upstream or downstream) that is designed for a much lower pressure, then I might no longer meet the exclusion rule. See the reference paragraph.

Q2. I ran out of time for this one. I'll leave it up to someone else to answer this for now.

 

[fdomin]

maddocks,

As you mentioned you MUST evaluate fire case as it is likely to occur and be the design case.
I agree with pleckner that you should use tubeside design pressure for tube rupture case evalution.

Regarding your second question, I don´t believe that a tubeside fire case should be considered. During a fire case the heat will lead to propane boiling at a temperature depending on the relief pressure, and this will remain constant. Remaining gas in tubes would raise its temperature to that of boiling propane (aprox 120ºF @ 225 psig). You can make a quick estimation, using ideal gas law, of the required temperature to reach tubeside design pressure due to gas thermal expansion.

Also you could make an analogy to a case of an unwetted vessel exposed to fire. For these cases API 521 stands that due to low thermal expansion coeff of gases, metal rupture is likely to occur before pressure reachs vessel design pressure, then a depressuring system should be installed instead of a PSV.