Instrumentation and Relief Liability

[gleng]

I have always heard (and may have at one time read), that field instrumentation cannot be employed to reduce or eliminate relief liability. I am currently looking at a system that has a low flow switch on the shellside of the exchanger with hot oil on the tubeside. The flow switch activates a shutoff valve on the hot oil to prevent overheating the shellside fluid. The shellside for all intents and purposes is a closed system. There is a relief valve on the shellside sized for fire, however, the governing scenario for valve sizing is "blocked-in" shellside fluid with hot oil continuing to flow. I understand it is good engineering practice to size the relief valve for the max case assuming the flow switch does not save you from this scenario, but I'm looking for the actual reference in ASME or API 520, or wherever it could be. Is this a code issue or a guidline issue? Does anyone know where the issue of field instrumentation and relief is specifically addressed?

 

[jay165]

gleng:

API RP 14C addresses these issues for offshore production facilities. The jurisdictional authority, the MMS, requires that 14C be followed.

 

[MikeClay]

Try API 521 paragraph 2.2

--Mike--

 

[EGT01]

To add to MikeClay's post, also see API RP-521 section 3.10 which covers Failure of Process Stream Automatic Controls.