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WELLHEAD PROTECTION DEVICES 1

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Lots of changes in 2017

Current CFR here... Title 30 Part 250 ss 880 & 1628


See also API 14E

--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
 
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Can we see the text extract on the justification on configuration and location of these SSVs' / SDVs' in this Yr 2017 edition of RP14C that goes with these 2 figures ?
 
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Can we see the text extract on the justification on configuration and location of these SSVs' / SDVs' in this Yr 2017 edition of RP14C that goes with these 2 figures ?
Click to expand...

unfortunately there is not clear explanation about these figures. do you have any idea?
 
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The justification is more related to offshore production moving very much farther out away from shore, logistics, damage control, response access timing, potential for catastrophic spills, and Macondo-type disaster prevention then it is to actual necessity to control Flow. Obviously one valve would work, if it did work. These requirements are fail safe backups needed only if the primary fails. Belts and suspenders is the new offshore, deep water, environment. Overkill for the typical land rig. But API 14s are only required for offshore environments. Not applicable to land production systems.

In short a near complete rewrite of the previous editions
You can get an idea of the extent in this. Click download link


--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
 
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There is always a description / narrative in API RP 14C for each of these figures. And one subsection in each of these narratives will be about the trip valves.
 
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Thanks for that, @1503. I've only got the Yr 2001 edition.

Apart from some re organisation of the sections for wellheads and headers / pipelines, they added a new figure to the satellite wells which shows a HIPPS like assembly at the satellite platform. There is nothing new here, it is merely a pictorial representation of the HIPPS like configuration suggested in the old Yr 2001 edition.
The narrative that goes with figure A.3 is table A.2 on page 37. Specifically A.1.c. Here, this 2nd SSV may alternatively be an SDV, but is is not necessary to have this SDV on the flowline, as clarified in A.2.3.3 on page 38. I am used to seeing this on the collection header, with the 2oo3 voting PSH's just upstream of this. This topside SDV is on one of the decks on the platform. Another pipeline isolation SDV is located on the outgoing riser and is auto closed on emergencies only. The design pressure break to pipeline design pressure is downstream of this riser SDV.
A PSV is located downstream of the topside SDV to cater for inevitable small leaks that may exist at any of the flowline SSVs' and/or topsides header SDV.

By the way, the reference to this mysterious 6.2.2.2.5 in Table A.2 subsection A.1c (3) is nowhere in this rehashed version of this RP.


 
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It was hard to find. The net is full of 2001 editions and I even found one from 1995.

I'm not a fan of HIPPS. I put up with them offshore, because I trust that testing and maintenance will be better than onshore, rightly or wrongly. Onshore you're lucky if they keep the relief valves unblocked.

--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
 
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These arrangements ( SSV + SDV with 2oo3 voting for trip) in API14C have their roots in in B31.8 ( see para 845 on overpressure protection) and in B31.4 also, which is in stark contrast to ASME Section 8 for pressure vessels and API 520/521. Such arrangements in the API RP14C / B31.4/ B31.8 for pipeline overpressure protection are not SIL 4 HIPPS - they are only SIL3, so less stringent requirements for testing/maintenance etc).
Pls note that justification for the SDV to be on the production gathering header (and not on the flowline) is on the assumption there is plenty of volume in the downstream B31.4/B31.8 subsea pipeline to accommodate the additional rise in pressure attendant with the finite speed of closure of the SDV. If the pipeline volume is small, this SDV may well have to be on the flowline.
 
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The definition of SSV and SDV are pretty close.

SSV is Surface Safety Valve - "An automatic wellhead valve assembly that closes upon loss of power supply"

SDV is shut down valve - "An automatically operated, fail closed valve used for isolating a process station"

So to me two SSV are simply the actuated Upper Master valve and the Wing valve on a tree. That's very common IME.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
 
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what is the difference between SDV and SSV in process-safety view (for example sil level) ? what will hapen if instead of installation 1 ssv and 2 sdv, 3ssv or 3sdv upstream the choke? Can it be said that ssv is the same as sdv with the exception that ssv must be only hydrulic?
with comparison of two last figure A.3, it seems that one ssv is equal 2 sdv?!
 
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dear georgeverghese (Chemical)
which is in stark contrast to ASME Section 8 for pressure vessels and API 520/521
Click to expand...
what is stark contrast between ASME and API 14c? As far as I know there is no obligation for sil 4 in ASME SECTION VIII for overpressure protection.

Pls note that justification for the SDV to be on the production gathering header (and not on the flowline) is on....
Click to expand...
i did not exactlly understand what is your comment in this parag. Are you saying that because of large production on sealine, SDV should be upstream the choke?
 
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A)Both ASME and API520/521, to my knowledge, do not accept substitutes to PSV, such as redundant instrumented trip loops, for ultimate pressure protection. These redundant trip loops ( which may be SIL 3 typically) are accepted as ultimate pressure protection mechanisms for B31.4 and B31.8 pipelines.

B)SDV on the production header can be used when there is ample buffer volume in the sealine.
If the pipeline volume is small however, then the SDV may need to be moved upstream close to the wellhead choke on the production flowline itself.
Which to choose - run a settleout pressure simulation on dynamic mode on your process simulator with realistic conservative closing times for SSV and SDV and see if the pipeline MAWP is exceeded, starting with pipeline at PSHH.
 
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