4 replies to this topic

[KenCummingsPEng]

 Relief Sketch.pdf   97.51KB   56 downloadsI'm part of a team that is reviewing the existing Safety Relief systems on our plant, based on tightening rules which require us to assume:

a) no operator intervention in the first 30 minutes

 no credit should be taken for favorable instrument response (4.4.8.2 of API 521)

c) assume bypass valves are open,

etc.

 

We have an engineering firm on contract to calculate the required and available capacities for the enlarged group of scenarios and one 'class' of scenarios is baffling to us.  I'll do my best to describe it, but you'll probably have to refer to the attached sketch to better understand.  I'll check back in regularly in case you have questions.

 

• LIC-10 fails open.  Even without the bypass open this still:

- fills the degasser vessel in just over 2 minutes (get to assume continued liquid outflow to G-8s).

- the PSV capacity is sufficient for this liquid relief (~ 33 usgpm).

• In ~11.8 minutes, the Cold HP Separator empties (even with continued inflow) and the gas (really 2 phase, but mostly gas) reaches the LIC-10 control valve.
• Once the gas passes the LIC, we are told that it expands/accelerates, rapidly increasing the pressure on the downstream piping/equipment, and driving very high relief rate requirements.  In this case the contractor is indicating that we need > 140 in² of orifice area (we currently have 3 in² installed).

 

We have a conference call booked with the contractor to 'double check,' but directionally I can already get my head around the requirement (though the exact magnitude may change).   We have four HP hydrotreaters with these issues (it is coming up on the Amine Flash Drum as well), so several circumstances where this issue is appearing.  I'm hopeful that I don't have to recommend installation of a combined 780+ in² of PSV capacity in the plant - it might be my last chance to make recommendations ;-) 

 

Has anyone else been through a similar experience? 

Did you encounter a similar huge jump in required capacity in similar services?

 

Did you come up with any ingenious methods to meet code?  We've been talking about all kinds of things (RDs, buckling pin devices, increasing drum sizes - substantially -  to ensure a vapor space remains, SIL level equipment on the upstream drum/control valves, .....) but nothing seems particularly cost effective yet. 

 

Any assistance/advice will be greatly appreciated.

[Bobby Strain]

The scenario you describe is not unlike rupture of a tube from a high pressure gas into a low pressure heating oil system. Of course, you should not be surprised to find major problems like this when you introduce long delays into the analysis. The resolution is quite simple, however. You either use a HIPPS or you provide adequate relieving capacity adjacent to the level control valve.

 

You can't be held accountable for such drastic resolutions, because it is your management who is setting new criteria. I suggest you step back a bit and look from a higher perspective. But, neither should you be pushed around by your management. Your contractor is obligated to give you the most severe conclusion from their analysis. The contractor is not paid to take upon risk on your behalf.

 

But, I have seen design criteria for certain equipment that includes this 30 minute delay. And the equipment was built. It only cost a few $ compared to the overall project cost. Good luck. But don't be bullied and make decisions based on a group vote. Which often occurs.

 

Bobby

[paulhorth]

Ken,

I have been away for a while so I have only just read this post.

I have some suggestions that you might consider, to mitigate the gas blowby relief case:

• Fit a LSLL on the cold separator,  and a ESD valve on the liquid outlet, upstream of LIC-10. This prvides a second level of protection against overpressure. I don't really understand why these features are not already present as they are generally standard. The ESDV should also be actuated by a PSHH on the downstream vessel.
• Raise the set pressure of PSV-100 to the MAWP of 110 psi. This costs nothing, and while it will not reduce the gas blowby flowrate (still in critical flow thru LIC-10) it will reduce the required orifice size of PSV-100.
• Reduce the trim size of LIC-10, and/or fit an orifice in series with it, to reduce the gas blowby flow. There is generally scope fo reducing the valve size without compromising the normal liquid flow requirement.

Paul

[KenCummingsPEng]

Thanks Bobby/Paul.  I've been working other issues, but back looking at it.

 

• The additional instrumentation described is already in place, but we are required to perform PSV sizing “favourable instrument response” due to § 4.4.8.1 of API 521. 
• We will certainly look into raising the PSV to the MAWP - we're not yet sure why it is set so low, but will investigate.
• The LV is properly sized, and installation of further pressure drop would likely push the LV out of its operability range.

Some further information I've determined is:

1. even installing a Rupture Disk, or buckling pin device, below the liquid line (set at a pressure less than the PSV so it goes first) would require a 24" disk/line to get to an adequately sized relief line (~130') - this means a nozzle about 1/2 the diameter of the C-14 vessel!!!)
2. the duration of the 'worst case' (time to push the liquid between the LV and C-14 out of the line) is 0.18 seconds.

 

• Do you see anything that we’ve missed that might make these worst cases not applicable?
• Do you feel that the vessel could significantly overpressure (rupture) in the short period during which the worst case scenario is occurring, given the compressible nature of the incoming stream, and continuing flow out the PSV (and bottoms pump in most cases)?
• If the cases are applicable, and could significantly overpressure the vessel, do you have any other ideas for pressure relief that might be more cost effective than a bank of PSVs, or a nozzle that’s ½ the diameter of the vessel itself?

[paulhorth]

Ken,

I'm going to try to provide a reply, though I fear it will not be much help in resolving the problem. I may not have a clear grasp of the issue here because I am struggling to see how such a huge relief rate can occur when the source of pressure is a 2 inch valve with a moderate upstream pressure.

As I understand it, if the LCV-10 sticks open (even though its failure mode is Closed), the liquid in the separator will be discharged to the degasser, which will fill with liquid, and liquid will relieve from the degasser. When the separator has emptied of liquid, gas will follow and when this gas, in the line at  about 315 psig, reaches the degasser at its relieving pressure of 55 psig, it will "explosively" expand and thus require a relief rate well in excess of the flow through LCV-10. Sizing the PSV-100 for the gas blowby flow through LCV-10 is therefore inadequate.

I will admit that this basis for sizing gas blowby relief cases is what has always been used, in my experience. Bobby Strain says, and has explained to me, that in the situation of a hot oil system, where an entire utiliity header can fill with highpressure gas from a tube rupture before it finds a route to the relief valve on the expansion drum, this basis is not valid. It seems to me though that the explosive expansion scenario would depend on the capacity of the gas-filled piping to hold a significant quantity of high pressure gas. Probably your degasser is relatively adjacent to the separator, with a relatively short length of 8 inch line between LCV-10 and the degasser? Since it takes only 0.18 seconds to travel, it must be quite close.

The gas in this length of line would expand by roughly six times going from 315 to 55 psig. Is this volume significant compared to the degasser volume? That's how much liquid would be displaced from the degasser, in a brief but hard-to-define time. Have I got that right?

The answer to your question, as is evident, is that I don't have prior experience of dealing with this particular relief problem, sorry to say.

 

Coming now to the API 521 code: I agree with Bobby that you can eliminate this relief case with a HIPPS, and I don't think that this is excluded by API 521.

The relevant paragraph in the version I have to hand reads thus:

 

4.4.8.2 Capacity credit
In evaluating relieving requirements due to any cause, any automatic control valves that are not under
consideration as causing a relieving requirement and that would tend to relieve the system should be
assumed to remain in the position required for minimum normal processing flow. In other words, no credit
should be taken for any favourable instrument response.   (my highlight)

 

I understand this to mean that, while you can't take credit for pressure control valves opening to vent the pressure, you are not prohibited from allowing for the action of shutdown systems of suitable integrity. The conventional philosophy would be that while a single shutdown system (instrument signal plus ESDV) would still leave the relief case unaffected, a second independent shutdown system (independent instrument signal plus second ESDV) could, if the integrity is SIL3 or better, eliminate the relief case. This is basically a HIPPS system, here you might have each instrument (high pressure, low level) acting on both ESDVs. Maybe you have already been down this route and eliminated it, but it would seem to offer a relatively low cost solution ( 2 x 8 inch 300# ESDVs, and you already have one?). I don't see such a system as infringing the above para of API 521. The instruments and valves would need to be regularly tested to prove the required integrity.

 

Hope all this is of some use to you...

 

Paul