4 replies to this topic

[K.Sandeep]

Hello all,
I am currently working on PSV calculations for seal oil system for a polymer plant. I have a single seal oil pump which pumps seal oil from a reservoir and supplies it to seals of 4 process pumps. The supply header is 1.5” and there are two sub headers 1” each. There is a regulator on each 1” subheader and then a PSV . Each subheader then splits in to two lines which go to seals of individual pumps through 0.5” lines. I have a isolation valve between subheader and individual 0.5” line.

There is a regulator at the end of main supply header 1.5” and then the same main header continues as return header back to reservoir. The two PSVs on the subheaders relieve to the return header. Also, the oil, after flowing through seals of process pumps joins return header through 0.5" line with a regulator on it just before it joining return header. All the piping and PSVs are located not more than 15’ from ground. The PSVs are small (I think those are for thermal relief only). I read the flow reading for seal oil for one of the process pump, it is 19 GPH and assume same for all other.

My questions on this:
1.Is regulator (which is at upstream of PSV) failure is a applicable scenario ?
2.Is blocked outlet is applicable? If yes, what is the relieving capacity (19 gph or 19x2 gph)?
3.How do I know that whether installed PSVs on the lines are only for thermal relief or for any other applicable scenarios as well?
4.If the fire case is applicable, and it is assumed that the valve serves for thermal relief only then is it expected that thermal relief valve should be able to relieve generated vapors?
5.If I consider these PSVs are process PSVs (not a thermal relief valve) then do I need to do the calculation for thermal relief for process PSVs?
6. Do thermal relief valve to be examined for inlet line pressure drop criteria?

Please excuse me for posting a big problem like this..but any replies on this would be a great help to me!
Thanks in advance

[skearse]

Any chance you could post a P&ID-that would help tremendously. Wihtout that, though, my (hedged) answers would be:
1) Probably (more than likely).
2) Sorry, need a drawing for this one, but I think it's debatable. Based on what I'm interpreting your system as, the most conservative approach would be to say yes, although it could be argued that even if 1 valve were closed (blocked) you would still have flow through the other three. If a "single credible failure scenario" of all four block valves being close (ie, after turnaround or maintenance on all four pumps, then yes, this would definately be a credible scenario-but that's for you to evaluate. In any case, the flow is not going to be based on the pump seal being fed but on the oil pump supplying the system.
3) If there's no documentation on what was considered and the sizing basis, then your only option is to go through a full analysis and calculate the flows valve sizing requirements for each credible scenario.
4) Vaporization vs. expansion-That's going to be for you to decide, based on the physical properties of the seal oil-like the boiling temperature, system design pressure ("MAWP" for the protected equipment), etc. If it's only 15' off the ground then it's likely that external fire should be considered-unless you can give a detailed explanation of why it's not credible.
5) Yes, again, if thermal expansion is a "credible scenario."
6) Yes.

Having said all this, let me note that these are simply my thoughts based on the information that you've provided. You, as the user and knowledgable person for the system, ultimately have to determine which scenarios are actually "credible."

[JoeWong]

1.Is regulator (which is at upstream of PSV) failure is a applicable scenario ?
2.Is blocked outlet is applicable? If yes, what is the relieving capacity (19 gph or 19x2 gph)?
3.How do I know that whether installed PSVs on the lines are only for thermal relief or for any other applicable scenarios as well?
4.If the fire case is applicable, and it is assumed that the valve serves for thermal relief only then is it expected that thermal relief valve should be able to relieve generated vapors?
5.If I consider these PSVs are process PSVs (not a thermal relief valve) then do I need to do the calculation for thermal relief for process PSVs?
6. Do thermal relief valve to be examined for inlet line pressure drop criteria?

The more i read your description, more question i have. There are some points confused me. For example,
- Why you need a regulator on 1.5" header, another one regulator at teh 1" header, another one at the return header...Wonder how they work...
- Are they regulating upstream pressure or downstream pressure?
- What is the seal oil pump type...centrifugal or screw pump ?

Similar to Skearse comment, please provide a drawing or sketch for entire loop and stating how the pressure is control, design conditions, etc.

If the pump is centrifugal pump, is the shut-off pressure exceed the design pressure of pump discharge ?
If the pump is screw pump, there is no protection again regulator stucked close position. The PSV downstream of regulator on 1.5 header does not protect gegulator upstream section...

I guess the best is for you to provide the information for further discussion. Without these information, any advice will not 100% help you (or worst lead to hazard !!!)

[K.Sandeep]

Thanks Joe and Skearse.

I am attaching PID this time. PSV 541 & 542 are to be checked for the adequacy for all applicable scenarios.

Per my understanding, the regulator on 1.5” main header controls the upstream pressure (supply header) and regulators on 1” subheader controls downstream (seal oil supply pressure to seal). Although one of the regulator/ control valve on 1” subheader is shown as out of service, I had considered as if it is in service per original design. The Seal oil pump is screw type as shown on PID.
The plant is 60 years old and most of the data is not available (not even datasheet of pump). I have to make necessary assumptions and check the adequacy of PSVs.

Thanks

Attached Files

•  Seal_Oil_PSVs_drawing.pdf   102.49KB   59 downloads

[skearse]

Thanks Joe and Skearse.

I am attaching PID this time. PSV 541 & 542 are to be checked for the adequacy for all applicable scenarios.

Per my understanding, the regulator on 1.5” main header controls the upstream pressure (supply header) and regulators on 1” subheader controls downstream (seal oil supply pressure to seal). Although one of the regulator/ control valve on 1” subheader is shown as out of service, I had considered as if it is in service per original design. The Seal oil pump is screw type as shown on PID.
The plant is 60 years old and most of the data is not available (not even datasheet of pump). I have to make necessary assumptions and check the adequacy of PSVs.

Thanks

OK. My first question is: what is driving the set pressures? The two PSVs have very different set pressures (240 vs. 150), which may be OK; I'm just wondering what the basis of using these set pressures is.

If I'm reading this right, you also have a VERY serious design issue (this probably should have been my first question...): If either of those PSVs lift, where is the discharge going to go? From your P&ID you have a regulator on the loop return that both of these PSVs discharge into that maintains the line pressure at 290 psi-I'm assuming that's a backpressure regulator bu twhat happens what happens if that fails ? You have 290 psi on the discharge of these PSVs versus an opening pressure of 240 or 150: your PSVs will never lift! Even during normal operating conditions, what it the pressure in the downstream segment of that line? Are your PSVs sized to include the backpressure on them? Is that backpressure regulator (I'm assuming that's what it is, at least) ever PMed?