Jump to content

  • Log in with Facebook Log In with Google      Sign In   
  • Create Account


ChExpress Blog - 10/15/14

Read the latest news from the chemical industry in Christa's blog.

Featured Articles

Check out the latest featured articles.

File Library

Check out the latest downloads available in the File Library.

New Article

Product Viscosity vs. Shear

Featured File

Air Vessel Sizing for Water Hammer Prevention

Emergency Depressuring For Fire Scenario

depressuring

This topic has been archived. This means that you cannot reply to this topic.
11 replies to this topic
Share this topic:

#1 astonkr

astonkr

    Brand New Member

  • Members
  • 7 posts

Posted 17 April 2012 - 10:19 PM

Dear everyone.

I'd like to apply emergency depressuring system for pressure vessels.
As commented API 521 5.20.1, Emerergency depressuring for the fire scenario should be
considered for large equipment operating at a gauge pressure of 1700 kPa(approx. 250 psi)
or higher.

Please tell me that there is any criteria of large equipment.

Vessel conditions are as follwing.

1. V-1(Vessel)

Operating Pressure : 19.99 kg/cm2g
Design Pressure : 27.5 kg/cm2g
Dime. : 3300mm ID X 18000 mmH

2. V-2(Vessel)

Operating Pressure : 22.8 kg/cm2g
Design Pressure : 27.5 kg/cm2g
Dime. : 1600mm ID X 6400 mmH

3. C-1(Column)

Operating Pressure : 18.7 kg/cm2g
Design Pressure : 27.5 kg/cm2g
Dime. : 2000mm ID X 23600 mmH

Regards

Astonkr

#2 fallah

fallah

    Gold Member

  • ChE Plus Subscriber
  • 3,246 posts

Posted 18 April 2012 - 01:13 AM

astonkr,

In fact, the isue is more complex than to be depended just to vessel dimentions and some other factors such as gas phase volume and type of inventory, also should be considered.
Anyway each company may interprete the mentioned API recommendation about "large equipment" as per its own perspective. We use the below criteria for having or not having emergency depressurization on a vessel:

If for a vessel containing flammable gas, the P.V(gas) >100 bar.m3, the BDV for depressurization of that vessel in fire case to be considered. (P=maximum operating pressure, V(gas)=Gas phase volume of the vessel).

Fallah

#3 astonkr

astonkr

    Brand New Member

  • Members
  • 7 posts

Posted 18 April 2012 - 10:14 PM

Thank you so much. Fallah.

#4 paulhorth

paulhorth

    Gold Member

  • ChE Plus Subscriber
  • 367 posts

Posted 20 April 2012 - 05:36 AM

Astonkr,
Emergency depressuring is a vital safety system in any hydrocarbon processing facility. In all the gas processing plants and offshore platforms for which I have been involved in the design, over a 40 year period, I cannot think of a single example where such a system was not installed - regardless of the size of the equipment. I believe this is a requirement of all international oil companies, certainly those I have worked for, and certainly for offshore installations. There is no vessel size criterion. There is sometimes a minimum design pressure criterion of either 6.9 barg (100 psig) or 17 barg (250 psig). There is sometimes a minimum quantity for the case of trapped NGL liquid in piping - I think 4 tonnes is often used.
It is important to note that depressuring is provided not only for the fire case. Non-fire emergencies such as gas detection will also initiate or at least enable depressuring. The system is there to provide safe disposal of flammable inventory in the event of equipment damage or rupture, hopefully before a fire starts.

Your vessels are certainly large enough to represent a major hazard in fire or loss of containment. So, just do it.

Paul

Edited by paulhorth, 20 April 2012 - 05:37 AM.


#5 kkala

kkala

    Gold Member

  • Banned
  • PipPipPipPipPip
  • 1,939 posts

Posted 20 April 2012 - 10:54 AM

Considering local refineries, emergency depressurization is not presently applied on LPG (propane, butane, and similar) storage spheres and drums, according to my information. I assume it is (still) considered not feasible, due to large size of depressurizing piping required (specifically on fire). On the contrary emergency depressurization is applicable to (selected?) equipment within units, if pressure is above 17 Barg. For instance, there are depressurization systems at following places (among other ones):
- Heavy naphtha desulfurization unit, catalytic desulphurization column (12 t gaseous+63 t liquid naphtha content, ~ 300 oC). On / off remote operated valve+ downstream orifice.
-LPG recovery unit, deethaniser column, METSO depressurizing valve (not on / off), without downstream orifice. Same on C3/C4 splitter column of same unit.
More information, along with other data for depressurization, can be seen at http://www.cheresou...cv-on-spheres/ , post No 19 and on. Scanpower practice referred in post No 27 recommends depressurizing for any hydrocarbon holdup higher than 1 t (1000 kg), lower in case of LPG.
http://www.cheresou...ief-scenarios/ , post No 29 and on, could be also useful.
Look also into http://www.cheresou...ves-on-spheres , presenting two cases of LPG spheres. API 2510 A (2001) is more favorable to depressurizing of LPG vessels, compared to its previous edition of 1996.
As safety alert is increasing with time, it is natural to result in more depressurizing systems on hydrocarbon vessels, though it might not be the common case today. E.g. emergency depressurizing of an LPG vessel on fire could save it from BLEVE, even if the vessel is destroyed.

Edited by kkala, 20 April 2012 - 11:34 AM.


#6 ankur2061

ankur2061

    Gold Member

  • Forum Moderator
  • 2,275 posts

Posted 21 April 2012 - 12:22 AM

astonkr,

As I remember "TOTAL" guidelines say that the inventory in the vessel / pipe segment should be 4000 kg of hydrocarbon for it to be considered for emergency depressurization. Please note this is a recommendation and not mandatory and there may be exceptions based on case-to-case studies.

The original idea for not providing emergency depressurization for each and every hydorcarbon holding vessel / piping segment was to avoid grossly oversizing the flare system based on emergency depressurization rates from the plant / unit.

Current practice is to consider staggered depressurization based on separate fire zones to prevent grossly oversizing the flare system by fully automating the emergency depressurization. This is all the more applicable to offshore applications where space is a major constraint.

Hope this helps.

Regards,
Ankur.

#7 kkala

kkala

    Gold Member

  • Banned
  • PipPipPipPipPip
  • 1,939 posts

Posted 21 April 2012 - 10:57 AM

1. Scandpower practice (referred in post No 5), http://www.scandpowe...m191-203082.pdf '> http://www.scandpowe...m191-203082.pdf , Chapter 4.1, specifies rather strict depressurizing criteria; some of them are not locally applied at present, but indicate the trend.
2. Several smaller vessels around the main vessel are connected to its depressurizing system and their corresponding flows at fire are also considered. This is locally applied. Scandpower practice speaks of segments, not vessels, probably for this reason.
3. Sequential depressurization per Scandpower is understood to be same as staggered one, mentioned in post No 6.
4. Yes, depressurization design should not overcharge the flare system. It is further assumed that:
-Relevant fire zones are same as those specified for fire fighting, according to NFPA methodology.
-All depressurizing systems of a mentioned fire zone should be able to discharge to flare simultaneously.
Comments on these two assumptions would be appreciated.

#8 paulhorth

paulhorth

    Gold Member

  • ChE Plus Subscriber
  • 367 posts

Posted 22 April 2012 - 05:06 AM

Kkala,

Relevant fire zones are same as those specified for fire fighting, according to NFPA methodology.
-All depressurizing systems of a mentioned fire zone should be able to discharge to flare simultaneously.


Yes I agree with both these points. If you are going to use a fire zone segregated blowdown system, you will need ESD valves on all the interconnecting piping at the fire zone boundaries, to isolate the inventory in the neighbouring zones.

Paul

#9 kkala

kkala

    Gold Member

  • Banned
  • PipPipPipPipPip
  • 1,939 posts

Posted 22 April 2012 - 03:55 PM

Thanks, paulhorth for confirmation. ESD valves are placed for isolation in local refineries, operated either from control room or from local panel at some distance from valve (5 m or more).

#10 mohds23

mohds23

    Junior Member

  • Members
  • 13 posts

Posted 23 April 2012 - 07:17 AM

Thanks everyone for nice inputs on the subject.

Mr. Paulhorth,

If you are going to use a fire zone segregated blowdown system, you will need ESD valves on all the interconnecting piping at the fire zone boundaries, to isolate the inventory in the neighbouring zones.


As per my understanding , ESD valves are not necessarily provided at fire zone boundaries whereas, their location depends on process sectioning philosophy. Equipment and piping sections falling under particular fire zone boundaries are considered for heat input area estimation and enclosed inventory (due to actuation of Fire/Gas detection resulting into ESD) within the equipment and piping is considered for depressuring load estimation.
Kindly suggest.

ESD valves are placed for isolation in local refineries, operated either from control room or from local panel at some distance from valve (5 m or more).


Mr. Kkala,

I understand that ESD valves are in fact actuated through PLC,and not operated from control room or local panel.
Kindly suggest.

regards,

Mohd

#11 fallah

fallah

    Gold Member

  • ChE Plus Subscriber
  • 3,246 posts

Posted 24 April 2012 - 01:54 AM

mohds23,

ESD activation would isolate the fire zone and bring all process and utility systems inside the zone into safe shutdown conditions, then ESDV's are normally provided at fire zone boundaries.
Indeed, ESD could be initiated manually from central control room and from field, or automatically further to F&G detection or loss of essential control.

Fallah

#12 kkala

kkala

    Gold Member

  • Banned
  • PipPipPipPipPip
  • 1,939 posts

Posted 24 April 2012 - 06:11 AM

-Concerning ESD valves for isolation, see also http://www.hse.gov....ced/hsg244.pdf , giving more info on the topic (UK HSE articles are generally useful).
There are few cases here of "automatic closure" of such a valve. For instance, the automatic closure of valve on the point connecting an LPG sphere to its feed line, http://www.cheresou...ief-scenarios/ - post No 9.
-Concerning atmospheric tanks of flammable liquids, the isolation valves in touch with tank walls (so within tank basin) had better be remote operated, I believe, but this is not often observed here. At least these valves should be manually closed, as soon as their line is not in service, otherwise all tank content could empty into the basin in case of a fire on the basin (line can be destroyed by fire).
-Interconnecting piping passing from fire zone boundary should have an isolation valve, to protect transmission of fire. This valve is usually not at the boundary, but close to equipment (e.g. a tank or vessel). Additional isolation valves within a fire zone are usually needed, e.g. at the tank wall, as mentioned previously.

Edited by kkala, 24 April 2012 - 07:05 AM.





Similar Topics