#  > Petroleum Industry Zone >  > Oil And Gas Production >  >  >  Slug catcher Desgin

## Mohamed

what procedure i must follows for slug catcher design

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## azeezy

If too much slug is actually produced at plant or is expected or simulated using a transient analysis software like OLGA, you need a pipe-finger type slug catcher. Other-wise use the contemporary separator sizing method.

The velocity at the inlet of any slug catchers primary bottle or bottle for separation of gas-produced liquid must be small enough so that slugs reduce to wave flow. This is given by Tait-Dukler correlation.

The diameter of the inlet header is sized to allow for such a transition. The primary bottle connected to is sized as a two-phase separator for the maximum possible instantaneous slug flow into catcher. some margin is given as the flow in the primary bottle is counter current. The control valve is sized for the normal flow with a dump valve for the slug flow arrival above design capacity.

The finger bottles are sized for retaining the liquid for a time enough for degassing. If the future productions increase the prevention of carryover is done by allowing a dump valve to operate which will push the entire liquid into a tank at a high flowrate. The breather valve is sized accordingly. Some Design and Engineering practices discuss designing to a little extent.

The Shell DEP is an example.
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## ahmed abou zena

Thank You

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## Mohamed

> If too much slug is actually produced at plant or is expected or simulated using a transient analysis software like OLGA, you need a pipe-finger type slug catcher. Other-wise use the contemporary separator sizing method.
> 
> The velocity at the inlet of any slug catchers primary bottle or bottle for separation of gas-produced liquid must be small enough so that slugs reduce to wave flow. This is given by Tait-Dukler correlation.
> 
> The diameter of the inlet header is sized to allow for such a transition. The primary bottle connected to is sized as a two-phase separator for the maximum possible instantaneous slug flow into catcher. some margin is given as the flow in the primary bottle is counter current. The control valve is sized for the normal flow with a dump valve for the slug flow arrival above design capacity.
> 
> The finger bottles are sized for retaining the liquid for a time enough for degassing. If the future productions increase the prevention of carryover is done by allowing a dump valve to operate which will push the entire liquid into a tank at a high flowrate. The breather valve is sized accordingly. Some Design and Engineering practices discuss designing to a little extent.
> 
> The Shell DEP is an example.
> ...



very thanks zeeshanzaki for your replay 
but the above for pipe-finger type slug catcher.but actually  in my question i interested by vertical  vessel slug catcher (for offshore platform ).   i can easily determine the slug frequency  , slug time  , Max. slug volume  for the two phase pipeline but how i can use this data to determine volume of vertical slug catcher and what dose i must put in mind while study sizing of slug catcher? and pipesim can calculate  directly  the slug  catcher volume ?

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## azeezy

The vertical slug catcher is easiest and also the biggest of them all.
OLGA is standard for transient analysis.

Use 90% of the maximum instantaneous/transient slug flow in design.

If you have the current operational parameters of slug frequency and slug size then these can guide you easily to determine the slug catcher volume.  The slug catcher must be able to retain the liquid for just time sufficient enough for degassing the liquid. This time can be calculated based on theoretical as well as rule of the thumb criterias.

As you know for vertical slug catcher the gas velocity governs the diameter. Gas flows may differ during slugging as compared to normal operations. But the design gas flow for normal operation  might be high and may yield a large diameter vessel which goes against the compact equipment philosophy for off-shore platforms. First determine the terminal velocity of the gas-liquid separation. 
0) You can use the equations given in Ken Arnolds Book Surface Production Operation vol 1 chapter 4-5. I prefer an updated coefficient of discharge equation.

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Vol 1
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1) First determine the terminal velocity of the gas liquid separation. This is independent of the flow rates but dependent only on the separation characteristics like particle size, gas/liquid density. You can use Archimede's Number or K factor method(or Galileo's number) to calculate the Drag Coefficient. Then calculate the velocity.
The other method is to iterate the terminal velcoity and reynolds number combination to yield the value.

2) Next find the diameter that will allow this velocity of gas for maximum of normal gas flow. This size will facilitate further separation at a lower gas flow expected rate during slugging. Use an L/D of 3 or 4 to calculate the vessel Seam-Seam or Tan-to-Tan length. Round up to the nearest 0.5 ft.

3) Now the vessel is adequate to handle the gas capacity. Check for liquid handling capacity by calculating how much residence time would the liquid have if the peak slug flow was to pass through this vessel.
This can be calculated by dividing the liquid volume at Normal liquid level of the vessel by the volume flow rate expected.
The ample residence time is debatable but certain design practices are in use nowadays.
As a rule of thumb the residence time for degassing must be 3 to 6 times the time required for liquid to settle at the terminal velocity for gas liquid separation. Some designers recommend 10-15minutes. Others may even say 30minutes. 

As liquid is usually governing during slugging (the liquid handling capacity capacity is not usually met) the design scheme can be reveresed. If liquid is governing and its capacity is not met use the following method

First determine the volume of liquid section needed. Say for 10 or 15 minutes of degassing the liquid flow is 100 ft/min. Then volume of vessel required in liquid section is 1000-1500 ft.

Using an L/D of 3-4 at a vessel half filled (Normal Liquid Level max =0.5 times the height) you obtain a Dia = 9.5 ft, tan to tan Height H=28.5 ft  (H/D=3, V=1000ft) this is a big vessel but sizes much bigger are also common. Space is usually the biggest problem in offshore platforms as there is not much leeway in expanding.

I can enumerate the steps but it may take some time for em to compile a complete reply.

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## Mohamed

very thanks for your answer 
but by the above answer  i will solve the problem  of slug  by design  huge  separator to handle slug flow but what i mean is to install vessel before current installed separator the job of this vessel will be to handle slug and prevent high level in separator and i will relate the outlet of slug vessel with the level in the separator also i will relate the inlet of the slug vessel with the level on it

So i think   it is not important  for  me to separate all gas in the slug vessel and I don't need any retention time for gas separation. only i want the flow to arrive to separator  in stratified flow instead of slug flow type 

Very thanks for the above book link but i read that Ken Arnolds Book Surface Production Operation vol 1 version 3 have Ch. about slug catcher.

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## azeezy

What you say you need in this case is to size a two phase separator vertical/horizontal, depending on the availability of space, which will rectify the high liquid level problem in medium sized slug catchers.

Sorry for the misunderstanding; retention concept is only necessary for liquid degassing as normally lesser time is needed for gas liquid separation. Retention does not deal primarily with gas separation but the gas must have some residence in the vessel just enough for the liquid droplet to fall to the liquid interface. The gas must not reach the outlet nozzle laden with these droplets. 

*Scheme 1 - Buffer vessel downstream separator*
Modifications to the existing vessel can be done to incorporate the capability to handle the slugs. The vessel can have an emergency dump valves/dump LCV (Level Control Valve) in addition to normal flow Level control valves sized for the 85-90% of the peak slug arrival/production rate. This valve can be activated by a high level switch in the existing separator vessel which would divert the produced liquid to a buffer vessel where degassing can occur say at 25psig or with direct transfer to a storage tank with a properly sized Pressure Vacuum Relief Valve (PVRV).
Blow-by can be controlled by switching to normal flow LCVs at low level and/or a proper vortex breaker.

The advantage of this method is a low cost low pressure buffer vessel, same dump LCVs  in both buffer vessel and separator,  a PVRV check/replacement and checking if the tank has a frangible roof or not just to see system integrity.

*Scheme 2 - Buffer Vessel Upstream Separator*
_Scheme 2a_
Using a buffer vessel upstream the existing separator is slightly complex. The vessel will now be handling primary production separation which is a role previously performed by the existing separator. It would probably be of the same size as the existing vessel. 
A higher liquid droplet size say 2000 micron could be used to allow some liquid to be trimmed by the existing separator. There would be no need for complete separation in this vessel as this is not its purpose.

The buffer vessel must have the dumping Level control valves in addition to the normal flow LCVs otherwise both vessels would have a high liquid level problem as liquid carryover from the first will eventually end up in the second. 
Its like filling 2 empty pitchers of water by a high flow-rate tap. As quickly as you fill one pitcher and move to the second the other would also be filled in no time unless the first is emptied quickly. Thus the inherent problem would remain. I have seen one case where the gas field promoted this overflowing philosophy in revamps and ended up with a bottlenecked produced water system with severe surging.

_Scheme-2b_
Another case in this scheme could be to have normal flow handled by existing, separator, if its adequate, and flow diverted to the buffer vessel when slugs start arriving. Sort of slugs bypassing the separator. This could be triggered by level switch in existing separator. During normal flow the existing separator works and when slugs come the complete production flow is diverted to the buffer vessel. The liquid is dumped by a high flow rate level control valves. The gas from the buffer vessel would then be diverted to the existing separator for trimming to specifications. The large liquid flow from the buffer vessel can be routed to produced liquid handling systems. By this option the buffer vessel would have large flow rate LCVs whereas no new LCVs would be needed in the existing separator other than a level switch or signal from its level controller. 

This modified scheme has a disadvantage that a high-pressure vessel would be needed which would be cost intensive compared to the Scheme 1. Furthermore the buffer vessel would have normal flow and dumping level control valves. A 1.5-3 minute surge in the buffer vessel would be necessary as the actual trimming of the liquid content is still handled by the existing separator.

To decrease the vapor overload through the LCVs in case of gas blow-by in any scheme, split-range LCVs can be used. A valve for (0-50% flow and another for 50-100%). This would decrease blow-by overload on downstream equipment as both valves cannot fail at the same time.
HAZOP would be needed in both schemes.

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## Mohamed

very thanks for your answer  you completely cover  the subject

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## ghazanfar

Will n e buddy share this program wid me?
Thnxz in Adv.

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## aboulfazl

thank you

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## harij_ac

Good discussion on the Slug catcher design. Let me add a missing point here even though it is not to be considered here.
If the Slug catcher outlet is connected directly to some turbine / compressors, then slug catcher Gas section also should be designd to provide adeqaute buffer for Maximum slugging time. Means Slug catcher should supply the required gas to Turbines, with out falling the vessel / supply pressure below turbine / compressor tripping pressure, when no gas is coming to it (Maximum slugging).

Azeezi, can you update the link on 4share?

Thank, jazakallah Khair

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## Mohamed

> Good discussion on the Slug catcher design. Let me add a missing point here even though it is not to be considered here.
> If the Slug catcher outlet is connected directly to some turbine / compressors, then slug catcher Gas section also should be designd to provide adeqaute buffer for Maximum slugging time. Means Slug catcher should supply the required gas to Turbines, with out falling the vessel / supply pressure below turbine / compressor tripping pressure, when no gas is coming to it (Maximum slugging).
> 
> Azeezi, can you update the link on 4share?
> 
> Thank, jazakallah Khair



yes  i think that is very important point must be take into account during design 
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## skb

Azeezy,

You have explained very well about the design of finger type slug catcher in the post "Slug Catcher design" (05-02-2008, 11:53 PM). When we talk about slug catcher, we concentrate on the slug volume and capacity of the fingers to be deisgned. However, the separation of gas/ liquid in the inlet header (primary separation bottle) of a finger type is rarely discussed or even published. 

In this post, you made a clear explanation that the "velocity must be small enough so that slugs reduce to wave form" or (rather to stratified smooth regime). Can you shed some more light on this separation bottle. Because I am working on an existing finger type slug catcher and with no historical data on this, I am trying to evaluate what this was designed for " as a Gas capacity". Any expalnation or reference would be great. Also, if you have the Shell DEP on this, can you post in the same.



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