What is the impact of operating pressure on slug catcher ?

[quangkhoa90]

Hi all,

I would like to ask you what happen to a slug catcher ( finger type ) when it is operated at higher (or lower) pressure ? Is the separated liquid lower than normal operation ?

Thank you for your help

 

[LittleInch]

for the same standard flow rate or mass flow rate, at lower pressures velocities will be higher and hence carry over of liquid or mist is more likely. However much depends o the configuration of the inlet and outlet pipework, number of fingers, type of incoming fluid etc etc, but in genral, the higher the pressure, lower the actual velocity the better the "separation" will be.

Vague question so kind of vague answer I'm afraid.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[EmmanuelTop]

All other things equal, increasing the operating pressure should give you some more gas handling capacity in the slug catcher. This may not be true in case there is significant condensation from the gas/vapor phase when pressure is increased.

Dejan IVANOVIC
Process Engineer, MSChE

 

[quangkhoa90]

Thank you for your help.

We have a plant to separate LPG from an associated petroleum gas (80% C2+C1, 15% C3+C4) at 109 bar and 26°C. The operating pressure of SC is 109 bar normally.

It looks like when we increase the operating pressure, the liquid separated level is decreased, and I am looking for a reasonable explanation. Phase diagram could not be applied in this case.

Please follow these two cases : 1/ Increasing P, remaining flowrate
2/ Increasing P due to increasing flowrate

BR,

 

[georgeverghese]

Dont see why level should vary with changes in pressure, since the slugcatcher is operated at constant level through LIC? Outlet liquid flow can vary depending on the feed composition / temp / pressure.

Agree that liquid entrainment in to SC exit vapor will increase with decreasing SC pressure, but this will hardly register on the SC liquid exit FT, if the liquid exit flow is high in comparison to the increment in entrainment.

We should see the process diagram or PFD for this slugcatcher and its process controls to try to tell why this SC level is changing with operating pressure. Also what the corresponding feed and exit flows are for gas and liquid.

 

[EmmanuelTop]

George is absolutely right, there should be no permanent change in liquid level if slug catcher is equipped with level control loop. Or are you referring to the yield (flow rate) of the liquid product from slug catcher? You also need to tell us why the phase diagram is not applicable in this case (I can't think of any reason why thermodynamics should suddenly become "irrelevant") - perhaps you operate in a retrograde region of the phase envelope where vaporization of liquid phase occurs when pressure is increased. This is, for example, the reason why mechanical refrigeration cannot be used for NGL recovery when operating pressure is above the cricondenbar of processed fluid.


Dejan IVANOVIC
Process Engineer, MSChE

 

[quangkhoa90]

How could I check if it is operated in a retrograde region of phase envelope ? Here is the composition of gas coming from offshore (%mol) : N2 (0.21), CO2 (0.06), C1 (70.85), C2 (13.41), C3 (7.5), iC4 (1.65), nC4 (2.37), iC5 ( 0.6), at 109b (gas pressure coming from offshore) , 26°C

I still do not see why the liquid obtained is lower when operating pressure is increased.

I am trying to explain with velocity : when pressure from offshore is increased => gas velocity is increased => more liquid particles is carried out of SC in the gaseous phase since SC is a gravity separator.

Thank you for your answer

 

[georgeverghese]

If you have a process simulation program, you can ask for a phase map with 1,2,3...5% liquid mole fraction to see if you are going into retrograde region.

But the explanation may be something simpler to account for lower liquid outflow when SC pressure is lower..

Do you have water in the incoming liquid, or can water carryover into the condensate? If water enters into condensate line, the flow reading will change because of discrepancy in liquid density used at liquid FT. As water content increases, for the same total liquid outflow in m3/hr , the FT reading will show higher.

So it may be something to do with water arrival rate into the SC.

 

[EmmanuelTop]

By increasing SC pressure, gas velocity decreases, not increases.

We have no idea what the system looks like. Perhaps increasing the operating pressure causes decrease in production of liquids, due to higher back pressure on the Wells. It could be anything. As LittleInch said, you posted a rather vague question so we are all just guessing here.

Dejan IVANOVIC
Process Engineer, MSChE

 

[LittleInch]

guangho,

If you know what the operating pressure increase to please tell us. Also what is the gas flow rate and liquid flowrate at your "normal" and "high" pressure?

The difference in liquid could be any number of things - properties of the fluid - 109 bar arrival is quite high - , the lower velocity may be increasing the liquid hold up offshore - how long is the incoming pipeline? If the increase in pressure is only over quite a short period of tie (hours, 1-2 days), the system might not get to equilibrium and hence be storing liquid in the pipeline which then comes back onto the slug catcher when the velocity increases.

S/C is there to catch slugs or surges of liquid - they are a pretty poor separator.

We have about 10% of the information required to help you any more.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[quangkhoa90]

Dear all,

It looks like we were operating in the retrograde region.

I have two other questions :

1/ In a distillation column (reboiler, condenser), suppose that the feed is constant, the hot oil supplied to reboiler is constant, if the reflux ratio is increased, what is the profiles of the temperature and pressure of the column ? Knowing that the top product is mainly C3+C4, the bottom product is mainly C5+.

2/ Refer to the attached picture, with the same feed entering to the same column, why the feed tray is 14th in case A and 20th in case B ?

Thank you,

 

[EmmanuelTop]

I'd suggest you better confirm whether you operate in the retrograde area, or it just "looks like that". You may be getting liquids downstream where you don't want them, or where you cannot tolerate them.

1) Answer to this depends on the tower controls. If tower bottom (or reboiler outlet) is on automatic temperature control, increasing reflux will initially cause cooling/temperature decrease of the entire tower, due to cold reflux liquid cascading down the trays. Reboiler temperature controls will react and increase firing/heating rate, in order to maintain the set point temperature. In this case you get the same bottom temperature (TIC maintains it) and decreased tower top temperature (reflux cools it). Pressure on each tray will be slightly increased as compared to the base case, due to increased vapor/liquid traffic and the corresponding pressure drop.

If reboiler is not on auto controls, increasing reflux will simply cool the entire tower and you'll see a bit lower temperatures in all sections of the tower - depending on how much reflux is added.

2) This can be anything - we don't know any details of this system. First tower is De-Butanizer, the 2nd column is De-Ethanizer. Operating conditions are different, feed composition is different, products are different. Not all the columns have feed entry on the same tray. The optimum feed tray location depends on all these parameters. See

http://lorien.ncl.ac.uk/ming/distil/distildes.htm

and

http://www.separationprocesses.com/Distillation/DT_Chp04i.htm

and

https://www.cpp.edu/~tknguyen/che313/pdf/chap4-4.pdf

Dejan IVANOVIC
Process Engineer, MSChE

 

[georgeverghese]

There is a routine in Pro II - Simsci that can help with estimating the optimum feed tray location for a given column operation - vaguely recall this is in the Shortcut Distillation option only.

It is possible to do this manually also if can identify the key separation components and you know what is the required ratio of the key components in the ovhd and btms products, but it will take much longer to do with the Fenske-Underwood-Gilliland method.

In the debutaniser, if there is water in the feed ( as commonly occurs in slugcatcher feed, even after a liquid coalescer is installed upstream), you need to install water removal on one or two of the top trays, else the water will get "trapped" in the column. Also beware that the reboiler hot oil tubes may most likely get coated on the tube OD with mineral salts from residual formation water in feed to the deC4, leading to loss of heat transfer duty over time.

If you are looking for a decent recovery of C3+ in the deC2 option, obviously you'll need a coolant which is a lot colder than cooling water.

 

[quangkhoa90]

Thank you George and Emmanuel,

I have discussed with a senior engineer, he told me that the system was operated in the retrograde region, however I could not confirm it by myself.

In the case of an deethanizer, if water is present in the feed ( natural gas ), what is the effect on column operation or product purity or material of the column ?

By the way, could you please explain me the difference between vapor pressure and saturation vapor pressure of a gas ? I'm a little bit confused. It's much better if you could provide an concrete example.

Thanks in advance

 

[quangkhoa90]

Is there any particular benefit to operate the natural gas (in the pipeline from offshore to the processing plant) in the retrograde region ?

 

[georgeverghese]

Dont think water is permitted in a deC2 feed - the feed will have to be dehydrated down to a water dewpoint which is lower than the top temp at the DeC2 at the operating press. of the column.

When the vapor press of a gas component = saturation vap press of the gas at the operating temp of the system, then the gas will condense and the gas will exist in both the vapor and liquid phase. Hope that explains it.

 

[quangkhoa90]

You mean the saturation vap press is a specific value at a specific temp, while there is different vap press at a specific temp, and thí vap press is smaller than sat vap press ? Did I get it right ?

 

[quangkhoa90]

FYI,

Our feed fractions are close to this one

http://books.ifpenergiesnouvelles.fr/ebooks/thermodynamics/02/exo_02_04.html

 

[EmmanuelTop]

You have opened a couple of completely different topics within a single thread. Perhaps you should start a new one.

In case you have water in the tower feed, there are several possibilities - it all depends on the amount of water, composition of feed, and operating conditions of the tower:

1) Water may go overhead and condense in the overhead receiver;
2) Water could condense on the tray(s);
3) Water could freeze inside the tower;
4) Water may end up with the bottom product.

Obviously, with so many unknown factors, it is not possible to provide you with a simple, straightforward answer.

As for the second question (operating in the retrograde region), the answers are again not simple - this depends on the amount of condensation as pressure gets lower along the pipeline, abilities of the plant to handle varieties in gas/liquid loads, frequency and intensity of slugging, etc. A detailed analysis of operating scenarios and variation in fluid composition is normally required before one can come up with definite conclusions.

Dejan IVANOVIC
Process Engineer, MSChE

 

[georgeverghese]

Yes, agree with your understanding on vapor pressure vs sat vap press.

We must also account for the water phase flows into the SC - the phase map only accounts for water free hydrocarbon - the flow of the water phase from the pipeline into the SC and out again through the liquid line can depend on many things as you may well know and would be a significant contribution to total liquid outflow from the SC.