8 replies to this topic

[cea]

Dear All-

This referes to oil & gas projects, wherein oil+gas+water phase are received from oilwell head (offshore platform), goes to production separator. The production separator (on attached PFD, it is indicated as test separator) is three phase separator, from where water cut is taken out & oil -gas is again mixed back in sub sea line which is further sent to onshore.

Please find attached PFD for clear understanding.

Now, my query is about a basics of chemical engineering.

Oil wellhead pressure is in range of 1450 psig (100 barg) which is operating condition of test separator too. There is single subsea export line to transfer oil & gas after removal of water.

Since the source pressure for oil & gas phase is same (operating pressure of test separator) & composition of oil phase & gas phase can vary from 0% to 100%, I do not understand how these two phases can be mixed again causing two phase flow in export line. There is no other means to "push" either oil into gas phase or gas into oil phase.

I am looking for concept part of it.

Thanks in advance.
Regards,

Attached Files

•  PFD.pdf   28.76KB   156 downloads

[daryon]

Hi,

The gas exiting the separtor (50-B-01) via the gas outlet will be at the same pressure of the oil exiting the oil outlet of the separator. The pressure in the separtor is maintained by the PCV on the gas outlet (at 100 barg). There will be a pressure drop associated with the PCV on the gas outlet and the LCV on the liquid outlet, but the pressure downstream of both of these valves is dictated by whatever is downstream. For this case it is the resitance of the export pipeline and required arrival pressure at the recieving facility. So the oil and gas downstream of their respctive control valves will be at the same pressure which is the pressure necessary to drive the two-phase mixture down the export pipeline and into the recieving facility. The fluids will commingle as they are at the same pressure and flow along the pipeline.

Remember fluids will always flow from high pressure soucre to low pressure source. As the low pressure source is at the end of the export pipeline both the gas and oil will flow down the pipeline to the recieving facility from the high pressure separator.

[cea]

Hi-

I gave a thought on same aspects as indicated in your explaination. However, here are few concern with respect to it.

Firstly, as I understand your views, control valves at oil service & gas service shall develop sufficient pressure drop to allow both the phases flow together. Am I right in understanding?

If yes, then I would like to indicate that oil flow in export line is turbulent flow. Hence, as long as oil flow exists in the line, I guess, gas cannot enter into it.
Now, if gas is expected to enter, one must see the oil control valve is fully closed. Then only, gas can enter into that export line, causing slug flow. In my opinion, whatsoever is control valve pressure drop one provides to gas side, it doesnot matter for achieving two phase flow as long as oil side control valve is open.

If you agree to me, we can further discuss the case when oil/gas ratio is ~60/40. Because in this case, closing of oil side control valve is not expected unless control valve itself is oversized.

The intention of putting my views is just to keep the discussion on same wavelength. In case, if you have different opinion, we can discuss on that line.

Thanks & Regards,

[daryon]

Hi again,

I don't think I have quite got the point i'm trying to make across...so let me elaborate.

I am assuming that the export pipeline downstream arrival pressure is fixed, let's say 10 barg.

The controls valves (CV) are used to conrtol the conditions in the separator not downstream. So the PCV opens and closes to maintain the set pressure in the separator (100 barg) and the LCV modulates the oil level in the separator to maintain the total separator liquid level at the set point (say 50% full). The pressure downstream of the CVs is determined by the required arrival pressure onshore and the back pressure built up in the export line. This pressure will vary with flowrate, higher flowrates will result in larger frictional losses in the export line and a higher pressure downstream of the CVs.

The pressure drop across the CVs will vary depending on the production rates from the separator and how much fluid is flowing down the export line. For example at high flowrate say 600 m³/h the pressure drop along the export line may be say 30 bar and the required arrival pressure is 10 barg. You would therefore have 40 barg downstream of the separator control valves (this assumes there is no additional backpressure being applied at the recieving end to limit the flowrate into the facilities). If the production drops off and the flowrate decreases to 200 m³/h you might only have a 5 bar pressure drop along the flowline so the pressure downstream of the CVs will be lower, 15 barg.

As the pressure of the oil leaving the separator drops across the LCV it will flash and a gas phase will form. You will have 2-phase flow imediatley downstream of the LCV (and inside it...so design it for flashing flow), becasue the oil leaving the separator is in equilibruim with the gas phase and therefore any isothermal pressure drop will result in a gas phase forming. The pressure between the 2-phase stream downstream of the LCV and the gas downstream of the PCV will be equal and the streams will quite happily mix.


This is my understanding of your system. I hope i am not misinforming you, but i don't see any problems with the system set-up. Hopefully some other forum memebers will share their veiws

[cea]

Hi again,

I don't think I have quite got the point i'm trying to make across...so let me elaborate.

I am assuming that the export pipeline downstream arrival pressure is fixed, let's say 10 barg.

The controls valves (CV) are used to conrtol the conditions in the separator not downstream. So the PCV opens and closes to maintain the set pressure in the separator (100 barg) and the LCV modulates the oil level in the separator to maintain the total separator liquid level at the set point (say 50% full). The pressure downstream of the CVs is determined by the required arrival pressure onshore and the back pressure built up in the export line. This pressure will vary with flowrate, higher flowrates will result in larger frictional losses in the export line and a higher pressure downstream of the CVs.

The pressure drop across the CVs will vary depending on the production rates from the separator and how much fluid is flowing down the export line. For example at high flowrate say 600 m³/h the pressure drop along the export line may be say 30 bar and the required arrival pressure is 10 barg. You would therefore have 40 barg downstream of the separator control valves (this assumes there is no additional backpressure being applied at the recieving end to limit the flowrate into the facilities). If the production drops off and the flowrate decreases to 200 m³/h you might only have a 5 bar pressure drop along the flowline so the pressure downstream of the CVs will be lower, 15 barg.

As the pressure of the oil leaving the separator drops across the LCV it will flash and a gas phase will form. You will have 2-phase flow imediatley downstream of the LCV (and inside it...so design it for flashing flow), becasue the oil leaving the separator is in equilibruim with the gas phase and therefore any isothermal pressure drop will result in a gas phase forming. The pressure between the 2-phase stream downstream of the LCV and the gas downstream of the PCV will be equal and the streams will quite happily mix.


This is my understanding of your system. I hope i am not misinforming you, but i don't see any problems with the system set-up. Hopefully some other forum memebers will share their veiws

Thanks Daryon for your elaborated answer.
I got your point.

However again there is small doubt remains in my mind. As indicated by you
" As the pressure of the oil leaving the separator drops across the LCV it will flash and a gas phase will form. You will have 2-phase flow imediatley downstream of the LCV (and inside it...so design it for flashing flow), becasue the oil leaving the separator is in equilibruim with the gas phase and therefore any isothermal pressure drop will result in a gas phase forming. The pressure between the 2-phase stream downstream of the LCV and the gas downstream of the PCV will be equal and the streams will quite happily mix"

So, I agree, that if two phase exists at LCV down stream, definately it shall accomodate vapor flow from PCV. However, for two phase to exist at downstream of LCV, there has to be considerable pressure drop at LCV.

Considering export line of 30 km (as in the case), control valve (LCV) pressure drop may be in the range of 10 bar. As indicated in composition, 99% is n-hexane in liquid phase. Considering these conditions, flashing at LCV outlet is not expected. (Please note that all lighter component like CO2, H2S, CH4 are getting removed at separator in vapor phase. However, there are few light components, such as H2S, ethane are indicated in liquid phase, which are in the range of about 1% that may flash at LCV).

Summerising all above points, I would like to know two things.
1) I agree to your views, provided the phenomenon, that you mentioned really occurs. I am looking for some reference, where the same scheme was implimented & your experience about the phenomenon that is mentioned by you.
2) As indicated, I do not envisaged any flashing at LCV. In that case, how do you see the scenerio?

Regards,

[daryon]

QUOTE:
"Summerising all above points, I would like to know two things.
1) I agree to your views, provided the phenomenon, that you mentioned really occurs. I am looking for some reference, where the same scheme was implimented & your experience about the phenomenon that is mentioned by you.
2) As indicated, I do not envisaged any flashing at LCV. In that case, how do you see the scenerio?"



1) This scheme is commonly applied on offshore well head platforms. It is common to have a test separator on the platform for testing and determining flowrates of gas and liquid from the producing wells. This can be done using a multiphase flowmeter, but i don't think they are generally trusted as accuracy is poor. So it is more typical for a separator to be installed to separate liquid and gas route them through single phase flowmeters proir to recombining them and routing them to the production facilities. I have an example P&ID but can't really post it here as it belongs to another company. Give me your email address and i'll send it to you for reference.

2) I definatlety think you will have flashing flow. The liquid leaving the separator is in equilibrium with the gas phase at the separator conditions, and as soon as the pressure reduces some gas will be liberated from solution. I can't say for certain without a composition and performing flash calculations but i'd be surprised if an oil leaving a 3-phase separator does not flash when the pressure is droped downstream. I bet you 10 Ringgit it flashes!

One more thing... even if the the oil/water downstream of the LCV is single phase the gas will still enter the export pipeline. If, like you suggest the gas cannot enter the pipeline because the line is liquid filled the pressure in the gas line will start to build slightly. There will be a small pressure differential between the gas and liquid and this will force the gas into the export line.

[cea]

QUOTE:
"Summerising all above points, I would like to know two things.
1) I agree to your views, provided the phenomenon, that you mentioned really occurs. I am looking for some reference, where the same scheme was implimented & your experience about the phenomenon that is mentioned by you.
2) As indicated, I do not envisaged any flashing at LCV. In that case, how do you see the scenerio?"



1) This scheme is commonly applied on offshore well head platforms. It is common to have a test separator on the platform for testing and determining flowrates of gas and liquid from the producing wells. This can be done using a multiphase flowmeter, but i don't think they are generally trusted as accuracy is poor. So it is more typical for a separator to be installed to separate liquid and gas route them through single phase flowmeters proir to recombining them and routing them to the production facilities. I have an example P&ID but can't really post it here as it belongs to another company. Give me your email address and i'll send it to you for reference.

2) I definatlety think you will have flashing flow. The liquid leaving the separator is in equilibrium with the gas phase at the separator conditions, and as soon as the pressure reduces some gas will be liberated from solution. I can't say for certain without a composition and performing flash calculations but i'd be surprised if an oil leaving a 3-phase separator does not flash when the pressure is droped downstream. I bet you 10 Ringgit it flashes!

One more thing... even if the the oil/water downstream of the LCV is single phase the gas will still enter the export pipeline. If, like you suggest the gas cannot enter the pipeline because the line is liquid filled the pressure in the gas line will start to build slightly. There will be a small pressure differential between the gas and liquid and this will force the gas into the export line.

Thanks for your convincing answer & time spend for me.
Regards,

[ashetty]

Dear All-

This referes to oil & gas projects, wherein oil+gas+water phase are received from oilwell head (offshore platform), goes to production separator. The production separator (on attached PFD, it is indicated as test separator) is three phase separator, from where water cut is taken out & oil -gas is again mixed back in sub sea line which is further sent to onshore.

Please find attached PFD for clear understanding.

Now, my query is about a basics of chemical engineering.

Oil wellhead pressure is in range of 1450 psig (100 barg) which is operating condition of test separator too. There is single subsea export line to transfer oil & gas after removal of water.

Since the source pressure for oil & gas phase is same (operating pressure of test separator) & composition of oil phase & gas phase can vary from 0% to 100%, I do not understand how these two phases can be mixed again causing two phase flow in export line. There is no other means to "push" either oil into gas phase or gas into oil phase.

I am looking for concept part of it.

Thanks in advance.
Regards,

[ashetty]

Pressure Balance for this case:

Vessel Pressure - lineloss = PV inlet Pressure
Vessel Pressure + Static head - lineloss = LV inlet Pressure
Vessel Pressure is same for both cases

Onshore terminal Pressure + Line loss + equipment loss (If any)+ static head = PV & LV Outlet pressure
The rest of the pressure is consumed by the control valves (PV & LV).For all pracical purposes pressure at LV & PV outlet would be same and the flow of both is dictated by downstream pressures.

As long as the vessel is operating at a higher pressure than downstream conditions there is no issue with flow of either liquid or gas.
In case of higher back pressures the % opening of the valve will vary....In the case where backpressure at control valve outlet is so high that even when valve is fully open no flow is possible, then a trip will be initiated on high-high level or high pressure.

Remember....the function of the control valve is to balance the pressure in the system by varying the flowrate.

Hope this helps.