8 replies to this topic

[amirentezari.k]

what is the definition of water cut in oil reservoir

[vikramltv]

The ratio of water produced compared to the volume of total liquids produced.

[amirentezari.k]

thank u vikramltv
but at which temperature and pressure? T & P stock tank ? T & P reservoir?
when they say water cut is 25%,they mean at which condition?

[ankur2061]

amirentezani,

Water cut can be measured at the following:

1. Well testing: At the liquid outlet of a test separator

2. Individual Well monitoring

3. Group production facilities

4. Dewatering from FWKO and stock tanks

It depends on where you want to measure the water cut

Refer the link below for water cut measurement using red-eye meters:

http://www.ep-soluti...r-cut_Meter.pdf

Hope this helps.

Regards,
Ankur.

[amirentezari.k]

thank u so much ankur2061
employer give me dry basis mole fraction of oil reservoir composition and said for material selection and design of wellhead paltform facility add 25% water .
i dont understand in which condition i should add water cut?! reservoir condition is 206 barg and 109 C and the stock tank condition is 1 barg and 15 C

there is another question
demulsifier chemical agent inject to test header in offshore platform to improve and help the separation water and oil in the test separator,i know demulsifier injection usage in test header,i cant understand why demulsifier inject to production header too,what is it's usage in production header?is it because of multi phase flowmeter that installed in production header?
thank u for ur reply

[paulhorth]

Amirintezari,
I'm sure that the 25% water is a ratio of water VOLUME to (water plus stock tank oil) VOLUME at stock tank conditions. Though it does not make much difference if you calculate it at bottom-hole conditions, especially when you consider that the 25% is not accurate, just a rough guess. Reservoir people only work with volumes, and usually stocktank volumes.

So here is how i suggest you do it - I assume you have access to a process simulation tool.

• Take 1000 kmol/h of the dry basis wellstream and flash it at stock tank conditions.
• Read off the stocktank barrels/day of the liquid stream
• You now have the ratio of stocktank barrels to wellstream kmols, which is important as a basis for the material balance.
• Calculate the water volume barrels/day to yield 25 vol % water in (water plus oil), that is, one barrel water to three barrels oil.
• Convert this water flow to water kmol/h, which will be added to the dry basis wellstream
• Now add some water to saturate the stocktank gas. This will be a small quantity, allow 2 mol% of the stocktank gas flow from the flash.
• Multiply the dry basis wellstream and the water by the ratio calculated in (3), for the oil production barrels/day that you want. This is your wet basis molar wellstream flowrate.
• Run this through the simulated stocktank flash to check the water cut in the stocktank liquid is correct.

Paul

[vikramltv]

amirentezari.k
You must be having reservior condition and Oil & Gas flow rates at stock tank condition.
Now 25% water cut at this point ussually means at stock tank condition as you must know the amount of water at stock tank condition to reach to actual flow line condition.
So calculate the amount of water at STC with 25% water cut.
I presume you have access to simulation software (Hysys)
Now you have to reach to actual flow line fluid specification & properties.
Follow the steps.
1. Creat a stream with dry basis molar composition. Assume any flow rate.
2. Put it in to separator and get gas and oil phase.
3. Install tee operation to gas as well as oil stream. an get streams say gas req., gas balance & liq. req, liq bal.
4. mix liq. req.& gas req. wil water of any assumed flow rate.
5. apply flashing follwed by heat exchanger operation and bring it to stock tank condition.
6. input this stream to 3 phase separator.
7. you will get the gas , liquid and water flow rate at outlet condition.
8. Now apply adjester operation at gas req. stream flow rate, oil req flow rate and water flow rate specified in step-4 to to get the known value of gas, oil & water flow rates respectively.
9. Now the stream just after the mixing operation (step-4) gives you the actual flow line characteristic.
I hope it will help you..

Edited by vikramltv, 22 February 2012 - 04:51 AM.

[amirentezari.k]

vikramltv & paulhorth

thank u so much it works absolutely

could u please explain demulsifier chemical agent usage in offshore platform?

[vikramltv]

MPFM is usually installed in test header along with test separator as bypass, and it does'nt need demulsification prior to it.
Demulsification is added to production header to ease the separation process of oil and water breaking the oil & water emulsion. otherwise it will need a greater temp. to atain more than 50 % separation. Well head platforms does'nt need demulsification rather Process platforms & FPSO has it before separators.