9 replies to this topic

[herrani]

Hi everybody. I am new at this, so I hope I am posting this properly.

I am trying to separate a liquid stream, with a total flowrate of 60 000 bpd, containg crude oil and water. The water cut changes between 0 and 15% all the time.

Does any of you have any references for which kind of technology I could use? I am thinking in the lines of a gravity settler or a coalescer, but never designed any of those either.

Any help will be much appreciated!

[Andree]

open settler are good, cheap and easy option of removal water at high concentration of water... efficiency however will not be high, especially if water is emulsified (dispersed into fine droplets)... in such situation electrostatic coalescer are quite effective (see attached articles)... classical coalescer (one or two-stage) will not be very effective as crude oil is usually very viscous, the same limits use of hydrocyclones

Attached Files

•  Pipe_separator.pdf   1.4MB   159 downloads
•  Electrostatic_Demulsification_on_Crude_Oil.pdf   527.59KB   191 downloads

[JoeWong]

What is the water spec at the crude oil outlet ? 3000 ppmw water-in-crude is acceptable ? It is a bulk separation ?

[djack77494]

Just in general terms, I'd say start with a simple three phase horizontal separator, assuming the possible presence of some gases with your produced fluids. Both the oil-rich and the water-rich streams will probably require additional treatment to get the final traces of the undesirable phases out. The specifics of treatments are highly dependent on your particular situation, including what you will do with the produced water stream and what is involved in getting the produced oil to market. Your design must be able to handle the extremes of water cuts expected over the years.

[herrani]

Thanks for your replies.

To answer your questions, the outlet water stream is to be sent to the sea, so it should contain less than 200 ppm of oil. The crude oil has to go through some special equipment, where the requirement is that water content should be less than 0.5%vol.

How can I find out if my crude oil is emulsified? Or about the droplet size distribution for design purposes?

[JoeWong]

My experience is 40 ppmw of dispersed oil. 200ppmw is high... don't you mind to advise the project location ?

Sampling and testing is the way to determine crude oil is emulsified. I doubt calculation is reliable.

There are number of correlation to define Droplet Size Distribution (DSD) i.e Jebson, Ambrosini. Azzopardi, etc. Again these equations are very system oriented. I guess no one is really for general purpose used.

[herrani]

Hi John

You were also right in your remark: I have been looking more into it, and the requirement is 40 ppm of oil instead of 200. Sorry for the mix-up.

I was asking about the droplet size distribution, because we suspect that there might be a high number of small droplets coming into our facilities: there are some 3-phase separators upstream that should do the job, but in practice they can't separate all the water (hence the 15% in my design requirements).

I hope this clarifies the issue.

[JoeWong]

JoeWong here...

I am glad to hear that the level is 40 ppmw instead of 200 ppmw...

What made you suspect the "smaller" droplet will come into you facilities ? What are the different compare to other facilities ?

There are number of way to increases the separation efficiency :
i) Demulsifier injection
ii) Heating to right temperature to break emulsion
iii) Installation of vane type inlet device to minimise turbulence and/or cyclone into 3-phases separator
iv) provide baffle to streamline to the mixtures
v) provide coalescene platepack to enhance separation
vi) increase retention time in the 3-phases separator

May consider hydrocyclone, CPI, electrostatic coalescer in downstream system.

I reserve my comments on the DSD (i am investigating this DSD art now...).

[Andree]

To define droplet size (i.e. average maximum stable size of droplet - to obtain a whole distribution analysis is very complex) you need to know "history" of your dispersion/emulsion. In other words, if it flows through high energy dissipating devices upstream your plant. For example a centrifugal pump is an example of such disitegrator. Based on energy dissipation factor you can estimate droplet size, provided you know the properties of liquids as viscosity, density and especially interfacial tension, which is strongly affected by various chemicals present in a system (natural or added as for example corrosion inhibitors, anti-icing agents, de-emulsifiers, antistatic additives in fuels etc). The are many correlations which enable estimating of the droplet size. Form of these relation is usually a function of Weber number and flow conditions (shear rate or energy dissipation rate)

[herrani]

Hi everyone. Thanks for the replies, and apologize for not coming back earlier.

The situtation is that there are some 3-phase separators already in place offshore, several kms away from my location. They are already using demulsifier, and emulsions have not been detected in the oil. There is some problem in the performance of these separators, since the water content in their outlet stream can be up to 15%. The operations and engineering people argue that this is because the water droplets are extremely small, and cannot be separated from the oil, and that is why I am thinking that I need to use some coalescence packing in addition to my equipment.

I have not seen any sources of flow disturbance in the connecting pipeline (like pumps, flow orifices, etc.); only a turbine flowmeter close to the place where my new equipment is to be installed.