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3 Phase Flow In Pressurized Pipeline

3 Phase Flow In Pressurized Pipeline

3 Phase Flow In Pressurized Pipeline

(OP)
I don't know if this is the correct place to post this or not, if not I apologize.

We have a potential project for controlling the pressure in a petroleum pipeline. The pipeline transports 3 phase flow (oil, water, and gas) from the wells to a degasser. The pressure measurement is right before a control valve that goes into the degasser. After much research, thought and making a very crude pipeline model, it seems the pipeline pressure is really a function of the gas volume (or the gas/liquid volume ratio) in the pipe. My question is this: since the oil/water is incompressible, is the pipe pressure a function of the surface area of the gas or the surface area of the inside of the pipe?

RE: 3 Phase Flow In Pressurized Pipeline

that might be the case for a closed container, but you are describing an open system under flowing, non-equilibrium conditions.





RE: 3 Phase Flow In Pressurized Pipeline

The pressure drop is dominated by the amount of work that the gas has to do to the liquid. Everything else is secondary until you get to very high gas velocities (usually around 0.25 Mach) when friction starts dominating drag. Take a look at the Duckler Method in the GPSA Field Data Book.

David Simpson, PE
MuleShoe Engineering

"Belief" is the acceptance of an hypotheses in the absence of data.
"Prejudice" is having an opinion not supported by the preponderance of the data.
"Knowledge" is only found through the accumulation and analysis of data.
The plural of anecdote is not "data"

RE: 3 Phase Flow In Pressurized Pipeline

The pressure coming from the well to the separator is basically a function of the well head pressure available and the choke valve setting next to the well christmas tree as, first, that is the pressure available to drive the flow through the pipeline. The pressure at the degasser is dependent on the force necessary to get the fluid from the well to the degasser, which will be dependent on the friction resistance against whatever amount of flow that happens to be at the time. A high fluid flowrate, whether it is composed of gas, liquid, or water, one, two, or all three, through a small diameter pipe, especially of long length, will produce a large frictional pressure drop, thus leaving little pressure at the degasser. The same large flow through a large diameter pipeline, especially of short length, can leave a high pressure at the degasser inlet. The highest pressure you might see at the degasser might be when the control valve at the degasser is closed and there is no flow in the pipeline. Such a situation could lead to the full well head pressure to be transmitted to the degasser, and even more pressure, if the pipeline was going downhill from the well site to the degasser, with the highest pressure most likely if the pipeline was full of mostly water. In that case the highest pressure would be equal to the well head pressure (at the well head before the choke valve, i.e. the well shut-in pressure) + density of water times the elevation difference between the well site and the degasser site.

Independent events are seldomly independent.

RE: 3 Phase Flow In Pressurized Pipeline

Calculating pressure drop in a multiphase pipeline is complicated and to some degree guesswork.

Schlumber (who now owns the OLGA model) and Tulsa university sits with some of the better models.

Try contacting professionals if this has any design and/or operational implcations.

Best regards,

Morten

RE: 3 Phase Flow In Pressurized Pipeline

(OP)
Wow, thanks for all the responses! Just so I can have a better understanding of this type of flow and pipelines in general, if I wanted to increase the pressure at the degasser, the amount of flow increase from the positive displacement pumps at the wells is a function of:
  1. Amount of pressure available at the well
  2. Increased friction in the pipeline
  3. Volume of compressible gas in the pipeline
The goal of this project is to control total oil flow, which is a function of the pipeline pressure, so finding the process gain and transport delay for the pipeline is really what I'm after. Both of these values will need to be adaptable based on the conditions of the fluid in the pipeline. This may not be possible to do with the current instrumentation. I wish I had some data to support these ideas, but I haven't been able to get any yet. zdas04, thanks for pointing me to the Dukler Method, very helpful.

Also, to rephrase my original question: I have two pipes that have two phases in them (gas and oil) and are at static conditions. The only difference between the pipes is the volume of gas in the pipe. The gas and oil densities are the same in both pipes. Are the pipes at the same pressure (pressure is a function of the pipe surface area) or different pressures (pipe pressure a function of the surface area of the gas)?

RE: 3 Phase Flow In Pressurized Pipeline

I think we need to get more specific. A diagram might be good, with elevations and distances along the pipeline if you can manage to post one.

Before you said nothing about pumps at the wells. If you have pumps, inlet pressure at the pipelines is a function of the pump discharge pressure. Outlet pressure in the pipeline is a function of many other things, mostly the pipe diameter and length and the flowrate you are moving through it. Elevation of inlet and outlet also matter. If your pipeline is static, usually meaning you have no, or zero flow at the time, then you will have no pressure reduction between inlet and outlet from friction of the fluid moving down the pipe. Forget about volumes of gas and surface areas of pipe, for the time being.

I will repeat.
Friction is proportional to flowrate and more flowrate = more friction in the pipeline and that reduces the pressure at the degasser. Lower flowrates will not have so much friction and the pipeline outlet pressure, degasser inlet pressure will be higher, when flowrates are lower .... assuming pump discharge pressures stay the same.

Generally the more gas you have in the pipelines, flowing, the friction loss is not so great as if you tried to flow all oil and the resulting degasser pressures would normally expected to be higher as gas flowrates increase and oil flowrates reduce.

If you wanted to get a range pressures at the degasser, calculate one pressure loss in the pipeline with 100% oil at maximum flow. That would normally result with the lowest pressure at the degasser. The highest pressure at the degasser would normally result, when pipelines are flowing, with maximum gas flowrate in the pipeline. The highest maximum possible pressure, in a flat pipeline, is with no flow and choke valve open. Then the degasser could experience pressures as high as well shut-in pressure.

Total oil flow is not a function of pipeline pressure. Total oil flow and gas flow too are the result of what the well is delivering. Anything else is not a steady state flowrate, which may vary by how much liquid and gas is in the pipeline at any given time, the elevation profile, the ratio of oil to gas volumes and the speed of the flow in the pipeline. In a hilly area oil and gas flows both may vary constantly as liquid is held up going up a hill and then accelerates going down the hill, etc. It's just like a soap box racer on a mountain road.

"I have two pipes that have two phases in them (gas and oil) and are at static conditions."
You have two pipelines. Gas phase in one? Oil phase in other? Or gas phase and oil in each pipeline?

"The only difference between the pipes is the volume of gas in the pipe."
Pipe is one pipe. Pipe or pipes?
How much gas in each one do you have? A lot in one and a little in the other?


"The gas and oil densities are the same in both pipes."
Gas density is not equal to an oil's density. That's pretty much impossible. Gas density is usually given in reference to air density. Oil density is usually given in reference to water's density. Do you mean the gases in each pipeline have the same densities and the oil in each pipeline have the same densities?


"Are the pipes at the same pressure (pressure is a function of the pipe surface area) or different pressures (pipe pressure a function of the surface area of the gas)? "

That will depend on if the pipeline pumps are the same, the flowrate is the same, the gas and oil content are the same in each pipeline, each pipeline is the same, temperatures are the same and any liquid is in the same position and at the same elevation in both pipelines all at the same time. DON'T COUNT ON THAT ONE. It is more likely that one pipeline will be at high discharge pressure while the other could be at lowest pressure. They do not have to be the same. Some oil may be going up hill in one pipeline while the oil in the other pipeline is going downhill. If that is the case there will be different pressures at the outlet.. possibly very different, even if pipeline pressures are the same, and flowrates at the wells are the same. Two phase flow can be very, very much different than one phase flow, even if both pipelines are very much the same.

Independent events are seldomly independent.

RE: 3 Phase Flow In Pressurized Pipeline

Here's a link to a Wolverine Tubes paper that will explain a lot more than I know about what's going on in there.
http://www.google.ae/url?sa=t&rct=j&q=&...

Independent events are seldomly independent.

RE: 3 Phase Flow In Pressurized Pipeline

(OP)
Thanks BigInch, I'll need to digest what you're saying and study the tube paper. I can see that I was not clear with stating my original question. It's more a thought experiment to see if I understand the basic principles. I'm a newbie with two-phase flow and pipelines, more used to dealing with steam. I'll include a picture to help clear it up too:

Two identical pipes (same ID and length), same elevation, each of them has two phases in them. They are both static, and they are both pressurized. The gas and oil content (by volume) are not the same in each pipeline, but the gas density is the same in pipe one as pipe two and the oil density is the same in pipe one as in pipe two. The temperatures are also the same.

Is the pressure the same in each pipe (pressure is a function of the pipe surface area) or different (pipe pressure a function of the surface area of the gas)?

RE: 3 Phase Flow In Pressurized Pipeline

What pressure are you talking about? If you are controlling pressure at the degasser then the pressure at the degasser is whatever you control it to. The question that is interesting is "how are the dP in the two lines different?". In a significant gas flow scenario, you will probably have a higher dP in the line on the left. I know that seems a bit counter intuitive, but as I said above, the dP will be dominated by the amount of work the gas has to do to drag the liquid along. In the line that is more full it takes less work to force the liquid to fill the line and launch a slug, so you get a lower dP. Surfaces really don't matter, it is fluid interaction that dominates.

David Simpson, PE
MuleShoe Engineering

"Belief" is the acceptance of an hypotheses in the absence of data.
"Prejudice" is having an opinion not supported by the preponderance of the data.
"Knowledge" is only found through the accumulation and analysis of data.
The plural of anecdote is not "data"

RE: 3 Phase Flow In Pressurized Pipeline

The absolute volume of gas or oil in the pipe is relatively unimportant. That will change along the pipeline with the elevation profile anyway. More important is the gas to oil flow ratio at the wells, pipe diameter, length and elevation profile.

We've pretty much told you all we can up to this point and you still don't seem to grasp the importance of gas to oil flow rations and elevation profiles. I'll now suggest you start reading and, once you've got that down, ask some more specific questions.

Independent events are seldomly independent.

RE: 3 Phase Flow In Pressurized Pipeline

OK, I'll have a go.

"Is the pressure the same in each pipe (pressure is a function of the pipe surface area) or different (pipe pressure a function of the surface area of the gas)? "

Err pressure is pressure, i.e. force per unit area and applies equally all the way around any given point. it has NOTHING to do with the relative amount of gas or liquid in the pipe.

"since the oil/water is incompressible, is the pipe pressure a function of the surface area of the gas or the surface area of the inside of the pipe? " NO, nothing whatsoever to do with it.

I hope you read what has been written by the posters above - they are very knowledgable.

Please be very careful when looking at two or three phase flow to realise that densities and volumes of the gas are usually stated in standard conditions, where as what is in your pipe is constantly changing in ACTUAL density and flow.

From my experience, what you want to aim for is an ACTUAL gas veleocity of 3 to 5 m/sec at the end point which lets the gas drive the fluid along quite well, but doesn't get too fast so you have lots of friction losses and not too slow so you have a lot of slugging. It seems a bit odd, but sometimes you actually need to increase the arrival presusre to get more liquids down the line.

To be honest, you can spend a long time analysing systems like this, but if you have the opportunity, just do some paractical experiemtns changing one thing at a time, such as arrival pressure, let it settle down for a while then take some flow measurments and change it to another figure. You'll find out more about your actual system this way than any analysis and thinking about it...

My motto: Learn something new every day

Also: There's usually a good reason why everyone does it that way

RE: 3 Phase Flow In Pressurized Pipeline

LittleInch,
There has been some really good experimental work done in the last 10-15 years that supports your 3-5 m/s number as being a sweet spot in gas flow with incidental liquid. I would guess that the amount of liquid in the OP's system would drive him towards lower velocities in the experiments you recommend.

David Simpson, PE
MuleShoe Engineering

"Belief" is the acceptance of an hypotheses in the absence of data.
"Prejudice" is having an opinion not supported by the preponderance of the data.
"Knowledge" is only found through the accumulation and analysis of data.
The plural of anecdote is not "data"

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