Flow Control

[Jriad]

Help. I need some info on wellhead and surface flow systems. I hear terms of 'tubing flow valve' and 'backpressure valve' thrown around. First off would those be the same thing. Are they standard on most gas wells? What kind of configuration should you have if you need to bleed down a well to pipeline pressure but do not want a large reservoir drawdown pressure? Any advice on pdfs or book on gas flow systems would be great!!

 

[DrillerNic]

I understand a BPV as a plug vlave that is set in the tubing hanger to provide a barrier if you want to remove the tree.

 

[Jriad]

Let me clarify/simplify. If you need to draw down pressure to pipeline pressures, where would this be done? Just at the choke? Possible to bring down pressure flowing at 2mmcf/d from 750 pounds to 300 pounds without the worry of waering away the pipeline?

 

[dcasto]

Most wells we connect as a pipeline, we will set a meter run with a control valve on the downstream side of the orifice (or ultrasonic). That control valve will either control the flowrate or the pressurre on the pipeline so as not to exceeded it MAOP. Upstream of the meter, we will put an other valve (MOV)that will shut the well in if the pressure from the well will exceed the MAOP of the meter and pipeline. The well owner/operator is responbible for everything up stream of the MOV. If the producer wants to choke the well, its their responsibility. We question why you would want to choke it unless you have fluid problems or some other resivior issues. Also, the producer may also have to install separation or other equipment.

The MOV may also be activated by instruments that monitor contaminates or BTU content.

This is a typical installation, each pipeline may provide other services or requirements. Just work with them.

 

[DrillerNic]

There are API recommended limits for flow through pipe to prevent erosion. I can't remember which API code though, I'm afraid. Usually you would want to get the FWHP as low as possible (to maximise production), but this may not be possible if your flowline is smaller than your tubing (don't laugh- I've seen it a lot!) and the erosion limits on the flowline are lower than the tubing.

 

[dcasto]

see this:

http://scitation.aip.org/getabs/ser...00122000002000071000001&idtype=cvips&gifs=yes

It's hard to reach an errosional velocity and keep a pressure drop per 100 under 5 psi.

 

[Jriad]

dcasto,

Sorry my knowledge is still limited on the functionality of the wellhead; You question why would you choke the well back? If a well is not choked then what is controlling the backpressure on the perfs? Too much drawdown is not gonna be good for the reservoir.

 

[dcasto]

The pipeline and flow control loop control rate and pressure. You may want to start the well up manually on a choke, but eventually it should be wide open. If the well is low pressure, a wellhead compressure will control the well. I see this all the time, a producer wants the pipeline to lower the pressure and I ask if the well has a choke and they say yes, I tell, open the choke and you'll get an automatic lower pipeline pressure.

 

[Jriad]

But does that affect drawdown across the perfs or does the tubing hanger control that?

 

[dcasto]

The whole system, tubing, line, valves controls it.

 

[DrillerNic]

But you do often want the choke to be in critical flow to isolate the upstream from the downstream- otherwise minor pressure fluctuations downstream will feed through to upstream and visa-versa.

The alst thing you want is to open the choke all the way and suddenly get water coning, especially if it's a stable cone (that won't go away if you then choke the well back!)

 

[dcasto]

That why producers start the wells up manually, to limit in flow of fluids. Once the well is stable, they may leave the choke at 5/64 or what ever. But they come back every day and slowly open as bottom hole pressure is reduced. Now, these are not to huge wells offshore, but typical 6000 foot wells with 100 mscfd to 10000 mscfd.