Relationship between Casing and Tubing Pressure? 1

[bdub4]

Can someone please explain the relationship between casing and tubing pressure? I am trying to understand what to take from the data once a new well is brought on production.

ie) A well begins flowing after a frac (all load fluid). Tubing pressure is at 640 psi and casing is at 750 psi. Tubing pressure decreases to 60 psi, and then once oil begins to flow, steadily increases to 550 psi before decreasing as the well dies. Meanwhile, the casing pressure increases from 750 psi to 1100 psi, and then decreases until its bled off at around 500 psi.

I am trying to understand what the pressure increases and decreases on the tubing/casing are indicating and the significance of each.
Thank You

 

[blacksmith37]

Not my area, but I am sure there are books written on the subject.

 

[zdas04]

This is simply not magic. It is fluid dynamics.

Having said that, you know that at the downhole entrance to the tubing the tubing pressure is the annulus pressure, right? They have to be equal because they are the same thing.

For a flowing well with the annulus shut, tubing pressure is BHP minus height of any fluid column in the tubing minus fluid friction in the tubing. Casing pressure is BHP minus any fluid column. If the fluid columns in the tubing and casing are the same (which is certainly not assured), then the difference between tubing pressure and casing pressure is fluid friction. The 60 psig (I'll assume psig since you didn't differentiate, it is a REALLY bad idea not to differentiate) tubing point is just the point where the reservoir pressure was greater than the fluid head. When the casing was 1100 psig and the tubing was 550 psig, my guess is that reservoir gas had bubbled through the fluid column in the annulus and reduced the fluid column substantially (probably not to the very end of the tubing, but close). At that point if the well died at 550 psig tubing pressure I would say that (with 0.8 SG fluid) you have around 1600 ft of fluid in the tubing and nearly zero in the casing.

If you are not flowing, then any difference in the tubing and casing is a static head difference. For your first data point (casing 750 psig, tubing 640 psig) the well isn't flowing so if you have a 0.8 SG fluid the difference in height is 319 ft.

This is really basic stuff.

David

 

[bdub4]

Thanks that helps.