Plugged gaswell tubing buckling due to hydrostatic pressure 1

[h082661]

While running tubing (bull-plugged) into a gas-well I understand the tubing begins to 'buckle' as the hydrostatic increases. My question is; where does this buckling occur as the tubing starts to helix and if you were to anchor the tubing with a packer and open the tubing end (kobe sub or slickline plug) does the area of buckling or severity of it change after the packer is set and the kobe is opened and after the weight transfer has taken place? I have noticed during a TCP well completion with a double grip packer, that after the kobe sub was opened (broke) during the confirmation logging run the wireline was unable to get back out of the tubing, it got stuck just above the packer.

Dave Dalzell
Halliburton Energy Services
Red Deer, AB. Canada

 

[DrillerNic]

Buckling is a response to compressive loads on the tubing, which can be exacerbated by dog legs. So, with the tubing closed, you've got piston forces acting upwards on the tubing plug, drag forces as you run in and so on putting compressive loads on the tubing, while there are tensile forces due to the tubing weight and external hydrostatic with the tubing closed (due to Poisson effect) and so on.

Or, if you run in open, land the hanger, then set a slick line plug and pressure set your packer, then the tubing will be in compression due to the internal pressure on it, which gets locked into the tubing as the packer sets. And then as it heats up due to production it may be in more compression (unless you've got a pre-spaced PBR...).

Usually, the point of maximum compression is just above the packer, (but the point of maximum buckling may be somewhere else, especially if you've got different tubing sizes, weights and connections!), but it may be different for different load cases (as run, pressure test tubing, production, bullhead kill for example) and the only way to find out is by doing a triaxial stress analysis. To do a tri-axial and helical buckling calculation by hand to account for all the different forces acting on tubing is very, very tedious, and it's better done using the various commercially available stress calculation packages- we use WS-Tube from Landmark where I am now, and I've used TDAS from Brother Blue in the past. I'm sure you can get hold of WS-Tube pretty easily at Halliburton!

 

[dangnm]

Thanks for your input "DrillerNic". Although these engineering programs do calculate all the hydraulic forces, I simply would like to visualize the effect, as the Cyberstring (Wellcat) program does not indicate where the buckling is occurring in the work string, during the trip into the well. I believe while the plugged work string is being run into the well at the point where it begins to buckle from upward hydrostatic force will be the bottom third of the workstring,,,maybe? After the packer is set and the temporary plug is removed it is my personal theory that the area of buckling is then located just above the anchor point (packer) where it is decidedly more severe than before the packer was set. Does anyone know this to be true?