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Mitigation plans for tubing buckling during production
12 May 2020
Dear community,

We would value your opinions, thoughts and comments with regards to mitigation plans for tubing buckling during production.

We plan to drill and complete HPHT and deep multi-lateral gas well with 1 string 2 packer like attached well schematic.
The first priority for this well is to be able to produce from each leg (zone) selectively for the productivity evaluation though the commingle production will be done mostly.  The base plan is to install a sliding sleeve at the junction and a landing nipple at the tubing edge, and to change the production leg by slickline operation (open/close sliding sleeve, set/retrieve plug).  
However, based on the experience of existing wells in this field, buckling is the biggest concern due to the hot produced fluid and it might be difficult to do the slickline operation even after a short period shut-in like ~1week.
The well specifications/conditions are below:
  • Location: Onshore
  • Reservoir Fluid: Gas
  • Reservoir(s) Depth: ~16,000ft
  • Reservoir Temp: ~400degF
  • Wellhead Temp during Production: ~200degF
  • Sliding Sleeve Depth (Inclination): ~15,200ft (40-50 degree)
  • Calculated Tubing Elongation during Production: ~16ft@3-1/2" tubing
We've searched the mitigation plan in terms of completion design and found the followings so far:
  • Install an expansion joint which compensates for tubing movement above the upper packer.
  • Install a large bore system and a long seal assemblies at tubing locator which allows for a floating seal to compensate for tubing elongation or contraction.
  • Complete with a larger size of tubing above the upper packer to help slickline assembly run easier to below the upper packer (the sliding sleeve and landing nipple).
  • Install remote tools (sliding sleeve and valve) and remove slickline operations.
We are still investigating each specification and effectiveness but we'd like to ask you about the followings:
  1. Is there any other mitigation plan in terms of completion design?
  2. Which one is the best practice based on your experience?
It is greatly appreciated if you could advise.
Best Regards,
Hiro
Documents uploaded by user:
Well Schematic.PNG
7 answer(s)
Punch
Managing director Punch Energy Services
Punch Energy Services
Total Posts: 9
Join Date: 24/06/20
Hello Hiro,

Next to the suggestions mentioned I would recommend to check the performance envelope of the tubing connections, some will have a 100% compression rating but there are also connections which have (for example) only a 40% compression rating.

The elongation also seems to be excessive, have you checked?

Hanging off in tension may offer some benefit.

Think, if you can, you shall keep is as simple as you can downhole.

Good luck with the project.

Best regards,

Marcel
udaniyar
Customer Engagement Coordinator
Schlumberger
Total Posts: 7
Join Date: 16/07/16
Dear Hiro,

If you will have possibility to use coiled tubing you can have a look recloseable frac port options which might be operated by shifting tool. but again it depends on your tubing size. As far as I know they are more reliable comparing to SSDs. Deviation might affect as well. This is a gas well which is requiring V0 validation and I am not sure if SSDs are compatible with ISO qualifications. I played with your schematic and changed some sections, please see the attachment. At the end i put bull-nose than frac port #1 below the lower packer. There should be enough rat hole in the tubing below the port to have a place for shifting tool manipulation. I used seal bore packer as a lower packer to sting in with seal assembly of upper completion. You will just need to calculate your tubemove and space out your Seal Assembly NoGo Locator to avoid stinging out during contraction or buckling during expansion.

Best regards,
Daniyar

Documents uploaded by user:
Well Schematic Rev.png
GordonDuncan
Technical Director / Trainer
SPREAD Associates
Total Posts: 10
Join Date: 31/03/20
Hiro,
Further adding to some of the comments.
The SSD if of modern manufacture from a reputable supplier are way more reliable than before and do not pose the issues of opening or sealing as before, the issue is if significant pressure difference across the SSD when trying to open or close may cause problems, damage seals or not reseal.
I believe that if you have tubing of a decent grade and chose to install a 21ft stroke Expansion Joint set at 14/7 you will not have any issues.
Ensure all seals in the Expansion Joint, SSD etc are fully compatible with both well fluids and potential injected fluids

Gordon
ahmedix
Consultant
SPREAD Associates
Total Posts: 15
Join Date: 26/09/13
Dear Hino

Both gentlemen who responded have very valid point. Only you know what production rates you anticipate, the SI pressures, the H2S and CO2 contents, Wt & Grade of tug. and casings exposed to the packer fluid (type &Wt.).

Adding accessories to the prod. string is adding potential leak paths to the TCA. Will there be a SSS valve ?(Usually shallow and exposed to H2S in SI cold mode), Working a SSD at the depth and angle will need luck.floating seals sounds good, I always found them stuck in production mode and a unsafe W/O thereafter. I prefer a single completion (if economically feasible).
Good Luck
ahmedix
cmcandrew
SPREAD Associates
Total Posts: 38
Join Date: 16/08/10
Hiro,
The problem with a lot of these posts, is that there is never quite complete information: hence limited responses because additional info is then fed out later.
But if quiz :  I will pick your second standard option, 3rd and 4th seem daft, and then you will tell me why not ? 
As example, from diagram, I would say look at  set Upper Packer above liner in larger OD casing- but no actual dimensions or depths given
Colin
Hiro
Well engineer
Japex
Total Posts: 4
Join Date: 03/12/19
Dear Gordon,

Thank you very much for sharing your thoughts.

1. The elongation length is calculated based on the Lubinski's equation which considers not only the temperature (described in the attached link) but also the Hooke's law (change in pressure area force), Helical buckling and balooning.
2. Normally we calculate the landing force with considering that A) tubing doesn't move (go up) after shut-in B)tubing doesn't come away from packer even if cold fluid is injected like during acidizing.
3. I guess the advantage of using these plugs is to be able to set the plug wherever we want like inside tubing.  However, in our case we have to set the plug somewhere between upper and lower packers anyway so still we have to overcome the buckling above the upper packer.

Additional advice and discussions are very much welcomed.

Best Regards,
Hiro
GordonDuncan
Technical Director / Trainer
SPREAD Associates
Total Posts: 10
Join Date: 31/03/20
Hiro,
couple of points from your supplied information
1. recalculate the elongation, i do not believe the 16ft, use this link http://www.drillingformulas.com/tubing-length-change-due-to-thermal-load/
ask your completion supply company to also recalculate and compare answers
2. Consider landing the string in compression, we used 20K as rule of thumb per 100 F so in your case 40k
3. i would not use landing nipples and opt for using a plug that does not need a profile, such as NPR (Baker) or Slickplug (weatherford) or Simplug (peak)
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