The concept of a tapered outside diameter coiled tubing system (TODCTS) was first presented in 2004.1 This paper laid out the basic requirements for a TODCT system and the advantages of the TODCTS in ultra-deep wells (30,000-ft range). The TODCT system includes:

  • A modified injector that can handle more than one diameter of tubing and maintain a constant grip on the tubing throughout the length of the TODCT string.

  • A "transition tube" that allows sections of tubing with different ODs to be joined together.

  • Well-pressure control equipment (i.e., blowout preventer and stripper) that has the capability to grip and seal more than one diameter of tubing and can also grip and seal the transition tube.

  • An operator control house that allows remote control of the stripper elements and injector gripper elements to open or close to different diameters of tubing while still maintaining control of well pressures inside the wellbore and grip on the tubing.

This paper continues the work that was started previously. A review of the yard testing completed on the equipment is included along with a subsequent field trial done onshore in south Texas. The end result is a tested and qualified TODCT system capable of safely running tubing strings into ultra-deep wells.


The basic concept of a coiled-tubing (CT) string using more than a single OD was introduced in 2004.1 Using the skills and efforts of an operating company, a service company, and equipment suppliers, a team approach was undertaken to design and develop a working TODCT unit. After extensive testing in both lab and yard testing, the TODCT unit was deployed to operate under field conditions in a well supplied by the operating company. The intent of this paper is to report the results of this testing and discuss future testing and development of TODCT.

Background of TODCT

In current CT operations, the OD of the tubing string has always been constant within a single string of tubing. As a result, CT equipment designers have assumed that the OD would not change significantly within any given string. The following are examples of this assumption made in current equipment designs:

  • Support surfaces for the injector/tubing interface are flat and linear to maintain an even gripping force along the length of the injector/tubing interface.

  • Gripping surfaces for the injector/tubing interface are size-specific. Changes in tubing size require that the gripping surface in the injector/tubing interface be changed to match the size of the tubing.

  • The hydraulic fluid in the cylinders providing gripper force for the tubing string is "locked off" from the rest of the hydraulic circuit during operation. The primary purpose of locking off the hydraulic fluid is to maintain hydraulic gripping force on the tubing string in the event of a loss of hydraulic pressure from the power source. The practice of locking off the oil in the gripper circuit cylinders assumes that during operation of the unit, the cylinders will not extend because of changes in tubing size

  • The practices discussed in the previous example also apply to the stripper circuit because this circuit also uses the lock-off philosophy to maintain pressure in the event of a loss of hydraulic power.

  • Stripper/packer elements are designed to fit a specific diameter tubing (i.e., 1.5-, 1.75-, 2.0-in., etc.). If tubing size changes, it is expected that the stripper/packer element and supporting brass will be changed to match the size of the tubing.

  • BOP slip and pipe functions are sized to fit a specific diameter of tubing. As with stripper/packers, it is expected that a change in tubing size will require a change-out of components within the BOP assembly.

This content is only available via PDF.
You can access this article if you purchase or spend a download.