The coiled-tubing (CT) industry has evolved from using smaller pipes with lower-grade materials to bigger pipes and high- strength materials. However, the offshore installations and equipment still need to catch up with increased weight and handling demands. A tapered outer-diameter (TOD) string is one solution that provides the benefits of larger string while keeping size and weight at manageable levels. This paper presents a study and analysis of using a spoolable connector (SC) to join strings of two different outer diameters (ODs). A TOD string requires an 8- or 10-ft long “transition section” so that the string can pass through specially retrofitted injectors. The transition section is milled, from one diameter size to another, using a cold-working process. This transition section needs to be welded to the two strings and requires a manual butt weld. As an alternative, a transitional spoolable connector is being developed and virtually tested using finite element analysis (FEA), thus eliminating the need for a specially milled, butt-welded transition section. One challenge with TOD-connection systems is that they tend to fail at the butt-weld between transition and core end of string. A 10-ft long SC was designed to transfer this high-strain area away from the transition where it would be less detrimental to fatigue life. SCs for regular pipes have been designed and tested in variety of sizes from 1.5- to 2.875-in. OD CT. The test data provided a base to compare the performance of this new transitional connector. Results from a 2- to 1.75-in. tapered OD string are presented. One complete bending event of a 20-ft long assembly was simulated on a drum using FEA, and results were compared with actual and virtual test data from pipe with SC and a TOD string with transition section.

Tapered outside diameter coiled-tubing (TODCT) systems have distinct advantages in ultra-deep wells (30,000-ft range) Introduced in 2004, the TODCT system includes: (1) 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, (2) an ODT "transition tube" that allows sections of tubing with different ODs to be joined together, (3) well pressure control equipment (i.e., blowout preventer and stripper) with the capability to grip and seal more than one diameter of tubing and also grip and seal the transition tube, and (4) 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 presents a review of the yard testing completed on the TODCT system equipment and then describes a subsequent field trial conducted onshore in south Texas. The end result is a tested and qualified TODCT system capable of safely running tubing strings into ultra-deep wells. Introduction 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 tests, 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.Blowout preventer (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.

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