The completion of wells with large diameter coiled tubing (CT) is a new addition to the scope of well services that can now be performed by coiled tubing units. (CTU's) This paper will detail the equipment necessary to perform an operation of this type and will share information from several case studies in Oman in which an operator has successfully deployed completion equipment on 3-1/2-inch-OD coiled tubing. In addition to a discussion of the equipment required to perform the necessary operations, the trial parameters that were established by this operator will be presented along with a review of the eight completions that have been successfully installed to date.

The summary of completion events will conclude that this innovative technique can provide a viable method for completing wells. Although long-term advantages regarding production and well maintenance cannot yet be determined for the subject wells, the experiences so far have indicated that use of coiled tubing in large continuous-pipe applications has the potential to provide a cost-effective deployment alternative.

The information presented has been chosen to allow an initial evaluation to be made of coiled tubing completions in general and will help the reader determine whether this method can prove to be competitive and economical compared to traditional rig-based completions.


The introduction of larger-diameter, higher-yield-strength coiled tubing presented the possibility to a major Middle East operator that a method for deploying completion equipment might be available that could eliminate the need for conventional rig intervention. The operator was of the opinion that if completion equipment could be successfully deployed using CT methods, greater cost efficiency, both in initial deployment and in well maintenance, could be derived. Following are the technical considerations for these assumptions:

  1. Coiled tubing units are smaller, therefore more mobile, requiring less infrastructure and office-based support. The mobility of a coiled tubing rig is particularly significant for an electric submersible pump completion. If a pump goes down, a rig cannot be called to location the next day to change it; however, a coiled tubing unit can be called out on little or no notice, allowing the well to be put back on production in a shorter time frame.

  2. The problems inherent to rig unavailability would be eliminated as scheduling for a coiled tubing operation would be less demanding and would allow greater operational flexibility.

  3. Nonjointed pipe might offer improved well flow performance.

  4. Actual completion time with coiled tubing should be faster.

  5. Completions with coiled tubing should be easier.

  6. CT has the potential to avoid reservoir impairment by completing in underbalanced conditions.

  7. Well re-entry life-cycle costs might be reduced since a smaller coiled tubing can be installed for remedial purposes in a 3-1/2 inch-OD tubing. Additionally, fewer wireline problems are expected with a smoother tubing wall finish.

  8. The jointed pipe used in a conventional completion has potential leak points at the collars; these are eliminated with the use of continuous pipe.

  9. The reservoir fluids produced in these fields are corrosive, and nonjointed pipe could reduce failure from corrosive influx by elimination of turbulence at collars where corrosion is concentrated.

  10. In addition to providing faster installations and removals than a comparable rig-based operation can provide, one-day workovers could be possible with a coiled tubing string.

To assess the technical merit of this theory, a series of trials employing 3-1/2-inch diameter coiled tubing as the primary completion string was attempted and has now been concluded. A total of eight 3-1/2-inch completions have been installed, four of which were gas lift completions with the remaining four being electrical submersible pump (FSP) completions.

P. 11

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