Job planning considerations, including coiled tubing forces, can be critical factors for the type of equipment and the associated risk of a wellbore entry. This paper presents estimated and actual values and explains the useful range of friction factors associated with the wellbore geometry. Emphasis is placed on the situation where equipment and tubular capabilities are close to safe operating limits. Operational alternatives are discussed which can help manage the risk and aid contingency planning.


  • Operations plan to perform acid stimulation using 1.75" OD QT900 coiled tubing

  • Estimated forces were 34,000 lbs at TD of 15,400’ MD (with flowing well and brine in CT)

  • Survey shows average DLS of 1.25 down to 15,000’ with a maximum of 4.3 DLS at 8600'

Show excel plot of well trajectory in 3D for azimuth change

  • Wellbore entry with periodic weight checks up to maximum of 58 Mlbs pull at 12000'

  • Attempted loading the well with fluid to increase buoyancy without success.

  • Used friction reducer mixed at 5% by volume to decrease friction, but obtained only 10% reduction (or 7 Mlbs).

  • Well entry planned with new friction factors to match the actual weight checks and using QT110 CT with friction reducer.

  • Not many wells with this type of azimuth change in the BP data set.

  • Should consider this limit to well servicing during drilling operations

  • Low IPR did not justify another cleanout attempt, but perforated upper intervals instead.

Need data from follow up operation (if any) to show the effect of change in planning procedure.

Possible mathematical factor applied to azimuth change to increase friction factor for future CT force estimates.


Estimated forces to be encountered during CT operations is a critical part of job planning in wells with high angles and tortuous trajectories. In order to have meaningful force estimates, the modeling software needs to be validated with historical information for wells with similar wellbore paths and depths. This will help provide consistency in the friction factors used to determine the forces. Fatigue life of the particular string is combined with the force estimates and estimated pressure profile to identify the limit of its use with respect to the particular CT reel.

The overall objective of this exercise is to manage the risk associated with the well entry by selection of equipment appropriate for the operation and balance that with the economic life of that same equipment and the cost of the completion. In most areas of operation, the coiled tubing reels are owned and managed by the service company and create a significant portion of the revenue from its useful life. However, in the case of operations in the Casanare Field in Colombia, BP purchases the CT reels used by the service company in an effort to minimize extended fatigue life by controlling that investment. The ultimate goal of this alternative is to prioritize the relatively high cost of completions in planning well interventions by retiring those reels at an earlier point in the useful life than would otherwise be the case. As a guideline, the reels are retired between 400 M and 500 M cumulative running footage which is equivalent to 20% to 40% of its predicted fatigue life. Although this is a conservative approach to use of a coiled tubing reel which has a landed/installed cost of approximately $80 M in the Casanare field, it is considered effective insurance for well interventions in completions that cost an average of $30 MM.

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