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.

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