Downhole vibration tools are becoming an accepted method of extending the reach of coiled tubing (CT) and jointed pipe (JP) in extended reach wells. They are being used in both well service and well drilling operations. Experimental work was done which shows how the energy generated by dynamic excitation mitigates a certain amount of friction. A tubing forces (torque and drag) model was modified to include friction mitigation due to the vibration. This modification to the model was much more complex than simply modifying the friction coefficient as has been done in the past. This paper will discuss the experimental work, the modifications to the model, and case histories in which a vibration tool was used. Model results will be compared to actual field results.


When significant compression is applied to a CT string, it helically buckles in the wellbore. Once helically buckled, additional wall contact forces 1 (WCF) are caused by the buckling. These additional WCF cause increased friction between the CT and the wellbore. This friction increases exponentially with the compressive force in the CT until no additional force can be transmitted downhole. This situation is known as helical lockup.

Figure 3 shows the exponential nature of the increase in WCF when a CT string is helically buckled. The dashed lines represent the WCF due simply to the weight of the CT, in pounds per foot. The solid lines represent the WCF due to helical buckling for various compressive axial forces. When the axial force reaches the helical buckling load (HBL), the additional WCF due to buckling far exceeds the WCF due to weight.

The following methods have been used or considered, to extend the reach in a well or to increase the WOB for slide drilling:

  • Geometry changes - increasing the diameter of the string or decreasing the hole diameter is an effective way of increasing the WOB. Increasing the string wall thickness may increase the WOB, especially in vertical wells.

  • Lubricants - various lubricating fluids have been used to reduce the friction coefficient between the string and the well tubulars or the wellbore. These lubricants have been somewhat successful in cased-hole workover applications. However in drilling applications the drilling fluid must turn the downhole motor, maintain pressure control (unless drilling under-balanced) and carry the cuttings out of the hole. It is difficult to design a drilling fluid which will perform all of these functions and also provide significant lubrication.

  • Tractors - downhole tractors are available for some drilling applications. The tractors provide the WOB, so that the string can remain in tension. However, a downhole tractor adds additional deployment logistics, risk and expense.

  • Rollers - various types of rollers have been developed which can be attached to the string and to the drilling BHA. The time and logistics associated with attaching and removing rollers on the string limits their use.

  • Straightening the CT - In the case of a CT string, the CT has residual curvature due to the bending it undergoes on the reel and guide arch. A device which causes a small reverse bend to straighten the CT can be used, so the CT in the well is straight (or nearly straight). This device does not remove the residual stresses. Instead it modifies the residual stresses so that they result in nearly straight pipe. Some work has been done which shows that straightened CT can be pushed further in a horizontal well before reaching helical lockup. Other work has shown that the maximum WOB provided by straightened CT is the same as the maximum WOB provided by curved CT. Thus the benefit of straightening appears to be inconclusive. It is clear that straightening CT exacerbates the fatigue damage.

  • Vibration - downhole tools that dynamically excite the drill string have been utilized to decrease friction, which improves ROP through better transfer of weight to the bit, and increases the reach in high angle wells. This method of friction reduction is the focus of this paper.

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