Abstract
The introduction of rotary steerable tools1,2 (RST) has drastically changed how the drilling industry plans and executes directional drilling projects. These tools address most of the technical and operational limitations, which previously hindered directional drilling efficiency. With RSTs, changes to wellbore trajectory are made while the drill string is in continuous rotation. This advantage improves wellbore quality, hole cleaning and Rate of Penetration (ROP). It also reduces well bore tortuosity, torque and drag, and eliminates the harmful effects of "negative weight on bit", especially on extended reach3 (ERD) programs.
The benefits listed above can only be achieved if RSTs are used with appropriate bits4,5,6 . The development and/or selection of the "right bit type" for an RST application is "not as simple as perceived". This is due to the numerous technical issues - functional challenges, stabilization requirements and operational compatibility - that have to be addressed. To achieve technical and economic success, bits used with RSTs must also address expected formation drillability issues7 , in terms of their ROP and durability.
PDC bits exhibit most of the characteristics needed to establish efficient partnerships with RSTs, especially their structural reliability and ROP potential. These attributes are further enhanced by the "absence of slide mode drilling", due to the continuous rotation of the drill string.
This paper will characterize the technical issues associated with the PDC/RST combination, and show how "appropriate PDC bits" address them. It will draw distinctions between bit aggressiveness (BA) and bit instability (BI), and demonstrate how these parameters are affected by well profile specificity and dog-leg (DLS) requirements. In addition, it will identify and evaluate the requirements needed to ensure operational effectiveness on PDC/RST operations. Several field examples will also be discussed.
