The evolution of steerable PDC technologies has four key milestones: 1) quantification of bit stability; 2) quantifying hole quality and the negative effects of overly aggressive gauges; 3) addressing tool-face control; and 4) accurately predicting achievable bit-bottomhole assembly (BHA) build rates and hole curvature.

Designing for steerability

A key to maximizing performance of steerable systems is to improve net (or effective) rate of

Figure 1. EZSteer Technology enhances tool face control on a PDC bit. (Images courtesy Hughes Christensen)
penetration (ROP); that is, the amount of footage drilled on target in a given period including all time spent adjusting tool face, restarting after motor stalls and changing the BHA to compensate for sub-optimal directional performance. To improve net ROP, a “steerable bit” must:
• Provide a superior-quality bore hole, free of ledges, with smooth transitions between the slide and rotate modes;
• Minimize tool face fluctuations despite erratic weight on bit (WOB); and
• Allow the theoretical dogleg severity (DLS) for a given assembly to be reached and maintained consistently.
Stability
Studies of PDC stability have documented that an unstable bit hinders steerability by:
• Increasing lateral aggressiveness;
• Drilling an oversize hole; and
• Creating poor borehole quality, with ledges, spiraling, etc.

In tests, the ROP of the new stable designs were typically 30% faster than conventional PDCs, with the slower conventional ROP being a result of inefficient drilling caused by excessive bit vibration and the drilling of an over-gauge hole. Caliper log comparisons of conventional vs. stable PDCs demonstrated that the new stable bit drilled an almost gauge hole for the run, while conventional PDCs appeared to drill 1¼2 in. to 1 in. over-gauge hole sections, which correlated with high-vibration events drilling a borehole with a distinctive sinusoidal pattern.

Build-up rate and borehole quality

Many thought that side cutting aggressiveness had to be maximized to deviate the well path quickly and gauge length minimized to support this side-cutting theory, thus enhancing the build up rate (BUR). In experiments, WOB and side loads were simultaneously applied to compare axial and lateral ROP. While the effect on build rate was not certain at this point, the implications for borehole quality became clear when the rock cores were sectioned. Severe ledges and irregularities in an actual bore hole were formed with the aggressive gauge PDC. These borehole features can cause stabilizers to hang up and make steering extremely difficult.

It was concluded that gauge aggressiveness had a pronounced effect on side cutting ability
Figure 2. Finite element analysis for BHA and bit response curves.
and hole quality. Although PDC bits with short, aggressive gauges provided higher instantaneous doglegs than roller cones bits, the dogleg severity was proven to fluctuate wildly. Consequently, borehole quality suffered as ledges, spiraling and “hour-glassing” would occur in both slide and rotate modes. Thus this poor hole quality would impact efficient weight transfer to the bit and significantly reduce drilling efficiency.

Although the steerable performance of a PDC bit is influenced by gauge aggressiveness, face aggressiveness also plays a key role. Face aggressiveness determines the relationship between WOB and bit torque: the more sensitive this relationship, the more difficult it is to control tool face in the presence of fluctuating WOB.

Toolface control at this time was improved by making the bit less aggressive. The idea is that instantaneous ROP can be sacrificed but net ROP improved if lost drilling time because of motor stalls and tool face resets can be avoided.

Bit face aggressiveness

PDC bits are four to 18 times more aggressive than roller cones. In this context, aggressiveness is defined as the relationship between applied WOB and the resulting reactive torque. Aggressiveness is proportional to the slope of the curve that relates drilling torque to WOB. The torque response of PDC bits is highly sensitive to changes in WOB, which results in fluctuations in reactive torque and leads to changes in tool-face position. A number of approaches have been used to improve performance: increased cutter back-rake, higher blade counts, small cutters, wear knots and large chamfers. These bits were often still too aggressive to drill even the softest and most forgiving formations. A new approach was needed that preserved ROP in the hard formations but still provided tool-face control in the softest shales. Hughes Christensen’s EZSteer Depth of Cut Control (DOCC) technology accomplished both objectives.

A bearing surface in the center of the bit (cone) engages the bottom hole to temper aggressiveness when steering and preserve ROP while rotating. When the bearing surface engages the formation, this reduces the reactive torque variation by absorbing WOB fluctuations without reducing the mean torque (aggressiveness of the bit), thus producing a similar tool face response to a roller cone bit (Figure 1). In rotary mode, the bit/motor combination still produces high ROP, which indicates the EZSteer concept bit is as aggressive and efficient as a standard PDC bit in harder formations.

The transfer of this motor steerable technology to rotary steerable systems to reduce torque fluctuations with PDC bits had a significant positive impact on the performance of rotary steerable systems. The application made great strides in maintaining stability while drilling even the most challenging formations. The reduction of unwanted vibrations allowed the bit and BHA systems to drill at increased ROP, deliver more predictable dogleg response and deliver longer intervals because of increased bit-BHA longevity.

This improved performance developed a need to reliably predict bit-BHA directional response for specific applications in response to greater challenges. A model to reliably predict achievable BUR for a given bit and rotary steerable assembly in a given formation was developed.

Rotary steerable systems BUR

The hypothesis that a bit drilling ahead with an applied side load will cut to the side at a rate based on the lateral aggressiveness of the bit was proven through extensive lab testing. The results of these tests demonstrated that longer, less laterally aggressive bits have sufficient side cutting ability to perform on steerable systems without compromising dogleg capabilities.

Understanding that bit side cutting is a nonlinear function of side force, gauge design, rotary speed, rate of penetration, rock strength and cutter dull state was key. With axial and lateral bit trajectories measured and response curves plotted, the bit side cutting angle measured in the lab is equivalent to the bit tilt angle calculated on a BHA. Figure 2 demonstrates the response of the bit and BHA in three different rock types. The intersection of each bit curve to the BHA response grid represents equilibrium between the bit and the BHA for each corresponding formation.

The BHA is modeled by finite element analysis over the range of hole curvatures and tool settings that define the operating envelope for the tool. A matrix of cases is generated and a static analysis is performed for each case. The data is then plotted on the same axes with the bit response from the laboratory testing, and since each data point is a static analysis case, the result represents a steady-state drilling condition between the bit, BHA and formation.

This model has been used to diagnose rotary steerable system issues since 2004 in applications worldwide, successfully predicting actual build and drop rates. Bit sizes have ranged from 5.875 in. to 16 in. The model is expanding to correctly select bits to match the steering application along with being applied to conventional rotary and steerable motor systems.

Old perceptions about steerable PDC design have been constantly challenged. New, innovative approaches are being applied to improve steerable system performance, predictable build rates, improved ROP and deliver extended tool life.