There is a familiar story about a customer who walks into a hardware store looking for a ½-in.-diameter drillbit. However, what the customer really wants is a ½-in.-diameter hole; the bit just helps construct it.

The same analogy can be applied to oil and gas wells. Operators want smooth trajectory boreholes drilled quickly and landed precisely in the target reservoir. But because of wide variation in geology, mineralogy and mechanical properties, some bits drill more efficiently.

In addition, some bits last longer than others, and this enables drillers to construct precisely drilled boreholes with fewer replacement trips to change out worn or broken bits. In every basin, rig rates form a significant portion of well costs, so elimination of just one bit replacement trip amounts to a major savings. Accordingly, longevity is perhaps the greatest benefit a bit can offer because savings go directly to the bottom line.

Based on these challenges, Smith Bits created a new drillbit technology called StingBlade, a conical diamond-element bit that offers both longevity and efficiency benefits. The chief characteristic is the implementation of conical diamond elements with very high impact resistance (Figure 1).

The elements have been strategically inserted across the blade of a fixed-cutter bit design. Smith Bits design engineers used the IDEAS integrated drillbit design platform to simulate drilling conditions and determine the optimal number and placement of the Stinger elements.

How does it work?
The key factor behind the new bit’s performance is its conical diamond element. The shape of the element creates an ultrahigh concentrated point load on the formation to fracture high-compressive-strength rocks more efficiently. Also, the element has a thicker diamond table compared with standard cylindrical cutters, which gives it superior impact strength.

In a direct comparison, two cutters—a standard polycrystalline diamond compact (PDC) cutter and a conical diamond element—were smashed with 18,000 lbf onto a steel plate to simulate instantaneous impact loads typically seen while drilling downhole. The standard PDC cutter failed on first impact, but the new element continued for 100 impacts without any damage (Figure 2).

In addition, the elements generate less torque than cylindrical cutters. This, in turn, yields better directional response (steerability) and smoother toolface control. Because cutting force is applied to the symmetrical point of the new diamond element, drilling proceeds with less shock and vibration.

The new technology also chips off larger pieces of rock, which are swept away up the junk slot by strategically placed nozzles and circulated to surface, compared to typical cutters that can waste energy regrinding cuttings. Currently, the conical diamond elements can be inserted in all bit sizes from 57⁄8-in. diameter to as large as 36-in. diameter.

Williston Basin breakthrough
In the prolific Williston Basin play of northwestern U.S. and southwestern Canada, operators are striving to reduce drilling costs, especially on wells designed with long lateral sections. Oasis Petroleum achieved immediate results by switching to StingBlade (Z613) bits in the Three Forks First Bench laterals.

To effectively produce the formation, the company drilled long, precise laterals. On the first lateral utilizing the Z613, there was a 50% increase in ROP compared to the rig’s average conventional PDC bit runs. One factor leading to the increase in ROP was that the bit provided sliding ROP twice that of conventional PDC bits. In addition to the increase in ROP, the biggest advantage Oasis observed with the bits was the ability to drill the entire lateral with a single bit.

The company realized a substantial drop in tripping time and number of bits used on wells. When adding up trip time saved, increase in single-bit laterals and an increase in ROP, Oasis achieved considerable cost savings on wells where the bits were used.

Tough test
In the Permian Basin, another operator chose a typical Wolfcamp well plan to test the StingBlade bit for ROP, impact resistance and overall longevity. The test required drilling the lateral section first with a Z516 five-blade bit design. After drilling 762 m to 915 m (2,500 ft to 3,000 ft) a motor failure required a pipe trip.

While the motor was being changed out, the bit was inspected and showed minimal wear. Continuing the comparison test, a standard MDSi516 bit with an identical diameter, blade and cutter arrangement but without any conical diamond elements was run into the hole. It only drilled 113 m (375 ft) before it was damaged beyond repair while drilling a transition zone. A Z516 bit of the same configuration was then run to drill the remaining 762 m of lateral, which it accomplished with minimum wear. In each case the new bit averaged higher ROP, greater longevity and superior impact resistance. It stayed sharper longer.

Vibration plays role
In both of the examples a third factor played a significant role in quality and safety. Destructive bottomhole assembly (BHA) vibration slows ROP, affects borehole quality and can severely damage downhole tools. Precise measurements have confirmed that vibration levels on BHAs utilizing bits with Stinger elements on the blade remain between zero and two for 99% of the time. Records for competitor bits where vibration was measured in the same area varied between a high of 74% and
a low of 64%, respectively, with two cases where destructive level 5 to level 7 vibration was experienced.

In general, the new technology has higher steerability that allows it to kick off from vertical at a greater depth and still land in target zones. The conical diamond elements chip off much larger cuttings that allow better geological analysis when circulated to surface. Design flexibility comes from the ability to change the numbers and placement of elements according to the design program to create a customized bit for special applications.

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