This article first appeared in the September 2019 edition of E&P Magazine.
Operators are Applying New PDC Bit Technology to Combine Sections and Drill Record Wells
As U.S. land operators continue to set production records, their need for more robust technology to reduce cost and enhance performance has never been greater. Ulterra, a PDC drillbit manufacturer, and its operator customers are utilizing the patented SplitBlade PDC bit technology to achieve stronger, faster drilling—a trend that combines the curve and lateral into one run and extends overall footage with longer lateral sections. By using this PDC technology that offers toolface control in the curve with high penetration rates, operators are reducing drilling time on record footage wells with record ROP and fewer trips to change the bit.
There is no question the oil and gas industry can be proud of decades of technology achievements that today power a thriving global economy. An important part of this history is the PDC drillbit, introduced in 1976, that enabled penetration into deeper reservoirs of oil and gas. Now, more than 40 years later, PDC technology allows operators to drill even deeper and faster. The SplitBlade class of PDC bits, recognized with a 2019 E&P Meritorious Award for Engineering Innovation, is a technology that is contributing to improved PDC bit performance. The Ulterra R&D team developed SplitBlade during a comprehensive, five-year project that studied the science of hydraulics and contact distribution. Based on operator experience, these design factors were fundamental to enhancing performance to support the new era of extended-reach drilling.
SplitBlade technology creates the split shape of the primary blades that have a rotational offset. The R&D team created drillbit geometry that enables multiple channels of fluid to flow through the same blade and junkslot. Typically, cuttings from the cone of the bit wash down the blade face during drilling only to accumulate around neighboring cutters, which wastes drilling energy and eventually leads to severe cutter damage. Instead, the split design creates high-velocity cuttings for clean evacuation from the cone of the bit that support the excellent high-volume cuttings evacuation from the shoulder cutters during drilling. Cuttings from the middle of a SplitBlade drillbit are evacuated up to seven times faster when compared with conventional designs. The cleaning allows the bit face to engage and fracture rock unimpeded, lowering heat buildup, which reduces thermal damage, and increasing bit longevity and raising ROP. The combination of these value drivers is establishing PDC benchmarks that are saving expensive rig time and bottomhole assembly (BHA) trips while allowing farther drilling.
Hands-on contact distribution
More contact means more control when drilling. As the bit rotates, each cutter’s individual depth of cut can change. This change is a repeating wave, the amplitude of which is directly related to bit stability. Visible as reactionary torque, this signal is vital in curve and lateral applications where control and steerability directly relate to final wellbore quality, well position in the pay zone and production throughout the well life. By achieving a smoother torque transmission, the torque spikes are reduced and the bit operates more responsively to the driller’s expectations, especially in instances of extreme lateral distance. Throughout the course of testing and engineering SplitBlade technology, the R&D team learned that spreading out and distributing the cutters would break up the torque spikes and angular forces that can build up while drilling. The design was better at distributing energy, which created a smoother method of transmitting torque through the bit to reduce the fluctuations that can lead to drilling dysfunction while failing rock formations. The result of these design improvements is a versatile drillbit that has a hands-on feel while distributing energy holistically across the toolface.
Combining vertical, curve and lateral
Since the launch of the SplitBlade PDC bit in fall 2017, operators have applied the company’s original drillbit technology on more than 5,000 runs, totaling more than 6.5 MMm (21.5 MMft) drilled. Currently, operators are averaging more than 1.2 MMm (4 MMft) per month with the technology. The footage drilled is growing with the technology as longer intervals are turning into combined sections of drilling. One such operator, working in the Eagle Ford Shale, has been setting new and unique drilling records. The operator devised an original well plan: drill the vertical, curve and lateral (VCL) with one bit and BHA, a new strategy for one of the more challenging areas of the Eagle Ford. An 8¾-in. SplitBlade PDC drilled the entire VCL, totaling nearly 5,180 m (17,000 ft) in the tough section, saving the operator $50,000 in the process and inaugurating a new drilling era in the Eagle Ford. Building upon success, the operator drilled another VCL, this time reaching more than 5,790 m (19,000 ft) with a single bit and BHA, setting an all-time Eagle Ford footage record. Then, the operator set consecutive 24-hour footage records with SplitBlade technology, the most recent of which clocked in at 1.9 km (1.2 miles) in 23.5 hours. Now, 70% of Dimmit County operators are drilling VCLs, firmly establishing VCL drilling as a successful strategy.
Increasing lateral length
Extended-reach laterals traditionally present major challenges in ensuring the proper weight is transferred to the bit to mitigate the increased torque and drag when the BHA is miles away from the rig. Without this weight transfer, there is not enough bit energy to resolve enough torque and drag efficiently to remove rock and drill ahead. The company’s R&D team is keeping pace with operator demands for greater drilling efficiency with increased lateral length by iterating cutting structures and depth-of-cut engagement to react consistently to the challenging environment that exists when drilling nearly 4.8 km (3 miles) horizontally. Early this year, a Permian Basin operator used an 8½-in. SplitBlade PDC technology to drill two consecutive, one-run curve laterals on conventional assemblies. One of these runs, at more than 4,420 m (14,500 ft), set the longest conventional curve-lateral bit run record in the Midland Basin while surpassing the threshold of more than 30 m/hr (100 ft/hr). Previously, this operator had applied Ulterra PDC bits in a dedicated lateral application only. With this record, the new drilling era that began in South Texas was established in West Texas. Going deeper in this new era of extended-reach intervals and combined sections will continue to allow operators to improve drilling efficiency and overall well production. As new milestones are reached by drilling up to 4.8-km laterals and beyond, the question of a potential one-bit, 6.4-km (4-mile) lateral is entering operators’ minds.
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