Interbedded formations, deep wells where a long drillstring is used and high-inclination wells with increased potential of drillstring interaction with the formation can all induce torsional vibrations. The result is inefficient drilling and damage to bottomhole assembly (BHA) components.
Due to their higher ROP potential, PDC bits are common bits of choice for many applications; however, due to their shearing action, PDC bits generally exhibit a higher level of torque fluctuation.
Historically, PDC bits use fixed depth-of-cut (DOC) control technology to address the torsional dysfunction by restricting bit/formation engagement at a predetermined ROP and drillstring rpm. The challenge of using fixed DOC control is finding a compromise between limiting torque fluctuation without limiting ROP.
Baker Hughes, a GE company (BHGE), has developed the TerrAdapt adaptive drillbit, which can deliver improvements in drilling economics by using adaptive technology for mitigating downhole torsional dysfunction to improve drilling efficiency and to avoid costly downhole tool failures.
With its self-adjusting DOC control elements, the TerrAdapt bit automatically adjusts its DOC with changing lithology and drilling conditions, mitigating stick/slip and eliminating manual parameter adjustment required at surface to manage torsional dysfunctions.
The ability to autonomously and rapidly adapt to changing drilling environments frees the TerrAdapt bit from the limitations of fixed DOC control and enables a single PDC bit to be used for a wider range of applications.
Adaptive DOC control cartridges installed inside the fixed blades autonomously extend when sudden changes in DOC is detected, preventing the bit from taking too large a bite. When normal drilling conditions prevail, the cartridges slowly retract to enable the maximum ROP for that section of rock.
Retractable ovoid elements protect cutters from any sudden overload or shock that could damage the TerrAdapt bit’s cutting structure, improving the durability of the bit/BHA.
Two case histories highlight the importance of improved torsional stability and its direct impact on drilling performance improvement. In the first example, the target well was in the Walker Ridge area of the Gulf of Mexico (GoM) in a water depth of about 2,895 m (9,500 ft). A 1,078-m (3,536-ft) tangent section was to be drilled at a 34-degree inclination with a rotary steerable system (RSS) BHA and a 12¼-in. bit to more than 9,144 m (30,000 ft) measured depth. The increased water depth and long tangent section through interbedded sand/shale sequence increased the likelihood of stick/slip due to higher torsional elasticity of the long drillstring. It also increased potential contact with the wellbore while lying on the low side of the tangent section of the well. The interbedded formation acted as a potential trigger of torsion instability due to changing DOC.
Offset data showed that a PDC bit run in a nearby well drilled 992 m (3,255 ft) of formation at 14.9 m/hr (48.9 ft/hr), indicating increased drilling efficiency and durability through the interbedded interval could potentially deliver better performance and save rig time.
To increase drilling efficiency, BHGE recommended a 12¼-in. TerrAdapt adaptive drillbit with seven blades, 16-mm cutters and shaped diamond elements for lateral vibration mitigation.
Analysis of downhole vibration severity levels against the percent of the bit run indicated that 97% of the run was free from stick/slip. Analysis also indicated the absence of any lateral and axial vibration during the run. The absence of axial vibration was expected, because it is typically associated with roller cone bits. The near-absence of stick/slip demonstrated the effectiveness of the self-adaptive technology and enabled the section to be drilled in a single bit/BHA run, which was an objective.
The improved torsional stability of the bit led to significant improvements in ROP, and the section was drilled with a 48% higher ROP than the previous best offset, saving the customer 23 drilling hours. The bit had a dull grade of 1-1-WT-A-X-I-NO-TD. All cartridges tested as fully functional upon return and disassembly, which is significant because this was the deepest that a self-adjusting PDC bit had been run, and the cartridges were exposed to significant downhole pressure.
The second target well was located in the Green Canyon area of the GoM, where the water depth was about 823 m (2,700 ft). A 1,316-m (4,319-ft) tangent section was to be drilled at a 17-degree inclination with the AutoTrak RSS with continuous proportional steering and a 12¼-in. bit. For ease of running casing and for lowering the equivalent circulating density, a 14½-in. concentric reamer was used for hole enlargement. The formation to be drilled in this section was predominantly argillaceous, with several layers of sandstone. The interbedded section, with reamer in BHA, increased the likelihood of bit-reamer mismatch and potential drilling dysfunction.
An offset data review indicated a PDC bit run in a nearby well drilled 1,372 m (4,500 ft) of formation at 19.8 m/hr (65.2 ft/hr). It was recognized that an increased drilling efficiency using self-adjusting PDC drillbit technology could potentially deliver better performance and save rig time. BHGE recommended a 12¼-in. TerrAdapt adaptive drillbit with seven blades, 16-mm cutters and self-adaptive DOC control technology. The bit also was equipped with shaped diamond elements for lateral vibration mitigation.
Analysis of vibration severity levels indicated that 98% of the run was free from stick/slip. The absence of axial vibration was expected, as it is typically associated with roller cone bits.
Near absence of stick/slip highlighted the effectiveness of the TerrAdapt self-adaptive technology and enabled the section to be drilled in a single bit/BHA run, which was an objective.
The 1,412-m (4,652-ft) long, 12¼-in. by 14½-in. interbedded tangent section of the target well was drilled at 34.9 m/hr (114.7 ft/hr). This was a 57% improvement over the offset PDC run that drilled a 1,372-m section at 19.8 m/hr (65.2 ft/hr).
Improved drilling performance in the target well resulted in 28.5 hours of rig time savings for this section, which was a significant value for the operator. The drilling performance improvement was attributed to lower vibration that lead to higher drilling efficiency achieved by self-adaptive technology due to its ability to provide a stable on-bottom drilling environment.
The application of self-adaptive technology coupled with shaped diamond elements helps operators achieve their goal of drilling efficiency improvement. It also provides cost savings for drilling operations by enhancing torsional stability, delivering higher ROP, mitigating lateral vibration and helping in-bit/reamer synchronization.
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