The greater Permian region is comprised of several component basins: 1) Midland basin is the largest; 2) Delaware basin is the second-largest; and 3) Marfa basin is the smallest. The Midland basin is well-known for hard rock formations that are part of its stratigraphic column. They are composed of highly interbedded zones with hard stringers of limestone that can exceed 30 Kpsi compressive rock strength.
One of the most challenging applications is the production vertical+curve+lateral (VCL) section, due to interbedded transitions that typically produce bit damage, the inability to track tangents (in vertical and lateral sections) and difficulty to achieve build rates while drilling the curve section. In the Midland basin, the production VCL section is typically drilled with 8¾-in. or 8½-in. PDC bits, using a conventional mud motor to drill a total of approximately 13,000 ft. The section lithology is composed of soft shale with hard stringers of limestone and occasionally abrasive zones, which lead to cutter damage and increase the number of bits/trips required to drill the entire hole section (i.e. more than two fixed-cutter bits).
Performance and dull analysis. Operators drilling in the Midland basin have been demanding new technologies to help improve their performance and consistently drill the entire section in a single run, at a higher rate of penetration. Six-bladed, fixed-cutter bits with 13-mm cutter size have been used to drill the section, where severe bit damage can prevent the bits from drilling further. Surface electronic drilling recorder systems have indicated severe vibrations when interbedded zones are found. The type of vibrations at the bit and their sources have been unknown, making it difficult to identify the right approach for a complete solution. Table 1 presents the performance of a drill-out bit featured with a sensor at the bit to capture electronic data. Figure 1 shows the dull condition of the bit before and after being used.
Table 1. Performance of drill-out PDC with a sensor at the bit used to drill the VCL section.
Fig. 1. Bit dull condition after the run.
Lithology evaluation. The section is composed of soft shale with a compressive rock strength of around 5 KSPI and hard stringers of limestone with medium-to-high abrasive sandstone that can exceed 30 KPSI of compressive rock strength. Figure 2 illustrates the VCL section rock analysis.
Fig. 2. Rock strength analysis of VCL production hole section.
Electronic data analysis. The electronic bit data captured across a series of 8¾-in. bits used in the VCL section were analyzed to identify the vibrations at the bit while drilling this challenging application. The goal was to determine the root cause of the issues in the cone, lower shoulder, and gauge areas that would show us the right approach for bit design modifications that can help eradicate the severe damage going forward. Figure 3 shows the sensor that recorded bit data and where it was located inside the bit.
Fig. 3. Location of the bit sensor.
The bit vibration data analysis did not show the presence of bit stick-slip. However, severe lateral vibration, combined with moderate-to-high axial vibration, was seen in the bit data throughout the entire run. Lateral and axial events found were long-lived and not a function of operating parameters. The high lateral and axial magnitudes were related to the bit side cutting while drilling the curve section and hard stringers that were found in the lateral section, where the downward rate of penetration (ROP) trend started toward the end of the run. Figure 4 shows electronic bit data analysis of the 8¾-in. VCL run that was shown previously, where the bit was damaged in the cone and was pulled for a low penetration rate.
Fig. 4. Electronic bit data analysis of 8¾-in. VCL run.
An in-depth bit data analysis of the lateral section was performed to understand how the high lateral and axial shocks were produced, which led to the bit damage and prevented the bit from completing the section in one run. The bit data showed an increase of lateral and axial vibration (vibes), along with a drop in ROP at lower values of gamma ray. The low gamma value typically indicates the presence of hard stringers. The analysis concluded that hard, interbedded transitions drilling was the source producing high lateral and axial vibes, generating severe bit damage, and stopping the bit from completing the section. Figure 5 shows the in-depth bit data analysis of the lateral section and presents the high lateral and axial vibes with low ROP produced by the low gamma values.
Fig. 5. Electronic bit data, showing the correlation of low-gamma ray intervals, with increased vibration and slow ROP.
The electronic bit data analysis also showed consistent events of high lateral vibes when the bit was spinning off bottom, while tagging bottom, or when picking up off bottom. Figure 6 shows the vibrations when drilling a stand in the lateral section, with high lateral vibes when the bit is out of bottom.
Fig. 6. Electronic bit data, showing peak lateral vibrations while off bottom at the beginning and end of a stand.
Automated dull grade analysis. Digitization and automation have been areas of increasing focus in the drilling industry during recent years. One critical area is digitalization in the assessment of drill bit wear and damage. Currently, using as a reference the International Association of Drilling Contractors (IADC) drill bit grading standard, oilfield personnel analyze and dull-grade drill bits through visual inspection, which can be subjective.
An automated dull grade (ADG) system was used to perform an accurate dull grading for several 8¾-in. bits damaged in this application. The system calculated the damage to individual drill bit cutters, using digital images as inputs. By using an automated process, the system provided a higher level of reliability, consistency and accuracy about the bit location where damage occurred in the bits analyzed. The AGD system showed the typical dull condition as catastrophic damage in the cone, along with high-impact damage in the lower shoulder and gauge areas. Figure 7 shows the ADG output from across a series of bits that were run in the VCL section.
Fig. 7. ADG output from across a series of bits run in the 8¾-in. VCL section.
The damage in the cone occurred from cutter 5 to 10, and then expanded toward the inner cone, or toward the nose and shoulder, which prevented the bits from drilling further. The chipping, breakage, and delamination from cutter 31 to 40 in the lower shoulder and gauge areas reduced the bit side cutting efficiency while drilling the curve or doing directional corrections in the lateral section.
Bit design analysis. The highest bit area of engagement is in the cone cutters, where any drastic cutter over-engagement produced by dysfunction can lead to failed cutters. Analyzing the bit design that was used to drill the 8¾-in. VCL section, the simulation shows the highest cutter engagement from cutter 5 to 10, matching with the cutters damaged in the cone detected by the ADG system. Figure 8 shows a cutter engagement simulation of the bit that was used to drill the 8¾-in. VCL section. Looking at the bit cutting layout, the areas with highest damage, per the ADG system, showed low back rakes. Figure 9 shows the back rake bit scheme for each cutter. The catastrophic bit damage was produced in the cone and gauge locations with low back rakes for those areas, due to cutter overloading during the axial and lateral dysfunction events while drilling the hard stringers in the lateral section.
Fig. 8. Cutter engagement simulation of the bit that has been used to the drill the 8¾-in. VCL section.
Fig. 9. Back rake of each cutter of the bit used for the application.
Improved PDC bit design. Based on the in-bit data and bit damage analyzed, an advanced bit cutting structure layout with more robust back rakes and optimum placement of DOC control elements was used to develop a fit-for-purpose design. The new six-bladed, 13-mm bit layout increased the back rakes in the cone and gauge areas, along with a longer cutter substrate and an increased area of engagement of the impact arrestors. The bit cutting structure improved impact resistance while drilling through interbedded zones with hard stringers. Figure 10 shows a back rake bit scheme comparison between the old and new designs. Figure 11 presents an impact arrestors contact area (in^2) simulation for the old and new designs.
Fig. 10. Back rake bit scheme comparison between the old and new designs.
Fig. 11. Impact arrestors contact area (in^2) simulation for a typical DOC (0.25 in/rev) in the lateral section.
New PDC bit design. Based on the findings, a new 8¾ -in. bit design was developed, using the electronic data and ADG system, and tested in the production VCL section of a Midland basin well. The new bit design improved performance, compared to the old design, and reduced severe cone and gauge damage while achieving an overall 6% increase in ROP and 11% footage improvement. At the same time, it reduced, by half, the bits that were pulled for low penetration rate. It also reduced the number of bits that were damaged beyond repair (DBR).
Figure 12 presents the performance of the new 8¾-in. VCL bit design in comparison to the previous design. The ADG system shows better dull condition when using the new 8¾ -in. VCL bit design. Figure 13 presents ADG results of the new bit design. Reviewing the top 10 drill-out VCL runs, the new 8¾-in. VCL bit design holds nine of the top ten runs. Figure 14 illustrates the top 10 runs of the 8¾-in. VCL application. The outstanding performance, using the new design, also reflected a savings of approximately $27,500 per well, due to the faster ROP, reduction of bit trips and cost of damage beyond repair charges.
Fig. 12. Performance comparison between the old and new 8¾-in. VCL bit design.
Fig. 13. ADG results of the new 8¾ -in. VCL bit design, documenting better dull condition.
Fig. 14. Top 10 runs of the 8¾ -in. VCL application.
CONCLUSIONS
- An advanced automated dull grade (ADG) system was able to show consistently delaminated and broken cutters in the cone and the lower shoulder and gauge areas, produced by high impact.
- The electronic bit-data and ADG system showed catastrophic damage in the cone, along with high-impact damage in the lower shoulder and gauge areas, produced from cutter overloading during lateral and axial dysfunction events while drilling the hard stringers. The bit damage was reduced by designing a cutting structure layout with increased back rakes in the cone and gauge areas, along with longer cutter substrate and an increased area of engagement of the impact arrestors that raised the resistance to the lateral and axial shocks while drilling through interbedded zones.
- The field data obtained from testing the new fixed cutter bit designed with the electronic data and the ADG system showed an overall 6% ROP and 11% footage improvement and reduced to half the bits that were pulled for penetration rate and bits with damage beyond repair, which led to savings of approximately $27,500 per well.
- The changes made in the design demonstrate that increasing cutter back rakes, and the area of engagement of the impact arrestors, will produce more efficient drilling, rather than slowing average ROP.
- The electronic bit data showed consistent events of high lateral vibes when the bit was spinning off bottom, while tagging bottom, or when picking up off bottom that might have led to the delaminated and broken cutters that the ADG system showed in the lower shoulder and gauge areas. It is recommended to decrease the surface RPMs and flowrate when picking the bit off bottom to reduce high lateral shocks.
ACKNOWLEDGEMENTS
The authors wish to thank Halliburton Drill Bits and Services and CrownQuest Operating for providing the support to allow development of the technological solutions and execution of the high-level engineering analysis outlined in this article. Furthermore, this article contains excerpts from SPE paper 212475-MS, “Utilizing electronic data captured at the bit, in combination with automated bit dull grading, to improve bit design features, dull condition and ultimately drilling performance,” presented at the SPE/IADC International Drilling Conference and Exhibition, held in Stavanger, Norway, March 7–9, 2023.
About the Authors
Carlos Galarraga
Halliburton
Carlos Galarraga is an application design evaluation specialist for the Permian basin at Halliburton. He has 17 years of industry experience in drill bits, coring, down hole tool operations and well construction. He graduated from Army Polytechnic School in Ecuador in 2005 with a bachelor’s degree in mechanical engineering.
Gabe Gusey
CrownQuest
Gabe Gusey is drilling lead at CrownQuest Operating. He has been with CrownQuest for nine years as a drilling engineer. He graduated from Colorado School of Mines in 2014 with a bachelor’s degree in petroleum engineering.
Derek Wade
Halliburton
Derek Wade is a technical field sales representative at Energyplex Distribution. He has 15 years of industry experience in drill bit sales in a variety of different regions. He graduated from the University of Texas at Tyler in 2008 with a bachelor’s degree in business administration.
Andrew Allen
Halliburton
Andrew Allen is territory manager at WireCo World Group. He has been with the company for 11 months. Prior to that, he spent nine years in drilling and production chemicals. He graduated from University of Texas of the Permian Basin in 2017 with a bachelor’s degree in industrial technology.
