Hybrid Bits Offer Distinct Advantages in Selected Roller-Cone and PDC-Bit Applications

96 March 2011 SPE Drilling & Completion

Hybrid Bits Offer Distinct Advantages in Selected Roller-Cone and PDC-Bit

ApplicationsRolf Pessier and Michael Damschen, SPE, Baker Hughes

Copyright © 2011 Society of Petroleum Engineers

This paper (SPE 128741) was accepted for presentation at the IADC/SPE Drilling Conference & Exhibition, New Orleans, Louisiana, 2–4 February 2010, and revised for publication. Original manuscript received for review 7 May 2010. Revised manuscript received for review 6 August 2010. Paper peer approved 9 August 2010.

SummaryEarly concepts of hybrid drill bits go back to the 1930s, but the development of a viable drilling tool has become feasible only with the recent advances in polycrystalline-diamond-compact (PDC) cutter technology. This paper describes a new generation of hybrid bits that is based on proven PDC-bit designs with rolling cutters on the periphery of the bit. Laboratory and field results will be presented that compare the performance of hybrid bits with that of conventional PDC and roller-cone bits. A hybrid bit can drill shale and other plastically behaving formations two to four times faster than a roller cone bit by being more aggressive and efficient. The penetration rate of a hybrid bit responds linearly to revolutions per minute (RPM) unlike that of roller-cone bits, which exhibit an exponential response with an exponent of less than unity. In other words, the hybrid bit will drill significantly faster than a compa-rable roller-cone bit in motor applications. Another benefit is the effect of the rolling cutters on the bit dynamics. Compared with conventional PDC bits, torsional oscillations are as much as 50% lower, and stick/slip is reduced at low RPM and whirl at high RPM. This gives the hybrid bit a wider operating window and greatly improves toolface control in directional drilling. The hybrid drill bit is a highly application-specific drill bit aimed at (1) traditional roller-cone applications that are rate-of-penetration (ROP) limited, (2) large-diameter PDC-bit and roller-cone-bit applications that are torque or weight-on-bit (WOB) limited, (3) highly interbedded formations where high torque fluctuations can cause premature failures and limit the mean operating torque, and (4) motor and/or directional applications where a higher ROP and better build rates and toolface control are desired.

IntroductionThe roller-cone bit replaced the fishtail bit in the early 1900s as a more durable tool to drill hard and abrasive formations (Hughes 1915), but its limitations in drilling shale and other plastically behaving rocks were well known. The underlying cause was a combination of chip holddown and/or bottom balling (Murray and Cunningham 1955), which becomes progressively worse at greater depth as borehole pressure and mud weight increase. Ball-ing reduces drilling efficiency of roller-cone bits to a fraction of what is observed under atmospheric conditions (Pessier and Fear 1992). Other phenomena such as tracking and off-center running aggravate the problem further. Many innovations in roller-cone-bit design and hydraulics have addressed these issues, but they improved the performance only marginally (Wells and Pessier 1993; Moffit et al. 1992). Fishtail, or fixed-blade, bits are much less affected by these problems because they act as mechanical scrapers that continuously scour the borehole bottom. This sug-gests that a combination of the two bit types could offer distinct advantages. The first prototype of a hybrid bit (Scott and Bettis 1932), (Fig. 1), which simply combines a fishtail and roller-cone bit, never succeeded commercially because the fishtail, or fixed-

blade part of the bit, would prematurely wear and large wear flats reduced the penetration rate to even less than what was achievable with the roller-cone bit alone. The concept of the hybrid bit was revived with the introduction of the much more wear-resistant fixed-cutter PDC bits in the 1980s, and a wide variety of designs was proposed and patented (Baker et al. 1982; Schumacher et al. 1984; Holster et al. 1992; Tandberg 1993). Some were fieldtested, but again with mixed results (Tandberg and Rodland 1990), mainly because of structural deficiencies in the designs and the lack of durability of the first-generation PDC cutters. Since then, significant advances have been made in PDC-cutter technology, and fixed-blade PDC bits have replaced roller-cone bits in all but some applications for which the roller-cone bits are uniquely suited. These are hard, abrasive, and interbedded formations; com-plex directional-drilling applications; and general applications in which the torque requirements of a conventional PDC bit exceed the capabilities of a given drilling system. It is in these applications that the hybrid bit can substantially enhance the performance of a roller-cone bit with a lower level of harmful dynamics compared with a conventional PDC bit.

Hybrid-Bit DesignTwo basic hybrid-bit designs are presented in this paper: a two-cone, two-bladed version for smaller-diameter bits and a larger three-cone, three-bladed version for larger diameters (Figs. 2 and 3, respectively). They are based on proven four- and six-bladed PDC-bit designs in which the secondary blades have been replaced with truncated rolling cutters. As a result, the central portion of the borehole is cut solely by PDC cutters on the primary blades while the more difficult to drill outer portion is being disintegrated by the combined action of the cutting elements on the rolling cutters and fixed blades. The rolling cutters are biased toward the backside of the blades to open up a space or junk slot in front of the blades for the return of cuttings and the placement of nozzles.

Drilling MechanicsIn a hybrid bit, the intermittent crushing of a roller-cone bit is com-bined with the continuous shearing and scraping of a fixed-blade bit. The characteristic drilling mechanics of a hybrid bit can be illustrated best by direct comparison with a roller-cone and fixed-blade bit in laboratory tests under controlled, simulated downhole conditions (Ledgerwood and Kelly 1991). The drilling mechanics of the different bit types and their performance are highly depen-dent on formation or rock type, structure, and strength.

Medium-Strength Carbonate. For the fi rst series of tests, Car-thage marble, with approximately 15,000-psi unconfi ned compres-sive strength (UCS), was chosen as a typical medium-strength formation. The downhole conditions were 3,000-psi bottomhole pressure (BHP) and 9.5-lbm/gal water-based mud. The tests were run at a constant 120 RPM and with incremental increases in WOB. The WOB intervals were approximately 3 to 6 in. long, which is enough to establish equilibrium conditions. Fig. 4 shows the ROP as a function of WOB for the roller-cone and PDC bits and two versions of a 77⁄8-in. two-cone, two-bladed hybrid bit. One version is called cone leading (CL) and the other blade leading (BL). The terms denote which cutting structure is dominating. In the CL ver-sion, the cutting elements on the rolling cutter precede those on the

March 2011 SPE Drilling & Completion 97

following blade, which are aligned in the same radial kerfs or paths. In other words, the PDC cutting elements are drilling in the shadow of the rolling cutter; they take only a small depth of cut (DOC) and barely scrape the borehole bottom. In the BL version on the other hand, the PDC cutting elements do most of the work and the rolling cutters act more like DOC limiters and stabilizers. Fig. 4 illustrates the well known fact that PDC bits are as much as four times more aggressive than roller-cone bits, with the hybrid bits (as expected) falling between the two extremes, the CL hybrid version falling closer to the roller-cone bit and the BL hybrid version closer to the PDC bit. This gives the drill-bit designer the option to select an aggressiveness that best fi ts a given drilling system or application. Fig. 5 shows the ROP as a function of torque for the same series of tests. All four bits require approximately the same amount of torque or power to drill at a given ROP. This suggests that the fundamental rock-fracture process is very similar for crushing and shearing or a combination of the two. The roller-cone bit appears to be slightly more effi cient in this medium-strength and still somewhat brittle rock. However, notice that at a WOB of 45,000 lbf, it could generate only 2,000 lbf-ft of torque, which is already approaching the limit of the WOB that can be applied to this size of bit. The roller-cone bit, therefore, cannot take advantage of more-powerful rigs and motors

because its WOB and torque operating window is too narrow. The hybrid bits on the other hand have a much wider operating window and can use the full torque or power provided by modern drilling systems. Another interesting aspect of bit performance is how a particular bit responds to RPM. Fig. 6 shows that the roller-cone bit has a very fl at response to RPM while the hybrid and PDC bits respond proportionally to the increase in RPM. The poor response of the roller-cone bits to RPM in rock under confi ning pressure is well known and is attributed to increased tracking at low depth of cut and less-effective bottom scouring and cleaning by jets travers-ing at high speed. The blades on the hybrid bit act as scrapers that break up the tracking pattern and clean the borehole bottom mechanically. This results in a signifi cant advantage in performance drilling when both torque and RPM can be optimized to transmit the maximum power to the bit.

Soft Shale. Catoosa shale with a UCS of approximately 3,000 psi was chosen for the second series of tests that were run at 4,000-psi BHP and with the same 9.5-lbm/gal water-based mud. In the soft shale, the weakness of the roller-cone bit is most pronounced, as shown in Fig. 7. The PDC is almost ten times more aggressive than the roller-cone bit at the lowest WOB, and the difference gets even larger at higher WOB because of the difference in slope. While this is advantageous in pure ROP terms, it can become a handicap in practice when small changes in WOB cause large variations in ROP and torque. Severe stick/slip or global bit balling might occur

Fig. 1—First hybrid prototype.Fig. 2—Two-cone/two-blade hybrid bit.

Fig. 3—Three-cone/three-blade hybrid bit.

0

30

60

90

5000 20000 35000 50000

ROP

/hr

WOB

ROP vs. WOB(Carthage Marble, 3,000 psi BHP, 120 RPM)

RC PDC Hybrid (BL) Hybrid (CL)

Fig. 4—ROP vs. WOB, Carthage marble.


as a result of the erratic torque and ROP response. The hybrid bit is as much as four (CL) or eight (BL) times faster than the roller-cone bit, but its response to WOB is fairly fl at and therefore ensures smoother running and a resistance against sudden, global balling. Fig. 8 shows ROP as a function of torque and emphasizes the weakness of roller-cone bits in softer shale and other plasti-cally behaving formation. It takes about three times more torque for the roller cone bit to match the ROP of the PDC bit, which is much more effi cient in shale because of its favorable scraping and shearing action. The hybrid bits are two (CL) or three times (BL) more effi cient than the roller-cone bit at light WOB, but they cannot match the PDC bit at higher WOB or greater DOC. A PDC bit is clearly the best tool for pure shale drilling.

Hard, Abrasive Quartzite. Jasper quartzite at 36,000-psi UCS and Gabbro at 49,000-psi UCS were selected for the hard-rock test series. These tests were run with a 12¼-in. three-cone, three-bladed hybrid bit at 4,000-psi BHP with 9.5-lbm/gal water-based mud. The three-cone, three-bladed bit allows a third option in the cone/blade arrangement, in which the matching pairs of cones and blades are located opposite [cones opposite (CO)] and thus share the drilling load equally between the two cutting structures, result-ing in a drill bit with an aggressiveness falling roughly midway between roller-cone and PDC bits. The hard-rock tests were run at 120 RPM and at constant WOB of 30, 40, and 70 kip for the PDC, hybrid (CO), and roller-cone bit, respectively. The different WOB values were chosen to reach comparable torque or power at the bit.

Fig. 9 shows a bar graph of the ROP achieved with each bit type. The hybrid bit was the fastest, leading the PDC and roller-cone bit, but it also drew a slightly higher torque, as shown in Fig. 10. To obtain a true measure of the effi ciency of the three bit types, Fig. 11gives the specifi c energy for each test. The fi gure shows that the roller-cone bit is indeed the most effi cient bit in hard rock, but, as in the medium-strength rock, it has already reached the maximum WOB limit and no further ROP gains can be made unless its aggressiveness is increased. The hybrid bit shows slightly lower specifi c energy than the PDC bit, which might indicate a possible synergy of the crushing and shearing action. The roller-cone cut-ting elements, which create a deep damage zone in the formation, might prefracture the hard rock and make it easier for the PDC cutting elements to penetrate and shear it. As in medium-strength rock, the hybrid bit has a much wider operating window and greater ROP potential than a roller-cone bit. The prefracturing of hard and abrasive material might make it possible to shear it more effectively and with less wear and damage than is experienced with conventional fi xed-cutter or PDC bits.

Drilling DynamicsDrilling dynamics can be defined as the variation and intensity of the drilling forces. Axial or vertical forces characterize the dynam-ics of a roller-cone bit, while torsional forces are dominant on fixed-cutter or PDC bits. Typical dynamic dysfunctions triggered by these forces are bit bounce for roller-cone bits and whirl and stick/slip for fixed-cutter bits.

Fig. 5—ROP vs. torque, Carthage marble.

0

30

60

90

0 1500 3000 4500

ROP

/hr

Torquelbf-

ROP vs Torque(Carthage Marble, 3,000 psi BHP, 120 rpm)

RC PDC Hybrid (BL) Hybrid (CL)

82.0

152.5

14.215.4

52.9

101.078.6

158.7

0

100

200

100 150 200 250

ROP

/hr

RPM

ROP vs. RPM(Carthage Marble, 3,000 psi BHP

WOB(klbs) 20 PDC, 45 RC, 35 Hybrid)

PDC RC Hybrid (CL) Hybrid (BL)

Fig. 6—ROP vs. RPM, Carthage marble.

0

100

200

300

5000 15000 25000 35000

ROP

/hr

WOBlbf

ROP vs. WOB(Catoosa Shale, 4,000 psi BHP, 120 rpm)

PDC Hybrid (BL) Hybrid (CL) RC

Fig. 7—ROP vs. WOB, Catoosa shale.

0

100

200

300

500 2000 3500 5000

ROP

/hr

Torquelbf-

ROP vs. Torque(Catoosa Shale, 4,000 psi BHP, 120 rpm)

PDC Hybrid (BL) Hybrid (CL) RC

Fig. 8—ROP vs. torque, Catoosa shale.


Dynamics Testing at Atmospheric Pressure. A fi rst simple assessment of drilling dynamics can be made in the laboratory by drilling in a large block of rock under atmospheric conditions (Cooley et al. 1992). A relatively soft Bedford limestone, with 5,000-psi UCS, was selected for a series of tests with the 12¼-in. three-cone, three-bladed hybrid bit (CO) and a conventional roller-cone and fi xed-cutter bit. The tests were run in the controlled-ROP mode at a constant 120 RPM. The independent variable was ROP, which was changed in steps from 3 ft/hr to 96 ft/hr, and the dependent variables were WOB and torque. The dependent vari-ables were recorded at a frequency of 512 Hz, but the data were averaged at 2 Hz or once per revolution to reduce the scatter and illustrate the fundamental differences between the bit types. Fig. 12shows the axial forces or WOB recording for the three bit types. As expected, the values are the highest for the roller-cone bit and low-est for the PDC bit, and the hybrid bit falls between the two. The variation in the averaged axial forces is relatively small. Fig. 13shows the tangential forces, or torque, for the same series of tests. There is a striking difference not only in the magnitude but also the variation of the averaged tangential forces for the three bit types. The tangential forces for the PDC bit are much higher and oscillate over a wide range, particularly at the lower ROP or lighter DOC at the beginning of the test. It has to be pointed out that in these tests at atmospheric pressure with a short and stiff assem-bly, the torsional oscillations are exaggerated and do not simulate downhole conditions. However, they allow us to make a relative comparison of the dynamic characteristics of different bit types. In the fi eld, there are many ways to suppress oscillations in PDC

bits, particularly in directional drilling in which tool-face control is critical (Al-Suwaidi et al. 2003; Sinor et al. 2001b). However, many of these design modifi cations introduced more sliding or rubbing, which reduces the drilling effi ciency. The rolling cutters on the hybrid bit accomplish the same result without the negative effect on drilling effi ciency. The problem becomes progressively worse with increasing bit size because the magnitude of the torque oscillations is directly proportional to bit size. Fig. 14 shows the results of a test with 16-in. diameter bits. This time, the 16-in.-PDC bit never settles down and the torque oscillations continue up to the 96-ft/hr ROP step.

Drilling Interbedded Formations. Harmful dynamics and accel-erated damage and wear of PDC bits are frequently observed in the fi eld when drilling a mix of medium-hard and hard abrasive forma-tions. To duplicate these conditions in the laboratory, a segmented rock core was created with three different-strength rocks. The three rocks used were Carthage marble, 15,000-psi UCS; Jasper quartz-ite, 36,000-psi UCS; and Gabbro, 49,000-psi UCS. The thickness and sequence in which the layers were placed in the segmented core were as follows: 6-in. Carthage; 3-in. Jasper; 6-in. Carthage; 5-in. Jasper; 6-in. Carthage; 3-in. Gabbro; 6-in. Carthage; 5-in. Gabbro. Fig. 15 shows a profi le section of the fi nished core. A 12¼-in. hybrid bit (CO) and conventional PDC and roller-cone bits were tested in the segmented core on the simulator under 4,000-psi BHP and with 9.5 lbm/gal water-based mud. The drilling param-eters were 120 rpm and constant WOB. The constant WOB levels for the PDC and hybrid bits (30,000 and 40,000 lbf, respectively)

40k

WO

B

40k

WO

B

30k

WO

B

30k

WO

B

70k

WO

B

70k

WO

B

0

10

20

30

Jasper Gabbro

ROP

/hr

Hard Rock Drilling at 120 rpmHybrid PDC RC

Fig. 9—ROP in hard-rock drilling.

40k

WO

B

40k

WO

B

30k

WO

B

30k

WO

B

70k

WO

B

70k

WO

B

0

2000

4000

6000

Jasper Gabbro

Torq

ue-lb

s

Hard Rock Drilling at 120 rpmHybrid PDC RC

Fig. 10—Torque in hard-rock drilling.

40k

WO

B

40k

WO

B

30k

WO

B

30k

WO

B

70k

WO

B

70k

WO

B

0

30000

60000

90000

120000

150000

Jasper Gabbro

Spec

ific

Ener

gylb

f/in

.2

Hard Rock DrillingHybrid PDC RC

Fig. 11—Specific energy in hard-rock drilling.

0

10000

20000

30000

0 100 200 300 400 500

WO

Blb

f

Timeseconds

12 ¼-in. Atmospheric Te g(Bedford, 5-25 klbs, 120 RPM, 2 hz)

Hybrid PDC RC

Fig. 12—WOB signature.


were selected to achieve comparable torque levels in Carthage marble. The WOB for the roller-cone bit was 75,000 lbf, which is at the upper end of its WOB rating. Fig. 16 shows the ROP of the three bit types drilling through the segmented core. As expected, the roller-cone bit is the slowest at approximately 12 ft/hr in both the Carthage marble and Jasper quartzite and approximately 7.5 ft/hr in the Gabbro, which is by far the hardest rock. The PDC bit is at least twice as fast, with an ROP in the 25- to 30-ft/hr range in Carthage, but it drops into the 12-ft/hr range in the quartzite, which is only slightly faster than the roller-cone bit. In the fi eld, this phenomenon is known as a negative drilling break for PDC

bits in harder sandstone. In Gabbro, the PDC bit drills at 10 ft/hr. The hybrid bit is slightly faster than the PDC bit in Carthage marble at approximately 30 ft/hr, but it does not drop off nearly as sharply in the much harder quartzite and Gabbro (with ROPs of 22 ft/hr and 20 ft/hr, respectively) which is almost double the ROP of either the PDC or the roller-cone bit. This again suggests a favorable synergy of the crushing and shearing action with the hybrid bit in harder rocks.

The most significant result of the segmented core test is the variation in the average torque at constant RPM and WOB. Drill-ing at constant parameters is the conventional drilling practice in the field. Fig. 17 shows a graph of the torque signature for each bit type as it drills through the different layers of rock in the seg-mented core. The torque of the PDC bit changes more than 60% (from approximately 4,200 to 7,000 lbf-ft when transitioning from the hard quartzite to the medium-strength Carthage. The process repeats itself in each transition from hard to medium or medium to hard. The torque response of the roller-cone bit is much smoother, changing from approximately 2,500 to 3,000 lbf-ft (or 20%) in the first transition. Notice also the much lower absolute torque values for the roller-cone bit. Even with 75,000-lbf WOB, it generates much lower torque and, therefore, drills proportionally slower. In comparison, the torque variations of the hybrid bit are roughly from 5,500 to 6,500 lbf-ft (or 18%), which is approximately the same as the roller cone bit but at a much higher torque level. The significance of these results is that there are many regions in the

0

1000

2000

3000

0 100 200 300 400 500

Torq

uelb

f-

Timeseconds

12¼-in. Atmospheric Te g(Bedford, 5-25 klbs, 120 RPM, 2 hz)

Hybrid PDC RC

Fig. 13—Torque signature.

0

2000

4000

6000

200 300 400 500

Torq

uelb

f-

Timeseconds

16-in. Atmospheric Tes g(Bedford, 5-25 klbs, 120 RPM, 2 hz)

PDC Hybrid RC

Fig. 14—Torque signature.

Fig. 15—Segmented core section.

0

10

20

30

0 10 20 30 40

ROP

/hr

Depthin.

ROP vs. Depth(Segmented Core, 4,000 psi BHP), 120 RPM)

Hybrid RC PDC

Fig. 16—ROP signatures in segmented core.


world in which sections, or even entire wells, consist of highly het-erogeneous formations in which torsional oscillations negatively affect the performance and durability of the drill bit as well as the reliability of the bottomhole assembly (BHA) and drillstring.

Directional Drilling. In directional drilling, the issue of high torque oscillations in mixed and interbedded formations is com-pounded further by erratic WOB transfer, which causes additional torque spikes with aggressive PDC bits and makes tool-face con-trol almost impossible. Therefore, many directional drillers still choose roller-cone bits for more-diffi cult and -demanding jobs. As shown by the laboratory tests, the hybrid bit offers an alternative by being smoother running and more effi cient than a typical PDC bit and faster and more responsive to RPM than a conventional roller-cone bit.

Field TestingAfter demonstrating the potential technical merits of the hybrid bit, the next phase of the development work focused on testing the field worthiness and durability of prototype 77⁄8-in., 12¼-in., and 16-in. diameter hybrid bits. The first tests were performed on an experimental drill rig (Sinor et al. 2001a) that is capable of drilling 2,000- to 3,000-ft-deep holes through a variety of forma-tions, ranging from soft shale to medium-strength limestone and sandstone sections. No structural deficiencies were found in these relatively short (10- to 20-hour) tests, and the unique drilling characteristics of the hybrid bit that were observed in the labora-tory were confirmed.

Canada. The fi rst true fi eld test was run in Canada with the 12¼-in. three-cone, three-bladed hybrid bit in a surface hole. The fact that a hybrid bit requires less WOB than a roller-cone bit and runs smoother than a PDC bit proves to be an advantage in large-diameter surface-hole drilling, which is quite often either WOB or torque limited. As shown in the depth vs. ROP plot in Fig. 18, the hybrid bit outdrilled the offset PDC bit by approximately 33% and the roller-cone bit by 134%. The driller observed that the bit drilled surprisingly smoothly, and he was therefore able to apply almost as much WOB (24 vs. 28 kip) as on the offset roller-cone bit without experiencing bit bounce. Compared with the PDC bit, it was possible to run at much higher WOB (24 vs. 11 kip) and lower RPM (110 vs. 140) without experiencing stick/slip. The dull was green after the short 242-m, 10½-hour run.

Saudi Arabia. The 12¼-in. hybrid bit run in Saudi Arabia was a directional motor application in medium-strength carbonates. It started with a short vertical section, then kicked off and built from 0 to 83°. A typical offset PDC bit drilled this section of approximately

3,400 ft at an average ROP of 51 ft/hr (17% sliding/83% rotating).The hybrid bit drilled 3,454 ft in 72 hours at average ROP of 48 ft/hr, (40% sliding/60% rotating). The greater amount of sliding was mainly because of the tight clearance between the borehole wall and the gauge pads and roller-cone-bit legs, which constrained the building capabilities of the bit. The fi rst prototype hybrid bits were designed for maximum stability and straight holes, which resulted in a low tilt angle. The gauge clearance has been increased on second-generation designs, and no further “build” limitations were experienced. Overall, the run was considered a good run because it fell within 90% of the offset ROP and the directional drillers commented on the smooth running and good tool-face control, which was seen as a signifi cant benefi t to improve not only the quality of the directional-drilling process itself but also the service life and reliability of the complex and expensive BHA components used in directional drilling. The dull condition was good, as shown in Fig. 19, and particularly the condition of the bearings and seals was encouraging after a total of 1.2 million revolutions on the rolling cutters.

North Texas. The fi rst 77⁄8-in. hybrid bit with two cones and two blades was run in north Texas in a motor directional application that is typically drilled by roller-cone bits at an average ROP of 78 ft/hr. The hybrid bit drilled the 3,800-ft-long section to target depth 47% faster than a roller-cone bit at an ROP of 115 ft/hr. The directional capabilities were excellent, with good tool-face control and good ROP during sliding. Although the footage drilled was comparable to the offsets, the dull condition was poor, as shown in Fig. 20. It appeared that the shoulder and gauge on the PDC blades got dam-aged and wore fi rst, which then transferred the full load to the roller cones and damaged the entire bit beyond repair. There are many design options to further increase the wear resistance and durabil-ity of the smaller-diameter, lighter-set two-cone/two-blade designs, which are now being incorporated in new prototype designs.

West Texas. Another 12¼-in. test was run in West Texas, which is a straight-hole, motor application in which deviation control is critical and requires frequent control drilling to fan back to verti-cal. The application is generally considered non-PDC drillable because of streaks of hard sandstone and chert. Fig. 21 shows the performance of two hybrid bits run back to back. The average ROP of 26 ft/hr for the fi rst hybrid run from 8,112 to 9,506 ft was from 30 to 62% faster than the roller-cone-offset runs and one PDC run on motors at RPMs ranging from 100 to 135. In shale, the instantaneous penetration rate of the hybrid bits was more than double that of the roller-cone bits. The fastest roller-cone offset in Fig. 21 at 28 ft/hr was run with conventional rotary at 68 RPM without the differential-pressure limits of the motor and at much higher hydraulic horsepower at the bit. Although it is not a valid

0

2500

5000

7500

0 10 20 30 40

Torq

uelb

f-

Depthin.

Torque vs. Depth(Segmented Core, 4,000 psi BHP, 120 RPM)

Hybrid RC PDC

Fig. 17—Torque signature in segmented core.

24 klbs110 RPM

11 klbs140 RPM

28 klbs120 RPM

100

200

300

400

9 14 19 24

Dep

thm

eter

s

ROPm/hr

Depth vs. ROP12¼-in. Canada Field Test

Hybrid Offset PDC Offset RC

Fig. 18—Depth vs. ROP, Canada field test.


comparison, this run is included here to illustrate that the chosen motor differential, and not the bit type, frequently determines the overall ROP. It also confi rms that roller-cone bits in general benefi t little from higher RPM. The run was terminated by a ring out in the hard caprock containing chert. The second run was slower mainly because of the fact that it deviated early in the run and did not come back to vertical as fast as a conventional roller-cone bit because of the tight clearance between the borehole wall and the heavily reinforced gauge pads and bit legs. The majority of the run was spent fanning back to vertical at light WOB. The tight clearance has been recognized as a design issue and has been rem-edied on subsequent designs without sacrifi cing stability. The dull condition was PDC-cutter chippage and wear on the shoulder that was aggravated in the harder sections by the less-stable operating parameters of light WOB and high RPM.

These are only a few examples of the more than 15 field tests run with prototype bits. They highlight the main issues and oppor-tunities for the next generation of hybrid bits, which are now being designed and field tested. The main challenges are the durability of the shoulder/gauge area in hard and abrasive formations and the development of higher-capacity bearing and seal packages. The greatest opportunities to be fully explored are directional drilling and the superior stability of large-diameter bits.

ConclusionsLaboratory and field tests show that hybrid technology can be used to improve the drilling mechanics and dynamic stability of drill bits. Hybrid bits are highly application specific and should not be consid-ered as a direct replacement for either PDC or roller-cone bits. They have the potential to greatly enhance the performance of roller-cone

Fig. 19—Hybrid dull, Saudi Arabia field test.Fig. 20—Hybrid dull, north Texas field test.

Fig. 21—Hybrid performance, west Texas field test.

7500

8500

9500

10500

72329151

Dep

th

ROP/hr

West Texas Field Test With Offsets

Hybrid Hybrid RC Offset RC Offset

PDC Offset RC Offset RC Offset RC Offset

RC Offset PDC Offset RC Offset Linear (RC Offset)Rotary BHA


bits in shale and other formations that behave plastically and that are subject to bottom balling under high confining pressure. The performance of roller-cone bits can be enhanced further in motor drilling where the inherently poor response to RPM limits their potential. Hybrid bits are well suited for drilling heterogeneous and interbedded formations where roller-cone bits are too slow and PDC bits are subject to premature damage because of harmful vibrations. In directional drilling, the hybrid bit can provide the good tool-face control of a roller-cone bit at ROPs typical for a PDC bit. The favor-able dynamics of a hybrid bit are most beneficial in large-diameter bits, which are run at the WOB and torque limits of most rigs, drillstrings, and BHAs. The smoother running characteristics, lower torque oscillations, and generally lower vibrations of the hybrid bit will improve not only the drilling performance but also the reliabilty and service life of today’s complex and expensive BHAs.

AcknowledgmentsThe authors want to thank Baker Hughes for supporting the work and giving permission to publish this paper. Special thanks go to the “Hybrid Bit” team that enthusiastically took on the design and manufacturing challenges that come with the development of a new product.

ReferencesAl-Suwaidi, A.S., Soliman, A.A., Klink, Z., Isbell, M., Dykstra, M., and

Jones, C. 2003. New PDC Design Process Solves Challenging Direc-tional Application in Abu Dhabi Onshore Fields. Paper SPE 79796 presented at the SPE/IADC Drilling Conference, Amsterdam, 19–21 February. doi: 10.2118/79796-MS.

Baker, W. III, Garner, L.L., and Harris, C.R. 1982. Hybrid rock bit. US Patent No. 4,343,371.

Cooley, C.H., Pastusek, P.E., and Sinor, L.A. 1992. The Design and Test-ing of Anti-Whirl Bits. Paper SPE 24586 presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, 4–7 October. doi: 10.2118/24586-MS.

Holster, J.L., Estes, R.D., Castle, J., and Parys, P.G. 1992. Kerf-cutting apparatus for increased drilling rates. US Patent No. 5,145,017.

Hughes, H.R. 1915. A Modern Rotary Drill. Trans., AIME, 51 (February): 620–626.

Ledgerwood, L.W. III and Kelly, J.L. Jr. 1991. High pressure facility re-cre-ates downhole conditions in testing of full size drill bits. Paper ASME 91-PET-1 presented at the Energy Sources Technology Conference and Exhibition, New Orleans, 20–24 January.

Moffitt, S.R., Pearce, D.E., and Ivie, C.R. 1992. New Roller Cone Bits With Unique Nozzle Designs Reduce Drilling Costs. Paper SPE 23871 presented at the SPE/IADC Drilling Conference, New Orleans, 18–21 February. doi: 10.2118/23871-MS.

Murray, A.S. and Cunningham, R.D. 1955. Effect of Mud Column Pressure on Drilling Rates. Paper TP 4166 presented at the Petroleum Branch Fall Meeting, New Orleans, 2–5 October. Trans., AIME, 204: 196–204.

Pessier, R.C. and Fear, M.J. 1992. Quantifying Common Drilling Prob-lems With Mechanical Specific Energy and a Bit-Specific Coefficient of Sliding Friction. Paper SPE 24584 presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, 4–7 October. doi: 10.2118/24584-MS.

Schumacher, P.W. Jr., Jones, K.W., Murdoch, H.W., and Pastusek, P.E. 1984. Combination drag and roller cutter drill bit. US Patent No. 4,444,281.

Scott, F.L. and Bettis, I.H. 1932. Combination rolling and scraping cutter drill. US Patent No. 1,874,066.

Sinor, A., Powers, J., Ripp, C., Lovin, S., and McEntire, M. 2001a. Unique Field Research Facility Designed to Accelerate New Technology Devel-opment and Enhance Tool Reliability. Paper AADE 01-NC-HO-36 presented at the AADE 2001 National Drilling Conference, Houston, 27–29 March.

Sinor, L.A., Hansen, W.R., Dykstra, M.W., Cooley, C.H., and Tibbitts, G.A. 2001b. Drill bits with controlled cutter loading and depth of cut. US Patent No. 6,298,930.

Tandberg, G. 1993. Combination drill bit. US Patent No. 5,176,212. Tandberg, G. and Rodland, A. 1990. GT-BIT: A New Hybrid Design. Oil

Gas European Magazine 16 (1-1990): 36–38.Wells, M.R. and Pessier, R.C. 1993. The Effects of Asymmetric Nozzle

Sizing on the Performance of Roller Cone Bits. Paper SPE 25738 presented at the SPE/IADC Drilling Conference, Amsterdam, 22–25 February. doi: 10.2118/25738-MS.

Rolf Pessier is a Research and Development Fellow for Baker Hughes. The focus of his work is the development and appli-cation of new drilling tools and technologies. Pessier received his education in Germany graduating with a Diplom Ingenieur degree in mining from the Technical University Clausthal. His professional career with Hughes Tool Company started in 1968 in engineering working on tunnel machines and shaft drilling equipment. In the late seventies, Pessier transferred from engi-neering to research to concentrate on the development of leading edge drill bit technologies. His key areas of interest are drilling mechanics, high pressure hydraulics, and the unique behavior of rocks under hydrostatic pressure. Pessier has been granted more than 50 US patents and published numerous technical papers. He is a member SPE and has served on the technical program committee. Michael Damschen is a mechanical engineer in the Product Development Group of Baker Hughes, Inc. located in The Woodlands, TX. His area of expertise is bit dynamics and hydraulics. Damschen received his BS in mechanical engineering from The University of Texas at Austin. He is a member of SPE and registered professional engineer (P.E.) in the state of Texas.

Documents

Hybrid Bits Offer Distinct Advantages in Selected Roller-Cone and PDC-Bit Applications