Diamond Bit Select

Diamond Drill Bits

Bit Selection & Application Click on the titles below to view the Documents. When you are  finished, shut down Adobe Acrobat to return to the Hughes Christensen Electronic Catalog.

Table of Contents (-- Application Guide

2

(-- Product Nomenclature

3

(-- API Diamond Bit   Tolerance

4

(-- TFA Values

4

(-- API Connection Chart

4

(-- Operating Guidelines For  PDC Bits

5

(-- PDC Application Check   List

6

(-- Recommended Make-Up   Torque

7

Diamond Product Applications

Diamond Product Applications Bit Applications Conventional Multipurpose Hard Abrasive Soft Abrasive Plastic Shales Steerable Slimhole Vibration Control Balling Hard Rock Turbine Hole Enlargement – Rotary Hole Enlargement – Steerable Hole Enlargement – Slimhole

ABD BD BDH BDS BDP BX STR

AG

G

S

RWD SRWD STRWD

Diamond Product Nomenclature

ABD, BD (Black Diamond) Series Diamond Compact Bits

STR (STAR) Series Diamond Compact Bits

Black Diamond is a premium line of multi-purpose bits, custom designed for specific applications. Utilizing “Application Engineered Cutters” and “Engineered Cutter Layouts”, Black Diamond bits can be tailored to meet the unique requirements of specific formations and operating parameters. Designs also utilize new hydraulics, gauge design and streamlined geometry.

This is a premium line of small diameter PDC bits. Gold Series features like Stress Engineered Cutters, Carbide Supported Edge geometry and Black Ice polished cutters make these the right choice for the challenges of slim hole and directional applications. Where steerability is a concern, STAR bits are available with increased cutter back rake, and wearknots to limit torque variability.

BX (Black Trax) Series Diamond Compact Bits

S-Series BallaSet Bits

BlackTrax is a revolutionary line of PDC bits designed specifically for steerable applications. BlackTrax bits feature a long tandem gauge. This less aggressive gauge with limited side cutting action, has improved steerability and delivers a quality wellbore. BlackTrax bits take advantage of Engineered Cutter Technology. Each bit’s cutter configuration is tailored for a specific application. Like BD bits, BX bits incorporate new hydraulics, gauge design and streamlined geometry.

S series bits utilize thermally-stable polycrystalline diamond cutters to drill medium to hard formations, or diamond impregnated segments to drill hard, abrasive formations.

D-Series Natural Diamond Bits The D Series bits are surface set with natural diamonds of various grades and concentrations to drill a variety of harder, more abrasive formations.

AG/G (Gold) Series Diamond Compact Bits Designed for conventional drilling, the AG/G bits feature Stress Engineered Cutters, Engineered Cutter Placement, Carbide Supported Edge, and Black Ice polished Cutters. AG Series bits incorporate Anti-Whirl technology to extend their life and application range.

Diamond Drill Bit Series PDC*

BallaSet

Natural Diamond

BallaSet/Natural Diamond

Spectrum Technology Black Diamond Anti-Whirl Black Diamond BlackTrax Auto Trak** Conventional PDC Gold Series Anti-Whirl Gold Series Impregnated PDC BallaSet

BD ABD BX TX** G AG S

Natural Diamond

D, T

SD Combination *PDC Cutter Size is identified by the first digit of the bit nomenclature 3 = 3/8” cutter 4 = 1/2” cutter 5 = 3/4” cutter i.e. BD554 has 3/4” cutters **Designed for use in conjunction with Baker Hughes INTEQ’s AutoTrak Rotary Steerable Tool

SD

Technical Data

TFA VALUES OF COMMON NOZZLE SIZES NUMBER OF NOZZLES 1

2

3

4

5

6

7

8

9

10

7

.0376

.0752

.1127

.1503

.1877

.2255

.2631

.3007

.3382

.3758

8 9 10

.0491 .0621 .0767

.0982 .1242 .1534

.1473 .1864 .2301

.1963 .2485 .3060

.2454 .3106 .3835

.2945 .3728 .4602

.3435 .4249 .5369

.3927 .4970 .6136

.4418 .5591 .6903

.4909 .6213 .7670

11 12 13 14

.0928 .1104 .1296 .1503

.1856 .2209 .2592 .3007

.2784 .3313 .3889 .4510

.3712 .4418 .5185 .6013

.4640 .5522 .6481 .7517

.5568 .6627 .7777 .9020

.6496 .7731 .9073 1.0523

.7424 .8836 1.0370 1.2026

.8353 .9940 1.1666 1.3530

.9281 1.1045 1.2962 1.5033

15 16

.1726 .1963

.3451 .3927

.5177 .5890

.6903 .7854

.8629 .9817

1.0354 1.1781

1.2080 1.3744

1.3806 1.5708

1.5532 1.7671

1.7258 1.9634

18 20 22

.2485 .3068 .3712

.4970 .6136 .7424

.7455 .9204 1.1137

.9940 1.2272 1.4849

1.2425 1.5340 1.8561

1.4910 1.8408 2.2273

1.7395 2.1476 2.5986

1.9880 2.4544 2.9698

2.2365 2.7612 3.3410

2.4850 3.0680 3.7122

NOZZLE SIZE IN 32nds

API DIAMOND BIT TOLERANCES NOMINAL BIT SIZE O.D. inches

O.D. TOLERANCE inches

mm*

up to 6 3 / 4, incl. 6 25 / 32 to 9, incl. 9 1 / 32 to 13 3 / 4, incl. 13 25 / 32 and larger

+0. - 0.015 +0. - 0.020 +0. - 0.030 +0. - 0.045

+0 - 0.38 +0. - 0.51 +0. - 0.76 +0. - 1.14

*Converted from inches

API CONNECTION CHART BIT O.D. RANGE inches 4-

45 / 8

4 1 / 2

-

4 3 / 4

55 / 8 - 6 3 / 4

API REG. PIN CONN inches 23 / 8

143 / 4 - 171 / 2 *Converted from ft - lbs

2.4 - 2.7 3.3 - 3.7 4.2 - 4.6

1.8 - 2.0 2.4 - 2.7 3.1 - 3.4

3 31 / 8 31 / 4

4.2 - 4.6

3.1 - 3.4

31 / 2

6.2 - 6.9

4.6 - 5.1

33 / 4

31 / 2

7.1 - 7.7 8.5 - 9.4 10.4 - 11.4

5.2 - 5.7 6.3 - 6.9 7.7 - 8.4

41 / 8 41 / 4 1 4  / 2 & larger

41 / 2

16.9 - 18.6 22.4 - 24.5 23.9 - 26.3

12.5 - 13.7 16.5 - 18.1 17.6 - 19.4

51 / 2 53 / 4 6 & larger

50.3 - 55.3

37.1 - 40.8

71 / 2

-9

95 / 8 - 121 / 4

BIT SUB O.D. inches

27 / 8

73 / 8 - 77 / 8 83 / 8

RECOMMENDED MAKE-UP TORQUE RANGE kNm* 1000 ft-lbs

75 / 8

51.5 - 56.7

38.0 - 41.8

65.5 - 72.0 78.2 - 86.1 81.3 - 89.5

48.3 - 53.1 57.7 - 63.5 60.0 - 66.0 NOZZLE SIZE IN 32nds

31 / 8

1

41 / 8

11 / 4

43 / 4

11 / 2

53 / 4

13 / 4

63 / 4

13 / 4

8

3

93 / 4

3

111 / 2

3

& larger

65 / 8 73 / 4

SHANK SIZE O.D. I.D. inches inches

& larger

81 / 2 83 / 4 9 & larger

Operating Guidelines for PDC Bits General Information Under the right combination of formation and operating conditions, all bits are subject to whirl and related cutter impact damage. HCC anti-whirl bits are designed to provide a much wider range of operating parameters and conditions under which the bit will not whirl. To take advantage of the unique features of these bits, it is necessary that the bits be run properly. In general, slower rotary speeds and higher weights than “typically” applied to PDC bits are preferred as a means of producing the desired penetration rates. It is also important that the proper procedures be followed starting the bit and when making connections. Following these procedures will assure maximum bit life and ROP. Pre-Run Preparation: Proper inspection of the previous bit is important to determine hole gauge conditions and if there are any pieces missing from the bit that could cause damage during the next run. Stabilization has proven effective in maintaining straight hole and maximizing bit performance and is recommended for all PDC bit applications. However, local experience or hole conditions may not require that stabilization be run. All stabilizers and roller reamers should be ring-gauged to be sure that they are not oversized. Operating Guidelines Rotary Applications:  1.With the bit just off bottom, bring the pumps up to full flow and start the rotary table at 30-60 rpm. 2.Drill the first few feet at the start-up weight-on-bit to establish the new bottomhole pattern. Tables are supplied with the correct start-up WOB for each bit size and style. The start-up parameters should be used for at least the length of the bit. 3.After the bit has formed its own bottomhole pattern, increase the weight on bit smoothly and evenly to the normal drilling weight on bit. In very soft formations this may be very close to the start-up WOB. Harder formations will take longer to break-in and eventually require higher operating weights. Optimal WOB is that point at which additional weight does not increase the penetration rate or the torque limit is reached. 4.The rotary speed can now be increased to the desired level. The optimal rotary speed is that point at which additional rpm does not increase the rate of penetration or the torque limit is reached. Softer formations will generally be more responsive to increases in rpm. In harder and more abrasive formations high rotary speeds can cause the cutters to wear prematurely. It is important to monitor the rop vs. rpm to ensure that lowest rpm is used for the desired penetration rate. Generally, the recommended operating range is 60-240 rpm.

5.Continual monitoring and adjusting of operational parameters as lithology changes are encountered will maximize bit life and penetration rates. Making a Connection:  Making a connection follows a similar procedure to starting up but without the break-in period. 1.At the end of the Kelly, lower the rotary to 30-60 rpm. 2.Clamp the brake and allow for a portion of the weight-on-bit to drill-off for several minutes. 3.Stop the rotary as the bit is lifted off bottom. 4.After making the connection, wash back to bottom at full circulation. Start the rotary at 30-60 rpm. 5.First increase the weight on bit and secondly the rotary speed as indicated in the prior section. Downhole Motor and Directional Applications:  It is recognized that control of the rpm range of the bit is limited in applications that use downhole motors. In general, the harder the formation, the lower the rpm should be. Therefore, it is important to know the application range the bit is required to drill and use the appropriate downhole motor configuration. AR-Series bits extend PDC applications into harder formations and are recommended to be run on high torque/low speed motors. Current information suggests that in directional applications, AR-Series bits may build angle slightly slower than a conventional PDC bit. Therefore, insure that there is sufficient room in the directional plan to adjust for a slightly slower build rate. Local experience will dictate the amount of adjustment. Reference SPE paper #24614 documenting directional field testing of anti-whirl bits. 1.Lower the bit bottom with half the normal drilling flow rate. Simultaneously bring up the weight and pump speed as drilling is initiated. If the bit is started in a very soft formation where bit balling is a possibility, full flow is recommended. The softness of the formation will probably cause little or no damage to the cutters and sufficient depth of cut will result in stable drilling in short order. 2.When a directional assembly is being utilized in the rotary mode, keep the drill pipe speed slow (20-40 rpm). Signs of Bit Whirl During the run:  1.Low penetration rates (120 RPM). 2.Non-linear ROP response to changes in RPM. 3.Drill string vibration. What to do if you suspect a bit is whirling:  1.Slow the rotary speed to 30-60 RPM. 2.Increase weight-on-bit until ROP is 12 ft./hr. or more. (Do not exceed maximum recommended WOB.) 3.Incrementally increase RPM and plot RPM vs. ROP (curve should be linear if the bit and drill string are not whirling.)

PDC Bit Application Check List Formation Considerations

Float Equipment

* PDC bits are sensitive to changes in lithology. Optimum parameters are formation dependent and change with formations drilled.

* Float equipment must be PDC compatible if drilled.

* PDC bits are mostly used in soft to medium formations where a large amount of cuttings is generated. Hydraulic energy is required to clean and cool the bit and is one of the most important factors affecting ROP. * PDC cutter wear is accelerated with high RPMs and high WOB when drilling hard and abrasive stringers. For extended bit life, use of low RPMs (approximately 80-120) and lowest possible WOB is recommended.

Bit Preparation * Check prior bit run  for broken teeth or inserts. If necessary, a junk basket run should be made. Junk in the hole results in early damage of the PDC bit. (Use of a junk basket on bit run prior to the PDC bit run is recommended.) * Remove PDC bit from box using a board or board mat placed under bit to avoid damage. Do not roll bit on steel, cement or similar surface. * Inspect PDC bit  prior to going in the hole to ensure there are no obstructions or foreign matter in it. * Gauge nozzles before RIH. * Prepare thread connection with dope and torque to API recommendations. A bit breaker should be used for make-up torque.

* WOB & RPM should be kept as low as possible and yet sufficiently high to drill the equipment (approximately: RPM=80, WOB=6Klbs.). * Allow WOB to drill off prior to applying additional weight. * Keep flow rate  at full volume to prevent damage to cutters with high uneven loading.

Bit Break-In * Before bit break-in, compare expected hydraulic calculations with actual hydraulic readings to detect plugged nozzles, blown nozzles or pump problems before bit is on bottom. * Soft formations: Bit break-in should be with maximum flow rate (approximately RPM=100, WOB=2-4 Klbs.). After 3-4 feet have been drilled, optimize parameters to begin to maximize ROP. * Firmer formations: More time should be spent establishing bottom hole pattern. RPM should be kept near 80-120 and WOB should be increased in increments of 2 Klbs until drill-off begins. After 2-3 feet of hole is drilled in this manner, increase operating parameters to achieve optimum ROP. * Hand and abrasive stringers:  Low RPMs (approximately 80-120) and lowest possible WOB should be used.

Drilling, Connections, Tripping Out of Hole

* Caution should be taken when passing through the BOPs, casing shoes and liner hangers.

* Drill off before picking up off bottom for next single/stand. This practice is useful to reduce thermal shocks of the PDC cutters, especially when drilling firmer formations.

* Slowly approach known tight intervals and sections of high dog leg severity and proceed carefully.

* After making connections, return to full flow rate while WOB and RPM should be increased gradually.

* Avoid reaming with compact bits. Short sections can be reamed with very light WOB (approximately 2-4 Klbs), maximum flowrate and moderate rotary speed.

* When tripping out of the hole, slow down through known tight spots to avoid gauge damage. Be aware that PDC bits are full gauge and could readily swab a well if pulled too fast. Again, slow down through casing shoe, liner hangers and BOPs to avoid bit damage.

Tripping in the Hole

* Wash down last single/stand slowly with maximum flow rate. * Tag bottom with pumps on. Circulate approximately 6”-12” off bottom for several minutes. If any fill is known to be on bottom, circulation should be considerably longer, while working pipe.

* PDC bit should be set on a board or board mat. Never stand bit back on steel drill floor.

Recommended Make-up Torque

Diamond Drill Bit Recommended Make-up Torque API Reg. Pin Conn.

Recommended Make-up Torque Range

Bit O.D.

inches

kNm*

1000 ft-lbs

inches

23 / 8

2.4 – 2.7 3.3 – 3.7 4.2 – 4.6

1.8 – 2.0 2.4 – 2.7 3.1 – 3.4

3 3 1 / 8 3 1 / 4

27 / 8

4.2 – 4.6 6.2 – 6.9

3.1 – 3.4 4.6 – 5.1

3 1 / 2 3 3 / 4 & larger

31 / 2

7.1 – 7.7 8.5 – 9.4 10.4 – 11.4

5.2 – 5.8 6.4 – 7.1 7.7 – 8.6

4 1 / 8 41 / 4 41 / 2 & larger

41 / 2

16.9 – 18.6 22.4 – 24.5 23.9 – 26.3

12.5 – 13.7 16.5 – 18.1 17.6 – 19.4

5 1 / 2 5 3 / 4 6 & larger

65 / 8

50.3 – 55.3 51.5 – 56.7

37.1 – 40.8 38.0 – 41.8

7 1 / 2 7 3 / 4 & larger

75 / 8

65.5 – 72.0 78.2 – 86.1 81.3 – 89.5

48.3 – 53.1 57.7 – 63.5 60.0 – 66.0

8 1 / 2 8 3 / 4 9 & larger

85 / 8

92.2 – 95.9

125.0 – 130.0

12