Diamond Bit Select

(-- Application Guide

(-- Application Guide

(-- Product Nomenclature

(-- Product Nomenclature

(-- API Diamond Bit

(-- API Diamond Bit

Tolerance

Tolerance

(-- TFA Values

(-- TFA Values

(-- API Connection Chart

(-- API Connection Chart

(-- Operating Guidelines For 

(-- Operating Guidelines For 

PDC

PDC Bits

Bits

(-- PDC Application Check

(-- PDC Application Check

List

List

(-- Recommended Make-Up

(-- Recommended Make-Up

Torque

Torque

Table of Contents

Table of Contents

Bit Selection

Bit Selection

&

&

Application

Application

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Hughes Christensen Electronic Catalog.

Hughes Christensen Electronic Catalog.

Diamond Drill Bits

Diamond Drill Bits

2 2 3 3 4 4 4 4 4 4 5 5 6 6 7 7

Diamond Product Applications

Diamond Product Applications

Bit Applications ABD BD BDH BDS BDP BX STR AG G S RWD SRWD STRWD

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

Diamond Product Nomenclature

ABD, BD (Black Diamond) 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.

BX (Black Trax) Series Diamond Compact 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.

AG/G (Gold) Series Diamond Compact Bits

Designed for conventional drilling, the AG/G bits fea-ture 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.

STR (STAR) Series Diamond Compact Bits

This is a premium line of small diameter PDC bits. Gold Series features like Stress Engineered Cutters, Carbide Supported Edge geometry and Black Ice pol-ished cutters make these the right choice for the chal-lenges of slim hole and directional applications.

Where steerability is a concern, STAR bits are avail-able with increased cutter back rake, and wearknots to limit torque variability.

S-Series BallaSet Bits

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 dia-monds of various grades and concentrations to drill a variety of harder, more abrasive formations.

Diamond Drill Bit Series

PDC* BallaSet Natural Diamond BallaSet/Natural Diamond

Spectrum Technology

Black Diamond BD Anti-Whirl Black Diamond ABD BlackTrax BX Auto Trak** TX** Conventional PDC

GoldSeries G Anti-Whirl Gold Series AG Impregnated PDC

BallaSet S

Natural Diamond D, T

SD Combination SD

*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

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 .0491 .0982 .1473 .1963 .2454 .2945 .3435 .3927 .4418 .4909 9 .0621 .1242 .1864 .2485 .3106 .3728 .4249 .4970 .5591 .6213 10 .0767 .1534 .2301 .3060 .3835 .4602 .5369 .6136 .6903 .7670 11 .0928 .1856 .2784 .3712 .4640 .5568 .6496 .7424 .8353 .9281 12 .1104 .2209 .3313 .4418 .5522 .6627 .7731 .8836 .9940 1.1045 13 .1296 .2592 .3889 .5185 .6481 .7777 .9073 1.0370 1.1666 1.2962 14 .1503 .3007 .4510 .6013 .7517 .9020 1.0523 1.2026 1.3530 1.5033 15 .1726 .3451 .5177 .6903 .8629 1.0354 1.2080 1.3806 1.5532 1.7258 16 .1963 .3927 .5890 .7854 .9817 1.1781 1.3744 1.5708 1.7671 1.9634 18 .2485 .4970 .7455 .9940 1.2425 1.4910 1.7395 1.9880 2.2365 2.4850 20 .3068 .6136 .9204 1.2272 1.5340 1.8408 2.1476 2.4544 2.7612 3.0680 22 .3712 .7424 1.1137 1.4849 1.8561 2.2273 2.5986 2.9698 3.3410 3.7122 NOZZLE SIZE IN 32nds

API DIAMOND BIT TOLERANCES

NOMINAL BIT SIZE O.D. O.D. TOLERANCE inches inches mm* up to 63 _{/ 4,incl. +0.-0.015 +0-0.38} 625 _{/ 32to 9, incl. +0. - 0.020 +0. - 0.51} 91 _{/ 32 to 13}3 _{/ 4, incl. +0. - 0.030 +0. - 0.76} 1325 _{/ 32and larger +0. - 0.045 +0. - 1.14}

*Converted from inches

API CONNECTION CHART

BIT O.D. RANGE _PIN API REG._CONN RECOMMENDED MAKE-UP_{TORQUE RANGE} BIT SUB_{O.D. O.D.}SHANK SIZE_I.D. inches inches kNm* 1000 ft-lbs inches inches inches

2.4 - 2.7 1.8 - 2.0 3 4 - 41 _{/ 2 2}3 _{/ 8 3.3 - 3.7 2.4 - 2.7 3}1 _{/ 8 3}1 _{/ 8 1} 4.2 - 4.6 3.1 - 3.4 31 _/ 4 4.2 - 4.6 3.1 - 3.4 31 _/ 2 45 _{/ 8- 4}3 _{/ 4 2}7 _{/ 8 4}1 _{/ 8 1}1 _/ 4 6.2 - 6.9 4.6 - 5.1 33 _{/ 4 & larger} 7.1 - 7.7 5.2 - 5.7 41 _/ 8 55 _{/ 8- 6}3 _{/ 4 3}1 _{/ 2 8.5 - 9.4 6.3 - 6.9 4}1 _{/ 4 4}3 _{/ 4 1}1 _/ 2 10.4 - 11.4 7.7 - 8.4 41 _{/ 2 & larger} 73 _{/ 8- 7}7 _{/ 8 16.9 - 18.6 12.5 - 13.7 5}1 _{/ 2 5}3 _{/ 4 1}3 _/ 4 41 _{/ 2 22.4 - 24.5 16.5 - 18.1 5}3 _/ 4 83 _{/ 8- 9 23.9 - 26.3 17.6 - 19.4 6 & larger 6}3 _{/ 4 1}3 _/ 4 50.3 - 55.3 37.1 - 40.8 71 _/ 2 95 _{/ 8- 12}1 _{/ 4 6}5 _{/ 8 8 3} 51.5 - 56.7 38.0 - 41.8 73 _{/ 4& larger} 65.5 - 72.0 48.3 - 53.1 81 _{/ 2 9}3 _{/ 4 3} 143 _{/ 4- 17}1 _{/ 2 7}5 _{/ 8 78.2 - 86.1 57.7 - 63.5 8}3 _/ 4 81.3 - 89.5 60.0 - 66.0 9 & larger 111 _{/ 2 3}

Operating Guidelines for PDC Bits

General Information

Under the right combination of formation and operat-ing 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 fol-lowed 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 forma-tions 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 for-mations 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 sug-gests 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 start-ed 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 (<12 ft./hr.) at high rotation speed (>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

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

* PDC bits are mostly used in soft to medium forma-tions 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.

Tripping in the Hole

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

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

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

* 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 consid-erably longer, while working pipe.

Float Equipment

* Float equipment must be PDC compatible if drilled. * WOB & RPM should be kept as low as possible and

yet sufficiently high to drill the equipment (approxi-mately: 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 maxi-mum 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 operat-ing parameters to achieve optimum ROP.

* Hand and abrasive stringers: 

Low RPMs (approximately 80-120) and lowest pos-sible WOB should be used.

Drilling, Connections, Tripping Out of Hole

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

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

* 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 2.4–2.7 1.8– 2.0 3 23 _{/ 8 3.3–3.7 2.4 –2.7 3}1 _/ 8 4.2 – 4.6 3.1 – 3.4 31 _/ 4 27 _/ 8 4.2 – 4.6 3.1 – 3.4 31 / 2 6.2–6.9 4.6–5.1 33 _{/ 4& larger} 7.1–7.7 5.2 –5.8 41 _/ 8 31 _{/ 2 8.5–9.4 6.4 –7.1 4}1 _/ 4 10.4 – 11.4 7.7 – 8.6 41 _{/ 2& larger} 16.9 – 18.6 12.5 – 13.7 51 _/ 2 41 _{/ 2 22.4 – 24.5 16.5 – 18.1 5}3 _/ 4 23.9 – 26.3 17.6 – 19.4 6 & larger 65 _/ 8 50.3 – 55.3 37.1 – 40.8 71 / 2 51.5 – 56.7 38.0 – 41.8 73 _{/ 4& larger} 65.5 – 72.0 48.3 – 53.1 81 _/ 2 75 _{/ 8 78.2 – 86.1 57.7 – 63.5 8}3 _/ 4 81.3 – 89.5 60.0 – 66.0 9 & larger 85 _{/ 8 92.2 – 95.9 125.0 – 130.0 12}