Bit Presentation

Bits and Related EquipmentPresentation 11

DRILLING TECHNICIAN SCHOOL ExxonMobil Development Company

Houston, Texas

2004

Sam Pickett

Mill Tooth Bit

Roller Cone Bits

• Soft formation bits are designed to have 2-5 degrees of offset (skew)

• Offset is what allows for the dragging action (increases the bottom hole action)

Roller Cone Bits

• Offset (angle or distance)

• Note: 0 offset would show the center lines of the cones intersecting at center of bit.

Roller Cone Bits

Soft formation milltooth bit. Note thedragging actiondue to offset.

Roller Cone Bits

• Hard formation mill tooth bits are designed to have 0 offset (or 0 skew)

• Thus, hard formation mill tooth bits have a true rolling action as seen in the next slide

• The rolling action provides a better crushing action needed for harder formations

Hard formation milltooth bit. Note thetrue rolling action - crushing(no dragging).

Roller Cone Bits

Soft Hard

Roller Cone Bits

Roller Cone Bits

• Soft roller cone bits have:– Less teeth and longer teeth– Large offset (or skew)– Small journal angle (30-36 degrees)– Large cone angle

• Hard roller cone bits have:– More teeth and shorter teeth– No offset (or skew)– Large journal angle– Small cone angle

Tungsten Carbide Insert Bit

Roller Cone Bits

• Insert bits originally designed to drill harder formations with a crushing action (hammer)

• Load applied via inserts to overcome the compressive strength of the formation

Button transfers load to the formation and chips rock away

Roller Cone Bits

• Today, mill tooth bits are usually used for soft shallow formations and insert bits are more common in the medium to hard range

Roller Cone Bits

• Bearing Types– Unsealed Roller Bearings– Sealed Roller Bearings– Sealed Journal Bearings (friction bearings)

Roller Bearings

Ball Bearings

Ball Bearings

Journal Bearing

Lubrication System

R1 ATX1 ATXG1 ATJ1/1S ATJG1H, MX1 Y11 S11 EMS11G/11DHHP11 MHT11G DSJ SDS MSDSH/0D FDS FDS+2GTX1 GTXG1 ATM1/1S GTG1/H, STR1 MS11G/11DH HP11+ MHT11DH MSDSSH/OD FDS+ FDSS+2

MAXG1/GT1 GT1 ATMG1/G1S EHT11 FDSS+MFDSH/0DATMGT1 MFDSSH

R2 ATJ2 Y12 EHP12 DTJ SDT FDTEHT12HP12

R3 ATX3 ATXG3, GTXG3 ATMG3 Y13 EMS13G HP13 HP13G DGJ SDGH FDG FDGHGTX3 MAXGT3 ATMGT3 EMS13DH MHP13G MSDGH/0D MFDGH/OD

MS13G MHT13GETS13G MHT13DH

R4 ATJ4 ATJG4 MS216 HP21 HP21G V2J SVH FV FVHS216

DR5 HP31GS31G

R7

ATJG8ATX05 ATJ05, MX03 EMS41H EHP41/41H M01S0D F02TGTX00/03 ATMGT00/03 EMS41HDH EHP41ADH M02S0D 02MFMAX05 ATM05, GT03 MS41H HP41A M02S, M02TMAXGT00/03 STR03, H03 02M

ATJ05C, MX09C M05S, M05SOD F05/05TMX09CG, GT09C M05T, 05M MF05/0DSTR05C, H09C 05MD MF05T, F07

05MF, 05MFDATX11/11H ATJ11/11S EMS43A/DH EHP43/43A/43H M1S/0D, M10T F1, F10D/10TGTX09 ATJ11H, GT09 MS43A-M EHP43ADH/HDH M12T/TY F12T, MF10TMAX11H ATM11/11H MS43AD-M HP43/43A 10M/MD MF1/12MAXGT09 ATMGT09 S43A HP43A-M 12M/MD/MY MF10D/120D

MX09/09G HP43-M 10MF/MFDSTR09, H09 12MF/MFD

12MFY, F14TATX11C ATJ11C, MX18 EMS44H/HDH HP44/44M M15S/SD/S0D F15/15OD, F15TMAXGT18 GT18/18C EMS44A/ADH EHP44H/HDH M15T, 15JS MF15/15D/15TGTX18 H18/18C S44A, MS44A 15M/MD MF15OD, MA15

ATMGT18 15MF/MFDATM11C/11CG

ATX22 ATJ22/22S EMS51A/51H EHP51/51A/51H A1JSL, MA1SL A1, F15H/15HTGTX20 ATM22/22G EMS51ADH EHP51ADH/HDH M2S/2SD/2S0D MF15H, F17MAX22 MX20/20G MS51A, S51A EHP51X, EMS51A M20T, 2JS F25/25A/25ODMAXGT20 GT20/20S MS51A-M HP51/51A/51A-M 20M, 20MD F2/2H/2D, 20MF

H20/20B/20C MS51ADHM HP51H/51H-M F20D/20TSTR20 ETS51/51H HP51X/51X-M MF2/2D, 25MF

MF20T/25T20MFD, MF2HD

MAXGT20CG ATJ22C, MX28 S52A HP52/52A/52X M27S, M3S0D F27/27D/27AGTX20C GT28/28C/20C HP52-M F27I, MF27/27D

ATM28/22C 20MFYODH28/28CATJ33/33A/33S EMS53A, MS53 EHP53/53A/53DH M3S, M3SOD F3/3D/30DATM33, STR30 MS53DH, S53A EHP53ADH 3JS F3H/3HODMX30/30G HP53/53A/53A-M MF3/3D/3HGT30, H30 HP53ADH MF30D/30T

HP53ADGH 30MFHP53-JA

MAXGT30CG ATJ33C/35C HP54 F35/35AGTX30C ATM33C, GT30C F37/37A

MX35C/35CG F36H, F37DSTR30C/35C F37OD, F37DDPD

MF37/37DMF37DDPD

G44 ATJ44/44A/44G EHP61/61A/61DH 4GA 4JS F4/4A/4H/4ODHR40, STR40 EHP61ADH F45H, F47/47OD

HP61/61A/61ADH F47A, MF47ODHP61DH F45A

MAX44C ATJ44CA Y62JA MS62/62DH EHP62/62A/62DG 47JA 5JS F47H/47HODATJ44C/A S62A HP62/62A/62JA 5GA F5/5ODMX40CG, HR40C HP62DH/62ADH MF5/5DSTR40C/44C

G55 MAX55 ATJ55/55A Y63JA EMS63, S63A EHP63 M57S F57/57D/57ODATJ55R/55RG HP63/63DH M57SD F57DDPDHR50/50R M57SOD MF57DDPDSTR50/50R MF57OD, F57AATJ66, HR60 HP64 F65OD, F67/67OD

G77 STR70, HR70 Y73JA EHP73, HP73 7GA F7/7OD/7DDPDATJ77 HP73DH 7JASTR80, HR80 HP74 F80DHR80B,ATJ88

G99 ATJ99 EHP83/83DH 9JA F9, F9ODY83JA HP83/83DH

XN1 XT1 XS1XSC1XL1XLC1

XN3 XT3 XS3XL3

XN4 XT4 XS4XL4

XN5

XT(D)00 to 05(D) XS(D)00 to 05(D)XL(D)00 to 05(D)











XT(D)61, 63, 65, 67, 69(D) XS(D)61, 63, 65, 67, 69(D)XT(D)71, 73, 75(D) XS(D)71, 73, 75(D)

XT(D)77, 79, 81(D) XS(D)77, 79, 81(D)

XT(D)83, 85, 87, 89(D) XS(D)83, 85, 87, 89(D)XT(D)91, 93(D) XS(D)91, 93(D)XT(D)95, 97(D) XS(D)95, 97(D)XT(D)99(D) XS(D)99(D)

NOTE: This chart shows the IADC code relationshipbetween specific bit types. Bit classifications are

general and are to be used only as simple guides.(Since bit changes are constantly being made, check

with a Security DBS representative if you desire acertain type which is not shown.)

HUGHES REED SMITH

STANDARD ROLLER BEARINGROLLER BEARING AIR COOLED

ROLLER BEARING GAGE PROTECTEDSEALED ROLLER BEARING

SEALED ROLLER BEARING GAGE PROTECTEDSEALED FRICTION BEARING

SEALED FRICTION BEARING GAGE PROTECTED1 2 5 6 7 1 2 4 5 6 74

1 5 6 72 3 4

1 2 3 4 5 6 7

SECURITY DBS

STEELTOOTHSOFT

STEELTOOTH

MEDIUMSTEELTOOTHHARD

INSER TVERYSOFT

INSER TSOFT

INSER TMEDIUM

INSER THARD

INSER TVERYHARD

1

2

3

4

5

6

7

8

3

1

121

32

4

1

3

2

4

1

3

2

4

1

3

2

412

3

123

2

4

• Find a Security DBS bit with the following specifications– Medium insert (6)– Hardness subset level (1)– Sealed friction bearing with gage protection

Answer: SEC XS40 - 45 or XL40 - 45

Types of Bits - Roller Cone

• What is the IADC number code for this bit?

Answer: 617

Roller Cone Bits

• Find an equivalent Hughes bit.

Answer: ATJ44

Roller Cone Bits

• Fixed Cutter Bits PDC Bits Natural Diamond Bits Diamond Impregnated Bits

Fixed Cutter Bits

Steel Drag Bit (Fish Tail)

PDC Cutters

Ring Claw Cutter

Steel Body PDC Bit Matrix Body PDC Bit

PDC Bits

Steel Body Bit (FS2441) Matrix Body Bit (FM2443)

Different PDC Body Types

Medium Hard Diamond Bit Hard Diamond Bit

Impreg Bits

Factors Effecting ROP

What effects ROP?– 1. Formation Characteristics– 2. Differential Pressure (Overbalance)– 3. Mud Type and Properties– 4. Bit Hydraulics (nozzles, HSI)– 5. Directional (slide vs. rotary)

1. Formation Characteristics• Drillability relates to Compressive Strength and Abrasiveness


Classification Compressive Strength Lithology Bit Type ( PSI )

Very Low Strength less than 4000 Anhydrite PDCChalk PDCSalt PDCSandstone PDCShale PDC

Low Strength 4000 - 8000 Anhydrite PDCChalk PDCLimestone PDCSalt PDCSandstone PDCShale PDC

Fixed Cutter Selections based onRock Compressive Strengths


Medium Strength 8000 - 16,000 Anhydrite PDCBasalt DiamondChalk PDCDolomite TSPLimestone PDCSandstone PDCShale PDC

High Strength 16,000 - 32,000 Basalt Diamond / Impreg Chert TSP/Diamond/Impreg

Sandstone TSP / DiamondShale TSP / DiamondLimestone TSP / Diamond



Very HighStrength Greater than 32,000 Basalt Diamond / Impreg

Chert Diamond / ImpregDolomite Diamond / ImpregGranite Diamond / ImpregLimestone Diamond / ImpregQuartzite Diamond / ImpregVolcanic Tuff Diamond / Impreg


• Differential Pressure (Overbalance) significantly effects ROP

• Differential Pressure is the difference between the mud hydrostatic pressure and the formation pore pressure

2. Differential Pressure


• The mud used to drill the well can have a large impact on ROP

• PDC bit will drill faster in OBM vs. WBM if hydratable shales are present.

• If lost returns are not a concern, OBM should improve torque and drag in a directional well, thus improving ROP

3. Mud Type and Properties


• WBM Properties

– Density

– Solids Content

– Oil Content

– Fluid Loss (API filtrate)

– Viscosity

3. Mud Properties

Increasing Mud Property

ROP


• Pressure drop across the bit aids in cleaning the bit and can improve ROP

• Bits should be nozzled to optimize hydraulics

• HSI > 2 is usually adequate

4. Bit Hydraulics


• Slide drilling reduces ROP ~30%

• Rotary drilling is preferred, hence rotary steering tools have been developed (new technology).

5. Directional


Bit Planning - Vision

• Ultimate Goal • Drill economic well for the lowest cost possible

• Compare alternatives with Cost/Foot Eqn.

C = B + R(T + t) F

= cost per foot ($/ft)

= bit cost ($)

= rig operating costs ($/hr), (spread rate)

= bit on bottom time (hr)

= trip time (hr)

= footage drilled by bit (ft)

C

B

R

T

t

F

Bit Planning - Economics

• Cost/Foot Example - Choose a bit!• Plan to drill 1000’ from 10000’ to 11000’

Bit B

Bit Cost: $5000/bit

ROP: 50 fph

Total Footage = 500’/bit

Trip Time: 10 hr/bit

Spread Rate = $2000/hour

C = B + R(T + t) F

Bit A

Bit Cost: $30000/bit

ROP = 50 fph

Total Footage = 1000’/bit

Trip Time: 10 hr/bit

Spread Rate: $2000/hour


• Bit A and B tie for low cost

Bit A: $90/ft

Bit B: $90/ft

• The low cost bit is.....


Bi-Center Bit Underreamer Hole OpenerReam While Drilling

Hole Enlarging Equipment

Ream While Drilling Technology

Typical Bi-center Assembly

D = PT x sin(180 - RA/2 - arcsin [(PT - P) x sin(RA/2)/PT)])/sin (RA/2)D = Drill Hole SizePT = Pass-Thru DiameterP = Pilot Hole DiameterRA = Reamer Angle

Pass-Thru Diameter (PT)

Pilot Diameter (P)

Drill Hole Diameter (D)

Reamer Angle (RA)

Eccentric Tool Geometry

Pass-thru size determined by casing that will be set.

Drill hole size determined by annular clearance required.

Pilot hole size determined by the drill hole size and pass-thru size.

Define Pass-Thru Size, Drill Hole Size And Pilot Hole Size

• Ability to drill a larger hole than the existing casing will allow.• Ream While Drilling from vertical to horizontal.• Maximize clearance between the casing and borehole, which

improves cement clearance.• Easier casing runs through high degree doglegs.• Larger wellbore for multi-laterals• Reduced risk of sticking pipe in high angle wells, swelling

formations, flowing formations, and depleted sands.• Eliminate underreaming in overbalanced conditions.

Ream While Drilling Technology Advantages

• Penetration rates comparable to historical offsets.• Reduced drilling costs.• Ability to run one size larger casing.• No risk of mechanical underreamer parts lost downhole.• Provides a larger hole for better completions of pre-packed

screens/gravel packs.• Ensures a larger diameter production zone.

Ream While Drilling Technology Advantages

• RWD - Rotary applications

• SRWD - Rotary or steerable motor • applications

• STRWD - Rotary or steerable motor• applications

Ream While Drilling Technology Tools

Fishing Neck 22” Minimum

Tong Neck 10” Minimum

Large Stabilization Pad

RWD Tool

Breaker Slots for Make-Up

Stabilization pad with optimized geometry for directional drilling.

Short compact body to be used on steerable systems.

Pilot bit flexibility

SRWD Tool

Breaker Slots for Make-Up

Stabilization pad with optimized geometry for slimhole drilling.

Short compact body to be used on steerable systems.

One-Piece matrix design

STRWD Tool

Hole Opening Blade*

Interchangeable Nozzles*

Pilot Stabilization Pad (PSP)

Black Ice/ CSE Cutters

Depth Adjusted Cutters

Pilot Bit Flexibility*

BHA Flexibility*

* denotes features available exclusively on RWD and SRWD tools

Tool Features

Smooth Transition from Pass-Thru to Drill size

Hole Opening BladePass Thru Hole

1/3 Open Hole2/3 Open HoleDrill Size Hole

Drill Center

Pass Thru Center

1/3 Open Hole Center

2/3 Open Hole Center

Patented Hole Opening Blade

• Dynamically positions Ream While Drilling tool in the center of the pilot hole.

• Offsets the resultant force created by the cutting structure.

• Minimizes bending.

• Forces fluid to travel up and around the blades for better hydraulic cleaning.

• Improves transition from pass-thru to drill size.

Patent Pending Pilot StabilizationPad (PSP)

• Packed Assembly

• Semi-packed Assembly

• Pendulum Assembly

• Logging Tool Placement

RWD BHA Flexibility

Packed Semi-Packed Pendulum

BHA Flexibility

• The RWD/SRWD tools have been run successfully with both Tricone and PDC bits.

• Base pilot bit choice on what would be run when not using an RWD/SRWD tool.

• Selection should be based on lithology, mud weight, mud type and hydraulics.

Pilot Bit Flexibility

Aggressive Design Hard Formation Design

Diamond Impregnated Bits

TSP (PDC) Core Bit Natural Diamond Core Bit

Core Bits

Core Barrel

Impregnated Diamond Cutters PDC Cutters Backed with Impregnated Diamond

Diamond Impregnated Bits

• Bit planning is required in order to obtain the lowest cost per foot

• The two basic types of bits are Roller Cone Bits and Fixed Cutter Bits

Summary

Name that Bit!

Any feedback regarding this lecture

or suggestions on improvements for

future presentations (topics, etc.)

are greatly appreciated.

Thank you.

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