Bit & Hydrolic

Bits and HolemakingIPM

IPM IDPT

Bits and Holemaking


Introduction

Drilling bits selection is crucial to the performance of all drilling projects.

Understanding the different types of bits and their respective applications is a pre-requisite to bit selection.

Holemaking involves not only the right bit in the right application but also running it with the right operating parameters.

Given that bit technology continues to improve at a rapid pace, well engineers must stay abreast of the latest developments to ensureoptimum bit selection.


Session ObjectivesAt the end of this training session, you will be able to:

• List the different type of bits• Describe the different rock failure mechanism• Describe the IADC (International Association of

Drilling Contractors) bit classification and dull bit evaluation code

• Describe the effect of change in weight on bit, rpm, hole size, mud weight and solids content on bit performance

• Perform bit economics• Select bits based on offset well data• Interpret Drill-Off Tests


Bit Types


Bit Types

Drill Bits

FixedCutter

RollerCone

InsertMill ToothDiamondP D C

NaturalDiamond

ImpregnatedDiamondT S P

RollerBearing

JournalBearing

Courtesy of


PDC (Polycrystalline Diamond Compact)

Drill Bits

FixedCutter

RollerCone


NaturalDiamond


RollerBearing

JournalBearing

Courtesy of


8 mm11 mm13 mm16 mm19 mm

Cutting Elements - PDC

Courtesy of


Natural Diamond

Drill Bits

FixedCutter

RollerCone


NaturalDiamond


RollerBearing

JournalBearing

IPM

Courtesy of


Cutting Elements – Natural Diamond

• Natural Diamonds• Size• Shape• Quality

Courtesy of


TSP (Thermally Stable Polycrystalline)

IPM

Courtesy of

Drill Bits

FixedCutter

RollerCone


NaturalDiamond


RollerBearing

JournalBearing


Cutting Elements - TSP

Courtesy of

• TSP


Impregnated Diamond

IPM

Courtesy of

Drill Bits

FixedCutter

RollerCone


NaturalDiamond


RollerBearing

JournalBearing


Cutting Elements - Impregnated

• Impregnated Diamond Blades

Courtesy of


Bit Types

Alternative Names

Rock BitTri-Cone™

Drill Bits

FixedCutter

RollerCone


NaturalDiamond


RollerBearing

JournalBearing

Courtesy of


Mill Tooth Bits

Drill Bits

FixedCutter

RollerCone


NaturalDiamond


RollerBearing

JournalBearing

IPM

Courtesy of


Cutting Elements – Mill Tooth

• Teeth and Hardfacing

Courtesy of


Insert Bits

Drill Bits

FixedCutter

RollerCone


NaturalDiamond


RollerBearing

JournalBearing

IPM

Courtesy of


Cutting Elements - Insert

• Tungsten Carbide Inserts

Courtesy of


Mill Tooth - Roller Bearing

Drill Bits

FixedCutter

RollerCone


NaturalDiamond


RollerBearing

JournalBearing

Courtesy of


Mill Tooth/Insert – Journal Bearing

Drill Bits

FixedCutter

RollerCone


NaturalDiamond


RollerBearing

JournalBearing

Courtesy of


Rock Failure Mechanisms


Failure Mechanisms

PDC BITPDC BITCONTINUOUSCONTINUOUS

SHEARINGSHEARING

ROLLER CONE BITCYCLIC COMPRESSION

– Compressive Failure

Failure Mechanisms

• Shear Failure

Courtesy of


Rock Strength

• Shear Strength

• Compressive Strength

Courtesy of


Drilling Mechanisms

• Compressive Failure

Courtesy of


Drilling Mechanisms

• Shear Failure

PDC BITPDC BITCONTINUOUSCONTINUOUS

SHEARINGSHEARING

Courtesy of


Drilling Mechanisms

• Shear/Compressive Failure

NATURAL DIAMONDOR IMPREG BIT

CONTINUOUSCRUSHING

& ABRASION

Courtesy of


Drilling Mechanisms vs Bit Type

Impregnated DiamondGrinding

Natural DiamondPloughing

PDCShearing

InsertChipping and Crushing

Mill ToothGouging & Scraping

Courtesy of


IADC Bit Classification


IADC Classification – Roller Cone517G

Soft Formations w ith Low Compressive Strength and High

Drillability1

Medium to Medium Hard Formations w ith

High Compressive Strength

2Hard Semi-Abrasive

and Abrasive Formations

3Soft Formations w ith Low Compressive Strength and High

Drillability4

Soft to Medium Formations w ith Low Compressive Strength

5Medium Hard

Formations w ith High Compressive Strength

6Hard Semi-Abrasive

and Abrasive Formations

7Extremely Hard and Abrasive Formations 8

INSERT BITS

STEEL TOOTH

BITS

Cutting Structure Series Cutting Structure Type (1 to 4)

1 refers to the softest formation in a

particular Series and 4 refers to the

hardest formation within the Series

Bearing/Gauge Description

Standard Roller

Bearing1

Roller Bearing Air

Cooled2

Roller Bearing Gauge

Protected3

Sealed Roller

Bearing4

Sealed Roller Brg -

Gauge Protected

5Sealed Friction Bearing

6Sealed

Frction Brg Gauge

Protected7

Features Available (Optional)

A - Air ApplicationB - Special Bearing SealC - Center JetD - Deviation ControlE - Extended NozzlesG - Gauge/Body ProtectionH - Horizontal Steering Appl.J - Jet DeflectionL - Lug PadsM - Motor ApplicationS - Standard Steel ToothT - Two Cone BitW - Enhanced Cutting StructureX - Predominantly Chisel Tooth InsertY - Conical Tooth InsertZ - Other Shape Insert

8-1/2” EHP 51

Ref: SPE 23937 The IADC Roller Bit Classification System


IADC Classification – Fixed CutterM432

Body Material Steel or Matrix.

Cutter Density PDC: 1 to 4, diamond bits: 6 to 8(the lower the number, the lighter set the bit). Cutter Size/Type For PDC cutter, 1 indicates >24 mm, 2

12-1/4” DS66H is between 14 and 24 mm, 3 is between 8 and 14 mm and 4 is smaller than 8. For diamond bits, 1 represents natural diamond, 2 is for TSP, 3 is a combination of natural diamond and TSP and 4 is for impregnated. Profile The final digit indicates the general body style and varies from 1 (flat profile) to 4 (long flanked turbine style).

Fixed cutter IADC codes are intended only to provide a means for characterizing the general physical appearance of fixed cutter drill bits. Unlike the IADC classification for roller bits, these codes do not represent an application guideline.

Ref: SPE 23940 Development of a New IADC Fixed Cutter Drill Bit Classification System


IADC CodesTooth

2

1

3

1-1

IPM

Soft

1-3

2-1Hard


IADC Codes

14-1

IPM

Tooth

Soft

Insert2 4

3 5

6

7 8-3Hard

8


IADC Codes

Soft

Hard

Tooth PDC

IPM

1

8

7

6

4

5

Insert2

1

3


IADC Codes

Diamond

PDCTooth

IPM

Soft

Hard 8

7

6

4

5

Insert

1

2

3


IADC Codes

Soft

Hard

Tooth

ImpregnatedDiamond

Diamond

PDC

IPM

1

8

7

6

4

5

Insert2

1

3


IADC Bit Dull Grading Code



The International Association of Drilling Contractors has developed a standard methodology for describing used bits. This information is essential for detailed bit performance analysis.

The methodology is composed of an 8 character code that describes bit wear and the reason why the bit was pulled.

INNER ROWS

OUTERROWS

DULL CHAR

LOCA-TION

BRNG/ SEALS

GAUGE 1/16”

OTHER CHAR

Cutting Structure B G RemarksREASON PULLED



INNER ROWS

OUTERROWS

DULL CHAR

LOCA-TION

BRNG/ SEALS

GAUGE 1/16”

OTHER CHAR


The cutting structure is graded from 0 to 8 depending on the proportion of cutting structure lost (0 = Intact, 8 = 100% worn).

Fixed Cutter Bits Roller Cone Bits

Inner Cutting Structure (All Inner Rows)

Outer Cutting Structure (Gauge Row Only)

0 1 2 3 4 5 6 7 8

Cone 2Cone 3

Cone 1

IPM Ref : Reed Hycalog PDC & Roller Cone Product Technology Reference Information



INNER ROWS

OUTERROWS

DULL CHAR

LOCA-TION

BRNG/ SEALS

GAUGE 1/16”

OTHER CHAR


Fixed Cutter Bits Roller Cone BitsBF - Bond Failure BT - Broken Cutters BU - Balled Up CT - Chipped Cutters ER - Erosion HC - Heat Checking JD - Junk Damage LN - Lost Nozzle LT - Lost Cutter NR - Not Rerunable PN - Plugged Nozzle RG - Rounded Gauge RO - Ring Out RR - Rerunable SS - Self Sharpening Wear TR - Tracking WO - Washed Out Bit WT - Worn Cutters NO - No Dull Characteristics

*BC - Broken ConeBF - Bone FailureBT - Broken Teeth/CuttersBU - Balled Up Bit*CC - Cracked Cone*CD - Cone DraggedCI - Cone InterferenceCR - CoredCT - Chipped Teeth/Cutters SS -ER - ErosionFC - Flat Crested WearHC - Heat CheckingJD - Junk Damage*LC - Lost Cone

LN - Lost NozzleLT - Lost Teeth/CuttersOC - Off-Center WearPB - Pinched BitPN - Plugged Nozzle/Flow PassageRG - Rounded GaugeRO - Ring Out SD - Shirttail Damage

Self Sharpening WearTR - TrackingWO - Washed Out BitWT - Worn Teeth/CuttersNO - No Dull Characteristic

* Show Cone under Location 4

Note that this is for the Primary dull characteristics.

Ref : Reed Hycalog PDC & Roller Cone Product Technology Reference Information


Fixed Cutter – Main Wear Characteristics

NO WEAR(NO)

WORNCUTTER

(WT)

BROKENCUTTER

(BT)

LOSTCUTTER

(LT)

EROSION(ER)

POST OR STUDCUTTERS

BONDFAILURE

(BF)

NO WEAR(NO)

WORNCUTTER

(WT)

BROKENCUTTER

(BT)

LOSTCUTTER

(LT)

CYLINDERCUTTERS BOND

FAILURE(BF)

Courtesy of


Dull Characteristics – Some ExamplesFixed Cutter BitsBF - Bond Failure BT - Broken Cutters BU - Balled Up CT - Chipped Cutters ER - Erosion HC - Heat Checking JD - Junk Damage LN - Lost Nozzle LT - Lost Cutter NR - Not Rerunable PN - Plugged Nozzle RG - Rounded Gauge RO - Ring Out RR - Rerunable SS - Self Sharpening Wear TR - Tracking WO - Washed Out Bit WT - Worn Cutters NO - No Dull Characteristics BU - Balled Up



Dull Characteristics – Some Examples

Roller Cone Bits*BC - Broken ConeBF - Bone FailureBT - Broken Teeth/CuttersBU - Balled Up Bit*CC - Cracked Cone*CD - Cone DraggedCI - Cone InterferenceCR - CoredCT - Chipped Teeth/Cutters SS -ER - ErosionFC - Flat Crested WearHC - Heat CheckingJD - Junk Damage*LC - Lost Cone



* Show Cone under Location 4BU – Balled Up Bit

(primary)CD – Cone Dragged

(secondary)Ref : IADC Drilling Manual – Eleventh Edition


Dull Characteristics – Some ExamplesFixed Cutter BitsBF - Bond Failure BT - Broken Cutters BU - Balled Up CT - Chipped Cutters ER - Erosion HC - Heat Checking JD - Junk Damage LN - Lost Nozzle LT - Lost Cutter NR - Not Rerunable PN - Plugged Nozzle RG - Rounded Gauge RO - Ring Out RR - Rerunable SS - Self Sharpening Wear TR - Tracking WO - Washed Out Bit WT - Worn Cutters NO - No Dull Characteristics CT – Chipped Cutter



Dull Characteristics – Some ExamplesFixed Cutter BitsBF - Bond Failure BT - Broken Cutters BU - Balled Up CT - Chipped Cutters ER - Erosion HC - Heat Checking JD - Junk Damage LN - Lost Nozzle LT - Lost Cutter NR - Not Rerunable PN - Plugged Nozzle RG - Rounded Gauge RO - Ring Out RR - Rerunable SS - Self Sharpening Wear TR - Tracking WO - Washed Out Bit WT - Worn Cutters NO - No Dull Characteristics

LT – Lost Cutter







* Show Cone under Location 4 BT – Broken Teeth/Cutters

Ref : IADC Drilling Manual – Eleventh Edition



La

RO – Ring Out







* Show Cone under Location 4JD – Junk Damage




WT – Worn Cutters







* Show Cone under Location 4 SD - Shirttail Damage




TR - Tracking










* Show Cone under Location 4SS – Self Sharpening Wear







* Show Cone under Location 4ER – Erosion




INNER ROWS

OUTERROWS

DULL CHAR

LOCA-TION

BRNG/ SEALS

GAUGE 1/16”

OTHER CHAR

REASON PULLED

Cutting Structure RemarksB G


C - Cone N - NoseT - Taper S - ShoulderG - Gauge

N - Nose RowM - Middle RowG - Gauge RowA - All Rows

Cone 1, 2 or 3




INNER ROWS

OUTERROWS

DULL CHAR

LOCA-TION

BRNG/ SEALS

GAUGE 1/16”

OTHER CHAR



This box is for roller cone bits. Fixed cutter bits will always be designated by "X".

Non Sealed BearingsA linear scale estimating bearing life used. (0 -No life used, 8 - All life used, i.e., no bearing life remaining.)

Sealed BearingsE - Seals EffectiveF - Seals FailedN - Not Able to Grade




INNER ROWS

OUTERROWS

DULL CHAR

LOCA-TION

BRNG/ SEALS

GAUGE 1/16”

OTHER CHAR


For all Bits

The letter “I” is used to designate bits that are in gauge.

If the bit is under gauge, the amount is recorded to the nearest 1/16” of an inch. For example, if the bit is 1/8” under gauge, this is reported as 2/16 or often only as 2.




INNER ROWS

OUTERROWS

DULL CHAR

LOCA-TION

BRNG/ SEALS

GAUGE 1/16”

OTHER CHAR


BF - Bond Failure BT - Broken Cutters BU - Balled Up CT - Chipped Cutters ER - Erosion HC - Heat Checking JD - Junk Damage LN - Lost Nozzle LT - Lost Cutter NR - Not Rerunable PN - Plugged Nozzle RG - Rounded Gauge RO - Ring Out RR - Rerunable SS - Self Sharpening Wear TR - Tracking WO - Washed Out Bit WT - Worn Cutters NO - No Dull Characteristics

Fixed Cutter Bits Roller Cone BitsThis is for the Secondary dull char. and it uses the same codes as for the Primary dull char.

*BC - Broken ConeBF - Bone FailureBT - Broken Teeth/CuttersBU - Balled Up Bit*CC - Cracked Cone*CD - Cone DraggedCI - Cone InterferenceCR - CoredCT - Chipped Teeth/Cutters SS -ER - ErosionFC - Flat Crested WearHC - Heat CheckingJD - Junk Damage*LC - Lost Cone







INNER ROWS

OUTERROWS

DULL CHAR

LOCA-TION

BRNG/ SEALS

GAUGE 1/16”

OTHER CHAR


For All Bits

HP - Hole Problems HR - Hours PP - Pump Pressure PR - Penetration Rate TD - Total Depth/Casing Point TQ - Torque TW - Twist Off WC - Weather Conditions WO - Washout -DrillString

BHA - Change Bottom Hole Assembly DMF - Down hole Motor Failure DSF - Drill String Failure DST - Drill Stem Test DTF - Down hole Tool Failure RIG - Rig Repair CM - Condition Mud CP - Core Point DP - Drill Plug FM - Formation Change



Key to Dull Bit Grading: Grade a Lot of Dulls !

Photo courtesy of


Drilling Parameters vs Bit Performance


Chip Formation• Tooth load overcomes rock compressive strength,

generates crater• Scraping helps to remove chips from craters.

CutterCutter

FormationFormation

Borehole pressure causes chip hold down effect

Courtesy of


Chip Removal

FormationFormation

CutterCutter

61 Courtesy of

• Removal of chips is required to allow for new chip formation

Hydraulics help to remove chips


WOB (Weight on Bit) Response

CHIP CREATION CHIP REMOVAL

RO

P

00 WEIGHT on BIT

Courtesy of


RPM Response

CHIP CREATION CHIP REMOVAL

RO

P

00 RPM

Courtesy of


Effects of Offset or Skew

– 0º - 2º– Reduced Gage Scraping– More Durable– Slower Drilling–Abrasive / Hard Formations

Reduced Offset– 3º - 5º– Increased Gage Scraping– Less Durable– Faster Drilling– Soft / Sticky Formations

Increased Offset

Courtesy of


Courtesy of

ROP vs OverbalanceData based on 7-7/8” bit with 30 klbs at 60 RPM

IPM


Bit Economics


Drilling Bit Economics - Cost per Foot

DtttCCC tcbrb

f ∆+++

=)(

fCbCrCbtctttD∆

Cost per foot ($/ft)

Cost of the bit ($)

Where:

If a mud motor is being used, the cost can be added to the operation

spread rate

Operation spread rate ($/day)

Time rotating (hrs)

Time for connections(hrs)

Round trip time (hrs)Footage drilled

Ref: SPE Applied Drilling Engineering, 1986 Edition


Drilling Bit Economics - Cost per Foot

fCbCrC

ttD∆

Cost per foot ($/ft)

Cost of the bit ($)

Where: DttCCC tdrb

f ∆++

=)(

dtOperation spread rate ($/day)

Time drilling (hrs) Combining rotating and circulating time

Round trip time (hrs)Footage drilled


Bit Selection


Bit Application Spectrum

Formation Compressive Strength

Pene

trat

ion

Rat

ePDC

Mill ToothInsert

Impreg& NaturalDiamond

Courtesy of

DP


Bit Selection Process

Which Which One ?One ?

Courtesy of


Bit Selection - PDC

Advantages• Very Fast ROP• Long Life Potential

Considerations• Impact Damage• Abrasiveness• Stability

Courtesy of


Bit Selection – Tooth Bit

Advantages• Fast ROP• Good Stability• Economic

Considerations• Tooth Wear Rate• Bearing Life

Courtesy of


Bit Selection – Insert Bits

Advantages• Cutting Structure Durability• Range of Formations• Interbed Tolerance• Steerability and Stability

Considerations• Slower ROP• Bearing Life

Courtesy of


Bit Selection – Natural & Impreg Diamond Bits

Advantages• Very Durable• Hard Rock Capability• Low Junk-in-Hole Risk

Considerations• Slower ROP• RPM Sensitivity• High Cost Applications

Courtesy of


The Bit Selection Process

Courtesy of


What Do We Look At?

Geology

LimitationsLimitations

Offset DataObjectives

Other

Courtesy of


Geology - Lithological Analysis

Courtesy of


• Vibration in Grid Sandstone

• Balling in Horda and Balder

• Pyrite in Balder and below• Stringers (40k psi)• Abrasive sands

• Hard Ekofisk Limestone

Courtesy of

Lithological Analysis

Potential Difficulties


Structural Geology

Courtesy of


Structural Geology

FaultsIn the Cusiana/Cupiaguafields of Colombia, thesame formation is muchharder & abrasive below the fault.

Courtesy of


Geology – Example of Local Feature

Bunter Sandstone (UK southern North Sea)Locally within Block 48 there is a hard, baked“crust” on the top of this formation which makesPDC application extremely risky. In adjacentBlocks this feature is not present and the intervalcan be effectively drilled with light-set, aggressivePDC bits.

Courtesy of


What Do We Look At?

Geology


Offset DataObjectives

Other

Courtesy of


Anadrill MWD/LWD BIT RUN SUMMARYPAGE 1 OF 4

JOB NUMBER COMPANY REP. DATE IN DATE OUT MWD RUN NO. LWD RUN NO. RIG BIT RUN NO. CELL MGR.

01-Nov-00COMPANY HOLE DEPTH - FROM TO COLLAR SIZE SONIC

MWD CDRRIG NAME DRIFT - FROM TO LAST CASING

SIZE DEPTHWELL NAME AZIMUTH - FROM TO BIT MFG / MODEL / IADC CODE

LOCATION HOLE SIZE WATER DEPTH DOWNHOLE MOTOR TYPE / SIZE / SN

FRAME FORMAT USED / DTL MAG DEC / GRID T/F ARC T/F ANGLE BENT HOUSING ANGLE PUMPING HOURS FT/M DRILLED

BIT-TO-SURVEY MODULATOR GAP BENT SUB ANGLE TRANS FAIL RT TRANS HOURS RT TRANS FT/M

YES NOBIT-TO-M1 0 ROP B DEPTH TO GR-RES DEN-POR SON VALT / FLOW-MIN. VALT / FLOW-MAX LWD REAM HOURS LWD REAM FT/M

BIT GRADING-MEL CONE LOCK PUMP OUTPUT / TYPE JETS / TFA LWD DRILL HOURS LWD DRILL FT/M

TEETH YES NO GAUGEIADC CUTTING STRUCTURE B G REMARKS EQUIV. DRILLING

INNER ROW N/A

OUTER ROW N/A

DULL CHAR N/A LOCATION N/A

BRNG/SEALS N/A

GAUGE 1 /1 6° N/A

OTHER CHAR N/A

REASON PULLED TD TIME

SOFTWARE VERSION BOT LWD BELOW ROTARY

IDEAL ADVISOR SPM Isonic M-1 0 CDR ADN HRS. HRS.

MWD PUMPING HOURS LWD PUMPING HOURS REAL TIME RECORDED TIMECODE S/N START CUM CODE S/N START CUM HRS Fail Y/N FT/M HRS Fail Y/N FT/M

MMA TEMP

MTA DWOB

MEA DTORBHA/ MDI MAG

ACC

SHK

GRA CDEA TRAN

TAARGEH/ CDEH SUR

PRSRGAS/ CDAS CDRES 1338

DFS CDLDS CDRGR 1338DFS RGCS CDR TEMP 1338MDC RGLS CDR ECD 1338

SLK RNGS CDR S HK 1338

SZR NDDC LWD S ON 1338RES NDPC FLS DSS DLS CDR ADN SONIC

NDPH FLW DSW DLW CDW CDW

ISS NDSE CDR RECORDED ONLY CDN RECORDED ONLY

MSB NDSS READ-OUT PORT TO BIT:

BSS NDPS CDR # # ADN M-1 0

XOS NDLX CHECK SHOT TYPE:

CSB ISONIC DC&E DEPTH: INCL: AZI:

OPERATING CONDITIONSAVG ROP (m/hr) AVG RPM AVG PP (bar) AVG LPM END VIS END MUD WT. (sg ) END MUD RES MUD ADDITIVES LCM

LCM HEMATITE TYPEBIT/SEC / CARRIER MAX CIRC TEMP (°C) AVG WOB (T) AVG TORQ (kNm) MAX MWD SHOCK MAX SHOCK DUR. TDH SHOCK BEADS BARITE SIZE

3bps / 12Hz NONE GILSONITE CONC lb /BBLMUD TYPE MUD CLEAN SAND % SOLID % BHA TYPE

F-FRESH H20 L-LIGNO O-OIL%__ 80 S-SALT H2 O B-BUILD M-MOTOR S- STEERABLE

K-KCL M-LIME MURREX P-POLYMER X-_ __ __ __ _ YES NO H-PACKED HOLE P-PENDULUM X-OTHERTURBINE JAMMING TOOL JAMMING SYNC TIME BIT TYPE MOD TYPE

ROTOR PRT. NO. STATOR PRT. NO. D-DIAMOND P-PDC A-PDC A N-NORMAL M3

YES NO TIME MINS. I-INSERT M-MILL TOOTH X-__ __ __ __ S-SINUSOIDAL M10COLLAR NOISE PROBLEMS PRES INCR AT FAIL FLOAT SUB LOST RIG TIME SURF. SYS FAIL TRIP TERM DUE CLIENT SURFACE BHA VIBRATION SURFACE

NORMAL SURFACE NONE DUE TO MWD DIRECTLY TO MWD INCONVENIENCE VIBRATION SCREEN

OTHER DOWNHOLE YES NO YES NO HRS YES NO YES NO YES NO YES NO YES NO YES NOSUMMARY

1338

M10

2

85 4 12 - - 203

33 150 200 3500 28 1.45 OBM

827 0 70

SON 33.45 10.85

ENP 001 0 70IWOB

N

70 NENP 001 0 70

N70

0 7011779 707070 N

1338

70 N

-70 N

387 0 70023 0 700 70 N 133870 RGM 8989MSSC JC 304063-3 0

70MSSC GB 77715-4 0--626 0 70

N

70 -

5.0C05 6.0x05 30

865 0 70 70

ID6_1x_12r N/A 6.1C-05 5.0B10

1312m

N/A N/A 13.2 LPS / TRIPLEX 8*13 / 1.037

2578 / 3550 2734 / 3566 1 26m

-3.60° / -1.380°

0.12 N/A 70

15/6-A-2-H 179.89° 336.47°

111.4m

Statoil 1277m 2589m ADN

B. Ribesen

8 1/4" 8 1/4" 8 1/4"

306-Nov-00 3 1

N/A N/A N/A

6.0B42

1.5 20

N

100

1270 m

40

1312m

PowerDrive900 / 9 1/4" / 90004

1312m

13 3/8"

70

Reed-Hycalog/DS130B1DF+NSUV/24510

Glitne

13.24m

40

411 0

-

12 1/4"

20078 Hans J. Rusnes

70

Byford Dolphin 32.15° 41.77°

2012-2014

10.85m 22.21/18.86/34.74/35.97/28

Wireline Logs and Mud Logs

Morning Reports and BHA Reports

Courtesy of


Offset Data – Bit RecordsWELL NAME : 15/5-5Run Bit Type Size Mnf Bit Name IADC TFA In Out Meters Hours ROP RPM WOB Flow SPP BitNo inch in2 m m m m/hr ton ton l/min l/min bar bar I O DC1 Mill Tooth 17.5 SEC SS44GLTJ 135M 0.838 210 210 74 7.4 10.0 19 88 0 14 1750 4150 16 95 HO 36 GRNT 6980 0.920 210 210 74 7.4 10.0 19 88 0 14 1750 4150 16 952 Mill Tooth 24 HTC ATX-CG1 115 1.595 210 210 0 1.2 0.0 11 50 5 11 3542 3600 51 553 Mill Tooth 17.5 STC MSDGHC 135 1.181 210 1000 790 16.5 47.9 45 95 0 22 3522 4432 100 180 2 3 NO4 PDC 12.25 HYC DS70HFG S424 0.752 1000 1549 549 19.4 28.3 122 165 0 20 2110 2560 157 190 8 6 RO5 Insert 8.5 HTC ATMGT-P09D 437 0.518 1549 2158 609 17.4 35.0 90 132 1 15 2500 2600 236 305 5 4 BT6 Core 8.5 DBS CD93 M626 0.700 2158 2176 18 1.0 18.0 80 107 2 10 1300 1300 62 987 Core 8.5 DBS CD93 M626 0.700 2176 2182 6 0.5 12.0 50 83 2 11 1300 1300 58 95 1 2 CT8 Core 8.5 DBS CD93 M626 0.700 2182 2200 18 1.3 13.8 80 104 1 2 832 832 50 76 1 4 CT9 Insert 8.5 HTC ATMGT-P09D 437 0.518 2200 2645 445 22.3 20.0 70 123 0 18 1360 1590 219 268 6 6 BT

WELL NAME : 15/5-6Run Bit Type Size Mnf Bit Name IADC TFA In Out Meters Hours ROP RPM WOB Flow SPP BitNo inch in2 m m m m/hr ton ton l/min l/min bar bar I O DC1 Mill Tooth 17.5 SEC SS33SGJ4 115M 1.117 134 196 62 7.9 7.8 70 90 2 5 4900 145 2 2 WT HO 26 Darrot HO 114 0.746 134 196 62 7.9 7.8 70 90 2 5 4900 1452 Mill Tooth 17.5 SEC SS33SGJ4 115M 1.117 196 200 4 1.0 4.0 70 70 4 7 4100 1063 Mill Tooth 17.5 RTC MS11GC 115 1.117 200 1002 802 21.9 36.6 120 140 1 9 4150 210 2 2 WT4 Mill Tooth 12.25 STC MSDGH 135 2.111 982 1005 23 3.0 7.7 70 80 3 10 2585 69 3 3 CD5 PDC 8.5 HYC DS56DGJV M432 0.720 1005 2180 1175 23.7 49.6 165 177 1 6 2562 210 1 1 CT6 Core 8.5 DBS CD93 M626 0.700 2180 2205 25 1.8 13.9 80 120 2 4 941 53 1 1 NO7 PDC 8.5 HYC DS56DGJV RR M432 0.720 2205 2725 520 17.1 30.4 114 176 1 12 2550 240 2 2 WT

Courtesy of


1983 1986 1990

Courtesy of


Offset Data - AnalysisBit Depth Out Interval Hours R.O.P. Dull Condition ATX11H 2253 1311 69 19 2 2 BT M E I No HR ATM22 2729 0 0 0 0 0 A E 0 TD ATM22 2729 476 77 6.2 8 7 BT A E 2 BT PR ATM22 2816 87 19 4.6 4 4 CT H E 1 JD TD

1st Run: Pulled too early2nd Run: No footage3rd Run: Major cutting structure damage4th Run: Junk damage?AlmostAlmost a two bit section

Courtesy of


Offset Data - Parameters Analysis

ROP v Average Torque v Depth

0

20

40

60

80

100

120

140

160

1247

0

1252

5

1258

0

1263

5

1269

0

1274

5

1280

0

1285

5

1291

0

1296

5

1302

0

1307

5

1313

0

1318

5

1324

0

1329

5

1335

0

1340

5

1346

0

1351

5

1357

0

1362

5

1368

0

1373

5

1379

0

1384

5

1390

0

1395

5

1401

0

RO

P (fp

h)

0

5

10

15

20

25

Torq

ue (K

ft/lb

s)

ROP Average Torque

Courtesy of


Offset Data – Benchmarking

• Average well performance

• Average interval performance

• Average single run performance

• Selected Averages (Best or most recent)

• Selected Averages (by other data)

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What Do We Look At?

Objectives

Other

Geology

Offset Data


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Defining the Objective

• Ask the customer(s) what they want!!!

• Durability, ROP, Directional, Cost,Dull Condition, Hours, (usually all)

• Determine the feasibility

• Finalize and agree upon objectives

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What Do We Look At?

Geology


Offset Data

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Objectives

Other


Recognizing the Limitations

• Operational restrictions (rig specs, etc)

• Contractual restrictions

• Economic restrictions

• Changing the mindset

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What Do We Look At?

Offset Data

Other

Objectives

Geology


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Other Factors (Mud)

• Mud Properties (base fluid, density, additives, etc)

• Bit Hydraulics (especially critical in WBM)

• Maximum/Minimum Flowrates

• Mud lubricity (effects on vibration & Impreg Bits)

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Other Factors

ROP & Mud Weight vs Well

0.00 2.00 4.00 6.00 8.00

10.00 12.00 14.00 16.00 18.00 20.00

D10 D11 D12 D13 D14 D15 D16 D17 D18 D19 D20 D21 D22 D24 D24st

Well Number

RO

P (ft/hr)

ave rop

mud wt

-2.00-1.80

-1.40

-0.40-0.20

-1.60

-1.20

-0.80-1.00

-0.60

-0.00

Mud W

eight

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Other Factors• Logistics

• Remote locations require large inventory load out

• Contingency Planning • Need to cover all potential possibilities• Can only be achieved by effective communications

• Economics• Potential impact on TOTAL revenue

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Drill-off Tests


Drill-off TestThe drill-off test is a simple and practical procedure proposed by Lubinski (1).

It has little or no impact on the rig time and the results are immediately apparent.

The objective is to find the combination of WOB and RPM which will yield the highest ROP.

All it requires is a watch with a seconds hand, a tally book and a pencil.

(1) Proposal for Future Tests, A Lubinski - The Petroleum Engineer, Jan 1958


Drill-off Test Procedure1. Determine the max WOB which can be applied given your bit

size/type & BHA.

2. Select three RPM’s at which you will conduct the test.

3. Ask the driller to apply the first RPM and to gradually bring the WOB up to the maximum recommended. If the maximum WOB is not achieved before high torque levels or vibrations occur, then settle for a lower WOB.

4. Ask the driller to chain the break down and allow the WOB to drill off. Write down the time taken to drill off each 2 Klb. The least time taken in seconds to drill off gives the WOB that willgive the highest ROP at that RPM.


Drill-off Test Procedure (cont.)

5. Test the other two RPM’s the same way.

6. Once the tests are completed, check with time based MWD shock data (if available) to see if unstable drilling conditionsexisted at particular WOB and RPM combinations – see InTouch Best Practice: Shocks and Drilling Optimization.http://intouchsupport.com/intouch/MethodInvokerpage.cfm?caseid=3287483

7. Select on the basis of the drill off test and shock data the optimum WOB and RPM.


Drill-off Test Example

Need to be completed.


Session ObjectivesAt the end of this training session, you will be able to:

• List the different type of bits• Describe the different rock failure mechanism• Describe the IADC (International Association of

Drilling Contractors) bit classification and dull bit evaluation code

• Describe the effect of change in weight on bit, rpm, hole size, mud weight and solids content on bit performance

• Perform bit economics• Select bits based on offset well data• Interpret Drill-Off Tests

Date post:	26-Dec-2015
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