Bit Selection

Bit selection

Slide 1 © 2012 Schlumberger. All rights reserved.

Objectives • Learn how bit selection is performed in Schlumberger • Learn bit selection workflow in PTECs – high tier projects • Learn principles of bit selection at rig site

Slide 2 © 2012 Schlumberger. All rights reserved.

Bit Selection in Schlumberger

Slide 3 © 2012 Schlumberger. All rights reserved.

Traditional Bit Selection Process •

Art, usually based on “experts” view Feature oriented:

• •

• Limitations: – Impossible to anticipate: • •

Gage pad geometry

•

Manage depth of cut

•

Bit Profile

•

Make up length

Slide 4 © 2012 Schlumberger. All rights reserved.

• • •

Vibrations Dogleg capabilities for a given BHA Bit aggressiveness Durability of the bit Effect on BHA behavior

That Smith Bit on Location, how was it chosen? Offset Performance

Formations (DBOS)

Sent to rig

Customer Ok ($)

IDEAS Modeling

Hyd. and T&D Slide 5 © 2012 Schlumberger. All rights reserved.

D&M DE

That Smith Bit on Location, how was it chosen? Offset Performance

Formations (DBOS)

Sent to rig

Customer Ok ($)

IDEAS Modeling

Hyd. and T&D Slide 6 © 2012 Schlumberger. All rights reserved.

D&M DE

Offset Performance • Most basic bit selection, based upon: Dull Condition

•

• • • •

“Measures” bit aggressiveness for formations Indicates impact due to vibration/transitional drilling Evidence of vibration BHA as reason to pull, may indicate lack of directional control

•

Interval length

•

ROP

Slide 7 © 2012 Schlumberger. All rights reserved.

Offset Performance - Limitations • • • •

Limited information about formation each bit drilled Limited or no information about vibrations Guess on how stable the bit will be for the application Guess on the directional capabilities of the bit

Slide 8 © 2012 Schlumberger. All rights reserved.

Application of Roller Cone Bits

• • • • •

• • • • • 9 © 2012 Schlumberger. All rights reserved.

Top hole sections, large sizes, soft formation Conglomerates / Gravel Short intervals where PDC are not cost effective Clean out runs, clean out junk Drill outs (less likely these days)

Low cost operations where PDC are not cost effective Presence of pyrite, chert ( risk of breaking PDC cutters) Some laminated formations - hard/soft Steerable Motor applications where tool face control is issue Hard & abrasive formations where diamond bits/turbines not cost effective • Some carbonates where PDC are not cost effective

Roller Cone Anatomy - Internal

Grease Reservoir

Grease Long lube hole Secondary (Inner) Bearing Primary (Outer) Bearing

Secondary Seal Primary Seal

10 © 2012 Schlumberger. All rights reserved.

Ball Hole

Ball Bearings (Cone Retention)

Seals

Major Bearing Types • Roller Bearing

• Friction Bearing



Typically used in large bit sizes



Typically used in small bit sizes



Also referred to as ‘Anti-Friction’ bearing



Also referred to as ‘Journal’ bearing

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Roller Cone Assembly

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Application of Roller Cone Bits - Agressiveness

+ + Soft Formations

13 © 2012 Schlumberger. All rights reserved.

Insert count Insert extension Offset

+ Hard Formations

Bit Offset Definition of Offset:  “...the horizontal distance between the axis of the bit and a vertical plane through the axis of the journal.”  Smith Bits measures offset in inches  Very Soft formations (aggressive) typically 3/8”  Very Hard formations (durable) typically 1/32” Slide

14

© 2012 Schlumberger. All rights reserved.

Roller Cone have limited bearing life - Reliability Graph Bit A has better reliability 100% 80%

Reliability

Bit B

Bit A

0%

0

© 2012 Schlumberger. All rights reserved.

200

400 Krevs

600

800

1000

Application of PDC Bits - Agressiveness

+ +

Blade count Cutter size Junk Slot Area

Hard Formations

Soft Formations

M419 16 © 2012 Schlumberger. All rights reserved.

+ -

M613

M1016

Cutter Size Various different Sizes (diameters) 

Size defined in millimeters

Common Sizes 

9, 11, 13, 16, 19, 22

Larger Diameter = More Aggressive Bit

Sharp Radius of Curvature © 2012 Schlumberger. All rights reserved.

Blunter Radius of Curvature

Cutter Chamfer Improves fracture resistance of diamond table Typical value 0.010 – 0.016 x 45degrees Too much will reduce ROP in hard rock Too little makes cutter fragile

© 2012 Schlumberger. All rights reserved.

Bit balling risk mitigation A6 Junk Slot Area

A5 A1

A4 A2

A3

Total JSA=SUM(A1:A6)

• Maximize Junk slot area • One nozzle per blade or more, usually located close to the center of the bit © 2012 Schlumberger. All rights reserved.

PDC Gauge Configurations  Available Gauge Configurations

Standard

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Undercut

Tapered

Active

Standard Gauge

 Typically used in nondirectional applications (vertical, tangent intervals)  3° DLS or less

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Gauge Pad within API tolerance

Undercut Gauge

 Used in directional applications  Used to maintain vertical  4° - 6° DLS  Customer preference

© 2012 Schlumberger. All rights reserved.

Gauge Pad “typically” .050”-0.100” Ø under nominal diameter

Tapered Gauge

 Used for directional applications  4° - 6° DLS  Minimizes drop tendency in tangent intervals  Customer preference

© 2012 Schlumberger. All rights reserved.

1” Typ.

0.6° Typ.

Gauge Pad typically begins with 1” pad length within API tolerance, then tapers (angle) to decrease final gauge pad diameter

Active Gauge

PDC gauge cutters with exposure

This feature is not endorsed by Smith Bits **Available on customer request © 2012 Schlumberger. All rights reserved.

Originally designed for RSS “Push the Bit” Drive systems. Side cutting capability can induce torque leading to lateral and torsional vibration. Can induce bit whirl and stick slip.

Bit Profile Types Soft

Tend to Whirl

Most common

Long Parabolic Medium Parabolic Short Parabolic Flat

Weak on the Shoulder

Weak on the Shoulder Hard © 2012 Schlumberger. All rights reserved.

Back Rake • Low back rake

• High back rake

Softer formations More aggressive

Harder formations Less aggressive

30°

10°

© 2012 Schlumberger. All rights reserved.

Cone: Nose: Shoulder : Trimmers:

15-20 deg 20-25 deg 20-25deg 25-45deg

Make-Up Length Axial distance from bit face to the make up face 



Bits with small make-up length are preferable as they require less side force or time to achieve the required DLS Not a selection criteria for EoM

© 2012 Schlumberger. All rights reserved.

Drilling Mechanics How does a Bit Drill? Roller Cone Bits 

Chipping/Crushing, or Gouging/Scraping

PDC Bits 

Shearing

Natural Diamond & Impregnated Bits 

Grinding

28 © 2012 Schlumberger. All rights reserved.

Roller Cone Mechanics Gouging-Scraping 

Soft formations



Most Aggressive Cutting Action



Typically high ROP applications

Like using a shovel in the garden

Slide

29

© 2012 Schlumberger. All rights reserved.

Gouging-Scraping Example

Slide

30 © 2012 Schlumberger. All rights reserved.

Roller Cone Mechanics Chipping-Crushing 

Hard formations



Most Durable Cutting Action



High WOB to fracture rock



Typically low ROP applications Like... using a hammer and chisel

Slide

31

© 2012 Schlumberger. All rights reserved.

Chipping-Crushing Example

Slide

32 © 2012 Schlumberger. All rights reserved.

PDC Mechanics • PDC Bits drill by shearing the rock • Rocks typically fracture more easily with shear loading (less energy, WOB) • Most efficient cutting action Polycrystalline Diamond Compact 33 © 2012 Schlumberger. All rights reserved.

Natural Diamond Mechanics • Natural Diamond Bits drill by ploughing and grinding the rock • Normally require higher RPM for better performance (e.g.: high speed motor or turbine)

34 © 2012 Schlumberger. All rights reserved.

Content Anatomy of fixed cutter and roller cone bits Nomenclature Drilling mechanics Application

© 2012 Schlumberger. All rights reserved.

© 2012 Schlumberger. All rights reserved.

36

IADC Roller Bit Classification Chart

© 2012 Schlumberger. All rights reserved.

37

TCI Roller Cone Nomenclature SOFT

Prefix

00

99

Cutting Structure Features FHi 23 ODPS FHi23ODPS FHi67D GT40 TD41H (IADC 417)

FHi90OD

HARD 38 © 2012 Schlumberger. All rights reserved.

Smith Bits PDC Nomenclature M = Matrix material S= Steel material

i = IDEAS Design

Example: MAi916LPX Cutting Structure Features

A = ARCS D = Directional S = SHARC No letter = Std Bit

Feature (Z: Stinger) 16 = Cutter Size / mm (09,11,13,16,19,22)

9 = Blade number (3 through 16)

L = Managed Depth of Cut MDi1013BPX Prefix + XXXX + Suffixes MDi 1013 BPX

© 2012 Schlumberger. All rights reserved.

Application PDC vs. Roller Cone • Roller Cone 

Common Advantages

• PDC 

– Low upfront cost – Low torque – Stable steerable motor tool face 

Common Disadvantages – Risk of losing cones, monitor total revolutions for seal life – Source of Axial vibrations, bit bounce

© 2012 Schlumberger. All rights reserved.

Common Advantages – Faster ROP – Long Runs replacing several Roller Cone bits



Common Disadvantages – Higher upfront cost but more cost per foot effective – Create high torque – Prone to Slip-Stick (use MDOC)

40

Application PDC vs. Roller Cone • Roller Cone 

Common Advantages

• PDC 

– Low upfront cost – Low torque – Stable steerable motor tool face 

Common Disadvantages – Risk of losing cones, monitor total revolutions for seal life – Source of Axial vibrations, bit bounce

© 2012 Schlumberger. All rights reserved.

Common Advantages – Faster ROP – Long Runs replacing several Roller Cone bits



Common Disadvantages – Higher upfront cost but more cost per foot effective – Create high torque – Prone to Slip-Stick (use MDOC)

41

Offset Performance Workflow (conventional wisdom) Short run?

Start

No Consider more Yes blades, smaller cutters, adjust cutter selection

Wear > 50% No

Slide 42

Consider same bit or less blades bigger cutters

© 2012 Schlumberger. All rights reserved.

Yes

Wear > 50%

Yes

No Consider same bit

No

Yes

No TF issues ?

Risk of balling?

Increase blade count, >=1 nozzle per blade*+ABC** Adjust cutter selection

Yes Increase Blade count/ reduce cutter size/adjust cutter selection

Offset Performance (Cont’d) SR

1 6

1

1

4

2

5

1

2

4

2

1

RSX192HF

RSX519M

RSX519MB2

HYC MRS89PX

MDI516HPX

S988BHPX 2

SDI419HSBPX

GEO RSX519MB2

RSX519M

SDI519HSBPX

MDI516HPX

S988BHPX 1

HYC SDI419HSBPX

GEO

4 10

What is the fastest and longest run SW(Vortex)/SR (RSS) /S (S.motor)?

1

0.0 10.0

3000

20.0

4000

30.0

5000 6000

40.0

7000

50.0

8000

60.0

9000

70.0

10000 Average of DepthIn Slide 43 © 2012 Schlumberger. All rights reserved.

Average of drilled_depth_msr_d

Average of rop_msr_d

Count of well_number_txt

ROP(ft/hr), # of Runs

Depth (ft)

2000

RSX519MB2

S988BHPX 0 1000

HYC SDI419HSBPX

GEO

SW

MRS98PX

S

Offset Performance (Cont’d) • Exercise 1: •

MDi516 drilled 3000ft @ 50ft/hr: 0/1/WT/S/X/I/NO/TD

What bit would you recommend to improve performance? • Exercise 2: •

•

MDi516 drilled 150ft @ 10ft/hr: 1/5/RO/S/X/I/NO/PR

•

What bit would you recommend to improve performance?

Slide 44 © 2012 Schlumberger. All rights reserved.

Offset Performance (Cont’d) • Exercise 3: •

M519 drilled 1500ft @ 70ft/hr: 0/1/WT/S/X/I/NO/BHA (tool face control)

What bit would you recommend to improve performance? • Exercise 4: •

•

M813 drilled 1500ft @ 35ft/hr: 0/0/NO/S/X/I/NO/PR

•

What bit would you recommend to improve performance?

Slide 45 © 2012 Schlumberger. All rights reserved.

Offset Performance (Cont’d) • Exercise 5: •

M816, 3000ft @ 20ft/hr

•

What bit would you recommend to improve performance?

Slide 46 © 2012 Schlumberger. All rights reserved.

Offset Performance (Cont’d) • Exercise 6: •

MSi616, 7000ft @ 100ft/hr (pull at TD)

•

What bit would you recommend to improve performance?

Slide 47 © 2012 Schlumberger. All rights reserved.

DRS: Source of offset performance data • Used by: •

Product Engineers

•

Technical Support Engineers

•

Design Engineers

•

Sales Engineers

•

Management (market share)

Slide 48 © 2012 Schlumberger. All rights reserved.

DRS History/Evolution – 25 years IBM Estab. May 1985 50% Recs to 1983

Progress

BRDB

DRS

End IBM Mainframe 1993 Dev Oracle – BRDB - 1996

Oldest Rec @1975 Hughes Lawsuit Dec 1985

Release – BRDB - 1998 Add Neyrfor - 2005 Add Smith Services - 2008

Original Data Entry: 3 Shifts/24 hrs 10,000 Bit Recs /month (peak) Est. to have saved Smith $300,000,000 in damage claims © 2012 Schlumberger. All rights reserved.

Well Chronicle Add: Surf Equip/RCD’s, Smith Completions/Liner Hanger Jobs July - 2010

Life of the Customer’s Well Asset Life Cycle Tracking in the DRS Permitting

Drilling Rig Up

Rig Down Completion

Production Work-over

Re-complete

Production

Rig Up

Plug & Aban. Rig Up

Smith Bits Hole Enlargement LWD/MWD Directional Motors/Turbodrills Rotary Steerables Jars/BHA Stabs/Roller Reamers Tubulars Surface Equip. Optimization Svcs.

© 2012 Schlumberger. All rights reserved.

Smith Liner Hangers Completion Strings Flow Subs Packers Casing Hardware

Smith SideTracking Window Milling Anchors Whipstocks Mills/Cutters

Smith P&A Casing Recovery

DRS Today

July 2013  Well Headers          

1,433,922 Permits/Intents (ave) 254,613 Wells Completed 935,820 BHA Runs 4,192,297 Param lines(24 hr data) 5,523,710 Bit Field Run Records 105,050 Turbodrill Jobs/Runs 2,830/8,032 Under-Reamers J/R 4,230/11,847 SideTrack Jobs/Runs 3,743/12,169 Liner Hanger Runs 254 RCD Jobs/Seal Runs 26/93

 Registered Users  Stand-alone Laptop Db’s  “Copy” Databases © 2012 Schlumberger. All rights reserved.

1742 200 @250

Bits TurboDrills Under-Reamers Whips/Sidetracks -

1985 2005 2008 2008

Surface Equip/RCD’s July, 2010 Roller Reamers Motors (expanded) Fixed Hole Openers Liner Hangers 51

Remember…….Offset Performance - Limitations • • • •

Limited information about formation each bit drilled Limited or no information about vibrations Guess on how stable the bit will be for the application Guess on the directional capabilities of the bit

Slide 52 © 2012 Schlumberger. All rights reserved.

That Smith Bit on Location, how was it chosen? Offset Performance

Formations (DBOS)

Sent to rig

Customer Ok ($)

IDEAS Modeling

Hyd. and T&D Slide 53 © 2012 Schlumberger. All rights reserved.

D&M DE

Formation characteristics and bit selection • DBOS: Drill Bit Optimization System • Most complete system for bit selection based upon Unconfined Compressive Rock Strength • Built to asses the best bit type based upon formation properties

Slide 54 © 2012 Schlumberger. All rights reserved.

Objectives of DBOS Analysis •

Formation Characterization

•

Optimum Bit Cutting Structure

•

Other Bit Design Features

•

Hydraulic Requirements

•

Gauge Protection

© 2012 Schlumberger. All rights reserved.

DBOS Limitations • • • •

Limited information about formation each bit drilled Limited or no information about vibrations Guess on how stable the bit will be for the application Guess on the directional capabilities of the bit

Slide 56 © 2012 Schlumberger. All rights reserved.

DBOS Formation Characterization • Calculate Unconfined Compressive Rock Strength (UCMPS) • Determine formation abrasion index. This index indicates the level of gauge protection and/or the need to adjust drilling parameters • Assessment of cutter impact based on the rate of change in rock strength from ft to ft. High impact zones can be related to destructive vibration and the need to modify drilling parameters to prevent unnecessary bit wear. © 2012 Schlumberger. All rights reserved.

Formation Analysis Lithology (Matrix) & Porosity •

Gamma Ray

•

Sonic DT

•

Bulk Density

•

Neutron Porosity

•

Resistivity

•

Composite/Mud Log

© 2012 Schlumberger. All rights reserved.

DBOS Formation Abrasion Index

The DBOS Abrasion Index is based on the combination of the % of quartzitic rocks at each depth step (ft or ½ m) and the determined rock strength for that ft. Thus potential abrasion can be assessed across a range of rock strengths, in soft and harder rock. Alternative methods using Angle of Internal Friction, tend to only be effective in higher strength rocks.

© 2012 Schlumberger. All rights reserved.

DBOS Formation Impact Index

The DBOS Impact Index is based on the rate of change in rock strength from ft-to-ft (ft or m). Impact Events are assessed from both soft-to-hard (potential bit whirl) and equally hard-tosoft (potential Slip Stick). Areas of extensive high impact events will require specific vibration reducing technologies and impact resistive materials.

© 2012 Schlumberger. All rights reserved.

DBOS™ Bit Selectors  Rock Bit Selector – Optimal Mill Tooth Bit – Optimal Insert (TCI) Bit – Optimal Insert Type – Abrasion/Gauge Protection – Hydraulic Configuration

 Fixed Cutter Bit Selector – Cutter Density/Blade Count – Bit Profile – Hydraulic Design/Junk Slots – Optimal Cutter Size – Abrasion – Impact Risk – Gauge Protection © 2012 Schlumberger. All rights reserved.

62 © 2012 Schlumberger. All rights reserved.

DBOS Bit Selectors • There are three bit selectors: Rock bit, Fixed Cutter and Turbodrill applications. • Logic for bit selection is based on historical runs as follows: Bit type

Number of runs

PDC Bits

345

TCI Bits

997

Milled Tooth Bits

348

Impreg Bits

80

• Currently being updated, selectors are usually on the conservative side:

© 2012 Schlumberger. All rights reserved.

DBOS™ Rock Bit Selector

© 2012 Schlumberger. All rights reserved.

Insert Type Applications

Diamond Insert

Chisel

Conical © 2012 Schlumberger. All rights reserved.

Gauge Insert Options

DE Chisel © 2012 Schlumberger. All rights reserved.

Hydraulic Configuration Ext. Jets

Mini-Jets

Center Jets

© 2012 Schlumberger. All rights reserved.

DBOS™ Fixed Cutter Bit Selector

© 2012 Schlumberger. All rights reserved.

Bit Profile Configurations

Light

Medium

Heavy

V.Heavy Flat

Short

Medium Long

Shallow © 2012 Schlumberger. All rights reserved.

Medium

Fishtail

Cutter Characteristics

Impact Resistant © 2012 Schlumberger. All rights reserved.

Abrasion Resistant

Gauge Protection

Standard Gauge DEI-TCI TSP

© 2012 Schlumberger. All rights reserved.

Remember…….DBOS Limitations • • • •

Limited information about formation each bit drilled Limited or no information about vibrations Guess on how stable the bit will be for the application Guess on the directional capabilities of the bit

Slide 72 © 2012 Schlumberger. All rights reserved.

That Smith Bit on Location, how was it chosen? Offset Performance

Formations (DBOS)

Sent to rig

Customer Ok ($)

IDEAS Modeling

Hyd. and T&D Slide 73 © 2012 Schlumberger. All rights reserved.

D&M DE

IDEAS modeling • IDEAS modeling of Drilling System and Bit features to determine their effect • IDEAS Analysis Request (IAR) Standardized Engineering Analysis that provides: • • •

Stability ROP Steerability

Slide 74 © 2012 Schlumberger. All rights reserved.

IDEAS modeling – Elimination of guess work • • • •

Limited information about formation each bit drilled Limited or no information about vibrations Guess on how stable the bit will be for the application Guess on the directional capabilities of the bit

Slide 75 © 2012 Schlumberger. All rights reserved.

What is IDEAS®? • IDEAS: Integrated Design and Engineering Analysis System. • Finite Element Analysis (FEA) software modeling of bit and drillstring • Utilizes bit – rock interaction data derived from lab testing • Predicts Vibrations • Directional Prediction • Calculates Stresses • Estimates rate of penetration © 2012 Schlumberger. All rights reserved.

What is IDEAS®? (cont’d)

• Runs in powerful workstations • Based on complex mechanical calculations • Simulates entire drillstring from bit to surface. © 2012 Schlumberger. All rights reserved.

What is IDEAS®? (cont’d)

Ability to simulate transitional drilling © 2012 Schlumberger. All rights reserved.

Variables considered within IDEAS • • • • • • • •

Smith Cutting structures Formation Effects Overbalance Hole size, wellbore trajectory, tortuosity BHA and drive type Parameters Eccentricity of components Fixed cutter cutting structure wear.

© 2012 Schlumberger. All rights reserved.

IDEAS – The backbone of dynamic predictions Drilling Applications Support

Product Development Support

Sales and Operations Group, ASE

IAR and IAP Services

Product Engineering Group

i-DRILL Service

Product Engineering

IDEAS FEA Modeling

IDEAS Lab

© 2012 Schlumberger. All rights reserved.

Engineering Design Models

®

What is i-DRILL ? • i-DRILL is a service that delivers engineered system designs that: 

Minimize Vibrations and Slip-Stick



Improve directional performance of bit and BHA



Improve ROP

• Provided by a group of engineers running IDEAS on high end LINUX boxes.

© 2012 Schlumberger. All rights reserved.

Current IDEAS limitations • • • • • • • • •

Simulations performed at depths of interest (From DBOS) 480 revs of pipe on surface:0.5ft to 4ft MD (UCMPS) Time and hard drive space Hole Cleaning Poor bit hydraulics Wellbore stability Poor Down hole tool Quality control Hydraulic forces Stuck Pipe

© 2012 Schlumberger. All rights reserved.

Capabilities - Transitional Drilling

Proving “conventional wisdom” wrong! © 2012 Schlumberger. All rights reserved.

Video courtesy of i-DRILL

Capabilities: Matching Bits and Motors High Speed

© 2012 Schlumberger. All rights reserved.

Speed

Video courtesy of i-DRILL

Capabilities: Vortex vs. Rotary

Using Vortex reduces torque and mitigates lateral vibration in this application 24 © 2012 Schlumberger. All rights reserved.

Video courtesy of i-DRILL

Capabilities: Effect of bit wear (PDC) New Bit

86 © 2012 Schlumberger. All rights reserved.

Worn Bit

Capabilities: Compare HEWD options

© 2012 Schlumberger. All rights reserved.

Video courtesy of i-DRILL

Capabilities: Investigate MWD Failures

Drill Collar

Flex Drill Collar

Cross section of top MWD Lateral Vibration (g)

88 © 2012 Schlumberger. All rights reserved.

Video courtesy of i-DRILL

Capabilities: Investigate BHA Failures

89

© 2012 Schlumberger. All rights reserved.

Video courtesy of i-DRILL

Capabilities: Stabilizer Geometry

© 2012 Schlumberger. All rights reserved.

Video courtesy of i-DRILL

Capabilities: Multiple Underreamers

© 2012 Schlumberger. All rights reserved.

Video courtesy of i-DRILL

Effect of Parameters

© 2012 Schlumberger. All rights reserved.

Video courtesy of i-DRILL

Maps of Parameters – i-DRILL

WOB & RPM Sensitivity Plot 40

10.92

13.17

15.70

18.47

21.22

23.69

Stable

35

8.86

11.23

13.64

15.92

17.96

20.44

Torsional

30

9.82

9.50

11.38

13.01

14.98

17.15

Lat-Tor

25

6.08

7.63

9.18

10.63

12.19

13.85

20

4.77

5.96

7.15

8.43

9.66

10.90

15

3.46

4.29

5.26

6.17

7.08

7.88

10

2.22

2.81

3.48

4.05

4.65

5.28

5

1.11

1.42

1.64

1.98

2.34

2.58

80

100

120

140

160

180

ROP values show n above, maximum ROP for stable conditions = 7.88 ft/hr 93 10/19/2015 © 2012 Schlumberger. All rights reserved.

Capabilities: Asses wellbore quality

Logging data showed Spiral has 11 – 12 threads per 10 meter (spiral pitch ~3ft). Appears very regular throughout well.

Depth (m)

Hole spiral is predicted by IDEAS with similar pitch 94 © 2012 Schlumberger. All rights reserved.

Data courtesy of i-DRILL R&D

What is IAR, IAP and IAD? • IAR: Ideas Analysis Request, IAP: IDEAS Analysis Project, IAD: Ideas Analysis Directional • Provide Field Engineers and Sales with IDEAS simulation outputs: • • • • •

Acceleration Torque DWOB DRPM ROP

• Commonly used to select the best cutting structure for an application • No interpretation is provided.

© 2012 Schlumberger. All rights reserved.

IAR/IAP/IAD

Slide 96 © 2012 Schlumberger. All rights reserved.

What data is needed? • • • • • • •

Sonic, GR, mud logs to characterize formations - DBOS Final BHA (options OK). Planned surveys (90ft ok) MW, and Type, PV, YP good to have Bit records (usually from customer, bit types & parameters) Vibration data to rule out poor performing bits/BHAs If a directional analysis: Formation dip & strike.

Slide 97 © 2012 Schlumberger. All rights reserved.

IAR Outputs 1. 2. 3. 4. 5. 6. 7.

Lateral Acceleration (g) Lateral Force (klb) Axial Acceleration Axial Force (Downhole WOB) Table Torque = Surface Troque Bit Torque = Total Torque Bit RPM

98 10/19/2015 © 2012 Schlumberger. All rights reserved.

Bit A MDi513LUPX BOM 64732A0102

Side View

Top View

2”

© 2012 Schlumberger. All rights reserved.

Bit B MDi513LUPX BOM 64732A0102

Side View

Top View

© 2012 Schlumberger. All rights reserved.

2” nom 2” tap

Lateral Acceleration (Zoomed)

MDi513LUPX BOM 64732A0102 2”

MDi513LUPX BOM 64732A0102 2” nom 2” tap

Analysis 2: 4921.5ft / 15klbs / 130rpm / Steering / TFA10 Trout Creek Sandstone 10-15kpsi UCS © 2012 Schlumberger. All rights reserved.

Lateral Force (Zoomed)

MDi513HWUBPX BOM 64790A0101 2”

MDi513HWUBPX BOM 64790A0101 2” nom 2” tap

Analysis 2: 4921.5ft / 15klbs / 130rpm / Steering / TFA10 Trout Creek Sandstone 10-15kpsi UCS © 2012 Schlumberger. All rights reserved.

Axial Acceleration (Bit Bounce)

MDi513LUPX BOM 64732A0102 2”

MDi513LUPX BOM 64732A0102 2” nom 2” tap

Analysis 2: 4921.5ft / 15klbs / 130rpm / Steering / TFA10 Trout Creek Sandstone 10-15kpsi UCS © 2012 Schlumberger. All rights reserved.

Axial Force (WOB)

MDi513LUPX BOM 64732A0102 2”

MDi513LUPX BOM 64732A0102 2” nom 2” tap

Analysis 2: 4921.5ft / 15klbs / 130rpm / Steering / TFA10 Trout Creek Sandstone 10-15kpsi UCS © 2012 Schlumberger. All rights reserved.

RPM

MDi513LUPX BOM 64732A0102 2”

MDi513LUPX BOM 64732A0102 2” nom 2” tap

Analysis 2: 4921.5ft / 15klbs / 130rpm / Steering / TFA10 Trout Creek Sandstone 10-15kpsi UCS © 2012 Schlumberger. All rights reserved.

Surface Torque (Torsional Vibration)

MDi513LUPX BOM 64732A0102 2”

MDi513LUPX BOM 64732A0102 2” nom 2” tap

Analysis 2: 4921.5ft / 15klbs / 130rpm / Steering / TFA10 Trout Creek Sandstone 10-15kpsi UCS © 2012 Schlumberger. All rights reserved.

Bit Torque (Torsional Vibration)

MDi513HWUBPX BOM 64790A0101 2”

MDi513HWUBPX BOM 64790A0101 2” nom 2” tap

Analysis 2: 4921.5ft / 15klbs / 130rpm / Steering / TFA10 Trout Creek Sandstone 10-15kpsi UCS © 2012 Schlumberger. All rights reserved.

Data in Box Whisker Plot (20.0 - 239.0 revs) 2” nom 2” tap

2”

MDi513LUPX BOM64732A0102

Box Whisker Data

MDi513LUPX BOM64732A0102

Lat. Disp. Uy(in) (min / max)

-0.054

0.005

-0.050

0.007

Lat. Disp. Uz(in) (min / max)

-0.069

-0.002

-0.074

-0.003

Lat. Acc. Ayz(G) (25% / MED / 75%)

0.501

0.817

1.430

0.394

0.658

1.089

Lat. Force(klbf) (25% / MED / 75%)

0.553

0.579

0.605

0.550

0.575

0.600

Axial Acc. Ax(G) (25% / MED / 75%)

0.017

0.038

0.074

0.016

0.034

0.063

Bit WOB (klbf) (25% / MED / 75%)

14.978

15.021

15.065

14.983

15.020

15.059

Table Dri. Tor. (klbf-ft) (25% / MED / 75%)

3.253

3.274

3.297

3.257

3.276

3.301

Total Torque (klbf-ft) (25% / MED / 75%)

2.422

2.441

2.461

2.426

2.443

2.464

RPM (revs/min) (25% / MED / 75%)

129.184

129.909

130.942

129.215

129.986

130.889

Analysis 2: 4921.5ft / 15klbs / 130rpm / Steering / TFA10 Trout Creek Sandstone 10-15kpsi UCS © 2012 Schlumberger. All rights reserved.

IDEAS Calculation ROP

MDi513LUPX (BOM 64732A0102)

38.09 ft/hr

MDi513LUPX (BOM 64732A0102)

38.13 ft/hr

MDi513HWUBPX (BOM 64790A0101)

53.79 ft/hr

MDi513HWUBPX (BOM 64790A0101)

53.80 ft/hr

Analysis 2: 4921.5ft / 15klbs / 130rpm / Steering / TFA10 Trout Creek Sandstone 10-15kpsi UCS © 2012 Schlumberger. All rights reserved.

AXIAL PLOT

IAP Output

RPM 140 120 100 80

RPM L L

L L

L L L

140 120 100 80

L L

5 10 15 20 WOB BHA1 Rotating Mode = No

L L

L L

5 10 15 20 WOB BHA2 Rotating Mode = No

STICK-SLIP PLOT RPM 140 120 100 80

RPM J J J J J 5 10 15 20 WOB BHA1 Rotating Mode = No

140 120 100 80

J J J J 5 10 15 20 WOB BHA2 Rotating Mode = No

LATERAL PLOT RPM 140 120 100 80 110 10/19/2015 © 2012 Schlumberger. All rights reserved.

RPM L L L L L L L L 5 10 BHA1 Rotating

L L L L 15

L L L L 20

Mode = No

140 120 100 80 WOB

L L L L L L L L L L L L L L L L 5 10 15 20 WOB BHA2 Rotating Mode = No

Analyzing IAP Results – Stability & ROP Depth

60.0

8

50.0

7 6

40.0

5

30.0 20.3

20.0

4

22.8 17.8

17.3

3 2

10.0

1

0.0

0

MDSi616

MDSi716

MSI619

MSi713

Values

Average of Initial ROP (ft/hr)

Average of Delta RPM

Average of Lateral Accel. (g) Median

Average of Axial Accel. (g) Median

Bit Type

Slide 111 © 2012 Schlumberger. All rights reserved.

If Stability is the main goal: MDSi616 If ROP is the main goal: MSi619

Av. Lat Acc (g), Av. Axial Acc(g)

Delta RPM, ROP

Average of Lateral Accel. (g) Median Average of Initial ROP (ft/hr) Average of Delta RPM Average of Axial Accel. (g) Median

IAD outputs Same IAR/IAP outputs plus: • Dogleg • BUR • Walk Rate • Well Diameter

Slide 112 © 2012 Schlumberger. All rights reserved.

IAD Output: Well Path

MDi419LKHUPX

MDSI616LBPX

BOM 64579C0401

BOM 64475B0001

Analysis 1: 5339ft / 35ft/hr / 130rpm / Steering / TFA0 Leuders Limestone 5-10kpsi UCS © 2012 Schlumberger. All rights reserved.

Well Dogleg Severity

MDi419LKHUPX BOM 64579C0401

MDSI616LBPX BOM 64475B0001

Analysis 1: 5339ft / 35ft/hr / 130rpm / Steering / TFA0 Leuders Limestone 5-10kpsi UCS © 2012 Schlumberger. All rights reserved.

Well Walk Rate

MDi419LKHUPX BOM 64579C0401

MDSI616LBPX BOM 64475B0001

Analysis 1: 5339ft / 35ft/hr / 130rpm / Steering / TFA0 Leuders Limestone 5-10kpsi UCS © 2012 Schlumberger. All rights reserved.

Well Build Rate

MDi419LKHUPX BOM 64579C0401

MDSI616LBPX BOM 64475B0001

Analysis 1: 5339ft / 35ft/hr / 130rpm / Steering / TFA0 Leuders Limestone 5-10kpsi UCS © 2012 Schlumberger. All rights reserved.

Well Diameter

MDi419LKHUPX BOM 64579C0401

MDSI616LBPX BOM 64475B0001

Analysis 1: 5339ft / 35ft/hr / 130rpm / Steering / TFA0 Leuders Limestone 5-10kpsi UCS © 2012 Schlumberger. All rights reserved.

Summarizing Results – (InTouch 5888017) Average of Build rate (deg/100') Average of Turn rate (deg/100') Average of Lateral (G) Average of Torsional (Kft/lbs) Average of ROP

27.4

5

30.0

27.3

25.0

4

20.0

3

15.0

2

10.0

1 0 MDi419LKHUPX

MDSI616LBPX

MDSi616 yields: • +4 % BUR5.0 • -36% Lat Vib 0.0 • +28% DTQ • Same ROP

Values

Average of Build rate (deg/100')

Average of Turn rate (deg/100')

Average of Lateral (G)

Average of Torsional (Kft/lbs)

Average of ROP Bit Type

© 2012 Schlumberger. All rights reserved.

ROP (ft/hr)

6

IDEAS Predictions and Field Data

© 2012 Schlumberger. All rights reserved.

Results and Interpretation – Is about trends Actual

120 © 2012 Schlumberger. All rights reserved.

Predicted

Results and Interpretation - Vibration It is all about trends, absolute field vibration values matching should not be performed: • Wellbore instability,

hydraulics, hole cleaning effects are not

simulated • Sampling

Frequency is different

• Data processing is different • Sensor location (off center) vs. IDEAS node location

(center) 121 © 2012 Schlumberger. All rights reserved.

Results and Interpretation - Vibration • i-DRILL has created a guideline for simulated vibration levels • Methodology compares IDEAS vs. Field trends • This is still a work in progress, feedback is welcome

122 © 2012 Schlumberger. All rights reserved.

Results and Interpretation - Vibration • i-DRILL R&D is currently working on a validation project comparing down hole data: •

Frequency of measurement in the same order of IDEAS simulations outputs ~1000Hz

•

Processing of data is the same – RMS values

•

Exact location of sensors modeled in IDEAS

123 © 2012 Schlumberger. All rights reserved.

Results and Interpretation - Vibration • i-DRILL R&D is cooperating closely with DMM tool developers from D&M to ensure IDEAS outputs can be compared with measured data in the future

124 © 2012 Schlumberger. All rights reserved.

Results and Interpretation - ROP It is all about trends, absolute field ROP values matching should not be expected: •

Wellbore instability, hydraulics, hole cleaning effects are not considered

•

Field overbalance pressure and rock strength are based on offset information and could/will vary with well location

125 © 2012 Schlumberger. All rights reserved.

i-DRILL® Vibration & Bending Stress Levels

i-DRILL Drilling Dynamics Guidelines Average LATERAL Vibration Level

Bit & Reamer (g)

MWD (g)

Low

100

1Index

calculated as (P95-P5)/(2 x P50 Downhole RPM), Downhole RPM can be either Bit, Reamer or MWD. to rotary shouldered connections (Drill collars), these values may be conservative for MWD, RSS and motor connections. These values don’t apply to HWDP and DP connections, 2000lb as a side contact force maximum to prevent tool joint wear should be used instead..

2Applies

126

≥12

Average AXIAL Vibration Level

© 2012 Schlumberger. All rights reserved.

That Smith Bit on Location, how was it chosen? Offset Performance

Formations (DBOS)

Sent to rig

Customer Ok ($)

IDEAS Modeling

Hyd. and T&D Slide 127 © 2012 Schlumberger. All rights reserved.

D&M DE

Real Time Optimization

Mechanical Specific Energy (MSE)

© 2012 Schlumberger. All rights reserved.

Mechanical Specific Energy (MSE) Fundamental Principles relate  Rock Strength  Amount of Energy required to destroy rock  Efficiency of rock destruction

© 2012 Schlumberger. All rights reserved.

Mechanical Specific Energy (MSE) Ideal Case MSE = 15,001 psi

15,000 psi UCS

© 2012 Schlumberger. All rights reserved.

Specific Energy (SE) Specific energy is defined as the ratio of energy input to drill/remove unit volume of rock to the output ROP. Input energy Specific Energy = Output ROP

Note: It is a dimensionless parameter.

© 2012 Schlumberger. All rights reserved.

Mechanical Specific Energy (MSE) Equation for Es :

Es = WOB + 120 x π x N x T AB AB x ROP 

Where : – – – –

Es = Specific Energy AB = Borehole area (in2) N = RPM T = Torque (ft-lb)

© 2012 Schlumberger. All rights reserved.

Mechanical Specific Energy (MSE) Minimum specific energy is equal to the unconfined compressive strength of the rock being drilled i.e: (ES) = (ESMIN) = σ (compressive strength) Note: Max efficiency is reached when

(ESMIN) = 1 (ES)

© 2012 Schlumberger. All rights reserved.

Factors influencing SE

FACTORS INFLUENCING SPECIFIC ENERGY

LITHO LOGY

RIG CAPABILITY

© 2012 Schlumberger. All rights reserved.

HYDROSTATIC PRESSURE

BIT DESIGN AND SELECTION

BEARING AND SEALS

BHA OPTIMIZATION

HYDRAULICS

Causes of Inefficiency • Dull / Damaged Bit • Vibration • Inadequate Hole Cleaning • Bit Balling • Bottom Hole Balling • Rig / BHA Limits

© 2012 Schlumberger. All rights reserved.

Process Drill-Off Test to determine optimum WOB & RPM MSE trend will develop while drilling ahead  Should

be observed while bit is sharp and adequate hole cleaning

Calibrate (match) predicted ROP (from offsets) to actual ROP  Most common reason for poor correlation is by using surface

values for WOB & RPM instead of down-hole values. – Surface values do not account for friction. Monitor Trends  Increase in MSE or mismatch of ROP’s

inefficiency!

© 2012 Schlumberger. All rights reserved.

could indicate a drilling

Determine Founder Point

DOT data showing non-linear response below the minimum depth of cut and above the founder point

© 2012 Schlumberger. All rights reserved.