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Slim-Hole and Coiled-TubingTechnology
Dr. William J. McDonaldThomas E. Williams
PTTC Technology Seminar
Lafayette, LA December 5, 2000
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Drilling Engineering Association(DEA)
Sponsors Joint-Industry R&D Projects
28 Members (Operating Companies)
22 Associates (Service Co’s and Consultants)
Currently 113 projects
Typical project: 10-15 participants
Most successful DEA projects:
DEA-44 Horizontal Well Technology
DEA-67 Slim-Hole and Coiled-Tubing
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DEA-67Slim-Hole and Coiled Tubing Technology
Sponsors: Texaco & BP
Start Date: January 1, 1992
End Date: December 31, 2000
Participants: 65
Tasks: 22
Budget: $3 Million
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DEA-67 Tasks
1. Update Software2. New Software
3. User’s Group
4. New Technology
5. Drill-String Design
6. Motors and Bits
7. MWD and Geosteering
8. Well Control
9. UB Drilling/Completion
10. Logging Tools
11. Perforating Systems
12. Completion Techniques13. Stimulation Techniques
14. Production/Workovers
15. Through-Tubing
16. Field Tests
17. Case Histories
18. Well-Planning Manual
19. Composite Tubulars
20. Multibranch CT
21. Schools
22. Forums
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DEA-67 Deliverables
Major reports 6
Computer programs 9
Forums 6
Schools 8
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Advances inSlim-Hole Technology
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Summary
Slimholes:
-Reduce Well Costs 40 to 70%
-Reduce Environmental Costs & Concerns-Tools and Equipment Exist, and are
Available and Reliable
-Safe
-Do Not Usually Limit Production
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Overview
Historical Background
Types of Slim-Holes
Slim-hole Cost Savings
Evolution and Experience
Concerns and Conclusions
Outlook
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Publications on Slim Hole
0
10
20
30
40
50
60
3 9 4 2 4 5 4 8 5 1 5 4 5 7 6 0 6 3 6 6 6 9 7 2 7 5 7 8 8 1 8 4 8 7 9 0 9 3 9 6
YEAR
N
u m b e r o f P u b l i c a t i o n s
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Stekoll SlimholePumping System (1960)
Flow Line
Rubber Hose
1” Tee
Clamp
Polished Rod Liner
2 7/8” Casing
1” EUE Pumping String
Traveling Barrel Insert Pump
Slip-Type Hold-Downwith Rubber RemovedScreen
Blind Cage
Gas Vent
ConventionalStuffing Box
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Stekoll Field Well (1960)
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STEKOLL Field Experience (1960)
Over 1,300 Wells: Kansas, Texas, Canada
1,000 to 3,000 Foot Wells
1” EUE Tubing (Hollow Sucker Rod)
2-1/2” & 2-7/8” Inch Casing
70 BOPD
40 to 50% Reduction in Tubular Costs
17% Overall Cost Savings
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STEKOLL SlimholeOperations (2- 7/8”)
Drilling & Logging
Perforating & Squeeze Cementing Acidizing & Fracturing
Fishing & Washovers
Sand Bailing
Dual Completions
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Hollow Sucker Rod Advantage
“The hollow sucker rod combines the
function of the sucker rod and the
tubing, so it is no longer necessary to
pull both sucker rods and tubing
when working over wells.”
STEKOLL, 1960
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STEKOLL System Limitations (1960)
Limited Slimhole Logging Tools
Workover Concerns
Tubing Failures
Resistance to Slimholes
Resistance to New Technology
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Slim-Hole Systems
Rotary
Drilling
C o l l a r
Downhole
Motor
M u d M o
t o r
Continuous
Coring
C o r e B a r r e l
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Amoco SHADS Rig( Continuous Coring)
Wireline overshot forcore retrieval
Top drive (0-2250 rpm)
Sandline
Drawworks
Hydraulic drive
4-3/8” core bit (0-10,000 lb WOB)
WellboreSlim annulus
(
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Slim-Hole Motor Dr i l l ing
in WyomingAmoco (1995)
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Microdrill Slim-Hole Rig(Rotary Drilling)
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Slim-Hole Drilling Site(BP, 1994)
Site Reduced by 75%
Slim-Hole Site
Conventional Site
200 ft
390 ft
1 6 0 f t
3 3 0 f t
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Material Cost Savings(3” vs. 8”)
0
10
20
30
40
50
60
70
80
MUD CASING CEMENT
80%
70%
40%
% S a v i n g s
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MICRODRILL COSTS (1500-5000 ft DEPTH)
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Slim -Hole Dri ll ing and Complet ionCost Savings
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SLIM-HOLE RIG COSTS
(McLAUGHLIN, 1959)
HOLE SIZE
D A I L Y C O S T S ( $ )
800
625
525
335
9" 6 3/4" 5 5/8" 3 3/4" 0
200
400
600
800
1,000
4 MEN
4 MEN
3 MEN
5 MEN
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SLIM-HOLE CASING AND TUBING COSTS
(McLAUGHLIN, 1959) 7" CASING
2 7/8" TUBING
5 1/2" CASING 2 3/8" TUBING
4" CASING 1 1/2" TUBING
2 3/8" CASING NO TUBING
R E L
A T I V E C O S T
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40% Saving s Fo r 5000-ft WELLS (BONSALL, 1960)
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SLIM HOLE
( $ )
CONVENTIONAL
( $ )
% OF TOTAL
SAVINGS
ACID
150
600
3
LOGGING 850 850 --
PERFORATING
450
350
-1
FRACTURING
3300
4500
8
LOCATION EXPENSE
2500
2500
--
MUD 1000 1000 --
CORE ANALYSIS
200
200
--
TOTAL:
52,220
100
37,470
Savings For 5000-ft Wells (con t.)
2209314X DEA-67
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Cost Savings with Slim Holes
OPERATOR LOCATION SAVINGS YEAR
Hudson's Bay Canada 28% 1959
Western Mining Australia 75% 1984
Oryx Texas 50% 1991Elf/Microdrill Paris Basin 65% 1992
Maraven Venezuela 20% 1994
Chevron California 66% 1995
Wilcox Operators Texas 15% 1995GUPCO/Amoco Gulf of Suez 20% 1995
Shell Madagascar 40% 1996
ARCO Alaska 26% 1996
Remote Coring Operations
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SLIM-HOLE COSTS (WESTERN MINING, 1984)
4.0
2.0
0
6.0
W E L L C O S T (
$ M M )
LOGISTICS
REMOTE LOCAL
SLIM HOLE
CONVENTIONAL
2000m TD
DRY HOLE ONSHORE
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Conoco Indonesia Sl im-Hole Cos ts
(MACFADYEN et al., 1986)
1980-81 (CONV)
1985-86 (SH)
NUMBER OF WELLS
5
3
12
AVERAGE WELL COST 7,670,000 4,680,000 2,060,000
DRILLING
TOTAL FOOTAGE 18,962 11,740 29,179
AVERAGE DEPTH 3,792 3,913 2,432
DRILLING COST/WELL
2,770,000
960,000
760,000
LOGISTICS
NO. OF LIFTS 317 187 100
NO. OF DAYS 16 9 5
HELICOPTER
PUMA
PUMA
S-58T
1983 (SH)
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ORYX
HORIZONTAL SL IM-HOLE COSTS
(HALL AND RAMOS, 1992)
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DAYS DEPARTURE LATERAL COST TOTAL COST
18 1458 3.88 (CT) 0.63
38 2018 3.31 0.74
24
2002
1.84
0.41
21 2692 1.46 0.43
20 2242 1.83 0.45
18 1927 2.36 0.50
14 1600 1.75 0.31
22 1900 2.60 0.54
1991-92 ORYX SL IM-HOLE RE-ENTRIES
(HALL AND RAMOS, 1992)
0.50
1980
2.38
AVG 22
1991 CONVENTIONAL COST = 1.00
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ORYX'S CONCLUSION (1992)
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Domain Energy Slimholes (1995)
Cased Hole
5-1/2” Casing
4-3/4” Hole
2-7/8” Production Casing
7-7/8” Hole
TD 10926’
1518’
TD 10909’
Open Hole
7-5/8” Casing
4-3/4” Hole
2-7/8” Production Casing
9-7/8” Hole
1520’
10697’
InflatableCasing Packer
Cement
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Domain Energy Slim-Hole (1995)
Location:
Rig Modification:
Hole Diameter:
Casing Diameter:
Drill Pipe Diameter:Collar Diameter:
Motor Diameter:
Drilling Rate:
Problems:Successes:
Cost Savings:
Green River Basin, WYBowen S3.5 Power Swivel
4-3/4 inches
2-7/8 inches
2-7/8 inches3-1/2 inches - 3 stabilizers
3-3/8 and 3-3/4 inches
Up to 2x increase
4 Twist-offs (stabilizer torque)Cementing/Logging/Perforating
Breakeven (due to twist-offs)
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Domain Energy Slim-Hole Problems (1995)
Slim-Hole No. 1 Plugged bit nozzles - 1,006 ft
Motor twist-off (stabilizer torque) - 7,071 ft
Fishing - 3 trips
Slim-Hole No. 2 Hole deviation (no stabilizers)
Low ROP (reduced WOB due to hole deviation) Stuck pipe - 8,085 ft (stabilizer torque)
Fishing - back-off, spear, 4 trips (7 days)
Logging - problem running tool
Slim-Hole No. 3
Motor twist-off (stabilizer torque) - 1,004 ft Fishing - 3 trips (23 hours)
Motor twist-off (stabilizer torque) - 5,187 ft
Fishing - 1 trip (grapple)
Lost cone - 10,871 ft (drilled with rock bit)
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Unocal Thailand Slim-holes (1999)
Conventional
2-7/8” TBG
Slimhole Ultra Slim
13-3/8” @ 1000’
9-5/8” @ 4500’
7” @ 10000’
SSSV SSSV SSSV
9-5/8” @ 850’
7” @ 2500’
2-7/8” TBG @ 4500’
6-1/8” Hole
7-5/8” @ 850’
5-1/2” @ 2500’
2-7/8” TBG @ 4500’
4-3/4” Hole
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Unocal Thailand Slimholes (1999)
0.75
1.3
0
0.2
0.4
0.6
0.8
1
1.2
1.4
W e l l
C o s t ( $ m i l l i o
n s )
Slimhole Conventional
(4-3/4”) (8-1/2”)
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Unocal Gas Production Rates (1999)
0.00 500 1000 1500 2000 2500
C u m u l a t i v e G a s P r o d u c t i o
n ( M M S C F )
Time (days)
Slimhole Wells
Conventional Wells
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Unocal, 1997
“Slimhole development has completely
Transformed the future of Gulf of Thailand
Operations and has paved the way for
Operators to continue providing a long-
term economic supply of gas to the
Kingdom of Thailand”
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Pemex Slimholes (1998)
Conventional
13-3/8” Casing
12-1/4” Drill Bit
7” Casing
Packer
9-5/8” Casing
17-1/2 Drill Bit
2-7/8” Tubing
8-1/2” Drill Bit
3000 m
1650 m
150 m
Slimhole
9-5/8” Casing
8-1/2” Drill Bit
Cement
7” Casing
12-1/4 Drill Bit
3-1/2” Tubing
5-7/8” Drill Bit
3000 m
1650 m
150 m
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Texaco Dual Completion Slimhole
13-3/8” Casing
12-1/4” Hole
2-7/8” Tubing
9-5/8” Casing
17-1/2 Hole
2-7/8” Tubing
8-1/2” Hole
10,500’
8,000’
2,500’
Cement
12,500’
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Slim-hole Well Concerns
Casing Program
Drillstring Torsional Strength
Fishing & Milling
Increased ECD (lost circulation)Bit Design and Reliability
Downhole Motors(cost & reliability)
Cementing (primary & squeeze)Stimulation
Workovers
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Conclusions
Slimholes:
-Reduce Well Costs 40 to 70%
-Reduce Environmental Costs & Concerns
-Tools and Equipment Exist, and are
Available and Reliable
-Safe
-Do Not Usually Limit Production
Hi h P Sli M t
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High-Power Slim Motors
Bearing
PackUniversal Jt
Long Power Section
StandardPower
Sections
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Leniek Pumping System (1999)
Production Line
1-1/2” Hydraulic
Hose
Clamp
Hollow Polish Rod
3-1/2” Cemented Tubing
2” Coiled Tubing
Hollow Rod Pump
AnchorScreen
Gas Vent
Stuffing Box
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Leniek CT Pumping System
Conventional Surface Equipment1,000 to 5,000 Feet
2-7/8” or 3-1/2” Casing (CT or
Tubing)1-1/2” CT (Hollow Sucker Rod)
Hollow Polish Rod
Hollow Rod Pump
YPF Installation
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YPF Installation
Leniek System Advantages
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Leniek System Advantages
Reduce Well Construction Cost 50
PercentEliminates Tubing Thread Failures
Eliminates Tubing Anchors
Reduce Lifting CostsReduce Paraffin Problems
Reduce Casing Wear
Treat Wells Through CTEliminate Rod Failures
Allows Ultraslim Holes
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Advances inCoiled-Tubing Technology
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Overview
History & Evolution
Current Status
Conventional Operations
Coiled Tubing Drilling (CTD)
Outlook
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Evolution
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Evolution
1944 Allied Invasion Europe1962 Bowen CTU
1975 - 200 Units - 1-1/4”
1980 - Improved Pipe/Welding
1983 - Continuously Milled 3000’
1987 - Bias-Welded Strips1992 - 2-3/8” to 3-1/2” OD CT
1999 - 110 ksi CT
Today
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Today
750 Units Worldwide
50% in North America
Few Pipe Failures
Multiple Applications
CT Pipelines
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Common Applications
Clean outs (50%)
Stimulations
Profile Modifications
Perf/Log
Artificial Lift
Sand Control
Coiled-Tubing Applications
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Coiled-Tubing Applications
Clean-outDownhole Tools
Stimulation
Nitrogen Lift
Drilling
Logging/Perf
Jetting
Fishing
Cementing
Source: Quality Tubing
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Cost Savings with Coiled Tubing
OPERATOR JOB SAVINGS YEAR
ARCO Alaska Cement Squeeze 90% 1987
Fracmaster Pipeline Cleanout 90% 1988
BP (North Sea) Barium Scale 80% 1990Chevron Velocity String 59% 1992
Amoco (GOM) Zinc Sulphide 94% 1993
BP Alaska Spoolable GL 68% 1993
Mobil Fracturing 21% 1994Amoco TT Gravel Pack 80% 1996
Workovers
Completions
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Hybrid Coiled Tubing/
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Hybrid Coiled-Tubing/Snubbing Rig
(Hydrarig)
CT Injector
Injector Trolley
Jack Cylinder
Quad BOP
Substructure
Support Pole
Oman Large-OD CT Completions
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Oman Large OD CT Completions
ESP Well
SlipConnection
ESP cable
3-1/2” CT
Slip connector
Landing nipple
Protector
Motor
Centralizer
7” K55, LTC
Pump
2-7/8” CT
4-1/2”
Tie back
Slim ConcentricWater Injector
4-1/2” Tie back
2-7/8” EU nipple
5-1/2” x 2-7/8” production
packer
Gas Lift Well
7” shoe
3-1/2” nipple
7” packer
Slidingsleevecirculatingdevice
13-3/8”
casing
Gas liftmandrels
Velocity String
2-7/8” EU nipple
Productionpacker
Hyd. setretrievable
packer
Bottom holepress. gauge
Gas liftmandrel
Top CT plug
1-1/2” CT
3-1/2” tubing
Taylor and Conrad (1996)
ARCO Coiled-Tubing Liner
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ARCO Coiled Tubing Liner
Production tubing
Hydraulic set packer
Open-hole well(possibly drilled with
coiled tubing)
CT liner Pre-perforatedCT liner with
optional screen
Pay Zone
CT Steam-Injection System
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j y
Coiled Tubing
SteamGenerator
Injector
BOP
Wellhead
8
0 0 0 ’
CasingProduction
Tubing
Concentric CT
SlottedLiner Concentric CT
Cross Section
Pearlite
Oil Reservoir
OilOil
Steam
Steam
2-7/8” CT
1-3/4” CT
Coiled Tubing Drilling
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Coiled Tubing Drilling(CTD)
History of CDT
Current Status
Demographics of Current Activity
Advantages and Limitations
Where are we headed with CTD?
Coiled-Tubing Drilling System
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Coiled-Tubing Drilling System
Injector ReelPower Supply
Whipstock orCement Plug
2” CT with Wireline
Connector
Orienter
MudMotor
Bent Sub Bit
GuidanceSystem
Why CTD or Why Not ?
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Why CTD or Why Not ?
Continuous CirculationPressure Control
Footprint, Environmental
LWD, Geosteering, Joystick OperationDeepenings, Side-Tracks
Through-Tubing Capable
Costs?
Availability
Acceptance
Brief CTD History
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Brief CTD History
1991 - Elf/Dowell & ORYX/Cudd1992 - Arco first window & MWD
1994 - First North Sea CTD wells
1994 - Maersk 3000’ Horizontal well
1995 - 200+ CTD Wells Worldwide
1999 - 1200± CTD Wells
Schlumberger Electrically-Controlled
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Schlumberger Electrically-ControlledCT Drilling System
2" CTDrilling
Head
Logging/Steering
Sub
ElectricOrienter Motor
7-Conductor
Wireline
Bit
Schlumberger “Viper” BHA
Transocean Hydraulically-Controlled
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Transocean Hydraulically ControlledCT Drilling System
1/4" SS Hydraulic Tubing
Connector
Logging/Steering SubHydraulicOrienter Motor
Monoconductor Wireline
Bit
2" CT
Check Valves/
Release Sub
Transocean Dual-Capillary BHA
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Arco CTD History
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y
1990-Initial interest for PRB ST1991-Initial ST effort unsuccessful
1992-94 Oklahoma Window Milling Tests
1992-Successful ST in West Texas
1993-Prudhoe program started
1994-95 THUMS Efforts,1997++ Algeria, Indonesia, CA, NM...
ARCO S (1999)
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ARCO Summary (1999)
120
11
1 1 3 10
20
40
60
80
100
120
Alaska California New Mexico Texas Indonesia Algeria
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Running 3 1/2” CTC after CTD
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g /
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Typical CTD Completion at PRB
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Surface Testing
17 PPG Fiber F/O PlugPilot HoleCasing Exit
“One Step” Mill
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1999-2000 CTD Developments
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Thru - 3-1/2” Tubing Operations Over 30 Slimhole Operations To-date
Fluid Loss/ECD Concerns
Lower DensityLower Polymer loading
Shale Stabilization Additives
Bi-center Bits
PRB CTD Average Footage
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817
1204
17941685
1950
0
200
400
600
800
1000
1200
1400
1600
1800
2000
A v e r a g e F o o t a g e
1995 1996 1997 1998 1999
Prudhoe Bay Summary
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100 wells 1993-99
Average Cost
1995 - $990M1996 - $1005M1997 - $1165M1998 - $1200M1999 - $1375M
•Harder, Longer Reach Targets• Avg. Production 1400 BOPD
•90% success
Grissom IslandTHUMS - Arco Project
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THUMS - Arco Project
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California CTD Project
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j
4/97- Drilled 7 shallow vertical wells
Fleet Cementers CTU - unique design
Used 2 7/8” OD CT, 4 3/4” PDMs
Hole size 6 to 6 1/2” holes, 1 to 9 1/2”
Depths 900-1000’ , Ran 3 1/2” casing
Total time 24 hours/well
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Indonesia
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Multiple well program in NW Java SeaOne ST/ window through 9-5/8” csg- 1997
870’ of 6-1/8” hole drilled w/ 2-3/8” CT
Used tinder barge rig as supportCompleted with cemented 3-1/2” liner
2nd well discontinued after 500’ - shale
3rd well April - June 1998- lost hole - shale
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Offshore Indonesia
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Current Status of CTD
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20 CTU’s capable of serious CTD
Less than 10 CTU’s actively drilling
AK, Oman, Canada, N. Sea, Venezuela
Currently active; Schl, Baker, BJFleet
MWD, electric/hydraulic BHA’s
Why CTD or Why Not ?
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Continuous CirculationPressure Control
Footprint, Environmental
LWD, Geosteering, Joystick OperationDeepenings, Side-Tracks
Through-Tubing Capable
Costs? Availability
Acceptance
What is the Future ?
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Underbalanced operations All-electric CTD BHA
Composite CT
Pre-programmed, self guided BHA
Smaller BHAs
Through-tubing rotary drilling
Fiberspar Composite Coiled Tubing
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e spa Co pos e Co ed u g
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FS CT Field Validation Trails
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FS CT Field Validation Trails
HalliburtonEnergy Services
To date, 6 - CO2
injection wellclean-outs withacid stimulationfor Altura in W.TX and Phillips
in NM
FS LP First Commercial Application
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FS LP First Commercial Application
Altura, Levelland,TX
40,000’ waterflood installation
2” ID, 1500-psiWP FibersparLinePipe used
Pipe shipped in8,000 ftcontinuouslengths
Mobile Spooling Unit
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Mobile Spooling Unit
Few Fittings
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Few Fittings
Long runs wereeasilyaccomplished withfew or no fittings
to account forturns
Several long runswith multiple turns
were successfullycompleted in asingle pull
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