Coil Tubing Drilling (CTD)
Kuparuk Field, North Slope, Alaska
2012 US Canada Research Forum
Dan Venhaus
What is CTD?
•
•
•
2” drill “pipe” on a continuous spool
– Drill with surface pressure
– Internal electric line to “talk” to drilling tools
and directional control
Use existing 3-1/2” wellbore to drill horizontal
sidetracks
Small design - few logging tools available
Flexible
– Higher doglegs, tighter turns
– Less “push”
3800
3600
3400
5 deg/100 ft dogleg
5°/100’
dogleg
3200
3000
2800
Northing
•
2600
2400
2200
2000
45 deg/100 ft dogleg
45°/100’
dogleg
1800
1600
1400
300
100
-100
-300
-500
-700
-900
-1100
-1300
-1500
-1700
-1900
-2100
Easting
CTD Drilling Rig
Mud Module
Mud Pits
Mud Pumps
Power Pack
Rig Module
Kuparuk Background
Field Development
• 6 Billion STBOOIP
• 2 main reservoir sands
•A&C
• Differing permeability
• Commingled production
• Direct N/S line drive development
• 160 acre well spacing
• ~1:1 producer/injector ratio
D
C
B
A
2 miles
Kuparuk Background
Faulting & Structural Complexity
•
•
Structure
– SE-plunging anticline with
1000’ of relief
– Single OWC on east flank
Significant reservoir faulting
– Faulting more pervasive than
imagined at discovery and
early development
– Controls reservoir
compartmentalization
– Fault Behavior =
Primary Uncertainty
Top Kuparuk Time
Structure
KRU 3D
North
~5 miles
Kuparuk CTD Evolution
2006: Slimhole resistivity
April 2011:
Aug. 2004:1st
lined multi-lat
1998: CTD BHAs
downsized
1998
1999
2000
165 CTD laterals
206,773’ drilled
2001
2002
2003
2004
2009: Ribsteer
2005
2005:1st quad-lat;
KWS 3D seismic
1998-2004:
single-laterals
2006
2007
2008
2009
2010
2011
Jan. 2010:
WK 3D
survey
May 2009: Dedicated,
purpose-built rig
Kuparuk CTD Evolution
•
Production
Tubing
What we used to drill…
– Single lateral
– Single window
– Simple completions
CTD Liner
Flow-by Whipstock
Slotted Liner
Kuparuk CTD Evolution
8 horizontal laterals
12900’ of total hole drilled and cased
Chemical tracer installed to monitor flow
Challenges and Solutions
High differential pressure
Increase pressure/
fluid compressibility
5035psi
Fault-bounded
amplitude
4672psi
1052psi
• Solution(s):
– Managed pressure drilling
– Shut in and back flow wells
1220psi
4221psi
5310psi
• Challenge:
Compartmentalized fault
blocks with high
differential pressures
1000’
Initial reservoir pressure = 3200 psi
Challenges and Solutions
Limited length
2000’
•
•
motor
Challenge: lateral length limited to ~3000’
Solution(s):
–
–
–
•
Result:
–
ribsteer
Agitator
Ribsteer vs. bent motor
Well design and planning
Recently completed 4200’ horizontal lateral
(World record 2” coiled tubing)
Summary
• Highly developed technique for challenged oil
– Requires existing wellbores & infrastructure
– Niche tool to develop small pockets of oil
• Technology has come a long way but…….
– Alaska development over a 20-year period
– Significant investment in people & technology
• Dedicated team of 18 engineers & geoscientists support rig
– Technology only used in Alaska  small R&D market for vendors
• The Challenges:
– 2012 Per Well cost ~7.5 mm$ (60% increase since 2009 start)
• Older wells & aging infrastructure
– Maintaining production results
• Oil rates typically in 100’s of barrels per day per well
Questions?
Target Types
Standoff from swept area
13000’MD
12000’MD
11000’MD
“parent”
well log
OWC 6550’
Pay
Watercut of parent: 90%
Watercut post-CTD sidetrack: 50%
~1200’ standoff from parent
drilled in non-pay portion of
reservoir
Target Types
Add length to increase rate
Sealing fault
Throw: ~60-90’
1500’
N
Challenges and Solutions
Unstable shale
Base permafrost
D
C
B
A
• Challenge: Geosteering in
complex reservoir with unstable
interbedded shale
• Solution(s):
– Managed pressure drilling
– Well design to avoid shale intervals
– Expedient plugbacks