2. Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl
Silviu Livescu
Baker Hughes, a GE Company
Coiled Tubing Telemetry –
State of the Technology
3. Outline
Pre-telemetry coiled tubing (CT)
Brief CT history
What can be done without telemetry
CT telemetry (CTT)
Description, benefits
Specific examples (case histories)
Top predictions for next five years
Conclusions
3
Courtesy Baker Hughes
4. 1944 – Project PLUTO
3-in. CT laid overnight under English Channel
Main driver: ability to intervene on live wells
1962 – First fully functional CT unit (first injector)
Wash out sand bridges in wells
CT Early Applications
4Courtesy BBC
5. CT Evolution
5
1970s – Improved injector head design (added
gooseneck, increased pull and CT size)
1980s – Dawn of CT modeling software
(tensile force analysis, flow and fatigue);
bias strip welds introduced in 1989
2000s – Significant
improvements in safety,
quality, and reliability
2000s/2010s – Sustained
growth of technological
capabilities; dawn of
telemetry
1990s – Rapid growth in CT size (from
1.5-in. in 1985 to 4.0-in. in 1995)
6. Current CT Status
Diameter: 0.75- to 4.5-in.
Length: 10,000 to 20,000 ft most
common
39,000 ft. 1.5-in. CT in 2013
Weight: more than 120,000 lb.
(2.875-in. CT)
Yield strength: 55,000 to 140,000
PSI
Improved fatigue modeling
Improved corrosion behavior
6
Courtesy Baker Hughes
7. CT Advantages and Disadvantages
7
Advantages
Live well intervention
Continuously circulating fluids
Ability to perform continuous well-control operations
Disadvantages
Limited pumping rates and push/pull ability
Service life limitations (fatigue, corrosion, wear)
Logistical challenges
No rotation
8. Pre-Telemetry CT Operations
8
Most common pumping applications
Cleanouts
Gas lifting
Stimulation – mostly multi-stage hydraulic fracturing
Most common mechanical applications
Milling and drilling
Setting plugs
Running large tools – perforating guns, logging tools
9. Telemetry with CT
9
Telemetry = tele [remote] + metron [measure]
Consider the drivers
Evolution of wells and reservoirs
Maturing reservoirs
Unconventional reservoirs
Deep water
More intelligent completions
10. CTT Applications
10
Acquire and interpret downhole
information in real time
Depth
Pressure and temperature
Force and torque
Flow pattern mapping
Video and imaging
Distributed temperature and acoustic
data
Courtesy Baker Hughes
11. CTT Benefits
Mitigate uncertainties in unknown downhole conditions
Enhance efficiency, safety and risk management
Reduce operational time and cost
Use available wireline evaluation tools
Applicable to wide range of CT operations
Cleanouts, gas lifting, stimulation, milling, logging operations,
camera services, etc.
554 “coiled tubing telemetry” results on www.onepetro.org as
of February 14, 2018
11
12. CTT Data Transmission
Wire
Insulated electrical conductor in
corrosion-resistant alloy tube
Electrical power from surface
Optical fiber
Distributed temperature and acoustic
data along CT
Downhole batteries
Transmission medium: wire, optical
fiber, or both
12
SPE-183026
14. CTT Downhole Sensors
For CTT systems with wire or optical fiber
Depth correlation (casing collar locator, gamma ray)
Pressure (internal and external)
Temperature (internal and external)
Tool inclination and acceleration
Force (tension and compression) and torque
For CTT systems with optical fiber
Distributed temperature sensing (DTS)
Distributed acoustic sensing (DAS)
14
15. Case History 1 - Drifting, Logging,
Jetting, Zonal Isolation, and Scale
Removal (SPE-174850)
Objective: restore hydrocarbon
production in a mature offshore well
in Brazil
CTT increased certainties in
unknown downhole conditions,
improved efficiency and safety
15
Outcome: 336 hours total run time (seven runs)
9 hours CTT waiting time (due mostly to using one reel and only
replacing the tools)
Potentially 92 hours conventional CT waiting time (due to using
multiple reels and tools)
16. Case History 1 – Continued
(SPE-174850)
16
Run Description Run
Time
(hours)
Conventional
CT Waiting
Time (hours)
CTT System
Waiting Time
(hours)
1 Well drifting 23 20 3
2 First logging 74
3 Rotary jetting for bridge
plug setting
57.5 20 3
4 First bridge plug locating
and setting
14.5 14 0
5 Chemical treatment with
scale solvent
86
6 Second bridge plug
locating and setting
14 14 0
7 Final logging 67 24 3
Totals 336 92 9
17. Case History 2 – Milling with
Vibratory Tool (SPE-187374)
Objective: mill three composite
bridge plugs an offshore well in the
Caspian Sea
CTT allowed better milling control in
unknown downhole conditions,
especially for third plug at 19,950 ft
17
Outcome: total run time reduced from 44 hours to 25 hours
8 hours milling time with no vibratory tool (unsuccessful)
34 minutes milling time with vibratory tool (successful)
18. Case History 2 – Continued
(SPE-187374)
18
Description CTT and Milling
BHA
CTT, Vibratory Tool and
Milling BHA
Total run time (RIH and
POOH)
44 hours 25 hours
Volume of brine used 872 bbl 236 bbl
Volume of H2S inhibitor used 370 gal 185 gal
Additional run needed Yes No
Total milling time 8 hours 34 minutes
19. Case History 3 – Perforating,
Stimulation, and Milling (SPE-189910)
Objective: perforate, stimulate and
mill two composite bridge plugs at
17,300 and 17,600 ft in Kazakhstan
21,000 ft long well completed with
10 swelling packers, eight ball-
activated sleeves and a perforated
joint (open hole)
19
Outcome: milling time reduced by 25% compared to similar
operations without CTT
Two plugs milled in one run by adjusting the weight on bit and
torque while keeping the pumping rate constant
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 22,000
TrueVerticalDepth,ft
Measured Depth, ft
21. Case History 3 – Continued
(SPE-189910)
21
Milling
1.8 bpm Rate
4,300 lbs Weight
280 lb/ft Torque
Plug Displacement
22. Case History 4 – CTT Conveyed
Camera Operation (IPTC-18294)
22
Objective: identify collapsed casing
during a multi-stage fracturing
operation in Texas, USA
Five unsuccessful runs were
performed with wireline, tractor and
camera due to unknown conditions
Outcome:
21 hours total run time for CTT (due mostly to pumping fresh
fluids through CT to clean camera lenses)
27 hours total run time plus 23 hours of standby for wireline,
tractor and camera
23. Case History 4 - Continued
(IPTC-18294)
23
Un-collapsed Casing Collapsed Casing
24. Putting Things Into Perspective
CT supervisor average experience has decreased from
eight years in 1999 to three years in 2016 (Source: ICoTA)
Plan
Re-Tune
Control
Optimize
Automate
Pre-job
Engineering Job Monitoring
Dynamic Limits Injector Control
Limits
CTT System
Feedback Controlled
Performance
24
25. Next Five Years Top Predictions
Further real-time data monitoring enhancements for
better decision making and lower costs
Pumping applications – e.g., friction reducing (lubricants,
vibratory tools, tractors), acid tunneling, cleanouts, etc.
Mechanical applications – e.g., milling/drilling
Electrical applications
Significant development for optimization and
automation of CT operations
Less prone to people-related safety incidents
25
26. Conclusions
CTT systems improve well intervention operations
Increase certainties in unknown downhole conditions
Enhance efficiency, safety and risk management
Reduce operational time and cost
Acquire and interpret downhole information in real time
Depth
Pressure
Temperature
Tool force and torque
Distributed temperature and acoustic data
26
27. Conclusions (Continued)
Applicable to many CT operations
Cleanouts, gas lifting, stimulation, milling, logging
operations, camera services, etc.
Telemetry will be commonly used for CT operations
27
With telemetry, CT operations will become
Less people intensive
More hardware and software intensive
Less prone to people-related safety incidents
28. Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl 28
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