Electronically Actuated Packers Electronically-Actuated Packers ...
SPE Drilling Systems Automation Technical Section (DSATS) Well Construction Automation Expands into Completions
Electronically-Actuated Electronically Actuated Packers Automate Installation Procedures
Ed Wood Product Line Manager Wellbore Isolation Baker Hughes
October 30,2011
Agenda g
• Technology for Automated Completions is Available – Concepts Date Back to 1960s
• Equipment Development Case Studies – Production Packers Activated by Pressure Pulses – Openhole Zone Isolation in Extended Reach Wells
– Mudline Gas Migration in Arctic Conditions – Deep Set Long String Wellbore Integrity
2
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Automated Completion Concepts Date back to 1960’s
•Downhole Battery •Gas Generating Setting Force •Magnetic Sensor •Electromagnetic Downlink •Computer Processor •Sonic Signal
3
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Technology gy In Use Today y Downlink
Downhole Sensors
Electromagnetic (Earth, (Earth Wellbore) Flow Rate (Magnitude, Pulse Pattern) Pressure (Applied, Pulsed) Rotation Movement Vibration (Sound) Weight, Torque
Process Data Computer, Firmware
Used in project 4
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Electromagnetic Temperature ( T) Pressure ( P) Accelerometer (Movement, Vibration, Sound) Radioactive Fluid velocity Magnetic RFD Time-Clock
Trigger Electronic To Mechanical
Power Electrical, Hydrostatic Nitrogen Gas generation Nitrogen, Power Charge
Remote Packer Actuation Saves Rig g Time • Remote actuation using pulse communication • Reduces time & risk- no plugging of tubing required • Independent secondary setting mechanism • 80+ Runs in Gulf of Mexico, North Sea and Argentina Surface Module Interface Box Computer Pulsating Unit Controller Fluid in tubing
Downhole M d l Module Frequency actuated completion tools
5
Extended Reach Wells Exceed Practical Limits of Conventional Completions • Develop Automated Multi-Zone Openhole Completion System • Universal Electronic Platform For Activation Of Multiple Tools • Activation Logic ,Temperature, ∆T, Pressure , ∆P , Time • Utilize Existing Field-Proven Hydrostatic Set Openhole Packer Design Reach (m)
0
1000
2000
3000
4000
5000
6000
7000
8000
0
9000 0
500 5000
TVD(m)
TVD(ft)
1000 10000
Depth vs Reach All wells
1500
15000 Low reach Medium Reach Extended Reach Very Extended Reach
2000
20000 0
5000
10000
15000
20000
25000
30000
5,000 ,
Technology Reach (ft MDRT) 10,000 , AB27 well 15,000 , Planned AB 20,000 , 25,000 , 35 30,000 , wells Potential 35,000 000' well Drilling
35000
2500 40000
Reach (ft)
0
One -trip Liner Perforating Completion
35,000 ,
40,000 ,
Current Pre -FDP2005
Bridging the the gap... gap... Bridging
Control Line Deployment C il d Tubing Coiled T bi
...and expanding the technical limits. …. 6
Top Completion ZoneZoneZoneZoneZoneZoneZoneZoneZoneZoneZoneZoneZoneZoneZon Zone
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Openhole p Automated Packer Development p Existing Openhole Packer
Atmospheric Chamber
Activation Mechanical shift Sleeve
Modifications for Automated Packer Activation Electronic Trigger assembly
Laptop Replaced Sledge Hammer
Sensors Valve
Pressure & Temperature
Programmable Electronics 7
© 2010 Baker Hughes Incorporated. All Rights Reserved.
Automated Barriers Enhanced Wellbore Integrity g y •Revised Industry Standards –Require additional Barriers • Enhance safety by preventing: • • • •
Annular hydrocarbon migration Flow after cementing Sustained casing pressure (SCP) Gas-contamination of cement
• Improve operational efficiency • Reduce well costs • Wellbore Integrity For Final P&A
8
© 2010 Baker Hughes Incorporated. All Rights Reserved.
Electronic Activated Wellbore Integrity g y • Solid-body packer mandrel with tubular
connections – No holes in the pipe
• Electronically activated setting module – Eliminates Eli i t need d ffor pressure or pipe i manipulation to set the packer – Self-contained pressurized gas and/or hydrostatic chambers maintain continuous setting force to enhance seal integrity • Proven (ISO 14310 V0) seal technology
9
© 2011 Baker Hughes Incorporated. All Rights Reserved.
5-1/2” X 9-5/8”
18-5/8” X 24”
Automated Annular Packer…Deep Applications 392°F 392 F, (200 (200°C) C) Seal Module
Hydrostatic Setting Mechanism
• M Magnetic ti Wiper Wi plug l activates ti t electronics l t i • Contingency timer will activate setting sequence at pre-determined time • Emergency magnetic drop bar deactivated timer • Hydrostatic Pressure sets Extruded Packer seal
Magnetic Pattern Pa cker Wa lls
Sensor with X-a xis Sensitivity
Radial Ma gnet Atta ched to Plug
10
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Electronics Module
Field Trials - 5½ X 9⅝ in. Automated Packer System • Operational parameters – Q4 2011 in Eagle Ford Field, South Texas – 17,000 ft – 18,000 ft TD (11,500 ft TVD) – Setting g temperature p ~200°F ((335°F max BHT)) – 11.5 – 12.5 lb/gal mud weight – Set packer above 9⅝ in. 40# casing shoe at ~6,000 6,000 ftt TVD • Packer specifications – Mandrel equivalent to 5½ in. 20# P-110 casing with Buttress threads – Packer element and seals rated to 400°F – Packer differential rating exceeds 9⅝ in. 40# N-80 N 80 casing burst
11
© 2010 Baker Hughes Incorporated. All Rights Reserved.
Automated Packer…Shallow Applications Seal Module
Setting Mechanism
Electronics Module
Air Hammer sends acoustic signal to activate • Electronics module activates setting sequence • Contingency timer provides back up activation • Extruded Seal ISO 14310 V0 qualified •
Vibration Sequence
12
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Nitrogen Spring
Mudline Packer System y Surface Control Box
Electronic Collar
Signal
13© 200
Transmitter
Standard Components.. p Only Bigger for 18⅝ X 24 in. • Proven Zero Extrusion metal/elastomeric seal – Overall reliability 99.52% (>35,000 ( 35,000 runs) – ISO 14310 V0 qualifications – 5½ X 9⅝ in. thru 18⅝ X 24 in. – 28°F/-2°C thru 395°F/200°C – Up to 15,000 psi
– Aflas and Nitrile elements available – Flow loop p testing g at over 17 bpm p – Body Lock Ring maintains setting force
• Existing sizes to be leveraged for seal
development when applicable
© 2010 Baker Hughes Incorporated. All Rights Reserved. 14
Field Trials - 18-5/8” X 24” Automated Packer • Operational parameters – Q2 2012 in Arctic Field – Setting temperature ~50°F – Operating temperature range from 28°F – 107°F – Set packer in 24” 125 125.5# 5# casing below the mudline at ~450 ft TVD • Packer specifications – Mandrel M d l equivalent i l t tto 18⅝ iin. 96 96.5# 5# N N-80Q 80Q casing i with VAM Big Omega IS-NA threads – Packer differential rating successfully V0 tested to 18⅝ in. in 96.5# 96 5# N N-80Q 80Q casing collapse
15
© 2010 Baker Hughes Incorporated. All Rights Reserved.
Vision For The Future Of Automated Completions p • Mass Produced Universal Electronics Packages • Life Lif off Well W ll Down D Hole H l Power P • Wireless Two Way Communication • Verification of Seal • Not Electronic, Mechanical Clocks • Disappearing pp g Lugs, g , Balls,, Plugs g • All Service Tools in Casing, Tubing Made of Composite
Drillable
16
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Questions?
17
© 2010 Baker Hughes Incorporated. All Rights Reserved.
Electronically-Actuated Electronically Actuated Packers Automate Installation Procedures
Ed Wood Product Line Manager Wellbore Isolation Baker Hughes
October 30,2011
Agenda g
• Technology for Automated Completions is Available – Concepts Date Back to 1960s
• Equipment Development Case Studies – Production Packers Activated by Pressure Pulses – Openhole Zone Isolation in Extended Reach Wells
– Mudline Gas Migration in Arctic Conditions – Deep Set Long String Wellbore Integrity
2
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Automated Completion Concepts Date back to 1960’s
•Downhole Battery •Gas Generating Setting Force •Magnetic Sensor •Electromagnetic Downlink •Computer Processor •Sonic Signal
3
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Technology gy In Use Today y Downlink
Downhole Sensors
Electromagnetic (Earth, (Earth Wellbore) Flow Rate (Magnitude, Pulse Pattern) Pressure (Applied, Pulsed) Rotation Movement Vibration (Sound) Weight, Torque
Process Data Computer, Firmware
Used in project 4
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Electromagnetic Temperature ( T) Pressure ( P) Accelerometer (Movement, Vibration, Sound) Radioactive Fluid velocity Magnetic RFD Time-Clock
Trigger Electronic To Mechanical
Power Electrical, Hydrostatic Nitrogen Gas generation Nitrogen, Power Charge
Remote Packer Actuation Saves Rig g Time • Remote actuation using pulse communication • Reduces time & risk- no plugging of tubing required • Independent secondary setting mechanism • 80+ Runs in Gulf of Mexico, North Sea and Argentina Surface Module Interface Box Computer Pulsating Unit Controller Fluid in tubing
Downhole M d l Module Frequency actuated completion tools
5
Extended Reach Wells Exceed Practical Limits of Conventional Completions • Develop Automated Multi-Zone Openhole Completion System • Universal Electronic Platform For Activation Of Multiple Tools • Activation Logic ,Temperature, ∆T, Pressure , ∆P , Time • Utilize Existing Field-Proven Hydrostatic Set Openhole Packer Design Reach (m)
0
1000
2000
3000
4000
5000
6000
7000
8000
0
9000 0
500 5000
TVD(m)
TVD(ft)
1000 10000
Depth vs Reach All wells
1500
15000 Low reach Medium Reach Extended Reach Very Extended Reach
2000
20000 0
5000
10000
15000
20000
25000
30000
5,000 ,
Technology Reach (ft MDRT) 10,000 , AB27 well 15,000 , Planned AB 20,000 , 25,000 , 35 30,000 , wells Potential 35,000 000' well Drilling
35000
2500 40000
Reach (ft)
0
One -trip Liner Perforating Completion
35,000 ,
40,000 ,
Current Pre -FDP2005
Bridging the the gap... gap... Bridging
Control Line Deployment C il d Tubing Coiled T bi
...and expanding the technical limits. …. 6
Top Completion ZoneZoneZoneZoneZoneZoneZoneZoneZoneZoneZoneZoneZoneZoneZon Zone
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Openhole p Automated Packer Development p Existing Openhole Packer
Atmospheric Chamber
Activation Mechanical shift Sleeve
Modifications for Automated Packer Activation Electronic Trigger assembly
Laptop Replaced Sledge Hammer
Sensors Valve
Pressure & Temperature
Programmable Electronics 7
© 2010 Baker Hughes Incorporated. All Rights Reserved.
Automated Barriers Enhanced Wellbore Integrity g y •Revised Industry Standards –Require additional Barriers • Enhance safety by preventing: • • • •
Annular hydrocarbon migration Flow after cementing Sustained casing pressure (SCP) Gas-contamination of cement
• Improve operational efficiency • Reduce well costs • Wellbore Integrity For Final P&A
8
© 2010 Baker Hughes Incorporated. All Rights Reserved.
Electronic Activated Wellbore Integrity g y • Solid-body packer mandrel with tubular
connections – No holes in the pipe
• Electronically activated setting module – Eliminates Eli i t need d ffor pressure or pipe i manipulation to set the packer – Self-contained pressurized gas and/or hydrostatic chambers maintain continuous setting force to enhance seal integrity • Proven (ISO 14310 V0) seal technology
9
© 2011 Baker Hughes Incorporated. All Rights Reserved.
5-1/2” X 9-5/8”
18-5/8” X 24”
Automated Annular Packer…Deep Applications 392°F 392 F, (200 (200°C) C) Seal Module
Hydrostatic Setting Mechanism
• M Magnetic ti Wiper Wi plug l activates ti t electronics l t i • Contingency timer will activate setting sequence at pre-determined time • Emergency magnetic drop bar deactivated timer • Hydrostatic Pressure sets Extruded Packer seal
Magnetic Pattern Pa cker Wa lls
Sensor with X-a xis Sensitivity
Radial Ma gnet Atta ched to Plug
10
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Electronics Module
Field Trials - 5½ X 9⅝ in. Automated Packer System • Operational parameters – Q4 2011 in Eagle Ford Field, South Texas – 17,000 ft – 18,000 ft TD (11,500 ft TVD) – Setting g temperature p ~200°F ((335°F max BHT)) – 11.5 – 12.5 lb/gal mud weight – Set packer above 9⅝ in. 40# casing shoe at ~6,000 6,000 ftt TVD • Packer specifications – Mandrel equivalent to 5½ in. 20# P-110 casing with Buttress threads – Packer element and seals rated to 400°F – Packer differential rating exceeds 9⅝ in. 40# N-80 N 80 casing burst
11
© 2010 Baker Hughes Incorporated. All Rights Reserved.
Automated Packer…Shallow Applications Seal Module
Setting Mechanism
Electronics Module
Air Hammer sends acoustic signal to activate • Electronics module activates setting sequence • Contingency timer provides back up activation • Extruded Seal ISO 14310 V0 qualified •
Vibration Sequence
12
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Nitrogen Spring
Mudline Packer System y Surface Control Box
Electronic Collar
Signal
13© 200
Transmitter
Standard Components.. p Only Bigger for 18⅝ X 24 in. • Proven Zero Extrusion metal/elastomeric seal – Overall reliability 99.52% (>35,000 ( 35,000 runs) – ISO 14310 V0 qualifications – 5½ X 9⅝ in. thru 18⅝ X 24 in. – 28°F/-2°C thru 395°F/200°C – Up to 15,000 psi
– Aflas and Nitrile elements available – Flow loop p testing g at over 17 bpm p – Body Lock Ring maintains setting force
• Existing sizes to be leveraged for seal
development when applicable
© 2010 Baker Hughes Incorporated. All Rights Reserved. 14
Field Trials - 18-5/8” X 24” Automated Packer • Operational parameters – Q2 2012 in Arctic Field – Setting temperature ~50°F – Operating temperature range from 28°F – 107°F – Set packer in 24” 125 125.5# 5# casing below the mudline at ~450 ft TVD • Packer specifications – Mandrel M d l equivalent i l t tto 18⅝ iin. 96 96.5# 5# N N-80Q 80Q casing i with VAM Big Omega IS-NA threads – Packer differential rating successfully V0 tested to 18⅝ in. in 96.5# 96 5# N N-80Q 80Q casing collapse
15
© 2010 Baker Hughes Incorporated. All Rights Reserved.
Vision For The Future Of Automated Completions p • Mass Produced Universal Electronics Packages • Life Lif off Well W ll Down D Hole H l Power P • Wireless Two Way Communication • Verification of Seal • Not Electronic, Mechanical Clocks • Disappearing pp g Lugs, g , Balls,, Plugs g • All Service Tools in Casing, Tubing Made of Composite
Drillable
16
© 2011 Baker Hughes Incorporated. All Rights Reserved.
Questions?
17
© 2010 Baker Hughes Incorporated. All Rights Reserved.
