1. Optical Sensing Systems Gisle Vold

2. © 2006 Weatherford. All rights reserved. Slide 1  1870 : Principle of Total Internal Reflection discovered  1950 : Invention of first laser  1970 : First low-loss fibre produced  1974 : Launch of optical communications  1986 : Introduction of optical amplifiers  1994 : Introduction of multi-wavelength systems  2000 : Peak of Telecom bubble History

3. © 2006 Weatherford. All rights reserved. Slide 2 Transmission Data Rate and Capacity Broadband capability of optical fiber allows multiple channel transmission –Currently 128 channels with existing components –Each channel can carry 10Gb/s –Unlike electrical signals, optical signals do not interfere with each other Each Fiber has an aggregate data rate of 1.28Tb/s = 1,280,000,000,000 bps ! This translates to: –20 million simultaneous phone connections (64kb/s each); typical telecom twisted-pair cable 300 phone calls 2 Twisted Pair Copper- MHz - 300 Phone Calls Single Fiber - THz - Over 20 Million Phone Calls

4. © 2006 Weatherford. All rights reserved. Slide 3 Bandwidth !

5. © 2006 Weatherford. All rights reserved. Slide 4 What makes us different ? Operation Principle Suite of Sensors Extreme Long Term Stability Unmatched Durability

6. © 2006 Weatherford. All rights reserved. Slide 5 Bragg Grating Operating Principle Input Spectrum P Transmitted Spectrum P

7. © 2006 Weatherford. All rights reserved. Slide 6 Bragg Grating Operating Principle UV interference UV laser beams photo-inscribed grating in core

8. © 2006 Weatherford. All rights reserved. Slide 7 Bragg Grating Operating Principle Reflected component Transmitted light Input Spectrum P Transmitted Spectrum P B Reflected Spectrum P B

9. © 2006 Weatherford. All rights reserved. Slide 8 Bragg Grating Operating Principle stretch Strain-induced shift in grating resonance wavelength

10. © 2006 Weatherford. All rights reserved. Slide 9 Reflected component Transmitted light Input Spectrum P Transmitted Spectrum P B Reflected Spectrum P strain-induced shift B Bragg Grating Operating Principle

11. © 2006 Weatherford. All rights reserved. Slide 10 Optical Wave 1 Optical Wave 2 Interference of 1 + 2 Interference of Two Optical Waves

12. © 2006 Weatherford. All rights reserved. Slide 11 Interference of Two Optical Waves

13. © 2006 Weatherford. All rights reserved. Slide 12 Interference of Two Optical Waves

14. © 2006 Weatherford. All rights reserved. Slide 13 Interference of Two Optical Waves

15. © 2006 Weatherford. All rights reserved. Slide 14 Interference of Two Optical Waves

16. © 2006 Weatherford. All rights reserved. Slide 15 Path 1 Path 2   =2*  *n*L    =2*  *n*L   L 2 -L 1  Bulk-Optic Michelson Interferometer

17. © 2006 Weatherford. All rights reserved. Slide 16 Mirrors Two Legs with Mirrors Fiber Michelson Interferometer

18. © 2006 Weatherford. All rights reserved. Slide 17 Single Leg with Grating Reflectors Fiber Michelson Interferometer

19. © 2006 Weatherford. All rights reserved. Slide 18 What makes us different ? Operation Principle Suite of Sensors Extreme Long Term Stability Unmatched Durability

20. © 2006 Weatherford. All rights reserved. Slide 19 The Case for Fiber Optic Sensors High Reliability –No Downhole Electronics –No Moving Parts –Nominal Part Count Ideally Suited For Harsh Environments –High Temperature Capability –Vibration and Shock Tolerant High Data Transmission Capability –Multiple Sensors on Common Fiber Infrastructure –Technological Advances Driven by Telecom

21. © 2006 Weatherford. All rights reserved. Slide 20 Downhole Cable

22. © 2006 Weatherford. All rights reserved. Slide 21 Temperature Profiling Thermal profile of well Production and injection profiling Identify well problems Monitor water, gas, steam breakthrough Artificial lift monitoring Distributed Temperature Sensing (DTS) and Array Temperature Sensing (ATS)

23. © 2006 Weatherford. All rights reserved. Slide 22 DTS - Operation Principle Spectrometer Laser sourc e Processing Spectral Processing T(z) Fiber T e m p e r a t u r e P r o f i l e T(z) Scattered light at location z Pulse Modul ator Raman Stokes/Anti-Stoke Ratio Surface Unit

24. © 2006 Weatherford. All rights reserved. Slide 23 Raman Stokes Anti-Stokes ratio DTS – measurement principle

25. © 2006 Weatherford. All rights reserved. Slide 24 Array Temperature Sensing Accurate/stable point measurements –15-18 points/fiber –P/T gauge can be deployed on same fiber 1 P/T + 12 ATS –<0.01°C (0.018°C) temperature resolution –Update rate 3 – 5 seconds Similar technology to Weatherford optical P/T gauge –Glass microstructure –Manufactured by Weatherford –Integrated into standard ¼” Inc 825, 3-fiber cable Temperature sensor isolated from strain Standard deployment techniques –Location of sensors needs to be defined in advance of installation Same instrument as optical P/T gauge (platform or subsea) Long distance (>30km) reach Field trials planned for 2006 (land) and 2007 (subsea) Leveraging Existing Technology

26. © 2006 Weatherford. All rights reserved. Slide 25 Build model to evaluate DTS sensitivities to : total flow rate oil, gas and water profile differences flow allocation water breakthrough gas coning pressure drawdown Specific input required from customer Simulation of well candidates

27. © 2006 Weatherford. All rights reserved. Slide 26 WFT-PLATO software –Three-phase PLT analysis –Statistical optimization –Global statistical modeling of entire well –Automatic determination of flow regime –Interactive visualization –Simultaneous use of all logs and surface information to determine production profile –Emulation capabilities Temperature Profiling Design & Analysis –Warm-back tests for injectors –Specialized tests for producers –Temperature array array design –Service –Software WFT Temperature Profiling Analysis Capabilities

28. © 2006 Weatherford. All rights reserved. Slide 27 Temperature Profiling Data Viewer Standalone application for viewing DTS data SQL Database, LAS, POSC, ASCII format files Features –Animations relative to baseline DTS data –User-specified data interval density (in time) –User-settable zooming, scaling, gridding, scrolling, smoothing, etc. Intended users –Operators – for quick qualitative analysis –Production and reservoir engineers – for identifying trends and visualizing specialized tests, e.g., warmback tests in injection wells

29. © 2006 Weatherford. All rights reserved. Slide 28 Why Measure Flow Downhole Reduce surface facilities and well tests –Eliminates the need for test separator –Handling of high gas rates –Favorable measurement conditions Allocation from/to multiple zones –Production and Injection well applications –In multi-zone and multi-lateral completions Commingling –Regulatory requirements Faster identification of production anomalies

30. © 2006 Weatherford. All rights reserved. Slide 29 Weatherford’s Optical Flowmeter Measurements –Flow velocity (gives volumetric flow rate) –Speed of sound (gives gas volume fraction) Measurement Advantages –Liquid, gas, or multiphase –High accuracy: single-phase ±1% multiphase ±5% –Zero drift –Bi-directional flow rate –High turndown ratio, scalable to any pipe size Turndown Ratio is the ratio of the highest to the lowest measurable flow rate

31. © 2006 Weatherford. All rights reserved. Slide 30 Weatherford’s Clarion™ In-Well Seismic System High Performance –Broad bandwidth, high sensitivity and wide dynamic range Optical Seismic Sensors –3-component accelerometer –hydrophone (prototype only) Standard Weatherford optical backbone –Combines with optical PT, DTS & Flowmeter Dry tree solutions available –Subsea under development ALL OPTICAL SYSTEM LIFE OF FIELD RELIABILITY Life of Well Seismic™

32. © 2006 Weatherford. All rights reserved. Slide 31 RUGGEDIZED SENSOR CARRIER 3-C SENSOR Clarion™ Deployment in Production/Injection Wells ARRAY SPOOLING UNIT SENSOR MANDREL Tubing or casing conveyed

33. © 2006 Weatherford. All rights reserved. Slide 32 Weatherford’s Clarion™ In-Well Seismic System Geophysicists (benefit) Permanent Measurement Repeatability Real time on demand seismic data Passive event gathering Active Seismic event Gathering Calibration of Seabed Sensors Intended Wellbore viewing High resolution Imaging in 4D Timeline Geometry understanding Inversion – Porosity/ Resistivity Fluid Movement understanding Fracture Delineation Bypass Pay Cap Rock Integrity

34. © 2006 Weatherford. All rights reserved. Slide 33 Weatherford’s Clarion™ In-Well Seismic System Reservoir Engineers (Benefit) Available with P/T, Flow and DTS systems Material Balance help Formation Activity Fracture Tracing Cross Flow Well Balance when shut in Reservoir Loss path Reservoir Boundaries Injection performance Interference Test greater understanding Uncertainty reduction

35. © 2006 Weatherford. All rights reserved. Slide 34 Weatherford’s Clarion™ In-Well Seismic System Drilling Engineer (Benefit) Infill well placement Real time seismic while drilling Look ahead Drilling Production Engineer (Benefit) Stimulation

36. © 2006 Weatherford. All rights reserved. Slide 35 1990’sDTS installations 1993 First In-well Optical P/T Gauge 1996First Subsea Optical P/T Gauge 1999First In-well Bragg Grating P/T Gauge 1999First In-well Seismic Accelerometer 2000First Non-intrusive In-well Fiber Optic Flowmeter 2001Optical P/T Gauge and DTS in Single Completion 2002Multiple Optical P/T Gauges in Single Completion 2003Full 3-phase Fiber Optic Flowmeter with P/T Gauges 2003 Multi-zone Optical P/T Gauges and Remote Flow Control 2004Multi-zone Optical P/T Gauges and Flowmeters with Remote Flow Control 2004Casing-conveyed, Multi-station, Seismic with P/T Gauge 2005Multiple Optical P/T Gauges and DTS Integrated with Sand Control 2006Offshore Tubing-conveyed, Multi-station, Seismic with P/T Gauge In-Well Optical Sensing Chronology WORLD-FIRST DOWNHOLE FIBER OPTIC INSTALLATIONS: