Monitoring of downhole parameters and tools utilizing fiber optics

• US 20030205083A1
• Filed: 05/29/2003
• Published: 11/06/2003
• Est. Priority Date: 05/02/1997
• Status: Abandoned Application

• Current Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Original Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Inventors: Johnson, Michael, Harrell, John, Tubel, Paulo, Voll, Benn, Bidigare, Brian
• Application Number:
  US10/447,855
• Publication Number:
  US 20030205083A1
• Time in Patent Office: Days
• US Class Current: 73/152.19
• CPC Class Codes: E21B 33/1275 inflated by down-hole pumping means operated by a down-hole drive
• CPC Class Codes: E21B 37/06 using chemical means for preventing or limiting , e.g. eliminating, the deposition of paraffins or like substances
• CPC Class Codes: E21B 41/0035 Apparatus or methods for multilateral well technology, e.g. for the completion of or workover on wells with one or more lateral branches
• CPC Class Codes: E21B 41/02 in situ inhibition of corrosion in boreholes or wells
• CPC Class Codes: E21B 43/12 Methods or apparatus for controlling the flow of the obtained fluid to or in wells E21B43/25 takes precedence; valve arrangements E21B34/00
• CPC Class Codes: E21B 43/16 Enhanced recovery methods for obtaining hydrocarbons
• CPC Class Codes: E21B 43/20 Displacing by water
• CPC Class Codes: E21B 43/25 Methods for stimulating production by vibrating earth formations E21B43/003
• CPC Class Codes: E21B 43/26 by forming crevices or fractures
• CPC Class Codes: E21B 47/00 Survey of boreholes or wells monitoring pressure or flow of drilling fluid E21B21/08
• CPC Class Codes: E21B 47/017 Protecting measuring instruments
• CPC Class Codes: E21B 47/06 Measuring temperature or pressure
• CPC Class Codes: E21B 47/07 Temperature
• CPC Class Codes: E21B 47/107 using acoustic means
• CPC Class Codes: E21B 47/11 using tracers; using radioactivity
• CPC Class Codes: E21B 47/113 using electrical indications; using light radiations
• CPC Class Codes: E21B 47/135 using light waves, e.g. infrared or ultraviolet waves
• CPC Class Codes: E21B 49/00 Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
• CPC Class Codes: E21B 49/006 Measuring wall stresses in the borehole
• CPC Class Codes: E21B 49/008 by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor measuring pressure E21B47/06
• CPC Class Codes: E21B 49/08 : Obtaining fluid samples or testing fluids, in boreholes or wells
• CPC Class Codes: G01D 5/268 : using optical fibres G01D5/28 - G01D5/38 take precedence
• CPC Class Codes: G01N 21/31 : Investigating relative effect of material at wavelengths characteristic of specific elements or molecules, e.g. atomic absorption spectrometry G01N21/72 takes precedence
• CPC Class Codes: G01V 1/40 : specially adapted for well-logging
• CPC Class Codes: G01V 1/42 : using generators in one well and receivers elsewhere or vice versa G01V1/52 takes precedence
• CPC Class Codes: G01V 1/46 : Data acquisition
• CPC Class Codes: G01V 1/52 : Structural details
• CPC Class Codes: G01V 11/00 : Prospecting or detecting by methods combining techniques covered by two or more of main groups G01V1/00 - G01V9/00
• CPC Class Codes: G01V 11/002 : Details, e.g. power supply systems for logging instruments, transmitting or recording data, specially adapted for well logging, also if the prospecting method is irrelevant means for transmitting well survey signals E21B47/12; signal transmission systems in general G08C; transmission in general H04B
• CPC Class Codes: G01V 2210/6163 : Electromagnetic
• CPC Class Codes: G01V 2210/6167 : Nuclear
• CPC Class Codes: G01V 7/08 : using balances
• CPC Class Codes: G01V 7/16 : specially adapted for use on moving platforms, e.g. ship, aircraft
• CPC Class Codes: G01V 8/02 : Prospecting

Abstract

The present invention provides systems utilizing fiber optics for monitoring downhole parameters and the operation and conditions of downhole tools. In one system fiber optics sensors are placed in the wellbore to make distributed measurements for determining the fluid parameters including temperature, pressure, fluid flow, fluid constituents and chemical properties. Optical spectrometric sensors are employed for monitoring chemical properties in the wellbore and at the surface for chemical injection systems. Fiber optic sensors are utilized to determine formation properties including resistivity and acoustic properties compensated for temperature effects. Fiber optic sensors are used to monitor the operation and condition of downhole devices including electrical submersible pumps and flow control devices. In one embodiment, a common fluid line is used to monitor downhole parameters and to operate hydraulically-operated devices. Fiber optic sensors are also deployed to monitor the physical condition of power lines supplying high electric power to downhole equipment. A light cell disposed downhole is used to generate electric power in the wellbore, which is used to charge batteries.

Claims

1. A system for monitoring a downhole production fluid parameter, comprising:

(a) an optical spectrometer in a wellbore, said optical spectrometer making measurements for the production parameter in response to the supply of optical energy to the spectrometer; and

(b) a source of optical energy providing the optical energy to the optical spectrometer.

2. The tool of claim 1 wherein the spectrometer provides signals responsive to a downhole parameter which is one of (a) presence of gas in a fluid, (b) presence of water in a fluid, (c) amount of solids in fluid, (d) density of a fluid, (e) constituents of a downhole fluid, and (f) chemical composition of a fluid.

3. The system of claim 1 wherein the optical spectrometer is permanently deployed in the wellbore.

4. The system of claim 1 wherein the source of optical energy is located in the wellbore.

5. The system of claim 1 wherein the optical spectrometer is located in a drill string and makes the measurements during drilling of the wellbore.

6. The system of claim 1 further comprising a processor determining the downhole parameter utilizing the measurements from the optical spectrometer.

7. The system of claim 6 wherein the processor processes data at least in part downhole.

19. The system of claim 1 wherein the fiber optic sensor is one of (a) vibration sensor (b) strain sensor (c) chemical sensor (e) optical spectrometer sensor and (f) flow rate sensor, (g) temperature sensor, and (h) pressure sensor.

8. A system for determining an acoustic property of a subsurface formation, comprising:

(a) an acoustic fiber optic sensor in a wellbore providing measurements of an acoustic property of the formation surrounding the wellbore;

(b) a fiber optic temperature sensor in the wellbore for determining the temperature of the formation; and

(c) a processor determining from the acoustic sensor measurements the acoustic property of the formation that is compensated for temperature effects utilizing the temperature sensor measurements.

9. The system of claim 8 wherein the acoustic property is one of (a) acoustic velocity of the formation, and (b) travel time of an acoustic wavefront in the formation.

10. The system of claim 8 wherein the processor processes the measurements at least in part downhole.

11. The system of claim 8 wherein the acoustic sensor is one of (a) permanently installed in the wellbore and (b) carried by a measurement-while drilling tool taking said measurements during drilling of the wellbore.

12. A system for determining resistivity of a subsurface formation, comprising:

(a) a fiber optic sensor in a wellbore providing measurements for resistivity of the formation surrounding the wellbore; and

(b) a processor determining from the fiber optic sensor measurements the resistivity of the formation surrounding the wellbore.

13. The system of claim 12 wherein the fiber optic sensor is disposed in one of (a) on a measurement-while-drilling tool taking said measurements during drilling of the wellbore and (b) permanently installed in the wellbore.

14. The system of claim 12 wherein the processor processes the measurements at least in part downhole.

15. A system for determining a formation parameter of a subsurface formation, comprising:

(a) a fiber optic sensor in a wellbore providing measurements for determining a parameter selected from a group consisting of electric field, radiation and magnetic field; and

(b) a processor determining from the fiber optic sensor measurements the selected parameter.

16. The system of claim 15 wherein the fiber optic sensor is one of (a) permanently installed in the wellbore and (b) carried by a measurement-while drilling tool taking said measurements during drilling of the wellbore.

17. A downhole tool monitoring system, comprising:

(a) a tool in the wellbore; and

(b) a fiber optic sensor in a wellbore providing measurements for an operating parameter of the tool.

18. The system of claim 17 wherein the operating parameter is one of (a) vibration, (b) noise (c) strain (d) stress (e) displacement (f) flow rate (g) mechanical integrity (h) corrosion (i) erosion (j) scale (k) paraffin (1) hydrate, (m) displacement, (n) temperature, (o) pressure, (p) acceleration, and (q) stress.

20. The system of claim 17 wherein the downhole tool is one of a flow control device, packer, sliding sleeve, screen, mud motor, drill bit, bottom hole assembly, coiled tubing and casing.

21. A method of monitoring chemical injection into a surface treatment system of an oilfield well, comprising:

(a) injecting one or more chemicals into the treatment system for the treatment of fluids produced in the oilfield well; and

(b) sensing at least one chemical property of the fluid in the treatment system using at least one fiber optic chemical sensor associated with the treatment system.

22. The method of claim 21 wherein the fiber optic chemical sensor is one of (a) a probe that includes a sol gel and (b) an optical spectrometer that provides refracted light indicative of the chemical property of the fluid.

23. A measurement-while drilling (“

MWD”

) tool for use in drilling of a wellbore, comprising;

(a) at least one fiber optic sensor carried by the tool providing measurements responsive to one or more downhole parameters of interest during drilling of the wellbore;

(b) a light source in the tool providing light energy to the at least one fiber optic sensor for taking sid measurements; and

(c) a processor determining from said measurements the one or more parameters of interest at least in part downhole.

24. The tool of claim 23 wherein the at least one fiber optic sensor includes at least one of (a) a fluid flow rate sensor, (b) a vibration sensor, (d) a spectrometer, (e) sensor that determines a chemical property of the fluid, (f) a density measuring sensor, (g) resistivity measuring sensor, (h) a plurality of distributed pressure sensors, (i) a temperature sensor, (j) a pressure sensor, (k) a strain gauge, (1) a hydrophone, (m) a plurality of distributed pressure sensors, (n) a plurality of distributed temperature sensors, (o) an accelerometer, and (p) an acoustic sensor.

25. The tool of claim 23 wherein the one or more parameters of interest include at least one of (a) fluid flow rate, (b) flow of fluid through the tool, (c) vibration, (d) composition of wellbore fluid, (e) constituents of fluid in the wellbore, (f) constituents of the formation fluid, (g) water content in the formation fluid, (h) presence of gas in the formation fluid (i) fluid density (j) a physical condition of the tool (k) a formation evaluation property, (1) resistivity, (m) temperature gradient, and (n) pressure gradient.

26. The tool of claim 23 wherein the at least one fiber optic sensor includes a set of fiber optic sensors spaced along a fiber optic string.

27. The tool of claim 26 wherein at last some of the sensors are configured to provide measurements for more than one downhole parameters.

28. The tool of claim 23 wherein the at least one fiber optic sensor includes a set of sensors and the processor multiplexes between such sensors according to programmed instructions provided to the processor to obtain measurements of the desired parameters of interest.

29. The tool of claim 23 further comprising a mud motor, said mud motor having a rotor rotating in an elastomeric stator upon the supply of a fluid under pressure to the mud motor.

30. The tool of claim 29 wherein the at least one fiber optic sensor includes a plurality of fiber optic temperature sensors in the mud motor for measuring the temperature of the elastomeric stator, thereby providing an operating condition of the stator.

31. The tool of claim 30 wherein the processor provides signals for adjusting supply of the fluid under pressure to the mud motor so as to maintain the temperature of the stator at a desired value.

32. A method of monitoring and controlling an injection operation, comprising:

(a) locating in a production well a plurality of distributed fiber optic sensors;

(b) injecting a fluid in an injection well formed spaced apart from the production wellbore;

(b) determining from the fiber optic sensor measurements a parameter of the formation between the production well and the injection well; and

(c) controlling the injection of the fluid in response to the determined parameter.

33. A downhole injection evaluation system comprising:

(a) at least one sensor permanently disposed in an injection well for sensing at least one parameter associated with injecting of a fluid into a formation.

34. A downhole injection evaluation system as claimed in claim 33 wherein said system further includes an electronic controller operably connected to said at least one downhole sensor.

35. A downhole injection evaluation system as claimed in claim 34 wherein said at least one downhole sensor is operably connected to at least one production well sensor to provide said electronic controller, operably connected to said at least one downhole sensor and to said at least one production well sensor, with information from both sides of a fluid front moving between said injection well and said production well.

36. A system for optimizing hydrocarbon production comprising:

(a) a production well;

(b) an injection well, said production well and said injection well being data transmittably connected; and

(c) at least one sensor located in either of said injection well and said production well, said at least one sensor being capable of sensing at least one parameter associated with an injection operation, said sensor being operably connected to a controller for controlling injection in the injection well.

37. A method for avoiding injection induced unintentional fracture growth comprising:

(a) providing at least one acoustic sensor in an injection well;

(b) monitoring said at least one sensor; and

(c) varying pressure of a fluid being injected to avoid a predetermined threshold level of acoustic activity received by said at least one sensor.

38. A method for enhancing hydrocarbon production wherein at least one injection well and an associated production well include at least one sensor and at least one flow controller comprising providing a system capable of monitoring said at least one sensor in each of said wells and controlling said at least one flow controller in each of said wells in response thereto to optimize hydrocarbon production.

39. A method of making measurements in a wellbore, comprising:

(a) locating at least one fiber-optic sensor in the wellbore, said sensor providing measurements responsive to one or more downhole parameters;

(b) locating a light source in the wellbore, said light source providing light energy to the at least one fiber optic sensor for making the measurements; and

(c) processing the fiber optic sensor measurements and computing therefrom the one or more downhole parameters.

40. The method according to claim 39, wherein the downhole parameters include at least one of (a) fluid flow rate, (b) flow of fluid through the tool, (c) vibration, (d) composition of wellbore fluid, (e) constituents of fluid in the wellbore, (f) constituents of the formation fluid, (g) water content in the formation fluid, (h) presence of gas in the formation fluid (i) fluid density (i) a physical condition of the tool (k) a formation evaluation property, (1) resistivity, (m) temperature gradient, (n) pressure gradient, and (o) seismic response of induced acoustic energy.

41. A method of avoiding drilling into preexisting wellbore, comprising:

drilling a wellbore with a drilling assembly carrying a drill bit wherein the drill bit induces acoustic energy into subsurface formations;

providing at least one fiber optic acoustic sensor in the preexisting wellbore for detecting acoustic energy generated by the drill bit;

determining from the detected signals location of the drill bit relative to the preexisting wellbore; and

drilling the wellbore a desired distance from the preexisting wellbore thereby avoiding drilling the wellbore into the preexisting wellbore.