Monitoring of downhole parameters and tools utilizing fiber optics

• US 6,588,266 B2
• Filed: 06/01/2001
• Issued: 07/08/2003
• Est. Priority Date: 05/02/1997
• Status: Expired due to Term

• Current Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Original Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Inventors: Johnson, Michael, Harrell, John, Tubel, Paulo, Bidigare, Brian, Voll, Benn
• Primary Examiner(s): Kwok, Helen
• Assistant Examiner(s): Politzer, Jay L
• Application Number:
  US09/872,591
• Publication Number:
  US 20010023614A1
• Time in Patent Office: 767 Days
• Field of Search: 731/520.1, 731/523.9, 731/524.3, 731/525.4, 166/250.01, 166/250.05, 166/53, 166/310, 250/254, 250/255, 250/256, 250/339.12, 356/301, 356/303, 356/326, 385/436, 385/12, 385/123
• US Class Current: 73/152.39
• 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 method of monitoring chemical injections into a treatment system of an oilfield well, comprising:

(a) injecting one or more chemicals into the treatment system for treatment of a fluid 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.

2. The method of claim 1 wherein the at least one 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.

3. The method of claim 1 wherein said one or more chemicals are injected into an annulus between a production tubing and a casing of said well.

4. The method of claim 1 wherein the at least one chemical property is selected from the group consisting of (i) potential ionic content, (ii) covalent content, (iii) pH level, (iv) oxygen level, (v) organic precipitate level, and (vi) H₂S content.

5. The method of claim 1 further comprising measuring at least one physical property of the fluid, said at least one physical property selected from the group consisting of (i) oil/water cut, (ii) viscosity, (ii) percent solids, (iv) paraffin build-up, and (v) scale build-up.

6. The method of claim 1 further comprising monitoring the produced fluid for parameters related to the content and amount of at least one of (i) hydrogen sulfide, (ii) hydrates, (iii) paraffins, (iv) water, (v) solids, and (v) gas.

7. The method of claim 3 further comprising using distributed sensors along the production tubing for monitoring chemical content of the fluid as it travels up the production tubing.

8. The method of claim 1 further comprising using a determined value of the at least one chemical property for controlling the injection of said at least one or more chemicals.

9. The method of claim 1 wherein said at least one or more chemicals are selected from the group consisting of:

(i) corrosion inhibitors, (ii) de-emulsifier, and (iii) dewaxer.

10. The method of claim 1 wherein said at least one or more chemicals are corrosion inhibitors selected from the group consisting of (i) long chain amines, and, (ii) aminodiazolines.

11. The method of claim 1 wherein an injection location for said one or more chemicals is upstream of a location of said at least one fiber optic sensor.

12. The method of claim 1 further comprising using at least one additional sensor selected from the group consisting of (i) flow rate sensors, (ii) temperature sensors, and, (iii) pressure sensors for monitoring fluid in the well.

13. The method of claim 12 wherein said at least one additional sensor is a fiber optic sensor.

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

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

(b) sensing at least one chemical property of the fluid using at least one fiber optic chemical sensor permanently installed in the well.

15. The method of claim 14 wherein said one or more chemicals are injected into an annulus between a production tubing and a casing of said well.

16. The method of claim 14 wherein the at least one chemical property is selected from the group consisting of (i) potential ionic content, (ii) convalent content, (iii) pH level, (iv) oxygen level, (v) organic precipitate level, and (vi) H₂S content.

17. The method of claim 14 further comprising using a determined value of the at least one chemical property for controlling the injection of said at least one or more chemicals.

18. The method of claim 14 further comprising using at least one additional sensor selected from the group consisting of (i) flow rate sensors, (ii) temperature sensors, and, (iii) pressure sensors for monitoring fluid in the well.

19. A method of monitoring chemical injection into a surface treatment system of an oilfield well having a casing, the method comprising:

(a) injecting one or more chemicals into the treatment system for the treatment of a fluid inside the casing and 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.

20. The method of claim 19 wherein the at least one 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.

21. The method of claim 19 wherein said one or more chemicals are injected into an annulus between a production tubing and a casing of said well.

22. The method of claim 19 wherein the at least one chemical property is selected from the group consisting of (i) potential ionic content, (ii) convalent content, (ii) pH level, (iv) oxygen level, (v) organic precipitate level, and (vi) H₂S content.

23. The method of claim 19 further comprising measuring at least one physical property of the fluid in the treatment system, said at least one physical property selected from the group consisting of (i) oil/water cut, (ii) viscosity, (iii) percent solids, (iv) paraffin build-up, and (v) scale build-up.

24. The method of claim 19 further comprising monitoring the produced fluid for parameters related to the content and amount of at least one of (i) hydrogen sulfide, (ii) hydrates, (ii) paraffins, (iv) water, (v) solid, and (v) gas.

25. The method of claim 21 further comprising using distributed sensors along the production tubing for monitoring chemical content of the produced fluid as it travels up the production tubing.

26. The method of claim 19 further comprising using a determined value of the at least one chemical property for controlling the injection of said at least one or more chemicals.

27. The method of claim 19 wherein said at least one or more chemicals are selected from the group consisting (i) corrosion inhibitors, (ii) de-emulsifier, and (iii) dewaxer.

28. The method of claim 19 wherein said at least one or more chemicals are corrosion inhibitors selected from the group consisting of (i) long chain amines, and, (ii) aminodiazlines.

29. The method of claim 19 wherein an injection location for said one or more chemicals is upstream of a location of said at least one fiber optic sensor.

30. The method of claim 19 further comprising using at least one additional sensor selected from the group consisting of (i) flow rate sensors, (ii) temperature sensors, and, (iii) pressure sensors for monitoring fluid in the well.

31. The method of claim 30 wherein said at least one additional sensor is a fiber optic sensor.

32. The method of claim 19 wherein said fluid inside the casing consists substantially of a liquid.