Wellbores utilizing fiber optic-based sensors and operating devices

• US 7,040,390 B2
• Filed: 09/29/2003
• Issued: 05/09/2006
• 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 H., Tubel, Paulo S., Lembcke, Jeffrey J., Hickey, Kurt A., Harrell, John W.
• Primary Examiner(s): TSAY, FRANK
• Application Number:
  US10/674,248
• Publication Number:
  US 20040065439A1
• Time in Patent Office: 953 Days
• Field of Search: 166/250.01, 166/252.1, 166/266, 166/305.1, 166/64, 166/66, 166/113, 250/227.14, 250/256, 250/254.2, 359/143
• US Class Current: 166/64
• 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 43/25 Methods for stimulating production by vibrating earth formations E21B43/003
• 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 47/114 using light radiation
• 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 49/08 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 1/226 Optoseismic systems
• CPC Class Codes: G01V 1/52 : Structural details
• 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

Abstract

This invention provides a method for controlling production operations using fiber optic devices. An optical fiber carrying fiber-optic sensors is deployed downhole to provide information about downhole conditions. Parameters related to the chemicals being used for surface treatments are measured in real time and on-line, and these measured parameters are used to control the dosage of chemicals into the surface treatment system. The information is also used to control downhole devices that may be a packer, choke, sliding sleeve, perforating device, flow control valve, completion device, an anchor or any other device. Provision is also made for control of secondary recovery operations online using the downhole sensors to monitor the reservoir conditions. The present invention also provides a method of generating motive power in a wellbore utilizing optical energy. This can be done directly or indirectly, e.g., by first producing electrical energy that is then converted to another form of energy.

Claims

1. A downhole injection evaluation system comprising:

(a) at least one downhole fiber optic sensor permanently disposed a first well for sensing at least one parameter associated with injecting a fluid into a formation;

(b) at least one additional downhole fiber optic sensor in a second well, the at least one additional sensor operably connected to the at least one fiber optic sensor in the first well;

wherein said first well is one of (I) an injection well, and (II) a production well and the second well is the other of (I) an injection well, and (II) a production well.

2. A downhole injection evaluation system as claimed in claim 1 wherein said system further includes an electronic controller operably connected to at least one of the downhole fiber optic sensors.

3. The system of claim 2 wherein said electronic controller is at one of (i) a surface location, and (ii) a downhole location.

4. A downhole injection evaluation system as claimed in claim 1 wherein said system further includes at least one downhole acoustic signal generator whereby signals generated by said at least one signal generator reflect off a flood fluid/hydrocarbon interface and are received by at least one of the downhole sensors.

5. The system of claim 4 further comprising an acoustic receiver in at least one of the first well and the second well.

6. The system of claim 5 wherein said acoustic receiver receives acoustic signals indicative of at least one of (i) a location of fluid front between the first well and the second well, and (ii) a fracture between the first well and the second well.

7. The system of claim 6 wherein said signals are produced by a change in a fracture in the earth formation.

8. The system of claim 1 wherein said sensor in said first well is operably connected to said sensor in said second well by a fiber optic link.

9. The system of claim 1 further comprising a controller which controls a flow control device in at least one of the first well and the second well.

10. The system of claim 9 wherein said flow control device is selected from the group consisting of:

(i) a valve, (ii) fluid control device, (iii) packer, (iv) sliding sleeve, (v) safety valve, (vi) an anchor, and (vii) a pump.

11. A system for controlling hydrocarbon production comprising:

a) a production well;

b) an injection well having a data link to said production well;

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.

12. A method of producing hydrocarbons from a subterranean reservoir comprising:

a) permanently installing at least one downhole fiber optic sensor in a first well;

(b) operably connecting at least one fiber optic sensor in a second well to the at least one fiber optice sensor in the first well;

wherein the first well is one of (I) an injection well, and (II) a production well and the second well is the other of (I) an injection well, and (II) a production well.

13. The method of claim 12 further comprising using an electronic controller operably connected to at least one of the downhole fiber optic sensors.

14. The method of claim 13 further comprising positioning said electronic controller at one of (i) a surface location, and (ii) a downhole location.

15. The method of claim 13 further comprising operably connecting said at least one sensor in said first well to said at least one sensor in said second well by a fiber optic link.

16. The method of claim 12 further comprising

(i) using at least one downhole acoustic signal generator for generating signals that interact with a flood front in said reservoir, and

(ii) receiving signals resulting from said interaction with at least one of the downhole sensors.

17. The method of claim 12 further comprising using a controller for controlling a flow control device in at least one of the first well and the second well.

18. The method of claim 17 wherein said flow control device is selected from the group consisting of:

(i) a valve, (ii) fluid control device, (iii) packer, (iv) sliding sleeve, (v) safety valve, (vi) an anchor, and (vii) a pump.

19. The method of claim 12 further comprising using an acoustic receiver in at least one of the first well and the second well for receiving acoustic signals.

20. The method of claim 19 further comprising using said acoustic receiver for receiving acoustic signals indicative of at least one of (i) a location of a fluid front between the first well and the second well, and (ii) a fracture between the first well and the second well.

21. The method of claim 20 wherein said signals are produced by a change in said fracture.

22. The method of claim 12 further comprising using an acoustic transmitter in at least one of the first well and the second well for sending acoustic signals into said reservoir.

23. The method of claim 22 further comprising using said acoustic receiver for receiving acoustic signals indicative of a location of fluid front between the first well and the second well.

24. The method of claim 22 further comprising using said acoustic receiver for receiving acoustic signals indicative of a location of a fracture between the first well and the second well.

25. The method of claim 12 further comprising:

(i) using an acoustic transmitter in one of said two wells for propagating acoustic signals into said reservoir, and

(ii) using an acoustic receiver in the other of said two wells for receiving said signals after passing through said reservoir.

26. The method of claim 25 further comprising using a controller for processing said signals and determining from said received signals an indication of pressure transmissivity of said reservoir.

27. The method of claim 25 further comprising:

(A) using a controller for processing said received signals,

(B) using a controller for controlling the operation of a fluid control device in at least one of the first well and the second well.

28. A downhole injection evaluation system comprising:

a) at least one downhole fiber optic sensor permanently disposed a first well for sensing at least one parameter associated with injecting a fluid into a formation; and

(b) at least one downhole acoustic signal generator whereby signals generated by said at least one signal generator interact with at least one of (I) a fluid front, and (II) a fracture and are received by said at least one downhole sensor.

wherein said first well is selected from (III) an injection well, and (IV) a production well.