Wellbores utilizing fiber optic-based sensors and operating devices

• US 7,201,221 B2
• Filed: 05/09/2006
• Issued: 04/10/2007
• Est. Priority Date: 05/02/1997
• Status: Expired due to Fees

• Current Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Original Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Inventors: Tubel, Paulo S., Johnson, Michael H., Lembcke, Jeffrey J., Hickey, Kurt A., Harrell, John W.
• Primary Examiner(s): Tsay; Frank
• Application Number:
  US11/430,729
• Publication Number:
  US 20060272809A1
• Time in Patent Office: 336 Days
• Field of Search: 166/64, 166/250.01, 166/254.2, 250/227.14
• 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 method for performing secondary recovery operations in an earth formation, the method comprising:

a) injecting a fluid in an injection well;

b) monitoring sound levels received by at least one acoustic sensor in the earth formation;

c) varying pressure of a fluid being injected in the injection well based at least in part on the sound level received by said at least one sensor.

2. The method of claim 1 wherein varying the pressure further comprises avoiding a predetermined level of the sound received by the at least one acoustic sensor.

3. The method of claim 1 further comprising positioning the at least one sensor in at least one of (i) the injection well, and (ii) a production well.

4. The method of claim 1 further comprising using a fiber optic sensor as the at least one acoustic sensor.

5. The method of claim 1 wherein varying the pressure of the fluid being injected further comprises using a flow control device in the injection well.

6. A method of performing secondary recovery operations, the method comprising:

(a) injecting fluid in an injection well;

(b) providing at least one acoustic signal generator and at least one acoustic sensor in the injection well;

(c) receiving a signal in the at least one acoustic sensor in response to at least one of;

(A) activation of the at least one signal generator, and (ii) injection of the fluid; and

(d) using the signal for controlling injection of the fluid.

7. The method of claim 6 wherein the signal comprises a reflected signal resulting from activation of the at least one signal generator, and wherein controlling the injection further uses a property of a fault in the earth formation determined from the signal.

8. The method of claim 6 wherein the signal comprises a reflected signal resulting from activation of the at least one signal generator, and wherein controlling the injection further uses a position of a fluid front in the earth formation determined from the signal.

9. The method of claim 6 further comprising using a fiber optic sensor as the at least one acoustic sensor.

10. The method of claim 6 wherein the signal results from a fracture in the earth formation resulting from the injection of the fluid.

11. The method of claim 6 further comprising:

(i) providing at least one acoustic signal generator and at least one acoustic sensor in a production well,

(ii) receiving an additional signal resulting in one of (I) the production well, and (II) the injection well resulting from activation of a signal generator in the other of (I) the production well, and (II) the injection well;

(iii) using the additional signal to estimate at least one of (III) a pressure transmittivity, (IV) a fault location, and (V) a fluid front between the injection well and the production well.