GB2403292A - System and method for making fiber optic measurements in a wellbore using a downhole opto-electronic uint - Google Patents

Abstract

The invention is a system and method for making a fiber optic measurement in a wellbore, comprising a opto-electronic unit adapted to provide an optical signal into a fiber optic sensor and to receive a return signal from the fiber optic sensor; the fiber optic sensor adapted to measure a parameter of interest and the return signal including information related to the parameter of interest; a surface acquisition unit in communication with the opto-electronic unit via an electrical cable; the opto-electronic unit adapted to convert the return optical signal into an electrical signal; and the electrical signal being transmitted through the electrical cable to the surface acquisition unit. An additional downhole sensor may be utilized to provide a reference measurement point. In another embodiment, the surface acquisition unit is in communication with the opto-electronic unit via wireless telemetry. In one embodiment, the opto-electronic unit is retrievable to enable repair or replacement.

Description

SYSTEM AND METHOD FOR MAKING FIBER OPTIC MEASUREMENTS IN A

WELLBORE USING A DOWNHOLE OPTO-ELECTRONIC UNIT

BACKGROUND

This invention generally relates to a system and method for making fiber optic measurements in a wellbore. More particularly, the invention relates to such a system in which the optical losses are minimized so as to enable adequate transmission of the measurement over long lengths.

One of the main concerns with fiber optic measurement systems are the optical losses incurred when the optical signal is transmitted over long distances or through splices and dry and wet connectors. The resolution of the measurement depends on the total light losses in the fiber and the various splices and connectors. Although this concern is present when the fiber optic measurement system is deployed in all wellbores (including land wellbores), it is specially problematic when the fiber optic measurement system is deployed in a subsea wellbore. This is because the distance that the optical signal needs to travel to provide a measurement in subsea wellbores tends to be longer than in land wellbores, and subsea wellbores tend to include a greater number of connectors and splices with high losses.

In the prior art and when used in subsea wellbores, a fiber optic light box is typically placed at the seabed for reducing the length of the fiber optic cable and light losses from downhole to the data gathering station on a surface production facility. The light box is used for transmitting light and converting returned light signal to electrical signal. The optical signal is transmitted and reflected through fiber optic cable from downhole to the light box and is then converted to an electrical signal and transmitted to data gathering station on production facility.

However, in the prior art, the number of optical connectors used between the light box at the seabed and the downhole optic sensor may still provide an unacceptable optical loss. For instance, fiber optic wet connects may be required at the production tree, tubing hanger, and down hole between the upper and lower completions. Also, several dry connects or fused connections are required for the completion installation. The optical losses through these connectors and through the length of the fiber optic cable add up and impact the resolution of the measurement.

Thus, there exists a continuing need for an arrangement and/or technique that addresses one or more of the problems that are stated above.

SUMMARY

The invention is a system and method for making a fiber optic measurement in a wellbore, comprising a downhole opto-electronic unit adapted to provide an optical signal into a fiber optic sensor and to receive a return signal from the fiber optic sensor; the fiber optic sensor adapted to measure a parameter of interest and the return signal including information related to the parameter of interest; a surface acquisition unit in communication with the opto-electronic unit via an electrical cable; the opto-electronic unit adapted to convert the return optical signal into an electrical signal; and the electrical signal being transmitted through the electrical cable to the surface acquisition unit. In another embodiment, the surface acquisition unit is in communication with the opto-electronic unit via wireless telemetry. In one embodiment, the opto-electronic unit is retrievable from the downhole environment to enable repair or replacement.

BRIEF DESCRIPTION OF THE DRAWING

Fig. I is a schematic of a subsea wellbore including one embodiment of the fiber optic measurement system.

Fig. 2 is a top cross-sectional view of one embodiment of the optoelectronic unit.

Fig. 3 is a longitudinal view of another embodiment of the optoelectronic unit.

Fig. 4 is a schematic of a subsea wellbore including the fiber optic measurement system with a double-ended optical fiber configuration.

Figs. 5- 10 are schematics of a wellbore including other embodiments of the fiber optic measuring system.

DETAILED DESCRIPTION

Figure I shows the system 10 of the present invention. A tubing 12, such as a production or coiled tubing, is deployed within a wellbore 14. The wellbore 14 may be a land or, as shown in Figure 1, a subsea wellbore. A fiber optic measurement system 16 is used to obtain measurements of a parameter of interest from the wellbore 14. The parameter of interest may be pressure, temperature, distributed pressure, distributed temperature, strain, flow, or chemical properties, among others. The wellbore 14 intersects at least one formation 26. Depending on whether the wellbore 14 is a producing or injecting well, fluids are either produced from the formation 26 and up the tubing 12 or fluids are injected from the tubing 12 into the formation 26.

The fiber optic measurement system 16 comprises an opto-electronic unit 18, an optical fiber 20, and a surface acquisition unit 22. In this invention, the opto-electronic unit 18 is located downhole and is functionally connected to the surface acquisition unit 22 by way of an electrical cable 24. The opto-electronic unit 18 can include a light source for transmitting optical signals (such as pulses) into the optical fiber 2O, a receptor for receiving return optical signals from the optical fiber 20, and a converter for converting the return optical signals into electrical signals or other types of signals (such as for wireless telemetry as will be explained herein). In one embodiment, the electrical cable 24 provides power to the opto-electronic unit 18. In another embodiment, at least one battery (not shown) provides power to the opto-electronic unit 18.

The optical fiber 20 may be housed within a control conduit, which control conduit protects the optical fiber 20 from the downhole environment and also enables the deployment of the optical fiber 20 therein by way of fluid drag. The fluid drag deployment method is described US Reissue Patent 37,283, which is incorporated herein by reference.

Electrical cable 24 can also transmit signals between the surface acquisition unit 22 and the downhole opto-electronic unit 18 (in both directions). An activation signal is transmitted from the surface acquisition unit 18 through the electrical cable 24 to the optoelectronic unit 18.

Upon reception of the activation signal, the opto-electronic unit 18 provides a light signal to the optical fiber 20. In one embodiment, the optical fiber 20 serves as a sensor itself (such as in the optical time domain reflectometry- OTDR - technique used to detect Raman scattering to measure the temperature profile along the fiber as described in U.S. Pat. Nos. 4,823,166 and 5,592,282 issued to Hartog, both of which are incorporated herein by reference). In another embodiment, the optical fiber 20 includes at least one optical sensor therein (such as when fiber Brag gratings are written onto the fiber and serve as sensors to measure a downhole parameter).

In another embodiment, the optical fiber 20 is functionally attached to at least one optical sensor (such as when the fiber is attached to an extrinsic sensor and the fiber is used only as a means of tranmission). In any case, a return optical signal is transmitted back through the optical fiber 20 to the opto- electronic unit 18, with such return optical signal including information relating to the parameter of interest. The return optical signal is converted into an electrical signal at the opto-electronic unit 18. The electrical signal is then transmitted through the electrical cable 24 to the surface acquisition unit 22.

For purposes of completeness, OTDR will now be described, although it is understood that OTDR is not the only way (and this patent is therefore not limited to OTDR) to obtain a distributed temperature measurement. In OTDR, a pulse of optical energy is launched into an optical fiber and the backscattered optical energy returning from the fiber is observed as a function of time, which is proportional to distance along the fiber from which the backscattered light is received. This backscattered light includes the Rayleigh, Brillouin, and Raman spectrums. The Raman spectrum is the most temperature sensitive with the intensity of the spectrum varying with temperature, although Brillouin scattering and in certain cases Rayleigh scattering are temperature sensitive. Generally, in one embodiment, pulses of light at a fixed wavelength are transmitted from a light source down the fiber optic line. Light is back-scattered along the length of the optical fibre and returns to the instrument. Knowing the speed of light and the moment of arrival of the return signal enables its point of origin along the fiber line to be determined. Temperature stimulates the energy levels of molecules of the silica and of other index-modifying additives - such as germania - present in the fiber line. The back-scattered light contains upshifted and downshifted wavebands (such as the Stokes Raman and Anti-Stokes Raman portions of the backscattered spectrum) which can be analyzed to determine the temperature at origin. In this way the temperature along the fiber line can be calculated by the instrument, providing a complete temperature profile along the length of the fiber line.

One of the objectives of this invention is to minimize the length of the optical fiber 20 in order to minimize the optical losses associated with transmitting optical signals over long lengths. Moreover, when deploying an optical fiber in a wellbore, it is often times necessary to pass the optical fiber through completion or wellbore hardware, such as packers, tubing hangers, and production trees. Typically, a fiber optic connector is used at the hardware to transmit the optical signal across the hardware. However, fiber optic connectors are still unproven products and in any respect provide a certain amount of optical loss that can become unacceptably high if many optical connectors are used (such as in a subsea well). To achieve these objectives and minimize these concerns, the opto-electronic unit 18 of this invention is placed as close as possible to the area that will be subject to the fiber optic measurement (in Figure 1, the area is across the formation 26). This is a shorter length than in prior art systems, which include the optical fiber from the surface to the measurement area. Moreover, in the present invention, the return optical signal is transmitted to the surface acquisition unit 22 via an electrical cable 24 (as opposed to another optical cable). Although electrical connectors must also be used to pass the 1 S relevant electrical signal through the relevant hardware, such electrical connectors are proven products that do not have the degree of loss present in still unproven optical connectors.

Each of the electrical connectors may be an electrical wet connect or a dry connect; each type of connector being existing field proven technology. Instead of the electrical connectors, it is also possible to run inductive couplers, a technology that is also field proven.

Figure 1 shows one possible placement of the system 10 in a subsea well 14. The opto electronic unit 18 is placed between the completion packer 30 and the gravel packer 32. In another embodiment the downhole optoelectronic unit 18 can be placed below the gravel pack packer. In another embodiment the downhole source can be run below or above the expandable screen hanger packer. In another embodiment the downhole source can be run below or above the stand-alone screen hanger packer. The opto- electronic unit 18 can be run anywhere in lower completion or upper completion. The optical fiber 20 extends from the opto-electronic unit 18, through a feedthrough 34 in the gravel packer 32 to the region of interest - in this case the area across formation 26. The electrical cable 24 extends from the opto-electronic unit 18, through the completion packer 30 by way of a feedthrough 34 and to the surface acquisition unit 22.

Depending on the equipment and hardware that is part of the completion and is appended to the tubing 12, the electrical cable 24 may have to pass through additional electrical connectors, such as the wellhead electrical connector 38 shown in Figure 1. The signal from the surface acquisition unit 22 is then transmitted to a production facility (not shown) via additional electrical conduits 44.

The surface acquisition unit 22 may be located at the ocean floor 40 (as shown in Figure 1). In another embodiment, the surface acquisition unit 22 is located on a platform (not shown) on the ocean surface 42, in which case the signal passing through the electrical cable 24 would be transmitted to the platform and through the ocean via additional electrical conduits. In still another embodiment, the surface acquisition unit 22 is located at the land-based production facility (not shown) and the signal passing through the electrical cable 24 is transmitted to the production facility via additional electrical conduits such as those at 44.

In one embodiment, the opto-electronic unit 18 is designed to perform a minimum amount of data processing downhole. In this case, the optoelectronic unit 18 preferably only converts the return optical signal into a corresponding electrical signal. The electrical signal is then analyzed at the surface acquisition unit 22, which as previously disclosed may be located at the ocean floor 40, on a platform on the ocean surface 42, or at the land-based production facility. Thus, the power provided to the opto-electronic unit 18 through the electrical cable 24 or by a battery is necessary only to power the emission of light signals into the optical fiber 20, the conversion of the return optical signal to the electrical signal carrying the necessary parameter information, and the transmission of the electrical signal through the electrical cable 24 back to the surface acquisition unit 22.

In one embodiment as shown in the Figures, the opto-electronic unit 18 is annular in shape in order to enable full tubing 12 diameter flow therethrough. Figure 2 shows the opto electronic unit 18 attached to the exterior of the tubing 12. In another embodiment as shown in Figure 3, the opto-electronic unit 18 is connected at either end to a section of tubing 12 and is therefore an extension of the tubing 12 with fluid flowing directly therethrough. In another embodiment the opto-electronic unit 18 is packaged in a cylinder that is run in the middle of the tubing and a flow shroud is run outside the opto-electronic unit 18 for providing an annular flow path between the exterior of the opto- electronic unit 18 and the interior of the flow shroud.

The electrical cable 24 can comprise cables as known in the art, such as the cable that is run to collect information from pressure gauges. For instance, a WellNet station telemetry and twisted pair electrical cable can be used for communicating data between the opto-electronic unit 18 and the surface acquisition unit 22.

More then one electrical cable 24, fiber optic sensor 20 and downhole surce unit 18 can be run for redundancy.

In one embodiment as shown in Figure 4, the optical fiber 20 has a Ushape (see 20C) so that it has two connections 20A, 20B to the optoelectronic unit 18. This type of configuration is particularly useful when the optical fiber 20 is used to measure a temperature profile along its length, such as by way of OTDR as previously described. As previously disclosed, the optical fiber 20 can be housed in a control conduit, which also has the U-shape in this embodiment. The use of this U-shape or double-ended configuration improves the resolution of the measurements.

This configuration includes two feedthroughs 33 through gravel packer 32. In this configuration, an additional electrical cable (not shown) can also be used to transmit data to the surface acquisition unit 22.

Figure 5 illustrates another embodiment of this invention. A completion 100 is deployed in a wellbore 102 that may be cased 104. Opto-electronic unit 18 is deployed in the wellbore 102 as part of the completion 100. Optical fiber 20 extends from the opto- electronic unit 18 therebelow and provides the measurement as previously indicated. An electrical cable 24 extends from the opto-electronic unit 18 to the surface acquisition unit 22 (not shown) and transmits the relevant signals, also as previously indicated.

Opto-electronic unit 18 may be located directly above the gravel packer 32, with the optical fiber 20 extending through the gravel packer 32 by way of feedthrough 34. Electrical cable 24 extends from the optoelectronic unit 18 and through the completion packer 30 by way of feedthrough 36. The electrical cable 24 may be spliced at several points along its length, such as for ease of deployment below the completion packer 30. The optical fiber 20 extends across the formation 26, which may include perforations 28. Gravel pack 110 may be located between the gravel packer 32 and the bottom packer 112 surrounding the optical fiber 20.

Completion 100 may include conveyance tubing 114 (which may comprise coiled tubing or production tubing, among others), with at least one safety valve 116 and at least one pressure and temperature gauge 118 connected thereto. Below the completion packer 30, the completion may comprise a tubing isolation and auto fill valve 120 and a space out joint 122. Space out joint 122 enables the expansion and contraction of the completion 100 including the electrical cable 24 which is deployed in a coil 124 around the joint 122 to enable such contraction and expansion. A formation isolation valve 126 may also be deployed above the gravel pack screen 116.

Completion 100 may be divided into a lower completion 106 and an upper completion 108. The lower completion 106 may comprise the gravel pack assembly, including the bottom packer 112, gravel packer screen 116, formation isolation valve 126, gravel pack packer 32, optical fiber 20, and opto- electronic unit 18. The upper completion 108 may comprise the joint 122, the tubing isolation and auto fill valve 120, the completion packer 30, and the other components thereabove.

In one embodiment, the lower completion 106 is deployed prior to the deployment of the upper completion 108. Once the lower completion 106 is properly deployed (as is known in the art), the upper completion 106 is latched into the upper completion 108 by way of snap latch assembly 128. Thereafter, the completion packer 30 is set. In this embodiment, completion 100 also includes an electrical wet connector 130 to electrically connect the electrical cable 24 and the opto-electronic unit 18 as the upper completion 108 latches into the lower completion 106.

Electrical connection enables the functionality of the sensor, as previously disclosed.

In another embodiment as shown in Figures 6-8, the opto-electronic unit 18 is retrievable from the wellbore 14. The retrievability of the optoelectronic unit 18 enables the source unit to be replaced upon failure or regular maintenance without also having to retrieve the electrical cable 24 or remainder of the completion 100, which may be costly. Depending on the embodiment, the optical fiber 20 may be retrieved to the surface in conjunction with the downhole opto-electronic unit 18. In the embodiments of Figures 6-8, full bore flow and access can be achieved when the optoelectronic unit 18 is retrieved. The opto-electronic unit 18 may be retrieved in one embodiment by way of tubing, wireline, slickline, or coiled tubing mechanisms including relevant latches.

Referring generally to Figure 6, a completion 200 comprises a lower completion 202, an upper completion 204 and a stinger or a dip tube 206 with opto-electronic unit 18 connected thereto. Lower completion 202 may comprise a variety of components. For example, the lower completion 202 may compose a packer 208 and a formation isolation valve 210. Other embodiments may also include a screen, such as a base pipe screen. Formation isolation valve 210 may be selectively closed and opened by pressure pulses, electrical control signals or other types of control inputs. By way of example, valve 210 may be selectively closed to set packer 208 via pressurization of the system. In some applications, formation isolation valve 210 may be designed to close automatically after gravel packing. However, the valve 210 is subsequently opened to enable the insertion of dip tube 206.

In the embodiment illustrated, upper completion 204 may includes a side pocket sub 214, which may comprise an electrical connection feature 216, such as an electrical wet connect. Side pocket sub 214 may be mounted on tubing 218 and is adapted to mechanically and selectively latch to the dip tube 206 (as disclosed below). The lower completion 202 and upper completion 204 may be designed with a gap (not shown) therebetween such that there is no fixed point connection. By utilizing gap between the lower and upper completions, a "space out" trip into the well to measure tubing 218 is not necessary. As a result, the time and cost of the operation is substantially reduced by eliminating the extra out trip down hole.

Upon placement of lower completion 202 and upper completion 204, dip tube 206 is run through tubing 218 on, for example, coiled tubing or a wireline. Dip tube 206 comprises a corresponding connection feature 222, such as an electrical wet connect mandrel 224 that engages electrical connection feature 216.

In the embodiment illustrated, engagement of connection feature 216 and corresponding connection feature 222 forms an electrical wet connect by which the electrical cable 24 becomes functionally connected to the optoelectronic unit 18, providing a functional connection to the optical fiber 20 as previously disclosed. The dip tube 206 also becomes mechanically attached or locked in the side pocket sub 214.

The dip tube 206, opto-electronic unit 18, and electrical connection feature 222 may be retrieved to the surface when desired by the user (such as for repair or maintenance). Retrieval may be performed by any retrieval mechanism, such as tubing, wireline, slickline, or coiled tubing, with appropriate latches to latch to the dip tube 206. Upon retrieval, the electrical wet connect (the connection between the connection features 216 and 222) is disconnected.

Another embodiment of system 200 is illustrated in Figure 7. In this embodiment, side pocket sub 214 comprises an upper connection feature 234 to which dip tube 206 is coupled (mechanically and electrically) in a "lock-up" position rather than a "lock-down" position, as in the embodiments illustrated in Figure 6. In other words, an electrical connection, such as an electrical wet connect, is formed by moving a corresponding electrical connecting feature 236 of dip tube 206 upwardly into engagement with upper connection feature 234 of side pocket sub 214. As described with previous embodiments, the connection may be an electrical wet connect in which corresponding connection feature 236 is formed on a wet connect mandrel 238 sized to fit within the side pocket 240 of side pocket sub 214. As previously discussed, electrical cable 24 is functionally connected to opto-electronic unit 18 and optical fiber 20 once the dip tube 206 is properly secured. Retrieval of the dip tube 206, opto-electronic unit 18, and connecting feature 236 are as described in relation to the embodiment of Figure 7.

Another embodiment of system 200 is shown in Figure 8. In this embodiment, the upper completion 204 may be deployed in a single trip. By way of example, lower completion 202 comprises a packer 322, such as a screen hangar packer, and sand screen 324, such as an expandable sand screen, suspended from packer 322, and formation isolation valve 330.

Initially, packer 322, formation isolation valve 330, and expandable sand screen 324 are positioned in the wellbore, and sand screen 324 is expanded. Subsequently, upper completion 204 along with one or more electrical cables 24 is run in hole and the upper packer 338 is set. In to this embodiment, upper completion 204 may comprise a tubing isolation valve 336, a slotted joint 337, and an upper packer 338 all mounted to tubing 340. The electrical cable 24 extends through a feedthrough 36 in upper packer 338.

In this embodiment, the dip tube 342 is coupled to a retrievable plug 344 and the opto electronic unit 18 is coupled to the retrievable plug 344. The retrievable plug 344 allows the dip tube 342 and opto-electronic unit 18 to be retrieved through tubing 340 without pulling upper completion 204. An electrical wet connector 345 provides selective electrical connection between the electrical cable 24 and the opto-electronic unit 18 to thereby functionally connect the electrical cable 24 to the optical cable 20, as previously disclosed, to perform the measurements, also as previously disclosed. Upper completion 204 in this case must also have a mating section of the electrical wet connector 345. Seals 347 may be disposed between retrievable plug 344 and upper completion 204 to ensure the electrical connection. Latch mechanisms (not shown) may also be included to selectively mechanically connect and lock the retrievable plug 344 and the upper completion 204. Flow in this embodiment is around the plug 344 and through the slots 339 of the slotted joint 337. Retrieval of the dip tube 342, opto electronic unit 18, and electrical wet connector 345 are as described in relation to the embodiment of Figure 7.

An alternate dip tube embodiment is illustrated in Figure 9. In this embodiment, a dip tube 414 is deployed at a desired wellbore location. Dip tube 414 and an electrical wet connector 416 are mounted to a retrievable plug 418 including the opto-electronic unit 18. The plug 418 includes a fishing feature 420. Fishing feature 420 may be an internal or external feature configured for engagement with a fishing tool (not shown) to permit retrieval and potentially insertion of dip tube 414 through production tubing 422.

Although fishing feature 420 and dip tube 414 may be utilized in a variety of applications, an exemplary application utilizes a flow shroud 424 connected between tubing 422 and a lower segment tubing or sand screen 426. A completion packer 428 is disposed about tubing 426, and dip tube 414 extends into tubing 426 through completion packer 428. In this embodiment, fluid flow typically moves upwardly through tubing 426 into the annulus between flow shroud 424 and in internal mounting mechanism 430 to which retrievable plug 418 is mounted. Mounting mechanism 430 comprises an opening 432 through which dip tube 414 passes and a plurality of flow ports 434 that communicate between the surrounding annulus and the interior of tubing 422. Thus, retrievable plug 418 and dip tube 414 can readily be retrieved through tubing 422 without obstructing fluid flow from tubing 426 to tubing 422.

A base 436 of mounting mechanism 430 may be formed as a removable component. For -I example, the base 436 may be coupled to a side wall 438 of mounting mechanism 430 by a sheer pin or other coupling mechanism 440. Thus, the base 436 can be released or broken free from the remainder mounting mechanism 430 to provide a substantially uninhibited axial flow from tubing 426 through mounting mechanism 430 and into tubing 422. By way of example, the fishable dip tube 414 can be retrieved from the completion, and base 436 may be knocked down hole to provide a full bore flow.Fishing feature 420 may be incorporated into the other embodiments of the dip tube.

Although the system has been described and illustrated for use in subsea wellbores, it can also be used in other wells, such as landbased wells including deep wells or extended horizontal wells.

In another embodiment of the present invention as shown in Figure 10, the electrical cable 24 is substituted by a wireless telemetry mechanism 500 that transmits and receives signals between the surface acquisition unit 22 and the downhole opto-electronic unit 18. The use of wireless telemetry eliminates all optical losses due to optical connections (as known in the prior art). The wireless telemetry mechanism 500 comprises a first component 502 located proximate the surface acquisition unit 22 and asecond component 504 located proximate the downhole opto-electronic unit 18. Signals from the surface acquisition unit 22 are sent from the first component 502 to the second component 504, and signals from the downhole opto-electronic unit 18 are sent from the second component 504 to the first component 502. The telemetry of wireless telemetry mechanism 500 can comprise electro-magnetic telemetry, acoustic telemetry, or pressure pulse telemetry, and thus the components 502 and 504 are adapted to provide the relevant types of telemetry. At least one repeater 506 may be implemented along the tubing 12 to reinforce signals between the components 502 and 504. This is specially important in long length wells.

In this embodiment, the opto-electronic unit 18 and second component 504 convert the return optical signals from the optical fiber 20 into the proper wireless telemetry signal (such as electro-magnetic, acoustic, or pressure, among others). In one embodiment, the return optical signals are first converted into electrical signals and are then converted into the proper wireless telemetry signal. The second component 504 is also adapted to transmit the wireless telemetry signal, such as by including an electro-magnetic, acoustic, or pressure pulse emitter. The second component 504 is also adapted to receive the wireless telemetry signal from the first component 502 or the repeater 506, such as by including an electro-magnetic, acoustic, or pressure pulse receiver.

In this embodiment, the surface acquisition unit 22 and first component 502 convert the electrical signal from the unit 22 into the proper wireless telemetry signal (such as electro magnetic, acoustic, or pressure, among others). The first component 502 is also adapted to transmit the wireless telemetry signal, such as by including a electromagnetic, acoustic, or pressure pulse emitter. The first component 502 is also adapted to receive the wireless telemetry signal from the second component 504 or the repeater 506, such as by including an electromagnetic, acoustic, or pressure pulse receiver.

In one embodiment (not shown), the opto-electronic unit 18 and second component 504 may be run with the lower completion below the screen or liner hanger packer. The upper completion is then run in the wellbore 14. No physical connection is required between the upper and lower completions. Both completions are separated by a certain gap. This eliminates a need for wet connections between the upper and lower completions and simplifies the completion installation procedure.

In one embodiment, the opto-electronic unit 18, second component 504, and repeater 506 are powered by one or more batteries.

While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of the invention.

Claims (10)

1. What is claimed is: 1. A fiber optic measurement system for use in a wellbore, comprising: a opto-electronic unit adapted to provide an optical signal into a fiber optic sensor and to receive a return signal from the fiber optic sensor; the fiber optic sensor adapted to measure a parameter of interest and the return signal including information related to the parameter of interest; a surface acquisition unit in communication with the opto-electronic unit via an electrical l O cable; the opto-electronic unit adapted to convert the return optical signal into an electrical signal; and the electrical signal being transmitted through the electrical cable to the surface acquisition unit.
2. 2. The system of claim 1, wherein the fiber optic sensor comprises a sensing optical fiber for measuring a temperature profile along its length.
3. 3. The system of claim 1, wherein the fiber optic sensor comprises a sensor intrinsic to an optical fiber.
4. 4. The system of claim 1, wherein the opto-electronic unit is located intermediate a completion packer and gravel packer.
5. 5. The system of claim I, wherein an additional sensor is disposed downhole to collect a reference measurement point. s
6. 6. The system of claim 1, wherein the surface acquisition unit is located on the ocean floor.
7. 7. The system of claim 1, wherein the surface acquisition unit is located on a platform on the ocean surface.
8. 8. The system of claim 1, wherein the surface acquisition unit is located on a landbased production facility.
9. 9. The system of claim 1, wherein the opto-electronic unit is retrievable from the wellbore.
10. 10. A fiber optic measurement system for use in a wellbore, comprising: a opto-electronic unit adapted to provide an optical signal into a fiber optic sensor and to receive a return signal from the fiber optic sensor; the fiber optic sensor adapted to measure a parameter of interest and the return signal including information related to the parameter of interest; a surface acquisition unit in communication with the opto-electronic unit via a wireless telemetry mechanism; the wireless telemetry mechanism adapted to transmit wireless telemetry signals between the surface acquisition unit and the opto-electronic unit; the opto-electronic unit adapted to convert the return optical signal into the wireless telemetry signal; and the wireless telemetry signal being transmitted by the wireless telemetry mechanism to the surface acquisition unit.