GB2353055A

GB2353055A - A downhole service tool

Info

Publication number: GB2353055A
Application number: GB0025855A
Authority: GB
Inventors: Greg Nazzal; Paulo S Tubel; Gerald D Lynde; John W Harrell; Iii James V Leggett
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 1996-07-17
Filing date: 1997-07-17
Publication date: 2001-02-14
Anticipated expiration: 2017-07-17
Also published as: GB0025858D0; GB2353310A; GB0025855D0; GB2353055B; GB2353310B

Abstract

A downhole service tool 400 comprises an inflatable packer 410 and an imaging device 420 for analysing the quality of the bond between the packer element 412 and the formation 404. The imaging device 420 may be an acoustic sensor.

Description

2353055 PATENT APPLICATION TITLE: APPARATUS AND METHOD FOR PERFORMING

IMAGING AND DOWNHOLE OPERATIONS AT WORK SITE IN WELLBORES

-Field of the Invention

This invention relates generally to downhole tools for use in wellbores and more particularly to tools which can image a work site or an object in a wellbore, communicate with the surface and perform a desired end work or service at t he work site, during a single trip in the wellbore. The present invention also provides novel imaging devices and end work devices and various downhole tool configurations for imaging worksites and performing the desired end works.

Background of the Invention

To produce hydrocarbons (oil and gas) from the earth's formations, wellbores (also referred to in industry as boreholes) are formed to desired depths. The shallow portion of the wellbore is typically large in diameter, which is lined with a metal casing to prevent caving of the wellbore. The wellbore is then drilled to a desired depth to recover hydrocarbons from the subsurface formations. After the wellbore has been drilled, a metal pipe, generally referred to in the art as the casing or pipe, is set in the wellbore by injecting cement through the annulus'between the casing and the wellbore. Branch or lateral wellbores are frequently drilled from a main wellbore to form deviated or horizontal wellbores for improving production of hydrocarbons from the subsurface formations.

A large proportion of the current drilling activity involves directional drilling, i.e., drilling deviated and horizontal wellbores, to improve the b-ydmcarbGn pmducti-Qn andLor -wLthdraw additio-nal h-ydtocarho-as-ftomthe earth's formations. The wellbores are then completed and put into production.

The drilling and completion processes involve a number of different operations.

Such operations may include cutting and milling operations (including cutting relatively precise windows in the wellbore casings), sealing junctures between intersecting wellbores, welding, re-entering lateral wellbores, perforating, setting devices such as plugs, sliding sleeves, packers and sensors, remedial operations, sealing, stimulating, cleaning, testing and inspection including determining the quality and integrity of a juncture, testing production from a perforated zone or a portion thereof, collecting and analyzing fluid samples, and analyzing cores.

Oilfield wellbores usually continue to produce hydrocarbons for many years. Various types of operations are performed during the life of producing wellbores. Such operations include removing, installing and replacing different 2 types of devices, including fluid flow control devices, sensors, packers or seals, remedial work including sealing off zones, cementing, reaming, repairing junctures, milling and cutting, freeing stuck sleeves, diverting fluid flows, controlling production from perforated zones, setting sleeves, and testing wellbore production zones or portions thereof.

Typically, to perform downhole operations at a work site in a preexisting wellbore, wh ether during -the drilling, completion, production, or servicing and maintaining the wellbore, a desired tool is conveyed downhole, positioned into the wellbore at the work site and the desired operation is performed. Most of .15 the prior art tools are substantially mechanical tools or electro- mechanical tools.

Such tools lack downhole maneuverability, in that the various elements of the tools do not have sufficient degrees of freedom of movement, lack local or downhole intelligence, do not obtain sufficient data with respect to the work site or of the opeiration being performed, do not provide an image of the work site during the trip made for performing the end work, and do not provide confirmation of the quality and integrity of the work performed. Such prior art tools usually require multiple trips downhole to image a work site, perform an operation and then to confirm whether the operation has been properly performed. Multiple downhole trips can be very expensive, due to the rig or production down time.

3 The present invention addresses some of the above-noted problems and provides downhole service tools (also referred to as the downhole tool or service tool) which can be positioned and oriented adjacent a desired work site, images of the work site to the surface, perform the desired work at the work site and confirm or inspects the quality of the work during a single trip into a preexisting wellbore. The present invention provides imaging devices, end work devices and various downhole tool configurations to image work sites and to perform desired operations in preexisting wellbores. The imaging devices include an optical viewing device, an inflatable imaging device, ultrasonic devices and a tactile device.. The end work-devices include cutting devices, reentry devices, 15. sealing devices, -welding devices, testing and servicing -devices.

SUMMARY OF THE INVENTION

The present invention provides a downhole tool for imaging a location constituting a work site of interest in a preexisting wellbore and for performing a tool operation at the work site during a single trip in the wellbore. The downhole tool includes.an imaging. device for imaging the work site and an end work. device for performing a desired operation or an end work at the work site.

The imaging device may determine the image downhole and transmit the image to the surface or transmit the image data for processing at the surface. The downhole tool may be conveyed into the wellbore by any suitable method, 4 including a wireline, a tubing, and a robotics device that moves the downhole tool inside the wellbore.

Any suitable imaging device may be utilized for the purpose of this invention, including a camera for optical viewing, microwave device, contact 0 device (tactile device) such as a probe or a rotary device, an acoustic device, ultrasonic device, infra-red device and radio frequency ("RF") device.

The end work devices may include a fishing tool to engage a fish downhole, whipstock, diverter, re-entry tool, packer, seal, plug, perforating tool, 0 5 fluid stimulation tool, fluid fracturing tool, milling tool, cutting tool, patch tool, drilling tool, cladding. tool, welding tool, deforming tool, sealing tool, cleaning tool, tool for installing a device, tool for removing a device; setting device, testing device, an inspection device, acidizing.tool, an anchor, and a tool that engages with a downhole object.

In the downhole tools of the present invention, one or more devices are provided to position and orient the imaging device and the end work device as desired. Each downhole tool preferably includes a computer or processor ancl associated memory for storing therein models and programs for controlling the operations of the imaging device and the end work device. A surface computer receives the data from the downhole tool and displays the image of the work7 site for use by an operator, A two-way telemetry system provides communication between the surface computer and the downhole tool.

The present invention also provides ultrasonic imaging devices, including a device which can image radially and downhole (in front)'of the downhole tool.

In one.mode, the ultrasonic imaging device transmits signals by sweeping a preselected frequency range to obtain an effective operating frequency. The device then continues to operate the transmitter at such effective frequency -to generate data. representative of the attributes of the work site.

The present invention also.provides an imaging. device for obtaining still and/or video pictures of a work site in the wellbore. This viewing device includes a camera or another suitable device for taking the pictures and a mechanism to displace the non-transparent fluid in the wellbore with a transparent fluid. This invention further provides an inflatable device for providing the image of an object in the wellbore when such device is inflated and urged against the object.

The downhole tool may further include sensors for providing information about the condition of the downhole tool in the wellbore. Such sensors may include sensors for determining temperature, pressure, fluid flow, pull force, gripping force, tool centerfine position, tool configuration, inclination, and 6 acceleration. Formation evaluation sensors and other sensors to log the wellbore may also be included in the downhole tool of the present invention.

The present invention also provides certain end work devices, including a high pressure fluid cutting tool, which includes a source of supplying a fluid at a relatively high pressure and a cutting element for discharging the high pressure fluid. The fluid source may include serially arranged pressure stages, wherein each such stage increases the fluid pressure above its preceding stage.

The fluid may- be pulsed prior to supplying it to the cutting element. A control unit controls the position and orientation of the cutting element relative to the work site. The control unit may be programmed to cut according to a predetermined pattern provided to the control unit.

In each of the downhole-tools of the present invention, the operation of the imaging device and the end work device may be controlled from the surface and/or by the computer or processor in the downhole tool.

Examples of the more important features of the invention have been summarized rather broadly in order that the detailed'description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims 7 appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present invention, reference should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, and wherein:

FIGS. I and 1A are schematic diagrams of a system utilizing a service tool, conveyed into a wellbore; for imaging a work site in the wellbore and performing a- desired operation at the work site during a single trip according -to one embodiment of the present invention.

FIG. 2.is a,schematic diagram of a pressurized fluid cutting tool as an end work device for use in the system of FIG. 1.

FIG. 2A shows a manner of positioning the cutting element of the cutting tool shown in FIG. 2 in a wellbore to cut material located downhole of the cutting tool.

FIG. 213-C show alternative ways to position the cutting element of the downhole cutting tool shown in FIG. 2 to cut materials located downhole of the 8 cutting tool.

FIG. 3 is an example of a predetermined profile of a section of the casing to be cut that may be stored in a memory associated with the cutting system of FIG 1.

FIG. 4 is a schematic diagram of the cutting tool shown in FIG. 1 with a downhole imaging device for obtaining images of areas to be cut before and after the cutting operation.

FIG. 5A is a schematic diagram of an embodiment of a downhole, (service) tool having an ultrasonic imaging sensor for imaging a work site downhole of the service tool and an end work device for performing a desired operation at the work site during. a single trip.

FIG. 5B is a schematic diagram of an alternative embodiment of a downhole tool having an ultrasonic imaging sensor for radially imaging a work site and an end work device for performing a desired operation at the work site during a single trip.

FIG. 5C is a schematic diagram of yet another embodiment of a downhole, service tool having an ultrasonic imaging sensor for radially imaging a work site 9 and an end work device for performing a desired operation at the work site during a single trip.

FIG. 5D shows the downhole service tool of FIG. 5A positioned adjacent a wellbore juncture desired work site in a preexisting Wellbore.

FIG. 6A shows a schematic diagram of an embodiment of an imaging tool for obtaining still and/or video pictures of object downhole.

FIG.. 6B shows a schematic diagram of the imaging tool of FIG. 5D positioned -adjacent to aijuncture between:a main wellbore and a branch.

wellbore.

FIG. 6C shows a schematic diagram of an inflatable imaging tool position at a wellbore juncture for determining a contour of the juncture.

FIG. 6D shows a configuration of the placement of sensors in the inflatable member used in the imaging tool of FIG. 5F.

FIG. 7 is a schematic diagram of an embodiment of a downhole tool having an imaging device and a milling tool disposed at a bottom end of the tool for imaging a work site and performing a milling or cutting operation at the work site during a single trip.

FIG. SA is a schematic diagram of an embodiment of a downhole tool having an imaging device and an end work device for use in lateral wellbore operations.

FIGS. 813-813 are schematic diagrams of downhole tools with an imaging device and re entry device.

FIG. 9 is a schematic diagram of an embodiment of a downhole tool having an imaging device and an inflatable packer wherein the imaging device is adapted to obtain images during setting of the inflatable packer in a wellbore.

FIGS. 1 OA-1 OB are schematic diagrams of an embodiment of a downhole service tool having an imaging device and a welding device disposed for imaging a work site and performing a welding operation at the work site.

FIG. 11 is a schematic diagram of an embodiment of a downhole tool having an imaging device and an end work device for pressure testing the integrity of a juncture.

FIG. 12 is a schematic diagram of an embodiment of a downhole tool for performing testing of a perforated zone.

FIG. 13 is a schematic diagram of an embodiment of a downhole tool having an imaging device and an end work device for performing rework operations in wellbores.

FIG. 14 is a schematic diagram of an alternative embodiment of a downhole tool according to the present invention for performing cementing, fracturing and squeeze-off operations in wellbores.

FIGS.-15-16 are-schematic diagrams of-embodiments of a downhole tool for performing fishing operations in wellbores.

FIG. 17 is a schematic functional block diagram relating to the general operation of the downhole imaging and servicing tools of the present invention.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

FIG. 1 is a schematic diagram of a system 100 for use in oilfiefd wellbores for imaging a work site, communicating data about the image to the surface and performing a desired operation (endwork) at the work site during a single trip in the wellbore. The system 100 includes a downhole service tool 12 200 (also referred to herein as the downhole tool or the service tool) conveyed from a platform 11 of a rig 12 into a wellbore 22 by a suitable conveying device 24 from a source 66 thereof, such as a reel, being operated by a prime mover 68. As an example, and not as any limitation, F[G. 1 shows the conveying device 24 to be a coiled-tubing.. Other conveying methods, such as - wireline or robotics devices may also be utilized. The upper end 202 of the service tool is connected to the tubing 24 via a suitable connector 204. During operations, a drilling fluid from a source thereof 60 may be supplied to the wellbore 22 by a pump 68.

A surface control unit'70 placed at a suitable location on the rig'platform 11 preferably controls the operation of the system 100. The control unit 70 includes a suitable computer and memory for processing data, providing selected information to an operator -on a display 72, including images of the work site, logs during tripping of the wellbore, location (depth) of the tool 200 in the wellbore and orientation of the various elements of the service tool 200 in the wellbore 22 and values of selected tool, formation and wellbore parameters. The data from the service tool 200 may be transmitted to the surface by a suitable data link (telemetry) and recorded by a recorder 75 for later use. Suitable alarms 74, coupled to the control unit 70, are selectively activated by the control unit 70 when certain operating parameters exceed their respective limits. The operation of control units, such as the control unit 70, 13 is known and is, thus, not described in detail herein.

The service tool 200 includes one or more imaging devices or image sensors 210 for imaging work sites downhole, one or more end work devices 212a-212b, one. or more control mechanisms (hydraulic or electromechanical) 214 for controlling the operation of the end work devices 212a-212b and/or the imaging devices 210. The tool 200 may also include other sensors and devices, generally denoted herein by numeral 216, for determining desired parameters or characteristics relating to the tool 200 and the wellbore 22. Such sensors and devices may include devices for measuring temperature and pressure inside the tool 200. and in the: wellbore. 22,. sensors for determining the depth of the tool -in the wellbore 22, position (x, y, and z coordinates) of the tool 200, inclinometer for determining the inclination of the tool 200'in the wellbore 22, gyroscopic devices, accelerometers, devices for determining the pull force, center line position, gripping force, tool configuration and devices for determining the flow of fluids downhole.

The tool 200 further may include one or more formation evaluation tools for determining the characteristics of the formation surrounding the tool in the wellbore. Such devices may include gamma ray devices and devices for determining the formation resistivity. The tool 200 may include devices for determining the wellbore inner dimensions, such as calipers, casing collar 14 locator devices for locating the casing joints and determining and correlating tool depth in the wellbore 22, casing inspection devices for determining the condition of the casing, such as casing 16 for pits and fractures. The formation evaluation sensors, depth measuring devices, casing collar locator devices and the inspection devices may be used to log the wellbore while tripping into and or out of the wellbore 22.

The service tool 200 preferably includes a central' electronic and data processing unit or downhole control unit or circuit 218 for receiving signals and data from downhole devices, processing such data, communicating with the surface control unit 70 and for controlling the operations of the downhole devices. The control unit 218 preferably includes one or more processors (micro-controllers or micro-processors) for performing data manipulation according to programmed instructions provided thereto from the surface or stored in memory in the downhole tool 200.

The service tool 200 preferably includes a two-way telemetry 220 that includes a transmitter for receiving data including -the image data, from the control unit 218, downhole sensors. and devic es and transmits signals representative of such data to the surface control unit 70. Any suitable transmitter may be utilized for the purpose of this invention including an electro magnetic transmitter, a fluid acoustic transmitter, a tubular fluid transmitter, a mud pulse transmitter, a fiber optics device and a conductor. The telemetry system 220 also includes a receiver which receives signals transmitted from the surface control unit 70 to the tool 200. The receiver communicates such received signals to the various devices in the tool via the control unit 218 as' explained later in reference to. FI.G. 17.

Still referring to FIG 1, the imaging sensor or device 210 may be any suitable sensor. including a camera for optical viewing, microwave devi6e, contact device. (tactile device), such as a probe or a rotary device, an acoustic -device, ultrasonic device, infra-red device, or RF device. The imaging sensor 210 may be a- non-contacting device, such as an ultrasonic device, or a contacting - device -that has -one:or a series of projections from.- the tool 200 that engage with the wellbore and objects in the wellbore. If the quality or resolution of the image of the work site provided by the imaging device 210 depends, at least in part, on the frequency of the transmitted signal by the imaging device 210, then it is preferred to adapt the device to sweep the frequency in a predetermined range of frequencies to determine an effective frequency and then obtain the image at such effective frequency. The imaging sensor 210 may be employed to provide a still or motion picture of a work site or an object downhole, or to determine the general shape of the object or the work site or to distinguish certain features of the work site prior to, during and/or after the desired operation has been performed at the work site.

16 Still referring to FIG. 1, the end work devices 212a and 212b may include any device for performing a desired operation at the work site in the wellbore.

The end work device 212a-212b may include a fishing tool adapted to grab a fish downhole, whipstock, diverter, re-entry tool, packer, seal, plug, perforating tool, fluid stimulation tool, fluid fracture tool, milling tdol, cutting tool, drilling tool, workover tool, testing tool, cementing tool, welding tool, an anchor, acidizing tool or inspection tool. As noted earlier, one or more end work devices 22la-212b may be included in the tool 200 for performing the desired operations at one or more work sites in the wellbore. Use of certain of these devices with an imaging sensoris described below as examples.

Additionally, the service tool 200 may include downhole controllable stabilizers 219a and 219b, each such stabilizer having a plurality of independently adjustable pad segments for providing lateral: movement and lateral stability to the tool 200 and for anchoring the:tool 200. in the wellbore 22. Such stabilizers are especially useful in deviated and horizontal wellbores.

A plurality of independently controlled outwardly extending arms 219c may be utilized to provide lateral movement and stability to the tool 200 within the wellbore 22. For a majority of the downhole imaging and servicing applications the end work device utilized is designed for the specific application. In some applications, "Several end work devices may be incorporated into the service toc)l 200. To provide desired degrees of freedom for each of the end work devices 212a-212b and the imaging device 210, such devices are coupled to the tool 17 via knuckle joints, such as joints, 212a,' 212b' and 210a respectively. The movement of such knuckle joints is preferably controlled by the control unit 218. The degrees of freedom present in the tool 200 and the type of image sensor utilized preferably allow obtaining the image of any work site in the wellbore.

The service tool 200 is preferably modular in design, in that selected devices in the tool are individual modules that can be interconnected to each other to assemble the desired configuration of the tool 200. It is preferred to -form.-the image device. 210--and the- end-: work- devices 212a-212b as modules so-that. they can be placed in any order in the tool 200. Also, each of the end work devices 21.2a-21-2b and the.image device 210 have- independent degrees of freedom so that the tool 200 and any of the devices can be positioned, maneuvered and oriented in the wellbore in substantially any desired manner to perform the desired downhole operations. 20 The service tool 200 may be conveyed into the wellbore by a wireline, a coile d-tubing, a drill, pipe, a downhole thruster or locomotive for pushing the tool 200 into a horizontal wellbore or a robotics device on the tool to move and guide the service tool in the wellbore.

As shown in FIG. 1A, the end work device 212' or any other device'in 18 the tool 220 may have independently controlled downhole movements, such as shown by the solid lines 212' a and dotted lines 212' b, which allow the device 212' to be positioned at any angle in the wellbore 22. Thus, the service tool can be positioned adjacent to a work site in a wellbore, image the work site, communicate such images online to the surface, perform the desired work at the work site, and confirm the work performed during a single trip into the wellbore.

As noted-above, the system 100 may utilize any number of different imaging devices and end work devices. A number of such tool combinations are described below. Prior to describing such tools, a novel cutting and milling device and imaging sensors are first described while referring to FIGS. 2- 4.

FIG. 2 shows a schematic diagram of the system utilizing a novel high pressure fluid cutting device or tool 20 for cutting and milling materials in the wellbore 22 according to one embodiment of the present invention. In general, the cutting tool includes a cutting element such as a nozzle, for discharging a relatively high pressure fluid to cut the member. A source of supplying the high pressure fluid in the downhole tool provides the high pressure fluid to the cutting element. The cutting element may be continuously positioned ancl oriented at the desired location about the member to be cut by a control circuit contained in the downhole tool and/or at the surface.

19 The cutting tool 20 has a tubular housing (body) 26, which is adapted for connection with the conveying device 24 via a suitable connector 202. The housing 26 contains the various elements of the cutting tool 20, which include a cutting element section 28, a power section 34 for supplying pressurized fluid to the cutting element section 28, a control unit 36 which controls -the vertical and radial position of the control element 28 and a downhole control unit 38 for housing the circuits and memories associated with the downhole tool 20.

The bottom section 28 of the housing 26 houses a cutting element 30 -that terminates in a nozzle or-probe 30a!suit&ble for discharging a relatively high 15- -pressure fluid in-the form- of a jet stream of a relatively small cross-sectional area.- For the majority -of downhole -cutting: or milling applications, water discharged at a pressure greater that 60,000 psi is adequate in removing materials from within a wellbore. In cutting pipes, which are more than one-half inch thick, higher pressure may be required. The sect-ion 28 preferably rotates about -the joint 32, which connects the section 28. with a -hydraulic power section, generally denoted herein by numeral 34.

The power section 34 preferably includes a plurality of serial sections P. 3 each of which increases the pressure of a fluid above the pressure of the preceding section by a predetermines amount. The last section P,, discharges the fluid into the cutting element 30 at the desired pressure. The power section 34 also may contain a device 33 which pulses the fluid at a predetermined rate before it is supplied to the cutting element 30. High pressure pulsed jet stream is generally more effective in cutting materials than non-pulsed jet streams. The cutting element 30 may be a telescopic member that is moved along the tool's longitudinal axis z-z (axially) within the section 28 which enables positioning the probe 30a at the desired depth adjacent to the wellbore. In an alternative embodiment, the section 28 may be fixed while the nozzle 30 may be rotated radially about the tool longitudinal axis. The above described movements of the cutting element 30 provide multiple degrees of freedom, i.e., along the axial and radial direction thereby allowing accurate positioning of the nozzle 30 at any desired location within the wellbore.

A section 36 devices for orienting the nozzle tip 30a at the desired position. The cutting'element section 28 is rotated -about the wellbore axis to radially: position the nozzle tip 32a. The cutting element 30 is moved axially to position the nozzle tip 30a along the wellbore axis z-z. Hydraulically operated devices or electric motors are preferably utilized for performing such functions. The section 36 also 'preferably includes sensors for providing information about the tool inclination, nozzleposition relative to the material to be cut and relative to one or more known reference points in the tool. Such sensors, however, may be placed at any other desired locations in the tool 20.

In the configuration shown in FIG. 2, the cutting element 30 can cut materials 21 along the wellbore interior, which may include the casing or an area around a junction between the wellbore 22. (main wellbore) and a branch wellbore, as shown in FIG. 4. To cut the casing 23, the cutting element 30a is positioned at a desired location. As the tool 20 starts to cut the casing 23, it is rotated to .circumferentially cut the pipe. If concentric casings are present, the fluid 10. pressure may be increased accordingly to cut concentric p ipes.

FIG. 2A shows. a configuration of a cutting element 30' that may be utilized to cut materials below the cutting tool 20. In -this configuration, the probe 30a' dischargesthe fluid downhole -of the tool.20. - Arrows A-A indicate that the cutting element 30'. may be moved radially while-the circular motion defined.by arrows 13713 indicates that the cutting element 30' may be moved along a circular path within the section 28'. The cutting element configuration shown in FIG. 2A is usefulfor performing reaming operations in a tubular member, such as a production tubing, which are -required when interior of such tubing is lined with sediments.

To -remove a. permanent packer diff icult.to remove, it is desirable to remove (cut away) only the packing elements and-the associated anchors, if any, which typically lie between a packer body and the wellbore interior. The packers and anchors typically engage the casing at areas that are relatively smaller than the tool body. Prior art tools typically cut through the entire

22 packer, which can take excessive time. The packers can readily be removed by only cutting the packing elements and any associated anchors disposed between the packer and the casing. In such applications, the cutting nozzle needs to be positioned over the packing element alone. FIGS. 213-C show a configuration of the cutting element 30" whose nozzle 30a" may be placed at any desired location abo ve a packing element within the wellbore and then rotated to cut through the such element below the nozzle. Arrows C-C indicate that the probe 30a" may be moved radially within the section 28" while circular path defined by arrows D-D indicate that the cutting element may be rotated within the wellbore. FIG. 2C shows the position of the cutting element 30" after it has been moved radially a predetermined distance. As is seen in FIG.

2C, the nozzle tip 30a" extends beyond the section 28" which will allow the tool 20 to cut a material anywhere below the tool 20.

Electrical circuits and downhole power supplies for operating and controlling the operation of the cutting element 30, the power unit 34, and the devices and sensors placed in section 34 are preferably placed in a common electrical circuit section 38. Electrical connections between the electrical circuit section 38 and other elements are provided through suitable wires and connectors. The surface control unit 70 preferably controls the operation of the cutting system 10.

23 The operation of the cutting system 10 will now be described with respect to cutting a section or window in a casing while referring to FIGS. 2 and 3. The tool 20 is conveyed downhole and'positioned such that the nozzle is adjacent the section to be cut. The stabilizers 40a-b are set to ensure minimal radial movement of the tool 20 in the wellbore 22. A cutting profile 80 (FIG.

3) defining the coordinates for the outline of the section to be cut is stored in a memory (not shown) associated with the system 10. Such memory may be in the downhole circuit 36 or in the surface control unit 70. An example of such outline -is shown in FIG. 3. The arrows 82 define th e vectors associated the profile '80. The profile W is preferably displayed on the monitor 72 at 1"5 -the- surf ace. An operator oridnts the nozzle tip 30a at a location within the section of the casing to be cut. The desired values of the fluid pressure and the pulse rate are input into the sU rface control unit 70 by a suitable means. The tool 20 is then activated to generate the required pressure and the pulse rate.

The fluid to the tool 20 is preferably provided from the surface via the tubing 24. Alternatively, the wellbore fluid may be used.

If the section to be cut is'such that it will remain in position after it has been cut, perhaps due-to the presence of a cement bond, or if the cut section can be dropped to the wellbore bottom as debris, then the system 10 may be set so that the nozzle tip 30a will follow the profile 80, either by manual control by the operator or due to the use of a computer model or program in the 24 system. If the section must be cut into small pieces or cutting so that they may be transported to the surface, the cutting element is moved within the profile at a predetermined speed along a predetermined pattern, such as a matrix. This method ensures that the casing. section will be cut into pieces that are small enough to be transported to.the surface by circulating a fluid through the wellbore. During operations, the downhole circuits contained in the section 38 communicate with the surface control unit 70 via a two-way telemetry. The downhole telemetry is preferably contained in a section 39.

FIG. 4 shows the downhole cutting tool of FIG. 2 with an imaging device 90 attached -below the cutting section 28. Any suitable imaging device may be utilized. The imaging device 90 is utilized to conf irm the shape of the section of the casing or the junction after the cutting operation has been performed.

The imaging device 90 may also be utilized to image the area to be cut to generate the desired cutting profile and then to confirm the cut profile after the cutting operation. This enables the imaging of a location at a work site of interest and the performance of desired operation at the work site in a preexisting wellbore. Other types of downhole service tools may be utilized for imaging a location in a wellbore at which a tool operation is to be performed and performing the desired tool operation at the work site without retrieving the tool from the wellbore. Certain downhole end work devices are described later.

FIGS. 5A-5C show embodiments of downhole ultrasonic imaging devices for use with an end work device to image a work site of interest and to perform a desired operation at the work site during a single trip into the wellbore.

FIG 5A shows.a downhole service tool 250 having an end work device 252 for.performing a -desired operation downhole, an ultrasonic device 260 (ultrasonic imaging sensor) placed downhole of the end work device 252 for imaging a work site or an object. in the wellbore. The imaging device 280 has a number of sensor elements 264 arrange on a body. Each sensor element 264 acts as. a -transmitter. and. receiver. The preferred. frequency range is between 1 00,,..KHz and 500 KHz. - The-. ultrasonic transmitter.is preferably adapted to sweep the Jrequenc-y. within. a predetermined range of frequencies. The signals transmitted by the sensor element 264 are reflected back from the work site or the object and the reflected signals are received by the sensor elements 264, which a re processed by the control unit 256 or circuit in the tool 250 and transmitted, uphole via telemetry 258 to provide an image of the work site.

The ultrasonic sensor 260 may be rotated or beam steered (i.e.

electrically rotating or directing) to scan the inside of the wellbore. The ultrasonic signals are transmitted at a predetermined rate and the reflec- ted signals are received by the sensor elements 264 between successive firings of the transmitter. The end work device 252 may include a work element 253 26 that may be rotated by device 254 along the arrows 252a to orient the work element radially and may be moved vertically as shown by the arrows 252b, i.e., longitudinally to move the work element 253 uphole or downhole, which enables positioning the work element at any desired location in the wellbore.

The sensor 260 and the end work device 252 ate independently rotatable. The sensor 260 may be disposed above the end work device 252.

As shown in the tool 250' of FIG. 5B, the sensor elements 264' may be arranged on the body 255 of the end work device 252' around the end work element 253'. The sensor elements 264' may be disposed in any desired manner to image a segment of the wellbore or the entire wellbore interior. The tool may -be moved along the directions denoted by arrows:252a' and 252b'.

The vertical length of -the sensor elements 264' and the spacing there between defines the vertical imaging sweep and the resolution. Similarly, the horizontal distance, of the sensor elements 264' and the spacing between the sensor elements defines the radial sweep and the resolution. Alternatively, sensor elements may be arranged on the tool to direct signals downhole, as shown in FIG. 5C here the sensor elements 264" are disposed at the downhole (bottorn) end of a service tool 250". This enables the service tool 250" to image an object or a work site downhole of the service tool 250".

FIG. 5D shows the downhole service tool 250, shown in FIG. 5A, 27 positioned adjacent to a juncture 304 between a main wellbore 300 and a branch or lateral wellbore 302. The tool 250 may be utilized to image the juncture 304 and perform an operation thereat. The tool 250 provides an image of the juncture 304 to the surface prior to performing an operation. The image may be utilized to position the tool 250 at the desired location and to appropriately orient the tool 250 adjacent the juncture 304. The desired operation may then be performed at the juncture 304, which may include a window cutting operation, reaming operation, -cementing, welding, sealing or any other desired operation.

FIG. 6A:.,shows a schematic diagram of a.-system- 710 for obtaining still and/or..-video images of a wellbore interior.-or an object in -the wellbore. The system 710 includes a downhole tool 720 that contains a camera for taking pictures of. the.work site and a mechanism for displacing the non- transparent fluid around the work- site with a transparent or substantially transparent fluid.

For convenience and ease of explanation and understanding, and not as a limitation system 710 shows only the imaging device, i.e. without any end work device.

The system 710 includes a downhole imaging tool 720 conveyed from a platform 11 of a derrick 12 into a wellbore 122 by a suitable conveying devic;e 124, such as a tubing or wireline. The imaging tool 720 has a tubular housing 28 5.726, which is adapted for connection with the conveying device 724 via a suitable connector 719. The housing 726 contains the various elements of imaging tool 720. The bottom section of the housing 726 contains a camera section 728, which houses a retractable camera 730. The camera 730 may be moved within a camera housing 732 by a hydraulic means or an electric means, such as motor, generally denoted herein by numeral 734. The electrical circuits and downhole power supplies for operating and controlling the camera movements are preferably placed in a common electrical circuit section 736.

Electrical connections between the camera section 728 and the electrical circuit section 736 are provided through suitable wires and connectors between the two sections. The camera 730 in its retracted position, as shown by the solid lines 730, may be sealed from the outside environment by closing a hatch or door 738. The hatch may be -adapted to open outward as shown by the dotted line 738a. or by a sliding door (not shown). In the fully retracted position, the camera 730 resides completely inside the housing 728 so that the hatch 738 may be closed to seat the camera 730 from the outside environment.

In the fully extended position, the camera 730 extends far enough from the camera section 728 or any other obstruction, as shown by the dotted line 730a, so that the camera 730 can be rotated 360 degrees and can take unobstructed pictures of its surroundings. A light source 740 attached near the camera provides sufficient light for the camera to obtain pictures downhole.

29 I Additional light sources (not shown) may be provided on the tool body 726 to provide light in all the directions. The camera 730 may be focused downward as shown in FIG. 6A or horizontally as shown in FIG. 6B or along any other desired direction depending upon the intended application.

The imaging tool 720 contains a fluid injection section 744 for injecting a substantia lly transparent fluid (herein referred to as the clear fluid) into the wellbore. The fluid injection section 744 is preferably placed above (uphole) the camera section 7M The fluid injection section 744 includes one or more chambers, such as 746a -and 746b, for- storing therein the clear fluid. A pump 746 -in the - section - 744 is. -used tocontrollably inject the clear fluid f rom the chambers- 746a-746b-,into the wellbore below the camera section 728 via a fluid line 748. The fluid line 748 runs from the fluid injection section 744 through the camera section 728 to an outlet point 748a below the camera section 728.

Any downhole electrical control circuits and related power supplies for operating the pump 746 are preferably housed in the electrical section 736 A surface control unit 770 placed at a suitable location on the rig platform 711 preferably controls the Operation of the imaging system 710. The, control unit 770 includes a suitable computer, associated memory, a recorder for recording data and a display or monitor 772. The operation of control units, such as the control unit 770, is known and is, thus, not described in detail herein.

The operation of the imaging system 710 will now be described in reference to obtaining an image of an object, such as object 750, stuck in the wellbore 722. To obtain the image of the object 750, the location of the object is first determined. A number of techniques have been utilized in the oilfield applications for determining the location 'of an object or work site in a wellbore.

Any such technique or method may be utilized for determining the location of the object 750 for the purposes of this invention. The tool 720 is then conveyed into the wellbore 722 until the bottom end 752a of the fluid return pipe 752 is below the surface 750a of the object 750 that is to be imaged. The packer 733 is then inflated or set in the wellbore 722 to sea] the wellbore section 722a below the camera section 728 from the wellbore section 722b above the packer 733. The pump. 746 is then activated from the surface control unit 770 to inject the clear fluid from the chambers 746a-b into the wellbore section 722a via fluid line 748. The injection of the clear fluid into the section 722a causes the wellbore fluid present in the section 722a to enter the fluid pipe 752, which fluid is discharged into the wellbore section 722b above the packer 733 via a port 752b. This processes. is co. ntinued until the wellbore fluid between the port 752a and the camera section 728 has been replaced with the clear fluid. The clear fluid chosen is preferably lighter than the wellbore fluid and will not mix with the wellbore fluid. Such a clear fluid when injected intc) 31 the wellbore section 722a will uniformly displace the wellbore fluid. In some applications, it may be necessary to continue to inject additional clear fluid so as to completely flush out the wellbore fluid from section 722a. The system of the present invention may.employ a clear fluid source at the surface (not shown) instead of downhole chambers. In this embodiment,the clear fluid is continuously. supplied to.the chamber 746 from a surface source via a line placed in the conveying. means 724. Such a system may be necessary when large quantities of clear fluid arerequired to flush out the wellbore fluid.

After the.-object 750:has been exposed to the clear fluid, the camera dQof 738 is opened and the camera. 730 is lowered to - its f ully extended position 730a. To -obtain the. images of the object 750, the camera lights 740 are activated, the camera 730 is oriented in a desired position and the camera is operated to obtain images of the object 750. The images from the camera are transmitted by the downhole control circuits in section...736 to the surface control unit 770 via a two-way telemetry 725. The,images are displayed on the monitor 772. The operatorcan orient the camera in any desired direction and continue to obtain.images. If a video camera is used, the motion pictures are displayed on the monitor. The images are recorded in the recorder associated with the surface control unit 770.

FIG. 6B shows the application of the imaging system 710 described 32 above in reference to FIG. 5D for obtaining images of a junction 760 between a main wellbore 722 and a branch wellbore 723. To obtain images of the junction 760, a packer 735 is first set in the wellbore 722 below the junction 760 to completely seal off the wellbore section 22c lying below the packer 35.

The imaging tool 720 is then conveyed in the wellbore 722 so that the packer 33 is completely above the junction 760 while the port 752a' of the fluid return fine 752 is below the junction 760. The imaging tool 720 is operated as described earlier to displace the wellbore fluid in the wellbore section 722a' between the packers 733 and 735 with the clear fluid. The camera 730 is then oriented in the- direction of the junction 760 to obtain'the desired images.

Images of other objects in the wellbore and any section of the wellbore may be obtained by the imaging system 710 in the above-described manner.

FIG. 6C shows another embodiment of a downhole imaging tool 800.

The imaging tool 800 includes a flexible inflatable device 810 at a lower end of the tool 800. A fluid injection system 812 in the tool 800 injects a fluid into the device 810, thereby inflating the device 810. The fluid injection system 812 preferably contains a fluid pump section 814 having a reversible pump therein for injecting or pump ing a fluid from a chamber 816 into the device 810 and vice versa.

FIG. 6D shows a cross section of the flexible inflatable device 810. It 33.' includes a bladder 840 made from a flexible material, such as rubber. A plurality of sensors 842 are arranged along the inner surface 840a of the bladder 840 in a matrix or grid as shown in FIG. 6D. Each such sensor provides a signal corresponding to the deformation.of the bladder surface to which the sensor is attached from a predetermined norm. The signals from each such sensor are transmitted to a. downhole control circuit 816 via a conductor 844 and communication link 848. Ruid line 846 provides access to the bladder inside 840a. The downhole control circuit 816. controls the operation of the pump section 812, receives data:or signals from the each of the sensors 842, -condit.ions-the signalsan&may-rnanipulate the signals to obtain an image. The downhole control circuit 816,may -transmit the conditioned signals to a surface control unit, such as unit 970 shown. in FIG. 17, which produces the image based on a model stored in the control unit. The model is predetermined or predefined based on the.geometry of the flexible member 810 and the configuration of the sensors 842. The model is stored in a downhole memory associated with the downhole control circuit 816 when the system is designed to compute the. model downhole.

Operation of the tool 800 will now be described in the context of obtaining an image of a junction between the main wellbore 822 and the branch wellbore 823. To obtain an image of the junction 860, the tool 800 is conveyed into the main wellbore 822 until the flexible member is adjacent to the 34 junction 860. The fluid from the fluid section 812 is then injected into the flexible member 810, thereby inflating the member 810. A portion of the flexible member at the junction 860 attains the shape that corresponds to the junction 860 outline. The downhole control circuit 816 measures the signals from each of the sensors 842 and processes such signals as described above to obtain the image of the junction. Image of an object in the wellbore, such as object 850 shown in FIG. 613, is obtained by inflating the flexible me mber 810 while urging it against the object.

FIGS. 7 - 16 show embodiments of certain downhole tools which are adapted to image a work site of interest and perform a desired operation at work sites in a pre-existing wellbores during a single trip according to the present invention.

FIG. 7 shows an embodiment of a downhole service tool 350 conveyable by a tubular member 356, such as a drill pipe. The end work devic6 352 is a milling device and is disposed at the -bottom end of the conveying member 35 6.

A suitable imaging device 354 is disposed above the milling device 352. A conduit 358 may be utilized to supply hydraulic or electric power to the toc)l 350. A control unit, other sensors, and associated electronic circuitry and telemetry may be disposed in the tool.350 as described earlier. During operation, the work site or the object to be milled is imaged by the imaging.

sensor 354 and the cutting operation is performed by the milling device 352.

Images of the area being out are periodically obtained to ensure that the cutting operation is being performed correctly. Other end work devices, such as tools for determining the widow seal integrity may be disposed with the milling device 352.

FIG. 8A shows a downhole service tool 370 that may be utilized to image a location in the wellbore 375 and then drill the lateral wellbore 377 and/or to facilitate re-entry of an end work device into the lateral wellbore 377. To drill -the. I ateral, well bore.377,:,th e- tool 370 is positioned above a whipstock or any .15 other suitable -re-entry.device.3.79. An image device 380 provides images of the location where the lateral wellbore 377 Will be.dr-illed, which image may be utilized to position and orient the drilling element (bit) 372. Alternatively, since the image is available, the operator can set kick-off devices 382 to cause. the device 372 to perform an operation at a juncture 377a without first requiring the installation of the re-entry device 379, thereby avoiding another trip downhole. The tool 370 may similarly be used to reenter the-wellbore 377 to perform secondary operations in the branch wellbore 377, thereby eliminating an extra trip to install the re-entry device 379.

FIGS. 8B and 8C show another embodiment of a downhole service tool 385 which can be utilized to enter a branch wellbore 377 from a main wellbore 36 375 without the use of a re-entry device, such as a whipstock or a d. iverter.

The downhole service tool 385 includes an end work device 386 at the service tool 385 downhole end, a suitable imaging device 387 and a downhole operated tool orientation device 388. The device 388 preferably is a hydraulically or electrically operated knuckle-type joint which bends the tool 385 portions above and below the device 388 up to a predetermined maximum angle. The service tool 388 is lowered:into the main wellbore 375 to a known distance above the juncture 377a. The image device 387 provides images of the juncture 377a. The operator then orients the tool 385 and activates the device 388 to bend the tool 385 at a predetermined angle. Tbe'device is locked into the bent position and the tool 385 continues to be lowered into the wellbore. Inserting the tool 385 further causes it to enter into the branch wellbore 377 as shown in FIG. 8C.

Once the bottom end device 386 has entered into the branch wellbore 377, the device 388 is unlocked, which allows the front portion of the tool 385 to straighten as it moves further into the branch wellbore 377. After the tool 385 has been conveyed to the desired work site in the branch wellbore 377, the end work device 386 is then utilized to perform the desired operation. Thus, the service tool configuration ofFIGS. 813-8C allows the operator to (a) convey the service tool 385 into a branch or lateral wellbore 377 without the use of a secondary device, such as a diverter, and (b) image a desired work site in the 37 branch wellbore and perform a desired operation at the work site in a single trip.

This service tool 385 can eliminate two downhole trips, one to install a diverter, such as the diverter 379 shown in FIG. 8 and a second trip to image the work site prior to.performing the work at the work site.

FIG. 8D shows an alternative device 390 for causingthe service tool 385 to enter the -branch wellbore without the use of a diverter. The device 390 includes a plurality of arms or members which canabe independently extended outward from the service tool body to urge against the wellbore wall 375a.

Selectively -urg ing, the -members. 392- against -the wellbore wall 375a causes the tool to enter the branch. wellbore 377.

The kriuckle-joint 388 shown -in FIG. 8B and the arm members 392 shown in FIG. SID are operated by their respective control units in the service tool 385. The downhole control -unit (FIG. 1) controls the operation of these devices based on instructions provided fromithe surface control unit 70 or downhole stored programmed instructions. The service tool may also be programmed to locate the juncture 377a and cause the tool 385 to enter the branch wellbore 377. Thus, the service tool shown. in FIGS. 8B-8C can locate a lateral or multilateral juncture, adjust or orient itself and penetrate the lateral wellbore without the use of additional devices, such as diverters and whipstocks, and thereafter perform an end work in the lateral wellbore during 38 a single trip downhole.

FIG. 9 shows an embodiment of a service tool 400 with an imaging device 420 and a packer 410 as the end work device. The service tool 400 is shown conveyed by 6 tubular 402 into an open hole 404. The packer 410 has an inflatable packer element 412, which when inflated seals an annulus between the packer 410 and the wellbore 404. The packer 410 is attached to the tubular 402 by ashear bolt 406 having a weak pbint'406a' that may be sheared to separate the packer 410 from the tubular 402. Ahimagingdevice 420f or imaging the -annulus; 407 between the packer 410 and the wellbore 404 is -placed above the shear point 406a.

To set the packer element 412 in the annulus 407, the tool 400 is positioned in the wellblore, 404 so that the packer 410 is across from the area 407. The packer 410 is set by -injecting a hardening' fluid, such as cement, epoxy, or another sUitable material, into the: packer element 412. If -an acoustic device is-used as the imaging -device, its' response characteristics are a function of the manner the annulus is being enclosed with the hardening material. The data f roni Ahe imaging device 420 is analyzed to determine the quality of the bond between the packer-element 412 and the formation 404. Based on the imaging characteristics, the amount of the hardening material being supplied tc) the packer element 412 can be adjusted to improve the integrity of the seal.

39 After the packer 410 has been set, the bolt 406 is sheared to retrieve the service tool 400 from the wellbore 404.

FIGS. 1 OA and 1 OB show examples of embodiments of clownhole service tools for imaging a work site of interest and perform ing'weld in g operations at the work site during a.-single trip in the.-wellbore. FIG. 10A shows the service tool 450 for welding a juncture 434 between a casing 430 in a main wellbore 435 and -a casing 432 in a branch or lateral wellbore 437. The service tool 450 includes a welding device 452 at its bottomhole end. The service tool 45 0 may alsoAnclude a milling device 456 to dress or smooth.any rough welding performed by the welding device 452. An Jmage device 458 is. preferably placed above the welding device 452 and the milling device 456. The welding device 452 is coupled in the tool 450 with a rotatable joint 453. Similarly, if a milling device 456 is utilized, it is preferably disposed in the service tool 450 via rotatablejoints 455a and 455b. The rotatable joints 453, and 455a and 455b allow the welding device 452 and the milling device 456 to independently rotate in the wellbore 435. The service tool 450 also includes a control unit 461 to position and orient the tool 450 in the casing 430 and other desired devices 462. A central processor 460 processes signals.and data from the downhole devices and communicates with the surface computer 70 (FIG. 1) via a two-way telemetry 464.

To weld the casings 430 and 432 at the juncture 434, the service tool 450 is conveyed into the casing 430 by a suitable conveying system 451. The imaging device 456 provides an image of the juncture 434 to the surface control unit 70 (FIG. 1)., The welding device 452 is positioned adjacent to the juncture 434. The welding tip or probe 454, having its own degrees of freedom, is positioned at the-juncture to perform the welding operation. The probe. 454 may be extended radially and/or axially to position the probe 454 at any desired location in the casing 430. The axial movement of the service tool 450, rotary movement of the joint 453 and the axial and radial movements of the probe 454 provide necessary degrees of freedom of movement to position the welding probe 454 at any desired spot in the casing 430. One or more -operated stabilizers or radially downhole-controlled and independently extendable arms 466 or any other suitable device may be utilized to urge the probe 454 against the juncture 434 to'-be welded.

The image device 456 may be utilized to image the juncture 434 after welding operations or intermittently during welding operations to ensure quality and integrity of the welds 434a. The tool 450 may then be repositioned to place the milling:device 456 adjacent to the weld 434a. The milling device 456 has a milling surface 456a on its outside. which is extended outwardly anci urged against the weld 434a to smooth out the weld 434a. Any suitable milling - device, including any commercially 'available mechanical milfing device may be 41 utilized in the service.tool 450.

FIG. 1 OB shows a manner of utilizing the service tool 450 for welding a device 470, such as..a- permanent packer, a.plug, or a plate below the pl!ate inside a. casing 475. To weld.the device 470 inside the casing 475, the service tool 450 -is. placed. above the device 470 to image the work site 471 to be welded. The tool 450 is then repositioned to place the welding probe 454 against the area 471. The welding operation is then performed in the manner described above. It should be noted that only one type of welding device has - been -.d escri bed above.to perform selected -welding operations to describe the concept of the invention. - Any other suitable welding device may be utilized with.the service,tool,450. to perform any type of welding operations.

FIGS. 11 and 12 show a service tool 500 for performing testing operations in the wellbore. FIG. 11 shows a configuration for testing the integrity of a sea]. In the example of FIG. 11, a seal 514 is placed in a lateral wellbore 512 formed from a main wellbore 510. The service tool 500 is shown conveyed. into the main wellbore 510. It includes a suitable imaging device 502, a device 504 for discharging a high pressure fluid into the wellbore 5 10 and a pair of packers 506a and 506b spaced apart on the service tool 500 to seal a zone of interest 518 in the wellbore 510. To test the integrity of the seal 514, the service tool 500 is positioned adjacent to a juncture 515 to provide an 42 image of the juncture 515, which image is utilized to position the tool 500 such that the upper packer 506a is above the juncture 515 and the lower packer 506b is below the juncture 515. The'packers 506a-506b are then set as shown in FIG. 11 to seal the space 518 enclosed by the seal 514, the upper packer 506a and the lower packer, 506b. Pressurized fluid is then discharged from the device 504 into the space 518 via openings 504a. The pressure drop'.

if any, in the space 518 is measured over a predetermined time period, which provides an indication of the sealintegrity.

FIG. 12 shows a confi guration of a service tool 520 for use in testing a 1,5 production zone or reservoir 525. This configuration is substantially similar to the tool configuration shown in FIG. 11. FIG. 12 shows a cased hole 540 having a production zone 539. The casing 530 has a plurality of perforations 532 through which fluids from the.reservoir 525 enter into the casing 530 at zone 539. Periodic testing of production zones is commonly performed during the life of such production zones to determine the fluid flow from each zone or a portion thereof, to build and update reservoir models and to estimate the future production from such reservoirs. To test a production zone, such as zone 539, the tool 520 images the perforated zone 542 (work site). The image is utilized, among other things, to position the tool 520 adjacent to the perforations 532. The packers 526a and 526b are set in the casing 530 to sea I the zone 539 between the packers 526a-526b. A testing device 524 is ther- i 43 utilized to perform desired testing. The testing device 524 shown has a flow control valve 524a to control the fluid flow from the reservoir into the too] 530.

The received fluid may be collected in chambers 527 for further analysis or discharged into the wellbore uphole of the upper packer 526a. The testing device 524 also may include temperature sensors, pressure sensors and may include -devices to determine chemical and/or physical properties of the fluids, including specific gravity, oil, gas and water content in the formation fluid. To determine pressure and temperature build up, commonly performed for reservoir modeling, the valve 524 is closed and required measurements are made over a predetermined 'time -period.- Any -other Aype -of testing device may also be employed in addition to or as an alternative-to the device 424. The image obtained of the perforated zone 539 allows an operator to position the tool 530 precisely adjacent to the desired perforations 532. The packers 526a and 526b may be made slidable over the tool 530 so that the length of the zone 539 may be adjusted downhole.

It will be obvious that FIGS. 11 and 12 show specific examples in which the service tool of the present invention can be utilized to image a work site in a' wellbore and then perform testing (end work) during a single trip in the wellbore. Any other suitable testing device may be utilized for the purposes of this invention.

44 FIGS. 13 and 14 show examples of the service tool of the present invention for performing remedial work in preexisting wellbores. FIG. 13 shows the service tool 550 conveyed in-a cased wellbore 555 lined with a casing 556.

The casing 556 has a plurality of perforations 558 adjacent to a reservoir 560.

The service tool 550 includes a suitable image device 564 and a device or unit 1 Ot 566 for injecting fluids under pressure into the wellbore 555. The remedial work in the wellbore'555'may include injecting a fluid (Water, sand, glass, chemicals or mixture of water and additives, etc.) under pressure through the perforations 558 to increase the flow of formation fluids from the reservoir 560 into the wellbore 555. To perform such a remedial work, the service tool 550 1 F, is positioned in the wellbore 555- to obtain images of the perforated zone 568.

The images are utilized to reposition the tool, if necessary. Packers 570a and 570b are set in place to isolate the desired zone of interest or the work site 568. The desired fluid is then injected into the zone 568 by the device 566 via control valves 566a. The desired fluid may be injected via tubing 557 from the surf ace. The flow from each of the control valves 566a is preferably independently controlled by a downhole control unit 571. The above- described system is equally applicable for open hole fracturing applications.

The service tool 550 shown in FIG. 13 may also contain a test device, such as the test device 572, similar to the test device 534 shown in FIG. 11 to perform testing of the zone 568 to determine the effectiveness of the work performed.The service tool 550 shown in FIG. 13 thus may be utilized to image a work site (production zone 568), perform a work (remedial work) at the work site, and then determine the effectiveness of the work performed during a single trip in the wellbore.

During the life of:a wellbore, it is sometimes desired or- even required to seal off a production zone or a portion thereof for reasons such.as the zone is producing excessive amounts. of water and is impeding the flow of hydrocarbons from other production. zones in the same wellbore. FIG. 14 shows a -.conf iguration. of a service tool 580 of the present invention f or sealing a!production zone:599. or:a thereof by,cementing the zone 599 and then conf irmingthe. integrity- of the seal. +IG. 14 shows a service tool 580 conveyed in a cased wellbore 581 lined with a casing 582. The casing 582:has a plurality of perforations. 584 adjacent to a. reservoir 585. The service tool 580 includes a suitable image device 586 and a device or unit 588 for injecting cement slurry under pressure into the wellbore 581. The remedial work in the wellbore 581 may include closing off a single perforation 584a or the zone 599 having a number of perforations 584. To close off the zone.599, the tool 580 is positioned in the wellbore 581 to obtain images of the perforated zone 599.

The images are utilized to reposition the tool 580, if necessary, and packers 596a and 596b are set in place to isolate the desired zone of interest or the work site of interest 599. The cement is then injected from the cement device 46 588 into the zone 599 via a control valve 592b to seal the intended zone 599.

The tool 580 is then retrieved. To cement a single perforation, such as perforation 584a, a flexible cup 590 on the outside of the tool 580 is urged against the perforation 584a. ' Cement or any other desired fluid is then controllably discha rged from an opening 592a to close the perforation 584a.

1.0 The tool 580 may also include a testing device 594 to test the integrity of cementing work. The. device 594 may be a flow measuring device to determine if any fluid is flowing out of the:cemented zone. Pressure and temperature measuring devices and resistivity measuring devices may also be utilized as test devices. Additionally, the image device 586 may be utilized to obtain secondary images of the cemented work.site to-determine the"effectiveness of the work performed. It should be noted that the term cement is used to!generally mean hardening materials, including- qement slurry, epoxies and any other suitable material. In some -cases, it is desirable to intentionally damage a formation or zone to seal unwanted production of formation fluids. The above-described method may also be utilized for such applications.

FIGS. 1.5 and 16 show examples of service tools of the present invention for performing fishing operations preexisting wellb6res. FIG. 15 shows a service tool 630 conveyed in a wellbore 632 by a tubing 633. The service tool 630 includes a suitable image device 635 having a retractable tactile sensor for imaging an object, such as a fish 640 stuck in the wellbore 632. The tactile 47 image device 635 includes a retractable probe 637, which has a tip 639 that can scan the entire inside of the wellbore 632. The probe tip 639 attached to an arm 641 which can move radially and axially around a rotary joint 638. The joint 638 can move axially as shown by the dotted lines 643, thereby providing sufficient numbers of degrees of freedom to the probe tip 639 to scan the wellbore 632. The service tool 630 includes a suitable fishing device for engaging the fish 640 and other devices, sensors, control circuits and Aelemetry, collectively designated by numeral 645. To retrieve the fish 640 from the wellbore 632, the service tool 1630 is positioned above the fish 640. The imaging device'.635 sentes the location and profile of -the fish 640, which is 15. communicated:.to the surface. The tool 630 is then -repositioned, thefishing .device,644 is activated to engage the-fish 640. Any other suitable imaging device may be utilized for imaging the fish 640. Also any suitable fishing device may be utilized for the purpose of this invention. For example, the fishing device may be the type that grabs the fish from the outside or the inside of the fish 640. It may be a spear type or an over-shot type device as described in U.S. Patent No. 5,242,201, which is incorporated herein by reference. The fishing tool 635 may drill into the fish 640 to securely engage the fish 640.

The fish 640 is retrieved by retrieving the tool 630. It should be obvious that the tactile imaging device 635 may include more than one probes and that such imaging devices may be utilized in any of the service tools made according to this invention.

48 FIG. 16 shows the use of a service tool 650 conveyed in a wellbore 652 by a tubing 653. The service tool 650 includes a suitable imaging device 660, including an ultrasonic and tactile device. In the example of FIG. 16 a fish 666 is shown stuck in a wash-out area 654 of the wellbore 652. To retrieve the fish 666, the tool 650 is positioned adjacent to the fish 666 to image the 666 fish by the imaging device 660. The tool 650 may include a one or more knuckle devices 672 that can be activated, from the surface or downhole control circuits 670 to position the image device 660 and a fishing device 664 in the wash-out region 654. After the image is taken, the fishing device 664 is repositioned to engage the fish 666. The fish 666 may be moved from the wash-out region 654 by reactivating the knuckle joints 672. The fish 666 is retrieved by retrieving the tool 650. It should be noted that any suitable imaging and fishing devices may be utilized for the.-purpose of this application.

The fishing tools of this invention preferably have degrees of freedom of movement that are sufficient to position the tool to retrieve the fish at any place in the wellbore.

Thus far selected examples of the downhole service tool have been described above to illustrate the concepts of the present invention. It will, however, be understood that many other end work devices and imaging devices can be utilized to image an object and work site in a wellbore and to perform a desired operation at the work site without requiring retrieving the service tool 49 according to the concepts of this invention. For example, the service tool 200 (FIG. 1) of the present invention may be utilized to locate a weak point in the well casing, such as a crack or a pit, and perform welding. The service tool 200 may be utilized -to perform swaging operations downhole or to inject polymers into the wellbore. Yet, in.-certa.in other applications, it is desirable to confirm the.:engagement of a tool conveyed f rom the -surface lo downhole device prior to performing an operation with such tool. The service tool of the present invention may include an engagement device and a sensor for generating signals that differ when the tool is engaged with the downhole device and when it fully or:properly engaged. The service tool may include without limitation any desired engagement. device, i.including -a collet type device, a screw typedevice, a:latching device-that.-is designed to latch into or onto a receptacle associated with the downhole device, a cone type device, a device that is designed to mate with. a matching profile in the -downhole device, or a callet or a pressure activated device. To perform the desired operation, the service tool is placed at a desired location in the wellbore and the sensor is activated to provide the tool response. The tool is engaged with the downhole device. The sensor continues to provide signals responsive to the engagement process. The response signature is utilized to confirm the engagement of the tool device with the downhole device.

Additionally, the service tool 200 may incorporate one or more robotics devices that can remove a member or a sensor, install a sens& or a device, such as a fluid control valve, remove a liner, interchange parts, replace power sources, such as batteries, turbines, etc., inflate a device, manipulate a device or part downhole from its current position to a new position, such as a sliding sleeve from an open position to a closed position or vice versa, and perform any other desired function. The image device in the service tool is preferably utilized to locate the part to be replaced, installed or manipulated.

It is often desirable to measure selected wellbore and formation parameters either prior -to: or after performing an end work. Frequently, such information is obtained by logging the wellbore prior to performing the end work, which typically requires an extra trip downhole. The service tool of the present invention, such as tool 200 shown in FIG. 1 and other tools shown in FIGS. 2-16 may include one or more logging devices or sensors. For example, for the work to be performed in'cased holes, such as shown in FIGS. 10a- 14, a collar locator may be incorporated in the service tool 200 to log the depth of the tool 200 while tripping downhole. Collar locators provide relatively precise measurements of the wellbore depth and can be utilized to correlate depth meas urement made from surface instruments, such as wheel type devices. The collar locator depth measurements can be utilized to position and locate the imaging and end work devices of the tool 200 in the wellbore. Also, casing inspection devices, such as eddy current devices or magnetic devices may be 51 utilized to determine the condition of the casing, such as pits and cracks. Similarly, a device to determine the cement bond between the casing and the formation may be incorporated to obtain a cement bond log during tripping downhole. Information about the cement bond quality and the casing condition .are especially useful for well bores which have been in production for a relatively long time period or wells which produce high amounts of sour crude oil or gas.

Additionally, resistivity measurement devices may be utilized to determine the presence of water in the wellbore or to obtain a log of the formation resistivity.

Similarly gamma ray devices may be utilized measure ba ckground radiation.

Qther - formation. evaluation sensors may also be utilized to provide 1-5 corresponding logs while tripping -into or out of the.wellbore.

The description thus far substantially relates to a service tool which utilizes an image sensor and an end work device to image a work site in a wellbore and perform a selected end work. As described earlier, the service tool of the present invention also provides confirmation about the quality and effectiveness of the end work performed downhole during the same trip. The general operation of the above-described tools is described by way of an example of a functional block diagram for use with the system of FIG. 1. Such methods and operations are equally applicable to the other downhole service tools made according to the present invention. Such operations will now be described while referring to FIG. 17.

52 The downhole section of the control circuit 900 preferably includes a microprocessor-based downhole control circuit 910. The control circuit 910 determines the position and orientation of the tool as shown in box 912. A circuit 915 controls the operation of the downhole tool. The control circuit 910 also controls the end work devices, such as cutting tool 914a and any other end work devices, generally designated herein by numeral 914n. During operations, the control circuit 910 receives information from other downhole devices and sensors, such as a depth indicator 918 and orientation devices, such as accelerometers and gyroscopes. The control unit 900 communicates with the surface control unit 970 via the downhole telemetry 939 and via a data or 15- communication link 939a. The control circuit 910 also preferably controls the operation of the downhole devices, such as the power unit 934, stabilizers and other desired downhole devices (not shown). The downhole control circuit 910 includes a memory 920 for storing therein data and programmed instructions.

The surface control unit 970 preferably includes a computer 930, which manipulates data, a recorder 932 for recording images and other data and an input device. 934, such as a keyboard or a touch screen for inputting instructions and for displaying information on the monitor 972. The surface control unit 970 and the downhole tool communicate with each other via a suitable two-way telemetry system.

While the foregoing disclosure is directed to the preferred embodiments

53 of the invention, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope and spirit of the appended claims be embraced by the foregoing disclosure.

54

Claims

1 CLAIMS

2 3 1. A downhole service tool, comprising:

4 (a) a packer adjacent a lower end of the tool, said packer having a packing member on a 6 housing that forms a seal between the 7 housing and a work site in a pre-existing 8 wellbore when a fluid is injected into the 9 packing member; and (b) a sensor uphole of the packer for providing 11 data representative of an image of the work 12 site when the downhole tool is conveyed 13 into the wellbore for setting the packer in 14 the wellbore.

16 2. A downhole service tool substantially as 17 hereinbefore described with reference to the 18 accompanying drawings.

19 3. A downhole tool for imaging a work site within a 21 pre-existing wellbore and performing a tool 22 operation at the work site during a single trip 23 of the tool in the wellbore, the tool 24 comprising:

(a) an imaging device in the downhole tool for 26 imaging the work site; and 27 (b) a work device in the downhole tool for 28 performing the tool operation at the work 29 site, whereby the downhole-tool obtains the image of the work site and performs the 31 tool operation at the work site during a 1 single trip of the downhole tool into the 2 wellbore.

3 4 4. The downhole tool of claim 3, wherein the imaging device is selected from the group 6 comprising a camera for optical viewing, an 7 acoustic device, an ultrasonic device, an infra 8 red device, an RF device, a microwave device, a 9 contacting device, a tactile device and a fibre optic device.

11 12 5. The downhole tool of claim 3, wherein the 13 wellbore is a cased wellbore.

14 6. The downhole tool of claim 3, wherein the 16 imaging device is a contacting device comprising 17 a series of projections extending from the 18 downhole tool that can engage with the wellbore 19 and objects in the wellbore.

21 7. The downhole tool of claim 3, wherein the 22 transmitter is selected from the group 23 comprising an electromagnetic transmitter, a 24 fluid acoustic transmitter, a tubular fluid transmitter, a mud-pulse transmitter, a fibre 26 optics transmitter and a conductor wire 27 transmitter.

28 29 8. The downhole tool of claim 3, wherein the end work device is selected from the group 31 comprising a fishing tool to engage with a fish 56 1 downhole, a whipstock, a diverter, a re-entry 2 tool, an anchor, a packer, a seal, an inflatable 3 packer, a plug, a perforating tool, a fluid 4 stimulation tool, an acidizing tool, a fluid fracturing tool, a milling tool, a cutting tool, 6 a patch tool, a drilling tool, a cladding tool, 7 a welding tool, a deforming tool, a sealing 8 tool, a cleaning tool, a device for installing a 9 device in the wellbore; a device for removing a device downhole; a testing device for performing 11 a test in the wellbore; an inspection device; 12 and a tool for engaging with a downhole object 13 to perform a desired operation.

14 9. The downhole tool of claim 3 further comprising 16 a computer having at least one processor for 17 controlling the operation of the end work 18 device.

19 10. The downhole tool of claim 3, wherein the end 21 work device is movable radially and 22 longitudinally relative to the wellbore.

23 24 11. The downhole tool of claim 3 further comprising a memory positioned for recording date from the 26 sensor for data retrieval when the service tool 27 is brought back to the surface.

28 29 12. The downhole tool of claim 3 further comprising a memory pre-programmed with a work site data 31 model for correlating data generated downhole 57 1 with pre-programmed work site data to facilitate 2 the identification of the work site.

3 4 13. The downhole tool of claim 12, wherein the transmitter generates signals for transmission 6 to the surface representative of the data 7 correlation and, thus, of the work site date 8 generated downhole.

9 14. The oilfield tool of claim 13, wherein the 11 transmitter communicates with other equipment 12 positioned downhole in the wellbore.

13 14 15. The downhole tool of claim 3 further comprising a receiver associated with the downhole tool for 16 receiving signals sent from the surface to the 17 downhole tool, with the receiver communicating 18 with a processor in the downhole tool.

19 16. The downhole tool of claim 3 further comprising 21 a formation evaluation sensor adjacent the lower 22 end of the tubing.

23 24 17. The downhole tool of claim 3 further comprising at least one sensor for determining an operating 26 condition of the downhole tool during drilling 27 of the wellbore, said at least one sensor 28 selected from the group comprising temperature, 29 pressure, fluid flow, tool orientation, pull force, gripping force, tool centerline position, 58 1 tool configuration, inclination, and 2 acceleration.

3 4 18. The downhole tool of claim 3, wherein the imaging device detects objects positioned 6 downhole of the tool.

7 8 19. The downhole tool of claim 3, wherein the 9 imaging device is an ultrasonic device positioned in the downhole tool to provide 11 images of the work site located downhole of the 12 downhole tool.

13 14 20. The downhole tool of claim 19, wherein the is ultrasonic device includes at least one 16 transmitter for transmitting signals to the work 17 site downhole of the downhole tool and a 18 receiver for receiving signals reflected by the 19 work site.

21 21. The downhole service tool of claim 20, wherein 22 the imaging device operates the transmitter by 23 sweeping a preselected frequency range to obtain 24 an effective operating frequency and continues to operate the transmitter at such effective 26 frequency to generate data representative of 27 attributes of the work site.

28 29 22. The downhole tool of claim 3, wherein the imaging device is beam steered to generate data 59 1 representative of the properties of the work 2 site.

3 4 23. The downhole tool of claim 3, wherein the imaging device includes a sensor that is rotated 6 to generate data representative of the 7 properties of the work site.

8 9 24. The downhole tool of claim 3, wherein the end work device is a cutting device that performs 11 cutting with a high pressure fluid.

12 13 25. The downhole tool of claim 3, wherein the end 14 work device is a re-entry device that includes an orienting device that can be oriented to 16 enter into a lateral wellbore intersecting the 17 wellbore.

18 19 26. The downhole tool of claim 25, wherein the orienting device is selected from a group of 21 devices consisting of a knuckle joint, a 22 flexible joint that is operated by a control 23 circuit in the downhole tool, a flexible joint 24 that is remotely operable, and a deflection device that reorients the downhole when said 26 deflection device is urged against the wellbore.

27 28 27. The downhole tool of claim 3 further comprising 29 two spaced apart isolators, said isolators isolating a zone of interest in the wellbore.

31 1 28. The downhole tool of claim 27 further comprising 2 a device for injecting fluid enterpriser into 3 the zone of interest to perform testing of the 4 zone of interest.

6 29. The downhole tool of claim 27, wherein the 7 isolated zone is selected from the group 8 consisting of a perforated zone, and juncture 9 between the wellbore and a lateral wellbore.

11 30. The downhole tool of claim 3, wherein the 12 imaging device is a tactile device having at 13 least one probe that extends from the downhole 14 tool to make contact with the work site to provide signals representative of the physical 16 attributes of the work site.

17 18 31. A method of imaging a location constituting a 19 work site of interest at which a tool operation is to be performed in a pre-existing wellbore 21 and performing a work at the work site during a 22 single trip, comprising:

23 (a) providing a tubing extending from the 24 surface down into the wellbore, a sensor adjacent the lower end of the tubing for 26 sensing properties associated with the work 27 site and generating data representative of 28 the work site, a transmitter for receiving 29 the data and transmitting signals representative of the data to the surface 31 and an end work device adjacent the lower 61 1 end of the tubing for performing the 2 desired tool operation; 3 (b) extending the tubing into the wellbore 4 toward the work site; (c) sensing properties associated with the work 6 site downhole; 7 (d) generating data representative of the image 8 of the work site; 9 (e) transmitting signals representative of the data to the surface; and 11 (f) performing the desired tool operation at 12 the work site location before removing the 13 tubing from the wellbore.

14 32. A method of imaging a work site and performing 16 an end work at the work site in a pre-existing 17 wellbore during a single trip into the wellbore, 18 comprising:

19 (a) conveying a downhole tool into the wellbore, said downhole tool having an 21 imaging device for imaging a work site in 22 the wellbore, a device for isolating the 23 work site, and an end work device for 24 performing a desired work at the work site; (b) isolating the work site; 26 (c) imaging the work site by the imaging 27 device; and 28 (d) operating the end work device to perform a 29 desired operation at the work site.

62 1 33. A method of imaging a location constituting a 2 work site of interest in a pre-existing wellbore 3 at which a desired operation is to be performed 4 without removing the tool from the wellbore, comprising:

6 (a) positioning a downhole tool adjacent the 7 work site, said downhole tool having an 8 imaging device for sensing properties 9 associated with the work site and generating data representative of the work 11 site, a transmitter for receiving the data 12 and transmitting signals representative of 13 the data to the surface and an end work 14 device for performing the desired tool operation; 16 (b) generating data representative of the work 17 site and transmitting signals 18 representative of the data to the surface 19 by the transmitter; and (c) performing the desired tool operation at 21 the work site location before removing the 22 tool from the wellbore.

23 24 34. A downhole oilfield service tool for imaging a work site in a wellbore and for performing a 26 desired operation at the work site without 27 requiring retrieving the service tool from the 28 wellbore prior to performing the desired 29 operation, said service tool conveyable into the wellbore by a tubing extending from a surface 63 1 location toward and adjacent the work site, 2 comprising:

3 (a) an ultrasonic sensor adjacent a lower end 4 of the tubing for providing an image of the work site and generating data 6 representative said image; 7 (b) a transmitter associated with the service 8 tool for receiving the data generated by 9 the sensor and transmitting signals representative of said data to the surface; 11 and 12 (c) a milling tool adjacent the lower end of 13 the tubing for performing a cutting 14 operation at the work site based at least is partially upon said data without retrieving 16 the service tool from the wellbore prior to 17 performing the desired operation.

18 19 35. A downhole service tool for entering into a branch wellbore from a juncture at a main 21 wellbore to perform an end work at a work site 22 in the branch wellbore during a single trip into 23 the main wellbore, comprising:

24 (a) a sensor adapted to obtain data for an 2S image of the juncture; 26 (b) a control circuit in the service tool for 27 receiving the data from the sensor and 28 transmitting signals representative of said 29 data to the surface to obtain the image of the juncture; 64 1 (c) a tool orientation device in the service 2 tool, said device adapted to be operated downhole by the control circuit, to cause the service tool to enter the branch wellbore; and 6 (d) an end work device for performing the 7 desired end work at the desired work site 8 in the branch wellbore, whereby the service 9 tool can locate the juncture, enter into the branch wellbore from the main wellbore 11 and perform the desired operation at the 12 work site in a single trip.

13 14 36. The downhole service tool of claim 35, wherein Is the tool orientation device is selected from a 16 group comprising, a knuckle joint that is 17 controlled from a command from the surface, a 18 knuckle joint that is controlled downhole, a 19 plurality of independently adjustable pads, and a member that extends outward from the service 21 tool to urge against the wellbore to cause the 22 service tool to move transverse to the wellbore 23 axis.

24 37. A downhole service tool for imaging a selected 26 work site in a wellbore and performing a welding 27 operation at the selected work site in a 28 wellbore during a single trip, comprising:

29 (a) a sensor adapted to obtain data to image the work site; 1 (b) a control circuit in the service tool for 2 receiving the data from the sensor and 3 transmitting signals representative of said 4 data to the surface to obtain the image of work site; and 6 (c) a welding device in the service tool, said 7 welding device adapted to be operated 8 downhole by the control circuit to perform 9 the welding operation at the work site during the single trip.

11 12 38. The downhole service tool of claim 37, wherein 13 the selected work site is selected from a group 14 comprising a joint between casing in a main wellbore and a branch wellbore formed from the 16 main wellbore and a packer.

17 18 39. A downhole oilfield service tool conveyable into 19 a wellbore for imaging a location constituting a work site of interest downhole and performing a 21 testing operation at the work site during a 22 single trip of the tool in the wellbore, the 23 tool comprising:

24 (a) a sensor adjacent for sensing properties associated with the desired work site in 26 the wellbore and generating data 27 representative of the work site; 28 (b) a transmitter for receiving the data from 29 the sensor and transmitting pignals representative of said data to the surface; 66 1 (c) a pair of spaced apart seals on the service 2 tool to seal at least a portion of the work 3 site of interest between the pair of seals; 4 and (d) a testing device in the tool to perform a 6 selected test in the sealed work site, 7 during the single trip.

8 9 40. The downhole service tool of claim 39, wherein the selected work site is a perforated zone.

11 12 41. The downhole service tool of claim 40, wherein 13 the testing device performs a test selected from 14 the group comprising pressure test of a sealed region, pressure build-up over a time period, 16 temperature test, temperature build-up over a 17 time period, reservoir analysis, formation 18 evaluation, resistivity of formation fluids, 19 sample collection, formation fluid analysis, and hydrocarbon content of formation fluids.

21 22 42. A downhole oilfield service tool conveyable into 23 a wellbore for imaging a location constituting a 24 work site of interest downhole and performing a workover operation at the work site during a 26 single trip of the tool in the wellbore, the 27 tool comprising:

28 (a) a sensor adjacent for sensing properties 29 associated with the desired work site in the wellbore and generating data 31 representative of the work site; 67 1 (b) a transmitter for receiving the data from 2 the sensor and transmitting signals 3 representative of said data to the surface; 4 (c) a pair of spaced apart seals on the service tool to seal at least a portion of the work 6 site of interest between the pair of seals; 7 and 8 (d) a device for injecting a pressurised fluid 9 into the sealed portion of the work site to perform the workover operation, during the 11 single trip.

12 13 43. The downhole service tool of claim 42, wherein 14 the work site of interest is a perforated region is and the sealed portion includes at least one 16 perforation.

17 18 44. The downhole service tool of claim 42, wherein 19 the fluid is selected from a group comprising cement slurry, polymer, water, steam, chemicals, 21 and acidizing fluids.

22 23 45. The downhole service tool of claim 42, wherein 24 the workover operation is selected from the group comprising injecting fluids into a 26 perforated zone to improve hydrocarbon 27 production, sealing of a zone to prevent 28 production of fluids therefrom, cementing, 29 fracturing, and cleaning.

68 1 46. A downhole visual imaging tool for obtaining an 2 image of a predetermined area of interest within 3 a wellbore having substantially non-transparent 4 fluid therein, the imaging tool comprising:

(a) a tool body conveyable into the wellbore; 6 (b) a seal for blocking fluid communication to 7 the area of interest, the tool body having 8 a device for providing a fluid seal between 9 the imaging tool and the work site when the imaging tool is placed a predetermined 11 distance from the work site; 12 (c) a fluid injection system for displacing the 13 non-transparent fluid between the imaging 14 tool and the work site with a substantially is transparent fluid; and 16 (d) a camera associated with the imaging tool 17 for taking an image of the work site.

18 19 47. The imaging tool of claim 46, wherein the tool body is conveyable into the wellbore by a 21 conveying device selected form a group 22 consisting of a wireline, a tubing and a 23 traction device that can move the downhole 24 imaging tool through the wellbore.

26 48. The imaging tool of claim 46, wherein the camera 27 is adapted to be remotely oriented in a desired 28 direction to take an image of the work site.

29 49. The imaging tool of claim 46 further having a 31 control unit at the surface for receiving data 69 1 from the camera and for displaying the image of 2 the work site.

3 4 50. The imaging tool of claim 49, wherein the control unit controls the operation of the fluid 6 injection system.

7 8 51. The imaging tool of claim 46 further having a 9 control circuit within the imaging tool for automatically controlling the operation of the 11 fluid injection system and for operating the 12 camera to obtain the desired image of the work 13 site according to programmed instructions 14 provided to the control circuit.

16 52. The imaging tool of claim 46, wherein the 17 imaging tool provides a multi-dimensional view 18 of the work site from data provided by the 19 camera.

21 53. The imaging tool of claim 46, wherein the fluid 22 injection system comprises:

23 (a) a source of substantially transparent 24 fluid; and (b) a fluid transfer mechanism for displacing 26 at least a portion of the substantially 27 non-transparent fluid with the 28 substantially transparent fluid wellbore.

29 54. The imaging tool of claim 53 further having a 31 fluid communication line coupled to the fluid I chamber for retrieving the substantially 2 transparent fluid from the wellbore into the 3 fluid chamber.

4 55. The imaging tool of claim 54, wherein the fluid 6 transfer mechanism is coupled to the fluid 7 communication line for causing the substantially 8 transparent fluid to flow from the wellbore into 9 the fluid chamber.

11 56. The imaging tool of claim 46, wherein the device 12 for providing the seal is a packer.

13 14 57. A method for imaging a work site of interest located within a wellbore below a surface 16 location, the wellbore containing a 17 substantially non-transparent fluid therein, 18 said method comprising:

19 (a) setting a fluid seal a predetermined distance above the work site; 21 (b) displacing the substantially non 22 transparent fluid between the work site and 23 the seal with a substantially transparent 24 fluid; and (c) taking an image of the work site with a 26 camera placed between the seal and the work 27 site.

28 29 58. A method for imaging a work site of interest located within a wellbore containing a 71 I substantially non-transparent fluid therein, 2 said method comprising:

3 (a) conveying an imaging tool within the 4 wellbore to a location above the work site; (b) isolating and utilising at least one seal 6 of the work site; 7 (c) displacing the substantially non 8 transparent fluid in the work site with a 9 substantially transparent fluid; and (d) obtaining an image of the work site with 11 the imaging tool.

12 13 59. The method of claim 58 further having a circuit 14 within the imaging tool for communicating the image to a surface location.

16 17 60. An imaging tool for obtaining an image of a work 18 site of interest within a wellbore, comprising:

19 (a) a tool body conveyable into the wellbore; (b) a flexible inflatable device on the tool 21 body having a plurality of spaced sensors 22 arranged at a plurality of predetermined 23 surface locations on the inflatable 24 flexible device, each such sensor providing a signal in response to deformation of the 26 surface locations of the flexible 27 inflatable device at which such sensor is 28 placed relative to a predetermined norm for 29 such sensor; and (c) a computer, said computer receiving signals 31 from the sensors in the plurality of 72 1 sensors when the inflatable flexible device 2 is inflated and urged against the work site 3 and in response thereto providing an image 4 of the work site.

6 61. The imaging tool of claim 60, wherein the 7 computer is located at a surface location.

8 9 62. The imaging tool of claim 60, wherein the computer is located within the imaging tool for 11 computing the image of the work site downhole 12 during operation of the imaging tool.

13 14 63. The imaging tool of claim 60, wherein the imaging tool transmits data to the computer 16 representative of an image of the work site 17 determined from the sensors in the plurality of 18 sensors.

19 64. The imaging tool of claim 60 further having a 21 fluid injection system for injecting a fluid 22 into the inflatable flexible device.

23 24 65. A downhole oilfield service tool for imaging a work site in a wellbore and for performing a 26 desired operation at the work site during a 27 single trip of the service tool conveyed into 28 the wellbore by a tubing extending from a 29 surface location toward and adjacent to the work site, comprising:

73 I an imaging device adjacent a lower end of 2 the tubing for providing an image of the 3 work site; and 4 (b) an end work device adjacent the lower end of the tubing for performing the desired 6 operation at the work site based at least 7 partially upon the image of the work site 8 during the single trip of the service tool 9 in the wellbore.

74 Amendments to the daims have been riled as follows -75 1 CLAIMS 2 3 1. A downhole service tool, comprising:

4 (a) a packer adjacent a lower end of the tool, said packer having a packing member on a housing 6 that forms a seal between.the housing and a 7 work site in a pre-existing wellbore when a 8 fluid is injected into the packing member; and 9 (b) a sensor uphole of the packer for providing data representative of an image of the work 11 site when the downhole tool is conveyed into 12 the wellbore for setting the packer in the 13 wellbore.

14 2. A downhole service tool as claimed in Claim 1 and 16 substantially as hereinbefore described with 17 reference to the accompanying drawings.