AU770991B2 - Downhole service tool - Google Patents

Description

P/00/011 Regulation 3.2

AUSTRALIA

Patents Act 1990

ORIGINAL

COMPLETE

SPECIFICATION

STANDARD

PATENT

Invention Title: Apparatus and method for performing imaging and downhole operations at work site in wellbores The following statement is a full description of this invention, including the best method of performing it known to us: Cranted 25 Jaur 002k (10:27) page 2 s ane. rn ead le Ivie lbourne\003985418YY~)4~ t Printed 25 January 2002 (10:27) page 2 1 DOWNHOLE SERVICE TOOL 2 3 Field of the Invention 4 This invention relates generally to downhole tools 6 for use in wellbores and more particularly to a 7 downhole service tool incorporating a sensor for 8 imaging worksites.

9 Background of the Invention 11 12 To produce hydrocarbons (oil and gas) from the 13 earth'.s formations, wellbores (also referred to in 14 industry as boreholes) are formed to desired depths.

The shallow portion of the wellbore is typically 16- large in diameter, which is lined with a metal casing 17 to prevent caving of the wellbore. The wellbore is 18 then drilled to a desired depth to recover 19 hydrocarbons from the subsurface formations. After the wellbore has been drilled, a metal pipe, 21 generally referred to in the art as the casing or 22 pipe, is set in the wellbore by injecting cement 23 through the annulus between the casing and the 24 wellbore. Branch or lateral wellbores are frequently 25 drilled from a main wellbore to form deviated or 26 horizontal wellbores for improving production of -27 hydrocarbons from the subsurface formations.

28 29 A large proportion of the current drilling activity 30 involves directional drilling, drilling 31 deviated and horizontal wellbores, to improve the 1 hydrocarbon production and/or to withdraw additional 2 hydrocarbons from the earth's formations. The 3 wellbores are then completed and put into production.

4 The drilling and completion processes involve a number of different operations. Such operations may 6 include cutting and milling operations (including 7 cutting relatively precise windows in the wellbore 8 casings), sealing junctures between intersecting 9 wellbores, welding, re-entering lateral wellbores perforating, setting devices such as plugs,.sliding 11 sleeves, packers and sensors, remedial operations, 12 sealing, stimulating, cleaning, testing and, 13 inspection including determining the quality and 14 integrity of a juncture, testing production from a perforated zone or a portion thereof, collecting and 16 analysing fluidsamples, and analysing cores.

17 18 Oilfield wellbores usually continue to produce 19 hydrocarbons for many years. Various types of operations are performed during the life.of producing 21 wellbores. Such operations include removing, 22 installing and replacing different types of devices, 23 including fluid flow control devices, sensors., 24 packers or seals, remedial work including sealing off 25 zones, cementing, reaming, repairing junctures, 26 milling and cutting, freeing stuck sleeves, diverting 27 fluid flows, controlling production from perforated 28 zones, setting sleeves, and testing wellbore 29 production zones or portions thereof.

S* 31 Typically, to perform downhole operations at a work 1 site in a pre-existing wellbore, whether during the 2 drilling, completion, production, or servicing and 3 maintaining the wellbore, a desired tool is conveyed 4 downhole, positioned into the wellbore at the work site and the desired operation is performed. Most of 6 the prior art tools are substantially mechanical 7 tools or electro-mechanical. tools. Such tools lack 8 downhole manoeuvrability, in that the various 9 elements of the tools do not have sufficient degrees of freedom of movement, lack local or downhole 11 intelligence, do not obtain sufficient data with 12 respect to the work site or of the operation being 13 performed, do not provide an image of the work site 14 during the trip made for performing the end work, and do not provide confirmation of the quality and 16 integrity of the work performed. Such prior art 17 tools usually require multiple trips downhole to 18 image a work site, perform an operation and then to 19 confirm whether the operation has been properly performed. Multiple downhole trips can be very 21 expensive, due to the rig or production down time.

22 o* 23 SUMMARY OF THE INVENTION 24 25 The present invention provides a downhole service 26 tool comprising: 27 a packer adjacent a lower end of the tool, said 28 packer having a packing member on a housing that 29 forms a seal between the housing and a work site 30 in a pre-existing wellbore when a fluid is 31 injected into the packing member; and •go oooo 1 a sensor uphole of the packer for providing data 2 representative of an image of the work site when 3 the downhole tool is conveyed into the wellbore 4 for setting the packer in the wellbore.

6 Any suitable imaging device may be utilised for the 7 purpose of this invention, including a camera for 8 optical viewing, microwave device, contact device 9 (tactile device) such as a probe.or a rotary device, an acoustic device, ultrasonic device, infra-red 11 device and radio frequency device.

12 13 The downhole tool preferably includes a computer or 14 processor and associated memory for storing therein models and programs for controlling the operations of 16 the imaging device and the end work device. A 17 surface computer receives the data from the downhole 18 tool and displays the image of the work site for use 19 by an operator. A two-way telemetry system provides communication between the surface computer and the 21 downhole tool.

22 23 The operation of the imaging device and the packer 24 may be controlled from the surface and/or by the 25 computer or processor in the downhole tool.

26 27 BRIEF DESCRIPTION OF THE DRAWINGS 28 29 For a detailed understanding of the present invention, reference should be made to the following 31 detailed description of the preferred embodiment,

•BOO

1 taken in conjunction with the accompanying drawings, 2 in which like elements have been given like numerals, 3 and wherein: 4 FIGS. 1 and 1A are schematic diagrams of a system 6 utilising a service tool conveyed into a wellbore for 7 imaging a work site in the wellbore and performing a 8 desired operation at the work site during a single 9 trip.

11 FIG. 2A is a schematic diagram of an embodiment of a 12 downhole .(service) tool having an ultrasonic imaging 13 sensor for imaging a work site downhole of the 14 service tool and an end work device for performing a desired operation at the work site during a single 16 trip.

17 18 FIG. 2B is a schematic diagram of an alternative 19 embodiment of a downhole tool having an ultrasonic imaging sensor for radially imaging a work site and 21 an end work device for performing a desired operation 22 at the work site during a single trip.

23 24 FIG. 2C is a schematic diagram of yet another 25 embodiment of a downhole service tool having an 26 ultrasonic imaging sensor for radially imaging a work 27 site and an end work device for performing a desired 28 operation at the work site during a single trip.

29 30 FIG. 2D shows the downhole service tool of FIG 2A 31 positioned adjacent a wellbore juncture desired work e *ooo 1 site in a pre-existing wellbore.

2 3 FIG. 3A shows a schematic diagram of an embodiment of 4 an imaging tool for obtaining still and/or video pictures of object downhole.

6 7 FIG. 3B shows a schematic diagram of the imaging tool 8 of FIG 2D positioned adjacent to a juncture between a 9 main wellbore and a branch wellbore.

11 FIG. 3C shows a schematic diagram of an inflatable 12 imaging tool position at a wellbore juncture for 13 determining a contour of the juncture.

14 FIG. 3D shows a configuration of the placement of 16 sensors in the inflatable member used in the imaging 17 tool of FIG. 3C.

18 19 FIG. 4 is a schematic diagram of an embodiment of a downhole tool having an imaging device and an 21 inflatable packer wherein the imaging device is 22 adapted to obtain images during setting of the 23 inflatable packer in a wellbore.

24 25 FIG. 5 is a schematic functional block diagram 26 relating to the general operation of the downhole 27 imaging and servicing tools of the present invention.

28 29 DETAILED DESCRIPTION OF PREFERRED EMBODIMENT 31 The present embodiment combines an imaging device and gee e* ee 1 a packer. Fig. 1 gives an overview of the apparatus 2. in use. Figs. 2 and 3 provide further detail of 3 imaging devices which may be used. Fig. 4 provides 4 further detail of the packer. Fig. 5 gives one example of a control arrangement.

6 7 FIG. 1 is a schematic diagram of a system 100 for use 8 in oilfield wellbores for imaging a work site, 9 communicating data about the image to the surface and performing a desired operation .(endwork) at the work 11 site during a single trip in the wellbore. The 12. system 100 includes a downhole service tool 200 (also 13 referred to herein as the downhole tool or the 14 service tool) conveyed from a platform 11 of a rig 12 into a wellbore 22 by a suitable conveying device 24 16 :from a source 66 thereof, such as a reel, being 17 operated by a prime mover 68. As an example, and not 18 as any limitation, FIG. 1 shows the conveying device 19 24 to be a coiled-tubing. Other conveying methods, such as wireline or robotics devices may also be 21 utilised. The upper end 202 of the service tool is 22 connected to the tubing 24 via a suitable connector 23 204. During operations, a drilling fluid from a 24 source thereof 60 may be supplied to the wellbore 22 by a pump 68.

S26 27 A surface control unit 70 placed at a suitable 28 location on the rig platform 11 preferably controls 29 the operation of the system 100. The control unit includes a suitable computer and memory for 31 processing data, providing selected information to an eeo o* eeoc 8 1 operator on a display 72, including images of the 2 work site, logs during tripping of the wellbore, 3 location (depth) of the tool 200 in the wellbore and 4 orientation of the various elements of the service tool 200 in the wellbore 22 and values of selected 6 tool, formation and wellbore parameters. The data 7 from the service tool 200 may be transmitted to the 8 surface by a suitable data link (telemetry) and 9 recorded by a recorder 75 for later use. Suitable alarms 74, coupled to the control unit 70, are 11 selectively activated by the control unit 70 when 12 certain operating parameters exceed their respective 13 limits. The operation of control units, such as the 14 control unit 70, is known and is, thus, not described in' detail herein.

16 17 The service tool 200 includes one or more imaging 18 devices or image sensors 210 for imaging work sites 19 downhole, one or more end work devices 212a-212b, one or more. control mechanisms (hydraulic or electro- 21 mechanical) 214 for controlling the operation of the 22 end work devices 212a-212b and/or the imaging devices 23 210. The tool 200 may also include other sensors and 24 devices, generally denoted herein by numeral 216, for determining desired parameters or characteristics 26 relating to the tool 200 and the wellbore 22. Such 27 sensors and devices may include devices for measuring 28 temperature and pressure inside the tool 200 and in 29 the wellbore 22, sensors for determining the depth of the tool in the wellbore 22, position y and z co- 31 ordinates) of the tool 200, inclinometer for o* o *ooo 1 determining the inclination of the tool 200 in the 2 wellbore 22, gyroscopic devices, accelerometers, 3 devices for determining the pull force, centre line 4 position, gripping force, tool configuration and devices for determining the flow of fluids downhole.

6 7 The tool 200 further may include one or more 8: formation evaluation tools for determining the 9 characteristics of the formation surrounding the tool in the wellbore. Such devices may include gamma ray 11 devices and devices for determining the formation 12 resistivity. The tool 200 may include devices for 13 determining the wellbore inner dimensions, such as 14 calipers, casing collar locator devices for locating the casing joints and determining and correlating 16 tool 200 depth in the wellbore 22, casing inspection 17 devices for determining the condition of the casing, 18 such as casing 16 for pits and fractures. The 19 formation evaluation sensors, depth measuring devices, casing collar locator devices and the 2:1 inspection devices may be used to log the wellbore 22 while tripping into and or out of the wellbore 22.

g23 24 The service tool 200 preferably includes a central *9o°° o electronic and data processing unit or downhole 26 control unit or circuit 218 for receiving signals and 27 data from downhole devices, processing such data, 28 communicating with the surface control unit 70 and e ee o29 for controlling the operations of the downhole o devices. The control unit 218 preferably includes 3mcmto 31 one or more processors (micro-controllers or microoo oo o••oo 1 processors) for performing data manipulation 2 according to programmed instructions provided thereto 3 from the surface or stored in memory in the downhole 4 tool 200.

6 The service tool 200 preferably includes a two-way 7 telemetry 220 that includes a transmitter for 8 receiving data including the image data, from the 9 .control unit 218., downhole sensors and devices and transmits signals representative ;of such data to the 11 surface control unit 70. Any suitable transmitter 12 may be utilised for the purpose of this invention 13 -including an. electro-magnetic transmitter, a fluid 14 acoustic transmitter, a tubular fluid transmitter, a mud pulse transmitter, a fiber optics device and a 16 .conductor. The telemetry system 220 also. includes a 17 receiver which receivers signals transmitted from the 18 surface control unit 70 to the tool 200. The 19 receiver communicates such received signals to the variousdevices in the tool via the control unit 218 21 as explained later in reference to FIG. 22 23 Still referring to FIG. 1, the imaging sensor or 24 -device 210 may be any. suitable sensor including a camera for optical viewing, microwave device, contact 26 device (tactile device), such as a probe or a rotary 27 device, an acoustic device, ultrasonic device, infra- 28 red device, or RF device. The imaging sensor 210 may 29 be a non-contacting device, such as an ultrasonic device, or a contacting device that has one or a 31 series of projections from the tool 200 that engage ooo9 1 with the wellbore and objects in the wellbore. If 2 the quality or resolution of the image of the work 3 site provided by the imaging device 210 depends, at 4 least in part, on the frequency of the transmitted signal by the imaging device 210, then it is 6 preferred to adapt the device to sweep the frequency 7 in a predetermined range of frequencies to determine 8 an effective frequency and then obtain the image at 9 such effective frequency. The imaging sensor 210 may be employed to provide a still or motion picture of a 11 work site or an object downhole, or to determine the 12 general shape of the object of the work site or to 13 distinguish certain features of the work site prior 14 to, during and/or after the desired operation has been performed at the work site.

16 17 Still referring to FIG. 1 the end work devices 212a 18 and 212b include a packer, as described below. The 19 end work devices 212a-212b may additionally include a fishing tool adapted to grab a fish downhole, 21 whipstock, diverter, re-entry tool, seal, plug, 22 perforating tool, fluid stimulation tool, fluid 23 fracture tool, milling tool, cutting tool, drilling 24 tool, workover tool, testing tool, cementing tool, 25 welding tool, an anchor, acidizing tool or inspection 26 tool.

27 28 Additionally, the service tool 200 may include 29 downhole controllable stabilisers 219a and 219b, each 30 such stabiliser having a plurality of independently 31 adjustable pad segments for providing lateral *e* eeo** 1 movement and lateral stability to the tool 200 and 2 for anchoring the tool 200 in the wellbore 22. Such 3 stabilisers are especially useful in deviated and 4 horizontal wellbores. A plurality of ihdependently controlled outwardly extending arms 219c may be 6 utilised to provide lateral movement and stability to 7 the tool 200 within the wellbore 22. For a majority 8 of the downhole imaging and servicing applications 9 the end work device utilised is designed for the specific application. In some applications, several 11 end work devices may be incorporated into the service 12 tool 200. To provide desired degrees of freedom for 13 each of the end work devices 212a-212b and the 14 imaging device 210, such devices are coupled to the tool via knuckle joints, such as joints 212a', 212b' 16 and 210a respectively. The movement of such knuckle 17 joints is preferably controlled by the control unit 18 218. The degrees of freedom present in the tool 200 19 and the type.of image sensor utilised preferably allow obtaining the image of any work site in the 21 wellbore.

22 23 The service tool 200 is preferably modular in design, 24 in that selected devices in the tool are individual 25 modules that can be interconnected to each other to 26 assemble the desired configuration of the tool 200.

27 It is preferred to form the image device 210 and the 28 end work devices 212a-212b as modules so that they 29 can be placed in any order in the tool 200. Also, 30 each of the end work devices 212a-212b and the image 31 device 210 have independent degrees of freedom so o*o* 1 that the tool 200 and any of the devices can be 2 positioned, maneuvred and oriented in the wellbore 3 in substantially any desired manner to perform the 4 desired downhole operations.

6 The service tool 200 may be conveyed into the 7 wellbore by a wireline, a coiled-tubing, a drill 8 pipe, a downhole thruster or locomotive for pushing 9 the tool 200 into a horizontal wellbore or a robotics device on the tool to move and guide the service tool 11 in the wellbore.

12 13 As shown in FIG. 1A, the end work device 212' or any 14 other device in the tool 220 may have independently controlled downhole movements, such as shown by the 16 solid lines 212'a and dotted lines 212'b, which allow 17 the device 212' to be positioned at any angle in, the 18 wellbore 22. Thus, the service tool 200 can be 19 positioned adjacent to a work site in a wellbore, image the work site, communicate such images online 21 to the surface, perform the desired work at the work .22 site, and confirm the work performed during a single 23 trip into the wellbore.

24 25 FIGS. 2A-2C show embodiments of downhole ultrasonic 26 imaging devices for use with an end work device to 27 image a work site of interest and to perform a 28 desired operation at the work site during a single 29 trip into the wellbore.

31 FIG 2A shows a downhole service tool 250 having an **oo *ooo* 1 end work device 252 for performing a desired 2 operation downhole, an ultrasonic device 260 3 (ultrasonic imaging sensor) placed downhole of the 4 end work device 252 for imaging a work site or an object in the wellbore. The imaging device 260 has a 6 number of sensor elements 264 arranged on a body.

7 Each sensor element 264 acts as a transmitter and 8 receiver. The preferred frequency range is between 9 100 KHz and 500 KHz. The ultrasonic transmitter is preferably adapted to sweep the frequency within a 11 predetermined range of frequencies. The signals 12 transmitted by the sensor element 264 are reflected 13 back from the work site or the object and the 14 reflected signals are received by the sensor elements 264, which are processed by the control unit 256 or 16 circuit in the tool 250 and transmitted uphole via 17 telemetry 258 to provide an image of the work site.

18 19 The ultrasonic sensor 260,may be rotated or beam steered electrically rotating or directing) to 21 scan the inside of the wellbore. The ultrasonic 22 signals are transmitted at a predetermined rate and eeoc 23 the reflected signals are received by the sensor oooe 24 elements 264 between successive firings of the 25 transmitter. The end work device 252 may include a 26 work element 253 that may be rotated by device 254 27 along the arrows 252a to orient the work element 28 radially and may be moved vertically as shown by the ooo• 29 arrows 252b, longitudinally to move the work 30 element 253 uphole or downhole, which enables S31 positioning the work element at any desired location o ooeo1 oitonn oooo 1 in the wellbore. The sensor 260 and the end work 2 device 252 are independently rotatable. The sensor 3 260 may be disposed above the end work device 252.

4 As shown in the tool 250' of FIG. 2B, the sensor 6 elements 264' may be arranged on the body 255 of the 7 end work device 252' around the end work element 8 253'. The sensor elements 264' may be disposed in 9 any desired manner to image a segment of the wellbore or the entire wellbore interior. The tool may be 11 moved along the directions denoted by arrows 252a' 12 and 252b'. The_vertical length of the sensor 13 elements 264' and the spacing there between defines 14 the vertical imaging sweep and the resolution.

Similarly, the horizontal distance of the.sensor 16 elements 264' and the spacing between the sensor 17 elements defined the radial sweep and the resolution.

18 Alternatively, sensor elements may be arranged on the 19 tool to direct signals .downhole, as shown in FIG. 2C here the sensor elements 264" are disposed at the 21 downhole (bottom) end of a service tool 250". This 22 enables the service tool 250" to image an object or a 23 work site downhole of the service tool 250".

24 24 25 FIG. 2D shows the downhole service tool 250, shown in 26 FIG. 2A, positioned adjacent to a juncture 304 27 between a main wellbore 300 and a branch or lateral 28 wellbore 302. The tool 250 may be utilised to image 29 the juncture 304 and perform an operation thereat.

The tool 250 provides an image of the juncture 304 to 31 the surface prior to performing an operation. The o* 1 image may be utilised to position the tool 250 at the 2 desired location and to appropriately orient the tool 3 250 adjacent the juncture 304. The tool 250 may then 4 be operated at the juncture 304.

6 FIG. 3A shows a schematic diagram of a system 710 for 7 obtaining still and/or video images of a wellbore 8 interior or an object in the wellbore. The system 9 710 includes a downhole tool 720 that contains a camera for taking pictures of the work site and a 11 mechanism for displacing the non-transparent fluid 12 around the work site with a transparent or 13 substantially transparent fluid. For convenience and 14 ease of explanation and understanding, and not as a limitation system 710 shows only the imaging device, 16 i.e. without any end work device.

17 18 The system 710 includes a downhole imaging tool 720 19 conveyed from a platform 11 of a derrick 12 into a wellbore 122 by a suitable conveying device 124, such 21 as a tubing or wireline. The imaging tool 720 has a 22 tubular housing 726, which is adapted for connection g 23 with the conveying device 724 via a suitable 24 connector 719. The housing 726 contains the various •ego S"25 elements of imaging tool 720. The bottom section of oooo 26 the housing 726 contains a camera section 728, which 27 houses a retractable camera 730. The camera 730 may 28 be moved within a camera housing 732 by a hydraulic ooo .29 means or an electric means, such as motor, generally denoted herein by numeral 734. The electrical 3ioooo 31 circuits and downhole power supplies for operating •go cote 1 and controlling the camera movements are preferably 2 placed in a common electrical circuit section 736.

3 Electrical connections between the camera section 728 4 and the electrical circuit section 736 are provided through suitable wires and connectors between the two 6 sections. The camera 730 in its retracted position, 7 as shown by the solid lines 730, may be sealed from 8 the outside environment by closing a hatch or door 9 738. The hatch may be adapted to open outward as shown by the dotted line 738a or by a sliding door 11 (not shown). In the fully retracted position, the 12 camera 730 resides completely inside the housing 728 13 so that the hatch 738 may be closed to seal the 14 camera 730 from the outside environment.

16 In the fully extended position, the camera 730 17 extends far enough from the camera section 728 or any 18 other obstruction, as shown by the dotted line 730a, 19 so that the camera 730 can be rotated 360 degrees and can take unobstructed pictures of its surroundings.

21 A light source 740 attached near the camera provides sufficient light for the camera to obtain pictures ge 23 downhole. Additional light sources (not shown) may 24. be provided on the tool body 726 to provide light in 25 all the directions. The camera 730 may be focused 26 downward as shown in FIG. 3A or horizontally as shown 27 in FIG. 3B or along any other desired direction 28 depending upon the intended application.

o 29 good 30 The imaging tool 720 contains a fluid injection 31 section 744 for injecting a substantially transparent oooo o o o* o 1 fluid (herein referred to as the clear fluid) into 2 the wellbore. The fluid injection section 744 is 3 preferably placed above (uphole) the camera section 4 728. The fluid injection section 744 includes one or more chambers, such as 746a and 746b, for storing 6 therein the clear fluid. A pump 746 in the section 7 744 is used to controllably inject the clear fluid 8 from the chambers 746a-746b into the wellbore below 9 the camera section 728 via a fluid line 748. The fluid line 748 runs from the fluid injection section 11 744 through the camera section 728 to an outlet point 12 748a below the camera section 728. Any downhole 13 electrical control circuits and related power 14 supplies for operating the pump 746 are preferably housed in the electrical section 736.

16 17 A surface control unit 770 placed at a suitable' 18 location on the rig platform 711 preferably controls 19 the operation of the imaging system 710. The control unit. 770 includes a suitable computer, associated 21 memory, a recorder for recording data and a display 22 or monitor 772. The operation of control units, such 23 as the control unit 770, is known and is, thus, not 24 described in detail herein.

26 The operation of the imaging system 710 will now be 27 described in reference to obtaining an image of an 28 object, such as object 750, stuck in the wellbore 29 722. To obtain the image of the object 750, the 30 location of the object is first determined. A number 31 of techniques have been utilised in the oilfield o S S 1 applications for determining the location of an 2 object or work site in a wellbore. Any such 3 technique or method may be utilised for determining 4 the location of the object 750 for the purposes of this invention. The tool 720 is then conveyed into 6 the wellbore 722 until the bottom end 752a of the 7 fluid return pipe 752 is below the surface 750a of 8 the object 750 that is to be imaged. The packer 733 9 is then inflated or set in the wellbore 722 to seal the wellbore section 722a below the camera section 11 728 from the wellbore section 722b above the packer 12 733. The pump 746 is then activated from the surface 13 control unit 770 to inject the clear fluid from the 14 chambers 746a-b into the wellbore section 722a via fluid line 748. The injection of the clear fluid 16 into the section 722a causes the wellbore fluid 17 present in the section 722a to enter the fluid pipe 18 752, which fluid is discharged into the wellbore 19 section 722b above the packer 733 via a port 752b.

This process is continued until the wellbore fluid 21 between the port 752a and the camera section 728 has 22 been replaced with the clear fluid. The clear fluid 23 chosen is preferably lighter than the wellbore fluid 24 and will not mix with the wellbore fluid. Such a 25 clear fluid when injected into the wellbore section 26 722a will uniformly displace the wellbore fluid. In 27 some applications, it may be necessary to continue to 28 inject additional clear fluid so as to completely 29 flush out the wellbore fluid from section 722a. The 30 system of the present invention may employ a clear 31 fluid source at the surface (not shown) instead of oooo 1 downhole chambers. In this embodiment, the clear 2 fluid is continuously supplied to the chamber 746 3 from a surface source via a line placed in the 4 conveying means 724. Such a system may be necessary when large quantities of clear fluid are required to 6 flush out the wellbore fluid.

7 8 After the object 750 has been exposed to the clear 9 fluid, the camera door 738 is opened and the camera 730 is lowered to its fully extended position 730a.

11 To obtain the images of the object 750, the camera 12 lights 740 are activated, the camera 730 is oriented 13 in a desired position and the camera is operated to 14 obtain images of the object 750. The images from the camera are transmitted by the downhole control 16 circuits in section 736 to the surface control unit 17 770 via a two-way telemetry 725. The images are 18 displayed on the monitor 772. The operator can 19 orient the camera in any desired direction and continue to obtain images. If a video camera is 21 used, the motion pictures are displayed on the 22 monitor. The images are recorded in the recorder 23 associated with the surface control unit 770.

0 25 FIG. 3B shows the application of the imaging system *o 26 710 described above in reference to FIG. 2D for 27 obtaining images of a junction 760 between a main 28 wellbore 722 and a branch wellbore 723. To obtain eeoc 29 images of the junction 760, a packer 735 is first set in the wellbore 722 below the junction 760 to 31 completely seal off the wellbore section 22c lying eo*e coo eeoc 1 below the packer 35. The imaging tool 720 is then 2 conveyed in the wellbore 722 so that the packer 33 is 3 completely above the junction 760 while the port 752a 4 of the fluid return line 752 is below the junction 760. The imaging tool 720 is operated as described 6 earlier to displace the wellbore fluid in the 7 wellbore section 722a' between the packers 733 and 8 735 with the clear fluid. The camera 730 is then 9 oriented in the direction of the junction 760 to obtain the desired images. Images of other objects 11 in the wellbore and any section of the wellbo~e may 12 be obtained by the imaging system 710 in the above- 13 described manner.

14 FIG. 3C shows another embodiment of a downhole 16 imaging tool 800. The imaging tool 800 includes a 17 flexible inflatable device 810 at a lower end of the 18 tool 800. A fluid injection system 812 in the tool 19 800 injects a fluid into the device 810, thereby inflating the device 810. The fluid injection system 21 812 preferably contains a fluid pump section 814 22 having a reversible pump therein for injecting or 23 pumping a fluid from a chamber 816 into the device i. 24 810 and vice versa.

S26 FIG. 3D shows a cross section of the flexible 27 inflatable device 810. It includes a bladder 840 28 made from a flexible material, such as rubber. A eeoc 29 plurality of sensors 842 are arranged along the inner surface 840a of the bladder 840 in a matrix or grid 3oeasr 31 as shown in FIG. 3D. Each such sensor provides a oO*o oooo ooooo 1 signal corresponding to the deformation of the 2 bladder surface to which the sensor is attached from 3 a predetermined norm. The signals from each such 4 sensor are transmitted to a downhole control circuit 816 via a conductor 844 and communication link 848.

6 Fluid line 846 provides access to the bladder inside 7 840a. The downhole control circuit 816 controls the 8 operation of the pump section 812, receives data or 9 signals from each-of the sensors 842, conditions,the signals and may manipulatethe signals to obtain an 11 image. The downhole control circuit 816 may transmit 12 the conditioned signals to a surface control unit, 13 such as unit 970 shown in FIG. 5, which produces the 14 image based on a model stored in the control unit.

The model is predetermined or predefined based on the 16 geometry of the flexible member 810 and the 17 configuration of the sensors 842. The model is 18 stored in a downhole memory associated with the 19 downhole control circuit 816 when the system is designed to compute the model downhole.

21 22 Operation of the tool 800 will now be described in 23 the context of obtaining an image of a junction 24 between the main wellbore 822 and the branch wellbore 823. To obtain an image of the junction 860, the 26 tool 800 is conveyed into the main wellbore 822 until 27 the flexible member is adjacent to the junction 860.

28 The fluid from the fluid section 812 is then injected ooo• 29 into the flexible member 810, thereby inflating the ooo member 810. A portion of the flexible member at the 3ieehs 31 junction 860 attains the shape that corresponds to e ee eeoc ooeoo 1 the junction 860 outline. The downhole control 2 circuit 816 measures the signals from each of the 3 sensors 842 and processes such signals as described 4 above to obtain the image of the junction. Image of an object in the wellbore, such as object 850 shown 6 in FIG. 3B, is obtained by inflating the flexible 7 member 810 while urging it against the object.

8 9 FIG. 4 shows a service tool 400 with an imaging device 420 and a packer 410 as the end work device.

11 The service tool 400 is shown conveyed by a tubular 12 402 into an open hole 404. The packer 410 has an 13 inflatable packer element 412, which when inflated 14 seals an annulus between the-packer 410 and the wellbore 404. The packer 410 is attached to the 16 tubular 402 by a shear bolt 406 having a weak point 17 406a that may be sheared to separate the packer 410 18 from the tubular 402. An imaging device 420 for 19 imaging the annulus 407 between the packer 410 and the wellbore 404 is placed above the shear point :21 406a.

S...22 23 To set the packer element 412 in the annulus 407, the 24 tool 400 is positioned in the wellbore 404 so that 25 the packer 410 is across from the area 407. The 26 packer 410 is set by injecting a hardening fluid, 27 such as cement, epoxy, or another suitable material, 28 into the packer element 412. If an acoustic device ooo 29 is used as the imaging device, its response oooo characteristics are a function of the manner the 3lelta 31 annulus is being enclosed with the hardening •go• 99 9 .9o9 999999 1 material. The data from the imaging device 420 is 2 analysed to determine the quality of the bond between 3 the packer element 412 and the formation 404. Based 4 on the imaging characteristics, the amount of the hardening material being supplied to the packer 6 element 412 can be adjusted to improve the integrity 7 of the seal. After the packer 410 has been set, the 8 bolt 406 is sheared to retrieve the service tool 400 9 from the wellbore 404.

11 It is often desirable to measure selected wellbore 12 and formation parameters either prior to or after 13 performing an end work. Frequently, such information 14' is obtained by logging the wellbore prior to performing the end work, which typically requires an 16 extra trip downhole. The service tool of the present 17 invention, such as tool 200 shown in FIG. 1, may 18 include one or more logging devices or sensors. For 19 example, for the work to be performed in cased holes, a collar locator may be incorporated in the service.

21 tool 200 to log the depth of the tool 200 while 22 tripping downhole. Collar locators provide 23 relatively precise measurements of the wellbore depth 24 and can be utilised to correlate depth measurement made from surface instruments, such as wheel type 26 devices. The collar locator depth measurements can 27 be utilised to position and locate the imaging and 28 end work devices of the tool 200 in the wellbore.

ego• S. 29 Also, casing inspection devices, such as eddy current devices or magnetic devices may be utilised to 31 determine the condition of the casing, such as pits eeoc eeoc 1 and cracks. Similarly, a device to determine the 2 cement bond between the casing and the formation may 3 be incorporated to obtain a cement bond log during 4 tripping downhole. Information about the cement bond quality and the casing condition are especially 6 useful for wellbores which have been in production 7 for a relatively long time period or wells which 8 produce high amounts of sour crude oil or gas.

9 Additionally, resistivity measurement devices may be utilised to determine the presence of water in the 11 wellbore or to obtain a log of the formation 12 resistivity. Similarly gamma ray devices may be 13 u-tilised to measure background radiation. Other 14 formation evaluation sensors may also be utilised to provide corresponding logs while tripping into or out 16 of the wellbore.

17 18 The description thus far substantially relates to a 19 service tool which utilises an image sensor and packer to image a work site in a wellbore and set the 21 packer. As described earlier, the service tool of 22 the present invention also provides confirmation :g 23 about the quality and effectiveness of the end work 24 performed downhole during the same trip. The general operation of the above-described tool is described by 26 way of an example of a functional block diagram for 27 use with the system of FIG. 1. Such operations will 28 now be described while referring to FIG. 29 30 The downhole section of the control circuit 900 31 preferably includes a microprocessor-based downhole o *o *ooo 1 control circuit 910. The control circuit 910 2 determines the position and orientation of the tool 3 as shown in box 912. A circuit 915 controls the 4 operation of the downhole tool. The control circuit 910 also controls the end work devices, that is, the 6 packer 914a and any other end work devices, generally 7 designated herein by numeral 914n. During 8 operations, the control circuit 910 receives 9 information from other downhole devices and sensors, such as a depth indicator 918 and orientation 11 devices, such as accelerometers and gyroscopes. The 12 control unit 900 communicates with the surface 13 control unit 970 via the downhole telemetry 939 and 14 via a data or communication link 939a. The control circuit 910 also preferably controls the operation of 16 the downhole devices, such as the power unit 934, 17 stabilisers and other desired downhole devices (not 18 shown). The downhole control circuit 910 includes a 19 memory 920 for storing therein data and programmed instructions. The surface control unit 970 21 preferably includes a computer 930, which manipulates 22 data, a recorder 932 for recording images and other "*fe 23 data and an input device 934, such as a keyboard or a o. 24 touch screen for inputting instructions and for 25 displaying information on the monitor 972. The 26 surface control unit 970 and the downhole tool 27 communicate with each other via a suitable two-way 28 telemetry system.

0

Claims (7)

1. A downhole service tool; comprising; a packer adjacent a lower end of the tool, said packer having a packing member on a housing that forms a seal between the housing and a work site in a pre-existing wellbore when a fluid is injected into the packing member; and a sensor uphole of the packer for providing data representative of an image of the work site when the downhole tool is conveyed into the wellbore for setting the packer into the wellbore.

2. The downhole tool of claim 1, wherein the wellbore is a cased wellbore.

3. The downhole tool of claim 1 further comprising a memory positioned for recording data from the sensor for data retrieval when the service tool is brought back to the surface.

4. The downhole tool of claim 1 further comprising a memory pre-programmed with a work site data model for correlating data generated downhole with pre- programmed work site data to facilitate the identification of the work site.

The downhole tool of claim 4, wherein a transmitter generates signals for transmission to a surface location representative of the data of the work site data generated by the downhole tool. 20

6. The downhole tool of claim 5, wherein the transmitter communicates with other equipment positioned downhole in the wellbore.

7. The downhole tool of claim 1 further comprising a receiver associated with the downhole tool for receiving signals sent from the surface to the downhole tool, with the receiver communicating with a processor in the downhole tool. 25 Baker Hughes Incorporated By its Registered Patent Attorneys Freehills Carter Smith Beadle 16 January 2004 ooeol