CA2383316C - Apparatus and methods relating to downhole operations - Google Patents

Abstract

A communication system for use in a wellbore, a down-hole tool, and a method includes a transmitter coupled to a wireline, and a receiver located remotely from the transmitter. The wireline is capable of acting as an antenna for the transmitter. The wireline is a slickline, and the transmitter may be associated with, provided on, or an integral part of a downhole tool or tool string. The transmitter typically transmits data col-lected or generated by the downhole tool or the like to the receiver, which is preferably located at, or near, the surface of the wellbore. The wireline is typically provided with an insulating coating. Also, a distance measure-ment apparatus and a method for measuring the distance travelled by a wire-line includes at least one sensor coupled to the wireline, and the sensor is capable of sensing known locations in a wellbore.

Description

1 "Apparatus and Methods Relating to Downhole

2 Operations"

3

4 The present invention relates to apparatus and methods relating to downhole operations, and 6 particularly, but not exclusively, to wireline 7 operations.

9 Wireline is a term commonly used for the operation of deploying and/or retrieving tools or the like using a 11 wire, the wire being one of several different types 12 of construction. For example, slicklines are wires 13 which comprise a single strand steel or alloy piano-14 type wire which currently have a diameter of around 0.092 inches to 0.125 inches (approximately 2.34mm to 16 3.17mm) in use, with the possibility of increasing 17 this to 0.25 inches (approximately 6.25mm) in the 18 future.

1 Wirelines may also be of a braided construction which 2 can also carry single or multiple electrical 3 conductor wires through its core and is typically of 4 a diameter in the order of 3/16 of an inch (approximately 4.76mm) or above. Slick tubing, more 6 commonly known as coiled tubing, is in the form of a 7 continuous hollow-cored steel or alloy tubing which 8 is usually of a diameter greater than the preceding 9 types of wireline.

11 Wirelines are conventionally used to insert and/or 12 retrieve downhole tools from a wellbore or the like.
13 The downhole tools are typically deployed to perform 14 various downhole functions and operations such as the deployment and setting of plugs in order to isolate a 16 section of the wellbore. It is advantageous and 17 often essential to know the distance of travel of the 18 wireline so that the location of the tool within the 19 wellbore is known.

21 Wirelines are conventionally stored on a winching 22 unit typically located at the surface in the 23 proximity of the top of a borehole. It should be 24 noted that "surface" in this context is to be understood as being either atmospheric above ground 26 or sea level, or aquatic above the seabed. Although 27 the methods and apparatus employed in wireline 28 operations vary in detail, the wireline is commonly 29 introduced into the wellbore (the wellbore conventionally being cased, as is known) via a series 31 of sheaves or guide rollers. The sheaves or guide 1 rollers facilitate, in the first instance, a 2 substantially vertical orientation of the wireline.
3 The wireline passes through a substantially 4 vertically-orientated superstructure tube having an internal open-ended bore, the tube being positioned 6 on top of a wellhead. Thus, any downhole tool can be 7 introduced into the wellbore.

9 The wireline is coupled at its distal (downhole) end to the downhole tool, typically via a part of the 11 tool known as a rope-socket. The rope-socket is 12 conventionally used to provide a mechanical 13 connection between the wireline and the downhole tool 14 (or a string of downhole tools known as a tool string).

17 The conventional method of measuring the downhole 18 tool depth is to run the wireline against a measuring 19 wheel which is a pulley wheel of known diameter. It should be noted that use of "depth" in this context 21 is to be understood as being the trajectory length of 22 the downhole tool, which may be different from 23 conventional depth if the wellbore is deviated, for 24 example. In order to calculate the distance of travel of the wireline, a number of variable factors 26 must be known. It is a prerequisite that the 27 rotational direction of the pulley wheel, the number 28 of revolutions thereof, the diameter of the pulley 29 wheel and, depending upon the type of pulley wheel (that is, whether a point-type contact or arc for 31 example), the diameter of the wireline, must all be 1 known before the distance of travel of the wireline 2 within the wellbore can be calculated.

4 However, with this conventional method for calculating the distance of travel of the wireline, a 6 number of factors can render the calculation 7 inaccurate. The occurrence of wheel slippage, the 8 stretch of the wireline (due to the weight of the 9 wireline itself, and/or the weight of the tool string which is attached thereto), the effect of friction 11 and the well-contained fluid buoyancy all contribute 12 to decrease the accuracy of the tool depth 13 measurement.

In order to improve the accuracy of this conventional 16 depth measurement, it is known to combine the 17 measured tensile load, the known stretch co-efficient 18 of the wireline, and the conventionally measured tool 19 depth as described above, to recalculate the tool depth measurement on a continuous basis (ie in real 21 time) using a processing means, such as a computer or 22 the like.

24 However, the accuracy of the aforementioned depth measurement correction method relies on an 26 experimentally determined constant (ie the stretch 27 co-efficient of the wireline) and the surface 28 measurements on the wireline. The resulting 29 correction does not include the significant combined effect that well fluid temperature, tool buoyancy and 1 well geometry have on the accuracy of the depth 2 correction.

4 According to a first aspect of the present invention

5 there is provided distance measurement apparatus for

6 measuring the distance travelled by a wireline, the

7 apparatus comprising at least one sensor coupled to

8 the wireline wherein the sensor is capable of sensing

9 known locations in a wellbore.

11 The wireline is typically a slickline.

13 According to a second aspect of the present invention 14 there is provided a method of measuring the distance travelled by a wireline, the method comprising the 16 steps of coupling at least one sensor to the 17 wireline, the at least one sensor being capable of 18 sensing known locations in a wellbore; running the 19 wireline into the wellbore; calculating the depth of the at least one sensor using any conventional means;
21 generating a signal when the at least one sensor 22 passes said known locations; using the signal to 23 calculate a depth correction factor; and correcting 24 the calculated depth using the depth correction factor.

27 Preferably, the apparatus includes transmission means 28 for transmitting data collected by the at least one 29 sensor to a receiver located remotely from the apparatus. Preferably, the wireline is capable of 31 acting as an antenna for the transmission means.

2 The sensor may be coupled to the wireline at any 3 point thereon, or may form an integral part thereof.
4 The sensor is preferably coupled at or near a downhole tool whereby the distance travelled by the 6 tool (and thus its location within the wellbore) can 7 be calculated. Alternatively, the sensor may form 8 part of a downhole tool or the like.

The sensor typically comprises a magnetic field 11 sensor, and preferably an array of magnetic field 12 sensors. The array of magnetic field sensors are 13 typically provided on a common horizontal plane.
14 Alternatively, the sensor may comprise a radio frequency (RF) sensor, and preferably an array 16 thereof. Where an RF sensor is used, the wellbore is 17 typically provided with RF tags at known locations.

19 The wireline is preferably electrically insulated.

The wireline may be sheathed to facilitate electrical 21 insulation. Alternatively, the wireline may be 22 passed through a stuffing box or the like to 23 facilitate electrical insulation and/or isolation.

According to a third aspect of the present invention 26 there is provided a downhole tool comprising coupling 27 means to allow the tool to be attached to a wireline, 28 at least one sensor capable of detecting known 29 locations in a wellbore and generating a signal indicative thereof, and a transmission means capable 31 of transmitting the signal.

2 There is also provided a method of tracking a member 3 in a wellbore, the method comprising providing a 4 sensor on the member, inserting the member and sensor into the wellbore, obtaining information indicating 6 the position of the sensor in the wellbore, and 7 determining the distance travelled by said member 8 from said sensor information.

The wireline is preferably used as an antenna for the 11 transmission means.

13 The coupling means typically comprises a rope-socket.
14 The rope-socket is preferably provided with signal coupling means to couple the signal generated by the 16 transmission means to the wireline.

18 The sensor typically comprises a magnetic field 19 sensor, and preferably an array of magnetic field sensors. The array of magnetic field sensors are 21 typically provided on a common horizontal plane.
22 Alternatively, the sensor may comprise a radio 23 frequency (RF) sensor, and preferably an array 24 thereof. The array of RF sensors are typically provided on a common horizontal plane.

27 The downhole tool is preferably powered by a DC power 28 supply, and most preferably a local DC power supply.
29 The DC power supply typically comprises at least one battery.

1 According to a fourth aspect of the present invention 2 there is provided a wireline wherein the wireline is 3 provided with an insulating coating.

The insulating coating is typically an outer coating 6 of the wireline. The wireline typically comprises a 7 slickline.

9 The insulating coating typically comprises at least one enamel material. The enamel material typically 11 consists of one or more layers of coating whereby 12 each individual layer adds to the overall required 13 coating properties. Additionally, each layer of 14 enamel material preferably has the required bonding, flexibility and stretch characteristics at least 16 equal to those of the wireline.

18 The enamel material can typically be applied to the 19 wireline by firstly applying a thin layer of adhesive, such as nylon or other suitable primer.

21 Thereafter, one or more layers of an enamel material 22 such as polyester, polyamide, polyamide-imide, 23 polycarbonates, polysulfones, polyester imides, 24 polyether, ether ketone, polyurethane, nylon, epoxy, equilibrating resin, or alkyd resin or theic 26 polyester, or a combination thereof, are preferably 27 applied. The enamel material is preferably 28 polyamide-imide.

According to a fifth aspect of the present invention 31 there is provided a communication system for use in a 1 wellbore, the system comprising a transmitter coupled 2 to a wireline, and a receiver located remotely from 3 the transmitter, wherein the wireline is capable of 4 acting as an antenna for the transmitter.

6 The wireline is typically a slickline.

8 The transmitter is typically associated with, 9 provided on, or an integral part of a downhole tool or tool string, whereby the downhole tool or tool 11 string is typically suspended by the wireline.

13 The transmitter typically facilitates the 14 transmission of data collected by the downhole tool or the like to the receiver. The transmission means 16 typically comprises a transmitter. The receiver is 17 typically located at, or near, the surface.

19 optionally, the communication system is arranged whereby it can facilitate two-way communication 21 between the downhole tool and the receiver. In this 22 embodiment, a transmitter and a receiver are 23 typically located downhole. Additionally, a 24 transmitter and a receiver are also located at, or near, the surface. The transmitter and receiver at 26 the surface and/or downhole may be replaced by a 27 transceiver located downhole and at, or near, the 28 surface.

The transmitter may be coupled to the wireline at any 31 point thereon, or may form a part thereof. The 1 transmitter is typically coupled at or near a 2 downhole tool whereby the distance travelled by the 3 tool, the status of the tool or other parameters of 4 the tool, can be transmitted to the receiver.

5 Alternatively, the transmitter may form an integral 6 part of a downhole tool.

8 The wireline is preferably electrically insulated.

9 The wireline may be sheathed to facilitate electrical

10 insulation. Alternatively, the wireline may be

11 passed through a stuffing box or the like to

12 facilitate electrical insulation and/or isolation.

13

14 According to a sixth aspect of the present invention there is provided apparatus for indicating the 16 configuration of a downhole tool or tool string, the 17 apparatus comprising at least one sensor capable of 18 sensing a change in the configuration of the downhole 19 tool or tool string and generating a signal indicative thereof, and a transmission means 21 electrically coupled to the at least one sensor for 22 transmitting the signal to a receiver.

24 The downhole tool is preferably suspended in a borehole using a wireline, and the wireline is 26 preferably capable of acting as an antenna for the 27 transmission means.

29 The transmitter typically facilitates the transmission of data collected by the sensor to the 31 receiver. The transmission means typically comprises 1 a transmitter. The receiver is typically located at, 2 or near, the surface.

4 optionally, the communication system is arranged whereby it can facilitate two-way communication 6 between the downhole tool and the receiver. In this 7 embodiment, a transmitter and a receiver are 8 typically located downhole. Additionally, a 9 transmitter and a receiver are also located at, or near, the surface. The transmitter and receiver at 11 the surface and/or downhole may be replaced by a 12 transceiver located downhole and at, or near, the 13 surface.

The sensor typically comprises an electric or 16 magnetic sensor which is coupled to the downhole tool 17 wherein a discontinuity of the electric or magnetic 18 connection triggers a signal, or a plurality of 19 signals. These signals can then be transmitted to the surface to indicate the status of the tool. In 21 one embodiment, the sensor may be coupled between a 22 tool string and a downhole tool which is to be 23 deployed into a wellbore, wherein discontinuity of 24 the electric or magnetic connection indicates that the tool has been deployed. Alternatively, the 26 sensor may be coupled to a distal end of the tool 27 string, and the downhole tool which is to be 28 retrieved from a wellbore, is provided with a similar 29 sensor, wherein continuity of the electric or magnetic connection indicates that the tool has been 31 retrieved.

The sensor may also be coupled to part of a downhole tool which changes status during operation of the tool (ie a valve, sleeve or the like) wherein the sensor indicates the status of the part of the downhole tool by a change in continuity.

The sensor may comprise a proximity sensor, magnetic sensor or the like.

The wireline is preferably electrically insulated. The wireline may be sheathed to facilitate electrical insulation.
Alternatively, the wireline may be passed through a stuffing box or the like to facilitate electrical insulation and/or isolation.

According to another aspect of the present invention, there is provided a wellbore communication system, the system comprising a downhole tool coupled to a wireline, the downhole tool comprising a transmitter, wherein the downhole tool and wireline are adapted to be simultaneously deployed into the wellbore, at the surface thereof, and a receiver located remotely from the transmitter, characterised in that the wireline is capable of running the downhole tool into the wellbore and is also capable of acting as an antenna for the transmitter.

12a According to another aspect of the present invention, there is provided a method of communication in a wellbore, comprising providing a downhole tool comprising a transmitter, coupling the downhole tool to a wireline, simultaneously deploying the wireline and the downhole tool into the wellbore, and providing a receiver located remotely from the transmitter, characterised in that the wireline acts as an antenna for the transmitter.

Embodiments of the present invention shall now be described, by way of example only, with reference to the accompanying drawings in which:
Fig. 1 is a part cross-section of a downhole tool according to a third aspect of the present invention;
Fig. 2 is a schematic diagram of a typical wireline apparatus;
Fig. 3 is an enlarged view of part of the wireline apparatus of Fig. 2;
Fig. 4 is a schematic diagram of a transmitter which forms part of an electronic system for use with the downhole tool of Fig. 1; and Fig. 5 is a schematic diagram of a receiver which forms part of an electronic system located 1 at the surface for receiving signals from the 2 downhole tool of Fig. 1.

4 Referring to the drawings, Fig. 1 shows an embodiment of part of a distance measuring apparatus, generally 6 designated 10. The apparatus 10 includes a slickline 7 12. Although reference will be made herein to use of 8 a slickline, it will be appreciated that other types 9 of wireline may be used, such as a braided line or cable, coiled tubing or the like. Slickline 12 is 11 typically stored on a reel 14 which forms part of a 12 winching device 16 (Fig. 2), commonly known in the 13 art as a wireline winch unit. The winching device 16 14 is typically located at the surface. It should be noted that "surface" in this context is to be 16 understood as being either atmospheric above ground 17 or sea level, or aquatic above a seabed.

19 The slickline 12 is introduced into a cased wellbore (not shown) via a plurality of sheaves or guide 21 rollers, as illustrated in Fig. 2. The sheaves or 22 guide rollers divert the slickline 12 into a 23 substantially vertical orientation. The slickline 12 24 passes through a vertically-orientated superstructure tube 18 which has an internal open-ended bore, the 26 tube 18 being positioned above a wellhead, generally 27 designated 20.

29 Referring to Fig. 3, there is shown in more detail a part of the slickline apparatus of Fig. 2. Located 31 at an upper end of the tube 18 is a sheave wheel 22 1 which guides the slickline 12 from a substantially 2 upward direction through 180 to a substantially 3 downward direction. The slickline 12 then passes 4 through a stuffing box, generally designated 24 in Fig. 3, which typically includes an internal blow-out 6 preventer (BOP) 26.

8 The slickline 12 enters the tube 18 and continues 9 downward therethrough and into a main BOP 28 and the wellhead 20.

12 The slickline 12 is coupled at a lower end thereof to 13 a part of a downhole tool commonly known as a rope-14 socket 30 (Fig. 1). The main function of a rope-socket 30 is to provide a mechanical linkage between 16 the slickline 12 and the tool or tool string. The 17 mechanical linkage may be any one of a plurality of 18 different forms, but is typically a self-tightening 19 means. In the embodiment shown in Fig. 1, the rope-socket 30 includes a wedge or wire retaining cone 34 21 which engages in a correspondingly tapered retaining 22 sleeve 36.

24 The rope-socket 30 is also provided with a sealing means which seals around the slickline 12 to provide 26 a seal between the rope-socket 30 and the well 27 environment around the slickline 12. The sealing 28 means typically comprises a seal or gasket 44 which 29 isolates and insulates the interior of the rope-socket 30 from the well environment.

1 In the embodiment shown in Fig. 1, the rope-socket 30 2 also provides an electrical coupling between the 3 slickline 12 which is capable of acting as a 4 transmitter/receiver radio frequency (RF) antenna and 5 a downhole tool 32. The tool 32 typically comprises 6 an upper sub 38 which is coupled (typically by 7 threaded connection) to an intermediate sub 40, which 8 is in turn coupled (typically by threaded connection) 9 to a lower sub 42.

11 The upper sub 38 is provided with a screw thread 38t, 12 typically in the form of a pin, which engages with a 13 corresponding internal screw thread 30t, typically in 14 the form of a box, on the rope-socket 30. These (threaded) connections 30t, 38t allow the rope-socket 16 30 and tool 32 to be (mechanically) coupled together.

18 Additionally, the rope-socket 30 is provided with 19 coupling means which electrically couples a metal or otherwise electrically conductive portion of the 21 slickline 12 and a transmitter 46 (a transceiver 22 typically being used to facilitate two-way 23 communication) of the tool 32. The coupling means 24 typically comprises an electrical terminal 48 which is electrically isolated from the body of the rope-26 socket 30 using an insulating sleeve 50.

28 The upper sub 38 of the tool 32 is provided with an 29 electrical pin or contact plunger 52 which engages with the electrical terminal 48 within the rope-31 socket 30. The contact plunger 52 is typically 1 spring-loaded using spring 54 so that it can move 2 longitudinally (with respect to a longitudinal axis 3 of the tool 32) to facilitate coupling of the rope-4 socket 30 and the tool 32. A lower end of the plunger 52 is in contact with a main contactor 56 6 which is electrically coupled to the transmitter 46.
7 This facilitates coupling of signals generated by the 8 transmitter 46 through the plunger 52 and the 9 terminal 48 to the slickline 12, the slickline 12 acting as an antenna for transmitting and/or 11 receiving signals, as will be described.

13 The tool 32 is also provided with an array of field 14 sensors 58 which are used to detect differences in the magnetic flux at the junctions of, or collars 16 between, successive casing sections which are used to 17 case the wellbore, whereby the location of the tool 18 32 within the wellbore can be calculated, as will be 19 described.

21 The tool 32 is preferably powered by a (local) direct 22 current (DC) power source, typically comprising one 23 or more batteries 60. The batteries 60 provide a 24 local electrical power supply for the tool 32.

Conventionally, downhole tools are powered using a 26 central conductor of a braided line to transmit 27 electrical power to the tool from the surface.
28 However, there are substantial losses using this 29 method, particularly where the tool is located some distance down the wellbore. In addition, the central 31 conductor of the braided line is typically relatively small in diameter and thus high voltage drops can be induced.
Use of a local power supply (ie the batteries 60) obviates the need for an electrical power connection to the surface.

The tool 32 may include a pressure sensor 62 which is electrically coupled to the transmitter 46 and when present can be used to measure the pressure external to the tool 32.
Referring now to Fig. 4, there is shown a schematic diagram of a transmitter 46 which forms a part of an electronic system located within the tool 32. The batteries 60 provide electrical power to the system in general. On detection of a positive over-pressure to atmospheric level, that is after introducing the tool 32 into the tube 18 (Fig. 2) and opening of the wellhead 20 to allow well pressure to equalise in the tube 18, the pressure sensor 62 activates the magnetic field sensors 58.

The magnetic field sensors 58 may be of the type described in German Patent Application Publication Number DE 19711781 Al (Pepperl + Fuchs GmbH), for example, and are typically mounted within a section of the tool 32 which is at least partially manufactured from a conventional non-ferrous material. This ensures high sensitivity when detecting casing or collar joints.

German Patent Application Publication Number DE 19711781 Al describes use of the sensors 58 in conjunction with a 1 remnance inducing magnet ring. The wellbore casing 2 sections described therein exhibit a weak magnetic 3 remnance due to the influence of the earth's magnetic 4 field, the difference in the magnetic flux and/or the history of previous well service operations. If the 6 difference in the magnetic flux at the junctions 7 between the wellbore casing sections is 8 insufficiently weak or disorientated, it is 9 advantageous to re-magnetise the casing sections by either running in a separate downhole tool provided 11 with one or more axially orientated magnets prior to 12 commencing the tool detection, or to incorporate one 13 or more such magnets into the tool 32, or the tool 14 string of which the tool 32 forms part.

16 The plurality of sensors 58 are orientated to 17 preferentially sense the locality and proximity of a 18 collar or casing joint which the tool 32 passes, by 19 detecting the variation or switch in magnetic flux at the junctions or collars between successive casing 21 sections. It is preferred, but not essential, to 22 have the sensors 58 disposed on a common horizontal 23 plane within the tool 32. The latter, in combination 24 with the series connection of the sensors 58 maximise the positive sensing of the collars or casing joints 26 as the tool 32 passes.

28 When a casing collar or joint is detected, power is 29 supplied to the transmitter 46. The transmitter 46 is located within the tool 32 and is electrically 31 coupled to the batteries 60, the pressure sensor 62 1 and the magnetic field sensors 58 via suitable 2 electrical connections within the tool 32.

3 Alternatively, the transmitter 46 may be coupled 4 thereto via a system of insulated downhole tool components which provide electrical connections 6 isolated from the well environment, the electrical 7 connections being suitable connectors between the 8 separate downhole sections which make up the complete 9 downhole tool string.

11 The transmitter 46 may be of a type supplied by RS
12 Components under catalogue number RS 740-449, which 13 is designed to operate in conjunction with a 418 MHz 14 FM transmitter module also supplied by RS Components under catalogue number RS 740-297. However, it 16 should be noted that the transmitter specified above 17 is only an example of one possible transmitter, and 18 that there are many other possible transmitters and 19 frequencies which could be utilised in it's place.
The components identified above should be tested for 21 conformity to the particular operational requirements 22 and criteria and for operation in wellbore 23 environments.

The transmitter 46 typically has the facility for 26 address coding (using DIL switch settings 66 in Fig.
27 4), and data bit settings using either a DIL switch 28 68 (Fig. 4) or driven by external switches, relay 29 transistors or CMOS logic via an auxiliary connector, designated 70 in Fig. 4). DIL switch 68 is used to 31 switch data channels (ie the four data channels 1 relating to each one of the sensors 58) on and off, 2 typically using opto-electronic switches 69. Thus, 3 the signal from any one, some or all of the sensors 4 58 can be set to be transmitted. The output from the 5 DIL switch 66 is typically processed by an encoder 6 convertor 67 which encodes the address coding (as set 7 by the DIL switch 66) into the transmission. RF

8 transmission can be initiated by external contact 9 closure and the provided link on the auxiliary 10 connector 70 (eg, coupling TXEN to ground).

12 It will be appreciated that with the above described 13 transmission method, the transmitter 46 is not 14 permanently activated and allows only a single

15 transmission upon external contact closure. The

16 duration of the transmission may be altered by

17 changing the values of RT, CT and/or RT2 and CT2

18 respectively, but is typically in the order of 1

19 second duration (set by default). The period of

20 transmission may be determined as follows :-

21 2.2*RT*CT (which changes the interval between

22 transmission in seconds) and 0.7*RT2*CT2 (which

23 changes the duration of the transmissions in

24 seconds).
26 The transmitter 46 ground connection (ie from any 27 point on the ground connection 64) and RFout 28 connection 65 are electrically coupled to the rope-29 socket 30 using, for example, electrical connections within the tool 32 (or otherwise as described above) 31 and the plunger 52 and electrical terminal 48 1 provided on the tool 32 and rope-socket 30 2 respectively (Fig. 1). These connections are shown 3 schematically in Fig. 4, with the RFout connection 65 4 being coupled to the slickline 12 which acts as an antenna.

7 As previously noted, the slickline 12 acts as an 8 antenna for this RF transmission and thus the 9 slickline antenna 12 carries and guides the transmission towards the surface. The RF
11 transmission (ie the electromagnetic (modulated) 12 wave) contains encoded data which is radiated into 13 free-space or any other antenna surrounding medium at 14 or near the tube 18, for example. The precise location of where the RF transmission is radiated 16 into free-space is not important, but it is typically 17 at some point at the surface where the RF

18 transmission can be radiated over a larger area.

Located within the radiation range of the transmitter 21 antenna (ie the slickline 12), for example located at 22 the surface or within the tube 18, is a receiver 80, 23 shown in Fig. 5. Fig. 5 is a schematic diagram of 24 the receiver 80 which forms a part of an electronic system located at or near the surface. The receiver 26 80 may be, for example, of the type supplied by RS
27 Components under catalogue number RS 740-455, which 28 is designed to operate in conjunction with a 418 MHz 29 FM receiver module 84 supplied by RS Components under catalogue number RS 740-304. However, it should be 31 noted that the receiver specified above is only an 1 example of one possible receiver, and that there are 2 many other possible receivers which could be utilised 3 in it's place. It should also be noted that the 4 receiver 80 should be matched to the frequency of the transmitter 46. The components identified above 6 should be tested for conformity to the particular 7 operational requirements and criteria and for 8 operation in wellbore environments.

The receiver 80 typically has the facility for 11 address coding (using suitable DIL switch settings on 12 switch 82) to match and pair with the address code of 13 the transmitter 46. The settings of the receiver 14 board jumpers JP1 and JP2 determine the output configuration of the transmission from the tool 32.
16 Jumper JP2 is used to select whether the output is 17 high or low (ie the logic level) which selects 18 whether the output on the four channels out 0 to out 19 3 on an auxiliary connector 88) are either a logic high or a logic low. Jumper JP1 is used to select 21 whether the output on the channels out 0 to out 3 are 22 latched (ie permanently high or low) or intermittent.

24 The receiver module 84 receives the signal from the antenna 12 at an RFin connection 86. The signal is 26 then processed in the FM receiver module 84 and 27 output to a decoder 90. The decoder 90 decodes the 28 address coding from the transmission and thus the 29 receiver 80 is only activated when the address of the transmitter 46 matches the address settings of the 31 DIL switch 82 (ie the address of the receiver 80).

1 The output from the decoder 90 is then fed to a data 2 selector 92 which automatically activates one, some 3 or all of the output channels out 0 to out 3, 4 depending upon which of the four channels have been activated by the settings of the DIL switch 68 on the 6 transmitter 46. The output of the selector 92 is 7 then fed to a seven stage darlington driver 94 which 8 is used to drive the outputs on the auxiliary 9 connector 88. The outputs of the auxiliary connector 88, in particular the outputs out 0 to out 3 are 11 typically coupled to a visual indicator (ie a light 12 emitting diode (LED)) which can be used to allow a 13 user to determine which of the sensors 58 detected a 14 collar or casing joint. Alternatively, or additionally, the outputs of the auxiliary connector 16 88 may be coupled to a processing means (eg a 17 computer) located at or near the surface for further 18 processing of the data.

It should be noted that although the transmitter 46 21 is shown coupled to four sensors 58 (Fig. 4) and thus 22 has four channels, the transmitter 46 may be provided 23 with more or less than four channels, depending upon 24 the number and grouping of sensors 58 within tool 32.
26 In use, the tool 32 is attached to the slickline 12 27 as described above and introduced into a cased 28 wellbore in a conventional manner. The casing can be 29 of any type, that is, for example, either electrically conductive or semi-conductive 31 ferromagnetic casing, or electrically non-conductive 1 or non-ferromagnetic casing. The casing string 2 typically comprises of a plurality of casing lengths 3 which are threadedly coupled together, thus making 4 joints (or collars) therebetween.

6 The tool 32 is lowered into the cased wellbore using 7 the slickline 12. The slickline 12 is typically 8 formed of a metal which has a high yield strength to 9 weight ratio and is capable of supporting the tool 32 (and any other tools which may form part of a 11 downhole tool string). It will be appreciated that 12 the slickline 12 should also be capable of 13 functioning as a monopole antenna.

The slickline 12 is preferably (but not essentially) 16 electrically insulated and/or isolated using a thin 17 outer coating of a flexible, non-conductive 18 insulating material. It is preferred that the 19 material should also be chemical, abrasion and temperature resistant to endure the hazardous 21 downhole environments. The coating is typically an 22 enamel coating.

24 It should be noted that it may not be necessary to provide an insulating coating on the slickline 12.
26 If a stuffing box or the like is used, the slickline 27 12 will be electrically isolated by the stuffing box.
28 However, this requires that the slickline 12 does not 29 come into contact with any part of the conductive wellbore which may be difficult in deviated 31 (horizontal) wells or the like. It is thus preferred 1 that the slickline 12 is coated with an insulating 2 coating to ensure good electrical isolation. It 3 should be noted that coating the slickline 12 with an 4 enamel material also protects the metal wire (from 5 which the slickline 12 is made) against corrosion.
6 In addition, or alternatively, a corrosive chemical 7 sensitive material(s) may be applied as a coating or 8 part thereof on the slickline 12, and this would have 9 the advantage that the presence of corrosive 10 chemicals, such as H2S or CO2 or nitrates, in the 11 well would be indicated to the operator when the 12 slickline 12 is removed from the well since the 13 corrosive chemical sensitive material will be 14 transformed; for example, the colour of the corrosive 15 chemical sensitive material may change. In addition, 16 or alternatively, a stress/impact sensitive 17 material(s) may be applied as a coating or part 18 thereof on the slickline 12, and this would have the 19 advantage that mechanical damage to the slickline 12 20 in the well would be indicated to the operator when 21 the slickline 12 is removed from the well, since the 22 stress/impact sensitive material will be transferred;
23 for example, the colour of the impact/stress 24 sensitive material may change.
26 The enamel material may consist of one or more layers 27 of coating whereby each individual layer adds to the 28 overall required coating properties. Additionally, 29 each layer of enamel material preferably has the required bonding, flexibility and stretch 31 characteristics at least equal to those of the metal 1 slickline 12 or coiled tubing. The thickness of the 2 enamel material can vary depending upon the downhole 3 conditions encountered, but is generally in the order 4 of 10 to 100 microns.

6 The enamel material can typically be applied to the 7 slickline 12 by firstly applying a thin layer of 8 adhesive, such as nylon or other suitable primer.

9 Thereafter, one or more layers of an enamel material such as polyester, polyamide, polyamide-imide, 11 polycarbonates, polysulfones, polyester imides, 12 polyether, ether ketone, polyurethane, nylon, epoxy, 13 equilibrating resin, or alkyd resin or theic 14 polyester, or a combination thereof. The enamel material is preferably polyamide-imide.

17 The conventional method of measuring downhole tool 18 depth is to run the slickline 12 against the sheave 19 wheel 22. It should be noted that use of "depth" in this context is understood as being the trajectory 21 length of the downhole tool, which may be different 22 from conventional depth if the wellbore is deviated, 23 for example. In order to calculate the distance of 24 travel of the slickline 12, a number of variable factors must be known. It is a prerequisite that the 26 rotational direction of the sheave wheel 22, the 27 number of revolutions thereof, the diameter of the 28 sheave wheel 22 and, depending upon the type of 29 sheave wheel 22 (that is, whether a point-type contact or arc for example), the diameter of the 31 slickline 12, must all be known before the distance 1 of travel of the slickline 12 within the wellbore can 2 be calculated (and thus the depth of the tool).

4 However, with this conventional method for calculating the distance of travel of the slickline 6 12, a number of factors render the calculation 7 inaccurate. The occurrence of wheel slippage, the 8 stretch of the slickline 12 (whether due to the 9 weight of the slickline 12 itself, or the weight of the tool string to which it is attached), the effect 11 of friction and the well-contained fluid buoyancy all 12 contribute to decrease the accuracy of the 13 conventional tool depth measurement.

In order to improve the accuracy of this conventional 16 depth measurement, it is known to combine the 17 measured tensile load, the known stretch co-efficient 18 of the slickline 12, and the conventionally measured 19 tool depth as described above, to recalculate the tool depth measurement on a continuous (ie real time) 21 basis using a processing means (eg a computer).

23 However, the accuracy of the aforementioned depth 24 measurement correction method relies on an experimentally determined constant (ie the stretch 26 co-efficient of the slickline 12) and the surface 27 measurements of the weight of the slickline 12. The 28 resulting correction does not include the significant 29 combined effect that well fluid temperature, tool buoyancy and well geometry have on the accuracy of 31 the depth correction.

2 When the tool 32 detects a casing collar or joint 3 during normal slickline operations at downhole tool 4 travelling speed, the tool 32 will process the collected data at normal wireline operational speed 6 using a processing device and signal generator 71 7 (Fig. 4) which forms part of the transmitter 46. The 8 processing device and signal generator 71 9 communicates a signal (via a SAW oscillator 73 and 418 MHz band-pass filter 75) indicative of the 11 location of the collar or joint to the slickline 12 12 which acts as an antenna. At the surface, this 13 signal is received by the surface receiver 80 (Fig.
14 5). The receiver 80 is coupled to the processing means (eg a computer) located at the surface and the 16 signal from the tool 32 is used to calibrate the 17 conventional measured depth against the known 18 distance between the preceding collar or joint, or 19 other known location. This distance is typically known from an existing record log of the individual 21 casing lengths.

23 A number of arrays of magnetic field sensors 58 24 positioned on axially spaced-apart horizontal planes within the tool 32 (as shown in Fig. 1) can be used, 26 each of the sensor arrays having their own channel as 27 described above and being set at known (but not 28 necessarily equal) distances along the longitudinal 29 axis of the tool 32. This allows for increased accuracy of the calibration due to the repeated 31 calibration against the detected collar or joint. It 1 should be noted that when using multiple arrays of 2 sensors 58, only a single transmitter 46 and receiver 3 80 need be used as each array 58 will have their own 4 individual channel which can be selected or deselected as required.

7 However, if the communication system is being used 8 with other sensors within the tool, these other 9 sensors may be coupled to another transmitter and receiver, the other transmitter and receiver 11 including a different address coding. This allows 12 multiple transmissions to multiple receivers 80 from 13 multiple transmitters 46 using only one slickline 12 14 as the antenna.

16 The signal from the tool 32 is, for the purpose of 17 the described tool depth measurement calibration, a 18 measure of a known trajectory length of the tool 32 19 in relation to a detected collar or casing joint end length (casing-section length calibration). This is 21 dependent upon the configuration of tool 32 within 22 the downhole tool or string. Alternatively, the 23 signal is a measure of the trajectory length as 24 travelled by the tool 32 in relation to the detected collar or casing joint as indicated by each separate 26 positive signal from the tool 32 (downhole tool 27 length calibration). For the casing section length 28 calibration technique, the accuracy of the 29 calibration may depend upon the accuracy and completeness of surveyea well details, that is the 31 length of the individual casing sections and the 1 configuration thereof. For the downhole tool length 2 calibration method, surveyed well details are not 3 necessary.

5 With the casing length calibration method 6 (hereinafter CLC), the trajectory length or tool 7 depth calibration, as performed by the processing 8 means at the surface, uses the received signal from 9 the tool 32 and references this signal against the 10 conventionally obtained surface measured depth, 11 obtained as described above, and the details of the 12 well. That is, the individual casing length is used 13 to calculate a depth correction factor wherein 15 cLC = Lc/ (D2 - D1) 17 wherein 19 L, = casing length;
20 Dl = surface depth at the previous casing collar or 21 joint;
22 D2 = surface depth at the detected casing collar or 23 joint, where D2 > D1; and 24 cLC = depth correction factor.

26 The depth correction factor cLC is used by the 27 processing means to correct the conventionally 28 obtained depth over the next downhole tool trajectory 29 casing length.

1 With the downhole tool length calibration method 2 (hereinafter TLC), the trajectory length or tool 3 depth calibration is performed by the processing 4 means located at the surface, for example. The processing means uses the received signal from the 6 tool 32 and references this signal against the 7 conventionally obtained surface measured depth to 8 calculate a depth correction factor . The 9 correction factor can be calculated as follows for equidistant sensor spacing (ie constant distance 11 between sensors) 13 TLC = Lu/ (Dn - Dn-1) wherein 17 Lu = tool sensor distance constant (ie the uniform 18 distance between the sensors);
19 D1 = surface depth at the first tool sensor;
Dn-1 = surface depth at the previous casing collar or 21 joint;
22 Dn = surface depth at the detected casing collar or 23 joint, where Dn > Dn-1 > D1; and 24 TLC = depth correction factor.

26 The correction factor can be calculated as follows 27 for non-uniform sensor spacing (ie non-constant 28 distance between sensors) TLC = Ln/ (Dn - Dn-1) i 2 wherein 4 Ln = tool sensor distance spacing (ie the non-uniform distant between the sensors);

6 D1 = surface depth at the first tool sensor;

7 Dn_1 = surface depth at the previous casing collar or 8 joint;
9 Dn = surface depth at the detected casing collar or j oint , where Dn > Dn_1 > D1; and 11 TLC = depth correction factor.

13 The depth correction factor [LTLC thus derived can be 14 used by the processing means to correct the conventionally obtained depth over the next travelled 16 spacing between the sensors (either uniform or non-17 uniform). If the total tool distance (that is the 18 distance between the sensors provided in the tool 32) 19 is less than the individual casing length, the derived multiple-calibrated correction factor TLC may 21 be used to correct the conventionally obtained depth 22 related input over the next downhole tool trajectory 23 individual casing length.

It will be appreciated that the depth correction 26 described above need not be performed in real-time.
27 A running history file can be constructed using each 28 surface-received signal from the tool 32 and after 29 completion of a slickline run (downhole tool travel from surface to a depth and return to surface), the 31 history file can be compared against a similar file 1 derived from the conventional depth measurement 2 technique and the results analysed to interpret and 3 evaluate the downhole tool run objectives and 4 results.
6 It will be appreciated that the use of a slickline as 7 an antenna is not limited to facilitate an increase 8 in accuracy of tool depth measurements. For example, 9 the conventional method for detecting the status of a downhole tool or tools (that is a tool which is 11 deigned to perform downhole functions such as setting 12 plugs or isolating sections of the wellbore to deploy 13 memory gauges) would be by a differential calculation 14 involving the experience of the slickline operator in conjunction with correlated depth between distance 16 travelled by the slickline (calculated using the 17 conventional technique) and the location of a 18 "nipple" in conjunction with the previously recorded 19 "nipple" depth or tubing tally, or by other means involving physical stresses in the slickline (for 21 example increased/decreased tension in the 22 slickline). A"nipple" is a receptacle in which the 23 downhole tool locates and latches into, or the 24 position in the tubing or casing string for the deployment of the downhole tool to carry out its 26 function.

28 Once the downhole tool has been deployed or 29 retrieved, the slickline winch operator typically sees a corresponding decrease or increase in the 31 weight of the tool string equivalent to the weight of 1 the tool, which would be indicative of a successful 2 deployment or retrieval.

4 However, where the downhole tool is of a marginal weight so as not to show a significant difference in 6 the weight of the tool string once it has been 7 deployed or retrieved, or when circumstances inside 8 the wellbore give a smaller indication than one of 9 those described above (for example an obstruction in the tubing or such like), the status of the downhole 11 tool is derived by conjecture until a time when the 12 function of the tool can be operatively tested or the 13 tool string is returned to the surface.

As will be appreciated, these methods of ascertaining 16 the status of downhole tools are not accurate and 17 rely on the experience of the slickline winch 18 operator, a careful tally of running and pulling 19 weights, and accurate weight indication and depth correlation means. Even when these criteria have all 21 been met, there is no guarantee that the downhole 22 tool has been successfully deployed or retrieved 23 correctly and where downhole tools which rely on the 24 position of sliding sleeves are used, there is no indication of the position thereof until further 26 tests have been carried out.

28 The present invention facilitates a means to actively 29 identify when a downhole tool has been deployed or retrieved etc by incorporating into the previously 31 described apparatus one or more sensors (eg a 1 proximity or electrically connecting/disconnecting 2 sensor) which activates the transmission of a signal 3 via the slickline antenna which is indicative of the 4 status of the tool (ie latched, unlatched, engaged, 5 disengaged etc). This would provide a more reliable 6 indication of the tool status in connection with the 7 previously described depth correlation which 8 substantially mitigates the possibility of human 9 error in identifying whether the downhole tool has 10 been correctly deployed or retrieved etc.

12 When a downhole tool has been deployed, retrieved or 13 otherwise, it is normally the case to use a 14 mechanical force in order to facilitate this 15 deployment, retrieval or otherwise in order to 16 operate a mechanism incorporated in the downhole tool 17 in order to carry out the function of the tool. An 18 example of this would be a running tool which is used 19 to deploy a downhole plug which typically relies on 20 the slickline operator to locate the tool in its 21 downhole position using the conventional depth 22 measurement. Thereafter, either pulling sharply on 23 the slickline or rapidly slackening it induces a 24 hammering effect on the tool whereby a pin (or a

25 plurality thereof) are sheared to allow the tool to

26 engage in a locking assembly, thus disconnecting the

27 tool from the string, or a collar is pulled to

28 retract such an assembly in order to release the tool

29 from the locking assembly thus connecting the tool to

30 the string.

31 1 A signal from a proximity sensor or the like can be 2 propagated to the surface using the slickline as an 3 antenna, the signal being received at the surface and 4 causing, for example, a second signal to be transmitted from the surface to a relay provided on 6 the (downhole) tool to electrically or 7 electromechanically operate an automatic locking or 8 unlocking device. This would eliminate the 9 requirement for mechanical hammering to initiate the functioning of the downhole tool.

12 Another application of the present invention would be 13 during the deployment of downhole tools, a part or 14 parts of the tool itself or the tool string can loosen or be disconnected from the tool or string.
16 This can then require several runs into the wellbore 17 in order to recover the tool or part thereof. This 18 can be a very expensive process.

To overcome this, the tools within the tool string or 21 the parts of the tool themselves can be coupled 22 together either electrically or magnetically wherein 23 discontinuity of the electrical or magnetic 24 connection triggers a signal or a plurality of signals which can be transmitted to the surface to 26 indicate to the slickline operator that such an event 27 is about to occur.

29 Modifications and improvements may be made to the foregoing without departing from the scope of the 31 present invention. For example, the foregoing 1 description relates to the use of a slickline as an 2 antenna, but it will be appreciated that it is 3 equally possible to use a braided line or a mono-4 conducting slickline. Additionally, the pulsed transmission to the surface could be replaced by a 6 continuous type transmission, or alternatively, may 7 be a pulsed or continuous two-way communication 8 between the surface and a tool, using suitable 9 transmitters and receivers (or transceivers) for such communications.

12 Although the foregoing description relates to the use 13 of a tool which detects the location and passage of 14 collars in a cased wellbore, it will be appreciated that tools exist which are sensitive to non-collared 16 pipe joints.

18 Additionally, it will be appreciated that the 19 communication system described herein enables the use of a slickline in combination with downhole tools, 21 such as flow meters, pressure, temperature, 22 gravitational, sonic and seismic sensors, downhole 23 cameras and/or optic/IR sensors which have hitherto 24 relied on electric (single- or multi-conductor) braided slicklines for operation.

Claims (22)

What is claimed is:

1. A wellbore communication system, the system comprising a downhole tool coupled to a wireline, the downhole tool comprising a transmitter, wherein the downhole tool and wireline are adapted to be simultaneously deployed into the wellbore, at the surface thereof, and a receiver located remotely from the transmitter, characterised in that the wireline is capable of running the downhole tool into the wellbore and is also capable of acting as an antenna for the transmitter.

2. A wellbore communication system according to claim 1, wherein the wireline is a slickline.

3. A wellbore communication system according to claim 2, wherein the slickline is provided with an insulating coating.

4. A wellbore communication system according to claim 3, wherein the insulating coating is an outer coating of the slickline.

5. A wellbore communication system according to either claim 3 or claim 4, wherein the coating comprises a stress/impact sensitive material.

6. A wellbore communication system according to any one of claims 3 to 5, wherein the insulating coating comprises at least one enamel material.

7. A wellbore communication system according to any one of claims 1 to 6, wherein the transmitter is further associated with, provided on, or is an integral part of a tool string.

8. A wellbore communication system according to claim 7, wherein the downhole tool and tool string are suspended by the wireline.

9. A wellbore communication system according to either claim 7 or claim 8, wherein the transmitter transmits data collected or generated by the downhole tool to the receiver.

10. A wellbore communication system according to any one of claims 1 to 9, wherein the receiver is located at, or near, the surface of the wellbore.

11. A wellbore communication system according to any one of claims 1 to 10, wherein the distance travelled by the downhole tool, the status of the downhole tool or other parameters of the downhole tool, can be transmitted to the receiver.

12. A wellbore communication system as claimed in any one of claims 1 to 11, further comprising distance measurement apparatus for measuring the distance travelled by the wireline, the distance measurement apparatus comprising at least two sensors coupled to the wireline wherein the sensors are capable of sensing known locations in the wellbore and are further capable of generating a signal indicative thereof, wherein the transmitter is capable of transmitting the signals.

13. A wellbore communication system according to any one of claims 1 to 12 further comprising coupling means to attach the downhole tool to the wireline.

14. A wellbore communication system according to claim 13, wherein the coupling means comprise a rope-socket.

15. A wellbore communication system according to claim 14, wherein the rope-socket is provided with signal coupling means to electrically couple the signals generated by the transmitter to the wireline.

16. A wellbore communication system according to any one of claims 1 to 15, wherein the downhole tool is powered by a DC
power supply.

17. A wellbore communication system according to claim 7 or to any one of claims 8 to 10 when dependent upon claim 7, the apparatus comprising at least two sensors capable of sensing a change in the configuration of the downhole tool or tool string and generating a signal indicative thereof, and a transmitter electrically coupled to the at least two sensors for transmitting the signals to a receiver.

18. A wellbore communication system according to claim 17, wherein the apparatus is arranged such that it can facilitate two-way communication between the downhole tool and the receiver.

19. A wellbore communication system according to either claim 12 or claim 17, wherein the sensors comprise electric or magnetic sensors which are coupled to the downhole tool wherein a discontinuity of the respective electric or magnetic connection triggers a signal by each sensor.

20. A method of communication in a wellbore, comprising providing a downhole tool comprising a transmitter, coupling the downhole tool to a wireline, simultaneously deploying the wireline and the downhole tool into the wellbore, and providing a receiver located remotely from the transmitter, characterised in that the wireline acts as an antenna for the transmitter.

21. A method of communication in a wellbore according to claim 20 further comprising the step of measuring the distance travelled by the wireline, including coupling at least two sensors to the wireline, the at least two sensors being capable of sensing known locations in the wellbore;
running the wireline into the wellbore; calculating the depth of the at least two sensors; generating a signal when each of the at least two sensors pass said known locations; using the signals to calculate a depth correction factor; and correcting the calculated depth using the depth correction factor.

22. A method according to claim 20 comprising the step of tracking the downhole tool in the wellbore, the method comprising providing at least two sensors on the downhole tool, inserting the downhole tool and said sensors into the wellbore, obtaining information indicating the position of the sensors in the wellbore, and determining the distance travelled by said downhole tool from said sensor information.