Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B47/00—Survey of boreholes or wells
  • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
  • E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency

Definitions

• the present invention relates to apparatus and methods relating to downhole operations, and particularly, but not exclusively, to wireline operations.
• Wirelines are conventionally stored on a winching unit typically located at the surface in the proximity of the top of a borehole. It should be noted that "surface” in this context is to be understood as being either atmospheric above ground or sea level, or aquatic above the seabed.
• surface in this context is to be understood as being either atmospheric above ground or sea level, or aquatic above the seabed.
• the sheaves or guide rollers facilitate, in the first instance, a substantially vertical orientation of the wireline.
• the wireline passes through a substantially vertically-orientated superstructure tube having an internal open-ended bore, the tube being positioned on top of a wellhead.
• any downhole tool can be introduced into the wellbore.
• the wireline is coupled at its distal (downhole) end to the downhole tool, typically via a part of the tool known as a rope-socket.
• the rope-socket is conventionally used to provide a mechanical connection between the wireline and the downhole tool (or a string of downhole tools known as a tool string) .
• the accuracy of the aforementioned depth measurement correction method relies on an experimentally determined constant (le the stretch co-efficient of the wireline) and the surface measurements on the wireline.
• the resulting correction does not include the significant combined effect that well fluid temperature, tool buoyancy and well geometry have on the accuracy of the depth correction.
• distance measurement apparatus for measuring the distance travelled by a wireline, the apparatus comprising at least one sensor coupled to the wireline wherein the sensor is capable of sensing known locations m a wellbore.
• the wireline is typically a slicklme.
• the apparatus includes transmission means for transmitting data collected by the at least one sensor to a receiver located remotely from the apparatus.
• the wireline is capable of acting as an antenna for the transmission means.
• the sensor may be coupled to the wireline at any point thereon, or may form an integral part thereof.
• the sensor is preferably coupled at or near a downhole tool whereby the distance travelled by the tool (and thus its location within the wellbore) can be calculated.
• the sensor may form part of a downhole tool or the like.
• the sensor typically comprises a magnetic field sensor, and preferably an array of magnetic field sensors.
• the array of magnetic field sensors are typically provided on a common horizontal plane.
• the sensor may comprise a radio frequency (RF) sensor, and preferably an array thereof. Where an RF sensor is used, the wellbore is typically provided with RF tags at known locations.
• RF radio frequency
• the wireline is preferably electrically insulated.
• the wireline may be sheathed to facilitate electrical insulation.
• the wireline may be passed through a stuffing box or the like to facilitate electrical insulation and/or isolation.
• the coupling means typically comprises a rope-socket.
• the rope-socket is preferably provided with signal coupling means to couple the signal generated by the transmission means to the wireline.
• the sensor typically comprises a magnetic field sensor, and preferably an array of magnetic field sensors.
• the array of magnetic field sensors are typically provided on a common horizontal plane.
• the sensor may comprise a radio frequency (RF) sensor, and preferably an array thereof.
• the array of RF sensors are typically provided on a common horizontal plane.
• the insulating coating is typically an outer coating of the wireline.
• the wireline typically comprises a slickline.
• the insulating coating typically comprises at least one enamel material .
• the enamel material typically consists of one or more layers of coating whereby each individual layer adds to the overall required coating properties. Additionally, each layer of enamel material preferably has the required bonding, flexibility and stretch characteristics at least equal to those of the wireline.
• the enamel material can typically be applied to the wireline by firstly applying a thin layer of adhesive, such as nylon or other suitable primer. Thereafter, one or more layers of an enamel material such as polyester, polyamide, polyamide-imide, polycarbonates, polysulfones, polyester imides, polyether, ether ketone, polyurethane, nylon, epoxy, equilibrating resin, or alkyd resin or theic polyester, or a combination thereof, are preferably applied.
• the enamel material is preferably polyamide-imide.
• a communication system for use in a wellbore, the system comprising a transmitter coupled to a wireline, and a receiver located remotely from the transmitter, wherein the wireline is capable of acting as an antenna for the transmitter.
• the transmitter is typically associated with, provided on, or an integral part of a downhole tool or tool string, whereby the downhole tool or tool string is typically suspended by the wireline.
• the transmitter typically facilitates the transmission of data collected by the downhole tool or the like to the receiver.
• the transmission means typically comprises a transmitter.
• the receiver is typically located at, or near, the surface.
• the communication system is arranged whereby it can facilitate two-way communication between the downhole tool and the receiver.
• a transmitter and a receiver are typically located downhole.
• a transmitter and a receiver are also located at, or near, the surface.
• the transmitter and receiver at the surface and/or downhole may be replaced by a transceiver located downhole and at, or near, the surface.
• the transmitter may be coupled to the wireline at any point thereon, or may form a part thereof.
• the transmitter is typically coupled at or near a downhole tool whereby the distance travelled by the tool, the status of the tool or other parameters of the tool, can be transmitted to the receiver.
• the transmitter may form an integral part of a downhole tool .
• apparatus for indicating the configuration of a downhole tool or tool string comprising at least one sensor capable of sensing a change in the configuration of the downhole tool or tool string and generating a signal indicative thereof, and a transmission means electrically coupled to the at least one sensor for transmitting the signal to a receiver.
• the downhole tool is preferably suspended in a borehole using a wireline, and the wireline is preferably capable of acting as an antenna for the transmission means.
• the transmitter typically facilitates the transmission of data collected by the sensor to the receiver.
• the transmission means typically comprises a transmitter.
• the receiver is typically located at, or near, the surface.
• the communication system is arranged whereby it can facilitate two-way communication between the downhole tool and the receiver.
• a transmitter and a receiver are typically located downhole.
• a transmitter and a receiver are also located at, or near, the surface.
• the transmitter and receiver at the surface and/or downhole may be replaced by a transceiver located downhole and at, or near, the surface.
• the sensor typically comprises an electric or magnetic sensor which is coupled to the downhole tool wherein a discontinuity of the electric or magnetic connection triggers a signal, or a plurality of signals. These signals can then be transmitted to the surface to indicate the status of the tool.
• the sensor may be coupled between a tool string and a downhole tool which is to be deployed into a wellbore, wherein discontinuity of the electric or magnetic connection indicates that the tool has been deployed.
• the sensor may be coupled to a distal end of the tool string, and the downhole tool which is to be retrieved from a wellbore, is provided with a similar sensor, wherein continuity of the electric or magnetic connection indicates that the tool has been 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.
• the wireline may be passed through a stuffing box or the like to facilitate electrical insulation and/or isolation.
• 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
• Fig. 5 is a schematic diagram of a receiver which forms part of an electronic system located at the surface for receiving signals from the downhole tool of Fig. 1.
• Fig. 1 shows an embodiment of part of a distance measuring apparatus, generally designated 10.
• the apparatus 10 includes a slickline 12.
• Slickline 12 is typically stored on a reel 14 which forms part of a winching device 16 (Fig. 2), commonly known m the art as a wireline winch unit.
• the winching device 16 is typically located at the surface. It should be noted that "surface” m this context is to be understood as being either atmospheric above ground or sea level, or aquatic above a seabed.
• the slickline 12 enters the tube 18 and continues downward therethrough and into a mam BOP 28 and the wellhead 20.
• the slickline 12 is coupled at a lower end thereof to a part of a downhole tool commonly known as a rope- socket 30 (Fig. 1) .
• the mam function of a rope- socket 30 is to provide a mechanical linkage between the slickline 12 and the tool or tool string.
• the mechanical linkage may be any one of a plurality of different forms, but is typically a self-tightening means.
• the rope- socket 30 includes a wedge or wire retaining cone 34 which engages m a correspondingly tapered retaining sleeve 36.
• the rope-socket 30 is also provided with a sealing means which seals around the slickline 12 to provide a seal between the rope-socket 30 and the well environment around the slickline 12.
• the sealing means typically comprises a seal or gasket 44 which isolates and insulates the interior of the rope- socket 30 from the well environment.
• the rope-socket 30 also provides an electrical coupling between the slickline 12 which is capable of acting as a transmitter/receiver radio frequency (RF) antenna and a downhole tool 32.
• the tool 32 typically comprises an upper sub 38 which is coupled (typically by threaded connection) to an intermediate sub 40, which is m turn coupled (typically by threaded connection) to a lower sub 42.
• the upper sub 38 is provided with a screw thread 38t, typically the form of a pm, which engages with a corresponding internal screw thread 30t, typically in the form of a box, on the rope-socket 30.
• a screw thread 38t typically the form of a pm
• a corresponding internal screw thread 30t typically in the form of a box
• the rope-socket 30 is provided with coupling means which electrically couples a metal or otherwise electrically conductive portion of the slickline 12 and a transmitter 46 (a transceiver typically being used to facilitate two-way communication) of the tool 32.
• the coupling means typically comprises an electrical terminal 48 which is electrically isolated from the body of the rope- socket 30 using an insulating sleeve 50.
• the tool 32 is also provided with an array of field sensors 58 which are used to detect differences the magnetic flux at the junctions of, or collars between, successive casing sections which are used to case the wellbore, whereby the location of the tool 32 within the wellbore can be calculated, as will be described.
• the tool 32 is preferably powered by a (local) direct current (DC) power source, typically comprising one or more batteries 60.
• the batteries 60 provide a local electrical power supply for the tool 32.
• downhole tools are powered using a central conductor of a braided line to transmit electrical power to the tool from the surface.
• the central conductor of the braided line is typically relatively small m diameter and thus high voltage drops can be induced.
• Use of a local power supply e 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.
• 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 m general .
• the pressure sensor 62 activates the magnetic field sensors 58.
• the magnetic field sensors 58 may be of the type described German Patent Application Number DE-A1- 19711781.3 (Pepperl + Fuchs GmbH), for example, and are typically mounted withm 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 oints.
• the plurality of sensors 58 are orientated to preferentially sense the locality and proximity of a collar or casing joint which the tool 32 passes, by detecting the variation or switch magnetic flux at the junctions or collars between successive casing sections. It is preferred, but not essential, to have the sensors 58 disposed on a common horizontal plane within the tool 32. The latter, m combination with the series connection of the sensors 58 maximise the positive sensing of the collars or casing joints as the tool 32 passes.
• the transmitter 46 When a casing collar or joint is detected, power is supplied to the transmitter 46.
• the transmitter 46 is located withm the tool 32 and is electrically coupled to the batteries 60, the pressure sensor 62 and the magnetic field sensors 58 via suitable electrical connections within the tool 32.
• the transmitter 46 may be coupled thereto via a system of insulated downhole tool components which provide electrical connections isolated from the well environment, the electrical connections being suitable connectors between the separate downhole sections which make up the complete downhole tool string.
• the transmitter 46 typically has the facility for address coding (using DIL switch settings 66 Fig. 4) , and data bit settings using either a DIL switch 68 (Fig. 4) or driven by external switches, relay transistors or CMOS logic via an auxiliary connector, designated 70 m Fig. 4) .
• DIL switch 68 is used to switch data channels (le the four data channels relating to each one of the sensors 58) on and off, typically using opto-electronic switches 69.
• the output from the DIL switch 66 is typically processed by an encoder convertor 67 which encodes the address coding (as set by the DIL switch 66) into the transmission.
• RF transmission can be initiated by external contact closure and the provided link on the auxiliary connector 70 (eg, coupling TXEN to ground) .
• the transmitter 46 is not permanently activated and allows only a single transmission upon external contact closure.
• the duration of the transmission may be altered by changing the values of RT, CT and/or RT2 and CT2 respectively, but is typically in the order of 1 second duration (set by default) .
• the period of transmission may be determined as follows :- 2.2*RT*CT (which changes the interval between transmission in seconds) and 0.7*RT2*CT2 (which changes the duration of the transmissions in seconds) .
• the slickline 12 acts as an antenna for this RF transmission and thus the slickline antenna 12 carries and guides the transmission towards the surface.
• the RF transmission ie the electromagnetic (modulated) wave
• contains encoded data which is radiated into free-space or any other antenna surrounding medium at or near the tube 18, for example.
• the precise location of where the RF transmission is radiated into free-space is not important, but it is typically at some point at the surface where the RF transmission can be radiated over a larger area.
• a receiver 80 Located within the radiation range of the transmitter antenna (ie the slickline 12), for example located at the surface or within the tube 18, is a receiver 80, shown in Fig. 5.
• Fig. 5 is a schematic diagram of the receiver 80 which forms a part of an electronic system located at or near the surface.
• the receiver 80 may be, for example, of the type supplied by RS Components under catalogue number RS 740-455, which is designed to operate in conjunction with a 418 MHz FM receiver module 84 supplied by RS Components under catalogue number RS 740-304.
• the receiver specified above is only an example of one possible receiver, and that there are many other possible receivers which could be utilised in it ' s place.
• the receiver 80 should be matched to the frequency of the transmitter 46.
• the components identified above should be tested for conformity to the particular operational requirements and criteria and for operation in wellbore environments.
• the receiver 80 typically has the facility for address coding (using suitable DIL switch settings on switch 82) to match and pair with the address code of the transmitter 46.
• the settings of the receiver board jumpers JP1 and JP2 determine the output configuration of the transmission from the tool 32.
• Jumper JP2 is used to select whether the output is high or low (ie the logic level) which selects whether the output on the four channels out 0 to out 3 on an auxiliary connector 88) are either a logic high or a logic low.
• Jumper JP1 is used to select whether the output on the channels out 0 to out 3 are latched (ie permanently high or low) or intermittent.
• the receiver module 84 receives the signal from the antenna 12 at an RFin connection 86.
• the signal is then processed in the FM receiver module 84 and output to a decoder 90.
• the decoder 90 decodes the address coding from the transmission and thus the receiver 80 is only activated when the address of the transmitter 46 matches the address settings of the DIL switch 82 (ie the address of the receiver 80) .
• the output from the decoder 90 is then fed to a data selector 92 which automatically activates one, some or all of the output channels out 0 to out 3, depending upon which of the four channels have been activated by the settings of the DIL switch 68 on the transmitter 46.
• the output of the selector 92 is then fed to a seven stage darlington driver 94 which is used to drive the outputs on the auxiliary connector 88.
• the outputs of the auxiliary connector 88, in particular the outputs out 0 to out 3 are typically coupled to a visual indicator (ie a light emitting diode (LED) ) which can be used to allow a user to determine which of the sensors 58 detected a collar or casing joint.
• a visual indicator ie a light emitting diode (LED)
• the outputs of the auxiliary connector 88 may be coupled to a processing means (eg a computer) located at or near the surface for further processing of the data.
• the casing can be of any type, that is, for example, either electrically conductive or semi -conductive ferromagnetic casing, or electrically non-conductive or non- ferromagnetic casing.
• the casing string typically comprises of a plurality of casing lengths which are threadedly coupled together, thus making joints (or collars) therebetween.
• the tool 32 is lowered into the cased wellbore using the slickline 12.
• the slickline 12 is typically formed of a metal which has a high yield strength to weight ratio and is capable of supporting the tool 32 (and any other tools which may form part of a downhole tool string) . It will be appreciated that the slickline 12 should also be capable of functioning as a monopole antenna.
• the slickline 12 is preferably (but not essentially) electrically insulated and/or isolated using a thin outer coating of a flexible, non-conductive insulating material . It is preferred that the material should also be chemical, abrasion and temperature resistant to endure the hazardous downhole environments.
• the coating is typically an enamel coating.
• the slickline 12 may not be necessary to provide an insulating coating on the slickline 12. If a stuffing box or the like is used, the slickline 12 will be electrically isolated by the stuffing box. However, this requires that the slickline 12 does not come into contact with any part of the conductive wellbore which may be difficult in deviated (horizontal) wells or the like. It is thus preferred that the slickline 12 is coated with an insulating coating to ensure good electrical isolation. It should be noted that coating the slickline 12 with an enamel material also protects the metal wire (from which the slickline 12 is made) against corrosion.
• a corrosive chemical sensitive material may be applied as a coating or part thereof on the slickline 12, and this would have the advantage that the presence of corrosive chemicals, such as H 2 S or C0 2 or nitrates, in the well would be indicated to the operator when the slickline 12 is removed from the well since the corrosive chemical sensitive material will be transformed; for example, the colour of the corrosive chemical sensitive material may change.
• a stress/impact sensitive material may be applied as a coating or part thereof on the slickline 12, and this would have the advantage that mechanical damage to the slickline 12 in the well would be indicated to the operator when the slickline 12 is removed from the well, since the stress/impact sensitive material will be transferred; for example, the colour of the impact/stress sensitive material may change.
• the enamel material may consist of one or more layers of coating whereby each individual layer adds to the overall required coating properties. Additionally, each layer of enamel material preferably has the required bonding, flexibility and stretch characteristics at least equal to those of the metal slickline 12 or coiled tubing.
• the thickness of the enamel material can vary depending upon the downhole conditions encountered, but is generally in the order of 10 to 100 microns.
• the enamel material can typically be applied to the slickline 12 by firstly applying a thin layer of adhesive, such as nylon or other suitable primer. Thereafter, one or more layers of an enamel material such as polyester, polyamide, polyamide-imide, polycarbonates, polysulfones, polyester imides, polyether, ether ketone, polyurethane, nylon, epoxy, equilibrating resin, or alkyd resin or theic polyester, or a combination thereof.
• the enamel material is preferably polyamide-imide.
• the conventional method of measuring downhole tool depth is to run the slickline 12 against the sheave wheel 22. It should be noted that use of "depth” in this context is understood as being the trajectory length of the downhole tool, which may be different from conventional depth if the wellbore is deviated, for example. In order to calculate the distance of travel of the slickline 12, a number of variable factors must be known.
• the accuracy of the aforementioned depth measurement correction method relies on an experimentally determined constant (ie the stretch co-efficient of the slickline 12) and the surface measurements of the weight of the slickline 12.
• the resulting correction does not include the significant combined effect that well fluid temperature, tool buoyancy and well geometry have on the accuracy of the depth correction.
• the processing device and signal generator 71 communicates a signal (via a SAW oscillator 73 and 418 MHz band-pass filter 75) indicative of the location of the collar or joint to the slickline 12 which acts as an antenna. At the surface, this signal is received by the surface receiver 80 (Fig. 5) .
• the receiver 80 is coupled to the processing means (eg a computer) located at the surface and the signal from the tool 32 is used to calibrate the conventional measured depth aga st the known distance between the preceding collar or joint, or other known location. This distance is typically known from an existing record log of the individual casing lengths.
• a number of arrays of magnetic field sensors 58 positioned on axially spaced-apart horizontal planes within the tool 32 can be used, each of the sensor arrays having their own channel as described above and being set at known (but not necessarily equal) distances along the longitudinal axis of the tool 32. This allows for increased accuracy of the calibration due to the repeated calibration agamst the detected collar or joint. It should be noted that when using multiple arrays of sensors 58, only a single transmitter 46 and receiver 80 need be used as each array 58 will have their own individual channel which can be selected or deselected as required.
• the trajectory length or tool depth calibration uses the received signal from the tool 32 and references this signal agamst the conventionally obtained surface measured depth, obtained as described above, and the details of the well. That is, the individual casing length is used to calculate a depth correction factor ⁇ wherein
• L c casing length
• Di surface depth at the previous casing collar or joint
• the depth correction factor ⁇ CL c is used by the processing means to correct the conventionally obtained depth over the next downhole tool trajectory casing length.
• TLC downhole tool length calibration method
• the trajectory length or tool depth calibration is performed by the processing means located at the surface, for example.
• the processing means uses the received signal from the tool 32 and references this signal against the conventionally obtained surface measured depth to calculate a depth correction factor ⁇ .
• the correction factor ⁇ can be calculated as follows for equidistant sensor spacing (ie constant distance between sensors)
• L u tool sensor distance constant (ie the uniform distance between the sensors) ;
• Di surface depth at the first tool sensor;
• D n -i surface depth at the previous casing collar or joint;
• the correction factor ⁇ can be calculated as follows for non-uniform sensor spacing (ie non-constant distance between sensors)
• the depth correction factor ⁇ TLC thus derived can be used by the processing means to correct the conventionally obtained depth over the next travelled spacing between the sensors (either uniform or non- uniform) . If the total tool distance (that is the distance between the sensors provided m the tool 32) is less than the individual casing length, the derived multiple-calibrated correction factor ⁇ T C may be used to correct the conventionally obtained depth related input over the next downhole tool trajectory individual casing length.
• a slickline as an antenna is not limited to facilitate an increase in accuracy of tool depth measurements.
• the conventional method for detecting the status of a downhole tool or tools would be by a differential calculation involving the experience of the slickline operator in conjunction with correlated depth between distance travelled by the slickline (calculated using the conventional technique) and the location of a "nipple" in conjunction with the previously recorded "nipple" depth or tubing tally, or by other means involving physical stresses in the slickline (for example increased/decreased tension in the slickline) .
• a "nipple” is a receptacle in which the downhole tool locates and latches into, or the position in the tubing or casing string for the deployment of the downhole tool to carry out its function.
• the slickline winch operator typically sees a corresponding decrease or increase in the weight of the tool string equivalent to the weight of the tool, which would be indicative of a successful deployment or retrieval .
• the downhole tool is of a marginal weight so as not to show a significant difference m the weight of the tool string once it has been deployed or retrieved, or when circumstances inside the wellbore give a smaller indication than one of those described above (for example an obstruction m the tubing or such like)
• the status of the downhole tool is derived by conjecture until a time when the function of the tool can be operatively tested or the tool string is returned to the surface.
• the present invention facilitates a means to actively identify when a downhole tool has been deployed or retrieved etc by incorporating into the previously described apparatus one or more sensors (eg a proximity or electrically connecting/disconnecting sensor) which activates the transmission of a signal via the slickline antenna which is indicative of the status of the tool (ie latched, unlatched, engaged, disengaged etc) .
• sensors eg a proximity or electrically connecting/disconnecting sensor
• a signal from a proximity sensor or the like can be propagated to the surface using the slickline as an antenna, the signal being received at the surface and causing, for example, a second signal to be transmitted from the surface to a relay provided on the (downhole) tool to electrically or electromechanically operate an automatic locking or unlocking device. This would eliminate the requirement for mechanical hammering to initiate the functioning of the downhole tool.
• Another application of the present invention would be during the deployment of downhole tools, a part or parts of the tool itself or the tool string can loosen or be disconnected from the tool or string. This can then require several runs into the wellbore in order to recover the tool or part thereof. This can be a very expensive process.
• the tools within the tool string or the parts of the tool themselves can be coupled together either electrically or magnetically wherein discontinuity of the electrical or magnetic connection triggers a signal or a plurality of signals which can be transmitted to the surface to indicate to the slickline operator that such an event is about to occur.
• the foregoing description relates to the use of a slickline as an antenna, but it will be appreciated that it is equally possible to use a braided line or a mono- conducting slickline.
• the pulsed transmission to the surface could be replaced by a continuous type transmission, or alternatively, may be a pulsed or continuous two-way communication between the surface and a tool, using suitable transmitters and receivers (or transceivers) for such communications.
• the communication system described herein enables the use of a slickline in combination with downhole tools, such as flow meters, pressure, temperature, gravitational, sonic and seismic sensors, downhole cameras and/or optic/IR sensors which have hitherto relied on electric (single- or multi-conductor) braided slicklines for operation.
• downhole tools such as flow meters, pressure, temperature, gravitational, sonic and seismic sensors, downhole cameras and/or optic/IR sensors which have hitherto relied on electric (single- or multi-conductor) braided slicklines for operation.

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• Engineering & Computer Science (AREA)
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• Geology (AREA)
• Remote Sensing (AREA)
• Mining & Mineral Resources (AREA)
• Life Sciences & Earth Sciences (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Fluid Mechanics (AREA)
• Environmental & Geological Engineering (AREA)
• Geophysics (AREA)
• Electromagnetism (AREA)
• Geochemistry & Mineralogy (AREA)
• Measurement Of Length, Angles, Or The Like Using Electric Or Magnetic Means (AREA)
• Arrangements For Transmission Of Measured Signals (AREA)
• Earth Drilling (AREA)
• Diaphragms For Electromechanical Transducers (AREA)
• Switches With Compound Operations (AREA)
• Eye Examination Apparatus (AREA)
• Massaging Devices (AREA)
• Electrical Discharge Machining, Electrochemical Machining, And Combined Machining (AREA)
• Input Circuits Of Receivers And Coupling Of Receivers And Audio Equipment (AREA)
• Monitoring And Testing Of Transmission In General (AREA)
• Analysing Materials By The Use Of Radiation (AREA)

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• 1999
  • 1999-09-14 GB GBGB9921554.3A patent/GB9921554D0/en not_active Ceased
• 2000
  • 2000-09-12 WO PCT/GB2000/003491 patent/WO2001020129A2/en active IP Right Grant
  • 2000-09-12 AT AT00958874T patent/ATE293746T1/de not_active IP Right Cessation
  • 2000-09-12 CA CA002383316A patent/CA2383316C/en not_active Expired - Lifetime
  • 2000-09-12 EP EP00958874A patent/EP1214501B1/en not_active Expired - Lifetime
  • 2000-09-12 AU AU70286/00A patent/AU7028600A/en not_active Abandoned
  • 2000-09-12 DE DE60019620T patent/DE60019620D1/de not_active Expired - Lifetime
• 2002
  • 2002-03-14 NO NO20021279A patent/NO320707B1/no not_active IP Right Cessation

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