Method for determining the position of a movable device in an underground borehole

Abstract

 A method for determining the position of a moveable device within an underground borehole which is filled with a fluid, the method comprising:
- determining the travel time (At) of a signal transmitted through the fluid between the moveable device and a signal processing unit having a known location within or in the vicinity of the borehole, such as at the wellhead;
- assessing the velocity of the signal (v) through the borehole fluid; and
- determining the distance (d) between the moveable device and the signal processing unit by multiplying the measured travel time and the assessed velocity of the signal, (d=v.Δt).

Description

FIELD OF THE INVENTION

[0001] The invention relates to a method for determining the position of a moveable device in an underground borehole.

BACKGROUND TO THE INVENTION

[0002] If is often desirable to measure physical data, such as temperature, pressure and fluid velocity and/or composition in a borehole. However, it is not always feasible or economically attractive to provide the borehole with sensors, which are able to measure such data along the length of the wellbore over a prolonged period of time. In such circumstances so called intelligent pigs have been used to measure data, but since these pigs are pumped through the borehole they are large pieces of equipment which span the width of the borehole and therefore are not suitable to make in-situ measurements in the fluid flowing through the borehole. Also tethered sensor probes have been used to measure data in boreholes and/or other conduits, but these probes have a limited reach and involve complex and expensive reeling operations.

[0003] International patent application PCT/US97/17010 discloses an elongate autonomous robot, which is released downhole in an oil and/or gas production well by means of a launching module that is connected to a power and control unit at the surface. The elongated robot is equipped with sensors and arms and/or wheels, which allow the robot to walk, roll or crawl up and down through a lower region of the well. The insertion of the launching module into the well and the movement of the robot through the well is a complex operation and requires complex, fragile and expensive propulsion equipment.

[0004] US patent Re. 32,336 discloses an elongate well logging instrument, which is lowered into a borehole at the lower end of a drill pipe. When the pipe has reached a lower region of the borehole the logging tool is released, lowered to the bottom of a well and retrieved by means of an umbilical that extends through the drill pipe towards the wellhead.

[0005] US patent 3,086,167 discloses a borehole logging tool which is dropped through a drill string to a location just above the drill bit to take measurements during drilling. The tool can be retrieved from the drill string by means of a fishing tool.

[0006] US patents 4,560,437 and 5,553,677 and International patent application WO 93/18277 disclose other elongate downhole sensor assemblies that are removed from the well by means of a fishing tool or an umbilical.

[0007] US patent 6,241,028 discloses a moveable ball-shaped sensing device which may be released near a bottom of a well and then float together with the produced well effluents to the wellhead, whilst measuring the pressure, temperature, conductivity and other features of the well effluents throughout the length of the wellbore. The known device is equipped with a gyroscopic positioning sensor, which is a complex and bulky piece of equipment.

[0008] It is an object of the present invention to provide a method for determining the position of a moveable device in a borehole such that the use of a complex and bulky gyroscope is avoided.

SUMMARY OF THE INVENTION

[0009] In accordance with the invention there is provided a method for determining the position of a moveable device within an underground borehole which is filled with a fluid, the method comprising:

• determining the travel time (Δt) of a signal transmitted through the fluid between the moveable device and a signal processing unit having a known location within or in the vicinity of the borehole;
• assessing the velocity of the signal (v) through the borehole fluid; and
• determining the distance (d) between the moveable device and the signal processing unit by multiplying the measured travel time and the assessed velocity of the signal, (d=v.Δt).

[0010] Preferably, the signal processing unit comprises an acoustic pulsed signal transmitter, which transmits acoustic pulses into the borehole fluid in the vicinity of a wellhead of the underground borehole.

[0011] The borehole may be branched and the signal processing unit may comprise an acoustic pulsed signal transmitter, which transmits acoustic pulses into the borehole fluid in the vicinity of a branchpoint of the branched borehole.

[0012] Optionally, the moveable device has a substantially globular protective shell and is released in a borehole or well tubular which has an average internal diameter which is at least 20% larger than the average external diameter of the spherical protective shell and the sensors and data processor form part of a micro electromechanical system (MEMS) with integrated sensory, navigation, power and data storage and/or data transmission components.

[0013] The borehole may form part of an underground hydrocarbon fluid production wellbore and sensing devices having a spherical protective shell with an outer diameter which is less than 15 cm may be released sequentially in the borehole and are each induced to move along at least part of the length of the wellbore.

BRIEF DESCRIPTION OF THE FIGURES

[0014] 

Fig. 1 shows an oil and/or gas production well, which is equipped with a movable data measurement device equipped with a position determination system according to the present invention.

Fig. 2 shows an enlarged schematic three-dimensional view of a spherical sensing device shown in Fig. 1.

Fig. 3 shows an oil and/or gas production well, which is equipped with a data measurement system in which sensing devices are released at the wellhead and then roll into the well.

Fig. 4 shows a schematic enlarged three-dimensional view of a spherical sensing device for use in the system shown in Fig. 3.

Fig. 5 is a schematic longitudinal sectional view of a well in which sensing devices are released from a melting torpedo-shaped carrier tool.

Fig. 6 is a schematic longitudinal section view of a well including a processor, which is not located within the well.

Fig. 7 schematically shows a wellhead, which is equipped with a torpedo launch module.

Fig. 8 shows the launch module of Fig. 7 after the torpedo has been launched.

Fig. 9 and 10 show in more detail the lower part of the torpedo launch module during the torpedo launch procedure.

Fig. 11 shows the launch module during oil and/or gas production operations while sensor catching fingers are deployed.

Fig. 12 shows the flow sleeve in a retracted position thereof, after three sensors have been recovered.

DESCRIPTION OF A PREFERRED EMBODIMENT

[0015] Referring now to Fig. 1 there is shown an oil and/or gas production well 1 which traverses an underground formation 2 and which is equipped with a data measuring device which is equipped with a position monitoring system according to the invention. The well 1 comprises a downhole storage container 3 in which a plurality of spherical sensing devices 4 are stored.

[0016] The storage container 3 is equipped with a sensing device release mechanism 5 which releases a sensing device 4 when it is actuated by means of a telemetry signal 6 transmitted by a wireless signal source (not shown), such as a seismic source, at the earth surface 7.

[0017] The storage container 3 is installed by means of a wireline (not shown), which pulls the container 3 to the toe 8 of the well 1 or by means of a downhole tractor or robotic device (not shown), which moves the container to the toe 8 of the well 1.

[0018] The container 3 is then releasably secured near the toe 8 of the well so that it can be replaced when it is empty or if maintenance or inspection would be required.

[0019] If a sensing device 4 is released from the container 3 by the release mechanism 5 the flow 8 of oil and/or gas will drag the device 4 through the well 1 towards the wellhead 9. The release mechanism may be activated by telemetry, or may be pre-programmed to release sensing device on a time schedule or under certain conditions.

[0020] As shown in Fig. 2 the sensing device 4 has an epoxy or other robust plastic spherical shell 10 which contains a micro electro-mechanical system (MEMS) comprising a miniaturized piezo-silicon pressure sensor 11, a bi-metallic beam construct 12 for temperature measurements, a navigational acoustic signal receiver 13 and a clock which monitors the time of arrival of acoustic pulses transmitted by a and acoustic signal transmission unit at the wellhead 62 and miniature conductive optical capacitive/opacity systems that are combined into a single silicon construct or personal computer (PC)-board 14 or monolithic silicon crystal (custom-made).

[0021] The acoustic signal receiver 13 is configured to record the times of arrival of acoustic pulses transmitted at known moments in time by an acoustic transmission unit located at the wellhead 62, such that the distance d between the wellhead 9 and the device 4 when measured along the path of the borehole 1 can be determined on the basis of the time interval Δt between the time of transmission and reception of the acoustic pulses and the sound propagation velocity v in the borehole fluid, such that d=v.Δt.

[0022] A pressure port 15 in the shell 10 serves to provide open communication between the borehole fluids and the piezo-silicon pressure sensor 11 and a temperature port 16 in the shell 10 provides open communication between the borehole fluids and the bi-metallic beam construct 12 that serves as a temperature sensor.

[0023] The epoxy shell 10 is provided with circumferentially wrapped wire loops 17 encased in hard resin which function both as an antenna loop for wireless communications and as an inductive charger for the on-board high temperature battery or capacitor 18. Suitable high temperatures batteries are ceramic lithium ion batteries, which are described in International patent application WO 97/10620.

[0024] In addition to the navigational acoustic signal receiver 13 the sensing device 4 may also be equipped with hall-effect or micro-mechanical gyros to accurately measure the position of the sensing device 4 in the wellbore. The hall-effect sensors could count joints in a well casing in order to track distance.

[0025] When a sensing device 4 is released by the release mechanism 5 and travels through the well 1 the sensors 11, 12, 13 and 14 measure temperature, pressure and composition of the produced oil and/or gas or other wellbore fluids and the position of the sensing device 4 and transmit these data to a miniature random access memory (RAM) chip which forms part of the PC-board structure 14.

[0026] After the released sensing device 4 has travelled through the horizontal well inflow region 19 it flows together with the produced oil and/or gas into the production tubing 20 and then up to the wellhead 9. At or near the wellhead 9 or at nearby production facilities the sensing device 4 is retrieved by a sieve or an electromagnetic retrieving mechanism (not shown) and then the data stored in the RAM chip are downloaded by a wireless transmission method which uses the wire loops 17 as an antenna or inductive loop into a computer (not shown) in which the data are recorded, analysed and/or further processed.

[0027] The sensing devices 4 have an outer diameter of a few centimetres or less and therefore many hundreds of sensing devices 4 can be stored in the storage container 3.

[0028] By sequentially releasing a sensing device 4 into the produced well fluids, e.g. at time intervals of a few weeks or months, the system according to the invention is able to generate vast amounts of data over many years of the operating life of the well 1.

[0029] The system shown in Fig. 1 and 2 requires a minimum of down-hole infrastructure and no downhole wiring so that it can be installed in any existing well.

[0030] If a well contains a downhole obstruction, such as a downhole pump, then a sensing device catcher is to be installed downhole, upstream of the obstruction, and the data stored in the sensing device are read by the catcher and transmitted to surface, whereupon the depleted sensing device is released again and may be crushed by the pump or other obstruction.

[0031] Referring now to Fig. 3 there is shown an oil and/or gas production well 30 which traverses an underground formation 31.

[0032] The well 30 comprises a steel well casing 32 which is cemented in place by an annular body of cement 33 and a production tubing 34 which is at its lower end secured to the casing 32 by a production packer 35 and which extends up to the wellhead 36.

[0033] A frusto-conical steel guide funnel 37 is arranged at the lower end of the production tubing 34 and perforations 38 have been shot through the horizontal lower part of the casing 32 and cement annulus 33 into the surrounding oil and/or gas bearing formation 31 to facilitate inflow of oil and/or gas into the well 30.

[0034] Two sensing devices 40 are rolling in a downward direction through the production tubing 34 and casing 32 and a third sensing device is stored within a sensing device storage cage 41 at the wellhead 36.

[0035] As shown in Fig. 4 each sensing device has a spherical plastic shell 42 which houses sensing equipment and a series of chargeable batteries 43, a magnet 44, a drive motor 45, and electric motor 46 that drives a shaft 47 on which an eccentric weight 48 is placed, an inflatable rubber ring 49 and circumferentially wrapped wire loops 50 which serve both as an antenna loop for wireless communication and as an inductive charger for the batteries 43.

[0036] The magnet 44 and motor 45 which rotates the eccentric weight 48 form part of a magnetically-activated locomotion system which induces the sensing devices to roll along the inside of the steel production tubing 34 and casing 32 while remaining attached thereto. The navigation system of the sensing device includes a clock and a recorder which monitors the time of arrival of acoustic pulses that are transmitted at known moments in time by a signal processing unit near the wellhead 62 and may furthermore include a counter which counts the amount of revolutions made by the device to determine its position in the well 30.

[0037] The wellbore casing can function as a well tubular having a magnetizable wall or a longitudinal magnetizable strip or wire and when the sensing device is equipped with magnetically-activated rolling locomotion components, the casing can induce the sensing device to retain rolling contact with the tubular or longitudinal strip or wire when the sensing device traverses the wellbore. In this embodiment, the sensing device can be equipped with a revolution counter and a sensor for detecting marker points in the well tubular, such as a casing junction and/or bar code marking points, to determine its position in the well tubular.

[0038] A magnetically activated rolling locomotion system can include a magnetic rotor which actively induces the sensing device to roll in a longitudinal direction through the well tubular if the well tubular has a substantially horizontal or an upwardly sloping direction.

[0039] In the horizontal inflow region of the well 30 the motor 46 will induce the eccentric weight 48 to rotate such that the sensing device 40 rolls towards the toe 51 of the well 30. After reaching the toe 51 the motor 47 is rotated in reverse direction so that the sensing device 40 rolls back towards the guide funnel 37 at the bottom of the substantially vertical production tubing 34.

[0040] The sensing device 40 then inflates the rubber ring 49 and floats up through the production tubing 34 and back into the storage cage 41 at the wellhead in which data recorded by the device 40 during its downhole mission are retrieved via the wire loops 50 and the batteries 43 are recharged.

[0041] Apart from the revolution counter the sensing equipment of the sensing device 40 shown in Fig. 4 is similar to the sensing equipment of the device 4 shown in Fig. 2. Thus, the device 40 comprises a MEMS which includes a pressure sensor 52 that is in contact with the well fluids via a pressure port 53, a temperature sensor 54 is in contact with the well fluids via a temperature port 55, navigational accelerometers 56 and miniature conductive optical capacitance/opacity systems that are combined into an internal personal computer (PC) board 57 which comprises a central processor unit (PCU) and random access memory (RAM) system to collect, process and/or store the measured data. Some or all data can be stored in the PCU-RAM system until the device 40 is retrieved at the storage cage 41 at the wellhead 36.

[0042] Alternatively some or all data can be transmitted via the wire loops 50 as electromagnetic waves 58 towards a receiver system (not shown) which is either located at the earth surface or embedded downhole in the well 30. The latter system provides a real-time data recording and is attractive if the sensing device 40 is also equipped with an on-board camera so that a very detailed inspection of the well 30 is possible throughout many years of its operating life.

[0043] The spherical shell 42 of the sensing device 40 shown in Fig. 3 and 4 has an outer diameter, which is preferably between 5 and 15 cm, preferably between 9 and 11 cm, which is larger than the diameter of the shell 10 of the sensing device 4 shown in Fig. 1 and 2.

[0044] Optionally, the sensing devices 40 can be miniaturized to an outer width or diameter below one centimeter in a first step using nano technology and technology advances in electronics allowing for smaller foot print using less power hunger electronics and therefore reduce the size of battery etc. A further option is to further miniaturize the devices 40 such that they will enter the formation during a frac-pack or water injection and later be retrieved by a flowing well giving us formation data, not only well bore data. Experiments are currently ongoing to get/interprete formation data by measuring well bore data. These miniature devices 40 could potentially allow deployment through chemical injection lines or dedicated control lines in the future.

[0045] Alternatively a host/mother station could be lowered into the well to collect data real time during an operation like a frac-pack from short life span miniature devices with limited power supply. This could yield formation data if these miniature devices enters the formation and comes back or if they can transmit the data 10's of meters back to the host from the location in the frac-pack material in the induced fractures. US 6,978,832 B2 describes how fiber optic sensors potentially could be entered into the formation to collect formation data.

[0046] If the sensing device 40 is used in an oil and/or gas production well the outer diameter of the sensing device 40 is at least 20% smaller than the internal diameter of the production tubing 34 so that well fluids can fully flow around the spherical shell 42 of the device 40 and the device 40 does not obstruct the flux of well fluids so that the device 40 is able to collect realistic production data downhole.

[0047] If desired the same sensing device 40 may be released sequentially into the well 32 to gather production data, so that the data measurement system requires a minimal amount of equipment.

[0048] Referring now to Fig. 5 there is shown a well 60, which penetrates an underground formation 61. The well 60 has a wellhead 62, which is equipped with a launch pipe 63 via which a torpedo-shaped sensor device carrier tool 64 can be launched into the well 60.

[0049] The launch pipe 63 is equipped with an upper valve 65 and a lower valve 66. When the carrier tool 64 is inserted into the launch pipe 63 the upper valve 65 is open and the lower valve 66 is closed. Then the upper valve 64 is closed and the lower valve 65 is opened which allows the carrier tool 64 to drop into the well 60. The well 60 shown in Fig. 5 is J-shaped and is equipped with a vertical production tubing 67 in the upper part of the well 60. The lower part of the well 60 is inclined and forms the inflow zone through which oil and/or gas flow into the wellbore as indicated by arrows 68.

[0050] When the conduit is an open conduit the sensor could be inserted and released by, for example, manually dropping the sensor into the conduit.

[0051] The two carrier tools 64 that are present in the well 60 are made of a wax body in which two or more globular sensing devices 69 are embedded. The wax body may be ballasted by lead particles to provide the tools 64 with a higher density than the oil and/or gas produced in the well 60, so that the carrier tools 64 will descend to the bottom 70 of the well 60.

[0052] Alternatively, or in addition to ballast, the carrier could be motivated by a propulsion system such as, for example, a motor driven propeller or a jet of higher pressure gas 72. The motor driven propeller could be utilized to carry the sensing device into highly deviated wells, where gravity-driven deployment may not be effective.

[0053] The composition of the wax is such that it will slowly melt at the temperature at the bottom 70 of the well 60. After the wax body of the carrier tool 64 at the bottom 70 has at least been partly melted away the tool 64 disintegrates and the sensing devices 69 are released into the well as illustrated by arrow 71.

[0054] Each sensing device 69 has a lower density than the oil and/or gas in the well 60 so that the device 69 will flow up towards the wellhead 62.

[0055] The sensing devices may be equipped with a MEMS and navigational clocks and signal detectors and temperature and pressure sensors which are similar to those shown in and described with reference to Fig. 2. The data may be recorded by the sensing device 69 in the same way as described with reference to Fig. 2 and may be retrieved by a reading device after the sensing device 69 has been removed from the well fluids by a catcher at or near the wellhead 62.

[0056] The sensors of the sensing device 69 may already be activated when the carrier device 64 is dropped into the well 60 via the launch pipe 63. To allow the pressure and temperature sensors to make accurate measurements during the descent of the carrier device 64 into the well openings (not shown) must be present in the wax body of the device 64 which provide fluid communication between the pressure and temperature sensors and the well fluids. The two sensing devices 69 carried by the carrier tool 69 into the well 60 may contain different sensors.

[0057] One sensing device 69 may be equipped with pressure and temperature sensors whereas the other sensing device 69 may be equipped with a camera and videorecorder to inspect the well and with a sonar system which is able to detect the inner diameter of the well tubulars and/or the existence of corrosion and/or erosion of these tubulars and the presence of any deposits such as wax or scale within the well tubulars.

[0058] The sensing devices 69 may also be equipped with acoustic sensors, which are able to detect seismic signals produced by a seismic source which is located at the earth surface or downhole in a nearby well. In this way the sensing devices 69 are able to gather seismic data, which provide more accurate information about the underground oil and/or gas bearing strata than seismic recorders that are located at the earth surface. The acoustic sensors may collect seismic data both when the sensing device 69 descends and floats up through the well 60 and when the device 69 is positioned at a stationary position near the well bottom 70 before the waxy torpedo-shaped body of the carrier tool 64 has melted away.

[0059] Thus the sensors of the sensing device 69 may collect data not only when the device 69 moves through the well 60 but also when the device is located at a stationary position in the well 60. Furthermore, the protective shell of the sensing devices 69 may have a globular, elliptical, teardrop or any other suitable shape which allows the well fluids to flow around the sensing device 69 when the device 69 moves through the wellbore.

[0060] Referring now to Fig. 6, an alternative arrangement of the system of the present invention is shown. A processor 80 located outside of a well 83 is shown. A docket sensor 81 is shown, the docked sensor having been recovered from the fluids flowing from the well. The processor is also provided with a cable 82 providing communication to an antenna 97 for telemetric communication with the sensors within the wellbore. The well is provided with a production tubing 84 extending to below a packer 85 and extends into a 86 which is in fluid communication with the inside of the well through perforations 87, the perforations packed with permeable sand 88, and the perforations extending through cement 89 that supports the well within the wellbore. The casing includes joints 90, which can be counted by hall effect detectors in a sensor as the sensor rises through the well. Alternatively to the hall effect detectors, or in addition to the hall effect detectors, the casing and/or the production tubular could include bar codes 98 which could be read by the sensor as it rises through the well to identify which segment the data from the sensor was taken in. A ballasted sensor 91 is shown in a meltable wax ball 92 weighted by lead pellets 93. The weighted sensor can be placed in the well through a gate valve 94 which can isolate a holding volume 95 from the flowpath of the production tubing, and can be forced out of the holding volume by compressed gas through a line 96. After a sufficient amount of wax has melted, the sensor will be detached from the ballast, and rise through the well. Hall effect detectors will count the couplings passed, and either transmit data, including the passing of the couplings, to the processor outside of the well by telemetry through the antenna 83. Alternatively, the processor may be equipped with a connection for reading stored data from the sensor after the sensor is removed from the produced fluids.

[0061] Fig. 7 shows a wellhead, which included an X-mas tree 100, which is equipped with a number of valves 101 and a torpedo launch module 102.

[0062] The launch module 102 has upper and lower pressure containing chambers 103 and 104 connected by a structural member or yolk 105 holding both together. This structural member 105 has internal drillings, which communicate pressure between the chambers. By manipulating valves 106 in the system, pressure can be increased, decreased or isolated in the upper chamber 103. A polished rod 107 straddles the gap between the two chambers passing through a pressure containing seal mechanism in each chamber. This rod 107 is free to move up and down within both chambers 103 and 104 and is connected to a releasing/catching flow sleeve 108 housed in the lower pressure chamber. This sleeve is inserted into the X-mas tree bore by equalising the pressures in the upper and lower chambers through the pre-drilled pressure equalising system. When pressures in both chambers 103 and 104 are equalised the rod 107 with the sleeve 108 attached can be lowered into the tree bore as is shown in Fig. 8.

[0063] Fig. 9 shows the lower chamber 103 while the flow sleeve is in the retracted position thereof and a wax torpedo 110 in which three spherical sensors 111 are embedded is held in place by a series of locking arms 113. The locking arms 113 are pivotally connected to an intermediate sleeve 114 such that when the flow sleeve 108 is pushed down by the polished rod 107 the locking arms 113 pivot away from the tail of the torpedo 111 and the torpedo is released into the well, as is shown in Fig. 10.

[0064] Fig. 11 shows the flow sleeve 108 in its fully extended position in which a series of sensor catching fingers 115 extend into the flow sleeve. The fingers 115 will allow sensors 112 that flow up with the well fluids after dissolution of the waxy torpedo to enter into the flow sleeve 108, but prevent the sensors 112 to fall back into the well.

[0065] The flow sleeve 108 is provided with a series of orifices 116 which are smaller than the sensors 112.

[0066] When the flow sleeve 108 is fully lowered into the tree bore it straddles the outlet to the flowline and well flow is directed through the orifices 116 in the flow sleeve 108 as illustrated by arrows 117. When the sensors 112 return to the surface, carried by the well flow they are caught in the flow sleeve 108 and retained by the catching fingers 115. A detector in the sleeve 108 indicates when the sensors 112 are located in the catcher and can be recovered. To recover the sleeve 108, the valve 106 allowing pressure communication between the upper and lower pressure chambers 103 and 104 is closed. Pressure is bled off from the top pressure chamber 103. The rod 107 attached to the sleeve 108 is pushed into the upper chamber 103 due to the differential pressure between the lower and upper chambers, this in turn retracts the sleeve 108 containing the recovered sensors 112 from the X-mas tree bore as is illustrated in Fig. 12.

[0067] This invention provides a practical method to determine the location of the sensor oil-spores or other sensing devices 4 in the well 1 shown in FIG.1.

[0068] One way to determine the location of the oil-spores 4 in the well bore 1 would be to acoustically transmit a (directional) signal into the well-bore 1, and replace the navigational unit in the oil-spores 4 with an acoustically sensitive sensor and record the arrival time of the acoustic pulse. The time delay would be proportional to the distance from the source along the well bore 1.

[0069] Another way to determine location would be to use an acoustic receiver/transmitter and an accurate clock to measure time. All the clocks in the oil-spores 4 must be synchronized.

[0070] A fixed sensor/transmitter at the wellhead 9 would be used as a reference location and periodically transmit an acoustic pulse/signal. This signal would be received by the oil-spores 4and re-transmitted. All the oil-spores 4 would listen and record the time of arrival of the pulse. This time of flight information would be used to determine the distance between individual oil-spores 4.

[0071] Oil-spores 4 must be deployed in such a manner that they are within acoustic reach of each other so that the full length of the well bore 1 can be referenced to the location of the fixed transducer at the wellhead 9.

[0072] The transmitted pulse may be a coded pulse addressing specific sensors so that the re-transmit sequence is controlled and redundancy can be built into the system in case a sensor fails or is outside range.

[0073] The transmitted pulse could also be coded by varying the amplitude and/or frequency in such a way that coherent detection algorithms can be used and therefore significantly increase the reach of the system.

[0074] Another way would be to design specific acoustic repeater module with an acoustic sensor and acoustic transmitter. All the sensor oil-spores 4 would only listen and record the arrival time of the pulses sent by the acoustic repeater modules. The acoustic repeater module may include means to identify each repeater such as a unique code that could be transmitted at certain occasions.

[0075] Include a number of acoustic repeater oil-spores 4 with the sensor oil-spores, for example one acoustic repeater module for every ten sensor modules.

[0076] The mode of deployment of oil spores could be different from the deployment method described in US patent 6,241,028.

[0077] US patent 6,241,028 describes the use of a torpedo like device to deploy oil-spores 4 and release the oil-spores over time or the patent mentions fixed sensor cages that would release oil-spores at pre-determined intervals or released by a signal transmitted from the surface.

[0078] The drawback of the first deployment method is that you would leave the remnants of the torpedo like device or the size of the torpedo like device could cause it to get stuck in the hole.

[0079] The drawback of the second method would be that you would need to install the cages when you do the completion or to send in a robot to install the cage. The robot might get stuck and you have to shut in the well to do the work.

[0080] The following spore release method is simpler with less risk.

[0081] Inject fluid into the well at a pressure higher than the production pressure and release a number of oil-spores 4 per unit time into the fluid at the wellhead 9. The oil-spores 4 will then be transported down the well bore 1 by the fluid until the fluid has reached the last perforation or zone that would take fluids. Once a number of oil-spores 4 have reached the target zone the fluid injection would cease and the well would be converted into a producer. The oil-spores 4 would collect data along the full length of the well 1 as the fluid back to the surface 7 transports them. The oil-spores 4 would then be collected and the data retrieved.

[0082] All the sensor oil-spores 4 would continuously record the acoustic signals with a time stamp. This information together with the acoustic time of flight data would be used to decode the location of each sensor module. A pressure and temperature sensor would be beneficial to include in each oil-spore 4 to determine the pressure and temperature distribution along the well. The pressure and temperature information would be used to correct the speed of the acoustic signal in the fluid to allow an accurate positioning of the oil-spore sensor modules.

Claims

1. A method for determining the position of a moveable device within an underground borehole which is filled with a fluid, the method comprising:

- determining the travel time (Δt) of a signal transmitted through the fluid between the moveable device and a signal processing unit having a known location within or in the vicinity of the borehole;

- assessing the velocity of the signal (v) through the borehole fluid; and

- determining the distance (d) between the moveable device and the signal processing unit by multiplying the measured travel time and the assessed velocity of the signal, (d=v.Δt).

2. The method of claim 1, wherein the signal processing unit comprises an acoustic pulsed signal transmitter, which transmits acoustic pulses into the borehole fluid in the vicinity of a wellhead of the underground borehole.

3. The method of claim 2, wherein the borehole is branched and the signal processing unit comprises an acoustic pulsed signal transmitter, which transmits acoustic pulses into the borehole fluid in the vicinity of a branchpoint of the branched borehole.

4. The method of claim 1, wherein the moveable device has a substantially globular protective shell and is released in a borehole or well tubular which has an average internal diameter which is at least 20% larger than the average external diameter of the spherical protective shell and the sensors and data processor form part of a micro electromechanical system (MEMS) with integrated sensory, navigation, power and data storage and/or data transmission components.

5. The method of claim 4, wherein the borehole forms part of an underground hydrocarbon fluid production wellbore and sensing devices having a spherical protective shell with an outer diameter which is less than 15 cm are released sequentially in the wellbore and are each induced to move along at least part of the length of the wellbore.

6. The method of claim 5, wherein a plurality of sensing devices are stored at a downhole location near a toe of the well and released sequentially in the conduit, and each released sensing device is allowed to flow with the produced hydrocarbon fluids towards the wellhead.

7. The method of claim 6, wherein the sensing devices are stored in a storage bin which is equipped with a telemetry-activated sensing device release mechanism and each sensing device comprises a spherical epoxy shell containing a thermistor-like temperature sensor, a piezo-silicon pressure sensor and a position sensor, which sensors are powered off a chargeable battery or capacitor, and a data processor which is formed by an electronic random access memory chip.

8. The method of claim 7, wherein each sensing device comprises a spherical plastic shell which is equipped with at least one circumferentially-wrapped electrically conductive wire loop which functions as a radio-frequency or inductive antenna loop for communications and as an inductive charger for the capacitor or battery and each sensing device is exposed to an electromagnetic field at least before it is released in the wellbore by the sensing device release mechanism, and wherein each released sensing device is retrieved at or near the earth surface and then linked to a data reading and processing apparatus which removes data from the retrieved sensor device via a wireless method.

9. The method of claim 4, wherein the wellbore comprises a magnetizable element selected from the group consisting of a well tubular having a magnetizable wall and a longitudinal magnetizable strip or wire, and the sensing device is equipped with magnetically-activated rolling locomotion components which induce the sensing device to retain rolling contact with the magnetizable element when the sensing device moves over the selected longitudinal distance thorough the wellbore by the activated rolling locomotion components.

10. The method of claim 9, wherein the sensor further comprises a revolution counter which tracks distance moved and a sensor for detecting marker points in the wellbore.

11. The method of claim 10, wherein the marker points in the well are selected from the group consisting of a casing junction and/or bar code marking points.

12. The method of claim 9, wherein the magnetically-activated rolling locomotion components comprise a magnetic rotor which actively induces the sensing device to roll in a longitudinal direction through the well tubular if the well tubular has a substantially horizontal or an upwardly sloping direction.

13. The method of claim 1, wherein the sensing device is provided in a carrier that is released into the borehole at a first point of the borehole, and moves through a portion of the borehole, where the sensor is released from the carrier, and then the sensor moves back to the first point in the borehole.

14. The method of claim 13, wherein the carrier is a ballasted carrier, and the carrier is moved by gravity to a low point in the conduit.

15. The method of claim 13, wherein the carrier is moved through the borehole by a propulsion system.

16. The method of claim 13, wherein the carrier is made of a material that dissolves or melts in the borehole at the borehole temperature.

Drawing