Method for enabling well management on open well completions that are equipped with a production pip

专利摘要:
METHOD AND SYSTEM FOR WELL AND RESERVOIR MANAGEMENT IN OPEN WELL COMPLETIONS, AS WELL AS A METHOD AND SYSTEM FOR CRUDE OIL PRODUCTION The present invention relates to a method for well and reservoir management in open well completions, a module of data acquisition (100) that is advanced through the wellbore and acquires data that provides information that reveals fractures in the wellbore wall, and at least one locking system (1002, 3000), based on the acquired data, is placed in the wellbore (199, 2199, 3006) at the site of a fracture in the wall. The data acquisition module (100) is advanced by interacting with a fluid present in the wellbore and the data acquisition module acquires data that provides information about its own position in relation to the wall (3005) of the wellbore (199 , 2199, 3006) and is controlled based on said data to maintain a distance from the wall of the wellbore during its advance. A system for well and reservoir management in open well completions is additionally presented.
公开号:BR112013022520B1
申请号:R112013022520-3
申请日:2012-02-14
公开日:2021-08-31
发明作者:Wilhelmus Hubertus Paulus Maria Heijnen；Robert Bouke Peters；David Ian Brink
申请人:Maersk Olie Og Gas A/S；
IPC主号:

专利说明:

[0001] The present invention relates to a method for well and reservoir management in open well completions, in which a data acquisition module is advanced through a wellbore and obtains data that provides information that reveal fractures in a wellbore wall and where at least one blocking system, based on the data obtained, is placed in the wellbore at the location of a fracture in the wall.
[0002] To find and produce hydrocarbons, for example, petroleum oil or gaseous hydrocarbons, such as paraffins, naphthenes, aromatics and asphalt or gases such as methane, a well can be drilled in rock (or other) formations on Earth.
[0003] After the well hole is drilled in the rock formation, well pipes and accessories can be introduced into the well. The well pipes and fittings over the production or injection part of the rock formation are called the production seal lining. Pipes and fittings used to ensure the pressure and fluid integrity of the total well are called casings. Pipes and fittings that bring fluid into the rock formation or from are called pipes. The outer diameter of the sealing lining is smaller than the inner diameter of the wellbore that covers the production or injection section of the well, thus providing an annular, or annular, space between the sealing lining and the wellbore, which consists of in the rock formation. This annular space can be filled with pre-ventilated cement axial flow along the liner. However, if fluids need to enter or leave the well, small holes will be made which penetrate the casing wall and the cement in the annulus, thus allowing fluid and pressure communication between the rock formation and the well. The holes are called perforations. This project is known in the oil and natural gas industry as a coated orifice completion.
[0004] An alternative way to allow access of fluid from and to the rock formation can be performed, a so-called open well completion. This means that the well does not have a cement-filled annulus, but still has a sealing lining installed in the rock formation. The rear design is used to prevent the hole from collapsing. Yet another design is when the rock formation is judged not to collapse over time, so the well does not have a casing that covers the rock formation where fluids are produced. When used in horizontal wells, an uncoated reservoir section can be installed on the last drilled portion of the well. The well designs discussed here can be applied to vertical, horizontal and/or deviated well paths.
[0005] To produce hydrocarbons from an oil or natural gas well, a water flooding method can be used. In flood water, wells can be drilled in a pattern that alternates between injector wells and producer wells. Water is injected into injector wells, through which oil in the production zone is displaced to adjacent producer wells.
[0006] The water pressure required to press the oil into the producer wells has to overcome the fluid friction losses in the rock formation between injector and producer and has to overcome the reservoir pressure minus the hydrostatic head of the injection fluid. Water pressure, possibly combined with a low water temperature, for example on the order of 5 °C, can induce fractures in the rock of the reservoir formation. If a fracture extends from an injector well to a producer well, it can form a channel through which water can be transmitted directly from the injector well to the producer well, thus not pressing the oil or gas in front of the water to the oil or gas production well.
[0007] Water can also be transmitted through naturally occurring fractures in the rock formation and thus does not press the oil into the production well.
[0008] Knowledge of the position of such water-bearing fractures can, in the prior art, be determined by transmitting a set of petrophysical tools into the well to determine where the water is located. This can be done at an open pit completion or after cementing a seal casing in the open pit.
[0009] However, the cementation of a casing in an open well completion can be associated with several technical problems, for example: 1) the casing can run on a side rail, side rail or a leg of a well-shaped of herringbone; 2) cementation of the sealing coating cannot be carried out due to losses; 3) cementation causes fractures in the reservoir, creating a connection to another well.
[00010] Conveying petrophysical tools into wells, especially horizontal wells, is limited to the depth that can be reached by any means of transport suitable for particular well dimensions.
[00011] Therefore, it may be advantageous to be able to identify such water-bearing fractures without cementing a sealing lining at open well completion and without having to transmit petrophysical tools and logging into horizontal wells by conventional means.
[00012] Document No. 6,241,028 presents a method and system for measuring data in a fluid transport conduit, such as a well for the production of oil and/or gas. The system employs one or more miniature pickup devices comprising pickup equipment that is contained in a walnut-shaped, preferably spherical, container. However, horizontal wells do not need to be straight and additionally wells may contain obstructions such as erosion and/or well side rails, for example in fishbone shaped wells. Such conditions can prevent the above system from scanning the entire well.
[00013] In fact, an open, horizontal well completion well may comprise a main hole or a main hole with desired rail sides (fish connector well) or a main hole with unwanted/unknown side rails.
[00014] Furthermore, a horizontal open well completion well may, when producing hydrocarbons (producer well) or when being injected with water (injector well) be larger than the original drilled size due to wear and tear.
[00015] Additionally, horizontal open-hole completion wells may have wear from erosion and/or cave-ins.
[00016] Therefore, there is a need to also characterize open well completion wells to seal parts of the wellbore wall where fractures exist. Characterization can comprise, for example, measuring versus depth or time, or both, of one or more physical quantities in or about a well.
[00017] To determine such characteristics of an open pit completion, wire rope logging can be used. Wire rope logging may comprise tractor equipment that is moved downward through open pit completion during which data is documented, for example, by sensors in the tractor equipment.
[00018] However, an open pit completion can comprise soft and/or poorly consolidated formations that can present a problem for existing tractor equipment technologies. For example, chain-articulated tractor equipment can impact the wall of soft and/or poorly consolidated formations with a very large force and tractor equipment comprising gripping mechanisms can tear pieces of the soft and/or poorly open pit wall. completed. An additional problem with tractor equipment comprising gripping mechanisms is the restriction on the outside diameter, due to the drilled well, of the tractor equipment, which can restrict the length and mechanical properties of the gripping mechanisms.
[00019] An additional problem with existing tractor equipment technologies in relation to, for example, horizontal open pit completion wells, is that open pit completion can have a varying diameter of a nominal inside diameter, such as 21.6 cm (8.5 inches) of covered hole completion due to, for example, erosion and/or cave-ins.
[00020] The object of the present invention is to facilitate the exploration of wellbore of a different type in connection with the sealing of fractures in the wellbore wall.
[00021] In view of this object, the method is characterized by the fact that the data acquisition module is advanced by interacting with a fluid present in the wellbore, by the fact that the data acquisition module acquires data that provide information about its own position relative to the wall of the wellbore and is controlled based on said data to maintain a distance from the wall of the wellbore during this advance.
[00022] In this way, the data acquisition module can gently advance through the wellbore without interfering with the wellbore wall or getting stuck in cave-ins, as the data acquisition module can automatically seek to maintain a distance from the walls of the wellbore and therefore makes this advance through the wellbore in the central part of the wellbore. Therefore, it is also facilitated that the data acquisition module can traverse a wellbore that has a diameter substantially larger than a maximum outside diameter of the data acquisition module itself, which can be an advantage if, for example, the module data acquisition system has to travel through the pipe, which has a rather small diameter, to reach a part of the wellbore that has a larger diameter.
[00023] In one modality, the data acquisition module is advanced through the wellbore a first and a second time and during the second advance, the data acquisition module is advanced through at least one blocking system placed in the well hole. Therefore, it is possible to explore a wellbore already equipped with a blocking system to place an additional blocking system.
[00024] In one embodiment, the data acquisition module is advanced into the wellbore at least in part by means of liquid movement flowing through the wellbore. Thereby, the data acquisition module can simply be advanced by pumping fluid into the wellbore or by means of fluid flowing out of the wellbore.
[00025] In one embodiment, the data acquisition module is advanced into the wellbore at least partially by means of a propulsion device incorporated in the data acquisition module.
[00026] In one embodiment, the controlled radial movement of the data acquisition module with respect to the wellbore is established at least partially by means of at least one impeller or at least one jet stream. Thereby, a fast response can be obtained to move the data acquisition module in the radial direction, so that interference with the wellbore wall can be efficiently avoided.
[00027] In one embodiment, the controlled vertical movement of the data acquisition module in relation to the wellbore is established at least partially by a variable buoyancy system incorporated in the data acquisition module. Thereby, an effective response can be obtained to move the data acquisition module in the vertical direction, so that interference with the wellbore wall can be efficiently avoided.
[00028] In one embodiment, data providing information that reveals the position along the wellbore of a fracture in the wellbore wall is wirelessly communicated to a control module outside the wellbore, and the at least one locking system is placed in the wellbore at the fracture site in the wall based on data received by said control module. Thereby, the data obtained can be taken out of the wellbore, although the data acquisition module itself should not be removable. Said data can be processed outside the wellbore and/or communicated to another tool or device other than the data acquisition module to seal a part of the wellbore wall.
[00029] In one modality, an audible signal is communicated between the data acquisition module and a control module located outside the wellbore, in which the audible signal is transmitted through the fluid present in the wellbore and the position of a fracture in the wall of the wellbore is determined at least on the basis of said sound signal received by the control module or by the data acquisition module and at least on the basis of a time difference between the moment of emission of the sound signal and the moment of receipt of the beep. Thereby, the position of a fracture in the wellbore wall can be determined, rather than precisely, and possibly at the same time, being wirelessly communicated to a location outside the wellbore.
[00030] In one embodiment, data that provides information that reveals the position along the wellbore of a fracture in the wellbore wall is communicated outside the wellbore by means of a radio frequency identification (RFID) tag released by the data acquisition module, transmitted by the fluid present from the wellbore, and collected outside the wellbore. Thereby, the position of a fracture in the wellbore wall can be communicated to a location outside the wellbore, even if traditional wireless communication is impeded by, for example, environmental conditions.
[00031] In one modality, the at least one blocking system, based on at least the data acquired by the data acquisition module, is placed in the wellbore at the site of a fracture in the wall by means of a tractor equipment. pit. Thereby, the locking system can be placed even in places that are difficult to reach by traditional means, such as coiled tubing.
[00032] In one modality, an audible signal is communicated between the well tractor equipment and a control module located outside the wellbore, through which the audible signal is transmitted through the fluid present in the wellbore and the position of the well tractor equipment is determined at least on the basis of said sound signal received by the control module or by the well tractor equipment and at least based on a time difference between the sound signal emission time and the signal reception time sound. Thereby, the position of the downhole tractor equipment can be controlled very precisely so that the downhole tractor equipment reaches the correct location in the wellbore where a blocking system should be placed.
[00033] In one embodiment, the well tractor equipment pulls the at least one locking system in the form of a panel through the well hole to the location of a fracture in the wall, through which the panel is expanded until it is borderline against the wall of the wellbore and released from the well tractor equipment. Thereby, even very long panels can be transmitted through the downhole tractor equipment without the risk of the panel getting stuck in the wellbore.
[00034] In one embodiment, the well tractor equipment advances through a first panel already expanded and fixed in the well hole and pulls a second panel through the first panel. This makes it easier for even very long panels to be placed downstream of a panel already positioned in a wellbore.
[00035] In one embodiment, the data acquisition module advances through a first part of the wellbore to reach a second part of the wellbore, the at least one blocking system is placed in the second part of the wellbore and the first part of the wellbore has a diameter which is less than and preferably less than half the diameter of the second part of the wellbore.
[00036] The present invention further relates to a system for well and reservoir management in open well completions, the system comprising a data acquisition module adapted to be advanced through a wellbore and adapted to obtain data that provide information that reveal fractures in a wellbore wall and the system comprising at least one locking system and a tool adapted to, based on the obtained data, place the at least one locking system in the wellbore. well at the site of a fracture in the wall.
[00037] The system is characterized by the fact that the data acquisition module is adapted to be advanced by interacting with the fluid present in the wellbore and by the fact that the data acquisition module is adapted to obtain data that provide information about its own position in relation to the wall of the wellbore and is adapted to be controlled based on said data to maintain a distance in relation to the wall of the wellbore during this advance. Thereby, the characteristics mentioned above can be obtained.
[00038] In one embodiment, the at least one locking system is in the form of a panel adapted to be expanded from a disassembled state to an expanded state so that it becomes borderline against the wall of the wellbore and attaches to the wellbore. well and the data acquisition module has a maximum outside diameter that is less than a minimum inside diameter of the at least one panel in its expanded state. Thereby, the characteristics mentioned above can be obtained.
[00039] In one embodiment, the data acquisition module is adapted to be advancing into the wellbore at least partially by means of movement of the liquid flowing through the wellbore. Thereby, the characteristics mentioned above can be obtained.
[00040] In one embodiment, the data acquisition module comprises a propulsion device. Thereby, the characteristics mentioned above can be obtained.
[00041] In one embodiment, the data acquisition module comprises at least one impeller or at least one jet stream adapted for controlled radial movement of the data acquisition module with respect to the wellbore. Thereby, the characteristics mentioned above can be obtained.
[00042] In one embodiment, the data acquisition module comprises a variable buoyancy system adapted for the controlled vertical movement of the data acquisition module in relation to the wellbore. Thereby, the characteristics mentioned above can be obtained.
[00043] In one embodiment, the system comprises a control module adapted to be located outside the wellbore and adapted to receive wirelessly communicated data that provides information that reveals the position along the wellbore of a fracture in the wellbore wall and the system comprises a tool adapted to place the at least one wellbore locking system at the fracture site in the wall based on data received by said control module. Thereby, the characteristics mentioned above can be obtained.
[00044] In one embodiment, the system comprises a control module adapted to be located outside the wellbore, the system is adapted to communicate a sound signal between the data acquisition module and the control module, through which the sound signal is transmitted through the fluid present in the wellbore and the system is adapted to determine the position of a fracture in the wellbore wall at least based on said sound signal received by the control module or by the data acquisition module and at least based on a time difference between the time when the sound signal is issued and the time the sound signal is received. Thereby, the aforementioned characteristics can be obtained.
[00045] In one embodiment, the data acquisition module is adapted to perform various radio frequency identification (RFID) tags, to encode said radio frequency identification tags with data that provide information that reveals the position along the hole of well of a fracture in the wellbore wall and to release said radio frequency identification tags one by one during the advancement of the data acquisition module through the wellbore. Thereby, the aforementioned characteristics can be obtained.
[00046] In one embodiment, the tool adapted to place the at least one locking system in the wellbore is a well tractor equipment. Thereby, the aforementioned characteristics can be obtained.
[00047] In one embodiment, the system is adapted to communicate a sound signal between the well tractor equipment and a control module located outside the wellbore, whereby the sound signal is transmitted through the fluid present in the wellbore well and the system is adapted to determine the position of the well tractor equipment at least based on said sound signal received by the control module or by the well tractor equipment and at least based on a time difference between the moment of emission of the beep and the moment of receipt of the beep. Thereby, the aforementioned characteristics can be obtained.
[00048] In one embodiment, the well tractor equipment is adapted to pull the at least one locking system in the form of a panel through the wellbore to the location of a fracture in the wall and the system is adapted to expand the panel until it is abutting against the wall of the wellbore and to release the panel from the well tractor equipment. Thereby, the aforementioned characteristics can be obtained.
[00049] In one embodiment, the system comprises at least a first and a second panel and the well tractor equipment is adapted to advance through the first panel that is already expanded and fixed in the wellbore and to subsequently pull the second of the panel through the first panel. Thereby, the aforementioned characteristics can be obtained.
[00050] In one embodiment, the system comprises a pipe adapted to form a first part of a wellbore, said wellbore having a second part with a diameter that is greater than, and preferably greater than twice , the diameter of the first part and the data acquisition module is adapted to advance through said pipe, forming the first part of the wellbore to reach the second part of the wellbore and advance through the second part of the wellbore. Thereby, the aforementioned characteristics can be obtained.
[00051] The invention will now be explained in greater detail through examples of modalities with reference to the very schematic drawing, in which
[00052] Figure 1 shows a sectional view of an embodiment of a data acquisition module in the form of a device 100 for examining a tubular channel comprising a first, second and third part.
[00053] Figure 1A shows a device pumped down into the tubular channel.
[00054] Figure 1B shows a device connected to an external communication unit.
[00055] Figure 2 shows the device's finishing bottleneck.
[00056] Figure 3 shows a cross-sectional view of the finishing neck of the device.
[00057] Figure 4 shows an embodiment of a device 100 for examining a tubular channel comprising buoyancy means.
[00058] Figure 5 shows an embodiment of a device 100 for examining a tubular channel comprising jet nozzle means.
[00059] Figure 6 shows an embodiment of a device 100 for examining a tubular channel comprising means for contracting the flexible member.
[00060] Figure 7 shows an increase of the first part of a device modality.
[00061] Figure 8 shows an embodiment of a device for examining a tubular channel comprising a front and rear arrangement of detectors.
[00062] Figure 9 shows an embodiment of a device for examining a tubular channel comprising a second high pressure cylinder.
[00063] Figure 10 shows an embodiment of a device for examining a tubular channel comprising a compass.
[00064] Figure 11 shows an embodiment of a device for examining a tubular channel comprising a clock.
[00065] Figure 12 shows a sectional view of a device 2100 for moving in a tubular channel 2199.
[00066] Figure 13 shows a sectional view of an inflatable and deflatable handle means 2101.
[00067] Figure 14 shows a sectional view of a modality of a device 2100 for moving in a tubular channel 2199 comprising two inflatable and deflatable handle means, G1, G2.
[00068] Figure 15 shows a schematic diagram of a modality of a pumping unit 2308 adapted to translate the connecting rod 2305.
[00069] Figure 16 shows a schematic diagram of an embodiment of a pumping unit 2308 adapted to inflate and/or deflate the first and second inflatable and deflatable handle means G1, G2.
[00070] Figure 17 shows a method for moving device 2100 in a tubular channel 2199.
[00071] Figure 18 shows the angle between the tubular and vertical channel.
[00072] Figure 19 shows a sectional view of a modality of a device for moving in a tubular channel comprising directional means.
[00073] Figure 20 schematically shows a part of a net or cage of elongated members in which the elongated members are connected through intermediate links capable of rotating around them, thus increasing the distance between the elongated members, the part of the network is seen from one end.
[00074] Figure 21 schematically shows the net or cage in Figure 20 seen in sectional view A-A.
[00075] Figure 22 schematically shows a part of the network in Figure 20 and 21 in an expanded position.
[00076] Figure 23 schematically shows a net or cage mounted in a collapsed position.
[00077] Figure 24 schematically shows a net or cage in an expanded position.
[00078] Figure 25 schematically shows a collapsed net or cage placed inside a net or cage in an expanded position, with the outer circles representing the bag or bellows that must be inflated, thereby sealing against the well hole wall in a final adjustment position.
[00079] Figure 26 schematically shows a valve to be used during inflation of the bag or bellows.
[00080] Figure 27 schematically shows a panel apparatus, including a laying tool, with the panel apparatus in the expanded position.
[00081] Figure 28 schematically shows the panel apparatus when installed in a perforated section in a rock formation, with the intermediate connections not shown.
[00082] Figure 29 schematically shows a side view of a cross-section through the middle of an embodiment of an elongated member, in which an intermediate link (not shown) is to be positioned and locked.
[00083] Figure 30 schematically shows a front view of a sectional cut through the middle of an embodiment of an elongated member, in which an intermediate link (not shown) must be positioned and locked.
[00084] Figure 31 schematically shows a laying tool, a panel and a tractor equipment that are coupled to form an assembly.
[00085] Figure 32 schematically shows a laying tool and a tractor equipment that are coupled and advance through a first panel already expanded and fixed in the well hole.Device and system for examining a tubular channel
[00086] Figures 1 to 11 illustrate modalities, according to the invention, of employing a data acquisition module to advance through a wellbore to acquire data that provide information that reveal fractures in the wellbore wall, whereby at least one locking system, based on the acquired data, can be placed in the wellbore at the site of a fracture in the wall. Although the modalities of the data acquisition module discussed below comprise several features, many of these features may not be necessary to carry out the method according to the invention or may not necessarily be composed by the system according to the invention. According to the invention, the data acquisition module is adapted to be advanced by interacting with a fluid present in the wellbore, which means that it is adapted to be transmitted by means of fluid flowing in the wellbore or that it is adapted to propel itself through interaction with the fluid present in the wellbore. Furthermore, according to the invention, the data acquisition module acquires data that provides information about its own position in relation to the wall of the wellbore and is controlled based on said data to maintain a distance in relation to the wall of the wellbore of well during its advance. This means that the data acquisition module is adapted to steer radially relative to the wellbore based on its current position in the wellbore; however, this can be with or without interaction with other devices, such as a remote control unit, for example.
[00087] The person versed in the art will understand that the following modalities of a data acquisition module present examples of the data acquisition module, according to the invention, but that several other modalities are possible within the scope of the invention.
[00088] Figure 1 illustrates a sectional view of an embodiment of a data acquisition module in the form of a device 100 for examining a tubular channel 199; the device 100 comprising a first 101, a second 102 and a third 103 parts. In the above and below a tubular channel can be exemplified by a bore, a tube, a fluid filled conduit and an oil tube.
[00089] The tubular channel 199 may contain a fluid. In the above and below, the fluid in the tubular channel can be exemplified by water, hydrocarbons, for example, petroleum oil or gaseous hydrocarbons, such as paraffins, naphthenes, aromatics, asphalts and/or methane or gases with hydrocarbon chains plus long products such as butane or propane or any mixture thereof.
[00090] In one embodiment as illustrated in Figure 1A, the device 100 can, for example, be pumped down into the tubular channel 199 without any physical connection/connection with the surface/inlet of the tubular channel 199. , device 100 can be powered by batteries or obtain its power from the rock formation and/or fluids in the well. Furthermore, hydrogen cells or combustion processes can be used to power the device. In the case of batteries, the batteries can be powered/charged by ambient temperature differences through thermoelectric couples and/or by a rotor driven by the movement of the fluid around device 100, activating a dynamo that is electrically coupled to the batteries. A control module outside the wellbore in the form of an external communication unit 102A, such as a computer coupled with communication to an acoustic modem, situated in proximity to the input of the tubular channel 199 can communicate with the device 100, for example, through the acoustic modem. In this way, data providing information revealing the position along the wellbore 199 of a fracture in the wellbore wall can be communicated wirelessly to a control module in the form of a communication unit 102A outside the wellbore, and at least one blocking system 1002, 3000 exemplified below can be replaced in the wellbore at the fracture site in the wall based on data received by said control module.
[00091] In an alternative embodiment, as illustrated in Figure 1B, the device 100 can be connected through, for example, a wire 101B to an external communication unit 102A, such as a computer, located in proximity to the entrance of the tubular channel 199 The external communication unit 102A can supply power to the device 100 through wire which power would drive the device 100 down into the tubular channel 199. Additionally or alternatively, the external communication unit 102A can communicate with the device 100 through the of yarn 101B.
[00092] The device 100 may comprise a first part 101, a second part 102 and a third part 103.
[00093] The three parts 101, 102 and 103 can, for example, be cast or molded in plastic or aluminum or any other material or combinations thereof suitable for high pressure support, which, in high pressure wells, can go up to 200,000 kPa (2,000 bar) and temperatures ranging, for example, from 40 °C at a shallow depth to 200 °C and higher in the case of a high well temperature.
[00094] The first part 101 may, for example, contain a cylindrical part 104 and a hemispherical cover part 105. The first part 101 may also contain several sensors.
[00095] For example, the first part can contain several ultrasonic V sensors, for example 4 ultrasonic sensors, to determine the relative fluid velocity about the first part 101. An ultrasonic sensor can be represented by a transducer. Ultrasonic V sensors can be contained within the first part 101, for example within the cylindrical part 104. The ultrasonic V sensors can provide data representing a fluid velocity.
[00096] Additionally, the first part 101 may, for example, include several D ultrasonic distance sensors, for example 13 ultrasonic distance sensors. The number of ultrasonic distance sensors can provide data representing a distance to, for example, the surrounding tubular channel 199. The ultrasonic distance sensors can be contained within the first part 101. For example, 10 ultrasonic distance sensors can be contained in the cylindrical part 104 of the first part 101, for example, on a circumference of the cylindrical part 104 and thereby providing data representing a distance between the cylindrical part 104 and the surrounding tubular channel 199, and 3 ultrasonic distance sensors - only ones can be contained in the hemispherical covering part 105, for example, in front of the hemispherical covering part 105 which provides data representing a distance between the hemispherical covering part and, for example, potential obstacles such as cave-ins /erosions in front of device 100.
[00097] The ultrasonic sensors and the ultrasonic distance sensors of the first part may be probing fluid surrounding the device 100 and the tubular channel 199 through, for example, a glass window, so that the sensors are protected against the fluid flowing in the tubular channel 199.
[00098] The first part may additionally comprise a pressure sensor P. The pressure sensor P may be contained in the hemispherical cover part 105. The pressure sensor P may provide data representing a pressure of a fluid surrounding the device 100.
[00099] Furthermore, the first part may contain an ohmmeter R to measure the resistivity of the fluid surrounding the device 100. The ohmmeter may be contained in the hemispherical cover part 105. The ohmmeter may provide data representing the resistivity of the surrounding fluid the device 100.
[000100] In addition, the first part may contain a temperature sensor T to measure the temperature of the fluid surrounding the device 100. The temperature sensor T may be contained in the hemispherical cover part 105. The temperature sensor T may provide data that represent a temperature of the fluid surrounding the device 100.
[000101] The first part may additionally comprise a position determining unit 107 which provides data representing the position of the first part 101 and therefore allows the position tagging of the data from the aforementioned sensors. Position tagging can, for example, be carried out in relation, for example, to the inlet of the tubular channel 199.
[000102] In one embodiment, the position determination unit 107 can comprise Gyro gyroscopes and a Compass compass and G-forces accelerometers and a tilt meter (inclinometer) Tilt meter.
[000103] The device 100 may further comprise a programmable logic controller (PLC) 180 contained, for example, in the first 101 or in the third part 103. One or more of the above sensors, that is, the ultrasonic V sensors, the ultrasonic distance sensors D, pressure sensor P, ohmmeter R, temperature sensor T and position determination unit 107 can be connected to the PLC via, for example, a wire and an analog-to-digital converter ( A/D) and a multiplexer 109. For example, the PLC can be connected via the respective wires and the analog to digital converter (AD) and a multiplexer 109 for the ultrasonic V sensors, the ultrasonic D distance sensors and the unit of position determination 107. Through a number of data input from the sensors, the PLC is able to determine the environment and position of device 100 and calculate a control signal representing how device 100 should be shaken. Therefore, the PLC 180 can determine how to navigate through the tubular channel 199 through one or more of the steering mechanisms presented below, that is, in Figures 2, 3, 4 and 5 and associated text. For example, the PLC 180 can be coupled with communication, for example, via electrical wires, to each of the steering mechanisms, and the PLC 180 can control the steering mechanisms through the control signal. In this way, the data acquisition module can obtain data that provides information about its own position in relation to the wall 3005 of the wellbore 3006 and can be controlled based on said data to maintain a distance from the wall of the wellbore during this advance in the wellbore.
[000104] By inputting data from one or more of the sensors described above, the PLC or a 102A control module outside the wellbore may be able to provide information that reveals fractures in the wellbore wall; especially the position along the wellbore of such fractures.
[000105] The second part 102 may comprise a two-part bar ("fish connector") 202 and 203 connected via a ball joint 201, as seen in Figure 2. The two-part bar 202, 203 may have a cross-section cylindrical and can be hollow. Furthermore, the two-part bar 202, 203 can connect the first part 101 to the third part 103 through the ball joint 201. As shown in the Figure, a first part 202 of the two-part bar 202, 203 can be connected to the first part 101 of device 100 and a second part 203 the two-part bar 202, 203 may be connected to the third part 103 of device 100.
[000106] One of the parts of the two-part bar, for example the second part 203, may contain a bar 204 physically connected at one end 207 to the ball joint 201, for example, through glue, solder joint, or the like. The other end 208 of the bar may be connected to a first end 209 of a spring 205. The other end 210 of the spring 205 may be physically connected to a side 206 of the second part 102 of the device 100, for example, the side also connected to the second part 203 of the two-part bar. The force exerted by the spring on the side 206 and the other end 208 of the bar 204 is of such magnitude as to keep the device 100, i.e., the first part 202 and the second part 203 of the two-part bar, in a straight line (eg 180 degrees +/- 1 degree between the first part and the second part of the two part bar) through the ball joint 201 when none of the cylinders shown above is activated.
[000107] A cross-sectional view along line AA in Figure 2 is shown in Figure 3. Figure 3 illustrates three cylinders 301. The cylinders 301 can, for example, be hydraulic or mechanical or a combination of hydraulic and mechanical cylinders (For example, a first cylinder can be mechanical and a second and third cylinder can be hydraulic).
[000108] Each cylinder may comprise a cylinder body 302 and a piston 303. The cylinder bodies 302 may be connected to the inner wall of the second part 203 of the two-part bar. The connection can be carried out, for example, by a solder joint or a screw or glue or the like. Pistons 303 may be connected to the other end of bar 208, for example, by solder, glue, screw, or the like joints.
[000109] The bodies 302 of the cylinders 301 can, for example, be placed at a separation of 120 degrees along the circumference of the inner wall of the second part 203 of the two-part bar.
[000110] To navigate the device 100, one or more of the cylinders can be activated to move the bar 204 from the equilibrium position determined by the spring 205. The cylinders 301 may be able to move the bar 204 in any position. In Figure 3, for example, the top cylinder 301 was activated and displaced the bar 204 from its spring determined equilibrium position determined by the intersection of the two lines X and Y. Thereby, the straight line between the first part 202 and the second part 203 of the two-part bar is modified, for example, to 135 degrees +/- 1 degree, where the longitudinal axis of the device 100 is flexed around the spherical joint 201.
[000111] If the three cylinders are hydraulic, then spring 205 can be replaced by springs in the cylinders, so that when the cylinders are not activated, the spring forces of the springs in the cylinders are of such magnitude as to maintain the device 100, that is, the first part 202 and the second part 203 of the two-part bar, in a straight line. Springs are located in the cylinders pressing on the pistons, for example, between pistons 303 and bar 204.
[000112] In one embodiment, the springs between the pistons 303 and the bar 204 can be pressure springs.
[000113] The bar 204 and the ball joint 201 can be hollow so as, for example, to allow the passage of an electrical wire from the first part 101 to the third part 103 through the two-part bar and the ball joint 201 and bar 204. Additionally, bar 204 and ball joint 201 may allow the passage of a tube, e.g., a high pressure tube.
[000114] Therefore, the device 100 can be navigated by controlling the cylinders 301 and thereby the fish connector of the device 100.
[000115] In one embodiment, data from one or more of the sensors in the first part 101 can be transmitted to the third part 103 via an electrical wire from the first part 101 to the third part 103 through the spherical union 201 and from bar 204.
[000116] In one embodiment, the high pressure cylinder 407 of Figure 4 can be in fluid communication with the three hydraulic cylinders of Figure 2, for example, through high pressure pipes and their valves and restrictors (to provide more accuracy to fluid flow by limiting the volume per unit of time). Thereby, the three hydraulic cylinders 301 can be energized by the high pressure cylinder 407. The amount of second fluid transferred from the high pressure cylinder 407 to the cylinders 301 can be controlled by the PLC 180 through the control signal when controlling the valves.
[000117] In the above and below, the second fluid contained in the high pressure cylinder 407 can be chosen from the group of fluids that are known to expand when pressure drops. The most effective fluids are therefore gaseous. For example, nitrogen or helium or hydrocarbon gas or CO2 could be used as the second fluid with which cylinder 407 is filled.
[000118] In an alternative mode, the three cylinders can be mechanical cylinders being controlled and driven by motors which, in turn, are powered, for example, by batteries or any other alternative energy source.
[000119] Alternatively, in the mode where the device is connected via a wire to an external communication unit 102A positioned in proximity to the input that supplies power to the device 100 via the wire, the three cylinders can be powered via the wire.
[000120] The third part 103 of device 100 may comprise a communication means 108, such as an acoustic modem that allows communication between device 100 and the surface, for example, the external communication unit 102A positioned in proximity to the channel input tubular 199. For example, device 100 may transmit data from one or more of the sensors to external communication unit 102A via communication means 108.
[000121] In one mode, repeaters can be used in connection with the acoustic modem. A repeater can pick up a signal from the acoustic modem from device 100 (or another repeater) and amplify the received signal to its original strength. Thereby, the distance over which the device can communicate with the external communication unit 102A can be increased. Repeaters may, for example, be pumped down into tubular channel 199, for example, when/if the signal received from communication means 108 of device 100 falls below a threshold value, for example, 10 dBm.
[000122] Alternatively or additionally, the communication means 108 may comprise a number of radio frequency identification (RFID) tags, for example 100 RFID tags. RFID tags can be released from device 100 at a regular time interval, for example, an RFID tag every 2 minutes, and, prior to release, an RFID tag would be printed with the data recorded by the sensors at the position of your release. When device 100 travels a required distance, for example, to the end of tubular channel 199, the RFID tags can be brought up and retrieved at the entrance of tubular channel 199, for example, at the surface of the well, during the fluid production. On the surface of the well, the RFID tags can be read. Other microchips, which can contain data such as memory components on a USB device, can also be used. The requirement to get the data is that the well has to be produced so that RFID or other memory devices like memory chips will be brought to the surface.
[000123] In this way, data that provides information that reveals the position along wellbore 199 of a fracture in the wellbore wall can be communicated outside the wellbore by means of a radio frequency identification (RFID) tag released by the data acquisition module 100, transmitted by the fluid present in the wellbore and collected outside the wellbore.
[000124] In one embodiment, the RFID tags can be comprised in the device 100, for example, in the third part 103 and the RFID tags can be released from the device 100, for example, through a tube at the rear end of the third part 03, i.e. the end facing away from the second part 102. Through a controlled detonation carried out by a detonation means in fluid communication with the tube, an RFID tag can be released at certain intervals controlled by the PLC 180. For example , PLC 180 can control the detonation means.
[000125] In one embodiment, the communication means 108 can also be adapted to receive acoustic signals from the input of the tubular channel, allowing, by means, a two-way communication between the external communication means 102A which comprises an acoustic modem and is positioned in proximity to the input of the tubular channel 199 and the device 100. Thereby, the device 100 can, for example, receive control data from the external communication unit 102A via the communication means 108.
[000126] The third part may additionally comprise a valve controller 106 to control several valves, as shown below.
[000127] In addition, the third part 103 may comprise an analog to digital (A/D) converter and a multiplexer 109. The A/D converter and the multiplexer may receive analog data, for example, from one or more sensors in the first part 101 via an electrical wire and processing the analog data into digital data which, for example, can be transmitted to the well surface via the communication means 108 and/or via a wire 101B and/or the data can be processed by PLC 180.
[000128] The device 100 may further comprise a flexible member 109. For example, the flexible member may comprise arms 110 made of titanium and a texture 111 made of aramid. Flexible member 109 may have a hemispherical shape, as indicated in Figure 1, and device 100 may, for example, be able to adjust the maximum outer diameter of the hemispherical shape to between, for example, 88.9 mm (3.5 inches). ) and 215.9 mm (8.5 inches). The outside diameter is limited by the fact that the flexible member cannot expand more than the aforementioned 215.9 mm (8.5 inches) because the flexible member has reached its maximum outside diameter. In a tubular channel with an inside diameter below 215.9 mm (8.5 inches), the outside diameter of the flexible member can be determined by the inside diameter of the tubular channel.
[000129] Thereby, the device is able to travel through the pipeline and therefore the top completion of a well does not have to be removed (pulled) to run the device inside the well.
[000130] In fact, by means of this, the data acquisition module 100 can advance through a first part of the wellbore 199, 2199, 3006 to reach a second part of the wellbore, at least one blocking system 1002 , 3000 can be placed in the second wellbore part and the first wellbore part can have a diameter which is less than, and preferably less than half of, the diameter of the second wellbore part.
[000131] The flexible member 109 can, for example, be fixed to the first part 101. For example, the first part 101 can comprise a cylindrical fixing part 112 to which the flexible member 09 can be fixed, for example, by couplings by welding or a spherical bearing. The projection of the flexible member on the second part 102 can be varied and can depend on the outer diameter of the hemispherical shape. If, for example, the flexible member 109 is fully expanded (maximum outer diameter), then the projection of the flexible member 109 onto the second portion 102 (i.e., the longitudinal axis of the device 100) is minimal. If, for example, the flexible member 109 is fully collapsed (minimum outer diameter), then the projection of the flexible member 109 into the second part 102 is maximum. Alternatively or additionally, the projection of the flexible member 109 on the second part 102 can be varied by changing the angle of the flexible member. Changing the flex member angle will cause an unbalanced pressing force on the flex member against the geometry axis of the device, which will move the device away from the geometry axis.
[000132] The flexible member 109 can, for example, be used to propel the device 100 down into the tubular channel 199. By applying pressure to the inlet 198, the side of the tubular channel 199 can expand the flexible member 109 to its maximum size , wherein device 100 can be pushed down into tubular channel 199. If, for example, device 100 encounters a cave-in (or erosion) in its path, device 100 can change the maximum outer diameter of the flexible member in a manner allowing the passage of the device 100 through the cave-in by adapting the outer diameter of the device 100 to the diameter of the cave-in.
[000133] Figure 4 shows an embodiment of a device 100 for examining a tubular channel comprising buoyancy means 401. The device 100 of Figure 4 may comprise the technical characteristics described under Figures 1 and/or 2 and/or 3.
[000134] The buoyancy means 401 can provide a controlled vertical movement of the data acquisition module in the form of the device 100 with respect to the wellbore.
[000135] Furthermore, the device of Figure 4 may comprise a buoyancy means 401 (for example, flotation tanks or hydrophores) in the first part 101 and in the third part 103. Each of the buoyancy means 401 may comprise a bellows of 402 rubber contained in a 403 titanium cylinder. Instead of a 402 rubber bellows, of course, other suitable arrangements may be employed, such as a balloon-type device, a metal bellows or a cylinder with a displaceable piston. The 403 titanium cylinders prevent the 402 rubber bellows from bursting. The titanium cylinders 403 further comprise an inlet/outlet 404 which allows fluid from the tubular channel 199 to enter or exit. The titanium cylinder inlet/outlet 404 can be covered with a permeable metal membrane.
[000136] The first part 101 and the third part 103 may each additionally comprise a valve arrangement 409, 410, for example, in the form of a three-way valve V1, V2. The three-way valve V1, V2 can be fluidly coupled to the respective rubber bellows 402, for example through respective tubes 405. Furthermore, the three-way valves V1, V2 can be fluidly coupled to the fluid in the channel tube through respective vent lines 406. Additionally, each of the three-way valves V1, V2 can be fluidly coupled to a high pressure cylinder 407, e.g. located in the second part 102 of device 100, through respective tubes 408. High pressure cylinder 407 may contain a second fluid. Naturally, the distribution and arrangement of the different valves of the valve arrangement, the high pressure cylinder 407, the vent lines 406 and the piping connecting these parts may be different from that mentioned and shown in the Figures.
[000137] The valve arrangements 409, 410, for example, in the form of three-way valves V1, V2, can be controlled by the valve controller 106, illustrated in Figure 1, which can be coupled with communication to the three-way valves V1, V2, for example, through an electrical wire. The valve controller 106 can, for example, receive control signals from the PLC which directs the valve controller 106 to increase and/or decrease the buoyancy of the buoyancy means 401, in accordance with the calculation results obtained by the PLC. The PLC can be coupled with communication to the valve controller 106, for example, via an electrical wire.
[000138] With the use of the high pressure cylinder 407, the valve arrangements 409, 410 and the buoyancy means 401, the device 100 is able to control its buoyancy.
[000139] For example, in case the rubber bellows 402 is filled with a second fluid, for example N2, and the buoyancy is decreased, i.e. the device 100 has to dive, then the three-way valve V1. V2 is open between the rubber bellows 402 and the vent line N2 406, through which the fluid from the tubular channel 199 can enter the titanium cylinder 403 through the permeable metal membrane 404 and, simultaneously, the second fluid can flow out of the rubber bellows 402 through the N2 vent line 406 due to the elastic pressure exerted by the rubber bellows 402 on the second fluid. When the buoyancy of the device decreases enough, for example determined by one or more of the sensors and the PLC 108, the three-way valve 406 is set in a closed position upon receiving a control signal from the PLC 180.
[000140] Subsequently, if the buoyancy of the device 100 is increased, i.e. the device 100 has to be lifted, then the three-way valve V1, V2 is opened between the rubber bellows 402 and the high pressure cylinder 407, wherein the second fluid from the high pressure cylinder 407, eg N2, is pressed into the rubber bellows 402. Thereby the rubber bellows 402 expands and therefore displaces the fluid, eg. fluid from the tubular channel, present in the titanium cylinder 403 through the permeable metal membrane 404. When the buoyancy of the device has increased sufficiently, for example, determined by one or more of the sensors and the PLC 108, the three-way valve 406 is set in a closed position when receiving a control signal from the PLC 180.
[000141] Valve arrangements 409, 410 may, alternatively to the three-way valves V1, V2 described above, be composed of simple on/off valves, for example in the form of solenoid valves. Any other valve suitable for opening and closing a pipe connection can also be used. For example, each of the three-way valves V1, V2 can be replaced by a first and a second on/off valve, with the first on/off valve connecting the high pressure cylinder 407 and the bellows. rubber 402, and the second on/off valve connecting the rubber bellows 402 and the vent line 406. For example, the second on/off valve can be connected separately through its own tubing to the rubber bellows 402 , whereby the first on/off valve can be similarly connected via its own piping to the rubber bellows 402 (this modality is not, however, shown in the Figures). Alternatively, the second on/off valve can be connected, for example, via a T-connection, with a piping connecting the first on/off valve and the rubber bellows 402. Any other suitable valve arrangement for filling and emptying the 402 rubber bellows with fluid can be employed.
[000142] In the case of simple on/off valves or a functionally equivalent type of valve, the first on/off valve can be opened to let the second fluid, eg N2, flows into the bellows of rubber 402 and the second on/off valve can be opened to let the second fluid escape from the rubber bellows 402. When the rubber bellows 402 is filled with the second fluid to increase buoyancy, of course, the second on/off valve should normally be substantially closed to prevent second fluid from escaping from rubber bellows 402.
[000143] In one embodiment, a rotor/propeller can be attached to the permeable metal membrane 404 or placed within the permeable metal membrane, so that the rotor is dilated when the fluid from the tubular channel 199 flows in or out, through of the permeable metal membrane 404. Thereby, the rotor is able to act as a dynamo and, if device 100 is powered by batteries, the rotor can be selectively coupled, for example, via an electrical wire, to the batteries of the device 100, and thereby the batteries can be recharged by the rotor.
[000144] In one embodiment, valve arrangements 409, 410, for example, in the form of three-way valves V1, V2, can be equipped with a flow restriction to limit the volume of flow per unit of time to, for means of this, allow a certain precision of the three-way valves.
[000145] Therefore, the device 100 can be navigated by controlling its buoyancy with the use of the high pressure cylinder 407, a valve arrangement 409, 410 and the buoyancy means 401. The buoyancy of the device 100 can be controlled by the PLC 180 receiving data from the sensors and transmitting a control signal to valve arrangements 409, 410. Alternatively, buoyancy of device 100 may be controlled by external communication unit 102A which receives data from the sensors and transmits a control signal to the valve arrangements 409, 410.
[000146] In one embodiment, the buoyancy means 401 can be used, for example, to navigate the first part 101 up or down relative to the spherical joint 201, for example, by increasing the buoyancy of the buoyancy means 401 in the first part 101, for example, by pumping the second fluid from the high pressure cylinder 407, e.g. N2, into the rubber bellows 402 of the first part 101, thereby displacing fluid from the titanium cylinder. 403 to the tubular channel, and/or decreasing the buoyancy of the buoyancy means 401 in the third part 103, for example, by displacing the second fluid from the rubber bellows 402 with fluid from the tubular channel 199 in the titanium cylinder 403 of the third part 103 , as described above.
[000147] Figure 5 shows an embodiment of a device 100 for examining a tubular channel comprising jet nozzle means. Device 100 of Figure 5 may or may not comprise part or all of the technical features described in Figures 1 and/or 2 and/or 3 and/or 4.
[000148] Furthermore, the device of Figure 5 may comprise jet nozzle means 501 in the first part 101 and in the third part 103.
[000149] Each of the jet nozzle means 501 may comprise a number of nozzles 502, for example 5 nozzles, through which a jet of second fluid can be launched. Additionally, the jet nozzle means 501 may comprise a valve arrangement 503. The valve arrangement 503 may be fluidly coupled to the high pressure cylinder 407 through, for example, respective high pressure tubes 504. valve arrangement 503 can be fluidly coupled to each of the nozzles through respective high pressure tubes 505.
[000150] The nozzles 502 can be placed in the third part 103 and the front of the first part 101, as seen in Figure 5. In addition, the nozzles can be in fluid communication with the fluid in the tubular channel 199, thereby enabling that each nozzle ejects the second fluid, e.g., a high pressure fluid, from the high pressure cylinder 407 when allowed to do so through valve arrangement 502. Valve arrangement 503 can be coupled with communication to PLC 180, for example, via electrical wires, so that the valve arrangement 503 can be controlled by the PLC 180, for example, based on the sensor data processed by the PLC 180.
[000151] If, for example, the device 100 moves straight forward, the valve arrangement 501 can open a valve between the high pressure cylinder 407 and the center nozzle 502 in the valve arrangement 503 of the third part 103, stabilizing, hereby, a fluid coupling between the high pressure cylinder 407 and the central nozzle 502. Therefore, the second fluid can be propelled from the high pressure cylinder 407 through the central nozzle 502 straight back into the fluid of the tubular channel 199 Therefore, device 100 will move in the opposite direction to the second driven fluid, due to conservation of momentum, ie, straight forward.
[000152] If, for example, the device 100 is to move back and down, the valve arrangement 501 can open a valve between the high pressure cylinder 407 and the upper nozzle 502 in the first part 101, establishing, by means of Furthermore, a fluid coupling between the high pressure cylinder 407 and the upper nozzle 502. Therefore, the second fluid can be propelled from the high pressure cylinder 407 through the upper nozzle 502 upwards and forwards towards the fluid in the channel. tubular 199. Therefore, device 100 will move in the opposite direction to the thrust of the second fluid due to conservation of momentum, ie, downward and backward.
[000153] Therefore, the device 100 can be navigated using the nozzles 502, the valve arrangement 501 and the high pressure cylinder 407. The second fluid ejected from the nozzles of the device 100 can be controlled by the PLC 180 which receives data from the sensors and transmits a control signal to valve arrangement 503 which controls the valve fluidly coupled to the nozzle(s) from which the second fluid is to be ejected. Alternatively, the second fluid ejected from the nozzles of device 100 may be controlled by external communication unit 102A which receives data from the sensors and transmits a control signal to a valve arrangement 503.
[000154] In an alternative embodiment, the jet nozzle means 501 described above and shown in Figure 5 can be replaced or supplemented by various thrusters or similar devices (not shown) adapted to provide a thrust that can propel and/or change the direction of device 100 for examining a tubular channel. Said thrusters or similar devices can be powered by electric motors or in any other suitable way. Especially, the jet nozzle means 501 described above or the above mentioned alternative or supplementary thrusters or similar devices can provide a controlled radial movement of the data acquisition module in the form of device 100 with respect to the wellbore.
[000155] Figure 6 shows an embodiment of a device 100 for examining a tubular channel comprising means for contracting the flexible member. Device 100 of Figure 6 may comprise the technical features described under Figures 1 and/or 2 and/or 3 and/or 4 and/or 5.
[000156] Furthermore, the device 100 of Figure 6 may, in the first part 101, comprise a disc 601, for example, positioned in the cylindrical fixation part 112, with which disc 601 the arms 110 of the flexible member 109 can be in physical contact . Furthermore, the arms 110 can be attached to the cylindrical attachment portion 112 through the spherical bearing 602 or the like, allowing the flexible arms 110 to rotate around the spherical bearing 602. Thereby, by rotating the disc 601 to the right of the Figure 6, the arms 110 can be collapsed and by rotating the disc 601 to the left of Figure 6, the arms can be expanded, for example, due to fluid pressure in the tubular channel 199. In addition, the first part 101 can comprise a spring 603, a second swivel bar 604, and electromagnet 605 further described in Figure 7.
[000157] Figure 7 shows an enlargement of the first part 101 of the device 100 of Figure 6. Figure 7A) is a side view of the first part 101 and Figure 7B) is a front view. The first part comprises the spherical bearings 602, the arms 110, the disk 601, the electromagnet 605, the spring 603 and the second swivel bar 604. Additionally, the first part comprises a pin 701 fixed to one end of the disk 601. The pin is additionally connected to spring 603 which may be a pull spring. Spring 603 pulls pin 701 attached to disk 601 to the right of Figure 7. Thereby, the other end of pin 701 pushes a plate 702. Plate 702 is held in place at one end by a second plate 703 and at the the other end by the swivel bar 604. The second plate 703 is held in place by the electromagnet 605 and one end to a first swivel bar 704 and the other end holds the first end of the plate 702. Therefore, when the power to the electromagnet 605 is terminated , the electromagnet 605 releases the second plate 703, which rotates around the first swivel bar 704. Thereby, the first end of the plate 702 is released and the plate 702 rotates around the second swivel bar 604, enabling the pin 701 move to the right of Figure 7, where the disk 601 is moved to the right, thus exerting a force on the arms 110. Thereby, the arms 110 and therefore the texture 111 are collapsed.
[000158] With the above design, the force required to hold the pin 701 in position is small, eg on the order of half a Newton.
[000159] By being able to decrease the outer diameter of the device 100 through the flexible member 109, the device 100 can adjust its outer diameter according to obstructions in the tubular channel 199. The device 100 can likewise adjust its outer diameter to advance through a locking system, for example, in the form of a panel-like apparatus 3000, already placed in the tubular channel 199. or the like, the device is capable of collapsing the flexible member 109 by means for contracting the flexible member shown in relation to Figure 6 and Figure 7. In one embodiment, the PLC 180 can be coupled with communication to the electromagnet 605. a control signal for the electromagnet 605, the PLC 180 can control the electromagnet 605, for example, in the case where the speed of the device 100 is zero m/s for a given period, for example, one minute. Upon receiving the control signal, the electromagnet can be deactivated and thereby collapse the flexible member as shown above.
[000160] In one embodiment, the electromagnet 605 can be replaced with an acid soluble member and the pin 701 can be released by providing contact between the acid soluble member 605 and the plate 703. Thereby, the plate 703 can be notched, whereby the first end of plate 702 is released and plate 702 rotates about second swivel bar 604 which allows pin 701 to move to the right of Figure 7, wherein disk 601 is moved to the right, thus exerting a force on the arms 110. By this, the arms 110 and therefore also the texture 111 are collapsed.
[000161] In one embodiment, device 100 may comprise a mechanical arm or similar device, such as a balloon or bellows, which may be used to press device 100 from a wall of tubular channel 199 opposite to the direction. in which you want to move the device 100.
[000162] As an example, the device 100 may be heading towards a wall of the tubular channel 199. The ultrasonic distance sensors transmit data to the PLC which determines that, to avoid the wall, the upper front nozzle should eject the second fluid. Subsequently, PLC 180 transmits a control signal that indicates how much and/or how long the valve in valve arrangement 503 that controls the upper front nozzle should open to valve arrangement 503. When valve arrangement 503 receives the signal control, the valve fluidly coupled to the upper front nozzle is opened and a jet of second fluid is ejected from the nozzle.
[000163] Furthermore, as an example, device 100 may be heading towards an extension of a fish connector well. The ultrasonic distance sensors transmit data to the PLC, which determines that, to avoid extending the fish connector well, the buoyancy of device 100 should be increased. Subsequently, the PLC 180 transmits a control signal which indicates how much and/or the extent of the valve arrangements 409, 410 which control fluid coupling between the rubber bellows 402 and the high pressure cylinder 407 should open. When valve arrangements 409, 410 receive the control signal, the valves open in accordance with the control signal and the second fluid from high pressure cylinder 407 enters rubber bellows 402, thereby increasing the buoyancy of the device 100.
[000164] In one embodiment, the device 100 can be pumped down by means of the flexible member 109, as shown above, for a certain length of the tubular channel 199, for example, the covered part of the tubular channel 199, and from the same, i.e. in the open pit completion pit portion, the device may additionally or exclusively propel itself through nozzles 502 or equivalent thrusters as shown above.
[000165] In one embodiment, the device 100 can be lowered a certain distance from the tubular channel 199 by gravity, for example, until the angle between the tubular channel 199 and the vertical exceeds a certain angle, such as 60 degrees, at which the The gravitational force in most cases is not high enough to overcome the friction between the fluid and the device 100. From that point, the device 100 can propel itself through one or more of the means described above, e.g. jet nozzle 501 or thrusters and/or flexible member 109.
[000166] In one embodiment, device 100 can be connected to tractor equipment that can move a distance in tubular channel 199, for example, to an area of interest of a user of device 100, and subsequently device 100 can be released from the tractor equipment to propel itself through one or more of the means presented above, for example, the jet nozzle means 501 or thrusters and/or the flexible member 109.
[000167] In one embodiment, the device 100 may be connected to a drill assembly via a wire. The perforation assembly may be positioned in proximity to the external communication unit 102A (e.g., which contains the external communication unit 102A) on the surface of the tubular channel 199. Alternatively, the perforation assembly may be positioned on the tubular channel 199.
[000168] Figure 8 shows an embodiment of a device 100 for examining a tubular channel comprising a front F and rear R arrangement of detectors. Device 100 of Figure 8 may comprise the technical features described in Figures 1 and/or 2 and/or 3 and/or 4 and/or 5 and/or 6 and/or 7.
[000169] In an embodiment of Figure 8, each of the front and rear arrays of detectors comprises a number of ultrasonic distance sensors.
[000170] The front arrangement of ultrasonic distance sensors F can, for example, comprise the number of ultrasonic distance sensors D contained in the cylindrical part 104 of the first part 101, for example, in the circumference of the cylindrical part 104 and thereby , provide data representing a distance between the cylindrical part 104 and the surrounding tubular channel 199, as shown in relation to Figure 1. For example, the number of ultrasonic distance sensors D may be 10.
[000171] The rear array R of ultrasonic distance sensors 801 can comprise a number of ultrasonic distance sensors 801, eg 10 ultrasonic distance sensors. The number of ultrasonic distance sensors 801 can provide data representing a distance to, for example, the surrounding tubular channel 199. The ultrasonic distance sensors 801 can be contained in the third part 103. For example, the 10 ultrasonic distance sensors 801 can be contained in a cylindrical part of the third part 103, for example in a circumference of the cylindrical part, and thereby provide data representing a distance between the cylindrical part and the surrounding tubular channel 199.
[000172] The distance between the front F and rear R arrays of the ultrasonic distance sensors is known and can for example be XY mm, for example 300 mm.
[000173] As the device 100 travels in the tubular channel, the front arrangement and the rear arrangement of the ultrasonic distance sensors record the respective values of the tubular channel. For example, the front and rear arrangements can determine the diameter of the tubular channel.
[000174] The front and rear arrangements of the ultrasonic sensors can be connected to the PLC, for example, through a wire and an analog to digital converter (A/D) and a multiplexer 109.
[000175] Furthermore, when the PLC received a measurement of a diameter of the tubular channel from the front arrangement, it can start a timer such as a clock or the like. When the PLC receives an identical or substantially identical measurement (for example, 9 out of 10 ultrasonic sensors in the rear arrangement measure similar values to the sensors in the front arrangement), the PLC determines a time interval between receiving the measurement from the front arrangement and the measurement of the later arrangement. Based on the distance between the front and rear arrays and the time interval, the PLC is able to determine a speed of device 100 in the tubular channel.
[000176] In an embodiment of Figure 8, each of the front and rear arrays of detectors comprises a number of image sensors. Additionally, the device may comprise a light emitting diode in proximity to each of the image sensors.
[000177] The distance between the front F and rear R arrays of the image sensors is known and may, for example, be XY mm, for example 300 mm.
[000178] For example, the front array can transmit a registered image to the PLC. The PLC can perform at least one image processing, for example the use of geometric hashing to determine at least one parameter representative of the image.
[000179] Subsequently, the PLC can perform similar image processing on images received from the rear array, and, when a match is found between a front array image and a rear array image, a time interval between receiving the two images is determined and based on the distance between the front and rear arrays and the time interval, the PLC is able to determine a speed of the device 100 in the tubular channel.
[000180] In one embodiment, device 100 may comprise a pilot tube that allows an accurate determination of fluid velocity relative to device 100.
[000181] Figure 9 shows an embodiment of a device 100 for examining a tubular channel comprising a second high pressure cylinder 901. The device 100 of Figure 9 may comprise the technical features described in Figures 1 and/or 2 and/or 3 and/or 4 and/or 5 and/or 6 and/or 7 and/or 8.
[000182] High pressure cylinder 901 may contain a gas such as nitrogen or the like. Furthermore, device 100 can be hermetically sealed. Furthermore, device 100 can be hollow. Additionally, the second high pressure cylinder can be coupled with communication to the PLC, so that the PLC can control the second high pressure cylinder 901.
[000183] The device may further comprise a second pressure sensor 902 coupled with communication to the PLC.
[000184] An external pressure measured by the P pressure sensors and an internal pressure measured by the 902 pressure sensor can be transmitted to the PLC. Based on the difference between the measured pressures, the PLC can control the second high pressure cylinder 901 to emit gas to thereby increase the internal pressure and thereby reduce the difference between the measured pressures. In one embodiment, the PLC controls the second high pressure cylinder 901 to emit gas to equalize or substantially equalize (for example, the internal pressure is at 5% of the external pressure) the internal pressure and the external pressure.
[000185] Equalizing or substantially equalizing the internal and external pressures allows the device walls to be thin and light because they are not subjected to a large pressure differential.
[000186] Figure 10 shows an embodiment of a device 100 for examining a tubular channel comprising a compass 1001. The device 100 of Figure 10 may comprise the technical characteristics described under Figures 1 and/or 2 and/or 3 and/ or 4 and/or 5 and/or 6 and/or 7 and/or 8 and/or 9.
[000187] The device 100 may comprise a compass 1001 positioned in front of the device 100, for example, in the hemispherical cover part 105 of the first part 101, as shown in Figure 1. The compass may be coupled with communication, for example, through from an electrical wire or Bluetooth to the PLC and can allow the detection of, for example, one or more small 1003, 1004 magnets placed in one or more structures contained in the tubular channel.
[000188] For example, the structure can be a blocking system, for example, in the form of a panel 1002, placed by a tractor equipment to prevent water leakage in a hydrocarbon production well 1005. The blocking system 1002 it may contain a first magnet 1003, for example, aligned so that the south pole (S) of the magnet is pointing radially into the well and positioned so as to demarcate the start of the blocking system seen from the well inlet. the locking system may contain a second magnet 1004, for example, aligned so that the north pole (N) of the magnet is pointing radially into the well and positioned so as to demarcate the end of the locking system as seen from the inlet of the pit.
[000189] When the device 100 passes the start of the lock system 1002, the compass 1001 will change its orientation due to the first magnet 1003 and will indicate that the device 100 has passed through a magnetic element, for example, a part of a lock system 1002 When device 100 passes the end of interlock system 1002, compass 1001 will change its orientation due to the presence of second magnet 1004 and indicate that device 100 passes a magnetic element, e.g., a part of interlock system 1002.
[000190] In one embodiment, the locking system can comprise a number of magnets, for example three magnets, at each end, so that it is able to provide a specific signal for the beginning and end of the locking system. For example, the three magnets placed at the beginning of the locking system are aligned so that the south pole of the first magnet, the north pole of the second magnet, and the south pole of the third magnet are all pointing radially into the well 1005. for example, the three magnets placed at the end of locking system 1002 can be aligned so that the north pole of the first magnet, the south pole of the second magnet, and the north pole of the third magnet are all pointing radially into the well. 1005. Hereby, accurate identification of the start and end of the blocking system 1002 is possible. Other combinations of number of magnets and alignment of magnets are possible, such as SSS poles at the beginning and NNN poles at the end of the locking system.
[000191] In one modality, the PLC can use the information related to the start and end of the blocking system to, for example, control the speed and position of the device 100 in the well.
[000192] Figure 11 shows an embodiment of a device 100 for examining a tubular channel comprising a clock 1101. The device 100 of Figure 1 may comprise the technical characteristics described in Figures 1 and/or 2 and/or 3 and/or 4 and/or 5 and/or 6 and/or 7 and/or 8 and/or 9 and/or 10.
[000193] The device may comprise a clock 1101 contained, for example, in the PLC. Another clock 1102 can be contained in a wellhead 1103 positioned at the entrance of the tubular channel 199. Additionally, an ultrasonic transducer 1104 can be placed in the wellhead 1103. The clock 1102 and the ultrasonic transducer 1104 can both form part of or belong to a 102A control module placed outside the wellbore.
[000194] Clock 1101 in device 100 and clock 1102 in wellhead 1103 can be synchronized. Furthermore, the ultrasonic transducer 1104 can be programmed to transmit an ultrasonic signal to the tubular channel 199 towards device 100 at predetermined time intervals, eg 1 minute after device 100 leaves the wellhead, 2 minutes after, etc.
[000195] The device 100 can contain a log, for example, in the PLC, which includes information about when the signals are transmitted to the tubular channel 199 by the ultrasonic transducer 1104. Furthermore, the device 100 can determine the time difference between the moment of receiving a signal and the timing of actual transmission of the signal from transducer 1104. By knowing the speed of sound in the fluid in which the device is currently moving, the PLC can determine the distance traveled by device 100 at the time of receipt of the signal from transducer 1104 by multiplying the time difference by the velocity of sound in the fluid. For example, if the time difference between the moment of transmission and the moment of a signal is determined to be 5 seconds and the fluid is water in which the speed of sound is approximately 1,484 m/s, then the device has traveled approximately 7,420 m in the tubular channel 199. The device 100 can transmit the traveled distance to the external communication unit 102A via the acoustic modem 108.
[000196] In one embodiment, the external communication unit 102A can calculate the velocity of the fluid leaving the well. For example, the external communication unit may know the frequency at which the device 100 transmits (via, for example, the acoustic modem 108) a signal representing the distance traveled by the device 100. Thereafter, the external communication unit 102A may determine the Doppler shift in the frequency of the received signal and, from the Doppler shift, the velocity of the fluid in which the signal from device 100 is transmitted can be determined.
[000197] As described above, an audible signal can be communicated between the data acquisition module 100 and the control module 102A located outside the wellbore 199, where the audible signal can be transmitted through the fluid present in the borehole of wellbore and the position of a fracture in the wellbore wall can be determined at least based on said sound signal received by the control module or by the data acquisition module and at least based on a time difference between the moment of emission of the sound signal and the moment of receipt of the sound signal. Device and system for movement in a tubular channel
[000198] Figures 12 to 19 illustrate modalities according to the invention of employing a well tractor equipment for advancing through a wellbore to, based on data obtained by a data acquisition module (as exemplified by embodiments of Figures 1 to 11), place at least one locking system in the wellbore at the site of a fracture in the wall. Although the modalities of the well tractor equipment discussed below comprise several features, many of these features may not necessarily be in order to carry out the method according to the invention or may not necessarily be comprised by the system according to the invention. According to the invention, the at least one locking system can, in fact, be placed in the wellbore by means of tools other than a downhole tractor equipment, such as, for example, by coiled tubing.
[000199] The person skilled in the art will understand that the following modalities of a well tractor equipment present examples of a well tractor equipment that can be employed to carry out the invention, but that several other modalities are possible within the scope of the invention.
[000200] Figure 12 shows a sectional view of a well tractor equipment in the form of a device 2100 to move in a tubular channel 2199. As described above and below, a tubular channel can be exemplified by a hole, a pipe, a fluid filled conduit, and an oil tube.
[000201] The tubular channel 2199 can contain a fluid, such as hydrocarbons, for example, petroleum hydrocarbons, such as paraffins, naphthenes, aromatics and asphalts.
[000202] The device 2100 comprises inflatable and deflatable grip means 2101. The inflatable and deflatable grip means 2101 may, for example, be the flexible bellows which can adapt to the wall condition of the tubular channel 2199. The grip exerted by the device 2100 on the wall of the tubular channel 2199 depends on the pressure of the flexible bellows 2101 on the wall of the tubular channel 2199. The device 2100 further comprises a piece 2102 to which the inflatable and deflatable grip means 2101 can be attached and which it can be at least partially covered by the inflatable and deflatable grip means 2101. For example, the part 2102 can be in the form of a stick and the inflatable and deflatable grip means 2101 can be shaped like a tire without a tube and therefore , when attached to the stick-shaped part 2102, for example by a glue or the like, covers a part of the stick-shaped part 2102.
[000203] Figure 13 shows a sectional view of the inflatable and deflatable handle means 2101. The flexible bellows 2101 may comprise a woven texture bellows 2202, for example, made of woven aramid and/or Kevlar, and a sealed flexible bellows backpressure 2201, for example, made of a rubber or other flexible material and sealed against air/pressure/fluid. The backpressure sealed flexible bellows 2201 is covered by the woven texture 2202. The backpressure sealed flexible bellows 2201 provides the pressure integrity of the inflatable and deflatable handle means 2101.
[000204] The backpressure sealed flexible bellows 2201 can be secured to the part 202 by a first curved ring, for example in parabolic shape 2204 that provides a gradual clamping force along the horizontal geometric axis 2207 of the part 2102, in which the pinching and subsequent rupture of the pressure-sealed flexible bellows 2201 due to an internal pressure of the pressure-sealed flexible bellows 2201 can be avoided. The first curved ring 2204 can be secured to the part 2102 by a fastening means 2206 such as a screw, nail or the like. The first curved ring 2204 must be back pressure sealed, i.e. it must provide the pressure sealed flexible bellows 2201 seal to the part 2102, but may have any clamping force.
[000205] The woven texture bellows 2202 can be clamped between the first curved ring 2204 and a second curved ring, for example in parabolic shape 2203. The first and second curved rings therefore provide a gradual gripping force along the length. of the horizontal axis 2207 of part 2102, wherein pinching and fraying of the woven texture bellows 2202 can be avoided. The second curved ring 2203 can be secured to the part 2102 by a fastening means 2205, such as a screw, nail or the like. The second curved ring 2203 can be positioned on top of the first curved ring 2204, as illustrated in Figure 13. The second curved ring 2202 must be strong to maintain the shape of the woven texture, but can provide any pressure resistance, i.e. it is not necessary to seal back pressure.
[000206] The woven texture bellows 2202 can provide a shape of the pressure sealed flexible bellows 2201 so that the pressure sealed flexible bellows 2201 can not be over-tensioned and/or deformed beyond its permissible elastic range. In addition, the 2202 woven texture bellows provides physical strength and wear resistance to the 2201 back pressure sealed flexible bellows.
[000207] The curved rings can further provide format stability of the inflatable and deflatable grip means 2101. In addition, the curved rings can prohibit sharp edges, so that multiple inflations/deflations of the inflatable and deflatable grip means 2101 can be achieved.
[000208] In one embodiment, the woven texture 2202 can be converted with ceramic particles to provide wear resistance of the woven texture 2202.
[000209] Figure 14 shows a sectional view of an embodiment of a device 2100 for moving in a tubular channel 2199 comprising two inflatable and deflatable handle means, G1, G2. Device 2100 comprises a hydrophore 2301 attached to a pump section E which comprises a pumping unit 2308 and a programmable logic controller (PLC) 2309.
[000210] The hydrophore 2301 can, for example, be a covered rubber bellows or substantially covered in a steel cylinder. The hydrophore 2301 may contain oil (or any other pumpable fluid). The hydrophore prevents the oil from spilling out, for example, when the pressure changes and/or when the temperature changes. For example, the temperature at the inlet of the tubular channel 2199 may be -10°C and in the tubular channel 2199 the temperature may be 2100°C. Additionally, for example, the pressure at the inlet of the tubular channel 2199 may be 100 kPa (1 bar) and in the tubular channel 2199 the pressure may be 25,000 kPa (250 bar).
[000211] The pump section E may further comprise a battery which forensics power to the device 2100. Alternatively or additionally, the device 2100 may comprise a plug/socket for receiving a steel cable, through which the device 2100 can be fed. For example, the plug/socket may be located on oil tank 2301, eg on the end facing away from pump section E.
[000212] The pumping unit 2308 can, for example, comprise a bidirectional fixed displacement hydraulic pump.
[000213] The PLC 2309 can be coupled with communication, eg via an electrical wire, to a 2310 short-range radio unit, eg a Bluetooth unit.
[000214] Furthermore, attached to and partially or fully surrounding the pump section E is a first inflatable and deflatable grip means G1. The first inflatable and deflatable grip means G1 may be of the type shown in Figure 13. The first inflatable and deflatable grip means G1 may comprise a fluid, such as an oil or the like, which can be pumped by the pumping unit 2308 .
[000215] There is additionally attached to the pump section E a cylinder section 2302. The cylinder section 2302 comprises a reservoir A, for example an oil reservoir and a pressure chamber 2303 comprising a first piston pressure chamber B and a second piston pressure chamber C.
[000216] The cylinder section 2302 further comprises a piston 2304 fixed to a connecting rod 2305. A first end of connecting rod 2305 is located in oil reservoir A and the other end of connecting rod 2305 is fixed to a sensor section 2306. The sensor section 2306 is therefore fixed to the device 2100 via the connecting rod 2305. The connecting rod 2305 can translate along the longitudinal axis 2307 of the device 2100. The connecting rod 2305 can being hollow, that is, allowing, for example, a fluid to pass through it. Piston 2304 is located in pressure chamber 2303.
[000217] The oil reservoir and the first pressure chamber of the piston B and the second pressure chamber of the piston C may comprise a pumpable fluid, such as an oil or the like, which can be pumped by the pumping unit 2308. oil A can be sealed from pressure chamber 2303.
[000218] Attached to and partially or fully covering sensor section 2306 is a second inflatable and deflatable handle means G2. The second inflatable and deflatable handle means G2 may be of the type shown in Figure 13. The second inflatable and deflatable handle means G2 may comprise a fluid such as an oil or the like which can be pumped by the pumping unit 2308.
[000219] Furthermore, the sensor section 2306 may comprise a number of sensors F. For example, the sensor section 2306 may contain a number of ultrasonic sensors for determining the relative fluid velocity around the sensor section 2306. A sensor Ultrasonic can be represented by a transducer. Ultrasonic sensors can be contained in sensor section 2306. Ultrasonic sensors can provide data representing a fluid velocity.
[000220] Additionally, sensor section 2306 may, for example, include a number of distance sensors. The number of ultrasonic distance sensors can provide data representing a distance to, for example, the surrounding tubular channel 2199. Ultrasonic distance sensors can be contained in sensor section 2306. Ultrasonic distance sensors can provide data that represents a distance between sensor section 2306 and surrounding tubular channel 2199, i.e. data representing a radial view. Furthermore, ultrasonic distance sensors can provide data representing a distance between sensor section 2306 and, for example, potential obstacles such as cave-ins/erosions in front of device 2100, ie data representing a front view .
[000221] The ultrasonic sensors and the ultrasonic distance sensors of the sensor section 2306 may be probing the fluid surrounding the device 2100 and the tubular channel 2199 through, for example, glass windows, so that the sensors are protected against fluid flow in tubular channel 2199.
[000222] The sensor section 2306 may additionally comprise a pressure sensor. The pressure sensor may be contained in sensor section 2306. The pressure sensor may provide data representing a pressure of a fluid surrounding device 2100.
[000223] In addition, the sensor section 2306 may contain a resistivity meter to measure the resistivity of the fluid surrounding the device 2100. The resistivity meter may be contained in the sensor section 2306. The resistivity meter may provide data representing the resistivity of the fluid surrounding the 2100 device.
[000224] In addition, the sensor section 2306 may contain a temperature sensor to measure the temperature of the fluid surrounding the device 2100. The temperature sensor may be contained in the sensor section 2306. The temperature sensor may provide data representing a temperature of the fluid surrounding the 2100 device.
[000225] The sensor section 2306 can additionally comprise a position determination unit that provides data representing the position of the device 2100 and therefore allows the position tagging of the data from the aforementioned sensors. Position labeling can, for example, be carried out in relation to, for example, the inlet of the tubular channel 2199.
[000226] In one embodiment, the position determining unit may comprise a plurality of Gyro gyroscopes, for example, three gyroscopes (one for each of the three dimensional geometric axes) and a Compass Compass and a plurality of G-accelerometers forces, for example, three accelerometers (one for each of the three dimensional geometric axes) and a Tilt meter (inclinometer).
[000227] The sensor section 2306 may further contain a short-range radio unit 2311, such as a Bluetooth unit, capable of establishing a short-range radio link to the PLC 2309. In addition, the short-range radio unit range can be coupled with communication, for example via an electrical wire, to one or more of the aforementioned sensors and thereby the sensor section 2306 is allowed to transmit data from one or more F sensors to the PLC 2309 through the short range radio link.
[000228] The PLC 2309 can be coupled with communication, for example, through electrical wires, to the pumping unit 2308, where the PLC is able to control the pumping unit 2308, for example, by transmitting a control signal to the pump 2400 of pump unit 2308.
[000229] Figure 15 shows a schematic diagram of a modality of a pumping unit 2308 adapted to translate the connecting rod 2305. The pumping unit of Figure 15 may be contained in a device, as shown in relation to Figure 14 and /or 17 and/or 19.
[000230] The pumping unit 2308 comprises the pump 2400 of the pump section E. Furthermore, the pumping unit 2308 comprises a backflow valve 2401 and the oil tank 2301. The pump 2400, for example, a low pump pressure, is fluidly coupled, for example, through a tube 2402, to the backflow valve 2401 and through valve 2401 and a tube 2402 to the oil tank 2301. Additionally, the pump 2400 is fluidly coupled, by for example, through a tube 2403, to the second pressure chamber of the piston C and, for example, through a tube 2404, to the first pressure chamber of the piston B of the pressure chamber 2303.
[000231] The pumping unit 2308 is able, for example, in response to a control signal from the PLC 2309, to translate the piston 2304 and thereby the connecting rod 2305 along the longitudinal axis 2307 of the device 2100.
[000232] For example, to translate the piston 2304 towards the first pressure chamber of piston B, ie to the left in Figure 15, the PLC 2309 can transmit a control signal to the pump 2400, so that the pump 2400 begins to pump fluid from the first pressure chamber of piston B to the second pressure chamber of piston C through tube 2404. Thereby, the first pressure chamber of piston B is depressurized and the second pressure chamber of Piston C is pressurized and thereby the piston moves towards the first pressure chamber of piston B.
[000233] For example, to translate the piston 2304 towards the second pressure chamber of the piston C, that is, to the right in Figure 15, the PLC 2309 can transmit a control signal to the pump 2400, so that the pump 2400 begins to pump fluid from the second pressure chamber of piston C to the first pressure chamber of piston B through tube 2404. Thereby, the second pressure chamber of piston C is depressurized and the first chamber of The pressure of piston B is pressurized and thereby the piston moves towards the second pressure chamber of piston C.
[000234] The PLC 2309 can transmit a control signal to the additional pump 2400 to stop the pump 2400 when the piston 2304, and thereby also connecting rod 2305, has been moved a distance determined by the PLC based on the data received from one or more sensors. Alternatively or additionally, the pump 2400 may receive a stop signal from the PLC 2309 when the piston 2304 reaches an end wall of the pressure chamber 2303, e.g., by having a switch, e.g., a pressure switch, attached to the interior. of each of the end walls of pressure chamber 2303 that sense when piston 2304 abuts one of the end walls. The switches can be coupled with communication, for example via electrical wires, to the PLC 2309.
[000235] Figure 16 shows a schematic diagram of an embodiment of a pumping unit 2308 adapted to inflate and/or deflate the first and second inflatable and deflatable handle means G1, G2. The pumping unit of Figure 16 may be contained in a device as described in relation to Figure 14 and/or 17 and/or 19.
[000236] The pumping unit 2308 comprises the pump 2400 of the pump section E. In addition, the pumping unit 2308 comprises the backflow valve 2401 and the oil tank 2301. In addition, the pumping unit 2308 may comprise a valve relief valve 2501, the oil reservoir, the connecting rod 2305 and the first and second inflatable and deflatable grip means G1, G2.
[000237] The pressure relief valve 2501 can, for example, determine the pressure in the pump unit 2308.
[000238] The pump 2400, for example a low pressure pump, is fluidly coupled, for example, through a tube 2402, to the backflow valve 2401 and through valve 2401 and a tube 2406 to the oil tank 2301.
[000239] Additionally, the pump 2400 is fluidly coupled, for example, through a tube 2503, to the first inflatable and deflatable grip means G1 and, for example, through a tube 2504, to the second inflatable grip means and inflatable G2. Tube 2504 may further fluidly couple pump 2400 to pressure relief valve 2501. Pressure relief valve 2501 may be fluidly coupled through, for example, a tube 2505, to oil tank 2301 .
[000240] The pump unit 2308 is capable of, for example, in response to a control signal from the PLC 2309, inflating one of the inflatable and inflatable handle means while deflating the other.
[000241] For example, to inflate the first inflatable and deflatable grip means G1, the PLC 2309 can transmit a control signal to the pump 2400, so that the pump 2400 starts to pump fluid from the second grip means G2 for the first inflatable and deflatable grip means G1 via connecting rod 2305, oil reservoir A and tube 2504. Thereby, the second inflatable and deflatable grip means G2 deflates while the first grip means inflatable and deflatable G1 inflates.
[000242] For example, to inflate the second inflatable and deflatable grip means G2, the PLC 2309 can transmit a control signal to the pump 2400 so that the pump 2400 starts pumping fluid from the first inflatable and deflatable grip means G1 to the second inflatable and deflatable grip means G2 through the tube 2504, the oil reservoir A and the connecting rod 2305. Thereby, the first inflatable and deflatable grip means G1 deflates while the second inflatable and deflatable grip means G2 inflates.
[000243] The 2309 PLC can transmit a control signal to the additional 2400 pump to stop the 2400 pump when the inflatable and deflatable grip means have a volume that provides a sufficient grip on the wall of the tubular channel. The sufficient grip in the tubular channel can, for example, be determined by the pressure relief valve 2501, i.e., as long as the valve is close, the pump 2400 pumps from one inflatable and deflatable grip means to the other inflatable grip means and inflatable. Once the pressure relief valve 2501 opens, the pump pumps from the inflatable and deflatable handle means to be deflated to the oil tank via the pressure relief valve 2501.
[000244] The pressure relief valve 2501 can be coupled with communication to the PLC 2309, for example, via a wire. Once pressure relief valve 2501 opens, it can transmit a control signal to the PLC 2309 which subsequently transmits a control signal to pump 2400, stopping pump 2400. Once the pressure in pump unit 2500 reaches the pressure relief valve reset pressure, the pressure relief valve closes again.
[000245] Figure 17 shows a method for moving the device 2100 in a tubular channel 2199.
[000246] In a first step, the device 2100, for example, which contains a load such as a locking system or the like, can be moved to the entire tubular channel by a lubricating steel cable. Device 2100 can be moved in such a way as long as the angle, as shown in Figure 18, between tubular channel 2199 and vertical 2601 is less than 60 degrees. When the angle becomes equal to or greater than 60 degrees, the friction between device 2100 and tubular channel 2199 and/or the fluid in tubular channel 2199 may be greater than the gravitational force in device 2100, thus preventing device 2100 move additionally in that way. By moving device 2100 through a lubricating steel cable, both the first and second inflatable and deflatable handle means G1, G2 can be deflated to facilitate movement of device 2100 through tubular channel 2199.
[000247] Therefore, in a second step, the device is powered, comprising the start of the sensors F in the sensor section 2306. The power-up can further comprise a test of all sensors and communication between the short-range radio unit 2310 and 2311.
[000248] In a third step, as illustrated in Figure 17A), the first inflatable and deflatable grip means G1 is inflated. In the case that device 2100 has just been energized, both inflatable and deflatable grip means G1, G2 are deflated and therefore inflation is carried out by pumping fluid from oil tank 2301 through tube 2406, backflow valve 2401, pump tube 2308 and tube 2503 into the inflatable and deflatable handle means G1.
[000249] In a fourth step, the sensor section 2306 is translated (pressed) to the right by pressurizing the first pressure chamber of piston B and depressurizing the second pressure chamber of piston C, as shown above in relation to Figure 15 .
[000250] In a fifth step, as illustrated in Figure 17B), the second inflatable and deflatable grip means G2 are inflated and the first inflatable and deflatable gripper means G1 are deflated, as shown above in relation to Figure 6.
[000251] In a sixth step, as illustrated in Figure 17C), the oil tank 2301, the pump section E and the cylinder section 2302 are translated (pulled) to the right when pressurizing the second pressure chamber of the piston C and depressurizing the first pressure chamber of piston B, as described above in relation to Figure 15.
[000252] In a seventh step, as illustrated in Figure 17D), the first inflatable and deflatable grip means G1 is inflated and the second inflatable and deflatable grip means G2 is deflated, as shown above in relation to Figure 16.
[000253] The above steps, step seven, step four, step five and step six, provide a method for moving the device 2100 in a tubular channel 2199 once the inflatable and deflatable handle means G1, G2 has been inflated.
[000254] In one mode, device 2100 may move in the reverse of the direction described above. In the case where device 2100 is fed through and/or connected to a wire rope, the wire rope has to be pulled out of the tubular channel 2199 at the same speed or at approximately the same speed (eg at 1% ) that device 2100 moves through tubular channel 2199.
[000255] In one embodiment, the hydrophore 2301, the pump section E, the cylinder section 2302 and the sensor section can have a cylindrical cross section. For example, the 2100 device with the inflatable and deflated inflatable handle means G1, G2 may have a diameter of approximately 101.6 mm (approximately 4 inches).
[000256] In one modality, based on the data received by the PLC 2309 from the sensor section 2306, for example from the ultrasonic distance sensors, the PLC 2309 can determine by calculation whether the tubular channel 299 in front of the device 2100 allows movement from device 2100 additionally into tubular channel 2199. Alternatively or additionally, based on data received by the PLC 2309 from sensor section 2306, for example from the ultrasonic distance sensors, the PLC 2309 can determine the direction in which device 2100 is moving, for example, in the case of rail sides or the like in tubular channel 2199. Thereby, the PLC can calculate a control signal to control device 2100 based on data received from one or more of the sensors F.
[000257] In one embodiment, the 2100 device may further comprise an acoustic modem that allows the 2100 device to transmit data received from one or more of the F sensors to a computer or the like equipped with an acoustic modem and positioned at the channel input tubular 2199.
[000258] In this way, a sound signal can be communicated between the 2100 well tractor equipment and the 102A control module located outside the well hole 199, 2199, 3006, in which the sound signal can be transmitted through the fluid present in the wellbore and the position of the well tractor equipment can be determined at least based on said sound signal received by the control module or by the well tractor equipment and at least based on a time difference between the moment of emission of the signal sound and the moment of receipt of the sound signal.
[000259] In one embodiment, device 2100 comprises two pumps, one for pumping the unit of Figure 15 and one for the pumping unit of Figure 16. Alternatively, device 2100 may comprise a single pump that, through valves, serves the pump unit in Figure 15 and the pump unit in Figure 16.
[000260] Figure 19 shows a sectional view of a modality of a device 2100 for moving in a tubular channel 2199 comprising the directional means H. the device 2100 may comprise the technical characteristics presented in relation to Figures 13 and/or 14 and /or 15 and/or 16. Directional means H may allow navigation of device 2100, e.g., a change in orientation of device 2100 with respect to a longitudinal axis of tubular channel 2199, e.g., to move device in a lateral trajectory of a fish connector well or the like.
[000261] As seen in Figure 19 a), the directional means H can, for example, comprise a cylindrical element, for example, a stick or the like. A first end of the cylindrical element can be secured to the cylinder section 2302 through a ball bearing or a ball joint or a hinge or the like. The cylindrical element can act as a lever and can be connected to an actuator 2801 which can extend the other end of the lever in a direction radially outward from the cylinder section 2302. The length of the directional means H may, for example, be approximately equal to the diameter of the tubular channel 2199, for example, approximately 215.9 mm (8.5 inches) ± 5%.
[000262] The 2801 actuator can be electrically coupled, for example, through an electrical wire, to the PLC 2309, allowing the activation of the actuator through a control signal from the PLC 2309.
[000263] In one embodiment, as seen in Figure 19b), the directional means may comprise three cylindrical elements H, for example, placed 120 degrees apart along the circumference of the outer wall of the cylindrical section 2302 of device 2100. of the cylindrical elements H may act as a lever attached at one end to the cylinder section and connected to an actuator 2801 capable of extending the other end of the cylindrical element H radially outward from the cylinder section 2302.
[000264] In one modality, the PLC 2309 can receive data, with which the control signal is calculated, from the sensors in sensor section F. Alternatively, the PLC 2309 can receive a control signal via wire rope from the inlet of the tubular channel 2199.
[000265] The 2100 well tractor equipment can pull at least one locking system, for example in the form of a panel, through the well hole 199, 2199, 3006 to a location of a fracture in the wall, where the panel it can be expanded until it borders against the wall of the wellbore and released from the well tractor equipment.
[000266] In addition, the 2100 well tractor equipment can advance through a first panel 1002, 3000 already expanded and fixed in the well hole 199, 2199, 3006 and pulling a second panel 1002, 3000 through a first panel 1002, 3000 This procedure is illustrated in Figure 32, in which, however, only the first panel is shown. In Figure 32, the second panel should be mounted on the laying tool, as illustrated in Figure 31, to be pulled through the first panel which is already expanded and secured in the wellbore.
[000267] In general, as mentioned above and below, the inflatable and deflatable handle means G1, G2, G of the devices shown in relation to Figures 12 and/or 14 and/or 17 and/or 19 may be of the type shown in with respect to Figure 13.Blocking system and method for sealing a part of a wall in a section of a wellbore by such apparatus
[000268] Figures 20 to 30 illustrate the modalities of a locking system in the form of a panel 3000 apparatus for sealing a part of a wall according to the invention. According to the invention, the panel type apparatus 3000 is, based on the data obtained by a data acquisition module (as exemplified by the modalities of Figures 1 to 11), by means of a tool (such as a well tractor equipment exemplified by the modalities of Figures 12 to 19), placed in the well hole at the site of a fracture in the wall. Although the embodiments of the locking system in the form of a panel-like apparatus discussed below comprise several features, many of these features may not necessarily be in order to carry out the method according to the invention or may not necessarily be composed by the system according to the invention. with the invention. According to the invention, the at least one locking system is adapted to be placed in the wellbore at the location of a fracture in the wellbore wall to seal a part of the wellbore wall.
[000269] The person skilled in the art will understand that the following modalities of a panel 3000 apparatus present examples of a locking system that can be employed to carry out the invention, but that several other modalities are possible within the scope of the invention. For example, as an alternative to a mechanical system such as the panel-type apparatus described below, a chemical such as a gypsum-based substance can serve to block a fracture in a wellbore wall.
[000270] In one embodiment of a panel-like apparatus for sealing a portion of a wall 3005 in a section 3006 drilled into a rock formation and to be placed in the drilled section 3006 within the rock formation, apparatus 3000 comprises several elongated members 3001 arranged substantially parallel along a closed curve, wherein adjacent elongated members 3001 are connected via a plurality of intermediate links 3002, each link 3002 being movable relative to elongated members 3001 and secured from an unlatched position to a position. locked. Figures 20 and 21 show a part of a net or cage of elongated members 3001 connected to intermediate links 3002 in collapsed configuration and Figure 22 shows the same in an expanded position.
[000271] In an additional mode, intermediate links 3002 can be locked in collapsed position.
[000272] In another embodiment, the intermediate connections 3002 are held in collapsed position during insertion of the apparatus 3000 by means of a flexible member 3003.
[000273] In yet another embodiment, the flexible member 3003 is an outer bag or bellows 3003.
[000274] In another embodiment, panel-type apparatus 3000 for sealing a part of a wall 3005 in a section 3006 perforated in a rock formation and to be placed in the section 3006 perforated in the rock formation, the length of the intermediate connections 3002 and the number of elongated members 3001 are adapted to form an outer diameter of the apparatus in a collapsed state, the outer diameter being smaller than the inner diameter of the apparatus which is in an activated state, as shown in Figures 23, 24 and 25. This makes It is possible to introduce a collapsed apparatus in the drilled section 3006 into a rock formation through an existing pipe and also, if necessary, through an already positioned apparatus.
[000275] In a further embodiment of a panel type apparatus 3000 for sealing a portion of a wall 3005 in a section 3006 drilled in a rock formation and to be placed in the section 3006 drilled in the rock formation, the elongated members 3001 are provided with locking means for holding the intermediate links 3002 in a position substantially perpendicular to the elongated members 300. This provides a rigid cage type in an expanded configuration. When the intermediate links 3002 are in a locked position, which means that they cannot be moved so that the distance between two neighboring or adjacent elongated members 3001 is reduced, they will provide the apparatus with a minimum collapse resistance of the device employed.
[000276] This is also achieved in an embodiment in which a panel type apparatus 3000 for sealing a part of a wall 3005 in a section 3006 drilled in a rock formation and to be placed in the section 3006 drilled in the rock formation has a member of interlock 3007 formed by a groove or groove 3007 extending in a direction substantially perpendicular to the longitudinal direction of the elongated members 3001.
[000277] In one embodiment of an apparatus 3000 for sealing a part of a wall 3005 in a section 3006 drilled in a rock formation and to be placed in the section 3006 drilled in the rock formation, an inflatable bag or bellows 3003 is disposed on the outer diameter of apparatus for forming a sealing member against wall 3005 in section 3006 drilled into a rock formation. Therefore, it is possible for the apparatus to efficiently seal against the wall 3005 of the perforated section 3006. The bag or bellows 3003 is capable of increasing the outer diameter of the apparatus by up to more than twice the outer diameter of the cage in expanded configuration.
[000278] In a further embodiment of an apparatus 3000 for sealing a part of a wall 3005 in a section 3006 drilled in a rock formation and to be placed in the section 3006 drilled in the rock formation, the elongated members 3001 are provided with ends that are perforated in the rock formation. lean in one direction against wall 3005 of section 3006 drilled into a rock formation. Here, the passage to the additional devices and apparatus is obtained, that is, to seal an additional area below the perforated section 3006. The sloping ends will then act as a type of funnel that directs the equipment through the passage formed by the inner diameter. of the device.
[000279] Yet another embodiment of an apparatus 3000 for sealing a portion of a wall 3005 in a section 3006 drilled in a rock formation and to be placed in the section 3006 drilled in the rock formation, the apparatus is placed in an applied position when inflating a bag or bellows 3008 disposed along the inner diameter of the apparatus formed by the elongated members 3001 connected to the intermediate links 3002. This makes it possible to use an available type of fluid to inflate the bag or bellows 3008 and thereby place the apparatus in applied position. Furthermore, it is possible to achieve a higher pressure with the use of water or another fluid in place of a gas or simply atmospheric air. It is possible to use gas or air, but a liquid fluid is capable of reaching a higher pressure.
[000280] Examples of available fluids may be fluids from the 3006 section drilled into the rock formation or a fluid loaded into a 3010 laying tool.
[000281] Alternatively, any fluid or gas or epoxy or foam can be used to fill the bag or outer bellows 3003.
[000282] In an embodiment of an apparatus 3000 for sealing a part of a wall 3005 in a section 3006 drilled in a rock formation and to be placed in the section 3006 drilled in the rock formation, the intermediate connections 3002 in an unlatched position can be moved in a plane in the longitudinal direction of the elongated members 3001, thereby making it possible to expand a type of elongated member cage 3001 by means of intermediate links 3002.
[000283] In another embodiment of an apparatus 3000 for sealing a part of a wall 3005 in a section 3006 drilled in a rock formation and to be placed in the section 3006 drilled in the rock formation, the intermediate connections 3002 in an unlatched position can be moved in a plane substantially perpendicular to the longitudinal direction of the elongate members 3001 makes it possible to make a sharper curve of the elongate members 3001.
[000284] By having an apparatus 3000, as described above and below, it is possible to apply the apparatus in any geometry of a 3006 section drilled in a rock formation.
[000285] The device 3000 obtains, due to its configuration, a reliable resistance to collapse, thereby making it possible to maintain an applied seal with the use of the device.
[000286] When a 3000 fixture is installed, it will still be possible to allow the passage of another or additional fixtures that can be configured in addition to the passed fixtures.
[000287] It is possible to manufacture the apparatus 3000 of almost any length. The only limitation is the maximum slip length, determined by the lubricating wire rope length.
[000288] It is also possible to position the 3000 fixtures closely next to each other.
[000289] A device 3000 can be disabled by simply piercing the outer bag or bellows 3003.
[000290] The apparatus 3000 may be provided with a provision to deflate the outer bag or bellows 3003 by piercing the bag or bellows 3003 or when deflating the bag or bellows 3003 by letting the medium covered in the bag or bellows 3003 escape, i.e. through a valve or other type of closeable opening 3009.
[000291] This is achieved by having an apparatus 3000 for sealing a part of a wall 3005 in a section 3006 drilled in a rock formation and being placed in the section 3006 drilled in the rock formation, said apparatus comprising several elongated members 3001 arranged substantially parallel along a closed curve, wherein adjacent elongate members 3001 are connected via a number of intermediate links 3002, each link 3002 being movable relative to elongate members 3001 to which it is secured from a position. not locked to a locked position.
[000292] An apparatus 3000 for sealing a part of a wall 3005 in a section 3006 drilled in a rock formation and to be placed in the section 3006 drilled in the rock formation, wherein the length of the intermediate links 3002 and the number of the elongated members 3001 are adapted to form an outer diameter of the apparatus in a collapsed state, the outer diameter being smaller than the inner diameter of the apparatus while in an activated state, makes it possible to introduce a collapsed apparatus into the perforated section 3006 in a rock formation through an apparatus already positioned.
[000293] Furthermore, it makes it possible to introduce the device 3000 through the pipe and into the well.
[000294] An apparatus 3000 for sealing a part of a wall 3005 in a section 3006 drilled in a rock formation and to be placed in the section 3006 drilled in the rock formation, the elongated members 3001 being provided with locking means to retain the intermediate links 3002 in a position substantially perpendicular to elongated members 3001 provide a rigid cage type in expanded configuration. When the intermediate links 3002 are in a locked position, meaning that they cannot be moved in such a way that the distance between two neighboring or adjacent elongated members 3001 is reduced, they will provide the apparatus with minimal collapse resistance of the positioned device .
[000295] In an embodiment of the panel-type apparatus, the material from which the intermediate connecting members are selected has a minimum collapse strength of the positioned device in excess of 3500 kPa (35 bar).
[000296] In another mode of panel-type apparatus, the entire assembly can work in coiled pipe (external diameter of 5.1 cm), small drill pipe (external diameter of 39.4 cm) or tractor equipment. The device can be equipped with one or more electric batteries to make it possible to use electric current as a source of energy.
[000297] In one embodiment, a hydraulic pump (not shown) can supply the apparatus with well fluids (oil, water or a mixture) through a filter to inflate the outer bag or bellows 3003. A similar arrangement comprising a hydraulic pump 3017, a filter 3018 and a fluid inlet 3019 can be used to inflate the inner bag or bellows 3008 to expand the mesh, as shown in Figure 27.
[000298] When inflating the outer bag or bellows 3003, a 3009 valve can be used. When valve 3009 is connected to the apparatus, a spring 3011 activated shear pin 3012. Shear pin 3012 will not succeed at a predetermined internal pressure and a flexible steel tube 3013 will be 'pressed' out by that pressure . The 3009 valve is provided with a 3015 gusset that extends to the 3008 inner bellows so that the valve will not disengage from the 3008 inner bellows.
[000299] After full expansion pressure is reached, more pressure is applied to release hydraulic line 303 of seating tool 3010 from outer bag or bellows 3003. A backflow valve 3014, together with shear pin 3012, ensures that a certain pressure is reached and that the fluid pressure will not decrease in the bag or bellows 3003 when the hydraulic line 3013 is released.
[000300] When pressure is increased and shear pin 3012 is sheared, inner bag or bellows 3008 is deflated and seating tool 3010 is then retracted.
[000301] The 3010 laying tool with a 3000 panel mounted on it can be advanced through a well hole by means of a 2100 tractor equipment, as described above. The 3010 laying tool is provided with a 3016 pole adapted to be releasably connected to the 2100 tractor equipment, see Figure 27. Figures 31 and 32 show the 3010 laying tool connected to the 2100 tractor equipment by means of the 3016 pole. The 3010 laying tool may further comprise an electrical connection 3020 and a steel cable connector 3021, see Figure 27.
[000302] A method for applying an apparatus 3000 to seal a portion of a wall 3005 in a section 3006 drilled in a rock formation comprises the steps of:
[000303] - positioning an apparatus for sealing a part of a wall 3005 in a section 3006 perforated in a rock formation with respect to a part of the wall 3005 to be sealed, the apparatus being positioned in collapsed configuration;
[000304] - expand a net or cage in the apparatus, wherein the net or cage is formed by several elongated members 3001 connected by intermediate connections 3002;
[000305] - expanding a flexible member 3003 disposed on an outer diameter of the apparatus to seal against wall 3005 in section 3006 drilled into the rock formation.
[000306] The method further describes an embodiment in which an apparatus for sealing a part of an additional wall 3005 in a section 3006 perforated in a rock formation is introduced in collapsed configuration through an inner diameter of an already positioned apparatus.
[000307] The above descriptions of embodiments of the invention have been presented for the purpose of illustration and description only. They are not intended to be exhaustive or to limit the invention to the forms presented. Accordingly, many modifications and variations will be apparent to those skilled in the art. Additionally, the above presentation is not intended to limit the invention. The scope of the invention is defined by the appended claims.
[000308] In another embodiment of the method, an apparatus for sealing a portion of an additional wall 3005 in a section 3006 perforated in a rock formation is introduced in collapsed configuration through a pipe further down the well in the perforated section than an already positioned device.
[000309] In general, any of the technical characteristics and/or modalities described above and/or below can be combined into one modality. Alternatively or additionally, any of the technical features and/or embodiments described above and/or below may be in separate embodiments. Alternatively or additionally, any of the technical features and/or modalities described above and/or below may be combined with any number of other technical features and/or modalities described above and/or below to yield any number of modalities.
[000310] In device claims that enumerate several means, several of these means can be incorporated by the same piece of hardware. The mere fact that certain measures are cited in claims independently mutually different or described in different modalities does not indicate that a combination of these modalities cannot be used to advantage.
[000311] It should be emphasized that the term "comprises/understands" when used in this descriptive report shall be interpreted as specifying the presence of the declared characteristics, integers, steps or components, but does not exclude the presence or addition of one or plus features, integers, steps, components or groups thereof.

权利要求:
Claims (28)
[0001]
1. Method for enabling well management on open well completions that are equipped with a production pipeline, said method comprising the steps of: advancing a data acquisition module (100) having a propulsion system through the pipeline of production and further into an open well section of a wellbore and obtain data that provides information about the shape, size and condition of the surface and reveals fractures in a wall of the open well section of the wellbore, and in which at least one locking system (1002, 3000), based on the acquired data, in the open well wellbore (199, 2199, 3006) is placed at a site of a fracture in the wall characterized by the fact that the data acquisition module (100) is advanced by interacting with a fluid present in the wellbore and wherein the data acquisition module acquires data that provides information at a position of the data acquisition module (100) with respect to the wall (3005) of the wellbore (199, 2199, 3006) and is controlled based on said data to maintain a distance from the wall of the wellbore during advancement of the data acquisition module (100).
[0002]
2. Method for well and reservoir management in open well completions, according to claim 1, characterized in that the data acquisition module (100) is advanced through the wellbore (199, 2199, 3006) a first and a second time, and in which during the second advance time, the data acquisition module (100) is advanced through at least one blocking system (1002, 3000) placed in the wellbore.
[0003]
3. Method for well and reservoir management in open well completions, according to claim 1, characterized by the fact that the data acquisition module (100) is advanced into the wellbore (199, 2199, 3006 ) by the fluid present in the wellbore as the fluid flows through the wellbore.
[0004]
4. Method for well and reservoir management in open well completions, according to claim 1, characterized in that the data acquisition module (100) is advanced into the wellbore (199, 2199, 3006) by by means of a propulsion device (502) incorporated in the data acquisition module.
[0005]
5. Method for well and reservoir management in open well completions, according to claim 1, characterized in that the controlled radial movement of the data acquisition module (100) in relation to the wellbore (199, 2199 , 3006) is established by means of at least one impeller or at least one jet stream.
[0006]
6. Method for well and reservoir management in open well completions, according to claim 1, characterized in that the controlled vertical movement of the data acquisition module (100) in relation to the wellbore (199, 2199 , 3006) is established by a variable buoyancy system (401, 407, 408, 409, 410, 406, 404, 402, 405) incorporated in the data acquisition module.
[0007]
7. Method for well and reservoir management in open well completions, according to claim 1, characterized by the fact that the data providing information that reveals the position along the wellbore (199, 2199, 3006) of the wellhole wall fractures are communicated wirelessly to a control module (102A) outside the wellbore, and wherein the at least one blocking system (1002, 3000) is placed in the wellbore on site of the fracture in the wall based on the data received by said control module.
[0008]
8. Method for well and reservoir management in open well completions, according to claim 1, characterized in that an audible signal is communicated between the data acquisition module (100) and a control module (102A) located outside the wellbore (199, 2199, 3006), where the sound signal is transmitted through the fluid present in the wellbore, and where the position of the fracture in the wellbore wall is determined at least based on the said sound signal received by the control module or by the data acquisition module and at least based on a time difference between the moment of emission of the sound signal and the moment of receipt of the sound signal.
[0009]
9. Method for well and reservoir management in open well completions, according to claim 1, characterized in that the data providing information that reveals the position along the wellbore (199, 2199, 3006) of the wellhole wall fractures are communicated outside the wellbore through a radio frequency identification tag (RFID) released by the data acquisition module (100), transmitted by the fluid present in the wellbore and collected outside the wellbore pit.
[0010]
10. Method for well and reservoir management in open well completions, according to claim 1, characterized in that the at least one blocking system (1002, 3000), based at least on the data acquired by the data acquisition (100), is placed in the wellbore (199, 2199, 3006) at the site of the fracture in the wall by means of a well-tractor equipment (2100).
[0011]
11. Method for well and reservoir management in open well completions, according to claim 10, characterized by the fact that an audible signal is communicated between the well tractor equipment (2100) and a control module (102A ) located outside the wellbore (199, 2199, 3006), where the sound signal is transmitted through the fluid present in the wellbore, and where the position of the well tractor equipment is determined at least based on said signal sound received by the control module or by the well tractor equipment and based on at least one time difference between the moment of emission of the audible signal and the moment of receipt of the audible signal.
[0012]
12. Method for well and reservoir management in open well completions, according to claim 10, characterized by the fact that the well tractor equipment (2100) pulls the at least one blocking system in the form of a panel through the wellbore (199, 2199, 3006) to the fracture site in the wall, where the panel is expanded until it abuts against the wellbore wall and released from the well tractor equipment.
[0013]
13. Method for well and reservoir management in open well completions, according to claim 12, characterized by the fact that the well tractor equipment (2100) advances through a first panel (1002, 3000) already expanded and secured in the wellbore (199, 2199, 3006) and pulls a second panel (1002, 3000) through the first panel (1002, 3000).
[0014]
14. Method for well and reservoir management in open well completions according to claim 1, characterized in that the data acquisition module (100) advances through a first part of the wellbore (199, 2199 , 3006) to reach a second part of the wellbore, wherein the at least one locking system (1002,3000) is placed in the second part of the wellbore, and wherein the first part of the wellbore has a diameter which is less than, and preferably less than half the diameter of the second part of the wellbore.
[0015]
15. System for well and reservoir management in open well completions, the system comprising: a data acquisition module (100) adapted to be advanced through a wellbore (199, 2199, 3006) and adapted to acquire data providing information revealing fractures in a wall (3005) of the wellbore, and the system comprising at least one locking system (1002, 3000); and a tool (3010, 2100) adapted to, based on the acquired data, place the at least one blocking system in the wellbore at a location of a wall fracture characterized by the fact that the data acquisition module (100) is adapted to be advanced by interacting with the fluid present in the wellbore, and wherein the data acquisition module is adapted to acquire data that provides information at a position of the data acquisition module with respect to the wall (3005) of the wellbore and is adapted to be controlled based on said data to maintain a distance from the wellbore wall during advancement of the data acquisition module.
[0016]
16. System for well and reservoir management in open well completions, according to claim 15, characterized by the fact that the at least one locking system has the form of a panel (1002, 3000) adapted to be expanded from a collapsed state to an expanded state to border against the wall of the wellbore (199, 2199, 3006) and fixed in the wellbore, and wherein the data acquisition module (100) has a diameter maximum outer diameter that is less than a minimum inner diameter of the at least one panel in its expanded state.
[0017]
17. System for well and reservoir management in open well completions, according to claim 15, characterized in that the data acquisition module (100) is adapted to be advanced in the wellbore (199, 2199, 3006) by moving fluid flowing through the wellbore.
[0018]
18. System for well and reservoir management in open well completions, according to claim 15, characterized in that the data acquisition module (100) comprises a propulsion device (502).
[0019]
19. System for well and reservoir management in open well completions, according to claim 15, characterized in that the data acquisition module (100) comprises at least one thruster or at least one jet stream adapted for controlled radial movement of the data acquisition module relative to the wellbore (199, 2199, 3006).
[0020]
20. System for well and reservoir management in open well completions, according to claim 15, characterized in that the data acquisition module (100) comprises a variable buoyancy system (401, 407, 408 , 409, 410, 406, 404, 402, 405) adapted for controlled vertical movement of the data acquisition module relative to the wellbore (199, 2199, 3006).
[0021]
21. System for well and reservoir management in open well completions, according to claim 15, characterized in that the system comprises a control module (102A) adapted to be located outside the wellbore (199 , 2199, 3006) and adapted to receive wirelessly communicated data that provides information revealing the position along the wellbore of the fracture in the wall (3005) of the wellbore, and wherein the system comprises a tool (3010 , 2100) adapted to place the at least one locking system (1002, 3000) in the wellbore at the fracture site in the wall based on data received by said control module.
[0022]
22. System for well and reservoir management in open well completions, according to claim 15, characterized in that the system comprises a control module adapted (102A) to be located outside the wellbore (199, 2199 , 3006), wherein the system is adapted to communicate a sound signal between the data acquisition module (100) and the control module, wherein the sound signal is transmitted through the fluid present in the wellbore, and wherein the system is adapted to determine the position of the fracture in the wellbore wall based at least on said sound signal received by the control module or by the data acquisition module and based on at least one time difference between the moment of emission of the sound signal and the moment of receipt of the sound signal.
[0023]
23. System for well and reservoir management in open well completions, according to claim 15, characterized in that the data acquisition module (100) is adapted to carry a number of radio identification tags -the frequency (RFID), to encode said radio frequency identification tags with data that provide information revealing the position along the wellbore (199, 2199, 3006) of the fracture in the wellbore wall and to release said radio frequency identification tags one by one as the data acquisition module advances through the wellbore.
[0024]
24. System for well and reservoir management in open well completions, according to claim 15, characterized by the fact that the tool adapted to place the at least one blocking system in the wellbore is a tractor equipment. well (2100).
[0025]
25. System for well and reservoir management in open well completions, according to claim 24, characterized by the fact that the system is adapted to communicate an audible signal between the well tractor equipment (2100) and a module control (102A) located outside the wellbore (199, 2199, 3006), where the sound signal is transmitted through the fluid present in the wellbore, and where the system is adapted to determine the position of the tractor equipment. well based at least on said sound signal received by the control module or by the well tractor equipment and based on at least one time difference between the moment of emission of the sound signal and the moment of receipt of the sound signal .
[0026]
26. System for well and reservoir management in open well completions, according to claim 24, characterized in that the well tractor equipment (2100) is adapted to pull the at least one locking system in shape of a panel (1002, 3000) through the wellbore (199, 2199, 3006) to the fracture site in the wall, and wherein the system is adapted to expand the panel until it abuts against the wall of the wellbore and to release the panel from the well tractor equipment.
[0027]
27. System for well and reservoir management in open well completions, according to claim 24, characterized in that the system comprises at least a first and a second panel (1002, 3000), and in which the downhole tractor equipment (2100) is adapted to advance through the first panel already being expanded and secured in the wellbore (199, 2199, 3006) and to subsequently pull the second panel through the first panel.
[0028]
28. System for well and reservoir management in open well completions, according to claim 15, characterized in that the system comprises a pipe adapted to form a first part of a wellbore (199, 2199, 3006), said wellbore having a second part with a diameter that is greater than, and preferably greater than, twice the diameter of the first part, and wherein the data acquisition module (100) is adapted to advance through of said pipe forming the first part of the wellbore to reach the second part of the wellbore and advance through the second part of the wellbore.

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法律状态:
2018-12-18| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|

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2019-10-15| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|

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2021-03-02| B06A| Patent application procedure suspended [chapter 6.1 patent gazette]|

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2021-06-29| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

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2021-08-31| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 14/02/2012, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

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申请号 | 申请日 | 专利标题

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DKPA201170110A|DK177547B1|2011-03-04|2011-03-04|Process and system for well and reservoir management in open-zone developments as well as process and system for production of crude oil|

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DKPA201170110|2011-03-04|

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US201161450326P| true| 2011-03-08|2011-03-08|

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US61/450,326|2011-03-08|

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PCT/EP2012/052447|WO2012119837A2|2011-03-04|2012-02-14|Method and system for well and reservoir management in open hole completions as well as method and system for producing crude oil|

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