WO2024137903A1 - Unités de télémétrie de fond de trou positionnables - Google Patents

Unités de télémétrie de fond de trou positionnables Download PDF

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Publication number
WO2024137903A1
WO2024137903A1 PCT/US2023/085288 US2023085288W WO2024137903A1 WO 2024137903 A1 WO2024137903 A1 WO 2024137903A1 US 2023085288 W US2023085288 W US 2023085288W WO 2024137903 A1 WO2024137903 A1 WO 2024137903A1
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WO
WIPO (PCT)
Prior art keywords
telemetry
latch
units
downhole component
telemetry units
Prior art date
Application number
PCT/US2023/085288
Other languages
English (en)
Inventor
Hugues Trifol
Thibault VEXIAU
Original Assignee
Schlumberger Technology Corporation
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Schlumberger Technology Corporation, Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Technology B.V. filed Critical Schlumberger Technology Corporation
Publication of WO2024137903A1 publication Critical patent/WO2024137903A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
    • E21B47/16—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the drill string or casing, e.g. by torsional acoustic waves
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/02—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for locking the tools or the like in landing nipples or in recesses between adjacent sections of tubing

Definitions

  • a rig may be a system of components that can be operated to form a bore in a geologic environment, to transport equipment into and out of a bore in a geologic environment, etc.
  • a rig may be a system that can be used to drill a wellbore and/or to acquire information about a geologic environment, drilling, etc., via one or more tools that can be operatively coupled to a string of equipment such as a drillstring, tool string, etc.
  • a rig may be an onshore rig or an offshore rig, which may be on a vessel or a drilling platform.
  • a wellbore may be completed using various components where the wellbore may be utilized to produce and/or injection fluid.
  • a system can include a series of telemetry units, where each of the telemetry units includes telemetry circuitry and a latch, where the latch is actuatable to couple to a surface of a downhole component at a desired position.
  • a method can include deploying a stack of telemetry units into a bore of a downhole component; and latching each of the telemetry units to a position along the downhole component.
  • FIG. 1 depicts an example of a geologic environment and various examples of equipment that may be operated in the geologic environment;
  • FIG. 2 depicts an example of a geologic environment that includes equipment disposed at least in part in a bore and an example of a method
  • FIGS. 3A and 3B depict examples of systems
  • FIG. 4 depicts an example of a system
  • FIG. 5 depicts an example of a method with respect to examples of units and tubing and an example of a monobore completion
  • Fig. 6 depicts an example of a unit
  • Fig. 7 depicts examples of equipment and an example of a network environment.
  • Various examples of systems and techniques can allow downhole parameters associated with completions-related operations, for example, including liner hanger-related completions operations, to be monitored at the Earth surface in real time or near real time so that appropriate actions may be undertaken to regulate or control these operations as the operations are occurring.
  • Fig. 1 shows an example of a geologic environment 120.
  • the geologic environment 120 may be a sedimentary basin that includes layers (e.g., stratification) that include a reservoir 121 and that may be, for example, intersected by a fault 123 (e.g., or faults).
  • the geologic environment 120 may be outfitted with a variety of sensors, detectors, actuators, etc.
  • equipment 122 may include communication circuitry to receive and to transmit information with respect to one or more networks 125.
  • Such information may include information associated with downhole equipment 124, which may be equipment to acquire information, to assist with resource recovery, etc.
  • Other equipment 126 may be located remote from a well site and include sensing, detecting, emitting or other circuitry. Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc. As an example, one or more pieces of equipment may provide for measurement, collection, communication, storage, analysis, etc. of data (e.g., for one or more produced resources, etc.). As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc. For example, Fig. 1 shows a satellite in communication with the network 125 that may be configured for communications, noting that the satellite may additionally or alternatively include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).
  • imagery e.g., spatial, spectral, temporal, radiometric, etc.
  • Fig. 1 also shows the geologic environment 120 as optionally including equipment 127 and 128 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 129.
  • equipment 127 and 128 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 129.
  • a well in a shale formation may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.
  • a well may be drilled for a reservoir that is laterally extensive.
  • lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop the reservoir (e.g., via fracturing, injecting, extracting, etc.).
  • the equipment 127 and/or 128 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, injection, production, etc.
  • the equipment 127 and/or 128 may provide for measurement, collection, communication, storage, analysis, etc. of data such as, for example, production data (e.g., for one or more produced resources).
  • production data e.g., for one or more produced resources
  • one or more satellites may be provided for purposes of communications, data acquisition, etc.
  • Fig. 1 also shows an example of equipment 170 and an example of equipment 180.
  • Such equipment which may be systems of components, may be suitable for use in the geologic environment 120. While the equipment 170 and 180 are illustrated as land-based, various components may be suitable for use in an offshore system.
  • the equipment 170 includes a platform 171 , a derrick 172, a crown block 173, a line 174, a traveling block assembly 175, drawworks 176 and a landing 177 (e.g., a monkeyboard).
  • the line 174 may be controlled at least in part via the drawworks 176 such that the traveling block assembly 175 travels in a vertical direction with respect to the platform 171.
  • the drawworks 176 may cause the line 174 to run through the crown block173 and lift the traveling block assembly 175 skyward away from the platform 171 ; whereas, by allowing the line 174 out, the drawworks 176 may cause the line 174 to run through the crown block 173 and lower the traveling block assembly 175 toward the platform 171.
  • the traveling block assembly 175 carries pipe (e.g., casing, etc.)
  • tracking of movement of the traveling block 175 may provide an indication as to how much pipe has been deployed.
  • a derrick can be a structure used to support a crown block and a traveling block operatively coupled to the crown block at least in part via line.
  • a derrick may be pyramidal in shape and offer a suitable strength-to-weight ratio.
  • a derrick may be movable as a unit or in a piece by piece manner (e.g., to be assembled and disassembled).
  • drawworks may include a spool, brakes, a power source and assorted auxiliary devices.
  • Drawworks may controllably reel out and reel in line.
  • Line may be reeled over a crown block and coupled to a traveling block to gain mechanical advantage in a “block and tackle” or “pulley” fashion.
  • Reeling out and in of line can cause a traveling block (e.g., and whatever may be hanging underneath it), to be lowered into or raised out of a bore.
  • Reeling out of line may be powered by gravity and reeling in by a motor, an engine, etc. (e.g., an electric motor, a diesel engine, etc.).
  • a crown block can include a set of pulleys (e.g., sheaves) that can be located at or near a top of a derrick or a mast, over which line is threaded.
  • a traveling block can include a set of sheaves that can be moved up and down in a derrick or a mast via line threaded in the set of sheaves of the traveling block and in the set of sheaves of a crown block.
  • a crown block, a traveling block and a line can form a pulley system of a derrick or a mast, which may enable handling of heavy loads (e.g., drillstring, pipe, casing, liners, etc.) to be lifted out of or lowered into a bore.
  • line may be about a centimeter to about five centimeters in diameter as, for example, steel cable. Through use of a set of sheaves, such line may carry loads heavier than the line could support as a single strand.
  • a derrickman may be a rig crew member that works on a platform attached to a derrick or a mast.
  • a derrick can include a landing on which a derrickman may stand. As an example, such a landing may be about 10 meters or more above a rig floor.
  • a derrickman may wear a safety harness that enables leaning out from the work landing (e.g., monkeyboard) to reach pipe in located at or near the center of a derrick or a mast and to throw a line around the pipe and pull it back into its storage location (e.g., fingerboards), for example, until it a time at which it may be desirable to run the pipe back into the bore.
  • a rig may include automated pipe-handling equipment such that the derrickman controls the machinery rather than physically handling the pipe.
  • a trip may refer to the act of pulling equipment from a bore and/or placing equipment in a bore.
  • equipment may include a drillstring that can be pulled out of the hole and/or place or replaced in the hole.
  • a pipe trip may be performed where a drill bit has dulled or has otherwise ceased to drill efficiently and is to be replaced.
  • Fig. 2 illustrates an example of a system 210 that includes a drill string 212 with one or more tools (or module(s)) 220 and an example of a method 250.
  • the system 210 is illustrated with respect to a wellbore 202 (e.g., a borehole) in a portion of a subterranean formation 201 (e.g., a sedimentary basin).
  • the wellbore 202 may be defined in part by an angle (0); noting that while the wellbore 202 is shown as being deviated, it may be vertical (e.g., or include one or more vertical sections along with one or more deviated sections, which may be, for example, lateral, horizontal, etc.).
  • a portion of the wellbore 202 includes casings 204-1 and 204-2 having casing shoes 206-1 and 206-2.
  • cement annuli 203- 1 and 203-2 are disposed between the wellbore 202 and the casings 204-1 and 204-2.
  • Cement such as the cement annuli 203-1 and 203-2 can support and protect casings such as the casings 204-1 and 204-2 and when cement is disposed throughout various portions of a wellbore such as the wellbore 202, cement can help achieve zonal isolation.
  • a large diameter section may be a surface casing section, which may be three or more feet in diameter and extend down several hundred feet to several thousand feet.
  • a surface casing section may aim to prevent washout of loose unconsolidated formations.
  • an intermediate casing section it may aim to isolate and protect high pressure zones, guard against lost circulation zones, etc.
  • intermediate casing may be set at about X thousand meters and extend lower with one or more intermediate casing portions of decreasing diameter (e.g., in a range from about 30 cm to about 12 cm in diameter).
  • a so-called production casing section may extend below an intermediate casing section and, upon completion, be the longest running section within a wellbore (e.g., a production casing section may be thousands of feet in length).
  • production casing may be located in a target zone where the casing is perforated for flow of fluid into a lumen of the casing.
  • FIG. 3A shows an example of a system 300 that can implement acoustic telemetry such as, for example, via one or more components of an acoustic telemetry system 350 as shown in Fig. 3B.
  • a system may be deployed as a land- based system or as a sea-based system, for example, the acoustic telemetry system 350 is illustrated as extending from below a seabed through water to a platform that is at and/or above an air/water interface.
  • the system 300 can include components that propagate acoustic telemetry signals in one or more directions along equipment.
  • repeaters 301 can be placed at intervals (e.g., every 100 m, every 300 m, every 500 m, etc.) to relay and/or boost acoustic messages.
  • telemetry may be bi-directional; measurements from one or more (e.g., three, five, seven or more) sensors (e.g., pressure, temperature, force, position, etc.) may be in real time or near real time.
  • the system 300 is illustrated as deployed in a wellbore 302.
  • the wellbore 302 is illustrated as extending downwardly from a surface location 310 through one or more layers of rock to a subterranean formation 314, e.g., a hydrocarbon reservoir.
  • the system 300 can be used in one or more types of wells having generally vertical and/or deviated wellbores.
  • the wellbore 302 is defined by a surrounding wellbore wall 303 that may be an open wellbore wall, a casing, or a combination of cased and open section.
  • the wellbore wall 303 is defined by a casing 304.
  • a liner 306 is suspended by way of a liner hanger 305 within the interior of the casing 304.
  • a running tool 309 may have disposed about its exterior a plurality of repeaters 301 to relay and boost messages obtained from one or more sensors 308 disposed proximate to the lowermost end of the running tool 309.
  • the liner 306 may have disposed on its interior and/or exterior one or more repeaters 301a to relay and boost messages.
  • the repeaters 301a are disposed on the casing elements (e.g., the casing 304, the liner 306, etc.).
  • some of the repeaters 301a are disposed on casing elements (e.g., casing 304, liner 306, etc.) while other repeaters 301 are disposed on running tool 309.
  • One or more packers 307 may be used to isolate the terminal end of running tool 309 to perform various operations.
  • the running tool 309 may be a part of a string.
  • the running tool 309 may be a rotating running tool.
  • the running tool 309 may be a collet running tool (CRT).
  • the running tool 309 can move (e.g., at least up and down).
  • a measurement may be a position measurement, a velocity measurement, an acceleration measurement, a translational velocity measurement, a translational acceleration measurement, a rotational position measurement, a rotational velocity measurement, a rotational acceleration measurement, etc.
  • acoustic telemetry system 350 it is shown in Fig.
  • acoustic telemetry system 350 is shown as including a valve 392, a sampler 394, and an isolation system 396.
  • One or more instances of such equipment may or may not be included in a system such as the system 300.
  • the acoustic telemetry system 350 can include the repeaters 370 as being attached to tubing 360 (e.g., or other equipment), for example, via clamps. As mentioned, one or more features, components, etc., of the acoustic telemetry system 350 may be included in the system 300.
  • Fig. 4 presents an example embodiment of a system 400.
  • the repeaters 301 as in Fig. 3A e.g., consider the repeaters 370 as in Fig. 3B
  • the repeaters 301 as in Fig. 3A can be located along a string to relay information between the one or more downhole sensors 308 (e.g., and/or optionally one or more downhole actuators) and a unit 430, which may communicate via a serial link 444 and/or via an acoustic wireless telemetry link 448 with an acquisition system 450 operatively coupled to a computing device 480, for example, as operated by one or more personnel at surface (e.g., an operator or operators 484).
  • a computing device 480 for example, as operated by one or more personnel at surface (e.g., an operator or operators 484).
  • the acquisition system 450 may include features, components, etc. suitable for acquiring information from an acoustic telemetry system such as, for example, the acoustic telemetry system 350 of Fig. 3B.
  • the unit 430 includes circuitry that receives and processes acoustic signals as part of an acoustic telemetry system.
  • the acquisition system 450 can receive information that has been transmitted at least in part via acoustic signals. As shown, the acquisition system 450 may receive information via the serial link 444 (e.g., RS232, etc.) and/or via the acoustic wireless telemetry link 448.
  • the serial link 444 e.g., RS232, etc.
  • the acquisition system 450 can include one or more features of the HELIOS suite (e.g., OPC-UA, etc.), which can include local and remote components (e g., local machine executing a LINUX OS and remote cloud platform resources).
  • HELIOS suite e.g., OPC-UA, etc.
  • local and remote components e.g., local machine executing a LINUX OS and remote cloud platform resources.
  • an acoustic telemetry system may be utilized for transmission of one or more types of information.
  • information may include data that can be used to characterize reservoir and formation fluids and, for example, to predict a reservoir’s ability to produce.
  • gauges such as quartz gauges are utilized
  • information sensed via the gauges may be communicated at least in part via acoustic telemetry.
  • other types of information may be associated with one or more sensors such as in the system 300, which may be germane to motion, tension, compression, etc.
  • the commercially available MUZIC wireless telemetry may be utilized in a system that is to transmit acoustic signals.
  • the MUZIC wireless telemetry can include circuitry that is embedded in a system that can generate acoustic waves that can be transmitted at least in part via one or more tools (e.g., consider a tool string).
  • Such acoustic waves can carry information (e.g., data, etc.).
  • information carried by acoustic waves may be received via an acquisition system such as, for example, the acquisition system 450.
  • the system 400 may provide access to downhole data and/or control of one or more downhole tools in real time (e.g., near real time).
  • retrieved data may be sent to one or more remote locations (e.g., a client’s office, etc.) via one or more networks 405, for example, to one or more of a global, regional or local connectivity platform, such as the INTERACT framework 460 service offered by SLB, Houston, Texas.
  • the one or more networks 405 can include and/or be operatively coupled to network equipment 492 and servers and storage 495.
  • a device 462 can be operatively coupled to the framework 460 (e.g., consider a computing device that executes instructions, modules, etc. to instantiate at least a portion of the framework 460, that includes a web browser or other application for interacting with the framework 460, etc.).
  • a testing manager 464 may utilize the device 462 to control various operations via the framework 460 and/or via other equipment of the system 400.
  • the device 462 may be operatively coupled to equipment in the field where field operations may be performed.
  • the equipment can include one or more controllers that control equipment.
  • the device 462 of the testing manager 464 can be in communication with the device 480 of the operator 484 and/or, for example, another device such as a mobile device (e.g., a tablet, a smartphone, etc.) of the operator 484.
  • a mobile device e.g., a tablet, a smartphone, etc.
  • information rendered to a display via the device 462 as operatively coupled to the framework 460 may pertain to one or more field operations, which may be planned, on-going, etc.
  • a graphical user interface rendered to the display may include one or more graphical controls that can be actuated to cause transmission of information, which may include, for example, one or more commands, signals, etc. that can cause one or more pieces of equipment to perform one or more actions.
  • the work string may include a control station (see, e.g., the unit 430).
  • the control station may be part of a service tool or may be disposed on another part of a work string.
  • a control station may include a processor (one or more microprocessors and/or microcontrollers, for example), memory and a power and telemetry module to allow communication between downhole sensors and surface monitoring equipment.
  • a control station may be used to process multiple readings from the sensors and communicate the processed information to the Earth surface, and the control station may be used to receive commands communicated from the Earth surface for purposes of controlling certain downhole sensors.
  • a control station may communicate signals to components in a well (e.g., one or more actuators, etc.) that automatically change treatment of the well including, for example: 1 ) partially or fully opening/closing valves to control flow rates and pressures in the well; and/or 2) stopping movement or rate of movement of a service tool.
  • a well e.g., one or more actuators, etc.
  • automatically change treatment of the well including, for example: 1 ) partially or fully opening/closing valves to control flow rates and pressures in the well; and/or 2) stopping movement or rate of movement of a service tool.
  • a control station may include one or more additional sensors (pressure, temperature, acoustic, etc.) that may be used to acquire measurements that are communicated in real time or near real time to the Earth surface.
  • sensors of an acoustic telemetry system can be linked to a control station by wired and/or wireless telemetry systems, depending on such factors as the distance between the sensor and the control station, space limitations, and the like.
  • a well can serve as part of a communication path between a downhole control station and surface monitoring equipment.
  • a communication path may include at least one fiber optic cable that is connected to a control station and extends to the Earth surface via a work string, for example.
  • a communication path may be formed from one or more electrically conductive wires that are disposed in a string (for example, the string may be a wired drill pipe).
  • a communication path may be formed at least in part from a wireless communication path.
  • a wireless communication path may use such wireless communication techniques as acoustic communication, electromagnetic (EM) communication, pressure pulse communication, etc.
  • EM electromagnetic
  • Surface monitoring equipment may be, in accordance with some embodiments, a processor-based machine, which includes a processor (one or more microcontrollers and/or microprocessors, as non-limiting examples) that executes machine executable instructions that are stored in a non-transitory memory that is not a carrier wave (e.g., a semiconductor memory, an optical memory, a magnetic storagebased memory, etc.) for purposes of processing sensor or sensor-derived measurements that are communicated to the Earth surface by the control station in real time or near real time.
  • a processor one or more microcontrollers and/or microprocessors, as non-limiting examples
  • a non-transitory memory that is not a carrier wave (e.g., a semiconductor memory, an optical memory, a magnetic storagebased memory, etc.) for purposes of processing sensor or sensor-derived measurements that are communicated to the Earth surface by the control station in real time or near real time.
  • a carrier wave e.g., a semiconductor memory, an optical memory, a magnetic storagebased memory,
  • surface monitoring equipment can be constructed to provide (e.g., on a monitor, a display, etc.) indications of direct measurements and indirect measurements of various downhole parameters to a surface operator. Based on one or more of these measurements, the surface operator may then take the appropriate measures, or remedial actions, to control or regulate downhole operations to achieve the desired results.
  • software e.g., instructions, etc.
  • Fig. 5 shows an example of a method 500 that can include a releasing action 510 for releasing a series of units 570 in tubing 560, a latching action 520 for latching one of the units 570 in the tubing 560 and a spacing action 530 for spacing out the units 570 in the tubing 560.
  • the units 570 can be telemetry units that may include one or more features of repeaters such as the repeaters 301 of the system 300 of Fig. 3A and/or the repeaters 370 of the system 350 of Fig. 3B.
  • the units 570 can be telemetry units that may include one or more features of repeaters such as the repeaters 301 of the system 300 of Fig. 3A and/or the repeaters 370 of the system 350 of Fig. 3B.
  • the repeaters 370 as shown as being disposed on the outer perimeter of the tubing 360 (e.g., an outer surface of the tubing).
  • the units 570 can be disposed in the tubing 560, for example, to couple to an inner perimeter of the tubing 560.
  • latching can refer to one or more types of mechanisms may be utilized to secure a unit to a downhole component.
  • a pressure biasing mechanism that may rely on fluid pressure, spring pressure, etc. to generate a force to secure a unit to an inner surface of a downhole component.
  • the method 500 of Fig. 5 may be utilized for one or more types of operations such as, for example, testing operations, completions operations, etc.
  • the units 570 may be deployed in along an inner perimeter and/or along an outer perimeter of a component (e.g., a tool, tubing, casing, etc.).
  • the units 570 of the example of Fig. 5 can include circuitry that can execute processes, which can include telemetry processes and optionally one or more types of latching processes.
  • a unit may include a latching mechanism that can be actuated to latch the unit to a desired location (e.g., with respect to another unit, a component, a depth, a fluid location, etc.).
  • a unit may include one or more types of sensors.
  • a unit can include telemetry circuitry where the unit may operate as a node in a network.
  • a unit can include networking circuitry.
  • a series of units may be deployed, optionally without using a specialized physical conveyance tool and/or a manual clamping workflow that physically conveys each of the units to a desired location.
  • units can include features (e.g., hardware, optionally operatively coupled to circuitry) that can provide for deployment underground directly from surface without having to convey them using a specialized physical conveyance tool and/or a manual clamping workflow.
  • a unit may be suitable for deployment using a specialized conveyance tool and/or a manual clamping workflow and suitable for automated deployment (e.g., self-deployment using unit features).
  • a manual clamping workflow can include deploying each unit by clamping it manually onto the outside of a completion tubing while the completion tubing is run in hole (RIH).
  • RHIH hole
  • a well may be a so-called monobore well, which may be referred to as a monobore completion.
  • Fig. 5 also shows an example of a monobore completion 590.
  • a monobore completion can include a production string of uniform diameter, for example, from reservoir to surface.
  • casing may be set well above the reservoir, for example, up to half the well depth.
  • a smaller diameter hold can be drilled to a total depth and a long liner run sets a liner (e.g., liner as a type of casing that does not reach to the surface).
  • liner e.g., liner as a type of casing that does not reach to the surface.
  • Such operations and equipment can result in a monobore well as the well includes a “monobore” with the liner serving as both casing, providing protection, and as tubing, conveying production.
  • a monobore completion can conserve cost, for example, by using a less expensive, smaller hole to reduce tubular costs, while also providing a relatively large diameter production string.
  • monobore completions exist in the North Sea and Venezuela; noting that monobore completions can be utilized elsewhere.
  • the well includes a 20 inch casing shoe, a 13 3/8 inch casing shoe, a 9 5/8 inch casing shoe, a 7 inch casing shoe and a 4 1/2 inch tubing shoe.
  • cement can be disposed between the tubing and a borehole wall of a formation. While 4 1/2 inch tubing is mentioned, a suitable diameter may be utilized where, for example, units (e.g., nodes) can be of a corresponding diameter for purposes of deployment and latching. As to some other sizes, consider, for example, 7 inch monobore, 9 5/8 inch “big-bore” monobore, etc. As explained, where a monobore completion (e.g., monobore well) is utilized, units may be deployed in a bore of the monobore completion given its relatively large diameter production string.
  • a monobore completion e.g., monobore well
  • a stack of units e.g., communication modules
  • each of the units may automatically latch on tubing at a desired depth (e.g., measured depth), which may optionally be specified prior to deployment.
  • a desired depth e.g., measured depth
  • pressure may be utilized and/or one or more other techniques.
  • a notch counter consider a mechanism that can detect notches as a unit moves along a component where after counting a number of notches, as may be known a priori, the unit deploys a latch to latch to the next notch.
  • units may stop at a depth (e.g., measured depth and/or vertical depth) to preset where one or more additional mechanisms may be utilized to fully set each of the units.
  • a fluid pressurization mechanism that may trigger fully setting of each of the units.
  • units may be fully set responsive to one or more telemetry signals. For example, consider a method that includes sensing a signal and actuating a mechanism to fully set a unit to secure the unit to an inner surface of a bore of a downhole component.
  • the signal may be emitted by a deployed unit ahead of another unit or by a unit behind a deployed unit.
  • units may emit signals and utilized communication, for example, to use a handshake technique that can provide for signaling when a unit is to be latched for proper positioning.
  • a setting can either be performed on the way down as a unit reaches a desired depth or after having reached bottom and the lowermost module being set.
  • a depth check can be performed by a unit itself, for example, by having a dissolvable link between units that provides spacing between the units.
  • a weighted spacer may be added below a stack of units to ensure the units reach the desired depth(s).
  • a weight may be utilized to drive units under the influence of gravity where, for example, the weight may be dissolvable after an amount of time such that the weight does not interfere with field operations, fluid flow, etc.
  • units may be deployable based on depth, one or more dissolvable features (e.g., link, weight, etc.), using automated control, etc.
  • dissolvable features e.g., link, weight, etc.
  • Fig. 6 shows an example of a unit 600 that can include telemetry circuitry 610, latching circuitry 620 and/or a latching mechanism 630.
  • the latching circuitry 620 and/or the latching mechanism 630 can provide for automated latching on a downhole component.
  • a single unit may be autonomous and/or a single unit may operate in conjunction with one or more other units for purposes of proper positioning.
  • a method can include disposing units (e.g., nodes) in a bore of a component or string of components that extends downhole where, when each unit reaches a particular depth it stops, for example, consider to set or preset where extra force may be applied to fully set. Such an approach may be utilized in one or more portions of a borehole that has sufficient verticality (e.g., at a sufficient angle for gravity to assist in deployment).
  • a method can include pumping down one or more units and/or conveying one or more units in a deviated well that may lack sufficient verticality; noting that pumping and/or conveying may be utilized in a well with sufficient verticality, optionally with gravity assist.
  • a system can provide for deployment of units (e.g., nodes) inside tubing/casing, for example, of a monobore type of completion.
  • a system can include a series of telemetry units, where each of the telemetry units includes telemetry circuitry and a latch, where the latch is actuatable to couple to a bore surface of a downhole component at a desired position.
  • each of the telemetry units can include a sensor where, for example, the sensor detects notches on the bore surface of the downhole component, the sensor is a depth sensor, and/or the sensor is a proximity sensor that detects proximity of the telemetry unit to one or more other telemetry units.
  • a latch can be a circumferential latch.
  • a latch can be an outer perimeter latch.
  • a latch can include one or more prongs.
  • a latch may include a recess that can receive a component to latch a unit.
  • a downhole component can be a part of a monobore completion.
  • each of the telemetry units can include an outer diameter that is less than an inner diameter of a monobore of the monobore completion that forms the bore surface.
  • telemetry circuitry of telemetry units can include acoustic telemetry circuitry.
  • a method can include deploying a stack of telemetry units into a bore of a downhole component; and latching each of the telemetry units to a position along the downhole component.
  • the method can include successively transmitting a signal from one of the telemetry units to the other telemetry units.
  • latching can include depth sensing and actuating a latch at a predetermined depth.
  • latching can include proximity sensing and actuating a latch at a predetermined distance.
  • latching can include notch sensing and actuating a latch after sensing a number of notches.
  • a method can include utilizing telemetry units as nodes in a telemetry system.
  • a downhole component can be a downhole component of a monobore completion.
  • Fig. 7 shows components of an example of a computing system 700 and an example of a networked system 710 that includes a network 720.
  • the system 700 includes one or more processors 702, memory and/or storage components 704, one or more input and/or output devices 706 and a bus 708.
  • instructions may be stored in one or more computer-readable media (e.g., memory/storage components 704). Such instructions may be read by one or more processors (e.g., the processor(s) 702) via a communication bus (e.g., the bus 708), which may be wired or wireless.
  • the one or more processors may execute such instructions to implement (wholly or in part) one or more attributes (e.g., as part of a method).
  • a user may view output from and interact with a process via an I/O device (e.g., the device 706).
  • a computer-readable medium may be a storage component such as a physical memory storage device, for example, a chip, a chip on a package, a memory card, etc. (e.g., a computer-readable storage medium).
  • components may be distributed, such as in the network system 710.
  • the network system 710 includes components 722-1 , 722-2, 722-3, . . . 722-N.
  • the components 722-1 may include the processor(s) 702 while the component(s) 722-3 may include memory accessible by the processor(s) 702.
  • the component(s) 702-2 may include an I/O device for display and optionally interaction with a method.
  • the network may be or include the Internet, an intranet, a cellular network, a satellite network, etc.
  • a device may be a mobile device that includes one or more network interfaces for communication of information.
  • a mobile device may include a wireless network interface (e.g., operable via IEEE 802.11 , ETSI GSM, BLUETOOTHTM, satellite, etc.).
  • a mobile device may include components such as a main processor, memory, a display, display graphics circuitry (e.g., optionally including touch and gesture circuitry), a SIM slot, audio/video circuitry, motion processing circuitry (e.g., accelerometer, gyroscope), wireless LAN circuitry, smart card circuitry, transmitter circuitry, GPS circuitry, and a battery.
  • a mobile device may be configured as a cell phone, a tablet, etc.
  • a method may be implemented (e.g., wholly or in part) using a mobile device.
  • a system may include one or more mobile devices.
  • a system may be a distributed environment, for example, a so-called “cloud” environment where various devices, components, etc. interact for purposes of data storage, communications, computing, etc.
  • a device or a system may include one or more components for communication of information via one or more of the Internet (e.g., where communication occurs via one or more Internet protocols), a cellular network, a satellite network, etc.
  • a method may be implemented in a distributed environment (e.g., wholly or in part as a cloud-based service).
  • information may be input from a display (e.g., consider a touchscreen), output to a display or both.
  • information may be output to a projector, a laser device, a printer, etc. such that the information may be viewed.
  • information may be output stereographically or holographically.
  • a printer consider a 2D or a 3D printer.
  • a 3D printer may include one or more substances that can be output to construct a 3D object.
  • data may be provided to a 3D printer to construct a 3D representation of a subterranean formation.
  • layers may be constructed in 3D (e.g., horizons, etc.), geobodies constructed in 3D, etc.
  • holes, fractures, etc. may be constructed in 3D (e.g., as positive structures, as negative structures, etc.).

Landscapes

  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Acoustics & Sound (AREA)
  • Remote Sensing (AREA)
  • Geophysics (AREA)
  • Arrangements For Transmission Of Measured Signals (AREA)

Abstract

Un système peut comprendre une série d'unités de télémétrie, chacune des unités de télémétrie comprenant des circuits de télémétrie et un verrou, le verrou pouvant être actionné pour s'accoupler à une surface d'un composant de fond de trou à une position souhaitée. Un procédé peut consister à déployer une pile d'unités de télémétrie dans un trou d'un composant de fond de trou; et à verrouiller chacune des unités de télémétrie à une position le long du composant de fond de trou.
PCT/US2023/085288 2022-12-23 2023-12-21 Unités de télémétrie de fond de trou positionnables WO2024137903A1 (fr)

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US202263476978P 2022-12-23 2022-12-23
US63/476,978 2022-12-23

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Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2009074884A2 (fr) * 2007-10-18 2009-06-18 Neidhardt Dietmar J Méthode et appareil de détection de défauts dans des éléments tubulaires de puits de pétrole
US20160108689A1 (en) * 2014-10-15 2016-04-21 Sercel Anchoring mechanism and method for down-hole tool
US20180328170A1 (en) * 2015-12-16 2018-11-15 Halliburton Energy Services, Inc. Electroacoustic Pump-Down Sensor
US10648264B2 (en) * 2015-10-14 2020-05-12 Comitt Well Solutions LLC Positioning system
US20210156211A1 (en) * 2018-08-03 2021-05-27 Interra Energy Services Ltd. Device and method for actuating downhole tool

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2009074884A2 (fr) * 2007-10-18 2009-06-18 Neidhardt Dietmar J Méthode et appareil de détection de défauts dans des éléments tubulaires de puits de pétrole
US20160108689A1 (en) * 2014-10-15 2016-04-21 Sercel Anchoring mechanism and method for down-hole tool
US10648264B2 (en) * 2015-10-14 2020-05-12 Comitt Well Solutions LLC Positioning system
US20180328170A1 (en) * 2015-12-16 2018-11-15 Halliburton Energy Services, Inc. Electroacoustic Pump-Down Sensor
US20210156211A1 (en) * 2018-08-03 2021-05-27 Interra Energy Services Ltd. Device and method for actuating downhole tool

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