WO2016089964A1 - Capteur de fond de trou et télémétrie à distance de suspension de colonne perdue - Google Patents

Capteur de fond de trou et télémétrie à distance de suspension de colonne perdue Download PDF

Info

Publication number
WO2016089964A1
WO2016089964A1 PCT/US2015/063377 US2015063377W WO2016089964A1 WO 2016089964 A1 WO2016089964 A1 WO 2016089964A1 US 2015063377 W US2015063377 W US 2015063377W WO 2016089964 A1 WO2016089964 A1 WO 2016089964A1
Authority
WO
WIPO (PCT)
Prior art keywords
liner hanger
tool
running tool
sensor
liner
Prior art date
Application number
PCT/US2015/063377
Other languages
English (en)
Inventor
James Matthew HALL
Shawn ADAIR
Asif Javed
Travis Raymond BURKE
Askhat TURLYBAYEV
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
Schlumberger Technology Corporation
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 Canada Limited, Services Petroliers Schlumberger, Schlumberger Technology B.V., Schlumberger Technology Corporation filed Critical Schlumberger Canada Limited
Publication of WO2016089964A1 publication Critical patent/WO2016089964A1/fr

Links

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
    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/04—Casing heads; Suspending casings or tubings in well heads
    • 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
    • E21B47/09—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes

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 system can include a liner hanger running tool that includes a through bore; and an acoustic telemetry circuit operatively coupled to the liner hanger running tool.
  • a method can include receiving an acoustic signal at an acoustic telemetry circuit operatively coupled to a liner hanger running tool; and repeating the acoustic signal using the acoustic telemetry circuit operatively coupled to the liner hanger running tool.
  • a method can include receiving information transmitted at least in part via an acoustic telemetry system where the information pertains to a specified event of a liner hanger operation plan; analyzing at least a portion of the information; and, based at least in part on the analyzing, outputting a probability for the specified event.
  • Various other apparatuses, systems, methods, etc. are also disclosed.
  • 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 an operation using various types of equipment
  • FIG. 3 depicts an example of a geologic environment that includes equipment disposed at least in part in a bore and an example of a method
  • Fig. 4 depicts an example of a string of equipment
  • Fig. 5 depicts an example of a string of equipment
  • Figs. 6A and 6B depict examples of equipment that can be included in a string
  • FIGs. 7A and 7B depict examples of equipment in a bore
  • FIGS. 8A and 8B depict examples of systems
  • FIG. 9 depicts an example of a system
  • FIG. 10 depicts an example of a method
  • FIG. 1 1 depicts an example of a method
  • FIGs. 12A, 12B and 12C depict an example of a system, an example of a method and an example of a method
  • Fig. 13 depicts a perspective view of an illustrative sensor assembly in the disengaged position, according to one or more embodiments of the disclosure
  • Fig. 14 depicts a perspective view of the illustrative sensor assembly of Fig. 13 in the engaged position, according to one or more embodiments of the disclosure
  • FIG. 15 depicts a perspective view of another illustrative sensor assembly, according to one or more embodiments of the disclosure.
  • Fig. 16 depicts a cross-sectional view of the sensor assembly of Fig. 15, according to one or more embodiments of the disclosure
  • Fig. 17 depicts an illustrative wheel that can be coupled to the sensor assembly, according to one or more embodiments of the disclosure
  • Fig. 18 depicts an illustrative sensor disposed proximate the wheel of Fig. 17, according to one or more embodiments of the disclosure
  • Fig. 19 depicts another illustrative sensor assembly, according to one or more embodiments of the disclosure.
  • Fig. 20 depicts another illustrative sensor assembly, according to one or more embodiments of the disclosure.
  • Fig. 21 depicts a cross-sectional view of another illustrative sensor assembly, according to one or more embodiments of the disclosure.
  • Fig. 22 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
  • 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.
  • 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 . For example, by drawing the line 174 in, 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
  • 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 shows a wellsite system (e.g., at a wellsite that may be onshore or offshore).
  • a borehole 21 1 is formed in subsurface formations by rotary drilling; noting that various example embodiments may also use directional drilling.
  • a drill string 212 is suspended within the borehole 21 1 and has a bottom hole assembly 250 that includes a drill bit 251 at its lower end.
  • a surface system provides for operation of the drill string 212 and other operations and includes platform and derrick assembly 210 positioned over the borehole 21 1 , the assembly 210 including a rotary table 216, a kelly 217, a hook 218 and a rotary swivel 219.
  • the drill string 212 can be rotated by the rotary table 216, energized by means not shown, which engages the kelly 217 at the upper end of the drill string 212.
  • the drill string 212 is suspended from a hook 218, attached to a traveling block (not shown), through the kelly 217 and a rotary swivel 219 which permits rotation of the drill string 212 relative to the hook 218.
  • a top drive system may be suitably used.
  • the surface system further includes drilling fluid (e.g., mud, etc.) 226 stored in a pit 227 formed at the wellsite.
  • drilling fluid e.g., mud, etc.
  • a wellbore may be drilled to produce fluid, inject fluid or both (e.g.,
  • the drill string 212 (e.g., including one or more downhole tools) may be composed of a series of pipes threadably connected together to form a long tube with the drill bit 251 at the lower end thereof.
  • the drilling fluid 226 may be pumped by a pump 229 from the pit 227 (e.g., or other source) via a line 232 to a port in the swivel 219 to a passage (e.g., or passages) in the drill string 212 and out of ports located on the drill bit 251 (see, e.g., a directional arrow 208).
  • a pump 229 from the pit 227 (e.g., or other source) via a line 232 to a port in the swivel 219 to a passage (e.g., or passages) in the drill string 212 and out of ports located on the drill bit 251 (see, e.g., a directional arrow 208).
  • the drilling fluid 226 As the drilling fluid 226 exits the drill string 212 via ports in the drill bit 251 , it then circulates upwardly through an annular region between an outer surface(s) of the drill string 212 and surrounding wall(s) (e.g., open borehole, casing, etc.), as indicated by directional arrows 209. In such a manner, the drilling fluid 226 lubricates the drill bit 251 and carries heat energy (e.g., frictional or other energy) and formation cuttings to the surface where the drilling fluid 226 (e.g., and cuttings) may be returned to the pit 227, for example, for recirculation (e.g., with processing to remove cuttings, etc.).
  • heat energy e.g., frictional or other energy
  • the drilling fluid 226 pumped by the pump 229 into the drill string 212 may, after exiting the drill string 212, form a mudcake that lines the wellbore which, among other functions, may reduce friction between the drill string 212 and surrounding wall(s) (e.g., borehole, casing, etc.). A reduction in friction may facilitate advancing or retracting the drill string 212.
  • the entire drill string 212 may be pulled from a wellbore and optionally replaced, for example, with a new or sharpened drill bit, a smaller diameter drill string, etc.
  • tripping the act of pulling a drill string out of a hole or replacing it in a hole.
  • a trip may be referred to as an upward trip or an outward trip or as a downward trip or an inward trip depending on trip direction.
  • pumping of the drilling fluid 226 commences to lubricate the drill bit 251 for purposes of drilling to enlarge the wellbore.
  • the drilling fluid 226 is pumped by pump 229 into a passage of the drill string 212 and, upon filling of the passage, the drilling fluid 226 may be used as a transmission medium to transmit energy, for example, energy that may encode information as in mud-pulse telemetry.
  • mud-pulse telemetry equipment may include a downhole device configured to effect changes in pressure in the drilling fluid 226 to create an acoustic wave or waves upon which information may modulated.
  • information from downhole equipment e.g., one or more modules of the drill string 212
  • uphole device 234 may relay such information to other equipment 236 for processing, control, etc.
  • the drill string 212 may be fitted with telemetry equipment 240 that includes a rotatable drive shaft, a turbine impeller mechanically coupled to the drive shaft such that the drilling fluid 226 can cause the turbine impeller to rotate, a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes said modulator rotor to rotate, a modulator stator mounted adjacent to or proximate to the modulator rotor such that rotation of the modulator rotor relative to the modulator stator creates pressure pulses in the drilling fluid 226, and a controllable brake for selectively braking rotation of the modulator rotor to modulate pressure pulses.
  • telemetry equipment 240 that includes a rotatable drive shaft, a turbine impeller mechanically coupled to the drive shaft such that the drilling fluid 226 can cause the turbine impeller to rotate, a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes said modulator rotor to rotate, a modulator stator mounted adjacent to or proxi
  • an alternator may be coupled to the aforementioned drive shaft where the alternator includes at least one stator winding electrically coupled to a control circuit to selectively short the at least one stator winding to electromagnetically brake the alternator and thereby selectively brake rotation of the modulator rotor to modulate the pressure pulses in the drilling fluid 226.
  • the uphole device 234 may include circuitry to sense pressure pulses generated by telemetry equipment 240 and, for example, communicate sensed pressure pulses or information derived therefrom to the equipment 236 for process, control, etc.
  • the bottom hole assembly 250 of the illustrated embodiment includes a logging-while-drilling (LWD) module 252, a measuring-while-drilling (MWD) module 253, an optional module 254, a roto-steerable system and motor 255, and the drill bit 251 .
  • LWD logging-while-drilling
  • MWD measuring-while-drilling
  • optional module 254 a roto-steerable system and motor 255, and the drill bit 251 .
  • the LWD module 252 may be housed in a suitable type of drill collar and can contain one or a plurality of selected types of logging tools. It will also be
  • LWD and/or MWD module can be employed, for example, as represented at by the module 254 of the drill string 212.
  • position of an LWD module is mentioned, as an example, it may refer to a module at the position of the LWD module 252, the module 254, etc.
  • An LWD module can include capabilities for measuring, processing, and storing information, as well as for
  • the LWD module 252 may include a seismic measuring device.
  • the MWD module 253 may be housed in a suitable type of drill collar and can contain one or more devices for measuring characteristics of the drill string 212 and drill bit 251 .
  • the MWD tool 253 may include equipment for generating electrical power, for example, to power various components of the drill string 212.
  • the MWD tool 253 may include the telemetry equipment 240, for example, where the turbine impeller can generate power by flow of the drilling fluid 226; it being understood that other power and/or battery systems may be employed for purposes of powering various components.
  • the MWD module 253 may include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.
  • Fig. 3 illustrates an example of a system 310 that includes a drill string 312 with one or more tools (or module(s)) 320 and an example of a method 350.
  • the system 310 is illustrated with respect to a wellbore 302 (e.g., a borehole) in a portion of a subterranean formation 301 (e.g., a sedimentary basin).
  • the wellbore 302 may be defined in part by an angle ( ⁇ ); noting that while the wellbore 302 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 302 includes casings 304-1 and 304-2 having casing shoes 306-1 and 306-2.
  • cement annuli 303- 1 and 303-2 are disposed between the wellbore 302 and the casings 304-1 and 304-2.
  • Cement such as the cement annuli 303-1 and 303-2 can support and protect casings such as the casings 304-1 and 304-2 and when cement is disposed throughout various portions of a wellbore such as the wellbore 302, 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 feet and extend lower with one or more intermediate casing portions of decreasing diameter (e.g., in a range from about thirteen to about five inches 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.
  • the method 350 can include a set block 352 for setting a liner hanger, a release block 354 for releasing a running tool, a cement block 356 for cementing a liner and a set block 358 for setting a liner top packer.
  • a method can include a liner hanger setting procedure.
  • a procedure may include positioning a liner shoe at a depth at which a hanger is to be set, dropping a setting ball from a ball dropping sub of a cementing manifold, gravitating or pumping the ball down to a ball catch landing collar (e.g., at about a maximum rate of approximately 1 to 3 barrels per minute or as otherwise
  • a method can include releasing a running tool.
  • a method can include preparing a running tool for release once a liner hanger is set, slacking off (e.g., about 10,000 to about 20,000 lbs) on the running tool (e.g., to ensure it is in compression), pressuring up (e.g., to about 200 psi over a running tool release pressure), ensuring slack off weight compensates for hydraulic forces that may be pushing the running string up, bleeding the pressure and picking up the string to check for release (e.g., where liner string weight will be lost when setting tool is released), when the liner weight has been lost and the tool is released, setting back down onto the top of the liner (e.g., slacking off about 10,000 to 15,000 lbs), and shearing the ball seat to increase pressure up to a shear value (e.g., as may be indicated on an inspection sheet) where a pressure drop will indicate successful shear and allow circulation to resume.
  • a shear value e.g
  • a method can include cementing a liner.
  • such a method may include rigging up cementing equipment and pressure testing one or more steel lines (e.g., to a specified pressure), circulating a hole volume to condition mud (e.g., or as otherwise specified) and releasing a drill pipe dart from a cement head and pumping cement behind the dart.
  • the dart may be translated along a longitudinal axis to an axial location.
  • a method can include setting a liner top packer after performing a cementing process.
  • Fig. 4 shows an example of a system 400 (e.g., a string of equipment) that includes a tieback receptacle 410, a PV liner top packer 420, a high-capacity rotating liner hanger 430, landing collar 440, a float collar 450, and reamer float shoe 460.
  • the tieback receptacle 410 can permit landing, sealing and extension of an additional liner above a main liner.
  • the PV liner top packer 420 can include an anti-swab element and hold-down slips.
  • the high-capacity rotating liner hanger 430 can include pocketed slips, an anti-preset mechanism and a bypass.
  • the landing collar 440 can include features that help to ensure rapid and complete drillout.
  • the float collar 450 can be used when running and cementing liner casing strings and, for example, can help to prevent uncured cement in an annulus from cycling back to a liner after displacement.
  • the reamer float shoe 460 can include features that facilitate reaching a desired target depth.
  • Fig. 5 shows an example of a system 500 that can include a pump down plug (PDP) 510, a setting ball 512 (SB), a junk bonnet 520 (JB), a rotating dog assembly (RDA) 530, a collet running tool (CRT) 540, a retrievable cementing bushing (RCB) 550, a rotational ball seat stub assembly (RBS) 560, and a liner wiper plug 570 (LWP).
  • the PDP 510 can provide for separating cement and displacing fluid and can include a locking mechanism to protect against backpressure.
  • the JB 520 can provide for blockage of debris from a tieback receptacle, include a positive latch assembly that helps to prevent premature release, a built-in bypass that can help to balance pressure across a tieback receptacle and secondary shear release features.
  • the RDA 530 can provide for rotation of a workstring to facilitate load transfer, can include tool joint connections for high-torque applications, can include one or more bearings and can have a tensile strength rating suitable for various applications.
  • the CRT 540 can carry liner load, can include a clutch that transmits torque to a liner and can provide a back-up mechanical release mechanism.
  • the RCB 550 can include locking lugs for pressure resistance, a piston area that acts to reduce force on a worksting during circulating and/or cementing processes, and features that allow for retrieving the RCB 550 with a setting tool in a manner that provides an opening to a liner.
  • the RBS 560 can provide for fullbore clearance after a ball seat shears, can include a
  • the LWP 570 can include a profile for the PDP 510 to latch and seal, can include a mechanism for wiping cement from inside a liner and to keep it separated from displacing fluid, can include a locking mechanism that can protect against backpressure and can include an anti-rotation feature that can help to reduce drillout time.
  • Fig. 6A shows examples of running tools including an example of the collet running tool (CRT) 540 of Fig. 5, an example of a mechanical right hand release running tool (RRT) 542 and an example of a hydraulic right hand release running tool (RRT) 544.
  • CRT collet running tool
  • RRT mechanical right hand release running tool
  • RRT hydraulic right hand release running tool
  • a running tool can be used for running a liner hanger, for example, with or without a liner top packer.
  • a running tool can include a mechanical (M) release or a hydro-mechanical (HM) release (e.g., hydraulic release).
  • HM hydro-mechanical
  • a running tool can include a clutch that can transmit torque to a liner.
  • a running tool can be employed to set a liner hanger system and can allow for drilling the liner during an operation. As an example, where a rotational liner hanger is deployed, a running tool may allow for the liner to be rotated after the liner hanger is set.
  • a running tool may be used to run a mechanically or hydraulically set liner system that can include a PV-3 liner top packer or PV-3 setting adapter.
  • a setting string assembly can include a running tool, a slick joint, a cementing pack-off bushing, a liner wiper plug adapter, and an extension to connect to a running string.
  • a packer-dog assembly may be included if a liner top pack is being run.
  • Fig. 6B shows an example of a collet running tool (CRT) 640 such as, for example, the CRT 540 of Fig. 5.
  • CRT collet running tool
  • the CRT 640 may be employed to enable a liner to be rotated after a liner hanger is set.
  • the CRT 640 can include features for hydraulic-release such that, for example, release may occur without rotation (e.g., consider an example of a tool that is released by a rotational mechanism).
  • the CRT 640 can include a clutch and joint connections that are torque rated for various applications such as, for example, high-torque rotating and/or drilldown throughout a liner system.
  • the CRT 640 may enable rotation of a liner after the rotational liner hanger is set.
  • the CRT 640 can include a back-up mechanical release mechanism that can be actuated for release of the CRT 640 from a liner (e.g., consider a standing valve profile in bottom sub for contingency release).
  • the CRT 640 can be used to run a liner hanger system that may utilize a PV liner top packer (e.g., PV-3) or a setting adapter (e.g., PV3-SA).
  • a setting string assembly can include a CRT, a slick joint, a cementing packoff bushing, a liner wiper plug adapter and an extension to connect to a running string.
  • a packer dog assembly may be included, for example, where a PV-3 packer is being run.
  • a running tool can be a device that can be used in placement and/or setting of one or more pieces of downhole equipment such as, for example, one or more packers or plugs.
  • a running tool can be retrievable, for example, a retrievable running tool may be retrieved after an operation, a setting process, etc.
  • some types of running tools may be utilized to retrieve equipment or a tool that has been set in a wellbore.
  • the dog collar is temporarily attached to the assembly between the tool joint and the slips. If the slips fail to hold the tool assembly, the dog collar will prevent the entire assembly from dropping through and being lost in the wellbore.
  • Fig. 7A depicts a cutaway view of a downhole tool assembly 700 having a sensor assembly 710 in a disengaged position, according to one or more embodiments.
  • the downhole tool assembly 700 can include a workstring 704, a service tool 706, and a lower completion assembly 708.
  • the workstring 704 can be coupled to the service tool 706 and adapted to move the service tool 706 axially and rotationally within a wellbore 702.
  • the service tool 706 may be a liner hanger running tool (LHRT).
  • LHRT liner hanger running tool
  • the lower completion assembly 708 may include liners, liner hangers, casing, other lower completion components and accessories, or the like.
  • the service tool 706 can include one or more tool position sensors or sensor assemblies (one is shown) 710 adapted to monitor the position of the service tool 706 in the wellbore 702. If the service tool 706 includes multiple sensor assemblies 710, the sensor assemblies 710 can be axially and/or circumferential ly offset on the service tool 706.
  • the sensor assembly 710 in Fig. 7A is shown in the disengaged position meaning that the sensor assembly 710 is not in contact with a wall 712 of the wellbore 702.
  • the wall 712 of the wellbore 702 can include an uncased wall of the wellbore 702 or the inner surface of a casing disposed in the wellbore 702.
  • Fig. 7B depicts a cutaway view of the downhole tool assembly 700 having the sensor assembly 710 in an engaged position, according to one or more
  • the lower completion assembly 708 may include one or more packers 714.
  • the packer 714 may be a compression-set packer, a hookwall packer, an inflatable packer, a production packer, a retrievable packer, a swellable packer, a tension-set packer, a tie-back packer, or the like.
  • the one or more packers 714 can be set, as shown in Fig. 7B, for example, to anchor the lower completion assembly in place and isolate a first, upper annulus 716 from a second, lower annulus 718.
  • the sensor assembly 710 can actuate into the engaged position such that at least a portion of the sensor assembly 710, e.g., a wheel as described further below, is in contact with the wall 712 of the wellbore 702.
  • the sensor assembly 710 can be in the engaged position when the service tool 706 is run into the wellbore 702, operated at depth in the wellbore 702, and/or pulled out of the wellbore 702.
  • the sensor assembly 710 can be in the disengaged position when the service tool 706 is run into the wellbore 702, and in the engaged position when the service tool 706 is operated at depth in the wellbore 702 and pulled out of the wellbore 702.
  • the sensor assembly 710 can be in the disengaged position when the service tool 706 is run into the wellbore 702, in the engaged position while the service tool 706 is operated at depth in the wellbore, and in the disengaged position when the service tool 706 is pulled out of the wellbore 702.
  • the sensor assembly 710 can be actuated into the engaged position by an electric motor, a solenoid, an actuator (including electric, hydraulic, or electro- hydraulic), a timer-based actuator, a spring, pressure within the wellbore 702, or the like.
  • the sensor assembly 710 can maintain contact with the wall 712 of the wellbore 702 via a spring, a wedge, an actuator, a screw jack mechanism, or the like.
  • the sensor assembly 710 can activate and begin taking measurements to monitor the position and azimuthal orientation of the service tool 706 in the wellbore 702 when the sensor assembly 710 actuates into the engaged position, i.e., contacts the wall 712, or the sensor assembly 710 can activate at a later, predetermined time.
  • the sensor assembly 710 can activate when a predetermined temperature or pressure is reached or when a signal (via cable or wirelessly) is received.
  • the service tool 706 can release from the lower completion assembly 708 such that that the service tool 706 is free to move axially and rotationally within the wellbore 702 with respect to the stationary lower completion assembly 708.
  • the sensor assembly 710 can be adapted to take measurements to monitor the axial and/or rotational position of the service tool 706 as the service tool 706 is run in the wellbore 702, operated at depth in the wellbore 702, and/or pulled out of the wellbore 702.
  • Another embodiment of the sensor assembly 710 can also measure rotation of the service tool 706 with respect to the anchored lower completion assembly 708 or reference point 720 in the wellbore 702.
  • the service tool 706 can be released or disconnected from the anchored lower completion assembly 708 by rotating the service tool 706 to unthread it from the lower completion assembly 708 (e.g., or otherwise decouple it).
  • the sensor assembly 710 can be adapted to measure both axial and rotational movement of the service tool 706 with respect to the wellbore 702.
  • the position of the service tool 706 within the wellbore 702 can be measured with respect to a reference point 720 having a known position within the wellbore 702.
  • the reference point 720 can be located on the stationary lower completion assembly 708.
  • the service tool 706 can be pulled out of the wellbore 702 after it is released from the completion assembly 708, and a second service tool (not shown) can be run in the wellbore 702.
  • the second service tool can also have a sensor assembly coupled thereto and use the reference point 720 on the lower completion assembly 708.
  • the measurements can be processed in the service tool 706 and/or transmitted to an operator and/or recording device at the surface through a wire and/or wirelessly.
  • the measurements can be transmitted via wired drill pipe, cable in the workstring 704, cable in the annulus 716, acoustic signals, electromagnetic signals, mud pulse telemetry, or the like.
  • the measurements can be processed in the service tool 706 and/or transmitted to the surface continuously or intermittently to determine the position of the service tool 706 in the wellbore 702.
  • time between the processing and/or transmission of the measurements can be from about 0.5 s to about 2 s, about 2 s to about 10 s, about 10 s to about 30 s, about 30 s to about 60 s (1 min), about 1 min to about 5 min, about 5 min to about 10min, about 10 min to about 30 min, or more.
  • the sensor assembly 710 can be used to monitor and identify when the service tool 706 starts, stops, or otherwise moves, to more accurately determine the up, down, and neutral weights used at the surface. This data can then be correlated against engineering prediction models, in real time or post- job history matching, to calibrate the models. Calibration can be achieved by varying one or more variables, such as pumping/fluid viscous friction factors in the casing or an openhole section, until the prediction matches the actual measurement.
  • the sensor assembly 710 described herein can be used by one or more types of downhole tools to measure downhole distances and determine downhole positions.
  • the sensor assembly 710 can be used in a centralizer used in other wireline tools, drilling and measurement logging tools, shifting tools, and fishing tools that are used to, for example, create logs of information about the adjacent formation or map the adjacent formation.
  • the position of the downhole tool can be correlated with logs, maps, or the like.
  • Some examples of technologies for measuring and monitoring the position of the service tool 706 in the wellbore 702 can include acoustic, magnetic, and electromagnetic techniques.
  • the position of the service tool 706 can also be measured and monitored with a linear variable differential transformer or a tether or cable coupled to the service tool 706.
  • a linear variable differential transformer or a tether or cable coupled to the service tool 706.
  • one end of a tether can be coupled to the service tool 706, and the other end of the tether can be coupled to the stationary lower completion assembly 708 or the packers 714.
  • the tether can be intension as the service tool 706 moves within the wellbore 702.
  • the length of the tether can vary.
  • the length of the tether can be measured to determine the position of the service tool 706 in the wellbore 702. Upon completion of the job, the tether can be released or severed from the lower completion assembly 708 or the packers 714 allowing the service tool 706 to be pulled out of the wellbore 702.
  • the sensor assembly 710 can include an acoustic sensor or transceiver, and the reference point 720 can include a target.
  • the target 720 can be placed on the stationary lower completion assembly 708 or the packers 714.
  • the sensor assembly 710 can be adapted to send acoustic signals to and receive acoustic signals from the target 720.
  • the signals can be used to determine a distance travelled by the service tool 706 and/or the position of the service tool 706 in the wellbore 702.
  • At least one of the distance travelled and the position of the service tool 706 can then be transmitted to an operator or recorder at the surface, and once the position is known or determined (based on the distance travelled), the service tool 706 can be moved to precise locations within the wellbore 702.
  • Fig. 8A shows an example of a system 800 that can implement acoustic telemetry such as, for example, via one or more components of an acoustic telemetry system 850 as shown in Fig. 8B.
  • a system may be deployed as a land- based system or as a sea-based system, for example, the acoustic telemetry system 850 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 800 can include components that propagate acoustic telemetry signals in one or more directions along equipment.
  • repeaters 801 can be placed at intervals (e.g., every 500 ft, every 1000 ft., every 1500 ft., etc.) to relay and/or boost acoustic messages.
  • intervals e.g., every 500 ft, every 1000 ft., every 1500 ft., etc.
  • a scheme may be of the command-response type where the command is propagated from the surface to a target tool, then the target tool answers and the answer is propagated back to the surface.
  • 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, and commands to operate a service tool, which may be an electric or an electro-hydraulic service tool, can be sent downhole.
  • sensors e.g., pressure, temperature, force, position, etc.
  • commands to operate a service tool which may be an electric or an electro-hydraulic service tool, can be sent downhole.
  • the system 800 is illustrated as deployed in a wellbore 802.
  • the wellbore 802 is illustrated as extending downwardly from a surface location 810 through one or more layers of rock to a subterranean formation 814, e.g., a hydrocarbon reservoir.
  • the system 800 can be used in one or more types of wells having generally vertical and/or deviated wellbores.
  • the wellbore 802 is defined by a surrounding wellbore wall 803 that may be an open wellbore wall, a casing, or a combination of cased and open section.
  • the wellbore wall 803 is defined by a casing 804 (see, e.g., Fig. 3).
  • a liner 806 is suspended by way of a liner hanger 805 within the interior of the casing 804.
  • a running tool 809 may have disposed about its exterior a plurality of repeaters 801 to relay and boost messages obtained from one or more sensors 808 disposed proximate to the lowermost end of the running tool 809.
  • the liner 806 may have disposed on its interior and/or exterior one or more repeaters 801 a to relay and boost messages.
  • the repeaters 801 a are disposed on the casing elements (e.g., the casing 804, the liner 806, etc.).
  • the repeaters 801 a are disposed on casing elements (e.g., casing 804, liner 806, etc.) while other repeaters 801 are disposed on running tool 809.
  • One or more packers 807 may be used to isolate the terminal end of running tool 809 to perform various operations.
  • the running tool 809 may be a part of a string.
  • the running tool 809 may be a rotating running tool.
  • the running tool 809 may be a collet running tool (CRT).
  • the running tool 809 may be or include one or more features of one or more of the running tools 540, 542, 544 and 640 of Figs. 6A and 6B.
  • a component 830 is shown as being disposed at least in part in a bore of the running tool 809 or a bore of a string to which the running tool 809 is a part thereof.
  • the component 830 may optionally include circuitry 832 and one or more sensors 834.
  • the component 830 may include a magnet and/or one or more other features.
  • the component 830 may be a pump down plug or dart such as the pump down plug 510 of Fig. 5.
  • a component may include memory that can store sensor information where upon proximity to
  • the sensor information may be transmitted and then, for example, further communicated using, for example, acoustic telemetry.
  • a component may be part of a system that can perform one or more operations (e.g., setting, hanging, retrieving, cementing, wiping, etc.).
  • the component 830 may include a nose sensor and a tail sensor.
  • the nose and tail sensors can acquire information as to a differential across the component 830.
  • a pressure differential across the component with respect to time e.g., and optionally depth
  • such information may be generated as a differential signal that can be "broadcast" as it passes by a
  • a communication circuit may register a time, a position and a pressure differential of a component.
  • a sensor or sensors may be or include one or more temperature sensors.
  • a component may include one or more types of sensors.
  • the running tool 809 can move (e.g., at least up and down).
  • the component 830 may 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 850 it is shown in Fig. 8B as including a surface unit 852, a hanger 852, tubing 860, repeaters 870, and various equipment disposed downhole from the repeaters 870.
  • equipment can include, for example, one or more instances of wireless acoustic telemetry circuitry 882 and 884, which may be operatively coupled to one or more sensors, etc.
  • the acoustic telemetry system 850 is shown as including a valve 892, a sampler 894, and an isolation system 896.
  • One or more instances of such equipment may or may not be included in a system such as the system 800.
  • the acoustic telemetry system 850 can include the repeaters 870 as being attached to tubing 860 (e.g., or other
  • components, etc., of the acoustic telemetry system 850 may be included in the system 800.
  • a system can include a liner hanger (see, e.g., the liner hanger 805 of Fig. 8A).
  • a liner hanger can be device (e.g., an assembly) that can be utilized to attach or hang liners, for example, from an internal wall of a previous casing string.
  • a liner hanger may be specified with respect to size and/or material properties, for example, to suit particular completion conditions.
  • a liner is a casing, for example, a liner may be a string of casing in which the top does not extend to the surface but instead is suspended from inside a previously hung casing string.
  • a liner hanger can grip a casing (see, e.g., the casing 804 of Fig. 8A).
  • a liner hanger may have a length defined by a top end (e.g., uphole end) and a bottom end (e.g., downhole end). At the top end, where the liner hanger grips the casing, this may define an upper limit of a measurement zone.
  • a measurement zone for making measurements using the sensor system may be defined at least in part by an end of a liner hanger and/or an uphole-most component or uphole- most component sensing range of an uphole-most component.
  • a measurement may pertain to tension and/or compression in a region where a liner hanger grips casing.
  • a measurement may pertain to relative motion of a running tool (e.g., running string) with respect to a liner hanger.
  • a liner hanger can be disposed in a well and a running tool (e.g., running string) can be retrieved in a manner whereby relative motion exists between the liner and the running tool.
  • a running tool e.g., running string
  • relative motion upon release, relative motion may commence.
  • a wheel type of sensor may be employed to measure motion (see, e.g., various examples described below).
  • a running tool extension can run through a bore of a junk bonnet (see, e.g., the junk bonnet 520 of Fig. 5).
  • relative motion may be measured with respect to the junk bonnet and the running tool extension (e.g., running tool).
  • a sensor or a portion of a sensor system may be operatively coupled to a junk bonnet.
  • a magnet and trigger system may be utilized where at least one component of the system is operatively coupled to the junk bonnet.
  • Fig. 9 presents an example embodiment of a system 900.
  • the repeaters 801 as in Fig. 8A e.g., consider the repeaters 870 as in Fig. 8B
  • the unit 930 which may communicate via a serial link 944 and/or via an acoustic wireless telemetry link 948 with an acquisition system 950 operatively coupled to a computing device 980, for example, as operated by one or more personnel at surface (e.g., an operator or operators 984).
  • the acquisition system 950 may include features, components, etc. suitable for acquiring information from an acoustic telemetry system such as, for example, the acoustic telemetry system 850 of Fig. 8B.
  • the unit 930 includes circuitry that receives and processes acoustic signals as part of an acoustic telemetry system.
  • the acquisition system 950 can receive information that has been transmitted at least in part via acoustic signals. As shown, the acquisition system 950 may receive information via the serial link 944 (e.g., RS232, etc.) and/or via the acoustic wireless telemetry link 948.
  • the serial link 944 e.g., RS232, etc.
  • 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 800, 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 950.
  • the system 900 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 905, for example, to one or more of a global, regional or local connectivity platform, such as the
  • the one or more networks 905 can include and/or be operatively coupled to network equipment 992 and servers and storage 995.
  • a device 962 can be operatively coupled to the framework 960 (e.g., consider a computing device that executes instructions, modules, etc. to instantiate at least a portion of the framework 960, that includes a web browser or other application for interacting with the framework 960, etc.).
  • a testing manager 964 may utilize the device 962 to control various operations via the framework 960 and/or via other equipment of the system 900.
  • the device 962 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 962 of the testing manager 964 can be in communication with the device 980 of the operator 984 and/or, for example, another device such as a mobile device (e.g., a tablet, a smartphone, etc.) of the operator 984.
  • a mobile device e.g., a tablet, a smartphone, etc.
  • information rendered to a display via the device 962 as operatively coupled to the framework 960 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 930).
  • 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
  • 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 the 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 the service tool.
  • a control station may include one or more additional sensors (pressure, temperature, acoustic, etc.) that may be used to acquire
  • 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 storage- based memory, etc.) for purposes of processing sensor or sensor-derived
  • 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 storage- based memory, etc.) for purposes of processing sensor or sensor-derived
  • a carrier wave e.g., a semiconductor memory, an optical memory, a magnetic storage- based memory, etc.
  • 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.
  • sensors of a liner hanger completion system may be constructed to directly or indirectly measure, alone or in combination, one or more of the following: pressure, temperature, force, torque, density, rheology, pH, flow rate, acoustic energy, seismic energy, acceleration, logging images and/or other downhole properties.
  • Such one or more types of measurements or information based on these measurements may be communicated to surface equipment in real time or near real time via a control station and its associated telemetry system (e.g., a telemetry system including the communication path) in order to allow an operator at the Earth surface to monitor an ongoing downhole operation; control or regulate the operation in real time or near real time; determine whether a given downhole operation is proceeding according to plan; make decision regarding corrective actions, which should be taken; and monitor these corrective actions, as just a few examples.
  • a control station and its associated telemetry system e.g., a telemetry system including the communication path
  • one or more corrective actions that may be taken at the Earth surface of the well based on the information that is communicated uphole from the liner hanger completion system may include actions to regulate a fluid pumping rate, regulate the introduction of fluid stages, regulate the volumetric amounts of certain fluids that are introduced into the well, time the introduction of fluid stages, regulate a force that is applied at the Earth surface to the work string, regulate manipulation (turning, up/down movement, etc.) of the work string, regulate an amount of weight placed on the work string, regulate travel of the work string, and so forth.
  • a liner hanger completion system may contain one or more sensors to measure pressures, for example, at one or more of various downhole locations.
  • sensors to measure pressures, for example, at one or more of various downhole locations.
  • a liner hanger completion system includes one or more of the following pressure sensors: a pressure sensor that is located inside the tubing and measures the pressure within the work string inner bore; a pressure sensor that is located outside the tubing and measures the pressure within the casing annulus; and a pressure sensor that is located on the lower completion section to measure pressure in the annulus.
  • the sensors may be distributed discretely or continuously along the service tool string and/or the lower completion section at the locations discussed above.
  • One or more of the aforementioned pressure sensors of the liner hanger running tool system may allow various pressures to be transmitted to the Earth surface and observed in real time or near real time such that appropriate real time/near real time actions may be taken from the Earth surface.
  • the pressure measurements may include rate of change measurements with respect to time and volume as well as measurements that hydrostatic pressures and differential pressures to be derived.
  • the pressure differentials may be used for purposes of calculating a friction pressure.
  • downhole pressure measurements indicate whether the downhole fluid pressure is within a suitable range to control the well. If the pressure reading is too low indicating an underbalanced condition, then heavier fluid may be pumped from the surface. If the pressure reading is too high indicating an overbalanced condition where formation fracturing might occur, then a lighter fluid may be pumped from the surface.
  • the pressure sensors may be used to monitor other parameters, in accordance with many potential embodiments of the invention. In real time or near real time, for example, pressure may be monitored across downhole components.
  • the surface pump rate may be decreased or a surface choke may be opened to maintain the component within the appropriate operating envelope.
  • the pressure sensors may be used to observed friction pressures throughout the system. As an example, current operation may be stopped and reversed out.
  • the pressure sensors may also be used to calibrate design models to match friction pressures in real time or near real time and facilitate better predictions for future events.
  • a liner hanger running tool system may include, in accordance with some embodiments, one or more sensors to acquire distributed temperature measurements and/or measurements at discrete downhole locations.
  • the temperature readings from such sensors may be monitored in real time or near real time at the Earth surface before, during and after the completions- related operations to verify whether the operations are proceeding according to plan and if not, whether remedial steps should be taken.
  • Such temperature measurements may be direct measurements, may be taken over time, and may, in general, be functions of the amount of fluid pumped downhole.
  • a wide range of temperature measurements may be acquired by temperature sensors of the liner hanger running tool system, such as direct measurements and rates of change of temperature with respect to time and volume.
  • distributed temperature measurements similar to distributed temperature sensing (DTS) measurements may be made, in accordance with some embodiments of the invention.
  • one or more sensors of a liner hanger running tool system may be used to measure the displacement of the liner hangers and/or various completion-related equipment and/or the forces that are acting on the system, such as tension,
  • Such types of sensors may be or include gauges referred to as strain gauges.
  • Such physical measurements may be made using a strain sensor (replacing or in addition to the other sensors, which are disclosed herein) that is located on the service tool and a strain sensor (replacing or in addition to the other sensors, which are disclosed herein) that is located elsewhere.
  • One or more additional sensors that are constructed to acquire tension measurements may be disposed on the service tool between the two sensors.
  • Force measurements that are acquired by one or more strain sensors during a completion operation may be monitored to determine whether the operation is proceeding according to the plan and if not, whether remedial actions are to be taken.
  • a sensor at the bottom of the liner hanger running tool may be a strain sensor.
  • the sensor indicates a sudden increase in compression force while the service tool is being run into wellbore with a completion section, the sudden increase indicates that a restriction has been encountered. If so, and if a wellbore is an openhole wellbore, fluid may be pumped from the Earth surface to reduce the restriction with the service tool being raised and lowered as appropriate.
  • one or more of the above-mentioned strain sensors may be monitored at the Earth surface while applying pulling and rotational forces from the Earth surface to ensure that the forces that are exerted on service tool, the completion section and in general, that the components of the completion system, do not exceed equipment failure limitations.
  • sensed acceleration and/or calculated displacement may be communicated to the Earth surface from downhole in real time or near real time so that the communicated measurements may be monitored at the Earth surface to determine whether the completion-related operation is proceeding as planned (e.g., for purposes of determining whether corrective action is to be taken).
  • a liner hanger running tool completion system may include one or more sensors to measure torque such that the measured torque may be observed in real time or near real time at the Earth surface, in accordance with embodiments of the invention.
  • the liner hanger running tool system may contain a torque sensor on the service tool, which acquires a torque measurement for the scenario in which the lower completion section has become stuck and a rotational force is being applied to the work string in an attempt to rotate the lower completion section.
  • the measured torque may be monitored at the Earth surface in real time or near real time for purposes of controlling the torque that is applied at the Earth surface to avoid exceeding downhole equipment limitations.
  • one or more torque sensors may be disposed above a service tool and may be disposed on a shoe at a bottom of a string.
  • torque may be measured at a service tool for purposes of identifying when the service tool begins rotating such that the required number of turns of the work string may be observed at the Earth surface in real time or near real time.
  • Various aforementioned sensors are examples of a few sensors that may be disposed on a liner hanger running tool completion system for purposes of allowing downhole parameters to be remotely observed at the Earth surface in real time or near real time.
  • one or more sensors to monitor downhole parameters may be formed from downhole tools, such as a packer, a service tool, a fluid loss control device, etc. This feedback may be used to identify and record tool position, verify tool activation, etc. In this manner a tool, may be referred to as an "intelligent" tool, may be used to provide this feedback.
  • one or more technologies may be used to measure and relay to the surface piston movement to verify engagement of hanger slips or measurement position of tie back receptacle (TBR) top, for example, prior to setting down about 10 to about 20 klbs to verify that a system did not move from an initial position.
  • one or more technologies may be implemented to verify movement of a ball in a rotational ball seat (RBS) and relay this information to the surface.
  • one or more technologies may also be used in setting packers, for example, using positional measurements as a proxy for the compressive force applied and relaying this information to the surface.
  • one or more technologies may be used to take and relay positional measurements related to release of a retrievable cement bushing (RCB).
  • RCS retrievable cement bushing
  • One or more embodiments may be used to determine if a liner wiper plug has been released by measuring local pressure differentials in the vicinity of the liner wiper plug and relaying this information to the surface.
  • One or more embodiments may facilitate the simultaneous use of pressure, tension, and compression data to fine tune the system and allow for various decisions to be made.
  • One or more embodiments may allow for measurement of rotation of a liner hanger running tool, for example, to avoid premature release by compression at the tool. As an example, one or more embodiments can provide greater confidence on tripping in a string as compression at a tool can be more closely controlled. [00125] As an example, one or more embodiments can provide compression-at- tool data (obtained from axial load sensors disposed on a liner hanger running tool) to the surface in real time, or near real time, allowing an operator to fine tune the slack off and ensure the proper set down (e.g., 12,000 lbs, 15,000 lbs, 18,000 lbs, or more) at the tool before pressuring up to shear the pins.
  • compression-at- tool data obtained from axial load sensors disposed on a liner hanger running tool
  • one or more embodiments can relay tool position date to the surface during a secondary release of a liner hanger running tool to indicate if one or more rotational shear screws have, in fact, been sheared. For example, if the tool moves downward by a given amount, e.g., 1 inch, 1 .5 inch, 3 inch, etc., relative to the packer when weight is slacked after rotating left handedly, may indicate that the shear screws have been sheared already.
  • a liner hanger running tool may not necessarily be in tension or compression when rotating left hand and the obtainment and real time, or near real time, transmission of tension/compression data to the operation may aid in locating the liner hanger running tool into its neutral position. .
  • the use of accurate positional data obtained by one or more techniques may help determine, when pulling out to set liner top packer that a Rotating Dog Assembly (RDA) is out of the TBR.
  • RDA Rotating Dog Assembly
  • measuring the annulus pressure and temperature at the running tool, and providing this data to the surface in real time or near real time may help estimate cement slurry thickening times which can be related to how much time remains available to release a possibly stuck running tool before the cement sets.
  • Fig. 10 shows an example of a method 1010 that includes a reception block 1020 for receiving data associated with multiple jobs (e.g., multiple operations at different sites, etc.), a generation block 1030 for generating one or more baselines via processing at least a portion of the received data and one or more output blocks 1042 and 1044 for outputting a reference or references (e.g., a baseline reference, baseline references, etc.).
  • a reference or references e.g., a baseline reference, baseline references, etc.
  • various jobs are illustrated as X, X+1 to X+N where data associated with each of the jobs can be acquired and analyzed, for example, to generate a baseline or baselines (e.g., baseline Y, baseline Z, etc.).
  • the method 1010 may implement one or more prognostics algorithms (e.g., prognostics and health management (PHM) algorithms).
  • Prognostics can include predicting a time at which a system or a component may degrade (e.g., no longer reliably perform an intended function or functions, etc.).
  • a predicted time may be a basis to estimate a remaining useful life (RUL), which may be utilized for contingency mitigation, etc.
  • RUL remaining useful life
  • a method can include analyzing information to predict future performance of a component, for example, by assessing the extent of deviation or degradation from expected operation.
  • a method can include building one or more models, for example, using one or more of data-driven approaches, model- based approaches, and hybrid approaches.
  • Fig. 1 1 shows an example of a method 1 1 10 that includes a reception block 1 120 for receiving data (e.g., in real time or near real time), for example, as equipment is operated per an operation block 1 1 15.
  • the method 1 1 10 can include a generation block 1 130 for generating a database of information (e.g., in real time or near real time "on the fly") based at least in part on the received data, an analysis block 1 140 for analyzing at least a portion of the information in the database with respect to an existing database (e.g., a baseline, etc.), an output block 1 150 for outputting one or more results of the analysis or analyses, a decision block 1 160 for deciding whether to adjust one or more operational parameters of equipment, a decision block 1 170 for deciding whether an operation is complete and a continuation block 1 180 for continuing to one or more actions, for example, when an operation is complete.
  • a generation block 1 130 for generating a database of information (e.g., in real time or near real time "on the fly
  • the method 1 1 10 can include one or more loops, which may be open and/or closed.
  • a loop may continue in real time or near real time during an operation.
  • Such a loop can include assessing information acquired via one or more downhole sensors where such information may be communicated at least in part via an acoustic telemetry system.
  • one or more commands, signals, etc. may be communicated to one or more pieces of equipment in a downhole environment at least in part via an acoustic telemetry system.
  • a method can provide for automatic prognosis of successfully setting a liner hanger using downhole measurements, which can be real time or near real time downhole measurements.
  • a real time or near real time telemetry system for a liner hanger can allow for collecting of a suite of data types, for example, from various sensors located where events may be occurring downhole.
  • decision making may be based at least in part on information held by experienced operators who understand expected ranges of various data types, for example, by analyzing various data types in serial, in parallel or in serial and in parallel.
  • a method can include implementing prognostics and health management (PHM) data analytics techniques to make real time or near real time prognosis of setting of a liner hanger by using downhole measurements and comparing data (e.g., a real time data "cloud") to one or more reference baselines (e.g., that may represent "healthy” operations, conditions, etc.).
  • PLM prognostics and health management
  • the method 1010 can include generating one or more references whereas in Fig.
  • the method 1 1 10 can include generating a data "cloud” or database for an ongoing operation, which may be a liner hanger setting operation and then comparing at least a portion of the data of the data "cloud” or database to, for example, the one or more references of the method 1010.
  • a method may help to lessen dependency on having experienced specialists on a rig floor during an on-going operation.
  • a method may help to minimize risk of human error in analyzing multitude of data types.
  • a method may provide additional assistance in decision making and, for example, extra assurance to one or more operators.
  • a method may add value to a liner hanger real time or near real time telemetry system such as the system 800 of Fig. 8A.
  • a method can include automatic prognosis of success of one or more types of downhole operation where, for example, one or more healthy baselines are available that describe and/or characterize a successful event.
  • a method can include progressing through a workflow where various events are to occur sequentially and/or in parallel.
  • a method may be implemented for one or more types of events, for example, an event may pertain to setting of a packer, gravel packing, setting of a liner hanger, passage of a dart, passage of a ball, etc.
  • a real time or near real time telemetry module for a liner hanger may convey one or more of the following data types from downhole to surface: pressure and temperature measurements; vertical and rotational tool movement measurements; tension, compression and/or torque measurements.
  • a method or workflow as to a PHM implementation may occur in phases. For example, consider a two phase process where, in phase 1 , measurements and possibly additional signals will make up the basis for performance parameters to construct a healthy reference baseline (e.g., for an event or events) which describes at least one operational condition with a successful outcome.
  • a healthy reference baseline e.g., for an event or events
  • the reference baseline can be constructed over a period of time by collecting and analyzing data from multiple successful liner hanger jobs.
  • different reference baselines might be developed according to different reservoir and/or usage conditions.
  • a second phase, phase 2 may commence after one or more reference baseline(s) are ready to use, for a subsequent liner hanger job or jobs where real time or near real time downhole measurements can be acquired to compute a running "line” or data "cloud” in real time or near real time that can be compare to one or more existing reference baselines.
  • Such an approach may indicate the success or failure of an on-going liner hanger setting operation, for example, optionally at one or more confidence levels.
  • Fig. 12A shows an example of a system 1210
  • Fig. 12B shows an example of a method 1230
  • Fig. 12C shows an example of a method.
  • the system 1210 includes a liner hanger running tool that includes a through bore 1212; and an acoustic telemetry circuit 1214 operatively coupled to the liner hanger running tool.
  • the system 1210 can include at least one sensor operatively coupled to the liner hanger running tool and operatively coupled to the acoustic telemetry circuit.
  • a pressure sensor e.g., wherein the position sensor includes a rotating component.
  • a liner hanger running tool can be a portion of a tool string where the tool string includes a plurality of acoustic telemetry circuits.
  • a liner hanger running tool can be or include a collet running tool or, for example, a rotating running tool.
  • a system can include a plug that includes a maximum diameter that is less than a diameter of a through bore of a liner hanger running tool.
  • the plug can include circuitry, for example, such circuitry can include at least one sensor.
  • a plug can include communication circuitry and a liner hanger running tool can include corresponding communication circuitry (e.g., operable via a communication protocol, etc.).
  • system can include a liner where the liner includes at least one acoustic telemetry circuit.
  • a system can include a tool operatively coupled to a liner hanger running tool where the tool includes an acoustic telemetry circuit and where the liner hanger running tool includes an acoustic telemetry circuit.
  • the method 1230 includes a reception block 1232 for receiving an acoustic signal at an acoustic telemetry circuit operatively coupled to a liner hanger running tool; and a repetition block 1234 for repeating the acoustic signal using the acoustic telemetry circuit operatively coupled to the liner hanger running tool.
  • a method can include receiving an acoustic signal that includes position information associated with a position of a component operatively coupled to a liner hanger running tool.
  • a method can include receiving an acoustic signal that includes measurement information for at least one environmental condition (e.g., pressure, temperature, tension, compression, etc.).
  • the method 1250 includes a reception block 1252 for receiving information transmitted at least in part via an acoustic telemetry system where the information pertains to a specified event of a liner hanger operation plan; an analysis block 1254 for analyzing at least a portion of the information; and an output block 1256 for, based at least in part on the analyzing, outputting a probability for the specified event (e.g., to a display, etc.).
  • the probability can correspond to a likelihood of occurrence of the event of the liner hanger operation plan.
  • a method can include monitoring position information of a downhole tool in a bore.
  • a method can include monitoring the position of a service tool during one or more completions operations.
  • some method can involve equipment usable with a well where the equipment includes a liner hanger running tool.
  • equipment that includes a tubular string; a liner hanger service tool adapted to be run downhole as a unit; and at least one sensor to be run downhole as part of the unit.
  • a system may include a surface controller disposed at the Earth's surface to communicate with the at least one sensor during a completion operation.
  • a surface controller may be adapted to display information to an operator.
  • a system may include a plurality of repeater stations to relay a signal from a sensor to a surface controller or from the surface controller to a service tool.
  • a system can include a completion assembly and a service tool.
  • a packer can be operatively coupled to a completion assembly and adapted to anchor the completion assembly in a stationary position within a wellbore.
  • a service tool can be operatively coupled to the completion assembly, and the service tool can be adapted to release from the
  • a sensor assembly can be coupled to such a service tool.
  • a sensor assembly can include a wheel that is adapted to contact and roll along a wall of a wellbore as a service tool moves a distance within the wellbore.
  • a sensor assembly can be adapted to measure distance travelled by a service tool, for example, where the distance can correspond to a number of revolutions of a wheel.
  • a sensor assembly can be adapted to determine a position of a service tool in a wellbore by comparing the distance travelled to a stationary reference point.
  • Fig. 13 depicts a perspective view of an illustrative sensor assembly 1300 in the disengaged position, according to one or more embodiments.
  • the sensor assembly 1300 can include a housing 1302, a motor 1304, one or more arms (two are shown) 1306a, 1306b, and one or more wheels (one is shown) 1308.
  • the housing 1302 can be coupled to or integral with the service tool 706 (see Fig. 7A).
  • the housing 1302 can be cylindrical with a longitudinal bore 1310 extending partially or completely therethrough.
  • the housing 1302 can also include a recess 1312 in which the motor 1304, arms 1306a, 1306b, and a wheel 1308 are disposed when the sensor assembly 1300 is in the disengaged position, as shown in Fig. 13.
  • Fig. 14 depicts a perspective view of the illustrative sensor assembly 1300 of Fig. 13 in the engaged position, according to one or more embodiments.
  • the motor 1304 can move a screw 1314 axially along a shaft 1316 causing the arms 1306a, 1306b to move the wheel 1308 radially outward toward the wall 712 of the wellbore 702 (see Figs. 7A and 7B).
  • the motor 1304 can be used to control the amount of force applied to the wheel 1308 to maintain contact between the wheel 1308 and the wall 712.
  • the motor 1304 can also be used to retract the wheel 308 back into the disengaged position.
  • Fig. 15 depicts a perspective view of another illustrative sensor assembly 1500
  • Fig. 16 depicts a cross-sectional view of the sensor assembly 1500 of Fig. 15, according to one or more embodiments.
  • the sensor assembly 1500 can include first and second axles 1502, 1504 one or more springs (one is shown) 1506, an arm or yoke 1508, a wheel 1510, and one or more sensors (one is shown) 1512.
  • the first axle 1502 can extend through a first end 1514 of the yoke 1508, and the spring 1506 can be disposed around the first axle 1502.
  • the spring 1506 can be adapted to actuate and maintain the sensor assembly 1500 in the engaged position.
  • the second axle 1504 can be coupled to and extend through the wheel 1510 proximate a second end 1516 of the yoke 1508.
  • the wheel 1510 can be adapted to roll against the wellbore 702, i.e., roll along the wall 712 of the wellbore 702, as the service tool 706 moves within the wellbore 702 (see Figs. 7A and 7B).
  • the second axle 1504 can be adapted to rotate through the same angular distance as the wheel 1510, i.e., one revolution of the wheel 1510 corresponds to one revolution of the second axle 1504.
  • one or more magnets (one is shown) 1518 can be disposed on or in the second axle 1504 and/or the wheel 1510 such that the magnet 1518 is adapted to rotate through the same angular distance as the wheel 1510.
  • the sensor 1512 can be disposed proximate the magnet 1504 and adapted to sense or measure the variations in the magnetic field as the magnet 1504 rotates.
  • the sensor 1512 can be disposed in an atmospheric chamber 1520. As such, a wall 1522 can be disposed between the magnet 1518 and the sensor 1512.
  • the atmospheric chamber 1520 can be airtight to prevent fluid from the wellbore 702 from leaking therein.
  • One or more circuits (one is shown) 1524 can also be disposed within the atmospheric chamber 1520 and in communication with the sensor 1512; however, in at least one embodiment, the sensor 1512 and the circuit 1524 can be a single
  • the circuit 1524 can be adapted to receive the measurements from the sensor 1512 corresponding to the variations in the magnetic field and determine the number of revolutions and/or partial revolutions completed by the wheel 1510. The circuit 1524 can then measure the distance travelled by the service tool 706 in the wellbore 702 (see Figs. 7A and 7B) based upon the number of revolutions and/or partial revolutions completed by the wheel 1510, as explained in more detail below.
  • the number of revolutions completed by the wheel 1510 and/or the distance travelled by the service tool 706 can be transmitted to an operator or recording device at the surface through a wire or wirelessly.
  • a cable or wire (not shown) may be adapted to receive signals from the sensor 1512 and/or circuit 1524 through a bulkhead 1526.
  • the cable can run through a channel 1528 in the yoke 1508 and out an opening 1530 through the end 1514 of the yoke 1508.
  • the yoke 1508 can be made of a non-magnetic material.
  • the yoke 1508 can be made of a metallic alloy, such as one or more INCONEL® alloys.
  • Fig. 17 depicts an illustrative wheel 1700 that can be coupled to a sensor assembly (see, e.g., 710, 1300, 1500, etc.), according to one or more embodiments.
  • a sensor assembly see, e.g., 710, 1300, 1500, etc.
  • the wheel 1700 can be adapted to roll against the wellbore 702 when the service tool 706 moves within the wellbore 702.
  • the axial and/or rotational distance travelled by the service tool 706 can be measured, e.g., by the sensor 1512 and/or circuit 1524 in Fig. 16.
  • a full revolution of the wheel 1700 represents an distance travelled by the service tool 706 calculated by the following equation:
  • D 2 * TT*R
  • ⁇ is the mathematical constant pi
  • R is the radius of the wheel 1700.
  • the radius R of the wheel 1700 is a known quantity and can range from a low of about 0.05 cm, about 1 cm, about 2 cm, or about 3 cm to a high of about 5 cm, about 10 cm, about 20 cm, about 40 cm, or more.
  • the radius R of the wheel 1700 can be from about 1 cm to about 3 cm, about 3 cm to about 6 cm, about 6 cm to about 10 cm, or about 10 cm to about 20 cm.
  • One or more targets (six are shown) 1702 a-f can be disposed at different circumferential positions on the wheel 1700. As the number of targets 1706a/increases, the precision of the measurement of the distance D can also increase.
  • the distance D travelled by the service tool 706 can be calculated the following equation:
  • D (2 * ⁇ * R * S)/N
  • ⁇ is the mathematical constant pi
  • R is the radius of the wheel
  • S is the number of targets 1702 a-f sensed or counted by the sensor, e.g., sensor 1800 in Fig. 18, and N is the total number of targets 1702 a-f disposed on the wheel 1700.
  • the distance D travelled by the service tool 706 is equal to (2 * ⁇ * R * 3)/6 because the wheel 1700 includes 6 targets, and 3 targets will be sensed or counted when the wheel 1700 rotates half of a revolution.
  • the number N of targets 1702 a-f disposed on the wheel 1700 can range from a low of about 1 , about 2, about 3, about 4, or about 5 to a high of about 6, about 8, about 10, about 12, about 24, or more.
  • the number N of targets 1702 a-f can be from about 1 to about 12, from about 2 to about 10, or from about 4 to about 6.
  • the targets 1702 a-f can be disposed on the side or axial end 1704 of the wheel 1700, as shown, or the targets 1702a-f can be disposed on the radial end 1706 of the wheel 1700.
  • the targets 1702 a-f can be disposed within one or more recesses (not shown) on the radial end 1706 of the wheel 1700 so that the targets 1702 a-f do not come in direct contact with the wall 712 of the wellbore 702 (see Figs. 7A and 7B) as the wheel 1700 rotates.
  • the radial end 1706 of the wheel can include a coating or layer having a high coefficient of friction that prevents the wheel 1700 from slipping or skidding as the wheel 1700 rotates along the wall 712 of the wellbore 702.
  • the coating or layer can also have a high wear resistance to improve longevity.
  • Fig. 18 depicts an illustrative sensor 1800 disposed proximate the wheel 1700 of Fig. 17, according to one or more embodiments.
  • the sensor 1800 can be disposed on the sensor assembly 710, 1300, 1500, etc., such that the sensor 1800 is stationary with respect to the rotatable wheel 1700. Further, the sensor 1800 can be disposed on the sensor assembly 710, 1300, 1500, etc., such that the sensor 1800 can sense or count the targets 1702 a-f on the wheel 1700 as targets 1702 a-f pass by the sensor 1800 when the wheel 1700 rotates.
  • the senor 1800 can be disposed proximate the side 1704 of the wheel 1700 if the targets 1702 a-f are disposed on the side 1704 of the wheel 1700, as shown in Fig. 17, or the sensor 1800 can be disposed proximate the radial end 1706 of the wheel 1700 if the targets 1702 a-f are disposed on the radial end 1706 of the wheel 1700.
  • the communication between the targets 1702 a-f and the sensor 1800 can be magnetic, electrical, mechanical, optical, or direct contact.
  • the targets 1702 a-f can be magnets, as described above.
  • the targets 1702 a-f can be radio frequency identification (RFID) tags.
  • RFID radio frequency identification
  • the distance between the sensor 1800 and the targets 1702 a-f can range from a low of about 0 cm (direct contact), about 0.1 cm, about 0.2 cm, or about 0.3 cm to a high of about 0.5 cm, about 1 cm, about 5 cm, about 10 cm, or more.
  • the distance between the sensor 1800 and the targets 1702 a-f can be from about 0 cm to about 0.2 cm, about 0.2 cm to about 0.5 cm, about 0.5 cm to about 1 cm, or about 1 cm to about 4 cm.
  • Fig. 19 depicts another illustrative sensor assembly 1900, according to one or more embodiments.
  • the sensor assembly 1900 can include a wheel 1902, a shaft 1904, and a sensor 1906 disposed within a housing 1908.
  • the wheel 1902 can be in contact with the wall 712 of the wellbore 702 (see Figs. 7A and 7B) and adapted to rotate when the service tool 706 moves within the wellbore 702.
  • the shaft 1904 can be coupled to the wheel 1902 and adapted to rotate through the same angular distance as the wheel 1902.
  • the shaft 1904 can be in communication with the sensor 1906 in the housing 1908.
  • the sensor 1906 can measure the number of revolutions and/or partial revolutions of the shaft 1904, which can then be used to calculate the distance D travelled by the service tool 706 in the wellbore 702 (see Figs. 7A and 7B).
  • the sensor 1906 can include a gear tooth counter, an optical encoder, a mechanical encoder, a contact encoder, a resolver, a rotary variable differential transformer (RVDT), a synchro, a rotary potentiometer, or the like.
  • Fig. 20 depicts another illustrative sensor assembly 2000, according to one or more embodiments.
  • the sensor assembly 2000 can include a wheel 2002, a shaft 2004, a gear 2006, a sensor 2008, and a housing 2010.
  • the wheel 2002 can be in contact with the wall 712 of the wellbore 702 (see Figs. 7A and 7B) and adapted to rotate when the service tool 706 moves within the wellbore 702.
  • the shaft 2004 can be coupled to the wheel 2002 and adapted to rotate through the same angular distance as the wheel 2002.
  • the gear 2006 and the sensor 2008 can be disposed within the housing 2010, and a seal 2012, such as a rotary seal, can be used to prevent fluid from entering the housing 2010.
  • the gear 2006 can be coupled to the shaft 2004 and adapted to rotate through the same angular distance as the shaft 2004.
  • the gear 2006 can include one or more teeth 2014 disposed on an outer radial or axial surface thereof.
  • the number of teeth 2014 can range from a low of about 1 , about 2, about 4, about 5, or about 6 to a high of about 8, about 10, about 12, about 20, about 24, or more.
  • the number of teeth 2014 can range from about 1 to about 4, from about 4 to about 8, from about 8 to about 12, or from about 12 to about 24.
  • the sensor 2008 can be in direct or indirect contact with the gear 2006 and adapted to sense or count the number of teeth 2014 that pass by as the gear 2006 rotates. This measurement can be used to calculate the distance D that the service tool 706 moves in the wellbore 702. This measurement can also be used to calculate the velocity V and/or the acceleration A of the service tool 706 in the wellbore 702.
  • the gear 2006 can be in direct contact with the wall 712 of the wellbore 702, and the sensor 2008 can be exposed, i.e., not disposed within the housing 2010.
  • Fig. 21 depicts a cross-sectional view of another illustrative sensor assembly 2100, according to one or more embodiments.
  • the sensor assembly 2100 can be coupled to or integral with the service tool 706.
  • the sensor assembly 2100 can include a housing 2101 having first and second connectors 2102, 2104 adapted to connect the sensor assembly 2100 to the service tool 706.
  • the sensor assembly 2100 can also include a bore 2106 extending partially or completely
  • At least a portion of the sensor assembly 2100 can include a stand-off 2108 that extends radially outward from the remaining portion of the sensor assembly 2100.
  • the sensor assembly 2100 can include an arm or yoke 21 10 having a wheel 21 12 coupled thereto.
  • the yoke 21 10 and wheel 21 12 can be akin to the yoke 1508 and wheel 1510 described above.
  • One or more electronic components 21 14 can be disposed within the housing 2101 .
  • the electronic components 21 14 can include one or more circuits adapted to receive the data from the wheel 21 12, e.g., the number of revolutions.
  • the electronic components 21 14 can be adapted to measure the distance travelled by the service tool 706 based on the data from the wheel 21 12.
  • the electronic components 21 14 can be adapted to measure the distance travelled by the service tool 706 and determine the position of the service tool 706 in the wellbore 702 based upon the distance measurements.
  • the electronic components can be adapted to transmit the distance travelled and/or the position of the service tool 706 in the wellbore to an operator or recording device at the surface.
  • One or more batteries 21 16 can also be disposed within the housing 2101 .
  • the batteries 21 16 can form an annular battery pack within the housing 2101 .
  • the batteries 21 16 can be adapted to supply power to the yoke 21 10, the motor actuating the yoke 21 10, the electronic components 21 14, or other downhole devices.
  • Fig. 22 shows components of an example of a computing system 2200 and an example of a networked system 2210.
  • the system 2200 includes one or more processors 2202, memory and/or storage components 2204, one or more input and/or output devices 2206 and a bus 2208.
  • instructions may be stored in one or more computer-readable media (e.g., memory/storage components 2204). Such instructions may be read by one or more processors (e.g., the
  • 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 2210.
  • the network system 2210 includes components 2222-1 , 2222-2, 2222-3, . . . 2222-N.
  • the components 2222-1 may include the processor(s) 2202 while the component(s) 2222-3 may include memory accessible by the processor(s) 2202.
  • the component(s) 2202-2 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 802.1 1 , 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.).
  • a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. ⁇ 1 12, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words "means for" together with an associated function.

Landscapes

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

Abstract

Système pouvant comprendre un outil de pose de suspension de colonne perdue qui comprend un trou débouchant; et un circuit de télémétrie acoustique fonctionnement accouplé à l'outil de pose de suspension de colonne perdue. Un procédé peut consister à recevoir un signal acoustique au niveau d'un circuit de télémétrie acoustique fonctionnellement accouplé à un outil de pose de suspension de colonne perdue; et à répéter le signal acoustique en utilisant le circuit de télémétrie acoustique fonctionnellement accouplé à l'outil de pose de suspension de colonne perdue.
PCT/US2015/063377 2014-12-05 2015-12-02 Capteur de fond de trou et télémétrie à distance de suspension de colonne perdue WO2016089964A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201462088393P 2014-12-05 2014-12-05
US62/088,393 2014-12-05

Publications (1)

Publication Number Publication Date
WO2016089964A1 true WO2016089964A1 (fr) 2016-06-09

Family

ID=56092370

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2015/063377 WO2016089964A1 (fr) 2014-12-05 2015-12-02 Capteur de fond de trou et télémétrie à distance de suspension de colonne perdue

Country Status (1)

Country Link
WO (1) WO2016089964A1 (fr)

Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN108233233A (zh) * 2018-01-26 2018-06-29 国家电网公司 一种变压器检修平台用防护工具
US10570723B2 (en) 2016-05-23 2020-02-25 Schlumberger Technology Corporation System and methodology for coupling tubing
CN110998624A (zh) * 2017-06-27 2020-04-10 斯伦贝谢技术有限公司 用于优化井测试操作的方法和设备
CN113027411A (zh) * 2021-03-05 2021-06-25 中海石油(中国)有限公司 一种智能油气田丛式井井下组网方法
WO2022051752A1 (fr) * 2020-09-03 2022-03-10 Defiant Engineering, Llc Drone d'intervention et de complétion en fond de trou et procédés d'utilisation
GB2628745A (en) * 2020-04-10 2024-10-02 Drill Quip Inc Method of and system for control/monitoring of internal equipment in a riser assembly

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20090045974A1 (en) * 2007-08-14 2009-02-19 Schlumberger Technology Corporation Short Hop Wireless Telemetry for Completion Systems
US20110079401A1 (en) * 2009-10-02 2011-04-07 Philippe Gambier Equipment and Methods for Deploying Line in a Wellbore
US20110192593A1 (en) * 2007-04-02 2011-08-11 Halliburton Energy Services, Inc. Use of Micro-Electro-Mechanical Systems (MEMS) in Well Treatments
US20120090836A1 (en) * 2008-08-20 2012-04-19 Baker Hughes Incorporated Arrangement and method for sending and/or sealing cement at a liner hanger
US20140008083A1 (en) * 2010-11-12 2014-01-09 Lev Ring Remote Operation of Setting Tools for Liner Hangers

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20110192593A1 (en) * 2007-04-02 2011-08-11 Halliburton Energy Services, Inc. Use of Micro-Electro-Mechanical Systems (MEMS) in Well Treatments
US20090045974A1 (en) * 2007-08-14 2009-02-19 Schlumberger Technology Corporation Short Hop Wireless Telemetry for Completion Systems
US20120090836A1 (en) * 2008-08-20 2012-04-19 Baker Hughes Incorporated Arrangement and method for sending and/or sealing cement at a liner hanger
US20110079401A1 (en) * 2009-10-02 2011-04-07 Philippe Gambier Equipment and Methods for Deploying Line in a Wellbore
US20140008083A1 (en) * 2010-11-12 2014-01-09 Lev Ring Remote Operation of Setting Tools for Liner Hangers

Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10570723B2 (en) 2016-05-23 2020-02-25 Schlumberger Technology Corporation System and methodology for coupling tubing
CN110998624A (zh) * 2017-06-27 2020-04-10 斯伦贝谢技术有限公司 用于优化井测试操作的方法和设备
EP3646265A4 (fr) * 2017-06-27 2021-04-07 Services Pétroliers Schlumberger Procédés et appareil d'optimisation des opérations d'essai de puits
CN108233233A (zh) * 2018-01-26 2018-06-29 国家电网公司 一种变压器检修平台用防护工具
CN108233233B (zh) * 2018-01-26 2023-08-04 国家电网公司 一种变压器检修平台用防护工具
GB2628745A (en) * 2020-04-10 2024-10-02 Drill Quip Inc Method of and system for control/monitoring of internal equipment in a riser assembly
WO2022051752A1 (fr) * 2020-09-03 2022-03-10 Defiant Engineering, Llc Drone d'intervention et de complétion en fond de trou et procédés d'utilisation
CN113027411A (zh) * 2021-03-05 2021-06-25 中海石油(中国)有限公司 一种智能油气田丛式井井下组网方法

Similar Documents

Publication Publication Date Title
EP3494276B1 (fr) Commande de transport d'équipement de fond de trou
US9896926B2 (en) Intelligent cement wiper plugs and casing collars
WO2016089964A1 (fr) Capteur de fond de trou et télémétrie à distance de suspension de colonne perdue
US20200362686A1 (en) Machine Learning Drill Out System
CA3114557C (fr) Puits dans une structure geologique
US10920561B2 (en) Drilling assessment system
US9404358B2 (en) Wiper plug for determining the orientation of a casing string in a wellbore
US12006822B2 (en) High flowrate formation tester
US10358883B2 (en) Multi-run retrievable battery pack for electronic slickline tools
CA2509603C (fr) Bouchon separable pour utilisation avec un outil de puits de forage
CA3028081C (fr) Systeme de service filaires
AU2013402086B2 (en) Wiper plug for determining the orientation of a casing string in a wellbore
US20230287785A1 (en) Bore plug analysis system
US20230287784A1 (en) Bore plug analysis system
WO2024137903A1 (fr) Unités de télémétrie de fond de trou positionnables
WO2023212270A1 (fr) Surveillance d'espace annulaire de tubage

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 15864325

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 15864325

Country of ref document: EP

Kind code of ref document: A1