WO2009018420A2 - Appareil et procédé de communication de données entre un puits et la surface par impulsions de pression - Google Patents

Appareil et procédé de communication de données entre un puits et la surface par impulsions de pression Download PDF

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Publication number
WO2009018420A2
WO2009018420A2 PCT/US2008/071720 US2008071720W WO2009018420A2 WO 2009018420 A2 WO2009018420 A2 WO 2009018420A2 US 2008071720 W US2008071720 W US 2008071720W WO 2009018420 A2 WO2009018420 A2 WO 2009018420A2
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WO
WIPO (PCT)
Prior art keywords
conduit
signals
pressure pulses
transducer
location
Prior art date
Application number
PCT/US2008/071720
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English (en)
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WO2009018420A3 (fr
Inventor
Michael H. Johnson
Original Assignee
Baker Hughes Incorporated
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 Baker Hughes Incorporated filed Critical Baker Hughes Incorporated
Priority to CA2693485A priority Critical patent/CA2693485A1/fr
Publication of WO2009018420A2 publication Critical patent/WO2009018420A2/fr
Publication of WO2009018420A3 publication Critical patent/WO2009018420A3/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves

Definitions

  • This disclosure relates to apparatus and methods for communicating data between a well and the surface.
  • Wells also referred to as “wellbores” or “boreholes” are drilled and completed to produce hydrocarbons (oil and gas) from one or more production zones penetrated by a wellbore.
  • a typical completed well may include a metallic casing that lines the well. Cement is generally placed between the casing and the well to provide a seal between the formation surrounding the well and the casing. Perforations made in the formation through the casing at selected locations across from the producing formations (also referred to as the "production zones” or “reservoirs”) allow the formation fluid containing the hydrocarbons to flow into the cased well.
  • the formation fluid flows to the surface via a production tubing placed inside the casing because the pressure in the production zone is generally higher than the pressure caused by the weight of the fluid column in the well.
  • An artificial lift mechanism such as an electrical submersible pump (“ESP”) or a gas-lift mechanism is often employed when the formation pressure is not adequate to push the fluid in the well to the surface.
  • ESP electrical submersible pump
  • gas-lift mechanism is often employed when the formation pressure is not adequate to push the fluid in the well to the surface.
  • a variety of devices are used in the well to control the flow of the fluid from the production zones to optimize the oil and gas production over the life of the well.
  • Remotely-controlled flow control valves and chokes are often used to control the flow of the fluid.
  • Chemicals are injected at certain locations in the well via one or more tubes that run from the surface to the production zones to inhibit the formation of harmful chemicals, such as corrosion, hydrate, scale, hydrogen sulfide, methane, asphaltene, etc.
  • a number of sensors are typically placed in the well to provide information about a variety of downhole parameters, including the position of the valves and chokes, pressure, temperature, fluid flow rate, acoustic signals responsive to water front and surface or downhole induced signals in the subsurface formations, resistivity, porosity, permeability, water-cut, etc.
  • the measurement data is typically transmitted to the surface via conductors, such as electrical wires, that run from the surface to selected locations in the well. Signals are also sent from the surface to the downhole sensors and devices via such conductors to control their operations. Such conductors can degrade over time or become non-functional. It is therefore desirable to have a data communication system that may be less prone to degradation.
  • the present disclosure provides improved apparatus, systems and methods for communicating data between a well and the surface.
  • a method in one aspect, includes: placing a conduit containing non-circulating liquid therein in a well; and generating pressure pulses through the liquid in the tubing to transmit information between a location in the well and the surface.
  • the system may further include one or more repeaters that detect pressure pulses in the conduit and transmit pressure pulses through the liquid in the conduit that correspond to the detected pressure pulses.
  • a well data communication system includes: a conduit which extends from a downhole location to an uphole location and a transducer that is configured to send information through the liquid medium in the form of pressure pulses.
  • a detector spaced from the transducer detects the pulses in the conduit.
  • an apparatus for use in a well that includes: a conduit that has a liquid medium therein, which conduit is configured to be deployed in the well; and a transducer that is configured to generate pressure pulses through the liquid medium in the conduit to transmit data signals.
  • FIG IA shows a schematic diagram of an exemplary well configured to provide data communication between devices in the well and a surface controller according to one embodiment of the disclosure
  • FIG IB shows a schematic diagram of certain controllers and devices at the surface that may be utilized to establish data communication between the well and the surface;
  • FIG 2 shows a functional block diagram of a transducer that may be utilized to generate pressure pulses in a well system to establish data communication between a well and the surface, such as shown in FIGS. 1 and 2.
  • FIGS. IA and IB collectively show schematic diagrams of an exemplary embodiment of a well system 100 that includes a data communication system between a completed well 50 and the surface 112 according to one embodiment of the disclosure.
  • FIG IA shows the schematic diagram of the equipment of the well system 100 that is below the surface 112
  • FIG IB shows the functional block diagram of exemplary equipment of the well system 100 that may be deployed at the surface 112 to manage the operations of the system 100.
  • the system 100 shows the well 50 formed in a formation 55 that produces formation fluids 56a and 56b (such as hydrocarbons) from two exemplary production zones 52a (upper production zone) and 52b (lower production zone) respectively.
  • formation fluids 56a and 56b such as hydrocarbons
  • the well 50 is shown lined with a casing 57 containing perforations 54a, adjacent the upper production zone 52a and perforations 54b adjacent the lower production zone 52b.
  • a packer 64 which may be a retrievable packer, positioned above or uphole of the lower production zone perforations 54a isolates the lower production zone 52b from the upper production zone 52a.
  • a screen 59b adjacent to the perforations 54b may be installed to prevent or inhibit solids, such as sand, from entering into the wellbore from the lower production zone 54b.
  • a screen 59a may be used adjacent the upper production zone perforations 59a to prevent or inhibit solids from entering into the well 50 from the upper production zone 52a.
  • Formation fluid 56b from the lower production zone 52b enters the annulus 51a of the well 50 through the perforations 54a and into a tubing 53 via a flow control valve 67.
  • the flow control valve 67 may be a remotely controlled sliding sleeve valve or any other suitable valve or choke that is configured to regulate the flow of the fluid from the annulus 51a into the production tubing 53.
  • An adjustable choke 40 in the tubing 53 may be used to regulate the fluid flow from the lower production zone 52b to the surface 112.
  • the formation fluid 56a from the upper production zone 52a enters the annulus 51b (the annulus portion above the packer 64) via perforations 54a.
  • the formation fluid 56a enters production tubing or line 45 via inlets 42.
  • An adjustable valve or choke 44 regulates the fluid flow into the tubing 45.
  • Each valve, choke and other such device in the well may be operated electrically, hydraulically, mechanically and/or pneumatically by a surface control unit, such as controller 150 and/or by a downhole control unit or controller, such as controller 60.
  • the fluid from the upper production zone 52a and the lower production zone 52b enter the line 46.
  • an artificial lift mechanism such as an electrical submersible pump (ESP), gas lift system or other desired systems may be utilized to lift the fluids from the well 50 to the surface 112.
  • ESP electrical submersible pump
  • gas lift system gas lift system
  • a cable 134 provides power to the ESP 30 from a surface power source 132.
  • the cable 134 also may include two-way data communication links 134a and 134b (FIG IB), which may include one or more electrical conductors or fiber optic links to provide two-way signals and data communication between the ESP 30, ESP sensors S E and an ESP control unit 130 (FIG IB).
  • FOG IB two-way data communication links 134a and 134b
  • a variety of sensors are placed at suitable locations in the well 50 to provide measurements or information relating to a number of downhole parameters of interest.
  • one or more gauge or sensor carriers such as a carrier 15, may be placed in the production tubing to house any number of suitable sensors.
  • the carrier 15 may include one or more temperature sensors, pressure sensors, flow measurement sensors, resistivity sensors, sensors that may provide information about density, viscosity, water content or water cut, etc., and chemical sensors that provide information about scale, corrosion, hydrate, paraffin, hydrogen sulfide, emulsion, asphaltene, etc.
  • Density sensors may provide fluid density measurements for fluid produced from each production zone and that of the combined fluid from two or more production zones.
  • the resistivity sensor or another suitable sensor may provide measurements relating to the water content or the water-cut of the fluid mixture received from each production zones and/or the combined fluid.
  • Other sensors may be used to estimate the oil/water ratio and gas/oil ratio for each production zone and for the combined fluid.
  • the temperature, pressure and flow sensors provide measurements for the pressure, temperature and flow rate of the fluid in the line 53.
  • Additional gauge carriers may be used to obtain one or more of the above-noted and other measurements relating to the formation fluid received from the upper production zone 52a.
  • Additional downhole sensors may be used at other desired locations to provide measurements relating to the presence and extent of chemicals downhole.
  • sensors Si-S n may be permanently installed in the wellbore 50 to provide acoustic, seismic or microseismic measurements, formation pressure and temperature measurements, resistivity measurements and measurements relating to the properties of the casing 51 and formation 55.
  • sensors may be installed in the casing 57 or between the casing 57 and the formation 55.
  • Microseismic and other sensors may be used to detect water fronts, which may aid in making adjustments to the flow rates fro each zone, chemical injection rate, ESP frequency, etc. Pressure and temperature changes or expected changes may provide early warning of changes in the chemical composition of the production fluid.
  • the screen 59a and/or screen 59b may be coated with tracers that are released due to the presence of water, which tracers may be detected at the surface or downhole to determine or predict the occurrence of water breakthrough.
  • ESP sensors S E may include sensors that provide information about temperature, pressure and flow rate of the ESP, differential pressure across the ESP, ESP frequency, power, etc. Sensors also may be provided at the surface, such as a sensor for measuring the water content in the received fluid, total flow rate for the received fluid, fluid pressure at the wellhead, temperature, etc. Other devices may be used to estimate the production of sand for each zone.
  • sensors may be suitably placed in the well 50 to obtain measurements relating to each desired parameter of interest.
  • sensors may include, but are not limited to: sensors for measuring pressures corresponding to each production zone, pressure along the wellbore, pressure inside the tubing carrying the formation fluid, pressure in the annulus; sensors for measuring temperatures at selected places along the wellbore; sensors for measuring fluid flow rates corresponding to each of the production zones, total flow rate, flow through the ESP; sensors for measuring ESP temperature and pressure; chemical sensors for providing signals relating to the presence and extent of chemicals, such as scale, corrosion, hydrates, paraffin, emulsion, hydrogen sulfide and asphaltene; acoustic or seismic sensors that measure signals generated at the surface or in offset wells and signals due to the fluid travel from injection wells or due to a fracturing operation; optical sensors for measuring chemical compositions and other parameters; sensors for measuring various characteristics of the formations surrounding the well, such as resistivity, porosity, permeability, fluid density, etc.
  • the sensors may be installed in the tubing in the well or in any device or may be permanently installed in the well.
  • sensors may be installed in the wellbore casing, in the wellbore wall or between the casing and the wall.
  • the sensors may be of any suitable type, including electrical sensors, mechanical sensors, piezoelectric sensors, fiber optic sensors, optical sensors, etc.
  • the signals from the downhole sensors may be partially or fully processed downhole, such as by a controller 60 that includes a microprocessor and associated electronic circuitry that is in signal or data communication with the downhole sensors and devices, and then communicated to the surface controller 150 (FIGL IB) via a signal/data link, such as link 101.
  • the signals from downhole sensors may also be sent directly to the surface controller 150.
  • a variety of hydraulic, electrical and data communication lines are run inside the well 50 to operate the various devices in the well 50 to obtain measurements and other data from the various sensors in the well 50 and to provide power and data communication between the surface and downhole equipment.
  • a tube or tubing 21 may supply or inject a particular chemical from the surface into the fluid 56b via a mandrel 36.
  • a tubing 22 may supply or inject a particular chemical to the fluid 56a in the production tubing via a mandrel 37.
  • Separate lines may be used to supply the additives at different locations in the well 50 or to supply different types of additives.
  • Lines 23 and 24 may operate the chokes 40 and 44 and may be used to operate any other device, such as the valve 67.
  • Lines 25 may provide electrical power to certain devices downhole from a suitable surface power source.
  • Two-way data communication between downhole sensors, devices located at any one or more suitable downhole locations and a downhole controller, such as a controller 60 and/or one or more transducers, such as a transducer 110, may be established by any desired method, including, but not limited to, wires, optical fibers, acoustic telemetry using a fluid line, electromagnetic telemetry, optical fibers, wirelessly, etc.
  • one or more conduits or tubings such as tubings 101 and 102 are placed or run between a suitable location in the well 50 and the surface 112 to establish data communication using pressure pulses through a liquid medium in the tubings 101 and/or 102 through.
  • the tubings may be enclosed at a downhole end and may also be enclosed at the uphole or surface end. Additionally, the tubings include a suitable non- circulating liquid, such as water, oil, etc., which is suitable for sending pressure pulses therethrough.
  • the tubings 101, 102 may be made from any suitable material, such as an alloy or a composite material capable of withstanding the downhole environment for an extended time period. Tubing 102 may be same or similar to the tubing 101.
  • tubing 101 is shown in fluid communication with a downhole transducer 110, which may include any device that is configured to generate pressure pulses in the liquid medium in the tubing 101.
  • the transducer 110 may include a receiver that receives signals or data from one or more sensors, such a sensors Sl-Sm in the well 50 and other devices, such as a sensors that provide signals relating to the position of the sleeve 53, ESP operating parameters, such a flow rate through the ESP, and pump speed, etc.
  • Such data or signals may be provided to the transducer 110 via any suitable data link, such as electrical conductors, optical fibers or wireless links.
  • the transducer may be an active device that include a processor, memory and other circuitry that are configured to receive signals from one or more sensors and devices, process the received signals and transmit the processed signals as pressure signals through the liquid medium in the tubing 101.
  • the processor may use any telemetry scheme, including but not limited to, amplitude, frequency, phase, pulse duration, pulse shape, time between the pulses or any combination thereof.
  • a second transducer 120 spaced from the transducer 110 detects or receives the pressure pulses and sends the received signals to a surface controller or control unit, such as the central controller ISO.
  • the second transducer may include any suitable detector for detecting pressure pulses, such as a pressure sensor.
  • the surface controller 150 decodes the signals received from the receiver 120 (FIG IB) and uses the signals to manage one or more operations of the well system 10.
  • the surface controller may send data signals to the transducer 120, which transmits the received signals via the liquid media in the tubing 101 in the form of pressure pulses.
  • a separate transducer 122 and tubing 102 may be used to send pressure pulses from the surface 112 to a downhole controller 60 via the liquid medium in the tubing 102.
  • Each of the transducers 110 and 120 may be configured to generate the pressure pulses at multiple frequencies.
  • the pressure pulses may be coded signals and may use any desired signals modulation technique, such as amplitude, phase, frequency, shape, pulse duration, time between pulses modulation or any combination thereof.
  • Any suitable device may be used to generate pressure pulses, including but not limited to, a piezoelectric device, a poppet- type pulser, an oscillating-type or shear-wave pulser, a rotary-type pulser, or another suitable pulser.
  • the pressure pulses transmitted by a transducer may attenuate and may not be detectable by the receiver 120.
  • the transducer 110 over time may not be able to send signals that are strong enough to reach the receiver 120.
  • one or more additional transducers 110 or repeaters such as Ri - R n (generally designated by numeral 114), may be deployed in the well 50 and configured to detect signals from the conduit medium and retransmit the detected signals to the next repeater and/or the receiver 120. Similar transducers and repeaters may be deployed in the second conduit 102.
  • Each of the transducers may be an autonomous device.
  • FIG 2 shows a functional diagram of an autonomous transducer or repeater 200 according to one embodiment of the disclosure.
  • the device 200 may include: a processor 210, such as a micro-controller, microprocessor or another suitable circuit combination; a data storage device or memory device 212, such a solid state memory device (Read-only-memory "ROM,” random access memory (“RAM”, flash memory, etc.) that is suitable for downhole application; and one or more computer programs or sets of instructions 214 that may be stored in the memory 212 and are accessible to the processor 210.
  • a processor 210 such as a micro-controller, microprocessor or another suitable circuit combination
  • a data storage device or memory device 212 such a solid state memory device (Read-only-memory "ROM,” random access memory (“RAM”, flash memory, etc.) that is suitable for downhole application
  • RAM random access memory
  • computer programs or sets of instructions 214 that may be stored in the memory 212 and are accessible to the processor
  • the processor 210 communicates with the memory 212 and the programs 214 via links 211 and 213 respectively.
  • a power source 220 provides power to the processor 210 as shown by link 221 and to the other components of the device 200 via link 223.
  • signals Ti — T p from sensors and other devices may be received by an interface 230.
  • the interface 230 may be configured to condition the received signals, such as by amplifying and digitizing the signals.
  • the processor 210 processes the signals from the interface 230, such as by sequencing the signals, putting the signals in appropriate data packets, assigning addresses of the sensors or the devices from which such signals were received by the interface 230, etc.
  • the processor 210 processes the surface-sent signals and may control one or more downhole devices 260 or send these signals to the downhole controller 60.
  • the processor 210 may store any information in the memory device 212 and/or programs 214 to perform one or more of the functions described herein.
  • the processor 210 is shown to communicate with the receiver 245 via link 243 and with downhole devices 260 via link 261.
  • the downhole transducer 110 receives signals from one or more devices or sensors in the well and transmits signals representative of the received signals as pressure pulses through a liquid-filled conduit placed in the well.
  • a receiver spaced from the downhole transducer detects the pressure pulses and retransmits them to a surface controller for further use.
  • the surface controller may send signals in the form of pressure pulses or by any other method to a downhole receiver via the same or a separate liquid- filled conduit.
  • One or more repeaters may be provided along the liquid-filled tubing's to retransmit the pressure pulses.
  • the exemplary equipment shown in FIG IB may be utilized to manage and control the various operations of the well system 10 in response to the signals received from the downhole transducer 110.
  • the controller ISO may manage injection of additives from a chemical injection unit 120 into the well 50 to enhance production from one or more zones in response to the signals received from a chemical sensor that may provide information about the presence of certain chemicals, such as scale, hydrate, corrosion, asphaltene, hydrogen sulfide, etc. or in response to a water-cut sensor, resistivity sensor, etc.
  • the central controller ISO may control the operation of one or more downhole devices directly or via a downhole device control unit 160 by sending commands via a link 161.
  • the commands may be instructions to alter the position of a choke or a sliding sleeve, etc and such commands may be in response to signals received from one or more downhole devices or sensors and/or signals received from a remote controller, such as controller 185 that may communicate with the controller 150 via a suitable link 189, such as Ethernet, the Internet, etc.
  • the downhole device controller 160 may control the downhole devices via links 21-25.
  • the central controller 150 may control the operation of the ESP 30 directly or via an ESP controller 130.
  • the ESP controller may control power to the ESP from a power source 132 in response to the signals received from the ESP sensors and/or signals received from the central controller 150.
  • a system for communicating information between at least one location in a well and the surface includes: a conduit that filled with a non-circulating liquid and a transducer that generates pressure pulses representative of signals to be transmitted through the conduit.
  • a detector spaced from the transducer detects the pressure pulses in the conduit and generates electrical signals representative of the detected pressure pulses.
  • the transducer may include a pulser that generates the pressure pulses in the liquid in the conduit.
  • the pulser may be any suitable device that is configured to generate the pressure pulses downhole, including but not limited to: a piezoelectric device that generates acoustic signals to generate the pressure pulses; a poppet-type pulser that includes a reciprocating piston or valve that obstructs fluid flow to generate pressure pulses; a shear-wave pulser that generates pressure pulses when a disc oscillates proximate a stationary disc to obstruct fluid flow; a rotary pulser that generates pressure pulses when a disc rotates proximate a stationary to obstruct a fluid flow.
  • the system may include one or more repeaters uphole of the transducer that detects the pressure pulses generated by the transducer.
  • the repeater may condition the detected pressure pulses and generate the conditioned pulses through the liquid medium in the conduit.
  • the uphole location may be in the well or at the surface.
  • the system may further include a surface transducer that generates pressure pulses in a liquid-filled conduit to a downhole location and a detector downhole that detects the pressure pulses sent from the surface.
  • the downhole detector may provide signals corresponding to the detected pulses to a downhole controller or processor.
  • the transducer and /or any of the repeaters may be an autonomous device, which may include: a receiver that receives signals from at least one sensor; a processor that converts the signals received from the at least one sensor into coded signals; and a pulser that generates pressure pulses in the liquid corresponding to the coded signals.
  • the system in another aspect, may further include an interface that receives signals from at least one senor or device in the well.
  • the sensor or device may be one or more of: (i) a pressure sensor; (ii) a temperature sensor; (iii) an acoustic sensor; (iv) a flow rate measuring device; (v) a water-cut measurement device; (vi) a resistivity measuring device; (vii) a chemical detection sensor; (viii) a fiber optic sensor; (ix) a piezoelectric sensor; and (x) a density sensor.
  • the uphole location in the system may be a location in a branch wellbore, a main wellbore, a location at the surface of the earth, a location at the sea bed, a location on a land rig or a location on an offshore vessel or platform.
  • the downhole sensors or devices may send signals to the transducer or a downhole controller via any suitable connection, including, but not limited to, electrical conductors, optical fibers and wireless links.
  • a suitable power source in the well or at the surface may provide power to the downhole transducers and repeaters, which may include: a battery; (ii) a power generation unit that generates electrical power in the wellbore; and (iii) a power unit at the surface that supplies electrical power via an electrical conductor disposed in or along the conduit.
  • the conduit may conduit may be placed: (i) inside a production tubing carrying fluid to thee surface; (ii) between a production tubing and a casing; or (iii) between a casing and formation surrounding the wellbore.
  • the system may include a plurality of sensors distributed in the well, and wherein the system may include a plurality of transducers, each of which receives signals from an associated sensor or device and transmits coded signals as pressure pulses through the liquid in the conduit that are representative of the received signals.
  • the system may include an additional liquid-filled conduit that is used to transmit pressure pulses from the surface to a downhole location.
  • the system may include another telemetry system for transmitting signals from the surface, such an electro-magnet telemetry system, an acoustic telemetry system, wire in a tubing, etc.
  • each transducer and/or repeater may be an autonomous device and may include: an electronics module; and an energy source.
  • the electronic module may further include a processor that acts according to programmed instructions for controlling an operation of the transducer.
  • the energy source may be: (i) a battery; (ii) a thermoelectric generator; (iii) a combination of a battery and a thermoelectric generator; or (iv) a source at the surface.
  • the transducers and repeaters may transmit signals at different frequencies and at more than one frequency. Additionally, the one or more sensors associated with the transducer or repeater may detect at least one parameter of interest related to: (i) a health of the transducer; or (ii) a downhole condition.
  • the sensors downhole may include any suitable sensor or device, including, but not limited to, sensors for providing a measurement relating to: (i) pressure; (ii) temperature; (iii) resistivity; (iv) fluid flow rate; (v) capacitance; (v) viscosity; (vi) density; (vii) presence of a chemical in the wellbore; (viii) paraffin; (ix) scale; (x) hydrate; (xi) hydrogen sulfide; ( xii) asphaltene; (xiii) corrosion; (xiv) water content; (xv) presence of gas; (xvi) water cut.
  • a method in another aspect, includes: placing a liquid-filled conduit in the wellbore; receiving from at least one sensor in the wellbore signals relating to a parameter of interest; transmitting pressure pulses in the liquid in the conduit at a downhole location that are representative of the signals received from the at least one sensor; and detecting the pressure pulses at an uphole location; processing the detected signals to estimate the parameter of interest; and recording the estimated parameter of interest in a suitable medium.
  • the method may further include at last one repeater device at a downhole location that detects the pressure pulses, conditions the detected pressure pulses and transmits the conditioned pressure pulses through the liquid in the conduit.
  • the parameter of interest may by any suitable parameter, including, but not limited to: (i) pressure; (ii) temperature; (iii) resistivity; (iv) fluid flow rate; (v) capacitance; (v) viscosity; (vi) density; (vii) presence of a chemical in the wellbore; (viii) paraffin; (ix) scale; (x) hydrate; (xi) hydrogen sulfide; ( xii) asphaltene; (xiii) corrosion; (xiv) water content; and (xv) presence of gas.
  • suitable parameter including, but not limited to: (i) pressure; (ii) temperature; (iii) resistivity; (iv) fluid flow rate; (v) capacitance; (v) viscosity; (vi) density; (vii) presence of a chemical in the wellbore; (viii) paraffin; (ix) scale; (x) hydrate; (xi) hydrogen sulfide; ( xii) asphaltene; (
  • the method may include: placing a conduit in the well that contains a non-circulating liquid medium therein; and transmitting information in the form of pressure pulses through the medium
  • the apparatus may include: a conduit in a well that contains a non-circulating liquid medium therein and a transmitter configured to transmit pressure pulses through the medium that are representative of signals to be transmitted between a downhole location and an uphole location of a well.

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  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • Geophysics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Remote Sensing (AREA)
  • Acoustics & Sound (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Arrangements For Transmission Of Measured Signals (AREA)
  • Testing Or Calibration Of Command Recording Devices (AREA)
  • Measuring Fluid Pressure (AREA)
  • Measuring Volume Flow (AREA)
  • Infusion, Injection, And Reservoir Apparatuses (AREA)
  • Surgical Instruments (AREA)

Abstract

Dans un aspect, l'invention concerne un appareil de sondage qui comporte un conduit renfermant un liquide non circulant et qui est conçu pour être placé dans un puits ainsi qu'un émetteur conçu pour transmettre des impulsions de pression à travers le liquide renfermé dans le conduit. Dans un autre aspect, l'invention décrit un procédé consiste à placer un conduit dans l'appareil de sondage qui est fermé à une extrémité et renferme un milieu liquide ; et à transmettre des informations sous forme d'impulsions de pression à travers le milieu liquide du conduit.
PCT/US2008/071720 2007-08-02 2008-07-31 Appareil et procédé de communication de données entre un puits et la surface par impulsions de pression WO2009018420A2 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
CA2693485A CA2693485A1 (fr) 2007-08-02 2008-07-31 Appareil et procede de communication de donnees entre un puits et la surface par impulsions de pression

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US11/833,066 US20090034368A1 (en) 2007-08-02 2007-08-02 Apparatus and method for communicating data between a well and the surface using pressure pulses
US11/833,066 2007-08-02

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Publication Number Publication Date
WO2009018420A2 true WO2009018420A2 (fr) 2009-02-05
WO2009018420A3 WO2009018420A3 (fr) 2011-07-21

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WO2014184586A3 (fr) * 2013-05-17 2015-08-13 Halliburton Manufacturing And Services Limited Surveillance et transmission de données de puits de forage jusqu'à la surface

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