WO2021112843A1 - Système de télémétrie acoustique bidirectionnelle - Google Patents
Système de télémétrie acoustique bidirectionnelle Download PDFInfo
- Publication number
- WO2021112843A1 WO2021112843A1 PCT/US2019/064510 US2019064510W WO2021112843A1 WO 2021112843 A1 WO2021112843 A1 WO 2021112843A1 US 2019064510 W US2019064510 W US 2019064510W WO 2021112843 A1 WO2021112843 A1 WO 2021112843A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- acoustic
- downhole
- transmitter
- uphole
- wellbore
- Prior art date
Links
- 230000003287 optical effect Effects 0.000 claims description 66
- 239000012530 fluid Substances 0.000 claims description 53
- 238000000034 method Methods 0.000 claims description 30
- 230000000638 stimulation Effects 0.000 claims description 12
- 238000011282 treatment Methods 0.000 claims description 9
- 230000015572 biosynthetic process Effects 0.000 claims description 8
- 238000005259 measurement Methods 0.000 claims description 7
- 230000005355 Hall effect Effects 0.000 claims description 6
- 238000001514 detection method Methods 0.000 claims description 6
- 230000003116 impacting effect Effects 0.000 claims description 5
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 4
- 238000002955 isolation Methods 0.000 claims description 3
- 238000012360 testing method Methods 0.000 claims description 3
- 230000001133 acceleration Effects 0.000 description 14
- 238000006073 displacement reaction Methods 0.000 description 12
- 238000005516 engineering process Methods 0.000 description 11
- 230000001902 propagating effect Effects 0.000 description 10
- 239000000203 mixture Substances 0.000 description 9
- 230000008569 process Effects 0.000 description 9
- 238000010586 diagram Methods 0.000 description 8
- 238000005755 formation reaction Methods 0.000 description 7
- 238000004891 communication Methods 0.000 description 5
- 230000001939 inductive effect Effects 0.000 description 5
- 239000002245 particle Substances 0.000 description 4
- 238000012545 processing Methods 0.000 description 4
- 230000000644 propagated effect Effects 0.000 description 4
- 230000006870 function Effects 0.000 description 3
- -1 wellbore diameter Substances 0.000 description 3
- 238000005452 bending Methods 0.000 description 2
- 239000004020 conductor Substances 0.000 description 2
- 238000012937 correction Methods 0.000 description 2
- 238000001914 filtration Methods 0.000 description 2
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 239000000463 material Substances 0.000 description 2
- 238000005086 pumping Methods 0.000 description 2
- 230000005855 radiation Effects 0.000 description 2
- 238000004088 simulation Methods 0.000 description 2
- 238000001228 spectrum Methods 0.000 description 2
- 238000009987 spinning Methods 0.000 description 2
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 239000004696 Poly ether ether ketone Substances 0.000 description 1
- 229910000831 Steel Inorganic materials 0.000 description 1
- 239000002253 acid Substances 0.000 description 1
- 238000003491 array Methods 0.000 description 1
- JUPQTSLXMOCDHR-UHFFFAOYSA-N benzene-1,4-diol;bis(4-fluorophenyl)methanone Chemical compound OC1=CC=C(O)C=C1.C1=CC(F)=CC=C1C(=O)C1=CC=C(F)C=C1 JUPQTSLXMOCDHR-UHFFFAOYSA-N 0.000 description 1
- 229910052799 carbon Inorganic materials 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 239000002131 composite material Substances 0.000 description 1
- 230000006835 compression Effects 0.000 description 1
- 238000007906 compression Methods 0.000 description 1
- 230000008602 contraction Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000005684 electric field Effects 0.000 description 1
- 238000011156 evaluation Methods 0.000 description 1
- 239000000835 fiber Substances 0.000 description 1
- 239000011152 fibreglass Substances 0.000 description 1
- 238000007667 floating Methods 0.000 description 1
- 230000005251 gamma ray Effects 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 125000001183 hydrocarbyl group Chemical group 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 229920002530 polyetherether ketone Polymers 0.000 description 1
- 238000005070 sampling Methods 0.000 description 1
- 230000011664 signaling Effects 0.000 description 1
- 239000002904 solvent Substances 0.000 description 1
- 239000010959 steel Substances 0.000 description 1
- 230000001960 triggered effect Effects 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
- E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
- E21B47/18—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the well fluid, e.g. mud pressure pulse telemetry
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
- E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
- E21B47/16—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the drill string or casing, e.g. by torsional acoustic waves
Definitions
- the present disclosure relates generally to acoustic telemetry systems.
- the present disclosure relates to bi-directional acoustic telemetry systems for use in a wellbore.
- Wellbores are drilled into the earth for a variety of purposes including accessing hydrocarbon bearing formations.
- a variety of downhole tools may be used within a wellbore in connection with accessing and extracting such hydrocarbons.
- Such downhole tools often include a number of components such as electronic equipment, sensors, or other modules used for various purposes.
- the downhole tools may require instructions and/or may need to pass along data obtained by sensors of the downhole tool.
- Telemetry is often performed via an electrical cable or fiber optic cable disposed inside a conduit, for example, within coiled tubing. In the absence of such a wired telemetry system, downhole tools may need to be set via a timing mechanism, or triggered by a mechanical event from the surface.
- FIG. 1 is a diagram illustrating an exemplary environment for a bi-directional acoustic telemetry system, in accordance with various aspects of the subject technology
- FIG. 2 is a diagram of a controller of a bi-directional acoustic telemetry system, in accordance with various aspects of the subject technology
- FIG. 3A is a diagram illustrating an exemplary acoustic receiver, in accordance with various aspects of the subject technology
- FIG. 3B is a diagram illustrating another example of an acoustic receiver with multiple optical vibrometers, in accordance with various aspects of the subject technology; and [0008] FIG. 4 is an example method for transmitting and receiving different acoustic signals in a wellbore system, in accordance with various aspects of the subject technology.
- the acoustic telemetry system includes a first acoustic telemetry component and a second acoustic telemetry component.
- the first acoustic telemetry component may include a downhole acoustic transmitter configured to transmit a first acoustic signal from a downhole tool disposed in a wellbore to a surface, and an uphole acoustic receiver to receive signals conveyed by the downhole acoustic transmitter.
- the second acoustic telemetry component may include an uphole acoustic transmitter configured to transmit a second acoustic signal from the surface to the downhole tool disposed in the wellbore, and a downhole acoustic receiver to receive signals conveyed by the uphole acoustic transmitter.
- the downhole and uphole acoustic transmitters can each be operable to convey acoustic signals to their corresponding acoustic receiver by inducing vibrations on a conduit/wellbore and/or by interrupting a flow of a fluid such that longitudinal, compressional, torsional, rotational, and/or flexural waves are propagated through the conduit/wellbore and/or fluid.
- the waves can include components such as, for example, longitudinal components, flexural components, axial components, torsional components, frequencies, phases, amplitudes, velocities, accelerations, angular velocities, angular accelerations, angular displacement, and/or displacement.
- the downhole or uphole acoustic transmitter may impact the conduit at predetermined frequencies, directions and/or intensities such that waves corresponding to the predetermined frequencies, directions, and/or intensities propagate through the conduit to the corresponding acoustic receiver.
- the downhole or uphole acoustic transmitter may interrupt with a flow of fluid to generate a pressure pulse at a predetermined frequency such that waves corresponding to the predetermined frequency propagate through the fluid to the corresponding acoustic receiver.
- the downhole acoustic transmitter may transmit the first acoustic signal via the conduit by inducing vibrations on the conduit.
- the first acoustic signal may represent data gathered from a sensor of the downhole tool.
- the uphole acoustic transmitter may transmit the second acoustic signal via the fluid flowing within the conduit by interrupting flow of the fluid using a valve to thereby generate a pressure pulse within the fluid.
- the second acoustic signal may represent commands or instructions for controlling an operation of the downhole tool.
- the second acoustic telemetry component is separate from the first acoustic telemetry component.
- the downhole acoustic transmitter may be a different type of transmitter than the uphole acoustic transmitter.
- the uphole acoustic receiver may be different than the downhole acoustic receiver.
- the first acoustic telemetry component can send the signal separate and independently through a different method of acoustic telemetry than the second acoustic telemetry component.
- the first acoustic signal may have a higher data rate when compared to the second acoustic signal.
- the first acoustic signal and the second acoustic signal utilize different acoustic telemetry components (for example inducing vibrations on conduit, interrupting flow of a fluid to generate a pressure pulse, etc.), the first and second acoustic signals do not interfere with each other.
- FIG. 1 is a schematic diagram illustrating an exemplary environment for a bi directional acoustic telemetry system 100, in accordance with various aspects of the subject technology.
- the environment may include a wellhead 30 extending over and around a wellbore 14.
- the wellbore 14 is within an earth formation 22 and, in at least one example, can have a casing 20 lining the wellbore 14.
- the casing 20 can be held into place by cement 16.
- the casing 20 can be at least partially made of an electrically conductive material, for example steel.
- the casing 20 can be at least partially made of a non- electrically conductive material, for example fiberglass or PEEK, or of a low-conductivity material, for example carbon composite, or a combination of such materials.
- a downhole tool 50 can be disposed within the wellbore 14 and moved down the wellbore 14 via a conduit 18 to a desired location.
- the conduit 18 may be coiled tubing.
- the conduit 18 can be, for example, tubing-conveyed via a wireline, slickline, work string, joint tubing, jointed pipe, pipeline, and/or any other suitable means.
- the downhole tools 50 can include, for example, downhole sensors, chokes, and valves.
- the chokes and valves may include actuatable flow regulation devices, such as variable chokes and valves, and may be used to interrupt, regulate, or alter the flow of the fluids flowing within the conduit 18.
- the wellhead 30 can include a blowout preventer 34, a stripper 36, and/or an injector 32.
- the injector 32 can inject the conduit 18 into the wellbore 14.
- the conduit 18 can be stored in a reel 12 and when dispatched, may extend from the reel 12, pass through the injector 32, and into the wellbore 14.
- the injector 32 can pull the conduit 18 to retrieve the conduit 18 from the wellbore 14.
- the stripper 36 can provide a pressure seal around the conduit 18 as the conduit 18 is being run into and/or pulled out of the wellbore 14.
- the blowout preventer 34 can seal, control, and/or monitor the wellbore 14 to prevent blowouts, or uncontrolled and/or undesired release of fluids from the wellbore 14.
- different systems may be utilized based on the type of conduit 18 and/or the environment, such as those involving subsea or surface operations.
- FIG. 1 generally depicts a land-based operation
- those skilled in the art would readily recognize that the principles described herein are equally applicable to operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.
- FIG. 1 depicts a vertical wellbore
- the present disclosure is equally well- suited for use in wellbores having other orientations, including horizontal wellbores, slanted wellbores, multilateral wellbores or the like.
- the bi-directional acoustic telemetry system 100 includes a first acoustic telemetry component 150 and a second acoustic telemetry component 160.
- the first acoustic telemetry component 150 is operable to transmit a first acoustic signal 151 from a downhole tool 50 disposed in a wellbore 14 to a surface.
- the first acoustic telemetry component 150 includes a downhole acoustic transmitter 152 disposed in the wellbore 14 and operable to transmit the first acoustic signal 151 by creating waves to propagate in the wellbore 14, and an uphole acoustic receiver 154 positioned uphole from the downhole acoustic transmitter 152 and operable to detect the waves transmitted by the downhole acoustic transmitter 152.
- the second acoustic telemetry component 160 is operable to transmit a second acoustic signal 161 from the surface to the downhole tool 50 disposed in the wellbore 14.
- 160 includes an uphole acoustic transmitter 162 operable to transmit the second acoustic signal
- a downhole acoustic receiver 164 positioned downhole from the uphole acoustic transmitter 162 and operable to detect the waves transmitted by the uphole acoustic transmitter 162.
- the second acoustic telemetry component 160 is separate from the first acoustic telemetry component 150.
- the downhole acoustic transmitter 152 may be a different type of transmitter than the uphole acoustic transmitter 162.
- the uphole acoustic receiver 154 may be different than the downhole acoustic receiver 164.
- the first acoustic telemetry component 150 can send the signal separate and independently through a different method of acoustic telemetry than the second acoustic telemetry component 160.
- the first acoustic telemetry component 150 may be utilized to transmit acoustic signals representing data from a sensor of the downhole tool 50, to the surface.
- the data from the sensor of the downhole tool 50 may include wellbore temperature, wellbore pressure, collar location, gamma ray, inclination, vibration, tool face, azimuth, tension, compression, torque, fluid rate, fluid resistivity, magnetic field strength and direction, gravitational field strength and direction, acoustic readings, casing composition, wellbore composition, wellbore diameter, particle concentration, gas concentration, still images, video, fluid composition, and/or fluid density.
- the data may also include status of the downhole tool, such as board temperature, current consumption, battery status, voltage or current levels, warnings and/or failure indicators.
- the second acoustic telemetry component 160 may be utilized to transmit acoustic signals representing data, such as instructions for the downhole tool 50, from the surface to the downhole tool 50.
- the downhole acoustic transmitter 152 of the first acoustic telemetry component 150 may convey the first acoustic signal 151 to the uphole acoustic receiver 154 by inducing vibrations such that compressional, torsional, rotational and/or flexural waves are propagated through the conduit 18 disposed within the wellbore 14; or by interrupting a flow of fluid within an annulus of the wellbore 14 to generate a pressure pulse at a predetermined frequency such that waves corresponding to the predetermined frequency propagate through the fluid to the uphole acoustic receiver 154.
- the waves may propagate through the conduit 18, along an annulus of the wellbore 14, along the annulus of the wellbore 14 through a fluid, annulus of the conduit 18 disposed within the wellbore 14, or along the annulus of the conduit 18 through a fluid.
- the vibrations may be induced by impacting the conduit or by opening or closing a valve or by altering rotation of a turbine to affect fluid flow to generate a pressure pulse.
- the waves generated by the downhole acoustic transmitter 152 may include components such as, for example, longitudinal components, flexural components, axial components, torsional components, frequencies, phases, amplitudes, velocities, accelerations, angular velocities, angular accelerations, angular displacement, and/or displacement.
- Other waveforms may also be utilized, such as Ricker pulses (or other form of wavelet), Gaussian pulses, square wave pulses, and/or sinusoidal pulses.
- the downhole acoustic transmitter 152 may be disposed within the wellbore 14, on the downhole tool 50, and electrically coupled to a sensor of the downhole tool 50 to receive electrical signals from the coupled sensor. In at least one example, the downhole acoustic transmitter 152 may be communicatively coupled with the downhole tool 50. In some examples, the downhole acoustic transmitter 152 may be part of the downhole tool 50, such that the downhole tool 50 can be shipped and disposed within the wellbore 14 along with the downhole acoustic transmitter 152.
- the downhole acoustic transmitter 152 may be coupled with the conduit 18 such that the acoustic transmitter 152 can induce the conduit 18 to vibrate, compress, rotate, bend, flex, and/or expand such that waves are propagated through the conduit 18 to the uphole acoustic receiver 154.
- the downhole acoustic transmitter 152 may include at least one of: a piezoelectric transducer, a siren, a mud pulse, an Electro-Magnetic Acoustic Transducer (“EMAT”), a pinger, a voice coil, and/or a phased acoustic array.
- EMAT Electro-Magnetic Acoustic Transducer
- the uphole acoustic receiver 154 is configured to detect compressional, torsional, rotational, and/or flexural waves propagating through the conduit 18 created by the downhole acoustic transmitter 152.
- the uphole acoustic receiver 154 may be positioned between the injector 32 and the reel 12 at a side of the system 100 with a lower pressure.
- the uphole acoustic receiver 154 may be positioned to measure waves propagating through the conduit 18 through the blowout preventer 34, and/or the stripper 36 at the side of the system 100 with a higher pressure.
- the uphole acoustic receiver 154 may be positioned to measure components of waves propagating through the conduit 18 at the injector 32.
- the uphole acoustic receiver 154 may be disposed proximate to the conduit 18. In at least one example, the uphole acoustic receiver 154 may be coupled with the conduit 18 by a stand which protrudes from the conduit 18 and/or a casing. In some examples, the uphole acoustic receiver 154 may function without being in direct contact with the conduit 18. In at least one example, the uphole acoustic receiver 154 may be removably coupled with the system 100. For example, the uphole acoustic receiver 154 may be removed and/or installed independently from the rest of the system 100. Accordingly, the uphole acoustic receiver 154 may be independently delivered, installed in, and/or removed from the system 100. In other examples, the uphole acoustic receiver 154 may be installed during operation of the system 100, such as while undertaking coiled tubing operations.
- the uphole acoustic receiver 154 may include an optical vibro meter that may be configured to emit at least one optical beam to a single point of reference on the conduit 18 and receive one or more reflections of the at least one optical beam off of the single point of reference on the conduit 18.
- the uphole acoustic receiver 154 may include a time of flight-based laser system such as a light detection and ranging (“LIDAR”) system. The laser system may be utilized to extract the flexural component of the compressional wave propagating through the conduit 18.
- LIDAR light detection and ranging
- the uphole acoustic receiver 154 may include a Doppler sonar, Doppler LIDAR, Doppler vibrometer, laser Doppler velocimeters, strain gauge, pressure sensor, accelerometer, laser microphone, laser scanning vibrometer, optical amplitude system, optical phased array LIDAR, flash LIDAR, spinning LIDAR, mechanical scanning LIDAR, frequency modulated continuous-wave LIDAR, amplitude- modulated continuous wave LIDAR, proximity detectors, acoustic ranging devices, magnetic ranging devices, a Hall effect sensor, and/or other suitable systems to detect flexural and longitudinal components of an acoustic signal.
- the uphole acoustic receiver 154 is configured to detect the first acoustic signal 151 generated by the downhole acoustic transmitter 152 and provide data representing the detected first acoustic signal 151 to a first controller 156, which is discussed in further detail with reference to FIG. 2.
- the first controller 156 is configured to receive the data from the uphole acoustic receiver 154 and determine the components of the compressional, torsional, rotational, and/or flexural waves propagating through the conduit 18 and created by the downhole acoustic transmitter 152.
- the first controller 156 is thus configured to determine the first acoustic signal 151 transmitted by the downhole acoustic transmitter 152 based on the components of the waves propagating through the conduit 18.
- the first controller 156 determines the compressional, torsional, rotational, and/or flexural waves of the first acoustic signal 151 by processing data (for example, filtering, error correction, cross correlations, time-reversal pre-equalization, equalization, Golay encoding, etc.) received from the uphole acoustic receiver 154.
- processing data for example, filtering, error correction, cross correlations, time-reversal pre-equalization, equalization, Golay encoding, etc.
- the first controller 156 may, for example, use or integrate displacement data, velocity data, and/or acceleration data received from the uphole acoustic receiver 154 to determine the components of the waves, which may, for example, comprise longitudinal components, torsional components, frequencies, phases, amplitudes, velocities, accelerations, angular velocities, angular accelerations, angular displacement, and/or displacement. Based on the components of the waves, the first controller 156 reconstructs the first acoustic signal 151 and demodulates the first acoustic signal 151 to determine the data being conveyed by the downhole acoustic transmitter 152.
- the downhole acoustic transmitter 152 can generate compressional acoustic waves at two distinct frequencies fl and f2 to represent the binary 1 and 0.
- the first acoustic signal 151 can be coded using sequences of these two frequencies.
- the uphole acoustic receiver 154 is configured to detect the two frequencies as time sequences and the first controller 156 demodulates the components of the wave to determine the original transmitted binary sequence.
- modulation schemes include time-delay schemes, time domain modulation (TDM), On-Off keying, higher order modulations (such as QAM), orthogonal frequency division multiplexing (OFDM), spread spectrum, time domain modulation, and/or amplitude shift keying.
- TDM time domain modulation
- On-Off keying higher order modulations
- OFDM orthogonal frequency division multiplexing
- spread spectrum time domain modulation
- time domain modulation and/or amplitude shift keying.
- the data conveyed by the downhole acoustic transmitter 152 may include wellbore data such as temperature, pressure, casing collar locations, radiation levels, tool weights, magnetic field strength and direction, gravitational field strength and direction, acoustic readings, casing composition, wellbore composition, wellbore diameter, particle concentration, gas concentration, still images, video, fluid composition, and/or fluid density taken from sensors of the downhole tool 50.
- the data may also include status of the downhole tool, such as board temperature, current consumption, battery status, voltage or current levels, warnings and/or failure indicators.
- the uphole acoustic transmitter 162 of the second acoustic telemetry component 160 may convey the second acoustic signal 161 to the downhole acoustic receiver 164 by inducing vibrations such that compressional, torsional, rotational, and/or flexural waves are propagated through the conduit 18; or by interrupting a flow of fluid within an annulus of the wellbore 14 to generate a pressure pulse at a predetermined frequency such that waves corresponding to the predetermined frequency propagate through the fluid to the downhole acoustic receiver 164.
- the vibrations may be induced by impacting the conduit or by opening or closing a valve or by altering rotation of a turbine to affect fluid flow to generate the pressure pulse.
- the waves may propagate through the conduit 18, along an annulus of the wellbore 14, along the annulus of the wellbore 14 through a fluid, annulus of the conduit 18 disposed within the wellbore 14, or along the annulus of the conduit 18 through a fluid.
- the waves generated by the downhole acoustic transmitter 152 may include components such as, for example, longitudinal components, flexural components, axial components, torsional components, frequencies, phases, amplitudes, velocities, accelerations, angular velocities, angular accelerations, angular displacement, and/or displacement.
- Other waveforms may also be utilized, such as Ricker pulses (or other form of wavelet), Gaussian pulses, square wave pulses, and/or sinusoidal pulses.
- the uphole acoustic transmitter 162 may be disposed uphole from the downhole tool 50 and the downhole acoustic receiver 164. As illustrated in FIG. 1, the uphole acoustic transmitter 162 may be disposed within the wellbore 14 below the wellhead 30 and/or after the injector 32. It is understood, however, that the uphole acoustic transmitter 162 may be disposed between the wellhead 30 and the reel 12 or in any other suitable location as would be understood by one of ordinary skill.
- the uphole acoustic transmitter 162 may include at least one of a piezoelectric transducer, a siren, a mud pulse, an Electro-Magnetic Acoustic Transducer (“EMAT”), a pinger, a voice coil, and/or a phased acoustic array.
- the uphole acoustic transmitter 162 is configured to receive electrical signals representing instructions and convert the electrical signals into the second acoustic signal 161.
- the downhole acoustic receiver 164 is configured to detect compressional, torsional, rotational, and/or flexural waves propagating through the conduit 18 created by the uphole acoustic transmitter 162. In some examples, the downhole acoustic receiver 164 is configured to detect the pressure pulse created by the uphole acoustic transmitter 162. The downhole acoustic receiver 164 may be disposed in the wellbore 14, on the downhole tool 50, and communicatively coupled with a downhole tool 50. The downhole acoustic receiver 164 is configured to detect the second acoustic signal 161.
- the downhole acoustic receiver 164 may include at least one of an optical vibrometer, LIDAR, Doppler sonar, Doppler LIDAR, Doppler vibrometer, laser Doppler velocimeters, strain gauge, pressure sensor, accelerometer, laser microphone, laser scanning vibrometer, optical amplitude system, optical phased array LIDAR, flash LIDAR, spinning LIDAR, mechanical scanning LIDAR, frequency modulated continuous- wave LIDAR, amplitude-modulated continuous wave LIDAR, acoustic ranging system, magnetic ranging system, a piezoelectric sensor, a Hall effect sensor, and/or other suitable systems to detect flexural and longitudinal components of an acoustic signal or to detect a pressure pulse of a fluid.
- an optical vibrometer LIDAR, Doppler sonar, Doppler LIDAR, Doppler vibrometer, laser Doppler velocimeters, strain gauge, pressure sensor, accelerometer, laser microphone, laser scanning vibrometer, optical amplitude system, optical phased array
- the downhole acoustic receiver 164 is configured to detect the second acoustic signal 161 generated by the uphole acoustic transmitter 162 and provide data representing the detected second acoustic signal 161 to a second controller 166, which is discussed in further detail with reference to FIG. 2.
- the second controller 166 is configured to receive the data from the downhole acoustic receiver 164 and determine components of the compressional, torsional, rotational, and/or flexural waves propagating through the conduit or fluid and created by the uphole acoustic transmitter 162.
- the second controller 166 is thus configured to determine the second acoustic signal 1561 transmitted by the uphole acoustic transmitter 162 based on the components of the waves propagating through the conduit or the fluid.
- the second controller 166 determines the compressional, torsional, rotational, and/or flexural waves of the second acoustic signal 161 by processing data (for example, filtering, error correction, cross correlations, time-reversal pre-equalization, equalization, Golay encoding, etc.) received from the downhole acoustic receiver 164.
- processing data for example, filtering, error correction, cross correlations, time-reversal pre-equalization, equalization, Golay encoding, etc.
- the second controller 166 may, for example, use or integrate displacement data, velocity data, and/or acceleration data received from the downhole acoustic receiver 164 to determine the components of the waves, which may, for example, include longitudinal components, torsional components, frequencies, phases, amplitudes, velocities, accelerations, angular velocities, angular accelerations, angular displacement, and/or displacement. Based on the components of the waves, the second controller 166 reconstructs the second acoustic signal 161 and demodulates the second acoustic signal 161 to determine the instructions being conveyed by the uphole acoustic transmitter 162.
- Modulation schemes utilized by the second controller 166 may include time-delay schemes, time domain modulation (TDM), On-Off keying, higher order modulations (such as QAM), orthogonal frequency division multiplexing (OFDM), spread spectrum, time domain modulation, frequency shift keying (FSK), and/or amplitude shift keying.
- TDM time domain modulation
- On-Off keying higher order modulations
- OFDM orthogonal frequency division multiplexing
- FSK frequency shift keying
- the instructions conveyed by the uphole acoustic transmitter 162 and provided to the downhole tool 50 may be used to conduct an operation. For example, if the downhole tool 50 includes a valve, the instructions may include opening or closing the valve.
- the first acoustic telemetry component 150 and the second acoustic telemetry component 160 are separate and utilize different acoustic telemetry methods.
- the first acoustic telemetry component 150 may be operable to induce vibrations on the conduit 18 by impacting the conduit 18 to transmit the first acoustic signal 151.
- the first acoustic signal 151 may represent data gathered from a sensor of the downhole tool 50.
- the second acoustic telemetry component 160 may be operable to interrupt a flow of fluid to generate a pressure pulse (e.g., second acoustic signal 161) at a predetermined frequency such that waves corresponding to the predetermined frequency propagate through the fluid to the downhole acoustic receiver 164.
- the second acoustic signal 161 may represent commands or instructions for controlling an operation of the downhole tool 50.
- the downhole acoustic transmitter 152 and the uphole acoustic transmitter 162 may include different transmitter components
- the uphole acoustic receiver 154 and the downhole acoustic receiver 164 may include different receiver components.
- the first acoustic telemetry component 150 may utilize an EMAT as the downhole acoustic transmitter 152 to generate the first acoustic signal 151 through the conduit 18 and an optical vibro meter as the uphole acoustic receiver 154.
- the second acoustic telemetry component 160 may utilize a siren as the uphole acoustic transmitter 162 to generate the second acoustic signal 161 comprising a pressure pulse within fluid flowing in an annulus of the wellbore 14, and a pressure sensor as the downhole acoustic receiver 164.
- a data rate for each component may be different. For example, a data rate for the first acoustic signal 151 may be higher compared to a data rate of the second acoustic signal 161.
- FIG. 2 is a schematic diagram of a controller 156, 166 of a bi-directional acoustic telemetry system, in accordance with various aspects of the subject technology.
- the controller 156, 166 is configured to perform processing of data and communicate with the acoustic receiver 1154, 164, for example as illustrated in FIG. 1.
- controller 156, 166 communicates with one or more of the above-discussed components, for example the uphole acoustic receiver 154 and downhole acoustic receiver 164, respectively, and may also be configured to communicate with remote devices/systems.
- controller 156, 166 includes hardware and software components such as network interfaces 210, at least one processor 220, sensors 260 and a memory 240 interconnected by a system bus 250.
- Network interface(s) 210 can include mechanical, electrical, and signaling circuitry for communicating data over communication links, which may include wired or wireless communication links.
- Network interfaces 210 are configured to transmit and/or receive data using a variety of different communication protocols, as will be understood by those skilled in the art.
- Processor 220 represents a digital signal processor (e.g., a microprocessor, a microcontroller, or a fixed-logic processor, etc.) configured to execute instructions or logic to perform tasks in a wellbore environment.
- Processor 220 may include a general purpose processor, special-purpose processor (where software instructions are incorporated into the processor), a state machine, application specific integrated circuit (ASIC), a programmable gate array (PGA) including a field PGA, an individual component, a distributed group of processors, and the like.
- Processor 220 typically operates in conjunction with shared or dedicated hardware, including but not limited to, hardware capable of executing software and hardware.
- processor 220 may include elements or logic adapted to execute software programs and manipulate data structures 245, which may reside in memory 240.
- Sensors 260 typically operate in conjunction with processor 220 to perform measurements, and can include special-purpose processors, detectors, transmitters, receivers, and the like.
- sensors 260 may include hardware/software for generating, transmitting, receiving, detection, logging, and/or sampling magnetic fields, electric fields, seismic activity, and/or acoustic waves, temperature, pressure, fluid types and concentrations, particle concentrations, or other parameters.
- sensors 260 may include the uphole acoustic receiver 154 and downhole acoustic receiver 164, as disclosed herein.
- Memory 240 comprises a plurality of storage locations that are addressable by processor 220 for storing software programs and data structures 245 associated with the embodiments described herein.
- An operating system 242 portions of which may be typically resident in memory 240 and executed by processor 220, functionally organizes the device by, inter alia, invoking operations in support of software processes and/or services 244 executing on controller 200. These software processes and/or services 244 may perform processing of data and communication with controller 200, as described herein. Note that while process/service 244 is shown in centralized memory 240, some examples provide for these processes/services to be operated in a distributed computing network.
- processors and memory types including various computer-readable media, may be used to store and execute program instructions pertaining to the fluidic channel evaluation techniques described herein.
- various processes may be embodied as modules having portions of the process/service 244 encoded thereon.
- the program modules may be encoded in one or more tangible computer readable storage media for execution, such as with fixed logic or programmable logic (e.g., software/computer instructions executed by a processor, and any processor may be a programmable processor, programmable digital logic such as field programmable gate arrays or an ASIC that comprises fixed digital logic.
- any process logic may be embodied in processor 220 or computer readable medium encoded with instructions for execution by processor 220 that, when executed by the processor, are operable to cause the processor to perform the functions described herein.
- FIG. 3A is a diagram illustrating an exemplary acoustic receiver 154, 164, in accordance with various aspects of the subject technology.
- the waves propagating through the conduit 18 as illustrated in FIG. 3 A are illustrative and may not be indicative of the relative amount of flexural expansion.
- the acoustic receiver 154, 164 is positioned and supported such that an optical beam 173 is focused on the conduit 18.
- the acoustic receiver 154, 164 can include an optical emitter 171 and an optical receiver 172.
- the optical emitter 171 is operable to emit an optical beam 173 to a single point of reference 175 on the conduit 18.
- the optical beam 173 can have a wavelength between about 100 nm and about 10,000 nm.
- the optical beam 173 reflects off of and/or interferes at the single point of reference 175 of the conduit 18, and the reflections 174 can scatter and/or reflect back to the optical receiver 172.
- the optical receiver 172 is operable to receive one or more of the reflections 174 of the optical beam 173 off of the single point of reference on the conduit 18. While FIG. 3A illustrates that the optical emitter 171 and the optical receiver 172 are separate components, in at least one example, the optical emitter 171 and the optical receiver 172 can be one component. In some examples, the optical emitter 171 and the optical receiver 172 may be independent and separate components and are not housed in the same device.
- the optical receiver 172 can either be positioned near the optical emitter 171, or at any angle to receive the reflections 174.
- the optical emitter 171 and optical receiver 172 can be time gated and share a time reference to permit distance resolution with LIDAR techniques.
- at least two optical receivers 172 can be included to extract out two or more waves, for example both torsional and compressional waves simultaneously.
- a single optical receiver 172 can be rotated to extract compressional waves and then separately, the optical receiver 172 can be rotated to extract torsional waves.
- two optical receivers 172 can be positioned to generate an interference pattern on the conduit 18 imaged by an optical receiver 172.
- the optical beam 173 reflects off of the conduit 18 directly.
- the conduit 18 may include a reflector to enhance and/or deflect the reflection of the optical beam 173.
- two acoustic receivers 154, 164 can be utilized and/or the optical emitter 171 and the optical receiver 172 can be positioned separate from one another, the transmitted optical beam 173 and the reflections 174 can be separated.
- the conveyed signal from the acoustic transmitters 152, 162 can be determined in such an example by cross correlation.
- the conduit 18 may include a retroreflector such that the reflections 174 are directed back in the same path as the optical beam 173.
- FIG. 3B is a diagram illustrating another example of an acoustic receiver 154, 164 with multiple optical vibrometers 155, 355, in accordance with various aspects of the subject technology.
- one optical vibrometer 155 emits an optical beam 173 and receives reflections 174 on a single point of reference 175 on the conduit 18.
- Another optical vibrometer 355 also emits an optical beam 373 and receives reflections 374 on the single point of reference 175 on the conduit 18.
- optical vibrometer 155 may detect longitudinal components of the waves while optical vibrometer 355 may be rotated 90 degrees to detect torsional components of the waves.
- the controller 156, 166 can receive the detected components of the waves and more accurately determine the signal conveyed by the downhole acoustic transmitter 152 and uphole acoustic transmitter 162, respectively.
- the acoustic receiver 154, 164 may include an optical vibrometer 155 that is configured to emit a first and second optical beam such that the first and second optical beams interfere at the single point of reference 175 on the conduit 18.
- the controller 156, 166 may be configured to measure a spacing of the interference pattern to determine a velocity of the conduit 18 or to measure an optical frequency of the reflections on the single point of reference 175 to determine the velocity of the conduit.
- the one optical vibrometer 155 and another optical vibrometer 355 can be positioned on opposite sides of the conduit 18, for example 180 degrees from one another. In other examples, more than two optical vibrometers 155, 355 may be included. In at least one example, the optical vibrometers 155, 355 can be spaced equally apart from one another about the circumference of the conduit 18. In some examples, the optical vibrometers 155, 355 can be spaced at any desired and predetermined distance from one another. However, the optical vibrometers 155, 355 can all independently detect the compressional waves and do not need a second point of reference. Additionally, the single point of reference 175 can refer to a single longitudinal point of reference 175 on the conduit 18. For example, a single longitudinal point along the circumference of the conduit 18 can be the single point of reference 175.
- a first acoustic signal is transmitted by a first acoustic telemetry component from a downhole tool disposed in a wellbore to a surface.
- a second acoustic signal is transmitted by a second acoustic telemetry component separate from the first acoustic telemetry component from the surface to the downhole tool.
- the first acoustic telemetry component includes a downhole acoustic transmitter disposed in the wellbore and operable to transmit the first acoustic signal by creating waves to propagate in the wellbore.
- the first acoustic telemetry component further includes an uphole acoustic receiver positioned uphole from the downhole acoustic transmitter and operable to detect the waves transmitted by the downhole acoustic transmitter.
- the second acoustic telemetry component includes an uphole acoustic transmitter operable to transmit the second acoustic signal by creating waves to propagate in the wellbore.
- the second acoustic telemetry component further includes a downhole acoustic receiver positioned downhole from the uphole acoustic transmitter and operable to detect the waves transmitted by the uphole acoustic transmitter.
- the first acoustic telemetry component and the second acoustic telemetry component are separate and different systems.
- the downhole acoustic transmitter and the uphole acoustic transmitter may include different transmitter components
- the uphole acoustic receiver and the downhole acoustic receiver may include different receiver components.
- a data rate for each component may be different. For example, a data rate for the first acoustic signal may be higher compared to a data rate of the second acoustic signal.
- the acoustic transmitter of the first acoustic telemetry component and/or the second acoustic telemetry component may transmit compressional waves, torsional, rotational, and/or flexural waves to convey data to the corresponding acoustic receiver.
- a controller of each system is configured to measure components of the compressional waves which may include velocities, distances, and/or accelerations, flexural components of the flexural waves which may include bending angle, outer and inner diameters, and associated dynamics of bending and radial expansion and/or contraction, and torsional components of the torsional waves which may include angular velocities, angular distances, and/or angular accelerations of the torsional waves.
- the controller is also configured to demodulate the waves to determine data conveyed from the acoustic transmitter.
- the data can include measurements from sensors downhole or instructions for a downhole tool. Based on the data, adjustments to the system can be made.
- the data can include wellbore data such as temperature, pressure, casing collar locations, radiation levels, tool weights, magnetic field strength and direction, gravitational field strength and direction, acoustic readings, casing composition, wellbore composition, wellbore diameter, particle concentration, gas concentration, still images, video, fluid composition, and/or fluid density taken from sensors of the downhole tool.
- the data may also include status of the downhole tool, such as board temperature, current consumption, battery status, voltage or current levels, warnings and/or failure indicators.
- the data can be received by the acoustic receiver, and input into logs and/or simulations. Based on such data, adjustments may be made such as closing sections of the well, stimulation of the formation, or any other suitable actions. Additionally, if the data is being transmitted to an acoustic receiver disposed downhole and in communication with a downhole tool, the downhole tool may be adjusted, for example opening or closing valves, or for example enabling and disabling sensors.
- the bi-directional acoustic telemetry system described above may be used in a fracturing or stimulation operation where the fluid is pumped either through the annulus of the conduit (e.g., coiled tubing or jointed pipe), directly through the string, or a combination of both.
- the bi-directional acoustic telemetry system described above may be used in a stimulation operation that involves pumping more than one fluid trough the string into the reservoir formation.
- the fluids used in the operation can be acid, solvents or a combination of both.
- the bi-directional acoustic telemetry system described above may be used in a wellbore operation that involves pumping a fluid either through the annulus of conduit (e.g., coiled tubing), directly through the string or a combination of both to prevent flow of water or unwanted gas from a reservoir formation.
- the bi-directional acoustic telemetry system described above may be used in a wellbore operation that requires the use of isolation tools like mechanical packers, single and straddle inflatable packers.
- the bi-directional acoustic telemetry system described above may be used to perform a stimulation operation involving water control or gas control treatment through an inflatable packer.
- the bi-directional acoustic telemetry system described above may be used in a wellbore operation that involves the use of an indexing tool to enter a lateral branch of a multilateral well; performing a stimulation operation, after entering the lateral with the above indexing tool; and obtaining wellbore measurements during the above treatments and using the data to adjust the treatments volumes, rates, fluids concentration, fluid type and properties in real-time.
- the bi-directional acoustic telemetry system described above may be used in a wellbore operation involving the use of perforating guns, as well as a wellbore operation requiring performance of a well test.
- a telemetry system comprising: a first acoustic telemetry component operable to transmit a first acoustic signal from a downhole tool disposed in a wellbore to a surface, the first acoustic telemetry component including a downhole acoustic transmitter disposed in the wellbore and operable to transmit the first acoustic signal by creating waves to propagate in the wellbore, and an uphole acoustic receiver positioned uphole from the downhole acoustic transmitter and operable to detect the waves transmitted by the downhole acoustic transmitter; and a second acoustic telemetry component separate from the first acoustic telemetry component operable to transmit a second acoustic signal from the surface to the downhole tool disposed in the wellbore, the second acoustic telemetry component including an uphole acoustic transmitter operable to transmit the second acoustic signal by creating waves to propagate in the well
- Statement 2 A telemetry system is disclosed according to Statement 1, further comprising a controller coupled with the uphole acoustic receiver, the controller determining components of the waves created by the downhole acoustic transmitter and determining the acoustic signal transmitted from the downhole acoustic transmitter based on the components of the waves.
- Statement 3 A telemetry system is disclosed according to Statements 1 or 2, wherein the downhole acoustic transmitter and/or the uphole acoustic transmitter is coupled with a conduit disposed in the wellbore through a wellhead, and the downhole acoustic transmitter and/or the uphole acoustic transmitter creates the waves by impacting the conduit.
- Statement 4 A telemetry system is disclosed according to any of preceding Statements 1-3, wherein the downhole acoustic transmitter and the uphole acoustic transmitter each include at least one of the following transmitter components: a piezoelectric transducer, a voice coil, a pinger, a siren, a mud pulse, and/or an electromagnetic acoustic transducer (EMAT).
- EMAT electromagnetic acoustic transducer
- a telemetry system is disclosed according to any of preceding Statements 1-4, wherein the uphole acoustic receiver and the downhole acoustic receiver each include at least one of the following receiver components: an optical vibrometer, a light detection and ranging (LIDAR) system, an optical amplitude system, a microphone, a pressure sensor, an electromagnetic acoustic transducer (EMAT), proximity detector, acoustic ranging device, magnetic ranging device, a Hall effect sensor, and/or an accelerometer.
- LIDAR light detection and ranging
- EMAT electromagnetic acoustic transducer
- proximity detector acoustic ranging device
- magnetic ranging device magnetic ranging device
- Hall effect sensor a Hall effect sensor
- Statement 7 A telemetry system is disclosed according to any of preceding Statements 1-6 wherein the uphole acoustic receiver and the downhole acoustic receiver include different receiver components.
- Statement 8 A telemetry system is disclosed according to any of preceding Statements 1-7, wherein the downhole acoustic transmitter and the uphole acoustic transmitter convert electric signals into the first and second acoustic signals, respectively.
- Statement 9 A telemetry system is disclosed according to any of preceding Statements 1-8, wherein at least one of the downhole acoustic transmitter and the uphole acoustic transmitter transmit the corresponding first and/or second acoustic signal by creating the waves to propagate along a conduit disposed in the wellbore.
- Statement 10 A telemetry system is disclosed according to any of preceding Statements 1-9, wherein at least one of the downhole acoustic transmitter and the uphole acoustic transmitter transmit the corresponding first and/or second acoustic signal by creating the waves to propagate along an annulus of the wellbore.
- Statement 11 A telemetry system is disclosed according to any of preceding Statements 1-10, wherein the waves propagate along the annulus of the wellbore through a fluid.
- Statement 12 A telemetry system is disclosed according to any of preceding Statements 1-11, wherein at least one of the downhole acoustic transmitter and the uphole acoustic transmitter transmit the corresponding first and/or second acoustic signal by creating the waves to propagate along an annulus of a conduit disposed in the wellbore.
- a telemetry system is disclosed according to any of preceding Statements 1-12, wherein the waves propagate along the annulus of the conduit through a fluid.
- a wellbore system comprising: a conduit disposed in a wellbore; a first acoustic telemetry component operable to transmit a first acoustic signal from a downhole tool disposed in a wellbore to a surface, the first acoustic telemetry component including: a downhole acoustic transmitter disposed in a wellbore and operable to transmit the first acoustic signal by creating waves to propagate in the wellbore, and an uphole acoustic receiver positioned uphole from the downhole acoustic transmitter and operable to detect the waves transmitted by the downhole acoustic transmitter; and a second acoustic telemetry component separate from the first acoustic telemetry componentoperable to transmit a second acoustic signal from
- Statement 15 A wellbore system is disclosed according to Statement 14, further comprising a controller coupled with the uphole acoustic receiver, the controller determining components of the waves created by the downhole acoustic transmitter and determining the acoustic signal transmitted from the downhole acoustic transmitter based on the components of the waves.
- Statement 16 A wellbore system is disclosed according to Statements 14 or 15, wherein the downhole acoustic transmitter and the uphole acoustic transmitter each include at least one of the following transmitter components: a piezoelectric transducer, a voice coil, a pinger, a siren, a mud pulse, a phased acoustic array, and/or an electromagnetic acoustic transducer (EMAT); wherein the downhole acoustic transmitter and the uphole acoustic transmitter include different transmitter components.
- EMAT electromagnetic acoustic transducer
- Statement 17 A wellbore system is disclosed according to any of preceding Statements 14-16, wherein the uphole acoustic receiver and the downhole acoustic receiver each include at least one of the following receiver components: an optical vibrometer, a light detection and ranging (LIDAR) system, an optical amplitude system, a microphone, a pressure sensor, an electromagnetic acoustic transducer (EMAT), proximity detector, acoustic ranging device, magnetic ranging device, a Hall effect sensor, and/or an accelerometer.
- LIDAR light detection and ranging
- EMAT electromagnetic acoustic transducer
- proximity detector acoustic ranging device
- magnetic ranging device magnetic ranging device
- Hall effect sensor a Hall effect sensor
- Statement 18 A wellbore system is disclosed according to Statement 17, wherein the uphole acoustic receiver and the downhole acoustic receiver include different receiver components.
- Statement 19 A method for transmitting and receiving different acoustic signals in a wellbore system comprising: transmitting, by a first acoustic telemetry component, a first acoustic signal from a downhole tool disposed in a wellbore to a surface; transmitting, by a second acoustic telemetry component separate from the first acoustic telemetry component, a second acoustic signal from the surface to the downhole tool.
- Statement 20 A method is disclosed according to Statement 19, further comprising utilizing the first acoustic telemetry component and the second acoustic telemetry component in a wellbore operation, the wellbore operation including at least one of: a fracturing operation; a stimulation operation; a fluid being pumped either through an annulus of a conduit, directly through a string, or a combination of both to prevent a flow of fluid from a reservoir formation; utilizing an isolation tool; a stimulation operation involving a water control or gas control treatment through an inflatable packer; utilizing an indexing tool to enter a lateral branch of a multilateral well; a stimulation operation performed after entering a lateral branch of a multilateral well with an indexing tool; obtaining measurements during a treatment and using the measurements to adjust a treatment volume, rate, fluid concentration, fluid type or property in real-time; utilizing a perforating gun; and/or performance of a well test.
- a fracturing operation including at least one of: a fracturing operation
- Statement 21 A method is disclosed according to Statements 19 or 20, wherein the downhole acoustic transmitter and the uphole acoustic transmitter include different transmitter components, and the uphole acoustic receiver and the downhole acoustic receiver include different receiver components.
Landscapes
- Physics & Mathematics (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Life Sciences & Earth Sciences (AREA)
- Acoustics & Sound (AREA)
- Remote Sensing (AREA)
- Fluid Mechanics (AREA)
- Environmental & Geological Engineering (AREA)
- Geophysics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Geophysics And Detection Of Objects (AREA)
- Radio Relay Systems (AREA)
Abstract
Priority Applications (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US17/050,801 US20230112854A1 (en) | 2019-12-04 | 2019-12-04 | Bi-directional acoustic telemetry system |
GB2206062.8A GB2604059B (en) | 2019-12-04 | 2019-12-04 | Bi-directional acoustic telemetry system |
PCT/US2019/064510 WO2021112843A1 (fr) | 2019-12-04 | 2019-12-04 | Système de télémétrie acoustique bidirectionnelle |
NO20220477A NO20220477A1 (en) | 2019-12-04 | 2022-04-26 | Bi-directional acoustic telemetry system |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
PCT/US2019/064510 WO2021112843A1 (fr) | 2019-12-04 | 2019-12-04 | Système de télémétrie acoustique bidirectionnelle |
Publications (1)
Publication Number | Publication Date |
---|---|
WO2021112843A1 true WO2021112843A1 (fr) | 2021-06-10 |
Family
ID=76222078
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/US2019/064510 WO2021112843A1 (fr) | 2019-12-04 | 2019-12-04 | Système de télémétrie acoustique bidirectionnelle |
Country Status (4)
Country | Link |
---|---|
US (1) | US20230112854A1 (fr) |
GB (1) | GB2604059B (fr) |
NO (1) | NO20220477A1 (fr) |
WO (1) | WO2021112843A1 (fr) |
Citations (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
JPH0681877B2 (ja) * | 1989-03-17 | 1994-10-19 | シュラムバーガー オーバーシーズ ソシエダ アノニマ | 減衰と遅延装置を含む音響井戸装置の送受信器配列 |
US20130038464A1 (en) * | 2010-02-04 | 2013-02-14 | Laurent Alteirac | Acoustic Telemetry System for Use in a Drilling BHA |
CN105545297A (zh) * | 2016-01-26 | 2016-05-04 | 中国石油集团长城钻探工程有限公司 | 用非旋转工具检测地层边界的设备 |
US20170168183A1 (en) * | 2015-12-15 | 2017-06-15 | Schlumberger Technology Corporation | Coherent noise estimation and reduction for acoustic downhole measurements |
US20180003845A1 (en) * | 2016-06-30 | 2018-01-04 | Schlumberger Technology Corporation | Acoustic Sensing with Azimuthally Distributed Transmitters and Receivers |
Family Cites Families (8)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US6920085B2 (en) * | 2001-02-14 | 2005-07-19 | Halliburton Energy Services, Inc. | Downlink telemetry system |
US6909667B2 (en) * | 2002-02-13 | 2005-06-21 | Halliburton Energy Services, Inc. | Dual channel downhole telemetry |
US10222507B2 (en) * | 2008-11-19 | 2019-03-05 | Halliburton Energy Services, Inc. | Data transmission systems and methods for azimuthally sensitive tools with multiple depths of investigation |
US8757254B2 (en) * | 2009-08-18 | 2014-06-24 | Schlumberger Technology Corporation | Adjustment of mud circulation when evaluating a formation |
US9249648B2 (en) * | 2013-02-06 | 2016-02-02 | Baker Hughes Incorporated | Continuous circulation and communication drilling system |
DE112013007536T5 (de) * | 2013-10-28 | 2016-07-07 | Landmark Graphics Corporation | Verhältnisbasierter Moduswechsel zur Optimierung des Meißelandrucks |
CA2946621C (fr) * | 2014-04-22 | 2023-05-02 | Cold Bore Technology Inc. | Procedes et systemes de correction d'erreur directe pour des systemes de communication de mesures en cours de forage (mwd) |
EP4065816A4 (fr) * | 2019-11-27 | 2024-04-10 | Baker Hughes Oilfield Operations Llc | Système de télémesure combinant deux procédés de télémesure |
-
2019
- 2019-12-04 WO PCT/US2019/064510 patent/WO2021112843A1/fr active Application Filing
- 2019-12-04 US US17/050,801 patent/US20230112854A1/en active Pending
- 2019-12-04 GB GB2206062.8A patent/GB2604059B/en active Active
-
2022
- 2022-04-26 NO NO20220477A patent/NO20220477A1/no unknown
Patent Citations (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
JPH0681877B2 (ja) * | 1989-03-17 | 1994-10-19 | シュラムバーガー オーバーシーズ ソシエダ アノニマ | 減衰と遅延装置を含む音響井戸装置の送受信器配列 |
US20130038464A1 (en) * | 2010-02-04 | 2013-02-14 | Laurent Alteirac | Acoustic Telemetry System for Use in a Drilling BHA |
US20170168183A1 (en) * | 2015-12-15 | 2017-06-15 | Schlumberger Technology Corporation | Coherent noise estimation and reduction for acoustic downhole measurements |
CN105545297A (zh) * | 2016-01-26 | 2016-05-04 | 中国石油集团长城钻探工程有限公司 | 用非旋转工具检测地层边界的设备 |
US20180003845A1 (en) * | 2016-06-30 | 2018-01-04 | Schlumberger Technology Corporation | Acoustic Sensing with Azimuthally Distributed Transmitters and Receivers |
Also Published As
Publication number | Publication date |
---|---|
US20230112854A1 (en) | 2023-04-13 |
GB2604059A (en) | 2022-08-24 |
GB2604059B (en) | 2024-04-03 |
GB202206062D0 (en) | 2022-06-08 |
NO20220477A1 (en) | 2022-04-26 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US10837276B2 (en) | Method and system for performing wireless ultrasonic communications along a drilling string | |
US9494033B2 (en) | Apparatus and method for kick detection using acoustic sensors | |
US5372207A (en) | Seismic prospecting method and device using a drill bit working in a well | |
CA2209947C (fr) | Systeme de diagraphie acoustique pendant le forage utilisant des emetteurs segmentes multiples et des recepteurs | |
US11299985B2 (en) | Acoustic telemetry system | |
CA2998330C (fr) | Attenuation de dommage de cable pendant une perforation | |
US20060077757A1 (en) | Apparatus and method for seismic measurement-while-drilling | |
US20120092960A1 (en) | Monitoring using distributed acoustic sensing (das) technology | |
CA3081792C (fr) | Procede et systeme pour effectuer des communications ultrasonores sans fil le long d'elements tubulaires | |
NO342472B1 (no) | Elektromagnetisk telemetrianordning og fremgangsmåte for å minimalisere syklisk eller synkron støy | |
WO2001099028A1 (fr) | Recepteur acoustique triaxial orthogonal | |
NZ229303A (en) | Geophysical prospecting from down-hole pipe string: compensating for pipe string reflections | |
WO2016141093A1 (fr) | Appareil et procédé de télémesure par transmission d'impulsions par la boue à modulation de fréquence | |
US20160130938A1 (en) | Seismic while drilling system and methods | |
US11513247B2 (en) | Data acquisition systems | |
US20230112854A1 (en) | Bi-directional acoustic telemetry system | |
GB2421614A (en) | Subterranean communication system | |
US20210372266A1 (en) | Gravel pack quality measurement | |
CN109312619B (zh) | 高速遥测信号处理 | |
WO2019108184A1 (fr) | Système de communication acoustique à travers un fluide | |
RU2658697C1 (ru) | Способ мониторинга добывающих или нагнетательных горизонтальных или наклонно-направленных скважин | |
US9470814B2 (en) | Seismic methods and systems employing flank arrays in well tubing | |
BR112020008579B1 (pt) | Sistema de comunicação para um ambiente de sistema de poço com transmissores que se comunicam por diferentes meios, e, método para comunicação de dados codificados em um ambiente de sistema de poço | |
NO318812B1 (no) | System og fremgangsmate for seismisk profilering ved bruk av vertikale sensorgrupper plassert under et vann-slam grensesjikt |
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: 19955126 Country of ref document: EP Kind code of ref document: A1 |
|
ENP | Entry into the national phase |
Ref document number: 202206062 Country of ref document: GB Kind code of ref document: A Free format text: PCT FILING DATE = 20191204 |
|
NENP | Non-entry into the national phase |
Ref country code: DE |
|
122 | Ep: pct application non-entry in european phase |
Ref document number: 19955126 Country of ref document: EP Kind code of ref document: A1 |
|
WWE | Wipo information: entry into national phase |
Ref document number: 522432501 Country of ref document: SA |