EP2890866A1 - System and method for downhole signal enhancement - Google Patents
System and method for downhole signal enhancementInfo
- Publication number
- EP2890866A1 EP2890866A1 EP13832420.7A EP13832420A EP2890866A1 EP 2890866 A1 EP2890866 A1 EP 2890866A1 EP 13832420 A EP13832420 A EP 13832420A EP 2890866 A1 EP2890866 A1 EP 2890866A1
- Authority
- EP
- European Patent Office
- Prior art keywords
- downhole
- signal
- bit
- parameters
- noise component
- Prior art date
- Legal status (The legal status 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 status listed.)
- Withdrawn
Links
- 238000000034 method Methods 0.000 title claims abstract description 37
- 230000001133 acceleration Effects 0.000 claims abstract description 44
- 238000005452 bending Methods 0.000 claims abstract description 9
- 238000004590 computer program Methods 0.000 claims description 9
- 230000015572 biosynthetic process Effects 0.000 claims description 7
- 230000003993 interaction Effects 0.000 claims description 7
- 230000003044 adaptive effect Effects 0.000 claims description 6
- 238000012986 modification Methods 0.000 claims description 4
- 230000004048 modification Effects 0.000 claims description 4
- 238000005259 measurement Methods 0.000 description 27
- 238000009530 blood pressure measurement Methods 0.000 description 17
- 238000005553 drilling Methods 0.000 description 15
- 238000001914 filtration Methods 0.000 description 9
- 239000000523 sample Substances 0.000 description 5
- 238000004891 communication Methods 0.000 description 4
- 238000012545 processing Methods 0.000 description 4
- 239000012530 fluid Substances 0.000 description 3
- 230000000116 mitigating effect Effects 0.000 description 3
- 230000005540 biological transmission Effects 0.000 description 2
- 230000006870 function Effects 0.000 description 2
- 238000000053 physical method Methods 0.000 description 2
- 230000001629 suppression Effects 0.000 description 2
- 238000013459 approach Methods 0.000 description 1
- 230000003190 augmentative effect Effects 0.000 description 1
- 230000001413 cellular effect Effects 0.000 description 1
- 230000000593 degrading effect Effects 0.000 description 1
- 230000001627 detrimental effect Effects 0.000 description 1
- 238000010348 incorporation Methods 0.000 description 1
- 230000006698 induction Effects 0.000 description 1
- 238000002955 isolation Methods 0.000 description 1
- 239000013074 reference sample Substances 0.000 description 1
- 239000003381 stabilizer Substances 0.000 description 1
- 238000010998 test method Methods 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/01—Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
Definitions
- Embodiments described herein generally relate to a system and method for communicating in a wellbore. More particularly, embodiments described herein relate to a system and method for reducing or mitigating downhole noise that interferes with mud pulse communications between a downhole location and a surface location.
- Drilling fluid telemetry systems such as mud pulse telemetry systems, are used to communicate information from a downhole location to a surface location or vice versa.
- the information may include pressure, temperature, direction, and deviation of the wellbore.
- Other information may include logging data such as resistivity of the formation, sonic density, porosity, induction, self-potential, and pressure gradients.
- Noise generated downhole may interfere with the mud pulses, degrading the quality of the signals in the mud pulses and making it difficult to recover the transmitted information.
- One or more downhole internal pressure measurements may be used to estimate the downhole noise component. Once estimated, the downhole noise component may be mitigated, thereby making it easier to recover the transmitted information in the mud pulses. It is difficult to distinguish downhole noise from surface noise using internal pressure measurements, and this may hinder the mitigation of the downhole noise.
- a system for downhole signal enhancement includes a downhole tool having sensors coupled thereto.
- the sensors may measure internal pressure and parameters selected from the group consisting of external pressure, pressure sensor temperature, weight on bit, torque on bit, bending moment, roll gyro, tangential acceleration, radial acceleration, and axial acceleration.
- a noise estimator may be coupled to the downhole tool and estimate a downhole noise component in the parameters.
- a telemetry modulator may be coupled to the downhole tool and generate a signal that includes the estimated downhole noise component and a telemetry component. The downhole noise component in the signal may be reduced based at least partially upon the estimate.
- a method for downhole signal enhancement may include measuring parameters with sensors coupled to a downhole tool.
- the parameters are selected from the group consisting of external pressure, pressure sensor temperature, weight on bit, torque on bit, bending moment, roll gyro, tangential acceleration, radial acceleration, and axial acceleration.
- a downhole noise component in the parameters may be estimated.
- a signal may be generated that includes the estimated downhole noise component and a telemetry component. The downhole noise component in the signal may be reduced based at least partially upon the estimate.
- a computer program is also disclosed.
- the computer program may be embodied on a non-transitory computer readable medium that, when executed by a processor, controls a method for downhole signal enhancement.
- the method may include measuring parameters with sensors coupled to a downhole tool.
- the parameters are selected from the group consisting of external pressure, pressure sensor temperature, weight on bit, torque on bit, bending moment, roll gyro, tangential acceleration, radial acceleration, and axial acceleration.
- a downhole noise component in the parameters may be estimated.
- a signal may be generated that includes the estimated downhole noise component and a telemetry component.
- the downhole noise component in the signal may be reduced based at least partially upon the estimate.
- Figure 1 is a schematic illustration of a downhole noise cancellation system, according to an embodiment of the disclosure.
- Figure 2 is a schematic illustration of hardware that may be used with the downhole noise cancellation system, according to an embodiment of the disclosure.
- Figure 3 is a schematic illustration of an internal pressure downhole noise estimation filter, according to an embodiment of the disclosure.
- Figure 4 is an illustrative computer system disposed within a downhole tool, according to an embodiment of the disclosure.
- Figure 5 is an illustrative spectrogram of an internal pressure signal during drilling, according to an embodiment of the disclosure.
- Figure 6 is an illustrative spectrogram of an axial acceleration signal during drilling, according to an embodiment of the disclosure.
- Figure 7 is an illustrative spectrogram of a residual signal in the internal pressure after noise cancellation using the axial acceleration signal, according to an embodiment of the disclosure.
- Figure 8 is an illustrative spectrogram of an internal pressure signal during a stick-slip event, according to an embodiment of the disclosure.
- Figure 9 is an illustrative spectrogram of an axial acceleration signal during the stick- slip event, according to an embodiment of the disclosure.
- Figure 10 is an illustrative spectrogram of a residual signal in the internal pressure after noise cancellation using the axial acceleration signal, according to an embodiment of the disclosure.
- the present disclosure generally involves a system and methodology that relate to the reach and performance of mud pulse telemetry systems that use internal pressure pulses to convey signals through a wellbore.
- Mud pulse telemetry systems may be negatively impacted (i.e., interfered with) by noise generated by downhole sources during downhole operations, such as drilling operations.
- an active downhole noise cancellation system may be employed as described herein.
- an estimate of the downhole noise components contained in the internal pressure may be measured with one or more downhole sensors.
- internal pressure refers to the pressure of the fluid within a downhole tool (which includes a drill pipe and/or drill string), and “external pressure” refers to the pressure of the fluid in the annulus between the downhole tool and the casing or wellbore wall.
- the downhole internal pressure measurements may contain a superposition of the mud pulse telemetry signals, noise generated at the surface (e.g., mud pump noise), and noise generated downhole (e.g., mud motors, rotary-steerable systems, drill pipe rotation, and the interaction of the drill string and the drill bit with the formation).
- a noise estimator may be used to distinguish between at least a subset of these three components.
- the noise estimator may be formed by using a filtered version of other downhole physical measurements taken by sensors which may be designed to measure a variety of physical quantities or parameters.
- the sensors may be designed to measure internal pressure (“IP”), external pressure (“EP”), pressure sensor temperature, weight on bit (“WOB”), torque on bit (“TOB”), bending moment, roll gyro, tangential acceleration, radial acceleration, axial acceleration (“AA”), and/or a variety of other physical quantities.
- IP internal pressure
- EP external pressure
- WOB weight on bit
- TOB torque on bit
- bending moment bending moment
- roll gyro tangential acceleration
- radial acceleration radial acceleration
- axial acceleration axial acceleration
- AA tangential acceleration
- any of these measurements contain a subset of the three components (i.e., mud pulse telemetry signals, surface noise, and downhole noise)
- filtering may be employed so the respective components in the internal pressure may be estimated and subtracted from the original measurements to enable the three components in the internal pressure measurements to be distinguished.
- the axial acceleration measurements include surface noise but not mud pulse telemetry signals or downhole noise
- the surface noise component may be identified within the internal pressure measurements and subsequently removed.
- the downhole drilling noise component of the internal pressure may be fed into an active downhole noise cancellation system.
- components of the downhole internal pressure measurements may be isolated and fed into a downhole echo cancellation system for mud pulse telemetry.
- an illustrative noise cancellation system 20 for reducing or mitigating the downhole noise via an active downhole noise cancellation technique is illustrated.
- measurements of various physical quantities may be taken via a plurality of downhole sensors 22.
- the measurements may include internal pressure (“IP”), external pressure (“EP”), pressure sensor temperature, weight on bit (“WOB”), torque on bit (“TOB”), bending moment, roll gyro, tangential acceleration, radial acceleration, axial acceleration (“AA”), and the like.
- a downhole noise estimator 24 may estimate the noise component in the internal pressure produced by downhole sources including, but not limited to, mud motors, rotary steerable systems, drill pipe rotation, and the mechanical interaction of the drill string and bit with the formation during drilling operations.
- the downhole noise estimates along with telemetry data symbols 26 may be processed via a downhole noise compensation algorithm 28.
- the algorithm 28 may be employed to form a sequence of modular positions that are used to generate a pressure signal (e.g., a wavefront) to transmit information to the surface via a modified mud pulse telemetry modulator 30 while canceling or reducing the superimposed (estimated) downhole noise component that would travel to the surface.
- the generated signal may include a weighted combination of the mud pulse telemetry signal and the downhole noise component.
- the generated signal may be modulated based upon the estimated downhole noise component. Modulation may include switching the frequency, modulation rate, and/or data rate based upon the estimated downhole noise component.
- the algorithm Given a maximum possible transmission pressure amplitude, the algorithm may be used to reduce the downhole noise component while maintaining as strong a telemetry signal component as possible.
- the system 20 may mitigate the detrimental effects of drilling noise at the mud pulse receiver located at the surface.
- the algorithm 28 may be used to transmit information from the surface to the downhole tool while canceling or reducing the superimposed (estimated) downhole noise and/or surface noise components. This may be referred to as a downlink communication.
- a downlink communication For downlink communications, changes in pressure, flow, collar rotation and/or depth may be used to encode data to cancel or reduce the superimposed downhole noise and/or surface noise components.
- the hardware may include one or more sensors 22-1, 22-2.
- the sensors 22-1, 22-2 may be coupled to an inner surface and/or an outer surface of a downhole tool 36.
- the downhole tool 36 may be or include a drill string, a drill pipe, a drill bit, a mill, an underreamer, a stabilizer, a measurement while drilling (“MWD”) tool, a logging while drilling (“LWD”) tool, combinations thereof, and the like.
- the downhole tool 36 may have a mud pulse telemetry modulator 30 and a computer system 33 disposed therein and/or coupled thereto.
- the sensors 22-1, 22-2 may be positioned above and/or below the telemetry modulator 30.
- three sensors 22-1 are positioned below the telemetry modulator 30, and three sensors 22-2 are positioned above the telemetry modulator 30.
- the number of sensors 22-1, 22-2 below and/or above the telemetry modulator 30 may be from about 1 to about 3, about 3 to about 5, about 5 to about 10, about 10 to about 20, about 20 to about 50, or more, and each of the sensors 22-1, 22-2 may measure the same quantity or parameter and/or different physical quantities or parameters.
- the modulator 30 and/or the computer system 33 may be designed to process data and may include a sensor data processor and a modulation generator located along and/or within the downhole tool 36 disposed in a wellbore 38.
- Multiple sensors 22-1, 22-2 for the same physical quantity may be placed at different locations, and the sensor measurements may be fed to the computer system 33 which, in turn, may be connected to the telemetry modulator 30.
- the sensors 22-1, 22-2 may be used to acquire measurements before and after noise cancellation processing. This allows use of a feedback loop to monitor the processing accuracy.
- the noise cancellation system 20 utilizes the downhole noise estimator 24 ( Figure 1) to estimate noise that is to be canceled or reduced from the mud pulses.
- the measurements acquired by the downhole sensors 22-1, 22-2 may contain a superposition of the mud pulse telemetry signals, surface noise, and downhole noise.
- the noise cancellation system 20 may isolate the noise due to the downhole sources from the mud pulse signals and the surface noise. This allows the noise cancellation system 20 to focus on canceling or reducing the downhole noise as opposed to the other two components. Distinguishing between the three components using internal pressure measurements may be difficult, so other measurements obtained by the sensors 22-1, 22-2 may be employed to distinguish the noise components.
- one or more of the sensors 22-1, 22-2 may be internal pressure sensors, and measurements from the internal pressure sensors may be augmented and/or replaced by using filtered versions of measurements from other sensors, such as measurements related to external pressure, weight on bit, torque on bit, axial acceleration, and/or other measurements.
- the noise cancellation system 20 is used to separate out particular components in the internal pressure which may then be canceled by an echo canceller or which may be used to otherwise assist in the echo cancellation process.
- a filtered version of other downhole physical measurements taken by the sensors 22-1, 22-2 may be used. As illustrated in Figure 3, the other downhole measurements are fed into a filter 40 of the downhole noise estimator 24.
- the telemetry data symbols or pulse-shaped samples may be input to the filter 40 as well. Due to the unique interaction each measurement mode has with the physical events and phenomena occurring downhole during drilling operations, some of the measurements may contain a subset of the three downhole measurement components (i.e., mud pulse telemetry signals, surface noise, and downhole noise). Using the filter 40 with these measurements as inputs, the respective components in the internal pressure measurements may be estimated, thus allowing a distinction to be made between the three components in the internal pressure measurements.
- the filtering process may then be repeated, replacing the internal pressure measurements in Figure 3 with the pre-processed internal pressure measurements, and then using the filtering operation with a different measurement input to remove yet another component from the internal pressure measurements.
- the largest non-downhole drilling noise component may be removed using a first filtering stage followed by the next largest unwanted component in a subsequent filtering stage.
- torque on bit measurements may contain components of the mud pulse telemetry signals and downhole noise but not surface noise.
- the filter 40 may initially be used with the torque on bit measurements as inputs to isolate the mud pulse telemetry signals and the downhole noise components in the internal pressure measurements. Applying a second round of filtering, the telemetry data symbols or pulse-shaped samples may be used as the filter input, and the output of the previous filtering may be used in place of the internal pressure measurements illustrated in Figure 3. This may enable isolation and removal of the telemetry signal component from the pre-processed internal pressure measurements, leaving the downhole drilling noise component of the original internal pressure measurements.
- This data may then be fed into the active downhole noise cancellation system 20 illustrated in Figure 1. In another example, the data may be fed into a downhole echo cancellation system.
- the filter 40 may be either analog or digital and may include an analog-to-digital converter followed by a digital processor which, in turn, may be followed by a digital-to- analog converter. In another example, the digital sample outputs of the digital processor may be fed directly into the noise cancellation system 20.
- the filter 40 may have a linear or nonlinear structure and, using a variable delay, may be employed to estimate past, present, and/or future samples of the reference internal pressure process.
- the filter 40 may be fixed for a certain time duration or it may vary with each measurement sample. Additionally, if a multi-dimensional filter 40 is used, more than one non-internal pressure measurement may be filtered at the same time to produce an estimate of the reference process.
- the difference between the filter output sample dk and the reference sample dk may be minimized.
- a suitable methodology may be to choose filter parameters w to minimize the mean squared error (MSE):
- JO) E ⁇
- E ⁇ denotes the expected value.
- a linear filter e.g., a Wiener filter or an adaptive filter
- sample estimates may be used over time durations where the processes are approximately stationary.
- adaptive filtering algorithms may be used to determine the filter parameters.
- LMS least mean square
- RLS recursive least squares
- Figure 4 is an illustrative computer system 33 disposed within the downhole tool 36, according to an embodiment of the disclosure.
- the computer system 33 may be or include any processor or microprocessor based device configured to execute a computer program or instructions embodied on a non-transitory computer readable medium. When executed by the computer system 33, the computer program may control a method for canceling or reducing noise generated by a downhole source that may interfere with mud pulse telemetry signals.
- the computer system 33 may be located at the surface or at least partially located within the downhole tool 36 (see Figure 2). When located within the downhole tool 36, the computer system 33 may be coupled to and/or integrated with the mud pulse telemetry modulator 30.
- the computer system 33 may include a central processing unit 402, an input device or keyboard 404, and/or a monitor 406.
- the computer system 33 may also include a memory 408 to store data and/or software or program information.
- the computer system 33 may also include additional input and output devices such as a mouse 410, a microphone 412, and/or a speaker 414, which may be used for universal access and voice recognition or commanding.
- the monitor 406 may be touch-sensitive to operate as an input device as well as a display device.
- the computer system 33 may interface with the mud pulse telemetry modulator 30, a database 416, a processor 418, and/or the Internet via an interface 420. It should also be understood that the database 416 and the processor 418 are not limited to interfacing with computer system 33 using the network interface 420 and may interface with the computer system 33 in any manner sufficient to create a communications path between the computer system 33 and the database 416 and/or processor 418.
- the database 416 may interface with the computer system 33 via a USB interface while the processor 418 may interface via another high-speed data bus without using the network interface 420.
- one or more of the components e.g., the mouse 410) may be omitted when the computer system 33 is disposed within the downhole tool 36.
- the various illustrative embodiments described herein may be used or implemented on any device that has computing/processing capability. These devices may include, but are not limited to: supercomputers, arrayed server networks, arrayed memory networks, arrayed computer networks, distributed server networks, distributed memory networks, distributed computer networks, desktop personal computers (PCs), tablet PCs, hand held PCs, laptops, devices sold under the trademark names BLACKBERRY ® or PALM ® , cellular phones, hand held music players, or any other device or system having computing capabilities.
- Figures 5-10 are illustrative spectrograms of signals in the wellbore 38.
- the X-axis represents frequency in (Hz)
- the Y-axis represents the energy or power density in decibels (dB).
- Figure 5 is an illustrative spectrogram of an internal pressure signal 500 during drilling, according to an embodiment of the disclosure.
- the strongest components in the internal pressure signal 500 may be the telemetry component 510 at about 2 Hz, the downhole noise component 520 at about 5 Hz (e.g., due to the mud motor when weight on bit is applied) and the surface noise harmonics 530, 532, 534 at about 3, 6, and 9 Hz (e.g., due to the surface mud pumps).
- the peak of the telemetry component 510 is about 10 dB
- the peak of the downhole noise component 520 is about 20 dB
- the peak of the surface noise harmonics 530, 532, 534 is about 8 dB.
- Figure 6 is an illustrative spectrogram of an axial acceleration signal 600 during drilling, according to an embodiment of the disclosure. As shown, downhole noise component 620 shows up in the axial acceleration at about 5 Hz. The peak of the downhole noise component 620 is about 15 Hz.
- Figure 7 is an illustrative spectrogram of the residual internal pressure signal 700 after noise cancellation using the axial acceleration signal 600, according to an embodiment of the disclosure.
- noise cancellation may be applied to the internal pressure signal 500.
- the output of this noise cancellation is the residual signal 700 from the output of the adaptive filter.
- the interference to the telemetry component 710 due to the downhole noise component 720 may be reduced.
- Figure 8 is an illustrative spectrogram of an internal pressure signal 800 during a stick-slip event, according to an embodiment of the disclosure.
- the strongest components in the internal pressure signal 800 may be the telemetry component 810 at about 0.625 Hz and the downhole noise component 820 at about 0.16 Hz (e.g., due to the mud motor when weight on bit is applied).
- the peak of the telemetry component 810 is about 10 dB
- the peak of the downhole noise component 820 is about 20 dB.
- Figure 9 is an illustrative spectrogram of an axial acceleration signal 900 during the stick-slip event, according to an embodiment of the disclosure.
- downhole noise component 920 shows up in the axial acceleration at about 0.16 Hz.
- the peak of the downhole noise component 920 is about 15 Hz.
- Figure 10 is an illustrative spectrogram of a residual signal 1000 in the internal pressure after noise cancellation using the axial acceleration signal 900, according to an embodiment of the disclosure.
- noise cancellation may be applied to the internal pressure signal 800.
- the output of this noise cancellation is the residual signal 1000 from the output of the adaptive filter.
- there is suppression of the downhole noise component 1020 at about 0.16 Hz, while the telemetry component 1010 at 0.625 Hz is largely intact.
- the interference to the telemetry component 1010 due to the downhole noise component 1020 may be reduced.
- the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation.
- the terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.”
Abstract
Description
Claims
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US201261694591P | 2012-08-29 | 2012-08-29 | |
PCT/US2013/056705 WO2014035914A1 (en) | 2012-08-29 | 2013-08-27 | System and method for downhole signal enhancement |
Publications (2)
Publication Number | Publication Date |
---|---|
EP2890866A1 true EP2890866A1 (en) | 2015-07-08 |
EP2890866A4 EP2890866A4 (en) | 2016-07-20 |
Family
ID=50184213
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP13832420.7A Withdrawn EP2890866A4 (en) | 2012-08-29 | 2013-08-27 | System and method for downhole signal enhancement |
Country Status (5)
Country | Link |
---|---|
US (1) | US20150218937A1 (en) |
EP (1) | EP2890866A4 (en) |
BR (1) | BR112015004047A2 (en) |
CA (1) | CA2881648A1 (en) |
WO (1) | WO2014035914A1 (en) |
Families Citing this family (6)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US9840910B2 (en) * | 2014-06-25 | 2017-12-12 | Evolution Engineering Inc. | Fluid pressure pulse generator for a downhole telemetry tool |
WO2016093819A1 (en) | 2014-12-10 | 2016-06-16 | Halliburton Energy Services, Inc. | Devices and methods for filtering pump interference in mud pulse telemetry |
US10113418B2 (en) * | 2016-06-30 | 2018-10-30 | Schlumberger Technology Corporation | Methods and systems for spectrum estimation for measure while drilling telemetry in a well system |
US11162358B2 (en) | 2017-06-21 | 2021-11-02 | Schlumberger Technology Corporation | Downhole characterization of formation pressure |
CN109522802B (en) * | 2018-10-17 | 2022-05-24 | 浙江大学 | Pump noise elimination method applying empirical mode decomposition and particle swarm optimization algorithm |
US11634982B2 (en) * | 2021-01-22 | 2023-04-25 | Halliburton Energy Services, Inc. | Filtering of RSS pad noise in mud pulse telemetry systems and detection of RSS pad leaks |
Family Cites Families (13)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US6370082B1 (en) * | 1999-06-14 | 2002-04-09 | Halliburton Energy Services, Inc. | Acoustic telemetry system with drilling noise cancellation |
GB2361789B (en) * | 1999-11-10 | 2003-01-15 | Schlumberger Holdings | Mud pulse telemetry receiver |
BR0106104B1 (en) * | 2000-05-08 | 2013-08-06 | Method for noise reduction in a measured telemetry signal | |
US6626253B2 (en) * | 2001-02-27 | 2003-09-30 | Baker Hughes Incorporated | Oscillating shear valve for mud pulse telemetry |
US6657597B2 (en) * | 2001-08-06 | 2003-12-02 | Halliburton Energy Services, Inc. | Directional signal and noise sensors for borehole electromagnetic telemetry system |
US20040155794A1 (en) * | 2003-02-06 | 2004-08-12 | Halliburton Energy Services, Inc. | Downhole telemetry system using discrete multi-tone modulation with adaptive noise cancellation |
US7313052B2 (en) * | 2005-04-08 | 2007-12-25 | Baker Hughes Incorporated | System and methods of communicating over noisy communication channels |
US8004421B2 (en) * | 2006-05-10 | 2011-08-23 | Schlumberger Technology Corporation | Wellbore telemetry and noise cancellation systems and method for the same |
WO2007095153A1 (en) * | 2006-02-14 | 2007-08-23 | Baker Hughes Incorporated | System and method for pump noise cancellation in mud pulse telemetry |
US8811118B2 (en) | 2006-09-22 | 2014-08-19 | Baker Hughes Incorporated | Downhole noise cancellation in mud-pulse telemetry |
US7508734B2 (en) * | 2006-12-04 | 2009-03-24 | Halliburton Energy Services, Inc. | Method and apparatus for acoustic data transmission in a subterranean well |
US20090294174A1 (en) * | 2008-05-28 | 2009-12-03 | Schlumberger Technology Corporation | Downhole sensor system |
US8408330B2 (en) * | 2009-04-27 | 2013-04-02 | Schlumberger Technology Corporation | Systems and methods for canceling noise and/or echoes in borehole communication |
-
2013
- 2013-08-27 WO PCT/US2013/056705 patent/WO2014035914A1/en active Application Filing
- 2013-08-27 US US14/424,430 patent/US20150218937A1/en not_active Abandoned
- 2013-08-27 EP EP13832420.7A patent/EP2890866A4/en not_active Withdrawn
- 2013-08-27 CA CA2881648A patent/CA2881648A1/en not_active Abandoned
- 2013-08-27 BR BR112015004047A patent/BR112015004047A2/en not_active IP Right Cessation
Also Published As
Publication number | Publication date |
---|---|
BR112015004047A2 (en) | 2017-07-04 |
CA2881648A1 (en) | 2014-03-06 |
WO2014035914A1 (en) | 2014-03-06 |
EP2890866A4 (en) | 2016-07-20 |
US20150218937A1 (en) | 2015-08-06 |
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