Patent Application
20210396132
This disclosure is related to the field of measurement of electromagnetic fields within the earth. More particularly, the disclosure relates to techniques to improve the ability of sensors placed at or near the earth's surface to measure electromagnetic fields emanating from within the earth by employing noise cancellation techniques. Noise cancellation can be used for a wide variety of applications, including but not limited to electromagnetic telemetry (“EMT”), geosteering, reservoir characterization and monitoring, and hydraulic fracturing. EMT is of particular interest and is used with measurement while drilling (“MWD”) and logging while drilling (“LWD”). The disclosure relates to techniques, methods, and systems to improve signal quality and/or reduce noise in the measured data, and/or improve the ability of MWD and/or LWD instruments to communicate with instruments at or near the earth's surface.
The field of measuring electromagnetic fields within the earth includes a wide array of applications, non-limiting examples of which are electromagnetic telemetry to communicate with downhole instruments, geosteering, electromagnetic surveys of the earth for locating and imaging oil and gas deposits, including enhanced oil recovery, and electromagnetic surveys for carbon dioxide storage. For example, U.S. Patent Application Publication 2017/0097441 A1, incorporated herein by reference, discloses a system and method for performing distant geophysical surveys by measuring the electromagnetic field emanating from the subsurface. The source of the electromagnetic field in these applications can be either natural or manmade.
Drilling operations widely employ MWD and LWD in order to maintain smooth operation of the equipment and provide decision support. The instrumentation data recorded during drilling is often vital in verifying drill direction in horizontal drilling, and often is the primary source of geophysical information about the formation. While data can be communicated to the surface using a mud pulse or other means, EMT is generally able to transmit real-time data from a wellbore transmitter to the surface at higher data rates compared to mud pulse and more cost effectively compared to other electromagnetic methods. U.S. Pat. No. 7,145,473, incorporated herein by reference, describes an example of electromagnetic telemetry for communicating signals between MWD and/or LWD instruments placed in a wellbore and equipment placed at the earth's surface (“uplink’). Various types of MWD/LWD instruments are known in the art, such as ones that emit primarily electric fields using a dipole antenna, or ones that emit primarily magnetic fields using wire coils. These instruments generate a time-varying electromagnetic field that propagates out to the earth's surface and is acquired by a plurality of sensors. Measurements of interest from the MWD/LWD instrument may be encoded into the time-varying electromagnetic field, and are subsequently decoded. On the other hand, transceivers or other signal sources at the earth's surface can generate a time-varying electromagnetic field that propagates down near the wellbore and is acquired by the MWD/LWD instruments (“downlink”). Similarly, information of interest from the earth's surface may be encoded into the time-varying electromagnetic field, and are subsequently decoded by the instruments in the wellbore. The EMT signals travel large distance in the earth and hence are generally small and hence readily obscured by large electromagnetic noise interference that is present during drilling operations. This noise often prevents the driller from obtaining the important MWD/LWD data in a timely fashion and hence it is desirable to remove or reduce this electromagnetic noise from the signal.
There have been several proposals set forth in the industry in an attempt to address this problem. For example, U.S. Pat. No. 6,781,520 teaches the use of adaptive filters to remove noise from a signal channel in a borehole telemetry system. However, the process requires additional motion sensors that detect noise and provide a noise reference channel free of telemetry signal content. U.S. Pat. No. 10,190,408 takes a different approach and employs numerous pairs of antennas each receiving a signal. The method in the '408 patent relies on using a complicated decoding step. WO 2018/174900 discloses method for active noise cancellation in electromagnetic telemetry. However, the method relies on employing single counter electrodes and a wellhead in combination to measure signals, as such the method suffers from the disadvantage of measuring very high noise generated near the wellhead by drilling equipment. Therefore, there exists a need in the art for a more effective way to measure a received signal containing a signal from a wellbore transmitter and noise and to separate the signal from the noise. There also exists a need to have the signal be measured in an efficient way without requiring the extra equipment or steps required by the prior art methods.
One aspect of the disclosure relates to a method of improving the signal quality of the electromagnetic field acquired at or near the earth's surface emanating from the EMT transmitter within a MWD/LWD instrument by reducing electromagnetic noise interference. In this method, signal processing techniques, including but not limited to onboard/embedded digital signal processing circuitry, proprietary signal processing algorithms, etc., are applied to the acquired signals, either in real time, near real time (defined here as approximately less than one minute delay from real time), or during post-processing.
Another aspect of the disclosure relates to a method of configuring sensor modules at the earth's surface to improve the signal quality of the electric and/or magnetic field “electromagnetic field” acquired at or near the earth's surface. In this method, the location of and/or the configuration of each sensor module is judiciously chosen so as to reduce noise in the electromagnetic field and to obtain the desired signal.
More specifically, one preferred embodiment of the invention is directed to a system for measuring, at or near the surface of the earth, a telemetry signal generated by a wellbore transmitter in the presence of at least one interfering signal. The system includes a first sensor module including a first electronic circuit and first and second individual sensors, with at least one individual sensor connected to the first electronic circuit unit. The first sensor module is located at or near the surface of the earth. Also, the first sensor module is configured to measure a first signal encompassing both the telemetry signal generated by the wellbore transmitter and the at least one interfering signal. The system also includes a second sensor module including a second electronic circuit and third and fourth individual sensors, with at least one individual sensor connected to the second electronic circuit. The second sensor module is located at or near the surface of the earth and is configured to measure a second signal encompassing the telemetry signal and the at least one interfering signal. The system also includes a signal processing unit connected to the first and second sensor modules for executing signal processing techniques on the first and second signals to develop an estimate of the at least one interfering signal and to obtain the telemetry signal.
The invention is also directed to an associated method for measuring a telemetry signal generated by a wellbore transmitter. The method includes measuring, at or near the surface of the earth, a first signal encompassing both the telemetry signal generated by the wellbore transmitter and at least one interfering signal with a first sensor module including a first electronic circuit and first and second individual sensors, with at least one individual sensor connected to the first electronic circuit unit. Next the method includes measuring, at or near the surface of the earth, a second signal encompassing the telemetry signal and the at least one interfering signal with a second sensor module including a second electronic circuit and third and fourth individual sensors, with at least one individual sensor connected to the second electronic circuit. The method then executes signal processing techniques, with a signal processing unit on the first and second signals, and develops an estimate of the at least one interfering signal and obtains the telemetry signal.
In another preferred embodiment, a method is provided that includes measuring a first signal representing the desired signal and the interfering signal with a first individual sensor and a second individual sensor and then measuring a second signal representing the desired signal and the interfering signal with a third individual sensor and a fourth individual sensor or at least one of the first and second individual sensors. At least one of the individual sensors is a capacitive electrode connected to an electronic circuit. The method then includes executing signal processing techniques, with a signal processing unit on the first and second signals to develop an estimate of the at least one interfering signal and to obtain the telemetry signal.
The invention improves the ability of the wellbore instruments and sensors at the earth's surface to communicate with one another in an environment that typically has electromagnetic noise interference from sources such as active drilling operations, pumps, motors, heavy machinery, electric line voltages, generators, AC or DC electric drives or the like. Electromagnetic noise from drawworks motors, top drive motors, and mud pumps are particularly large during drilling operations. The EMT communication signals decrease in magnitude when they travel long distances through the earth and the small signal measured at the surface can often be obscured by much larger electromagnetic noise interference. The invention allows the equipment operator to detect smaller signals in highly resistive or highly conductive formations both unfavorable to EMT, to increase the transmit frequency to increase the data throughput rate, or to reduce the transmit power to save precious battery life. The overall benefit is to increase the amount of useful data exchanged between the wellbore instruments and sensors at the earth's surface thereby enabling the well to be drilled faster, more accurately and at lower cost.
The preceding summary is provided to facilitate an understanding of some of the innovative features unique to the present disclosure and is not intended to be a full description. A full appreciation of the disclosure can be gained by taking the entire specification, claims, drawings, and abstract as a whole.
The disclosure may be more completely understood in consideration of the following description of various illustrative embodiments in connection with the accompanying drawings.
The following detailed description should be read with reference to the drawings in which similar elements in different drawings are numbered the same. The detailed description and the drawings, which are not necessarily to scale, depict illustrative embodiments and are not intended to limit the scope of the disclosure. The illustrative embodiments depicted are intended only as exemplary. Selected features of any illustrative embodiment may be incorporated into an additional embodiment unless clearly stated to the contrary. While the disclosure is amenable to various modifications and alternative forms, specifics thereof have been shown by way of example in the drawings and will be described in detail. It should be understood, however, that the intention is not to limit aspects of the disclosure to the particular illustrative embodiments described. On the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure.
As used in this specification and the appended claims, the singular forms “a”, “an” and “the” include plural referents unless the content clearly dictates otherwise. As used in this specification and the appended claims, the term “or” is generally employed in its sense including “and/or” unless the content clearly dictates otherwise.
In the description of embodiments disclosed herein, any reference to direction or orientation is merely intended for convenience of description and is not intended in any way to limit the scope of the present invention. Relative terms such as “lower,” “upper,” “horizontal,” “vertical,”, “above,” “below,” “up,” “down,” “top” and “bottom” as well as derivative thereof (e.g., “horizontally,” “downwardly,” “upwardly,” etc.) should be construed to refer to the orientation as then described or as shown in the drawing under discussion. These relative terms are for convenience of description only and do not require that the apparatus be constructed or operated in a particular orientation. Terms such as “attached,” “affixed,” “connected,” “coupled,” “interconnected,” and similar refer to a relationship wherein structures are secured or attached to one another either directly or indirectly through intervening structures, as well as both movable or rigid attachments or relationships, unless expressly described otherwise.
As used throughout, any ranges disclosed herein are used as shorthand for describing each and every value that is within the range. Any value within the range can be selected as the terminus of the range.
MWD and LWD instruments 110 in the wellbore 15 are typically used to measure a set of properties of the earth 30 in contact with or in proximity to the drill string. The instruments 110 have the ability to measure, process, and/or store information. These instruments 110 measure properties such as, but not limited to, electrical properties, magnetic properties, gamma ray, nuclear magnetic resonance, optical properties, acoustic properties, radiological properties, mechanical properties, or the like. These non-limiting examples account for the various properties and information which may aid in probing the earth 30, identifying the content of the material, guiding the drill path or otherwise providing useful information to the operator of the apparatus.
Wellbore instruments 110 communicate with sensors at the earth's surface. MWD/LWD instruments in the wellbore 15 may typically be configured to send data to the surface by encoding it onto a time-varying electromagnetic field such as telemetry signal 135. Specifically, the data may be encoded into the amplitude, phase and/or frequency of any spatial component of either the electric or magnetic field. Examples of encoding include, but are not limited to Quadrature Phase Shift Keying (QPSK), Quadrature Amplitude Modulation (QAM), Binary Phase Shift Keying (BPSK), Differential Phase Shift Keying (DPSK) and Frequency Shift Keying (FSK).
Sensors, in sensor arrangement 40, placed at or near the earth's surface have the ability to measure electromagnetic field at frequencies of interest, which span a range of frequencies from 0 to at most 1 kHz. In certain embodiments, the lowest frequency is at least 0.01 Hz and at most 1 kHz. Non-limiting examples of sensors are capacitive electrode-based sensors, galvanic electrode sensors, magnetic sensors, and hybrid sensors.
Conventional galvanic electrode sensors can be used to connect to the earth to measure electric potential. These galvanic electrodes typically consist of metal rods driven into the earth. They could also use a metal/metal salt interface which is in direct contact to the earth. These electrodes rely on the flow of electrical current across the interface to measure the local electric potential. The contact between the electrode and the earth is primarily resistive and this contact resistance needs to be sufficiently low for practical applications where the resistance is below 5 kΩ and more preferably below 1 kΩ. For convenience, this entire class of conventional electrodes is termed “galvanic electrodes” and comprises an example of an individual sensor.
Capacitive electrode-based sensors can either be a capacitive electrode alone or a capacitive electrode attached to an electronic circuit (also termed a “capacitive sensor”). The capacitive electrode is an individual sensor that measures the electric potential at one point at or near the surface of the earth by virtue of operative capacitive coupling between the earth and a sensing plate. The sensing plate includes a barrier which provides electrochemical segregation between the sensing plate and the earth. A capacitive electrode attached to an electronic circuit adds, for example, as an amplifier having at least one stage for receiving and amplifying a signal carrying the potential measured by the sensing plate. Capacitive sensors were disclosed in U.S. Pat. No. 9,405,032 B2 by Hibbs, incorporated herein by reference. As disclosed by Hibbs, the electrochemical segregation provided by the barrier is defined by a resistance larger than 10 kΩ between the sensing plate and the earth.
Non-limiting examples of magnetic sensors are induction-type sensors, fluxgate magnetometer sensors, or the like. Such non-limiting examples were disclosed in U.S. Pat. No. 7,141,968 B2 by Hibbs at al. and U.S. Pat. No. 7,391,210 B2 by Zhang et al, each incorporated herein by reference. The particular architecture and method of action of the magnetic sensors is not pertinent to this application. The common features of the sensors are that they measure the magnetic field of the earth or of the surrounding area between frequencies of 0 Hz and 10 kHz and are placed at the earth's surface.
There are a wide variety of noise sources on the drill rig 10 that can interfere with EM telemetry signals 135. Because EM telemetry operates at relatively low frequencies, below 200 Hz, sources of electromagnetic noise, such as the interfering signal 71, at these frequencies are of the greatest concern. Major sources of EM noise typically include top drive and drawworks motors that move the drill string, mud motors that circulate drilling mud down to the drill bit 80, and electrical generators that power the drill rig 10. The noise that is generated when a large motor is turned on or off can often impact the signal 135. Other noise sources can include vibration of electrical conductors from the drilling operations and improper or suboptimal electrical grounding of the drill rig 10.
The EMT signal 135 generated by the transmitter 120 in the BHA is generally strongest at the surface for sensors located closer to the wellbore 15. Due to the metal in the drill string and higher up in the casing, the EM signal 135 travels in proximity to these conductors as opposed to traveling through the much more resistive formation. This has been shown to hold true by Jannin et al even for deviated wells where the EM signal is generated 5,000 feet out along the lateral. See “Deep electrode: A game-changing technology for electromagnetic (EM) telemetry” Gaelle Jannin, Juiping Chen, Luis Eduardo DePavia, Liang Sun and Michael Schwartz, SEG Technical Program Expanded Abstracts, 1059-1063, 2017. Jannin et al also indicates that the EMT signal value near the surface will be smaller at larger radial distances away from the wellbore 15 and that this signal is generally symmetric in magnitude at the same radial distance from the wellbore 15 for positions all around the wellbore 15.
Using a plurality of sensors in sensor arrangement 40 to measure or acquire the combination of LWD signals and/or MWD signals 135, in the presence of interfering signals 71, enables various data signal processing methods to separate the desired telemetry signals 135 from the electromagnetic noise interfering signals 71. Each individual sensor in the sensor modules or plurality of sensors in sensor arrangement 40 will receive different amounts of the desired signal 135 and the interfering signals 71, dependent on the location of the individual sensors in relation to the source of the various signals (desired telemetry signal 135 and interfering noise signals 71). The desired signal as received by any one of the sensor modules will be correlated with the desired signal as received by any of the other sensor modules. Likewise, any signal from an interfering source as received by any one of the sensor modules will be correlated with the signal from that same interfering source as received by any of the other sensor modules. In general, the desired signal will not be well correlated with any of the interfering signals. Well known signal processing methods can be used to remove the noise, including Adaptive Noise Cancellation. Related data processing methods, such as Principal Component Analysis (PCA), Independent Component Analysis (ICA) and Singular Value Decomposition (SVD), can be used to separate the desired signal from the interfering signal by separating signals from a plurality of sensors into a mutually uncorrelated set of signals. The sensitivity of each sensor module to the desired signal and to each of the interfering signals can be measured.
Data signal processing methods based on the correlation of signals detected by a plurality of individual sensors can also be used in real-time, near real-time, or post processing. An example of a sensor arrangement 40 of a plurality of individual sensors that can be used with this approach is shown in
Another approach to reducing the noise is configuring a plurality of individual sensors in fixed locations where the noise cancellation stems from the geometric arrangement of the sensors with respect to the signal and noise sources. This is sometimes referred to as a gradiometer arrangement for two individual sensors located as shown in
An alternative arrangement for the gradiometer method is shown in
Other embodiments that take advantage of using a plurality of sensor modules configured for improved noise cancellation are shown in
Another embodiment shown in
In another embodiment shown in
Both embodiments shown on
As another example, these signal processing techniques here, including adaptive noise cancellation can be combined with well-known filtering methods, such as bandpass filtering. As one specific example, bandpass filter can be used on the signal channel input and noise channel input prior to adaptive noise cancellation. This can improve the adaptive noise cancellation by reducing the amount of noise interference that lies outside the signal frequency band of interest (near the transmitter frequency), allowing the adaptive noise cancellation to focus on reducing the interfering signals that most impact the desired signal. Additional signal processing methods can be used with adaptive noise cancellation to help reduce or limit cancellation of the signal of interest. Adaptive noise cancellation, as well as other correlation-based signal processing methods can be used in combination with deploying sensors in a geometrically useful fashion such as in a gradiometer arrangement as also shown in
A preferred embodiment includes measuring, at or near the surface of the earth, a third signal encompassing the telemetry signal and the at least one interfering signal with a third sensor module including a third electronic circuit and fifth and sixth individual sensors, with at least one individual sensor connected to the third electronic circuit. In addition, the method includes determining the estimate of the at least one interfering signal at the first sensor module and using the estimate to reduce the at least one interfering signal from the first signal to obtain the telemetry signal.
In operation, and in accordance with a preferred embodiment of the invention, the method includes one of the sensor modules measuring the at least one interfering signal enabling this sensor module to be used as a noise reference channel to execute adaptive noise cancellation based on the noise reference channel. Alternatively, the adaptive noise cancellation may use outputs of at least two noise reference channels combined to produce a synthetic noise reference channel for the adaptive noise cancellation along with a third sensor module used as a signal channel input for the adaptive noise cancellation. Further, the adaptive noise cancellation may use the outputs of the at least two noise reference channels added or subtracted together to produce a synthetic noise reference channel having a reduced amount of the telemetry signal. Alternatively, or in addition, the outputs of at least two of the sensor modules, may be combined to produce a synthetic signal channel employed as a signal channel input for the adaptive noise cancellation.
In operation, and in accordance with another preferred embodiment of the invention, the method for measuring a desired signal generated by a wellbore transmitter includes measuring a first signal representing the desired signal and the interfering signal with a first individual sensor and a second individual sensor while measuring a second signal representing the desired signal and the interfering signal with a third individual sensor and either a fourth individual sensor or at least one of the first and second individual sensors. The method then includes executing signal processing techniques on the first and second signals with a signal processing unit to develop an estimate of the at least one interfering signal and to obtain the telemetry signal.
The signal processing techniques include calculating a mutually uncorrelated set of signals to determine the estimated interfering signal from the mutually uncorrelated set of signals. The signal processing techniques include determining an estimated sensitivity of each sensor module to the telemetry signal and to the at least one interfering signal based on the mutually uncorrelated set of signals and determining the estimate of the at least one interfering signal based on the estimated sensitivity. The signal processing techniques further include updating the estimated sensitivity over time. The signal processing techniques include one or more of principal component analysis, independent component analysis, single value decomposition, or adaptive noise cancellation, either used alone or in combination with one or more of the others. The signal processing techniques include convolutional neural networks, machine learning or artificial intelligence. An electromagnetic field signal of interest is measured to aid in geosteering the drill.
In another preferred embodiment of the invention a method is provided that includes measuring a first signal representing the desired signal and the at least one interfering signal with a first individual sensor and a second individual sensor. The method further includes measuring a second signal representing the desired signal and the at least one interfering signal with a third individual sensor and either a fourth individual sensor or at least one of the first and second individual sensors. At least one of the individual sensors is a capacitive electrode connected to an electronic circuit. The method further includes executing signal processing techniques on the first and second signals with a signal processing unit to develop an estimate of the at least one interfering signal and to obtain the telemetry signal
Yet another preferred method includes measuring a first signal representing the desired signal and the at least one interfering signal with a first individual sensor and a second individual sensor and measuring a second signal representing the desired signal and the at least one interfering signal with a third individual sensor and either a fourth individual sensor or at least one of the first and second individual sensors. At least one of the individual sensors is a capacitive electrode connected to an electronic circuit. The method further includes executing signal processing techniques on the first and second signals with a signal processing unit to develop an estimate of the at least one interfering signal and to obtain the telemetry signal. Preferably at least two of the individual sensors are configured in a gradiometer arrangement and the signal processing techniques include adaptive noise cancellation and/or principal component analysis, independent component analysis or singular value decomposition. Also, the signal processing techniques include adaptive noise cancellation and principal component analysis, independent component analysis or singular value decomposition. At least one individual sensor configured to measure the telemetry signal and at least one additional individual sensor configured to measure interfering noise are located on the same side of the wellbore as the lateral and within an angle of 90 degrees from each other as measured in the plane of the surface of the earth with respect to the wellbore.
Having thus described several illustrative embodiments of the present disclosure, those of skill in the art will readily appreciate that yet other embodiments may be made and used within the scope of the claims hereto attached. Numerous advantages of the disclosure covered by this document have been set forth in the foregoing description. It will be understood, however, that this disclosure is, in many respects, only illustrative. Changes may be made in details, particularly in matters of shape, size, and arrangement of parts without exceeding the scope of the disclosure. The disclosure's scope is, of course, defined in the language in which the appended claims are expressed.
This application claims the benefit of U.S. Provisional Application No. 62/779,866 filed on Dec. 14, 2018 and entitled, “Noise Cancellation for Measuring Electromagnetic Fields Within the Earth”. The entire contents of this application are incorporated herein by reference.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2019/066335 | 12/13/2019 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 62779866 | Dec 2018 | US |
