BACKGROUND

[0001] 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.

[0002] 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.

[0003] 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.

SUMMARY

[0004] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0005] A system for downhole signal enhancement is disclosed. The system 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.

[0006] A method for downhole signal enhancement is also disclosed. 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.

[0007] 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.

BRIEF DESCRIPTION OF THE DRAWINGS

[0008] So that the recited features may be understood in detail, a more particular description, briefly summarized above, may be had by reference to one or more embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings are illustrative embodiments, and are, therefore, not to be considered limiting of its scope.

[0009] Figure 1 is a schematic illustration of a downhole noise cancellation system, according to an embodiment of the disclosure.

[0010] 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. [0011] Figure 3 is a schematic illustration of an internal pressure downhole noise estimation filter, according to an embodiment of the disclosure.

[0012] Figure 4 is an illustrative computer system disposed within a downhole tool, according to an embodiment of the disclosure.

[0013] Figure 5 is an illustrative spectrogram of an internal pressure signal during drilling, according to an embodiment of the disclosure.

[0014] Figure 6 is an illustrative spectrogram of an axial acceleration signal during drilling, according to an embodiment of the disclosure.

[0015] 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.

[0016] Figure 8 is an illustrative spectrogram of an internal pressure signal during a stick-slip event, according to an embodiment of the disclosure.

[0017] Figure 9 is an illustrative spectrogram of an axial acceleration signal during the stick- slip event, according to an embodiment of the disclosure.

[0018] 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.

DETAILED DESCRIPTION

[0019] In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure. However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

[0020] 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. To reduce or mitigate the downhole noise, an active downhole noise cancellation system may be employed as described herein. [0021] To mitigate the downhole noise, an estimate of the downhole noise components contained in the internal pressure may be measured with one or more downhole sensors. As used herein, "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. For example, 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. Additionally, a filtered version of the mud pulse data symbols or pulse-shaped samples may be used.

[0022] If 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. For example, if the axial acceleration measurements include surface noise but not mud pulse telemetry signals or downhole noise, then the surface noise component may be identified within the internal pressure measurements and subsequently removed. Once the downhole drilling noise component of the internal pressure has been isolated, it may be fed into an active downhole noise cancellation system. In another example, components of the downhole internal pressure measurements may be isolated and fed into a downhole echo cancellation system for mud pulse telemetry.

[0023] Referring generally to Figure 1, an illustrative noise cancellation system 20 for reducing or mitigating the downhole noise via an active downhole noise cancellation technique is illustrated. In this example, 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. Using these measurements, 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. In at least one embodiment, 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. 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.

[0024] In another embodiment, 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. 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.

[0025] An example of the hardware that may be used to implement the system 20 is illustrated in Figure 2. 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. As shown, three sensors 22-1 are positioned below the telemetry modulator 30, and three sensors 22-2 are positioned above the telemetry modulator 30. However, as may be appreciated, 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.

[0026] 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.

[0027] 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. To use the available mud pulse transmission power efficiently, 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. For example, 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. In this example, 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. [0028] To form the downhole noise estimator 24, 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 (see telemetry data symbols 26 in Figure 1) 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. In some embodiments, 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. To reduce estimator bias, 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.

[0029] In a hypothetical example, 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.

[0030] 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.

[0031] In the case of a digital filter where both the reference internal measurement process and the input process have been converted into a sequence of measurement samples, the difference between the filter output sample dk and the reference sample dk may be minimized. For the case where the input and reference sequences are wide sense stationary, a suitable methodology may be to choose filter parameters w to minimize the mean squared error (MSE):

JO) = E{ |dk - dk| ² } where E{} denotes the expected value. Specializing further to a linear filter (e.g., a Wiener filter or an adaptive filter) may depend on the second-order statistics of dk and Xk and may be used to select the filter tap weight parameters w which minimize the MSE. To estimate the second-order statistics, sample estimates may be used over time durations where the processes are approximately stationary.

[0032] If the measurement processes (including the internal pressure) vary with time, another approach may utilize adaptive filtering algorithms to determine the filter parameters. For a finite-length linear filter, adaptive filtering algorithms such as the least mean square (LMS), normalized LMS, and recursive least squares (RLS) algorithms may be used. These algorithms may be used to compute the filter tap weight parameters, for example, on a block- by-block or sample-by-sample basis in either the time or frequency domains.

[0033] 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. [0034] 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.

[0035] 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. For example, in an illustrative embodiment, 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. As may be appreciated, 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.

[0036] It should be understood that even though the computer system 33 is shown as a platform on which the illustrative methods described may be performed, the methods described may be performed on a number of computer or microprocessor based platforms. For example, 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. [0037] Figures 5-10 are illustrative spectrograms of signals in the wellbore 38. In each of the Figures, the X-axis represents frequency in (Hz), and 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. During a clean drilling operation, 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). As shown, the peak of the telemetry component 510 is about 10 dB, the peak of the downhole noise component 520 is about 20 dB, and the peak of the surface noise harmonics 530, 532, 534 is about 8 dB.

[0038] 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.

[0039] 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. Using the axial acceleration signal 600 as a reference, noise cancellation may be applied to the internal pressure signal 500. As shown in Figure 7, the output of this noise cancellation is the residual signal 700 from the output of the adaptive filter. As shown, there is suppression of the downhole noise component 720 at about 5 Hz, while the telemetry component 710 and surface noise harmonics 730, 732, 734 are largely intact. As such, when the residual internal pressure signal 700 is received at the surface, the interference to the telemetry component 710 due to the downhole noise component 720 may be reduced.

[0040] Figure 8 is an illustrative spectrogram of an internal pressure signal 800 during a stick-slip event, according to an embodiment of the disclosure. During a stick-slip event, 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). As shown, the peak of the telemetry component 810 is about 10 dB, and the peak of the downhole noise component 820 is about 20 dB.

[0041] Figure 9 is an illustrative spectrogram of an axial acceleration signal 900 during the stick-slip event, according to an embodiment of the disclosure. As shown, 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.

[0042] 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. Using the axial acceleration signal 900 as a reference, noise cancellation may be applied to the internal pressure signal 800. As shown in Figure 10, the output of this noise cancellation is the residual signal 1000 from the output of the adaptive filter. As shown, 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. As such, when the residual internal pressure signal 1000 is received at the surface, the interference to the telemetry component 1010 due to the downhole noise component 1020 may be reduced.

[0043] As used herein, 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."

[0044] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from "System and Method for Downhole Signal Enhancement." Accordingly, all such modifications are intended to be included within the scope of this disclosure. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 120, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words 'means for' together with an associated function.

[0045] Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges including the combination of any two values, e.g., the combination of any lower value with any upper value, the combination of any two lower values, and/or the combination of any two upper values are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below. All numerical values are "about" or "approximately" the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.

[0046] Various terms have been defined above. To the extent a term used in a claim is not defined above, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.