阅读说明：本技术 减弱井下声波工具测量中获取的工具产生的噪声 (Attenuating tool-generated noise acquired in downhole sonic tool measurements ) 是由 R.H.琼斯 T.瓦戈 C.E.亚曼 于 2018-05-29 设计创作，主要内容包括：一种技术包括接收表示由井下声波测量工具的工具运动传感器获取的测量结果的数据；以及接收表示由声波测量工具的压力传感器获取的测量结果的数据。该技术包括至少部分地基于由工具运动传感器获取的测量结果来修改由压力传感器获取的测量结果,以减弱工具产生的噪声。(A technique includes receiving data representing measurements taken by a tool motion sensor of a downhole sonic measurement tool; and receiving data representing measurements taken by a pressure sensor of the sonic measurement tool. The technique includes modifying measurements taken by the pressure sensor based at least in part on measurements taken by the tool motion sensor to attenuate noise generated by the tool.)

1. A method, comprising:

receiving data representing measurements taken by a tool motion sensor of a downhole sonic measurement tool;

receiving data representing measurements taken by a pressure sensor of an acoustic wave measurement tool; and

the measurements taken by the pressure sensor are modified based at least in part on the measurements taken by the tool motion sensor to attenuate noise generated by the tool.

2. The method of claim 1, wherein the tool motion sensor comprises an accelerometer providing an acceleration signal, and modifying the measurements acquired by the pressure sensor comprises manipulating the acceleration signal.

3. The method of claim 1, wherein the tool-generated noise comprises noise propagating through a body of the sonic measurement tool due to energy from a source of the sonic measurement tool.

4. The method of claim 1, wherein receiving data acquired by the tool motion sensor comprises receiving data acquired by a sensor disposed outside a pressure sealed chamber in which an electronic device of the tool is disposed.

5. The method of claim 1, wherein receiving data representative of measurements acquired by the pressure sensor comprises receiving data representative of movement of an acoustic measurement tool in response to energy generated by emission of a source of the acoustic measurement tool.

6. The method of claim 1, wherein receiving data representative of measurements acquired by the tool motion sensor comprises receiving data representative of energy sensed by the tool motion sensor in a frequency range of 1 up to 150 kilohertz.

7. The method of claim 1, wherein compensating measurements taken by the pressure sensor comprises determining a velocity of energy propagating from an acoustic wave source of the tool along a tool body of the acoustic wave measurement tool, and based on the identified velocity, identifying a time period of a pressure versus time curve associated with tool-generated noise.

8. The method of claim 1, wherein compensating for measurements taken by the pressure sensor comprises:

moving the sonic measurement tool to a downhole location;

obtaining measurements of a tool motion sensor while the sonic measurement tool is at a given downhole location;

obtaining a measurement of the pressure sensor while the sonic measurement tool is at a given downhole location;

repeatedly obtaining measurements of tool motion and pressure at least one other downhole location of the sonic measurement tool; and

the noise generated by the tool is determined based at least in part on the measurements of pressure and tool motion at the location of the sonic measurement tool.

9. The method of claim 8, wherein determining the tool-generated noise based on the measurements of pressure and tool motion at the downhole locations of the sonic measurement tool comprises superimposing estimated tool-generated noise derived from the measurements of pressure and tool motion at each downhole location.

10. The method of claim 9, wherein the superposition depends on formation differences or properties of the well that affect energy propagation from the acoustic wave source through the well fluid or through the formation.

11. An apparatus usable with a well, comprising:

a tool body;

an acoustic wave source attached to the tool body;

a pressure sensor attached to the tool body to sense pressure related to the emission of the acoustic wave source; and

an accelerometer attached to the tool body to sense a component related to pressure sensed by the pressure sensor, the pressure being due to noise generated by the tool.

12. The apparatus of claim 11, further comprising at least one additional pressure sensor attached to the tool body; and

at least one additional accelerometer attached to the tool body to sense a noise component generated by the tool in relation to pressure measurements taken by at least one other pressure sensor.

13. The apparatus of claim 11, further comprising:

a pressure chamber; and

an electronic device disposed within the pressure chamber,

wherein an accelerometer is coupled to the tool body and decoupled from the formation fluid.

14. The apparatus of claim 11, wherein the tool-generated noise comprises noise due to energy propagating directly from the acoustic wave source through the tool body to the pressure sensor.

15. The apparatus of claim 11, further comprising:

at least one other accelerometer attached to the tool body to sense a sensed pressure component associated with noise generated by the tool.

16. An article comprising a non-transitory computer-readable storage medium storing instructions that, when executed by a processor-based system, cause the processor-based system to:

receiving data representing measurements taken by a tool motion sensor of a downhole sonic measurement tool;

receiving data representing measurements taken by a pressure sensor of an acoustic wave measurement tool; and

the measurements taken by the pressure sensor are modified based at least in part on the measurements taken by the tool motion sensor to attenuate noise generated by the tool.

17. The article of claim 16, wherein the tool motion sensor comprises an accelerometer, and the computer-readable storage medium stores instructions that, when executed by the processor-based system, cause the processor-based system to manipulate the acceleration signal provided by the tool motion sensor to determine at least one characteristic of noise produced by the tool.

18. The article of claim 16, wherein the tool-generated noise comprises noise attributed to energy from a source of the sonic measurement tool propagating through a body of the sonic measurement tool.

19. The article of claim 16, the computer-readable storage medium storing instructions that, when executed by the processor-based system, cause the processor-based system to receive data acquired by a sensor disposed outside of a pressure-sealed chamber in which the tool's electronics are disposed.

20. The article of claim 16, said computer-readable storage medium storing instructions that, when executed by a processor-based system, cause said processor-based system to receive data representative of movement of an acoustic measurement tool in response to energy generated by emission of a source of said acoustic measurement tool.

21. An article comprising a non-transitory computer-readable storage medium storing instructions that when executed by a processor-based system cause the processor-based system to:

receiving data representing the compensation signal based on measurements obtained by a tool motion sensor of a downhole sonic measurement tool in a test environment;

receiving data representing measurements taken by a pressure sensor of a downhole sonic measurement tool in a well; and

the measurements taken by the pressure sensor are modified based at least in part on the compensation signal to attenuate noise generated by the tool.

Background

This application claims priority and benefit of U.S. patent application No. 15/607708 filed on 30/5/2017, the entire contents of which are expressly incorporated herein by reference.

Hydrocarbon fluids, such as oil and gas, are obtained from subterranean geological formations (known as reservoirs) by drilling wells that penetrate hydrocarbon-bearing formations. During drilling and other exploration phases throughout the production process, various downhole tools may be used to acquire data for the purposes of evaluating, analyzing, and monitoring the wellbore and surrounding geological formations. In some cases, the acquired data includes acoustic or seismic data, i.e., data acquired by sensors or receivers in response to acoustic/seismic energy interacting with the wellbore and surrounding geological formations. The acquired data may be processed and interpreted for the purpose of deriving information about the hydrocarbon bearing formation, the well, and other aspects related to the subsurface survey.

Disclosure of Invention

According to an example embodiment, a technique includes receiving data representing measurements taken by a tool motion sensor of a downhole sonic measurement tool; and receiving data representing measurements taken by the pressure sensor of the sonic measurement tool. The technique includes modifying measurements taken by the pressure sensor based at least in part on measurements taken by the tool motion sensor to attenuate noise generated by the tool.

According to another example embodiment, an apparatus usable within a well includes a tool body; an acoustic wave source attached to the tool body; pressure sensors and accelerometers. A pressure sensor is attached to the tool body to sense pressure related to the source of acoustic waves (emission; and an accelerometer is attached to the tool body to sense a component related to the pressure sensed by the pressure sensor due to noise generated by the tool.

According to another example embodiment, an article includes a non-transitory computer-readable storage medium for storing instructions that, when executed by a processor-based system, cause the processor-based system to receive data representing measurements acquired by a tool motion sensor of a downhole sonic measurement tool; receiving data representing measurements taken by a pressure sensor of an acoustic wave measurement tool; and modifying the measurements taken by the pressure sensor based at least in part on the measurements taken by the tool motion sensor to attenuate noise generated by the tool.

According to yet another example embodiment, an article includes a non-transitory computer-readable storage medium for storing instructions that, when executed by a processor-based system, cause the processor-based system to receive data representative of a compensation signal based on measurements acquired by a tool motion sensor of a downhole sonic measurement tool in a test environment; receiving data representing measurements taken by a pressure sensor of a sonic measurement tool downhole in a well; and modifying the measurements taken by the pressure sensor based at least in part on the compensation signal to attenuate noise generated by the tool.

Advantages and other features will become apparent from the following description, the drawings, and the claims.

Drawings

FIG. 1 is a diagram of a sonic measurement tool in a borehole according to an example embodiment;

2A, 2B, and 2C are flow diagrams describing techniques for compensating measurements taken by a downhole sonic measurement tool to attenuate tool-generated noise, according to an example embodiment;

FIG. 3 is a graphical representation of a pressure versus time waveform produced by the transmission of a source of a sonic measurement tool in accordance with an example embodiment;

FIG. 4 shows acceleration versus time waveforms sensed by an accelerometer of a sonic measurement tool in response to a transmission of a source, according to an example embodiment;

FIG. 5 illustrates a waveform of pressure sensed by a pressure sensor of a sonic measurement tool in response to a transmission of a source versus time, according to an example embodiment;

FIG. 6 illustrates a pressure versus time waveform generated by applying compensation to the pressure versus time waveform of FIG. 5 to remove tool generated noise, according to an example embodiment;

FIG. 7 is a schematic diagram of a data processing system according to an example embodiment.

Detailed Description

Reference throughout this specification to "one embodiment," "an embodiment," "certain embodiments," "one aspect," "an aspect," or "certain aspects" means that a particular feature, structure, method, or characteristic described in connection with the embodiment or aspect is included in at least one embodiment of the present disclosure. Thus, the appearances of the phrases "in one embodiment" or "in an embodiment" or "in some embodiments" in various places throughout this specification are not necessarily all referring to the same embodiment. Furthermore, the particular features, structures, methods, or characteristics may be combined in any suitable manner in one or more embodiments. The words "including" and "having" shall have the same meaning as the word "comprising".

As used throughout the specification and claims, the term "downhole" refers to a subterranean environment, particularly in a well or wellbore. "downhole tool" is used broadly to mean any tool used in a subterranean environment, including, but not limited to, logging tools, imaging tools, acoustic tools, permanent monitoring tools, and combination tools.

Various techniques disclosed herein may be used to facilitate and improve data acquisition and analysis in downhole tools and systems. Downhole tools and systems are provided that utilize an array of sensing devices configured or designed for attachment and detachment in a downhole sensor tool or module deployed within a borehole for sensing data related to a downhole environment and downhole tool parameters. The tools and sensing systems disclosed herein may effectively sense and store properties related to components of downhole tools and formation parameters at elevated temperatures and pressures. The sensing systems herein may be incorporated into tool systems such as wireline logging tools, measurement-while-drilling and logging-while-drilling tools, permanent monitoring systems, drill bits, drill collars, sondes, and the like. For the purposes of this disclosure, when any of the terms "wireline," "cable line," "slickline" or "coiled tubing" or "conveyance" are used, it should be understood that any of the referenced deployment equipment or any other suitable equivalent equipment may be used with the present disclosure without departing from the spirit and scope of the present disclosure.

Furthermore, inventive aspects lie in less than all features of a single disclosed embodiment. Thus, the claims following the detailed description are hereby expressly incorporated into this detailed description, with each claim standing on its own as a separate embodiment.

Wellbore sonic logging is a major component of the evaluation of subterranean formations and is critical to the exploration and production of hydrocarbons. Logging may be accomplished, for example, using a sonic measurement tool that includes one or more acoustic transducers or sources, and one or more sensors or receivers. An acoustic measurement tool may be deployed in a flowfield borehole to excite and record acoustic waveforms. Thus, the receiver may acquire data indicative of the acoustic energy generated by the acoustic energy emitted by the acoustic wave source of the acoustic wave measurement tool.

Acoustic propagation in the borehole is affected by the properties of the rock surrounding the borehole. More specifically, the fluid-filled wellbore supports the propagation of a number of wellbore-guided acoustic modes that are generated by energy from sources disposed within the wellbore fluid. These borehole acoustic modes are characterized by their acoustic slowness (i.e., inverse velocity) dispersion, which contains valuable information about the mechanical properties of the rock. Thus, acoustic logging may provide answers relating to a variety of applications such as geophysical calibration of seismic imaging, geomechanical evaluation of borehole stability, and stress characterization of fracture stimulation. In the context of the present application, "acoustic energy" refers to energy in the acoustic spectrum and may be, for example, energy between 200 hertz (Hz) and 30 kilohertz (kHz). In addition to formation slowness, sonic logging is also used in well integrity applications to determine the cement conditions between the casing and the wellbore.

In general, energy emitted by a source of an acoustic measurement tool may travel through a rock formation in the form of a bulk wave or a surface wave (also referred to as a "flexural wave"). Bulk waves include compressional or P-waves, which are waves in which small particle vibrations occur in the same direction as the direction in which the waves travel. Bulk waves may also include shear waves or S-waves, which are waves in which particle movement occurs in a direction perpendicular to the direction of wave propagation. In addition to body waves, there are a variety of borehole guidance modes whose propagation characteristics can be analyzed to estimate certain rock properties of the surrounding formation. For example, axisymmetric Stoneley (Stoneley) waves and borehole flexural waves are particularly important in determining formation shear slowness. As described herein, bending waves may also include waves propagating along the sonic measurement tool.

The acoustic wave measurement tool may include a plurality of acoustic wave sources associated with a plurality of acoustic wave source classifications or categories. For example, the sonic measurement tool may include one or more monopole sources. In response to energy from a monopole acoustic wave source, a receiver of an acoustic wave measurement tool may acquire data representative of energy attributable to various wave modes, such as data representative of P-waves, S-waves, and stoneley waves.

The sonic measurement tool may also include one or more directional sources, such as quadrupole sources, that generate additional borehole guided waves that travel through the fluid in the borehole and along the sonic tool itself. Data representative of these flexural waves may be processed for purposes such as determining the presence or absence of azimuthal anisotropy and/or determining formation shear slowness.

The velocity of the aforementioned wave propagation is affected by various characteristics of the downhole environment, such as rock mechanical properties, density and elastic dynamic constants, the amount and type of fluids present in the formation, the composition of the rock grains, the degree of intergranular cementation, and the like. Thus, by measuring the speed of propagation of acoustic waves in the borehole, the surrounding formation may be characterized based on the sensed parameters related to these characteristics. The velocity, velocity or waveform of a given sound wave may be represented by the inverse of its velocity, referred to herein as "slowness". Herein, "acoustic wave" or "acoustic waveform" may refer to a particular period of time of energy recorded by one or more receivers and may correspond to a particular acoustic waveform pattern, such as a bulk wave, bending wave, or other guided borehole wave.

Some sound waves are non-dispersive or do not change significantly with respect to frequency. However, other acoustic waves are dispersive, meaning that the wave slowness varies with frequency.

Referring to FIG. 1, according to an example embodiment, a downhole sonic measurement tool 100 may be deployed in a borehole 110 for the purpose of acquiring sonic measurements generated by transmitting one or more sonic sources of the sonic measurement tool 100. For example, the sonic measurement tool 100 may include a source 130 (e.g., a monopole, dipole, and/or quadrupole source) that may be transmitted for the purpose of generating acoustic energy through the surrounding formation. According to example embodiments, the sonic measurement tool 100 may include one or more other sources. Depending on the particular implementation, the sonic measurement tool 100 may also include one or more receivers or sensors 120 (e.g., one or more pressure sensors). One or more receivers or sensors 120 (particular sensors 120-1, 120-2, 120-3, and 120-4, shown in FIG. 1) will sense the energy generated by a given acoustic wave source (e.g., acoustic wave source 130) of the transmitted acoustic wave measurement tool 120 for the purpose of measuring the speed and amplitude of acoustic wave propagation. From the measured acoustic wave propagation, the surrounding geological formation can be characterized.

According to an example embodiment, the sonic measurement tool 100 may be a cement evaluation tool used for the purpose of evaluating cement bond between a casing (not shown in FIG. 1) and the wellbore 110. More specifically, according to an example embodiment, the sonic measurement tool 100 may measure the pressure waveform amplitude at each sensor 120 and compare that amplitude to the amplitude of a non-cement bond reference measurement (referred to as a free pipe measurement). If the cement bonds poorly, the received amplitude will be similar to that of the free pipe, whereas if the cement bonds well, the pressure wave will be highly attenuated and the amplitude will be much lower than that of the free pipe.

Tool-generated noise can present particular challenges in assessing cement bond in the manner described above, as it may arrive at about the same time that energy is propagated through the casing. In this manner, energy from source 130 may propagate to each sensor 120 in two paths. As shown in particular for sensor 120-1 in FIG. 1, the two paths include a direct path 154 associated with the stronger received signal, and an indirect path 150 associated with energy propagating through the formation and arriving at sensor 120-1 at a later time. Since both the casing and the tool body are made of steel, the propagation velocity/slowness of the casing wave may be similar to the arrival velocity of the tool, thus presenting a potential challenge in obtaining a noiseless pressure amplitude measurement representative of cement bonding. The techniques and systems described herein are intended to reduce, if not remove, tool-generated noise, even for such challenging situations.

One way to attenuate the noise generated by the tool is by active cancellation. In this way, an actively canceling transmitter may be built into the acoustic measurement tool such that the acoustic waves generated by the transmitter constructively interfere with the tool body acoustic waves. However, using such active cancellation methods may present some challenges. For example, using this approach, additional transmitters are added to the tool, thereby increasing expense, consuming energy, and affecting the overall reliability of the tool. With active cancellation, the two sources transmit at or near the same time, thus requiring higher timing accuracy (e.g., less than 1 microsecond (μ s) timing accuracy). To obtain sufficient constructive interference, active cancellation uses relatively complex transmit waveforms. Thus, the cancellation waveform may be a high-pressure, complex waveform, and the waveform may vary with tool position, well conditions, and other potential factors.

According to example embodiments described herein, tool-generated noise is passively attenuated using signal processing rather than using active noise attenuation or using attenuators from measured pressure signals or traces. In this context, "attenuating" the noise generated by the tool refers to removing or eliminating at least a portion, if not all, of the noise generated by the tool. More specifically, according to an example embodiment, the sonic measurement tool 100 includes one or more tool motion sensors, such as one or more accelerometers 134, depending on the particular embodiment. As described herein, according to an example embodiment, accelerometer 134 obtains measurements indicative of movement of the body of acoustic wave measurement tool 100 in response to the emission of an acoustic wave source, such as acoustic wave source 130. The measurements by the accelerometer 134 are again decoupled from the well fluid and the formation; thus, the measurement may be considered to be closely related to the noise propagated by the tool. Accordingly, based at least in part on measurements taken by one or more such accelerometers 134, tool-generated noise may be estimated and removed from the pressure measurements.

As a more specific example, according to some embodiments, each pressure sensor 120 may have an associated accelerometer 134 located near or at the pressure sensor 120. For example, according to some embodiments, a given pressure sensor 120 may have an associated accelerometer 134 located within one meter of the pressure sensor 120. The accelerometer 134 may or may not be disposed within a pressure-tight chamber 140 that houses the electronics (e.g., telemetry circuitry 141 and controller 144) of the acoustic wave measurement tool 100, depending on the particular implementation. According to an example embodiment, the accelerometer 134 is coupled to the tool body (e.g., to a collar of the tool 100) and is not coupled to the well fluid.

Further, unlike conventional arrangements, the accelerometer 134 is configured to sense energy in a frequency spectrum associated with the sound pressure measurement. For example, according to some embodiments, the accelerometer 134 may be sensitive to energy in a range from 1 to 150kHz or higher, for example. Further, according to an example embodiment, the accelerometer 134 may have one or more sensitive measurement axes. For example, according to some embodiments, the accelerometer 134 may have a sensitive axis aligned with the longitudinal axis of the tool to sense acceleration along that axis. According to an example embodiment, the accelerometer 134 may have multiple sensitive axes, and thus, the accelerometer 134 may measure acceleration along multiple orthogonal axes (e.g., along three orthogonal axes).

Although an accelerometer is described herein as a particular example of a tool motion sensor, other sensors may be used according to other example embodiments. For example, according to some embodiments, the acoustic wave measurement tool may include a speed sensor that acquires data indicative of a sensed speed of a body of the acoustic wave measurement tool.

Thus, according to some embodiments, referring to fig. 2A in conjunction with fig. 1, the technique 200 includes receiving (block 204) data representing one or more measurements acquired by one or more tool motion sensors of a downhole sonic measurement tool and receiving (block 206) data representing one or more measurements acquired by one or more pressure sensors of the sonic measurement tool. The measurement(s) acquired by the pressure sensor may be modified based at least in part on the measurement(s) acquired by the tool motion sensor to mitigate tool-generated noise.

Fig. 3, 4, 5 and 6 illustrate the attenuation of noise generated by a tool according to an example embodiment. Referring to FIG. 3 in conjunction with FIG. 1, an acoustic wave source 130 can be emitted, producing emitted energy, as depicted at reference numeral 304 in a pressure versus time waveform 300 for the source 130. The emission of acoustic wave source 130 generates energy that propagates through the tool body and to accelerometer 134, as shown in FIG. 4. In this manner, referring to FIG. 4 in conjunction with FIG. 1, accelerometers 134-1, 134-2, 134-3, and 134-4 sense energy 404 propagating directly from source 130 to produce corresponding sensed acceleration signals 402-1, 402-2, 402-3, and 404-4, respectively.

The energy generated by the tool propagating directly from the acoustic wave source 134 is in turn combined with the energy propagating through the fluid and formation to produce a composite pressure and time waveform 500 that is sensed by the sensor 120, as shown in FIG. 5. In this manner, referring to FIG. 5 in conjunction with FIG. 1, the time window 510 of the pressure and time waveform 500 may be attributed to noise generated by the tool.

According to an example, portions of the sensed pressure due to tool-generated noise are identified and removed. For example, according to some embodiments, the signal provided by the accelerometer 134 may be integrated over time to derive a corresponding tool body velocity versus time curve. From these velocity versus time curves, the arrival time of the energy propagating through the tool body can be estimated to correspondingly identify time segments of the sensed pressure versus time waveform that are correlated with noise generated by the tool. Thus, as shown in FIG. 5, the time window 510 may be identified such that the sensed pressure within the time window 510 is subtracted from the pressure signal to yield a compensated pressure signal 610 shown in FIG. 6. In fig. 6, if not eliminated, the tool-generated noise is substantially eliminated in the corresponding time window 610 of the pressure signal 600.

Thus, referring to fig. 2B, according to an example embodiment, the technique 220 includes receiving (block 222) data representing one or more measurements acquired by one or more tool motion sensors of an acoustic wave measurement tool and receiving (block 224) data representing one or more measurements acquired by one or more pressure sensors of the acoustic wave measurement tool. The tool body velocity may then be determined according to block 226 based at least in part on the measurements acquired by the tool motion sensor. In this way, the tool motion sensor may be an accelerometer, and determining the tool body velocity may involve integrating the acceleration sent by the accelerometer over time.

The technique 220 includes estimating (block 228) a time of arrival of tool-generated noise in the pressure sensor measurements based on the determined tool body velocity. Then, in accordance with block 230, based at least in part on the estimated time of arrival and the measurements taken by the pressure sensors, the tool-generated noise for each pressure sensor measurement may be determined. The pressure sensor measurement(s) may then be modified based at least in part on the determined tool-generated noise (block 232).

According to further exemplary embodiments, a noise compensation signal generated by the tool that is applied to the pressure amplitude sensed by a given pressure sensor of the sonic measurement tool may be predetermined based on measurements taken in the test environment (e.g., measurements taken with the sonic measurement tool placed in a puddle). More specifically, according to an example embodiment, a sonic measurement tool receives data representing a compensation signal, the data being constructed based on measurements taken by a tool motion sensor of the sonic measurement tool downhole in a test environment. The test environment may be a test well, sump, or the like. For example, measurements may be made in a test well where the borehole diameter is larger than the tool, so that the tool and formation arrivals are well separated in time and velocity, so that the noise signature produced by a "clean" tool can be used as a calibration.

Downhole in the well, the sonic measurement tool receiving data representing measurements taken by pressure sensors of the sonic measurement tool; the tool modifies the measurements taken by the pressure sensor based at least in part on the compensation signal to attenuate noise generated by the tool.

According to further example embodiments, more robust baseline techniques may be used to attenuate tool-generated noise. In this manner, during the entire operation in which the sonic measurement tool is moved to different downhole locations and used to obtain measurements at those locations, the arrival time and characteristics of the noise generated by the tool remain relatively constant during the sensed acceleration, while the energy path experienced by the indirectly propagating energy from the sonic source changes. In this regard, at different downhole locations of the acoustic measurement tool, the energy propagating from the acoustic source may experience different mud types, formation types, borehole sizes, and the like. Based on this premise, the tool-generated noise can be characterized by more "conditions" and can be more accurately cancelled than, for example, estimating the tool-generated noise from a single shot at a particular depth for a sonic measurement tool.

Referring to FIG. 2C, according to an example embodiment, a technique 250 includes moving the sonic measurement tool downhole to a next downhole location where a pressure measurement is to be obtained (block 252). In accordance with the technique 250, data representing one or more measurements acquired by one or more tool motion sensors of a sonic measurement tool is received (block 254), and data representing one or more measurements acquired by one or more pressure sensors of the sonic measurement tool is received (block 256). In accordance with the technique 250, the tool-generated noise for each pressure sensor measurement is then determined in accordance with block 258. In response to determining (decision block 260) that the noise signature depth range generated by the tool is to be updated, the sonic measurement tool is moved (block 252) and blocks 254, 256, and 258 are repeated. Once all measurements have been taken, the technique 250 includes averaging or superimposing the noise generated by the determined tool, according to block 262. In this way, the superposition averages out the changing conditions experienced by the energy propagating through the fluid and surrounding formation at the different measurement locations of the tool 100. Thus, according to block 264, the pressure measurements may then be compensated based at least in part on the superposition of noise generated by the tool.

Referring to fig. 7, according to some embodiments, the data processing system 700 may be used for the purpose of determining/identifying tool-generated noise and compensating pressure measurements to attenuate tool-generated noise, as described herein. Depending on the particular implementation, the data processing system 700 may be part of a sonic measurement tool (as shown in FIG. 1, part of the controller 144 of the tool 100), may be part of a processing system disposed on the Earth, may be part of a processing system disposed remotely from a well, etc., depending on the particular implementation.

In general, the data processing system 700 may be a processor-based architecture formed from one or more actual physical machines made up of actual hardware 710 and machine-executable instructions 750 or "software".

According to some embodiments, hardware 710 may include one or more processors 714 (one or more Central Processing Units (CPUs), one or more CPU processing cores, etc.). Hardware 710 may further include memory 718, which may, for example, contain data representing acceleration measurements taken by an accelerometer of the sonic measurement tool, data representing measurements taken by other tool motion sensors of the sonic measurement tool, data representing pressure measurements taken by pressure sensors of the sonic measurement tool, parameters related to techniques that model noise generated by the tool based on sensed acceleration, and so forth. Memory 718 may further store executable instructions that, when executed by processor 714, cause processor 714 to perform some or all of one or more of the techniques described herein.

Generally, the memory 718 is a non-transitory memory that may be composed of, for example, semiconductor memory devices, memristors, magnetic memory devices, phase change memory devices, combinations of one or more of these memory technologies, depending on the particular implementation.

According to an example embodiment, the hardware 710 of the data processing system 700 may include various other components, such as one or more telemetry interfaces 720 (e.g., which communicate with the telemetry interface 141 of the tool 100), a display, and so forth. According to some embodiments, the display may display pressure measurements, tool-generated noise-compensated pressure measurements, acceleration measurements, and the like.

According to some embodiments, machine-executable instructions 750 may include, for example, instructions 754, which when executed by processor 714 may cause processor 714 to form a tool noise compensation engine that performs the following tasks: as described herein, time integration of acceleration measurements, tool arrival estimation, tool-generated noise compensation that converts sensed acceleration into a pressure signal, attenuation of tool-generated measurements to derive compensated pressure measurements, and the like. According to some embodiments, the instructions 754, when executed by the processor 714, may cause the processor 714 to form a tool-borne compensation to apply a tool-generated noise compensation signal derived from measurements taken in the test environment, as described herein. Further, according to an example embodiment, machine-executable instructions 750 may include one or more other sets of instructions that form various other components of data processing system 700, such as a set of instructions 758 that when executed cause processor 714 to form an operating system.

According to other example embodiments, all or part of the above processor-based architecture may be replaced by dedicated hardwired circuitry or Application Specific Integrated Circuits (ASICs). Accordingly, many embodiments are contemplated which are within the scope of the following claims.

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 this disclosure. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. 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. Applicants' explicit intent is to not cite any limitations of paragraph 6 of 35u.s.c. § 112 to any claims herein, except for those claims explicitly using "means for … …" and related functional limitations.