Detection and evaluation of ultrasonic subsurface backscatter

Abstract

A system for estimating a property of a region of interest includes an acoustic measurement device including a transmitter configured to transmit an acoustic signal having at least one selected frequency, the acoustic signal configured to penetrate a surface of a wellbore in a formation and produce internal diffuse backscatter from formation material behind the surface and within the region of interest, and a receiver configured to detect a return signal from the region of interest and produce return signal data. The system also includes a processing device configured to receive the return signal data, process the return signal data to identify internal diffuse backscatter data indicative of the internal diffuse backscatter, calculate one or more characteristics of the internal diffuse backscatter, and estimate the property of the region of interest based on the one or more characteristics of the internal diffuse backscatter.

Description

[0001] Cross Reference to Related Applications

[0002] This application claims the benefit of earlier filing date of U.S. Application Serial No. 62 / 932,215 filed November 7, 2019, the entire disclosure of which is incorporated herein by reference. BACKGROUND

[0003] Acoustic imaging includes various techniques used in the energy industry to measure or estimate formation properties. Such techniques include borehole acoustic imaging and borehole ultrasonic imaging of a borehole surface. For example, an ultrasonic imaging tool can be deployed in a borehole and used to obtain information about formation properties, such as lithology and fracture morphology, based on acoustic images of the borehole’s surface. SUMMARY

[0004] An embodiment of a system for estimating properties of a region of interest includes an acoustic measurement device configured to be disposed in a region of interest in a formation, the acoustic measurement device including a transmitter configured to transmit acoustic signals having at least one selected frequency configured to penetrate a surface of a borehole and produce internal diffuse backscatter from formation material behind the surface and within the region of interest, and a receiver configured to detect return signals from the region of interest and generate return signal data. The system also includes a processing device configured to receive the return signal data, process the return signal data to identify internal diffuse backscatter data indicative of the internal diffuse backscatter, calculate one or more properties of the internal diffuse backscatter, and estimate properties of the region of interest based on the one or more properties of the internal diffuse backscatter.

[0005] An embodiment of a method of estimating properties of a region of interest includes deploying an acoustic measurement device in a borehole within the region of interest in a formation, the acoustic measurement device including a transmitter and a receiver. The method also includes transmitting, by the transmitter, acoustic signals having at least one selected frequency configured to penetrate a surface of the borehole and produce internal diffuse backscatter from formation material behind the surface and within the region of interest, and detecting, by the receiver, return signals from the region of interest and generating return signal data. The method further includes processing, by a processing device, the return signal data to identify internal diffuse backscatter data indicative of the internal diffuse backscatter, calculating one or more properties of the internal diffuse backscatter, estimating properties of the region of interest based on the one or more properties of the internal diffuse backscatter, and controlling operational parameters of an energy industry operation based on the estimated properties. BRIEF DESCRIPTION OF DRAWINGS

[0006] The following description should not be read as limiting in any way. With reference to the drawings, like elements are numbered alike:

[0007] Figure 1 Embodiments of a system for evaluating or measuring a formation are depicted;

[0008] Figure 2A and Figure 2B Aspects of surface echoes of acoustic signals are depicted;

[0009] Figure 3 Aspects of internal diffuse backscatter from a region of interest of a formation are depicted;

[0010] Figure 4 Examples of acoustic return signals generated by reflections of acoustic measurement signals from a region of interest of a formation are depicted;

[0011] Figures 5A to 5D Examples of acoustic return signals and portions of the acoustic return signals associated with internal diffuse backscatter from a region of interest of a formation are depicted;

[0012] Figure 6 Examples of gated portions of acoustic return signals are depicted;

[0013] Figure 7 Examples of power spectra computed based on gated portions of Figure 6 are depicted;

[0014] Figure 8 Aspects of transmitting acoustic measurement signals and processing acoustic return signals to estimate non-linearity of a region of interest of a formation are depicted;

[0015] Figure 9 Aspects of transmitting acoustic measurement signals and processing acoustic return signals to estimate non-linearity of a region of interest of a formation are depicted;

[0016] Figure 10 Embodiments of a method of estimating at least one structural property of a region of interest of a formation are depicted; and

[0017] Figure 11 Examples of images of a region of interest generated using a method of Figure 10 are depicted. DETAILED DESCRIPTION

[0018] Systems, methods, and apparatuses for acoustic evaluation of properties of a resource-bearing formation or a region of a formation are provided herein. Embodiments of a system for evaluating a region of interest include at least one transmitter device configured to emit an acoustic signal (an acoustic measurement signal) having an ultrasonic frequency configured to penetrate a surface of a wellbore wall into an internal structure of a region of interest behind and / or around the wellbore. Acoustic return signals are generated by interaction with the environment surrounding the transmitter device.

[0019] In one embodiment, the system includes at least one receiver device configured to detect the acoustic return signals, generate return signal data, and process the return signal data to identify internal diffuse backscatter data indicative of acoustic internal diffuse backscatter (referred to as "internal diffuse backscatter") from internal structure features of the region of interest. The internal diffuse backscatter is used to estimate structural properties of the region of interest based on one or more characteristics of the internal diffuse backscatter.

[0020] Figure 1 Aspects of an exemplary embodiment of a system 10 for performing energy industry operations (e.g., subterranean operations and / or surveys), such as formation measurement and / or evaluation, oil and gas production, well completion, and stimulation, are shown. The system 10 includes a wellbore string 12 (such as a pipe string), coiled tubing, logging cable, or other carrier disposed in a wellbore 14 that is adapted to lower tools or other components through the wellbore or connect components to the surface. The wellbore 14 can be a vertical wellbore as shown, but is not so limited. The wellbore or portions thereof can be vertical, deviated, horizontal, and can have any selected path through a formation. Figure 1

[0021] In Figure 1 embodiments, the system 10 is configured as a logging system that includes a logging assembly or logging tool 16 disposed in the wellbore 14 via a logging cable 18. It is noted that the logging tool 16 is not so limited as the logging tool 16 can be configured for and deployed as part of any other type of system, such as a measurement-while-drilling (MWD) or logging-while-drilling (LWD) system in a drill string.

[0022] ​The surface deployment system includes a surface control unit 20 for controlling a drawworks 22 or other deployment device that lowers the wireline 18 from a drilling rig 24, platform, wellhead, and / or other surface structure. The system 10 can include various other components for facilitating measurement operations and / or facilitating other energy operations. For example, the system 10 can include a pumping device in fluid communication with a fluid tank or other fluid source for circulating fluid through the wellbore 14. The system 10 can also include a drilling assembly including a drill string, bottom hole assembly, and drill bit. The bottom hole assembly can include formation evaluation sensors (FE tools), a rotary steerable system, a mud motor, and / or a communication device (e.g., a mud pulse generator). The formation evaluation sensors can include acoustic sensors, resistivity sensors, gamma sensors, NMR sensors, sampling tools, pressure sensors, density sensors (nuclear), and / or other sensors or measurement devices. Thus, the measurement operations can be performed in conjunction with various energy industry operations such as drilling operations, stimulation operations (e.g., hydraulic fracturing and steam lift), completion operations, and production operations.

[0023] The logging tool 16 can be configured as a data acquisition tool as part of an acoustic measurement and / or monitoring system. The logging tool 16 can include a memory for storing acquired data within the logging tool 16 while the logging tool 16 is inside the wellbore 14. In alternative embodiments, the acquired data is stored in a memory at a surface location (e.g., inside the surface control unit 20). The logging tool 16 is disposed in the wellbore 14 and advanced to a selected location corresponding to a region of interest that includes at least a portion of the formation 26. The formation 26 can be a resource-bearing formation. The logging tool 16 is configured to emit acoustic measurement signals into the region of interest and the formation 26 to estimate properties thereof.

[0024] The logging tool 16 includes an acoustic measurement assembly having one or more acoustic monopole and / or multipole transmitters or transceiver devices 28 that emit ultrasonic and / or other acoustic signals as energy pulses (also referred to as “measurement signals” or “acoustic signals”). One or more acoustic receivers or transceiver devices 30 are disposed at the tool 16 for receiving return signals (also referred to as echoes) resulting from reflections and other interactions between the acoustic measurement signals and the environment surrounding the transmitter devices 28. The receiver devices 30 and transmitter devices 28 can be configured in any suitable manner that allows for ultrasonic measurements of the region of interest. For example, the acoustic measurement assembly can include a rotating acoustic transducer or a phased array transducer that rotates an ultrasonic beam of electricity. Rotation refers to rotation about a longitudinal axis of the tool 16 or rotation about a longitudinal axis of the wellbore 14.

[0025] The receiver devices 30 and the transmitter devices can be configured as pulse-echo transducers and / or a fire-and-receive transducer. When operating in pulse-echo mode, one transducer is used and is used as both a transmitter and a receiver (transceiver). When operating in fire-and-receive mode, one transducer is configured as a transmitter and transmits an acoustic measurement signal as an acoustic pulse (e.g., an ultrasonic pulse), while another transducer behaves as a receiver and collects return signals resulting from reflections of the acoustic pulse. The receivers can include piezoelectric receivers that use piezoelectric crystals. The transmitters can include piezoelectric transmitters that use piezoelectric crystals.

[0026] The acoustic measurement assembly can have various arrangements and numbers of transmitters and receivers. For example, the arrangement can include one or more transmitters that transmit multiple frequencies, and / or include multiple transducers arranged along the logging tool 16 to detect backscatter.

[0027] The logging tool 16 and / or other downhole components are in communication with one or more processing units or devices, such as a downhole electronics unit 32 that includes a processor and / or a surface processor, such as the surface control unit 20. The processing device(s) are configured to perform various functions, including receiving, storing, transmitting, and / or processing data from the tool 16. The processing devices include any number of suitable components, such as a processor, memory, communication devices, and a power source. Communication can be achieved through any suitable configuration, such as acoustic, electrical, or optical communication, wireless communication, and mud pulse telemetry. For example, communication is between devices included in the tool 16, between different tools in a bottom hole assembly in a drill string, or between the tool 16 and the surface control unit.

[0028] In drilling operations, in one embodiment, the drill string can be rotated by a top drive or rotary table drive. The drill string transmits rotation to the drill bit, which cuts formation material (e.g., rock) and propagates into the formation at a certain penetration rate. The tool 16 rotates with the rotating drill string and passes through the formation at a certain penetration rate while performing acoustic measurements at increasing depths (or decreasing depths when tripping out). Acoustic signals are emitted by the transmitters into the surrounding formation, and acoustic return signals are received by the receivers from the surface of the borehole and from regions of interest within the formation surrounding the borehole. The acquired logging data is typically time-based, as the downhole depth is typically unknown. The acquired logging data can be processed in the borehole by a processor in the tool 16. In alternative embodiments, the acquired data is transmitted to the surface by using mud pulse telemetry or alternative communication means (e.g., wired pipe), thereby providing real-time data. Once the acquired data is received at the surface, the acquired data can be further processed by a surface processor and depth assigned. Advanced techniques can allow for downhole depth attribution (downhole depth). Having depth-based data available downhole provides for automatic drilling control without the need for drilling control information transmitted from the surface to the bottom hole assembly in the borehole (downlink). With automatic drilling control, automated geosteering for optimal well placement downhole becomes feasible.

[0029] In one embodiment, the system 10 is configured to image or otherwise estimate properties of structural features of a region of interest that is remote from and behind the surface of the borehole 14. Such features are referred to herein as “internal structural features.” The internal structural features can be different from other features in the volume surrounding the logging tool 16, such as features of the borehole fluid, features of components disposed in the borehole 14, fluid properties of the formation, and features of the borehole surface (e.g., the wall of an open borehole or casing or). The logging tool 16 is configured to estimate the internal structural features based on internal diffuse backscattering (internal diffuse backscattering) of acoustic signals (e.g., ultrasonic signals) within the region of interest that is remote from and behind the surface of the borehole 14. The term “remote from and behind the surface of the borehole” refers to acoustic signals from a location or region corresponding to a depth of investigation (DOI) into the formation surrounding the borehole 14. A typical DOI can be in a range from about a few centimeters to about a meter. In some embodiments, the DOI can be from about 1 cm to about 10 cm. In other embodiments, the DOI can be from about 1 cm to about 5 cm. In further embodiments, the DOI can be from about 1 cm to about 3 cm. The DOI is measured in a direction perpendicular to the longitudinal axis of the tool 16, or alternatively, in a direction perpendicular to the longitudinal axis of the borehole 14.

[0030] As noted above, in one embodiment, the system 10 is configured to image or estimate internal structural features of the region of interest using ultrasonic or ultrasonic frequencies. Ultrasonic frequencies can be classified as frequencies above about 20 kHz. In contrast to sonic frequencies below 20 kHz, ultrasonic frequencies allow for detection and evaluation of relatively small structural features (e.g., microstructure). Small structural features can refer to features in the centimeter range. In some embodiments, small structural features can refer to features in the millimeter range. In further embodiments, small features can refer to features in the micron range.

[0031] For example, at sonic frequencies below 20 kHz and wavelengths greater than 175 mm, the granular structure of the rock in the formation effectively presents a continuous, homogeneous wave medium, where the primary source of coherent wave attenuation is dissipative. Sonic wave instruments using such frequencies measure sonic velocity, attenuation, and allowed acoustic modes to characterize the formation with a resolution of about 1000 mm, but do not address microstructural features of the rock. As used herein, the term "rock" refers to rock material in the formation material.

[0032] In contrast, the transmitter device 28 is configured to transmit acoustic signals at ultrasonic frequencies that produce internal diffuse backscatter. The ultrasonic frequencies are selected to have a favorable value of the parameter kd, which is the product of the wave number k of the acoustic signal and the grain size d (e.g., the size of the particles or the size of the pores in the formation material). In one embodiment, the frequency is selected based on the grain size characteristics of the formation such that kd is less than about 2.

[0033] For example, the transmitter device 28 is configured to transmit acoustic signals having the following attributes: having an ultrasonic frequency greater than about 500 kHz, having one or more wavelengths on the order of about 7 mm, and having a value of kd of about 0.2250. In this example, the ultrasonic wavefield (acoustic signal) interacts with the granular microstructure of the rock such that the wave attenuation (acoustic signal attenuation) is enhanced by diffuse scattering. This allows for characterization of the rock microstructure by measuring diffuse ultrasonic wavefield characteristics from within the rock. In one embodiment, the transmitter device 28 is configured to transmit acoustic signals having a frequency between about 250 kHz to about 1 MHz, which has been found to be practical for tools operating in drilling fluids with high attenuation.

[0034] In addition to transmitting ultrasonic acoustic signals having the above-mentioned attributes, the logging tool 16 is configured to detect acoustic return signals and process the acoustic return signals to identify or isolate and evaluate components of the return signals that represent internal diffuse backscatter. As discussed further below, internal diffuse backscatter is one of many components of the acoustic return signals.

[0035] In addition to internal diffuse backscatter, the return signal includes reflected signals (echoes) from the surface of the wellbore 14, including specular surface echoes and diffuse surface echoes. Existing pulsed echo wireline and LWD ultrasonic open-hole imaging instruments can detect the surface of the wellbore 14 by capturing such surface reflected signals and recording their amplitudes and travel times.

[0036] Figure 2A and Figure 2B Aspects of the specular echoes and diffuse surface echoes resulting from the acoustic measurement signal 40 are shown, respectively. As shown, the surface specular echoes 42 originate from surface features that are relatively large and / or regularly shaped with smooth surfaces. These echoes are relatively high in intensity and angularly dependent. The diffuse surface echoes 44 originate from features that are relatively small, weakly reflective, and / or irregularly shaped, and are less angularly dependent and lower in intensity. Specular echoes are also referred to as specular reflections. Diffuse surface echoes are also referred to as diffuse surface reflections.

[0037] Specular reflections are a function of the contrast between the wellbore fluid and the formation acoustic impedance, while diffuse surface reflections are dominated by the wellbore surface texture. The resulting amplitude images can indicate both the bedding and fractures crossing the wellbore as well as the surface roughness of the wellbore.

[0038] The receiver device 30, which includes a detector and a processing device (which can be incorporated with the detector within the receiver device 30 or disposed remotely from the detector), is configured to process the return signal data to distinguish or separate data indicative of surface echoes from data indicative of internal diffuse backscatter. An example of internal diffuse backscatter is shown at Figure 3 In this example, the return signal 46 generated in accordance with the embodiments described herein includes internal diffuse backscatter 48 generated within the bulk of the formation region due to reflections caused by the particles, voids, and other microstructure 50. The term internal diffuse backscatter is also referred to as internal diffuse reflection echoes or internal diffuse reflections. The detector includes a transducer. The transducer can include a piezoelectric crystal.

[0039] The return signal 46 can be gated and / or otherwise processed to separate the component representative of internal diffuse backscatter. In one embodiment, the return signal 46 is gated by selecting a particular length of time associated with the internal diffuse backscatter. The gating is controlled by the processing device.

[0040] This is shown at Figure 4 Figure 4 ​An example of an acoustic measurement signal comprising an ultrasonic time-domain (Tx) signal pulse 52 is shown, which produces a backscattered signal or acoustic return signal 54 after interaction with the formation volume surrounding the well tool. The measurement signal can have a single frequency or multiple frequencies. The return signal 54 is shown as a time-domain waveform having a first portion 56 primarily caused by surface reflections and a second portion 58 primarily caused by internal diffuse backscattering. By properly gating the waveform (i.e., isolating a selected length of the time axis), the second portion 58 of the waveform indicative of internal diffuse backscattering (subsurface backscattering) can be identified. This portion can then be evaluated to estimate one or more structural features of the region of interest.

[0041] Figures 5A to 5D An example of an acoustic return signal 54 produced by transmitting a single ultrasonic pulse toward a formation material having different microstructures is shown. In Figure 5A the acoustic return signal 54 is taken from a thick zero-porosity reflector. The signal 54 contains only surface reflections, and thus is dominated by a return pulse having little or no subsequent wave energy.

[0042] Figure 5B A return signal 54 from a low-density material is shown. In this example, the signal includes a high-energy initial portion including an initial pulse corresponding to a surface reflection and a different trailing portion corresponding to internal diffuse backscattering from internal structural features in the region of interest. Figure 5C and Figure 5D Return signals 54 from a medium-density material and a high-density material are shown, respectively.

[0043] As shown above, by isolating (gating) and analyzing the trailing portion of an ultrasonic acoustic return signal as discussed herein, internal structural features of a formation material, such as density and porosity, can be estimated.

[0044] Identifying and analyzing internal diffuse backscattering can be performed in a variety of ways. Techniques for isolating and characterizing internal diffuse backscattering are described below. Each technique includes processing the return signal to estimate a characteristic or property of the internal diffuse backscattering, and then associating that characteristic or property with one or more internal structural features of the region of interest, such as density, porosity, and / or brittleness.

[0045] Referring to Figure 6In one embodiment, the system gates and analyzes the acoustic return signal to estimate the attenuation characteristics of the acoustic return signal. In this embodiment, multiple segments or portions of the tail portion of the time domain return signal are selected and compared to estimate the attenuation. For example, the time domain return signal 60 is gated by selecting two portions following the initial portion with the high energy return pulse. The two portions are denoted as a first time domain return signal segment s1 and a second time domain return signal segment s2. The gating interval for s1 is denoted by τ W and the gating interval for s2 is denoted by τ st . As discussed further below, these portions are compared in different ways to estimate the attenuation characteristics of the acoustic return signal, which can then be used to estimate one or more structural properties of the region of interest. Figure 6 The time interval τ d includes the strong signal of the transducer response, which is a characteristic of the particular transducer (or particular emitter). In order to extract information of the internal structure features from the acoustic return signal in the processing steps, it is necessary to separate the transducer response from the tail portion (s1 and s2) of the acoustic return signal. The separation is achieved by processing only the return signal in the time intervals τ W and τ st , where the time interval τ S is between τ W and τ st . The time interval τ d can be obtained by a reference measurement using a perfect or near perfect uniform reflector, such as glass or steel.

[0046] In one embodiment, the receiver device 30 estimates the attenuation value by performing a spectral difference attenuation analysis. The result of the analysis is an attenuation coefficient a, which can be related to the formation structural properties.

[0047] The analysis includes selecting two segments of the acoustic return signal, which are associated with different spatial distances from the wellbore surface in the region of interest. For example, once the time-based return signals of the segments s1 and s2 are selected, the power spectrum as a function of frequency (f) is calculated for each segment s1 and s2 using a Fourier transform. The power spectrum of segment s1 is denoted as P1(f), and the power spectrum of segment s2 is denoted as P2(f). An attenuation coefficient function a(f) is estimated based on the following equation:

[0048]

[0049] where Δz is the difference between the distance from the transmitter to the first return signal segment s1 (along the direction of the ultrasound signal or longitudinal direction) and the distance from the transmitter to the second return signal segment s2. The attenuation coefficient a is calculated as the slope of the best fit line of the coefficient function a(f). The distance z is in meters (m) and is defined as the propagation distance of the acoustic signal within the time interval. Δz is the difference between the distance from the transmitter to the first return signal segment s1 and the distance from the transmitter to the second segment s2. Δz can be calculated by multiplying the time difference between the first return signal segment s1 and the second return signal segment s2 by the speed of sound. The time difference is defined between the representative time within the time length τ W associated with the first return signal segment s1 and the representative time within the time length τ st associated with the second return signal segment s2. According to embodiments of the present disclosure, the representative times within the time lengths associated with the first and second return signal segments can, without limitation, be the center times of the selected time lengths (τ W and τ st ) of the gated return signal. Other definitions of the representative times are possible and do not change equation (1).

[0050] Figure 7 An example of the power spectrum at different distances z that can be calculated from the return signal 60 is shown. As shown, any number n of return signal segments (s1, s2, s3, sn) and associated power spectra (P1, P2, P3, P n ) can be used to calculate the attenuation coefficient. In some embodiments, the use of power spectra can be replaced with the use of log power spectra. The power spectrum or log power spectrum can also be referred to as the frequency spectrum. Using the power spectrum or log power spectrum, all equations disclosed herein hold true.

[0051] In one embodiment, the receiver device 30 estimates the attenuation of the acoustic return signal by estimating the spectral centroid shift and / or the apparent spectral centroid shift of the power spectrum. In this embodiment, the receiver device 30 estimates the spectral centroid, which is calculated in a similar manner to the energy or mass center calculation. The spectral centroid is calculated as the spectral centroid frequency (f c ), which corresponds to the weighted average of each frequency (fi) in the return signal segments (si) of the signal 60. For example, the spectral centroid frequency (f c ) is calculated as follows:

[0052]

[0053] where fi is the center frequency between frequencies i1 and i2, P(fi) is the power spectrum at a given frequency fi, and Δf is the difference between the lowest and highest frequencies.

[0054] To obtain the attenuation shift (a), the spectral centroid frequency of the second segment (f c2 ) is subtracted from the spectral centroid frequency of the first segment (f c1 ). For example, the apparent spectral centroid shift attenuation is calculated as follows:

[0055]

[0056] where s 2 is the spectral bandwidth (variance) of the transducer used to measure the return signal. In some embodiments, s 2 is the spectral bandwidth of the receiver or the spectral bandwidth of the transmitter.

[0057] Alternatively, instead of f c1 taken from a segment or window corresponding to surface specular echoes, the spectral centroid shift attenuation can be calculated similarly to the apparent spectral centroid shift attenuation.

[0058] In one embodiment, the receiver device 30 is configured to estimate an internal diffuse backscatter difference parameter, which is used to estimate structural properties of the region of interest. In this embodiment, power spectra are obtained from two different gated portions of the signal (e.g., si and s2). The power spectra (in dB) are subtracted to obtain an internal diffuse backscatter difference spectrum D(f).

[0059] Statistical properties of the difference spectrum can be calculated to estimate structural properties. For example, by frequency-averaging D(f) over an analysis bandwidth, the mean of the internal diffuse backscatter difference spectrum (MBD) is obtained. By measuring the frequency slope of D(f) over the same bandwidth, the slope of the internal diffuse backscatter difference spectrum (SBD) is obtained. The power spectra Pi(f) and P2(f) from the first and second gated portions of the internal diffuse backscatter signal (return signal segments) are converted to decibels and subtracted to obtain the difference spectrum D(f):

[0060]

[0061] In one embodiment, the entropy characteristics of the signal are analyzed to estimate structural properties. Entropy can be used to analyze the raw radio frequency (RF) ultrasound signal to quantitatively characterize changes in the microstructure of the scattering medium. Such characteristics include, for example, weighted entropy and spectral entropy. In acoustic logging, the term RF signal or RF waveform refers to the time-domain signal or time-domain waveform before any type of filter (envelope filter, Kalman filter, etc.) is applied to the time-domain signal or time-domain waveform.

[0062] In one embodiment, to increase the sensitivity of the receiver device 30, the weighted entropy can be estimated. The weighted entropy can be expressed as:

[0063]

[0064] where y is the amplitude of the time series data, w(y) is the probability distribution function (PDF) of the time series data (raw ultrasound wave RF data), and y min and y max denote the minimum and maximum values of the time series data. The PDF can be expressed as

[0065]

[0066] where a n is a series of Fourier coefficients, and N co denotes a finite number of terms in the series. Weighting refers to the selection of the amplitude resolution Ay and N co to obtain the best sensitivity in detecting the ultrasound scattering concentration change. For example, for N co = [0, 2, 4, 8, 16, 32, 64, 128] and Ay = [0.01, 0.02, 0.04,... 0.25], Ay of 0.02 for the normalized RF amplitude is selected, and Nco is 64.

[0067] In one embodiment, the receiver device computes the spectral entropy (S) of the return signal. The power spectrum of the return signal is computed, and the power spectrum is normalized to compute the normalized power spectrum P n (fi). The normalized power spectrum is computed by setting a normalization constant C n such that the sum of the normalized power spectrum over a selected frequency region [fl, f2] equals 1:

[0068]

[0069] The spectral entropy S corresponding to the frequency range [fl, f2] is computed as the sum:

[0070]

[0071] The entropy value S is normalized to a range between 1 (maximum irregularity) and 0 (perfect regularity). The value is divided by a factor log(N[fl, f2]), where N[fl, f2] equals the total number of frequency components in the range [fl, f2]:

[0072]

[0073] The normalized spectral entropy S N may be expressed in various ways. For example, the normalized spectral entropy S NIt can be the total spectral entropy (entropy of the entire return signal), the internal diffuse backscatter spectral entropy (entropy of the entire internal diffuse backscatter signal), and / or the internal diffuse backscatter difference entropy (difference between entropies calculated for different gated portions of the return signal).

[0074] Figure 8 and Figure 9 Additional examples of signal characteristics that can be calculated and used to estimate structural properties of a region of interest are shown. In these examples, the receiver device 30 calculates a linear index of the region or other value indicative of non-linearity by estimating the difference between two return pulses or echoes, where the pulses are reversed with respect to each other. The reversed return pulses can be generated by, for example, using a reversed frequency chirp excitation or using a wide transmit pulse for transmission.

[0075] As shown in FIG. 7, the transmitter device 28 can be excited using a wide excitation pulse 70, which results in two reversed pulses Al and A2. The pulses are time synchronized using the first rising edge of the return pulse Al and the first falling edge of the pulse A2. If the medium (region of interest) that produces internal diffuse backscatter is linear, the sum of the two pulses will be zero when time synchronized and summed. However, if the medium is non-linear, the pulses will not cancel out. Thus, the relative non-linearity of the rock sample can be detected. Figure 8 In the example of FIG. 7, a non-linear value or index is estimated by calculating the sum of the time synchronized return pulses Al and A2. The non-linearity can be estimated by detecting internal diffuse backscatter from within the rock after exciting the transducer with a reversed or half-amplitude transmit pulse.

[0076] Figure 8 In the example of FIG. 8, a first pulse 72 and a second pulse 74 are transmitted. The second pulse 74 is a half-amplitude replica of the first pulse 72. These pulses produce a first return pulse 76 (first return signal segment) and a second return pulse 78 (second return signal segment), which can be time synchronized. The second return pulse 78 is multiplied by two and added to the first return pulse 76.

[0077] If the region of interest is linear (e.g., a high density rock), the structure of the region responds the same to positive and negative pressures and reflects back equal but opposite echoes (first return signal segment and second return signal segment), which will cancel out. Any non-linear target (such as a low density rock with fluid-filled pores) responds with a higher order harmonic response with different phases that add constructively. Thus, this sum provides a non-linear index that can be correlated to a characteristic such as density or porosity. Figure 9

[0078]

[0079] ​​​As noted above, the transmitter device 28 can be configured to transmit acoustic measurement signals having a plurality of frequencies. In one embodiment, the structural properties of the region of interest can be estimated by comparing the return signals generated by the different frequency acoustic measurement signals. For example, it has been found that 400 kHz to 2 MHz ultrasound propagation in sandstone rock is frequency dependent, and the amplitude of the internal diffuse backscatter will change when the value of kd varies around 0.2. The entropy of the internal diffuse backscatter signal at two frequencies (e.g., 500 and 750 kHz) can be measured as a means of detecting physical differences in the rock matrix.

[0080] For example, the entropy of the return signal associated with a first frequency is compared to the entropy of the return signal associated with a second frequency, and the difference is associated with a structural characteristic, such as density and porosity. Furthermore, since the intervening drilling mud can have a significant effect on the internal diffuse backscatter signal, operating at two frequencies provides a means of correcting for this effect.

[0081] The embodiments described herein are not limited to estimating internal structural characteristics, as the excitation, detection, and processing methods described herein can be used for other purposes. For example, by gating portions of the return signal received before the surface reflection pulse, the return signal data can be used to detect non-linearities of the wellbore fluid. For example, the signal data before the surface pulse can be gated and analyzed similar to that discussed above to estimate a non-linearity index, which can be associated with fluid characteristics, such as the presence of mud cuttings and gas. In another embodiment, similar detection methods can be used to assess the properties (e.g., density, porosity) of cement behind the casing.

[0082] Figure 10 A method 100 for estimating structural properties of a formation and / or performing aspects of energy industry operations is shown. The method 100 includes one or more stages 101-105. The method 100 is described herein in connection with a processor that receives signals (e.g., the receiver device 30 and / or the surface control unit 20), but the method is not limited to this and can be performed in connection with any number of processing devices. In one embodiment, the stages 101-105 are performed in the order described, although some steps can be performed in a different order or one or more steps can be omitted.

[0083] In a first stage 101, an imaging tool or logging tool, such as the logging tool 16, is disposed in a wellbore in a formation. The logging tool 16 can include separate transmitter devices 28 and receiver devices 30 (which can be located in the same location or at different locations along the wellbore), or a single transducer device for transmitting and detecting acoustic signals.

[0084] In one embodiment, receiver device 30 is a phase-insensitive transducer that detects the total amount of backscattered energy (return signal) without signal degradation due to phase cancellation and with reduced sensitivity to the angle of incidence. In one embodiment, receiver device 30 and transmitter device 28 are configured as multi-stage transducers to eliminate stick-slip and stick-pull image artifacts. Such transducers are discussed in more detail in U.S. Patent No. 9,766,363B2, granted September 19, 2017, the entire contents of which are incorporated herein by reference.

[0085] In the second stage 102, an ultrasonic acoustic measurement signal comprising a series of time-domain pulses is transmitted to a region of interest, such as a region of resource-bearing formations or other formations. One or more transmitters (such as one or more transmitter devices 28 or any other suitable phased array transmitter or rotating transmitter) can be used to transmit the acoustic measurement signal. The measurement signal includes one or more frequencies selected to penetrate the surface of the wellbore and into the internal structure of the region of interest, generating a return signal that includes a component corresponding to diffuse backscattering from the interior. In one embodiment, the one or more transmitter devices may utilize coded excitation to increase ultrasonic penetration within the rock to enhance the signal-to-noise ratio of the backscattering.

[0086] A detector (such as a detector in one or more receiver devices 30) detects the acoustic return signal.

[0087] In the third stage 103, the returned signal is processed by gating it to distinguish or separate portions of the returned signal associated with internal diffuse backscattering. For example, multiple portions of the returned signal are gated and compared with estimated signal characteristics such as attenuation, entropy, linearity, and frequency difference, as discussed above.

[0088] In one implementation, an image log is generated based on the estimated characteristics. Figure 11 An example of image log 110 is shown. Image log 110 may include two-dimensional and / or three-dimensional components. For example, image log 110 includes a first image layer 112 and a second image layer 114, which show surface reflection characteristics as a function of depth (along the length of the borehole) and angular position. A third image layer 116 shows internal diffuse backscattering characteristics (e.g., attenuation value, linear exponent) that can be associated with structural features.

[0089] Similarly, Figure 11 As shown, the image log can be converted into a three-dimensional image 118, which displays the features of the wellbore surface, the wellbore interior, and the internal structure of the region of interest. Additional images can be generated, such as a two-dimensional image 120 in a plane orthogonal to the wellbore axis.

[0090] In a fourth stage 104, one or more structural features of the region of interest are estimated based on one or more of the above-described internal diffuse backscatter signal characteristics. For example, if the signal characteristics and / or image data include values or distributions of attenuation or linearity, such characteristics and / or image data can be correlated to structural features such as rock density, porosity, permeability, and brittleness.

[0091] In one example, signal characteristics with absolute values can be directly correlated to values of density and porosity, and characteristics with statistical values can be correlated to properties such as permeability and brittleness.

[0092] In a fifth stage 105, the images and data representing structural properties are used to facilitate and / or control other operations such as modeling and planning, drilling, stimulation, and production. For example, the image log data can be displayed to an operator or input to another process or program that changes or controls operational parameters of energy industry operations based on the image log data.

[0093] For example, the images and data can be used to generate or develop mathematical models such as geologic models, facies models, structural models, fracturing models, production models, and drilling navigation models. They can also be used in conjunction with other measurements such as surface and vertical wellbore seismic results, active and microseismic interpretation results, and reservoir characterization results using other measurement techniques (e.g., resistivity, porosity, gamma ray, density, neutron, and other measurements). Additionally, the structural data and images can be used to improve interpretation results for techniques such as surface seismic and microseismic measurement techniques.

[0094] Other operations that can be improved using the structural data and images include drilling operations, which can be directed based on structural properties, for example, to target areas having high hydrocarbon concentrations. Additionally, stimulation planning and operations can be enhanced, for example, by placing perforations and fracturing locations in hot spots or other areas where structural data can provide higher production. For example, an operator or processing device such as control unit 20 can manipulate or otherwise control the direction of a drilling assembly and / or control other parameters such as fluid flow rate and weight on bit based on the estimated structural features. In another example, control unit 20 or other processing device can select, control, or adjust one or more locations at which production components (e.g., sand screens) or stimulation components (e.g., perforation and / or fracturing assemblies) are to be positioned to maximize or otherwise increase the production capacity of a wellbore.

[0095] The implementation schemes described herein offer numerous advantages. For example, the various features and implementation schemes described herein are used to improve the performance of acoustic measurement tools in logging cables and LWD operations. Existing pulse-echo logging cables and LWD ultrasonic open-well imaging instruments detect the wellbore surface by capturing echoes from the wellbore wall surface and recording their amplitude and propagation time, but do not assess diffuse backscattering from within the formation to detect the internal microstructure of the rock formation surrounding the wellbore.

[0096] In addition to providing additional structural information, the implementation described herein can significantly improve the spatial resolution of these rock properties compared to the spatial resolution currently available from existing wellbore cores and acoustic tools, due to the relatively small ultrasonic point size and increased depth of field capability.

[0097] The following are some of the aforementioned publicly disclosed implementation schemes:

[0098] Implementation Scheme 1: A system for estimating properties of a region of interest, the system comprising: an acoustic measurement device configured to be disposed in the region of interest within a formation, the acoustic measurement device including a transmitter and a receiver, the transmitter being configured to emit an acoustic signal having at least one selected frequency, the acoustic signal being configured to penetrate the surface of a wellbore and generate internal diffuse backscattering from formation material behind the surface and within the region of interest, the receiver being configured to detect a return signal from the region of interest and generate return signal data; and a processing device configured to receive the return signal data, the processing device being configured to: process the return signal data to identify internal diffuse backscattering data indicative of the internal diffuse backscattering; calculate one or more characteristics of the internal diffuse backscattering; and estimate the properties of the region of interest based on the one or more characteristics of the internal diffuse backscattering.

[0099] Implementation Scheme 2: The system according to any of the foregoing implementation schemes, wherein the attribute is selected from at least one of the density, porosity, permeability and brittleness of the formation material constituting the region of interest.

[0100] Implementation Scheme 3: The system according to any of the foregoing embodiments, wherein the processing device is configured to identify internal diffuse backscattering data by gating a portion of the return signal data that appears after one or more initial pulses in the return signal data associated with surface reflection.

[0101] Implementation Scheme 4: The system according to any of the foregoing embodiments, wherein the processing device is configured to gate a first portion and a second portion of the return signal data that appear after the one or more initial pulses.

[0102] Implementation Scheme 5: A system according to any of the preceding embodiments, wherein the processing device is configured to calculate a first power spectrum of the first portion and a second power spectrum of the second portion, and to calculate an attenuation value based on the difference between the first power spectrum and the second power spectrum, the attenuation value being associated with the attribute.

[0103] Implementation Scheme 6: A system according to any of the foregoing embodiments, wherein the processing device is configured to calculate a first spectrum of the first portion and a second spectrum of the second portion, estimate a first spectral centroid frequency of the first spectrum and a second spectral centroid frequency of the second spectrum, and calculate a spectral centroid frequency offset based on the difference between the first spectral centroid frequency and the second spectral centroid frequency, the spectral centroid frequency offset being associated with the attribute.

[0104] Implementation Scheme 7: A system according to any of the preceding embodiments, wherein the processing device is configured to calculate a probability distribution function of a gating portion of the returned signal data, and estimate an entropy value based on the probability distribution function, the entropy value being associated with the attribute.

[0105] Implementation Scheme 8: The system according to any of the foregoing embodiments, wherein the acoustic signal comprises at least two pulses configured to be reflected from a structure within the region of interest as at least a first return pulse and a second return pulse, the first return pulse being reversed relative to the second return pulse.

[0106] Implementation Scheme 9: A system according to any of the foregoing embodiments, wherein the processing device is configured to synchronize the first return pulse and the second return pulse in time, and to estimate the nonlinearity of the region of interest based on the sum of the amplitudes of the first return pulse and the second return pulse, the nonlinearity being associated with the attribute.

[0107] Implementation Scheme 10: A system according to any of the preceding embodiments, wherein the acoustic signal includes a first acoustic signal having a first frequency and a second acoustic signal having a second frequency, and the processing device is configured to estimate the difference between the energy of the internal diffuse backscattering of the first acoustic signal and the energy of the internal diffuse backscattering of the second acoustic signal.

[0108] Implementation Scheme 11: A method for estimating the properties of a region of interest, the method comprising: deploying an acoustic measurement device in a wellbore within the region of interest in a formation, the acoustic measurement device including a transmitter and a receiver; transmitting an acoustic signal having at least one selected frequency by the transmitter, the acoustic signal being configured to penetrate the surface of the wellbore and generate internal diffuse backscattering from formation material behind the surface and within the region of interest; detecting a return signal from the region of interest by the receiver and generating return signal data; processing the return signal data by a processing device to identify internal diffuse backscattering data indicative of the internal diffuse backscattering; calculating one or more characteristics of the internal diffuse backscattering; estimating the properties of the region of interest based on the one or more characteristics of the internal diffuse backscattering; and controlling operating parameters of energy industry operations based on the estimated properties.

[0109] Implementation Scheme 12: The method according to any of the preceding implementation schemes, wherein the attribute is selected from at least one of the density, porosity, permeability and brittleness of the formation material in the region of interest.

[0110] Implementation Scheme 13: The method according to any of the preceding embodiments, wherein processing the returned signal data includes gating a portion of the returned signal data that appears after one or more initial pulses in the returned signal data associated with surface reflection.

[0111] Implementation Scheme 14: The method according to any of the preceding embodiments, wherein processing the return signal data includes gating a first portion of the return signal data that occurs after the one or more initial pulses and a second portion of the return signal data.

[0112] Implementation Scheme 15: According to the method of any of the preceding embodiments, wherein the one or more characteristics of the internal diffuse backscattering include an attenuation value, the attenuation value being calculated by: calculating a first spectrum of the first portion and a second spectrum of the second portion, and calculating the attenuation value based on the difference between the first spectrum and the second spectrum.

[0113] Implementation Scheme 16: According to the method of any of the preceding embodiments, wherein the one or more characteristics of the internal diffuse backscattering include an attenuation value, the attenuation value being calculated by: calculating a first spectrum of the first portion and a second spectrum of the second portion, estimating a first spectral centroid frequency of the first spectrum and a second spectral centroid frequency of the second spectrum, and calculating a spectral centroid frequency offset based on the difference between the first spectral centroid frequency and the second spectral centroid frequency.

[0114] Implementation Scheme 17: The method according to any of the preceding embodiments, wherein the one or more characteristics of the internal diffuse backscattering include an entropy value, the entropy value being calculated by computing a probability distribution function of the gated portion of the returned signal data.

[0115] Implementation Scheme 18: The method according to any of the preceding embodiments, wherein the acoustic signal comprises at least two pulses, the at least two pulses being configured to be reflected from the structure of the region of interest as at least a first return pulse and a second return pulse, the first return pulse being reversed relative to the second return pulse.

[0116] Implementation Scheme 19: The method according to any of the preceding embodiments, wherein processing the returned signal data includes synchronizing the first returned pulse and the second returned pulse in time, and calculating the one or more characteristics of the internal diffuse backscattering includes estimating the nonlinearity of the region of interest based on the sum of the amplitudes of the first returned pulse and the second returned pulse.

[0117] Implementation Scheme 20: The method according to any of the preceding embodiments, wherein the acoustic signal includes a first acoustic signal having a first frequency and a second acoustic signal having a second frequency, and calculating the one or more characteristics of the internal diffuse backscattering includes estimating the difference between the energy of the internal diffuse backscattering of the first acoustic signal and the energy of the internal diffuse backscattering of the second acoustic signal.

[0118] In the context of describing the invention (particularly in the context of the appended claims), the terms “an,” “a,” and “the,” and similar designations, should be interpreted to cover both the singular and plural, unless otherwise specified herein or clearly contradicted by the context. Furthermore, it should be noted that the terms “first,” “second,” etc., used herein do not indicate any order, quantity, or importance, but are used to distinguish one element from another. The modifier “about,” used in conjunction with quantity, includes the stated value and has a meaning determined by the context (e.g., it includes the degree of error associated with a particular quantity of measurement).

[0119] The teachings of this disclosure can be applied to a variety of well operations. These operations may involve treating a formation, fluids residing in the formation, the wellbore, and / or equipment within the wellbore, such as production tubing, with one or more treatment agents. Treatment agents can be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Exemplary treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, corrosion inhibitors, binders, permeability modifiers, drilling mud, emulsifiers, demulsifiers, tracers, flow improvers, etc. Exemplary well operations include, but are not limited to, hydraulic fracturing, production enhancement, tracer injection, cleaning, acidizing, steam injection, water injection, cementing, etc.

[0120] Although the invention has been described with reference to one or more exemplary embodiments, those skilled in the art will understand that various changes can be made and equivalents can be substituted for elements therein without departing from the scope of the invention. Furthermore, many modifications can be made to adapt particular situations or materials to the teachings of the invention without departing from the basic scope of the invention. Therefore, it is contemplated that the invention is not limited to the specific embodiments disclosed as the best mode contemplated for carrying out the invention, but rather that the invention will include all embodiments falling within the scope of the claims. Additionally, exemplary embodiments of the invention have been disclosed in the drawings and detailed descriptions, and although specific terminology has been used, it is used in a general and descriptive sense only, and not for limiting purposes, unless otherwise specified, and therefore the scope of the invention is not limited thereto.

Claims

1. A system for estimating attributes of a region of interest, the system comprising: An acoustic measurement device is configured to be disposed in a region of interest in a formation. The acoustic measurement device includes a transmitter and a receiver. The transmitter is configured to emit an acoustic signal having at least one selected frequency. The acoustic signal is configured to penetrate the surface of the wellbore and generate internal diffuse backscattering from the formation material behind the surface and in the region of interest. The receiver is configured to detect the return signal from the region of interest and generate return signal data. and A processing device configured to receive the returned signal data, the processing device being configured to: process the returned signal data to identify internal diffuse backscattering data indicative of the internal diffuse backscattering by gating a portion of the returned signal data that appears after one or more initial pulses in the returned signal data associated with surface reflection; Calculate the probability distribution function of the gating portion of the returned signal data, and estimate the entropy value based on the probability distribution function; And to estimate the properties of the region of interest based on the estimated entropy value.

2. The system of claim 1, wherein the property is selected from at least one of the density, porosity, permeability, and brittleness of the formation material in the region of interest.

3. The system of claim 1, wherein the processing means is configured to gate a first portion and a second portion of the return signal data that occur after the one or more initial pulses.

4. The system of claim 3, wherein the processing device is configured to calculate a first spectrum of the first portion and a second spectrum of the second portion, estimate a first spectral centroid frequency of the first spectrum and a second spectral centroid frequency of the second spectrum, and calculate a spectral centroid frequency offset based on the difference between the first spectral centroid frequency and the second spectral centroid frequency, the spectral centroid frequency offset being associated with the attribute.

5. The system of claim 1, wherein the acoustic signal comprises a first acoustic signal having a first frequency and a second acoustic signal having a second frequency, and the processing means is configured to estimate the difference between the energy of the internal diffuse backscattering of the first acoustic signal and the energy of the internal diffuse backscattering of the second acoustic signal.

6. A method for estimating the attributes of a region of interest, the method comprising: An acoustic measurement device, comprising a transmitter and a receiver, is deployed in a wellbore within the region of interest in the formation. An acoustic signal with at least one selected frequency is emitted by the transmitter, the acoustic signal being configured to penetrate the surface of the wellbore and generate internal diffuse backscattering from the formation material behind the surface and in the region of interest; The receiver detects the return signal from the region of interest and generates return signal data; The returned signal data is processed by a processing device to identify internal diffuse backscattering data indicative of the internal diffuse backscattering by gating a portion of the returned signal data that appears after one or more initial pulses in the returned signal data associated with surface reflection; Calculate the probability distribution function of the gating portion of the returned signal data, and estimate the entropy value based on the probability distribution function; The properties of the region of interest are estimated based on the estimated entropy value; as well as The estimated properties are used to control the operating parameters of the energy industry.

7. The method of claim 6, wherein the property is selected from at least one of the density, porosity, permeability, and brittleness of the formation material in the region of interest.

8. The method of claim 6, wherein the acoustic signal comprises a first acoustic signal having a first frequency and a second acoustic signal having a second frequency, and estimating the properties of the region of interest comprises estimating the difference between the energy of the internal diffuse backscattering of the first acoustic signal and the energy of the internal diffuse backscattering of the second acoustic signal.

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