LWD acoustic wave assessment of formation heterogeneity

Abstract

A method for acoustic logging of a wellbore includes: performing acoustic logging measurements while rotating a logging-while-drilling tool in the wellbore, the acoustic logging measurements including low frequency measurements and high frequency measurements; estimating a low frequency slowness of the subterranean formation from the low frequency measurements; estimating a high frequency slowness of the subterranean formation from the high frequency measurements; and classifying the subterranean formation as homogeneous when a difference between the low frequency slowness and the high frequency slowness is less than a threshold and classifying the subterranean formation as heterogeneous when the difference is greater than the threshold.

Description

[0001] Cross - reference to related applications

[0002] None Background art

[0003] Acoustic (sonic) logging measurements are well - known and are commonly used in downhole logging applications, such as logging - while - drilling (LWD) and wireline logging (WL) applications. For example, acoustic logging measurements can be used to determine the slowness (inverse velocity) of acoustic energy through a formation, which together with other logging measurements can be used to estimate the porosity of the formation. Acoustic logging can also be used, for example, to identify formation lithology and source rocks and to identify other borehole features, such as fractures and compaction.

[0004] One difficulty in interpreting acoustic logging measurements is distinguishing between formation heterogeneity (such as the presence of formations or formation boundaries) and intrinsic anisotropy (such as caused by fine layering within a formation). There is a need in the industry to use acoustic logging measurements to identify formation heterogeneity. Brief description of the drawings

[0005] To more fully understand the disclosed subject matter and its advantages, reference is now made to the following description taken in conjunction with the accompanying drawings, in which:

[0006] Figure 1 An example rig including the disclosed directional acoustic logging tool is depicted.

[0007] Figure 2 Depicted is Figure 1 A portion of an exemplary embodiment of the shown directional acoustic logging tool.

[0008] Figure 3 A flowchart depicting an example method for evaluating a subterranean formation is depicted.

[0009] Figure 4 A flowchart depicting another example method for evaluating a subterranean formation is depicted.

[0010] Figure 5 A schematic cross - section is depicted that shows an exemplary X - axis and Y - axis and an exemplary orthogonal pair given by dipole measurements D1 and D2.

[0011] Figure 6A And 6B (Collectively referred to as FIG. 6) depicts example graphs (dispersion curves) of slowness versus frequency for a first homogeneous formation (6A) and a second heterogeneous formation (6B).

[0012] Figure 7A And 7B (Collectively referred to as FIG. 7) depicts graphs of modeled high and low frequency XX (7A) and YY (7B) shear wave slowness on the horizontal axis versus boundary position on the vertical axis. Detailed implementation manners

[0013] The present invention discloses a method and a system for performing acoustic LWD measurements. In one exemplary embodiment, a method for acoustic logging of a wellbore includes: rotating a logging tool in a wellbore penetrating a subterranean formation, the logging tool including an acoustic transmitter and an acoustic receiver; performing acoustic logging measurements while rotating the logging tool in the wellbore, the acoustic logging measurements including low-frequency measurements and high-frequency measurements; estimating a low-frequency slowness of the subterranean formation from the low-frequency measurements; estimating a high-frequency slowness of the subterranean formation from the high-frequency measurements; and classifying the subterranean formation as homogeneous when a difference between the low-frequency slowness and the high-frequency slowness is less than a threshold, and classifying the subterranean formation as heterogeneous when the difference is greater than the threshold.

[0014] Figure 1 An example rig 20 including the disclosed directional acoustic logging tool 50 is depicted. The rig 20 can be positioned above a subterranean formation (not shown) and can be configured for drilling a geothermal well or a hydrocarbon exploration and / or production well. The rig 20 can include, for example, a derrick and hoisting means (also not shown) for raising and lowering a drill string 30, as shown, the drill string 30 extending into a wellbore 40 and including a bottom hole assembly, which can also include, for example, a drill bit 32, a steering tool (such as a rotary steerable tool), and other logging while drilling (LWD) tools and measurement while drilling (MWD) tools. It should be understood that the disclosed embodiments are not limited to any particular drill string or BHA configuration.

[0015] The wellbore 40 can be formed in the subterranean formation and thereby penetrate the subterranean formation by rotary drilling or sliding drilling in a manner known to those of ordinary skill in the art (e.g., via known directional drilling techniques). For example, the drill string 30 can be rotated at the surface and / or via a downhole-deployed mud motor to drill the well. A pump can deliver drilling fluid into the interior of the drill string 30, such that the drilling fluid flows downward through the drill string 30. The drilling fluid exits the drill string 30, for example, via ports in the drill bit 32, and then circulates upward through the annulus 42 between the exterior of the drill string 30 and the wall of the wellbore 40. In this known manner, the drilling fluid lubricates the drill bit 32 and transports formation cuttings to the surface uphole. LWD measurements (such as acoustic LWD measurements) are typically performed while drilling and can be used to evaluate the properties of the subterranean formation.

[0016] It should be understood that the disclosed embodiments are not limited to use with an onshore rig 20 as Figure 1 shown. The disclosed embodiments are equally applicable to onshore or offshore subterranean operations. The disclosed embodiments can also be used with wireline logging operations.

[0017] Now turning to Figure 2, depicts an exemplary embodiment of a directional acoustic logging tool 50. In the depicted example, the tool 50 includes an acoustic transmitter 60 and an acoustic receiver 70 that are axially spaced apart from each other on a tool collar 55. The tool collar 55 and any optional inner mandrel or outer stabilizer blades may be collectively referred to herein as the tool body. The acoustic transmitter 60 may include a multipole transmitter that includes a plurality (e.g., four or six) azimuthally (circumferentially) spaced transmitter (transducer) elements T1, T2, T3, T4. The acoustic receiver 70 may include a directional receiver that also includes a plurality of azimuthally spaced receiver arrays R1, R2, R3, R4, where each receiver array includes a plurality of axially spaced receiver (transducer) elements (e.g., 8 or 12 axially spaced transducers per array). The multipole transmitter and the directional receiver may be configured to transmit and receive acoustic signals having different azimuthal harmonics. For example, monopole, dipole, quadrupole, and monopole wavefields may be transmitted and received by the directional acoustic logging tool 50.

[0018] In certain advantageous embodiments, the transmitter 60 may be configured to transmit a broadband acoustic waveform into the wellbore. A broadband acoustic waveform may mean that the transmitted waveform has a wide range of frequencies. In other words, a broadband acoustic waveform includes frequency components over a wide range of acoustic frequencies. In an exemplary embodiment, the transmitter may be configured to transmit a waveform having frequency components ranging from 1 kHz to 20 kHz (e.g., from 1 kHz to 16 kHz or from 2 kHz to 16 kHz). In other embodiments, the transmitter may be configured to transmit a multimode acoustic waveform that includes a first low-frequency mode and a second high-frequency mode (e.g., where the low-frequency mode has frequency components in the range of 1 kHz to 6 kHz and the high-frequency mode has frequency components in the range of 7 kHz to 16 kHz). In other embodiments, the transmitter may be configured to transmit a first narrowband acoustic waveform and a second narrowband acoustic waveform (e.g., sequentially transmit the first narrowband waveform and the second narrowband waveform). A narrowband acoustic waveform may mean that the waveform includes frequency components within a narrow frequency range. In an exemplary embodiment, the transmitter may be configured to transmit a first waveform having frequency components ranging from 1 kHz to 6 kHz and a second waveform having frequency components ranging from 7 kHz to 16 kHz.

[0019] Although the disclosed embodiments are not limited in this regard, the transmitter may advantageously be configured to transmit a dipole waveform. Figure 2 The multipole transmitter depicted above may transmit a dipole waveform, for example, as follows:

[0020] Dipole 1 = T1 + T2 - T3 - T4

[0021] Dipole 2 = T1 - T2 - T3 + T4

[0022] Dipole 3 = T1 - T3

[0023] Dipole 4 = T2 - T4

[0024] The directional receiver 70 can also advantageously be configured to receive dipole waveforms. Example dipole waveform reception can include, for example:

[0025] Dipole 1 = R1 + R2 - R3 - R4

[0026] Dipole 2 = R1 - R2 - R3 + R4

[0027] Dipole 3 = R1 - R3

[0028] Dipole 4 = R2 - R4

[0029] Continuing to refer to Figure 2 , the acoustic logging tool 50 can also include an electronic controller 80 that is configured to cause the tool 50 to perform acoustic LWD measurements (e.g., dipole measurements) as the tool 50 rotates in a wellbore (e.g., Figure 1 wellbore 40 in). The controller 80 can be configured to cause the transmitter 60 to transmit an acoustic waveform (e.g., a dipole waveform) into the wellbore. The controller 80 can further be configured to cause the receiver 70 to receive the transmitted waveform. The controller 80 can optionally be further configured to evaluate the received waveform to classify the subterranean formation as homogeneous or heterogeneous (e.g., to identify formation boundaries within the sensing range of the acoustic logging tool). To perform these functions, the controller can include hardware such as one or more processors (e.g., a microprocessor) that can be connected to one or more data storage devices (e.g., a hard disk drive or solid state memory). It will be further understood that the controller can further include processor-executable instructions stored in the data storage device. The executable instructions can be configured to, for example, perform and process acoustic logging measurements as described herein. Of course, it should be understood that the disclosed embodiments are not limited to the use or configuration of any particular computer hardware and / or software.

[0030] It should be understood that although not depicted, the acoustic logging tool 50 may also include one or more toolface (azimuth) sensors, e.g., including an accelerometer package, a magnetometer package, or a gyroscope sensor package. The toolface sensor may be configured to measure the toolface angle of the multipole transmitter 60 and the directional receiver 70 while rotating, and pair the acoustic sensor measurements with the corresponding toolface angles (e.g., by timestamping the measurements). These measurements can then be processed as described in more detail below to construct azimuthal (directional) acoustic logging measurements. It should be understood that the toolface sensor may also be deployed elsewhere in the drill string, e.g., in an MWD tool or a steerable rotary tool, and the acoustic logging tool 50 may communicate electronically with such a remote toolface sensor.

[0031] Turning now to Figure 3 , a flowchart of an example method 100 for evaluating a subterranean formation is depicted. At 110, multiple acoustic logging measurements may be made in a wellbore. The acoustic logging measurements include a first low-frequency measurement and a second high-frequency measurement. Making the measurements may include rotating an acoustic logging tool (such as tool 50) in the wellbore at 102 (e.g., as depicted Figure 1 above). For example, when the tool is rotated at 104, a transmitter (such as the multipole transmitter 60) may be fired to generate acoustic waves (such as dipole acoustic waves) in the borehole (wellbore) and the surrounding formation. The waves transmitted may include a broadband waveform or a multimode waveform including both low and high frequencies, or a first-order waveform and a second-order waveform including a first low-frequency waveform and a second high-frequency waveform. At 106, the transmitted dipole waves may be received by an acoustic receiver (such as the directional receiver 70). A toolface measurement may be made at 108 to determine the rotational orientation of the acoustic logging tool in the wellbore while rotating, firing, and receiving.

[0032] The low-frequency acoustic logging measurements may be evaluated at 112 to estimate the low-frequency slowness of the formation, and the high-frequency acoustic logging measurements may be evaluated at 114 to estimate the high-frequency slowness of the formation. It should be understood that dispersion or non-dispersion processing techniques (such as dispersion slowness time coherence (DSTC) or non-dispersion slowness time coherence (NDSTC or simply STC)) may be used to evaluate the low-frequency and high-frequency acoustic logging measurements. The formation may be classified as homogeneous or heterogeneous at 116 based on the difference between the low-frequency slowness and the high-frequency slowness. For example, at 116, when the difference between the high-frequency slowness estimate and the low-frequency slowness estimate is less than a threshold, the formation may be classified as homogeneous, and when the difference between the high-frequency slowness estimate and the low-frequency slowness estimate is greater than a threshold, the formation may be classified as heterogeneous.

[0033] Continuing to refer to Figure 3, it will be appreciated that the classification at 116 may alternatively include comparing the difference between the high-frequency slowness estimate and the low-frequency slowness estimate with a first threshold and a second threshold (where the first threshold is less than the second threshold). When the difference is less than the first threshold, the formation may be classified as homogeneous, and when the difference is greater than the second threshold, the formation may be classified as heterogeneous. When the difference is between the first threshold and the second threshold (e.g., greater than the first threshold and less than the second threshold), the classification may be indeterminate. As described in more detail below, in some operations, an indeterminate classification may indicate that a formation boundary is close to the borehole but not close enough to give a clear indication of heterogeneity.

[0034] Turning now to Figure 4 , a flowchart of another example method 150 for evaluating a subterranean formation is depicted. Multiple broadband or multimode dipole acoustic logging measurements may be made at 160, e.g., as described above with respect to Figure 3 . Briefly, an acoustic logging tool rotates in a wellbore while dipole waveforms are transmitted into the wellbore and the corresponding waveforms are received by acoustic receivers. These measurements may be made in groups corresponding to predetermined time intervals or depth intervals in the wellbore. At 162, orthogonal measurement pairs may be identified, e.g., based on the corresponding toolface angles of dipole emitter excitations. At 164, the identified orthogonal pairs may be mathematically rotated to align with orthogonal axes (e.g., predefined or computed X and Y orthogonal axes). The low-frequency portions of the orthogonal pairs may be evaluated at 166 to estimate the low-frequency slowness of the formation, and the high-frequency portions of the orthogonal pairs may be evaluated at 168 to estimate the high-frequency slowness of the formation. The high-frequency slowness estimate and the low-frequency slowness estimate may be compared, and the formation may be classified as homogeneous or heterogeneous at 170 (e.g., classified as homogeneous when the difference between the high-frequency slowness estimate and the low-frequency slowness estimate is less than a threshold, and classified as heterogeneous when the difference between the high-frequency slowness estimate and the low-frequency slowness estimate is greater than the threshold).

[0035] Identifying orthogonal measurement pairs at 162 may include evaluating the rotational orientation (toolface angle) corresponding to each of the dipole emissions of the emitter used to make the acoustic dipole logging measurements at 160. The rotational orientation (toolface angle) may then be evaluated to identify orthogonal pairs. Orthogonal pairs mean measurement pairs where the emitter excitations have corresponding rotational orientations that are orthogonal or nearly orthogonal to each other. The term orthogonal pair may also refer to the corresponding received waveforms aligned with each of the orthogonal emitter excitations at the receiver array. These waveforms or measurements may further be referred to as XX and YY measurements (or XX and YY orthogonal pairs). Of course, it should be understood that orthogonal means a 90-degree difference in rotational orientation (e.g., within an acceptable orthogonal error, such as 5 degrees or 10 degrees).

[0036] Figure 5depicts a schematic cross-section that shows an exemplary X-axis and Y-axis and an exemplary orthogonal pair identified at 162 given by dipole measurements D1 and D2. In this example illustration, α represents the angle between the D1 dipole measurement and the X-axis and β represents the angle between the D2 dipole measurement and the Y-axis. When α = β, the identified orthogonal pair has perfect orthogonality (i.e., the angle between D1 and D2 equals 90 degrees). When α ≠ β, the orthogonality error equals α - β. Measurement pairs having an orthogonality error less than a certain criterion (e.g., 5 or degrees) can be identified as orthogonal pairs. Figure 4 Continuing to refer to

[0037] and Figure 4 and 5 at 164, rotating the orthogonal pair can include compiling the corresponding 4C component waveforms and mathematically rotating the 4C component waveforms to coincide with previously defined X and Y axes. The 4C component waveforms can be rotated, for example, as follows:

[0038]

[0039] where represents the compiled 4C component waveforms, represents the rotated waveforms, and α represents the angle between the X transmitter excitation and the X-axis. It should be understood that Equation (1) assumes that the orthogonal pair has perfect orthogonality (i.e., such that α = β in Figure 5 ). For example, when the orthogonality error is less than about 1 or 2 degrees, this assumption may be valid. For LWD applications, where the orthogonal pair is typically only approximately orthogonal (e.g., when the orthogonality error is up to 5 or 10 degrees or more), Equation (1) can be modified, for example, as follows:

[0040]

[0041] where again represents the compiled 4C component waveforms, represents the rotated waveforms, α represents the angle between the X transmitter excitation and the X-axis, and β represents the angle between the Y transmitter excitation and the Y-axis. It should be understood that Equation (2) first corrects the orthogonality error (α - β) and then rotates the corrected waveforms by the angle α. Note that the YX component of the original 4C component waveforms is corrected by the +(YY - XX)tan(α - β) term and the original YY component is corrected by the -(XY + YX)tan(α - β) term.

[0042] Equation (2) advantageously includes only linear combinations of the original 4C waveforms and can be implemented using downhole processors (e.g., via Figure 2The controller 80) in quickly calculates. Additionally, Equation (2) has been described with respect to rotating the waveform to align with the mutually orthogonal X and Y directions. However, Equation (2) can also be used to rotate the waveform towards any non-orthogonal X and Y axes. It should be understood that the 4C component waveform means the XX and YY orthogonal pairs (coupled or inline components) and the XY and YX cross components, where the first symbol (X or Y) represents the transmitter orientation, and the second symbol (X or Y) represents the receiver orientation relative to the X and Y axes. It should also be understood that the XX measurement can be made with a dipole substantially aligned with the formation boundary, and the YY measurement can be made with a dipole substantially orthogonal to the formation boundary.

[0043] Continuing to refer to Figure 4 , the evaluation at 168 can further include evaluating the rotated orthogonal pairs to estimate the low-frequency XX and YY slowness values and the high-frequency XX and YY slowness values. The comparison and classification at 170 can further include comparing the low-frequency XX slowness value and the high-frequency XX slowness value and comparing the low-frequency YY slowness value and the high-frequency YY slowness value. When the difference between the low-frequency YY slowness value and the high-frequency YY slowness value exceeds a threshold, the formation can be classified as heterogeneous. When both the difference between the low-frequency YY slowness value and the high-frequency YY slowness value and the difference between the low-frequency XX slowness value and the high-frequency XX slowness value exceed the threshold, the formation can also be classified as heterogeneous. When both the difference between the low-frequency YY slowness value and the high-frequency YY slowness value and the difference between the low-frequency XX slowness value and the high-frequency XX slowness value are less than the threshold, the formation can be classified as homogeneous. In some embodiments, when the difference between the low-frequency YY slowness value and the high-frequency YY slowness value exceeds the threshold and the difference between the low-frequency XX slowness value and the high-frequency XX slowness value is less than the threshold, the classification can be indeterminate.

[0044] Now turning to Figure 6A and 6B (collective Figure 6), an example graph (dispersion curve) of slowness versus frequency for a first homogeneous formation (6A) and a second heterogeneous formation (6B) is depicted. In Figure 6AIn the example shown, non-dispersive processing (STC) is used to evaluate the high-frequency acoustic logging measurement (as indicated at 212) to estimate a high-frequency shear wave slowness estimate. As indicated, the high-frequency shear wave slowness estimate may represent most of the acoustic energy within the high-frequency acoustic measurement range (e.g., in the depicted example, in the range from about 9 - 14 kHz or 10 - 12 kHz). Dispersion processing (DSTC) is used to evaluate the low-frequency acoustic logging measurement (as indicated at 214) to estimate a low-frequency shear wave slowness estimate. As indicated, the low-frequency shear wave slowness estimate may be considered as the slowness value at the low-frequency limit or extrapolated to the low-frequency limit (e.g., in the depicted example, in the range from about 2 kHz to 3 kHz). Alternatively, the low-frequency shear wave slowness estimate may be obtained from curve fitting techniques using models based on mathematics or physics. Note that in Figure 6A the example depicted, the high-frequency slowness estimate is approximately equal to the low-frequency slowness estimate (about equal to 125 μs / ft, as shown at 216). Since the difference between the high-frequency slowness estimate and the low-frequency slowness estimate is less than the threshold, the formation can be classified as homogeneous.

[0045] In Figure 6B the example shown, STC is used to evaluate the high-frequency acoustic logging measurement (as indicated at 222) to estimate the high-frequency shear wave slowness. As described above and as indicated at 222, the high-frequency shear wave slowness estimate may be represented by the acoustic energy within a series of high-frequency acoustic measurements (e.g., from 9 kHz to 15 kHz or from 10 kHz to 14 kHz). DSTC is used to evaluate the low-frequency acoustic logging measurement (as indicated at 224) to estimate the low-frequency shear wave slowness. As described above and as indicated at 224, the low-frequency shear wave slowness estimate may be considered as the slowness value at or near the low-frequency limit. The high-frequency slowness estimate 226 is less than the low-frequency slowness estimate 228 (about 130 μs / ft versus about 140 μs / ft). Since the difference between the high-frequency slowness estimate 226 and the low-frequency slowness 228 estimate exceeds the threshold (e.g., example thresholds of 2 μs / ft, 4 μs / ft, or 6 μs / ft), the formation can be classified as heterogeneous.

[0046] The disclosed embodiments are now described in further detail by the following modeling example. Table 1 lists the modeling parameters used in this embodiment. A heterogeneous formation including a first and a second (upper and lower) formation is modeled. A 4-inch diameter acoustic logging tool is modeled in a 6-inch diameter horizontal wellbore. The modeled acoustic logging tool includes a 7-foot transmitter-receiver axial spacing. As listed in Table 1, the first (upper) formation has a modeled density of 2541.2 kg / m , 3 , 3 ,

[0046] and a modeled longitudinal wave slowness of 67.1 μs / ft and a modeled shear wave slowness of 125.5 μs / ft. The second (lower) formation has a modeled density of 2503.0 kg / m 3Modeling density, modeling longitudinal wave slowness of 71.3 μs / ft, and modeling shear wave slowness of 135.5 μs / ft. The density of the drilling fluid was modeled as 950 kg / m 3 , and the modeled slowness was 220 μs / ft. The position of the borehole was changed such that the formation boundary (between the first and second formations) was located 0, 2.1, 3, 6, 12, 24, or 36 inches below the center of the borehole. High-frequency and low-frequency shear wave slowness values were calculated for both XX and YY measurements (where the X-axis is horizontal and aligned with the formation boundary, and the Y-axis is vertical and perpendicular to the formation boundary) for each formation boundary position. STC processing with a processing band of 8 - 16 kHz was used to calculate the high-frequency shear wave slowness. DSTC processing with a processing band of 2.5 - 5 kHz and the corresponding tool model assumed in this numerical modeling was used to calculate the low-frequency shear wave slowness. Anisotropy was not assumed.

[0047] Table 1: Model Parameters

[0048] Drilling diameter 6 inches Tool diameter 4 inches Transmitter-receiver spacing 84 inches Formation 1 density <![CDATA[2541.2 kg / m 3 > Formation 1 P-wave slowness 67.1 μs / ft Formation 1 S-wave slowness 125.5 μs / ft Formation 2 density <![CDATA[2503.0kg / m 3 > Formation 2 P-wave slowness 71.3 μs / ft Formation 2 S-wave slowness 135.5 μs / ft Drilling fluid density <![CDATA[950kg / m 3 > Drilling fluid slowness 220 μs / ft

[0049] Figure 7A and 7B (collectively referred to as Figure 7) depict graphs of the high-frequency and low-frequency shear wave slowness calculated on the horizontal axis for XX measurement (7A) and YY measurement (7B) versus the boundary position from the center of the borehole on the vertical axis. The calculated high-frequency slowness values are plotted as dashed lines, and the calculated low-frequency slowness values are plotted as solid lines. Note that when the formation boundary is far from the center of the borehole over a long distance (e.g., in this example, as shown at 232 and 242, greater than about 10 or 15 inches), the high-frequency slowness values and low-frequency slowness values are similar (essentially no difference or very small difference). It has been recognized that when the formation boundary is at a long distance from the center of the borehole, the formation is essentially homogeneous (within the sensing range of the acoustic measurement). Therefore, it is further recognized that an acoustic measurement indicating a small difference (less than a threshold) between the high-frequency slowness value and the low-frequency slowness value can indicate a homogeneous formation.

[0050] Continuing to refer to Figure 7, it should also be noted that when the formation boundary is close to or intercepted by the borehole (e.g., in this example, as shown at 234 and 244, less than about 10 or 15 inches), there is a significant difference between the high-frequency slowness value and the low-frequency slowness value. It has been recognized that when the boundary of the formation is close to the center of the borehole or intercepted by the borehole, the formation is essentially heterogeneous (within the sensing range of the acoustic measurement). Therefore, it is further recognized that an acoustic measurement indicating a large difference (greater than a threshold) between the high-frequency slowness value and the low-frequency slowness value can indicate a heterogeneous formation.

[0051] It is obvious from the modeling results set in Figure 7 that the difference between the high-frequency shear wave slowness and the low-frequency shear wave slowness for the YY measurement ( Figure 7B)This may be more obvious, as shown at 244, especially when intercepting boreholes at formation boundaries (at distances 0, 2.1, and 3 in FIG. 7). Thus, in some exemplary operations, the YY measurement can provide a better indication of formation heterogeneity for the type of horizontal boundary assumed in this example.

[0052] While not wishing to be bound by theory, it is believed that the slowness difference between high-frequency and low-frequency measurements may be caused by different detection depths. In particular, high-frequency acoustic waveforms have a smaller wavelength than low-frequency acoustic waveforms and thus have a smaller detection depth than low-frequency acoustic waveforms. Low-frequency measurements may be affected by remote formations, while high-frequency measurements tend to be more sensitive to the local formation environment. Thus, different detection depths may result in the observed slowness difference when the formation boundary is within the detection depth of the low-frequency measurement.

[0053] Referring further to FIG. 7, it will of course be appreciated that the low-frequency slowness is not necessarily (or always) greater than the high-frequency slowness. On the contrary, for example, when the slowness of the upper formation is greater than the slowness of the lower formation, the low-frequency slowness can be less than the high-frequency slowness. The disclosed embodiments are not limited to any particular sign (positive or negative) of the difference.

[0054] It should be understood that the present disclosure includes many embodiments. These embodiments include, but are not limited to, the following embodiments.

[0055] In a first embodiment, a method for acoustic logging of a wellbore includes: rotating a logging tool in a wellbore penetrating an underground formation, the logging tool including an acoustic transmitter and an acoustic receiver; performing acoustic logging measurements while rotating the logging tool in the wellbore, the acoustic logging measurements including low-frequency measurements and high-frequency measurements; estimating a low-frequency slowness of the underground formation from the low-frequency measurements; estimating a high-frequency slowness of the underground formation from the high-frequency measurements; and classifying the underground formation as homogeneous when the difference between the low-frequency slowness and the high-frequency slowness is less than a threshold, and classifying the underground formation as heterogeneous when the difference is greater than the threshold.

[0056] A second embodiment may include the first embodiment, which further includes generating a classified log of the underground formation.

[0057] A third embodiment may include any one of the first to second embodiments, wherein the acoustic transmitter is configured to transmit a broadband acoustic waveform having frequency components ranging from 1 kHz to 16 kHz.

[0058] A fourth embodiment may include any one of the first to third embodiments, wherein the low-frequency measurements are made at frequencies in the range from 1 kHz to 6 kHz; and the high-frequency measurements are made at frequencies in the range from 7 kHz to 16 kHz.

[0059] The fifth embodiment may include any one of the first to fourth embodiments, wherein the estimated low-frequency slowness is the low-frequency shear-wave slowness of the subterranean formation and the estimated high-frequency slowness is the high-frequency shear-wave slowness of the subterranean formation.

[0060] The sixth embodiment may include the fifth embodiment, wherein estimating the low-frequency slowness includes using dispersion processing to estimate the shear-wave slowness value at the low-frequency limit; and estimating the high-frequency slowness includes using dispersion or non-dispersion processing to estimate the shear-wave slowness value in the high-frequency range.

[0061] The seventh embodiment may include any one of the first to sixth embodiments, wherein the acoustic logging measurement includes a dipole acoustic logging measurement.

[0062] The eighth embodiment may include the seventh embodiment, wherein performing the acoustic logging measurement further includes: exciting an acoustic emitter multiple times while the logging tool rotates in the wellbore to generate corresponding multiple dipole waveforms; receiving the multiple dipole waveforms at a directional receiver including a plurality of circumferentially spaced receiver arrays; and measuring the tool face angle corresponding to each of the multiple emitter excitations.

[0063] The ninth embodiment may include any one of the seventh to eighth embodiments, and further includes: evaluating the acoustic logging measurement to identify an orthogonal measurement pair including a first measurement and a second measurement, wherein the measured tool face angle of the first measurement is orthogonal to the measured tool face angle of the second measurement within a predetermined tool face tolerance; rotating the orthogonal measurement pair to align with a predefined orthogonal axis; and wherein the low-frequency slowness and the high-frequency slowness are estimated from the rotated orthogonal measurement pair.

[0064] The tenth embodiment may include the ninth embodiment, wherein the low-frequency slowness and the high-frequency slowness are estimated based on acoustic logging measurements made using a dipole orthogonal to a formation boundary in the subterranean formation.

[0065] In an eleventh embodiment, a system for evaluating a subterranean formation includes: an acoustic logging-while-drilling tool including an acoustic emitter and an acoustic receiver deployed in a logging-while-drilling tool body; and one or more processors configured to: while the logging-while-drilling tool rotates in a wellbore, cause the acoustic emitter and the acoustic receiver to perform high-frequency acoustic logging measurements and low-frequency acoustic logging measurements; estimate the low-frequency slowness of the subterranean formation from the low-frequency measurements; estimate the high-frequency slowness of the subterranean formation from the high-frequency measurements; and classify the subterranean formation as homogeneous when the difference between the low-frequency slowness and the high-frequency slowness is less than a threshold, and classify the subterranean formation as heterogeneous when the difference is greater than the threshold.

[0066] The twelfth embodiment may include the eleventh embodiment, wherein: the acoustic transmitter is configured to transmit a broadband acoustic waveform; the low-frequency measurement is performed at frequencies in the range of 1 kHz to 6 kHz; and the high-frequency measurement is performed at frequencies in the range of 7 kHz to 16 kHz.

[0067] The thirteenth embodiment may include any one of the eleventh embodiment to the twelfth embodiment, wherein one or more processors are configured to estimate the low-frequency slowness using dispersion processing to estimate the shear-wave slowness value at the low-frequency limit; and one or more processors are configured to estimate the high-frequency slowness using dispersion or non-dispersion processing to estimate the shear-wave slowness value in the high-frequency range.

[0068] The fourteenth embodiment may include any one of the eleventh embodiment to the thirteenth embodiment, wherein one or more processors are configured to cause the transmitter to generate a plurality of dipole waveforms while the logging tool rotates in the wellbore, and to receive the plurality of dipole waveforms at a directional receiver including a plurality of circumferentially spaced receiver arrays.

[0069] The fifteenth embodiment may include the fourteenth embodiment, wherein one or more processors are further configured to: evaluate the acoustic logging measurement to identify an orthogonal measurement pair including a first measurement and a second measurement, wherein the measured tool-face angle of the first measurement is orthogonal to the measured tool-face angle of the second measurement within a predetermined tool-face tolerance; rotate the orthogonal measurement pair to align with a predefined orthogonal axis; and wherein the low-frequency slowness and the high-frequency slowness are estimated from the rotated orthogonal measurement pair.

[0070] In a sixteenth embodiment, a method for acoustic logging of a wellbore includes: rotating a logging tool in a wellbore penetrating a subterranean formation, the logging tool including an acoustic transmitter and an acoustic receiver; performing dipole acoustic logging measurements while rotating the logging tool in the wellbore; evaluating the acoustic logging measurements to identify an orthogonal measurement pair including a first measurement and a second measurement, wherein the measured tool-face angle of the first measurement is orthogonal to the measured tool-face angle of the second measurement within a predetermined tool-face tolerance; rotating the orthogonal measurement pair to align with a predefined orthogonal axis; estimating the low-frequency slowness of the subterranean formation from the low-frequency portion of the measurements in the rotated orthogonal pair; estimating the high-frequency slowness of the subterranean formation from the high-frequency portion of the measurements in the rotated orthogonal pair; and classifying the subterranean formation as homogeneous when the difference between the low-frequency slowness and the high-frequency slowness is less than a threshold, and classifying the subterranean formation as heterogeneous when the difference is greater than the threshold.

[0071] The seventeenth embodiment may include the sixteenth embodiment, wherein the acoustic transmitter is configured to transmit a broadband acoustic waveform having frequency components ranging from 1 kHz to 16 kHz; the measured low-frequency portion is at a frequency within the range from 1 kHz to 6 kHz; and the frequency of the measured high-frequency portion is within the range from 7 kHz to 16 kHz.

[0072] The eighteenth embodiment may include any one of the sixteenth embodiment to the seventeenth embodiment, wherein estimating the low-frequency slowness includes using dispersion processing to estimate the shear-wave slowness value at the low-frequency limit; and estimating the high-frequency slowness includes using dispersion or non-dispersion processing to estimate the shear-wave slowness value within the high-frequency range.

[0073] The nineteenth embodiment may include any one of the sixteenth embodiment to the eighteenth embodiment, wherein the orthogonal measurement pair includes XX measurement and YY measurement. For the XX measurement, the emitted dipole is aligned with the formation boundary in the subterranean formation; for the YY measurement, the emitted dipole is orthogonal to the formation boundary in the subterranean formation; and the classification further includes classifying the subterranean formation as homogeneous when the difference between the low-frequency slowness and the high-frequency slowness of the YY measurement is less than a threshold, and classifying the subterranean formation as heterogeneous when the difference is greater than the threshold.

[0074] The twentieth embodiment may include any one of the sixteenth embodiment to the nineteenth embodiment, wherein performing the dipole acoustic logging measurement further includes: exciting the acoustic transmitter multiple times while the logging tool rotates in the wellbore to generate corresponding multiple dipole waveforms; receiving the multiple dipole waveforms at a directional receiver including a multiple circumferentially spaced receiver array; and measuring the tool-face angle corresponding to each of the multiple transmitter excitations.

[0075] Although the LWD acoustic evaluation of formation heterogeneity has been described in detail, it should be understood that various changes, substitutions, and alterations can be made herein without departing from the spirit and scope of the disclosure defined by the embodiments of the present application.

Claims

1. A method for acoustic logging of a wellbore, the method comprising: Rotating a logging tool in a wellbore penetrating a subterranean formation, the logging tool comprising an acoustic transmitter and an acoustic receiver; Performing acoustic logging measurements while rotating the logging tool in the wellbore, the acoustic logging measurements comprising a low-frequency measurement and a high-frequency measurement; Estimating a low-frequency slowness of the subterranean formation from the low-frequency measurement; Estimating a high-frequency slowness of the subterranean formation from the high-frequency measurement; and Classifying the subterranean formation as homogeneous when a difference between the low-frequency slowness and the high-frequency slowness is less than a threshold, and classifying the subterranean formation as heterogeneous when the difference is greater than the threshold.

2. The method according to claim 1, further comprising generating a classified log of the subterranean formation.

3. The method according to claim 1, wherein the acoustic transmitter is configured to emit a broadband acoustic waveform having frequency components ranging from 1 kHz to 16 kHz.

4. The method according to claim 1, wherein: The low-frequency measurement is performed at frequencies in the range of 1 kHz to 6 kHz; and The high-frequency measurement is performed at frequencies in the range of 7 kHz to 16 kHz.

5. The method according to claim 1, wherein the estimated low-frequency slowness is a low-frequency shear-wave slowness of the subterranean formation, and the estimated high-frequency slowness is a high-frequency shear-wave slowness of the subterranean formation.

6. The method according to claim 5, wherein: Estimating the low-frequency slowness comprises using dispersion processing to estimate a shear-wave slowness value at a low-frequency limit; and Estimating the high-frequency slowness comprises using dispersion or non-dispersion processing to estimate a shear-wave slowness value in a high-frequency range.

7. The method according to claim 1, wherein the acoustic logging measurements comprise dipole acoustic logging measurements.

8. The method according to claim 7, wherein performing the acoustic logging measurements further comprises: Exciting the acoustic transmitter multiple times while the logging tool rotates in the wellbore to generate corresponding multiple dipole waveforms; Receiving the multiple dipole waveforms at a directional receiver comprising a plurality of circumferentially spaced receiver arrays; and Measuring a toolface angle corresponding to each of the multiple transmitter excitations.

9. The method according to claim 7, further comprising: Evaluating the acoustic logging measurements to identify an orthogonal measurement pair comprising a first measurement and a second measurement, wherein a measured toolface angle of the first measurement is orthogonal within a predetermined toolface tolerance to a measured toolface angle of the second measurement; Rotating the orthogonal measurement pair to align with a predefined orthogonal axis; and Wherein the low-frequency slowness and the high-frequency slowness are estimated from the rotated orthogonal measurement pair.

10. The method according to claim 9, wherein the low-frequency slowness and the high-frequency slowness are estimated from acoustic logging measurements performed using a dipole orthogonal to a formation boundary in the subterranean formation.

11. A system for evaluating a subterranean formation, the system comprising: An acoustic logging-while-drilling tool, the acoustic logging-while-drilling tool comprising an acoustic transmitter and an acoustic receiver deployed in a logging-while-drilling tool body; and One or more processors configured to: While the logging-while-drilling tool rotates in the wellbore, cause the acoustic transmitter and the acoustic receiver to perform high-frequency acoustic logging measurements and low-frequency acoustic logging measurements; Estimate the low-frequency slowness of the subterranean formation from the low-frequency measurements; Estimate the high-frequency slowness of the subterranean formation from the high-frequency measurements; and When the difference between the low-frequency slowness and the high-frequency slowness is less than a threshold, classify the subterranean formation as homogeneous, and when the difference is greater than the threshold, classify the subterranean formation as heterogeneous.

12. The system of claim 11, wherein: The acoustic transmitter is configured to transmit a broadband acoustic waveform; The low-frequency measurements are made at frequencies in the range of 1 kHz to 6 kHz; and The high-frequency measurements are made at frequencies in the range of 7 kHz to 16 kHz.

13. The system of claim 11, wherein: One or more processors are configured to estimate the low-frequency slowness using dispersion processing to estimate the shear-wave slowness value at the low-frequency limit; and One or more processors are configured to estimate the high-frequency slowness using dispersion or non-dispersion processing to estimate the shear-wave slowness value in the high-frequency range.

14. The system of claim 11, wherein one or more processors are configured to cause the transmitter to generate a plurality of dipole waveforms while the drilling tool rotates in the wellbore, and receive the plurality of dipole waveforms at a directional receiver including a plurality of circumferentially spaced receiver arrays.

15. The system of claim 14, wherein one or more processors are further configured to: Evaluate the acoustic logging measurements to identify an orthogonal measurement pair including a first measurement and a second measurement, wherein the measured tool face angle of the first measurement is orthogonal within a predetermined tool face tolerance to the measured tool face angle of the second measurement; Rotate the orthogonal measurement pair to align with a predefined orthogonal axis; and Wherein the low-frequency slowness and the high-frequency slowness are estimated from the rotated orthogonal measurement pair.

16. A method for acoustic logging of a wellbore, the method comprising: Rotating a logging tool in a wellbore penetrating a subterranean formation, the logging tool including an acoustic transmitter and an acoustic receiver; Performing dipole acoustic logging measurements while rotating the logging tool in the wellbore; Evaluating the acoustic logging measurements to identify an orthogonal measurement pair including a first measurement and a second measurement, wherein the measured tool face angle of the first measurement is orthogonal within a predetermined tool face tolerance to the measured tool face angle of the second measurement; Rotating the orthogonal measurement pair to align with a predefined orthogonal axis; Estimating the low-frequency slowness of the subterranean formation from the low-frequency portion of the measurements in the rotated orthogonal pair; Estimating the high-frequency slowness of the subterranean formation from the high-frequency portion of the measurements in the rotated orthogonal pair; and When the difference between the low-frequency slowness and the high-frequency slowness is less than a threshold, classify the subterranean formation as homogeneous, and when the difference is greater than the threshold, classify the subterranean formation as heterogeneous.

17. The method of claim 16, wherein: The acoustic transmitter is configured to transmit a broadband acoustic waveform having frequency components ranging from 1 kHz to 16 kHz; The measured low-frequency portion is at a frequency in the range from 1 kHz to 6 kHz; and The measured high-frequency portion is at a frequency in the range from 7 kHz to 16 kHz.

18. The method according to claim 16, wherein: estimating the low-frequency slowness includes using dispersion processing to estimate the shear-wave slowness value at the low-frequency limit; and estimating the high-frequency slowness includes using dispersion or non-dispersion processing to estimate the shear-wave slowness value in the high-frequency range.

19. The method according to claim 16, wherein: the orthogonal measurement pair includes XX measurement and YY measurement, for the XX measurement, the emitted dipole is aligned with the formation boundary in the subterranean formation; for the YY measurement, the emitted dipole is orthogonal to the formation boundary in the subterranean formation; and the classification further includes classifying the subterranean formation as homogeneous when the difference between the low-frequency slowness and the high-frequency slowness of the YY measurement is less than a threshold, and classifying the subterranean formation as heterogeneous when the difference is greater than the threshold.

20. The method according to claim 16, wherein performing the dipole acoustic logging measurement further includes: exciting the acoustic transmitter multiple times while the logging tool rotates in the wellbore to generate corresponding multiple dipole waveforms; receiving the multiple dipole waveforms at a directional receiver including a plurality of circumferentially spaced receiver arrays; and measuring the tool face angle corresponding to each of the multiple transmitter excitations.

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