Method for calculating formation porosity based on acoustic logging information of horizontal well
By collecting and processing array sonic logging data from horizontal wells in shale reservoirs, and combining this with rock physics experiments, the anisotropic conversion ratio of P-waves and S-waves was calculated. This solved the problem of the difficulty in measuring the vertical P-wave velocity in shale reservoirs and enabled the accurate calculation of shale reservoir porosity.
Patent Information
- Application Number
- CN202410645477.9
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- Filing Date
- 2024-05-23
- Publication Date
- 2025-11-25
AI Technical Summary
Existing technologies make it difficult to directly calculate vertical P-wave velocity in shale reservoirs using horizontal well acoustic logging, which makes it difficult to accurately calculate porosity.
By collecting array acoustic logging data from horizontal wells, waveform preprocessing is performed, horizontal and vertical shear wave time differences are calculated, and rock physics experiments are combined to calculate the anisotropic conversion ratio of P-waves and S-waves. Vertical P-wave time difference is calculated at each depth point, and finally, formation porosity is calculated using the Willy time evaluation formula.
It enables accurate porosity calculation in shale reservoirs based on horizontal well sonic logging data, overcoming the difficulties of existing technologies and providing the ability to continuously calculate porosity at depth points.
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Figure CN121008323A_ABST
Abstract
Description
Technical Field
[0001] This invention relates to the field of oil and gas exploration in unconventional reservoirs such as shale, and more specifically, to a method for calculating formation porosity based on horizontal well acoustic logging data. Background Technology
[0002] China possesses abundant shale gas resources with significant exploration and development potential. Porosity is a key parameter for shale reservoir evaluation and shale gas reserve calculation. Shale is composed of clastic particles with a diameter less than 0.0625 mm, clay, and organic matter, exhibiting foliation and being a fragile, fine-grained sediment. Shale primarily develops micro- and nano-pores, with complex pore structures and low permeability, making accurate porosity calculation more challenging than for conventional reservoirs. Current porosity calculation methods mainly fall into two categories: laboratory porosity measurement methods for shale cores and well logging evaluation methods implemented downhole.
[0003] Laboratory porosity measurement methods for shale reservoirs mainly include the helium method, liquid saturation method, and nuclear magnetic resonance (NMR) method. The helium method includes the particle sample helium method and the plunger sample helium method. The result of the particle sample helium method can be considered as the total porosity, while the result of the plunger sample helium method can be considered as the effective porosity. The liquid saturation method typically uses a plunger sample, saturating the sample with liquid media such as alcohol or water, and the measured result is the effective porosity. The NMR method calculates the total porosity of the shale by obtaining the T2 spectrum of the shale sample after saturation with fluid. Literature review indicates that the plunger sample helium method is the preferred method for shale porosity measurement due to its high reliability in determining the effective porosity. However, laboratory measurement methods generally suffer from drawbacks such as high coring costs, long measurement time, and difficulty in continuously calculating porosity at depth points, and can only be used as auxiliary evaluation methods for porosity logging evaluation.
[0004] The earliest formula for estimating reservoir porosity based on sonic logging data was proposed by MR J. Wyllie in 1956, namely the Wyllie time-averaged equation:
[0005] DT P =φ s DT f +(1-φ s )DT ma (1)
[0006] In the formula: DT P The longitudinal wave transit time measured by sonic logging, in seconds per minute (s / m); DT ma For the P-wave time difference of the skeleton, s / m; DT f For fluid acoustic transit time, s / m; φ s Let be the acoustic porosity. Transforming the above equation, we obtain the acoustic porosity formula:
[0007]
[0008] However, for highly anisotropic reservoirs like shale, there is a significant difference between horizontal and vertical P-wave velocities. In horizontal wells of shale reservoirs, only the horizontal P-wave velocity can be measured; the vertical P-wave velocity cannot be directly obtained. Therefore, it is difficult to accurately calculate formation porosity at depth points using the vertical P-wave velocity. Summary of the Invention
[0009] The present invention aims to provide a method for calculating formation porosity based on horizontal well acoustic logging data, in order to solve the above-mentioned problems.
[0010] This invention provides a method for calculating formation porosity based on horizontal well acoustic logging data, comprising the following steps:
[0011] Step 1: Collect array acoustic logging data of the current horizontal well and perform waveform preprocessing to obtain the monopole longitudinal wave array waveform and the four-component dipole transverse wave array waveform;
[0012] Step 2: Calculate the horizontal longitudinal wave time difference using the monopole longitudinal wave array waveform;
[0013] Step 3: Invert the horizontal and vertical shear wave array waveforms using the four-component dipole shear wave array waveform and azimuth curve.
[0014] Step 4: Calculate the horizontal and vertical shear wave time differences based on the horizontal and vertical shear wave array waveforms, and calculate the shear wave anisotropy at each depth point.
[0015] Step 5: Conduct rock physics experiments on the core samples collected from the current horizontal well or the corresponding pilot hole vertical well, and calculate the anisotropic conversion ratio of the P-wave and S-wave.
[0016] Step 6: Based on the shear wave anisotropy and horizontal P-wave transit time obtained from the well logging data inversion and the P-wave anisotropy conversion ratio obtained from the rock physics experiment, calculate the vertical P-wave transit time at each depth point.
[0017] Step 7: Calculate the formation porosity of the horizontal well using the vertical P-wave time difference at each depth point.
[0018] In step 1, array acoustic logging data of the current horizontal well is collected, including instrument azimuth curve, original waveform of monopole array acoustic logging, monopole array acoustic logging gain curve and monopole array acoustic logging delay curve, and original waveform of four-component dipole array acoustic logging, four-component dipole array acoustic logging gain curve and four-component dipole array acoustic logging delay curve.
[0019] In step 1, waveform preprocessing of the array acoustic logging data includes: first, gain recovery; then, delay recovery; and finally, bandpass filtering.
[0020] When acquiring array acoustic waveforms downhole, automatic gain control is used to ensure the waveform amplitude is at its highest accuracy. This amplifies the waveform amplitude from a decimal to an integer for easier storage and recording. Therefore, the acquired waveform must first undergo gain recovery, with the gain parameter AGN as shown in equation (3):
[0021] AGN=10 GN*0.05 (3)
[0022] In the formula, GN represents the noise gain. Gain recovery is achieved by dividing the array acoustic waveform by AGN.
[0023] During waveform acquisition, to reduce the amount of stored data, waveform data for a period of time before the arrival of the first wave is often not acquired. The purpose of delay recovery is to fill in zeros before the zero point of the array acoustic waveform, thereby obtaining waveform data with accurate timing. After waveform preprocessing, the monopole longitudinal wave array waveform and the four-component dipole transverse wave array waveform are obtained.
[0024] In step 2, since the array acoustic logging data is collected in a horizontal well, the P-waves in the monopole P-wave array waveform obtained from the preprocessing in step 1 propagate horizontally along the well wall. This invention selects the time-time difference correlation method to extract the horizontal P-wave time difference from the monopole P-wave array waveform. This time-time difference correlation method calculates the correlation function of the monopole P-wave array waveform in both time and time difference dimensions; the time difference at which the correlation function reaches its maximum value is the horizontal P-wave time difference. Specifically:
[0025] First, a time window is opened for the multiple channels in the monopole longitudinal wave array waveform, and the correlation function values of the multiple channels within the time window are calculated. Then, the slope of the time window is gradually changed within the slowness search range (DTMIN—DTMAX), and the correlation function values are calculated again. After the entire time difference range is calculated, the time of the time window is moved forward by one position, and the same time difference search calculation is performed again until the entire time range (CWBEGIN—CWEND) is calculated. The formula for calculating the correlation function Corr is shown in equation (4):
[0026]
[0027] In the formula, DT represents the horizontal longitudinal wave time difference, Time represents the start time of the current time window, CWLENTH represents the duration of the time window, N represents the number of channels in the monopole longitudinal wave array waveform, m is the channel number of the monopole longitudinal wave array waveform, and RRSP represents the distance between two adjacent receivers.
[0028] In step 3, the horizontal and vertical shear wave array waveforms are inverted based on the preprocessed four-component dipole shear wave array waveform and the RB azimuth curve. The RB azimuth curve is the angle between the X-plate and the horizontal borehole height in the array acoustic logging instrument. Assuming the RB azimuth curve refers to the angle at which the X(+) plate is rotated counterclockwise to the horizontal borehole height, according to the vector composition and decomposition rules, the inversion formulas for the horizontal and vertical shear wave array waveforms after rotating the X(+) plate to the horizontal borehole height are as follows:
[0029]
[0030] In the formula, SH is the horizontal shear wave array waveform, SV is the vertical shear wave array waveform, RB is the RB azimuth curve, XX is the XX component dipole shear wave array waveform, XY is the XY component dipole shear wave array waveform, YX is the YX component dipole shear wave array waveform, and YY is the YY component dipole shear wave array waveform.
[0031] In step 4, the horizontal and vertical shear wave array waveforms obtained in step 3 are used to extract the horizontal and vertical shear wave time differences at depth points using the correlation method introduced in step 2. Furthermore, formula (6) is used to calculate the shear wave anisotropy of the shale reservoir at depth points.
[0032]
[0033] In the formula, TI S (i) represents the transverse wave anisotropy at the i-th depth point; DT SH (i) represents the horizontal transverse wave time difference at the i-th depth point, DT SV (i) represents the vertical transverse wave time difference at the i-th depth point.
[0034] In step 5, at least one full-diameter core sample must be taken from the current horizontal well or the corresponding pilot hole vertical well. It is recommended to take one full-diameter core sample from the current horizontal well first, but considering the difficulty of core sampling under horizontal well conditions, one full-diameter core sample can also be taken from the corresponding reservoir section of the corresponding pilot hole. The full-diameter core sample is further cut in the laboratory to obtain vertical plunger rock samples and horizontal plunger rock samples. P-wave and S-wave time difference measurements are carried out on the vertical plunger rock samples and the horizontal plunger rock samples respectively, and the P-wave anisotropy and S-wave anisotropy corresponding to the plunger rock samples are further calculated. Finally, the ratio of the two is taken to obtain the P-wave and S-wave anisotropy conversion ratio. The calculation formulas are shown in equations (7), (8) and (9).
[0035]
[0036]
[0037]
[0038] In the formula, DT SVR DT represents the transverse wave time corresponding to the vertical plunger rock sample experiment. SHR TI represents the transverse wave time difference corresponding to horizontal plunger rock sample experiments. PR The representative plunger rock sample experiment corresponds to the longitudinal wave anisotropy, DT PVR DT represents the P-wave time difference corresponding to the vertical plunger rock sample experiment. PHR TI represents the longitudinal wave time difference corresponding to horizontal plunger rock sample experiments. SR The RTI represents the transverse anisotropy corresponding to the plunger rock sample experiment, and the P-wave to S-wave anisotropy conversion ratio.
[0039] In step 6, the transverse wave anisotropy and horizontal P-wave time difference were calculated at each depth point in step 4, and the P-wave and transverse wave anisotropy conversion ratio based on rock physics experiments was calculated in step 5. Based on the above three parameters, the vertical P-wave time difference can be calculated at each depth point, as shown in formulas (10) and (11).
[0040] TI P (i)=TI S (i)·RTI (10)
[0041]
[0042] In the formula, TI P (i) represents the longitudinal wave anisotropy at the i-th depth point; TI S (i) represents the shear wave anisotropy at the i-th depth point; RTI represents the P-wave to S-wave anisotropy conversion ratio; DT PV (i) represents the vertical P-wave time difference at the i-th depth point; DT PH (i) represents the horizontal P-wave time difference at the i-th depth point.
[0043] In step 7, based on the depth-by-depth vertical P-wave time difference calculated in step 6 and the reservoir rock skeleton time difference in the region, the formation porosity of the horizontal well is calculated depth-by-depth using the Willy time evaluation formula.
[0044]
[0045] In the formula, φ s (i) represents the formation porosity at the i-th depth point, DT ma DT represents the time lag of the reservoir rock framework in this region. f This represents the sonic travel time of the fluid in the horizontal well.
[0046] In summary, due to the adoption of the above technical solution, the beneficial effects of the present invention are:
[0047] This invention uses the anisotropic conversion ratio of longitudinal and transverse waves obtained from rock physics experiments, and then calculates the vertical longitudinal wave time difference at each depth point to realize the calculation of the actual porosity of the formation based on the acoustic logging data of horizontal wells. Attached Figure Description
[0048] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings in the embodiments will be briefly described below. It should be understood that the following drawings only show some embodiments of the present invention and should not be regarded as a limitation on the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort.
[0049] Figure 1 This is a flowchart of a method for calculating formation porosity based on horizontal well acoustic logging data.
[0050] Figure 2 This is a preprocessed image of acoustic logging data from the X1 horizontal well array.
[0051] Figure 3 This is a diagram showing the anisotropy of shear waves at depth points in the X1 horizontal well.
[0052] Figure 4 The diagram shows the cutting of vertical and horizontal plunger rock samples during a rock physics experiment. (a) is a full-diameter core, (b) is a vertical plunger rock sample, and (c) is a horizontal plunger rock sample.
[0053] Figure 5a A schematic diagram of the clamping device used to hold two plunger rock samples during the sound velocity measurement experiment of the X1 horizontal well plunger rock samples.
[0054] Figure 5b This is a physical diagram of the experimental setup for measuring longitudinal and transverse wave velocities under pressure during the sound velocity measurement experiment of rock samples from the X1 horizontal well plunger.
[0055] Figure 6 This is a diagram showing the formation porosity at each depth point in the X1 horizontal well. Detailed Implementation
[0056] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.
[0057] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.
[0058] Example
[0059] like Figure 1 As shown in the figure, this embodiment proposes a method for calculating formation porosity based on horizontal well sonic logging data, including the following steps:
[0060] Step 1: Collect array acoustic logging data of the current horizontal well and perform waveform preprocessing to obtain the monopole longitudinal wave array waveform and the four-component dipole transverse wave array waveform;
[0061] Figure 2 From bottom to top, the channels are: Channel 1, Channel 2, Channel 3, Channel 4, Channel 5, Channel 6, Channel 7, and Channel 8. Channel 1 is the X1 horizontal well depth curve; Channel 2 is the original waveform of the monopole array longitudinal wave; Channel 3 is the original waveform of the XX component dipole transverse wave array; Channel 4 is the original waveform of the YY component dipole transverse wave array; Channel 5 is the monopole array acoustic waveform after waveform preprocessing. Compared with Channel 2, the monopole longitudinal wave array waveform has undergone gain recovery and delay recovery, representing the actual measured waveform shape underground; Channel 6 is the XX component dipole transverse wave array waveform after waveform preprocessing; Channel 7 is the YY component dipole transverse wave array waveform after waveform preprocessing.
[0062] Step 2: Calculate the horizontal longitudinal wave time difference using the monopole longitudinal wave array waveform;
[0063] Figure 2 The eighth channel is the horizontal P-wave time difference curve corresponding to the X1 horizontal well, extracted using the time-time correlation method based on the P-wave waveform of the fifth channel monopole array. From this, the horizontal P-wave time difference value can be observed to be between 55 μs / ft and 70 μs / ft.
[0064] Step 3: Invert the horizontal and vertical shear wave array waveforms using the four-component dipole shear wave array waveform and azimuth curve.
[0065] Figure 3The first track is the X1 horizontal well depth curve; the second track is the horizontal shear wave array waveform (WVSH) obtained by inverting the azimuth inversion method in step 3; the third track is the vertical shear wave array waveform (WVSV) obtained by inverting the azimuth inversion method in step 3; the fourth track includes the horizontal shear wave time difference (DTSH, solid line) obtained by processing the horizontal shear wave array waveform using the time-time difference correlation method described in step 2, and the vertical shear wave time difference (DTSV, dashed line) obtained by processing the vertical shear wave array waveform. It can be observed that the horizontal shear wave time difference is always higher than the vertical shear wave time difference. This is because the horizontal shear wave velocity propagating and polarizing along the reservoir bedding direction is always the fastest.
[0066] Step 4: Calculate the horizontal and vertical shear wave time differences based on the horizontal and vertical shear wave array waveforms, and calculate the shear wave anisotropy at each depth point.
[0067] Figure 3 The fifth line represents the shear wave anisotropy calculated at each depth point for the X1 horizontal well. It is calculated using the horizontal shear wave transit time (DTSH, fourth solid line) and vertical shear wave transit time (DTSV, fourth dashed line) at each depth point of the horizontal well, according to the method described in step 4 and formula (6). It can be seen that its value is basically above 5%, with an average value of about 10%, which indicates that the reservoir encountered by the horizontal well is a strongly anisotropic reservoir, and it is necessary to use the vertical P-wave transit time to accurately calculate the formation porosity at each depth point.
[0068] Step 5: Conduct rock physics experiments on the core samples collected from the current horizontal well or the corresponding pilot hole vertical well, and calculate the anisotropic conversion ratio of the P-wave and S-wave.
[0069] Full-diameter core samples were taken from this reservoir section corresponding to the pilot hole in horizontal well X1. After... Figure 4 The core sample (a) shown was cut to obtain one vertical plunger sample (b) and one horizontal plunger sample (c). Based on this, a clamp was applied to each of the two plunger samples. Figure 5a ), and placed in the experimental apparatus for measuring longitudinal and transverse wave velocities ( Figure 5b Perform pressurization measurements. The pressurization value should be as close as possible to the actual conditions. Referring to the formation pressure data of the X1 horizontal well, the pressurization value should be 55 MPa. After measurement, the corresponding shear wave time DT for the vertical plunger rock sample experiment can be obtained. SVR The transverse wave time (DT) was 120.2 μs / ft; the corresponding transverse wave time (DT) for the horizontal plunger rock sample experiment was... SHR 100.9 μs / ft; corresponding P-wave time difference DT for vertical plunger rock sample experiments PVR The time to propagation (TP) of the horizontal plunger rock sample experiment was 70.7 μs / ft. PHRThe value is 58.9 μs / ft. Furthermore, based on formulas (7), (8), and (9) in step 5, the transverse wave anisotropy TI corresponding to the acoustic velocity experiment of the X1 horizontal well drilling plunger rock sample can be calculated sequentially. SR 17.5%, longitudinal wave anisotropy TI PR The anisotropic conversion ratio (RTI) was 18.2% and the longitudinal and transverse anisotropic conversion ratio was 1.04.
[0070] Step 6: Based on the shear wave anisotropy and horizontal P-wave transit time obtained from the well logging data inversion and the P-wave anisotropy conversion ratio obtained from the rock physics experiment, calculate the vertical P-wave transit time at each depth point.
[0071] In Figure 5, the first line is the X1 horizontal well depth curve; the second line is the transverse wave anisotropy curve (TIS); and the third line is the longitudinal wave anisotropy curve (TIP) calculated at each depth point based on the TIS and the longitudinal wave anisotropy conversion ratio RTI obtained through rock physics experiments in step 5. Since RTI is greater than 1, TIP is always higher than TIS in this horizontal well. Furthermore, using the method described by formula (11) in step 6, the vertical longitudinal wave time difference (DTPV) can be calculated at each depth point, as shown by the fourth dashed line in Figure 5.
[0072] Step 7: Calculate the formation porosity of the horizontal well using the vertical P-wave time difference at each depth point.
[0073] The Willy time evaluation formula or other acoustic porosity calculation formulas modified for specific reservoirs can be used to calculate formation porosity at depth points based on the vertical P-wave transit time curve. For the X1 horizontal well, the Willy time evaluation formula described in formula (2) is used here to calculate the shale reservoir porosity. Based on the geological data of this area and the logging data of adjacent wells, the vertical P-wave transit time DT of the shale skeleton is determined. ma 55 μs / ft, mud time difference DT f The value was 189 μs / ft. Further, based on the vertical P-wave transit time (DTPV) calculated in step 6, the formation porosity (POR) of the well was calculated at each depth point, as shown in the fifth line of Figure 5. It can be observed that the formation porosity ranges from 5% to 20%, consistent with the reservoir geological characteristics of this area. Except for two anomalous depth locations, indicated by the black arrows in Figure 5, these anomalies may be caused by wellbore enlargement or other reasons.
[0074] The above description is merely a preferred embodiment of the present invention and is not intended to limit the invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.
Claims
1. A method for calculating formation porosity based on horizontal well acoustic logging data, characterized in that, Includes the following steps: Step 1: Collect array acoustic logging data of the current horizontal well and perform waveform preprocessing to obtain the monopole longitudinal wave array waveform and the four-component dipole transverse wave array waveform; Step 2: Calculate the horizontal longitudinal wave time difference using the monopole longitudinal wave array waveform; Step 3: Invert the horizontal and vertical shear wave array waveforms using the four-component dipole shear wave array waveform and azimuth curve. Step 4: Calculate the horizontal and vertical shear wave time differences based on the horizontal and vertical shear wave array waveforms, and calculate the shear wave anisotropy at each depth point. Step 5: Conduct rock physics experiments on the core samples collected from the current horizontal well or the corresponding pilot hole vertical well, and calculate the anisotropic conversion ratio of the P-wave and S-wave. Step 6: Based on the shear wave anisotropy and horizontal P-wave transit time obtained from the well logging data inversion and the P-wave anisotropy conversion ratio obtained from the rock physics experiment, calculate the vertical P-wave transit time at each depth point. Step 7: Calculate the formation porosity of the horizontal well using the vertical P-wave time difference at each depth point.
2. The method for calculating formation porosity based on horizontal well acoustic logging data according to claim 1, characterized in that, In step 1, array acoustic logging data of the current horizontal well is collected, including instrument azimuth curve, original waveform of monopole array acoustic logging, monopole array acoustic logging gain curve and monopole array acoustic logging delay curve, and original waveform of four-component dipole array acoustic logging, four-component dipole array acoustic logging gain curve and four-component dipole array acoustic logging delay curve.
3. The method for calculating formation porosity based on horizontal well acoustic logging data according to claim 1, characterized in that, In step 1, waveform preprocessing of the array acoustic logging data includes: first, gain recovery; then, delay recovery; and finally, bandpass filtering. During gain recovery, the array acoustic waveform is divided by AGN; the formula for calculating the gain parameter AGN is as follows: AGN=10 GN*0.05 In the formula, GN is the noise gain; Delay recovery involves filling the array acoustic waveform with zeros before the zero moment, thereby obtaining waveform data with accurate timing.
4. The method for calculating formation porosity based on horizontal well acoustic logging data according to claim 1, characterized in that, In step 2, the time-time correlation method is selected to extract the horizontal longitudinal wave time difference from the monopole longitudinal wave array waveform. This time-time correlation method calculates the correlation function of the monopole longitudinal wave array waveform in two dimensions: time and time difference. The time difference where the maximum value of the correlation function is located is the horizontal longitudinal wave time difference.
5. The method for calculating formation porosity based on horizontal well acoustic logging data according to claim 4, characterized in that, The time-time difference correlation method works as follows: First, a time window is opened for the multiple channels of the single-pole longitudinal wave array waveform. The correlation function values of the multiple channels within the time window are calculated. Then, the slope of the time window is gradually changed within the slowness search range, and the correlation function values are calculated again. After the entire time difference range has been calculated, the time of the time window is moved forward by one position, and the same time difference search calculation is performed again until the entire time range has been calculated. The formula for calculating the correlation function Corr is as follows: In the formula, DT represents the horizontal longitudinal wave time difference, Time represents the start time of the current time window, CWLENTH represents the duration of the time window, N represents the number of channels in the monopole longitudinal wave array waveform, m is the channel number of the monopole longitudinal wave array waveform, and RRSP represents the distance between two adjacent receivers.
6. The method for calculating formation porosity based on horizontal well acoustic logging data according to claim 1, characterized in that, In step 3, the horizontal and vertical shear wave array waveforms are inverted by combining the RB azimuth curves with the preprocessed four-component dipole shear wave array waveforms. Assuming the RB azimuth curve refers to the angle at which the X(+) plate is rotated counterclockwise to the high side of the horizontal wellbore, according to the vector composition and decomposition rules, the inversion formulas for the horizontal and vertical shear wave array waveforms after rotating the X(+) plate to the high side of the horizontal wellbore are: In the formula, SH is the horizontal shear wave array waveform, SV is the vertical shear wave array waveform, RB is the RB azimuth curve, XX is the XX component dipole shear wave array waveform, XY is the XY component dipole shear wave array waveform, YX is the YX component dipole shear wave array waveform, and YY is the YY component dipole shear wave array waveform.
7. The method for calculating formation porosity based on horizontal well acoustic logging data according to claim 1, characterized in that, In step 4, the calculation formula for calculating the shear wave anisotropy of the shale reservoir at each depth point is as follows: In the formula, TI S (i) represents the transverse wave anisotropy at the i-th depth point; DT SH (i) represents the horizontal transverse wave time difference at the i-th depth point, DT SV (i) represents the vertical transverse wave time difference at the i-th depth point.
8. The method for calculating formation porosity based on horizontal well acoustic logging data according to claim 1, characterized in that, In step 5, a full-diameter core sample is taken and further cut in the laboratory to obtain vertical and horizontal plunger samples. P-wave and S-wave transit time measurements are performed on both samples, and the P-wave and S-wave anisotropy corresponding to the plunger samples are calculated. The ratio of these two values yields the P-wave and S-wave anisotropy conversion ratio, calculated using the following formula: In the formula, DT SVR DT represents the transverse wave time corresponding to the vertical plunger rock sample experiment. SHR TI represents the transverse wave time difference corresponding to horizontal plunger rock sample experiments. PR The representative plunger rock sample experiment corresponds to the longitudinal wave anisotropy, DT PVR DT represents the P-wave time difference corresponding to the vertical plunger rock sample experiment. PHR TI represents the longitudinal wave time difference corresponding to horizontal plunger rock sample experiments. SR The RTI represents the transverse anisotropy corresponding to the plunger rock sample experiment, and the P-wave to S-wave anisotropy conversion ratio.
9. The method for calculating formation porosity based on horizontal well acoustic logging data according to claim 1, characterized in that, In step 6, the formula for calculating the vertical P-wave time difference at each depth point is as follows: IT P (i)=TI S (i)·RTI In the formula, TI P (i) represents the longitudinal wave anisotropy at the i-th depth point; TI S (i) represents the transverse wave anisotropy at the i-th depth point; RTI represents the ratio of anisotropy conversion between P-waves and S-waves; DT PV (i) represents the vertical P-wave time difference at the i-th depth point; DT PH (i) represents the horizontal P-wave time difference at the i-th depth point.
10. The method for calculating formation porosity based on horizontal well acoustic logging data according to claim 1, characterized in that, In step 7, the formation porosity of the horizontal well is calculated point by point using the Willy time evaluation formula: In the formula, φ s (i) represents the formation porosity at the i-th depth point, DT ma DT represents the time lag of the reservoir rock framework in this region. f This represents the sonic travel time of the fluid in the horizontal well.