CN112065361A - Method for determining gas saturation of tight reservoir based on sound wave attenuation - Google Patents

Method for determining gas saturation of tight reservoir based on sound wave attenuation Download PDF

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CN112065361A
CN112065361A CN202010971966.5A CN202010971966A CN112065361A CN 112065361 A CN112065361 A CN 112065361A CN 202010971966 A CN202010971966 A CN 202010971966A CN 112065361 A CN112065361 A CN 112065361A
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attenuation
gas saturation
saturation
ratio
gas
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CN112065361B (en
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漆乔木
曹俊兴
王兴建
杨宇勇
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Chengdu Univeristy of Technology
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells

Abstract

The invention discloses a method for determining gas saturation of a tight reservoir based on sound wave attenuation, which belongs to the technical field of gas reservoir exploration and development and comprises the steps of obtaining measured sound waves and conventional logging data and respectively obtaining longitudinal wave attenuation according to the data in the step (1)
Figure DDA0002684401530000011
And transverse wave attenuation
Figure DDA0002684401530000012
Calculating the ratio of longitudinal wave attenuation to transverse wave attenuation

Description

Method for determining gas saturation of tight reservoir based on sound wave attenuation
Technical Field
The invention relates to the technical field of gas reservoir exploration and development, in particular to a method for determining gas saturation of a tight reservoir based on sound wave attenuation.
Background
The formation gas saturation has important significance for predicting the future reservoir dynamics, and is an important parameter for estimating the oil and gas reserves (Rezaee, 2015). Accurate estimation of gas saturation has been one of the most challenging calculations related to petrophysical properties, especially for low pore, hypotonic shale and tight gas reservoirs (Xu et al, 2017). The alder equation was originally developed for clean sandstone and is generally not applicable to clay-bearing shales and heterogeneous tight formations. To solve the unconventional resource saturation determination problem, the scholars propose improved Simandoux, indonesia, whole shale and bi-water models. These methods are applicable to typical high gas barrier layers. However, they often underestimate the gas saturation of low resistivity reservoirs. The low-resistivity oil layer refers to the difference of low resistivity between a reservoir water-bearing segment and a hydrocarbon-bearing segment, and the formation causes of the difference are various, such as abundant micropores and conductive minerals, such as pyrite, in organic shale. Traditional methods of saturation analysis are based on electrical logging information and often do not accurately reflect the gas content of shale and tight gas reservoirs, particularly low resistivity reservoirs. Therefore, it is highly desirable to provide a more accurate saturation determination method.
Disclosure of Invention
The invention aims to provide a method for determining the gas saturation of a tight reservoir based on sound wave attenuation so as to solve the problems.
In order to achieve the purpose, the technical scheme adopted by the invention is as follows:
a tight reservoir gas saturation determination method based on acoustic attenuation comprises the following steps:
(1) acquiring and obtaining measurement sound waves and logging data;
(2) respectively calculating the longitudinal wave attenuation of each depth point according to the measured acoustic wave and the logging data obtained in the step (1)
Figure BDA0002684401510000021
And transverse wave attenuation
Figure BDA0002684401510000022
And based on attenuation of longitudinal waves at various points of depth
Figure BDA0002684401510000023
Drawing to obtain a longitudinal wave attenuation logging curve, and based on the transverse wave attenuation of each depth point
Figure BDA0002684401510000024
Drawing to obtain a transverse wave attenuation logging curve;
(3) calculating to obtain the ratio of longitudinal wave attenuation to transverse wave attenuation of each depth point
Figure BDA0002684401510000025
(4) When the rock core exists, the gas saturation of the rock core is taken as the ordinate, and the ratio obtained in the step (3)
Figure BDA0002684401510000026
Drawing to obtain a saturation-attenuation ratio relation graph as a horizontal coordinate; in the saturation-attenuation ratio graph, linear least square fitting is carried out on the scatter point relation, and x represents
Figure BDA0002684401510000027
The attenuation ratio, y, represents the gas saturation, and the fit yields the relationship as follows:
y＝b+a×x
wherein the coefficients a and b are respectively a slope and an intercept in a linear least square fitting relationship;
finally, the attenuation ratio obtained by extracting each depth point
Figure BDA0002684401510000028
Substituting the formula to obtain and output a final gas saturation logging curve:
Figure BDA0002684401510000029
(b) without a core, the attenuation ratio is first adjusted
Figure BDA00026844015100000210
The logging curve is converted into a double-peak probability histogram, the abscissa of the histogram is the arrangement distribution of the attenuation ratios from small to large, and the ordinate of the histogram is each attenuation ratio
Figure BDA00026844015100000211
Percentage number of data points within the range; then setting the first peak value of the double-peak probability histogram as the minimum gas saturation of the stratum, namely the gas saturation is zero, setting the second peak value as the maximum gas saturation of the stratum, and obtaining the maximum water saturation calculated by subtracting a resistivity logging curve from 1; finally recording the correspondence of the positions of the two peaks
Figure BDA00026844015100000212
A value size;
then the attenuation ratio distributed between the two peaks
Figure BDA0002684401510000031
Performing linear normalization processing to obtain the gas saturation corresponding to the attenuation ratio of each depth point;
will attenuate the ratio
Figure BDA0002684401510000032
Assigning a formation gas saturation less than the first peak value to a minimum gas saturation value, and assigning an attenuation ratio
Figure BDA0002684401510000033
Assigning a formation gas saturation greater than the second peak value as a maximum gas saturation;
and finally outputting a final gas saturation logging curve.
The inventor of the application shows through a large number of experimental experiments and combined with theoretical analysis that: in tight reservoir rock, the P-S wave attenuation ratio and the gas saturation are in a linear positive correlation relationship. The attenuation ratio and neutron density porosity difference logs show the same trend in different formations. The consistency of the two different oil and gas indexes shows that the attenuation ratio is most sensitive to the pore fluid saturation and is less influenced by lithology changes. In view of the above, the inventor proposes a method for constructing a saturation logging curve by using attenuation ratio based on the analysis result of the correlation between the acoustic attenuation ratio and the gas saturation of the rock core. Meanwhile, under the condition of no core saturation data, the inventor proposes another tight reservoir gas saturation determination method based on the attenuation ratio probability histogram. Compared with the conventional resistivity method, the attenuation method is used as a non-electrical method, and can be used for more accurately predicting the gas saturation of the low-resistivity reservoir rock. Practical application results show that the method can effectively analyze the gas content of tight reservoirs such as shale and carbonate rock.
As a preferred technical scheme: in the step (2), the longitudinal wave is attenuated
Figure BDA0002684401510000034
The method of obtaining (1) is a median frequency shift method.
Specifically, the median frequency shift method proposed by Sun et al (P-and S-wave attenuation from monomer sonic data, 2000) is preferably employed. The method can be summarized as follows: the monopole longitudinal wave head wave amplitude spectrum recorded by the ith receiver on the array acoustic wave instrument can be written as follows:
Xi(z，f)＝S(f)CS(z，f)Ri(f)CR(z，f)Gi(z，f，di)exp(-αdi)， (3)
where f is the frequency, diIs the offset of the source to the ith receiver and z is the measured depth, defined as the center point between the source and the ith receiver. S and RiRespectively, the source spectrum and the receiving instrument response. CSAnd CRRespectively, the coupling function of the source and receiver. G is a geometric spreading function related to frequency and depth. α ═ π f/(Q)pVp) Is the attenuation coefficient, which contains the quality factor QpSum wave velocity Vp。
By taking the natural logarithm of both sides of equation (3) and rearranging, we obtain:
Φi(z，f)＝φi(z)+Ai(z，f)， (4)
wherein phii＝2lnXi/ω，
Figure BDA0002684401510000041
And Ai＝2ln(SCSRiCRGi)/ω。ΔtiIs the head wave arrival time, approximately equal to di/Vp. The spectrum Φ consists of a frequency independent term Φ and a frequency dependent term a. The central idea of the median frequency shift method is to apply a series of mean and median filters to phi to eliminate the frequency dependent term a. Thus, the log is attenuated, i.e.
Figure BDA0002684401510000042
Can be directly obtained from phi. Based on the algorithm, the equation for estimating the monopole longitudinal wave attenuation is as follows:
Figure BDA0002684401510000043
wherein the content of the first and second substances,
Figure BDA0002684401510000044
here, the first and second liquid crystal display panels are,
Figure BDA0002684401510000045
represents phii(z, f) average over frequency, similarly,
Figure BDA0002684401510000046
means taking the median. The attenuation obtained from equation (5) is a relative value whose magnitude depends on the attenuation value at the depth ξ
Figure BDA0002684401510000047
And next, by utilizing data of two offset distances, the real stratum attenuation can be recovered:
Figure BDA0002684401510000048
wherein:
Figure BDA0002684401510000049
since the a term in equation (4) may also be depth dependent, averaging alone is generally not sufficient to eliminate a from Φ, and the resulting attenuation may be biased. To solve this problem, the modified spectrum of Sun et al (P-and S-wave attenuation from monomer sonic data, 2000) can be used
Figure BDA0002684401510000051
Figure BDA0002684401510000052
Is the synthetic spectrum modeled by the elastic waveform. Subtracting this spectrum from the original data spectrum will reduce the depth dependence of the a term. And then, carrying out mean filtering and median filtering on the corrected frequency spectrum to generate a longitudinal wave attenuation logging curve.
As a preferred technical scheme: in the step (2), the transverse wave is attenuated
Figure BDA00026844015100000511
The obtaining method of (2) is a multi-frequency inversion method.
Specifically, the multi-frequency inversion method proposed by Qi et al (Determination of formation shear estimation from dipole sonic log data 2019) is preferably employed. Dipole sources primarily excite flexural waves that propagate at the formation shear wave velocity and experience shear wave attenuation in the low frequency band. Dipole flexural wave is a borehole guided wave whose attenuation varies with frequency and can be expressed as:
Figure BDA0002684401510000053
wherein the content of the first and second substances,
Figure BDA0002684401510000054
in the above formulas (9) and (10), the subscripts p, s, f represent the formation longitudinal wave, the formation transverse wave, and the mud longitudinal wave, respectively; piIs the energy distribution coefficient, which is the ratio of the bulk wave velocity to the bending wave group velocity (i.e., V)i/Uflex) And the partial derivative of the bending wave phase velocity with respect to the bulk wave velocity (i.e.
Figure BDA0002684401510000055
) The product of the two. The velocity and attenuation of flexural waves with frequency can be estimated from dipole waveforms using weighted spectral similarity analysis (Tang and Cheng, 2004). According to the formula (9), the inventor establishes a linear optimization problem by min | | Ax-b | | survival of the fly ash2Solving for longitudinal wave attenuation
Figure BDA0002684401510000056
Transverse wave attenuation
Figure BDA0002684401510000057
And mud attenuation
Figure BDA0002684401510000058
The linear operator of the system, i.e., a ═ p (f), consists of the energy distribution coefficients at N discrete frequencies. Data vectors, i.e.
Figure BDA0002684401510000059
Figure BDA00026844015100000510
Is the bending wave attenuation in the high frequency range.
Because the propagation speed of the bending wave in a high frequency band is far lower than that of the head wave, the inversion process effectively inhibits the interference of the first-arrival wave and provides accurate estimation of the attenuation of the transverse wave.
Compared with the prior art, the invention has the advantages that: the attenuation method is used as a non-electrical method, and can be used for more accurately predicting the gas saturation of low-resistivity reservoir rock; practical application results show that the method can effectively analyze the gas content of tight reservoirs such as shale and carbonate rock and has wide application range.
Drawings
FIG. 1 is a flow chart of a longitudinal wave attenuation extraction technique;
FIG. 2 is a flow chart of a transverse wave attenuation extraction technique;
FIG. 3 is a flow chart of the present invention for tight reservoir gas saturation determination based on acoustic attenuation;
FIG. 4 is the well log analysis of well A of example 1;
in the figure: a) the total gamma ray (SGR) is the sum of all radiation contributions, the Calculated Gamma Ray (CGR) is the sum of the potassium and thorium responses, excluding the uranium content; b) shallow resistivity (R)XO) And deep resistivity (R)t) (ii) a c) Bulk density; d) porosity; e) total Organic Carbon (TOC); f) gas saturation calculated from resistivity; the horizontal lines in each sub-plot represent core data;
FIG. 5 is a cross-plot of the relationship between core gas saturation and sonic logging properties;
in the figure, (a) gas saturation and attenuation ratio
Figure BDA0002684401510000061
The relationship of (1); (b) gas saturation and velocity ratio Vp/VsThe relationship of (1);
FIG. 6 is a natural gas saturation evaluation of a Longmaxi shale formation in accordance with example 1 of the present invention: (a) free and adsorbed gas content ((m)3T)) (b) saturation calculated from resistivity; (c) calculating saturation according to the neutron density porosity difference; (d) according to
Figure BDA0002684401510000062
Calculated saturation (e) according to Vp/VsThe calculated saturation;
FIGS. 7a-f are well log analysis results of well B in example 2 of the present invention;
in the figure, (a) total gamma rays (SGR) and Calculated Gamma Rays (CGR); (B) Vp/VsA ratio; (c) shallow resistivity (R)XO) Deep resistivity (R)t)；(d)
Figure BDA0002684401510000071
A ratio; (e) neutron density-porosity difference; FIG. 7f is a graph of results of gas saturation determined by different methods;
fig. 8 (a) is a probability histogram of the method of the present invention, and (b) is a probability histogram of the neutron density porosity difference method.
Detailed Description
The invention will be further explained with reference to the drawings.
Example 1
Based on core calibration
Figure BDA0002684401510000072
Gas saturation calculation of (2):
the well A is a shale gas exploration well in southeast Sichuan area.
And determining the A underground Chinesia Longmaxi group as a main power producing layer. The Longmaxi group is 150m thick and mainly comprises silty carbonaceous shale, carbonaceous mudstone, calcareous and non-calcareous mudstone. The A-well log data is shown in FIG. 4. Comprehensive well logging and core data analysis show that the Longmaxi organic-rich shale mainly contains layered carbon shale phase, the Total Organic Carbon (TOC) content is 1.33-4.09 wt%, and vitrinite reflectivity (R)0) 2 to 3.8 percent of the total gas content of 0.9 to 4.8m3T is calculated. The gas shale has an average porosity of 4.1% and a permeability of 0.23 millidarcy; the total organic carbon and gas content tend to increase along with the depth; the natural gas mainly exists in the forms of free gas and secondary absorption gas; organic pores develop due to the high maturity of organic matter and the production and removal of hydrocarbons.
The traditional porosity calculation method is not suitable for the Longmaxi shale. An empirical relationship between the core porosity and the sonic moveout is introduced to calculate a porosity log for well A, and a bulk density method is used for calculating a TOC log (refer to: Huang et al, 2015, Selection of logging-based TOC calculation methods for shell velocities: A case study of the Jiaoshiba shell field in the Sichuan base). The calculated porosity, TOC and bulk density logs were in good agreement with the core data shown in fig. 4c, 4d and 4 e.
The Longmaxi shale from well A belongs to a resistivity-dip formation (reference: Xu et al, 2017, Two effective methods for calculating water formations in short-gas resurvoirs) because of the development of microfractures in organic-rich shale and the abundance of clay and pyrite minerals. Conventional methods are not suitable for saturation analysis of such low resistivity reservoirs. FIG. 4f shows a comparison between the core data and the calculated gas saturation from the resistivity Log (FIG. 4b), using a modified total shale equation (ref: Schlumberger,1987, Log interpretation criteria/applications: Schlumberger depletion Services; Xu et al, 2017). And directly outputting the water saturation by the modified total shale equation, and subtracting the water saturation by 1 for the two-phase gas reservoir to obtain the gas saturation.
Figure 4f shows that the natural gas saturation in the lower part of the formation (3670-3730m) is severely underestimated, while this part actually has the highest natural gas potential. The natural gas saturation in this interval is expected to be high because more hydrocarbons are produced by the increasingly mature kerogen. The resistivity method has a limited effect on analyzing the saturation of the Longmaxi organic-rich shale.
In this embodiment, a longitudinal wave attenuation log and a transverse wave attenuation log are extracted from monopole and dipole data sets respectively by applying a median frequency shift and a multi-frequency inversion method. The technical flows of the two methods are shown in fig. 1 and fig. 2. During the drilling phase of well a, a large number of cores have been recovered, covering the entire ramstream shale formation. Comprehensive petrophysical measurements including water saturation were performed on shale core samples. Core water saturation was determined by distillation (Rezaee, R.,2015, Fundamentals of gas share resurvoirs: John Wiley&Sons). The additional information obtained from the core data enabled the inventors to establish a quantitative relationship between attenuation and pore fluid saturation. FIGS. 5a and 5b show core gas saturation (obtained by subtracting core water saturation from 1) versus shale gas saturation
Figure BDA0002684401510000091
And Vp/VsThe relationship between them. Invention of the inventionIt was found that the gas saturation is respectively equal to
Figure BDA0002684401510000092
And Vp/VsThe ratio is positive and negative. The linear least squares fit yields the following relationship:
Figure BDA0002684401510000093
Sgas＝236-99×Vp/Vs (2)
within the range of the measured gas saturation, the gas saturation follows
Figure BDA0002684401510000094
The ratio increases with Vp/VsThe ratio increases and decreases. From equations (1) and (2), the inventors can calibrate and calibrate
Figure BDA0002684401510000095
And Vp/VsThe logging curve is converted into a gas saturation logging curve, and the specific technical process is shown in fig. 3. The results are shown in FIGS. 6d and 6 e. The gas content log calculated by direct desorption is shown in fig. 6 a. The gas saturation log from the decay rate fits well with the overall trends of the core measurements and free gas content. The gas saturation log from the velocity ratio substantially coincided with the core measurements, but underestimated the gas saturation at the top and bottom of the profile.
In summary, the method for determining gas saturation of tight reservoir based on acoustic attenuation provided by this embodiment includes the following steps:
(1) obtaining measured acoustic waves (measured by an array acoustic tool) and logging data (as shown in FIG. 4);
(2) respectively calculating the longitudinal wave attenuation of each depth point according to the measured acoustic wave and the logging data obtained in the step (1)
Figure BDA0002684401510000096
And transverse wave attenuation
Figure BDA0002684401510000097
And based on attenuation of longitudinal waves at various points of depth
Figure BDA0002684401510000098
Drawing to obtain a longitudinal wave attenuation logging curve, and based on the transverse wave attenuation of each depth point
Figure BDA0002684401510000099
Drawing to obtain a transverse wave attenuation logging curve;
(3) calculating to obtain the ratio of longitudinal wave attenuation to transverse wave attenuation of each depth point
Figure BDA00026844015100000910
(4) Taking the gas saturation of the rock core as a vertical coordinate, and obtaining the ratio in the step (3)
Figure BDA00026844015100000911
Drawing to obtain a saturation-attenuation ratio relation graph as a horizontal coordinate; in the saturation-attenuation ratio graph, linear least square fitting is carried out on the scatter point relation, and x represents
Figure BDA0002684401510000101
The attenuation ratio, y, represents the gas saturation, and the fit yields the relationship as follows:
y＝b+a×x
wherein the coefficients a and b are respectively a slope and an intercept in a linear least square fitting relationship;
finally, the attenuation ratio obtained by extracting each depth point
Figure BDA0002684401510000102
Substituting the formula to obtain and output a final gas saturation logging curve:
Figure BDA0002684401510000103
for comparison, the inventors also calculated natural gas saturation according to neutron density porosity difference method (zhangjin et al, 2017, "new method for low resistivity shale gas formation saturation calculation") developed for saturation evaluation of low resistivity reservoir rock, with the results shown in fig. 6 c. The gas saturation obtained from the neutron density difference was generally consistent with the core data, but was significantly underestimated at the top of the formation (3580-. Finally, compared with the saturation logging calculated by the resistivity method in fig. 6b, the attenuation method provided by the invention is used as a non-electrical method, so that the accuracy of the prediction of the natural gas in the low-resistivity shale is obviously improved.
Example 2:
based on
Figure BDA0002684401510000104
Calculation of gas saturation for ratio probability histogram (for coreless cases)
The well B and the well A are located in the same shale gas field, and the well logging data of the well B is shown in figure 7. The total thickness of the selected section is 791m, the section comprises a lower Shimadu to upper Ordoku stratum and consists of a lower Shimadu Han shop group (3577-. The low-gamma-ray high-resistivity fractured carbonate reservoir is identified as an original production layer and is located at the upper part (3975-. The carbonate reservoir had an average porosity of 3.2% and a permeability of 0.7 millidarcy. The low resistivity gas shale reservoir of the quincunx-Longmaxi group (4220-4368m) is determined as a secondary target.
The number of core data available for B wells is limited. Thus, the inventors were unable to calibrate as done for well A in example 1
Figure BDA0002684401510000111
The relation with the gas saturation. Thus, the inventors utilized the second method, i.e., when there is insufficient core data to calibrate
Figure BDA0002684401510000112
In a saturated relation, use
Figure BDA0002684401510000113
The gas saturation was calculated. The specific technical process is shown in fig. 3. As shown in the view of figure 8a,
Figure BDA0002684401510000114
the ratio follows an overall bimodal distribution. This enables the inventors to follow the maximum possible given the grey bar in FIG. 8a
Figure BDA0002684401510000115
The ratio determines two saturation baseline values. Similarly, the inventors can apply a similar method to calculate a saturation log from the density neutron porosity difference probability histogram shown in fig. 8 b.
That is, for the case of no core or lack of core data, a gas saturation log may be obtained by:
1) first attenuation ratio
Figure BDA0002684401510000116
The logging curve is converted into a double-peak probability histogram, the abscissa of the histogram is the arrangement distribution of the attenuation ratios from small to large, and the ordinate of the histogram is each attenuation ratio
Figure BDA0002684401510000117
Percentage number of data points within the range; then setting a first peak value of the double-peak probability histogram as the minimum gas saturation of the stratum, namely the gas saturation is zero, setting a second peak value as the maximum gas saturation of the stratum, wherein the second peak value is obtained by subtracting the maximum water saturation obtained by calculating a resistivity logging curve from 1; finally recording the correspondence of the positions of the two peaks
Figure BDA0002684401510000118
A value size;
2) will be distributed over two peaksAttenuation ratio between values
Figure BDA0002684401510000119
Performing linear normalization processing to obtain the gas saturation corresponding to the attenuation ratio of each depth point;
3) then the attenuation ratio
Figure BDA00026844015100001110
Assigning a minimum gas saturation value to the formation gas saturation less than the first peak, and assigning an attenuation ratio
Figure BDA00026844015100001111
Assigning a formation gas saturation greater than the second peak value as a maximum gas saturation;
4) and finally outputting the finally obtained gas saturation logging curve.
Finally, the inventors compared gas saturation calculated by different methods, including resistivity logging based methods. The results are shown in FIG. 7 f. According to
Figure BDA0002684401510000121
The neutron density-porosity difference and resistivity yield gas saturation logs that are generally very consistent. Although the principles of these saturation calculation methods are completely different, their results are consistent. This further confirms the reliability of the decay method. And in the lower part (4337-4368 m) of the Longmaxi group, the gas saturation predicted by the neutron density method is obviously greater than the predicted value of the attenuation method. This is because there is a considerable increase in organic matter (i.e., kerogen) in the shale in this interval, as shown by the difference between the total and calculated gamma rays in fig. 7 a. Typical organic matter particle densities of 1.1-1.4g/cm 3 are much lower than those of common rock-making minerals, the latter being 2.6-2.8g/cm 3. The density porosity calculated from the dolomite density overestimates the actual porosity due to the presence of organic matter. Thus, the neutron density porosity difference overestimates natural gas saturation. 5 cores were collected separately in one interval of Tanbotu gas carbonate (3984-. Attenuation methodThere is good agreement between the estimated value of (c) and the core saturation. At the same time, the neutron density method again slightly overestimates the natural gas saturation of the interval because the density-porosity calculations are sensitive to local lithological changes. In this case, it is preferable that the air conditioner,
Figure BDA0002684401510000122
the attributes extracted directly from the acoustic waveform can be used as an effective tool for natural gas saturation evaluation.
Comparing FIGS. 7b, 7c, 7d, and 7e, the differences in resistivity, neutron density porosity, and,
Figure BDA0002684401510000123
The overall trend of the three different logging curves along with the change of the depth is consistent, which shows that the three logging curves are all sensitive to the gas content of the stratum. However Vp/VsThe ratio has no obvious relation with the gas saturation of the stratum. Therefore, for the case that the target interval contains various lithologies, the gas saturation determination method based on the longitudinal-transverse wave time difference (refer to the patent CN 201611263196.9-gas saturation determination method and device) cannot effectively reflect the real gas saturation of the well section stratum generally.
The above description is only for the purpose of illustrating the preferred embodiments of the present invention and is not to be construed as limiting the invention, and any modifications, equivalents and improvements made within the spirit and principle of the present invention are intended to be included within the scope of the present invention.

Claims (3)

1. A tight reservoir gas saturation determination method based on sound wave attenuation is characterized by comprising the following steps:
(1) acquiring and obtaining measurement sound waves and logging data;
(2) respectively calculating the longitudinal wave attenuation of each depth point according to the measured acoustic wave and the logging data obtained in the step (1)
Figure FDA0002684401500000011
And transverse wave attenuation
Figure FDA0002684401500000012
And based on attenuation of longitudinal waves at various points of depth
Figure FDA0002684401500000013
Drawing to obtain a longitudinal wave attenuation logging curve, and based on the transverse wave attenuation of each depth point
Figure FDA0002684401500000014
Drawing to obtain a transverse wave attenuation logging curve;
(3) calculating to obtain the ratio of longitudinal wave attenuation to transverse wave attenuation of each depth point
Figure FDA0002684401500000015
(4) When the rock core exists, the gas saturation of the rock core is taken as the ordinate, and the ratio obtained in the step (3)
Figure FDA0002684401500000016
Drawing to obtain a saturation-attenuation ratio relation graph as a horizontal coordinate; in the saturation-attenuation ratio graph, linear least square fitting is carried out on the scatter point relation, and x represents
Figure FDA0002684401500000017
The attenuation ratio, y, represents the gas saturation, and the fit yields the relationship as follows:
y＝b+a×x
wherein the coefficients a and b are respectively a slope and an intercept in a linear least square fitting relationship;
finally, the attenuation ratio obtained by extracting each depth point
Figure FDA0002684401500000018
Substituting the formula to obtain and output a final gas saturation logging curve:
Figure FDA0002684401500000019
(b) without a core, the attenuation ratio is first adjusted
Figure FDA00026844015000000110
The logging curve is converted into a double-peak probability histogram, the abscissa of the histogram is the arrangement distribution of the attenuation ratios from small to large, and the ordinate of the histogram is each attenuation ratio
Figure FDA00026844015000000111
Percentage number of data points within the range; then setting a first peak value of the double-peak probability histogram as the minimum gas saturation of the stratum, namely the gas saturation is zero, setting a second peak value as the maximum gas saturation of the stratum, wherein the second peak value is obtained by subtracting the maximum water saturation obtained by calculating a resistivity logging curve from 1; finally recording the correspondence of the positions of the two peaks
Figure FDA00026844015000000112
A value size;
then the attenuation ratio distributed between the two peaks
Figure FDA0002684401500000021
Performing linear normalization processing to obtain the gas saturation corresponding to the attenuation ratio of each depth point;
will attenuate the ratio
Figure FDA0002684401500000022
Assigning a minimum gas saturation value to the formation gas saturation less than the first peak, and assigning an attenuation ratio
Figure FDA0002684401500000023
Assigning a formation gas saturation greater than the second peak value as a maximum gas saturation;
and finally outputting a final gas saturation logging curve.
2. According toThe method for determining the gas saturation of the tight reservoir based on the acoustic attenuation is characterized by comprising the following steps of: in the step (2), the longitudinal wave is attenuated
Figure FDA0002684401500000024
The method of obtaining (1) is a median frequency shift method.
3. The tight reservoir gas saturation determination method based on acoustic attenuation is characterized in that: in the step (2), the transverse wave is attenuated
Figure FDA0002684401500000025
The obtaining method of (2) is a multi-frequency inversion method.
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