Fracture porosity calculation method for complex lithologic carbonate rocks

Abstract

The invention belongs to the technical field of oil and gas logging, and particularly relates to a crack porosity calculation method for complex lithologic carbonate rocks, which comprises the following steps: S1, acquiring a correlation curve reflecting the shale content of a stratum; the correlation curve comprises a natural gamma curve and a potassium thorium curve; s2, selecting a curve with good correlation between the shale content and the element logging shale content from the S1 to calculate the shale content; s3, determining a critical value of the shale content according to the imaging data; S4, introducing potassium and thorium as a limiting condition to constrain a crack porosity calculation formula: when the potassium and thorium sum is greater than or equal to the critical value determined in S3, the crack porosity is 0; when the sum of potassium and thorium is smaller than the critical value determined in S3, the fracture porosity is calculated through a fracture porosity calculation formula; s5, reservoir division is carried out according to the fracture porosity obtained through calculation in the step S4; the method provided by the invention can be used for calculating the fracture porosity under complex lithologic conditions, and the accuracy of reservoir identification is improved.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas well logging, and in particular relates to a fracture porosity calculation method for complex lithology carbonate rocks. Background Art

[0002] The current fracture porosity calculation method is to calculate it through a calculation formula without excluding the influence of mud. The porosity calculated by this method is often affected by the decrease in resistivity caused by mud, which leads to a larger calculation result and makes it difficult to divide the reservoir efficiently and accurately.

[0003] The prior art attempts to consider the influence of mud to calculate the fracture porosity. For example, invention patent 202110513391.7 discloses a method and device for calculating reservoir filling material content and porosity. According to the natural gamma logging curve of the reservoir, and according to the matching degree between the mud content of the reservoir and the natural gamma logging curve, different methods are selected to obtain the mud content. If the mud content of the reservoir matches the natural gamma logging curve well, the mud content is calculated by using the relative value of natural gamma and natural potential. If the relationship between the mud content of the reservoir and the natural gamma logging curve is complex and cannot be well matched, and cannot reflect the mud content well, the natural gamma logging curve is used. The relative value calculation chart is used to obtain the mud content, and the calcium content is calculated taking into account the influence of the calcium content on the reservoir properties, and the reservoir porosity can be calculated based on the mud content and the calcium content respectively. The mud and calcium fillings in the reservoir are comprehensively considered, and the filling content porosity in the reservoir can be quickly, accurately and reliably obtained, providing technical guidance for oil and gas logging. However, the invention does not involve the use of electrical imaging data to determine the critical value of the mud content, so it is not clear when and how to add other factors to consider. At the same time, it also does not involve the calculation method of fracture porosity constrained by mud content, which results in the obtained fracture porosity being inaccurate and it is difficult to accurately divide the reservoir. Summary of the invention

[0004] The present invention solves the problem that the fracture porosity obtained by the existing fracture porosity calculation method in the prior art is inaccurate, which makes it difficult to accurately divide the reservoir, and proposes a fracture porosity calculation method for complex lithology carbonate rocks. By introducing the use conditions of the fracture porosity calculation formula, the accuracy of reservoir division is improved.

[0005] The technical solution claimed in the present invention is as follows:

[0006] A fracture porosity calculation method for complex lithology carbonate rocks comprises the following steps:

[0007] S1: Obtaining a correlation curve reflecting the mud content of the formation; the correlation curve includes a natural gamma curve and a potassium-thorium curve;

[0008] S2: Select the relevant curve with a good correlation between the shale content and the shale content in the elemental logging to calculate the shale content; the selected relevant curve is the potassium-thorium sum curve;

[0009] S3: Determine the influence of the shale content on the reservoir capacity: According to the imaging data, when the shale content calculated in S2 is greater than a certain critical value, the reservoir has no reservoir capacity, that is, the reservoir is an ineffective reservoir;

[0010] S4: Based on the relevant curve selected in S2 and the critical value in S3, introduce the potassium-thorium sum value as a limiting condition to constrain the fracture porosity calculation formula: when the potassium-thorium sum value is greater than or equal to the critical value in S3, the fracture porosity is 0; when the potassium-thorium sum value is less than the critical value in S3, use the fracture porosity calculation formula to calculate the fracture porosity;

[0011] S5: Divide the reservoir according to the fracture porosity calculated in S4.

[0012] In a specific embodiment of the present invention, the critical value in S3 is determined by the statistical results of the test conclusions.

[0013] Preferably, the critical value in S3 is 20.

[0014] Preferably, the boundary value of the potassium-thorium sum value in S4 is 20.

[0015] Preferably, when the shale content in S3 is greater than a certain critical value, the average value of the fracture porosity is 0.000086, and the value approaches 0.

[0016] Preferably, when the potassium-thorium sum value is less than the critical value, the calculation formula of the fracture porosity is as follows:

[0017]

[0018] Among them, φ F represents the fracture porosity, %; Rd represents the deep resistivity logging value, Ω.m; Rs represents the shallow resistivity logging value, Ω.m; R MF represents the resistivity of the mud filtrate, Ω.m; A1, A2, A3 are constants, and their values are determined according to the fracture state.

[0019] In the specific embodiments of the present invention, the values of A1, A2, and A3 under different fracture states are as follows: when Y < 0, the fracture dip angle is less than 50 degrees, which is a low-angle fracture, and A1, A2, and A3 are -1.28751, 1.76982, and 0.000295 respectively; when 0 ≤ Y ≤ 0.1, the fracture dip angle ranges from 50 degrees to 74 degrees, which is an inclined fracture, and A1, A2, and A3 are -4.960181, 6.108863, and 0.001918 respectively; when Y > 0.1, the fracture dip angle is greater than 74 degrees, which is a high-angle fracture, and A1, A2, and A3 are -0.52436, -0.212330, and 0.006523 respectively.

[0020] Preferably, in S5, the reservoir is divided into a reservoir and a non-reservoir; the non-reservoir is an ineffective reservoir.

[0021] Preferably, when the fracture porosity is greater than 0.01%, it is a reservoir; when the fracture porosity is less than or equal to 0.01%, it is a non-reservoir.

[0022] Preferably, the method for calculating the fracture porosity of complex lithology carbonate rocks can be applied to the calculation of fracture porosity of multiple reservoir types.

[0023] Beneficial effects:

[0024] The present invention provides a method for calculating the fracture porosity of complex lithology carbonate rocks, which obtains relevant curves reflecting the shale content of the formation and preferably calculates the shale content using curves with good correlation between the shale content and the elemental logging shale content; through imaging data, when the shale content is greater than a certain critical value, the reservoir is determined as an ineffective reservoir. Based on the relevant curve (potassium-thorium sum curve) selected in S2 and the critical value in S3, the potassium-thorium sum value is introduced as a limiting condition to constrain the fracture porosity calculation formula, and the fracture porosity calculation formula is determined by comparing the critical value with the potassium-thorium sum, and the reservoir is divided through the calculated fracture porosity; the present invention introduces the shale content critical value, that is, considering when the critical value appears, and more comprehensively considers the influence of shale on the fracture porosity. The porosity calculation formula can be used not only for limestone and dolomite formations, but also for calculating the fracture porosity under other complex lithologies (including gypsum rock and salt rock) formations. In actual production, the calculation of fracture porosity is mainly affected by two parameters, the deep resistivity log value Rd and the shallow resistivity log value Rs. The shale content will cause a significant decrease in the deep resistivity log value Rd and the shallow resistivity log value Rs, resulting in an overestimated fracture porosity calculation result, and thus the situation of misidentifying a non-reservoir as a reservoir. After eliminating the influence caused by the shale content, the accuracy of fracture porosity calculation can be significantly improved, thereby improving the accuracy of reservoir identification and solving the problem that the fracture porosity obtained by the existing fracture porosity calculation method is inaccurate, making it difficult to accurately divide the reservoir.

[0025] The relevant curve selected in S2 is the potassium-thorium sum curve. It is found through the measured curve that the shale content calculated by the potassium-thorium sum curve has a good correlation with the shale content in elemental logging. Therefore, the potassium-thorium sum curve can calculate the shale content more accurately. BRIEF DESCRIPTION OF THE DRAWINGS

[0026] Figure 1 It is a flow chart of the solution of the present invention.

[0027] Figure 2 It is the shale laminae of carbonate rock identified by electrical imaging in the embodiment of the present invention; wherein: (a) is the calculation result diagram of fracture porosity of conventional curve and the corresponding electrical imaging shows the shale laminae section; (b) is the interpretation result diagram of dipole array acoustic wave. In (b), in the carbonate rock sections of 7374 - 7376m and 7378 - 7380m, weak gas-bearing is shown, with low values of conventional natural gamma and resistivity. Although there is weak gas-bearing display in these two sections, due to the influence of shale, there is no attenuation of P-wave, S-wave and Stoneley wave, indicating no seepage ability and reservoir capacity, and it should actually be identified as a non-reservoir.

[0028] Figure 3 It is a schematic diagram of the correlation curve between the potassium-thorium sum curve and the shale content in elemental logging in the embodiment of the present invention. The left figure is the proportion diagram of shale content in elemental logging, and the right figure is the proportion diagram of potassium-thorium sum distribution.

[0029] Figure 4 It is a comparison diagram of the shale content in the formation reflected by the potassium-thorium sum curve and the natural gamma log curve in the embodiment of the present invention.

[0030] Figure 5 It is a crossplot of the potassium-thorium sum value KTH and the deep resistivity log value Rd of the production well in the embodiment of the present invention. The abscissa is the potassium-thorium sum value KTH, and the ordinate is the deep resistivity log value Rd. DETAILED DESCRIPTION OF THE INVENTION

[0031] The present invention will be further described below with reference to the drawings:

[0032] A method for calculating fracture porosity of carbonate rock with complex lithology, as Figure 1 shown, includes the following steps:

[0033] S1: Obtain relevant curves reflecting the shale content in the formation; the relevant curves include natural gamma curve and potassium-thorium sum curve; using electrical imaging data, it is judged according to the electrical imaging to identify shale laminae that a large amount of shale in carbonate rock will affect the calculation of fracture porosity of carbonate rock. As Figure 2 (a) shows, in the section with developed shale, the conventionally calculated fracture porosity is large, and the imaging shows shale laminae without fracture development; in actual production, generally, the oil and gas shows in logging are important indicators for judging oil and gas layers. As Figure 2As shown in (b), there are weak gas-bearing shows in the intervals of 7374 - 7376m and 7378 - 7380m, which can be judged as oil and gas-bearing. However, due to the influence of shale, there is no attenuation of P-wave, S-wave, and Stoneley wave in these two intervals, indicating no seepage capacity and reservoir capacity. Actually, it should be identified as a non-reservoir. Therefore, it is necessary to accurately determine the shale content in carbonate rocks and determine the fracture porosity calculation formula by considering the influence of shale content.

[0034] S2: Select the correlation curve with a good correlation between the shale content and the shale content of elemental logging from S1 to calculate the shale content; the selected correlation curve is the potassium-thorium sum curve; by observing the proportion diagram of elemental logging shale content ( Figure 3 left) and the proportion diagram of potassium-thorium sum value distribution ( Figure 3 right), it can be seen that both the trends and proportions are consistent, and the correlation is relatively high; as Figure 4 shown, when there is a large difference between the natural gamma curve and the potassium-thorium sum curve, the shale content calculated by the potassium-thorium sum curve has a good correlation with the shale content of elemental logging. Thus, it is judged that the potassium-thorium sum curve can accurately calculate the shale content.

[0035] S3: Determine the influence of shale content on reservoir capacity: According to the imaging data, when the shale content calculated in S2 is greater than a certain critical value, the reservoir has no reservoir capacity, that is, the reservoir is an ineffective reservoir; when the shale content is greater than a certain critical value, the pore frequency spectrum analysis method is used for calculation, and the average value of fracture porosity is 0.000086, and the value approaches zero. In a specific embodiment of the present invention, the critical value determined by the statistical results of test conclusions is 20. As Figure 5 shown, by analyzing the production wells (including oil-producing wells and water-producing wells), the critical value is determined by the cross-plot of the potassium-thorium sum value KTH and the deep resistivity logging value Rd, and the critical value is the value (potassium-thorium sum value) corresponding to the point on the potassium-thorium sum curve of the production well. Therefore, the following can use the potassium-thorium sum value as a limiting condition to constrain the fracture porosity calculation formula, and determine the boundary value of the potassium-thorium sum value as the critical value 20.

[0036] S4: Based on the correlation curve (potassium-thorium sum curve) selected in S2 and the critical value in S3, introduce the potassium-thorium sum value as a limiting condition to constrain the fracture porosity calculation formula: when the potassium-thorium sum value is greater than or equal to the critical value determined in S3, the fracture porosity is 0; when the potassium-thorium sum value is less than the critical value determined in S3, use the fracture porosity calculation formula to calculate the fracture porosity;

[0037] When the potassium-thorium sum value is less than the critical value, the calculation formula of fracture porosity is as follows:

[0038]

[0039] Where: φ FIndicates the fracture porosity, %; Rd indicates the deep resistivity logging value, Ω·m; Rs indicates the shallow resistivity logging value, Ω·m; R MF Indicates the resistivity of the mud filtrate, Ω·m; A1, A2, and A3 are constants, and their values are determined according to the fracture state.

[0040] In a specific embodiment of the present invention, the values of A1, A2, and A3 are determined according to the fracture angle; the values of A1, A2, and A3 under different fracture states are as follows: when Y < 0, the fracture dip angle is less than 50 degrees, which is a low-angle fracture, and A1, A2, and A3 are -1.28751, 1.76982, and 0.000295 respectively; when 0 ≤ Y ≤ 0.1, the fracture dip angle ranges from 50 degrees to 74 degrees, which is an inclined fracture, and A1, A2, and A3 are -4.960181, 6.108863, and 0.001918 respectively; when Y > 0.1, the fracture dip angle is greater than 74 degrees, which is a high-angle fracture, and A1, A2, and A3 are -0.52436, -0.212330, and 0.006523 respectively; the values of A1, A2, and A3 under different fracture angles are shown in the following table:

[0041]

[0042] S5: Perform reservoir division according to the fracture porosity calculated in S4; divide the reservoir into a reservoir and a non-reservoir, and the non-reservoir is an ineffective reservoir; the fracture porosity greater than 0.01% is the reservoir; the fracture porosity less than or equal to 0.01% is the non-reservoir.

[0043] In a specific embodiment of the present invention, the above method can be applied to the calculation of fracture porosity of multiple reservoir types.

[0044] Although the present invention has been disclosed above with preferred embodiments, it is not intended to limit the present invention. Anyone familiar with this technology can make various modifications and decorations without departing from the spirit and scope of the present invention. Therefore, the protection scope of the present invention should be defined by the claims.

Claims

1. A method for calculating fracture porosity of complex lithology carbonate rocks, characterized in that, It includes the following steps: S1: Obtain relevant curves reflecting the shale content of the formation; the relevant curves include the natural gamma curve and the potassium-thorium sum curve; S2: Select from S1 the relevant curve with a good correlation between the shale content and the shale content of the elemental logging to calculate the shale content; the selected relevant curve is the potassium-thorium sum curve; S3: Determine the influence of the shale content on the reservoir capacity: According to the imaging data, when the shale content calculated in S2 is greater than a certain critical value, the reservoir has no reservoir capacity, that is, the reservoir is an ineffective reservoir; S4: Based on the relevant curve selected in S2 and the critical value in S3, introduce the potassium-thorium sum value as a limiting condition to constrain the fracture porosity calculation formula: When the potassium-thorium sum value is greater than or equal to the critical value in S3, the fracture porosity is 0; when the potassium-thorium sum value is less than the critical value in S3, use the fracture porosity calculation formula to calculate the fracture porosity; S5: Divide the reservoir according to the fracture porosity calculated in S4.

2. The method for calculating fracture porosity of complex lithology carbonate rocks according to claim 1, wherein The critical value in S3 is determined by the statistical results of the test conclusions.

3. The method for calculating fracture porosity of complex lithology carbonate rocks according to claim 2, characterized in that, The critical value in S3 is 20.

4. The method for calculating fracture porosity of complex lithology carbonate rocks according to claim 3, characterized in that The boundary value of the potassium-thorium sum value in S4 is 20.

5. The method for calculating fracture porosity of complex lithology carbonate rocks according to claim 3, characterized in that When the shale content in S3 is greater than a certain critical value, the average fracture porosity is 0.000086, and the value approaches 0.

6. The method for calculating fracture porosity of complex lithology carbonate rocks according to claim 3, wherein When the potassium-thorium sum value is less than the critical value, the calculation formula for the fracture porosity is as follows: Among them, φ F represents the fracture porosity, %; Rd represents the deep resistivity log value, Ω·m; Rs represents the shallow resistivity log value, Ω·m; R MF represents the resistivity of the mud filtrate, Ω·m; A1, A2, and A3 are constants, and their values are determined according to the fracture state.

7. The method for calculating fracture porosity of complex lithology carbonate rocks according to claim 6, characterized in that, The values of A1, A2, and A3 in different fracture states are: when Y < 0, the fracture dip angle is less than 50 degrees, which is a low-angle fracture, and A1, A2, and A3 are -1.28751, 1.76982, and 0.000295 respectively; when 0 ≤ Y ≤ 0.1, the fracture dip angle range is between 50 degrees and 74 degrees, which is an inclined fracture, and A1, A2, and A3 are -4.960181, 6.108863, and 0.001918 respectively; when Y > 0.1, the fracture dip angle is greater than 74 degrees, which is a high-angle fracture, and A1, A2, and A3 are -0.52436, -0.212330, and 0.006523 respectively.

8. The method for calculating fracture porosity of complex lithology carbonate rocks according to any one of claims 1-7, characterized in that, In S5, the reservoir is divided into a reservoir and a non-reservoir; the non-reservoir is an ineffective reservoir.

9. The method for calculating fracture porosity of complex lithology carbonate rocks according to claim 8, characterized in that, The fracture porosity greater than 0.01% is a reservoir; the fracture porosity less than or equal to 0.01% is a non-reservoir.

10. The method for calculating fracture porosity of complex lithology carbonate rocks according to any one of claims 1-7, characterized in that, It can be applied to the calculation of fracture porosity for multiple reservoir types.

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