A method for correcting acoustic travel time in horizontal well logging

Abstract

The present application relates to the technical field of well logging, in particular to a kind of horizontal well logging acoustic travel time correction method.Horizontal well logging acoustic travel time Δt, formation fast mineral content Vf, the included angle θ between borehole and formation layer are obtained in work area;The logging acoustic travel time Δtc of the corresponding guide eye well of horizontal well is obtained;Δt0, Vf0, θ0 of the horizontal well to be evaluated are obtained;Horizontal well logging acoustic travel time initial correction model Δtc=Δt*(1+a*Vf+b*cosθ+c) is established;According to horizontal well logging acoustic travel time initial correction model and Δtc, Δt, Vf, θ, determine model coefficients a, b, c, obtain horizontal well logging acoustic travel time correction model Δtc0=Δt0*(1+a*Vf0+b*cosθ0+c);Δt0, Vf0, θ0 of the horizontal well to be evaluated are brought into horizontal well logging acoustic travel time correction model, and the corrected logging acoustic travel time Δtc0 of the horizontal well to be evaluated is calculated.This method greatly reduces the difficulty and cost of data acquisition, and the correction process is simple, and the correction result is accurate.

Description

Technical Field

[0001] This invention relates to the field of well logging technology, and specifically to a method for correcting the sonic time difference in horizontal well logging. Background Technology

[0002] Sonic transit-time logging is an important method for evaluating reservoir properties. However, current sonic logging instruments are designed for vertical well environments, which leads to significant differences in sonic transit time between horizontal and vertical wells when applied to horizontal wells. Furthermore, porosity logging interpretation models established using sonic logging are generally based on vertical wells. Therefore, to accurately determine formation porosity using sonic logging, corrections for sonic transit time in horizontal wells are necessary.

[0003] Currently, publicly available methods for correcting sonic transit time in horizontal well logging mainly analyze the geometric relationship between the wellbore trajectory and the formation interface, as well as formation anisotropy. For correcting rock anisotropy, domestic and international scholars primarily determine formation anisotropy parameters through experimental conditions. While these methods have achieved certain geological results, they suffer from high costs and complex correction processes due to the need for extensive rock anisotropy core data.

[0004] Chinese patent application CN102454399B discloses a method for correcting acoustic transit time signals in well logging. This method utilizes acoustic transit time data along with spontaneous potential, neutron, density, resistivity, wellbore, drilling time (logging), and burial depth data. Through recursive data processing, it corrects the distortion of the acoustic transit time curve, thereby improving the quality of well logging acoustic transit time data. This method is applicable to the correction of acoustic transit time distortion in vertical wells but not to horizontal wells or shale formations containing fast-moving mineral interlayers.

[0005] Chinese patent application CN110320562B discloses a method for correcting sonic transit time in horizontal wells of shale gas reservoirs, constructing a horizontal well sonic transit time correction model that includes the degree of anisotropy and the true dip angle. This method involves core testing, which is costly, requires multiple numerical simulations, and is computationally cumbersome and overly complex.

[0006] Studies have found that rapid mineral interlayers in formations can affect formation anisotropy, thus having a significant impact on the sonic logging time difference in horizontal wells. Therefore, a more convenient correction method needs to be proposed. Summary of the Invention

[0007] The purpose of this invention is to address the shortcomings of existing technologies by providing a method for correcting the sonic transit time of horizontal well logging. This method utilizes mathematical statistics to establish relevant empirical models based on two aspects: the rapid mineral content of the formation and the angle between the wellbore trajectory and the formation bedding plane. Correction of the sonic transit time of horizontal well logging is then performed using empirical formulas. By simply obtaining the sonic transit time of the horizontal well, the rapid mineral content of the formation, the angle between the wellbore and the formation bedding plane, and the sonic transit time of the corresponding pilot well, correction of the sonic transit time of horizontal well logging can be achieved. This significantly reduces the difficulty and cost of data acquisition, simplifies the correction process, and yields high accuracy results.

[0008] This invention provides a method for correcting the sonic transit time in horizontal well logging, comprising the following steps:

[0009] 1) Obtain the logging sonic transit time Δt, formation rapid mineral content Vf, and the angle θ between the wellbore and the formation bedding plane of the horizontal wells in the work area;

[0010] 2) Obtain the logging sonic transit time Δtc of the pilot well corresponding to the horizontal well;

[0011] 3) Obtain the logging sonic transit time Δt0, formation rapid mineral content Vf0, and the angle θ0 between the wellbore and the formation bedding plane for the horizontal well to be evaluated in the work area;

[0012] 4) Establish the initial correction model for the sonic time difference of horizontal well logging: Δtc = Δt * (1 + a * Vf + b * cosθ + c), where a, b, and c are model coefficients and are dimensionless.

[0013] 5) Based on the initial correction model of the horizontal well logging sonic transit time and the obtained Δtc, Δt, Vf, and θ, the model coefficients a, b, and c are determined, and the horizontal well logging sonic transit time correction model Δtc0=Δt0*(1+a*Vf0+b*cosθ0+c) is obtained, where Δtc0 is the corrected logging sonic transit time of the horizontal well to be evaluated;

[0014] 6) Substitute the obtained Δt0, Vf0, and θ0 of the horizontal well to be evaluated into the horizontal well logging sonic transit time correction model to calculate the corrected logging sonic transit time Δtc0 of the horizontal well to be evaluated.

[0015] 7) Output the results.

[0016] Preferably, the data obtained in steps 1), 2), and 3) are obtained at certain depth intervals.

[0017] Preferably, the model coefficients a, b, and c are determined based on a multivariate fitting method.

[0018] Preferably, determining the model coefficients a, b, and c includes:

[0019] Acquire the sonic logging transit time Δt, formation fast mineral content Vf, angle θ between the wellbore and the formation bedding plane, and the sonic logging transit time Δtc of the corresponding pilot well at a certain depth for multiple horizontal wells;

[0020] Based on the initial correction model of acoustic time difference in horizontal well logging, the model coefficients a, b, and c are determined using the multivariate fitting method.

[0021] Preferably, the angle θ between the wellbore and the formation plane is calculated based on the well inclination and the formation dip angle.

[0022] Preferably, the initial correction model for the acoustic transit time of the horizontal well logging, Δtc = Δt*(1+a*Vf+b*cosθ+c), is established based on the response of the formation rapid mineral content and the angle between the wellbore and the formation bedding plane to the acoustic transit time of the logging.

[0023] Preferably, the depth interval is 0.1-0.5m.

[0024] Preferably, the output results include:

[0025] The corrected logging sonic transit time data of multiple horizontal wells to be evaluated are calculated, and the multiple data are plotted into corrected logging sonic transit time curves at specified depth intervals.

[0026] Preferably, the specified depth interval is consistent with the depth interval of the data obtained in steps 1), 2), and 3).

[0027] The preferred method is to obtain the rapid mineral content of the formation through interpretation of complex lithology via well logging.

[0028] The beneficial effects of this invention are as follows: The method corrects the required logging sonic transit time of the pilot well and the corresponding horizontal well data, formation fast mineral content, and the angle between the wellbore and the formation bedding plane. Compared to existing large amounts of rock anisotropic core experimental data, the difficulty and cost of obtaining these data are significantly reduced. Furthermore, based on the response of formation fast mineral content and the angle between the wellbore and the formation bedding plane to logging sonic transit time, after establishing the correction model of this scheme, the corrected logging sonic transit time of the horizontal well to be evaluated can be obtained through calculation using the above data. The calculation process is simpler than existing technologies, and the correction results have high accuracy. Attached Figure Description

[0029] Figure 1 This is a schematic diagram of the process of the present invention;

[0030] Figure 2 A graph showing the relationship between the rapid mineral content of the formation and the sonic transit time correction of horizontal well logging;

[0031] Figure 3A diagram showing the relationship between the angle between the wellbore and the formation plane and the sonic logging time difference of a horizontal well.

[0032] Figure 4 This is a schematic diagram of the acoustic transit time curve generated from the corrected logging acoustic transit time data of the horizontal well H to be evaluated in this invention;

[0033] Figure 5 This is a comparison chart of the corrected logging sonic time difference of horizontal well H and its corresponding pilot well. Detailed Implementation

[0034] To make the technical problems, technical solutions, and beneficial effects to be solved by this application clearer, the following detailed description is provided in conjunction with the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are merely illustrative and are not intended to limit the scope of this application.

[0035] It should be understood that, when used in this application specification and the appended claims, the term "comprising" indicates the presence of the described features, integrals, steps, operations, elements and / or components, but does not exclude the presence or addition of one or more other features, integrals, steps, operations, elements, components and / or a collection thereof.

[0036] It should also be understood that the term “and / or” as used in this application specification and the appended claims means any combination of one or more of the associated listed items and all possible combinations, and includes such combinations.

[0037] As used in this application specification and the appended claims, the term "if" may be interpreted, depending on the context, as "when," "once," "in response to determination," or "in response to detection." Similarly, the phrase "if determined" or "if detected [the described condition or event]" may be interpreted, depending on the context, as meaning "once determined," "in response to determination," "once detected [the described condition or event]," or "in response to detection [the described condition or event]."

[0038] Furthermore, in the description of this application and the appended claims, the terms "first," "second," "third," etc., are used only to distinguish descriptions and should not be construed as indicating or implying relative importance.

[0039] References to "one embodiment" or "some embodiments" in this specification mean that one or more embodiments of this application include a specific feature, structure, or characteristic described in connection with that embodiment. Therefore, the phrases "in one embodiment," "in some embodiments," "in other embodiments," "in still other embodiments," etc., appearing in different parts of this specification do not necessarily refer to the same embodiment, but rather mean "one or more, but not all, embodiments," unless otherwise specifically emphasized. The terms "comprising," "including," "having," and variations thereof mean "including but not limited to," unless otherwise specifically emphasized. "A plurality" means "two or more."

[0040] Example 1

[0041] Figure 1 A preferred embodiment of this application is shown. Figure 1 The diagram shows a structural schematic of a horizontal well logging sonic time difference correction method according to the first embodiment of this application. For ease of explanation, only the parts relevant to this embodiment are shown, and are described in detail below:

[0042] This invention provides a method for correcting the sonic transit time in horizontal well logging, comprising the following steps:

[0043] Step 1: Obtain the logging sonic transit time Δt of horizontal wells in the work area, in μs / m; the rapid mineral content of the formation Vf, in %; and the angle θ between the wellbore and the formation bedding plane, in °.

[0044] Step 2: Obtain the logging sonic transit time Δtc of the pilot well corresponding to the horizontal well, with the dimension in μs / m;

[0045] Step 3: Obtain the logging sonic transit time Δt0 of the horizontal well to be evaluated in the work area, in μs / m; the formation rapid mineral content Vf0, in %; and the angle θ0 between the wellbore and the formation bedding plane, in °.

[0046] Step 4: Based on the rapid mineral content of the formation and the response of the angle between the wellbore and the formation to the logging sonic transit time, establish an initial correction model for the logging sonic transit time of a horizontal well: Δtc = Δt*(1+a*Vf+b*cosθ+c), where a, b, and c are model coefficients and are dimensionless.

[0047] Step 5: Based on the initial correction model of the horizontal well logging sonic transit time and the obtained Δtc, Δt, Vf, and θ, determine the model coefficients a, b, and c using the multivariate fitting method to obtain the horizontal well logging sonic transit time correction model Δtc0=Δt0*(1+a*Vf0+b*cosθ0+c), where Δtc0 is the corrected logging sonic transit time of the horizontal well to be evaluated;

[0048] Step 6: Substitute the obtained Δt0, Vf0, and θ0 of the horizontal well to be evaluated into the horizontal well logging sonic transit time correction model to calculate the corrected logging sonic transit time Δtc0 of the horizontal well to be evaluated.

[0049] Step 7: Plot the multiple Δtc0 scatter data points into a corrected logging sonic time difference curve at certain depth intervals and output it.

[0050] In one embodiment, the model coefficients a, b, and c are obtained through a multivariate fitting method, specifically including:

[0051] Acquire the logging sonic transit time Δt, formation fast mineral content Vf, angle θ between the wellbore and the formation bedding plane, and the logging sonic transit time Δtc of the corresponding pilot well at a certain depth for multiple horizontal wells. Based on the initial correction model of the logging sonic transit time of horizontal wells, the model coefficients a, b, and c are determined using the multivariate fitting method.

[0052] In one embodiment, calculating the corrected logging sonic transit time of the horizontal well to be evaluated includes:

[0053] The Δt0, Vf0, and θ0 data of the horizontal well to be evaluated, as well as the calculated model coefficients a, b, and c, are respectively substituted into the horizontal well logging sonic transit time correction model to calculate the corrected logging sonic transit time Δtc0 of the horizontal well to be evaluated.

[0054] Example 2

[0055] To facilitate understanding of the embodiments and effects of the present invention, a specific application example is given below. Fast minerals refer to those whose acoustic transit time is less than that of casing waves (187 μs / m). Figure 2 The following is an embodiment of the invention showing the relationship between the horizontal well logging sonic transit time correction and the formation fast mineral content. As the formation fast mineral content increases, the horizontal well logging sonic transit time correction decreases. Figure 3 The diagram illustrates the relationship between the angle between the wellbore and the formation bedding plane and the acoustic transit time of a horizontal well logging operation, according to one embodiment of the present invention. For the same formation, the smaller the angle between the wellbore and the formation bedding plane, the smaller the acoustic transit time value of the horizontal well logging operation, and the larger the acoustic transit time correction relative to the pilot well logging operation. As the angle between the wellbore and the formation bedding plane increases, the acoustic transit time value of the horizontal well logging operation also increases, and the acoustic transit time correction relative to the pilot well logging operation decreases.

[0056] This embodiment uses a specific horizontal well H to be evaluated as an example to illustrate the scheme and establishes a logging sonic time difference correction model for the horizontal well in this work area.

[0057] Step 1: Obtain the sonic transit time Δt of horizontal well N in the work area from 2850.0 to 3900.0 m, in μs / m; the rapid mineral content of the formation Vf, in %; and the angle θ between the wellbore and the formation bedding plane, in °. The data depth interval is 0.2 m.

[0058] Step 2: Obtain the logging sonic transit time Δtc of the horizontal well N corresponding to the pilot well M from 2730.0 to 2800.0 m, in μs / m, with a data depth interval of 0.2 m;

[0059] Step 3: Obtain all Δt0, Vf0, and θ0 data for the horizontal well H to be evaluated within the work area, from 2940.0 to 3940.0 m, with a depth interval of 0.2 m.

[0060] Step 4: Based on the rapid mineral content of the formation and the response of the angle between the wellbore and the formation to the logging sonic transit time, establish an initial correction model for the logging sonic transit time of a horizontal well: Δtc = Δt*(1+a*Vf+b*cosθ+c), where a, b, and c are model coefficients.

[0061] Step 5: Read Δt, Vf, and θ data of some marker depth points in horizontal well N (2850.0-3900.0m) and Δtc data of the corresponding pilot well M. Based on the initial correction model of the horizontal well logging sonic transit time in Step 4, use the multivariate fitting method to determine the model coefficients a = -0.008, b = 4.53, c = -3.93, and the correlation coefficient R = 0.91. Then, the correction model of the horizontal well H logging sonic transit time is Δtc0 = Δt0 * (1 - 0.008 * Vf0 + 4.53 * cosθ0 - 3.93).

[0062] Step 6: Substitute the multiple sets of Δt0, Vf0, and θ0 data obtained in Step 3 for the 2940.0-3940.0m range of the horizontal well H to be evaluated into the formula Δtc0=Δt0*(1-0.008*Vf0+4.53*cosθ0-3.93) to calculate the corrected logging sonic time difference data for multiple horizontal wells H to be evaluated.

[0063] Step 7: Plot the multiple Δtc0 scatter data points at 0.2m depth intervals to create a corrected logging sonic transit time curve, as shown below. Figure 2 As shown.

[0064] The corrected logging sonic transit time of well H was statistically compared with that of its corresponding pilot well, and the correlation was good. Figure 3 The result indicates that the correction model is relatively reliable.

[0065] It should be understood that the specific order or hierarchy of steps in the disclosed process is an example of an exemplary method. Based on design preferences, it should be understood that the specific order or hierarchy of steps in the process may be rearranged without departing from the scope of this disclosure. The appended method claims provide elements of various steps in an exemplary order and are not intended to limit the scope to the specific order or hierarchy described.

[0066] In the above detailed description, various features are combined together in a single embodiment to simplify this disclosure. This approach to disclosure should not be construed as reflecting an intention that embodiments of the claimed subject matter require more features than are explicitly stated in each claim. Rather, as reflected in the appended claims, the invention is presented with fewer features than all of the features of the single disclosed embodiment. Therefore, the appended claims are hereby explicitly incorporated into the detailed description, wherein each claim stands alone as a preferred embodiment of the invention.

[0067] The disclosed embodiments have been described above to enable any person skilled in the art to implement or use the present invention. Various modifications to these embodiments will be apparent to those skilled in the art, and the general principles defined herein can be applied to other embodiments without departing from the spirit and scope of this disclosure. Therefore, this disclosure is not limited to the embodiments given herein, but is consistent with the broadest scope of the principles and novel features disclosed in this application.

[0068] The foregoing description includes examples of one or more embodiments. It is certainly impossible to describe all possible combinations of components or methods in order to describe the above embodiments, but those skilled in the art will recognize that further combinations and arrangements of the various embodiments are possible. Therefore, the embodiments described herein are intended to cover all such changes, modifications, and variations that fall within the scope of the appended claims. Furthermore, the term "comprising" as used in the specification or claims is interpreted in a manner similar to the term "including," as it is used as a conjunction in the claims. Additionally, the use of any term "or" in the specification of the claims is intended to mean "non-exclusive or."

[0069] The above-described embodiments are only used to illustrate the technical solutions of this application, and are not intended to limit them. Although this application has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of this application, and should all be included within the protection scope of this application.

Claims

1. A method for correcting the sonic transit time in horizontal well logging, characterized in that, Includes the following steps: 1) Obtain the logging sonic transit time Δt, formation rapid mineral content Vf, and the angle θ between the wellbore and the formation bedding plane of the horizontal wells in the work area; 2) Obtain the logging sonic transit time Δtc of the corresponding pilot well for this horizontal well; 3) Obtain the logging sonic transit time Δt0, formation rapid mineral content Vf0, and the angle θ0 between the wellbore and the formation bedding plane for the horizontal well to be evaluated in the work area; 4) Establish an initial correction model for the sonic transit time of horizontal well logging. a, b, and c are model coefficients, dimensionless; the initial correction model for the acoustic transit time difference in horizontal well logging. The response of logging sonic transit time is established based on the rapid mineral content of the formation and the angle between the wellbore and the formation bedding plane. The fast formation minerals are those whose sonic transit time is less than 187 μs / m of the casing wave sonic transit time, and the content of the fast formation minerals is obtained by interpreting complex lithology through well logging. 5) Based on the initial correction model for acoustic transit time in horizontal well logging and the obtained Δtc, Δt, Vf, and θ, the model coefficients a, b, and c are determined to obtain the correction model for acoustic transit time in horizontal well logging. Where Δtc0 is the corrected logging sonic transit time of the horizontal well to be evaluated; 6) Substitute the obtained Δt0, Vf0, and θ0 of the horizontal well to be evaluated into the horizontal well logging sonic transit time correction model to calculate the corrected logging sonic transit time Δtc0 of the horizontal well to be evaluated. 7) Output the results.

2. The horizontal well logging sonic time difference correction method according to claim 1, characterized in that: The data obtained in steps 1), 2), and 3) are acquired at certain depth intervals.

3. The horizontal well logging sonic time difference correction method according to claim 1, characterized in that: The model coefficients a, b, and c are determined based on the multivariate fitting method.

4. The horizontal well logging sonic time difference correction method according to claim 3, characterized in that, Determining the model coefficients a, b, and c includes: Acquire the sonic logging transit time Δt, formation fast mineral content Vf, angle θ between the wellbore and the formation bedding plane, and the sonic logging transit time Δtc of the corresponding pilot well at a certain depth for multiple horizontal wells; Based on the initial correction model of acoustic time difference in horizontal well logging, the model coefficients a, b, and c are determined using the multivariate fitting method.

5. The horizontal well logging sonic time difference correction method according to claim 1, characterized in that: The angle θ between the wellbore and the formation plane is calculated based on the well inclination and the formation dip angle.

6. The horizontal well logging sonic time difference correction method according to claim 2, characterized in that: The specified depth interval is 0.1-0.5m.

7. The horizontal well logging sonic time difference correction method according to claim 1, characterized in that, The output results include: The corrected logging sonic transit time data of multiple horizontal wells to be evaluated are calculated, and the multiple data are plotted into corrected logging sonic transit time curves at specified depth intervals.

8. The horizontal well logging sonic time difference correction method according to claim 7, characterized in that: The specified depth interval is consistent with the depth interval of the data obtained in steps 1), 2), and 3).

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