Reservoir fluid identification method and device, electronic equipment and medium
By standardizing and correcting the raw reservoir data, and combining the neutron-sonic envelope area and reservoir density, the problem of low accuracy of the Archie formula in argillaceous sandstone reservoirs was solved, and accurate identification of reservoir fluid type was achieved.
Patent Information
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- CHINA PETROCHEMICAL CORP
- Filing Date
- 2024-11-11
- Publication Date
- 2026-05-12
AI Technical Summary
In existing technologies, Archie's formula has low accuracy in determining reservoir fluid type in argillaceous sandstone, low-resistivity reservoirs, and complex-pore reservoirs, mainly due to uncertainties in rock cementation index, lithology coefficient, saturation index, and formation resistivity.
By acquiring the raw conventional data of the reservoir, standardizing and correcting it, determining the neutron-acoustic envelope area, and combining it with the reservoir density, the fluid type is determined using the reservoir fluid identification criteria, thus avoiding the influence of formation resistivity and formation water resistivity.
It enables accurate, rapid, and intuitive identification of reservoir fluid types, improving the accuracy of judgment and reducing the influence of human factors.
Smart Images
Figure CN122018031A_ABST
Abstract
Description
Technical Field
[0001] This application relates to the field of sandstone reservoirs, and in particular to a method, apparatus, electronic device and medium for reservoir fluid identification. Background Technology
[0002] Archie's formula is the basis for calculating oil saturation in sandstone reservoirs using well logging data and determining whether the current reservoir is a gas-bearing or poorly gas-bearing reservoir. However, the formula becomes less effective when used in argillaceous sandstone, low-resistivity reservoirs, and reservoirs with complex porosity. The reason is that the Archie formula involves parameters such as rock cementation index, lithology-related lithology coefficient, saturation index, rock sample-related constant, formation water resistivity, formation resistivity, and reservoir porosity. Among these parameters, the rock cementation index, lithology-related lithology coefficient, saturation index, and rock sample-related constant are all different for different layers; formation water resistivity varies with depth and temperature; and formation resistivity varies with mud intrusion. In other words, the rock cementation index, lithology-related lithology coefficient, saturation index, rock sample-related constant, formation water resistivity, and formation resistivity all have great uncertainty. Only reservoir porosity is basically accurate. Therefore, the accuracy of using the Archie formula to calculate the hydrocarbon saturation of tight sandstone reservoirs and determine the current reservoir type is relatively low.
[0003] In view of the above-mentioned technologies, finding a reservoir fluid identification method is a problem that urgently needs to be solved by those skilled in the art. Summary of the Invention
[0004] The purpose of this application is to provide a method, apparatus, electronic device, and medium for identifying reservoir fluids. This can improve the accuracy of determining the current reservoir fluid type in existing technologies.
[0005] To address the aforementioned technical problems, this application provides a reservoir fluid identification method, comprising:
[0006] Obtain the original conventional data and reservoir density of the reservoir corresponding to the well to be tested, and determine the original curve corresponding to the original conventional data;
[0007] The original curve is corrected based on the correction curve specifications to obtain the corrected curve;
[0008] The neutron-acoustic envelope area, composed of neutron data and acoustic data in the original conventional data, is determined based on the calibration curve.
[0009] Based on the reservoir fluid identification criteria, the fluid type corresponding to the reservoir is determined according to the reservoir density and the neutron-acoustic envelope area.
[0010] Preferably, the process involves acquiring the original conventional data of the reservoir corresponding to the well to be tested, and determining the original curve corresponding to the original conventional data, including:
[0011] Obtain raw, conventional data of the reservoir;
[0012] Based on standard data specifications, the original routine data is standardized to obtain standard routine data;
[0013] Standard, conventional data is sorted according to depth-based sorting requirements to obtain sorted data;
[0014] The original curve is determined based on the sorted data.
[0015] Preferably, the original curve is corrected based on the correction curve specifications to obtain a corrected curve, including:
[0016] Obtain historical conventional data for at least one reservoir corresponding to a well log;
[0017] The calibration curve specifications are determined based on historical conventional data and the fluid type of the reservoir in the well logging.
[0018] The original curve is corrected based on the calibration curve specifications to obtain the corrected curve.
[0019] Preferably, determining the neutron-acoustic envelope area composed of neutron data and acoustic data in the original conventional data based on the correction curve includes:
[0020] Obtain the neutron curve characterizing the neutron data from the calibration curve;
[0021] Obtain the acoustic wave curve representing the acoustic wave data from the calibration curve;
[0022] Based on the envelope area formula, the neutron-sound wave envelope area corresponding to the neutron curve and the sound wave curve is determined.
[0023] Preferably, based on reservoir fluid identification criteria, the fluid type corresponding to the reservoir is determined according to the reservoir density and the neutron-acoustic envelope area, including:
[0024] If the reservoir density is less than the first density threshold and the neutron-acoustic envelope area is not less than the first area threshold, then the current reservoir is determined to be a gas layer.
[0025] If the reservoir density is not less than the first density threshold and is less than the second density threshold, and the neutron-acoustic envelope area is not less than the second area threshold and is less than the first area threshold, then the current reservoir is determined to be a gas-deficient layer.
[0026] Preferably, based on the reservoir fluid identification criteria, determining the fluid type corresponding to the reservoir according to the reservoir density and the neutron-acoustic envelope area further includes:
[0027] If the reservoir density is not greater than the second density threshold and the neutron-acoustic envelope area is not less than the third area threshold and less than the second area threshold, then the current reservoir is determined to be a gas-bearing layer.
[0028] If the neutron-acoustic envelope area is less than the third area threshold, the reservoir is determined to be a dry reservoir.
[0029] Preferably, the neutron data calibration range is 0%-80%; the reservoir density calibration range is 1.2 g / cm³. 3 -2.8g / cm 3 The scale range for acoustic data is 591 μs / m to 131 μs / m.
[0030] To address the aforementioned technical problems, this application also provides a reservoir fluid identification device, comprising:
[0031] The acquisition module is used to acquire the original conventional data and reservoir density of the reservoir corresponding to the well to be tested, and to determine the original curve corresponding to the original conventional data;
[0032] The processing module is used to perform calibration processing on the original curve based on the calibration curve specifications to obtain the calibrated curve;
[0033] The determination module is used to determine the neutron-acoustic envelope area composed of neutron data and acoustic data in the original conventional data based on the calibration curve;
[0034] The determination module is used to determine the fluid type of the reservoir based on the reservoir density and the neutron-acoustic envelope area, according to the reservoir fluid identification criteria.
[0035] To address the aforementioned technical problems, this application also provides an electronic device, including a memory for storing computer programs;
[0036] A processor is used to implement the steps of the reservoir fluid identification method described above when executing a computer program.
[0037] To address the aforementioned technical problems, this application also provides a computer-readable storage medium storing a computer program, which, when executed by a processor, implements the steps of the reservoir fluid identification method described above.
[0038] This application provides a reservoir fluid identification method, comprising: acquiring the original conventional data and reservoir density of the reservoir corresponding to the well to be tested, and determining the original curve corresponding to the original conventional data; performing calibration processing on the original curve based on calibration curve specifications to obtain a calibrated curve; determining the neutron-sonic envelope area composed of neutron data and acoustic data in the original conventional data according to the calibrated curve; and determining the fluid type corresponding to the reservoir based on the reservoir density and the neutron-sonic envelope area according to the reservoir fluid identification criteria. It can be seen that this application determines the type of reservoir fluid by comprehensively analyzing the two parameters of neutron-sonic envelope area and reservoir density. These two parameters are not affected by factors such as formation resistivity and formation water resistivity, nor by human factors of the processing personnel, and can accurately, quickly, and intuitively identify the properties of reservoir fluids, thereby improving the accuracy of reservoir fluid identification. Attached Figure Description
[0039] To more clearly illustrate the embodiments of this application, the accompanying drawings used in the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.
[0040] Figure 1 A flowchart of a reservoir fluid identification method provided in the application;
[0041] Figure 2 A combination diagram of the first well logging provided in an embodiment of this application;
[0042] Figure 3 A combination diagram of the second well logging provided in an embodiment of this application;
[0043] Figure 4 A combination diagram of the third well logging provided in the embodiments of this application;
[0044] Figure 5 A block diagram of a reservoir fluid identification device provided in this application;
[0045] Figure 6 A structural diagram of an electronic device provided in another embodiment of this application. Detailed Implementation
[0046] The technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, and not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those of ordinary skill in the art without creative effort are within the protection scope of this application.
[0047] The core of this application is to provide a reservoir fluid identification method, device, electronic device, and medium.
[0048] To enable those skilled in the art to better understand the present application, the present application will be further described in detail below with reference to the accompanying drawings and specific embodiments.
[0049] Figure 1 A flowchart of a reservoir fluid identification method provided in the application, such as... Figure 1 As shown, it includes the following steps:
[0050] S10: Obtain the original conventional data and reservoir density of the reservoir corresponding to the well to be tested, and determine the original curve corresponding to the original conventional data.
[0051] In a specific embodiment, conventional technical means (electronic equipment) are used to acquire raw conventional data of the reservoir within the well to be tested. Reservoir density is not included in the raw conventional data. Examples of raw conventional data include: formation water resistivity, formation resistivity, porosity, rock cementation index, lithology coefficient, saturation index, etc. After acquiring the raw conventional data, it is plotted as a curve for easy viewing.
[0052] It should be noted that the format of the raw conventional data obtained using conventional techniques may differ from the data used in the calculation. Therefore, format processing is required when converting the raw conventional data into the original curve format. As a preferred method, the steps for determining the original curve corresponding to the raw conventional data are as follows: obtain the raw conventional data of the reservoir; standardize the raw conventional data based on standard data specifications to obtain standard conventional data; sort the standard conventional data according to depth sorting requirements to obtain sorted data; and determine the original curve based on the sorted data.
[0053] S11: Correct the original curve based on the correction curve specifications to obtain the corrected curve.
[0054] In a specific embodiment, the original curve is determined based on raw conventional data, which is obtained using conventional techniques. However, the raw conventional data obtained in this process may contain some error data. For example, normally, the range of formation water resistivity is 0-1, but in the obtained raw conventional data, there is a data point representing formation water resistivity as 2. This data is clearly an error. Therefore, when the raw conventional data becomes the original curve, the error data becomes more obvious in the original curve. Thus, it is necessary to further correct the original curve using curve calibration to obtain a calibrated curve.
[0055] As a preferred method, the steps of correcting the original curve based on the correction curve specification to obtain the corrected curve are as follows: acquiring historical conventional data of at least one well logging reservoir; determining the correction curve specification based on the historical conventional data and the fluid type of the reservoir in the well logging; and correcting the original curve based on the correction curve specification to obtain the corrected curve.
[0056] S12: Determine the neutron-acoustic envelope area composed of neutron data and acoustic data in the original conventional data based on the correction curve.
[0057] S13: Based on the reservoir fluid identification criteria, determine the fluid type corresponding to the reservoir according to the reservoir density and the neutron-acoustic envelope area.
[0058] In a specific embodiment, this application determines the type of reservoir fluid by comprehensively analyzing the "neutron-acoustic envelope area" and reservoir density. Preferably, all data uses a 10-division linear scale, with density and acoustic data using a mutual compatibility scale; the neutron data scale ranges from 0% to 80%; and the reservoir density scale ranges from 1.2 g / cm³. 3 -2.8g / cm 3 The calibration range for the acoustic data is 591 μs / m to 131 μs / m. The formula for obtaining the neutron-acoustic envelope area is:
[0059] S=(80-CNL) / 80*10-(591-DT) / (591-131)*10;
[0060] Wherein, CNL stands for compensated neutron, in units of %; and DT stands for acoustic transit time, in units of μs / m.
[0061] Figures 2-4 The images show logging combinations for different gas-bearing formations. It can be seen from the images that a larger envelope area corresponds to a lower density value and better gas-bearing properties. Therefore, based on this, a reservoir fluid identification criterion is determined. Finally, the fluid type corresponding to the reservoir is determined based on the reservoir density and neutron-sonic envelope area of the well being tested.
[0062] As a preferred embodiment, the reservoir fluid identification criteria are as follows: when the reservoir density is less than a first density threshold and the neutron-acoustic envelope area is not less than a first area threshold, the current reservoir is determined to be a gas-bearing reservoir; when the reservoir density is not less than the first density threshold and less than a second density threshold, and the neutron-acoustic envelope area is not less than the second area threshold and less than the first area threshold, the current reservoir is determined to be a poor-quality gas-bearing reservoir; when the reservoir density is not greater than the second density threshold, and the neutron-acoustic envelope area is not less than a third area threshold and less than the second area threshold, the current reservoir is determined to be a gas-bearing reservoir; when the neutron-acoustic envelope area is less than the third area threshold, the reservoir is determined to be a dry reservoir.
[0063] It should be noted that the steps mentioned in the embodiments of this application for determining the original curve corresponding to the original conventional data, obtaining the corrected curve, the formula for the neutron-acoustic envelope area, and the reservoir fluid identification and judgment criteria are only one possible way to implement them, but are not limited to this only implementation method. Users can set them themselves according to their needs.
[0064] This application provides a reservoir fluid identification method, comprising: acquiring the original conventional data and reservoir density of the reservoir corresponding to the well to be tested, and determining the original curve corresponding to the original conventional data; performing calibration processing on the original curve based on calibration curve specifications to obtain a calibrated curve; determining the neutron-sonic envelope area composed of neutron data and acoustic data in the original conventional data according to the calibrated curve; and determining the fluid type corresponding to the reservoir based on the reservoir density and the neutron-sonic envelope area according to the reservoir fluid identification criteria. It can be seen that this application determines the type of reservoir fluid by comprehensively analyzing the two parameters of neutron-sonic envelope area and reservoir density. These two parameters are not affected by factors such as formation resistivity and formation water resistivity, nor by human factors of the processing personnel, and can accurately, quickly, and intuitively identify the properties of reservoir fluids, thereby improving the accuracy of reservoir fluid identification.
[0065] Based on the above embodiments, as a preferred embodiment, the process of obtaining the original conventional data of the reservoir corresponding to the well to be tested and determining the original curve corresponding to the original conventional data includes: obtaining the original conventional data of the reservoir; standardizing the original conventional data based on standard data specifications to obtain standard conventional data; sorting the standard conventional data according to depth sorting requirements to obtain sorted data; and determining the original curve based on the sorted data.
[0066] In a specific embodiment, because the electronic devices used to acquire the raw conventional data and the electronic devices used for the final calculation and judgment are different, the format of the acquired raw conventional data may differ from the data used for calculation and judgment. Therefore, it is necessary to standardize the raw conventional data based on standard data specifications to obtain standard conventional data, so that the electronic devices used for the final calculation and judgment can process it normally according to the standard conventional data. Then, the standard conventional data is sorted according to the depth sorting requirements to obtain sorted data; finally, the original curve is determined based on the sorted data.
[0067] In a preferred embodiment, the original curve is corrected based on the correction curve specification to obtain a corrected curve, including: acquiring historical conventional data of at least one well logging reservoir; determining the correction curve specification based on the historical conventional data and the fluid type of the reservoir in the well logging; and correcting the original curve based on the correction curve specification to obtain a corrected curve.
[0068] In a specific embodiment, the original curve is determined based on original conventional data, which is obtained using conventional techniques. However, the original conventional data obtained in this process may contain individual error data, thus requiring correction processing. First, historical conventional data of at least one reservoir corresponding to a well log is obtained as the basis for correction processing. Based on a large amount of historical conventional data and the fluid type of the corresponding reservoir in the current well log, the correction curve specification can be determined. Finally, the original curve is corrected according to the correction curve specification to obtain the corrected curve.
[0069] As a preferred embodiment, determining the neutron-sound envelope area composed of neutron data and acoustic data in the original conventional data based on the calibration curve includes: obtaining the neutron curve representing the neutron data in the calibration curve; obtaining the acoustic curve representing the acoustic data in the calibration curve; and determining the neutron-sound envelope area corresponding to the neutron curve and the acoustic curve based on the envelope area formula.
[0070] In a specific embodiment, both neutron data and acoustic data use a 10-grid linear scale. The scale range for neutron data is 0%-80%, and the scale range for acoustic data is 591 μs / m-131 μs / m. The envelope area formula is as follows:
[0071] S=(80-CNL) / 80*10-(591-DT) / (591-131)*10;
[0072] Wherein, CNL stands for compensated neutron, in units of %; and DT stands for acoustic transit time, in units of μs / m.
[0073] In a specific embodiment, as a preferred embodiment, the reservoir fluid identification criterion is as follows:
[0074] 1. When the reservoir density RHOB is less than the first density threshold (e.g., the first density threshold is 2.48) and the neutron-acoustic envelope area S is not less than the first area threshold (e.g., the first area threshold is 1.2), the current reservoir is determined to be a gas layer.
[0075] 2. When the reservoir density RHOB is not less than the first density threshold and less than the second density threshold (e.g., the second density threshold is 2.52), and the neutron-acoustic envelope area S is not less than the second area threshold (e.g., the second area threshold is 0.7) and less than the first area threshold, the current reservoir is determined to be a gas-deficient layer.
[0076] 3. If the reservoir density is not greater than the second density threshold, and the neutron-acoustic envelope area is not less than the third area threshold (e.g., the third area threshold is 0.2) and less than the second area threshold, then the current reservoir is determined to be a gas-bearing layer.
[0077] 4. If the neutron-acoustic envelope area is less than the third area threshold, the reservoir is determined to be a dry reservoir.
[0078] The criteria for identifying reservoir fluids are shown in Table 1.
[0079] Table 1
[0080]
[0081] It should be noted that this application is only one possible method, and the size of the S value and the size of the RHOB value can be set according to the user's needs.
[0082] Therefore, this application uses a comprehensive analysis of two parameters, neutron-acoustic envelope area and reservoir density, to determine the type of reservoir fluid. These two parameters are not affected by factors such as formation resistivity and formation water resistivity, nor by human factors of the processing personnel. They can accurately, quickly, and intuitively identify the properties of reservoir fluids and improve the accuracy of reservoir fluid identification.
[0083] In the above embodiments, a reservoir fluid identification method has been described in detail. This application also provides an embodiment corresponding to a reservoir fluid identification device. It should be noted that this application describes the device embodiment from two perspectives: one based on functional modules and the other based on hardware.
[0084] Figure 5 A module diagram of a reservoir fluid identification device provided in this application includes:
[0085] The acquisition module 11 is used to acquire the original conventional data and reservoir density of the reservoir corresponding to the well to be tested, and to determine the original curve corresponding to the original conventional data;
[0086] Processing module 12 is used to perform calibration processing on the original curve based on the calibration curve specifications to obtain a calibrated curve;
[0087] Module 13 is used to determine the neutron-acoustic envelope area composed of neutron data and acoustic data in the original conventional data based on the calibration curve;
[0088] The determination module 14 is used to determine the fluid type of the reservoir based on the reservoir density and the neutron-acoustic envelope area according to the reservoir fluid identification criteria.
[0089] Since the embodiments of the apparatus and the embodiments of the method correspond to each other, please refer to the description of the embodiments of the method for the embodiments of the apparatus, which will not be repeated here.
[0090] Figure 6 A structural diagram of an electronic device provided in another embodiment of this application, such as... Figure 6 As shown, the electronic device includes: a memory 20 for storing computer programs;
[0091] The processor 21 is configured to execute a computer program to implement the steps of the reservoir fluid identification method as described in the above embodiments.
[0092] The electronic devices provided in this embodiment may include, but are not limited to, smartphones, tablets, laptops, or desktop computers.
[0093] The processor 21 may include one or more processing cores, such as a quad-core processor or an octa-core processor. The processor 21 may be implemented using at least one of the following hardware forms: Digital Signal Processor (DSP), Field-Programmable Gate Array (FPGA), or Programmable Logic Array (PLA). The processor 21 may also include a main processor and a coprocessor. The main processor, also known as the Central Processing Unit (CPU), is used to process data in the wake-up state; the coprocessor is a low-power processor used to process data in the standby state. In some embodiments, the processor 21 may integrate a Graphics Processing Unit (GPU), which is responsible for rendering and drawing the content to be displayed on the screen. In some embodiments, the processor 21 may also include an Artificial Intelligence (AI) processor, which is used to handle computational operations related to machine learning.
[0094] The memory 20 may include one or more computer-readable storage media, which may be non-transitory. The memory 20 may also include high-speed random access memory and non-volatile memory, such as one or more disk storage devices or flash memory devices. In this embodiment, the memory 20 is used to store at least the following computer program 201, which, after being loaded and executed by the processor 21, is capable of implementing the relevant steps of the reservoir fluid identification method disclosed in any of the foregoing embodiments. In addition, the resources stored in the memory 20 may also include an operating system 202 and data 203, and the storage method may be temporary or permanent storage. The operating system 202 may include Windows, Unix, Linux, etc.
[0095] In some embodiments, the electronic device may further include a display screen 22, an input / output interface 23, a communication interface 24, a power supply 25, and a communication bus 26.
[0096] Those skilled in the art will understand that Figure 6 The structures shown do not constitute a limitation on electronic devices and may include more or fewer components than those shown.
[0097] The electronic device provided in this application includes a memory and a processor. When the processor executes the program stored in the memory, it can implement the reservoir fluid identification method described above and has the same beneficial effects.
[0098] Finally, this application also provides an embodiment corresponding to a computer-readable storage medium. The computer-readable storage medium stores a computer program, which, when executed by a processor, implements the steps described in the above method embodiments.
[0099] It is understood that if the methods in the above embodiments are implemented as software functional units and sold or used as independent products, they can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of this application, in essence, or the part that contributes to the prior art, or all or part of the technical solution, can be embodied in the form of a software product. This computer software product is stored in a storage medium and executes all or part of the steps of the methods described in the various embodiments of this application. The aforementioned storage medium includes various media capable of storing program code, such as USB flash drives, portable hard drives, read-only memory (ROM), random access memory (RAM), magnetic disks, or optical disks.
[0100] The foregoing has provided a detailed description of a reservoir fluid identification method, apparatus, electronic device, and medium provided in this application. The various embodiments in the specification are described in a progressive manner, with each embodiment focusing on its differences from other embodiments. Similar or identical parts between embodiments can be referred to interchangeably. For the apparatus disclosed in the embodiments, since it corresponds to the method disclosed in the embodiments, the description is relatively simple; relevant parts can be referred to in the method section. It should be noted that those skilled in the art can make several improvements and modifications to this application without departing from the principles of this application, and these improvements and modifications also fall within the protection scope of the claims of this application.
[0101] It should also be noted that, in this specification, relational terms such as "first" and "second" are used only to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes said element.
Claims
1. A method for identifying reservoir fluids, characterized in that, include: Obtain the original conventional data and reservoir density of the reservoir corresponding to the well to be tested, and determine the original curve corresponding to the original conventional data; The original curve is corrected based on the correction curve specifications to obtain a corrected curve; The neutron-acoustic envelope area formed by the neutron data and acoustic data in the original conventional data is determined based on the correction curve. Based on the reservoir fluid identification criteria, the fluid type corresponding to the reservoir is determined according to the reservoir density and the neutron-acoustic envelope area.
2. The reservoir fluid identification method according to claim 1, characterized in that, Obtain the raw conventional data of the reservoir corresponding to the well to be tested, and determine the raw curve corresponding to the raw conventional data, including: Obtain the original conventional data of the reservoir; Based on standard data specifications, the original conventional data is standardized to obtain standard conventional data; The standard conventional data is sorted according to depth sorting requirements to obtain sorted data; The original curve is determined based on the sorted data.
3. The reservoir fluid identification method according to claim 1, characterized in that, The process of correcting the original curve based on the correction curve specifications to obtain a corrected curve includes: Obtain historical conventional data for at least one reservoir corresponding to a well log; The calibration curve specification is determined based on the historical conventional data and the fluid type of the reservoir in the well logging. The original curve is corrected based on the correction curve specifications to obtain the corrected curve.
4. The reservoir fluid identification method according to claim 1, characterized in that, Determining the neutron-acoustic envelope area composed of neutron data and acoustic data in the original conventional data based on the corrected curve includes: Obtain the neutron curve characterizing the neutron data from the calibration curve; Obtain the acoustic wave curve characterizing the acoustic wave data from the calibration curve; Based on the envelope area formula, the neutron-sound wave envelope area corresponding to the neutron curve and the sound wave curve is determined.
5. The reservoir fluid identification method according to claim 1, characterized in that, The reservoir fluid identification and judgment criteria, which determine the fluid type corresponding to the reservoir based on the reservoir density and the neutron-acoustic envelope area, include: If the reservoir density is less than a first density threshold and the neutron-acoustic envelope area is not less than a first area threshold, then the current reservoir is determined to be a gas layer. If the reservoir density is not less than the first density threshold and is less than the second density threshold, and the neutron-acoustic envelope area is not less than the second area threshold and is less than the first area threshold, then the current reservoir is determined to be a gas-differential layer.
6. The reservoir fluid identification method according to claim 5, characterized in that, The reservoir fluid identification and judgment criterion, which determines the fluid type corresponding to the reservoir based on the reservoir density and the neutron-acoustic envelope area, further includes: If the reservoir density is not greater than the second density threshold, and the neutron-acoustic envelope area is not less than the third area threshold and less than the second area threshold, then the current reservoir is determined to be a gas-bearing layer. If the neutron-acoustic envelope area is less than the third area threshold, the reservoir is determined to be a dry reservoir.
7. The reservoir fluid identification method according to any one of claims 1-6, characterized in that, The neutron data is calibrated from 0% to 80%; the reservoir density is calibrated from 1.2 g / cm³. 3 -2.8g / cm 3 The scale range of the acoustic data is 591μs / m-131μs / m.
8. A reservoir fluid identification device, characterized in that, include: The acquisition module is used to acquire the original conventional data and reservoir density of the reservoir corresponding to the well to be tested, and to determine the original curve corresponding to the original conventional data; The processing module is used to perform calibration processing on the original curve based on the calibration curve specifications to obtain a calibrated curve; The determination module is used to determine the neutron-sound envelope area composed of neutron data and acoustic data in the original conventional data based on the correction curve. The determination module is used to determine the fluid type corresponding to the reservoir based on the reservoir density and the neutron-acoustic envelope area, according to the reservoir fluid identification criteria.
9. An electronic device, characterized in that, Includes memory used to store computer programs; A processor, configured to implement the steps of the reservoir fluid identification method as described in any one of claims 1 to 7 when executing the computer program.
10. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores a computer program that, when executed by a processor, implements the steps of the reservoir fluid identification method as described in any one of claims 1 to 7.