Stratigraphic fluid type identification method and device, electronic equipment and storage medium

Abstract

Embodiments of the present application provide a method and device for identifying a formation fluid type, electronic equipment and a storage medium. The method comprises: determining formation porosity and formation water saturation of a formation to be measured at different depths according to measurement data of the formation to be measured at the different depths; the measurement data comprises density logging data, neutron logging data and resistivity logging data; determining forward density data of the formation to be measured at the different depths according to the formation porosity and the formation water saturation of the formation to be measured at the different depths; determining error values of the density logging data of the formation to be measured at the different depths according to the density logging data and the forward density data of the formation to be measured at the different depths; and determining a fluid type of the formation to be measured according to the error values of the density logging data of the formation to be measured at the different depths. The method is used to improve the accuracy of identifying the fluid type of the formation to be measured.

Description

Technical Field

[0001] This application relates to the field of resource exploration, and in particular to a method, apparatus, electronic device, and storage medium for identifying formation fluid types. Background Technology

[0002] Resource exploration is of great significance and value to social development. Formation logging is a commonly used technique in resource exploration, capable of acquiring information such as the physical properties of formations. Identification of formation fluid types is a key issue in interpreting formation information using formation logging technology.

[0003] In some techniques, schemes that identify the fluid type of the formation under test by measuring data without obtaining core samples have poor identification results. Summary of the Invention

[0004] This application provides a method, apparatus, electronic device, and storage medium for identifying formation fluid types, in order to improve the accuracy of fluid type identification in the formation to be tested.

[0005] In a first aspect, embodiments of this application provide a method for identifying formation fluid types, including:

[0006] Based on the measurement data of the formation at different depths, the formation porosity and water saturation at different depths were determined respectively; the measurement data included density logging data, neutron logging data and resistivity logging data.

[0007] Based on the formation porosity and water saturation at different depths, the forward density data of the formation at different depths are determined.

[0008] Based on density logging data and forward density data of the formation to be tested at different depths, the error values ​​of density logging data of the formation to be tested at different depths are determined respectively.

[0009] The fluid type of the formation to be tested is determined based on the error values ​​of density logging data at different depths.

[0010] In one possible implementation, based on the formation porosity and water saturation at different depths, forward-modeled density data of the formation at different depths are determined, including:

[0011] Assuming the fluid type at the first depth of the formation to be measured is a gas layer, the first forward-modeled density data of the formation at the first depth is determined based on the formation porosity and water saturation at the first depth, and a pre-defined forward-modeled gas layer formula; and

[0012] Assuming the fluid type at the first depth of the stratum to be measured is a hydrate layer, the second forward density data of the stratum at the first depth are determined based on the stratum porosity and water saturation at the first depth, as well as the preset forward hydrate layer formula.

[0013] In one possible implementation, based on density logging data and forward density data of the formation to be tested at different depths, the error value of the density logging data of the formation to be tested at different depths is determined, including:

[0014] Based on the density logging data and the first forward density data of the formation to be tested at the first depth, determine the first error value of the density logging data of the formation to be tested at the first depth; and

[0015] Based on the density logging data and the second forward density data of the formation to be tested at the first depth, the second error value of the density logging data of the formation to be tested at the first depth is determined.

[0016] In one possible implementation, the fluid type of the formation to be tested is determined based on the error values ​​of density logging data at different depths, including:

[0017] The error values ​​of density logging data at different depths of the formation to be tested are obtained and mapped to multiple coordinate positions of a pre-constructed formation fluid type identification map. The formation fluid type identification map is used to indicate the coordinate regions corresponding to formations with different fluid types.

[0018] The fluid type of the formation to be tested is determined based on the coordinate regions corresponding to multiple coordinate locations.

[0019] In one possible implementation, the fluid type of the formation to be tested is determined based on the coordinate regions corresponding to multiple coordinate locations, including:

[0020] If multiple coordinate positions with a ratio greater than or equal to a preset ratio are all located in the first coordinate region of the formation fluid type identification map, the fluid type corresponding to the first coordinate region will be taken as the fluid type of the formation to be tested.

[0021] In one possible implementation, the method further includes:

[0022] Based on the measurement data of the known strata at different depths, the porosity and water saturation of the known strata at different depths are determined respectively.

[0023] Based on the known porosity and water saturation of the strata at different depths, the forward density data of the known strata at different depths are determined respectively.

[0024] Based on density logging data and forward density data of known formations at different depths, determine the error values ​​of density logging data of known formations at different depths;

[0025] Map the error values ​​of density logging data of known formations at different depths to a preset coordinate map to obtain multiple coordinate points corresponding to the known formations in the preset coordinate map; repeat the above steps to obtain multiple coordinate points corresponding to known formations of different fluid types in the preset coordinate map.

[0026] Based on multiple coordinate points corresponding to known strata of different fluid types in the preset coordinate map, a strata fluid type identification map containing the strata fluid type boundary line is obtained; the strata fluid type boundary line is used to divide the preset coordinate map into multiple coordinate regions, and different coordinate regions correspond to strata of different fluid types.

[0027] In one possible implementation, based on measurement data of the formation at different depths, the formation porosity and water saturation at different depths are determined, including:

[0028] Based on the density logging data of the formation to be tested at the first depth, the density porosity of the formation to be tested at the first depth is determined.

[0029] Based on the neutron logging data and density porosity of the formation at the first depth, the formation porosity at the first depth is determined.

[0030] In one possible implementation, based on measurement data of the formation at different depths, the formation porosity and water saturation at different depths are determined, including:

[0031] Based on the resistivity logging data and formation porosity of the formation at the first depth, the water saturation of the formation at the first depth is determined.

[0032] Secondly, embodiments of this application provide a formation fluid type identification device, comprising:

[0033] The processing module is used to determine the formation porosity and water saturation of the formation at different depths based on the measurement data of the formation at different depths; the measurement data includes density logging data, neutron logging data and resistivity logging data;

[0034] The processing module is also used to determine the forward density data of the stratum at different depths based on the porosity and water saturation of the stratum at different depths.

[0035] The processing module is also used to determine the error value of the density logging data of the formation under test at different depths based on the density logging data and forward density data at different depths of the formation under test.

[0036] The processing module is also used to determine the fluid type of the formation to be tested based on the error values ​​of density logging data at different depths.

[0037] Thirdly, embodiments of this application provide an electronic device, including: a memory and a processor;

[0038] The memory stores the instructions that the computer executes;

[0039] The processor executes computer execution instructions stored in memory, causing the processor to perform the first aspect and / or various possible implementations of the first aspect as described above.

[0040] Fourthly, embodiments of this application provide a computer-readable storage medium storing computer-executable instructions, which, when executed by a processor, are used to implement the first aspect and / or various possible implementations of the first aspect.

[0041] Fifthly, embodiments of this application provide a computer program product, including a computer program that, when executed by a processor, implements the first aspect and / or various possible implementations of the first aspect.

[0042] The formation fluid type identification method, device, electronic device, and storage medium provided in this application embodiment obtain measurement data of the formation at different depths by measuring the formation at different depth points. Based on the measurement data, the formation porosity and water saturation at different depths are determined using formulas. Forward modeling is used to obtain forward density data of the formation at different depths. The error value is then obtained by comparing the forward modeling data with the actual density logging data at different depths. The fluid type of the formation is identified based on the error value, thereby improving the accuracy of fluid type identification of the formation. Attached Figure Description

[0043] The accompanying drawings, which are incorporated in and form part of this specification, illustrate embodiments consistent with this application and, together with the description, serve to explain the principles of this application.

[0044] Figure 1 A flowchart illustrating the formation fluid type identification method provided in this application embodiment;

[0045] Figure 2 This is a graph showing the measurement data of the first well to be logged in this embodiment of the application.

[0046] Figure 3 This is a graph showing the measurement data of the second well to be logged in this embodiment of the application.

[0047] Figure 4 This is a diagram showing the fluid type determination results for different formations in the first well to be tested in this embodiment of the application.

[0048] Figure 5 This is a diagram showing the fluid type determination results for different formations in the second well to be tested in this embodiment of the application.

[0049] Figure 6 A schematic diagram illustrating the process of constructing a formation fluid type identification map provided in an embodiment of this application;

[0050] Figure 7 An exemplary formation fluid type identification map provided for embodiments of this application;

[0051] Figure 8 A schematic diagram of the structure of the formation fluid type identification device provided in the embodiments of this application;

[0052] Figure 9 This is a schematic diagram of the structure of an electronic device provided in an embodiment of this application.

[0053] The accompanying drawings illustrate specific embodiments of this application, which will be described in more detail below. These drawings and descriptions are not intended to limit the scope of the concept in any way, but rather to illustrate the concept of this application to those skilled in the art through reference to particular embodiments. Detailed Implementation

[0054] Exemplary embodiments will now be described in detail, examples of which are illustrated in the accompanying drawings. When the following description relates to the drawings, unless otherwise indicated, the same numbers in different drawings denote the same or similar elements. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with this application. Rather, they are merely examples of apparatuses and methods consistent with some aspects of this application as detailed in the appended claims.

[0055] First, let me explain the terms used in this application:

[0056] Density logging: This refers to a logging method commonly used to measure the density of a formation. It typically uses a density logging instrument, which includes a radioactive source and a detector. The radioactive source emits gamma rays, which pass through the formation and are received by the detector. The rays are scattered as they pass through the formation, causing their energy to attenuate. The density of the formation is measured by calculating the degree of attenuation as the rays pass through it.

[0057] Neutron logging is a logging method commonly used to measure formation porosity or water content. It typically involves a neutron source and a detector. The neutron source emits neutrons that migrate outwards in a spherical pattern. As they pass through the borehole medium and enter the formation, the high-energy neutrons interact with the atomic nuclei of the matter, slowing them down and continuously losing energy. The detector measures the rate at which the formation scatters neutrons to determine the formation's water content or porosity.

[0058] Resistivity logging is a logging method that uses power supply and measurement electrodes placed at different locations to determine the resistivity of rocks or fluids within them. Specifically, resistivity refers to the ability of a formation to resist an electric current.

[0059] Forward modeling is a simulation method that uses computer simulation and other means to predict the properties of the Earth's interior or generate geophysical data based on known geological models and physical laws.

[0060] Resource exploration is of great significance and value to social development. For example, it can help ensure energy security, provide important support for economic development, and help manage resource development, reducing environmental damage and pollution. Formation logging technology is a commonly used technique in source exploration, which can obtain information such as the physical properties of the formation. Formation logging techniques include electromagnetic logging, sonic logging, nuclear logging, and other logging methods.

[0061] The specific application scenario of this application is to identify the fluid type of the formation under test. In some embodiments, core samples are obtained directly by drilling into the formation under test, and then the core samples are identified using specialized testing equipment. Specifically, infrared scanning of the sediment in the core sample can be used to determine whether hydrates are present in the formation under test, and density logging data and neutron logging data can be used to determine whether gas is present in the formation under test. This method requires drilling and coring the formation under test to identify the fluid type, which is costly and involves cumbersome procedures.

[0062] In some embodiments, the gas-hydrate co-layer and hydrate layer are distinguished by judging the changing trends of density, neutron porosity, and P-wave velocity of the formation under test. The gas-hydrate co-layer and gas layer are further distinguished by the relationship between shear modulus and background values ​​and the changing trend of chloride ion concentration in pore water of the core sample. However, this method requires verification of chloride ion concentration in pore water of the core sample, and the background value compared with the shear modulus is affected by lithology, resulting in poor fluid type identification of the formation under test and low efficiency.

[0063] In some embodiments, measurement data are obtained through neutron logging, density logging, and sonic transit-time logging. Neutron logging curves, density logging curves, and sonic transit-time logging curves are plotted using logging evaluation software with different scales. The areas where the three curves intersect are marked, and the fluid type of the formation corresponding to these intersection areas is determined based on the markings. This method does not require drilling to obtain core samples, but it is suitable for gas hydrate layers and gas layers, which have similar measurement data characteristics and small differences in measurement data, resulting in low accuracy in identifying the fluid type of the formation being tested.

[0064] Therefore, it can be seen that the above-described embodiments have the technical problem of low accuracy in fluid type identification.

[0065] The formation fluid type identification method provided in this application obtains various measurement data of the formation at different depths by measuring the formation at different depth points. Based on these measurement data, the formation porosity and water saturation at different depths are determined using formulas. Forward modeling is used to obtain forward density data of the formation at different depths. Then, the error value is calculated by comparing the forward modeling data with the actual density logging data at different depths. The fluid type of the formation is identified based on the error value. Compared with the aforementioned embodiments, this method can improve the accuracy of fluid type identification of the formation.

[0066] The technical solution of this application and how it solves the above-mentioned technical problems will be described in detail below with specific embodiments. These specific embodiments can be combined with each other, and the same or similar concepts or processes may not be described again in some embodiments. The embodiments of this application will be described below with reference to the accompanying drawings.

[0067] Figure 1 A flowchart illustrating the formation fluid type identification method provided in this application embodiment is shown below. Figure 1 As shown, the method includes:

[0068] Step 101. Based on the measurement data of the stratum to be tested at different depths, determine the porosity and water saturation of the stratum at different depths.

[0069] The measurement data includes density logging data, neutron logging data, and resistivity logging data.

[0070] In this embodiment, the formation to be tested refers to the formation for which fluid type identification is required; formation porosity refers to the proportion of pore space in rocks or soil, usually expressed as a decimal or percentage, representing the proportion of pore space in the total volume; formation water saturation refers to the ratio of the volume of water in underground rocks or reservoirs to the pore volume, used to describe the degree to which the pore space in rocks or reservoirs is filled with water.

[0071] In practical applications, density logging, neutron logging, and resistivity logging are used to obtain density data, neutron logging, and resistivity logging data at different depths of the formation under test. These measurements at different depths are then used to determine the formation porosity and water saturation at those depths.

[0072] In one example, taking the first depth of the formation to be tested as an example, the formation porosity at the first depth can be determined by the following steps:

[0073] Step 1011. Determine the density porosity of the formation at the first depth based on the density logging data of the formation to be tested at the first depth.

[0074] As an example, the formula for calculating density porosity can be:

[0075]

[0076] In formula (1), ρ represents density porosity, where ρ is the density logging data of the formation at the first depth. m ρ represents the density of the stratigraphic framework. w Represents the formation water density, where the formation skeleton density ρ m and formation water density ρ w All are constants, and the formation skeleton density ρ m The value is 2.71 g / cm³. 3 The density of formation water is taken as 1.02 g / cm³. 3 .

[0077] Step 1012. Determine the formation porosity at the first depth of the formation to be tested based on the neutron logging data and density porosity of the formation to be tested at the first depth.

[0078] As an example, the formula for calculating formation porosity can be:

[0079]

[0080] In formula (2), Indicates formation porosity. This represents the density and porosity of the formation at the first depth, as determined by formula (1). This represents the neutron logging data at the first depth of the formation to be tested.

[0081] The first depth can be any depth of the stratum to be measured, and can be determined based on depth points. In practical applications, the selection strategy for depth points is not limited. For example, a fixed number of depth points can be selected in the stratum to be measured, or depth points can be determined at a fixed depth. As an example, the depth can be determined to be 5m, meaning that a depth point is set every 5m in the stratum to be measured. It is understandable that the selection of depth points determines the amount of measurement data and computation. Specifically, when the number of depth points increases, the accuracy of judgment and identification increases, but the corresponding amount of measurement data and computation increases; when the number of depth points decreases, the amount of measurement data and computation decreases, the processing speed increases, but the accuracy of judgment and identification decreases.

[0082] After determining the formation porosity at different depths, it is also necessary to determine the formation water content at different depths based on the resistivity logging data and formation porosity from the measurement data.

[0083] In one example, continuing with the first depth of the stratum to be measured, after step 1012, the following is also included:

[0084] Step 1013. Based on the resistivity logging data and formation porosity of the formation at the first depth, determine the water saturation of the formation at the first depth.

[0085] Based on the resistivity logging data of the formation at the first depth and the formation porosity at the first depth determined by formula (2), the formation water saturation at the first depth is determined. As an example, the formula for calculating the formation water saturation can be:

[0086]

[0087] In formula (3), S w R represents the formation's water saturation, 'a' represents the lithology coefficient, and 'm' represents the cementation index. Both the lithology coefficient 'a' and the cementation index 'm' are constants. Specifically, the lithology coefficient 'a' and the cementation index 'm' can be obtained from a Pickett cross plot. A Pickett cross plot is a type of graph commonly used in rock physics and rock engineering. Different rock types or formations can be represented by specific curves or sets of curves. The lithology coefficient can be obtained based on the horizontal distance between different sets of curves, and the cementation index can be obtained based on the slope of the curve. w The resistivity of the formation water can be specifically obtained from a sodium chloride solution resistivity chart; n represents the saturation exponent, which is a constant with a value of 1.9386; and RD represents the resistivity logging data of the formation at the first depth. This represents the formation porosity at the first depth of the formation to be tested, as determined by formula (2).

[0088] It should be noted that the process of determining the formation porosity and water saturation at other depths of the stratum to be tested can refer to the process of determining the formation porosity and water saturation at the first depth mentioned above, and will not be repeated here.

[0089] Step 102. Based on the formation porosity and water saturation at different depths, determine the forward density data of the formation at different depths.

[0090] In this step, the formation to be tested can be assumed to be one of the fluid types. Based on the preset forward modeling formula for the fluid type layer, such as formula (4) or formula (5) below, the forward modeling density data when the formation to be tested is forward modeled as the fluid type layer can be determined.

[0091] In one example, taking the formation to be tested at the first depth as an example, assuming that the fluid type at the first depth of the formation to be tested is a gas layer, the first forward density data of the formation to be tested at the first depth is determined based on the formation porosity and formation water saturation at the first depth of the formation to be tested, as well as the preset forward gas layer formula.

[0092] As an example, the preset forward-modeling formula for gas layers can be expressed as follows:

[0093]

[0094] In formula (4), DENGS represents the first forward density data, also known as the forward gas layer density data. S represents the formation porosity at the first depth of the formation to be tested, as determined by formula (2). w ρ represents the formation water saturation at the first depth of the stratum to be tested, as determined by formula (3). g This represents the density of natural gas, which is a constant and has a value of 0.2 g / cm³. 3 .

[0095] In one example, taking the formation to be tested at the first depth as an example, assuming that the fluid type at the first depth of the formation to be tested is a hydrate layer, the second forward density data of the formation to be tested at the first depth is determined based on the formation porosity and formation water saturation at the first depth of the formation to be tested, as well as the preset forward hydrate layer formula.

[0096] As an example, the preset forward modeling formula for hydrate layers can be expressed as follows:

[0097]

[0098] In formula (5), DENGH represents the second forward density data, also known as the forward hydrate layer density data. S represents the formation porosity at the first depth of the formation to be tested, as determined by formula (2). w ρ represents the formation water saturation at the first depth of the stratum to be tested, as determined by formula (3). gh This represents the density of natural gas hydrate, which is a constant and has a value of 0.92 g / cm³. 3 .

[0099] Based on the foregoing, the forward density data of the stratum to be measured at the first depth includes the first forward density data and the second forward density data of the stratum to be measured at the first depth.

[0100] It should be noted that the process of determining the forward density data of the strata to be tested at other depths can refer to the process of determining the forward density data of the strata to be tested at the first depth, which will not be repeated here.

[0101] Step 103. Based on the density logging data and forward density data of the formation to be tested at different depths, determine the error value of the density logging data of the formation to be tested at different depths.

[0102] In this step, the density logging data of the formation at different depths are the actual density logging data obtained by measuring using the density logging method. Step 103 will be explained in detail below with two examples.

[0103] In one example, taking the formation to be tested at the first depth as an example, the first error value of the density logging data of the formation to be tested at the first depth is determined based on the density logging data and the first forward density data of the formation to be tested at the first depth.

[0104] In this example, assuming the fluid type at the first depth of the formation to be tested is a gas layer, the first forward density data of the formation at the first depth can be obtained. The first forward density data can also be described as forward gas layer density data. By inputting the density logging data and the first forward density data of the formation at the first depth into a preset first error formula, the first error value based on the density logging data of the formation at the first depth can be obtained.

[0105] As an example, the preset first error formula expression can be:

[0106] DETGS=(DENGS-ρ) / ρ (6)

[0107] In formula (6), DETGS represents the first error value, also known as the forward modeling gas layer error value, DENGS represents the first forward modeling density data of the formation to be tested at the first depth determined by formula (4), and ρ represents the density logging data of the formation to be tested at the first depth.

[0108] In one example, taking the formation to be tested at the first depth as an example, the second error value of the density logging data of the formation to be tested at the first depth is determined based on the density logging data and the second forward density data of the formation to be tested at the first depth.

[0109] In this example, assuming the fluid type at the first depth of the formation to be tested is a hydrate layer, the second forward density data of the formation at the first depth can be obtained. This second forward density data can also be described as forward hydrate layer density data. By inputting the density logging data and the second forward density data of the formation at the first depth into a preset second error formula, the second error value of the density logging data of the formation at the first depth can be obtained.

[0110] As an example, the preset expression for the second error formula can be:

[0111] DETGH=(DENGH-ρ) / ρ (7)

[0112] In formula (7), DETGH represents the second error value, also known as the forward modeling error value after the hydrate layer, DENGH represents the second forward modeling density data of the formation to be tested at the first depth determined by formula (5), and ρ represents the density logging data of the formation to be tested at the first depth.

[0113] It should be noted that the process of determining the error value of density logging data at other depths of the formation to be tested can refer to the process of determining the error value of density logging data at the first depth, which will not be repeated here.

[0114] Based on the foregoing, by selecting multiple depth points of the formation to be tested, for example, k depth points, k sets of forward density data can be obtained by performing step 103. Each set of forward density data includes two types of forward density data: forward gas layer density data (such as the first forward density data mentioned above) and forward hydrate layer density data (such as the second forward density data mentioned above). For each set of forward density data, by performing step 104, k sets of error values ​​can be obtained. Each set of error values ​​includes two types of error values, such as the first error value and the second error value of the logging density data at the first depth.

[0115] Step 104. Determine the fluid type of the formation to be tested based on the error values ​​of density logging data at different depths.

[0116] In this step, the fluid type of the formation to be tested is determined by the error value of the density logging data at different depths of the formation to be tested obtained based on the aforementioned steps 101 to 103.

[0117] In one example, the error values ​​of density logging data at different depths of the formation to be tested are mapped to multiple coordinate positions of a pre-constructed formation fluid type identification map. Based on the coordinate regions corresponding to the multiple coordinate positions, the fluid type of the formation to be tested is determined. The formation fluid type identification map is used to indicate the coordinate regions corresponding to formations with different fluid types.

[0118] Taking the formation to be tested at the first depth as an example, the first and second error values ​​of the density logging data of the formation at the first depth are obtained, namely the forward modeling error value after gas layer (DETGS) and the forward modeling error value after hydrate layer (DETGH). Using DETGS as the ordinate and DETGH as the abscissa, the coordinate points corresponding to the error values ​​of the density logging data of the formation at the first depth are obtained. The coordinate positions corresponding to these points are then plotted on a pre-constructed formation fluid type identification map.

[0119] It should be noted that the process of determining the coordinate points corresponding to the error values ​​of density logging data at other depths of the formation to be tested can refer to the process of determining the coordinate points corresponding to the error values ​​of density logging data at the first depth of the formation to be tested, so as to obtain multiple coordinate points corresponding to the error values ​​of density logging data at different depths of the formation to be tested. The multiple coordinate positions corresponding to the multiple coordinate points are plotted on the pre-constructed formation fluid type identification map, which will not be elaborated here.

[0120] As can be seen from the foregoing, the error values ​​of density logging data at different depths of the formation to be tested will have multiple corresponding coordinate positions. These corresponding coordinate positions are plotted in the formation fluid type identification map, and these coordinate positions may be located in different coordinate regions of the formation fluid type identification map.

[0121] Furthermore, in one example, the fluid type of the formation to be tested is determined based on the coordinate regions corresponding to multiple coordinate locations, including:

[0122] If multiple coordinate positions with a ratio greater than or equal to a preset ratio are all located in the first coordinate region of the formation fluid type identification map, the fluid type corresponding to the first coordinate region will be taken as the fluid type of the formation to be tested.

[0123] For example, some coordinate locations may fall within the first coordinate region of the formation fluid type identification map. The coordinate locations within the first coordinate region are counted, and the actual proportion of these locations relative to all coordinate locations is calculated. If this actual proportion is greater than or equal to a preset proportion, the fluid type corresponding to the first coordinate region is taken as the fluid type of the formation being analyzed. The first coordinate region can be any coordinate region on the formation fluid type identification map. Specifically, the preset proportion value depends on the actual situation and can be determined based on the strategy used when constructing the formation fluid type identification map. For example, the preset proportion value could be set to 75%.

[0124] Understandably, if 75% or more of the coordinate positions of the tested stratum at different depths fall within a certain area, the fluid type of the tested stratum is determined to belong to the fluid type corresponding to that area; otherwise, the fluid type identification is considered a failure. It should be noted that when the coordinate position is exactly on the boundary line, it is necessary to calculate the proportion of other coordinate positions of the tested stratum at different depths within a certain area. If more than 50% of the coordinate points of the tested stratum at different depths fall within a certain area, the coordinate point on the boundary line is determined to belong to that area; otherwise, the coordinate point is invalid.

[0125] Thus, the fluid type identification of the stratum under test can be achieved through steps 101 to 104.

[0126] For a practical application example, the target area has two wells to be logged. The first well contains three formations to be measured: layer 1 (1461-1505.5 meters), layer 2 (1505.5-1510 meters), and layer 3 (1510-1522 meters). The second well contains two formations to be measured: layer 4 (1896.5-1899 meters) and layer 5 (1899-1902.4 meters). Measurements are taken at different depths for each formation to obtain measurement data. The representation of the measurement data is not limited; it can be in vector format, database format, list format, etc. Curves can also be plotted based on the measurement data at different depths to obtain density logging curves, neutron logging curves, and resistivity logging curves. In one example, the measurement data of the formations at different depths are plotted as curves, such as... Figure 2 and Figure 3 As shown, Figure 2 This is a graph showing the measurement data of the first well to be logged in this embodiment of the application. Figure 3 This is a graph showing the measurement data of the second well to be logged in this embodiment of the application. Figure 2 and Figure 3 In the first track, MD refers to the depth of the well being logged; in the second track, GR refers to the natural gamma value, and UCAV refers to the well diameter; in the third track... This refers to neutron logging data, where ρ refers to density logging data; in the fourth channel, RD refers to resistivity logging data; in the fifth channel... This refers to formation porosity. This refers to density and porosity; in the sixth channel, S w This refers to the water saturation of the formation. It's understandable that the data from the first to fourth passes are measured data, while the data from the fifth and sixth passes are calculated based on the measured data.

[0127] Based on the measurement data of each formation at different depths, the error values ​​of density logging data at different depths for each formation are calculated according to steps 101 to 103. The DETGS and DETGH values ​​from the density logging data at different depths for layers 1, 2, and 3 in the first well are used as the ordinate and abscissa, respectively, to transform them into multiple coordinate positions. These coordinate positions are then plotted on the formation fluid type identification map, and different markers are used to distinguish the different coordinate positions corresponding to layers 1, 2, and 3. Figure 4 This is a diagram showing the fluid type determination results for different formations in the first well to be tested in this application embodiment, as shown below. Figure 4As shown in the diagram, the circular dots correspond to the coordinate positions of layer 1 at different depths, the triangular dots correspond to the coordinate positions of layer 2 at different depths, and the star-shaped dots correspond to the coordinate positions of layer 3 at different depths. For layer 1, all coordinate positions fall in region a, so the fluid type of layer 1 is identified as a hydrate layer; for layer 2, 85% of the coordinate positions fall in region b, so the fluid type of layer 2 is identified as a gas-hydrate co-layer; for layer 3, 94.7% of the coordinate positions fall in region c, so the fluid type of layer 3 is identified as a gas layer. It can be understood that... Figure 4 If none of the three strata to be tested fall within region d, it indicates that the fluid type of strata 1, 2, and 3 is not water.

[0128] The error values ​​of DETGS and DETGH in the density logging data of layers 4 and 5 at different depths in the second well to be logged are used as the vertical and horizontal axes to transform them into multiple coordinate positions. These coordinate positions are plotted on the formation fluid type identification map, and different markers are used to distinguish the different coordinate positions corresponding to layers 4 and 5. Figure 5 This is a diagram showing the fluid type determination results for different formations in the second well to be tested in this embodiment of the application. Figure 5 As shown in the diagram, the circular dots correspond to the coordinate positions of layer 4 at different depths, and the triangular dots correspond to the coordinate positions of layer 5 at different depths. For layer 4, all coordinate positions fall within region a, therefore the fluid type of layer 4 is identified as a hydrate layer; for layer 5, 77% of the coordinate positions fall within region b, therefore the fluid type of layer 5 is identified as a gas-hydrate co-layer. It can be understood that... Figure 5 If no coordinate position in either of the two tested strata falls within region d, it indicates that the fluid type in both strata 4 and 5 is not water.

[0129] During the actual drilling and coring operations of the first and second wells to be logged, hydrate samples were obtained from layers 1 and 2. Gas was observed in layers 2 and 3 using seabed imaging, while no gas was observed in layer 1. This confirms that layer 1 is a hydrate layer, layer 2 is a gas-hydrate co-layer, and layer 3 is a gas layer. Similarly, hydrate samples were obtained from layers 4 and 5. Gas was observed in layer 5 using seabed imaging, while no gas was observed in layer 4. This confirms that layer 4 is a hydrate layer, and layer 5 is a gas-hydrate co-layer. Based on the above drilling and coring results, the formation fluid type identification method provided in this embodiment demonstrates its accuracy and reliability in identifying the fluid type of the formation to be logged.

[0130] The formation fluid type identification method provided in this application involves measuring the formation at different depths to obtain measurement data, which determines the formation porosity and water saturation at different depths. A forward modeling simulation is then performed on the formation, assuming it to be a gas layer or a hydrate layer, to determine the first and second forward density data at different depths. Based on the forward density data and density logging data at different depths, the error value of the density logging data at different depths is determined, and the fluid type of the formation is determined based on this error value. This method avoids directly identifying the characteristics of the measurement data, reducing the error rate of fluid type identification due to similar characteristics of the measurement data, thereby improving the accuracy of fluid type identification. Furthermore, it avoids the need for core drilling to observe the formation, simplifying the fluid type identification process and improving efficiency.

[0131] As can be seen from the foregoing embodiments, when identifying the fluid type of a formation, the fluid type of the formation can be determined by mapping the error values ​​of density logging data at different depths of the formation to a pre-constructed formation fluid type identification map. The formation fluid type identification map is constructed based on measurement data of known formations with known fluid types. The following provides a detailed explanation of how to construct the formation fluid type identification map of the foregoing embodiments.

[0132] For example, Figure 6 This is a schematic diagram of the process for constructing a formation fluid type identification map provided in an embodiment of this application, as shown below. Figure 6 As shown, a formation fluid type identification map can be constructed through the following steps:

[0133] Step 201. Based on the measurement data of the known strata at different depths, determine the porosity and water saturation of the known strata at different depths.

[0134] Step 202. Based on the known formation porosity and water saturation at different depths, determine the forward density data of the known formation at different depths.

[0135] Step 203. Based on the density logging data and forward density data of the known formation at different depths, determine the error values ​​of the density logging data of the known formation at different depths.

[0136] In the target area where the formation to be tested is located, measurements are taken at wells containing known formations of known fluid types to obtain measurement data of the known formations at different depths. Data processing operations from steps 201 to 203 are then performed to obtain the error values ​​of the density logging data of the known formations at different depths. The known formations of known fluid types can include gas layers, hydrate layers, and gas-hydrate co-layers. In practical applications, density logging methods are used to obtain density logging data of the known formations at different depths, neutron logging methods are used to obtain seed logging data of the known formations at different depths, and resistivity logging methods are used to obtain resistivity logging data of the known formations at different depths. These measurement data of the known formations at different depths are used to determine the formation porosity and water saturation of the formation to be tested at different depths. Based on the formation porosity and water saturation of the known formations at different depths, two aspects of forward modeling are performed. Assuming the known formations as gas layers and hydrate layers respectively, and based on preset forward modeling formulas for gas layers and hydrate layers, the forward modeling density data of the known formations at different depths are determined. Based on the forward modeling density data of the known formations at different depths, the error values ​​of the density logging data of the known formations at different depths are determined using preset first and second error formulas. The specific implementation principles of steps 201 to 203 are similar to those of steps 101 to 103 in the aforementioned embodiment, and will not be repeated here.

[0137] It should be noted that even though the fluid type of the formation is known before forward modeling, it can still be performed. The purpose of this process is to determine the criteria for identifying the fluid type of the formation to be tested based on known formations with known fluid types.

[0138] Step 204. Map the error values ​​of density logging data of known formations at different depths to a preset coordinate map to obtain multiple coordinate positions corresponding to the known formations in the preset coordinate map.

[0139] Taking a known formation at the first depth as an example, the first and second error values ​​of the density logging data at the first depth are obtained, namely the forward modeling error value DETGS for gas layers and the forward modeling error value DETGH for hydrate layers. Using DETGS as the ordinate and DETGH as the abscissa, the coordinate points corresponding to the error values ​​of the density logging data at the first depth are obtained. The coordinate positions corresponding to these points are then mapped onto a preset coordinate graph. The process of determining the coordinate points corresponding to the error values ​​of the density logging data at other depths for the known formation can refer to the process of determining the coordinate points corresponding to the error values ​​of the density logging data at the first depth, thus obtaining multiple coordinate points corresponding to the error values ​​of the density logging data at different depths for the known formation. These multiple coordinate points are then mapped onto a preset coordinate graph, and the graph is plotted with distinguishable markers. The preset coordinate graph is a Cartesian coordinate system.

[0140] Step 205. Obtain multiple coordinate points corresponding to known strata of different fluid types in the preset coordinate map.

[0141] By executing steps 201 to 204, multiple coordinate points corresponding to known strata of different fluid types at different depths in a preset coordinate map can be obtained. Specifically, steps 201 to 204 are executed for the gas layer, hydrate layer, and gas-hydrate co-layer, respectively, to obtain multiple coordinate points corresponding to the gas layer, multiple coordinate points corresponding to the hydrate layer, and multiple coordinate points corresponding to the gas-hydrate co-layer.

[0142] Step 206. Based on multiple coordinate points corresponding to known strata of different fluid types in the preset coordinate map, fit to obtain a strata fluid type identification map containing the boundary line of strata fluid types.

[0143] Among them, the formation fluid type boundary line is used to divide the preset coordinate map into multiple coordinate regions, with different coordinate regions corresponding to formations with different fluid types.

[0144] For example, Figure 7 An exemplary formation fluid type identification map provided for embodiments of this application, such as Figure 7As shown in the diagram, the circular dots correspond to the coordinates of the hydrate layer at different depths, the triangular dots correspond to the coordinates of the gas-hydrate co-layer at different depths, and the star-shaped dots correspond to the coordinates of the gas layer at different depths. Based on the locations of multiple coordinate points corresponding to known strata of different fluid types, fluid type boundaries are fitted. Specifically, firstly, a horizontal boundary line is fitted to separate the coordinate positions corresponding to the gas layer from those corresponding to the gas-hydrate co-layer; secondly, a vertical boundary line is fitted to separate the coordinate positions corresponding to the gas-hydrate co-layer from those corresponding to the hydrate layer. These two linear boundary lines intersect at point A, whose coordinates are (-0.5%, -0.5%), and the preset coordinate map is divided into four regions: region a, region b, region c, and region d, namely the hydrate layer, the gas-hydrate co-layer, the gas layer, and the water layer.

[0145] It is understandable that if the error values ​​of density logging data at different depths of the formation to be tested are mapped to... Figure 7 If multiple coordinate locations in the formation fluid type identification map are shown, and a percentage of these coordinate locations (e.g., 75%) fall within one of the aforementioned four regions, then the fluid type corresponding to that region can be taken as the fluid type of the formation to be tested.

[0146] In this embodiment, the order in which fluid type boundaries are defined is not limited. Horizontal boundaries can be fitted first, followed by vertical boundaries, or vice versa. It should be noted that in some embodiments, the boundaries may also be oblique lines or curves.

[0147] The above embodiments illustrate the construction process of a formation fluid type identification map. By acquiring measurement data of known formations with multiple fluid types, the error values ​​of multiple sets of density logging data at different depths of known formations with different fluid types are determined. The error values ​​of multiple sets of density logging data are mapped onto a preset coordinate map. Since the fluid type corresponding to the error value of each set of density logging data is known, fluid type boundaries can be fitted on the preset coordinate map based on the error values ​​of multiple sets of density logging data. This allows the preset coordinate map to be divided into multiple coordinate regions, each corresponding to a fluid type, thus realizing the construction of a formation fluid type identification map and providing data support for the aforementioned formation fluid type identification scheme.

[0148] Figure 8 A schematic diagram of the structure of the formation fluid type identification device provided in the embodiments of this application is shown below. Figure 8 As shown, the formation fluid type identification device 80 provided in this embodiment includes:

[0149] The processing module 81 is used to determine the formation porosity and formation water saturation at different depths of the formation to be tested based on the measurement data at different depths of the formation to be tested; the measurement data includes density logging data, neutron logging data and resistivity logging data.

[0150] The processing module 81 is also used to determine the forward density data of the stratum at different depths based on the porosity and water saturation of the stratum at different depths.

[0151] The processing module 81 is also used to determine the error value of the density logging data of the formation under test at different depths based on the density logging data and forward density data of the formation under test at different depths.

[0152] The processing module 81 is also used to determine the fluid type of the formation to be tested based on the error value of the density logging data at different depths of the formation to be tested.

[0153] In one possible implementation, when the processing module 81 determines the forward density data of the formation at different depths based on the formation porosity and water saturation at different depths, it specifically performs the following:

[0154] Assuming the fluid type at the first depth of the stratum to be measured is a gas layer, the first forward density data of the stratum at the first depth is determined based on the formation porosity and water saturation at the first depth, as well as the preset forward gas layer formula.

[0155] Furthermore, assuming that the fluid type at the first depth of the stratum to be measured is a hydrate layer, the second forward density data of the stratum to be measured at the first depth are determined based on the stratum porosity and stratum water saturation at the first depth, as well as the preset forward hydrate layer formula.

[0156] In one possible implementation, when the processing module 81 determines the error value of the density logging data of the formation at different depths based on the density logging data and forward density data of the formation to be tested at different depths, it is specifically used for:

[0157] Based on the density logging data and the first forward density data of the formation to be tested at the first depth, the first error value of the density logging data of the formation to be tested at the first depth is determined.

[0158] And based on the density logging data of the formation to be tested at the first depth and the second forward density data, determine the second error value of the density logging data of the formation to be tested at the first depth.

[0159] In one possible implementation, when determining the fluid type of the formation to be tested based on the error values ​​of density logging data at different depths, the processing module 81 is specifically used for:

[0160] The error values ​​of density logging data at different depths of the formation to be tested are obtained and mapped to multiple coordinate positions of a pre-constructed formation fluid type identification map. The formation fluid type identification map is used to indicate the coordinate regions corresponding to formations with different fluid types.

[0161] The fluid type of the formation to be tested is determined based on the coordinate regions corresponding to multiple coordinate locations.

[0162] In one possible implementation, the processing module 81 determines the fluid type of the formation to be tested based on the coordinate regions corresponding to multiple coordinate positions, specifically for:

[0163] If multiple coordinate positions with a ratio greater than or equal to a preset ratio are all located in the first coordinate region of the formation fluid type identification map, the fluid type corresponding to the first coordinate region will be taken as the fluid type of the formation to be tested.

[0164] In one possible implementation, the processing module 81 is further configured to:

[0165] Based on the measurement data of the known strata at different depths, the porosity and water saturation of the known strata at different depths are determined respectively.

[0166] Based on the known porosity and water saturation of the strata at different depths, the forward density data of the known strata at different depths are determined.

[0167] Based on density logging data and forward density data of known formations at different depths, the error values ​​of density logging data of known formations at different depths are determined respectively.

[0168] Map the error values ​​of density logging data of known formations at different depths to a preset coordinate map to obtain multiple coordinate points corresponding to the known formations in the preset coordinate map; repeat the above steps to obtain multiple coordinate points corresponding to known formations of different fluid types in the preset coordinate map.

[0169] Based on multiple coordinate points corresponding to known strata of different fluid types in the preset coordinate map, a strata fluid type identification map containing the strata fluid type boundary line is obtained; the strata fluid type boundary line is used to divide the preset coordinate map into multiple coordinate regions, and different coordinate regions correspond to strata of different fluid types.

[0170] In one possible implementation, when the processing module 81 determines the formation porosity and water saturation at different depths of the formation based on measurement data at different depths, it specifically performs the following:

[0171] Based on the density logging data of the formation at the first depth, the density porosity of the formation at the first depth is determined.

[0172] Based on the neutron logging data and density porosity of the formation at the first depth, the formation porosity at the first depth is determined.

[0173] In one possible implementation, when the processing module 81 determines the formation porosity and water saturation at different depths of the formation based on measurement data at different depths, it specifically performs the following:

[0174] Based on the resistivity logging data of the formation at the first depth and the formation porosity at different depths, the water saturation of the formation at different depths is determined.

[0175] Optionally, the formation fluid type identification device 80 provided in this embodiment may further include:

[0176] The acquisition module 82 is used to acquire measurement data of the strata to be measured at different depths obtained by the measuring tool.

[0177] The formation fluid type identification device provided in this embodiment can execute the method provided in the above method embodiment. Its implementation principle and technical effect are similar, and will not be described in detail here.

[0178] Figure 9 This is a schematic diagram of the structure of an electronic device provided in an embodiment of this application. Figure 9 As shown, the electronic device 90 provided in this embodiment includes at least one processor 901 and a memory 902. Optionally, the device 90 further includes a communication component 903. The processor 901, memory 902, and communication component 903 are connected via a bus 904.

[0179] In a specific implementation, at least one processor 901 executes computer execution instructions stored in memory 902, causing at least one processor 901 to perform the above-described method.

[0180] The specific implementation process of processor 901 can be found in the above method embodiments, and its implementation principle and technical effect are similar. It will not be repeated here.

[0181] In the above embodiments, it should be understood that the processor can be a Central Processing Unit (CPU), or other general-purpose processors, digital signal processors (DSPs), application-specific integrated circuits (ASICs), etc. The general-purpose processor can be a microprocessor or any conventional processor. The steps of the method disclosed in this invention can be directly implemented by a hardware processor, or implemented by a combination of hardware and software modules within the processor.

[0182] The memory may include random access memory (RAM) and may also include non-volatile memory (NVM), such as at least one disk storage device.

[0183] The bus can be an Industry Standard Architecture (ISA) bus, a Peripheral Component Interconnect (PCI) bus, or an Extended Industry Standard Architecture (EISA) bus, etc. Buses can be categorized as address buses, data buses, control buses, etc. For ease of illustration, the buses shown in the accompanying drawings are not limited to a single bus or a single type of bus.

[0184] This application also provides a computer-readable storage medium storing computer-executable instructions, which, when executed by a processor, implement the above-described method.

[0185] This application also provides a computer program product, including a computer program that, when executed by a processor, implements the above-described method.

[0186] The aforementioned readable storage medium can be implemented by any type of volatile or non-volatile storage device or a combination thereof, such as static random access memory (SRAM), electrically erasable programmable read-only memory (EEPROM), erasable programmable read-only memory (EPROM), programmable read-only memory (PROM), read-only memory (ROM), magnetic storage, flash memory, magnetic disk, or optical disk. The readable storage medium can be any available medium accessible to a general-purpose or special-purpose computer.

[0187] An exemplary readable storage medium is coupled to a processor, enabling the processor to read information from and write information to the readable storage medium. Of course, the readable storage medium can also be a component of the processor. The processor and the readable storage medium can reside in an Application Specific Integrated Circuit (ASIC). Alternatively, the processor and the readable storage medium can exist as discrete components in the device.

[0188] The division of units is merely a logical functional division; in actual implementation, there may be other division methods. For example, multiple units or components may be combined or integrated into another system, or some features may be ignored or not executed. Furthermore, the coupling or direct coupling or communication connection shown or discussed may be indirect coupling or communication connection through some interfaces, devices, or units, and may be electrical, mechanical, or other forms.

[0189] The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; that is, they may be located in one place or distributed across multiple network units. Some or all of the units can be selected to achieve the purpose of this embodiment according to actual needs.

[0190] In addition, the functional units in the various embodiments of the present invention can be integrated into one processing unit, or each unit can exist physically separately, or two or more units can be integrated into one unit.

[0191] If a function is implemented as a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of this invention, or the part that contributes to the prior art, or a 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 includes several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) to execute all or part of the steps of the methods of the various embodiments of this invention. 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.

[0192] Those skilled in the art will understand that all or part of the steps of the above-described method embodiments can be implemented by hardware related to program instructions. The aforementioned program can be stored in a computer-readable storage medium. When executed, the program performs the steps of the above-described method embodiments; and the aforementioned storage medium includes various media capable of storing program code, such as ROM, RAM, magnetic disks, or optical disks.

[0193] Finally, it should be noted that other embodiments of the invention will readily occur to those skilled in the art upon consideration of the specification and practice of the invention disclosed herein. This invention is intended to cover any variations, uses, or adaptations of the invention that follow the general principles of the invention and include common knowledge or customary techniques in the art not disclosed herein, and is not limited to the precise structures described above and shown in the accompanying drawings, and various modifications and changes can be made without departing from its scope. The scope of the invention is limited only by the appended claims.

Claims

1. A method for identifying formation fluid types, characterized in that, include: Based on the measurement data of the formation at different depths, the formation porosity and water saturation of the formation at different depths are determined respectively; the measurement data includes density logging data, neutron logging data and resistivity logging data; Based on the formation porosity and water saturation at different depths of the formation to be tested, the forward density data of the formation to be tested at different depths are determined respectively. Based on the density logging data and forward density data of the formation to be tested at different depths, the error values ​​of the density logging data of the formation to be tested at different depths are determined respectively. Based on the error values ​​of density logging data at different depths of the formation to be tested, the fluid type of the formation to be tested is determined; Among these methods, the fluid type of the formation to be tested is determined based on the error values ​​of density logging data at different depths, including: The error values ​​of density logging data at different depths of the formation to be tested are obtained and mapped to multiple coordinate positions of a pre-constructed formation fluid type identification map, which is used to indicate the coordinate regions corresponding to formations with different fluid types. The fluid type of the formation to be tested is determined based on the coordinate regions corresponding to the multiple coordinate positions. Specifically, based on measurement data of the strata at different depths, the formation porosity and water saturation at different depths are determined, including: Based on the density logging data of the formation to be tested at the first depth, the density porosity of the formation to be tested at the first depth is determined; Based on the neutron logging data and density porosity of the formation to be tested at the first depth, the formation porosity at the first depth is determined. Specifically, based on the measurement data of the stratum to be tested at the first depth, the formation porosity and water saturation at the first depth are determined, including: Based on the resistivity logging data and formation porosity of the formation at the first depth, the water saturation of the formation at the first depth is determined.

2. The method according to claim 1, characterized in that, The process of determining forward density data of the formation at different depths based on the formation porosity and water saturation at different depths includes: Assuming the fluid type at the first depth of the formation under test is a gas layer, the first forward-modeled density data of the formation at the first depth is determined based on the formation porosity and water saturation at the first depth, and a preset forward-modeled gas layer formula; and Assuming the fluid type at the first depth of the formation to be tested is a hydrate layer, the second forward density data of the formation to be tested at the first depth is determined based on the formation porosity and formation water saturation at the first depth, as well as a preset forward hydrate layer formula.

3. The method according to claim 2, characterized in that, The step of determining the error value of the density logging data of the formation at different depths based on density logging data and forward density data at different depths includes: Based on the density logging data of the formation to be tested at the first depth and the first forward density data, determine the first error value of the density logging data of the formation to be tested at the first depth; and Based on the density logging data of the formation to be tested at the first depth and the second forward density data, a second error value of the density logging data of the formation to be tested at the first depth is determined.

4. The method according to claim 1, characterized in that, The step of determining the fluid type of the formation to be tested based on the coordinate regions corresponding to the multiple coordinate positions includes: If any of the multiple coordinate positions is greater than or equal to a preset ratio and is located in the first coordinate region of the formation fluid type identification map, the fluid type corresponding to the first coordinate region is taken as the fluid type of the formation to be tested.

5. The method according to claim 1, characterized in that, The method further includes: Based on the measurement data of the known strata at different depths, the porosity and water saturation of the known strata at different depths are determined respectively. Based on the known strata porosity and water saturation at different depths, the forward density data of the known strata at different depths are determined respectively. Based on the density logging data and forward density data of the known formation at different depths, the error values ​​of the density logging data of the known formation at different depths are determined respectively. The error values ​​of density logging data at different depths of the known formation are mapped to a preset coordinate map to obtain multiple coordinate points corresponding to the known formation in the preset coordinate map; the above steps are repeated to obtain multiple coordinate points corresponding to the known formation with different fluid types in the preset coordinate map; Based on multiple coordinate points corresponding to known formations of different fluid types in the preset coordinate map, a formation fluid type identification map containing formation fluid type boundaries is obtained by fitting the coordinates. The formation fluid type boundaries are used to divide the preset coordinate map into multiple coordinate regions, with different coordinate regions corresponding to formations of different fluid types.

6. A device for identifying formation fluid types, characterized in that, include: The processing module is used to determine the formation porosity and formation water saturation at different depths of the formation to be tested based on the measurement data at different depths; the measurement data includes density logging data, neutron logging data, and resistivity logging data. The processing module is also used to determine the forward density data of the formation at different depths based on the formation porosity and formation water saturation at different depths. The processing module is also used to determine the error value of the density logging data of the formation under test at different depths based on the density logging data and forward density data at different depths of the formation under test. The processing module is also used to determine the fluid type of the formation to be tested based on the error value of the density logging data at different depths of the formation to be tested; Specifically, when determining the fluid type of the formation to be tested based on the error values ​​of density logging data at different depths, the processing module is used for: The error values ​​of density logging data at different depths of the formation to be tested are obtained and mapped to multiple coordinate positions of a pre-constructed formation fluid type identification map, which is used to indicate the coordinate regions corresponding to formations with different fluid types. The fluid type of the formation to be tested is determined based on the coordinate regions corresponding to the multiple coordinate positions. Specifically, when the processing module determines the formation porosity and water saturation at different depths based on measurement data from the formation at different depths, it is used for: Based on the density logging data of the formation to be tested at the first depth, the density porosity of the formation to be tested at the first depth is determined; Based on the neutron logging data and density porosity of the formation to be tested at the first depth, the formation porosity at the first depth is determined. Specifically, when the processing module determines the formation porosity and water saturation at the first depth based on the measurement data of the formation to be tested at the first depth, it is used for: Based on the resistivity logging data and formation porosity of the formation at the first depth, the water saturation of the formation at the first depth is determined.

7. An electronic device, characterized in that, include: Memory, processor; The memory stores computer-executed instructions; The processor executes computer execution instructions stored in the memory, causing the processor to perform the method as claimed in any one of claims 1-5.

8. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores computer-executable instructions, which, when executed by a processor, are used to implement the method as claimed in any one of claims 1-5.

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