A fluid identification method and system using water-saturated hydrogen index contrast

Abstract

The application discloses a kind of fluid identification method and system of water-saturated hydrogen index contrast method, calculate reservoir matrix porosity;Electric imaging and double lateral data are combined to calculate rock fracture porosity, and sum matrix porosity to total porosity;Assume that bedrock reservoir pore is water-saturated, select the dynamic skeleton neutron value of the dense layer section of lowest porosity, high resistivity dynamic skeleton as fixed skeleton value, calculate the dynamic skeleton neutron value of the purpose layer in combination with total porosity;According to dynamic skeleton neutron value, calculate water-saturated hydrogen index of research interval;Water-saturated hydrogen index is compared with neutron actual logging value to calculate neutron difference value;In combination with gas production test data, the relationship between acoustic time difference and neutron difference value and the change relationship between matrix porosity and neutron difference value are analyzed using neutron difference value, and the relationship chart of quantitative identification gas-water layer is obtained.The method eliminates the influence of anisotropy, fracture occurrence and the like of bedrock lithology, highlights the characteristics of reservoir gas layer, and can more accurately identify the properties of reservoir fluid.

Description

Technical Field

[0001] This invention belongs to the field of reservoir fluid property evaluation, and relates to a fluid identification method and system based on the comparison of water-saturated hydrogen content index. Background Technology

[0002] Gas reservoir identification methods mainly include the three-porosity intersection method, the three-porosity difference ratio method, the P-wave velocity ratio method, the apparent elastic modulus coefficient method, the nuclear magnetic resonance differential spectroscopy method, and the shift spectral method. However, most oilfield reservoirs are characterized by complex lithology, low porosity and permeability, low maturity, strong heterogeneity, and complex pore structures. This results in a weak resistivity signal reflecting fluid properties, making it difficult to accurately identify the gas-bearing nature of the reservoir. Therefore, there is an urgent need to develop a non-electrical method for effectively identifying gas reservoirs. Summary of the Invention

[0003] The purpose of this invention is to solve the problems in the prior art and provide a fluid identification method and system based on the water-saturated hydrogen index comparison method. This aims to solve the defective technical problem in the prior art where the resistivity signal reflecting fluid properties is weak, making it difficult to accurately identify the gas content of reservoirs.

[0004] To achieve the above objectives, the present invention employs the following technical solution:

[0005] The present invention proposes a fluid identification method based on the comparison of hydrogen content in water saturation index, characterized by comprising the following steps:

[0006] Obtain the reservoir matrix porosity within the study area; obtain the rock fracture porosity based on matrix porosity, electrical imaging, and bilateral lateral data; obtain the total porosity of the rock based on the rock fracture porosity and matrix porosity.

[0007] The dynamic skeleton neutron value of the target layer is obtained based on the rock physical volume model and the total porosity of the rock.

[0008] The water-saturated hydrogen index of the study section was obtained based on the dynamic skeleton neutron value and the rock physical volume model.

[0009] The neutron difference is obtained by comparing the hydrogen content index of saturated water with the actual neutron logging value.

[0010] By combining test gas and production data with neutron difference values, the relationship between acoustic transit time and neutron difference values ​​and matrix porosity and neutron difference values ​​is analyzed to obtain a relationship chart for quantitative identification of gas-water layers.

[0011] Preferably, the method for calculating the reservoir matrix porosity within the study area includes the following steps:

[0012] Determine the mineral percentage of each mineral in the reservoir rock;

[0013] The mineral percentage of each mineral is multiplied by the corresponding theoretical acoustic value and summed to obtain the acoustic time difference value of the mineral matrix skeleton of the rock.

[0014] The acoustic transit time of the rock matrix mineral framework is input into the rock physical volume model to obtain the matrix porosity; matrix porosity Φ 基质 The calculation is shown in formula (1):

[0015]

[0016] Where, Φ 基质 Δt represents matrix porosity, expressed as a percentage (%). 测量 Δt represents the sonic transit time value in well logging, in µs / ft. 流体 Δt represents the fluid acoustic time difference, measured in µs / ft. 混ma The time difference of acoustic waves in the rock matrix mineral framework is expressed in µs / ft.

[0017] Preferably, the methods for obtaining rock fracture porosity and total rock porosity are as follows:

[0018] Rock fracture porosity was calculated by coring section electrical imaging logging fracture picking method based on fracture density description of core samples.

[0019] The total porosity of the rock is obtained by summing the rock fracture porosity and the matrix porosity.

[0020] Preferably, the sub-values ​​in the target layer dynamic skeleton The calculation is shown in formula (2):

[0021]

[0022] in, The value represents the sub-value of the dynamic skeleton, expressed as a percentage. The theoretical hydrogen content index of water, expressed as a percentage. The total porosity of the rock.

[0023] Preferably, the dynamic skeleton neutron value of the dense layer segment is selected as the fixed skeleton value.

[0024] Preferably, the hydrogen content index of the water-saturated layer is studied. The calculation is shown in formula (3):

[0025]

[0026] in, The total porosity of the rock. The porosity of formation water. The neutron value represents the dynamic skeleton of the rock.

[0027] Preferably, neutron difference The calculation is shown in formula (4):

[0028]

[0029] in, This represents the actual logging value for neutrons.

[0030] The present invention proposes a system for fluid identification using a water-saturated hydrogen index comparison method, comprising:

[0031] A porosity acquisition module is used to acquire the reservoir matrix porosity in the study area; acquire rock fracture porosity based on matrix porosity, electrical imaging and two-sided lateral data; and acquire the total porosity of the rock based on rock fracture porosity and matrix porosity.

[0032] A dynamic skeleton neutron value acquisition module is used to acquire the dynamic skeleton neutron value of the target layer based on the rock physical volume model and the total porosity of the rock.

[0033] A water-saturated hydrogen content index acquisition module is used to acquire the water-saturated hydrogen content index of the study section based on the dynamic skeleton neutron value and the rock physical volume model.

[0034] The neutron difference acquisition module is used to obtain the neutron difference by comparing the hydrogen content index of saturated water with the actual neutron logging value.

[0035] The gas-water layer relationship map acquisition module is used to combine test gas and production data and neutron difference values ​​to analyze the relationship between acoustic transit time and neutron difference values ​​and matrix porosity and neutron difference values, and to acquire a relationship map for quantitative identification of gas-water layers.

[0036] A computer device includes a memory and a processor, the memory storing a computer program, and the processor executing the computer program to implement the steps of a fluid identification method based on a comparison of water saturation hydrogen content index.

[0037] A computer-readable storage medium storing a computer program that, when executed by a processor, implements the steps of a fluid identification method based on a comparison of water-saturated hydrogen content index.

[0038] Compared with the prior art, the present invention has the following beneficial effects:

[0039] This invention provides a fluid identification method based on the comparison of water-saturated hydrogen index. After calculating the porosity of the rock matrix and fractures, the neutron value of the dynamic rock skeleton is calculated according to a rock physical volume model. Then, assuming the bedrock reservoir is saturated with water, the water-saturated hydrogen index is calculated based on the volume model and compared with the actual neutron logging value to calculate the neutron difference. If the reservoir contains natural gas, the measured neutron logging value will be lower than the water-saturated hydrogen index, and this characteristic is more pronounced the better the reservoir properties and the higher the gas saturation. Furthermore, by combining gas testing and production data, the relationship between acoustic transit time and neutron difference, and between matrix porosity and neutron difference, is analyzed to obtain a relationship chart for quantitatively identifying gas-water layers, which can effectively identify reservoir fluid properties. Compared with traditional methods such as the three-porosity intersection method, the three-porosity difference ratio method, and the P-wave velocity ratio method, this method eliminates the influence of anisotropic variations in bedrock lithology by segmenting single wells and taking different neutron framework values. Based on neutron logging, this non-electric logging method eliminates the influence of fracture occurrence on logging response characteristics. The rock physics model calculation includes matrix porosity and fracture porosity, ensuring that the fluid property identification covers the influence of lithological and physical property variations. The generated map shows outstanding gas layer identification performance, providing a reliable guarantee for the exploration of natural gas in oilfields.

[0040] The fluid identification method proposed in this invention, which uses a water-saturated hydrogen index comparison method, divides the system into a porosity acquisition module, a dynamic skeleton neutron value acquisition module, a water-saturated hydrogen index acquisition module, a neutron difference acquisition module, and a gas-water layer relationship map acquisition module. By adopting a modular approach, each module is made independent of the others, which facilitates unified management of each module. Attached Figure Description

[0041] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the embodiments will be briefly introduced below. It should be understood that the following drawings only show some embodiments of the present invention and should not be regarded as a limitation on the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort.

[0042] Figure 1 This is a flowchart of the fluid identification method based on the hydrogen content index comparison method for water saturation of the present invention.

[0043] Figure 2 This is a cross-plot of neutron difference and acoustic time difference in an embodiment of the present invention.

[0044] Figure 3 This is a cross-plot of neutron difference and matrix porosity in an embodiment of the present invention.

[0045] Figure 4 This is a diagram illustrating the overall implementation of an embodiment of the present invention.

[0046] Figure 5 This is a diagram of the fluid identification system of the hydrogen content index comparison method for water saturation of the present invention. Detailed Implementation

[0047] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0048] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0049] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0050] In the description of the embodiments of the present invention, it should be noted that if terms such as "upper," "lower," "horizontal," or "inner" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, or the orientation or positional relationship commonly used when the product of the invention is in use, they are only for the convenience of describing the present invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of the present invention. Furthermore, terms such as "first" and "second" are only used to distinguish descriptions and should not be construed as indicating or implying relative importance.

[0051] Furthermore, the use of the term "horizontal" does not imply that the component must be absolutely horizontal, but rather that it can be slightly tilted. For example, "horizontal" simply means that its direction is more horizontal than "vertical," and does not mean that the structure must be completely horizontal, but can be slightly tilted.

[0052] In the description of the embodiments of the present invention, it should also be noted that, unless otherwise explicitly specified and limited, the terms "set," "install," "connect," and "link" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in the present invention according to the specific circumstances.

[0053] The present invention will now be described in further detail with reference to the accompanying drawings:

[0054] This invention provides a fluid identification method based on the comparison of hydrogen content in water saturation index, such as... Figure 1 As shown, it includes the following steps:

[0055] Obtain the reservoir matrix porosity within the study area; obtain the rock fracture porosity based on matrix porosity, electrical imaging, and bilateral lateral data; obtain the total porosity of the rock based on the rock fracture porosity and matrix porosity.

[0056] The dynamic skeleton neutron value of the target layer is obtained based on the rock physical volume model and the total porosity of the rock.

[0057] The water-saturated hydrogen index of the study section was obtained based on the dynamic skeleton neutron value and the rock physical volume model.

[0058] The neutron difference is obtained by comparing the hydrogen content index of saturated water with the actual neutron logging value.

[0059] By combining test gas and production data with neutron difference values, the relationship between acoustic transit time and neutron difference values ​​and matrix porosity and neutron difference values ​​is analyzed to obtain a relationship chart for quantitative identification of gas-water layers.

[0060] Specifically:

[0061] Step 1: Calculate the reservoir matrix porosity within the study area;

[0062] Step 2: Combine electrical imaging with bilateral lateral data to calculate rock fracture porosity, and sum it with the matrix porosity calculated in Step 1 to obtain the total porosity of the rock.

[0063] Step 3: Assuming the bedrock reservoir pores are saturated with water, select the dynamic framework neutron value of the tight section with the lowest porosity and high resistivity (the water-bearing section with extremely low resistivity) as the fixed framework value. According to the rock physics volume model, the neutron value of the dynamic skeleton of the target layer is calculated based on the total porosity obtained in step 2.

[0064] Step 4: Based on the dynamic framework neutron values ​​obtained in Step 3, calculate the water-saturated hydrogen index of the studied section according to the rock physics volume model.

[0065] Step 5, calculate the hydrogen content index of saturated water obtained in Step 4. Compared with actual neutron logging values By comparing the values, the neutron difference was calculated. If the reservoir contains natural gas, the measured neutron logging values It will be less than the hydrogen index of saturated water.

[0066] Step 6: Combining the test gas and test production data, and using the neutron difference value calculated in Step 5, analyze the relationship between the changes in acoustic transit time and neutron difference value and matrix porosity and neutron difference value to obtain a relationship chart for quantitative identification of gas-water layers.

[0067] Preferably, in step 1, the reservoir matrix porosity within the study area is calculated using the following method:

[0068] S101, determine the mineral percentage of each mineral in the reservoir rock;

[0069] S102, multiply the mineral percentage content of each mineral by the corresponding theoretical acoustic value of the mineral;

[0070] S103, sum the products of each mineral obtained in S102 to obtain the time difference of sound waves in the mineral skeleton of the rock matrix.

[0071] S104. The time difference of acoustic waves of the rock matrix mineral skeleton obtained in S103 is substituted into the rock physical volume model to calculate the porosity of the rock matrix.

[0072] Matrix porosity Φ 基质 The calculation is shown in formula (1):

[0073]

[0074] Where, Φ 基质 Δt represents matrix porosity, expressed as a percentage (%). 测量 Δt represents the sonic transit time value in well logging, in µs / ft. 流体 Δt represents the fluid acoustic time difference, measured in µs / ft. 混ma The time difference of acoustic waves in the rock matrix mineral framework is expressed in µs / ft.

[0075] Preferably, combining the matrix porosity obtained in step 1, step 2 calculates the rock fracture porosity to obtain the total porosity of the rock. The specific method is as follows:

[0076] Rock fracture porosity was calculated by coring section electrical imaging logging fracture picking method based on fracture density description of core samples.

[0077] Based on the calibrated fracture porosity, a relationship is established with the deep and shallow lateral aspects to form a bedrock reservoir fracture porosity model.

[0078] The calculated fracture porosity is summed with the matrix porosity obtained in step 1 to obtain the total porosity of the rock.

[0079] Preferably, based on a rock physical volume model, step 3 calculates the neutron values ​​of the dynamic skeleton of the target layer. The specific method is as follows:

[0080] The dynamic skeleton neutron value of the compact layer segment is selected as the fixed skeleton value.

[0081] Based on the rock physical volume model Set fixed skeleton value The total porosity of the rock obtained from step 2. Substitute these values ​​into the calculation of the sub-values ​​in the dynamic skeleton of the target layer. In the formula The porosity of the subsurface water;

[0082] Preferably, the total porosity of the rock obtained in step 3 is combined with the calculation of the hydrogen content index of the water saturation zone in step 4. The specific method is as follows:

[0083]

[0084] In the formula, The total porosity of the rock. The porosity of formation water. For the neutron value of the dynamic rock skeleton;

[0085] Preferably, based on the neutron difference value calculated in step 5, the relationship between the neutron difference value and the acoustic transit time and the neutron difference value and the matrix porosity of different reservoirs is analyzed, and the fluid properties of the reservoir are determined according to the different distribution positions of the data points on the relationship chart.

[0086] This invention establishes a template for the relationship between sonic transit time and neutron difference, and between matrix porosity and neutron difference, by studying the difference between the hydrogen content index of water-saturated reservoirs and the actual neutron logging values. Combined with gas testing and production data, it can accurately identify reservoir fluids, solving problems such as complex bedrock reservoir lithology, large variations in physical properties, complex pore structure, weak resistivity response to fluid properties, and poor reliability of conventional interpretation methods for fluid identification. After extensive well validation, this invention can effectively identify reservoir fluid properties, meeting the evaluation requirements for oilfield production enhancement and storage improvement. The technical solution is as follows:

[0087] This invention provides a fluid identification method based on the hydrogen content index comparison method for saturated water, comprising the following steps:

[0088] Step (1): Based on core porosity analysis data, elemental logging and conventional logging data are combined to calculate the porosity of the rock matrix. The percentage content of each mineral in the reservoir lithology is determined through lithological scanning logging. Then, the percentage content of each mineral is multiplied by its corresponding theoretical sonic transit time value. Finally, the products of all minerals in the reservoir lithology are summed to obtain the variable sonic transit time skeleton value, as shown in the following formula:

[0089] Δt 混ma =Δt 石英 ×v 石英 +Δt 长石 ×v 长石 +Δt 灰 ×v 灰 +Δt 云母 ×v 云母 +Δt 膏 ×v 膏 +Δt 黄铁矿× v 黄铁矿

[0090] The theoretical acoustic transit time values ​​for different minerals are shown in the table below:

[0091]

[0092]

[0093] Step (2): Obtain the variable acoustic time difference skeleton value of the rock matrix minerals through step (1), and calculate the matrix porosity by combining it with the rock physical volume model.

[0094] The matrix porosity is calculated using the following formula:

[0095]

[0096] Where, Φ 基质 Δt represents matrix porosity, in percentages. 测量 Δt represents the sonic transit time value in microseconds (µs / ft). 流体 The fluid acoustic time difference is expressed in µs / ft.

[0097] Based on the obtained matrix porosity, electrical imaging logging combined with dual lateral logging is used to obtain fracture porosity. 裂缝 .

[0098] Step (3): Assuming the bedrock reservoir pores are saturated with water, the dynamic skeleton neutron value of the tight section with the lowest porosity and high resistivity (the water-bearing section with extremely low resistivity) is selected as the fixed skeleton value. According to the rock physical volume model, the dynamic skeleton neutron value of the target layer is calculated.

[0099]

[0100] in, For sub-values ​​in the dynamic skeleton, %. The theoretical hydrogen content index of water, %.

[0101] Step (4): Assuming the reservoir pores contain only water, the hydrogen content index of the reservoir is calculated using a rock physical volumetric model, and defined as the hydrogen content index for water saturation.

[0102]

[0103] Where, Φ 裂缝 The value represents the crack porosity, in %; The theoretical hydrogen content index of water, %.

[0104] Step (5) is to use the hydrogen content index of saturated water obtained in step (4). Compared with actual neutron logging values ​​of the reservoir By comparing the values, the neutron difference can be calculated.

[0105]

[0106] Step (6): Combine the gas test and production data to analyze the correspondence between neutron difference and acoustic time difference and neutron difference and matrix porosity, and obtain the interpretation criteria for quantitative identification of gas-water layers.

[0107]

[0108] Taking the bedrock formation of well XX in DP oilfield as an example

[0109] The logging data processing and loading for Well XX involved determining the percentage content of each mineral in the reservoir lithology through lithological scanning logging. Then, the percentage content of each mineral was multiplied by its corresponding theoretical sonic transit time (SLT). Finally, the products of all minerals in the reservoir lithology were summed to obtain the variable SLT skeleton value. Next, the matrix porosity was calculated using a rock physical volume model. Based on the obtained matrix porosity, fracture porosity was obtained by combining electrical imaging logging and dual-lateral logging. Assuming the bedrock reservoir pores were saturated with water, the dynamic skeleton neutron value of the tightest section (aquatic section with extremely low resistivity) with the lowest porosity was selected as the fixed skeleton value. The dynamic skeleton neutron value of the target layer was then calculated according to the rock physical volume model. Then, the hydrogen index of saturated water corresponding to the reservoir was calculated using a volumetric model. and compared with actual neutron logging values By comparing the results, the neutron difference was calculated. Combined with test gas production data, the correlation between the neutron difference and acoustic transit time, and between the neutron difference and matrix porosity, was analyzed to obtain the target layer fluid identification chart and standard for the study area. Continuous interpretation and evaluation were performed on other wells within the study area. Different reservoir characteristic points were selected, and the properties of the reservoir fluids were determined based on the specific locations of these characteristic points on the interpretation chart.

[0110] like Figure 2 The image shows a cross-plot of neutron difference values ​​and acoustic transit time for different reservoirs, established based on gas testing and production data. Figure 3 The diagram shows the cross-plot of neutron difference values ​​and matrix porosity for different reservoirs. Interpretation standards for the study area were established based on these plots: Gas reservoirs have a neutron difference greater than 2.0%, acoustic transit time greater than 176 μS / m, and matrix porosity greater than 3.3%; Gas-water reservoirs have a neutron difference greater than 0% and less than 2%, acoustic transit time greater than 176 μS / m, and matrix porosity greater than 3.3%; Water reservoirs have a neutron difference less than 0%, acoustic transit time greater than 176 μS / m, and matrix porosity greater than 3.3%; Dry reservoirs have a neutron difference less than 0%, acoustic transit time less than 176 μS / m, and matrix porosity less than 3.3%.

[0111] like Figure 4 The diagram shows a comprehensive interpretation, with well logging data including conventional combinations, formation elements, and electrical imaging data. From right to left, the first line shows the well logging interpretation layers; the second line shows the mineral content profile obtained from formation element logging; the third line shows the envelope area of ​​the measured compensated neutron values ​​and the neutron values ​​of water-saturated formations, filled with color to facilitate differentiation of the differences; the fourth line compares the overlap between the measured compensated neutron values ​​and the neutron skeleton values ​​in water-saturated formations, facilitating the selection of overlapping layers as fixed skeleton neutron values ​​in tight formations with low porosity and high resistivity (extremely low resistivity water-bearing formations); the fifth line shows the matrix porosity of the variable acoustic skeleton; and the sixth line shows the fracture porosity obtained from electrical imaging logging. The seventh channel is the dynamic image of electrical imaging; the eighth channel is the acoustic transit time, compensated density, and compensated neutron curve channel; the ninth channel is the deep and shallow lateral resistivity channel; and the tenth channel is the natural gamma, spontaneous potential, and wellbore curve channel. In the figure, the third channel represents a gas layer where the measured compensated neutron value is less than that of a water-saturated formation, and the larger the value, the better the gas content. The third channel represents a water layer or a dry layer where the measured compensated neutron value is close to or greater than that of a water-saturated formation. Among these, the dry layer is defined as one with an acoustic transit time below 176 μS / m and a matrix porosity below 3.3%.

[0112] This invention proposes a system for fluid identification based on the comparison of hydrogen content in water saturation index, such as... Figure 5 As shown, it includes:

[0113] A porosity acquisition module is used to acquire the reservoir matrix porosity in the study area; acquire rock fracture porosity based on matrix porosity, electrical imaging and two-sided lateral data; and acquire the total porosity of the rock based on rock fracture porosity and matrix porosity.

[0114] A dynamic skeleton neutron value acquisition module is used to acquire the dynamic skeleton neutron value of the target layer based on the rock physical volume model and the total porosity of the rock.

[0115] A water-saturated hydrogen content index acquisition module is used to acquire the water-saturated hydrogen content index of the study section based on the dynamic skeleton neutron value and the rock physical volume model.

[0116] The neutron difference acquisition module is used to obtain the neutron difference by comparing the hydrogen content index of saturated water with the actual neutron logging value.

[0117] The gas-water layer relationship map acquisition module is used to combine test gas and production data and neutron difference values ​​to analyze the relationship between acoustic transit time and neutron difference values ​​and matrix porosity and neutron difference values, and to acquire a relationship map for quantitative identification of gas-water layers.

[0118] An embodiment of the present invention provides a terminal device comprising: a processor, a memory, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the steps in the various method embodiments described above. Alternatively, when the processor executes the computer program, it implements the functions of each module / unit in the various device embodiments described above.

[0119] The computer program can be divided into one or more modules / units, which are stored in the memory and executed by the processor to complete the present invention.

[0120] The terminal device may be a desktop computer, laptop, handheld computer, or cloud server, etc. The terminal device may include, but is not limited to, a processor and a memory.

[0121] The processor may be a central processing unit (CPU), or other general-purpose processors, digital signal processors (DSPs), application-specific integrated circuits (ASICs), field-programmable gate arrays (FPGAs), or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, etc.

[0122] The memory can be used to store the computer program and / or module. The processor implements various functions of the terminal device by running or executing the computer program and / or module stored in the memory and calling the data stored in the memory.

[0123] If the modules / units integrated into the terminal device 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, all or part of the processes in the methods of the above embodiments can also be implemented by a computer program instructing related hardware. The computer program can be stored in a computer-readable storage medium, and when executed by a processor, it can implement the steps of the various method embodiments described above. The computer program includes computer program code, which can be in the form of source code, object code, executable files, or certain intermediate forms. The computer-readable medium can include: any entity or device capable of carrying the computer program code, recording media, USB flash drives, portable hard drives, magnetic disks, optical disks, computer memory, read-only memory (ROM), random access memory (RAM), electrical carrier signals, telecommunication signals, and software distribution media, etc. It should be noted that the content included in the computer-readable medium can be appropriately added or removed according to the requirements of legislation and patent practice in the jurisdiction. For example, in some jurisdictions, according to legislation and patent practice, computer-readable media do not include electrical carrier signals and telecommunication signals.

[0124] This invention calculates the neutron value of the dynamic rock skeleton based on the rock matrix porosity and fracture porosity using a rock physical volume model. Then, assuming the bedrock reservoir is saturated with water, the hydrogen content index of the saturated water is calculated using the volume model, and compared with the actual neutron logging value to calculate the neutron difference. If the reservoir contains natural gas, the measured neutron logging value will be lower than the hydrogen content index of the saturated water, and this characteristic is more pronounced the better the reservoir properties and the higher the gas saturation. Furthermore, by combining gas testing and production data, the relationship between acoustic transit time and neutron difference, and between matrix porosity and neutron difference, is analyzed to obtain a relationship chart for quantitatively identifying gas-water layers, which can effectively identify reservoir fluid properties. Compared with traditional methods such as the three-porosity intersection method, the three-porosity difference ratio method, and the P-wave velocity ratio method, this method eliminates the influence of anisotropic variations in bedrock lithology by segmenting single wells and taking different neutron framework values. Based on neutron logging, this non-electric logging method eliminates the influence of fracture occurrence on logging response characteristics. The rock physics model calculation includes matrix porosity and fracture porosity, ensuring that the fluid property identification covers the influence of lithological and physical property variations. The generated charts show outstanding gas layer identification performance, meeting the evaluation requirements for oilfield production enhancement and storage improvement.

[0125] This invention proposes a fluid identification method based on the comparison of water-saturated hydrogen content index. Based on a rock physical volumetric model, it combines lithological scanning logging, micro-resistivity scanning imaging logging, sonic transit time, and compensated neutron logging data. Taking into account the significant differences in hydrogen content indices between water-saturated reservoirs and natural gas, a comparison method between the reservoir's water-saturated hydrogen content index and reservoir neutron logging values ​​is established and compared with traditional methods. This method, by processing each well individually and taking different neutron framework values, eliminates the influence of anisotropic variations in bedrock lithology. The non-electrical logging method based on neutron logging eliminates the influence of fracture occurrence on logging response characteristics. The rock physical model calculation includes matrix porosity and fracture porosity, ensuring that fluid property identification covers the influence of lithological and physical property variations. This provides a reliable guarantee for the development of natural gas in oilfields. The method selects logging curves sensitive to the fluid properties of the target area, highlighting different fluid characteristics on the chart, thus overcoming the shortcomings of existing methods for identifying fluid properties in bedrock reservoirs.

[0126] The above are merely preferred embodiments of the present invention and are not intended to limit the present invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A fluid identification method based on a comparison of water-saturated hydrogen content index, characterized in that, Includes the following steps: Obtain the reservoir matrix porosity within the study area; obtain the rock fracture porosity based on matrix porosity, electrical imaging, and bilateral lateral data; obtain the total porosity of the rock based on the rock fracture porosity and matrix porosity. The dynamic skeleton neutron value of the target layer is obtained based on the rock physical volume model and the total porosity of the rock. The water-saturated hydrogen index of the study section was obtained based on the dynamic skeleton neutron value and the rock physical volume model. The neutron difference is obtained by comparing the hydrogen content index of saturated water with the actual neutron logging value. By combining test gas and production data with neutron difference values, the relationship between acoustic transit time and neutron difference values ​​and matrix porosity and neutron difference values ​​is analyzed to obtain a relationship chart for quantitative identification of gas-water layers. The methods for obtaining rock fracture porosity and total rock porosity are as follows: rock fracture porosity is calculated by using the fracture density calibration core section electrical imaging logging fracture picking method; the rock fracture porosity is summed with the matrix porosity to obtain the total rock porosity. Target layer dynamic skeleton neutron value The calculation is as follows: ;in, Subvalues ​​in the dynamic skeleton, in units of % ; The theoretical hydrogen content index of water, in units of... %， The total porosity of the rock.

2. The fluid identification method based on the hydrogen content index comparison method for saturated water according to claim 1, characterized in that, The calculation method for reservoir matrix porosity within the research area includes the following steps: Determine the percentage content of each mineral in the reservoir rock; The mineral percentage of each mineral is multiplied by the corresponding theoretical acoustic value and summed to obtain the acoustic time difference value of the mineral matrix skeleton of the rock. The acoustic transit time of the rock matrix mineral framework is input into the rock physical volume model to obtain the matrix porosity; matrix porosity The calculation is shown in formula (1): （1） in, The matrix porosity is expressed in units of... % ; This represents the sonic transit time value for well logging, in units of... us / ft ; This represents the fluid acoustic time difference, in units of... us / ft ; The acoustic transit time value of the rock matrix mineral framework is expressed in units of 1000 m / s. us / ft .

3. The fluid identification method based on the hydrogen content index comparison method for saturated water according to claim 1, characterized in that, The dynamic skeleton neutron value of the compact layer segment is selected as the fixed skeleton value. .

4. The fluid identification method based on the hydrogen content index comparison method for saturated water according to claim 1, characterized in that, The study section has a water saturation and hydrogen content index. The calculation is shown in formula (3): （3） in, The total porosity of the rock. The porosity of formation water. The neutron value represents the dynamic skeleton of the rock.

5. The fluid identification method based on the hydrogen content index comparison method for saturated water according to claim 4, characterized in that, Neutron difference The calculation is shown in formula (4): （4） in, This represents the actual logging value for neutrons.

6. A system employing the fluid identification method based on the hydrogen content index comparison method for saturated water as described in any one of claims 1 to 5, characterized in that, include: A porosity acquisition module is used to acquire the reservoir matrix porosity in the study area; acquire rock fracture porosity based on matrix porosity, electrical imaging and two-sided lateral data; and acquire the total porosity of the rock based on rock fracture porosity and matrix porosity. A dynamic skeleton neutron value acquisition module is used to acquire the dynamic skeleton neutron value of the target layer based on the rock physical volume model and the total porosity of the rock. A water-saturated hydrogen content index acquisition module is used to acquire the water-saturated hydrogen content index of the study section based on the dynamic skeleton neutron value and the rock physical volume model. The neutron difference acquisition module is used to obtain the neutron difference by comparing the hydrogen content index of saturated water with the actual neutron logging value. The gas-water layer relationship map acquisition module is used to combine test gas and production data and neutron difference values ​​to analyze the relationship between acoustic transit time and neutron difference values ​​and matrix porosity and neutron difference values, and to acquire a relationship map for quantitative identification of gas-water layers.

7. A computer device comprising a memory and a processor, wherein the memory stores a computer program, characterized in that, When the processor executes a computer program, it implements the steps of the fluid identification method of the water saturation hydrogen index comparison method as described in any one of claims 1 to 5.

8. A computer-readable storage medium storing a computer program, characterized in that, When the computer program is executed by the processor, it implements the steps of the fluid identification method of the water saturation hydrogen index comparison method as described in any one of claims 1 to 5.

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