Reservoir fluid property identification method, system, device and storage medium

Abstract

The present invention discloses a reservoir fluid property identification method, system, device, and storage medium. The method includes: obtaining inverted apparent resistivity data and well logging data for a study area; performing a first-order derivative on the inverted apparent resistivity data to obtain first-order derivative data; assigning corresponding weight coefficients to the average thin layer thicknesses of different reservoirs based on the well logging data, and establishing a resistivity correspondence between the apparent resistivity and the well logging resistivity; determining standard data for the numerical difference in well logging resistivity between different reservoir fluids in the study area based on the well logging data; determining standard data for the numerical difference in apparent resistivity based on the resistivity correspondence and the standard data for the numerical difference in well logging resistivity; and determining a boundary line between different reservoir fluids based on the sawtooth points of the standard data for the numerical difference in apparent resistivity and the first-order derivative data. The reservoir fluid property identification method, system, device, and storage medium of the embodiments of the present invention can improve the accuracy of reservoir fluid property identification.

Description

Technical Field

[0001] The present invention relates to the technical field related to oil and gas exploration and development, and in particular to a reservoir fluid property identification method, system, device and storage medium. Background Art

[0002] In the field of oil and gas exploration and development, the geological conditions of unconventional oil and gas resources are very complex. They are usually characterized by dense reservoirs, thin sand bodies, strong heterogeneity, and close and difficult-to-distinguish gas-water relationships. In addition, the internal structure of the reservoir will become increasingly difficult to predict as the development of oil and gas reservoirs enters the middle and late stages.

[0003] In the existing technology, there is a method of locating favorable areas of the reservoir by establishing a standard interpretation profile by determining the correlation formula between wide-area apparent resistivity, logging resistivity, acoustic wave velocity and post-stack seismic data under different lithologic conditions. However, this technology only simply concatenates the seismic, logging and electromagnetic data of the work area with different lithologies (carbonaceous shale, siltstone) through linear analysis, and finally forms a unified empirical formula that includes the three technical parameters of seismic, logging and electromagnetic. Such formulas are often greatly affected by the actual geological conditions of the work area. When the geological conditions of the work area are complex and the gas-water relationship is close and difficult to distinguish, the three types of seismic, logging and electromagnetic data may not be able to be concatenated and formulated through simple linear analysis. In addition, the scope of application of this technology is limited by lithology and is only applicable to carbonaceous shale and siltstone, resulting in limited application scenarios. Summary of the Invention

[0004] The present invention aims to solve at least one of the technical problems existing in the prior art. To this end, the present invention proposes a reservoir fluid property identification method that can improve the accuracy of reservoir fluid property identification.

[0005] The present invention also provides a reservoir fluid property identification system, a control device for executing the reservoir fluid property identification method, and a computer-readable storage medium.

[0006] According to a first aspect of the present invention, a reservoir fluid property identification method includes:

[0007] Obtain inverted apparent resistivity data and well logging data in the study area;

[0008] performing a first-order derivative on the inverted apparent resistivity data to obtain first-order derivative data;

[0009] Based on the well logging data, assigning corresponding weight coefficients to the average thin layer thicknesses of different reservoirs, and establishing a resistivity correspondence between apparent resistivity and logging resistivity;

[0010] Determining standard data of the difference in well logging resistivity values ​​between different reservoir fluids in the study area based on the well logging data;

[0011] Determining apparent resistivity numerical difference standard data according to the resistivity corresponding relationship and the logging resistivity numerical difference standard data;

[0012] The boundary lines of fluids in different reservoirs are determined according to the apparent resistivity numerical difference standard data and the sawtooth points of the first-order derivative data.

[0013] The reservoir fluid property identification method according to the embodiment of the present invention has at least the following beneficial effects:

[0014] Compared to existing empirical formulas that use simple linear analysis, the present invention takes into account the complex realities of the study area. Based on well logging data, weight coefficients are assigned to the average thin layer thicknesses of different reservoirs, and a resistivity correspondence between apparent resistivity and logging resistivity is established. This makes the formula parameters dynamic and has greater applicability. Furthermore, only the relationship between apparent resistivity and logging resistivity is established, allowing the demarcation of different reservoir fluid boundaries through inverted apparent resistivity, which is more sensitive to reservoir structure and fluid identification. This not only improves the accuracy of reservoir fluid property identification but also reduces complexity. Because logging resistivity is the actual measured value, while apparent resistivity is the inverted value, standard data for the numerical differences in logging resistivity between different reservoir fluids in the study area is determined using well logging data, and then the standard data for the numerical differences in apparent resistivity between different reservoir fluids in the study area is determined using the resistivity correspondence. This results in a more realistic apparent resistivity, and the demarcation of different reservoir fluid boundaries using the sawtooth points of the apparent resistivity numerical difference standard data and the first-order derivative data is more accurate.

[0015] According to some embodiments of the present invention, the constraint formula of the resistivity correspondence is:

[0016] ;

[0017] +b;

[0018] in, is the fluid weighting parameter, is the average thin layer thickness of the water layer, is the average thin layer thickness of the gas layer, is the average lamella thickness of the dry layer, is the average thin layer thickness of the gas-water layer, is the weight coefficient of the water layer, is the weight coefficient of the gas layer, is the weight coefficient of the dry layer, is the weight coefficient of gas and water in the same layer, is the apparent resistivity, is the logging resistivity, and b are calculation parameters.

[0019] According to some embodiments of the present invention, determining standard data of the difference in logging resistivity values ​​between different reservoir fluids in the study area based on the logging data includes:

[0020] Screening out calibration layers of different reservoir fluids in the study area based on the well logging data;

[0021] Determining calibrated logging resistivities corresponding to calibration layers of different reservoir fluids based on the logging data;

[0022] The standard data of the difference in the well logging resistivity values ​​between the calibration layers of different reservoir fluids are calculated based on the respective calibration well logging resistivities.

[0023] According to some embodiments of the present invention, the calibration layers of different reservoir fluids are respectively a water layer calibration layer, a gas layer calibration layer and a dry layer calibration layer, the calibration logging resistivities corresponding to the different calibration layers are respectively a water layer calibration logging resistivity, a gas layer calibration logging resistivity and a dry layer calibration logging resistivity, and the standard data of the logging resistivity numerical differences between the calibration layers of different reservoir fluids are respectively water-gas difference data and gas-dry difference data;

[0024] The method of calculating the standard data of the difference in well logging resistivity values ​​between calibration layers of different reservoir fluids based on the respective calibrated well logging resistivities includes:

[0025] Calculating the water-gas difference data based on the water layer calibration logging resistivity and the gas layer calibration logging resistivity;

[0026] The gas-dry layer difference data is obtained by calculation based on the gas layer calibration logging resistivity and the dry layer calibration logging resistivity.

[0027] According to some embodiments of the present invention, determining the boundary line between different reservoir fluids based on the apparent resistivity numerical difference standard data and the sawtooth point of the first-order derivative data includes:

[0028] Determining the area of ​​the sawtooth point in the first-order derivative data;

[0029] The boundary lines of fluids in different reservoirs are determined according to the areas of the sawtooth points in the first-order derivative data and the apparent resistivity value difference standard data.

[0030] According to some embodiments of the present invention, the standard data for the difference in logging resistivity values ​​between different reservoir fluids are water-gas difference data and gas-dry difference data, and the boundaries between different reservoir fluids are water-layer-gas-layer boundary lines and gas-layer-dry-layer boundary lines;

[0031] Determining the boundary lines of different reservoir fluids based on the areas of the sawtooth points in the first-order derivative data and the apparent resistivity value difference standard data includes:

[0032] Determining that the area of ​​the sawtooth points in the first-order derivative data conforms to the first sawtooth band of the water vapor difference data;

[0033] Determining that the area of ​​the sawtooth points in the first-order derivative data conforms to a second sawtooth band of the air-dry difference data;

[0034] Determining the water layer and air layer boundary line according to the first sawtooth band;

[0035] The air layer dry layer boundary line is determined according to the second sawtooth band.

[0036] According to some embodiments of the present invention, determining the water layer and air layer boundary line according to the first sawtooth band includes:

[0037] Connecting the vertices of the first sawtooth belt in the horizontal direction to obtain the water layer and air layer boundary line;

[0038] The step of determining the dry layer boundary line of the air layer according to the second sawtooth band includes:

[0039] The vertices of the second serrated belt in the horizontal direction are connected to obtain the boundary line of the air layer and the dry layer.

[0040] According to a reservoir fluid property identification system of an embodiment of the second aspect of the present invention, the system includes:

[0041] Data acquisition module, used to obtain inversion apparent resistivity data and logging data of the study area;

[0042] A first-order derivative module, used for performing a first-order derivative on the inverted apparent resistivity data to obtain first-order derivative data;

[0043] a corresponding relationship determination module, configured to assign corresponding weight coefficients to the average thin layer thicknesses of different reservoirs based on the well logging data, and establish a resistivity corresponding relationship between apparent resistivity and logging resistivity;

[0044] a well logging resistivity difference data determination module, configured to determine standard data of well logging resistivity value differences between different reservoir fluids in the study area based on the well logging data;

[0045] an apparent resistivity difference data determining module, configured to determine apparent resistivity numerical difference standard data according to the resistivity correspondence relationship and the logging resistivity numerical difference standard data;

[0046] The reservoir fluid boundary line determination module is used to determine the boundary lines of different reservoir fluids according to the apparent resistivity value difference standard data and the sawtooth points of the first-order derivative data.

[0047] The reservoir fluid property identification system according to the embodiment of the present invention has at least the following beneficial effects:

[0048] Compared to existing empirical formulas that use simple linear analysis, the present invention takes into account the complex realities of the study area. Based on well logging data, weight coefficients are assigned to the average thin layer thicknesses of different reservoirs, and a resistivity correspondence between apparent resistivity and logging resistivity is established. This makes the formula parameters dynamic and has greater applicability. Furthermore, only the relationship between apparent resistivity and logging resistivity is established, allowing the demarcation of different reservoir fluid boundaries through inverted apparent resistivity, which is more sensitive to reservoir structure and fluid identification. This not only improves the accuracy of reservoir fluid property identification but also reduces complexity. Because logging resistivity is the actual measured value, while apparent resistivity is the inverted value, standard data for the numerical differences in logging resistivity between different reservoir fluids in the study area is determined using well logging data, and then the standard data for the numerical differences in apparent resistivity between different reservoir fluids in the study area is determined using the resistivity correspondence. This results in a more realistic apparent resistivity, and the demarcation of different reservoir fluid boundaries using the sawtooth points of the apparent resistivity numerical difference standard data and the first-order derivative data is more accurate.

[0049] A control device according to a third embodiment of the present invention includes a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the reservoir fluid property identification method described in the first embodiment. Because the control device utilizes all of the technical solutions of the reservoir fluid property identification method described in the above embodiment, it at least has all of the beneficial effects provided by the technical solutions of the above embodiment.

[0050] A computer-readable storage medium according to a fourth embodiment of the present invention stores computer-executable instructions for executing the reservoir fluid property identification method described in the first embodiment. Because the computer-readable storage medium employs all of the technical solutions of the reservoir fluid property identification method described in the aforementioned embodiment, it at least has all of the beneficial effects provided by the technical solutions of the aforementioned embodiment.

[0051] Other features and advantages of the present invention will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by practice of the present invention. BRIEF DESCRIPTION OF THE DRAWINGS

[0052] The above and / or additional aspects and advantages of the present invention will become apparent and readily understood from the following description of the embodiments with reference to the accompanying drawings, in which:

[0053] Figure 1 is a flow chart of a reservoir fluid property identification method according to an embodiment of the present invention;

[0054] Figure 2 This is an electromagnetic pseudo-phase waveform diagram of the first-order derivative data of an embodiment of the present invention;

[0055] Figure 3 Schematic diagram of the division of fluid boundaries between different reservoirs according to an embodiment of the present invention;

[0056] Figure 4 is a schematic diagram of the boundary lines of different reservoir fluids according to an embodiment of the present invention;

[0057] Figure 5 Schematic diagram of a three-dimensional apparent resistivity model of a study area after reservoir fluid division according to an embodiment of the present invention. DETAILED DESCRIPTION

[0058] The following describes embodiments of the present invention in detail. Examples of the embodiments are shown in the accompanying drawings, wherein the same or similar reference numerals throughout represent the same or similar elements or elements having the same or similar functions. The embodiments described below with reference to the accompanying drawings are exemplary and are intended only to explain the present invention and are not to be construed as limiting the present invention.

[0059] In the description of the present invention, if there is a description of first, second, etc., it is only for the purpose of distinguishing technical features, and cannot be understood as indicating or implying relative importance or implicitly indicating the number of the indicated technical features or implicitly indicating the order of the indicated technical features.

[0060] In the description of the present invention, it should be understood that descriptions involving orientation, such as the orientation or positional relationship indicated by up, down, etc., are based on the orientation or positional relationship shown in the accompanying drawings, and are only for the convenience of describing the present invention and simplifying the description, rather than indicating or implying that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and therefore cannot be understood as a limitation on the present invention.

[0061] In the description of the present invention, it should be noted that, unless otherwise clearly defined, terms such as setting, installing, and connecting should be understood in a broad sense, and technicians in the relevant technical field can reasonably determine the specific meanings of the above terms in the present invention based on the specific content of the technical solution.

[0062] The following will be combined Figures 1 to 5A clear and complete description of the reservoir fluid property identification method according to an embodiment of the present invention is given. Obviously, the embodiment described below is only a part of the embodiments of the present invention, not all of the embodiments.

[0063] refer to Figure 1 , Figure 1 4 is a flow chart of a reservoir fluid property identification method according to an embodiment of the present invention.

[0064] According to a first aspect of the present invention, the reservoir fluid property identification method includes:

[0065] Obtain inverted apparent resistivity data and well logging data in the study area;

[0066] Perform first-order derivative on the inverted apparent resistivity data to obtain first-order derivative data;

[0067] Based on the well logging data, the average thin layer thickness of different reservoirs is assigned corresponding weight coefficients, and the resistivity correspondence between apparent resistivity and logging resistivity is established;

[0068] Determine the standard data of the difference in logging resistivity values ​​between different reservoir fluids in the study area based on the logging data;

[0069] Determine the standard data of apparent resistivity numerical difference according to the resistivity correspondence and the standard data of well logging resistivity numerical difference;

[0070] The boundary lines of different reservoir fluids are determined based on the sawtooth points of the standard data of apparent resistivity value difference and the first-order derivative data.

[0071] The inverted apparent resistivity data can be presented in the form of an inverted apparent resistivity distribution profile. In some embodiments, the inverted apparent resistivity data is obtained by the following steps:

[0072] Obtain electromagnetic field information, seismic data, well logging data, geological data, drilling data, and oil testing data in the study area;

[0073] An initial geoelectric model is established based on electromagnetic field information, seismic data, and geological data, and the geoelectric model is inverted by electromagnetic method to obtain the inverted apparent resistivity data of the study area.

[0074] It should be noted that the principle of obtaining inverted apparent resistivity data is an existing technology known to those skilled in the art and will not be described in detail here.

[0075] Performing a first-order derivative on the inverted apparent resistivity data to obtain first-order derivative data includes: obtaining the first-order derivative of the discrete function along the vertical depth direction of the inverted apparent resistivity data to obtain the first-order derivative data. The first-order derivative data can be plotted into an electromagnetic pseudo-phase waveform diagram using Matlab software, such as Figure 2 As shown, Figure 2is an electromagnetic pseudo-phase waveform diagram of the first-order derivative data of an embodiment of the present invention, Figure 2 The vertical and horizontal axes are consistent with the inverted apparent resistivity distribution profile. Figure 2 The area of ​​the sawtooth points represents the magnitude of the first-order derivative data, and the orientation of the sawtooth points' vertices in the horizontal direction is used to distinguish the amplitude of the first-order derivative data: positive toward the right and negative toward the left. The amplitude of the resistivity change represents the magnitude of the resistivity change of the next formation compared to the previous formation. A positive amplitude change indicates an increase in resistivity from a high altitude to a low altitude, representing a positive phase, indicating a transition from a relatively low-resistance formation to a relatively high-resistance formation. A negative amplitude change indicates a decrease in resistivity from a low altitude to a high altitude, representing a negative phase, indicating a transition from a relatively high-low-resistance formation to a relatively low-resistance formation. The electromagnetic pseudo-phase waveform can be used to describe the change in apparent resistivity within a formation.

[0076] It should be noted that Matlab software belongs to the existing technology known to those skilled in the art, and the specific working process and principle will not be described in detail here.

[0077] In some embodiments of the present invention, the inverted apparent resistivity data and well logging data must be data from the same region. That is, the inverted apparent resistivity data must be obtained from production wells within the study area that have well logging data. A resistivity correspondence between the apparent resistivity and the well logging resistivity is established using the well logging data. Apparent resistivity and well logging resistivity are measured using different principles, and while numerical differences are inevitable, the two resistivities respond identically to fluids. When the two resistivities are plotted in the same coordinate system with depth and resistivity as the horizontal and vertical axes, the two curves should exhibit similar trends but differ in numerical value, which can be simply understood as being approximately "parallel." Since well logging resistivity is the actual measured value, while apparent resistivity is the inverted value, determining standard data for the numerical differences in well logging resistivity between different reservoir fluids within the study area using well logging data, and then determining standard data for the numerical differences in apparent resistivity between different reservoir fluids within the study area using the resistivity correspondence, can yield an apparent resistivity that is closer to reality.

[0078] The constraint formula for the resistivity correspondence is:

[0079] ;

[0080] +b ;

[0081] in, is the fluid weighting parameter, is the average thin layer thickness of the water layer, is the average thin layer thickness of the gas layer, is the average lamella thickness of the dry layer, is the average thin layer thickness of the gas-water layer, is the weight coefficient of the water layer, is the weight coefficient of the gas layer, is the weight coefficient of the dry layer, is the weight coefficient of gas and water in the same layer, is the apparent resistivity, is the logging resistivity, and b All are calculation parameters.

[0082] The average thin layer thickness of the water layer, the average thin layer thickness of the gas layer, the average thin layer thickness of the dry layer, and the average thin layer thickness of the gas-water layer were all obtained from well logging data. The weight coefficients of the water layer, the gas layer, the dry layer, and the gas-water layer were obtained by conducting indoor physical parameter testing on gas-saturated and water-saturated cores from multiple production wells in the study area. and b All are adjustable calculation parameters.

[0083] In some embodiments of the present invention, determining standard data of the difference in logging resistivity values ​​between different reservoir fluids in a study area based on logging data includes:

[0084] Based on the well logging data, calibration layers of different reservoir fluids in the study area were screened out;

[0085] Determine the calibration logging resistivity corresponding to the calibration layer of different reservoir fluids based on the logging data;

[0086] The standard data of the difference in logging resistivity values ​​between the calibration layers of different reservoir fluids are calculated based on the various calibration logging resistivities.

[0087] Well logging data includes logging resistivity, drilling data, and oil testing data. Based on these data, gas and water layers with relatively thick and stable fluid distribution are selected as calibration layers for the gas and water layers, respectively. It should be noted that an effective thickness of 5 meters or greater is sufficient. "Relatively stable" means that the corresponding fluid content within the effective thickness exceeds 75%. Dry layers are also a type of reservoir, but due to their extremely poor rock properties and low porosity and permeability, they are essentially incapable of producing oil or gas. Therefore, in general, the oil and gas production characteristics of dry layers and mudstone layers are the same. For calibration, mudstone layers with stable distribution within the same formation group or adjacent formation groups as measured by logging resistivity can be used.

[0088] In some embodiments, each reservoir fluid may have more than one calibration layer. In such cases, the corresponding calibration logging resistivity can be obtained by weighting the logging resistivity of each calibration layer according to the layer thickness. It should be noted that the specific weighting method can be selected based on actual needs and is not limited here.

[0089] In the embodiment of the present invention, the standard data of the difference in well logging resistivity values ​​between different reservoir fluids calculated based on the well logging resistivity of the calibration layer is more accurate and the reliability of the parameters is higher.

[0090] In some embodiments of the present invention, the calibration layers for different reservoir fluids are respectively a water layer calibration layer, a gas layer calibration layer, and a dry layer calibration layer; the calibration logging resistivities corresponding to the different calibration layers are respectively a water layer calibration logging resistivity, a gas layer calibration logging resistivity, and a dry layer calibration logging resistivity; and the standard data for the difference in logging resistivity values ​​between the calibration layers for different reservoir fluids are respectively water-gas difference data and gas-dry difference data;

[0091] The standard data of the difference in logging resistivity values ​​between calibration layers of different reservoir fluids is calculated based on each calibration logging resistivity, including:

[0092] The water-gas difference data is calculated based on the water layer calibration logging resistivity and the gas layer calibration logging resistivity;

[0093] The gas-dry difference data is calculated based on the gas layer calibration logging resistivity and the dry layer calibration logging resistivity.

[0094] The difference between the water layer calibration logging resistivity and the gas layer calibration logging resistivity is the water-gas difference data; the difference between the gas layer calibration logging resistivity and the dry layer calibration logging resistivity is the gas-dry difference data.

[0095] It is understandable that the internal resistivity difference of reservoirs with the same fluid in the formation is very small, while the resistivity difference of reservoirs with different fluids is large at the junction. For example, the difference between the boundary of gas layer and water layer (i.e., water-gas difference data) is about 160 -200 This value should be significantly different from that inside the reservoir, because there is no significant difference in the stable resistivity of the fluid inside the reservoir, while the resistivity at the boundary between different fluid reservoirs is significantly different. As for why this value is a range, it is because the actual situation of the strata varies intricately, and it is impossible to guarantee that the difference between the gas layer and the water layer within a few thousand meters underground in this area is a fixed value. It is more reasonable and reliable to use the average difference between the gas layer and the water layer in a certain group / section of strata within the corresponding altitude range obtained through well logging data as the corresponding division standard. This data is related to the specific geological conditions of the study area. When the geological conditions are complex and the reservoir heterogeneity is strong, the data range may be larger, but there is no doubt that this data is significantly different from the interior of the reservoir.

[0096] In some embodiments of the present invention, reference Figures 2 to 4 , Figure 2 is an electromagnetic pseudo-phase waveform diagram of the first-order derivative data of an embodiment of the present invention, Figure 3Schematic diagram of the division of different reservoir fluid boundaries according to an embodiment of the present invention. Figure 4 Schematic diagram of the boundary lines of different reservoir fluids according to an embodiment of the present invention, wherein the boundary lines of different reservoir fluids are determined based on the sawtooth points of the apparent resistivity value difference standard data and the first-order derivative data, including:

[0097] Determine the area of ​​the sawtooth point in the first-order derivative data;

[0098] The fluid boundary lines of different reservoirs are determined based on the area of ​​the sawtooth points in the first-order derivative data and the standard data of apparent resistivity value differences.

[0099] It can be understood that the area of ​​a sawtooth point represents the apparent resistivity. There is a certain ratio / coefficient between the area and the apparent resistivity, which is a known parameter. Apparent resistivity can be filtered based on the area. If the area of ​​a sawtooth point meets the standard data for apparent resistivity difference, it indicates that the sawtooth point is the boundary between different reservoir fluids. The boundary between different reservoir fluids can be determined by the area of ​​the sawtooth point and the standard data for apparent resistivity difference.

[0100] In some embodiments of the present invention, the standard data for the difference in logging resistivity values ​​between different reservoir fluids are water-gas difference data and gas-dry difference data, and the boundaries between different reservoir fluids are water-layer gas-layer boundary and gas-dry layer boundary;

[0101] The boundary lines of different reservoir fluids are determined based on the area of ​​the sawtooth points in the first-order derivative data and the standard data of the apparent resistivity value difference, including:

[0102] Determine that the area of ​​the sawtooth point in the first-order derivative data conforms to the first sawtooth band of the water-vapor difference data;

[0103] Determine that the area of ​​the sawtooth points in the first-order derivative data conforms to the second sawtooth band of the air-dry difference data;

[0104] Determine the boundary between the water layer and the air layer based on the first serrated band;

[0105] The boundary line of the air layer and dry layer is determined according to the second serrated belt.

[0106] Taking the water layer, gas layer and dry layer as examples, the electromagnetic pseudo-phase waveform under ideal conditions is as follows: Figure 3 As shown in Figure 2, the reservoir fluid distribution is stable within the water layer, gas layer, and dry layer, so there is almost no resistivity difference inside. Figure 3There are almost no sawtooth points (i.e., resistivity differences) in the reservoir, but there are obvious resistivity differences at the junction of the three layers. The size of the difference can be obtained through the area of ​​the sawtooth points. The size of the difference can be used to determine which of the three boundary lines is gas / water, gas / dry, or water / dry. The specific upper and lower arrangement of the reservoir can be determined by the direction of the vertices of the sawtooth points on the upper and lower dividing lines of the reservoir in the horizontal direction.

[0107] It should be noted that the above embodiment only illustrates the arrangement of "water layer-gas layer-dry layer", but the three reservoirs can also be arranged in other ways, which cannot be regarded as a limitation of the present invention.

[0108] Figure 3 The area of ​​each sawtooth point in the first sawtooth band to the right is within the range of the water vapor difference data. , then the first zigzag belt can be represented as the boundary between the water layer and the gas layer, and because the apex of the first zigzag belt in the horizontal direction faces right, it means that the upper resistance is lower than the lower resistance, so it can be concluded that the upper part is the water layer and the lower part is the gas layer. Figure 3 The area of ​​each sawtooth point in the second sawtooth band on the left is within the range of the air-dry difference data. , then the second serrated belt can be represented as the boundary between the gas layer and the dry layer, and because the apex of the second serrated belt in the horizontal direction faces left, it means that the upper resistance is higher than the lower resistance, so it can be concluded that the upper part is the gas layer and the lower part is the dry layer.

[0109] The final boundary lines of water layer and air layer and air layer and dry layer are as follows: Figure 4 shown.

[0110] In some embodiments of the present invention, determining the water layer and air layer boundary according to the first sawtooth band includes:

[0111] Connect the vertices of the first sawtooth belt in the horizontal direction to obtain the boundary line between the water layer and the air layer;

[0112] Determine the boundary line of the dry layer of the gas layer according to the second sawtooth belt, including:

[0113] Connect the vertices of the second serrated belt in the horizontal direction to obtain the boundary line between the air layer and the dry layer.

[0114] The serrated belt belongs to a range of values ​​in the longitudinal direction. Connecting the vertices of the serrated belt in the horizontal direction is equivalent to taking the middle value (or average value) to obtain a more accurate dividing line.

[0115] It should be noted that other positions of the serrated belt can also be connected to serve as the dividing line. The specific position calibration can be selected in a corresponding manner according to actual conditions and should not be regarded as a limitation of the present invention.

[0116] Compared to existing empirical formulas that use simple linear analysis, the reservoir fluid property identification method according to the present invention takes into account the complex realities of the study area. Based on well logging data, the average thin layer thicknesses of different reservoirs are assigned corresponding weight coefficients, and a resistivity correspondence between apparent resistivity and well logging resistivity is established. This makes the formula parameters dynamic and has greater applicability. Furthermore, only the relationship between apparent resistivity and well logging resistivity is established, and the boundary lines between different reservoir fluids are delineated by inverting the apparent resistivity, which is more sensitive to reservoir structure and fluid identification. This not only improves the accuracy of reservoir fluid property identification but also reduces complexity. Because well logging resistivity is an actual measured value, while apparent resistivity is an inverted value, standard data for the numerical differences in well logging resistivity between different reservoir fluids in the study area is determined using well logging data, and then the standard data for the numerical differences in apparent resistivity between different reservoir fluids in the study area is determined using the resistivity correspondence. This results in an apparent resistivity that is closer to reality. Consequently, the boundary lines between different reservoir fluids delineated by the sawtooth points of the apparent resistivity numerical difference standard data and the first-order derivative data are more accurate.

[0117] In some embodiments, reference Figure 5 , Figure 5 This figure is a schematic diagram of a three-dimensional apparent resistivity model of the study area after reservoir fluid division according to one embodiment of the present invention. After demarcating the boundaries between different reservoir fluids, the electromagnetic pseudo-phase waveform and the inverted apparent resistivity distribution profile can be vector-superimposed using Voxler software to obtain a three-dimensional apparent resistivity model of the study area after precise reservoir fluid division. This allows for spatial identification of reservoir fluid properties across the entire study area. Vector arrows at approximately the same depth are combined to form horizon boundaries, providing a highly intuitive visualization of reservoir fluid properties within the study area and enabling fluid identification.

[0118] It should be noted that Voxler software is an existing technology known to those skilled in the art. It is a technical means to achieve three-dimensional results. The specific working process and principle will not be described in detail here.

[0119] According to the reservoir fluid property identification system of the second embodiment of the present invention, the system includes a data acquisition module, a first-order derivative module, a correspondence determination module, a logging resistivity difference data determination module, an apparent resistivity difference data determination module and a reservoir fluid boundary line determination module.

[0120] Data acquisition module, used to obtain inversion apparent resistivity data and logging data of the study area;

[0121] The first-order derivative module is used to perform the first-order derivative of the inverted apparent resistivity data to obtain the first-order derivative data;

[0122] A corresponding relationship determination module is used to assign corresponding weight coefficients to the average thin layer thicknesses of different reservoirs based on well logging data, and to establish a resistivity corresponding relationship between apparent resistivity and well logging resistivity;

[0123] The well logging resistivity difference data determination module is used to determine the standard data of the well logging resistivity value difference between different reservoir fluids in the study area based on the well logging data;

[0124] The apparent resistivity difference data determination module is used to determine the apparent resistivity numerical difference standard data according to the resistivity correspondence relationship and the logging resistivity numerical difference standard data;

[0125] The reservoir fluid boundary line determination module is used to determine the boundary lines of different reservoir fluids based on the standard data of apparent resistivity value difference and the sawtooth points of the first-order derivative data.

[0126] Performing first-order derivative of the inverted apparent resistivity data to obtain first-order derivative data includes: obtaining the first-order derivative of the discrete function along the vertical depth direction of the inverted apparent resistivity data to obtain the first-order derivative data. The first-order derivative data can be plotted into an electromagnetic pseudo-phase waveform diagram using relevant software, such as Figure 2 As shown, Figure 2 The vertical and horizontal axes are consistent with the inverted apparent resistivity distribution profile. Figure 2 The area of ​​the sawtooth points represents the magnitude of the first-order derivative data, and the orientation of the sawtooth points' vertices in the horizontal direction is used to distinguish the amplitude of the first-order derivative data: positive toward the right and negative toward the left. The amplitude of the resistivity change represents the magnitude of the resistivity change of the next formation compared to the previous formation. A positive amplitude change indicates an increase in resistivity from a high altitude to a low altitude, representing a positive phase, indicating a transition from a relatively low-resistance formation to a relatively high-resistance formation. A negative amplitude change indicates a decrease in resistivity from a low altitude to a high altitude, representing a negative phase, indicating a transition from a relatively high-low-resistance formation to a relatively low-resistance formation. The electromagnetic pseudo-phase waveform can be used to describe the change in apparent resistivity within a formation.

[0127] In some embodiments of the present invention, the inverted apparent resistivity data and well logging data must be data from the same region. That is, the inverted apparent resistivity data must be obtained from production wells within the study area that have well logging data. A resistivity correspondence between the apparent resistivity and the well logging resistivity is established using the well logging data. Apparent resistivity and well logging resistivity are measured using different principles, and while numerical differences are inevitable, the two resistivities respond identically to fluids. When the two resistivities are plotted in the same coordinate system with depth and resistivity as the horizontal and vertical axes, the two curves should exhibit similar trends but differ in numerical value, which can be simply understood as being approximately "parallel." Since well logging resistivity is the actual measured value, while apparent resistivity is the inverted value, determining standard data for the numerical differences in well logging resistivity between different reservoir fluids within the study area using well logging data, and then determining standard data for the numerical differences in apparent resistivity between different reservoir fluids within the study area using the resistivity correspondence, can yield an apparent resistivity that is closer to reality.

[0128] The constraint formula for the resistivity correspondence is:

[0129] ;

[0130] +b ;

[0131] in, is the fluid weighting parameter, is the average thin layer thickness of the water layer, is the average thin layer thickness of the gas layer, is the average lamella thickness of the dry layer, is the average thin layer thickness of the gas-water layer, is the weight coefficient of the water layer, is the weight coefficient of the gas layer, is the weight coefficient of the dry layer, is the weight coefficient of gas and water in the same layer, is the apparent resistivity, is the logging resistivity, and b All are calculation parameters.

[0132] The average thin layer thickness of the water layer, the average thin layer thickness of the gas layer, the average thin layer thickness of the dry layer, and the average thin layer thickness of the gas-water layer were all obtained from well logging data. The weight coefficients of the water layer, the gas layer, the dry layer, and the gas-water layer were obtained by conducting indoor physical parameter testing on gas-saturated and water-saturated cores from multiple production wells in the study area. and b All are adjustable calculation parameters.

[0133] In some embodiments of the present invention, determining standard data of the difference in logging resistivity values ​​between different reservoir fluids in a study area based on logging data includes:

[0134] Based on the well logging data, the calibration layers of different reservoir fluids in the study area were screened out. The calibration layers of different reservoir fluids are water layer calibration layer, gas layer calibration layer and dry layer calibration layer.

[0135] The calibration logging resistivity corresponding to the calibration layers of different reservoir fluids is determined based on the logging data. The calibration logging resistivity corresponding to the different calibration layers are respectively the water layer calibration logging resistivity, the gas layer calibration logging resistivity and the dry layer calibration logging resistivity. The standard data for the difference in logging resistivity values ​​between the calibration layers of different reservoir fluids are respectively the water-gas difference data and the gas-dry difference data.

[0136] The water-gas difference data is calculated based on the water layer calibration logging resistivity and the gas layer calibration logging resistivity;

[0137] The gas-dry difference data is calculated based on the gas layer calibration logging resistivity and the dry layer calibration logging resistivity.

[0138] The difference between the water layer calibration logging resistivity and the gas layer calibration logging resistivity is the water-gas difference data; the difference between the gas layer calibration logging resistivity and the dry layer calibration logging resistivity is the gas-dry difference data.

[0139] Well logging data includes logging resistivity data, drilling data, and oil testing data. Based on these data, gas layers and water layers with relatively thick and stable fluid distribution are selected as calibration layers for the gas layer and water layer, respectively. It should be noted that an effective thickness of 5 meters or greater is sufficient. "Relatively stable" means that the corresponding fluid content within the effective thickness reaches more than 75%. It is worth mentioning that although dry layers are also a type of reservoir, they generally have poor rock properties and extremely low porosity and permeability, making them essentially incapable of producing oil and gas. When calibrating, mudstone layers with stable distribution within the formation group to which they belong or within adjacent formation groups, as measured by logging resistivity, are selected.

[0140] In some embodiments, each reservoir fluid may have more than one calibration layer. In such cases, the corresponding calibration logging resistivity can be obtained by weighting the logging resistivity of each calibration layer according to the layer thickness. It should be noted that the specific weighting method can be selected based on actual needs and is not limited here.

[0141] In the embodiment of the present invention, the standard data of the difference in well logging resistivity values ​​between different reservoir fluids calculated based on the well logging resistivity of the calibration layer is more accurate and the reliability of the parameters is higher.

[0142] It is understandable that the internal resistivity difference of reservoirs with the same fluid in the formation is very small, while the resistivity difference of reservoirs with different fluids is large at the junction. For example, the difference between the boundary of gas layer and water layer (i.e., water-gas difference data) is about 160 -200 This value should be significantly different from that inside the reservoir, because there is no significant difference in the stable resistivity of the fluid inside the reservoir, while the resistivity difference at the boundary between different fluid reservoirs is obvious. The reason why the boundary difference data is a range is because the actual situation of the stratum varies intricately. The resistivity difference between the gas layer and the water layer within several thousand meters underground cannot remain a constant. It is more reasonable and reliable to use the average difference between the gas layer and the water layer in a certain group / section of strata within the corresponding altitude range obtained through logging data as the corresponding division standard. This data is related to the specific geological conditions of the study area. When the geological conditions are complex and the reservoir heterogeneity is strong, the data range may be larger, but there is no doubt that this data is significantly different from the interior of the reservoir.

[0143] In some embodiments of the present invention, reference Figures 2 to 4 The standard data of the difference in logging resistivity values ​​between different reservoir fluids are water-gas difference data and gas-dry difference data, and the boundary lines of different reservoir fluids are the water-gas layer boundary line and the gas-dry layer boundary line. The boundary lines of different reservoir fluids are determined based on the sawtooth points of the apparent resistivity value difference standard data and the first-order derivative data, including:

[0144] Determine the area of ​​the sawtooth point in the first-order derivative data;

[0145] Determine that the area of ​​the sawtooth point in the first-order derivative data conforms to the first sawtooth band of the water-vapor difference data;

[0146] Determine that the area of ​​the sawtooth points in the first-order derivative data conforms to the second sawtooth band of the air-dry difference data;

[0147] Connect the vertices of the first sawtooth belt in the horizontal direction to obtain the boundary line between the water layer and the air layer;

[0148] Connect the vertices of the second serrated belt in the horizontal direction to obtain the boundary line between the air layer and the dry layer.

[0149] It can be understood that the area of ​​a sawtooth point represents the apparent resistivity. There is a certain ratio / coefficient between the area and the apparent resistivity, which is a known parameter. Apparent resistivity can be filtered based on the area. If the area of ​​a sawtooth point meets the standard data for apparent resistivity difference, it indicates that the sawtooth point is the boundary between different reservoir fluids. The boundary between different reservoir fluids can be determined by the area of ​​the sawtooth point and the standard data for apparent resistivity difference.

[0150] Taking the water layer, gas layer and dry layer as examples, the electromagnetic pseudo-phase waveform under ideal conditions is as follows: Figure 3 As shown in Figure 2, the reservoir fluid distribution is stable within the water layer, gas layer, and dry layer, so there is almost no resistivity difference inside. Figure 3 There are almost no sawtooth points (i.e., resistivity differences) in the reservoir, but there are obvious resistivity differences at the junction of the three layers. The size of the difference can be obtained through the area of ​​the sawtooth points. The size of the difference can be used to determine which of the three boundary lines is gas / water, gas / dry, or water / dry. The specific upper and lower arrangement of the reservoir can be determined by the direction of the vertices of the sawtooth points on the upper and lower dividing lines of the reservoir in the horizontal direction.

[0151] Figure 3 The area of ​​each sawtooth point in the first sawtooth band to the right is within the range of the water vapor difference data. , then the first zigzag belt can be represented as the boundary between the water layer and the gas layer, and because the apex of the first zigzag belt in the horizontal direction faces right, it means that the upper resistance is lower than the lower resistance, so it can be concluded that the upper part is the water layer and the lower part is the gas layer. Figure 3 The area of ​​each sawtooth point in the second sawtooth band on the left is within the range of the air-dry difference data. , then the second serrated belt can be represented as the boundary between the gas layer and the dry layer, and because the apex of the second serrated belt in the horizontal direction faces left, it means that the upper resistance is higher than the lower resistance, so it can be concluded that the upper part is the gas layer and the lower part is the dry layer.

[0152] The serrated belt belongs to a range of values ​​in the longitudinal direction. Connecting the vertices of the serrated belt in the horizontal direction is equivalent to taking the middle value (or average value) to obtain a more accurate dividing line.

[0153] Compared to existing empirical formulas that use simple linear analysis, the reservoir fluid property identification system according to the present invention takes into account the complex realities of the study area. Based on well logging data, the average thin layer thicknesses of different reservoirs are assigned corresponding weight coefficients, and a resistivity correspondence between apparent resistivity and well logging resistivity is established. This makes the formula parameters dynamic and has greater applicability. Furthermore, only the relationship between apparent resistivity and well logging resistivity is established, and the boundary lines between different reservoir fluids are delineated by inverting the apparent resistivity, which is more sensitive to reservoir structure and fluid identification. This not only improves the accuracy of reservoir fluid property identification but also reduces complexity. Because well logging resistivity is an actual measured value, while apparent resistivity is an inverted value, standard data for the numerical differences in well logging resistivity between different reservoir fluids in the study area is determined using well logging data, and then the standard data for the numerical differences in apparent resistivity between different reservoir fluids in the study area is determined using the resistivity correspondence. This results in an apparent resistivity that is closer to reality. Consequently, the boundary lines between different reservoir fluids delineated by the sawtooth points of the apparent resistivity numerical difference standard data and the first-order derivative data are more accurate.

[0154] In addition, an embodiment of the present invention further provides a control device, which includes: a memory, a processor, and a computer program stored in the memory and executable on the processor. The processor and the memory may be connected via a bus or other means.

[0155] The memory, as a non-transient computer-readable storage medium, can be used to store non-transient software programs and non-transient computer executable programs. In addition, the memory may include a high-speed random access memory and may also include a non-transient memory, such as at least one disk storage device, a flash memory device, or other non-transient solid-state storage device. In some embodiments, the memory may optionally include a memory remotely arranged relative to the processor, and these remote memories may be connected to the processor via a network. Examples of the above-mentioned network include, but are not limited to, the Internet, an intranet, a local area network, a mobile communication network, and combinations thereof.

[0156] The non-transient software program and instructions required to implement the reservoir fluid property identification method of the above embodiment are stored in the memory, and when executed by the processor, the reservoir fluid property identification method of the above embodiment is executed.

[0157] The device embodiments described above are merely illustrative. The units described as separate components may or may not be physically separate, i.e., they may be located in one place or distributed across multiple network units. Some or all of the modules may be selected based on actual needs to achieve the objectives of this embodiment.

[0158] In addition, an embodiment of the present invention also provides a computer-readable storage medium, which stores computer-executable instructions. The computer-executable instructions are executed by a processor or controller, for example, by the processor of the above embodiment, so that the above processor can execute the reservoir fluid property identification method in the above embodiment.

[0159] Those skilled in the art will appreciate that all or some of the steps and systems disclosed above can be implemented as software, firmware, hardware, or any suitable combination thereof. Some or all of the physical components may be implemented as software executed by a processor, such as a central processing unit, digital signal processor, or microprocessor, or as hardware, or as an integrated circuit, such as an application-specific integrated circuit. Such software may be distributed on computer-readable media, which may include computer storage media (or non-transitory media) and communication media (or transient media). As is well known to those skilled in the art, the term computer storage media includes volatile and non-volatile, removable and non-removable media implemented in any method or technology for storing information, such as computer-readable instructions, data structures, program modules, or other data. Computer storage media includes, but is not limited to, RAM, ROM, EEPROM, flash memory or other memory technologies, CD-ROM, digital versatile disks (DVDs) or other optical disk storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium that can be used to store the desired information and can be accessed by a computer. Furthermore, as is well known to those skilled in the art, communication media typically embodies computer-readable instructions, data structures, program modules, or other data in a modulated data signal such as a carrier wave or other transport mechanism, and may include any information delivery media.

[0160] The embodiments of the present invention are described in detail above with reference to the accompanying drawings, but the present invention is not limited to the above embodiments. Various changes can be made within the scope of knowledge possessed by ordinary technicians in the relevant technical field without departing from the scope of the present invention.

Claims

1. A reservoir fluid property identification method, characterized in that: The method comprises: Obtain inverted apparent resistivity data and well logging data in the study area; performing a first-order derivative on the inverted apparent resistivity data to obtain first-order derivative data; Based on the well logging data, assigning corresponding weight coefficients to the average thin layer thicknesses of different reservoirs, and establishing a resistivity correspondence between apparent resistivity and logging resistivity; Determining standard data of the difference in well logging resistivity values ​​between different reservoir fluids in the study area based on the well logging data; Determining apparent resistivity numerical difference standard data according to the resistivity corresponding relationship and the logging resistivity numerical difference standard data; The boundary lines of fluids in different reservoirs are determined according to the apparent resistivity numerical difference standard data and the sawtooth points of the first-order derivative data.

2. The reservoir fluid property identification method according to claim 1, characterized in that: The constraint formula of the resistivity correspondence is: ； +b； in, is the fluid weighting parameter, is the average thin layer thickness of the water layer, is the average thin layer thickness of the gas layer, is the average lamella thickness of the dry layer, is the average thin layer thickness of the gas-water layer, is the weight coefficient of the water layer, is the weight coefficient of the gas layer, is the weight coefficient of the dry layer, is the weight coefficient of gas and water in the same layer, is the apparent resistivity, is the logging resistivity, and b are calculation parameters.

3. The reservoir fluid property identification method according to claim 1, characterized in that: The step of determining standard data of the difference in logging resistivity values ​​between different reservoir fluids in the study area based on the logging data includes: Screening out calibration layers of different reservoir fluids in the study area based on the well logging data; Determining calibrated logging resistivities corresponding to calibration layers of different reservoir fluids based on the logging data; The standard data of the difference in the well logging resistivity values ​​between the calibration layers of different reservoir fluids are calculated based on the respective calibration well logging resistivities.

4. The reservoir fluid property identification method according to claim 3, characterized in that: The calibration layers for different reservoir fluids are respectively a water layer calibration layer, a gas layer calibration layer and a dry layer calibration layer; the calibration logging resistivities corresponding to the different calibration layers are respectively a water layer calibration logging resistivity, a gas layer calibration logging resistivity and a dry layer calibration logging resistivity; the standard data for the difference in logging resistivity values ​​between the calibration layers for different reservoir fluids are respectively water-gas difference data and gas-dry difference data; The method of calculating the standard data of the difference in well logging resistivity values ​​between calibration layers of different reservoir fluids based on the respective calibrated well logging resistivities includes: Calculating the water-gas difference data based on the water layer calibration logging resistivity and the gas layer calibration logging resistivity; The gas-dry layer difference data is obtained by calculation based on the gas layer calibration logging resistivity and the dry layer calibration logging resistivity.

5. The reservoir fluid property identification method according to claim 1, characterized in that: The determining of the boundary lines of different reservoir fluids based on the apparent resistivity numerical difference standard data and the sawtooth points of the first-order derivative data includes: Determining the area of ​​the sawtooth point in the first-order derivative data; The boundary lines of fluids in different reservoirs are determined according to the areas of the sawtooth points in the first-order derivative data and the apparent resistivity value difference standard data.

6. The reservoir fluid property identification method according to claim 5, characterized in that: The standard data for the difference in logging resistivity values ​​between different reservoir fluids are water-gas difference data and gas-dry difference data, and the boundary lines for different reservoir fluids are the water-gas boundary line and the gas-dry boundary line. Determining the boundary lines of different reservoir fluids based on the areas of the sawtooth points in the first-order derivative data and the apparent resistivity value difference standard data includes: Determining that the area of ​​the sawtooth points in the first-order derivative data conforms to the first sawtooth band of the water vapor difference data; Determining that the area of ​​the sawtooth points in the first-order derivative data conforms to a second sawtooth band of the air-dry difference data; Determining the water layer and air layer boundary line according to the first sawtooth band; The air layer dry layer boundary line is determined according to the second sawtooth band.

7. The reservoir fluid property identification method according to claim 6, characterized in that: The determining of the water layer and air layer boundary line according to the first sawtooth band includes: Connecting the vertices of the first sawtooth belt in the horizontal direction to obtain the water layer and air layer boundary line; The step of determining the dry layer boundary line of the air layer according to the second sawtooth band includes: The vertices of the second serrated belt in the horizontal direction are connected to obtain the boundary line of the air layer and the dry layer.

8. A reservoir fluid property identification system, characterized in that: The system comprises: Data acquisition module, used to obtain inversion apparent resistivity data and logging data of the study area; A first-order derivative module, used for performing a first-order derivative on the inverted apparent resistivity data to obtain first-order derivative data; a corresponding relationship determination module, configured to assign corresponding weight coefficients to the average thin layer thicknesses of different reservoirs based on the well logging data, and establish a resistivity corresponding relationship between apparent resistivity and logging resistivity; a well logging resistivity difference data determination module, configured to determine standard data of well logging resistivity value differences between different reservoir fluids in the study area based on the well logging data; an apparent resistivity difference data determining module, configured to determine apparent resistivity numerical difference standard data according to the resistivity correspondence relationship and the logging resistivity numerical difference standard data; The reservoir fluid boundary line determination module is used to determine the boundary lines of different reservoir fluids according to the apparent resistivity value difference standard data and the sawtooth points of the first-order derivative data.

9. A control device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein: When the processor executes the computer program, the reservoir fluid property identification method according to any one of claims 1 to 7 is implemented.

10. A computer-readable storage medium storing computer-executable instructions, characterized in that: The computer executable instructions are used to execute the reservoir fluid property identification method according to any one of claims 1 to 7.

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