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

Abstract

The invention discloses a reservoir fluid property identification method, system and device and a storage medium. The method comprises the steps that inversion apparent resistivity data and logging data of a research area are acquired; performing first-order derivation on the inversion apparent resistivity data to obtain first-order derivation data; based on logging data, corresponding weight coefficients are distributed to the average thin layer thicknesses of different reservoirs, and the resistivity corresponding relation between the apparent resistivity and the logging resistivity is established; determining logging resistivity value difference standard data among different reservoir fluids in the research area according to the logging data; apparent resistivity value difference standard data are determined according to the resistivity corresponding relation and the logging resistivity value difference standard data; and determining fluid boundaries of different reservoirs according to the apparent resistivity value difference standard data and the sawtooth points of the first-order derivation data. According to the reservoir fluid property identification method, system and device and the storage medium provided by the embodiment of the invention, the accuracy of reservoir fluid property identification can be improved.

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 usually have the characteristics of 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 through a correlation formula between wide-area apparent resistivity, logging resistivity, acoustic velocity and post-stack seismic data under different lithology conditions. However, this technology only simply connects the seismic, logging and electromagnetic data of the work area under different lithology (carbonaceous shale, siltstone) through linear analysis, and finally forms a unified empirical formula including 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 connected and formulated through simple linear analysis. In addition, the application scope of this technology is limited by lithology and is only applicable to carbonaceous shale and siltstone, which limits its 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, which 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 reservoir fluid property identification method of a first aspect of the present invention, 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 logging data, the average thin layer thickness of different reservoirs is assigned a corresponding weight coefficient, and a resistivity correspondence between the apparent resistivity and the logging resistivity is established; Determine the standard data of the difference in logging resistivity values ​​between different reservoir fluids in the study area according to the logging data; Determine 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 value difference standard data and the sawtooth points of the first-order derivative data.

[0007] The reservoir fluid property identification method according to the embodiment of the present invention has at least the following beneficial effects: Compared with the existing method of establishing empirical formulas by using simple linear analysis, the embodiment of the present invention takes into account the complex actual situation of the study area, assigns corresponding weight coefficients to the average thin layer thickness of different reservoirs based on logging data, establishes the resistivity correspondence between apparent resistivity and logging resistivity, makes the formula parameters dynamic, has stronger and more extensive applicability, and only establishes the relationship between apparent resistivity and logging resistivity, so as to divide the boundaries of different reservoir fluids by inverting apparent resistivity that is more sensitive to reservoir structure and fluid identification, which can not only improve the accuracy of reservoir fluid property identification, but also has low complexity. Since the logging resistivity is the actual measured value, and the apparent resistivity is the inverted value, the standard data of the numerical difference of the logging resistivity between different reservoir fluids in the study area is determined by the logging data, and then the standard data of the numerical difference of the apparent resistivity between different reservoir fluids in the study area is determined by the resistivity correspondence, so that a more actual apparent resistivity can be obtained, and then the boundary of different reservoir fluids divided by the sawtooth point of the apparent resistivity numerical difference standard data and the first-order derivative data has higher accuracy.

[0008] According to some embodiments of the present invention, 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 lamina 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 the gas-water layer, is the apparent resistivity, is the logging resistivity, and b are calculation parameters.

[0009] According to some embodiments of the present invention, determining the standard data of the difference in logging resistivity values ​​between different reservoir fluids in the study area according to the logging data includes: Screening out calibration layers of different reservoir fluids in the study area according to the well logging data; Determining the calibrated logging resistivity corresponding to the calibration layer of different reservoir fluids according to the logging data; The standard data of the numerical difference of the well logging resistivity between the calibration layers of different reservoir fluids are calculated according to each of the calibrated well logging resistivities.

[0010] 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 difference between the calibration layers of different reservoir fluids are respectively water-gas difference data and gas-dry difference data; The method of calculating the standard data of the numerical difference of the well logging resistivity between the calibration layers of different reservoir fluids according to each of the calibrated well logging resistivities includes: The water-gas difference data is calculated 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 according to the gas layer calibration logging resistivity and the dry layer calibration logging resistivity.

[0011] According to some embodiments of the present invention, determining the boundary lines of different reservoir fluids according to 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.

[0012] According to some embodiments of the present invention, 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 water-layer gas-layer boundary lines and gas-layer dry-layer boundary lines; Determining the boundary lines of different reservoir fluids according to the area of ​​the sawtooth points in the first-order derivative data and the apparent resistivity numerical difference standard data includes: 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; Determine 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; Determine the water layer and air layer boundary line according to the first sawtooth belt; The air layer dry layer boundary line is determined according to the second sawtooth belt.

[0013] According to some embodiments of the present invention, determining 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 air layer dry layer boundary line according to the second sawtooth belt comprises: The vertices of the second sawtooth belt in the horizontal direction are connected to obtain the air layer and dry layer boundary line.

[0014] According to a reservoir fluid property identification system of a second aspect of the present invention, the system comprises: Data acquisition module, used to obtain inversion apparent resistivity data and well 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, used for allocating corresponding weight coefficients to the average thin layer thicknesses of different reservoirs based on the well logging data, and establishing a resistivity corresponding relationship between the apparent resistivity and the well logging resistivity; A well logging resistivity difference data determination module, used to determine the well logging resistivity value difference standard data between different reservoir fluids in the study area according to the well logging data; An apparent resistivity difference data determination module is used to determine apparent resistivity numerical difference standard data according to the resistivity corresponding relationship and the logging resistivity numerical difference standard data; The reservoir fluid boundary determination module is used to determine the boundary lines of different reservoir fluids according to the apparent resistivity numerical difference standard data and the sawtooth points of the first-order derivative data.

[0015] The reservoir fluid property identification system according to the embodiment of the present invention has at least the following beneficial effects: Compared with the existing method of establishing empirical formulas by using simple linear analysis, the embodiment of the present invention takes into account the complex actual situation of the study area, assigns corresponding weight coefficients to the average thin layer thickness of different reservoirs based on logging data, establishes the resistivity correspondence between apparent resistivity and logging resistivity, makes the formula parameters dynamic, has stronger and more extensive applicability, and only establishes the relationship between apparent resistivity and logging resistivity, so as to divide the boundaries of different reservoir fluids by inverting apparent resistivity that is more sensitive to reservoir structure and fluid identification, which can not only improve the accuracy of reservoir fluid property identification, but also has low complexity. Since the logging resistivity is the actual measured value, and the apparent resistivity is the inverted value, the standard data of the numerical difference of the logging resistivity between different reservoir fluids in the study area is determined by the logging data, and then the standard data of the numerical difference of the apparent resistivity between different reservoir fluids in the study area is determined by the resistivity correspondence, so that a more actual apparent resistivity can be obtained, and then the boundary of different reservoir fluids divided by the sawtooth point of the apparent resistivity numerical difference standard data and the first-order derivative data has higher accuracy.

[0016] According to the third aspect of the present invention, the control device comprises a memory, a processor and a computer program stored in the memory and executable on the processor, and the processor implements the reservoir fluid property identification method as described in the first aspect of the present invention when executing the computer program. Since the control device adopts all the technical solutions of the reservoir fluid property identification method of the above embodiment, it has at least all the beneficial effects brought by the technical solutions of the above embodiment.

[0017] The computer-readable storage medium according to the fourth aspect of the present invention stores computer-executable instructions, and the computer-executable instructions are used to execute the reservoir fluid property identification method as described in the first aspect of the present invention. Since the computer-readable storage medium adopts all the technical solutions of the reservoir fluid property identification method of the above embodiment, it at least has all the beneficial effects brought by the technical solutions of the above embodiment.

[0018] Other features and advantages of the present invention will be set forth in the description which follows, and in part will be apparent from the description, or may be learned by practice of the present invention. BRIEF DESCRIPTION OF THE DRAWINGS

[0019] The above and / or additional aspects and advantages of the present invention will become apparent and easily understood from the description of the embodiments in conjunction with the following drawings, in which: Figure 1 is a flow chart of a reservoir fluid property identification method according to an embodiment of the present invention; Figure 2 is an electromagnetic pseudo-phase waveform diagram of first-order derivative data of an embodiment of the present invention; Figure 3is a schematic diagram of dividing lines of different reservoir fluids according to an embodiment of the present invention; Figure 4 is a schematic diagram of the boundary lines of different reservoir fluids according to an embodiment of the present invention; Figure 5 It is a schematic diagram of a three-dimensional model of apparent resistivity of a study area after dividing reservoir fluid according to an embodiment of the present invention. DETAILED DESCRIPTION

[0020] Embodiments of the present invention are described in detail below, examples of which 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 only used to explain the present invention, and cannot be understood as limiting the present invention.

[0021] 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.

[0022] In the description of the present invention, it should be understood that descriptions involving orientation, such as orientation or positional relationship indicated as up, down, etc., are based on the orientation or positional relationship shown in the 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 should not be understood as a limitation on the present invention.

[0023] In the description of the present invention, it should be noted that, unless otherwise clearly defined, terms such as setting, installing, connecting, etc. 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 in combination with the specific content of the technical solution.

[0024] The following will be combined Figures 1 to 5 A clear and complete description is given of the reservoir fluid property identification method according to the embodiment of the present invention. Obviously, the embodiment described below is only a part of the embodiments of the present invention, but not all of the embodiments.

[0025] refer to Figure 1 , Figure 1 It is a flow chart of a reservoir fluid property identification method according to an embodiment of the present invention.

[0026] According to a reservoir fluid property identification method of a first aspect of the present invention, the method comprises: Obtain inverted apparent resistivity data and well logging data in the study area; Perform the first-order derivative of the inverted apparent resistivity data to obtain the first-order derivative data; Based on the 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; Determine the standard data of the logging resistivity value difference between different reservoir fluids in the study area based on the logging data; Determine apparent resistivity numerical difference standard data according to resistivity correspondence and logging resistivity numerical difference standard data; The fluid boundary of different reservoirs is determined based on the sawtooth points of the standard data of apparent resistivity value difference and the first-order derivative data.

[0027] 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: Obtain electromagnetic field information, seismic data, logging data, geological data, drilling data, and oil testing data in the study area; 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.

[0028] 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.

[0029] The first-order derivative of the inverted apparent resistivity data is performed to obtain the first-order derivative data, including: 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 through Matlab software, such as Figure 2 As shown, Figure 2 is 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 point represents the numerical value of the first-order derivative data, and the direction of the vertex of the sawtooth point in the horizontal direction is used to distinguish the amplitude of the first-order derivative data. The right is positive and the left is negative. The amplitude of the resistivity change is the change in the resistivity of the next formation compared with the current formation. The positive change amplitude represents the elevation from high to low, the resistivity rises, and it is a positive phase, indicating that a relatively low-resistance formation enters a relatively high-resistance formation; the negative change amplitude represents the elevation from low to high, the resistivity decreases, and it is a negative phase, indicating that a relatively high-low-resistance formation enters a relatively low-resistance formation. The change of apparent resistivity within the formation range can be described by the electromagnetic pseudo-phase waveform diagram.

[0030] It should be noted that Matlab software belongs to the prior art known to those skilled in the art, and the specific working process and principle will not be described in detail here.

[0031] In some embodiments of the present invention, the inverted apparent resistivity data and the logging data must be data in the same area, that is, the inverted apparent resistivity data must pass through the production wells with logging data in the study area, and the resistivity correspondence between the apparent resistivity and the logging resistivity is established through the logging data. The measurement principles of apparent resistivity and logging resistivity are different, and there must be numerical differences between logging resistivity and apparent resistivity, but the two resistivities have the same response to the fluid. With depth and resistivity as the horizontal and vertical axes, respectively, when the two resistivities are plotted in the same coordinate system, the two curves should be two curves with the same trend but different values, which can be simply understood as two curves that are approximately "parallel". Since the logging resistivity is the actual measured value, and the apparent resistivity is the inverted value, the standard data of the numerical difference of the logging resistivity between different reservoir fluids in the study area is determined by the logging data, and then the standard data of the numerical difference of the apparent resistivity between different reservoir fluids in the study area is determined by the resistivity correspondence, so that a more actual apparent resistivity can be obtained.

[0032] The constraint formula of 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 lamina 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 the gas-water layer, is the apparent resistivity, is the logging resistivity, and b All are calculation parameters.

[0033] 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 are all obtained through well logging data. The weight coefficient of the water layer, the weight coefficient of the gas layer, the weight coefficient of the dry layer and the weight coefficient of the gas-water layer can be obtained by conducting indoor physical property parameter tests on gas-saturated cores and water-saturated cores of multiple production wells in the study area. and b All are adjustable calculation parameters.

[0034] In some embodiments of the present invention, determining the standard data of the difference in logging resistivity values ​​between different reservoir fluids in the study area based on the logging data includes: Based on the well logging data, the calibration layers of different reservoir fluids in the study area were screened out; Determine the calibration logging resistivity corresponding to the calibration layer of different reservoir fluids according to the logging data; 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.

[0035] Well logging data includes well logging resistivity data, drilling data and oil testing data. Based on the well logging resistivity data, drilling data and oil testing data, the gas layer and water layer with larger thickness and more stable fluid distribution are selected as the calibration layer of the gas layer and the calibration layer of the water layer respectively. It should be noted that the effective thickness can be greater than or equal to 5 meters. "Relatively stable" means that the corresponding fluid accounts for more than 75% of the effective thickness. The dry layer is also a type of reservoir, but due to its extremely poor rock properties and low porosity and permeability, it basically has no ability to produce oil and gas. Therefore, under normal circumstances, the oil and gas production characteristics of the dry layer and the mudstone layer are the same. When calibrating, the mudstone layer with stable distribution in the formation group or adjacent formation group in the well logging resistivity can be used for calibration.

[0036] In some embodiments, there may be more than one calibration layer for each reservoir fluid. When there are more than one, the corresponding calibration logging resistivity may 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 may be selected according to actual needs and is not limited here.

[0037] 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.

[0038] In 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 numerical difference of the logging resistivity between the calibration layers of different reservoir fluids are respectively water-gas difference data and gas-dry difference data; The standard data of the difference in logging resistivity values ​​between the calibration layers of different reservoir fluids are calculated based on each calibration logging resistivity, including: The water-gas difference data is calculated based on the water layer calibration logging resistivity and the gas layer calibration logging resistivity; The gas-dry difference data is calculated based on the gas layer calibration logging resistivity and the dry layer calibration logging resistivity.

[0039] 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.

[0040] It is understandable that the internal resistivity difference of reservoirs with the same fluid in the formation is very small, and the resistivity difference of reservoirs with different fluids at the junction is large. 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 of different fluid reservoirs is obvious. 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 obtain the average difference between the gas layer and the water layer of a certain group / section of strata within the corresponding altitude range 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 inside of the reservoir.

[0041] 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 3 is a schematic diagram of dividing lines of different reservoir fluids according to an embodiment of the present invention, Figure 4 Schematic diagram of different reservoir fluid boundary lines according to an embodiment of the present invention, wherein different reservoir fluid boundary lines are determined according to the sawtooth points of apparent resistivity value difference standard data and first-order derivative data, including: Determine the area of ​​the sawtooth point in the first-order derivative data; 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 numerical differences.

[0042] It can be understood that the area size of the sawtooth point indicates the size of the apparent resistivity. There is a certain ratio / coefficient between the area size and the apparent resistivity, which is a known parameter. The apparent resistivity can be screened according to the area size. If the area of ​​the sawtooth point meets the standard data of the apparent resistivity numerical difference, it means that the sawtooth point is the boundary position of different reservoir fluids. The boundary line of different reservoir fluids can be determined by the area size of the sawtooth point and the standard data of the apparent resistivity numerical difference.

[0043] In some embodiments of the present invention, the standard data of the difference in logging resistivity values ​​between different reservoir fluids are water-gas difference data and gas-dry difference data, respectively, and the boundary lines of different reservoir fluids are water-layer gas-layer boundary lines and gas-layer dry-layer boundary lines; 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 difference, including: Determine 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; 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; Determine the boundary between the water layer and the air layer according to the first sawtooth belt; The boundary line of the air layer and the dry layer is determined according to the second serrated belt.

[0044] 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 in 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 structure, while 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 orientation of the vertices of the sawtooth points on the upper and lower dividing lines of the reservoir in the horizontal direction.

[0045] It should be noted that the above embodiment only illustrates the arrangement of "water layer-gas layer-dry layer", but the three reservoirs may also be arranged in other ways, which cannot be regarded as a limitation of the present invention.

[0046] Figure 3 The area of ​​each sawtooth point in the first sawtooth band to the right shown in the figure is within the range of the water vapor difference data. , then the first sawtooth belt can be represented as the boundary between the water layer and the air layer, and because the apex of the first sawtooth 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 air 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 sawtooth belt can be represented as the boundary between the gas layer and the dry layer, and because the apex of the second sawtooth 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.

[0047] The final boundary lines of water layer and air layer and air layer and dry layer are as follows: Figure 4 shown.

[0048] In some embodiments of the present invention, determining the water layer and air layer boundary according to the first sawtooth band includes: 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; The boundary line of the dry layer of the gas layer is determined according to the second sawtooth belt, including: Connect the vertices of the second sawtooth belt in the horizontal direction to obtain the boundary line between the air layer and the dry layer.

[0049] The sawtooth belt belongs to a range of values ​​in the longitudinal direction. Connecting the vertices of the sawtooth belt in the horizontal direction is equivalent to taking the middle value (or average value) to obtain a more accurate dividing line.

[0050] It should be noted that other positions of the serrated belt may also be connected to serve as the dividing line, and the specific position calibration may be selected in a corresponding manner according to actual conditions, and it should not be regarded as a limitation of the present invention.

[0051] According to the reservoir fluid property identification method of the embodiment of the present invention, compared with the existing method of using simple linear analysis when establishing empirical formulas, the embodiment of the present invention takes into account the complex actual situation of the study area, allocates corresponding weight coefficients to the average thin layer thickness of different reservoirs based on logging data, establishes the resistivity correspondence between apparent resistivity and logging resistivity, makes the formula parameters dynamic, has stronger and more extensive applicability, and only establishes the relationship between apparent resistivity and logging resistivity, so as to divide the boundary lines of different reservoir fluids by inverting apparent resistivity that is more sensitive to reservoir structure and fluid identification, which can not only improve the accuracy of reservoir fluid property identification, but also has low complexity. Since the logging resistivity is the actual measured value, and the apparent resistivity is the inverted value, the standard data of the numerical difference of the logging resistivity between different reservoir fluids in the study area is determined by the logging data, and then the standard data of the numerical difference of the apparent resistivity between different reservoir fluids in the study area is determined by the resistivity correspondence, so that the apparent resistivity that is closer to the actual can be obtained, and then the boundary lines of different reservoir fluids divided by the sawtooth points of the apparent resistivity numerical difference standard data and the first-order derivative data are more accurate.

[0052] In some embodiments, reference Figure 5 , Figure 5 This is a schematic diagram of a three-dimensional model of apparent resistivity of a study area after dividing reservoir fluids according to an embodiment of the present invention. After dividing the boundaries of different reservoir fluids, the electromagnetic pseudo-phase waveform diagram and the inverted apparent resistivity distribution profile can be vector-superimposed through Voxler software to obtain a three-dimensional model of apparent resistivity of the study area after accurate division of reservoir fluids, and the properties of reservoir fluids in the entire study area can be distinguished. Vector arrows at approximately the same depth are combined into a stratum boundary line, which can intuitively display the properties of reservoir fluids in the study area and complete fluid identification.

[0053] It should be noted that Voxler software belongs to the 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 repeated here.

[0054] According to the reservoir fluid property identification system of the second aspect of the present invention, the system includes a data acquisition module, a first-order derivative module, a corresponding relationship determination module, a logging resistivity difference data determination module, an apparent resistivity difference data determination module and a reservoir fluid boundary line determination module.

[0055] Data acquisition module, used to obtain inversion apparent resistivity data and well logging data of the study area; 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; 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; A well logging resistivity difference data determination module is used to determine the standard data of well logging resistivity value differences between different reservoir fluids in the study area based on the well logging data; The apparent resistivity difference data determination module is used to determine the apparent resistivity value difference standard data according to the resistivity correspondence relationship and the logging resistivity value difference standard data; The reservoir fluid boundary determination module is used to determine the boundary of different reservoir fluids according to the standard data of apparent resistivity value difference and the sawtooth point of the first-order derivative data.

[0056] The first-order derivative of the inverted apparent resistivity data is performed to obtain the first-order derivative data, including: obtaining the first-order derivative of the discrete function of the inverted apparent resistivity data along the vertical depth direction to obtain the first-order derivative data. The first-order derivative data can be plotted into an electromagnetic pseudo-phase waveform diagram through 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 point represents the numerical value of the first-order derivative data, and the direction of the vertex of the sawtooth point in the horizontal direction is used to distinguish the amplitude of the first-order derivative data. The right is positive and the left is negative. The amplitude of the resistivity change is the change in the resistivity of the next formation compared with the current formation. The positive change amplitude represents the elevation from high to low, the resistivity rises, and it is a positive phase, indicating that a relatively low-resistance formation enters a relatively high-resistance formation; the negative change amplitude represents the elevation from low to high, the resistivity decreases, and it is a negative phase, indicating that a relatively high-low-resistance formation enters a relatively low-resistance formation. The change of apparent resistivity within the formation range can be described by the electromagnetic pseudo-phase waveform diagram.

[0057] In some embodiments of the present invention, the inverted apparent resistivity data and the logging data must be data in the same area, that is, the inverted apparent resistivity data must pass through the production wells with logging data in the study area, and the resistivity correspondence between the apparent resistivity and the logging resistivity is established through the logging data. The measurement principles of apparent resistivity and logging resistivity are different, and there must be numerical differences between logging resistivity and apparent resistivity, but the two resistivities have the same response to the fluid. With depth and resistivity as the horizontal and vertical axes, respectively, when the two resistivities are plotted in the same coordinate system, the two curves should be two curves with the same trend but different values, which can be simply understood as two curves that are approximately "parallel". Since the logging resistivity is the actual measured value, and the apparent resistivity is the inverted value, the standard data of the numerical difference of the logging resistivity between different reservoir fluids in the study area is determined by the logging data, and then the standard data of the numerical difference of the apparent resistivity between different reservoir fluids in the study area is determined by the resistivity correspondence, so that a more actual apparent resistivity can be obtained.

[0058] The constraint formula of 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 lamina 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 the gas-water layer, is the apparent resistivity, is the logging resistivity, and b All are calculation parameters.

[0059] 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 are all obtained through well logging data. The weight coefficient of the water layer, the weight coefficient of the gas layer, the weight coefficient of the dry layer and the weight coefficient of the gas-water layer can be obtained by conducting indoor physical property parameter tests on gas-saturated cores and water-saturated cores of multiple production wells in the study area. and b All are adjustable calculation parameters.

[0060] In some embodiments of the present invention, determining the standard data of the difference in logging resistivity values ​​between different reservoir fluids in the study area based on the logging data includes: According to the logging data, the calibration layers of different reservoir fluids in the study area are screened out, and the calibration layers of different reservoir fluids are water layer calibration layer, gas layer calibration layer and dry layer calibration layer respectively; The calibration logging resistivity corresponding to the calibration layers of different reservoir fluids is determined according to the logging data. The calibration logging resistivity corresponding to the different calibration layers are respectively the calibration logging resistivity of the water layer, the calibration logging resistivity of the gas layer and the calibration logging resistivity of the dry layer; the standard data of the numerical difference of the logging resistivity between the calibration layers of different reservoir fluids are respectively the water-gas difference data and the gas-dry difference data; The water-gas difference data is calculated based on the water layer calibration logging resistivity and the gas layer calibration logging resistivity; The gas-dry difference data is calculated based on the gas layer calibration logging resistivity and the dry layer calibration logging resistivity.

[0061] 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.

[0062] Well logging data include well logging resistivity data, drilling data and oil testing data. Based on the well logging resistivity data, drilling data and oil testing data, gas layers and water layers with larger thickness and more stable fluid distribution are selected as calibration layers for gas layers and water layers respectively. It should be noted that the effective thickness can be greater than or equal to 5 meters. "Relatively stable" means that the corresponding fluid accounts for more than 75% of the effective thickness. It is worth mentioning that although the dry layer is also a type of reservoir, it basically has no ability to produce oil and gas because its rock properties are usually poor and its porosity and permeability are extremely low. When calibrating, the mudstone layer with stable distribution in the formation group or adjacent formation group in the well logging resistivity is selected for calibration.

[0063] In some embodiments, there may be more than one calibration layer for each reservoir fluid. When there are more than one, the corresponding calibration logging resistivity may 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 may be selected according to actual needs and is not limited here.

[0064] 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.

[0065] It is understandable that the internal resistivity difference of reservoirs with the same fluid in the formation is very small, and the resistivity difference of reservoirs with different fluids at the junction is large. 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 that the actual situation of the strata varies intricately. The resistivity difference between the gas layer and the water layer within thousands of meters underground cannot be maintained as a constant. It is more reasonable and credible to use the logging data to obtain the average difference between the gas layer and the water layer in a certain group / section of strata within the corresponding altitude range 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 inside of the reservoir.

[0066] 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 boundaries of different reservoir fluids are water-gas boundary line and gas-dry boundary line. The boundaries of different reservoir fluids are determined according to the sawtooth points of the standard data of apparent resistivity value difference and the first-order derivative data, including: Determine the area of ​​the sawtooth point in the first-order derivative data; Determine 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; 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; 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; Connect the vertices of the second sawtooth belt in the horizontal direction to obtain the boundary line between the air layer and the dry layer.

[0067] It can be understood that the area size of the sawtooth point indicates the size of the apparent resistivity. There is a certain ratio / coefficient between the area size and the apparent resistivity, which is a known parameter. The apparent resistivity can be screened according to the area size. If the area of ​​the sawtooth point meets the standard data of the apparent resistivity numerical difference, it means that the sawtooth point is the boundary position of different reservoir fluids. The boundary line of different reservoir fluids can be determined by the area size of the sawtooth point and the standard data of the apparent resistivity numerical difference.

[0068] 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 in 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 structure, while 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 orientation of the vertices of the sawtooth points on the upper and lower dividing lines of the reservoir in the horizontal direction.

[0069] Figure 3 The area of ​​each sawtooth point in the first sawtooth band to the right shown in the figure is within the range of the water vapor difference data. , then the first sawtooth belt can be represented as the boundary between the water layer and the air layer, and because the apex of the first sawtooth 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 air 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 sawtooth belt can be represented as the boundary between the gas layer and the dry layer, and because the apex of the second sawtooth 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.

[0070] The sawtooth belt belongs to a range of values ​​in the longitudinal direction. Connecting the vertices of the sawtooth belt in the horizontal direction is equivalent to taking the middle value (or average value) to obtain a more accurate dividing line.

[0071] According to the reservoir fluid property identification system of the embodiment of the present invention, compared with the existing method of using simple linear analysis when establishing empirical formulas, the embodiment of the present invention takes into account the complex actual situation of the study area, allocates corresponding weight coefficients to the average thin layer thickness of different reservoirs based on logging data, establishes the resistivity correspondence between apparent resistivity and logging resistivity, makes the formula parameters dynamic, has stronger and more extensive applicability, and only establishes the relationship between apparent resistivity and logging resistivity, so as to divide the boundaries of different reservoir fluids by inverting apparent resistivity that is more sensitive to reservoir structure and fluid identification, which can not only improve the accuracy of reservoir fluid property identification, but also has low complexity. Since the logging resistivity is the actual measured value, and the apparent resistivity is the inverted value, the standard data of the numerical difference of the logging resistivity between different reservoir fluids in the study area is determined by the logging data, and then the standard data of the numerical difference of the apparent resistivity between different reservoir fluids in the study area is determined by the resistivity correspondence, so that the apparent resistivity that is closer to the actual can be obtained, and then the boundary of different reservoir fluids divided by the sawtooth point of the apparent resistivity numerical difference standard data and the first-order derivative data has higher accuracy.

[0072] 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.

[0073] 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 disposed 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.

[0074] 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.

[0075] The device embodiments described above are merely illustrative, and the units described as separate components may or may not be physically separated, that is, they may be located in one place or distributed on multiple network units. Some or all of the modules may be selected according to actual needs to achieve the purpose of the solution of this embodiment.

[0076] In addition, an embodiment of the present invention also provides a computer-readable storage medium, which stores computer-executable instructions, and 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.

[0077] It will be appreciated by those skilled in the art that all or some of the steps and systems in the methods disclosed above may be implemented as software, firmware, hardware, and appropriate combinations thereof. Some or all physical components may be implemented as software executed by a processor, such as a central processing unit, a digital signal processor, or a microprocessor, or as hardware, or as an integrated circuit, such as an application-specific integrated circuit. Such software may be distributed on a computer-readable medium, which may include a computer storage medium (or non-transitory medium) and a communication medium (or transient medium). As known to those skilled in the art, the term computer storage medium 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 include, but are not limited to, RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disk (DVD) or other optical disk storage, magnetic cassettes, magnetic tapes, disk storage or other magnetic storage devices, or any other medium that can be used to store desired information and can be accessed by a computer. Furthermore, it is well known to those skilled in the art that 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.

[0078] The embodiments of the present invention are described in detail above in conjunction with the accompanying drawings, but the present invention is not limited to the above embodiments, and various changes can be made within the knowledge scope of ordinary technicians in the relevant technical field without departing from the purpose of the present invention.

Claims

1. A method for identifying reservoir fluid properties, 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 logging data, the average thin layer thickness of different reservoirs is assigned a corresponding weight coefficient, and a resistivity correspondence between the apparent resistivity and the logging resistivity is established; Determine the standard data of the difference in logging resistivity values ​​between different reservoir fluids in the study area according to the logging data; Determine 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 value 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 lamina 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 the gas-water 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 the standard data of the difference in logging resistivity values ​​between different reservoir fluids in the study area according to the logging data includes: Screening out calibration layers of different reservoir fluids in the study area according to the well logging data; Determining the calibrated logging resistivity corresponding to the calibration layer of different reservoir fluids according to the logging data; The standard data of the numerical difference of the well logging resistivity between the calibration layers of different reservoir fluids are calculated according to each of the calibration well logging resistivities.

4. The reservoir fluid property identification method according to claim 3, characterized in that: 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 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 difference between the calibration layers of different reservoir fluids are respectively water-gas difference data and gas-dry difference data; The method of calculating the standard data of the numerical difference of the well logging resistivity between the calibration layers of different reservoir fluids according to each of the calibrated well logging resistivities includes: The water-gas difference data is calculated 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 according to 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 method of determining the boundary lines of different reservoir fluids according to the apparent resistivity numerical difference standard data and the sawtooth points of the first-order derivative data comprises: Determine 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 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 water-gas boundary line and gas-dry boundary line; Determining the boundary lines of different reservoir fluids according to the area of ​​the sawtooth points in the first-order derivative data and the apparent resistivity numerical difference standard data includes: Determine 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; Determine that the area of ​​the sawtooth point in the first-order derivative data conforms to a second sawtooth band of the air-dry difference data; Determine the water layer and air layer boundary line according to the first sawtooth belt; The air layer dry layer boundary line is determined according to the second sawtooth belt.

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

8. A reservoir fluid property identification system, characterized in that: The system comprises: Data acquisition module, used to obtain inversion apparent resistivity data and well 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, used for allocating corresponding weight coefficients to the average thin layer thicknesses of different reservoirs based on the well logging data, and establishing a resistivity corresponding relationship between the apparent resistivity and the well logging resistivity; A well logging resistivity difference data determination module, used to determine the well logging resistivity value difference standard data between different reservoir fluids in the study area according to the well logging data; An apparent resistivity difference data determination module is used to determine apparent resistivity numerical difference standard data according to the resistivity corresponding relationship and the logging resistivity numerical difference standard data; The reservoir fluid boundary determination module is used to determine the boundary lines of different reservoir fluids according to the apparent resistivity numerical 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, characterized in that: 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 as described in any one of claims 1 to 7.

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