Downhole reservoir oil-gas phase state fluid property identification method, device, equipment and medium

Abstract

The invention discloses a downhole reservoir oil-gas phase state fluid property identification method, device and equipment and a medium, and relates to the field of oil well exploration, the method comprises the following steps: collecting related data of cable formation test during pumping operation, and forming a data set; constructing a cable formation test three-dimensional seepage numerical simulation model, and discretizing and solving a mass conservation equation in the model to obtain a pressure distribution field and a water saturation distribution field; establishing a probe suction port fluid hydrocarbon content calculation model according to the pressure distribution field, the water saturation distribution field and probe node fluid spherical flow characteristics; utilizing the data set and a probe suction port fluid hydrocarbon content calculation model to simulate and calculate a hydrocarbon content curve of oil and gas classification of the same type of stratums, and constructing a clustering chart; and comparing the hydrocarbon phase breakthrough time of the actual formation test operation of the same type of to-be-processed formations with the clustering chart, and identifying the fluid properties of the to-be-processed formations. According to the invention, the fluid property of the stratum to be processed can be identified conveniently and accurately.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas field exploration and development, and in particular to a method, device, equipment and medium for identifying the properties of oil and gas phase fluids in a bottom hole reservoir. Background Art

[0002] Wireline formation testing is a key logging technology in oil and gas exploration and development. It involves lowering specialized testing instruments into the well via a cable, conducting in-situ formation testing in the target interval and rapidly acquiring dynamic pressure data, providing a key basis for reservoir evaluation, production capacity forecasting, and development decision-making. This invention aims to effectively identify subsurface reservoir fluid properties using hydrocarbon breakthrough time from wireline formation testing, providing a new approach for identifying oil and gas phases in bottomhole reservoirs. Summary of the Invention

[0003] In view of the above problems, the present invention is proposed to provide a method, device, equipment and medium for identifying the properties of oil and gas phase fluids in bottom hole reservoirs that overcome the above problems or at least partially solve the above problems.

[0004] According to one aspect of an embodiment of the present application, a method for identifying oil and gas phase fluid properties in a bottom hole reservoir is provided, the method comprising: Collect relevant data from cable formation testing during pumping operations to form a data set; A three-dimensional seepage numerical simulation model for cable formation testing was constructed, and the mass conservation equation in the model was discretized and solved to obtain the pressure distribution field and water saturation distribution field. Based on the pressure distribution field, water saturation distribution field and the spherical flow characteristics of the probe node fluid, a calculation model for hydrocarbon content in the probe suction port of wireline formation testing is established; Using the data set and the probe suction port fluid hydrocarbon content calculation model, we simulated and calculated the hydrocarbon content curves of oil and gas classification in the same type of formations, and constructed a clustering chart for identifying the fluid properties of oil and gas reservoirs; The hydrocarbon phase breakthrough time of actual formation test operations of the same type of to-be-treated formation is compared with the clustering chart to identify the fluid properties of the to-be-treated formation.

[0005] Furthermore, a three-dimensional seepage numerical simulation model of wireline formation testing is used to simulate the water saturation and formation pressure distribution of the near-wellbore reservoir during the pumping process; The three-dimensional seepage numerical simulation model of cable formation testing includes: model assumptions, mass conservation equations, boundary conditions, initial conditions and auxiliary equations; The calculation model of the fluid hydrocarbon content at the probe suction port includes: a fluid water content equation, a fluid water flow equation, a fluid hydrocarbon flow equation and a fluid hydrocarbon content equation.

[0006] Furthermore, the mass conservation equation in the three-dimensional seepage numerical simulation model of the cable formation test is discretized and solved to obtain the pressure distribution field and the water saturation distribution field, which further includes: The finite volume method is used to discretize the mass conservation equation to obtain the pressure discrete equation and the water saturation discrete equation. The pressure discrete equation and the water saturation discrete equation are solved by using the matrix pre-processed stable biconjugate gradient iterative solution method to obtain the pressure distribution field and the water saturation distribution field.

[0007] Furthermore, using the data set and the probe suction port fluid hydrocarbon content calculation model, the hydrocarbon content curves of oil and gas classifications of the same type of formations are simulated and calculated, and the clustering chart for identifying the fluid properties of oil and gas reservoirs is constructed, which further includes: Using the data set and the hydrocarbon content calculation model for the probe suction port fluid, the hydrocarbon content curve at the probe suction port with a preset probe size and the same wellbore and pumping operation parameters in the same target formation is simulated and calculated. The corresponding hydrocarbon phase breakthrough time is determined based on the hydrocarbon content curve. The sample data is generated based on the oil and gas type, hydrocarbon content curve and hydrocarbon phase breakthrough time of the same type of target formation in the wireline formation test, and a sample set is constructed; Based on the sample set, a clustering map is constructed using the dynamic time warping algorithm and the hierarchical clustering algorithm. The clustering map includes the hydrocarbon content curves and the boundaries of the hydrocarbon content curves of the same type of formation oil and gas classification.

[0008] Furthermore, based on the sample set, the clustering map is constructed by using the dynamic time warping algorithm and the hierarchical clustering algorithm, further including: intercepting a curve with the same pumping operation time length from the hydrocarbon content curve of each sample data in the sample set as a sample curve; A hierarchical clustering algorithm is used to form a single cluster using a single sample curve. The distance of each cluster is calculated using a dynamic time warping algorithm, and a preset number of clusters with similar distances are selected for merging. The distance strategy is updated based on the merged clusters, and this step is repeated. During the clustering process, pruning operations are performed according to the preset pruning decisions until the target cluster for oil and gas classification is obtained. The hydrocarbon content curve classification corresponding to the target cluster is projected onto the hydrocarbon content curve diagram to form a clustering plate, and the hydrocarbon content curve boundaries of the same type of formation oil and gas classification are determined based on the hydrocarbon content curve corresponding to the target cluster, and the hydrocarbon content curve boundaries of the same type of formation oil and gas classification are marked on the clustering plate.

[0009] Furthermore, comparing the hydrocarbon phase breakthrough time of actual formation test operations of the same type of formation to be treated with the cluster map to identify the fluid properties of the formation to be treated further includes: According to the hydrocarbon content curve boundary of the same type of strata oil and gas classification in the clustering chart, the maximum breakthrough time of gas phase hydrocarbon content and the minimum breakthrough time of oil phase hydrocarbon content are extracted; When the hydrocarbon phase breakthrough time is less than the maximum breakthrough time of the gas phase hydrocarbon content, the fluid property of the to-be-treated formation is determined to be gas phase fluid; When the hydrocarbon phase breakthrough time is greater than the minimum breakthrough time of the oil phase hydrocarbon content, the fluid property of the to-be-treated formation is determined to be oil phase fluid; When the hydrocarbon phase breakthrough time is greater than or equal to the maximum breakthrough time of the gas phase hydrocarbon content and less than or equal to the minimum breakthrough time of the oil phase hydrocarbon content, the fluid property of the to-be-treated formation is determined to be an oil-gas coexisting fluid.

[0010] According to another aspect of an embodiment of the present application, a device for identifying oil and gas phase fluid properties in a bottom hole reservoir is provided, the device comprising: An acquisition module, suitable for collecting relevant data of cable formation testing during pumping operations to form a data set; The first construction module is suitable for constructing a three-dimensional seepage numerical simulation model for cable formation testing, discretizing and solving the mass conservation equation in the three-dimensional seepage numerical simulation model for cable formation testing, and obtaining a pressure distribution field and a water saturation distribution field; The second building module is adapted to establish a calculation model for hydrocarbon content in the probe suction port fluid of the wireline formation test based on the pressure distribution field, the water saturation distribution field, and the spherical flow characteristics of the fluid at the probe node; The chart construction module is suitable for using the data set and the probe suction port fluid hydrocarbon content calculation model to simulate and calculate the hydrocarbon content curves of oil and gas classification in the same type of formation, and to construct a cluster chart for identifying the fluid properties of oil and gas reservoirs; The identification module is suitable for comparing the hydrocarbon phase breakthrough time of the actual formation test operation of the same type of to-be-treated formation with the clustering plate to identify the fluid properties of the to-be-treated formation.

[0011] According to another aspect of an embodiment of the present application, a computing device is provided, comprising: a processor, a memory, a communication interface, and a communication bus, wherein the processor, the memory, and the communication interface communicate with each other via the communication bus; The memory is used to store at least one executable instruction, and the executable instruction enables the processor to execute operations corresponding to the above-mentioned method for identifying the oil and gas phase fluid properties of the bottom hole reservoir.

[0012] According to another aspect of the embodiment of the present application, a computer storage medium is provided, in which at least one executable instruction is stored. The executable instruction enables a processor to perform operations corresponding to the above-mentioned method for identifying the oil and gas phase fluid properties of the bottom hole reservoir.

[0013] According to another aspect of the embodiments of the present application, a computer program product is provided, comprising at least one executable instruction, wherein the executable instruction enables a processor to perform operations corresponding to the above-mentioned method for identifying oil and gas phase fluid properties in a bottom hole reservoir.

[0014] According to the technical solution provided by the present invention, a three-dimensional seepage numerical simulation model for cable formation testing and a hydrocarbon content calculation model for probe suction port fluid are constructed. Through the dynamic time warping algorithm and the hierarchical clustering algorithm, a clustering plate for identifying the fluid properties of oil and gas reservoirs is constructed, and an identification standard for identifying the fluid properties of oil and gas reservoirs based on the hydrocarbon phase breakthrough time of actual formation testing operations is formulated. By comparing the hydrocarbon phase breakthrough time of actual formation testing operations of the same type of to-be-treated formations with the clustering plate, the fluid properties of the to-be-treated formation can be easily and accurately identified, achieving the goal of identifying the fluid properties of the bottom hole reservoir based on the hydrocarbon phase breakthrough time, and providing a reliable solution and technical means for the identification of oil and gas phase fluid properties of underground reservoirs in cable formation testing.

[0015] The above description is only an overview of the technical solution of the present invention. In order to more clearly understand the technical means of the present invention, it can be implemented in accordance with the contents of the specification. In order to make the above and other purposes, features and advantages of the present invention more obvious and easy to understand, the specific implementation methods of the present invention are specifically listed below. BRIEF DESCRIPTION OF THE DRAWINGS

[0016] Various other advantages and benefits will become apparent to those skilled in the art upon reading the detailed description of the preferred embodiment below. The accompanying drawings are for illustration purposes only and are not to be considered as limiting the present invention. The same reference symbols are used throughout the drawings to represent the same components. In the drawings: Figure 1 A schematic flow chart of a method for identifying oil and gas phase fluid properties in a bottom hole reservoir according to one embodiment of the present application is shown; Figure 2 Schematic diagram showing simulation of pumping operation and statistical calculation of hydrocarbon content curves for monitoring under wireline formation testing Figure 1 ; Figure 3 A schematic diagram of a clustering plate is shown; Figure 4 Schematic diagram showing simulation of pumping operation and statistical calculation of hydrocarbon content curves for monitoring under wireline formation testing Figure 2 ; Figure 5 Schematic diagram showing simulation of pumping operation and statistical calculation of hydrocarbon content curves for monitoring under wireline formation testing Figure 3 ; Figure 6 A structural block diagram of a device for identifying oil and gas phase fluid properties in a bottom hole reservoir according to one embodiment of the present application is shown; Figure 7 A schematic structural diagram of a computing device according to an embodiment of the present application is shown. DETAILED DESCRIPTION

[0017] Exemplary embodiments of the present disclosure will be described in more detail below with reference to the accompanying drawings. Although exemplary embodiments of the present disclosure are shown in the accompanying drawings, it should be understood that the present disclosure can be implemented in various forms and should not be limited by the embodiments set forth herein. Rather, these embodiments are provided to enable a more thorough understanding of the present disclosure and to fully convey the scope of the present disclosure to those skilled in the art.

[0018] Figure 1 FIG. 1 shows a flow chart of a method for identifying oil and gas phase fluid properties in a bottom hole reservoir according to an embodiment of the present application. Figure 1 As shown, the method includes the following steps: Step S101 : collecting relevant data of the cable formation test during the pumping operation to form a data set.

[0019] During the wireline formation test, data on various formation, wellbore, pumping, and fluid properties are collected to form a data set. This data set provides a foundation for the subsequent construction of a three-dimensional seepage numerical simulation model and fluid identification analysis for wireline formation testing. Specifically, the data set may include a subset of formation property data for the target formation near the wellbore, a subset of wellbore property data for the target formation near the wellbore, a subset of wireline formation test pumping probe data, and a subset of fluid property data for the target formation near the wellbore.

[0020] The formation property data subset of the near-well target formation is based on the target formation where the well is located, and contains formation property data determined through analysis of well logging data. The formation property data may specifically include formation depth, porosity, permeability, mud content, water saturation, lithology, rock compressibility, etc.

[0021] The wellbore property data subset of the near-wellbore target formation is based on the wellbore where the target formation is located, and includes wellbore property data from wireline formation tests such as logging and well logging. The wellbore property data may specifically include wellbore radius, mud density, and mud invasion range of the wellbore wall (for example, the radius of the flushing zone, transition zone, and invasion zone).

[0022] The pump probe data subset for wireline formation testing includes pump probe property data such as pumping speed, probe type, and suction port area.

[0023] The fluid property data subset of the near-well target formation is based on the fluid in the target formation where the well is located, and includes the collected fluid property data. The fluid property data may specifically include the density, viscosity, volume coefficient, compressibility, oil-water and gas-water relative permeability curves of hydrocarbon fluids such as oil and gas.

[0024] Step S102 : constructing a three-dimensional seepage numerical simulation model for cable formation testing, discretizing and solving the mass conservation equation in the three-dimensional seepage numerical simulation model for cable formation testing, and obtaining a pressure distribution field and a water saturation distribution field.

[0025] The 3D seepage numerical simulation model for wireline formation testing is used to simulate the flow of fluid in the near-wellbore formation during pumping. Specifically, it simulates the water saturation and formation pressure distribution in the near-wellbore formation during pumping. The 3D seepage numerical simulation model for wireline formation testing includes model assumptions, mass conservation equations, boundary conditions, initial conditions, and auxiliary equations.

[0026] Specifically, the model assumptions may include: the seepage is three-dimensional radial flow; the two-phase seepage of formation oil, formation water and mud filtrate mixed fluid is considered; the black oil model is adopted; the formation heterogeneity is considered; both incompressible and compressible fluids are supported; there is no diffusion phenomenon and no chemical reaction in the flow process (the adsorption of mud on the wellbore wall is not considered for the time being); the outer boundary supports constant pressure / closed boundary, and the inner boundary supports constant liquid / constant pressure.

[0027] The integral form of the mass conservation equation is shown in formula (1): (1) In formula (1), y Indicates the category number of different fluid components, where o represents the formation hydrocarbon phase, and (w+m) represents the formation water phase and mud filtrate phase; represents the flow velocity vector; Indicates the y The velocity vector of the fluid component; E represents the area; N represents the y The source term of the fluid component; V represents the volume; represents porosity; S represents the saturation of fluid components; Indicates the y The saturation of the fluid component; ρ represents the density of the fluid component; Indicates the y The density of the fluid component. The left side of the equal sign in Equation (1) represents the surface integral of the energy flux through the area E and the y The triple integral on the right side of the equal sign represents the rate of change of energy in the volume V. Equation (1) represents the energy flux through the area E and the y The sum of the source terms of the fluid components is equal to the rate of change of energy in the volume V, which describes the conservation relationship between the energy flux through the area E, the source terms of the fluid components, and the rate of change of energy in the volume V.

[0028] The initial conditions include the initial pressure distribution condition and the initial fluid distribution condition. The equation of the initial pressure distribution condition is shown in Equation (2), and the equation of the initial fluid distribution condition is shown in Equation (3): (2) (3) Where P represents pressure, S represents fluid saturation, x represents the distribution position, and t represents time.

[0029] The boundary conditions include constant pressure boundary conditions and constant liquid boundary conditions. The equation of the constant pressure boundary condition is shown in formula (4), and the equation of the constant liquid boundary condition is shown in formula (5): (4) (5) in, P Indicates pressure; q Indicates the amount of formation water, formation oil, and total flow rate of mud filtrate extraction; r Indicates the border radius; t Indicates time.

[0030] The auxiliary equations include the oil phase relative permeability equation, the water phase relative permeability equation, the oil phase viscosity equation, the oil phase volume coefficient equation, the oil phase density equation, and the formation fluid density equation. Among them, the oil phase relative permeability equation is shown in equation (6), the water phase relative permeability equation is shown in equation (7), the oil phase viscosity equation is shown in equation (8), the oil phase volume coefficient equation is shown in equation (9), the oil phase density equation is shown in equation (10), and the formation fluid density equation is shown in equation (11): (6) (7) (8) (9) (10) (11) in, represents the relative permeability of the oil phase; Indicates water saturation; represents the relative permeability of water phase; Indicates the viscosity of oil phase fluid; P Indicates pressure; represents the volume coefficient of oil phase; represents the density of oil phase fluid; represents the density of the aqueous fluid; Indicates mud density.

[0031] In step S102, the mass conservation equation is discretized using the finite volume method to obtain the pressure discrete equation and the water saturation discrete equation; the pressure discrete equation and the water saturation discrete equation are solved by the iterative solution method of matrix preprocessing stabilized biconjugate gradient to obtain the pressure distribution field and the water saturation distribution field.

[0032] Specifically, the finite volume method is used for spatial discretization and the backward first-order difference method is used for temporal discretization, and the mass conservation discrete control equation with pressure as the solution parameter is obtained, that is, the pressure discrete equation, as shown in Equation (12): (12) in, i and j Indicates the sequence number of the grid node with link relationship; For the i The grid node (well) and the j The connection conduction coefficient between grid nodes; n represents the time step coefficient; z ( i ) indicates the current i The total number of grid link relationships a grid has; For the i The grid node and j The density of the water phase fluid between the grid nodes; For the n Time grid j The oil phase fluidity; For the i The grid node and j The density of the oil phase (or hydrocarbon phase) fluid between the grid nodes; For the n Time grid j The water phase mobility; For the n +1 moment i The grid node and j Hydrocarbon phase pressure coefficient between grid nodes; V represents the volume, which here refers to the volume of the grid; Indicates the i Reservoir porosity of each grid; For the i The oil phase fluid density of each grid node; For the i Water phase fluid density at each grid node; represents the compressibility coefficient of hydrocarbon phase fluid; Indicates the n The hydrocarbon phase saturation at each moment; represents the compressibility coefficient of aqueous fluid; Indicates the n Water saturation at a certain moment; represents the comprehensive compression factor; For the n +1 moment i Hydrocarbon phase pressure of each grid; g represents the acceleration due to gravity; Indicates the i The grid node and j The adjacent grid depth difference between grid nodes; 、 Grid j The oil phase mobility and water phase mobility; For the n The moment j Oil-water capillary force at each grid node; For the n The moment i Oil-water capillary force at each grid node; For the n The moment i Hydrocarbon phase pressure of each grid; Indicates the time control step of iterative calculation; Indicates the pumping fluid speed.

[0033] The finite volume method is used for spatial discretization and the backward first-order difference method is used for temporal discretization to obtain the mass conservation discrete control equation with water saturation as the solution parameter, namely the water saturation discrete equation, as shown in Equation (13): (13) (14) in, 、 Respectively represent n +1 moment, n At each moment i Water saturation of each grid node; Indicates the i The grid node and j Water phase mobility between grid nodes; Indicates the n +1 moment j Water phase pressure at each grid node; Indicates the n +1 moment i Water phase pressure at each grid node; Indicates the total flow; Indicates the change in water phase pressure of the ith network node at the n+1th moment; Indicates the n +1 moment i The hydrocarbon phase saturation of each grid node. The explanations of other parameters in Equations (13) and (14) can refer to the explanations of various parameters in Equation (12), and will not be repeated here.

[0034] After obtaining the pressure and water saturation discrete equations, the pressure and water saturation discrete equations are solved using the matrix preconditioned stable biconjugate gradient iterative solution method to obtain the pressure distribution field and water saturation distribution field. This achieves the numerical calculation of reservoir water saturation and formation pressure distribution during pumping operations, providing technical support for subsequent hydrocarbon content calculation and further determination of hydrocarbon purity breakthrough time (i.e., hydrocarbon phase breakthrough time). The matrix preconditioned stable biconjugate gradient iterative solution method introduces additional step size parameters and a modified inverse preconditioner to handle the asymmetric matrix linear equation system, improving the convergence speed and numerical stability. In combination with the stable biconjugate gradient iterative solution method, the pressure field value calculated at each time step is used. Combined with the above equations (13) and (14), the calculation of the reservoir water and hydrocarbon phase saturation distribution can be further completed, thereby obtaining the pressure distribution field and water saturation distribution field.

[0035] Step S103 : establishing a hydrocarbon content calculation model for the probe suction port fluid of the wireline formation test based on the pressure distribution field, the water saturation distribution field, and the spherical flow characteristics of the probe node fluid.

[0036] After obtaining the pressure distribution field and the water saturation distribution field, the obtained pressure distribution field and water saturation distribution field can be combined with the spherical flow characteristics of the probe node fluid to establish a probe suction port fluid hydrocarbon content calculation model for wireline formation testing. The probe suction port fluid hydrocarbon content calculation model includes: a fluid water content equation, a fluid water flow equation, a fluid hydrocarbon flow equation, and a fluid hydrocarbon content equation. Specifically, the fluid water content equation is shown in Equation (15), the fluid water flow equation is shown in Equation (16), the fluid hydrocarbon flow equation is shown in Equation (17), and the fluid hydrocarbon content equation is shown in Equation (18): (15) (16) (17) (18) in, f w Indicates the water content of the fluid at the probe; represents the relative permeability of the oil phase; represents the relative permeability of water phase; Indicates the viscosity of oil phase fluid; Indicates the viscosity of the aqueous fluid; 、 and is the relationship between the water saturation distribution field solved by equation (13) as shown in equations (6), (7), and (8); q w Indicates the fluid water flow rate at the probe; Q Indicates the pumping fluid speed; q o Indicates the hydrocarbon flow rate at the probe; f o Indicates the hydrocarbon content of the fluid at the probe.

[0037] The resulting hydrocarbon content calculation model for the probe suction port fluid is essentially a time-dependent function. Based on this model, a curve can be plotted that plots the relationship between hydrocarbon content (i.e., hydrocarbon purity) and pumping time. This curve is referred to as the hydrocarbon content curve. The hydrocarbon content curve can be used to determine the hydrocarbon breakthrough time (i.e., the time when hydrocarbons first appear) during the probe extraction operation, providing a basis for distinguishing oil and gas fluids in different formation types and pumping modes. Specifically, the pumping time at which the hydrocarbon content curve first shows a hydrocarbon content greater than 0 and less than 1 is used as the hydrocarbon appearance time, i.e., the time when the hydrocarbon phase breaks through the probe. This is called the hydrocarbon breakthrough time.

[0038] Step S104 , using the data set and the probe suction port fluid hydrocarbon content calculation model, simulate and calculate the hydrocarbon content curves of oil and gas classifications of the same type of formations, and construct a clustering chart for identifying the fluid properties of the oil and gas reservoirs.

[0039] Among them, the data set and the hydrocarbon content calculation model of the probe suction port fluid can be used to simulate and calculate the hydrocarbon content curve at the preset probe size suction port under the same wellbore and pumping operation parameters under the same type of target formation, and the corresponding hydrocarbon phase breakthrough time can be determined according to the hydrocarbon content curve; then, sample data is formed according to the oil and gas type, hydrocarbon content curve and hydrocarbon phase breakthrough time of the same type of target formation tested by the cable formation, and a sample set is constructed; then, based on the sample set, a clustering plate is constructed through the dynamic time warping algorithm and the hierarchical clustering algorithm; wherein, the clustering plate contains the hydrocarbon content curves of the oil and gas classification of the same type of formation and the boundaries of the hydrocarbon content curves of the oil and gas classification of the same type of formation.

[0040] The data set is used to simulate and calculate the hydrocarbon content curve at the suction port of a certain probe size under the same wellbore and pumping operation parameters in the same type of target formation. The oil and gas type of the same type of formation (or similar formation property data) tested by the wireline formation test, the target formation of the wireline formation test, the wellbore, pumping and fluid property data, its hydrocarbon content curve and hydrocarbon phase breakthrough time are used as sample data. The sample data are used to construct a sample set, which provides a data basis for the construction of a cluster map for identifying the fluid properties of the target formation at the bottom of the wireline formation test well.

[0041] Figure 2 Schematic diagram showing simulation of pumping operation and statistical calculation of hydrocarbon content curves for monitoring under wireline formation testing Figure 1 ,like Figure 2 As shown, the blue curve is the hydrocarbon content curve obtained by simulation calculation based on the relevant data of the cable formation test during pumping operation and the hydrocarbon content calculation model of the probe suction port fluid. The orange data points are obtained through monitoring statistics in the cable formation test. It can be seen that the blue curve and the orange data points have a high degree of fit, indicating that the hydrocarbon content curve obtained by simulation calculation in this application is consistent with the actual change of hydrocarbon content over time and has high accuracy. Figure 2 The hydrocarbon breakthrough time is determined to be 200 seconds, indicating that the reservoir's oil and gas phase is oil-phase (i.e., the oil and gas type is oil-phase). Data such as the target formation, wellbore, pumping, and fluid properties from the wireline formation test, along with the simulated hydrocarbon content curve, hydrocarbon breakthrough time, and oil and gas display information, serve as sample data for subsequent clustering chart construction. The oil and gas display information is used to identify the oil and gas type.

[0042] After completing the construction of the sample set, a clustering chart can be constructed based on the sample set using the dynamic time warping algorithm and the hierarchical clustering algorithm. This provides a data basis for simulating hydrocarbon content curves in subsequent wireline formation test pumping operations and identifying bottomhole reservoir fluid properties based on hydrocarbon phase breakthrough time.

[0043] Hydrocarbon content curves are time series data. To compare the similarity of different hydrocarbon content curves, the present embodiment uses the Dynamic Time Warping (DTW) algorithm to determine curve similarity. DTW is an algorithm used to measure the similarity between two time series and is particularly well-suited for processing time series of varying lengths, velocities, or phases. The core of the DTW algorithm is to find an optimal alignment path through dynamic programming to minimize the cumulative distance between the two series.

[0044] To highlight the difference in breakthrough time, the curves are not scaled on the X-axis. Instead, curves with the same pumping operation time length are intercepted from the hydrocarbon content curves of each sample data in the sample set and used as sample curves to facilitate the calculation of the Euclidean distance between different sample curves using the dynamic time warping algorithm.

[0045] The hierarchical clustering algorithm is a classic unsupervised learning algorithm. Its core is to build a hierarchical clustering structure (similar to a tree diagram) by continuously merging or splitting data clusters (or clusters), and ultimately revealing the inherent hierarchical relationship between data. Unlike algorithms such as K-means that require the number of clusters to be specified in advance, hierarchical clustering does not require the number of clusters to be defined in advance, and the results have intuitive hierarchical interpretability. In an embodiment of the present application, a bottom-up (agglomerative) approach can be used to gradually build a hierarchical structure of clusters. Specifically, starting with each sample data as a separate cluster, the two most similar clusters are continuously merged until all samples are merged into the desired cluster.

[0046] Specifically, a hierarchical clustering algorithm is used to form a single cluster using a single sample curve; the distance of each cluster is calculated using a dynamic time warping algorithm, and a preset number of clusters whose distance is less than a preset distance threshold are selected for merging. The distance strategy is updated based on the merged clusters, and this step is repeated. During the clustering process, pruning operations are performed according to preset pruning decisions until a target cluster for oil and gas classification is obtained by merging; the hydrocarbon content curve corresponding to the target cluster is projected onto a hydrocarbon content curve graph to form a clustering plate, and the boundaries of the hydrocarbon content curves for oil and gas classifications of the same type of formation are determined based on the hydrocarbon content curves corresponding to the target cluster, and the boundaries of the hydrocarbon content curves for oil and gas classifications of the same type of formation are marked on the clustering plate. Those skilled in the art can set the preset distance threshold according to actual needs, and this is not specifically limited here.

[0047] For example, using an agglomerative hierarchical clustering algorithm, each sample curve is formed into a single cluster. The distance between each cluster is calculated using a dynamic time warping algorithm, and the clusters corresponding to the two closest sample curves are selected for merging. Using the nearest neighbor distance strategy for the merged cluster, the above steps are repeated until a single cluster is formed. Furthermore, during the clustering process, pruning operations are performed according to preset pruning decisions, ultimately forming two target clusters for oil and gas classification. The hydrocarbon content curves corresponding to the target clusters are then projected onto a hydrocarbon content curve graph, forming a clustering chart for identifying reservoir fluid properties.

[0048] Figure 3 A schematic diagram of a clustering chart is shown, as shown in Figure 3. The green hydrocarbon content curve is the gas phase hydrocarbon content curve, the red hydrocarbon content curve is the oil phase hydrocarbon content curve, and the dotted line is the boundary of the hydrocarbon content curve of the same type of formation oil and gas classification. Specifically, the green dotted line is the upper boundary of the gas phase hydrocarbon content curve, and the red dotted line is the lower boundary of the oil phase hydrocarbon content curve. Based on the hydrocarbon content curve boundary of the same type of formation oil and gas classification in the clustering chart, the maximum breakthrough time t of the gas phase hydrocarbon content can be extracted. gas_max and the minimum breakthrough time t of oil phase hydrocarbon content oil_minThis provides a basis for the subsequent formulation of identification standards for oil and gas reservoir fluid properties in similar formations through cable formation testing.

[0049] Step S105 : comparing the hydrocarbon phase breakthrough time of the actual formation test operation of the same type of formation to be treated with the clustering chart to identify the fluid properties of the formation to be treated.

[0050] Based on the hydrocarbon content curve boundaries of the oil and gas classification of the same type of formations in the clustering chart, an identification standard for identifying the fluid properties of the oil and gas reservoir based on the hydrocarbon phase breakthrough time of actual formation testing operations can be formulated, so as to predict the oil and gas type of the target formation based on the hydrocarbon phase breakthrough time of the same type of formations, providing a reliable solution for identifying the fluid properties of the bottom hole of the reservoir in wireline formation testing.

[0051] When identifying the fluid properties of a target formation, we collect data from wireline formation testing during pumping operations. Combined with a model for calculating hydrocarbon content in the probe's suction port, we simulate and calculate a hydrocarbon content curve at the probe during pumping operations that matches the actual formation testing. Based on this hydrocarbon content curve, we determine the hydrocarbon phase breakthrough time. Using the established identification criteria, we can then easily identify the fluid properties of the target formation.

[0052] Among them, according to the hydrocarbon content curve boundary of the same type of stratum oil and gas classification in the clustering chart, the maximum breakthrough time of gas phase hydrocarbon content t gas_max and the minimum breakthrough time t of oil phase hydrocarbon content oil_min ; When the hydrocarbon phase breakthrough time is less than the maximum breakthrough time of gas phase hydrocarbon content t gas_max When the hydrocarbon phase breakthrough time is greater than the minimum breakthrough time of oil phase hydrocarbon content t oil_min When the hydrocarbon phase breakthrough time is greater than or equal to the maximum breakthrough time of gas phase hydrocarbon content t gas_max And less than or equal to the minimum breakthrough time t of oil phase hydrocarbon content oil_min When the hydrocarbon phase breakthrough time is in the interval [t gas_max , t oil_min ], it is determined that the fluid properties of the formation to be treated are oil and gas coexisting fluid, that is, oil and gas mixed phase.

[0053] Figure 4 Schematic diagram showing simulation of pumping operation and statistical calculation of hydrocarbon content curves for monitoring under wireline formation testing Figure 2 , if the hydrocarbon content curve is a hydrocarbon content curve obtained by simulation calculation under the wireline formation test for the formation to be treated 1 and is consistent with the actual formation test operation, such as Figure 4 As shown, according to the hydrocarbon content curve, the hydrocarbon phase breakthrough time is determined to be 600s, which is less than the maximum breakthrough time t of gas phase hydrocarbon content.gas_max , then the fluid property of the formation 1 to be treated is identified as gas phase fluid.

[0054] Figure 5 Schematic diagram showing simulation of pumping operation and statistical calculation of hydrocarbon content curves for monitoring under wireline formation testing Figure 3 , if the hydrocarbon content curve is a hydrocarbon content curve obtained by simulation calculation under the wireline formation test for the formation to be treated 2 and is consistent with the actual formation test operation, such as Figure 5 As shown in the figure, the hydrocarbon phase breakthrough time is determined to be 13400s according to the hydrocarbon content curve, which is greater than the minimum breakthrough time t of the oil phase hydrocarbon content. oil_min , then the fluid property of the formation 2 to be treated is identified as oil phase fluid.

[0055] According to the method for identifying the oil and gas phase fluid properties of the bottom hole reservoir provided in the embodiment of the present application, a three-dimensional seepage numerical simulation model for cable formation testing and a hydrocarbon content calculation model for the probe suction port fluid are constructed. Through the dynamic time warping algorithm and the hierarchical clustering algorithm, a clustering plate for identifying the fluid properties of the oil and gas reservoir is constructed, and an identification standard for identifying the fluid properties of the oil and gas reservoir based on the hydrocarbon phase breakthrough time of the actual formation testing operation is formulated. The hydrocarbon phase breakthrough time of the actual formation testing operation of the same type of to-be-treated formation is compared with the clustering plate, which can conveniently and accurately identify the fluid properties of the to-be-treated formation, thereby achieving the goal of identifying the fluid properties of the bottom hole reservoir based on the hydrocarbon phase breakthrough time, and providing a reliable solution and technical means for the identification of the oil and gas phase fluid properties of the underground reservoir in cable formation testing.

[0056] Figure 6 FIG. 1 shows a structural block diagram of a device for identifying oil and gas phase fluid properties in a bottom hole reservoir according to an embodiment of the present application. Figure 6 As shown, the device includes: a collection module 610 , a first construction module 620 , a second construction module 630 , a plate construction module 640 and a recognition module 650 .

[0057] The acquisition module 610 is adapted to acquire relevant data of the wireline formation test during pumping operation to form a data set.

[0058] The first construction module 620 is adapted to construct a three-dimensional seepage numerical simulation model for cable formation testing, discretize and solve the mass conservation equation in the three-dimensional seepage numerical simulation model for cable formation testing, and obtain a pressure distribution field and a water saturation distribution field.

[0059] The second building module 630 is adapted to establish a calculation model for hydrocarbon content in the probe suction port fluid of the wireline formation test based on the pressure distribution field, the water saturation distribution field, and the spherical flow characteristics of the probe node fluid.

[0060] The chart construction module 640 is adapted to: utilize the data set and the probe suction port fluid hydrocarbon content calculation model to simulate and calculate hydrocarbon content curves of oil and gas classifications of the same type of formations, and construct a clustering chart for identifying fluid properties of oil and gas reservoirs.

[0061] The identification module 650 is adapted to compare the hydrocarbon phase breakthrough time of actual formation test operations of the same type of to-be-treated formation with the clustering chart to identify the fluid properties of the to-be-treated formation.

[0062] Optionally, the three-dimensional seepage numerical simulation model of cable formation testing is used to simulate the water saturation and formation pressure distribution of the near-wellbore reservoir during the pumping process; the three-dimensional seepage numerical simulation model of cable formation testing includes: model assumptions, mass conservation equations, boundary conditions, initial conditions and auxiliary equations; the probe suction port fluid hydrocarbon content calculation model includes: fluid water content equation, fluid water flow equation, fluid hydrocarbon flow equation and fluid hydrocarbon content equation.

[0063] Optionally, the first construction module 620 is further adapted to: discretize the mass conservation equation using the finite volume method to obtain a pressure discrete equation and a water saturation discrete equation; solve the pressure discrete equation and the water saturation discrete equation using an iterative solution method of matrix preprocessing stabilized biconjugate gradients to obtain a pressure distribution field and a water saturation distribution field.

[0064] Optionally, the map construction module 640 is further suitable for: using the data set and the probe suction port fluid hydrocarbon content calculation model to simulate and calculate the hydrocarbon content curve at the preset probe size suction port when the same wellbore and pumping operation parameters are under the same type of target formation, and determine the corresponding hydrocarbon phase breakthrough time based on the hydrocarbon content curve; forming sample data based on the oil and gas type, hydrocarbon content curve and hydrocarbon phase breakthrough time of the same type of target formation tested by the cable formation, and constructing a sample set; based on the sample set, constructing a clustering map through the dynamic time warping algorithm and the hierarchical clustering algorithm; wherein the clustering map contains the hydrocarbon content curves of the oil and gas classification of the same type of formation and the boundaries of the hydrocarbon content curves of the oil and gas classification of the same type of formation.

[0065] Optionally, the map construction module 640 is further adapted to: intercepting a curve of the same pumping operation time length from the hydrocarbon content curve of each sample data in the sample set as a sample curve; forming a single cluster using a single sample curve through a hierarchical clustering algorithm; calculating the distance of each cluster through a dynamic time warping algorithm, and selecting a preset number of clusters with similar distances to merge, updating the distance strategy through the merged clusters, repeating this step, and performing pruning operations according to preset pruning decisions during the clustering process until a target cluster for oil and gas classification is obtained through merging; projecting the hydrocarbon content curve corresponding to the target cluster onto the hydrocarbon content curve diagram to form a cluster map, and determining the boundaries of the hydrocarbon content curves of the same type of formation oil and gas classification based on the hydrocarbon content curve corresponding to the target cluster, and marking the boundaries of the hydrocarbon content curves of the same type of formation oil and gas classification in the cluster map.

[0066] Optionally, the identification module 650 is further adapted to: extract the maximum breakthrough time of gas phase hydrocarbon content and the minimum breakthrough time of oil phase hydrocarbon content based on the hydrocarbon content curve boundary of the same type of formation oil and gas classification in the clustering plate; when the hydrocarbon phase breakthrough time is less than the maximum breakthrough time of gas phase hydrocarbon content, determine that the fluid property of the formation to be treated is gas phase fluid; when the hydrocarbon phase breakthrough time is greater than the minimum breakthrough time of oil phase hydrocarbon content, determine that the fluid property of the formation to be treated is oil phase fluid; when the hydrocarbon phase breakthrough time is greater than or equal to the maximum breakthrough time of gas phase hydrocarbon content and less than or equal to the minimum breakthrough time of oil phase hydrocarbon content, determine that the fluid property of the formation to be treated is oil and gas coexisting fluid.

[0067] According to the device for identifying the oil and gas phase fluid properties of the bottom hole reservoir provided in the embodiment of the present application, a three-dimensional seepage numerical simulation model for cable formation testing and a hydrocarbon content calculation model for the probe suction port fluid are constructed. Through the dynamic time warping algorithm and the hierarchical clustering algorithm, a clustering map for identifying the fluid properties of the oil and gas reservoir is constructed, and an identification standard for identifying the fluid properties of the oil and gas reservoir based on the hydrocarbon phase breakthrough time of the actual formation testing operation is formulated. The hydrocarbon phase breakthrough time of the actual formation testing operation of the same type of to-be-treated formation is compared with the clustering map, so that the fluid properties of the to-be-treated formation can be identified conveniently and accurately, achieving the goal of identifying the fluid properties of the bottom hole reservoir based on the hydrocarbon phase breakthrough time, and providing a reliable solution and technical means for the identification of the oil and gas phase fluid properties of the underground reservoir in cable formation testing.

[0068] The present invention also provides a non-volatile computer storage medium storing at least one executable instruction, which can execute the method for identifying the oil and gas phase fluid properties of the bottom hole reservoir in any of the above method embodiments.

[0069] An embodiment of the present invention provides a computer program product, which includes at least one executable instruction or computer program, which enables a processor to perform operations corresponding to the method for identifying oil and gas phase fluid properties in the bottom hole reservoir in any of the above-mentioned method embodiments.

[0070] Figure 7 A schematic structural diagram of a computing device according to an embodiment of the present application is shown. The specific embodiment of the present application does not limit the specific implementation of the computing device.

[0071] like Figure 7 As shown, the computing device may include a processor 702 , a communication interface 704 , a memory 706 , and a communication bus 708 .

[0072] Processor 702, communication interface 704, and memory 706 communicate with each other via communication bus 708. Communication interface 704 is used to communicate with other devices, such as client devices or other server network elements. Processor 702 is used to execute program 710, which may specifically perform the steps described in the embodiment of the method for identifying oil and gas phase fluid properties in a bottom hole reservoir for a computing device.

[0073] Specifically, the program 710 may include program codes, which include computer operation instructions.

[0074] Processor 702 may be a central processing unit (CPU), an application-specific integrated circuit (ASIC), or one or more integrated circuits configured to implement the embodiments of the present application. The one or more processors included in a computing device may be processors of the same type, such as one or more CPUs, or processors of different types, such as one or more CPUs and one or more ASICs.

[0075] The memory 706 is used to store the program 710. The memory 706 may include a high-speed RAM memory, and may also include a non-volatile memory (non-volatile memory), such as at least one disk storage.

[0076] Program 710 can specifically be used to cause processor 702 to execute the method for identifying oil and gas phase fluid properties in a bottom hole reservoir described in any of the above-described method embodiments. The specific implementation of each step in program 710 can be found in the corresponding descriptions of the corresponding steps and units in the above-described methods for identifying oil and gas phase fluid properties in a bottom hole reservoir, and will not be repeated here. Those skilled in the art will clearly understand that, for ease and brevity of description, the specific operating processes of the devices and modules described above can refer to the corresponding process descriptions in the above-described method embodiments, and will not be repeated here.

[0077] The algorithm and display provided herein are not inherently related to any particular computer, virtual system or other device. Various general-purpose systems can also be used together with the teachings based on this. According to the above description, it is obvious that the structure required for constructing this type of system. In addition, the present invention is not directed to any specific programming language. It should be understood that various programming languages ​​can be utilized to realize the content of the present invention described herein, and the above description of specific languages ​​is for the purpose of disclosing the best mode of the present invention.

[0078] In the description provided herein, numerous specific details are described. However, it is understood that embodiments of the present invention may be practiced without these specific details. In some instances, well-known methods, structures, and techniques are not shown in detail so as not to obscure the understanding of this description.

[0079] Similarly, it should be understood that in order to streamline the present disclosure and aid understanding of one or more of the various inventive aspects, in the above description of exemplary embodiments of the invention, various features of the invention are sometimes grouped together into a single embodiment, figure, or description thereof. However, this disclosed method should not be interpreted as reflecting an intention that the claimed invention requires more features than are expressly recited in each claim. Rather, as reflected in the claims, inventive aspects lie in less than all the features of the individual embodiments disclosed above. Accordingly, the claims that follow the detailed description are hereby expressly incorporated into this detailed description, with each claim standing on its own as a separate embodiment of the invention.

[0080] Those skilled in the art will appreciate that the modules in the devices of the embodiments can be adaptively modified and installed in one or more devices different from the embodiments. The modules, units, or components in the embodiments can be combined into a single module, unit, or component, and furthermore, they can be divided into multiple sub-modules, sub-units, or sub-components. All features disclosed in this specification (including the accompanying claims, abstract, and drawings), and all processes or units of any method or device disclosed therein, can be combined in any combination, unless at least some of such features and / or processes or units are mutually exclusive. Unless expressly stated otherwise, each feature disclosed in this specification (including the accompanying claims, abstract, and drawings) may be replaced by an alternative feature that serves the same, equivalent, or similar purpose.

[0081] Furthermore, those skilled in the art will appreciate that although some embodiments described herein include certain features included in other embodiments but not other features, combinations of features from different embodiments are intended to be within the scope of the present invention and to form different embodiments. For example, in the claims, any of the claimed embodiments may be used in any combination.

[0082] The various component embodiments of the present invention may be implemented in hardware, as software modules running on one or more processors, or as a combination thereof. Those skilled in the art will appreciate that, in practice, a microprocessor or digital signal processor (DSP) may be used to implement some or all of the functionality of some or all of the components according to the embodiments of the present invention. The present invention may also be implemented as an apparatus or device program (e.g., a computer program or computer program product) for performing part or all of the methods described herein. Such a program implementing the present invention may be stored on a computer-readable medium or in the form of one or more signals. Such signals may be downloaded from an Internet website, provided on a carrier signal, or provided in any other form.

[0083] It should be noted that the above embodiments illustrate rather than limit the invention, and that those skilled in the art may devise alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between brackets should not be construed as limiting the claims. The word "comprising" does not exclude the presence of elements or steps not listed in the claims. The word "a" or "an" preceding an element does not exclude the presence of a plurality of such elements. The present invention may be implemented by means of hardware comprising several different elements and by means of appropriately programmed computers. In a unit claim enumerating several means, several of these means may be embodied by the same item of hardware. The use of the words first, second, and third etc. does not indicate any order. These words may be interpreted as names.

Claims

1. A method for identifying the properties of oil and gas phase fluid in a bottom hole reservoir, characterized in that: The method comprises: Collect relevant data from cable formation testing during pumping operations to form a data set; Constructing a three-dimensional seepage numerical simulation model for cable formation testing, discretizing and solving a mass conservation equation in the three-dimensional seepage numerical simulation model for cable formation testing, and obtaining a pressure distribution field and a water saturation distribution field; Based on the pressure distribution field, water saturation distribution field and the spherical flow characteristics of the probe node fluid, a calculation model for hydrocarbon content in the probe suction port of wireline formation testing is established; Using the data set and the probe suction port fluid hydrocarbon content calculation model, the hydrocarbon content curves of oil and gas classifications of the same type of formations are simulated and calculated to construct a clustering chart for identifying the properties of oil and gas reservoir fluids; Comparing the hydrocarbon phase breakthrough time of actual formation testing operations of the same type of formation to be treated with the cluster map to identify the fluid properties of the formation to be treated; The method of using the data set and the probe suction port fluid hydrocarbon content calculation model to simulate and calculate hydrocarbon content curves of oil and gas classifications of the same type of formations and constructing a clustering chart for identifying fluid properties of oil and gas reservoirs further includes: Using the data set and the hydrocarbon content calculation model for the probe suction port fluid, simulate and calculate a hydrocarbon content curve at a preset probe suction port under the same wellbore and pumping operation parameters in the same type of target formation, and determine a corresponding hydrocarbon phase breakthrough time based on the hydrocarbon content curve; Generating sample data based on the oil and gas type of the same type of target formation tested by the wireline formation test, the hydrocarbon content curve, and the hydrocarbon phase breakthrough time to construct a sample set; Based on the sample set, the clustering map is constructed by a dynamic time warping algorithm and a hierarchical clustering algorithm; wherein the clustering map includes hydrocarbon content curves of the same type of formation oil and gas classification and hydrocarbon content curve boundaries of the same type of formation oil and gas classification.

2. The method for identifying the properties of oil and gas phase fluid in a bottom hole reservoir according to claim 1, characterized in that: The three-dimensional seepage numerical simulation model of the wireline formation test is used to simulate the water saturation and formation pressure distribution of the near-wellbore reservoir during the pumping process; The three-dimensional seepage numerical simulation model for cable formation testing includes: model assumptions, mass conservation equations, boundary conditions, initial conditions and auxiliary equations; The probe suction port fluid hydrocarbon content calculation model includes: a fluid water content equation, a fluid water flow equation, a fluid hydrocarbon flow equation and a fluid hydrocarbon content equation.

3. The method for identifying the properties of oil and gas phase fluid in a bottom hole reservoir according to claim 1, characterized in that: The discretizing and solving the mass conservation equation in the three-dimensional seepage numerical simulation model of the cable formation test to obtain the pressure distribution field and the water saturation distribution field further includes: The mass conservation equation is discretized using the finite volume method to obtain a pressure discrete equation and a water saturation discrete equation; The pressure discrete equation and the water saturation discrete equation are solved by an iterative solution method of matrix preprocessing stabilized biconjugate gradient to obtain the pressure distribution field and the water saturation distribution field.

4. The method for identifying the properties of oil and gas phase fluid in a bottom hole reservoir according to claim 1, characterized in that: The step of constructing the clustering map based on the sample set by using a dynamic time warping algorithm and a hierarchical clustering algorithm further includes: intercepting a curve with the same pumping operation time length from the hydrocarbon content curve of each sample data in the sample set as a sample curve; A hierarchical clustering algorithm is used to form a single cluster using a single sample curve. The distance of each cluster is calculated using a dynamic time warping algorithm, and a preset number of clusters with distances less than a preset distance threshold are selected for merging. The distance strategy is updated based on the merged clusters, and this step is repeated. During the clustering process, pruning operations are performed according to the preset pruning decision until the target cluster for oil and gas classification is obtained. The hydrocarbon content curve classification corresponding to the target cluster is projected onto the hydrocarbon content curve diagram to form a clustering plate, and the hydrocarbon content curve boundaries of the same type of formation oil and gas classification are determined based on the hydrocarbon content curve corresponding to the target cluster, and the hydrocarbon content curve boundaries of the same type of formation oil and gas classification are marked on the clustering plate.

5. The method for identifying the properties of oil and gas phase fluid in a bottom hole reservoir according to any one of claims 1 to 4, characterized in that: The comparing the hydrocarbon phase breakthrough time of the actual formation test operation of the same type of formation to be treated with the cluster map to identify the fluid properties of the formation to be treated further includes: Extracting the maximum breakthrough time of gas phase hydrocarbon content and the minimum breakthrough time of oil phase hydrocarbon content based on the hydrocarbon content curve boundary of the same type of stratum oil and gas classification in the clustering chart; When the hydrocarbon phase breakthrough time is less than the maximum breakthrough time of the gas phase hydrocarbon content, determining that the fluid property of the to-be-treated formation is gas phase fluid; When the hydrocarbon phase breakthrough time is greater than the minimum breakthrough time of the oil phase hydrocarbon content, determining that the fluid property of the to-be-treated formation is oil phase fluid; When the hydrocarbon phase breakthrough time is greater than or equal to the maximum breakthrough time of the gas phase hydrocarbon content and less than or equal to the minimum breakthrough time of the oil phase hydrocarbon content, the fluid property of the to-be-treated formation is determined to be an oil-gas coexisting fluid.

6. A device for identifying the properties of oil and gas phase fluids in a bottom hole reservoir, characterized in that: The device comprises: An acquisition module, suitable for collecting relevant data of cable formation testing during pumping operations to form a data set; The first construction module is adapted to construct a three-dimensional seepage numerical simulation model for cable formation testing, discretize and solve the mass conservation equation in the three-dimensional seepage numerical simulation model for cable formation testing, and obtain a pressure distribution field and a water saturation distribution field; The second building module is adapted to establish a calculation model for hydrocarbon content in the probe suction port fluid of the wireline formation test based on the pressure distribution field, the water saturation distribution field, and the spherical flow characteristics of the fluid at the probe node; a chart construction module adapted to utilize the data set and the probe suction port fluid hydrocarbon content calculation model to simulate and calculate hydrocarbon content curves of oil and gas classifications of the same type of formations, and to construct a clustering chart for identifying fluid properties of oil and gas reservoirs; an identification module adapted to compare the hydrocarbon phase breakthrough time of actual formation test operations of the same type of formation to be treated with the clustering chart to identify the fluid properties of the formation to be treated; Wherein, the plate construction module is further adapted to: Using the data set and the hydrocarbon content calculation model for the probe suction port fluid, simulate and calculate a hydrocarbon content curve at a preset probe suction port under the same wellbore and pumping operation parameters in the same type of target formation, and determine a corresponding hydrocarbon phase breakthrough time based on the hydrocarbon content curve; Generating sample data based on the oil and gas type of the same type of target formation tested by the wireline formation test, the hydrocarbon content curve, and the hydrocarbon phase breakthrough time to construct a sample set; Based on the sample set, the clustering map is constructed by a dynamic time warping algorithm and a hierarchical clustering algorithm; wherein the clustering map includes hydrocarbon content curves of the same type of formation oil and gas classification and hydrocarbon content curve boundaries of the same type of formation oil and gas classification.

7. A computing device, characterized in that include: A processor, a memory, a communication interface, and a communication bus, wherein the processor, the memory, and the communication interface communicate with each other via the communication bus; The memory is used to store at least one executable instruction, and the executable instruction enables the processor to perform operations corresponding to the method for identifying oil and gas phase fluid properties in a bottom hole reservoir according to any one of claims 1 to 5.

8. A computer storage medium, characterized in that The computer storage medium stores at least one executable instruction, which enables the processor to perform operations corresponding to the method for identifying oil and gas phase fluid properties in a bottom hole reservoir according to any one of claims 1 to 5.

9. A computer program product, characterized in that The method comprises at least one executable instruction, wherein the executable instruction enables the processor to execute operations corresponding to the method for identifying oil and gas phase fluid properties in a bottom hole reservoir as described in any one of claims 1 to 5.

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