A method and apparatus for predicting oil well productivity after multi-scale plugging.

Abstract

This application provides a method, apparatus, processor, and storage medium for predicting the production capacity of an oil well after multi-scale plugging. The method includes: dividing the plugged high-water-cut fractured vertical well into multiple seepage zones, including a first seepage zone and a second seepage zone; determining the permeability k2 and porosity φ2 of the second seepage zone at the current time step after plugging; determining the basic seepage relationship for each seepage zone based on boundary conditions to determine the oil phase pseudo-pressure value and production capacity of each seepage zone in Laplace space at the current time step; determining the initial average pressure value p0; and determining the oil saturation S of the plugged high-water-cut fractured vertical well at the next time step. no And determine the permeability k n Based on the oil saturation S at the next time step no The oil phase pseudo-pressure value m1 of the main fracture zone in the first seepage zone at the next time step predicts the well production of the plugged well at the next time step.

Description

Technical Field

[0001] This application relates to the field of oilfield development technology, specifically to a method and apparatus for predicting the production capacity of oil wells after multi-scale plugging. Background Technology

[0002] Ultra-low permeability reservoirs often have well-developed natural fractures, which are then connected by hydraulic fracturing. Due to severe formation heterogeneity, varying oil-water mobility ratios, and inappropriate development plans and measures, sudden water flooding is common during water injection, reducing oilfield recovery. However, the recoverable reserves remain substantial, necessitating water shut-off in high-water-cut fracturing wells. While there is considerable research on plugging agents for water shut-off, the migration patterns of multi-scale plugging agents within the reservoir remain unclear, and the productivity evaluation of fracturing wells after water shut-off still faces challenges.

[0003] Currently, the main method for evaluating plugging agent migration patterns and post-plugging reservoir properties is direct laboratory measurement. While this method can measure the changes in porosity and permeability with location through sand-packed pipes, a quantitative mathematical model describing the relationship between post-plugging porosity and permeability and plugging agent migration distance has not yet been established. Furthermore, the method for evaluating post-plugging productivity in ultra-low permeability fracturing wells remains unclear. Therefore, existing technologies for obtaining post-plugging plugging agent migration patterns in high water-cut fracturing wells are limited in scope, lack quantitative description capabilities, and pose difficulties for post-plugging productivity evaluation. Summary of the Invention

[0004] The purpose of this application is to provide a method, apparatus, and processor for predicting the production capacity of oil wells after multi-scale plugging.

[0005] To achieve the above objectives, the first aspect of this application provides a method for predicting the productivity of oil wells after multi-scale plugging, comprising:

[0006] The sealed high water-cut fractured vertical well is divided into multiple seepage zones, including a first seepage zone and a second seepage zone;

[0007] Determine the permeability k2 and porosity φ2 at the current time step after the second seepage zone is blocked;

[0008] Based on the boundary conditions, the basic seepage relationship for each seepage region is determined, thereby identifying the oil phase pseudo-pressure value in Laplace space for each seepage region at the current time step. and output;

[0009] Determine the initial mean pressure value p0 for each seepage zone after closure at the next time step;

[0010] The oil saturation S of the high water-cut fractured vertical well after plugging is determined based on the initial average pressure value p0 of the next time step. noAnd determine the permeability k of each first seepage region in the next time step. n ;

[0011] Based on the oil saturation S at the next time step no The oil phase pseudo-pressure value m1 of the main fracture region in the first seepage zone at the next time step is used to predict the oil well production at the next time step after plugging.

[0012] A second aspect of this application provides a processor configured to perform the above-described method for predicting the productivity of an oil well after multi-scale plugging.

[0013] A third aspect of this application provides a device for predicting the productivity of an oil well after multi-scale plugging, including the processor described above.

[0014] A fourth aspect of this application provides a machine-readable storage medium storing instructions that, when executed by a processor, configure the processor to perform the aforementioned method for predicting the productivity of an oil well after multi-scale plugging.

[0015] The above-mentioned method for predicting the production capacity of oil wells after plugging with multi-scale plugging agents is based on physical model experiments. It can quickly evaluate the multi-scale migration law of plugging agents, characterize the reservoir attribute parameters after plugging, and quickly evaluate the production capacity of heterogeneous reservoirs after plugging, saving a lot of time. Moreover, it is more accurate in predicting the production capacity of oil wells after plugging.

[0016] Other features and advantages of the embodiments of this application will be described in detail in the following detailed description section. Attached Figure Description

[0017] The accompanying drawings are provided to further illustrate the embodiments of this application and form part of the specification. They are used together with the following detailed description to explain the embodiments of this application, but do not constitute a limitation on the embodiments of this application. In the drawings:

[0018] Figure 1 The schematic diagram illustrates a process flow diagram of a method for predicting oil well productivity after multi-scale plugging according to an embodiment of this application;

[0019] Figure 2 A schematic three-dimensional diagram of a four-zone seepage model according to an embodiment of this application is shown.

[0020] Figure 3 This illustration schematically shows a diagram illustrating the division of four seepage zones according to an embodiment of this application;

[0021] Figure 4 The diagram illustrates the relationship between permeability and porosity as a function of location according to embodiments of this application. Figure 1 ;

[0022] Figure 5 The diagram illustrates the relationship between permeability and porosity as a function of location according to embodiments of this application. Figure 2 ;

[0023] Figure 6 The diagram illustrates the internal structure of a computer device according to an embodiment of this application. Detailed Implementation

[0024] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are only for illustration and explanation of the embodiments of this application and are not intended to limit the embodiments of this application. All other embodiments obtained by those skilled in the art based on the embodiments of this application without creative effort are within the scope of protection of this application.

[0025] Figure 1 This illustration schematically depicts a flowchart of a method for predicting oil well productivity after multi-scale plugging according to an embodiment of this application. Figure 1 As shown in one embodiment of this application, a method for predicting the productivity of an oil well after multi-scale plugging is provided, comprising the following steps:

[0026] Step 101: Divide the sealed high water-cut fractured vertical well into multiple seepage zones, including a first seepage zone and a second seepage zone.

[0027] Step 102: Determine the permeability k2 and porosity φ2 at the current time step after the second seepage zone is blocked.

[0028] Step 103: Determine the basic seepage relationship for each seepage region based on the boundary conditions, so as to determine the oil phase pseudo-pressure value in the Laplace space for each seepage region at the current time step. and output.

[0029] Step 104: Determine the initial average pressure value p0 for each seepage zone after closure at the next time step.

[0030] Step 105: Determine the oil saturation S of the high water-cut fractured vertical well after plugging in the next time step based on the initial average pressure value p0 of the next time step. no And determine the permeability k of each first seepage region in the next time step. n .

[0031] Step 106, based on the oil saturation S in the next time step noThe oil phase pseudo-pressure value m1 of the main fracture zone in the first seepage zone at the next time step predicts the well production of the plugged well at the next time step.

[0032] The multi-scale well productivity prediction method proposed in this application is for high water-cut fractured vertical wells. After plugging, due to the plugging of the near-wellbore reservoir, water drive occurs around the well, mainly extracting untapped crude oil. The seepage area is divided into four zones, thus establishing a four-zone seepage model, the three-dimensional schematic diagram of which is shown below. Figure 2 As shown. Since the oil-water seepage is completely symmetrical, we can take 1 / 4 of the model as the research object, such as... Figure 3 The diagram shows oil-water two-phase flow. A high-water-cut fractured vertical well after plugging can be divided into multiple seepage zones, including a first seepage zone and a second seepage zone. Specifically, according to... Figure 3 It can be seen that, Figure 3 It includes four seepage zones: Zone 1, Zone 2, Zone 3, and Zone 4. The first seepage zone comprises Zones 1, 3, and 4, while Zone 2 is the second seepage zone. Further, Zone 1 is the main fracture zone, Zone 2 is the area formed by the plugging agent perpendicular to the main fracture zone, Zone 3 is the area from the farthest point of the main fracture zone to half the well distance, and Zone 4 is the area from the second seepage zone to the outlet distance. It is understood that this is done for the sake of simplicity. Figure 3 The text describes each seepage region as a regular rectangle, but in real-world scenarios, seepage regions are not like that. Figure 3 The rules for the area shown will not be elaborated upon here.

[0033] This method combines the migration patterns of multi-scale plugging agents in the reservoir after injection and proposes a reservoir parameter characterization method based on fractal diffusion theory for non-uniform plugging with multi-scale plugging agents. By combining experimentally measured relationships between porosity, permeability, and sand-filled pipe depth, the changes in porosity and permeability after plugging can be fitted to obtain characterization parameters. Specifically, firstly, a mathematical model characterizing the reservoir properties after plugging in high water-cut fracturing wells can be established based on the experimentally obtained relationships between permeability and porosity changes with location after multi-scale plugging agent injection. The Warren & Root dual-medium model is used to describe the fracture distribution in the fracturing zone. Experiments are conducted to obtain the migration patterns of micron-sized particles and gel plugging agents in the matrix and natural fractures. Experimental results show that micron-sized injected porous media (matrix) easily plugs at the injection end, while its deep porosity changes are not significant; gel easily plugs at the injection end, and its migration distance is much smaller than that of micron-sized particles, resulting in better plugging effects near the hydraulic fracture zone, with lower permeability. The experimental process aims to analyze the migration patterns of micron-sized particles in porous media and obtain the relationships between their permeability, porosity, and location.

[0034] Based on experimental results, fractal theory can be used to describe the heterogeneity of reservoir properties after plugging. Specifically, after multi-scale non-uniform plugging of high water-cut fracturing wells, the reservoir permeability and porosity are functions of the distance from the hydraulic fracture, meaning the reservoir permeability after plugging is related to the degree of connectivity. The permeability of the fracture network is calculated using the connectivity index θ and the fractal dimension D. In this embodiment, the permeability k2 and porosity φ2 at the current time step after plugging the second seepage zone can be calculated using the following formulas (1) and (2):

[0035]

[0036]

[0037] k0 is the permeability at the current time step before the second seepage zone is sealed, k2 is the permeability at the current time step after the second seepage zone is sealed, and y f φ is the length of the plugging agent perpendicular to the main fracture direction, i.e., the distance of the plugging agent migration; y is the variable of the distance from the hydraulic fracture; D is the fractal dimension; θ is the connectivity index; φ0 is the porosity at the current time step before the second seepage zone is plugged; and φ2 is the porosity at the current time step after the second seepage zone is plugged.

[0038] Since the permeability and porosity decrease the closer to the hydraulic fracture after plugging, they increase with distance. Using the permeability and porosity before plugging as initial values, and combining experiments, we can obtain curves showing the relationship between permeability and porosity and location, such as... Figure 4 and Figure 5 As shown.

[0039] Since regions 3 and 4 supply fluid to region 2 after the high water-cut fracturing vertical well is plugged, the pressure and fluid velocity at the interface of these three regions are equal. Simultaneously, region 2 supplies fluid to region 1, so the pressure and fluid velocity at the interface of region 2 and region 1 are equal. These two conditions constitute the boundary conditions. Therefore, based on these boundary conditions, the basic seepage relationship for each seepage region can be determined. Assuming the fluid in the region is an elastic porous incompressible fluid, then the porosity φ of seepage region n... n =φ0+C f (p n -p0), i.e., the first relation. Where φ0 is the porosity at the current time step before plugging, corresponding to each seepage region, and C f p is the compressibility coefficient of the rock. n The pressure value at the current time step after the seepage region n is sealed, via p n The average pressure of the region can be obtained, where p0 is the initial pressure value of the reservoir at the current time step. Furthermore, the pseudo-pressure value m of the oil phase can be defined. That is, the second relation. Where, ko =k n k nro k nro Let k be the relative permeability of the oil phase in the seepage region n at the current time step, where n = 1, 2, 3, 4. n Let m be the permeability of the seepage region n after it has been sealed at the current time step. n Let μ be the pseudo-pressure of the oil phase in the seepage region n. o B represents the viscosity of crude oil. o This is the volume coefficient of crude oil.

[0040] Furthermore, in one embodiment, after determining the permeability k2 and porosity φ2 at the current time step after the second seepage region is sealed, the basic seepage relationship for each seepage region can be determined based on the boundary conditions to determine the oil phase pseudo-pressure value in the Laplace space for each seepage region at the current time step. And output q.

[0041] The basic seepage equation for region 4 is formula (5):

[0042]

[0043] The basic seepage equation for region 3 is formula (6):

[0044]

[0045] Before sealing, the modified zone is a dual-medium model. After hydraulic fracturing, not only is a fracture formed, but it also connects to the natural fractures in the reservoir, forming a fracture network. This part forming the fracture network can be characterized using a common dual-medium model. Fluids from the bedrock flow into the fractures and then into the hydraulic fractures through the fracture network. That is, there are two media in the modified zone: matrix and fractures. The matrix is ​​the storage space, and the fractures are the flow channels. The flow equation in the fractures needs to include source and sink terms. The sink is the flow rate from the matrix. For the bedrock system, it satisfies the following formula:

[0046]

[0047] Where q″ is the mass flow rate per unit volume, representing the fluid mass exchange between the bedrock and the fracture system, ρ is the density of the crude oil, and v n Let B be the flow velocity of the liquid within the seepage region n. o Let be the volume coefficient of crude oil. For fractured systems, it satisfies the following formula:

[0048]

[0049] This method considers the channeling to be quasi-steady-state, meaning the pressure inside the matrix rock block is equal everywhere. For region 2, Where, pm p1 is the pressure value in the matrix of region 2, and p2 is the pressure value in the crack of region 2. Furthermore, After plugging, due to the non-uniform plugging of the multi-scale plugging agent, the permeability and porosity exhibit heterogeneity. Based on the fractal theory characterization model of permeability and porosity using formulas (1) and (2), the basic seepage equation for region 2 can be established, as shown in formula (7):

[0050]

[0051] The basic seepage equation for region 1 is formula (8):

[0052]

[0053] Where, p m p1 is the pressure value in the matrix of region 2, p2 is the pressure value in the crack of region 2, and p3 is the pressure value in region 3.

[0054] To simplify and homogenize the basic seepage equations for each seepage region, the following second relationship can be defined, namely, defining the pseudo-pressure of the oil phase. Where, k o =k n k nro Therefore, the basic seepage equations for each seepage region are substituted into formula (3): φ n =φ0+C f (p n -p0) can then define Therefore, the basic seepage equations for each seepage region can be transformed using the second relationship described above and substituted into the formula above. Then, by performing a Laplace transformation, the seepage equation for region 4 can be obtained as follows:

[0055] The seepage equation for region 3 is obtained as follows: The seepage equation for region 2 is obtained as follows:

[0056]

[0057] The seepage equation for region 1 is obtained as follows:

[0058]

[0059] Furthermore, in one embodiment, the fundamental seepage equations for all seepage regions can be solved to calculate the oil-phase pseudo-pressure value for each seepage region in the Laplace space at the next time step. Specifically, This refers to the oil phase pseudo-pressure value of region 4 at the next time step, C. 41 and C 42 Let be a coefficient, and be a general solution whose value can be determined based on the boundary conditions. Substituting the boundary conditions above and simplifying, we obtain the pressure derivative solution for region 4:

[0060]

[0061] Where F4 is the equation symbol,

[0062] Similarly, the oil phase pseudo-pressure value of region 3 in the next time step can be calculated. C 31 and C 32 Let be a coefficient, and be a general solution whose value can be determined based on the boundary conditions. Substituting the boundary conditions above and simplifying, we obtain the pressure derivative solution for region 3:

[0063]

[0064] Where F3 is the equation symbol,

[0065] Calculate the pseudo-pressure value of the oil phase in region 2 at the next time step.

[0066] Where A2 is a coefficient, which can be obtained using boundary conditions. The first type of imaginary argument Bessel function can be called directly. B2 is a coefficient that can be obtained using boundary conditions. Substituting the boundary conditions above and simplifying, we can obtain the pressure derivative solution for region 2:

[0067] Where F2 is the equation symbol, and its expression is shown in the following formula (12):

[0068]

[0069] Where α = -(D-2), β = -(D-2-θ), D is the fractal dimension, and θ is the connectivity index. and These are parameters obtained directly through boundary condition simplification. as well as These are Bessel functions of the first and second kind of imaginary arguments, respectively, and n, g1, and g2 are all equation symbols.

[0070] The expressions for g1, g2, and n are shown in formulas (13), (14), and (15) below, respectively:

[0071]

[0072]

[0073]

[0074] F3 is also an equation symbol, and its expression is shown in the following formula:

[0075]

[0076] y -θ μ is the intermediate quantity after transformation and simplification. o y represents the viscosity of crude oil. f x represents the sealing length of the sealant perpendicular to the main joint direction, i.e., the distance the sealant travels. f Half length of the main crack region, x e It is half the well spacing. C f The coefficient of rock compression. This represents the porosity of the seepage region n at the current time step after it has been sealed.

[0077] Calculate the oil phase pseudo-pressure value of region 1 at the next time step. in, F2 is the equation symbol, r is the wellbore radius, and A1 is the coefficient, which is obtained using boundary conditions. This is a Bessel function for a first-kind imaginary argument, which can be called directly. B1 represents the coefficients, which are obtained using boundary conditions. This is a Bessel function for the second type of virtual argument, which can be called directly. no Let k be the oil saturation of the high water-cut fractured vertical well after plugging at the next time step, and k1 be the permeability of region 1 at the next time step. 1ro w represents the relative permeability of the oil phase in the second seepage region at the current time step. f The width of the main crack area;

[0078] Furthermore, in one embodiment, the hydraulic fracture is an infinitely conductive flow, therefore the pseudo-pressure at the bottom of the well is... Approximately equal to The relationship between bottomhole flowing pressure under constant production conditions and well production under constant pressure conditions within the pull-type space is shown in formula (10):

[0079]

[0080] Specifically, in this embodiment, based on the oil saturation S at the next time step noThe oil phase pseudo-pressure value m1 of the main fracture region in the first seepage zone at the next time step is used to predict the well production of the plugged well at the next time step, including: calculating the well production of the plugged well in the Laplace space at the next time step according to formula (10). Oil well production A Stehfest numerical inversion is performed to obtain the well production q at the next time step after plugging. That is, in calculating... Afterwards, a Stehfest numerical inversion can be performed to obtain the true space solution, that is, to find the well production q of the well after plugging in the next time step.

[0081] Furthermore, in the production of fracturing wells after multi-scale non-uniform plugging, one day is considered one time step, and there are a total of n time steps. The average oil saturation and average formation pressure of the k-th time step can be obtained from the parameters of the (k-1)-th time step, that is, they can be obtained from the flow material balance equation (9). In this way, the production capacity of the k-th time step can be obtained, and the model parameters can be continuously updated and iterated to predict the production capacity of fracturing wells after multi-scale non-uniform plugging. In this embodiment, the oil saturation S of the high water-cut fracturing vertical well after plugging in the next time step is determined. no This includes calculating the oil saturation S of the high water-cut fractured vertical well after plugging at the next time step according to formula (9). no :

[0082]

[0083] in, N represents the original formation reserves. P To determine the amount of oil produced, x e S is half the well spacing. wc To constrain water saturation, w f x is the width of the main crack region. f y is half the length of the main crack region. e The spacing is denoted by S. It should be noted that S in formula (9) above... no In fact That is, the average oil saturation. The average oil saturation of the current time step is the oil saturation of the next time step.

[0084] The above-mentioned method for predicting the production capacity of oil wells after plugging with multi-scale plugging agents is based on physical model experiments. It can quickly evaluate the multi-scale migration law of plugging agents, characterize the reservoir attribute parameters after plugging, and quickly evaluate the production capacity of heterogeneous reservoirs after plugging, saving a lot of time. Moreover, it is more accurate in predicting the production capacity of oil wells after plugging.

[0085] Figure 1This is a flowchart illustrating a method for predicting well productivity after multi-scale plugging in one embodiment. It should be understood that, although... Figure 1 The steps in the flowchart are shown sequentially as indicated by the arrows, but these steps are not necessarily executed in the order indicated by the arrows. Unless otherwise specified herein, there is no strict order in which these steps are executed, and they can be performed in other orders. Figure 1 At least some of the steps in the process may include multiple sub-steps or multiple stages. These sub-steps or stages are not necessarily completed at the same time, but can be executed at different times. The execution order of these sub-steps or stages is not necessarily sequential, but can be executed in turn or alternately with other steps or at least some of the sub-steps or stages of other steps.

[0086] This application provides a processor for running a program, wherein the program executes the above-described method for predicting the production capacity of oil wells after multi-scale plugging.

[0087] In one embodiment, a method for predicting the productivity of an oil well after multi-scale plugging is provided, which includes the processor described above.

[0088] The processor contains a kernel, which retrieves the corresponding program units from memory. One or more kernels can be configured, and adjusting kernel parameters allows for methods to predict well productivity after multi-scale plugging.

[0089] The memory may include non-permanent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, such as read-only memory (ROM) or flash RAM, and the memory includes at least one memory chip.

[0090] This application provides a storage medium storing a program that, when executed by a processor, implements the above-described method for predicting the production capacity of oil wells after multi-scale plugging.

[0091] In one embodiment, a computer device is provided, which may be a server, and its internal structure diagram may be as follows: Figure 6As shown. The computer device includes a processor A01, a network interface A02, a memory (not shown), and a database (not shown) connected via a system bus. The processor A01 provides computing and control capabilities. The memory includes internal memory A03 and a non-volatile storage medium A04. The non-volatile storage medium A04 stores an operating system B01, a computer program B02, and a database (not shown). The internal memory A03 provides an environment for the operation of the operating system B01 and the computer program B02 stored in the non-volatile storage medium A04. The database stores relevant data. The network interface A02 communicates with external terminals via a network connection. When the processor A01 executes the computer program B02, it implements a method for predicting the production capacity of oil wells after multi-scale plugging.

[0092] Those skilled in the art will understand that Figure 6 The structure shown is merely a block diagram of a portion of the structure related to the present application and does not constitute a limitation on the computer device to which the present application is applied. Specific computer devices may include more or fewer components than those shown in the figure, or combine certain components, or have different component arrangements.

[0093] This application provides an apparatus, which includes a processor, a memory, and a program stored in the memory and executable on the processor. When the processor executes the program, it implements the steps of a method for predicting the production capacity of an oil well after multi-scale plugging.

[0094] This application also provides a computer program product that, when executed on a data processing device, is suitable for performing steps of a method for predicting the production capacity of an oil well after multi-scale plugging.

[0095] Those skilled in the art will understand that embodiments of this application can be provided as methods, systems, or computer program products. Therefore, this application can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, this application can take the form of a computer program product embodied on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0096] This application is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of this application. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart... Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0097] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0098] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0099] In a typical configuration, a computing device includes one or more processors (CPU), input / output interfaces, network interfaces, and memory.

[0100] Memory may include non-persistent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, such as read-only memory (ROM) or flash RAM. Memory is an example of computer-readable media.

[0101] Computer-readable media includes both permanent and non-permanent, removable and non-removable media that can store information using any method or technology. Information can be computer-readable instructions, data structures, modules of programs, or other data. Examples of computer storage media include, but are not limited to, phase-change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technologies, CD-ROM, digital versatile optical disc (DVD) or other optical storage, magnetic tape, magnetic magnetic disk storage or other magnetic storage devices, or any other non-transferable medium that can be used to store information accessible by a computing device. As defined herein, computer-readable media does not include transient computer-readable media, such as modulated data signals and carrier waves.

[0102] It should also be noted that the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such process, method, article, or apparatus. Unless otherwise specified, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0103] The above are merely embodiments of this application and are not intended to limit the scope of this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the scope of the claims of this application.

Claims

1. A method for predicting the productivity of oil wells after multi-scale plugging, characterized in that, The prediction method includes: The high water-cut fractured vertical well after sealing is divided into multiple seepage zones, including a first seepage zone and a second seepage zone. The first seepage zone includes zone 1, zone 3 and zone 4. Zone 1 is the main fracture zone, zone 3 is the zone formed by the farthest end of the main fracture zone to half the well distance, and zone 4 is the zone formed by the second seepage zone to the drain distance. Determine the permeability at the current time step after the second seepage zone is sealed. and porosity ; Based on the boundary conditions, the basic seepage relationship for each seepage region is determined, thereby identifying the oil phase pseudo-pressure value in Laplace space for each seepage region at the current time step. and output; Determine the initial mean pressure value of each seepage zone after closure at the next time step. ; Based on the initial average pressure value of the next time step Determine the oil saturation of the high water-cut fractured vertical well after plugging at the next time step. And determine the permeability of each first seepage zone in the next time step. ; Based on the oil saturation at the next time step The oil phase pseudo-pressure value of the main fracture region in the first seepage region at the next time step. Predict the well production at the next time step after the well is plugged; Specifically, the basic seepage relationship for each seepage region is determined based on boundary conditions to determine the oil phase pseudo-pressure value in Laplace space for each seepage region at the current time step. Production includes: Based on the boundary conditions, the basic seepage relationship for each seepage region is determined. The first and second relationships are then substituted into each basic seepage relationship for simplification to determine the oil phase pseudo-pressure value in Laplace space for each seepage region at the current time step. and output; The first relation is formula (3): （3） ； in, Let be the porosity of the seepage region n at the current time step after sealing. The porosity at the current time step before plugging, corresponding to each seepage zone. The coefficient of rock compression. This represents the pressure value at the current time step after the seepage zone n is sealed. This represents the initial pressure value of the reservoir at the current time step; The second relation is formula (4): （4）； in, , Let n be the relative permeability of the oil phase in the seepage region n at the current time step, where n = 1, 2, 3, 4. Let be the permeability of the seepage region n at the current time step after it has been sealed. Let be the pseudo-pressure of the oil phase in the seepage region n. The viscosity of crude oil, This is the volume coefficient of crude oil; The basic seepage relationship for determining each seepage region based on boundary conditions includes: The basic seepage equation for region 4 is formula (5): （5）； The basic seepage equation for region 3 is formula (6): （6）； The basic seepage equation for the second seepage zone is formula (7): （7）； The basic seepage equation for region 1 is formula (8): （8）； in, The pressure value in the matrix of region 2. The pressure value in the crack of region 2. The pressure value in region 3 is given by [value], and D is the fractal dimension. The connectivity index, The length of the sealant applied perpendicular to the main joint direction. The variable is the distance from the hydraulic fracture. The density of crude oil, The width of the main crack region. It is half the length of the main crack region.

2. The method for predicting oil well productivity after multi-scale plugging as described in claim 1, characterized in that, The permeability at the current time step after the second seepage zone is sealed is determined. and porosity This includes determining the permeability of the second seepage zone at the current time step after sealing, according to formula (1). : （1）； Let be the permeability at the current time step before the second seepage zone is sealed. This represents the permeability at the current time step after the second seepage zone has been sealed. The sealing length of the sealant perpendicular to the main joint direction, i.e., the distance the sealant travels. Let D be the distance from the hydraulic fracture, and D be the fractal dimension. The connectivity index.

3. The method for predicting oil well productivity after multi-scale plugging as described in claim 1, characterized in that, The permeability at the current time step after the second seepage zone is sealed is determined. and porosity This includes determining the porosity at the current time step after the second seepage zone is sealed, according to formula (2). : （2）； in, The sealing length of the sealant perpendicular to the main joint direction, i.e., the distance the sealant travels. Let D be the distance from the hydraulic fracture, and D be the fractal dimension. The porosity at the current time step before sealing the second seepage zone. This represents the porosity at the current time step after the second seepage region has been sealed.

4. The method for predicting oil well productivity after multi-scale plugging as described in claim 1, characterized in that, The oil saturation of the high water-cut fractured vertical well after plugging is determined at the next time step. This includes calculating the oil saturation of the high water-cut fractured vertical well after plugging at the next time step according to formula (9). : （9） in, N represents the original formation reserves. To the amount of oil extracted, It is half the well spacing. To restrict water saturation, The width of the main crack region. The length of the main crack region is half of the length of the crack region. This refers to the row spacing.

5. The method for predicting oil well productivity after multi-scale plugging as described in claim 1, characterized in that, The oil saturation is based on the next time step. The oil phase pseudo-pressure value of the main fracture region in the first seepage region at the next time step. The predicted well production at the next time step after plugging includes: The well production rate in the Laplace space at the next time step after plugging is calculated according to formula (10). : For the production of the oil well Perform Stehfest numerical inversion to obtain the well production q of the plugged well at the next time step; （10）； in, Let be the oil phase pseudo-pressure value of the main fracture region in the first seepage region within the Laplace space at the next time step, and s be the variable in the Laplace transform.

6. The method for predicting oil well productivity after multi-scale plugging according to claim 5, characterized in that, Calculate according to formula (11) : （11） in, , The symbol for the equation. Where is the wellbore radius. The coefficients are obtained using boundary conditions. This is a Bessel function for a first-class virtual argument, which can be called directly. The coefficients are obtained using boundary conditions. This is a Bessel function for the second type of virtual argument, which can be called directly. To determine the oil saturation of the high water-cut fractured vertical well after plugging at the next time step. The penetration rate of region 1 at the next time step. This represents the relative permeability of the oil phase in the second seepage region at the current time step. The width of the main crack region; The expression for is shown in the following formula (12): （12） in, , D is the fractal dimension. The connectivity index, and These are parameters obtained directly through boundary condition simplification. , as well as These are Bessel functions for the first and second types of virtual arguments, respectively, n, and All are equation symbols; , The expressions for and n are shown in the following formulas (13), (14), and (15): （13）； （14）； （15）； in, , This refers to the intermediate quantity after transformation and simplification. The viscosity of crude oil, The sealing length of the sealant perpendicular to the main joint direction, i.e., the distance the sealant travels. The length of the main crack region is half of the length of the crack region. It is half the well spacing. , The coefficient of rock compression. This represents the porosity of the seepage region n at the current time step after it has been sealed.

7. A processor, characterized in that, It is configured to perform the method for predicting the productivity of oil wells after multi-scale plugging as described in any one of claims 1 to 6.

8. A device for predicting the productivity of an oil well after multi-scale plugging, characterized in that, Includes the processor according to claim 7.

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