Method and device for determining choke system in shale gas horizontal well flow-back stage

Abstract

The application provides a method and device for determining a choke system of a shale gas horizontal well in a flow-back stage. The method comprises the following steps: obtaining artificial fracture parameters, geological parameters and fracturing engineering parameters of a target shale gas horizontal well, and establishing a flow-back model based on the parameters. Then, a maximum choke size of the target shale gas horizontal well is determined according to production pressure differentials corresponding to different choke sizes. Furthermore, a choke replacement mode optimization model, an open-well choke size optimization model and a per-stage choke increase / decrease amplitude optimization model are established based on the production pressure differentials, a stress sensitivity curve, the flow-back model and production conditions of the target shale gas horizontal well. The choke system of the target shale gas horizontal well can be determined according to the models, and the choke system comprises a choke replacement mode, an open-well choke size and a per-stage choke increase / decrease amplitude. The method solves the problem that the determination of the choke system of the shale gas horizontal well in the flow-back stage lacks theoretical support and technical guidance.

Description

Technical Field

[0001] This application relates to the field of shale development technology, and in particular to a method and apparatus for determining the nozzle system during the flowback stage of shale gas horizontal wells. Background Technology

[0002] After large-scale volumetric fracturing, tens of thousands of cubic meters of fracturing fluid remain trapped in the shale reservoir in shale gas horizontal wells. Maximizing the production capacity of these wells hinges on employing a reasonable nozzle system to drain the fluid while minimizing reservoir damage. A crucial component of determining the flowback method during the flowback phase is the nozzle system, which includes determining the nozzle size for split wells, the maximum nozzle size, the nozzle replacement method, and the magnitude of increase / decrease at each nozzle stage.

[0003] Currently, in the flowback phase of shale gas horizontal well development, the determination of the nozzle system relies on the experience of the field operators.

[0004] Determining a reasonable nozzle system based on operator experience requires a high level of technical skill and may result in low accuracy. Furthermore, current research on establishing reasonable nozzle systems is limited, with most studies focusing on the flowback mechanism of shale gas horizontal wells and statistical analysis of production data. Therefore, there is an urgent need to conduct research on determining nozzle systems specifically for the flowback stage of shale gas horizontal wells. Summary of the Invention

[0005] This application provides a method and apparatus for determining the nozzle regime during the flowback stage of shale gas horizontal wells, in order to solve the problem that the existing technology relies on the experience of operators to determine a reasonable nozzle regime, which requires high technical skills from operators and results in low accuracy of the determined nozzle regime.

[0006] In a first aspect, this application provides a method for determining the nozzle regime during the flowback stage of a shale gas horizontal well, the method comprising:

[0007] Acquire the artificial fracture parameters, geological parameters, and fracturing engineering parameters of the target shale gas horizontal well, and input the geological parameters, fracturing engineering parameters, and artificial fracture parameters into a numerical simulator to establish a flowback model;

[0008] Obtain the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, determine the maximum production pressure difference based on the production pressure difference corresponding to the different nozzle sizes, and determine the nozzle size corresponding to the maximum production pressure difference as the maximum nozzle size of the target shale gas horizontal well. The maximum production pressure difference is the limit pressure difference that the reservoir permeability can recover.

[0009] Based on the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, the flowback model, and the production conditions of the target shale gas horizontal well, an optimal model for nozzle replacement method, an optimal model for well opening nozzle size, and an optimal model for the increase / decrease of nozzle size at each stage are established.

[0010] The nozzle regime for the target shale gas horizontal well is determined based on the preferred model for nozzle replacement method, the preferred model for nozzle size during well opening, and the preferred model for the increase / decrease range of nozzles at each stage. The nozzle regime includes the nozzle replacement method, the nozzle size during well opening, and the increase / decrease range of nozzles at each stage.

[0011] Optionally, obtaining the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes includes:

[0012] Obtain the formation pressure of the target shale gas horizontal well, and the bottom hole flowing pressure corresponding to different nozzle sizes;

[0013] Calculate the production pressure difference corresponding to different nozzle sizes based on the formation pressure and the bottom-hole flowing pressure corresponding to different nozzle sizes;

[0014] Obtain stress sensitivity curves corresponding to different production pressure differentials.

[0015] Optionally, obtaining the formation pressure of the target shale gas horizontal well and the bottom hole flowing pressure corresponding to different nozzle sizes includes:

[0016] The formation pressure of the target shale gas horizontal well is determined based on the formation pressure coefficient and the well depth of the target shale gas horizontal well.

[0017] The bottom-hole flowing pressure corresponding to different nozzle sizes can be obtained using the following formula:

[0018]

[0019] Where E is the elastic modulus of the rock, and H w L is the maximum fracture height in the formation. f For the crack length, w f h is the crack width. f For the crack height, C t Let L be the rock compressibility coefficient and L be the wellbore length. p It is the total length of the wellbore, d c Where is the nozzle diameter, v is the flow velocity of the backflow fluid in the crack, and H is... l P represents the liquid holdup. wf (t0) represents the bottom hole flowing pressure at time t0, P wf (t n ) for t n The bottom pressure at any given moment.

[0020] Optionally, obtaining the artificial fracture parameters of the target shale gas horizontal well includes:

[0021] Obtain the actual parameters of the target shale gas horizontal well within a preset time period, including the actual daily gas production, actual bottom hole pressure, and actual daily liquid production.

[0022] Based on the orthogonal experimental method, a preset number of shale gas reservoir models are generated, and each shale gas reservoir model corresponds to fracturing parameters with different value ranges.

[0023] Based on embedded discrete fracture EDFM technology, numerical simulation results of various shale gas reservoir models are generated. The numerical simulation results include simulated daily gas production, simulated bottom hole pressure, and simulated daily liquid production.

[0024] Calculate the first error value between the numerical simulation results and the actual parameters, and establish a surrogate model based on the first error value and the fracturing parameters of each shale gas reservoir model. The surrogate model includes the correspondence between each first error value and the fracturing parameters of its corresponding shale gas reservoir model.

[0025] Based on the Markov chain Monte Carlo inversion algorithm, the values ​​of the fracturing parameters of each shale gas reservoir model in the proxy model are selected from small to large or from large to small, and the corresponding shale gas numerical model is generated according to the selected values.

[0026] Based on the EDFM technology, numerical simulation results of each shale gas numerical model are generated, and the target value of the artificial fracture parameter is determined according to the second error value between the calculated numerical simulation results of each shale gas numerical model and the actual parameter.

[0027] The range of values ​​for the fracturing parameters of the shale gas reservoir model is updated based on the target value to gradually narrow the range of values ​​for the fracturing parameters of the shale gas reservoir model, and finally the optimal artificial fracture parameters are obtained.

[0028] Optionally, calculating the first error value between the numerical simulation result and the actual parameters includes:

[0029] The first error value is calculated based on the following historical fitting error function:

[0030]

[0031] Where n is the number of time points within the preset time period, m is the number of actual parameters, and x ij,model The numerical simulation result of the actual parameter j at time point i, x ij,history Let j be the actual parameter j corresponding to time point i, where i takes the value [1, n] and j takes the value [1, m]. NFj It is a normalized value, defined as the maximum difference between the numerical simulation result and the actual parameters, w ij The weights represent the numerical simulation results.

[0032] Optionally, determining the nozzle regime for the target shale gas horizontal well based on the nozzle replacement method optimization model, the wellhead nozzle size optimization model, and the nozzle increase / decrease range optimization model for each stage includes:

[0033] Under the conditions of the preferred model for nozzle replacement method, the preferred model for well opening nozzle size, and the preferred model for the increase / decrease range of each nozzle stage, the daily gas production and total gas production EUR values ​​corresponding to each nozzle system under different conditions are simulated. The nozzle system corresponding to the maximum value of the EUR value and the maximum daily gas production is determined as the nozzle system of the target shale gas horizontal well.

[0034] Secondly, this application provides an apparatus for determining the nozzle regime during the flowback stage of a shale gas horizontal well, the apparatus comprising:

[0035] The first processing module is used to acquire the artificial fracture parameters, geological parameters, and fracturing engineering parameters of the target shale gas horizontal well, and input the geological parameters, the fracturing engineering parameters, and the artificial fracture parameters into the numerical simulator to establish a flowback model;

[0036] The second processing module is used to obtain the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, determine the maximum production pressure difference according to the production pressure difference corresponding to the different nozzle sizes, and determine the nozzle size corresponding to the maximum production pressure difference as the maximum nozzle size of the target shale gas horizontal well. The maximum production pressure difference is the limit pressure difference that the reservoir permeability can recover.

[0037] A module is established to create an optimal model for nozzle replacement, an optimal model for well opening nozzle size, and an optimal model for increasing / decreasing the nozzle size at each stage, based on the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, the flowback model, and the production conditions of the target shale gas horizontal well.

[0038] The determination module is used to determine the nozzle regime of the target shale gas horizontal well based on the nozzle replacement method optimization model, the well opening nozzle size optimization model, and the nozzle increase / decrease range optimization model for each stage. The nozzle regime includes the nozzle replacement method, the well opening nozzle size, and the nozzle increase / decrease range for each stage.

[0039] Optionally, the second processing module is specifically used for:

[0040] Obtain the formation pressure of the target shale gas horizontal well, and the bottom hole flowing pressure corresponding to different nozzle sizes;

[0041] Calculate the production pressure difference corresponding to different nozzle sizes based on the formation pressure and the bottom-hole flowing pressure corresponding to different nozzle sizes;

[0042] Obtain stress sensitivity curves corresponding to different production pressure differentials.

[0043] Thirdly, this application provides an electronic device, including: a processor, and a memory communicatively connected to the processor;

[0044] The memory stores computer-executed instructions;

[0045] The processor executes computer execution instructions stored in the memory to implement the method for determining the nozzle regime during the flowback stage of shale gas horizontal wells as described in the first aspect.

[0046] Fourthly, this application provides a computer-readable storage medium storing computer-executable instructions, which, when executed by a processor, are used to implement the method for determining the nozzle regime during the flowback stage of a shale gas horizontal well as described in the first aspect.

[0047] Fifthly, this application provides a computer program product, including a computer program, which, when executed by a processor, determines the nozzle regime during the flowback stage of a shale gas horizontal well as described in the first aspect.

[0048] This application provides a method and apparatus for determining the nozzle regime during the flowback stage of a shale gas horizontal well. The method involves acquiring artificial fracture parameters, geological parameters, and fracturing engineering parameters of the target shale gas horizontal well, and establishing a flowback model based on these parameters. Then, it obtains the production pressure differential and stress sensitivity curves corresponding to different nozzle sizes, and determines the maximum production pressure differential (the limit pressure differential at which reservoir permeability can be recovered) based on the production pressure differential, thereby determining the maximum nozzle size for the target shale gas horizontal well. Based on the production pressure differential, stress sensitivity curves, flowback model, and production conditions of the target shale gas horizontal well, it establishes optimization models for nozzle replacement methods, well-opening nozzle sizes, and the increase / decrease range of nozzles per stage. These optimization models determine the nozzle regime for the target shale gas horizontal well, which includes the nozzle replacement method, well-opening nozzle size, and the increase / decrease range of nozzles per stage. This solves the problem of lack of theoretical support and technical guidance for determining the nozzle system during the flowback stage of shale horizontal wells in the field. It can reduce the impact of stress-sensitive damage, proppant backflow and embedding on the surface process during the flowback process, and lay the foundation for maximizing the production capacity of shale gas horizontal wells. Attached Figure Description

[0049] The accompanying drawings, which are incorporated in and form part of this specification, illustrate embodiments consistent with this application and, together with the description, serve to explain the principles of this application.

[0050] Figure 1 A flowchart illustrating a method for determining the nozzle regime during the flowback stage of a shale gas horizontal well, as provided in Embodiment 1 of this application;

[0051] Figure 2 A schematic diagram of the transient pressure pulse method provided in Embodiment 1 of this application;

[0052] Figure 3 This is a schematic diagram of the daily gas production for a three-month production period, corresponding to different nozzle replacement methods exemplified in Embodiment 1 of this application.

[0053] Figure 4 This is a schematic diagram illustrating the EUR values ​​corresponding to different nozzle replacement methods exemplified in Embodiment 1 of this application;

[0054] Figure 5 This is a schematic diagram illustrating the daily gas production over a three-month production period, corresponding to the increase in the level of each nozzle stage, as exemplified in Embodiment 1 of this application.

[0055] Figure 6 This is a schematic diagram showing the EUR values ​​corresponding to the increase in the nozzle size for each stage, as illustrated in Embodiment 1 of this application.

[0056] Figure 7 This is a schematic diagram of the fitting results for the daily gas production volume in Example 2 of this application;

[0057] Figure 8 This is a schematic diagram of the fitting results for the daily liquid production volume in Example 2 of this application;

[0058] Figure 9 This is a schematic diagram of the fitting results of the bottom hole flowing pressure as exemplified in Embodiment 2 of this application;

[0059] Figure 10 A flowchart illustrating a method for determining the nozzle regime during the flowback stage of a shale gas horizontal well, as provided in Embodiment 3 of this application;

[0060] Figure 11 This is a schematic diagram of the experimental setup for the shale stress sensitivity experiment exemplified in Embodiment 3 of this application;

[0061] Figure 12 This is a stress sensitivity curve diagram exemplified in Embodiment 3 of this application;

[0062] Figure 13 This is a graph illustrating the variation of gas permeability with production pressure differential, as exemplified in Embodiment 3 of this application.

[0063] Figure 14A schematic diagram of the structure of a device for determining the nozzle regime during the flowback stage of a shale gas horizontal well, provided in Embodiment 4 of this application;

[0064] Figure 15 This is a schematic diagram of the structure of an electronic device provided in Embodiment 5 of the present invention.

[0065] The accompanying drawings illustrate specific embodiments of this application, which will be described in more detail below. These drawings and descriptions are not intended to limit the scope of the concept in any way, but rather to illustrate the concepts of this application to those skilled in the art through reference to particular embodiments. Detailed Implementation

[0066] Exemplary embodiments will now be described in detail, examples of which are illustrated in the accompanying drawings. When the following description relates to the drawings, unless otherwise indicated, the same numbers in different drawings denote the same or similar elements. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with this application. Rather, they are merely examples of apparatuses and methods consistent with some aspects of this application as detailed in the appended claims.

[0067] The determination of a reasonable nozzle system is related to the magnitude of formation stress-sensitive damage. Oversized nozzles can lead to excessive production pressure differentials, resulting in greater stress-sensitive damage, which in turn significantly reduces the conductivity of early fractures, causing complex situations such as proppant backflow and embedding, as well as surface process erosion or blockage.

[0068] Currently, during the flowback phase of shale gas horizontal well development, the determination of the nozzle regime relies on the experience of the field operators. However, relying on the experience of operators to determine a reasonable nozzle regime requires a high level of technical skill from the operators, and the accuracy of the determined nozzle regime is not high.

[0069] Moreover, most current research focuses on the flowback mechanism of shale gas horizontal wells and statistical analysis of production data. Based on extensive research on the influencing factors of the flowback process of shale gas horizontal wells and the analysis of production data, it has been determined that changes in fluid flow during the flowback stage will seriously affect the gas well's production capacity. However, there is a lack of technical research on the nozzle system during the flowback stage of shale gas horizontal wells. Therefore, it is urgent to carry out research on determining the nozzle system during the flowback stage of shale gas horizontal wells.

[0070] Therefore, this application proposes a method and apparatus for determining the nozzle regime during the flowback stage of shale gas horizontal wells. Based on the basic physical property parameters of the target shale gas horizontal well and numerical simulation technology, an optimal nozzle regime model is established. This model can determine the reasonable opening nozzle size, maximum nozzle size, nozzle size replacement method, and the increase / decrease range of each nozzle stage. It solves the problem of lack of theoretical support and technical guidance for determining the nozzle regime during the flowback stage of shale gas horizontal wells in the field. It can reduce the impact of stress-sensitive damage, proppant backflow and embedding, and surface process erosion or blockage during the flowback process, laying the foundation for maximizing the productivity of shale gas horizontal wells.

[0071] The following explains the nozzle system, which includes the nozzle size for well opening, the maximum nozzle size, the nozzle size replacement method, and the increase / decrease range of nozzle size for each stage.

[0072] Among them, the nozzle size is the initial nozzle size for determining the development of shale gas horizontal wells.

[0073] The maximum nozzle size is determined for a single well after considering the effects of proppant backflow, embedding, and breakage. It is the maximum nozzle size that has a relatively small impact on fracture conductivity. When the production pressure differential of the well is greater than the production pressure differential value corresponding to the maximum nozzle size, the reservoir permeability damage is difficult to recover.

[0074] The method of changing the nozzle size is as follows during the development of shale horizontal wells. As production time increases, the nozzle size also needs to be changed in a reasonable way to improve production capacity. The nozzle size is generally changed from small to large or from large to small.

[0075] The increment / decrease of each nozzle size is determined after the nozzle size replacement method is determined, and the nozzle size is replaced according to the determined increment / decrease.

[0076] The technical solutions of this application and how they solve the aforementioned technical problems are described in detail below with specific embodiments. These specific embodiments may exist independently or in combination with each other. Identical or similar concepts or processes may not be repeated in some embodiments. The embodiments of this application will now be described with reference to the accompanying drawings.

[0077] refer to Figure 1 , Figure 1 The present application provides a method for determining the nozzle regime during the flowback stage of a shale gas horizontal well. This method can be executed by a nozzle regime determination device, which can be a server. The method includes the following steps.

[0078] S101. Obtain the geological parameters, fracturing engineering parameters, and artificial fracture parameters of the target shale gas horizontal well, and input the geological parameters, fracturing engineering parameters, and artificial fracture parameters into the numerical simulator to establish a flowback model.

[0079] To determine the nozzle regime of the target shale gas horizontal well, the server acquires the geological parameters, fracturing engineering parameters, and artificial fracture parameters of the target shale gas horizontal well. Among them, the geological parameters include porosity, permeability, and gas saturation, the fracturing engineering parameters include the length and number of fracturing sections, and the artificial fracture parameters include fracture height, half-length, fracture conductivity, water saturation, width, and cluster efficiency.

[0080] Specifically, artificial fracture parameters can be obtained from the engineering records of on-site personnel, while geological parameters can be obtained by on-site personnel using logging tools to measure in the target shale gas horizontal well, or by personnel conducting shale core experiments based on core samples from the target shale gas horizontal well. Then, the geological parameters and artificial fracture parameters are input into the server.

[0081] The specific implementation of the shale core experiment is as follows:

[0082] (1) Porosity is obtained by gas measurement method.

[0083] For example, the process ignores the valve displacement volume and isothermal control, and calculates the shale skeleton volume and the sample skeleton volume using formulas (1) and (2).

[0084]

[0085]

[0086] Among them, V r Reference chamber volume, unit: cm² 3 V s This refers to the volume of the sample chamber, in cm³. 3 V g The volume of the sample skeleton is in cm³. 3 p1 is the pressure of the reference chamber before expansion, in MPa; p2 is the equilibrium pressure of the system after expansion, in MPa; Z1 is the compressibility factor of the gas under pressure p1; and Z2 is the compressibility factor of the gas under pressure p2.

[0087] Then, the porosity of the sample is calculated based on the total sample volume using formula (3):

[0088]

[0089] Where, φ GIP V represents the porosity determined by the gas measurement method. tTotal sample volume, in cm³ 3 For example, the porosity value calculated from the sample of the experimental well used in this application experiment is 4.17%.

[0090] (2) Permeability was obtained by transient pressure pulse method.

[0091] The transient pressure pulse method involves placing a sealed container at each end of the test sample. During testing, after the pressure in the upper and lower containers and inside the rock sample has reached equilibrium, a pressure pulse is applied to the upstream container. An example schematic diagram of the transient pressure pulse method is shown below. Figure 2 As shown in the diagram. Then the pressure in the upstream container will gradually decrease, while the pressure in the downstream container will gradually increase. The pressure changes at both ends over time will be monitored until a new pressure equilibrium is reached within the containers.

[0092] Therefore, the permeability of the test sample can be obtained from the upstream and downstream pressure decay curves, and an approximate solution for the permeability can be calculated using formulas (4) and (5):

[0093]

[0094]

[0095] Where Δp(t) is the measured pressure difference across the rock sample, p i V is the initial pulse pressure, θ is the slope of the decay curve, and V u and V d The upstream and downstream volumes are respectively, A is the cross-sectional area of ​​the wellbore, k is the permeability, and C is the volume of the wellbore. w It is the fluid compressibility coefficient, μ w Where is the liquid phase viscosity and L is the wellbore length.

[0096] For example, the permeability value calculated from the sample of the experimental well used in this application experiment is 0.00053 mD.

[0097] (3) The water saturation was obtained by the liquid saturation method.

[0098] Water saturation is calculated using the following formula:

[0099]

[0100] Among them, S w The water saturation is given by m1, the mass of the reaction vessel is given by m2, the mass of the reaction vessel is given by m2 after the sample is placed in the reaction vessel, ρ1 is the total density of the shale, ρ2 is the density of the rock particles after crushing the shale, and V is the mass of the shale. w V is the volume of water. g This represents the volume of the gas.

[0101] For example, the water saturation value calculated from the sample of the experimental well used in this application is 33.69%.

[0102] The artificial fracture parameters can be obtained by the server fitting and inverting each parameter of the actual parameters of the target shale gas horizontal well within a preset time period based on the Markov chain Monte Carlo inversion algorithm, the orthogonal experimental method, and the embedded discrete fracture EDFM technology. The actual parameters mentioned above may include the actual daily gas production, the actual bottom hole pressure, and the actual daily liquid production. The specific implementation is described in detail in Example 2. Please refer to Example 2.

[0103] After obtaining the geological parameters, fracturing engineering parameters, and artificial fracture parameters, the server inputs these parameters into the numerical simulator to establish a flowback model. This flowback model serves as the foundation for subsequent models such as the optimal nozzle replacement method, the optimal nozzle size for well opening, and the optimal model for increasing / decreasing the nozzle size at each stage. Each optimal model is obtained by modifying the corresponding parameters on this foundational model. In other words, this flowback model can be understood as a practical simulation model that considers the basic parameters of actual shale gas horizontal wells. For example, some parameters of the flowback model are shown in Table 1, which were determined in this application based on experimental wells.

[0104] The aforementioned numerical simulator is a numerical simulation software used to simulate actual shale gas horizontal wells under development, and will not be described in detail here.

[0105] Table 1. Partial Parameters of the Return Model

[0106]

[0107] S102. Obtain the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, determine the maximum production pressure difference based on the production pressure difference corresponding to different nozzle sizes, and determine the nozzle size corresponding to the maximum production pressure difference as the maximum nozzle size of the target shale gas horizontal well.

[0108] After the server establishes the return model, in order to determine the corresponding nozzle size in the nozzle system, the server obtains the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes. Different nozzle sizes are determined based on multiple conventional nozzle sizes. For example, the nozzle sizes commonly used in field development are 3mm-12mm. For example, the production pressure difference corresponding to different nozzle sizes is shown in Table 2.

[0109] Table 2 Production Pressure Difference Corresponding to Different Nozzle Sizes

[0110]

[0111] After the server obtains the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, it can determine the maximum production pressure difference based on the production pressure difference corresponding to different nozzle sizes, and determine the nozzle size corresponding to the maximum production pressure difference as the maximum nozzle size of the target shale gas horizontal well. This maximum production pressure difference is the limit pressure difference that the reservoir permeability can recover.

[0112] The calculation of production pressure difference corresponding to different nozzle sizes, as well as the determination of the stress sensitivity curve and the maximum nozzle size, are explained in detail in Example 3. Please refer to Example 3.

[0113] S103. Based on the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, the flowback model, and the production conditions of the target shale gas horizontal well, establish an optimal model for nozzle replacement method, an optimal model for well opening nozzle size, and an optimal model for the increase / decrease of nozzle size at each stage.

[0114] After obtaining the production pressure differential and stress sensitivity curves corresponding to different nozzle sizes, the server uses these curves to perform a production pressure differential sensitivity analysis through the established flowback model. Specifically, the server inputs the production pressure differentials corresponding to different nozzle sizes into the flowback model, and then establishes optimization models for nozzle replacement methods, well opening nozzle sizes, and nozzle size increases / decreases per stage based on three different nozzle system schemes (nozzle replacement method, well opening nozzle size, and nozzle size corresponding to the increase / decrease of nozzle size per stage). Furthermore, the server inputs the stress sensitivity curve corresponding to each nozzle size into each optimization model to reflect the actual stress sensitivity effect under different production pressure differentials in the actual formation, which is more consistent with the actual field development situation.

[0115] Then, for the above different preferred models, corresponding production conditions are set to simulate different nozzle systems on site. For example, combined with the example production conditions and nozzle size (3mm-9mm), the three different preferred models are explained below.

[0116] (1) Optimal Model for Oil Nozzle Replacement Method

[0117] The optimal model for nozzle replacement includes simulation methods for four nozzle replacement methods:

[0118] ① Replace the nozzles gradually from small to large, that is, from 3mm to 9mm. Each nozzle size is used for 5 days. When the nozzle size is changed to 9mm, the replacement is stopped. The 9mm nozzle is used for production for 3 months.

[0119] ② Replace the nozzle gradually from small to large, that is, from 3mm to 9mm. Each nozzle size is used for 5 days. When the nozzle size is changed to 9mm, the replacement is stopped. The 9mm nozzle is used for production for 20 years.

[0120] ③ Replace the nozzles gradually from large to small, that is, from 9mm all the way down to 3mm. Each nozzle size is used for 5 days. When the nozzle size is changed to 3mm, the replacement is stopped. The 3mm nozzle is used for production for 3 months.

[0121] ④ Replace from large to small in stages, that is, from 9mm all the way down to 3mm. Each level of nozzle is used for 5 days. When the nozzle size is changed to 3mm, the replacement is stopped. The production stage uses 3mm for 20 years.

[0122] (2) Optimization model for well nozzle size

[0123] The optimal nozzle size model for well opening includes simulation methods for 14 nozzle sizes: It simulates seven initial nozzle sizes ranging from 3mm to 9mm, simulating two scenarios with total production times of 3 months and 20 years. Each production time corresponds to one of the seven nozzle sizes, resulting in a total of 14 simulation methods. Specifically, the initial nozzle size is 3mm, gradually increasing to 9mm, with each nozzle size model used for 3 days. The production phase uses 9mm nozzles for 3 months and 20 years. Similarly, the initial nozzle size is 4mm, gradually increasing to 9mm, with each nozzle size model used for 3 days. The production phase uses 9mm nozzles for 3 months and 20 years, and so on.

[0124] (3) Optimization model for the increase / decrease range of each nozzle stage

[0125] The optimal model for increasing / decreasing nozzle size per stage includes eight simulation methods for this: Taking the determination that replacing nozzles from small to large is more reasonable, we can simulate an initial nozzle size of 3mm, with each stage increasing by 1mm, 2mm, 3mm, and 4mm to reach 9mm. Production stages using 9mm nozzles would then be simulated for 3 months and 20 years, resulting in eight simulation methods. Similarly, if a decrease from large to small is determined to be more reasonable, we can simulate an initial nozzle size of 9mm, with each stage decreasing by 1mm, 2mm, 3mm, and 4mm to reach 3mm. Production stages using 3mm nozzles would then be simulated for 3 months and 20 years.

[0126] By observing the daily gas production and the magnitude of the EUR (Estimated Ultimate Recovery) value in the simulation results of the above simulation method, the reasonable increase in the opening of each stage of nozzle can be determined.

[0127] S104. Determine the nozzle system for the target shale gas horizontal well based on the nozzle replacement method optimization model, the well opening nozzle size optimization model, and the nozzle increase / decrease range optimization model for each stage.

[0128] After the server establishes optimal models for nozzle replacement methods, wellhead nozzle size, and nozzle increase / decrease range for each stage, technicians can determine the nozzle regime for the target shale gas horizontal well from various simulation modes within these optimal models, based on the actual production conditions of the target shale gas horizontal well. Specifically, under the conditions of the optimal models for nozzle replacement methods, wellhead nozzle size, and nozzle increase / decrease range, by observing the daily gas production and total gas production EUR values ​​generated by each simulation mode, the nozzle regime corresponding to the maximum EUR value and daily gas production is determined as the nozzle regime for the target shale gas horizontal well. This nozzle regime is then used for actual production to maximize the shale gas horizontal well's production capacity.

[0129] For example, based on the actual situation of the experimental well used in this application, in the nozzle replacement method optimization model, according to the daily gas production and EUR value generated by the four simulation methods, the optimal nozzle replacement method can be determined to be replacing from small to large. The reference daily gas production for three months of production time corresponding to different nozzle replacement methods is as follows: Figure 3 As production time increases, the EUR values ​​corresponding to different nozzle replacement methods are referenced. Figure 4 In the optimal nozzle size model for well opening, based on the daily gas production and EUR values ​​generated by 14 simulation methods, the optimal nozzle size for well opening is determined to be 3mm. In the optimal model for the increase / decrease of nozzle size per stage, based on the daily gas production and EUR values ​​generated by 8 simulation methods, the optimal increase per stage is determined to be 1mm. The reference daily gas production for a 3-month production period corresponds to this increase per stage. Figure 5 As production time increases, the EUR value corresponding to the increase in the amount of each nozzle stage is referenced. Figure 6 .

[0130] In this embodiment, the server acquires the artificial fracture parameters, geological parameters, and fracturing engineering parameters of the target shale gas horizontal well, and establishes a flowback model based on these parameters. Then, it acquires the production pressure differential and stress sensitivity curves corresponding to different nozzle sizes, and determines the limiting pressure differential at which reservoir permeability can be restored, i.e., the maximum production pressure differential, based on the production pressure differential and stress sensitivity curves, the flowback model, and the production conditions of the target shale gas horizontal well. Then, based on the production pressure differential, stress sensitivity curves, flowback model, and the production conditions of the target shale gas horizontal well, it establishes optimal models for nozzle replacement methods, optimal models for wellhead nozzle sizes, and optimal models for the increase / decrease range of nozzles at each stage. Based on these optimal models, the nozzle regime of the target shale gas horizontal well can be determined. The nozzle regime includes the nozzle replacement method, the wellhead nozzle size, and the increase / decrease range of nozzles at each stage. This solves the problem of lacking theoretical support and technical guidance for determining the nozzle regime during the flowback stage of shale horizontal wells in the field, and can reduce the impact of stress-sensitive damage, proppant backflow, and embedding on the surface process erosion or blockage during flowback, laying the foundation for maximizing the production capacity of shale gas horizontal wells.

[0131] The following example illustrates the inversion calculation of the artificial crack parameters in step S101 of example one.

[0132] This application provides a method for determining the nozzle regime during the flowback stage of a shale gas horizontal well, which can be executed by a nozzle regime determination device, which can be a server.

[0133] The inversion calculation process includes the following steps:

[0134] (1) The server generates a preset number of shale gas reservoir models according to the orthogonal experimental design. Each shale gas reservoir model corresponds to different ranges of fracturing parameters. The fracturing parameters include fracture height, half length, conductivity, water saturation, width and cluster efficiency. For example, the preset number is 25. The following examples use 25 shale gas reservoir models.

[0135] (2) Then, based on the Embedded Discrete Fracture Model (EDFM) technology, numerical simulation results of 25 shale gas reservoir models were generated. The numerical simulation results include the following simulation values: simulated daily gas production, simulated bottom hole pressure and simulated daily liquid production.

[0136] (3) The server inputs the simulated values ​​of each of the 25 numerical simulation results and the actual parameters of the target shale gas horizontal well within a preset time into the historical fitting error function to obtain the first error value corresponding to the 25 numerical simulation results.

[0137] The historical fitting error function is:

[0138]

[0139] Where n is the number of time points within the preset time period, m is the number of actual parameters, and x ij,model Numerical simulation results of the actual parameter j at time point i, x ij,history Let j be the actual parameter j corresponding to time point i, where i takes the value [1, n] and j takes the value [1, m]. NF j It is a normalized value, defined as the maximum difference between the reservoir numerical simulation results and the actual parameters, w ij The weights represent the numerical simulation results.

[0140] (4) The server establishes a proxy model based on the first error value and the fracturing parameters of the shale gas reservoir model. The proxy model includes the correspondence between each first error value and the corresponding fracturing parameters of the shale gas reservoir model. For example, the proxy model can be a polynomial relationship.

[0141] (5) The server uses the Markov Chain Monte Carlo (MCMC) algorithm to select values ​​from small to large or large to small within the range of values ​​of each fracturing parameter in the proxy model, and generates corresponding shale gas numerical models based on these values. That is, 25 shale gas numerical models are generated. It can be understood that the fracturing parameters corresponding to the shale gas numerical models are definite values, rather than a certain range.

[0142] (6) Then, based on the EDFM technology, the numerical simulation results of the shale gas numerical model are generated, and the numerical simulation results of the shale gas numerical model and the actual parameters are input into the above-mentioned historical fitting error function to obtain 25 second error values.

[0143] (7) When there is a second error value that is less than or equal to the preset threshold, the value of the fracturing parameter of the shale gas numerical model corresponding to the second error value that is less than or equal to the preset threshold is recorded, and the value range of the fracturing parameter of the corresponding shale gas reservoir model in the proxy model is updated according to the value.

[0144] For example, the fracture height in the fracturing parameters of the shale gas numerical model corresponding to a second error value less than or equal to a preset threshold is 18. The original range of fracture height in the fracturing parameters of the shale gas reservoir model was 5m-20m. So, based on this value, the range of fracture height in the fracturing parameters of the shale gas reservoir model is updated to 5m-18m. And so on, the range of fracturing parameters of the shale gas reservoir model can be gradually reduced, and finally the optimal value of artificial fracture parameters can be obtained.

[0145] (8) Based on the updated value range, repeat steps (5)-(7) to obtain the values ​​of the fracturing parameters of the shale gas numerical model corresponding to multiple error values ​​that are less than or equal to the preset threshold. Generate EUR values ​​based on the values ​​of the fracturing parameters of the shale gas numerical model corresponding to multiple error values ​​that are less than or equal to the preset threshold. Determine the value of the fracturing parameters of the shale gas numerical model corresponding to the maximum value of the EUR value as the artificial fracture parameter.

[0146] It should be noted that the actual parameters used for inverting artificial fracture parameters mentioned above—daily gas production, bottom hole pressure, and daily fluid production—can also be other parameters, and this application does not limit them. For example, the fitting results for daily gas production, daily fluid production, and bottom hole flowing pressure are as follows: Figure 7 , Figure 8 and Figure 9 .

[0147] In this embodiment, a preset number of shale gas reservoir models are generated based on the orthogonal experimental design principle. The fracturing parameters corresponding to these shale gas reservoir models all have different value ranges. Then, based on EDFM technology, numerical simulation results for each shale gas reservoir model are generated. The server then establishes a proxy model based on the first error value between the numerical simulation results and the actual parameters of the target shale gas horizontal well within a preset time, and the fracturing parameters of the shale gas reservoir model. Based on the MCMC algorithm, values ​​are selected from the value ranges of the fracturing parameters of each shale gas reservoir model in the proxy model, and a corresponding shale gas numerical model is generated based on these values. Then, based on EDFM technology, numerical simulation results for the shale gas numerical model are generated. Based on the second error value between the numerical simulation results and the actual parameters of the shale gas numerical model, the target values ​​of the fracturing parameters are determined, and the value range of the fracturing parameters of the shale gas reservoir model is updated according to these values ​​to gradually narrow the value range of the fracturing parameters of the shale gas reservoir model. Finally, accurate values ​​of the fracturing parameters can be obtained, and artificial fracture parameters can be determined, providing a data foundation for the subsequent establishment of the flowback model.

[0148] The following example, through Example 3, illustrates the calculation of production pressure difference and stress sensitivity curves corresponding to different nozzle sizes in step S102 of Example 1, as well as the determination of the maximum nozzle size.

[0149] refer to Figure 10 , Figure 10 This is a flowchart illustrating a method for determining the nozzle regime during the flowback stage of a shale gas horizontal well, as provided in Embodiment 3 of this application. This method can be executed by a nozzle regime determination device, which can be a server. The method includes the following steps.

[0150] S1001. Obtain the formation pressure of the target shale gas horizontal well, and the bottom hole flowing pressure corresponding to different nozzle sizes.

[0151] Formation pressure in a shale gas reservoir is the pressure exerted on the pore fluid of the rock. Its value can be determined based on the formation pressure coefficient and the depth of the target shale gas horizontal well, i.e., the formation pressure can be calculated using formula (8):

[0152] P d =GH=G(H) A -H B (8)

[0153] Among them, P d Ground pressure is measured in MPa, G is the formation pressure coefficient in MPa / m, and H is the well depth in meters. A The vertical depth of point A in the target shale gas horizontal well is given in meters (H). B The vertical depth of point B in the target shale gas horizontal well is given in meters.

[0154] In order to couple the formation flow with the determination of the nozzle system, the backflow fluid will flow out through the nozzle, so the pressure calculation of the nozzle flow is carried out. The process of the liquid and gas two-phase fluid flowing out of the fracture and then being discharged through the nozzle can be calculated by the principle of volume conservation. The fluid flowing out of the fracture is the same as the fluid discharged through the nozzle. Therefore, the relationship between the backflow fluid outflow volume and the nozzle size is formula (9).

[0155]

[0156] Among them, v f The volume of the backflow fluid is expressed in m³, v c The fluid velocity passing through the nozzle is expressed in m / s, d. c The nozzle diameter is in mm.

[0157] Then, the Bernoulli equation is used to describe the process of the flowback fluid from the wellbore through the nozzle in a shale gas horizontal well, so as to clarify the flow process from the wellbore to the nozzle at the wellhead and establish the relationship between the nozzle size and the bottom hole flowing pressure, i.e., formula (10), which lays the foundation for subsequent pipe flow calculation and nozzle size connection:

[0158]

[0159] Among them, P wf (t) represents the bottom hole flowing pressure at time t, in MPa, and γ represents the specific weight of the flowback fluid, in N / m³. 3 v is the flow velocity of the backflow fluid in the crack, in m / s, ΔP f Pressure loss in the wellbore, in MPa, v c Let P0 be the fluid velocity passing through the nozzle, P0 be atmospheric pressure (which can be 0.101 MPa), and g be the acceleration due to gravity (which can be 9.80665 m / s²).2 .

[0160] Then, the formula for calculating the gas-liquid two-phase flow in the vertical wellbore of a shale gas horizontal well is determined:

[0161]

[0162] Where, ρ m f is the density of the two-phase fluids, namely shale gas and shale liquid. m Where D is the two-phase friction coefficient, A is the wellbore diameter of the target shale gas horizontal well, P is the bottom hole flowing pressure, and G is the two-phase friction coefficient. m The mass flow rate of the gas-liquid mixture is expressed in kg / s, and g is the acceleration due to gravity, which can be taken as 9.80665 m / s². 2 .

[0163] Specifically:

[0164] G m =G l +G g =A(ν sl ρ l +ν sg ρ g (12)

[0165] Where A is the cross-sectional area of ​​the target shale gas horizontal well, and G g G represents the shale gas phase mass flow rate. l v is the shale liquid phase mass flow rate. sl v represents the apparent velocity of the shale liquid phase. sg ρ represents the apparent velocity of the shale gas phase. g ρ is the density of the gas phase fluid in shale. l The density of the shale liquid phase fluid.

[0166] ρ m =ρ l H l +ρ g (1-H l (13)

[0167] Where, ρ g ρ is the density of shale gas phase fluid, in kg / m³. l The density of the liquid phase fluid in shale is expressed in kg / m³, H. l Liquid holdup is the proportion of liquid in a unit pipe section volume during the two-phase flow of shale gas and liquid within the wellbore of a horizontal shale gas well.

[0168] To make the bottom hole flowing pressure calculation more accurate, the pressure loss due to friction between the mixture and the wellbore, as well as the pressure loss between the two phases of shale gas and shale fluid, is considered, and the following relationship is established:

[0169]

[0170] Transforming formula (14) yields:

[0171]

[0172] Where, ΔP f γ represents the pressure loss in the wellbore, in MPa, and γ represents the specific weight of the flowback fluid, in N / m³. 3 , τ w T is the drag force of the shale gas-liquid two-phase flow on the wellbore, in N; T is the force of the flowback fluid on the gas, in N; l is the wellbore length, in m; and D is the wellbore diameter of the target shale gas horizontal well.

[0173] Based on the above formula, the formula for calculating bottom hole flowing pressure is obtained:

[0174]

[0175] Where E is the elastic modulus of the rock, and H w L is the maximum fracture height in the formation. f For the crack length, w f h is the crack width. f For the crack height, C t Let L be the rock compressibility coefficient and L be the wellbore length. p It is the total length of the wellbore, d c Where is the nozzle diameter, v is the flow velocity of the backflow fluid in the crack, and H is... l P represents the liquid holdup. wf (t0) represents the bottom hole flowing pressure at time t0, P wf (t n ) for t n The bottom pressure at any given moment.

[0176] S1002. Calculate the production pressure difference corresponding to different nozzle sizes based on the formation pressure of the target shale gas horizontal well and the bottom hole flowing pressure corresponding to different nozzle sizes.

[0177] After the server determines the formation pressure of the target shale gas horizontal well and the bottom hole flowing pressure corresponding to different nozzle sizes, it obtains the production pressure difference corresponding to different nozzle sizes based on the relationship between the production pressure difference and the bottom hole flowing pressure difference.

[0178] S1003. Obtain the stress sensitivity curves corresponding to different production pressure differentials.

[0179] The stress sensitivity curves corresponding to different production pressure differentials can be determined by staff through laboratory experiments on shale stress sensitivity. These curves are then input into the server.

[0180] An exemplary experimental setup for shale stress sensitivity experiments is as follows: Figure 11 As shown in Table 2, the experimental procedure is explained below using the pressure difference example:

[0181] (1) Test the airtightness of the instrument.

[0182] (2) Place the rock sample 1, which has been filled with proppant and sealed completely, into the core holder and wrap it with black heat shrink film to fix it.

[0183] (3) The pressure was increased using a pressure tracking mode with a pressure difference of 3 MPa until the confining pressure reached 43 MPa and the flowing pressure reached 40 MPa. Then, the flowing pressure was fixed at 40 MPa, and the confining pressure was increased to 50 MPa. After the gas flow rate and pressure stabilized, the gas permeability of the rock sample under these conditions was measured.

[0184] (4) Fix the confining pressure at 50 MPa, reduce the flow pressure, and after the gas flow rate and pressure stabilize, measure the gas permeability at flow pressures of 49 MPa, 46 MPa, 46 MPa, 40 MPa, 37 MPa, 34 MPa, 31 MPa, 29 MPa, 27 MPa and 26 MPa respectively.

[0185] (5) Replace rock samples 2, 3, 4, 5, 6, 7 and 8, and measure the gas permeability under the same flow pressure conditions. Repeat steps (3) and (4).

[0186] (6) Organize the experimental data to obtain the stress sensitivity curves and maximum production pressure difference corresponding to different production pressure differences. For example, the stress sensitivity curves are as follows: Figure 12 As shown.

[0187] S1004. Determine the maximum production pressure difference based on the production pressure difference, and determine the nozzle size corresponding to the maximum production pressure difference as the maximum nozzle size of the target shale gas horizontal well.

[0188] For example, the gas permeability measured in the above experiment can be used to measure the change with the production pressure difference, such as... Figure 13 As shown, 19 MPa is determined to be the maximum production pressure differential; if this is exceeded, reservoir damage is difficult to recover. Therefore, Table 2 shows that the nozzle size corresponding to 19 MPa is 9 mm, and the maximum nozzle size for the target shale gas horizontal well is 9 mm.

[0189] In this embodiment, the server calculates the production pressure difference corresponding to different nozzle sizes, and then obtains the maximum nozzle size based on the production pressure difference. The stress sensitivity curves corresponding to different production pressure differences represent the stress change characteristics under different nozzle sizes (production pressure differences), providing a reliable data basis for the subsequent determination of nozzle specifications.

[0190] refer to Figure 14 , Figure 14 This is a schematic diagram of a device for determining the nozzle regime during the flowback stage of a shale gas horizontal well, as provided in Embodiment 4 of this application. The device 140 includes: a first processing module 1401, a second processing module 1402, a setup module 1403, and a determination module 1404.

[0191] The first processing module 1401 is used to acquire the artificial fracture parameters, geological parameters, and fracturing engineering parameters of the target shale gas horizontal well, and input the geological parameters, fracturing engineering parameters, and artificial fracture parameters into the numerical simulator to establish a flowback model.

[0192] The second processing module 1402 is used to obtain the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, determine the maximum production pressure difference based on the production pressure difference corresponding to different nozzle sizes, and determine the nozzle size corresponding to the maximum production pressure difference as the maximum nozzle size of the target shale gas horizontal well. The maximum production pressure difference is the limit pressure difference that the reservoir permeability can recover.

[0193] Module 1403 is established to create an optimal model for nozzle replacement, an optimal model for well opening nozzle size, and an optimal model for increasing / decreasing nozzle size at each stage, based on the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, the flowback model, and the production conditions of the target shale gas horizontal well.

[0194] The determination module 1404 is used to determine the nozzle system of the target shale gas horizontal well based on the nozzle replacement method optimization model, the well opening nozzle size optimization model, and the nozzle increase / decrease range optimization model. The nozzle system includes the nozzle replacement method, the well opening nozzle size, and the nozzle increase / decrease range for each stage.

[0195] Optionally, the second processing module 1402 is specifically used for:

[0196] Obtain the formation pressure of the target shale gas horizontal well, as well as the bottom hole flowing pressure corresponding to different nozzle sizes.

[0197] The production pressure differential corresponding to different nozzle sizes is calculated based on the formation pressure and the bottom-hole flowing pressure corresponding to different nozzle sizes.

[0198] Obtain stress sensitivity curves corresponding to different production pressure differentials.

[0199] Optionally, the second processing module 1402 is also used for:

[0200] The formation pressure of the target shale gas horizontal well is determined based on the formation pressure coefficient and the well depth of the target shale gas horizontal well.

[0201] The bottom-hole flowing pressure corresponding to different nozzle sizes can be obtained using the following formula:

[0202]

[0203] Where E is the elastic modulus of the rock, and H w L is the maximum fracture height in the formation. f For the crack length, w f h is the crack width. f For the crack height, C t Let L be the rock compressibility coefficient and L be the wellbore length. p It is the total length of the wellbore, d c Where is the nozzle diameter, v is the flow velocity of the backflow fluid in the crack, and H is... l P represents the liquid holdup. wf (t0) represents the bottom hole flowing pressure at time t0, P wf (t n ) for t n The bottom pressure at any given moment.

[0204] Optionally, the first processing module 1401 is specifically used for:

[0205] Obtain the actual parameters of the target shale gas horizontal well within a preset time period. The actual parameters include the actual daily gas production, the actual bottom hole pressure, and the actual daily liquid production.

[0206] Based on the orthogonal experimental design, a preset number of shale gas reservoir models are generated, with each shale gas reservoir model corresponding to fracturing parameters with different value ranges.

[0207] Based on embedded discrete fracture EDFM technology, numerical simulation results of various shale gas reservoir models are generated. The numerical simulation results include simulated daily gas production, simulated bottom hole pressure, and simulated daily liquid production.

[0208] The first error value between the numerical simulation results and the actual parameters is calculated. Based on the first error value and the fracturing parameters of each shale gas reservoir model, a surrogate model is established. The surrogate model includes the correspondence between each first error value and the fracturing parameters of its corresponding shale gas reservoir model.

[0209] Based on the Markov chain Monte Carlo inversion algorithm, the values ​​of the fracturing parameters of each shale gas reservoir model in the surrogate model are selected from small to large or from large to small, and the corresponding shale gas numerical model is generated according to the selected values.

[0210] Based on EDFM technology, numerical simulation results of various shale gas numerical models are generated, and the target values ​​of artificial fracture parameters are determined according to the second error value between the numerical simulation results of various shale gas numerical models and the actual parameters.

[0211] The range of values ​​for the fracturing parameters of the shale gas reservoir model is updated based on the target values ​​to gradually narrow down the range of values ​​for the fracturing parameters of the shale gas reservoir model, and finally the optimal artificial fracture parameters are obtained.

[0212] Optionally, the first processing module 1401 is also used for:

[0213] The first error value is calculated based on the following historical fitting error function:

[0214]

[0215] Where n is the number of time points within the preset time period, m is the number of actual parameters, and x ij,model The numerical simulation result of the actual parameter j at time point i, x ij,history Let j be the actual parameter j corresponding to time point i, where i takes the value [1, n] and j takes the value [1, m]. NF j It is a normalized value, defined as the maximum difference between the numerical simulation result and the actual parameters, w ij The weights represent the numerical simulation results.

[0216] Optionally, module 1404 is specifically used for:

[0217] Under the conditions of the optimal model for nozzle replacement method, the optimal model for nozzle size during well opening, and the optimal model for the increase / decrease of nozzles at each stage, the daily gas production and total gas production EUR values ​​corresponding to each nozzle system under different conditions are simulated. The nozzle system corresponding to the maximum value of EUR value and daily gas production is determined as the nozzle system for the target shale gas horizontal well.

[0218] The apparatus of this embodiment can be used to perform the steps of the method for determining the nozzle system in the flowback stage of a shale gas horizontal well as in Embodiments 1 to 3. The specific implementation and technical effects are similar, and will not be described again here.

[0219] Figure 15 This is a schematic diagram of the structure of an electronic device provided in Embodiment 5 of the present invention, as shown below. Figure 15 As shown, the electronic device 150 includes: a processor 1501, a memory 1502, and a transceiver 1503. The memory 1502 is used to store instructions, the transceiver 1503 is used to communicate with other devices, and the processor 1501 is used to execute the instructions stored in the memory so that the device 50 executes the method steps for determining the nozzle system in the flowback stage of any one of the shale gas horizontal wells in Embodiments 1 to 3. The specific implementation and technical effects are similar, and will not be described again here.

[0220] Embodiment 6 of the present invention provides a computer-readable storage medium storing a computer program. When executed by a processor, the computer program is used to implement the method steps for determining the nozzle regime in the flowback stage of any one of the shale gas horizontal wells as described in Embodiments 1 to 3 above. The specific implementation method and technical effects are similar and will not be repeated here.

[0221] Embodiment 7 of the present invention provides a computer program product, including a computer program. When the computer program is executed by a processor, it implements the method and steps for determining the nozzle system in the flowback stage of any one of the shale gas horizontal wells as described in Embodiments 1 to 3 above. The specific implementation method and technical effects are similar, and will not be repeated here.

[0222] Other embodiments of this application will readily occur to those skilled in the art upon consideration of the specification and practice of the invention disclosed herein. This application is intended to cover any variations, uses, or adaptations of this application that follow the general principles of this application and include common knowledge or customary techniques in the art not disclosed herein. The specification and examples are to be considered exemplary only, and the true scope and spirit of this application are indicated by the following claims.

[0223] It should be understood that this application is not limited to the precise structure described above and shown in the accompanying drawings, and various modifications and changes can be made without departing from its scope. The scope of this application is limited only by the appended claims.

Claims

1. A method for determining the nozzle regime during the flowback stage of a shale gas horizontal well, characterized in that, The method includes: Acquire the artificial fracture parameters, geological parameters, and fracturing engineering parameters of the target shale gas horizontal well, and input the geological parameters, fracturing engineering parameters, and artificial fracture parameters into a numerical simulator to establish a flowback model; Obtain the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, determine the maximum production pressure difference based on the production pressure difference corresponding to the different nozzle sizes, and determine the nozzle size corresponding to the maximum production pressure difference as the maximum nozzle size of the target shale gas horizontal well. The maximum production pressure difference is the limit pressure difference that the reservoir permeability can recover. Based on the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, the flowback model, and the production conditions of the target shale gas horizontal well, an optimal model for nozzle replacement method, an optimal model for well opening nozzle size, and an optimal model for the increase / decrease of nozzle size at each stage are established. The nozzle regime for the target shale gas horizontal well is determined based on the preferred model for nozzle replacement method, the preferred model for nozzle size during well opening, and the preferred model for the increase / decrease range of nozzles at each stage. The nozzle regime includes the nozzle replacement method, the nozzle size during well opening, and the increase / decrease range of nozzles at each stage.

2. The method according to claim 1, characterized in that, The process of obtaining the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes includes: Obtain the formation pressure of the target shale gas horizontal well, and the bottom hole flowing pressure corresponding to different nozzle sizes; Calculate the production pressure difference corresponding to different nozzle sizes based on the formation pressure and the bottom-hole flowing pressure corresponding to different nozzle sizes; Obtain stress sensitivity curves corresponding to different production pressure differentials.

3. The method according to claim 2, characterized in that, The process of obtaining the formation pressure of the target shale gas horizontal well and the bottom hole flowing pressure corresponding to different nozzle sizes includes: The formation pressure of the target shale gas horizontal well is determined based on the formation pressure coefficient and the well depth of the target shale gas horizontal well. The bottom-hole flowing pressure corresponding to different nozzle sizes can be obtained using the following formula: Where E is the elastic modulus of the rock, and H w L is the maximum fracture height in the formation. f For the crack length, w f h is the crack width. f For the crack height, C t Let L be the rock compressibility coefficient and L be the wellbore length. p It is the total length of the wellbore, d c Where is the nozzle diameter, v is the flow velocity of the backflow fluid in the crack, and H is... l P represents the liquid holdup. wf (t0) represents the bottom hole flowing pressure at time t0, P wf (t n ) for t n The bottom pressure at any given moment.

4. The method according to any one of claims 1-3, characterized in that, The acquisition of artificial fracture parameters for the target shale gas horizontal well includes: Obtain the actual parameters of the target shale gas horizontal well within a preset time period, including the actual daily gas production, actual bottom hole pressure, and actual daily liquid production. Based on the orthogonal experimental method, a preset number of shale gas reservoir models are generated, and each shale gas reservoir model corresponds to fracturing parameters with different value ranges. Based on embedded discrete fracture EDFM technology, numerical simulation results of various shale gas reservoir models are generated. The numerical simulation results include simulated daily gas production, simulated bottom hole pressure, and simulated daily liquid production. Calculate the first error value between the numerical simulation results and the actual parameters, and establish a surrogate model based on the first error value and the fracturing parameters of each shale gas reservoir model. The surrogate model includes the correspondence between each first error value and the fracturing parameters of its corresponding shale gas reservoir model. Based on the Markov chain Monte Carlo inversion algorithm, the values ​​of the fracturing parameters of each shale gas reservoir model in the proxy model are selected from small to large or from large to small, and the corresponding shale gas numerical model is generated according to the selected values. Based on the EDFM technology, numerical simulation results of each shale gas numerical model are generated, and the target value of the artificial fracture parameter is determined according to the second error value between the calculated numerical simulation results of each shale gas numerical model and the actual parameter. The range of values ​​for the fracturing parameters of the shale gas reservoir model is updated based on the target value to gradually narrow the range of values ​​for the fracturing parameters of the shale gas reservoir model, and finally the optimal artificial fracture parameters are obtained.

5. The method according to claim 4, characterized in that, The calculation of the first error value between the numerical simulation result and the actual parameters includes: The first error value is calculated based on the following historical fitting error function: Where n is the number of time points within the preset time period, m is the number of actual parameters, and x ij,model The numerical simulation result of the actual parameter j at time point i, x ij,history Let j be the actual parameter j corresponding to time point i, where i takes the value [1, n] and j takes the value [1, m]. NF j It is a normalized value, defined as the maximum difference between the numerical simulation result and the actual parameters, w ij The weights represent the numerical simulation results.

6. The method according to any one of claims 1-3 or 5, characterized in that, The process of determining the nozzle regime for the target shale gas horizontal well based on the nozzle replacement method optimization model, the well opening nozzle size optimization model, and the nozzle increase / decrease range optimization model for each stage includes: Under the conditions of the preferred model for nozzle replacement method, the preferred model for well opening nozzle size, and the preferred model for the increase / decrease range of each nozzle stage, the daily gas production and total gas production EUR values ​​corresponding to each nozzle system under different conditions are simulated. The nozzle system corresponding to the maximum value of the EUR value and the maximum daily gas production is determined as the nozzle system of the target shale gas horizontal well.

7. A device for determining the nozzle regime during the flowback stage of a shale gas horizontal well, characterized in that, The device includes: The first processing module is used to acquire the artificial fracture parameters, geological parameters, and fracturing engineering parameters of the target shale gas horizontal well, and input the geological parameters, the fracturing engineering parameters, and the artificial fracture parameters into the numerical simulator to establish a flowback model; The second processing module is used to obtain the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, determine the maximum production pressure difference according to the production pressure difference corresponding to the different nozzle sizes, and determine the nozzle size corresponding to the maximum production pressure difference as the maximum nozzle size of the target shale gas horizontal well. The maximum production pressure difference is the limit pressure difference that the reservoir permeability can recover. A module is established to create an optimal model for nozzle replacement, an optimal model for well opening nozzle size, and an optimal model for increasing / decreasing the nozzle size at each stage, based on the production pressure difference and stress sensitivity curves corresponding to different nozzle sizes, the flowback model, and the production conditions of the target shale gas horizontal well. The determination module is used to determine the nozzle regime of the target shale gas horizontal well based on the nozzle replacement method optimization model, the well opening nozzle size optimization model, and the nozzle increase / decrease range optimization model for each stage. The nozzle regime includes the nozzle replacement method, the well opening nozzle size, and the nozzle increase / decrease range for each stage.

8. The apparatus according to claim 7, characterized in that, The second processing module is specifically used for: Obtain the formation pressure of the target shale gas horizontal well, and the bottom hole flowing pressure corresponding to different nozzle sizes; Calculate the production pressure difference corresponding to different nozzle sizes based on the formation pressure and the bottom-hole flowing pressure corresponding to different nozzle sizes; Obtain stress sensitivity curves corresponding to different production pressure differentials.

9. An electronic device, characterized in that, include: A processor, and a memory communicatively connected to the processor; The memory stores computer-executed instructions; The processor executes the computer execution instructions stored in the memory to implement the method for determining the nozzle regime during the flowback stage of a shale gas horizontal well as described in any one of claims 1-6.

10. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores computer-executable instructions, which, when executed by a processor, are used to implement the method for determining the nozzle regime during the flowback stage of a shale gas horizontal well as described in any one of claims 1-6.

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