Method and device for establishing fine choke system in middle-deep shale gas horizontal well flow-back stage

Abstract

The application provides a method and device for establishing a fine choke system in a middle-deep shale gas horizontal well flowback stage, and the method comprises the following steps: S100, collecting original data of a research area; S200, calculating a production pressure difference corresponding to different choke sizes; S300, obtaining a stress sensitivity curve of the production pressure difference corresponding to different choke sizes; S400, obtaining artificial fracture parameters through history matching; S500, establishing a flowback model; S600, establishing a flowback numerical model; and S700, analyzing based on a numerical simulation result of the flowback numerical model. The application solves the problem that a field horizontal well flowback system lacks theoretical support and technical guidance, can reduce the influence of stress sensitivity damage, support agent backflow and embedding, and ground process erosion or blockage in the flowback process, and lays a foundation for maximizing the productivity of a shale gas well.

Description

Technical Field

[0001] This invention relates to the field of shale development technology, and more specifically, to a method and apparatus for establishing a fine nozzle system during the flowback stage of a horizontal well in medium-deep shale gas formation. Background Technology

[0002] Throughout the entire lifecycle of a shale gas well, effectively managing the well is crucial. After large-scale volumetric fracturing, tens of thousands of cubic meters of fracturing fluid remain trapped in the shale reservoir. Maximizing shale gas well productivity hinges on employing a reasonable flowback system to remove this fluid while minimizing reservoir damage. A vital component of this flowback system is the nozzle system. Developing a precise nozzle system is key to determining the appropriate nozzle size for different time periods. A well-designed nozzle system directly impacts the extent of formation stress-sensitive damage. Oversized nozzles lead to excessive production pressure differentials, resulting in greater stress-sensitive damage and significantly reduced early fracture conductivity, causing proppant backflow and embedding, as well as surface erosion or blockage. Therefore, establishing a reasonable and precise nozzle system before the flowback phase is essential.

[0003] Currently, there is limited research on the establishment of a reasonable nozzle system by scholars both domestically and internationally. Most studies focus on the flowback mechanism of shale gas wells and statistical analysis of production data. Therefore, there is an urgent need to conduct research on the formulation of a refined nozzle system for the flowback stage of shale gas horizontal wells. Summary of the Invention

[0004] This invention aims to provide a method and apparatus for establishing a refined nozzle regime during the flowback stage of mid-deep shale gas horizontal wells, in order to address the lack of theoretical support for the formulation of refined nozzle regimes during the flowback stage of existing shale gas horizontal wells. This method can clarify the reasonable duration for different nozzle sizes, the reasonable duration for small nozzle sizes, and the optimal small nozzle size under the reasonable duration, providing a theoretical basis and practical guidance for determining the refined nozzle regime during the flowback stage of shale gas horizontal wells.

[0005] This invention provides a method for establishing a fine nozzle system during the flowback stage of a mid-to-deep shale gas horizontal well, comprising the following steps:

[0006] Step S100: Collect raw data for the study area;

[0007] Step S200: Calculate the production pressure difference corresponding to different nozzle sizes through numerical simulation;

[0008] Step S300: Conduct stress sensitivity experiments on medium-deep shale to obtain stress sensitivity curves of production pressure differentials corresponding to different nozzle sizes;

[0009] Step S400: Obtain artificial crack parameters through historical fitting;

[0010] In step S500, the collected raw data and the artificial fracture parameters obtained after historical fitting in step S400 are combined with the shale adsorption and desorption characteristics, the stress sensitivity effect of the fracture, and the production pressure difference corresponding to different nozzle sizes obtained from the pipeline flow calculation in step S200. The numerical model is then improved by substituting these parameters into the numerical simulator to establish a backflow model.

[0011] Step S600: Using the stress sensitivity curve and the established run-out model, a production pressure difference sensitivity analysis is performed, thereby establishing a run-out numerical model.

[0012] Step S700: Based on the numerical simulation results of the return flow numerical model, analyze the optimal number of days for each nozzle size, the optimal number of days for the small nozzle size, and the optimal small nozzle size under a reasonable number of days.

[0013] Furthermore, the raw data collected in step S100 are porosity, permeability, adsorption-desorption parameters, and gas saturation obtained by averaging the results of typical shale core experiments.

[0014] Furthermore, the method for calculating the production pressure difference corresponding to different nozzle sizes through numerical simulation in step S200 includes:

[0015] S210, calculate formation pressure;

[0016] S220, establish the relationship between the outflow volume of the backflow fluid and the nozzle size;

[0017] S230 describes the process of shale gas well backflow fluid flowing out of the nozzle through the wellbore and establishes the relationship between nozzle size and bottom hole flowing pressure.

[0018] S240, calculate the bottom hole flowing pressure corresponding to different nozzle sizes;

[0019] S250, the production pressure difference corresponding to different nozzle sizes is calculated as: formation pressure - bottom hole flowing pressure.

[0020] Furthermore, the method for calculating formation pressure in step S210 is as follows:

[0021] P 地 =GH=G(H A -H B (1)

[0022] Among them, P 地 G is the formation pressure, MPa; G is the formation pressure coefficient, MPa / m; H is the well depth, m; H A HB is the vertical depth of point A in the horizontal well, in meters; HB is the vertical depth of point B in the horizontal well, in meters.

[0023] Furthermore, in step S220, a relationship between the outflow volume of the return fluid and the nozzle size is established using numerical simulation software.

[0024] Furthermore, in step S230, numerical simulation software is used to describe the process of the shale gas well flowback fluid through the wellbore and out of the nozzle, and to establish the relationship between the nozzle size and the bottom hole flowing pressure.

[0025] Furthermore, the numerical simulation software is pipesim, a pipe flow calculation software.

[0026] Furthermore, the method for obtaining artificial fracture parameters through historical fitting in step S400 is as follows: using artificial intelligence-neural network sampling method to achieve historical fitting of three parameters: daily gas production, daily water production, and bottom hole flowing pressure, thereby obtaining artificial fracture parameters that conform to reality.

[0027] This invention also provides a device for establishing a fine nozzle system for the flowback stage of a mid-deep shale gas horizontal well. The device is used to implement the above-mentioned method for establishing a fine nozzle system for the flowback stage of a mid-deep shale gas horizontal well. The device includes: a first correlation determination module, a second correlation determination module, a third correlation determination module, a fourth correlation determination module, and a target correspondence determination module.

[0028] The first correlation determination module is used to determine the basic parameter inputs of flowback models for different sizes of nozzle systems. The basic parameters input include geological condition parameters and reservoir physical property parameters. The geological condition parameters are used to determine the structural accuracy of flowback models for different sizes of nozzle systems, and the reservoir physical property parameters are used to finely depict the reservoir properties of shale gas wells, which can improve the matching degree between the model and the actual formation and gas well.

[0029] The second correlation determination module is used to determine the flow relationship between the coupled formation, wellbore and surface nozzle. It uses pipe flow calculation to determine the production pressure difference corresponding to the size of nozzles of different wellhead devices. It uses numerical simulation to realize the connection between mechanism and field system, and lays the parameter foundation for simulating the flowback system of nozzle system through numerical simulator.

[0030] The third correlation determination module is used to determine the stress sensitivity changes under different nozzle sizes in the flowback numerical model, so that the nozzle system simulation results are more in line with the actual formation stress sensitivity changes.

[0031] The fourth correlation determination module is used to determine the values ​​of artificial fracture parameters after hydraulic fracturing of shale gas wells, thereby improving the accuracy of artificial fracture parameters in the numerical model and making the fracture model of the flowback model more consistent with the evolution of artificial fractures after hydraulic fracturing in actual gas wells.

[0032] The target correspondence determination module is used to establish a fine nozzle system for the flowback stage of the medium-deep shale gas horizontal well based on different nozzle system flowback models established by the first correlation determination module, the second correlation determination module, the third correlation determination module, and the fourth correlation determination module.

[0033] In summary, due to the adoption of the above technical solution, the beneficial effects of the present invention are:

[0034] This invention patent solves the problem of lack of theoretical support and technical guidance in the formulation of on-site horizontal well flowback systems. 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 production capacity of shale gas wells. Attached Figure Description

[0035] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings in the embodiments will be briefly described below. It should be understood that the following drawings only show some embodiments of the present invention and should not be regarded as a limitation on the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort.

[0036] Figure 1 A flowchart illustrating the method for establishing a fine nozzle system during the flowback stage of horizontal wells in medium-deep shale gas formations.

[0037] Figure 2 This is a pressure profile of a wellbore with a 12mm nozzle size.

[0038] Figure 3 This is a stress sensitivity curve diagram corresponding to different production pressure differentials under medium-deep conditions.

[0039] Figure 4 This is a simulation diagram of the backflow model.

[0040] Figure 5 A comparison chart of daily gas production for different nozzles over a three-month period.

[0041] Figure 6 A comparison chart of EUR for different nozzle durations.

[0042] Figure 7 A comparison chart of daily gas production of a 3mm nozzle over three months at different durations.

[0043] Figure 8 A comparison chart of EUR for different durations of a 3mm nozzle.

[0044] Figure 9 A comparison chart of daily gas production for different nozzle sizes over 15 days (3 months).

[0045] Figure 10 A comparison chart of EUR values ​​for different small nozzle sizes over 15 days.

[0046] Figure 11 A structural diagram of the device for establishing a fine nozzle system during the flowback stage of a mid-deep shale gas horizontal well. Detailed Implementation

[0047] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0048] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0049] Example

[0050] like Figure 1 As shown in the figure, this embodiment proposes a method for establishing a fine nozzle system during the flowback stage of a mid-deep shale gas horizontal well, including the following steps:

[0051] Step S100: Collect raw data of the study area. The raw data includes geological condition parameters and reservoir physical property parameters. Among them, the geological condition parameters include the development of regional network fractures or fractures in a single direction, and whether the area is located in a syncline or anticline. The reservoir physical property parameters include matrix permeability, matrix porosity, matrix water saturation, adsorption and desorption parameters, rock compressibility coefficient, capillary force curve, and relative permeability curve, etc.

[0052] This embodiment uses the Changning Block as the study area, clearly defining the study area and ensuring the consistency of geology and reservoir throughout the entire study area. The raw data collected from the indoor experiments are parameters such as porosity, permeability, adsorption and desorption parameters, and gas saturation obtained by averaging the results of typical shale core experiments.

[0053] Step S200: Calculate the production pressure difference corresponding to different nozzle sizes through numerical simulation;

[0054] This embodiment selects the commonly used nozzle size of 3mm~12mm as the calculation object, and calculates the production pressure difference (formation pressure - bottom hole flowing pressure) corresponding to different nozzle sizes through numerical simulation. This lays the data foundation for the subsequent selection of the maximum nozzle size based on experiments, and also provides a technical method for adding the nozzle size simulation to the subsequent flowback model.

[0055] The method for calculating the production pressure difference corresponding to different nozzle sizes through numerical simulation includes:

[0056] S210, Calculate formation pressure

[0057] The formation pressure of a shale gas reservoir is the pressure acting on the pore fluid in the rock, and its value is the formation pressure coefficient multiplied by the well depth, i.e.:

[0058] P 地 =GH=G(H A -H B (1)

[0059] Among them, P 地 G is the formation pressure, MPa; G is the formation pressure coefficient, MPa / m; H is the well depth, m; H A HB is the vertical depth of point A in the horizontal well, in meters; HB is the vertical depth of point B in the horizontal well, in meters.

[0060] S220, Establish the relationship between the outflow volume of the backflow fluid and the nozzle size.

[0061] To couple the formation flow model with the nozzle system design, the backflow fluid will flow out through the nozzle. Therefore, numerical simulation software (pipesim pipe flow calculation software) is used to perform pressure calculations on the nozzle flow, thereby establishing the relationship between the backflow fluid outflow volume and the nozzle size.

[0062] S230 uses numerical simulation software (pipesim pipe flow calculation software) to describe the process of shale gas well backflow fluid flowing out of the nozzle through the wellbore, and establishes the relationship between nozzle size and bottom hole flowing pressure.

[0063] S240, calculate the bottom hole flowing pressure corresponding to different nozzle sizes.

[0064] By calculating the gas-water two-phase flow in the vertical wellbore of a shale gas well using numerical simulation software, the flow state in the wellbore corresponding to different nozzle sizes is calculated, thereby determining the bottomhole flowing pressure for different nozzle sizes. The Hagedorn-Brown vertical pipe two-phase flow calculation method can be used. The pressure drop relationship of the gas-water two-phase flow in the riser pipe under different flow patterns is clarified, satisfying the pipe flow calculation of shale gas and fracturing fluid two-phase flow in the shale gas wellbore, and the bottomhole flowing pressure under different nozzle sizes is obtained.

[0065] S250: Based on the numerical model constructed in step S240, establish the flow coupling relationship between the formation, wellbore, and nozzle, characterize the gas-water two-phase flow in the shale gas well, and thus calculate the wellbore pressure corresponding to different nozzle sizes, such as... Figure 2 As shown in Table 1, the production pressure difference corresponding to different nozzle sizes is calculated. In this embodiment, the commonly used nozzle sizes in the field are selected from 3mm to 12mm. The production pressure difference corresponding to different nozzle sizes is shown in Table 1.

[0066] Table 1. Production pressure difference corresponding to different nozzle sizes obtained in this embodiment:

[0067]

[0068] Step S300: Conduct stress sensitivity experiments on medium-deep shale to obtain stress sensitivity curves for production pressure differentials corresponding to different nozzle sizes; this embodiment uses indoor experimental shale core stress sensitivity experiments to obtain stress sensitivity curves for production pressure differentials corresponding to different nozzle sizes, such as... Figure 3 As shown, the stress sensitivity curves are input curves for different nozzle size values ​​used in the establishment of the stress sensitivity model for the backflow process, representing the stress variation under different nozzle sizes (production pressure difference).

[0069] Step S400: Obtain artificial crack parameters through historical fitting;

[0070] In this embodiment, the numerical simulation method of artificial intelligence-neural network sampling is used to achieve historical fitting of three parameters: daily gas production, daily water production and bottom hole flowing pressure, so as to obtain artificial fracture parameters that conform to reality.

[0071] Table 2. Artificial crack parameters obtained from historical fitting:

[0072]

[0073] The aforementioned historical fitting process yielded fracture parameters that closely approximate the actual post-compression fracture morphology of shale formations. These realistic fracture parameters characterize the fracture properties and can lay the foundation for improving the simulation accuracy of subsequent backflow models.

[0074] In step S500, the collected raw data is combined with the artificial fracture parameters obtained after historical fitting in step S400. Considering shale adsorption and desorption characteristics, the stress sensitivity effect of fractures, and the production pressure differentials corresponding to different nozzle sizes obtained from pipe flow calculation in step S200, the numerical model is refined in the numerical simulator to establish a flowback model. The basic numerical model describing the flowback stage of shale gas wells established in this embodiment is as follows: Figure 4 As shown.

[0075] Step S600 involves using the stress sensitivity curves obtained from the indoor experiments in step S300 and conducting a production pressure differential sensitivity analysis using the established runoff model, thereby establishing a runoff numerical model. Specifically, based on the runoff model established in S500, the calculated values ​​for each step of the numerical model are designed using the production pressure differentials corresponding to different nozzle sizes calculated in step S200. Different nozzle size combinations are then designed to establish simulation models for different nozzle regimes. The stress sensitivity curves obtained from the indoor experiments are then input into the numerical simulator via scripting, simulating the stress sensitivity curves corresponding to each nozzle size to reflect the actual stress sensitivity effect under different production pressure differentials in the actual formation. Finally, numerical simulation conditions such as production regime and development years are set for different nozzle regime models to simulate different nozzle regimes in the field. The resulting runoff numerical models under different nozzle regimes are of the following three types:

[0076] (1) Establish a system model for the optimal duration of each nozzle size.

[0077] Five production pressure differential sensitivity analysis models were established to simulate the optimal duration for each nozzle size level. In each model, the nozzle size increases progressively from 3mm to 9mm, with each increase being 1mm. The stress sensitivity curves for the production pressure differential corresponding to each nozzle size level were previously obtained experimentally. Here, the stress sensitivity curves for different nozzle sizes were input into the production pressure differential sensitivity analysis models by editing the model script, making the models more closely reflect actual production conditions. Five production pressure differential sensitivity analysis models were established with durations of 1 day, 2 days, 3 days, 4 days, and 5 days for each stage. A 9mm nozzle was used in the production phase, simulating two scenarios: a total production time of 3 months and 20 years.

[0078] ②Establish a system model for the optimal number of continuous days for small nozzle sizes.

[0079] Seven production pressure differential sensitivity analysis models were established to simulate the optimal duration of small nozzles. The nozzle size remained constant at 3mm during the run-out period in each model. Seven production pressure differential sensitivity analysis models were established for 3mm nozzle durations of 1 day, 5 days, 10 days, 15 days, 20 days, 25 days, and 30 days. Numerical simulations were performed using these models. The stress sensitivity curves under the 3mm nozzle size (production pressure differential) were used in the simulations. A 9mm nozzle was used during the production phase, simulating two scenarios with a total production time of 3 months and 20 years.

[0080] ③ Establish an optimal nozzle size system model under a reasonable number of continuous days.

[0081] Five production pressure differential sensitivity analysis models were established to simulate the optimal small nozzle size under a reasonable duration. In each model, the nozzle size increases progressively from 3mm to 9mm, with each increment being 1mm. Five production pressure differential sensitivity analysis models were established with small nozzles lasting 15 days and nozzle sizes of 3mm, 4mm, 5mm, 6mm, and 7mm. Other nozzle sizes in the models lasted for 3 days. Numerical simulations were performed using these models, employing different stress sensitivity curves for different nozzle sizes (under different production pressure differentials). A 9mm nozzle was used in the production phase, simulating two scenarios: a total production time of 3 months and 20 years.

[0082] Step S700: Based on the numerical simulation results of the backflow numerical model, study the optimal number of days for each nozzle size, the optimal number of days for the small nozzle size, and the optimal small nozzle size under a reasonable number of days.

[0083] (1) Research on the optimal number of continuous days for each level of nozzle size in the establishment of a refined nozzle system

[0084] The specific method is as follows: Based on the numerical simulation results of the optimal duration model for each nozzle size in step S600, observe the changes and magnitudes of daily gas production over three months for different durations of each nozzle stage; the larger the curve value, the better the effect. Furthermore, observe the 20-year EUR value and curve changes for different durations of each nozzle stage; the higher the EUR value, the optimal duration for each nozzle size. Analyze the results through the numerical simulation, such as... Figure 5 , Figure 6 As shown, the horizontal and vertical axes represent time and production, respectively. The comparison of their changes under different regimes helps to optimize the optimal nozzle duration days. The results show that the higher the duration of each nozzle stage, the lower the initial daily gas production within 3 months, and the higher the gas production in the later period. However, the increase becomes smaller after exceeding 3 days. After increasing the duration of each nozzle stage to 3 days, the 20-year EUR value does not change significantly. The EUR value for 3 days is 5.13% higher than that for 1 day, indicating that the optimal duration for each nozzle size determined by the method in this application is at least 3 days, allowing the gas well to achieve a higher cumulative gas production. With increasing production time, the improvement in final recoverable reserves becomes more significant with the optimal nozzle duration regime. This indicates that under a more stable nozzle regime, there is less proppant backflow, embedding, and breakage, resulting in lower stress-sensitive damage and thus protecting the gas well's productivity, leading to a higher EUR value. In contrast, the EUR of gas wells under an unreasonable nozzle size duration regime will significantly decrease, highlighting the necessity of using this method to refine and determine the optimal nozzle size duration regime.

[0085] (2) Research on the optimal continuous days of small nozzle size in the establishment of a refined nozzle system

[0086] The specific method is as follows: Based on the numerical simulation results of the optimal continuous days model for small nozzle size in step S600, observe the changes and magnitudes of daily gas production over 3 months for different continuous days for small nozzles; the larger the curve value, the better the effect. Furthermore, observe the 20-year EUR value and curve changes for different continuous days for small nozzles; the higher the EUR value, the optimal continuous days for small nozzle size. Through analysis of the numerical simulation results, such as... Figure 7 , Figure 8 As shown, the longer the duration of the 3mm nozzle, the higher the peak daily gas production, and the higher the daily gas production in the mid-to-late stages, but the increase decreases after exceeding 15 days. With increasing 3mm nozzle duration, the 20-year EUR increases, but the increasing trend slows down. When the 3mm nozzle duration exceeds 15 days, the EUR remains almost unchanged, with a 15-day duration resulting in a 5.64% higher EUR than a 1-day duration. This indicates that a small nozzle size duration of at least 15 days, determined by the method in this application, allows gas wells to achieve higher cumulative gas production. The increase in production time makes the optimal small nozzle duration regime more significant in improving the final recoverable reserves. This shows that the longer the small nozzle size duration, the longer the stress-sensitive damage level remains within a low damage range, significantly suppressing early damage such as proppant backflow, embedding, breakage, and surface process blockage, thus protecting the gas well's productivity and increasing its value. In contrast, under an unreasonable small nozzle size duration regime, gas well stress-sensitive damage increases and becomes irreversible, significantly reducing the EUR, demonstrating the necessity of using this method to refine and determine the optimal nozzle size duration regime.

[0087] (3) Research on the optimal small nozzle size under a reasonable number of continuous days for the establishment of a refined nozzle system

[0088] The specific method is as follows: Based on the numerical simulation results of the optimal small nozzle size model under the reasonable number of continuous days in step S600, observe the changes and magnitudes of daily gas production over 3 months under different small nozzle sizes for the reasonable number of continuous days; the larger the curve value, the better the effect. Furthermore, observe the 20-year EUR value and curve changes under different small nozzle sizes for the reasonable number of continuous days; the higher the EUR value, the optimal small nozzle size for the reasonable number of continuous days. Through analysis of the numerical simulation results, such as... Figure 9 , Figure 10As shown, the 3mm nozzle, when used for 15 days (3 months), resulted in the lowest early-stage daily gas production, but higher peak and mid-to-late-stage production compared to other sizes. The 3mm nozzle, when used for 15 days (20 years), yielded the highest EUR (Earnings Per Hour), and the decrease in EUR increased with increasing nozzle size, with a 10.13% increase in EUR for 3mm nozzles compared to 7mm nozzles. This indicates that, under the 15-day duration determined by the method in this application, a 3mm nozzle is optimal, allowing the gas well to achieve a higher cumulative gas production. The longer the duration of the minimum nozzle size, the lower and more easily recoverable the stress-sensitive damage value, thus protecting the gas well's productivity and increasing its value. In contrast, under an unreasonable small nozzle size regime during the 15-day duration, the gas well experiences increased and irreversible stress-sensitive damage, resulting in a significant decrease in EUR. This underscores the necessity of using this method to determine the optimal small nozzle size regime for a reasonable duration.

[0089] The simulation results above show that optimizing the nozzle system using the simulation results of this method can effectively improve the EUR of a single well, achieve the purpose of protecting the reservoir and the conductivity of artificial fractures, effectively reduce stress-sensitive damage, truly achieve "well management", maximize the gas well production capacity, and improve the recovery rate of a single well.

[0090] Figure 11 This is a structural diagram of an embodiment of the device for establishing a refined nozzle system for the flowback stage of a mid-deep shale gas horizontal well according to the present invention. The device provides geological condition parameters, reservoir property parameters, historical fitting parameters, laboratory experimental stress-sensitive curves, and flowback models for different nozzle systems for mid-deep shale gas. The geological condition parameters include regionally developed network fractures or unidirectional fractures, and whether the area is located in a syncline or anticline; the reservoir property parameters include matrix permeability, matrix porosity, matrix water saturation, adsorption / desorption parameters, rock compressibility coefficient, capillary force curve, and relative permeability curve; the historical fitting parameters include artificial fracture height, half-length, conductivity, water saturation, width, and cluster efficiency; the stress-sensitive curves include stress-sensitive curves corresponding to production pressure differentials for different nozzle sizes; and the nozzle system models include three refined nozzle system establishment models. Figure 11 As shown, the device for establishing a fine nozzle system for the flowback stage of a medium-deep shale gas horizontal well includes: a first correlation determination module, a second correlation determination module, a third correlation determination module, a fourth correlation determination module, and a target correspondence determination module.

[0091] The first correlation determination module is used to determine the basic parameter inputs of flowback models for different sizes of nozzle systems. This includes the collection of raw data from the study area. The basic parameters input include geological condition parameters and reservoir property parameters. The geological condition parameters are used to determine the structural accuracy of flowback models for different sizes of nozzle systems, and the reservoir property parameters are used to finely depict the reservoir properties of shale gas wells, which can improve the matching degree between the model and the actual formation and gas well.

[0092] The second correlation determination module includes the calculation of production pressure difference corresponding to different nozzle sizes, which is used to determine the flow relationship between the coupled formation, wellbore and surface nozzle. The production pressure difference corresponding to the nozzle size of different wellhead devices is determined by pipeline flow calculation. Numerical simulation is used to realize the connection between mechanism and field system, laying the parameter foundation for the nozzle system of backflow system to be simulated by numerical simulator.

[0093] The third correlation determination module includes conducting deep stress sensitivity experiments to determine the stress sensitivity changes under different nozzle sizes (production pressure difference) in the flowback numerical model, so that the nozzle system simulation results are more consistent with the actual formation stress sensitivity changes.

[0094] The fourth correlation determination module includes historical fitting to obtain artificial fracture parameters, which are used to determine the values ​​of artificial fracture parameters after hydraulic fracturing of shale gas wells. This improves the accuracy of artificial fracture parameters in the numerical model and makes the fracture model of the flowback model more consistent with the evolution of artificial fractures after hydraulic fracturing in actual gas wells.

[0095] The target correspondence determination module includes the establishment of a return flow model and a system model. It is used to establish a fine nozzle system for the return flow stage of the medium-deep shale gas horizontal well based on different nozzle system return flow models established by the first correlation determination module, the second correlation determination module, the third correlation determination module, and the fourth correlation determination module.

[0096] The above description is merely a preferred embodiment of the present invention and is not intended to limit the invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for establishing a fine nozzle system for the flowback stage of a mid-deep shale gas horizontal well, characterized in that, Includes the following steps: Step S100: Collect raw data for the study area; Step S200: Calculate the production pressure difference corresponding to different nozzle sizes through numerical simulation; Step S300: Conduct stress sensitivity experiments on medium-deep shale to obtain stress sensitivity curves of production pressure differentials corresponding to different nozzle sizes; Step S400: Obtain artificial crack parameters through historical fitting; In step S500, the collected raw data and the artificial fracture parameters obtained after historical fitting in step S400 are combined with the shale adsorption and desorption characteristics, the stress sensitivity effect of the fracture, and the production pressure difference corresponding to different nozzle sizes obtained from the pipeline flow calculation in step S200. The numerical model is then improved by substituting these parameters into the numerical simulator to establish a backflow model. Step S600: Using the stress sensitivity curve and the established run-out model, a production pressure difference sensitivity analysis is performed, thereby establishing a run-out numerical model. Step S700: Based on the numerical simulation results of the return flow numerical model, analyze the optimal number of days for each nozzle size, the optimal number of days for the small nozzle size, and the optimal small nozzle size under a reasonable number of days.

2. The method for establishing a fine nozzle system for the flowback stage of mid-deep shale gas horizontal wells according to claim 1, characterized in that, The raw data collected in step S100 are porosity, permeability, adsorption and desorption parameters and gas saturation obtained by averaging the results of typical shale core experiments.

3. The method for establishing a fine nozzle system for the flowback stage of mid-deep shale gas horizontal wells according to claim 1, characterized in that, The method for calculating the production pressure difference corresponding to different nozzle sizes through numerical simulation in step S200 includes: S210, calculate formation pressure; S220, establish the relationship between the outflow volume of the backflow fluid and the nozzle size; S230 describes the process of shale gas well backflow fluid flowing out of the nozzle through the wellbore and establishes the relationship between nozzle size and bottom hole flowing pressure. S240, calculate the bottom hole flowing pressure corresponding to different nozzle sizes; S250, the production pressure difference corresponding to different nozzle sizes is calculated as: formation pressure - bottom hole flowing pressure.

4. The method for establishing a fine nozzle system for the flowback stage of mid-deep shale gas horizontal wells according to claim 3, characterized in that, The method for calculating formation pressure in step S210 is as follows: P 地 =GH=G(H A -H B )(1) Among them, P 地 G is the formation pressure, MPa; G is the formation pressure coefficient, MPa / m; H is the well depth, m; H A HB is the vertical depth of point A in the horizontal well, in meters; HB is the vertical depth of point B in the horizontal well, in meters.

5. The method for establishing a fine nozzle system for the flowback stage of mid-deep shale gas horizontal wells according to claim 3, characterized in that, In step S220, the relationship between the outflow volume of the return fluid and the nozzle size is established using numerical simulation software.

6. The method for establishing a fine nozzle system for the flowback stage of mid-deep shale gas horizontal wells according to claim 3, characterized in that, In step S230, numerical simulation software is used to describe the process of the shale gas well flowback fluid through the wellbore and out of the nozzle, and to establish the relationship between the nozzle size and the bottom hole flowing pressure.

7. The method for establishing a fine nozzle system for the flowback stage of mid-deep shale gas horizontal wells according to claim 5 or 6, characterized in that, The numerical simulation software is pipesim, a pipe flow calculation software.

8. The method for establishing a fine nozzle system for the flowback stage of mid-deep shale gas horizontal wells according to claim 1, characterized in that, The method for obtaining artificial fracture parameters through historical fitting in step S400 is as follows: an artificial intelligence-neural network sampling method is used to achieve historical fitting of three parameters: daily gas production, daily water production, and bottom hole flowing pressure, thereby obtaining artificial fracture parameters that conform to reality.

9. A device for establishing a fine nozzle system during the flowback stage of a mid-deep shale gas horizontal well, characterized in that, The device is used to implement the method for establishing a fine nozzle system for the flowback stage of a medium-deep shale gas horizontal well as described in any one of claims 1-8; The device includes: a first association relationship determination module, a second association relationship determination module, a third association relationship determination module, a fourth association relationship determination module, and a target correspondence relationship determination module; The first correlation determination module is used to determine the basic parameter inputs of flowback models for different sizes of nozzle systems. The basic parameters input include geological condition parameters and reservoir physical property parameters. The geological condition parameters are used to determine the structural accuracy of flowback models for different sizes of nozzle systems, and the reservoir physical property parameters are used to finely depict the reservoir properties of shale gas wells and improve the matching degree between the model and the actual formation and gas well. The second correlation determination module is used to determine the flow relationship between the coupled formation, wellbore and surface nozzle. It uses pipe flow calculation to determine the production pressure difference corresponding to the size of the nozzle of different wellhead devices, and uses numerical simulation to realize the connection between mechanism and field system. The third correlation determination module is used to determine the stress sensitivity changes under different nozzle sizes in the flowback numerical model, so that the nozzle system simulation results are more in line with the actual formation stress sensitivity changes. The fourth correlation determination module is used to determine the values ​​of artificial fracture parameters after hydraulic fracturing of shale gas wells, thereby improving the accuracy of artificial fracture parameters in the numerical model and making the fracture model of the flowback model more consistent with the evolution of artificial fractures after hydraulic fracturing in actual gas wells. The target correspondence determination module is used to establish a fine nozzle system for the flowback stage of the medium-deep shale gas horizontal well based on different nozzle system flowback models established by the first correlation determination module, the second correlation determination module, the third correlation determination module, and the fourth correlation determination module.

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