Shale gas horizontal well liquid discharge method and device, electronic equipment and storage medium

Abstract

This application discloses a method, apparatus, electronic equipment, and storage medium for draining fluid from a shale gas horizontal well, relating to the field of shale gas extraction technology. The method includes: obtaining the initial production rate of the target shale gas horizontal well; calculating the expected shale gas production rate under different preset draining rates based on the initial production rate, a preset production time, a first production loss coefficient, and a second production loss coefficient, wherein the first production loss coefficient reflects the degree of production reduction caused by reservoir pressure depletion, and the second production loss coefficient reflects the degree of production reduction caused by reservoir stress sensitivity; determining the target draining rate among the preset draining rates based on the expected shale gas production rate; and performing draining operations on the target shale gas horizontal well according to the target draining rate. This application, by introducing a production loss coefficient, accurately simulates the declining trend of gas well production, optimizes the draining rate, thereby improving gas well production efficiency, reducing human error, and effectively enhancing recovery rate and production.

Description

Technical Field

[0001] This application relates to the field of shale gas extraction technology, and more specifically, to a method, apparatus, electronic equipment, and storage medium for draining fluid from a shale gas horizontal well. Background Technology

[0002] With the continuous advancement of shale gas development technology, fluid drainage operations in shale gas horizontal wells play a crucial role in improving gas production, extending wellbore life, and optimizing well production capacity. However, the complex formation conditions and variable reservoir pressures faced by shale gas wells at different stages of production make optimizing fluid drainage operations a challenging task. Especially in the later stages of production, as the formation pressure gradually decreases and the well's production capacity gradually declines, the problem of fluid accumulation becomes particularly prominent. If the accumulated fluid cannot be effectively drained, it may lead to well flooding or production loss.

[0003] Existing drainage methods often rely on empirical parameter adjustments, neglecting the actual production changes of gas wells under different drainage rates. In particular, the impact of drainage rate on production is not fully considered under reservoir pressure depletion and formation stress sensitivity. In traditional methods, the selection of drainage rate is often based on field experience, and production is tested by gradually adjusting the nozzle size, lacking accurate prediction of the impact of different drainage rates on gas well production capacity and long-term production performance.

[0004] Therefore, accurately calculating shale gas production at different drainage rates, especially considering the effects of reservoir pressure depletion and stress sensitivity, has become crucial for improving gas well production efficiency and recovery. Currently, research on drainage rate optimization largely focuses on the influence of single factors, lacking a systematic approach that comprehensively considers the effects of various factors (such as pressure depletion and stress sensitivity). In other words, existing drainage rate optimization methods suffer from insufficient precision, incomplete consideration of factors, and an inability to accurately reflect the interactions of multiple factors. Summary of the Invention

[0005] The summary section of this application introduces a series of simplified concepts, which will be further explained in detail in the detailed description section. The summary section of this application is not intended to limit the key features and essential technical features of the claimed technical solution, nor is it intended to determine the scope of protection of the claimed technical solution.

[0006] The shale gas horizontal well drainage method and related apparatus provided in this application can accurately simulate the declining trend of gas well production by introducing a production loss coefficient, optimize the drainage rate, thereby improving gas well production efficiency, reducing human error, and effectively increasing recovery rate and production.

[0007] In a first aspect, this application provides a method for draining fluid from a shale gas horizontal well, comprising: obtaining the initial production rate of a target shale gas horizontal well; calculating the expected shale gas production rate under different preset draining rates based on the initial production rate, a preset production time, a first production capacity loss coefficient, and a second production capacity loss coefficient, wherein the first production capacity loss coefficient reflects the degree of production capacity reduction caused by reservoir pressure depletion, and the second production capacity loss coefficient reflects the degree of production capacity reduction caused by reservoir stress sensitivity; determining a target draining rate among the preset draining rates based on the expected shale gas production rate; and performing a draining operation on the target shale gas horizontal well according to the target draining rate.

[0008] In one feasible implementation, the method further includes: determining a first capacity loss coefficient based on the preset production time; and determining a second capacity loss coefficient based on the preset production time and the preset drainage rate.

[0009] In one feasible implementation, determining the first production capacity loss coefficient based on the preset production time includes: when the preset production time is in the first stage of the total production cycle, determining the first production capacity loss coefficient based on the preset production time, the production time index of the target shale gas horizontal well, and the linear segment production decline coefficient; when the preset production time is in the second stage of the total production cycle, determining the first production capacity loss coefficient based on the initial production of the gas well, the preset production time, the nonlinear segment production decline coefficient of the target shale gas horizontal well, the initial gas production from fracture interference, and the initial gas production decline rate from fracture interference.

[0010] In one feasible implementation, determining the second capacity loss coefficient based on the preset production time and the preset drainage rate includes: obtaining the total stress change value corresponding to the preset production time; obtaining the page volume compression coefficient corresponding to the preset production time and the preset drainage rate; and determining the second capacity loss coefficient based on the stress change value and the page volume compression coefficient.

[0011] In one feasible implementation, obtaining the total stress change value corresponding to the preset production time includes: obtaining the pressure-driven stress change value and the gas desorption stress change value corresponding to the preset production time; and determining the total stress change value by summing the pressure-driven stress change value and the gas desorption stress change value.

[0012] In one feasible implementation, obtaining the pressure-driven stress change value and the gas desorption stress change value corresponding to the preset production time includes: obtaining the shale Young's modulus, adsorption expansion strain limit, half-limit expansion strain pressure, shale Poisson's ratio, and initial reservoir pressure of the target shale gas horizontal well; obtaining the reservoir pressure corresponding to the preset production time; determining the pressure-driven stress change value based on the shale Poisson's ratio, the initial reservoir pressure, and the reservoir pressure; and determining the gas desorption stress change value based on the shale Poisson's ratio, the Young's modulus, the adsorption expansion strain limit, the half-limit expansion strain pressure, and the reservoir pressure.

[0013] In one feasible implementation, obtaining the shale volume compressibility coefficient corresponding to the preset production time and the preset drainage rate includes: obtaining the shale Poisson's ratio, initial reservoir pressure, and initial shale permeability of the target shale gas horizontal well; obtaining the real-time pressure and shale permeability corresponding to the preset production time and the preset drainage rate; and determining the shale volume compressibility coefficient based on the shale Poisson's ratio, the initial reservoir pressure, the initial shale permeability, the real-time pressure, and the shale permeability.

[0014] Secondly, this application also provides a shale gas horizontal well drainage device, comprising: a data acquisition unit for acquiring the initial production rate of a target shale gas horizontal well; a production rate determination unit for calculating the expected shale gas production rate under different preset drainage rates based on the initial production rate, a preset production time, a first production rate loss coefficient, and a second production rate loss coefficient, wherein the first production rate loss coefficient reflects the degree of production rate decline caused by reservoir pressure depletion, and the second production rate loss coefficient reflects the degree of production rate decline caused by reservoir stress sensitivity; a rate determination unit for determining a target drainage rate among the preset drainage rates based on the expected shale gas production rate; and a drainage operation unit for performing drainage operations on the target shale gas horizontal well according to the target drainage rate.

[0015] Thirdly, this application also provides an electronic device, including: a memory and a processor, the processor being configured to execute a computer program stored in the memory to implement the steps of the shale gas horizontal well drainage method described in the first aspect.

[0016] Fourthly, this application also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the steps of the shale gas horizontal well drainage method described in the first aspect.

[0017] Fifthly, this application also provides a computer program product, including a computer program or computer-executable instructions, which, when executed by a processor, implement the shale gas horizontal well fluid drainage method provided in the embodiments of this application.

[0018] In summary, by introducing a first production loss coefficient and a second production loss coefficient, this application can separately consider the production loss caused by reservoir pressure depletion and stress sensitivity, thus more accurately simulating the production decline trend of gas wells at different stages. This provides more scientific and reliable data support for the selection of drainage rates. By calculating the expected production under different drainage rates, it can provide quantitative guidance for gas well drainage operations, effectively avoiding problems such as production waste or inability to remove accumulated fluid due to improper drainage rate selection. By calculating the target drainage rate, the uncertainty and error of human adjustment are greatly reduced, making drainage operations more controllable and precise. Furthermore, by scientifically calculating and optimizing the drainage rate, the overall production and recovery rate of shale gas wells can be improved. In conclusion, the shale gas horizontal well drainage method provided in this application, by introducing a production loss coefficient, accurately simulates the production decline trend of gas wells, optimizes the drainage rate, thereby improving gas well production efficiency, reducing human error, and effectively improving recovery rate and production. Attached Figure Description

[0019] Various other advantages and benefits will become apparent to those skilled in the art upon reading the following detailed description of preferred embodiments. The accompanying drawings are for illustrative purposes only and are not intended to limit this specification. Furthermore, the same reference numerals denote the same parts throughout the drawings. In the drawings:

[0020] Figure 1 A schematic flowchart of a shale gas horizontal well fluid drainage method provided for an embodiment of this application;

[0021] Figure 2 A schematic diagram of the composition structure of a shale gas horizontal well drainage device provided in this application embodiment;

[0022] Figure 3 This is a schematic diagram of the composition structure of an electronic device provided in an embodiment of this application. Detailed Implementation

[0023] The terms used in the specification, claims, and drawings of this application, such as "first," "second," "third," "fourth," etc. (if any), are used to distinguish similar objects and not to describe a specific order or sequence. Therefore, it is to be understood that these terms can be used interchangeably where appropriate, allowing the described embodiments to be used in different orders, unless specifically required by the illustrations or description. Furthermore, the terms "is" and "has," and any variations thereof, are intended to cover, non-exclusively, all possible constituent elements. For example, a process, method, system, product, or apparatus comprising several steps or units is not necessarily limited to the steps or units explicitly listed, but may also include other steps or units not explicitly listed, or steps or units inherent to the process, method, product, or apparatus.

[0024] In this application, a "module" or "unit" refers to a computer program or part of a computer program that has a specific function and works in conjunction with other related parts to achieve a predetermined goal. These modules or units can be implemented by software, hardware (e.g., processing circuitry or memory), or a combination of both. One or more processors or memories can implement one or more modules or units. Furthermore, each module or unit can also be part of a larger module or unit.

[0025] The technical solutions of this application will be described in detail below with reference to the accompanying drawings of the embodiments. It should be noted that the described embodiments are only a part of this application, and not all embodiments. In the following description, the "some embodiments" mentioned are only a subset of all possible embodiments, which may be the same or different subsets, and different embodiments can be combined with each other without conflict.

[0026] See Figure 1 , Figure 1 This is a schematic flowchart of a shale gas horizontal well fluid drainage method provided in an embodiment of this application. The method may specifically include the following steps 101 to 104:

[0027] Step 101: Obtain the initial production rate of the target shale gas horizontal well;

[0028] Specifically, the target shale gas horizontal well is a shale gas horizontal well selected during the specific development process that requires optimization of the drainage rate. The initial production of the gas well refers to the amount of gas flowing out of the target shale gas horizontal well during the initial stage of well opening (e.g., the first 5 days after opening), i.e., without significant production decline, which is approximately cubic meters per day (m³). 3 / d) is expressed in units.

[0029] For example, the initial production of the target shale gas horizontal well can be confirmed through field tests or historical data, serving as a benchmark for fluid drainage optimization calculations.

[0030] By implementing step 101, the initial production rate of the gas well is obtained, providing basic data for subsequent calculations and optimizations, and ensuring the accuracy and reliability of the target drainage rate.

[0031] Step 102: Based on the initial production of the gas well, the preset production time, the first production capacity loss coefficient, and the second production capacity loss coefficient, calculate the expected shale gas production under different preset drainage rates. The first production capacity loss coefficient reflects the degree of production capacity reduction caused by reservoir pressure depletion, and the second production capacity loss coefficient reflects the degree of production capacity reduction caused by reservoir stress sensitivity.

[0032] Specifically, the preset production time is a specific point in time after the target shale gas horizontal well is opened, usually on the day after the well begins production; for example, if the shale gas production is to be assessed on the 30th day after well opening, then the preset production time is the 30th day. The first production loss coefficient reflects the impact of reservoir pressure depletion on production capacity. As production time progresses, reservoir pressure gradually decreases. With decreasing reservoir pressure, gas flow is restricted, leading to reduced production and thus lower well production capacity. The second production loss coefficient measures the impact of reservoir stress sensitivity on production capacity, i.e., the impact of changes in reservoir stress on well production capacity as the drainage rate changes during production. Stress sensitivity is usually manifested through permeability loss, such as when the drainage rate is too fast, the reservoir may fracture and deform, leading to a decrease in permeability. The preset drainage rate is the liquid discharge rate set when formulating the drainage plan, usually expressed in cubic meters per day (m³ / day). 3 The unit is / d), and different drainage rates will affect the drainage effect and production of the gas well. The expected shale gas production is predicted based on factors such as the initial production of the target shale gas horizontal well, reservoir pressure, stress sensitivity, and preset drainage rate, to forecast the gas well production throughout the entire production cycle of the target shale gas horizontal well.

[0033] For example, the expected shale gas production can be calculated using the following formula:

[0034]

[0035] q gt =q gi C d (t)C s (t,q l (2)

[0036] In the formula, G p The expected shale gas production is expressed in cubic meters. 3 ;q gt This represents the gas well production rate at a preset production time (day t after well opening), expressed in meters. 3 / d; t is the preset production time, in days; T is the total production cycle length, in days; q gi Initial production of the gas well, in meters (m³). 3 / d;C d (t) is the first capacity loss coefficient for the preset production time, dimensionless; C s (t,q l ) is the second capacity loss coefficient under preset production time and preset drainage speed, and is dimensionless.

[0037] By implementing step 102, the introduction of the first production capacity loss coefficient (the effect of reservoir pressure depletion) and the second production capacity loss coefficient (the effect of stress sensitivity) can comprehensively consider the actual production capacity changes of gas wells at different stages of production, making the calculation of expected shale gas production more accurate. This provides more scientific and systematic data support for the selection of target drainage rate, avoiding the shortcomings of traditional methods that are based on only a single factor.

[0038] Step 103: Determine the target drainage rate in the preset drainage rate based on the expected shale gas production.

[0039] Specifically, the target drainage rate refers to the optimal drainage rate determined based on the expected shale gas production and production requirements of the target shale gas horizontal well. It is derived through calculation and analysis, and production can be predicted at different drainage rates (steps 101 to 102), selecting the drainage rate from the preset drainage rates that maximizes gas well production and economic benefits.

[0040] For example, when shale gas production is expected to be high, a slow drainage rate may lead to excessive stress and affect gas well production; while an excessively fast drainage rate may lead to unnecessary fracturing and decreased permeability. Through optimization analysis and comparison, a drainage rate that can maintain production capacity without excessively affecting the reservoir can be selected as the target drainage rate.

[0041] By implementing step 103, waste of production capacity or liquid accumulation caused by improper drainage speed is avoided, thereby optimizing the drainage operation process.

[0042] Step 104: Perform fluid drainage operations on the target shale gas horizontal well according to the target fluid drainage rate;

[0043] Specifically, the appropriate technical equipment (such as pumps or gas lifts) can be used to carry out the drainage operation according to the target drainage rate determined in step 103, so as to ensure that enough liquid is discharged, so that the gas well can maintain the optimal gas flow state and increase production.

[0044] By implementing step 104, the actual drainage operation is carried out according to the calculated target drainage rate, which helps to improve the controllability and accuracy of the drainage operation and reduce the uncertainty and error caused by human experience.

[0045] In summary, the embodiments of this application, by introducing a first production loss coefficient and a second production loss coefficient, can respectively consider the production loss caused by reservoir pressure depletion and stress sensitivity, and can more accurately simulate the production decline trend of gas wells at different stages, thus providing more scientific and reliable data support for the selection of drainage rate. By calculating the expected production under different drainage rates, quantitative guidance can be provided for gas well drainage operations, effectively avoiding problems such as production waste or inability to remove accumulated fluid due to improper selection of drainage rate. By calculating the target drainage rate, the uncertainty and error of human adjustment are greatly reduced, making the drainage operation more controllable and precise. Furthermore, by scientifically calculating and optimizing the drainage rate, the overall production and recovery rate of shale gas wells can be improved. In summary, the shale gas horizontal well drainage method provided by the embodiments of this application, by introducing a production loss coefficient, accurately simulates the production decline trend of gas wells, optimizes the drainage rate, thereby improving gas well production efficiency, reducing human error, and effectively improving recovery rate and production.

[0046] In some embodiments, the aforementioned method may further include: determining a first capacity loss coefficient based on a preset production time; and determining a second capacity loss coefficient based on a preset production time and a preset drainage rate.

[0047] Specifically, the first production loss coefficient can be determined by measuring the production history of the target shale gas horizontal well and combining it with reservoir characteristics. This coefficient can be estimated by the relationship between historical production data and pressure decline. The second production loss coefficient can usually be evaluated through geological simulation, fracturing experiments, and actual fluid drainage operations.

[0048] For example, suppose a gas well initially produces 100 cubic meters per day of gas and has an initial reservoir pressure of 10 MPa. As time progresses, the reservoir pressure decreases due to continuous production. The preset production time is the 30th day after well opening, at which point the reservoir pressure drops to 7 MPa. Assuming other conditions remain unchanged, the current production rate can be calculated using historical data or empirical formulas to be 67.4 cubic meters per day (a value obtained by fitting a production curve). This change indicates that the depletion of reservoir pressure has led to a decrease in the gas well's production. Therefore, the first production loss coefficient corresponding to this preset production time is 32.6%. Suppose a gas well has a permeability of 5 millidarcy (mD) at the beginning of its operation and a drainage rate of 100 cubic meters per day. On the 30th day of the planned production period, a stress change occurs in the reservoir, causing the permeability to decrease from 5 millidarcy to 4.08 millidarcy. Assuming other conditions remain unchanged, the well's production capacity is affected by the decrease in reservoir permeability due to drainage. Based on historical data or empirical formulas, the current production decrease is 18.4%. Therefore, the second production capacity loss coefficient corresponding to the planned production time and drainage rate is 18.4%.

[0049] By implementing the above embodiments, the first and second production capacity loss coefficients are dynamically determined by considering the preset production time, which can more accurately reflect the characteristics of gas wells at different production stages; in particular, the second production capacity loss coefficient takes into account the changes in production time and drainage rate, making the method more in line with actual production conditions and avoiding overly simplistic assumptions.

[0050] In some embodiments, determining the first production capacity loss coefficient based on a preset production time may include: when the preset production time is in the first stage of the total production cycle, determining the first production capacity loss coefficient based on the preset production time, the production time index of the target shale gas horizontal well, and the linear segment production decline coefficient; when the preset production time is in the second stage of the total production cycle, determining the first production capacity loss coefficient based on the initial production of the gas well, the preset production time, the nonlinear segment production decline coefficient of the target shale gas horizontal well, the initial gas production of fracture interference, and the initial gas production decline rate of fracture interference.

[0051] Specifically, the total production cycle refers to the entire production cycle from the start of production of the target shale gas horizontal well to its closure or reaching its economic life. The first stage of the total production cycle refers to the early stage after the well is opened; in this stage, production is high, and the well's production capacity has not yet been severely affected by reservoir pressure depletion or other factors. Production is mainly influenced by reservoir pressure, permeability, and other factors. For example, the first 12 months after well opening can be considered the first stage of the total production cycle. The second stage of the total production cycle is a period after well opening, during which the well enters a decline phase, and production decreases significantly. This decline is related to multiple factors, such as reservoir pressure depletion, stress sensitivity, and fracture closure. For example, the period after one year after well opening can be considered the second stage of the total production cycle. The production time index describes the rate of production decline. A power function model is used to fit the trend of production decline. Typically, the decline rate slows down in the later stages of well production. The decline time power function can be fitted based on historical production data.

[0052] The linear segment production decline factor is the rate of decline when production decreases linearly in the first stage of the total production cycle. It can be determined by fitting the linear segment of the double logarithmic curve of production rate versus production time. Specifically, when the logarithmic relationship between production rate and production time shows a linear trend, the corresponding intercept (and slope) can reflect the rate of decline of production at the gas well in that stage.

[0053] The nonlinear production decline coefficient occurs in the second stage of the overall production cycle, where production decline is nonlinear. In this stage, gas well production decline becomes more complex and can be influenced by various factors, such as a significant decrease in reservoir pressure, fracture closure, and stress sensitivity. The nonlinear production decline is typically more severe than that of the linear segment. The nonlinear production decline coefficient can be determined by fitting the nonlinear segment of the logarithmic curve of production rate versus production time. In this stage, production decline no longer exhibits a simple linear relationship but rather displays more complex curve characteristics, often showing curvature changes that lead to a gradually accelerating decline rate. A nonlinear regression model or a power function model can be used to fit the production decline trend to obtain the nonlinear production decline coefficient.

[0054] The initial gas production rate due to fracture interference refers to the gas production rate at the moment the fracture interference flow begins. The moment the fracture interference flow begins refers to the point in shale gas production where the influence of fractures on the gas well's production flow begins to manifest and take effect; that is, the point in time when the logarithmic curve of production rate versus production time deviates from its linear characteristic. The initial gas production decline rate due to fracture interference refers to the initial rate of decrease in gas well production due to the fracture effect after the fracture interference flow begins; that is, the decline rate corresponding to the point where the logarithmic curve of production rate versus production time deviates from its linear characteristic. Specifically, it describes the rate at which the gas well's production gradually decreases in the short term after the fractures begin to influence the gas well's production flow.

[0055] For example, when the preset production time is in the first stage of the total production cycle, the first capacity loss coefficient can be calculated according to the following formula:

[0056]

[0057] In the formula, C d (t) is the first capacity loss coefficient corresponding to the preset production time t; t is the preset production time, in d; m is the production time exponent; a is the linear segment output reduction coefficient.

[0058] When the preset production time is in the second stage of the total production cycle, the first capacity loss coefficient can be calculated according to the following formula:

[0059]

[0060] In the formula, C d (t) is the first capacity loss coefficient corresponding to the preset production time t; q sfi This represents the initial gas production rate during the crack disturbance, expressed in cubic meters (m³). 3 / d;q gi Initial production of the gas well, in meters (m³). 3 / d;D ye (t sfi ) represents the initial gas production decline rate during crack interference, in units of 1 / d; t represents the preset production time, in units of d; b represents the production decline coefficient in the nonlinear segment, dimensionless; t sfi The value represents the start time of the crack interference flow, in days (d); m represents the production time index.

[0061] Through the implementation of the above embodiments, the calculation of the first production capacity loss coefficient is more detailed by analyzing different stages of the production cycle. It takes into account the characteristics of fracture interference and the initial gas production decline of the gas well, and provides a more accurate model for predicting production loss at different stages, which helps to better optimize the drainage operation.

[0062] In some embodiments, determining the second capacity loss coefficient based on a preset production time and a preset drainage rate may include: obtaining the total stress change value corresponding to the preset production time; obtaining the foliation volume compression coefficient corresponding to the preset production time and the preset drainage rate; and determining the second capacity loss coefficient based on the stress change value and the foliation volume compression coefficient.

[0063] Specifically, the total stress change value represents the total stress change occurring in the reservoir within a given preset production time. As the gas well produces, changes in drainage and pressure lead to changes in the reservoir's stress state, which may manifest as an increase or decrease in stress. The total stress change value can be obtained by numerical simulation or field monitoring to track reservoir stress changes in real time, or by calculation based on historical production data and a pressure-stress relationship model. The foliation volume compressibility coefficient is a coefficient describing the relationship between the reservoir's volume change (such as compression) and pressure change under stress. It is closely related to the preset production time and drainage rate, because the drainage rate determines the reservoir's pressure change rate, thus affecting the foliation volume change. The foliation volume compressibility coefficient can be obtained from reservoir experimental data, theoretical calculations, or by extrapolating from a model relating reservoir pressure and drainage rate. It can also be obtained by fitting the relationship between historical production data and stress changes. By combining the stress change value and the volume compressibility coefficient, the second production loss coefficient can be calculated using empirical formulas or numerical simulation methods.

[0064] For example, the second capacity loss coefficient can be calculated using the following formula:

[0065] C s (t,q l )=exp{C c (q l )Δσ(t)} (5)

[0066] Among them, C s (t,q l C is the second capacity loss coefficient corresponding to the preset production time t and the preset drainage rate ql. c (q l ) represents the volumetric compressibility coefficient of the foliation corresponding to the preset drainage rate ql, in MPa. 1 ; Δσ(t) is the total stress change value corresponding to the preset production time t, in MPa; exp represents an exponential function with the natural constant e as the base.

[0067] By implementing the above embodiments, the stress change value and the foliation volume compression coefficient are obtained to dynamically adjust the second production capacity loss coefficient, which can more accurately reflect the impact of stress sensitivity on production capacity loss and ensure the high efficiency of drainage rate optimization under different geological conditions.

[0068] In some embodiments, the aforementioned acquisition of the total stress change value corresponding to the preset production time may include: acquiring the pressure-driven stress change value and the gas desorption stress change value corresponding to the preset production time; and determining the sum of the pressure-driven stress change value and the gas desorption stress change value as the total stress change value.

[0069] Specifically, pressure-driven stress variation represents the change in reservoir stress state caused by pressure changes during gas well production. Specifically, as gas is extracted from the reservoir, the pressure decreases, causing changes in the stress distribution within the reservoir rock. Pressure-driven stress variation measures the degree of stress change caused by pressure variations and can be calculated using numerical simulation methods or determined based on pressure field distribution models, by monitoring gas well pressure changes and combining them with the reservoir's mechanical properties. Gas desorption stress variation reflects the change in rock volume and resulting stress as gas desorbs from the reservoir rock pores. The gas desorption effect is usually more significant in the early stages of gas well production, especially when the gas content in the reservoir is high. The desorption process leads to changes in the reservoir rock pore structure, thus affecting the reservoir's stress state. Gas desorption stress variation can be calculated through laboratory tests or based on the reservoir's desorption characteristics combined with production data, or estimated by fitting historical production data with experimental data.

[0070] For example, the second capacity loss coefficient can be calculated using the following formula:

[0071] C s (t,q l )=exp{C c (q l )[Δσ e (t)+Δσ s (t)]} (6)

[0072] Among them, C s (t,q l ) represents the second capacity loss coefficient corresponding to the preset production time t and preset drainage rate ql, and is dimensionless; C c (q l ) represents the volumetric compressibility coefficient of the foliation corresponding to the preset drainage rate ql, in MPa. 1 ;Δσ e (t) represents the pressure-driven stress change value corresponding to the preset production time t, in MPa; Δσ s (t) represents the change in gas desorption stress corresponding to the preset production time t, in MPa.

[0073] By implementing the above embodiments, the pressure-driven stress change value and gas desorption stress change value related to the preset production time can be obtained, and the total stress change can be calculated more accurately. This allows for precise assessment of the reservoir's stress response, optimization of the drainage rate, and avoidance of gas well performance degradation due to excessively fast or slow drainage rates.

[0074] In some embodiments, the aforementioned acquisition of the pressure-driven stress change value and gas desorption stress change value corresponding to the preset production time may include: acquiring the shale Young's modulus, adsorption expansion strain limit, half-limit expansion strain pressure, shale Poisson's ratio, and initial reservoir pressure of the target shale gas horizontal well; acquiring the reservoir pressure corresponding to the preset production time; determining the pressure-driven stress change value based on the shale Poisson's ratio, initial reservoir pressure, and reservoir pressure; and determining the gas desorption stress change value based on the shale Poisson's ratio, Young's modulus, adsorption expansion strain limit, half-limit expansion strain pressure, and reservoir pressure.

[0075] Specifically, Young's modulus is a physical quantity describing a material's ability to deform under stress, reflecting its rigidity. In this embodiment, the Young's modulus of shale is used to characterize the elastic response of shale under external forces (such as gas extraction or pressure changes). The larger the Young's modulus, the less easily the shale deforms under stress. The Young's modulus of shale can be obtained through laboratory testing, with common methods including compression and tensile tests, or by inversion from seismic data. The adsorption-expansion strain limit refers to the maximum degree of deformation that shale can withstand when gas is adsorbed and expands in the pores. When gas is desorbed or adsorbed from shale, the volume of the shale changes. After reaching a certain level, the expansion strain affects the reservoir's permeability and stress state. The adsorption-expansion strain limit can be obtained through laboratory adsorption experiments, typically using specific equipment to simulate the expansion strain of shale during gas adsorption. The semi-limit expansion strain pressure refers to the pressure at which the volume expansion of shale reaches half the limit (0.5 times the adsorption expansion strain limit) under a specific pressure. Exceeding this pressure may cause significant changes in the shale structure, affecting the reservoir's physical properties and gas production capacity. The semi-limit expansion strain pressure can be determined experimentally by conducting adsorption and expansion experiments under different pressures and recording the relationship between expansion strain and pressure. Poisson's ratio is the ratio of the amount of deformation perpendicular to a material in one direction to the original deformation when the material is subjected to tension or compression in that direction. In this application embodiment, the shale Poisson's ratio is used to describe the relationship between lateral and longitudinal deformation of shale during gas extraction or pressure changes. The shale Poisson's ratio can be obtained through laboratory measurements or core experiments, or estimated through seismic data inversion. The initial reservoir pressure refers to the pressure of gas or fluid in the reservoir before production. It can be obtained through well logging, pressure testing, or back-calculation using production data. The pressure-driven stress change value and the gas desorption stress change value can be calculated by combining the initial reservoir pressure and the actual reservoir pressure using laboratory data or numerical simulations of the reservoir.

[0076] For example, the pressure-driven stress change and the gas desorption stress change can be calculated using the following formula:

[0077]

[0078] In the formula, Δσ e (t) represents the pressure-driven stress change value corresponding to the preset production time t, in MPa; Δσ s (t) represents the change in gas desorption stress corresponding to the preset production time t, in MPa; ν is the Poisson's ratio of the shale, dimensionless; p(t) is the reservoir pressure corresponding to the preset production time t, in MPa; p i ε is the initial reservoir pressure, in MPa; E is the Young's modulus of the shale, in MPa; ε smax p is the adsorption expansion strain limit, dimensionless.ε The pressure is the semi-limiting expansion strain, in MPa.

[0079] By implementing the above embodiments, the changes in gas desorption stress and pressure-driven stress can be calculated more accurately. These stress changes are crucial to the impact on production capacity loss and can further improve the accuracy of production forecasting and liquid discharge rate optimization.

[0080] In some embodiments, the aforementioned acquisition of the shale volume compression coefficient corresponding to the preset production time and preset drainage rate may include: acquiring the shale Poisson's ratio, initial reservoir pressure, and initial shale permeability of the target shale gas horizontal well; acquiring the real-time pressure and shale permeability corresponding to the preset production time and preset drainage rate; and determining the shale volume compression coefficient based on the shale Poisson's ratio, initial reservoir pressure, initial shale permeability, real-time pressure, and shale permeability.

[0081] Specifically, real-time pressure refers to the actual pressure within the reservoir at a preset production time. This pressure changes with the preset drainage rate, reflecting the pressure changes experienced by the reservoir during production. It is influenced by productivity, drainage rate, and other geological factors. Real-time pressure can be obtained through dynamic permeability testing or well test analysis, or it can be recorded in real time during production using pressure monitoring devices (such as pressure sensors). Shale permeability is a parameter describing the flow capacity of fluids (such as gas or water) in a shale reservoir. It is affected by factors such as pressure, porosity, and fracture structure. Shale permeability can be predicted through periodic production tests, pressure well tests, or numerical models based on geological and laboratory data. Initial shale permeability refers to the initial permeability of shale or shale gas layers in the reservoir before undergoing a production process; it can be obtained through core experiments, geological surveys, or field tests.

[0082] For example, the volumetric compressibility factor of a page can be calculated using the following formula:

[0083]

[0084] In the formula, C c (q l ) represents the volumetric compressibility coefficient of the foliation corresponding to the preset drainage rate ql, in MPa. 1 ν represents the Poisson's ratio of shale, which is dimensionless; p(q) l ) represents the real-time pressure corresponding to the preset drainage rate ql, in MPa; p i K represents the initial reservoir pressure, in MPa; f (q l (to match the preset drainage rate q) l Corresponding physical penetration rate, in mD; k f,iThe initial permeability is expressed in mD.

[0085] By implementing the above embodiments, parameters such as shale Poisson's ratio, initial reservoir pressure, and initial shale permeability can be obtained. Combined with real-time pressure and permeability data, the shale volume compressibility coefficient can be accurately calculated.

[0086] Furthermore, as an implementation of the aforementioned method embodiments, this application also provides a shale gas horizontal well fluid drainage device for implementing the aforementioned method embodiments. This device embodiment corresponds to the aforementioned method embodiments. For ease of reading, this shale gas horizontal well fluid drainage device embodiment will not repeat the details of the aforementioned method embodiments one by one, but it should be clear that the device in this application embodiment can correspondingly implement all the contents of the aforementioned method embodiments. For example... Figure 2 As shown, the shale gas horizontal well drainage device 20 includes: a data acquisition unit 201, a production rate determination unit 202, a rate determination unit 203, and a drainage operation unit 204. The data acquisition unit 201 is used to acquire the initial production rate of the target shale gas horizontal well. The production rate determination unit 202 is used to calculate the expected shale gas production rate under different preset drainage rates based on the initial production rate, preset production time, a first production capacity loss coefficient, and a second production capacity loss coefficient. The first production capacity loss coefficient reflects the degree of production capacity reduction caused by reservoir pressure depletion, and the second production capacity loss coefficient reflects the degree of production capacity reduction caused by reservoir stress sensitivity. The rate determination unit 203 is used to determine the target drainage rate among the preset drainage rates based on the expected shale gas production rate. The drainage operation unit 204 is used to perform drainage operations on the target shale gas horizontal well according to the target drainage rate.

[0087] In some embodiments, the shale gas horizontal well drainage device 20 further includes a coefficient calculation unit for determining a first production capacity loss coefficient based on a preset production time and a second production capacity loss coefficient based on a preset production time and a preset drainage rate.

[0088] In some embodiments, the coefficient calculation unit is further configured to determine a first production capacity loss coefficient based on the preset production time, the production time index of the target shale gas horizontal well, and the linear segment production decline coefficient when the preset production time is in the first stage of the total production cycle; and to determine the first production capacity loss coefficient based on the initial production of the gas well, the preset production time, the nonlinear segment production decline coefficient of the target shale gas horizontal well, the initial gas production of the fracture interference, and the initial gas production decline rate of the fracture interference when the preset production time is in the second stage of the total production cycle.

[0089] In some embodiments, the coefficient calculation unit is further configured to obtain the total stress change value corresponding to the preset production time; obtain the foliation volume compression coefficient corresponding to the preset production time and the preset drainage rate; and determine the second capacity loss coefficient based on the stress change value and the foliation volume compression coefficient.

[0090] In some embodiments, the coefficient calculation unit is further configured to obtain the pressure-driven stress change value and the gas desorption stress change value corresponding to the preset production time; and to determine the sum of the pressure-driven stress change value and the gas desorption stress change value as the total stress change value.

[0091] In some embodiments, the coefficient calculation unit is further configured to obtain the shale Young's modulus, adsorption expansion strain limit, half-limit expansion strain pressure, shale Poisson's ratio, and initial reservoir pressure of the target shale gas horizontal well; obtain the reservoir pressure corresponding to a preset production time; determine the pressure-driven stress change value based on the shale Poisson's ratio, initial reservoir pressure, and reservoir pressure; and determine the gas desorption stress change value based on the shale Poisson's ratio, Young's modulus, adsorption expansion strain limit, half-limit expansion strain pressure, and reservoir pressure.

[0092] In some embodiments, the coefficient calculation unit is further configured to obtain the shale Poisson's ratio, initial reservoir pressure, and initial shale permeability of the target shale gas horizontal well; obtain the real-time pressure and shale permeability corresponding to the preset production time and preset drainage rate; and determine the shale volume compressibility coefficient based on the shale Poisson's ratio, initial reservoir pressure, initial shale permeability, real-time pressure, and shale permeability.

[0093] This application also provides a computer-readable storage medium storing computer-executable instructions or computer programs that, when executed by a processor, will cause the processor to perform any step of the shale gas horizontal well drainage method provided in this application.

[0094] In some embodiments, the computer-readable storage medium may be a memory such as RAM, read-only memory (ROM), flash memory, magnetic surface memory, optical disc, or compact disc read-only memory (CD-ROM); or it may be a variety of devices including one or any combination of the above-mentioned memories.

[0095] In some embodiments, computer-executable instructions may take the form of programs, software, software modules, scripts, or code, written in any form of programming language (including compiled or interpreted languages, or declarative or procedural languages), and may be deployed in any form, including as stand-alone programs or as modules, components, subroutines, or other units suitable for use in a computing environment.

[0096] In some embodiments, computer-executable instructions may, but do not necessarily, correspond to files in a file system, and may be stored as part of a file that holds other programs or data, for example, in one or more scripts in a HyperText Markup Language (HTML) document, in a single file dedicated to the program in question, or in multiple co-located files (e.g., files that store one or more modules, subroutines, or code sections).

[0097] In some embodiments, computer-executable instructions may be deployed to execute on an electronic device, or on multiple electronic devices located at one location, or on multiple electronic devices distributed across multiple locations and interconnected via a communication network.

[0098] like Figure 3 As shown, this application also provides an electronic device 30, including a memory 310, a processor 320, and a computer program 311 stored in the memory 310 and executable on the processor. When the processor 320 executes the computer program 311, it implements any step of the above-described shale gas horizontal well drainage method.

[0099] This application also provides a computer program product comprising a computer program or computer-executable instructions stored in a computer-readable storage medium. A processor of an electronic device reads the computer program or computer-executable instructions from the computer-readable storage medium and executes the computer program or computer-executable instructions, causing the electronic device to perform any step of the shale gas horizontal well drainage method described above.

[0100] The above embodiments are only used to illustrate the technical solutions of this application, and are not intended to limit them. Although this application has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of this application.

Claims

1. A method for draining fluid from a shale gas horizontal well, characterized in that, include: Obtain the initial production rate of the target shale gas horizontal well; Based on the initial production of the gas well, the preset production time, the first production capacity loss coefficient, and the second production capacity loss coefficient, the expected shale gas production under different preset drainage rates is calculated. The first production capacity loss coefficient reflects the degree of production capacity reduction caused by reservoir pressure depletion, and the second production capacity loss coefficient reflects the degree of production capacity reduction caused by reservoir stress sensitivity. Based on the expected shale gas production, determine the target drainage rate in the preset drainage rate; The target shale gas horizontal well is drained according to the target drainage rate.

2. The method according to claim 1, characterized in that, The method further includes: The first capacity loss coefficient is determined based on the preset production time; The second capacity loss coefficient is determined based on the preset production time and the preset drainage rate.

3. The method according to claim 2, characterized in that, Determining the first capacity loss coefficient based on the preset production time includes: When the preset production time is in the first stage of the total production cycle, the first production capacity loss coefficient is determined based on the preset production time, the production time index of the target shale gas horizontal well, and the linear segment production reduction coefficient. When the preset production time is in the second stage of the total production cycle, the first production capacity loss coefficient is determined based on the initial production of the gas well, the preset production time, the nonlinear segment production decline coefficient of the target shale gas horizontal well, the initial gas production of fracture interference, and the initial gas production decline rate of fracture interference.

4. The method according to claim 2, characterized in that, The step of determining the second capacity loss coefficient based on the preset production time and the preset drainage rate includes: Obtain the total stress change value corresponding to the preset production time; Obtain the page volume compression coefficient corresponding to the preset production time and the preset drainage speed; The second production capacity loss coefficient is determined based on the stress change value and the page volume compression coefficient.

5. The method according to claim 4, characterized in that, The step of obtaining the total stress change value corresponding to the preset production time includes: Obtain the pressure-driven stress change value and the gas desorption stress change value corresponding to the preset production time; The sum of the pressure-driven stress change value and the gas desorption stress change value is determined as the total stress change value.

6. The method according to claim 5, characterized in that, The step of obtaining the pressure-driven stress change value and the gas desorption stress change value corresponding to the preset production time includes: Obtain the Young's modulus, adsorption expansion strain limit, half-limit expansion strain pressure, shale Poisson's ratio, and initial reservoir pressure of the target shale gas horizontal well; Obtain the reservoir pressure corresponding to the preset production time; The pressure-driven stress variation value is determined based on the shale Poisson's ratio, the initial reservoir pressure, and the reservoir pressure. The gas desorption stress variation value is determined based on the shale Poisson's ratio, the Young's modulus, the adsorption expansion strain limit, the half-limit expansion strain pressure, and the reservoir pressure.

7. The method according to claim 4, characterized in that, The step of obtaining the page volume compression coefficient corresponding to the preset production time and the preset drainage rate includes: Obtain the Poisson's ratio of the target shale gas horizontal well, the initial reservoir pressure, and the initial shale permeability; Obtain the real-time pressure and pore permeability corresponding to the preset production time and the preset drainage rate; The shale volume compressibility coefficient is determined based on the shale Poisson's ratio, the initial reservoir pressure, the initial shale permeability, the real-time pressure, and the shale permeability.

8. A shale gas horizontal well fluid drainage device, characterized in that, include: The data acquisition unit is used to acquire the initial production of the target shale gas horizontal well; The production determination unit is used to calculate the expected shale gas production under different preset drainage rates based on the initial production of the gas well, the preset production time, the first production capacity loss coefficient, and the second production capacity loss coefficient. The first production capacity loss coefficient reflects the degree of production capacity reduction caused by reservoir pressure depletion, and the second production capacity loss coefficient reflects the degree of production capacity reduction caused by reservoir stress sensitivity. A velocity determination unit is used to determine the target drainage velocity in the preset drainage velocity based on the expected shale gas production. The fluid drainage unit is used to perform fluid drainage operations on the target shale gas horizontal well according to the target fluid drainage rate.

9. An electronic device, comprising: The memory and processor are characterized in that the processor is used to execute a computer program stored in the memory to implement the steps of the shale gas horizontal well drainage method as described in any one of claims 1-7.

10. A computer-readable storage medium storing a computer program, characterized in that, When the computer program is executed by the processor, it implements the steps of the shale gas horizontal well drainage method as described in any one of claims 1-7.

Images