Method for optimizing gas production capacity of single well of gas storage

Abstract

The invention provides a gas storage single well gas production capacity optimization method, and relates to the technical field of gas storage gas well injection and production, and the method comprises the following steps: building a stable point binomial productivity equation basic theoretical model; establishing a theoretical curve of the gas production capacity and the effective thickness of the stratum by combining the characteristics of short-term strong injection and strong production of the gas storage; establishing an effective thickness productivity evaluation model layout under different production pressure difference conditions; according to sand production test results of different reservoir stratums, combining a density logging curve, and establishing a function relationship between the density and the sand production pressure difference through mathematical fitting; according to the model layout and the function relation between the density and the sand production pressure difference, a reservoir stratum with the appropriate effective thickness and the appropriate sand production pressure difference is selected, and the gas production capacity of a single well is optimized. The density is associated with the sand production pressure difference, a rapid quantitative evaluation technology for the sand production pressure difference of the multi-layer sandstone gas reservoir is established, and the critical sand production pressure difference of different reservoirs can be rapidly calculated.

Description

Technical Field

[0001] The present invention relates to the technical field of gas injection and production of gas storage wells, and particularly relates to a method for optimizing the gas production capacity of a single well in a gas storage reservoir. Background Art

[0002] The operation mode of a gas storage reservoir is a limit utilization state that changes from long-term low-speed exploitation of a gas field to short-term high-speed gas injection and production, achieving a double limit effect of safety and capacity. The gas production capacity is a decisive factor affecting the scale of the gas storage reservoir. The higher the gas production capacity of a single well, the larger the working gas volume of the gas storage reservoir, and the stronger the peak shaving capacity of the gas storage reservoir. Therefore, the optimization measures for the gas production capacity of gas injection and production wells in gas storage reservoirs are particularly important, and an effective optimization space evaluation method is the basis for subsequent measures.

[0003] Currently, in order to improve the gas production capacity of a single well as much as possible, generally, the method of improving the degree of reservoir utilization and optimizing the well type and well diameter is adopted to achieve the purpose of increasing production. Specifically, in terms of geology: fully utilize the reservoir and increase the effective thickness. The larger the effective thickness, the higher the gas production capacity of a single well; in terms of engineering: for pipe strings with different tubing sizes, as the tubing size increases, the gas production capacity also increases. Using large-diameter pipes is beneficial to improving the gas production capacity of gas wells.

[0004] For sandstone gas storage reservoirs, due to the differences in sand production pressure differences in different reservoir sections, when all reservoir sections are fully utilized, in order to ensure safe production, the production pressure difference is restricted by the lowest sand production pressure difference. The above-mentioned situation of increasing effective thickness and decreasing production pressure difference is not conducive to the fine utilization of the reservoir, and the improvement of the gas production capacity of sandstone gas storage reservoirs has not reached the ideal situation. A method that can effectively quantitatively evaluate the optimization space for improving the gas production capacity of a single well in a gas storage reservoir is needed. Summary of the Invention

[0005] The purpose of the present invention is to provide a method for optimizing the gas production capacity of a single well in a gas storage reservoir. Based on the theory of the stable point binomial productivity equation, a method for optimizing the gas production capacity of a single well in a gas storage reservoir based on effective thickness and sand production pressure difference is established and a model chart is drawn, which can not only quantitatively evaluate the optimization space of the peak shaving capacity of the gas storage reservoir, but also draw a model chart that can meet the actual engineering application.

[0006] To achieve the above purpose, the present invention is realized through the following technical solutions:

[0007] A method for optimizing the gas production capacity of a single well in a gas storage reservoir, comprising the following steps:

[0008] S1: Establish a basic theoretical model of the stable point binomial productivity equation;

[0009] S2: According to the basic theoretical model in S1, considering the degree of reservoir utilization in the vertical direction of a single well in the gas storage reservoir, establish a theoretical curve of gas production capacity and formation effective thickness;

[0010] S3: Based on the theoretical curve obtained in S2, establish the layout of the productivity evaluation model for effective thickness under different production pressure differences;

[0011] S4: According to the sand production test results of different reservoirs, combined with the density logging curve, establish the functional relationship between density and sand production pressure difference through mathematical fitting;

[0012] S5: According to the model layout in S3 and the functional relationship between density and sand production pressure difference in S4, select the reservoir with appropriate effective thickness and sand production pressure difference, and optimize the gas production capacity of a single well.

[0013] Furthermore: The specific steps of step S4 include:

[0014] S401: According to the sand production test results of different reservoirs, count the sand production pressure difference of different well sections and the corresponding logging interpretation density values of the well sections;

[0015] S402: According to the sand production pressure difference and density data of the well sections obtained by statistics, confirm the density value range and sand production pressure difference range;

[0016] S403: Make a scatter plot of the sand production pressure difference obtained by statistics and the corresponding density values;

[0017] S404: By observing the correlation trend between density and sand production pressure difference in the scatter plot, use an appropriate mathematical model for parameter fitting, and take the fitted parameter equation as the functional expression of the relationship between density and sand production pressure difference;

[0018] S405: Calculate the goodness of fit of the functional expression in S404 and evaluate the function fitting result;

[0019] S406: Draw the final density-sand production pressure difference fitting curve graph.

[0020] By analyzing the critical sand production pressure difference and logging curves such as natural gamma, density, and longitudinal wave slowness, the correlation between density and critical sand production pressure difference is the best. Therefore, establish the functional relationship between density and sand production pressure difference to quickly predict the sand production pressure difference.

[0021] Furthermore: In S401, the sand production pressure difference of different well sections is calculated based on the rock mechanics parameters and strength discrimination criteria of the corresponding well sections.

[0022] Furthermore: Through the longitudinal wave slowness, shear wave slowness, and density logging data, calculate the dynamic Poisson's ratio, dynamic Young's modulus, dynamic shear modulus, bulk modulus, and poroelastic coefficient of the rock, and construct the formation rock mechanics parameter profile of the entire well section.

[0023] Furthermore: Calculate the sand production pressure difference according to Drucker-Prager, specifically including the following steps:

[0024]

[0025] Where,

[0026] I1=σ1+σ2+σ3

[0027]

[0028] In conventional triaxial compression stress paths there are:

[0029]

[0030]

[0031] Where: β is the experimental constant of rock cohesion, σ s is the experimental constant of the rock internal friction angle; is the internal friction angle of the rock; c is the cohesion. I1 and J2 are the first stress invariant and the second stress deviator invariant respectively; σ1, σ2, σ3 are the first principal stress, the second principal stress, and the third principal stress of the formation around the well respectively;

[0032] When f(σ) is greater than 0, the rock will be damaged and sand will be produced in the formation. Therefore, f(σ) is selected as the sand production trend evaluation index. Analysis of the sand production trend index f(σ) shows that:

[0033] When f(σ) is less than 0, the formation is stable, and the smaller f(σ) is, the more stable the formation is;

[0034] When f(σ) is greater than 0, the formation becomes unstable and sand is produced, and the larger the f(σ) value is, the more serious the sand production is;

[0035] When f(σ) is equal to 0, the formation is in a limit equilibrium state. At this time, the corresponding production pressure difference is the critical production pressure difference for sand production from the formation skeleton.

[0036] Furthermore, the specific steps of step S5 include:

[0037] S501: According to the model layout in S3, the effective thickness and sand production pressure difference of different reservoir sections are determined, and the reservoir section with the second lowest sand production pressure difference is selected;

[0038] S502: Calculate the reduction in effective thickness when the reservoir section is not used;

[0039] S503: Evaluate the maximum production pressure difference value that is allowed to increase based on the reduction of effective thickness;

[0040] S504: Import the new effective thickness and production pressure difference parameters into the model layout in S3 to evaluate the production capacity and determine whether the production capacity of the single well has increased;

[0041] S505: If the single-well production capacity is improved, the optimization is successful, and another reservoir section with the second-lowest sand production pressure difference is selected, and steps S502 - S503 are repeated; if the single-well production capacity is not improved, a reservoir section with the second-lowest sand production pressure difference is reselected, and steps S502 - S503 are repeated; until the optimization effect is maximized.

[0042] S506: Analyze and compare the single-well production capacity before and after optimization, and calculate the production capacity improvement rate.

[0043] Furthermore: The specific steps of step S1 include: According to the stable point binomial productivity theory equation, establish a binomial productivity model between formation pressure and gas production q g :

[0044]

[0045] In the formula:

[0046] S a = S + Dq g

[0047] Convert the above formula into a binomial productivity equation:

[0048] P R 2 - P wf 2 = Aq g + Bq g 2

[0049] Then:

[0050]

[0051]

[0052] In the formula, P sc = 0.101 MPa, T sc = 293.16 K.

[0053] Among them, P R represents the original formation pressure, P wf represents the reduced bottom-hole flowing pressure, represents the average gas viscosity, is the average gas deviation factor under formation conditions, represents the average temperature under formation conditions, r e represents the well control radius, r w represents the wellbore radius, S represents the comprehensive skin factor, K represents the effective formation permeability, h represents the effective gas layer thickness, D represents the non-Darcy flow coefficient; T screpresents the temperature under the standard state of the gas; S a represents the apparent skin factor; A represents the laminar flow coefficient; B represents the turbulent flow coefficient.

[0054] Furthermore: The derivation formula of is as follows:

[0055]

[0056] Among them,

[0057] a = 1.390(T pr - 0.920) 0.920 - 0.360T pr - 0.101

[0058]

[0059] c = 0.132 - 0.32lg(T pr )

[0060]

[0061] Among them, a represents the first deviation factor calculation coefficient, b represents the second deviation factor calculation coefficient, c represents the third deviation factor calculation coefficient, d represents the fourth deviation factor calculation coefficient, T pr represents the pseudo-reduced temperature, P pr represents the pseudo-reduced pressure.

[0062] Furthermore: P wf The converted bottom-hole flowing pressure, and its conversion formula is as follows:

[0063]

[0064]

[0065] Among them, P wh represents the wellhead pressure, λ represents the tubing resistance coefficient, S represents the comprehensive skin factor, T av represents the average temperature of the moving gas column in the wellbore, Z av represents the average deviation coefficient of the moving gas column in the wellbore, d t represents the inner diameter of the tubing, γ g represents the relative density of natural gas, L represents the well depth.

[0066] Furthermore: S is the comprehensive skin factor, and its derivation formula is as follows:

[0067]

[0068] Among them, J represents the intercept of the straight line segment of the pressure buildup curve, P wforepresents the bottom-hole flowing pressure before well shut-in, m represents the slope of the straight-line segment of the pressure buildup curve, q g represents the gas production volume, B g represents the gas formation volume factor, φ represents the effective formation porosity, C t represents the total compressibility, h represents the effective formation thickness;

[0069] D is the non-Darcy flow coefficient, and its derivation formula is as follows:

[0070]

[0071] where, γ g represents the relative density of natural gas, K represents the effective formation permeability, φ represents the effective formation porosity, h represents the effective formation thickness, r w represents the wellbore radius, μ g represents the viscosity of natural gas.

[0072] Compared with the prior art, the present invention has the following beneficial effects:

[0073] First, the method of the present invention relates density to the sand production pressure difference, establishes a rapid quantitative evaluation technology for the sand production pressure difference in multi-layer sandstone gas reservoirs, and can quickly calculate the critical sand production pressure difference of different reservoirs.

[0074] Second, by using the method of the present invention, the influence of the effective thickness and the production pressure difference on the gas production capacity can be balanced, the reservoir can be exploited finely, and the production potential of the reservoir can be further tapped, forming an optimization technology for the single-well gas production capacity based on the effective thickness and the production pressure difference. BRIEF DESCRIPTION OF THE DRAWINGS

[0075] Figure 1 is a schematic diagram of the method of an embodiment of the present invention;

[0076] Figure 2 is a theoretical curve graph of the gas production capacity and the effective formation thickness;

[0077] Figure 3 is a theoretical chart for productivity evaluation under different production pressure difference conditions;

[0078] Figure 4 is a curve fitting graph of the relationship between the density and the sand production pressure difference of a certain gas storage reservoir;

[0079] Figure 5 is a fitting graph of the single-well gas production capacity of a certain gas storage reservoir before optimization and the theoretical model chart;

[0080] Figure 6 is a fitting graph of the single-well gas production capacity of a certain gas storage reservoir after optimization and the theoretical model chart. DETAILED DESCRIPTION OF THE INVENTION

[0081] The technical solution of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are part of the embodiments of the present invention, rather than all of them. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present invention without creative efforts shall fall within the protection scope of the present invention.

[0082] In the description of the present invention, it should be noted that the orientation or positional relationship indicated by the terms "center", "upper", "lower", "left", "right", "vertical", "horizontal", "inner", "outer", etc. is based on the orientation or positional relationship shown in the accompanying drawings. It is only for the convenience of describing the present invention and simplifying the description, rather than indicating or implying that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and thus should not be construed as a limitation of the present invention. In addition, the terms "first", "second", and "third" are only used for descriptive purposes and cannot be construed as indicating or implying relative importance.

[0083] An optimization method for the gas production capacity of a single well in a gas storage reservoir includes the following steps:

[0084] S1: Establish a basic theoretical model of the stable point binomial productivity equation;

[0085] S2: According to the basic theoretical model in S1, considering the degree of reservoir utilization in the vertical direction of a single well in the gas storage reservoir, establish a theoretical curve of gas production capacity and formation effective thickness;

[0086] S3: According to the theoretical curve obtained in S2, establish an evaluation model layout of the productivity of the effective thickness under different production pressure differences;

[0087] S4: According to the sand production test results of different reservoirs, combined with the density logging curve, establish a functional relationship between density and sand production pressure difference through mathematical fitting;

[0088] S5: According to the model layout in S3 and the functional relationship between density and sand production pressure difference in S4, select a reservoir with appropriate effective thickness for utilization and sand production pressure difference, and optimize the gas production capacity of a single well.

[0089] In some embodiments: The specific steps of step S4 include:

[0090] S401: According to the sand production test results of different reservoirs, count the sand production pressure difference of different well sections and the corresponding logging interpretation density values of the well sections;

[0091] S402: According to the sand production pressure difference and density data of the well sections obtained by statistics, confirm the density value range and sand production pressure difference range;

[0092] S403: Make a scatter plot of the sand production pressure difference obtained by statistics and the corresponding density values;

[0093] S404: By observing the correlation trend between density and sand production pressure difference in the scatter plot, use a suitable mathematical model for parameter fitting, and take the fitted parameter equation as the function expression of the relationship between density and sand production pressure difference;

[0094] S405: Calculate the goodness of fit of the function expression in S404 and evaluate the function fitting result;

[0095] S406: Draw the final density - sand production pressure difference fitting curve graph.

[0096] By analyzing the critical sand production pressure difference and well logging curves such as natural gamma, density, and longitudinal wave slowness, the correlation between density and critical sand production pressure difference is the best. Therefore, establish the functional relationship between density and sand production pressure difference to quickly predict the sand production pressure difference.

[0097] In S401, the sand production pressure differences of different well sections are calculated based on the rock mechanics parameters and strength discrimination criteria of the corresponding well sections. Through the longitudinal wave slowness, transverse wave slowness, and density logging data, the dynamic Poisson's ratio, dynamic Young's modulus, dynamic shear modulus, bulk modulus, and poroelastic coefficient of the rock are calculated to construct the formation rock mechanics parameter profile of the entire well section.

[0098] According to Drucker - Prager, calculate and study the sand production pressure difference, which specifically includes the following steps:

[0099]

[0100] In the formula,

[0101] I1 = σ1 + σ2 + σ3

[0102]

[0103] In the conventional triaxial compression stress path, there is:

[0104]

[0105]

[0106] Among them: β is the experimental constant of the rock cohesion, σ s is the experimental constant of the rock internal friction angle; is the internal friction angle of the rock; c is the cohesion. I1 and J2 are the first stress invariant and the second stress deviator invariant respectively. σ1, σ2, and σ3 are the first principal stress, the second principal stress, and the third principal stress of the formation around the wellbore respectively.

[0107] When f(σ) is greater than 0, the rock will be damaged and then lead to formation sand production. Therefore, select f(σ) as the sand production trend evaluation index. Analyzing the sand production trend index f(σ) shows that:

[0108] When f(σ) is less than 0, the formation is stable, and the smaller f(σ) is, the more stable the formation is;

[0109] When f(σ) is greater than 0, the formation becomes unstable and sand production occurs, and the larger the value of f(σ), the more serious the sand production of the formation;

[0110] When f(σ) is equal to 0, the formation is in a state of ultimate equilibrium. At this time, the corresponding production pressure difference is the critical production pressure difference for sand production from the formation skeleton.

[0111] In some embodiments: The specific steps of step S5 include:

[0112] S501: According to the model layout in S3, confirm the effective thickness and sand production pressure difference of different reservoir sections, and select the reservoir section with the second lowest sand production pressure difference;

[0113] S502: Calculate the reduction amount of the effective thickness when this reservoir section is not utilized;

[0114] S503: Evaluate the maximum allowable increase in the production pressure difference on the basis of reducing the effective thickness;

[0115] S504: Import the new effective thickness and production pressure difference parameters into the model layout in S3 to evaluate the productivity, and determine whether the productivity of a single well is improved;

[0116] S505: If the productivity of a single well is improved, the optimization is successful, and then select another reservoir section with the second lowest sand pressure difference, and repeat steps S502 - S503; if the productivity of a single well is not improved, re - select the reservoir section with the second lowest sand production pressure difference, and repeat steps S502 - S503; until the optimization effect is maximized;

[0117] S506: Analyze and compare the productivity of a single well before and after optimization, and calculate the productivity improvement rate.

[0118] In some embodiments: The specific steps of step S1 include: According to the binomial productivity theory equation of the stable point, establish a binomial productivity model between the formation pressure and the natural gas production q g between:

[0119]

[0120] In the formula:

[0121] S a = S + Dq g

[0122] Convert the above formula into a binomial productivity equation:

[0123] P R 2 -P wf2 = Aq g + Bq g 2

[0124] Then there is:

[0125]

[0126]

[0127] In the formula, P sc = 0.101 MPa, T sc = 293.16 K.

[0128] Among them, P R represents the original formation pressure, P wf represents the reduced bottom-hole flowing pressure, represents the average gas viscosity, is the average gas deviation factor under formation conditions, represents the average temperature under formation conditions, r e represents the well control radius, r w represents the wellbore radius, S represents the comprehensive skin factor, K represents the effective formation permeability, h represents the effective gas reservoir thickness, D represents the non-Darcy flow coefficient; T sc represents the temperature under standard gas conditions; S a represents the apparent skin factor; A represents the laminar flow coefficient; B represents the turbulent flow coefficient.

[0129] The derivation formula of

[0130]

[0131] Among them,

[0132] a = 1.390(T pr - 0.920) 0.920 - 0.360T pr - 0.101

[0133]

[0134] c = 0.132 - 0.32lg(T pr )

[0135]

[0136] Among them, a represents the first deviation factor calculation coefficient, b represents the second deviation factor calculation coefficient, c represents the third deviation factor calculation coefficient, d represents the fourth deviation factor calculation coefficient, T pr represents the pseudo-reduced temperature, P prRepresents the pseudo - comparison pressure.

[0137] P wf The converted bottom - hole flowing pressure, and its conversion formula is as follows:

[0138]

[0139]

[0140] Among them, P wh Represents the well - head pressure, λ represents the tubing resistance coefficient, S represents the comprehensive skin factor, T av Represents the average temperature of the moving gas column in the wellbore, Z av Represents the average deviation factor of the moving gas column in the wellbore, d t Represents the inner diameter of the tubing, γ g Represents the relative density of natural gas, L represents the well depth.

[0141] S is the comprehensive skin factor, and its derivation formula is as follows:

[0142]

[0143] Among them, J represents the intercept of the straight - line segment of the pressure build - up curve, P wfo Represents the bottom - hole flowing pressure before shut - in, m represents the slope of the straight - line segment of the pressure build - up curve, q g Represents the gas production volume of natural gas, B g Represents the gas - volume factor of natural gas, φ represents the effective porosity of the formation, C t Represents the total compressibility, h represents the effective thickness of the formation;

[0144] D is the non - Darcy flow coefficient, and its derivation formula is as follows:

[0145]

[0146] Among them, γ g Represents the relative density of natural gas, K represents the effective permeability of the formation, φ represents the effective porosity of the formation, h represents the effective thickness of the formation, r w Represents the wellbore radius, μ g Represents the viscosity of natural gas.

[0147] The present invention also provides a specific implementation case as follows to prove the effect of the present invention:

[0148] First, according to the sand - production test results, the sand - production pressure differences and density values of 22 well sections are statistically analyzed. The density is between 2.16 g / cm 3 ~2.55 g / cm 3 , and the sand - production pressure differences are between 6.34 MPa and 21.06 MPa, with relatively large differences in sand - production pressure differences. From Figure 4It can be seen that there is a certain correlation between density and sand production pressure difference, indicating that density can reflect the magnitude of the sand production pressure difference to a certain extent. According to the fitting curve, the sand production pressure differences of different reservoirs can be evaluated.

[0149] According to the sand production pressure difference evaluation method and combined with logging curves, the effective thickness and corresponding sand production pressure differences of 6 gas production wells are obtained, as shown in Table 1.

[0150] Table 1 Evaluation results of single-well effective thickness and sand production pressure difference

[0151]

[0152] Usage method of the productivity evaluation model chart: From the evaluation results of the sand production pressure difference, it can be seen that the sand production pressure differences of the 6 gas production wells are between 6.0 MPa and 8.2 MPa, the production pressure differences are basically controlled between 6.0 MPa and 8.0 MPa, and the effective formation thicknesses are mainly distributed between 26.6 m and 55.3 m. Project the gas production capacity of the gas wells onto the productivity evaluation model chart, as Figure 5 shown.

[0153] Analysis shows that when comparing Well No. 1, Well No. 2, and Well No. 3, the effective thickness gradually increases, the production pressure difference gradually decreases, and the single-well productivity differences are relatively small; when comparing Well No. 3, Well No. 4, and Well No. 5, the production pressure differences are basically the same, and the larger the effective thickness, the greater the single-well productivity; when comparing Well No. 5 and Well No. 6, the effective thickness of Well No. 5 is 10 m larger, the production pressure difference is 2.0 MPa lower, and the single-well productivity of Well No. 5 is lower than that of Well No. 6. This shows that the single-well productivity is affected by both the effective thickness and the production pressure difference. The larger the effective thickness, the greater the single-well productivity, and the larger the production pressure difference, the greater the single-well productivity. At the same time, it also shows that appropriately reducing the effective thickness and increasing the production pressure difference can improve the single-well productivity.

[0154] In order to maximize the single-well gas production capacity of the injection-production wells in the gas storage reservoir, generally, full utilization of the reservoir is considered. Taking the single-well productivity of Well No. 3 as an example, 15 reservoirs are fully utilized, the production pressure difference is 6.0 MPa, and the gas production capacity is 145×10 4 m 3 / d. Table 2 lists the effective thickness and corresponding sand production pressure difference evaluation results of the 15 reservoir sections of this well. The sand production pressure difference has a large span, between 6.0 MPa and 15.0 MPa. It can be seen from Table 2 that the sand production pressure differences of Reservoirs 7 and 8 are the smallest. Therefore, it is chosen to avoid using Reservoirs 7 and 8. Although the effective thickness is reduced by 5.4 m, the production pressure difference can be increased to 8.5 MPa. After optimization, the single-well gas production capacity can reach 160×10 4 m 3 / d, which is 10.3% higher than that before optimization. See Table 3 for details. Figure 6 In summary, through the present invention, the peak shaving potential of the injection-production wells in the gas storage reservoir can be quantitatively evaluated, and the optimization space can be quantitatively evaluated after optimization.

[0155] Table 2 Evaluation Results of Effective Thickness and Sand Production Pressure Difference of Different Reservoirs (Well No. 3)

[0156]

[0157]

[0158] Table 3 Comparison Table of Single Well Gas Production Capacity before and after Optimization

[0159]

[0160] The above embodiments are only used to illustrate the technical concept and characteristics of the present invention. The purpose is to enable those who are familiar with this technology to understand the content of the present invention and implement it accordingly, and it cannot be used to limit the protection scope of the present invention. Any equivalent transformation or modification made according to the spirit and essence of the present invention should be covered within the protection scope of the present invention.

Claims

1. A method for optimizing the gas production capacity of a single well in a gas storage reservoir, characterized in that: It includes the following steps: S1: Establish a basic theoretical model of the stable point binomial productivity equation; S2: Based on the basic theoretical model in S1 and in combination with the characteristics of short-term strong injection and strong production in the gas storage reservoir, establish a theoretical curve of gas production capacity and effective formation thickness; S3: Based on the theoretical curve obtained in S2, establish a productivity evaluation model layout of the effective thickness under different production pressure differences; S4: According to the sand production test results of different reservoirs, in combination with the density logging curve, establish a functional relationship between density and sand production pressure difference through mathematical fitting; S5: According to the model layout in S3 and the functional relationship between density and sand production pressure difference in S4, select reservoirs with appropriate effective thickness and sand production pressure difference, and optimize the gas production capacity of a single well.

2. The optimization method for the gas production capacity of a single well in a gas storage reservoir according to claim 1, characterized in that: The specific steps of step S4 include: S401: According to the sand production test results of different reservoirs, count the sand production pressure difference of different well sections and the corresponding logging interpretation density values of the well sections; S402: According to the data of the sand production pressure difference and density values of the well sections obtained by statistics, confirm the density value range and sand production pressure difference range; S403: Make a scatter plot of the sand production pressure difference obtained by statistics and the corresponding density values; S404: By observing the correlation trend between density and sand production pressure difference in the scatter plot, use a matching mathematical model for parameter fitting, and take the fitted parameter equation as the functional expression of the relationship between density and sand production pressure difference; S405: Calculate the goodness of fit of the functional expression in S404 and evaluate the function fitting result; S406: Draw the final density-sand production pressure difference fitting curve graph.

3. The optimization method for the gas production capacity of a single well in a gas storage reservoir according to claim 2, characterized in that: In S401, the sand production pressure difference of different well sections is calculated based on the rock mechanics parameters and strength discrimination criteria of the corresponding well sections.

4. The optimization method for the gas production capacity of a single well in a gas storage reservoir according to claim 3, characterized in that: Through the longitudinal wave slowness, transverse wave slowness and density logging data, calculate the dynamic Poisson's ratio, dynamic Young's modulus of elasticity, dynamic shear modulus, bulk modulus and poroelastic coefficient of the rock, and construct a profile of the formation rock mechanics parameters of the whole well section.

5. The optimization method for the gas production capacity of a single well in a gas storage reservoir according to claim 3, characterized in that: Calculate the sand production pressure difference according to Drucker-Prager. The specific calculation process is as follows: In the formula, I1 = σ1 + σ2 + σ3 In the triaxial compression stress path, there is: Where: β is the experimental constant of the rock cohesion, and σ s is the experimental constant of the rock internal friction angle; is the internal friction angle of the rock; c is the cohesion; I1 and J2 are the first stress invariant and the second stress deviator invariant respectively; σ1, σ2, and σ3 are the first principal stress, the second principal stress, and the third principal stress of the formation around the wellbore respectively; When f(σ) is greater than 0, the rock will be damaged and then lead to formation sand production. Therefore, f(σ) is selected as the sand production trend evaluation index. Analyzing the sand production trend index f(σ), it can be known that: When f(σ) is less than 0, the formation is stable, and the smaller f(σ) is, the more stable the formation is; When f(σ) is greater than 0, the formation is unstable and sand production occurs, and the larger the value of f(σ) is, the more serious the formation sand production is; When f(σ) is equal to 0, the formation is in the limit equilibrium state. At this time, the corresponding production pressure difference is the critical sand production pressure difference of the formation skeleton sand production.

6. The optimization method for the gas production capacity of a single well in a gas storage reservoir according to claim 1, wherein: The specific steps of step S5 include: S501: According to the model layout in S3, confirm the effective thickness and sand production pressure difference of different reservoir sections, and select the reservoir section with a low sand production pressure difference; S502: Calculate the reduction amount of the effective thickness when this reservoir section is not exploited; S503: Evaluate the maximum allowable increase in the production pressure difference on the basis of reducing the effective thickness; S504: Import the new effective thickness and production pressure difference parameters into the model layout in S3 to evaluate the productivity, and judge whether the productivity of a single well is improved. S505: If the single-well productivity is improved, the optimization is successful, and then select another reservoir section with the second-lowest sand production pressure difference, and repeat steps S502 - S503; if the single-well productivity is not improved, re-select the reservoir section with the second-lowest sand production pressure difference, and repeat steps S502 - S503; until the optimization effect is maximized; S506: Analyze and compare the single-well productivity before and after optimization, and calculate the productivity improvement rate.

7. The optimization method for the gas production capacity of a single well in a gas storage reservoir according to claim 1, characterized in that: The specific steps of S1 include: establishing a binomial productivity model between formation pressure and natural gas production q according to the binomial productivity theoretical equation of the stable point g : Where: S a = S + Dq g Convert the above formula into a binomial productivity equation: P R 2 -P wf 2 = Aq g + Bq g 2 Then there is: where P sc = 0.101 MPa, T sc = 293.16 K; Among them, P R represents the original formation pressure, P wf represents the bottom-hole flowing pressure, represents the average gas viscosity, is the average gas deviation factor under formation conditions, represents the average temperature under formation conditions, r e represents the well control radius, r w represents the wellbore radius, S represents the comprehensive skin factor, K represents the effective formation permeability, h represents the effective gas reservoir thickness, D represents the non-Darcy flow coefficient; T sc represents the temperature under standard gas conditions; S a represents the apparent skin factor; A represents the laminar flow coefficient; B represents the turbulent flow coefficient.

8. A method for optimizing the single-well gas production capacity of a gas storage reservoir according to claim 7, characterized in that: The derivation formula is as follows: Among them, a = 1.390(T pr - 0.920) 0.920 - 0.360T pr - 0.101 c = 0.132 - 0.32lg(T pr ) Among them, a represents the first deviation factor calculation coefficient, b represents the second deviation factor calculation coefficient, c represents the third deviation factor calculation coefficient, d represents the fourth deviation factor calculation coefficient, T pr represents the pseudo reduced temperature, P pr represents the pseudo reduced pressure.

9. The optimization method for the single-well gas production capacity of a gas storage reservoir according to claim 7, wherein: Calculate the bottom-hole flowing pressure P wf , and its calculation formula is as follows: Among them, P wh represents the wellhead pressure, λ represents the tubing resistance coefficient, S represents the comprehensive skin factor, T av represents the average temperature of the moving gas column in the wellbore, Z av represents the average deviation coefficient of the moving gas column in the wellbore, d t represents the inner diameter of the tubing, γ g represents the relative density of natural gas, and L represents the well depth.

10. A method for optimizing the gas production capacity of a single well in a gas storage reservoir according to claim 7, characterized in that: S is the comprehensive skin factor, and its derivation formula is as follows: Wherein, J represents the intercept of the straight-line segment of the pressure build-up curve, P wfo represents the bottom-hole flowing pressure before well shut-in, m represents the slope of the straight-line segment of the pressure build-up curve, q g represents the gas production rate, B g represents the gas formation volume factor, φ represents the effective formation porosity, C t represents the total compressibility, h represents the effective formation thickness; D is the non-Darcy flow coefficient, and its derivation formula is as follows: Among them, γ g represents the relative density of natural gas, K represents the effective formation permeability, φ represents the effective formation porosity, h represents the effective formation thickness, r w represents the wellbore radius, μ g represents the viscosity of natural gas.

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