A method for optimizing the tubing size of injection and production wells in a water-driven sandstone oil and gas reservoir

Abstract

This invention relates to a method for optimizing the tubing size of injection and production wells in a water-driven sandstone oil and gas reservoir, comprising the following steps: 1. Determine the coefficients A and B of the binomial production capacity equation for the gas well and establish the production capacity equation. 2. Analyze and determine the critical sand production pressure difference during gas production in the target gas reservoir's injection and production wells. 3. Establish a binomial function relationship between formation pressure and cumulative gas production. 4. Calculate the formation pressure during the peak winter gas production period of the target gas reservoir based on the established binomial function relationship. 5. Use nodal analysis to perform dynamic modeling and calculate the production capacity of different tubing sizes under different formation pressures and production pressure differences. 6. Based on the production capacity under peak formation pressure, use cross-plots to quantitatively optimize the tubing size with a production capacity increase of 10% and a critical sand production pressure difference of less than 3 MPa. This significantly reduces the blind selection of tubing and ensures the gas supply capacity and reliability of the gas reservoir during the critical peak-shaving period.

Description

Technical Field

[0001] This invention relates to the field of underground natural gas storage technology, and more specifically, to a method for optimizing the tubing size of injection and production wells in a water-driven sandstone oil and gas reservoir. Background Technology

[0002] Globally and in my country, most underground natural gas storage facilities (hereinafter referred to as gas storage facilities) are converted from mid-to-late-stage or depleted oil and gas reservoirs, with sandstone gas storage facilities being one of the main types. Unlike conventional gas field development, the core operational characteristic of gas storage facilities is their function of storing and regulating gas peak demand, and they generally operate in a cyclical manner using a "summer injection, winter production" approach. To efficiently meet the peak demand during extremely cold winter weather, gas storage facilities not only require gas to be "injectable, extractable, and storeable," but also to ensure that natural gas sufficient to meet market demand can be extracted in a very short time. Therefore, the economical and efficient operation of gas storage facilities places higher demands on the gas production capacity of injection and production wells.

[0003] Gas well productivity is controlled by multiple factors, primarily geological factors (such as formation pressure, reservoir properties, and heterogeneity) and engineering factors (such as tubing size, completion methods, and production enhancement measures). Among these, tubing size is a key controllable engineering factor affecting the gas production capacity of injection and production wells in a gas storage facility. Theoretically, the larger the tubing size, the stronger the gas supply flow capacity, and the higher the single-well productivity. Correspondingly, fewer wells are needed to produce the same working gas volume during extremely cold winter weather, which helps reduce the overall investment in the storage facility construction project. However, large wellbore sizes (corresponding to large-size tubing) require high investment in well construction engineering, and the construction difficulty and safety risks will also increase significantly. At the same time, for sandstone gas storage facilities, large wellbore sizes (corresponding to large-size tubing) may significantly increase the risk of sand production, further leading to wellbore collapse, and sand-containing produced gas may also endanger the safe operation of surface equipment. Therefore, in the design and construction of gas storage facilities, it is extremely important to select and determine the appropriate tubing size for injection and production wells, which is of great significance for the safe and efficient peak-shaving gas production operation of the gas storage facility and the optimization of engineering investment.

[0004] Currently, the design and evaluation of gas reservoir development wells focus on the impact of reservoir properties, heterogeneity, and water (oil) production on gas well productivity. However, the design and construction of injection and production wells for gas storage facilities generally rely on the dynamics of previous development wells and reservoir geological characteristics. Based on qualitative analysis of oil and gas reservoir production experience, the tubing size of injection and production wells is determined when converting oil and gas reservoirs into gas storage facilities. There is a lack of methods for optimizing the tubing size of injection and production wells to take into account multiple factors such as coordination of gas production nodes, erosion, sand production, and the need for efficient peak shaving in extremely cold winter weather. This has caused great difficulties for the economical and efficient construction of medium-deep and low-permeability gas storage facilities in China. Summary of the Invention

[0005] This invention provides a method for optimizing the tubing size of injection and production wells in sandstone oil and gas reservoirs with weak water drive. This method comprehensively considers multiple factors such as the coordination of gas production nodes, erosion, fluid carrying capacity, and sand production in the injection and production wells. Based on the gas well productivity under formation pressure during the peak winter gas production period, it quantitatively analyzes and determines the optimal tubing size for the injection and production wells, thus solving the problem of the lack of methods for optimizing the optimal tubing size in sandstone gas reservoir injection and production wells in the prior art. This method differs from conventional methods in several ways. First, it accurately calculates the formation pressure during the peak winter gas production period of the target gas storage facility using the gas production-inventory curve. Second, based on the gas well productivity under the formation pressure during the peak peak period, it comprehensively considers multiple factors such as the coordination of gas production nodes in the gas storage facility's injection and production wells, erosion, fluid carrying, and sand production, and plots cross-sectional diagrams of gas well productivity, tubing size, production pressure differential, and critical sand production pressure differential for different tubing sizes. Third, using the critical sand production pressure differential and the increase in gas well productivity as constraint indicators and evaluation criteria, it quantitatively analyzes and determines the reasonable tubing size for the gas storage facility's injection and production wells. This method overcomes the problems of conventional empirical or qualitative analysis methods based on reservoir development dynamics in determining the tubing size of gas storage facility injection and production wells, which lack comprehensive consideration of factors, fail to fully utilize the high efficiency of peak shaving in injection and production wells, and have unclear quantitative standards for optimal selection. It significantly improves the scientific nature of the tubing size selection for gas storage facility injection and production wells and its adaptability to the geological conditions of the storage facility, better meeting the needs of efficient peak shaving operation of gas storage facilities in winter.

[0006] The technical solution provided by this invention is: a method for optimizing the tubing size of injection and production wells in a water-driven sandstone oil and gas reservoir, comprising the following steps:

[0007] Step 1: Based on Darcy's seepage theory or the interpretation of well test results in the mining field, analyze and determine the coefficients A and B of the binomial productivity equation of the gas well, and establish the binomial productivity equation of the injection and production wells of the target gas storage.

[0008] Step 2: Based on indoor rock mechanics experiments or field gas well production sand production tests, analyze and determine the critical sand production pressure difference during gas production in the injection and production wells of the target gas storage facility;

[0009] Step 3: Based on the gas production and inventory curve of the gas storage facility, calculate the formation pressure and cumulative gas production during a single cycle of gas production in the gas storage facility, and fit and establish a binomial function relationship between the two.

[0010] Step 4: Based on the actual operation patterns of similar geological gas storage facilities already in operation during winter peak gas extraction, or the winter peak gas extraction operation requirements determined by the construction plan, calculate the formation pressure of the target gas storage facility during the peak winter peak gas extraction period using the binomial function relationship established above.

[0011] Step 5: Based on the binomial production capacity equation and vertical pipe flow equation of the gas well, dynamic modeling is performed using the nodal analysis method to calculate and evaluate the gas well production capacity of the gas storage injection and production wells under different formation pressures and production pressure differentials when using oil pipes of different diameters.

[0012] Step 6: Based on the gas well productivity at the formation pressure during the peak gas production period in winter, draw a cross-plot of gas well productivity, tubing size, production pressure difference and critical sand production pressure difference for tubing of different diameters, and analyze and determine the reasonable tubing size for injection and production wells in the target gas storage.

[0013] The binomial productivity equation for the gas well is as follows:

[0014]

[0015] Wherein, the equation coefficients A and B are respectively:

[0016]

[0017]

[0018] in, Formation pressure, MPa; The bottom hole flowing pressure is in MPa. This represents the daily gas production of the gas well, 10 4 m 3 / d; The relative density of the gas; The average viscosity of the gas is given in mPa. s; This is the gas average deviation factor; m is the velocity coefficient. -1 S is the skin coefficient, a decimal; T is the reservoir temperature, in K. The gas supply radius of the gas well, in meters; denoted as the wellbore radius (m); k is the effective gas permeability of the reservoir (mD); and h is the effective reservoir thickness (m).

[0019] The critical sand discharge pressure difference is based on the equation calculate;

[0020] Where C is the maximum tangential stress in the wellbore rock, in MPa; Poisson's ratio of the rock; The average density of the overlying rock strata is kg / m³. 3 ; Formation pressure, MPa; The bottom-hole flowing pressure is MPa; g is the acceleration due to gravity, m / s². 2 H represents the depth of the middle part of the reservoir, in meters. The inclination angle is (°).

[0021] The calculation of different formation pressures and cumulative gas production during a single cycle of gas production in a gas storage facility, and the establishment of a binomial function relationship between the two, is described below. ;

[0022] in, The amount of gas produced in a single cycle of gas production at a gas storage facility is Q. p Formation pressure at time, MPa; Q p This refers to the cumulative gas extraction volume during a single cycle of gas extraction production at the gas storage facility, 10 8 m 3 a, b, and c are the undetermined coefficients for mathematical fitting.

[0023] The formation pressure during the peak winter gas production period of the gas storage facility refers to the average formation pressure of the month with the highest gas production volume, as statistically analyzed by month, during the winter peak gas production of the gas storage facility.

[0024] The vertical pipe flow equation is as follows:

[0025]

[0026] The expression for the coefficient s is:

[0027]

[0028] in, The bottom hole flowing pressure is in MPa. q represents the wellhead oil pressure, in MPa; sc This represents the daily gas production of the gas well, 10 4 m 3 / d; e is the natural logarithm, e=2.71828; is the tubing resistance coefficient, dimensionless; D is the tubing inner diameter, in meters. The average temperature inside the wellbore, in K; This is the average deviation factor of natural gas in the wellbore, and it is dimensionless.

[0029] When the calculation and evaluation uses oil pipes of different diameters, the oil pipes of different diameters include inner diameters of 62.0, 75.9, 100.3, 125.7 and 163.8 mm, which correspond to outer diameters of 73.0, 88.9, 114.3, 139.7 and 177.8 mm, respectively.

[0030] The gas well production capacity of the gas storage injection and production wells under different formation pressures and different production pressure differentials, the different formation pressures including the upper and lower limit pressures of the gas storage operation as assessed by the construction plan, and the formation pressure of the gas storage during the peak gas production period in winter.

[0031] The aforementioned plotting of gas well productivity, tubing size, production pressure differential, and critical sand production pressure differential with tubing of different diameters refers to plotting the relationship between gas well productivity and production pressure differential and tubing size using tubing size as the horizontal axis, gas well productivity as the main vertical axis, and gas well production pressure differential and critical sand production pressure differential as the auxiliary vertical axes.

[0032] The analysis described above determines the appropriate tubing size for injection and production wells in the target gas storage facility based on the well productivity at formation pressure during the peak winter peak gas production period. The appropriate tubing size for injection and production wells in the gas storage facility is determined according to the following conditions:

[0033] When the gas well production capacity increases by ≤10% with the increase of tubing size, and the gas well production pressure difference is less than the critical sand production pressure difference, then the corresponding previous tubing size is the reasonable tubing size for the gas storage injection and production wells.

[0034] B. When the gas well production capacity increases by more than 10% with the increase of tubing size, and the gas well production pressure difference is less than the critical sand production pressure difference, then the maximum tubing size that the existing process conditions can provide is the reasonable tubing size for the gas storage injection and production wells.

[0035] C. When the gas well production capacity increases by more than 10% with the increase of tubing size, but the gas well production pressure difference is greater than the critical sand production pressure difference, then the maximum tubing size that satisfies the requirement that the gas well production pressure difference is less than the critical production pressure difference is the reasonable tubing size for gas storage injection and production wells.

[0036] The beneficial effects of this invention are as follows:

[0037] 1. Existing methods for selecting appropriate tubing sizes for injection and production wells in sandstone oil and gas reservoirs primarily rely on factors such as reservoir properties, burial depth, and reservoir development dynamics. The tubing sizes are determined qualitatively based on experience, or the tubing sizes used during the gas field's development phase are directly adopted. This method differs from the former by comprehensively considering key engineering factors such as node coordination, erosion limitations, and minimum fluid carrying capacity. In particular, it incorporates the critical production sand production pressure differential constraint, specifically addressing the core potential risk of sand production induced by high-intensity injection and production in sandstone gas reservoirs. This guides the quantitative selection of safe, reliable, and technically optimal tubing size schemes.

[0038] 2. Compared with existing methods, this invention addresses the "low-high-low" operating conditions of gas storage facilities during peak-shaving gas production. Based on the gas well productivity under formation pressure during peak production periods, this invention ensures that the tubing size can support the required high-intensity gas production during periods of maximum gas production in the well network system, rapid decrease in formation pressure, and most urgent gas demand. Furthermore, by quantifying and optimizing the most suitable tubing size through a 10% increase in gas well productivity, this effectively guarantees the gas supply capacity and reliability of the gas storage facility during critical peak-shaving periods, significantly reducing the blind selection of tubing size and investment risks. Attached Figure Description

[0039] Figure 1 This is a schematic diagram of the process for optimizing the tubing size of injection and production wells in a water-driven sandstone oil and gas reservoir according to an embodiment of the present invention.

[0040] Figure 2 This is a graph showing the functional relationship between the critical sand production pressure difference and compressive strength of the target gas storage reservoir in this embodiment of the invention.

[0041] Figure 3 is a graph showing the gas production and inventory curve of the target gas storage facility according to an embodiment of the present invention.

[0042] Figure 4 shows the monthly gas extraction volume and unevenness coefficient of the target gas storage facility according to an embodiment of the present invention.

[0043] Figure 5 is a binomial function diagram showing the relationship between formation pressure and cumulative gas production during a single-cycle gas production process of the target gas storage facility in an embodiment of the present invention.

[0044] Figure 6 is a node analysis diagram of the production capacity of injection and production wells under different formation pressures and tubing sizes in the target gas storage of the present invention.

[0045] Figure 7 is a cross-plot of the production capacity, tubing size, production pressure differential, and critical sand production pressure differential of the target gas storage well with different diameter tubing in an embodiment of the present invention.

[0046] Figure 8 shows the relationship between the increase in gas well productivity and tubing size under different formation pressures in the target gas storage facility according to an embodiment of the present invention. Detailed Implementation

[0047] Preferred embodiments of the invention will now be described in more detail. While preferred embodiments of the invention are described below, it should be understood that the invention can be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that the invention will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art.

[0048] The specific embodiments of the present invention will be further described in detail below with reference to the accompanying drawings.

[0049] refer to Figure 1 As shown in the figure, the method for optimizing the tubing size of injection and production wells in a water-driven sandstone oil and gas reservoir according to an embodiment of the present invention includes the following steps:

[0050] Step S101: Based on Darcy's seepage theory or interpretation from well tests at the mining site, analyze and determine the coefficients A and B of the binomial productivity equation for the gas well, and establish the binomial productivity equation for the injection and production wells of the target gas storage. Specifically:

[0051] The binomial production capacity equation is as follows:

[0052]

[0053] Wherein, the equation coefficients A and B are respectively:

[0054]

[0055]

[0056] in, Formation pressure, MPa; The bottom hole flowing pressure is in MPa. This represents the daily gas production of the gas well, 10 4 m 3 / d; The relative density of the gas; The average viscosity of the gas is given in mPa. s; This is the gas average deviation factor; m is the velocity coefficient. -1 S is the skin coefficient, a decimal; T is the reservoir temperature, in K. The gas supply radius of the gas well, in meters; denoted as the wellbore radius (m); k is the effective gas permeability of the reservoir (mD); and h is the effective reservoir thickness (m).

[0057] In this embodiment of the invention, taking the Nanbao No. 1 gas storage facility in the Bohai Bay Basin as an example, geological evaluation and laboratory natural gas analysis tests were conducted on the target gas storage facility. The obtained parameters included an effective natural gas permeability of 41.18 mD, an effective reservoir thickness of 11.41 m, a reservoir temperature of 85.7℃, a natural gas relative density of 0.59, and a natural gas average deviation factor of 0.9. These parameters were substituted into the binomial productivity equation coefficients A and B to calculate the binomial productivity equation coefficient for the target gas storage facility: A = 0.011529 MPa. 2 / (10) 4 m 3 ·d -1 B = 0.3145 MPa 2 / (10) 4 m 3 ·d -1 The corresponding binomial capacity equation is: .

[0058] Step S102: Based on indoor rock mechanics experiments or field gas well production sand production tests, analyze and determine the critical sand production pressure difference during gas production in the target gas storage injection and production wells. Specifically:

[0059] The critical sand discharge pressure difference is based on the equation: calculate;

[0060] Where C is the maximum tangential stress in the wellbore rock, in MPa; Poisson's ratio of the rock; The average density of the overlying rock strata is kg / m³. 3 ; Formation pressure, MPa; The bottom-hole flowing pressure is MPa; g is the acceleration due to gravity, m / s². 2 H represents the depth of the middle part of the reservoir, in meters. The inclination angle is (°).

[0061] In this embodiment of the invention, three representative cores from three different sedimentary microfacies in the Nanpu No. 1 gas storage reservoir were selected for indoor rock mechanics experiments. The uniaxial compressive strength, elastic model, Poisson's ratio, and other parameters of the reservoir rocks in different sedimentary microfacies were measured (Table 1). Considering the risk of sand production in the weakest area of ​​the reservoir rock's mechanical strength, the minimum critical sand production pressure difference was determined to be approximately 3 MPa. Figure 2 ).

[0062] Table 1. Statistical table of uniaxial compression test results of cores from reservoirs with different sedimentary microfacies.

[0063]

[0064] Step S103: Based on the gas production and inventory curve of the gas storage facility, calculate the formation pressure and cumulative gas production during a single cycle of gas production in the gas storage facility, and fit and establish a binomial function relationship between the two.

[0065] For the Nanpu No. 1 gas storage facility, the gas production-inventory curve determined by the construction plan is (…). Figure 3 The effective inventory level corresponding to different formation pressures can be obtained from this inventory curve. When the formation pressure of the gas storage facility is the upper limit pressure of 27 MPa, the effective inventory level is 9.69 × 10⁻⁶. 8 m 3 The cumulative gas production (working gas production) is the difference between the upper pressure limit of 27 MPa and the effective inventory corresponding to other pressure points. The cumulative gas production is calculated and statistically analyzed for formation pressures ranging from 27 MPa to 0.1 MPa. A binomial function relationship between the two is established by fitting the data. ( Figure 4 );

[0066] Step S104: Based on the actual operation patterns of winter peak gas production in nearby gas storage facilities with similar geological characteristics, or the winter peak gas production operation requirements determined by the construction plan, calculate the formation pressure during the peak winter peak gas production period of the target gas storage facility using the binomial function relationship established above.

[0067] The monthly unevenness coefficient of peak-shaving gas production in a gas storage facility refers to the ratio of the average daily gas production volume in different months to the average daily gas production volume during the total peak-shaving gas production period. The larger the unevenness coefficient for a given month, the more gas is produced in that month when the number of peak-shaving gas production days is the same.

[0068] For the oil layer of Nanpu No. 1 gas storage facility, the working gas volume determined by the construction plan is 5.52 × 10⁻⁶. 8 m 3 Since the gas storage facility's single-cycle gas production period is 120 days, the average daily gas production during the total peak-shaving period is 460 × 10⁻⁶ days. 4 m 3 The monthly unevenness coefficients for peak-shaving gas production at the Nanpu No. 1 gas storage facility were 0.82 (November), 1.11 (December), 1.27 (January), 0.83 (February), and 0.71 (March). Figure 5 The number of gas extraction days per month from November to March were 15, 31, 31, 28, and 15 days, respectively. Therefore, the average daily gas extraction volume per month from November to March can be calculated as 377.2 × 10⁻⁶ days using the gas storage facility's working gas volume, the number of gas extraction days per month, and the monthly unevenness coefficient. 4 m 3 510.6×10 4 m 3 584.2×10 4 m 3 381.8×10 4 m 3 326.6×10 4 m 3 Therefore, the monthly gas extraction volume (November to March) can be calculated to be 0.57 × 10⁻⁶. 8 m 3 1.58×10 8 m 3 1.81×10 8 m 3 1.07×10 8 m 3 and 0.49×10 8 m 3 The cumulative gas extraction volume for each month was 0.57 × 10 8 m 3 2.15×10 8 m 3 3.96×10 8 m 3 5.03×10 8 m 3 and 5.52×10 8 m 3 (Table 2).

[0069] Substituting the cumulative monthly gas production into the established binomial function, the formation pressure for different months can be calculated (Table 2). For the oil layer of Nanpu No. 1 gas storage, the average formation pressure (average of formation pressure at the beginning and end of gas production) at the maximum gas production in January was calculated to be 17.62 MPa (Table 2).

[0070] Table 2 Relationship between average formation pressure and cumulative gas production

[0071]

[0072] Step S105: Based on the binomial production capacity equation and vertical pipe flow equation of the gas well, dynamic modeling is performed using the nodal analysis method. The dynamic outflow curves of the gas wells in the gas storage reservoir under different formation pressures are calculated and evaluated when using tubing of different diameters. Specifically:

[0073] The vertical pipe flow equation of the gas well;

[0074]

[0075] The expression for the coefficient s is:

[0076]

[0077] in, The bottom hole flowing pressure is in MPa. q represents the wellhead oil pressure, in MPa; sc For natural gas production, 10 4 m 3 / d; e is the natural logarithm, e=2.71828; is the tubing resistance coefficient, dimensionless; D is the tubing inner diameter, in meters. The average temperature inside the wellbore, in K; This is the average deviation factor of the gas inside the wellbore, which is dimensionless.

[0078] Taking a typical well in the Nanpu No. 1 gas storage facility as an example, the calculated inflow and outflow curves ( Figure 6 For the Inflow Dynamics (IPR) curve, the larger the production pressure differential, the higher the gas well productivity. When the formation pressure is 27 MPa, 17.62 MPa, and 10.4 MPa, the IPR curve shows that the gas well productivity gradually decreases, and the corresponding gas well open flow rate (AOF) decreases from 327.66 × 10⁻⁶. 4 m³ / d decreased to 77.44 × 10 4 m³ / d.

[0079] For the outflow dynamics curve (OPR curve), under constant formation pressure, with the tubing inner diameter as the variable, the OPR curve increases with increasing tubing inner diameter, indicating enhanced tubing transport capacity. During peak gas production (formation pressure 17.62 MPa), the well productivity corresponding to the point of convergence between the tubing system and the formation IPR curve increased from 32.79 × 10⁻⁶. 4 m³ / d increased to 82.27 × 10 4 m³ / d.

[0080] Step S106: Based on the gas well productivity at the formation pressure during the peak winter gas production period, draw a cross-plot of gas well productivity, tubing size, production pressure differential, and critical sand production pressure differential for tubing of different diameters, and analyze and determine the reasonable tubing size for injection and production wells in the target gas storage. Figure 7 ).

[0081] In this embodiment of the invention, based on the upper limit pressure of 27 MPa and the lower limit pressure of 10.4 MPa obtained from the Nanpu No. 1 gas storage scheme assessment, and the average formation pressure of 17.62 MPa during the peak winter gas production period, a cross-plot of the production capacity, tubing size, production pressure differential, and critical sand production pressure differential of gas wells with different diameter tubing is plotted. Figure 8 It should be noted that the formation pressure in the gas storage facility is dynamically changing during the gas production period. The upper limit pressure of 27 MPa and the lower limit pressure of 10.4 MPa only represent the instantaneous state during the gas production operation of the gas storage facility. This embodiment of the invention mainly focuses on the optimal selection of reasonable tubing size for injection and production wells in the target gas storage facility under the more representative average formation pressure of 17.62 MPa during the peak winter gas production period.

[0082] Table 3. Reasonable flow rate of gas wells with different tubing sizes

[0083]

Claims

1. A method for optimizing the tubing size of injection and production wells in a water-driven sandstone oil and gas reservoir, characterized in that, The method includes the following steps: Step 1: Based on Darcy's seepage theory or the interpretation of well test results in the mining field, analyze and determine the coefficients A and B of the binomial productivity equation of the gas well, and establish the binomial productivity equation of the injection and production wells of the target gas storage. Step 2: Based on indoor rock mechanics experiments or field gas well production sand production tests, analyze and determine the critical sand production pressure difference during gas production in the injection and production wells of the target gas storage facility; Step 3: Based on the gas production and inventory curve of the gas storage facility, calculate the formation pressure and cumulative gas production during a single cycle of gas production in the gas storage facility, and fit and establish a binomial function relationship between the two. Step 4: Based on the actual operation patterns of similar geological gas storage facilities already in operation during winter peak gas extraction, or the winter peak gas extraction operation requirements determined by the construction plan, calculate the formation pressure of the target gas storage facility during the peak winter peak gas extraction period using the binomial function relationship established above. Step 5: Based on the binomial production capacity equation and vertical pipe flow equation of the gas well, dynamic modeling is performed using the nodal analysis method to calculate and evaluate the gas well production capacity of the gas storage injection and production wells under different formation pressures and production pressure differentials when using oil pipes of different diameters. Step 6: Based on the gas well productivity at the formation pressure during the peak gas production period in winter, draw a cross-plot of gas well productivity, tubing size, production pressure difference and critical sand production pressure difference for tubing of different diameters, and analyze and determine the reasonable tubing size for injection and production wells in the target gas storage.

2. The method for optimizing the tubing size of injection and production wells in a weak water-drive sandstone oil and gas reservoir according to claim 1, characterized in that, The aforementioned binomial productivity equation for gas wells is: ； Wherein, the equation coefficients A and B are respectively: ； ； in, Formation pressure, MPa; The bottom hole flowing pressure is in MPa. This represents the daily gas production of the gas well, 10 4 m 3 / d; The relative density of the gas; The average viscosity of the gas is given in mPa. s; This is the gas average deviation factor; m is the velocity coefficient. -1 S is the skin coefficient, a decimal; T is the reservoir temperature, in K. The gas supply radius of the gas well, in meters; denoted as the wellbore radius (m); k is the effective gas permeability of the reservoir (mD); and h is the effective reservoir thickness (m).

3. The method for optimizing the tubing size of injection and production wells in a weak water-drive sandstone oil and gas reservoir according to claim 1, characterized in that, The critical sand discharge pressure difference is based on the equation calculate; Where C is the maximum tangential stress in the wellbore rock, in MPa; Poisson's ratio of the rock; The average density of the overlying rock strata is kg / m³. 3 ; Formation pressure, MPa; The bottom-hole flowing pressure is MPa; g is the acceleration due to gravity, m / s². 2 H represents the depth of the middle part of the reservoir, in meters. The inclination angle is (°).

4. The method for optimizing the tubing size of injection and production wells in a weak water-drive sandstone oil and gas reservoir according to claim 1, characterized in that, The calculation of different formation pressures and cumulative gas production during a single cycle of gas production in a gas storage facility, and the establishment of a binomial function relationship between the two, is described below. ; in, The amount of gas produced in a single cycle of gas production at a gas storage facility is Q. p Formation pressure at time, MPa; Q p This refers to the cumulative gas extraction volume during a single cycle of gas extraction production at the gas storage facility, 10 8 m 3 a, b, and c are the undetermined coefficients for mathematical fitting.

5. The method for optimizing the tubing size of injection and production wells in a weak water-drive sandstone oil and gas reservoir according to claim 1, characterized in that, The formation pressure during the peak winter gas production period of the gas storage facility refers to the average formation pressure of the month with the highest gas production volume, as statistically analyzed by month, during the winter peak gas production of the gas storage facility.

6. The method for optimizing the tubing size of injection and production wells in a weak water-drive sandstone oil and gas reservoir according to claim 1, characterized in that, The vertical pipe flow equation is as follows: ； The expression for the coefficient s is: ； in, The bottom hole flowing pressure is in MPa. q represents the wellhead oil pressure, in MPa; sc This represents the daily gas production of the gas well, 10 4 m 3 / d; e is the natural logarithm, e=2.71828; is the tubing resistance coefficient, dimensionless; D is the tubing inner diameter, in meters. The average temperature inside the wellbore, in K; This is the average deviation factor of natural gas in the wellbore, and it is dimensionless.

7. The method for optimizing the tubing size of injection and production wells in a weak water-drive sandstone oil and gas reservoir according to claim 1, characterized in that, When the calculation and evaluation uses oil pipes of different diameters, the oil pipes of different diameters include inner diameters of 62.0, 75.9, 100.3, 125.7 and 163.8 mm, which correspond to outer diameters of 73.0, 88.9, 114.3, 139.7 and 177.8 mm, respectively.

8. The method for optimizing the tubing size of injection and production wells in a weak water-drive sandstone oil and gas reservoir according to claim 1, characterized in that, The gas well production capacity of the gas storage injection and production wells during the gas production process is under different formation pressures and different production pressure differentials. The different formation pressures include the upper and lower limit pressures of the gas storage operation determined by the construction plan, as well as the formation pressure during the peak gas production period of the gas storage in winter.

9. The method for optimizing the tubing size of injection and production wells in a weak water-drive sandstone oil and gas reservoir according to claim 1, characterized in that, The aforementioned plotting of gas well productivity, tubing size, production pressure differential, and critical sand production pressure differential with tubing of different diameters refers to plotting the relationship between gas well productivity and production pressure differential and tubing size using tubing size as the horizontal axis, gas well productivity as the main vertical axis, and gas well production pressure differential and critical sand production pressure differential as the auxiliary vertical axes.

10. The method for optimizing the tubing size of injection and production wells in a weak water-drive sandstone oil and gas reservoir according to claim 1, characterized in that, The analysis described above determines the appropriate tubing size for injection and production wells in the target gas storage facility based on the well productivity at formation pressure during the peak winter peak gas production period. The appropriate tubing size for injection and production wells in the gas storage facility is determined according to the following conditions: When the gas well production capacity increases by ≤10% with the increase of tubing size, and the gas well production pressure difference is less than the critical sand production pressure difference, then the corresponding previous tubing size is the reasonable tubing size for the gas storage injection and production wells. B. When the gas well production capacity increases by more than 10% with the increase of tubing size, and the gas well production pressure difference is less than the critical sand production pressure difference, then the maximum tubing size that the existing process conditions can provide is the reasonable tubing size for the gas storage injection and production wells. C. When the gas well production capacity increases by more than 10% with the increase of tubing size, but the gas well production pressure difference is greater than the critical sand production pressure difference, then the maximum tubing size that satisfies the requirement that the gas well production pressure difference is less than the critical production pressure difference is the reasonable tubing size for gas storage injection and production wells.

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