Low-permeability carbonate rock gas field and gas well optimization production allocation method based on multi-factor coupling

Abstract

The invention discloses a low-permeability carbonate rock gas field gas well optimization production allocation method based on multi-factor coupling, and belongs to the technical field of oil-gas exploration and development, and the method comprises the steps: building a multi-factor coupling description equation considering material balance, shaft flow and quasi-steady-state flow of a pure gas well; well shut-in static pressure testing before and after production is carried out, and original and current formation pressure of a gas well is obtained; the dynamic reserves of the gas well are calculated in combination with the accumulated gas production, and flow pressure changes under different designed gas production rates are predicted; the stable gas production rate, the wellhead oil pressure and the accumulated gas production rate of the target gas well in the pilot production period are recorded, a relation chart of the flowing bottomhole pressure and the time is drawn, and related parameters are solved; and the formation pressure corresponding to the designed gas production rate in the development period is substituted into the multi-factor coupling description equation, a relation chart for studying the gas well dynamic description stable production capacity is established, and gas well optimization production allocation is carried out. According to the method, the gas production rate of the gas well is designed by applying a multi-factor coupling optimized production allocation method, and the method has good adaptability to low-permeability carbonate rock gas reservoirs.

Description

Technical Field

[0001] This invention relates to the field of oil and gas exploration and development technology, specifically to a method for optimizing production allocation of gas wells in low-permeability carbonate gas fields based on multi-factor coupling. Background Technology

[0002] Carbonate gas fields are one of the important areas of natural gas exploration and development in China. The Puguang, Yuanba, Anyue, and Western Sichuan gas fields discovered since 2000 are all carbonate gas fields. As of the end of 2018, the proven reserves of China's gas fields were 11.01 × 10⁻⁶. 12 m 3 The proven reserves of the carbonate gas field are 3.12 × 10¹² m³. 3 This accounts for 28.34% of the total. The Sichuan Basin is a leader in carbonate gas field development, producing 66% of conventional gas in 2018. Among the 20 potential onshore natural gas resource zones in China, 9 are carbonate zones (strata), with a total resource potential of 11.43 × 10⁻⁶. 12 m 3 This accounts for 30.56 × 10 of the total resource potential. 12 m 3 Carbonate rocks account for 37.39% of the total, and are also a major area for domestic natural gas production, such as the high-sulfur Lower Permian strata in northeastern Sichuan Basin, with a planned production increase of 70 × 10⁸ m³. 3 .

[0003] Low permeability is a typical characteristic of gas reservoirs in carbonate rock gas fields discovered in recent years. Taking the Anyue Dengying Formation as an example, its permeability ranges from 0.0038 to 18.68 × 10⁻⁶. -3 μm 2 Average 2.71×10 -3 μm 2 .

[0004] Optimizing gas well production allocation is a fundamental technical task in gas field development and requires corresponding research methods. To address this issue, scholars both domestically and internationally have conducted extensive research, resulting in numerous methods and approaches for determining the reasonable production output of gas wells, such as reservoir numerical simulation. However, this method struggles to describe the actual production situation of gas wells in the early stages of reservoir development when dynamic and static data are limited. This makes it difficult to understand the relationship between gas well production allocation and stable production capacity.

[0005] Other methods include the absolute unobstructed flow ratio method, the gas production indicator curve method and the "inflection point" analysis method for deviations from a single tangent, the inflow-outflow curve method, the optimal calculation method for declining gas well productivity, and the multi-factor coupled analysis method based on the productivity equation, wellbore flow, and dynamic reserves. For example, patent CN117669854A discloses an optimized production allocation method for strongly heterogeneous carbonate gas reservoirs. Most of these methods rely on the gas well's productivity equation, but for low-permeability gas wells, solving the productivity equation and the absolute unobstructed flow rate is perplexing. This manifests in the inability of certain production regimes to reach stability during gas well productivity testing. If the testing time is extended, the calculated absolute unobstructed flow rate is usually small, making it difficult to guide gas well production allocation. The analytical method of determining reasonable production by controlling the reasonable rate of wellhead pressure drop requires using a large amount of actual well production data to statistically deduce the reasonable gas well production. This method is not very adaptable in the early stages of development, making it difficult to understand the relationship between gas well production allocation and stable production capacity. Summary of the Invention

[0006] This invention aims to solve the aforementioned problems in the existing methods for optimizing gas well production allocation in gas technology, and proposes an optimized production allocation method for gas wells in low-permeability carbonate gas fields based on multi-factor coupling. This method designs the gas production of gas wells using trial production and well test data without conducting production well tests, and has good adaptability to low-permeability carbonate gas reservoirs.

[0007] To achieve the above-mentioned objectives, the technical solution of the present invention is as follows:

[0008] A method for optimizing gas well production allocation in low-permeability carbonate gas fields based on multi-factor coupling, characterized by the following steps:

[0009] Step a: Establish the formation pressure description, flow pressure description, and wellbore flow equation for the target gas well, and establish a multi-factor coupled description equation by combining the three equations.

[0010] Step b: Conduct static pressure tests on the target gas well before and after production, record and interpret the pressure data, and determine the original formation pressure and current formation pressure of the gas well.

[0011] Step c: Calculate the dynamic reserves of the gas well from the original formation pressure, current formation pressure and cumulative gas production of the target gas well, and predict the change value of the flow pressure under different design gas production rates;

[0012] Step d: Record the stable gas production, wellhead oil pressure, and cumulative gas production of the target gas well during the trial production period; plot the relationship between bottom hole flowing pressure and time; and graphically determine the parameters related to the straight line intercept and the straight line slope of the quasi-steady-state flow stage during the trial production period.

[0013] Step e: Substitute the formation pressure corresponding to the designed gas production during the development period into the multi-factor coupled description equation to predict the changes in bottom hole flowing pressure, wellhead oil pressure, and stable production period of gas wells under different designed gas production during the development period. In this way, establish a relationship chart for studying the dynamic description of stable production capacity of gas wells, and optimize gas well production allocation based on chart comparison.

[0014] Furthermore, in step a, the multi-factor coupling description equation is a description equation that considers the three factors of material balance, wellbore flow, and quasi-steady-state flow in a pure gas well, and it is also the basic equation describing the production dynamics of a gas well.

[0015] Furthermore, in step b, the static pressure test refers to recording the stopping point depth and pressure data in the gas wellbore using a pressure gauge in the well test, converting the stopping point depth to the stopping point vertical depth, fitting the pressure gradient of the last two stopping points in the wellbore, and calculating the pressure in the middle of the gas well producing layer. This pressure is the original formation pressure.

[0016] Furthermore, the conversion of the stopping point depth to the stopping point vertical depth refers to converting the stopping point depth to the stopping point vertical depth using well inclination data.

[0017] Furthermore, the pressure in the middle of the gas well producing zone is calculated using the following formula:

[0018] p = p² + (H - H²)Δp;

[0019] In the formula, p is the pressure in the middle of the gas well producing zone, MPa; p2 is the pressure at the last stopping point, MPa; H is the vertical depth in the middle of the gas well producing zone, m; H2 is the vertical depth at the last stopping point, m; Δp is the pressure gradient.

[0020] Furthermore, in step c, the material balance equation of the closed gas reservoir is used to predict the formation pressure variation under different designed gas production rates.

[0021] Furthermore, the mass balance equation for a closed gas reservoir is expressed as follows:

[0022]

[0023] In the formula, G represents dynamic reserves, 10 8 m 3 G p This represents the cumulative gas production during the trial and development periods, 10 8 m 3 ;p i Z represents the original formation pressure, in MPa; i is the original natural gas deviation coefficient, dimensionless; p is the formation pressure, MPa; Z is the natural gas deviation coefficient, dimensionless.

[0024] Furthermore, in step d, the stable gas production, wellhead oil pressure, and cumulative gas production during the trial production period of the target gas well are recorded. Based on the flow pressure description equation, a graph showing the relationship between bottom hole flowing pressure and time is plotted. The expression for the flow pressure description equation during the gas well trial production period is:

[0025]

[0026] In the formula, p wf For the bottom hole flowing pressure, p i α represents the initial formation pressure, t represents the production time (d); 试采 The parameters related to the linear intercept during the quasi-steady-state flow stage of the trial production period are in MPa. 2 ;β 试采 The slope of the straight line during the quasi-steady-state flow stage of the trial production period is expressed in MPa. 2 / d;

[0027] The expression for the flow pressure description equation during the development period after the trial production period is as follows:

[0028]

[0029] In the formula, p R1 t is the average formation pressure within the well control radius at the end of the trial production period, in MPa; t is the production time, in days; q 试采 To ensure stable production during the trial mining period, 10 4 m 3 / d; the subscript sc represents the standard ground condition.

[0030] Furthermore, in step a, the wellbore flow equation is:

[0031]

[0032] In the formula, p wh The wellhead oil pressure under specified production conditions, in MPa; r g ρ is the relative density of the gas, dimensionless; H is the vertical depth of the middle part of the producing formation, m; L is the well depth of the middle part of the producing formation considering well inclination factors, m; The average temperature of the wellbore is K; ρ is the natural gas deviation coefficient under average wellbore pressure and average temperature conditions, dimensionless; f is the friction resistance coefficient, dimensionless; d is the tubing inner diameter, cm; p sc Standard atmospheric pressure, MPa.

[0033] In summary, the present invention has the following advantages:

[0034] 1. This invention designs the gas production of gas wells using a multi-factor coupled optimization method based on production test and well test data without conducting production tests. It has good adaptability to low-permeability carbonate gas reservoirs.

[0035] 2. This invention can effectively reduce the adverse factors of production capacity well testing, reduce the waste of resources caused by releasing a large amount of sulfur-containing natural gas when conducting production capacity well testing of sulfur-containing gas wells, and reduce the risks of on-site testing operations and safety management risks.

[0036] 3. Compared with conventional methods, the present invention can significantly save on the operating costs incurred by special well testing (a single special well test costs 800,000 yuan), effectively saving costs. Attached Figure Description

[0037] Figure 1 This is a flowchart illustrating the implementation of the present invention;

[0038] Figure 2 This is a dynamic prediction chart of gas well inflow at different production times in Embodiment 1 of the present invention;

[0039] Figure 3 This is a chart illustrating the prediction of oil pressure changes in gas wells in Embodiment 1 of the present invention.

[0040] Figure 4 This is a chart showing the predicted oil pressure changes of a typical gas well, B, in Embodiment 1 of the present invention.

[0041] Figure 5 This is a chart showing the predicted oil pressure changes of a typical gas well, C, in Embodiment 1 of the present invention.

[0042] Figure 6 This is a chart showing the predicted oil pressure changes of a typical gas well, D, in Embodiment 1 of the present invention.

[0043] Figure 7 This is a comparison diagram of the overall optimization of the Sinian gas reservoir in the Anyue gas field before and after in Embodiment 2 of the present invention. Detailed Implementation

[0044] To more clearly illustrate the present invention, the following description, in conjunction with preferred embodiments and accompanying drawings, further clarifies the invention. Those skilled in the art should understand that the specific description below is illustrative rather than restrictive and should not be construed as limiting the scope of protection of the present invention.

[0045] This invention provides a method for optimizing gas well production in low-permeability carbonate gas fields based on multi-factor coupling, comprising the following steps:

[0046] Step 1: Establish the formation pressure description equation, the flow pressure description equation, and the wellbore flow equation respectively. Combine these three equations to establish a multi-factor coupled description equation.

[0047] The formation pressure description equation adopts the material balance equation of a closed gas reservoir, which describes the relationship between cumulative gas production and formation pressure. Its expression is as follows:

[0048]

[0049] In the formula, G represents dynamic reserves, 10 8 m 3 G p To calculate the cumulative gas production, 10 8 m 3 , will G p The expression can also be rewritten as: (This is a breakdown of the two phases: the trial production phase and the development phase.)

[0050] G p =G p1 +a y q sc t (2)

[0051] In the formula G p1 This represents the cumulative gas production during the trial production period, 10 8 m 3 ;a y q represents the effective production days of a gas well, expressed as d / a. sc To ensure stable production from gas wells during the development phase, 10 4 m 3 / d; t represents the production time, d.

[0052] For low-permeability gas wells, inter-well interference is relatively weak during gas well production. After the fixed production rate experiences the early and late stages of unstable seepage and reaches a pseudo-steady state, the bottom hole flowing pressure exhibits the following relationship:

[0053]

[0054] in,

[0055]

[0056] In the formula, p wf The bottom hole flowing pressure is in MPa; p e K represents the original formation pressure, in MPa; K represents the effective permeability of the gas layer, in μm. 2 h is the effective thickness of the gas layer, in meters; μ is the viscosity of natural gas, in mPa·s; T is the temperature of the gas layer, in K; C t r is the overall compressibility coefficient of the gas layer, 1 / MPa; e r is the control radius of the gas well, in meters (m). w S is the wellbore radius, in meters; S is the skin coefficient, dimensionless; Z is the natural gas deviation coefficient, dimensionless; the subscript sc represents the standard surface condition.

[0057] Formula (3) can be rewritten in the form of gas well trial production period as follows:

[0058]

[0059] In the formula pi α is the original formation pressure, MPa; t is the production time, d; 试采 The parameters related to the linear intercept during the quasi-steady-state flow stage of the trial production period are in MPa. 2 ;β 试采 The slope of the straight line during the quasi-steady-state flow stage of the trial production period is expressed in MPa. 2 / d. α 试采 and β 试采 The solution is usually found using a graphical method.

[0060] Based on the pseudo-steady-state flow equation for gas wells, neglecting changes in formation seepage parameters and fluid properties during gas well production, and according to the principle of pressure superposition, the bottom hole flowing pressure of the gas well during the development period after the trial production period satisfies the following relationship:

[0061]

[0062] In the formula, p R1 q represents the average formation pressure within the well control radius at the end of the trial production period, in MPa; 试采 To ensure stable production during the trial mining period, 10 4 m 3 / d.

[0063] In this step, the wellbore flow equation is:

[0064]

[0065] In the formula, p wh The wellhead oil pressure under specified production conditions, in MPa; r g ρ is the relative density of the gas, dimensionless; H is the vertical depth of the middle part of the producing formation, m; L is the well depth of the middle part of the producing formation considering well inclination factors, m; The average temperature of the wellbore is K; Natural gas deviation coefficient under average wellbore pressure and average temperature conditions, dimensionless; f is the friction resistance coefficient, dimensionless; d is the tubing inner diameter, cm; p sc Standard atmospheric pressure, MPa.

[0066] In this step, the multi-factor coupled description equation is established to consider three factors: material balance, wellbore flow, and quasi-steady-state flow in a pure gas well. The dynamic variation law of the gas well is as follows:

[0067]

[0068] Equation (9) is the basic equation describing the production dynamics of a gas well. The relevant parameters of the model can be obtained from the production data and well test data obtained during the trial production period.

[0069] Step 2: For a gas well with optimized production requirements, conduct static pressure tests before and after well shutdown, record and interpret the pressure data, and calculate the original formation pressure and current formation pressure of the gas well based on the formation pressure description equation.

[0070] The static pressure test specifically refers to recording the stopping point depth and pressure data in the gas wellbore using a pressure gauge during well testing, converting the stopping point depth to the vertical depth of the stopping point, fitting the pressure gradient of the last two stopping points in the wellbore, and calculating the pressure in the middle of the gas well producing layer. This pressure is the original formation pressure.

[0071] Specifically, converting the stopping point depth to the stopping point vertical depth means converting the stopping point depth to the stopping point vertical depth using well inclination data.

[0072] Suppose there are 5 stopping points in the wellbore of the gas well. The vertical depth of the 4th stopping point is denoted as H1, the vertical depth of the 5th stopping point is denoted as H2, the pressure of the 4th stopping point is denoted as p1, and the pressure of the 5th stopping point is denoted as p2. The pressure gradient is calculated by equation (10).

[0073]

[0074] In the formula, Δp is the pressure gradient, MPa / m; H1 is the vertical depth of the 4th stop point, m; H2 is the vertical depth of the 5th stop point, m; p1 is the pressure at the 4th stop point, and p2 is the pressure at the 5th stop point.

[0075] Step 3: Calculate the dynamic reserves of the gas well based on the original formation pressure, current formation pressure, and cumulative gas production, and predict the formation pressure change value under different designed gas production rates.

[0076] Among them, the material balance equation of the closed gas reservoir is used to predict the formation pressure change under different design gas production rates. Its expression is:

[0077]

[0078] In the formula, G represents dynamic reserves, 10 8 m 3 G p To calculate the cumulative gas production, 10 8 m 3 , will G p The expression can also be rewritten as: (This is a breakdown of the two phases: the trial production phase and the development phase.)

[0079] G p =G p1 +a y q sc t (13)

[0080] In the formula G p1 This represents the cumulative gas production during the trial production period, 10 8m 3 ;a y q represents the effective production days of a gas well, expressed as d / a. sc To ensure stable production from gas wells during the development phase, 10 4 m 3 / d; t represents the production time, d.

[0081] Step 4: Record the stable gas production, wellhead oil pressure, and cumulative gas production during the trial production period of the gas well. Plot the relationship between bottom hole flowing pressure and time. Graph the parameters α related to the linear intercept during the quasi-steady-state flow stage of the trial production period. 试采 And the slope β of the straight line during the pseudo-steady-state flow stage of the trial production period 试采 .

[0082] Among them, the stable gas production, wellhead oil pressure, and cumulative gas production during the gas well trial production period were used to plot the relationship between bottom hole flowing pressure and time. The describing equation is as follows:

[0083]

[0084] In the formula p i α is the original formation pressure, MPa; t is the production time, d; 试采 The parameters related to the linear intercept during the quasi-steady-state flow stage of the trial production period are in MPa. 2 ;β 试采 The slope of the straight line during the quasi-steady-state flow stage of the trial production period is expressed in MPa. 2 / d. α 试采 and β 试采 The solution is usually found using a graphical method.

[0085] Based on the pseudo-steady-state flow equation for gas wells, neglecting changes in formation seepage parameters and fluid properties during gas well production, and according to the principle of pressure superposition, the bottom hole flowing pressure of the gas well during the development period after the trial production period satisfies the following relationship:

[0086]

[0087] In the formula p R1 q represents the average formation pressure within the well control radius at the end of the trial production period, in MPa; 试采 To ensure stable production during the trial mining period, 10 4 m 3 / d.

[0088] Step 5: Substitute the formation pressure corresponding to the designed gas production during the development period into the multi-factor coupled description equation (9) to predict the changes in bottom hole flowing pressure, wellhead oil pressure, and stable production period of gas wells under different designed gas production during the development period. Draw dynamic prediction charts of gas well inflow and gas well oil pressure changes under different designed gas production. Optimize gas well production based on chart comparison.

[0089] Example 1

[0090] This embodiment applies the gas well optimization and production allocation method established by the present invention to a super-large gas field in the Sichuan Basin. This gas field is a typical representative of low-permeability, highly heterogeneous carbonate gas fields, and its seepage is mainly based on a radial composite model. The well test interpretation permeability is 0.0038 × 10⁻⁶. -3 μm 2 ~18.68×10 -3 μm 2 Average 2.71×10 -3 μm 2 During the trial production period, abundant dynamic monitoring data was collected for the gas reservoir, and a preliminary evaluation of the dynamic reserves of the gas wells was conducted. Taking Well A as an example, dynamic monitoring was carried out four times during the trial production and early development stages, with dynamic reserves ranging from 59.85 to 66.60 × 10⁻⁶. 8 m 3 (See Table 1).

[0091] Table 1. Dynamic monitoring and dynamic reserve evaluation results of Well A

[0092]

[0093] Based on well test data from the trial production phase, the maximum gas production of the gas well was determined to be 45 × 10⁻⁶. 4 m 3 / d, combining dynamic monitoring data, and using the optimized production allocation method coupled with dynamic data to draw gas well dynamic prediction charts (see... Figure 2 , Figure 3 ). Figure 2 This is a chart showing the dynamic prediction of gas well inflow at different production times for Well A. The red curve represents the tubing dynamics under pressure constraints. The point where this curve coincides with the predicted future gas well inflow curve represents the maximum production capacity of the gas well in that year. For example, the maximum gas production of the gas well at the end of year 1 is 52 × 10⁻⁶. 4 m 3 / d, and by the end of the forecast period, this value will be 29 × 10. 4 m 3 Therefore, the annual production quota for each gas well must be less than the well's maximum production capacity.

[0094] Figure 3 This is a chart predicting the oil pressure changes in well A over different production times at varying gas production rates. The chart shows that when the transmission pressure is 10.7 MPa, if a pressure of 30 × 10⁻⁶ is applied... 4 m 3 / d production organization, the stable production period of gas wells is about 9.2 years, if 45×10 4 m 3 Production is organized by the well, but the stable production period is less than 3 years. It is recommended that the well's production be adjusted to 27 × 10⁻⁶. 4 m 3 / d, to achieve the designed stable production years.

[0095] This method was used to conduct optimized production allocation studies on three other typical wells, B, C, and D (see...). Figure 4 , Figure 5 , Figure 6 Among them, well B's well test interpretation showed poor reservoir properties in the outer area, with high test production, but poor test production results. From Figure 4 It can be seen that in order for Well B to achieve the designed stable production period of 9.5 years, the production output needs to be less than 4×10⁻⁶. 4 m 3 / d, therefore, it is recommended to adjust production to 3×10 4 ~4×10 4 m 3 / d. Based on the predicted oil pressure changes in well C, the chart for well D ( Figure 5 , Figure 6 Based on the current production situation, it is recommended that well C be equipped with a production capacity of 25-26 × 10⁻⁶. 4 m 3 / d, Well D operates according to the current production system of 10×10 4 m 3 / d can meet the design requirements for stable production for the specified number of years, and the output does not need to be adjusted.

[0096] Example 2

[0097] This embodiment takes the application of the gas well optimization and production allocation method established by the method of the present invention to the Sinian gas reservoir in Anyue Gas Field as an example.

[0098] Through specialized well testing of over 36 wells, the production capacity and dynamic reserves of gas wells were determined. It was found that the early production allocation of gas wells with consistent seepage capacity in the inner and outer zones of the Deng 4 gas reservoir was reasonable, and a high-production, high-oil-pressure strategy should be adopted. For reservoirs with good outer zones and poor inner zones, the early production capacity of gas wells would be underestimated, and the production allocation and gas production rate would be too low. A high-production, high-oil-pressure strategy should be adopted, and the production allocation ratio should be optimized to 1 / 4 to 1 / 3 of the initial qAOF. For reservoirs with poor outer zones and good inner zones, the production allocation and gas production rate would be too high, and the production capacity of gas wells would decline rapidly. A low-production, low-oil-pressure strategy should be adopted, and the production allocation ratio should be optimized to 1 / 12 to 1 / 10 of the initial qAOF.

[0099] By gaining a deeper understanding of already operational gas wells, optimization of production systems is being implemented for those with inefficient systems. A number of wells with good external performance but poor internal performance have excessively low production allocation and extraction rates, resulting in underutilization of their capacity. Furthermore, wells with poor external performance but good internal performance cannot meet stable production demands at their current production scale, necessitating a reduction in production allocation and extraction rates. For example... Figure 7 As shown, the daily gas production capacity of the 72 gas wells in the pre-optimization gas reservoir is 1529 × 10⁻⁶. 4 m 3 The average daily gas production per well is 21.2 × 10⁻⁶. 4 m 3Of the 14 wells, the production and oil pressure decreased rapidly, with 80.5% achieving stable production. Through verification of the production capacity of each individual well and refined optimization of production allocation, the daily gas production capacity of the gas reservoir reached 1457 × 10⁻⁶. 4 m 3 The average daily gas production per well is 20.2 × 10⁻⁶. 4 m 3 The proportion of stable production wells increased to 95%, the rate of oil pressure decline slowed down, and the development plan design requirements were basically met.

[0100] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. Any simple modifications or equivalent changes made to the above embodiments based on the technical essence of the present invention shall fall within the protection scope of the present invention.

Claims

1. A method for optimizing gas well production allocation in low-permeability carbonate gas fields based on multi-factor coupling, characterized in that, Includes the following steps: Step a: Establish the formation pressure description, flow pressure description, and wellbore flow equation for the target gas well, and establish a multi-factor coupled description equation by combining the three equations. Step b: Conduct static pressure tests on the target gas well before and after production, record and interpret the pressure data, and determine the original formation pressure and current formation pressure of the gas well. Step c: Calculate the dynamic reserves of the gas well from the original formation pressure, current formation pressure and cumulative gas production of the target gas well, and predict the change value of the flow pressure under different design gas production rates; Step d: Record the stable gas production, wellhead oil pressure, and cumulative gas production of the target gas well during the trial production period; plot the relationship between bottom hole flowing pressure and time; and graphically determine the parameters related to the straight line intercept and the straight line slope of the quasi-steady-state flow stage during the trial production period. Step e: Substitute the formation pressure corresponding to the designed gas production during the development period into the multi-factor coupled description equation to predict the changes in bottom hole flowing pressure, wellhead oil pressure, and stable production period of gas wells under different designed gas production during the development period. In this way, establish a relationship chart for studying the dynamic description of stable production capacity of gas wells, and optimize gas well production allocation based on chart comparison.

2. The method for optimizing gas well production in low-permeability carbonate gas fields based on multi-factor coupling as described in claim 1, characterized in that, In step a, the multi-factor coupling description equation is a description equation that considers the three factors of material balance, wellbore flow, and quasi-steady-state flow in a pure gas well. It is also the basic equation for describing the production dynamics of a gas well.

3. The method for optimizing gas well production in low-permeability carbonate gas fields based on multi-factor coupling as described in claim 1, characterized in that, In step b, static pressure testing refers to recording the stopping point depth and pressure data in the gas wellbore using a pressure gauge in the well test, converting the stopping point depth to the vertical depth of the stopping point, fitting the pressure gradient of the last two stopping points in the wellbore, and calculating the pressure in the middle of the gas well producing layer. This pressure is the original formation pressure.

4. The method for optimizing gas well production in low-permeability carbonate gas fields based on multi-factor coupling as described in claim 3, characterized in that, The aforementioned conversion of the stopping point depth to the stopping point vertical depth refers to converting the stopping point depth to the stopping point vertical depth using well inclination data.

5. The method for optimizing gas well production in low-permeability carbonate gas fields based on multi-factor coupling as described in claim 3, characterized in that, The pressure in the middle of the gas well producing zone is calculated using the following formula: p = p² + (H - H²)Δp; In the formula, p is the pressure in the middle of the gas well producing zone, MPa; p2 is the pressure at the last stopping point, MPa; H is the vertical depth in the middle of the gas well producing zone, m; H2 is the vertical depth at the last stopping point, m; Δp is the pressure gradient.

6. The method for optimizing gas well production in low-permeability carbonate gas fields based on multi-factor coupling as described in claim 1, characterized in that, In step c, the material balance equation of a closed gas reservoir is used to predict the formation pressure variation under different designed gas production rates.

7. The method for optimizing gas well production in low-permeability carbonate gas fields based on multi-factor coupling as described in claim 6, characterized in that, The mass balance equation for a closed gas reservoir is expressed as follows: In the formula, G is dynamic reserves, 10 8 m 3 ; G p is the cumulative gas production of the test production period and the development period, 10 8 m 3 ; p i Z represents the original formation pressure, in MPa; i is the original natural gas deviation coefficient, dimensionless; p is the formation pressure, MPa; Z is the natural gas deviation coefficient, dimensionless.

8. The method for optimizing gas well production in low-permeability carbonate gas fields based on multi-factor coupling as described in claim 1, characterized in that, In step d, the stable gas production, wellhead oil pressure, and cumulative gas production during the trial production period of the target gas well are recorded. Based on the flow pressure description equation, a graph showing the relationship between bottom hole flowing pressure and time is plotted. The expression for the flow pressure description equation during the gas well trial production period is: In the formula, p wf For the bottom hole flowing pressure, p i α represents the initial formation pressure, t represents the production time (d); 试采 The parameters related to the linear intercept during the quasi-steady-state flow stage of the trial production period are in MPa. 2 ;β 试采 The slope of the straight line during the quasi-steady-state flow stage of the trial production period is expressed in MPa. 2 / d.

9. The method for optimizing gas well production in low-permeability carbonate gas fields based on multi-factor coupling as described in claim 8, characterized in that, The expression for the flow pressure description equation during the development period after the trial production period of the target gas well is as follows: In the formula, p R1 t is the average formation pressure within the well control radius at the end of the trial production period, in MPa; t is the production time, in days; q 试采 To ensure stable production during the trial mining period, 10 4 m 3 / d; the subscript sc represents the standard ground condition.

10. The method for optimizing gas well production in low-permeability carbonate gas fields based on multi-factor coupling as described in claim 1, characterized in that, In step a, the wellbore flow equation is: In the formula, p wh The wellhead oil pressure under a specified production ratio, in MPa; r g ρ is the relative density of the gas, dimensionless; H is the vertical depth of the middle part of the producing formation, m; L is the well depth of the middle part of the producing formation considering well inclination factors, m; The average temperature of the wellbore is K; ρ is the natural gas deviation coefficient under average wellbore pressure and average temperature conditions, dimensionless; f is the friction resistance coefficient, dimensionless; d is the tubing inner diameter, cm; p sc Standard atmospheric pressure, MPa.

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