Shale gas well oil pipe size selection method

Abstract

The invention provides a shale gas well oil pipe size selection method, and belongs to the technical field of oil-gas field development. Fitting a productivity decline rule based on historical data, predicting a future yield sequence, combining with a multiphase flow pressure drop model, inversely calculating the bottom hole flow pressure required for realizing the yield, forming an initial shaft outflow curve, defining a future gas production index, obtaining the gas production index at each moment in the future, and deducing a formation pressure sequence changing along with time according to the gas production index; a stratum inflow dynamic curve family is constructed according to the sequence, on the basis, well shaft outflow curves of different oil pipe sizes are drawn, coordinated yield points of all pipe diameters at different moments in the future are obtained, the full-period yield decline trend corresponding to each pipe diameter is obtained, and the maximum cumulative gas production rate from the moment when a pipe column descends to the spraying stopping moment serves as a core index. And the optimal oil pipe size is determined through integral calculation. According to the method, dynamic optimization of the size of the oil pipe is achieved, and a reliable theoretical basis is provided for long-term stable yield and maximum development benefits of a shale gas well.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, and mainly relates to a method for selecting the size of oil tubing in shale gas wells. Background Technology

[0002] The heterogeneity and complex flow mechanisms of shale gas reservoirs, characterized by rapid early-stage decline and prolonged low-production in later stages, result in significant variations across the entire lifecycle production phase. However, current mainstream tubing size optimization methods are based on static nodal analysis, typically designing only for the critical fluid-carrying conditions or minimum wellbore pressure drop at a specific production moment. Essentially, this is a static decision based on instantaneous operating conditions. This method ignores the core characteristic of dynamic decline in shale gas well productivity and formation pressure over time, and severs the intrinsic link between size selection and the overall self-flowing lifecycle of the gas well. The selected size may fail to address later fluid accumulation issues and thus become ineffective prematurely. Therefore, this method cannot achieve the most economically efficient tubing diameter decision, easily leading to a shortened stable production period and a loss of ultimate recovery rate.

[0003] In shale gas well production, the appropriate tubing size can maximize long-term gas well productivity while ensuring stable fluid production, directly impacting the economic benefits of shale gas well development. Therefore, accurate tubing size selection is crucial for dynamic optimization of shale gas production. Invention patent (CN118008212A) proposes an optimization method for running production tubing in shale gas horizontal wells based on maximizing wellhead residual pressure, but it does not consider the core characteristic of dynamic capacity reduction and cannot achieve maximum well efficiency. Invention patent (CN119647024A) proposes a method for optimizing shale gas well tubing size considering the impact of fluid accumulation, introducing the cumulative effect of fluid accumulation into the wellbore pressure drop calculation process. However, it only uses a fixed, uniform calculation rule to adapt to all tubing sizes, without setting differentiated fluid holdup calculation models for different tubing sizes.

[0004] To this end, this invention obtains the gas well production decline law by calculation and fitting and predicts future gas production, back-calculates the bottom hole flow pressure, plots the future formation inflow dynamic curve, and further plots the production decline curves corresponding to different sizes of tubing. Finally, taking the maximization of cumulative gas production as the evaluation criterion, a method for selecting tubing size for shale gas wells is proposed. Summary of the Invention

[0005] This invention provides a method for selecting the tubing size of shale gas wells. By calculating, fitting, and extrapolating, the predicted gas production decline curve under different tubing size conditions is obtained, providing a theoretical basis for the optimal design of shale gas well tubing diameter.

[0006] To achieve the above objectives, the present invention provides a method for selecting the size of tubing in shale gas wells, comprising the following steps: Step 1: Collect wellbore structure data and production data of the target shale gas well, including vertical depth, sounding depth, well inclination angle, pipe diameter, gas production, fluid production, wellhead oil pressure, gas production index and formation mean pressure.

[0007] Step 2: Based on the historical production data, a generalized K-type production decline model is adopted, combined with the empirical formula for shale gas well production capacity, to obtain the reservoir dynamic decline characteristic coefficient. b .

[0008] The commonly used empirical formula for shale gas well productivity is selected: ; In the formula, Q g For gas well production, m 3 / d; J The gas production index, m 3 / (d×MPa) 2 ); p r The mean formation pressure is expressed in MPa. p wf The bottom hole pressure is MPa.

[0009] The generalized K-type declining output model is expressed as follows: ; In the formula, q i For the initial decreasing monthly gas production, 10 4 m 3 / moon; t Production time, in months; b The feature fitting coefficients are decreasing, month.

[0010] Step 3: Dynamic production capacity prediction. Based on the model described in Step 2, under the current casing production conditions, extrapolate the future discrete time points of the gas well. t 1. t 2. t 3… t m Predicted gas production sequence Q (1) , Q (2) , Q (3) … Q (m) .

[0011] Step 4: Back-calculate the wellbore outflow pressure for each predicted production point in Step 3. Q (i) Given the wellhead oil pressure, use a multiphase flow pressure drop model to solve for the bottom hole flow pressure required to achieve this production rate.P wf（i） To obtain the current sleeve size R Under condition 1, the curve showing the relationship between predicted production rate and bottom hole flowing pressure is used as the initial wellbore outflow curve. The corresponding calculation formula is as follows: The selected wellbore pressure drop model expression is: ; In the formula, p Pressure, Pa; z Let m be the depth. ρ m For mixed density, kg / m³ 3 ; g The acceleration due to gravity is m / s². 2 ; θ The inclination angle is °; f The coefficient of friction is dimensionless. V m The apparent velocity of the gas-liquid mixture is m / s; D The diameter is in meters (m).

[0012] The formula for the apparent velocity of a gas-liquid mixture is: ; In the formula, V SG The apparent airflow velocity is in m / s; V SL The apparent fluid velocity is given in m / s.

[0013] The mixing density is a function of liquid holdup, and its expression is: ; In the formula, H L The liquid holdup is expressed as %; ρ L The density of the liquid is kg / m³. 3 ; ρ G The density of the gas is kg / m³. 3 .

[0014] A new liquid holdup calculation model is introduced, that is, different calculation models are used according to different pipe diameters to ensure accurate liquid holdup calculation, thereby achieving the selection of the optimal tubing size.

[0015] For pipes with a diameter less than 50 mm, the liquid holdup rate H L The expression is: ; ; ; ; ; In the formula, f g The average gas content of the wellbore flow section is dimensionless. v sg The apparent velocity of the gas phase is m / s; v sL The apparent flow rate of the liquid phase is m / s; V m The apparent velocity of the gas-liquid mixture is m / s; ρ L Liquid phase density kg / m 3 ; g The acceleration due to gravity is m / s². 2 ; σ The gas-liquid interfacial tension, kg / s 2 ; N V This is a dimensionless velocity number; N d This refers to the dimensionless pipe diameter number; B The coefficients are the correlation fitting coefficients, which are dimensionless.

[0016] For pipe diameters greater than 50 mm, the liquid hold-up rate is calculated using the following formula: ; coefficient of friction f The calculation method used in the Mukherjee & Brill model is as follows: ; In the formula, e Let m be the absolute roughness. N Re It is the non-slip Reynolds number, which is dimensionless.

[0017] No slip Reynolds number N Re The calculation formula is: ; In the formula, ρ ns Density of non-slip mixture, kg / m³ 3 ; μ ns The viscosity of the non-slip mixture is expressed in Pa·s.

[0018] Step 5: Derivation of dynamic gas production index and definition of future gas production index ratio It is a gas production index that predicts future time points. Gas production index at the beginning of production The ratio, derived from the initial gas production index J 0~ J n and corresponding initial gas production Q 1~ Q n And utilize the future gas production index ratio With time relational formula Experimental fitting and derivation were performed to verify and calculate the coefficients of the polynomial. b 1. b 2. b 3. Further, based on this relationship, we can obtain any future prediction time. t 1. t 2. t 3… t m The gas production index is used to dynamically derive future timeframes. t i Corresponding gas production index J f ( t 1) ~ J f ( t m ).

[0019] Step Six: Derivation of the dynamic formation pressure sequence, using the gas production index from Step Five. J f ( t i (and combine steps three and four to correspond to future moments), t i Each data point ( Q (i) , P wf（i） Substituting this into the shale gas production capacity equation, we can dynamically invert the equation to obtain the future timeframes. t i Corresponding formation pressure P r（i） This forms a time-varying sequence of formation pressure. P r（1） , P r（2） , P r（3） … P r（m） .

[0020] Step 7: Constructing a family of dynamic inflow curves based on the aforementioned formation pressure sequence. P r（1） ~ P r（m） and gas production index Jf ( t 1) ~ J f ( t m ), drawing different moments in the future t i The inflow curves under formation pressure constitute a family of dynamic formation inflow curves that evolve over time.

[0021] Step 8: In the dynamic inflow curve family constructed in Step 7, with a fixed wellhead oil pressure, plot the curves for different tubing sizes. D 1. D 2… D N The wellbore outflow curves, where the intersection of the family of inflow curves with the outflow curves of each tubing represents the point at which the tubing is flowing at the corresponding time. t i and formation pressure P r（i） The gas production rate is then used to determine the coordinated production point for all pipe diameters at every future moment.

[0022] Step Nine: Determining the Theoretical Stop-Spray Point for Each Pipe Size. For each pipe size, as production time progresses, when the formation pressure drops to the point where the inflow curve and the corresponding pipe outflow curve are tangent or have only a single intersection, this is determined to be the theoretical stop-spray point for that pipe diameter. The corresponding time is recorded as follows: T D1 , T D2 … T DN .

[0023] Step 10: Plot the full-cycle production decline curve for each pipe diameter, extract all the coordinated production points mentioned above, and obtain the dimensions of each oil pipe. D 1. D 2… D N Production forecast series at the same time in the future Q （1）D1~DN , Q （2）D1~DN , Q （3）D1~DN … Q （m）D1~DN And plot the full-cycle production decline curves for each pipe diameter.

[0024] Step 11: Based on maximizing cumulative production over the entire cycle, optimize the pipe diameter and determine the timing of tubing insertion through node analysis. t Time 0, the time of tubing insertion t 0 to the theoretical stop spraying time for each pipe diameter T D1~DNFor the integration interval, calculate the size of each tubing section. D 1~N The theoretical cumulative gas production over the entire life cycle is compared with the cumulative production of each pipe diameter, and the pipe size with the largest cumulative gas production is determined as the final preferred size. Attached Figure Description

[0025] Figure 1 This is a technical roadmap for selecting tubing sizes in shale gas wells; Figure 2 This is a decline curve for shale gas well production forecasts; Figure 3 It is a curve showing the change of formation pressure over time; Figure 4 These are the outflow curves of oil pipes of different sizes; Figure 5 These are the production decline curves for oil pipes of different sizes. Detailed Implementation

[0026] To make the objectives, calculation process, and advantages of this invention clearer and easier to understand, the invention will be further described in detail below with reference to the accompanying drawings.

[0027] like Figure 1 As shown, Figure 1 This is a technical roadmap for the present invention. The present invention provides a method for selecting the size of tubing in shale gas wells. The main method involves plotting production decline curves for tubing of different sizes. The key point is to predict the future formation pressure decline trend, obtain the gas production value of each tubing at the same prediction time point, and then obtain the predicted production decline trend for each tubing diameter.

[0028] Based on the target shale gas well's wellbore structure data and production data, including well inclination angle, pipe diameter, gas production, fluid production, wellhead oil pressure, gas production index, and formation mean pressure.

[0029] In addition, it incorporates commonly used empirical formulas for engineering capacity: ; In the formula, Q g For gas well production, m 3 / d; J The gas production index, m 3 / (d×Mpa) 2 ), p r The mean formation pressure is expressed in MPa. p wf The bottom hole pressure is measured in MPa.

[0030] By combining the generalized K-type declining output model, the declining characteristic coefficients are obtained through fitting. b Then, a declining output curve is plotted, such as... Figure 2 As shown.

[0031] The generalized K-type declining output model is expressed as follows: ; In the formula, q i For the initial decreasing monthly gas production, 10 4 m 3 / moon; t Production time, in months; b The feature fitting coefficients are decreasing, month.

[0032] like Figure 2 As shown, node analysis clarifies the timing of tubing installation and the corresponding production time. t = t 0 This is the timing for lowering the tubing.

[0033] Furthermore, to predict the future production trend of the gas well, based on the decreasing law fitted in step two, and under the current casing production conditions, the future gas production of the gas well is extrapolated and predicted to obtain a series of future time points. t 1 、t 2 、t 3 、t 4 、t 5 、 t 6 …t m Corresponding predicted gas production sequence Q (1) , Q (2) , Q (3) , Q (4) , Q (5) , Q (6) … Q (m) .

[0034] Furthermore, the wellbore outflow pressure is back-calculated for each predicted production point obtained in step three. Q (i) Given the wellhead oil pressure, the bottom hole flow pressure required to achieve the predicted production rate is calculated using a multiphase flow pressure drop model. P wf（i） This gives us the current casing (diameter) R1) Under the condition of predicting the relationship between the gas production and the required bottom hole pressure, i.e. the initial wellbore outflow curve.

[0035] The selected wellbore pressure drop model expression is: ; In the formula, p Pressure, Pa; z Let m be the depth. ρ m For mixed density, kg / m³ 3 ; g The acceleration due to gravity is m / s². 2 ; θ The inclination angle is °; f The coefficient of friction is dimensionless. V m The apparent velocity of the gas-liquid mixture is m / s; D The diameter is in meters (m).

[0036] The formula for the apparent velocity of a gas-liquid mixture is: ; In the formula, V SG The apparent airflow velocity is in m / s; V SL The apparent fluid velocity is given in m / s.

[0037] The mixing density is a function of liquid holdup, and its expression is: ; In the formula, H L The liquid holdup is expressed as %; ρ L The density of the liquid is kg / m³. 3 ; ρ G The density of the gas is kg / m³. 3 .

[0038] A new liquid holdup calculation model is introduced, that is, different calculation models are used according to different pipe diameters to ensure accurate liquid holdup calculation, thereby achieving the selection of the optimal tubing size.

[0039] For pipes with a diameter less than 50 mm, the liquid holdup rate H L The expression is: ; ; ; ; ; In the formula, f g The average gas content of the wellbore flow section is dimensionless. v sg The apparent velocity of the gas phase is m / s; v sL The apparent flow rate of the liquid phase is m / s; V m The apparent velocity of the gas-liquid mixture is m / s; ρ L Liquid phase density kg / m 3 ; g The acceleration due to gravity is m / s². 2 ; σ The gas-liquid interfacial tension, kg / s 2 ; N V This is a dimensionless velocity number; N d This refers to the dimensionless pipe diameter number; B The coefficients are the correlation fitting coefficients, which are dimensionless.

[0040] For pipe diameters greater than 50 mm, the liquid hold-up rate is calculated using the following formula: ; coefficient of friction f The calculation method used in the Mukherjee & Brill model is as follows: ; In the formula, e Let m be the absolute roughness. N Re It is the non-slip Reynolds number, which is dimensionless.

[0041] No slip Reynolds number N Re The calculation formula is: ; In the formula, ρ ns Density of non-slip mixture, kg / m³ 3 ; μ ns The viscosity of the non-slip mixture is expressed in Pa·s.

[0042] Furthermore, a dynamic gas production index is derived, defining the future gas production index ratio. It is a gas production index that predicts future time points. Gas production index at the beginning of production The ratio, obtained from historical production data, is the initial gas production index. J O~ J n and corresponding gas production Q 1~ Q n And utilize the future gas production index ratio With time The relationship was experimentally fitted and derived, and the coefficients were verified and determined. b 1. b 2. b 3. Further, based on this relationship, we can obtain any future prediction time. t 1. t 2. t 3… t m The gas production index is used to dynamically derive future timeframes. t i Corresponding gas production index J f ( t 1) ~ J f ( t m ).

[0043] Furthermore, the derivation of future formation pressure sequences utilizes the productivity index from step five. J f ( t i (and combine steps three and four to correspond to future moments), t i Each data point ( Q (i) , P wf（i） Substituting this into the shale gas production capacity equation, we can dynamically invert the equation to obtain the future timeframes. t i Corresponding formation pressure P r（i） This forms a time-varying sequence of formation pressure. P r（1） , P r（2） , P r（3） … P r（m） .

[0044] Specific analysis as follows Figure 3 As shown, the obtained formation pressure sequence P r（i） Corresponding time t i Further analysis revealed the decreasing pattern of formation pressure over time, and based on this, the formation pressure at any future time was extrapolated.

[0045] Furthermore, the future formation inflow dynamic curve will be constructed based on the aforementioned formation pressure sequence. P r（1） ~ P r（m） and gas production index J f ( t 1) ~ J f ( t m ), drawing different moments in the future t i The inflow curves under formation pressure constitute a family of dynamic formation inflow curves that evolve over time.

[0046] Furthermore, a series of outflow dynamic curves of tubing of different sizes are plotted in the future formation pressure inflow dynamic curve obtained in step seven. After superimposing and analyzing the curves of the two systems, an intersection point is generated, which is the production of tubing of the corresponding size and the coordinated working point at the same time point.

[0047] Specific analysis as follows Figure 4 As shown, pipe diameters of [specific dimensions] are plotted in the inflow dynamic curve of the same formation. D 1. D 2… D N The dynamic curve of oil pipe outflow, pipe diameter R 1> D 1> D 2>… D N Corresponding pipe diameter D 1. Gas production at the intersection of the outflow curves is Q (1)D1 , Q (2)D1 , Q (3)D1 , Q (4)D1 , Q (5)D1 ... Q (m)D1 Similarly, the corresponding pipe diameter is obtained. D The gas production at the intersection of the effluent curves is 2. Q (1)D2 , Q (2)D2 , Q (3)D2 , Q (4)D2 , Q (5)D2 ... Q (m)D2， The gas production at each curve intersection point corresponds to a common time point sequence, that is, they correspond to the respective time points. t 1. t 2. t 3. t 4. t 5. ... t m Based on the above dimensions D 1. D 2… D N The gas production at each intersection point of the tubing outflow dynamic curve and the formation inflow dynamic curve is plotted, and the decreasing curve of production over time for each tubing size is shown, as follows. Figure 5 As shown, the reasonable extrapolation of the production decline curve is indicated by a dashed line.

[0048] Furthermore, based on node analysis, the timing for stopping the flow of each tubing is determined. When the dynamic curve of formation inflow in the shale gas well is tangent to the dynamic curve of outflow from tubing of different sizes, or when there is only a single intersection, the corresponding production time is the time for stopping the flow. Specific analysis is as follows... Figure 5 As shown, corresponding inner diameter R 1. Gas production volume corresponding to the point where spraying stops q 0, Stop spraying time T 0, size D For oil pipe 1, the point where injection stops corresponds to the amount of gas produced when injection stops. q D1 Stop spraying time T D1 ,size D 2 The oil pipe, the point where the injection stops corresponds to the amount of gas produced when the injection stops. q D2 Stop spraying time T D2 As illustrated in the diagram, T D2 > T D1 > T 0, q D2 < q D1 < q 0. The smaller the oil pipe size, the later the corresponding stop-spray time, which means a longer stable production time, but the production output is low during this period. In other words, it is a long-term production with low gas volume, and the gas production at the stop-spray point is low. Conversely, the larger the oil pipe size, the higher the gas production during the stable production stage, but the earlier the stop-spray time, and the shorter the high-gas-volume production stage.

[0049] Furthermore, with the goal of maximizing cumulative gas production, the optimal tubing size is selected.

[0050] like Figure 5As shown, the cumulative gas production from the moment the tubing is lowered to the moment it stops spraying is calculated on the gas production decline curves for tubing of different sizes. The specific analysis is as follows, corresponding to tubing sizes. D The decreasing relationship of gas production for 1 is as follows: Q D1 (t), calculate the timing of the tubing run-in. t 0 to the moment when the oil pipe stops spraying T D1 The cumulative gas production within the area is expressed by the following formula: Q D1 Integrating over time (t) yields the cumulative gas production. The integral formula for cumulative gas production is as follows: ; ; Similarly, corresponding to the tubing size D The decreasing relationship of gas production for 2 is as follows: Q D2 By integrating this relationship over time (t), the cumulative gas production can be obtained. Furthermore, different tubing sizes were selected. D 3~ D N The above calculations yield the cumulative gas production for each tubing size. ~ By comparing the cumulative gas production of each pipe diameter, the pipe size with the largest cumulative gas production is determined as the final preferred size.

Claims

1. A method for selecting the size of tubing in a shale gas well, characterized in that, The main steps include the following: Step 1: Collect wellbore structure data and production data of the target shale gas well, including vertical depth, sounding depth, well inclination angle, pipe diameter, gas production, fluid production, wellhead oil pressure, gas production index and formation mean pressure; Step 2: Based on the historical production data, a generalized K-type production decline model is adopted, combined with the empirical formula for shale gas well production capacity, to obtain the reservoir dynamic decline characteristic coefficient. b ; Step 3: Dynamic production capacity prediction. Based on the model described in Step 2, under the current casing production conditions, extrapolate the future discrete time points of the gas well. t 1. t 2. t 3… t m Predicted gas production sequence Q (1) , Q (2) , Q (3) … Q (m) ; Step 4: Back-calculate the wellbore outflow pressure for each predicted production point in Step 3. Q (i) Given the wellhead oil pressure, use a multiphase flow pressure drop model to solve for the bottom hole flow pressure required to achieve this production rate. P wf（i） To obtain the current sleeve size R Under condition 1, the curve showing the relationship between predicted production and bottom hole flowing pressure is used as the initial wellbore outflow curve; Among these, the liquid holdup model is selected differently. By introducing a new liquid holdup calculation model, different calculation models are used for different pipe diameters to ensure accurate liquid holdup calculation, thereby achieving the selection of the optimal tubing size: For pipes with a diameter less than 50 mm, the liquid holdup rate H L The expression is: ； ； ； ； ； In the formula, f g The average gas content of the wellbore flow section is dimensionless. v sg The apparent velocity of the gas phase is m / s; v sL The apparent flow rate of the liquid phase is m / s; V m The apparent velocity of the gas-liquid mixture is m / s; ρ L Liquid phase density kg / m 3 ; g The acceleration due to gravity is m / s². 2 ; σ The gas-liquid interfacial tension, kg / s 2 ; N V This is a dimensionless velocity number; N d This refers to the dimensionless pipe diameter number; B These are the correlation coefficients, which are dimensionless. For pipe diameters greater than 50 mm, the liquid hold-up rate is calculated using the following formula: ； In the formula, p Pressure, Pa; z Let m be the depth. ρ m For mixed density, kg / m³ 3 ; g The acceleration due to gravity is m / s². 2 ; θ The inclination angle is °; f The coefficient of friction is dimensionless. V m The apparent velocity of the gas-liquid mixture is m / s; D Pipe diameter, in meters (m); Step 5: Derivation of dynamic gas production index and definition of future gas production index ratio It is a gas production index that predicts future time points. Gas production index at the beginning of production The ratio of the initial gas production index J 0~ J n and corresponding initial gas production Q 1~ Q n And utilize the future gas production index ratio With time relational formula Experimental fitting and derivation were performed to verify and calculate the coefficients of the polynomial. b 1. b 2. b 3. Further, based on this relationship, we can obtain any future prediction time. t 1. t 2. t 3… t m The gas production index is used to dynamically derive future timeframes. t i Corresponding gas production index J f ( t 1) ~ J f ( t m ); Step Six: Derivation of the dynamic formation pressure sequence, using the gas production index from Step Five. J f ( t i (and combine steps three and four to correspond to future moments), t i Each data point ( Q (i) , P wf（i） Substituting this into the shale gas production capacity equation, we can dynamically invert the equation to obtain the future timeframes. t i Corresponding formation pressure P r（i） This forms a time-varying sequence of formation pressure. P r（1） , P r（2） , P r（3） … P r（m） ; Step 7: Constructing a family of dynamic inflow curves based on the aforementioned formation pressure sequence. P r（1） ~ P r（m） and gas production index J f ( t 1) ~ J f ( t m ), drawing different moments in the future t i The inflow curves under formation pressure constitute a family of dynamic formation inflow curves that evolve over time. Step 8: In the dynamic inflow curve family constructed in Step 7, with a fixed wellhead oil pressure, plot the curves for different tubing sizes. D 1. D 2… D N The wellbore outflow curves, where the intersection of the family of inflow curves with the outflow curves of each tubing represents the point at which the tubing is flowing at the corresponding time. t i and formation pressure P r（i） The gas production rate is then used to determine the coordinated production point for all pipe diameters at every future moment. Step Nine: Determining the Theoretical Stop-Spray Point for Each Pipe Size. For each pipe size, as production time progresses, when the formation pressure drops to the point where the inflow curve and the corresponding pipe outflow curve are tangent or have only a single intersection, this is determined to be the theoretical stop-spray point for that pipe diameter. The corresponding time is recorded as follows: T D1 , T D2 … T DN ; Step 10: Plot the full-cycle production decline curve for each pipe diameter, extract all the coordinated production points mentioned above, and obtain the dimensions of each oil pipe. D 1. D 2… D N Production forecast series at the same time in the future Q （1）D1~DN , Q （2）D1~DN , Q （3）D1~DN … Q （m）D1~DN And plot the full-cycle production decline curves for each pipe diameter; Step 11: Based on maximizing cumulative production over the entire cycle, optimize the pipe diameter and determine the timing of tubing insertion through node analysis. t Time 0, the time of tubing insertion t 0 to the theoretical stop spraying time for each pipe diameter T D1~DN For the integration interval, calculate the size of each tubing section. D 1~N The theoretical cumulative gas production over the entire life cycle is compared with the cumulative production of each pipe diameter, and the pipe size with the largest cumulative gas production is determined as the final preferred size.

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