A method for optimizing tubing size in shale gas wells while considering the effects of fluid accumulation.

Abstract

This invention relates to a method for optimizing tubing size in shale gas wells, taking into account the impact of fluid accumulation. It addresses the problems of severe fluid accumulation throughout the entire production cycle of shale gas wells, making tubing size selection difficult. The technical solution involves: using a wellbore pressure drop calculation method that considers the impact of fluid accumulation, predicting the daily wellbore pressure drop and fluid accumulation volume of tubing of different sizes throughout the gas well's production cycle; comprehensively considering the impact of wellbore pressure drop and fluid accumulation volume throughout the entire production cycle; calculating the comprehensive utility value of tubing of different sizes; and selecting the optimal tubing size by comparing the comprehensive utility values ​​of different sizes. This method for optimizing tubing size in shale gas wells, considering the impact of fluid production changes throughout the entire production cycle on tubing fluid accumulation, promotes efficient and stable production throughout the entire shale gas well production cycle.

Description

Technical Field

[0001] This invention relates to a method for optimizing the tubing size of shale gas wells, taking into account the effects of fluid accumulation, and belongs to the field of shale gas well development. Background Technology

[0002] Shale gas wells experience rapid changes in production and pressure throughout their entire production cycle. In the early stages, high fluid production can lead to fluid accumulation in the wellbore if tubing is installed too early, impacting production. Later, lower pressure and gas production similarly cause fluid accumulation in the tubing, increasing pressure drop. Given the complex impact of fluid accumulation on wellbore pressure drop throughout the entire shale gas well production cycle, optimizing tubing size, reducing pressure loss, and minimizing the effects of fluid accumulation are crucial for efficient and stable production throughout the entire shale gas well production cycle.

[0003] There are currently some studies on the optimal tubing string for shale gas wells. For example, patent application CN202310061510.9, entitled "An Optimization Method for Shale Gas Well Production Based on Optimized Tubing Strings," constructs a wellbore pressure drop model for shale gas wells. By calculating the variation of pressure drop with gas production for different tubing inner diameters, it optimizes the tubing inner diameter to ensure shale gas wells produce with minimal pressure drop loss at the point of minimum pressure drop. Currently, research on shale gas well tubing string optimization mainly considers the impact of wellbore pressure drop, but no optimization method considering the impact of fluid accumulation throughout the entire production cycle has been found. Summary of the Invention

[0004] The purpose of this invention is to solve the problems of severe liquid accumulation and difficulty in optimizing tubing size during the entire production cycle of shale gas wells, thereby helping shale gas wells to produce efficiently and stably and reducing pressure loss.

[0005] To achieve the above objectives, the present invention provides a method for optimizing the tubing size of shale gas wells considering the influence of fluid accumulation, the method comprising the following steps:

[0006] S100: Prepare formulas for the decline in gas production, water production, and bottom hole pressure of gas wells; prepare gas well depth data.

[0007] S200: Based on the gas production decline formula, water production decline formula, and bottom hole pressure decline formula, the predicted daily gas production, water production, and bottom hole pressure are obtained throughout the entire production cycle, where the entire production cycle is from the start of gas well production to the point where the gas production decreases to 1000 m³ / s. 3 The entire production phase;

[0008] S300: Based on the wellbore pressure drop calculation method considering the effect of fluid accumulation, calculate the daily wellbore pressure drop and fluid accumulation volume for different sizes of tubing throughout the entire gas well production cycle. The steps of the wellbore pressure drop calculation method considering the effect of fluid accumulation are as follows:

[0009] ① Enter the first t Daily gas production, water production, bottom hole pressure and the first t -1 day's fluid volume, of which the fluid volume on day 0 is 0;

[0010] ② Divide the well shaft into equal parts according to depth. n Each well section is assumed to be free of fluid accumulation.

[0011] ③ The theoretical pressure drop of each section of the wellbore is calculated based on the wellbore pressure drop equation that takes into account the effect of fluid accumulation. ; For the first i Wellbore pressure drop, MPa; g The acceleration due to gravity is m / s². 2 ; f i For the first i The friction coefficient of the wellbore section is dimensionless. v sg The apparent velocity of the gas is in m / s; The height of each section of the wellbore is in meters (m). q wci For the first i Liquid carrying capacity of section wellbore, m 3 ; q w For water production, m 3 ; V w The amount of fluid accumulated the previous day, m 3 ; ρ mi For the first i Mixture density of section wellbore, kg / m 3 ; D The pipe dimension is in meters (m).

[0012] ④ Calculate the first t Fluid carrying capacity of each section of the wellbore ;in A Let m be the cross-sectional area of ​​the oil pipe. 2 ; Time step, d;

[0013] ⑤ Calculate the first t Liquid holdup per section of the wellbore ;in H Li For the first i Liquid holdup in the wellbore section, dimensionless; X Lockhart-Martinelli coefficient, dimensionless; is... v ∞T The limit of the Taylor bubble rise velocity, in m / s;

[0014] ⑥ Recalculate the actual wellbore pressure drop for each section based on the wellbore pressure drop equation that takes into account the effect of fluid accumulation. Compare the theoretical wellbore pressure drop for each section with the actual wellbore pressure drop for each section. If the accuracy requirements are met, proceed to the next step. If the accuracy requirements are not met, repeat steps ③ to ⑥ until the accuracy requirements are met.

[0015] ⑦ Calculate the volume of accumulated fluid and output the result. t The wellbore pressure drop over the day; where the wellbore pressure drop is the sum of the actual pressure drops of each section of the wellbore;

[0016] S400: Based on the comprehensive utility value equation Calculate the overall utility value of tubing of each size; the tubing with the lowest overall utility value is the optimal tubing. E j For the first j The overall utility value of the oil pipeline is dimensionless; For the first j Average wellbore pressure drop over the entire production cycle of the tubing, in MPa; No. j Average fluid accumulation volume (m) throughout the entire production cycle of the oil pipe 3 .

[0017] Furthermore, the formula for calculating the mixture density of the i-th section of the wellbore in S300 is as follows: ,in ρ g The density of the gas is kg / m³. 3 ; ρ w The density of water is kg / m³. 3 .

[0018] Furthermore, the formula for calculating the liquid accumulation in S300 is as follows: . Attached Figure Description

[0019] In the attached diagram:

[0020] Figure 1 This is the technical roadmap for this method.

[0021] Figure 2 This is a prediction chart of gas production, water production, and bottom hole pressure for well N1.

[0022] Figure 3 This is a prediction chart of the liquid accumulation volume during the entire production cycle of oil tubing of different sizes in well N1.

[0023] Figure 4 This is a prediction chart of wellbore pressure drop during the entire production cycle of well N1 with different sizes of tubing. Detailed Implementation

[0024] The invention will now be further described with reference to the accompanying drawings.

[0025] To achieve the above objectives, the present invention provides a method for optimizing the tubing size of shale gas wells considering the influence of fluid accumulation, the method comprising the following steps:

[0026] To achieve the above objectives, the present invention provides a method for optimizing the tubing size of shale gas wells considering the influence of fluid accumulation, the method comprising the following steps:

[0027] S100: Prepare formulas for the decline in gas production, water production, and bottom hole pressure of gas wells; prepare gas well depth data.

[0028] S200: Based on the gas production decline formula, water production decline formula, and bottom hole pressure decline formula, the predicted daily gas production, water production, and bottom hole pressure are obtained throughout the entire production cycle, where the entire production cycle is from the start of gas well production to the point where the gas production decreases to 1000 m³ / s. 3 The entire production phase;

[0029] S300: Based on the wellbore pressure drop calculation method considering the effect of fluid accumulation, calculate the daily wellbore pressure drop and fluid accumulation volume for different sizes of tubing throughout the entire gas well production cycle. The steps of the wellbore pressure drop calculation method considering the effect of fluid accumulation are as follows:

[0030] ① Enter the first t Daily gas production, water production, bottom hole pressure and the first t -1 day's fluid volume, of which the fluid volume on day 0 is 0;

[0031] ② Divide the well shaft into equal parts according to depth. n Each well section is assumed to be free of fluid accumulation.

[0032] ③ The theoretical pressure drop of each section of the wellbore is calculated based on the wellbore pressure drop equation that takes into account the effect of fluid accumulation. ; For the first i Wellbore pressure drop, MPa; g The acceleration due to gravity is m / s². 2 ; f i For the first i The friction coefficient of the wellbore section is dimensionless. v sg The apparent velocity of the gas is in m / s; The height of each section of the wellbore is in meters (m). q wci For the first i Liquid carrying capacity of section wellbore, m 3 ; q w For water production, m 3 ; V wThe amount of fluid accumulated the previous day, m 3 ; ρ mi For the first i Mixture density of section wellbore, kg / m 3 ; D The pipe dimension is in meters (m).

[0033] ④ Calculate the first t Fluid carrying capacity of each section of the wellbore ;in A Let m be the cross-sectional area of ​​the oil pipe. 2 ; Time step, d;

[0034] ⑤ Calculate the first t Liquid holdup per section of the wellbore ;in H Li For the first i Liquid holdup in the wellbore section, dimensionless; X Lockhart-Martinelli coefficient, dimensionless; is... v ∞T The limit of the Taylor bubble rise velocity, in m / s;

[0035] ⑥ Recalculate the actual wellbore pressure drop for each section based on the wellbore pressure drop equation that takes into account the effect of fluid accumulation. Compare the theoretical wellbore pressure drop for each section with the actual wellbore pressure drop for each section. If the accuracy requirements are met, proceed to the next step. If the accuracy requirements are not met, repeat steps ③ to ⑥ until the accuracy requirements are met.

[0036] ⑦ Calculate the volume of accumulated fluid and output the result. t The wellbore pressure drop over the day; where the wellbore pressure drop is the sum of the actual pressure drops of each section of the wellbore;

[0037] S400: Based on the comprehensive utility value equation Calculate the overall utility value of tubing of each size; the tubing with the lowest overall utility value is the optimal tubing. E j For the first j The overall utility value of the oil pipeline is dimensionless; For the first j Average wellbore pressure drop over the entire production cycle of the tubing, in MPa; No. j Average fluid accumulation volume (m) throughout the entire production cycle of the oil pipe 3 .

[0038] Furthermore, the formula for calculating the mixture density of the i-th section of the wellbore in S300 is as follows: ,in ρ g The density of the gas is kg / m³. 3 ; ρw The density of water is kg / m³. 3 .

[0039] Furthermore, the formula for calculating the liquid accumulation in S300 is as follows: .

[0040] Taking well N1 as an example, well N1 is a shale gas well in a domestic atmospheric pressure shale gas field. The wellbore is 3150m long and began production on November 5, 2024. Using production data from adjacent wells on the same platform, the formulas for decreasing gas production, decreasing water production, and decreasing bottom hole pressure were obtained. The predicted daily gas production, water production, and bottom hole pressure for well N1 throughout its entire production cycle were calculated. The results are as follows: Figure 2 As shown in the figure. Three commonly used tubing sizes (inner diameters of 0.043m, 0.050m, and 0.062m) were selected for prediction. Gas production, water production, and bottom hole pressure were incorporated into a wellbore pressure drop calculation method that considers the effect of fluid accumulation. The daily fluid accumulation and wellbore pressure drop for different tubing sizes throughout the gas well's entire production cycle were calculated. The results are as follows. Figure 3 , Figure 4 As shown. Substituting the average tubing pressure and average fluid accumulation of each tubing size into the comprehensive utility value calculation equation, the comprehensive utility value of the tubing with a size of 0.043m is 0.30, the comprehensive utility value of the tubing with a size of 0.050m is 0.28, and the comprehensive utility value of the tubing with a size of 0.062m is 0.42. The tubing with a size of 0.050m is preferred.

[0041] Compared with the prior art, the present invention has the following beneficial effects: the method takes into account the impact of the change in production volume of shale gas wells throughout the entire production cycle on the accumulation of fluid in the tubing, and establishes an optimal method for tubing size of shale gas wells that takes into account the impact of fluid accumulation, so that on-site personnel can conveniently and quickly determine the optimal tubing size of shale gas wells.

[0042] Finally, it should be noted that the above embodiments are only used to illustrate and not limit the technical solutions of the present invention. Although the present invention has been described in detail with reference to the above embodiments, those skilled in the art should understand that modifications or equivalent substitutions can still be made to the present invention without departing from the spirit and scope of the present invention. Any modifications or partial substitutions should be covered within the scope of the claims of the present invention.

Claims

1. A method for optimizing the tubing size of shale gas wells considering the influence of fluid accumulation, characterized in that, The method includes the following steps: S100: Prepare formulas for the decline in gas production, water production, and bottom hole pressure of gas wells; prepare gas well depth data. S200: obtaining predicted daily gas production, water production and bottom hole pressure in the whole production cycle according to the gas well production decline relationship, water production decline relationship and bottom hole pressure decline relationship, wherein the whole production cycle is the whole production stage from the beginning of gas well production to the gas production reducing to 1000 m 3 ​ S300: Based on the wellbore pressure drop calculation method considering the effect of fluid accumulation, calculate the daily wellbore pressure drop and fluid accumulation volume for different sizes of tubing throughout the entire gas well production cycle. The steps of the wellbore pressure drop calculation method considering the effect of fluid accumulation are as follows: ① Enter the first t Daily gas production, water production, bottom hole pressure and the first t -1 day's fluid volume, of which the fluid volume on day 0 is 0; ② Divide the well shaft into equal parts according to depth. n Each well section is assumed to be free of fluid accumulation. ③ The theoretical pressure drop of each section of the wellbore is calculated based on the wellbore pressure drop equation that takes into account the effect of fluid accumulation. ; For the first i Wellbore pressure drop, MPa; g The acceleration due to gravity is m / s². 2 ; f i For the first i The friction coefficient of the wellbore section is dimensionless. v sg The apparent velocity of the gas is in m / s; The height of each section of the wellbore is in meters (m). q wci For the first i Liquid carrying capacity of section wellbore, m 3 ; q w For water production, m 3 ; V w The amount of fluid accumulated the previous day, m 3 ; ρ mi For the first i Mixture density of section wellbore, kg / m 3 ; D The pipe dimension is in meters (m). ④ Calculate the first t Fluid carrying capacity of each section of the wellbore ;in A Let m be the cross-sectional area of ​​the oil pipe. 2 ; Time step, d; ρ gi For the first i Gas density in the wellbore section, kg / m³ 3 ; ρ w The density of water is kg / m³. 3 ; ⑤ Calculate the first t Liquid holdup per section of the wellbore ;in For the first i The liquid holdup rate of the wellbore section; ⑥ Recalculate the actual wellbore pressure drop for each section based on the wellbore pressure drop equation that takes into account the effect of fluid accumulation. Compare the theoretical wellbore pressure drop for each section with the actual wellbore pressure drop for each section. If the accuracy requirements are met, proceed to the next step. If the accuracy requirements are not met, repeat steps ③ to ⑥ until the accuracy requirements are met. ⑦ Calculate the volume of accumulated fluid and output the result. t The pressure drop in the wellbore over a day; where the pressure drop in the wellbore is the sum of the actual pressure drops in each section of the wellbore; S4 00: According to the comprehensive utility value equation Calculate the overall utility value of tubing of each size; the tubing with the lowest overall utility value is the optimal tubing. E j For the first j The overall utility value of the oil pipeline is dimensionless; For the first j Average wellbore pressure drop over the entire production cycle of the tubing, in MPa; No. j Average fluid accumulation volume (m) throughout the entire production cycle of the oil pipe 3 .

2. The method for optimizing the tubing size of shale gas wells considering the influence of fluid accumulation according to claim 1, characterized in that: The formula for calculating the mixture density of the i-th section of the wellbore in S300 is as follows: ,in ρ g The density of the gas is kg / m³. 3 ; ρ w The density of water is kg / m³. 3 .

3. The method for optimizing the tubing size of shale gas wells considering the influence of fluid accumulation according to claim 1, characterized in that: The formula for calculating the amount of liquid accumulated in S300 is as follows: .

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