A shale gas horizontal well circulating gas lifting gas injection parameter design method

Abstract

The present application relates to the technical field of shale oil and gas exploration and development, and particularly relates to a shale gas horizontal well circulating gas lift injection parameter design method, which comprises determining an optimal injection amount of minimum wellbore energy loss, a minimum injection amount of critical liquid carrying, and a minimum injection amount of reservoir and well coupling, then selecting the maximum value among the optimal injection amount of minimum wellbore energy loss, the minimum injection amount of critical liquid carrying, and the minimum injection amount of reservoir and well coupling as the final circulating gas lift injection parameter under the known reservoir and gas well production characteristics. The technical scheme integrates system energy loss, gas well critical liquid carrying, and reservoir energy supply, optimizes the field circulating injection parameter according to the shale gas horizontal well production characteristics and in combination with the reservoir energy, and provides an effective technical means for ensuring continuous and stable production of the gas well.

Description

Technical Field

[0001] This invention relates to the field of shale oil and gas exploration and development technology, and in particular to a method for designing circulating gas lift injection parameters for shale gas horizontal wells. Background Technology

[0002] my country is rich in shale gas resources, and its proven reserves account for an increasingly large proportion of unconventional resources. The efficient development of shale gas is of great significance for improving my country's future energy structure. However, shale gas wells differ from conventional natural gas wells primarily in two aspects: First, shale gas wells experience rapid energy decay. While production is high in the early stages of shale gas extraction, the maintenance period is short, and energy decays rapidly. To ensure effective utilization of well production capacity, gas extraction technologies are needed in the later stages of production to improve well efficiency. Second, horizontal sections are prone to fluid accumulation. To improve the extraction efficiency of the target layer, shale gas reservoirs employ horizontal well production, combined with volumetric fracturing for artificial stimulation. Large amounts of flowback fluid need to be discharged from the formation. As formation pressure decreases, the gas's own energy reduces, resulting in insufficient fluid-carrying capacity, leading to fluid accumulation or even water flooding of the well.

[0003] To address the aforementioned gas well issues, compressed natural gas (CNG) lift or truck-mounted nitrogen lift is commonly used to restore production in water-flooded wells. CNG lift utilizes a truck-mounted gas compressor to pressurize natural gas separated by the well site separator, then injects it into the tubing or casing of the water-flooded well. This continuously lifts the accumulated liquid from the wellbore and near-wellbore area, ultimately restoring normal production to the water-flooded gas well. Truck-mounted nitrogen lift uses a truck-mounted nitrogen generator to separate and pressurize nitrogen from the air, ensuring nitrogen purity before injecting it into the wellbore to lift out the accumulated liquid, thus restoring production.

[0004] The above-mentioned technological measures can effectively restore production in some wells with accumulated liquid, but the restoration efficiency is limited. The main problems are as follows:

[0005] 1) On-site gas injection parameters are mainly obtained based on experience, which leads to uncertainty in the gas injection volume. Excessive gas volume results in resource waste, while insufficient gas volume leads to low production recovery efficiency.

[0006] 2) Conventional gas lift only considers the removal of liquid accumulation in the wellbore, without taking into account the liquid accumulation in the reservoir or near-wellbore formation. This makes it difficult to maintain subsequent production of the gas well after the gas lift stops, resulting in problems such as repeated gas lifts and low economic benefits. Summary of the Invention

[0007] This invention addresses the objective challenges of the aforementioned gas lift processes or measures, providing a method for designing circulating gas lift injection parameters for shale gas horizontal wells to ensure efficient well recovery and long-term effectiveness. This method integrates system energy loss, critical fluid carrying capacity of the gas well, and reservoir energy supply. Based on the production characteristics of shale gas horizontal wells and combined with reservoir energy, it optimizes on-site circulating gas injection parameters, providing an effective technical means to ensure continuous and stable gas well production.

[0008] This invention is achieved by adopting the following technical solution:

[0009] A method for designing circulating gas lift injection parameters in a shale gas horizontal well includes:

[0010] Determine the optimal gas injection rate that minimizes wellbore energy loss: Based on the relationship between different gas injection rates and bottom-hole flowing pressure of the gas well, establish the corresponding bottom-hole flowing pressure function relationship. Under known gas well production characteristics, obtain the bottom-hole flowing pressure value at different gas injection rates based on the bottom-hole flowing pressure function relationship. Select the gas injection rate at which the bottom-hole flowing pressure is the minimum as the optimal gas injection rate that minimizes wellbore energy loss.

[0011] Determine the minimum gas injection rate for critical fluid carrying: Determine the inclination angle of shale gas horizontal wells most prone to fluid accumulation through wellbore flow simulation experiments, and obtain the minimum gas injection rate required for critical fluid carrying based on the determined inclination angle.

[0012] Determine the minimum gas injection rate for reservoir-well coupling: Under the known reservoir and gas well production characteristics, obtain the minimum gas injection rate to achieve continuous and stable gas well production, i.e., the minimum gas injection rate for reservoir-well coupling.

[0013] Determine the circulating gas lift injection parameters: Under the known reservoir and gas well production characteristics, select the maximum value among the three factors: the optimal gas injection rate with the minimum wellbore energy loss, the minimum gas injection rate with critical fluid carrying capacity, and the minimum gas injection rate coupled with the reservoir as the final circulating gas lift injection parameters.

[0014] Preferably, the gas well production characteristics are determined by characteristic parameters, including liquid-to-gas ratio, oil pressure, casing pressure, and daily gas production.

[0015] Preferably, the bottom-hole flowing pressure function relationship of the gas well is as follows: Where p is the average pressure in the wellbore, in MPa; z is the axial flow distance, in meters; and g is the acceleration due to gravity, in m / s². 2 θ is the angle between the wellbore and the horizontal, i.e., the well inclination angle; f m ρ is the friction coefficient of the gas-liquid two-phase mixture; m Density of a gas-liquid two-phase mixture, in kg / m³ 3 ;v m The velocity of a gas-liquid two-phase mixture is expressed in m / s; v sg , where is the apparent velocity of the gas phase change, in m / s; D is the outer diameter of the oil pipe, in mm.

[0016] Preferably, obtaining the optimal gas injection rate that minimizes wellbore energy loss includes obtaining the corresponding calculation parameters in the bottom-hole flowing pressure function relationship of the gas well, i.e., based on the formula ρ m =H L ρ l+(1-H L )ρ g Obtain the density ρ of the gas-liquid two-phase mixture m , where H L ρ is the liquid holdup; l Liquid density, unit: kg / m³ 3 ;ρ g This refers to the gas phase density, in kg / m³. 3 Based on the formula for calculating the annular flow coefficient f m =f r f ns Obtain the friction coefficient f of the gas-liquid two-phase mixture m ; where f r The ratio of friction coefficients; f ns It is the coefficient of friction without slippage.

[0017] Preferably, in the process of obtaining the corresponding calculation parameters in the bottom-hole flowing pressure function relationship of the gas well, the non-slip friction coefficient f is obtained by establishing a friction coefficient calculation formula. ns The formula for calculating the friction coefficient is:

[0018]

[0019] Among them, Re ns It is a no-slip Reynolds number; This represents the relative roughness of the pipe wall.

[0020] Preferably, in the process of obtaining the corresponding calculation parameters in the bottom-hole flowing pressure function relationship of the gas well, the liquid holdup H is obtained by establishing a liquid holdup calculation formula for shale gas wells. L The formula for calculating the liquid holdup of shale gas wells is:

[0021]

[0022] v R =(-0.468×In(v) sg )+5.069)×(0.301×v sl +0.802)×(0.818×D+0.316);

[0023] Among them, v R The defined speed ratio; v sl The apparent flow rate of the liquid phase is expressed in m / s.

[0024] Preferably, the minimum gas injection volume required to obtain the critical liquid carrying capacity includes the following steps:

[0025] Under the condition that the inclination angle of the most prone to liquid accumulation well meets the requirement that liquid droplets on the wellbore wall do not flow back, the calculation formula based on the apparent gas phase velocity is used. Calculate the apparent gas velocity; where ρg This refers to the gas phase density, in kg / m³. 3 ;ρ l Liquid density, unit: kg / m³ 3 ;v sl The apparent fluid velocity is expressed in m / s. The critical fluid-carrying capacity of the gas well is obtained by multiplying the apparent fluid velocity by the cross-sectional area of ​​the wellbore. The minimum gas injection rate required to meet the critical fluid-carrying capacity is obtained by subtracting the gas production rate of the gas well from the critical fluid-carrying capacity.

[0026] Preferably, determining the minimum gas injection volume for well coupling includes the following steps:

[0027] Given the production characteristics of a gas well, the corresponding bottom-hole flowing pressure curves are plotted based on the bottom-hole flowing pressure function relationship of the gas well according to different gas injection rates.

[0028] Obtaining the dynamic inflow curve of shale gas horizontal wells involves, under the condition of known current average reservoir pressure and gas production index, determining the gas production function based on different bottomhole flowing pressures. Plot the corresponding gas well production curve; where q is the gas production rate, in units of 10. 4 m 3 / d; J is the gas production index, in units of 10. 4 m 3 / d / MPa; p represents the average formation pressure, in MPa. wf Bottom hole flowing pressure, in MPa;

[0029] By placing the bottom-hole flowing pressure curve and the gas well production curve together, the point of tangency between the two curves is the minimum gas injection rate that satisfies the reservoir's production capacity and allows the gas well to maintain continuous and stable production, i.e., the minimum gas injection rate for reservoir-well coupling.

[0030] Preferably, the inclination angle of the shale gas horizontal well most prone to fluid accumulation is 52° to 63°.

[0031] The beneficial technical effects of this invention are as follows:

[0032] 1) Compared with existing technologies, this technical solution obtains the optimal gas injection rate with the minimum wellbore energy loss, the minimum gas injection rate with critical liquid carrying capacity, and the minimum gas injection rate coupled with the well reservoir. The maximum value among these three is selected as the final circulating gas lift injection parameter, forming a complete circulating gas lift injection parameter design system. The logic is simple and clear. Through the quantitative means of gas injection parameters, it provides a reliable basis and standard for setting gas injection parameters in the field, solving the problem of relying on experience to set the gas injection rate. It makes an important contribution to saving resources and improving the efficiency of gas injection production recovery.

[0033] 2) In determining the minimum gas injection volume for well coupling, this technical solution takes into account the reservoir or near-well formation fluid accumulation, ensuring that the gas well maintains continuous and stable production and solving problems such as repeated gas lift and low economic benefits.

[0034] 3) This technical solution is not only applicable to shale gas horizontal wells, but can also be extended to tight gas horizontal wells, thus improving the gas lift construction and gas injection design system for gas-water co-production horizontal wells. Attached Figure Description

[0035] Figure 1 This is a basic implementation flowchart of the technical solution. Detailed Implementation

[0036] To make the purpose, technical solution and advantages of the invention clearer, the technical solution of the invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are some embodiments of the invention, but not all embodiments.

[0037] Therefore, the following detailed description of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0038] Example 1

[0039] This embodiment discloses a method for designing circulating gas lift injection parameters in a shale gas horizontal well, as a preferred embodiment of the present invention, such as... Figure 1 As shown, it includes:

[0040] Determine the optimal gas injection rate qi1 with the minimum wellbore energy loss: Based on the relationship between different gas injection rates and bottom flow pressure of the gas well, establish the corresponding bottom flow pressure function relationship of the gas well. Under the known production characteristics of the gas well, obtain the bottom flow pressure value at different gas injection rates based on the bottom flow pressure function relationship of the gas well. Select the gas injection rate with the minimum bottom flow pressure as the optimal gas injection rate with the minimum wellbore energy loss.

[0041] Determine the minimum gas injection rate qi2 for critical fluid carrying: Determine the inclination angle of shale gas horizontal wells most prone to fluid accumulation through wellbore simulation flow experiments, and obtain the minimum gas injection rate required for critical fluid carrying based on the determined inclination angle.

[0042] Determine the minimum gas injection rate qi3 for reservoir-well coupling: Under the known reservoir and gas well production characteristics, obtain the minimum gas injection rate to achieve continuous and stable gas well production, i.e., the minimum gas injection rate for reservoir-well coupling.

[0043] Determine the circulating gas lift injection parameters: Under the known reservoir and gas well production characteristics, select the maximum value among the following three: the optimal gas injection rate qi1 with the minimum wellbore energy loss, the minimum gas injection rate qi2 with critical liquid carrying capacity, and the minimum gas injection rate qi3 coupled with the reservoir, as the final circulating gas lift injection parameters.

[0044] Among them, the production characteristics of a gas well are determined by characteristic parameters, including the liquid-to-gas ratio, oil pressure, casing pressure, and daily gas production. Known gas well production characteristics refer to conditions where the relevant characteristic parameters such as the liquid-to-gas ratio, oil pressure, casing pressure, and daily gas production are constant.

[0045] Example 2

[0046] This embodiment discloses a method for designing circulating gas lift injection parameters in a shale gas horizontal well. As a preferred embodiment of the present invention, it includes:

[0047] Determining the optimal gas injection rate that minimizes wellbore energy loss: Based on the relationship between different gas injection rates and bottom hole flowing pressure, establish the corresponding bottom hole flowing pressure function formula. Under known gas well production characteristics, the bottom-hole flowing pressure values ​​for different injection rates are obtained based on the bottom-hole flowing pressure function relationship. The injection rate at which the bottom-hole flowing pressure is minimized is the optimal injection rate that minimizes wellbore energy loss. Here, p is the average pressure in the wellbore (MPa); z is the axial flow distance (m); and g is the acceleration due to gravity (m / s²). 2 θ is the angle between the wellbore and the horizontal, i.e., the well inclination angle; f m ρ is the friction coefficient of the gas-liquid two-phase mixture; m Density of a gas-liquid two-phase mixture, in kg / m³ 3 ;v m The velocity of a gas-liquid two-phase mixture is expressed in m / s; v sg , where is the apparent velocity of the gas phase change, in m / s; D is the outer diameter of the oil pipe, in mm.

[0048] Determine the minimum gas injection rate for critical fluid carrying: Determine the inclination angle at which shale gas horizontal wells are most prone to fluid accumulation through wellbore flow simulation experiments, and obtain the minimum gas injection rate required for critical fluid carrying based on the determined inclination angle.

[0049] Determine the minimum gas injection rate for reservoir-well coupling: Under known reservoir and gas well production characteristics, obtain the minimum gas injection rate to achieve continuous and stable gas well production, i.e., the minimum gas injection rate for reservoir-well coupling.

[0050] Determine the circulating gas lift injection parameters: Under the known reservoir and gas well production characteristics, select the maximum value among the three factors: the optimal gas injection rate with the minimum wellbore energy loss, the minimum gas injection rate with critical fluid carrying capacity, and the minimum gas injection rate coupled with the reservoir as the final circulating gas lift injection parameters.

[0051] Example 3

[0052] This embodiment discloses a method for designing circulating gas lift injection parameters in a shale gas horizontal well. As a preferred embodiment of the present invention, it includes:

[0053] Determining the optimal gas injection rate that minimizes wellbore energy loss: Based on the relationship between different gas injection rates and bottom hole flowing pressure, establish the corresponding bottom hole flowing pressure function formula. Under known gas well production characteristics, the bottom-hole flowing pressure values ​​for different injection rates are obtained based on the bottom-hole flowing pressure function relationship. The injection rate at which the bottom-hole flowing pressure is minimized is the optimal injection rate that minimizes wellbore energy loss. Here, p is the average pressure in the wellbore (MPa); z is the axial flow distance (m); and g is the acceleration due to gravity (m / s²). 2 θ is the angle between the wellbore and the horizontal, i.e., the well inclination angle; f m ρ is the friction coefficient of the gas-liquid two-phase mixture; m Density of a gas-liquid two-phase mixture, in kg / m³ 3 ;v m The velocity of a gas-liquid two-phase mixture is expressed in m / s; v sg , where is the apparent velocity of the gas phase change, in m / s; D is the outer diameter of the oil pipe, in mm.

[0054] Furthermore, obtaining the optimal gas injection rate that minimizes wellbore energy loss includes obtaining the corresponding calculation parameters in the bottom-hole flowing pressure function formula of the gas well, namely:

[0055] Based on formula ρ m =H L ρ l +(1-H L )ρ g Obtain the density ρ of the gas-liquid two-phase mixture m , where H L ρ is the liquid holdup; l Liquid density, unit: kg / m³ 3 ;ρ g This refers to the gas phase density, in kg / m³. 3 ;

[0056] Based on the calculation formula f of the circulation coefficient m =f r f ns Obtain the friction coefficient f of the gas-liquid two-phase mixture m ; where f r The ratio of friction coefficients; f ns It is the coefficient of friction without slippage.

[0057] Determine the minimum gas injection rate for critical fluid carrying: Determine the inclination angle of shale gas horizontal wells most prone to fluid accumulation through wellbore flow simulation experiments, and obtain the minimum gas injection rate required for critical fluid carrying based on the determined inclination angle.

[0058] Determine the minimum gas injection rate for reservoir-well coupling: Under the known reservoir and gas well production characteristics, obtain the minimum gas injection rate to achieve continuous and stable gas well production, i.e., the minimum gas injection rate for reservoir-well coupling.

[0059] Determine the circulating gas lift injection parameters: Under the known reservoir and gas well production characteristics, select the maximum value among the three factors: the optimal gas injection rate with the minimum wellbore energy loss, the minimum gas injection rate with critical fluid carrying capacity, and the minimum gas injection rate coupled with the reservoir as the final circulating gas lift injection parameters.

[0060] Example 4

[0061] This embodiment discloses a method for designing circulating gas lift injection parameters in a shale gas horizontal well. As a preferred embodiment of the present invention, it includes:

[0062] Determining the optimal gas injection rate that minimizes wellbore energy loss: Based on the relationship between different gas injection rates and bottom hole flowing pressure, establish the corresponding bottom hole flowing pressure function formula. Under known gas well production characteristics, the bottom-hole flowing pressure values ​​for different injection rates are obtained based on the bottom-hole flowing pressure function relationship. The injection rate at which the bottom-hole flowing pressure is minimized is the optimal injection rate that minimizes wellbore energy loss. Here, p is the average pressure in the wellbore (MPa); z is the axial flow distance (m); and g is the acceleration due to gravity (m / s²). 2 θ is the angle between the wellbore and the horizontal, i.e., the well inclination angle; f m ρ is the friction coefficient of the gas-liquid two-phase mixture; m Density of a gas-liquid two-phase mixture, in kg / m³ 3 ;v m The velocity of a gas-liquid two-phase mixture is expressed in m / s; v sg , where is the apparent velocity of the gas phase change, in m / s; D is the outer diameter of the oil pipe, in mm.

[0063] Furthermore, obtaining the optimal gas injection rate that minimizes wellbore energy loss includes obtaining the corresponding calculation parameters in the bottom-hole flowing pressure function formula of the gas well, namely:

[0064] Based on formula ρ m =H L ρ l +(1-H L )ρ g Obtain the density ρ of the gas-liquid two-phase mixture m , where H L ρ is the liquid holdup; l Liquid density, unit: kg / m³3 ;ρ g This refers to the gas phase density, in kg / m³. 3 Among them, the liquid holdup rate H is obtained by establishing a formula for calculating the liquid holdup rate of shale gas wells. L The formula for calculating the liquid holdup of shale gas wells is:

[0065]

[0066] v R =(-0.468×In(v) sg )+5.069)×(0.301×v sl +0.802)×(0.818×D+0.316);

[0067] Among them, v R The defined speed ratio; v sl The apparent flow rate of the liquid phase is expressed in m / s.

[0068] Based on the calculation formula f of the circulation coefficient m =f r f ns Obtain the friction coefficient f of the gas-liquid two-phase mixture m ; where f r The friction coefficient ratio (f varies depending on the liquid holdup) r The values ​​vary, ranging from 1.0 to 1.3; f ns Let f be the coefficient of friction without slippage. The coefficient of friction without slippage, f, is obtained by establishing a formula for calculating the coefficient of friction. ns The formula for calculating the friction coefficient is:

[0069]

[0070] Among them, Re ns It is a no-slip Reynolds number; This represents the relative roughness of the pipe wall.

[0071] Determine the minimum gas injection rate for critical fluid carrying: Determine the inclination angle of shale gas horizontal wells most prone to fluid accumulation through wellbore flow simulation experiments, and obtain the minimum gas injection rate required for critical fluid carrying based on the determined inclination angle.

[0072] Determine the minimum gas injection rate for reservoir-well coupling: Under the known reservoir and gas well production characteristics, obtain the minimum gas injection rate to achieve continuous and stable gas well production, i.e., the minimum gas injection rate for reservoir-well coupling.

[0073] Determine the circulating gas lift injection parameters: Under the known reservoir and gas well production characteristics, select the maximum value among the three factors: the optimal gas injection rate with the minimum wellbore energy loss, the minimum gas injection rate with critical fluid carrying capacity, and the minimum gas injection rate coupled with the reservoir as the final circulating gas lift injection parameters.

[0074] Example 5

[0075] This embodiment discloses a method for designing circulating gas lift injection parameters in a shale gas horizontal well. As a preferred embodiment of the present invention, it includes:

[0076] Determining the optimal gas injection rate that minimizes wellbore energy loss: Based on the relationship between different gas injection rates and bottom hole flowing pressure, establish the corresponding bottom hole flowing pressure function formula. Under known gas well production characteristics, the bottom-hole flowing pressure values ​​for different injection rates are obtained based on the bottom-hole flowing pressure function relationship. The injection rate at which the bottom-hole flowing pressure is minimized is the optimal injection rate that minimizes wellbore energy loss. Here, p is the average pressure in the wellbore (MPa); z is the axial flow distance (m); and g is the acceleration due to gravity (m / s²). 2 θ is the angle between the wellbore and the horizontal, i.e., the well inclination angle; f m ρ is the friction coefficient of the gas-liquid two-phase mixture; m Density of a gas-liquid two-phase mixture, in kg / m³ 3 ;v m The velocity of a gas-liquid two-phase mixture is expressed in m / s; v sg , where is the apparent velocity of the gas phase change, in m / s; D is the outer diameter of the oil pipe, in mm.

[0077] Furthermore, obtaining the optimal gas injection rate that minimizes wellbore energy loss includes obtaining the corresponding calculation parameters in the bottom-hole flowing pressure function formula of the gas well, namely:

[0078] Based on formula ρ m =H L ρ l +(1-H L )ρ g Obtain the density ρ of the gas-liquid two-phase mixture m , where H L ρ is the liquid holdup; l Liquid density, unit: kg / m³ 3 ;ρ g This refers to the gas phase density, in kg / m³. 3 Among them, the liquid holdup rate H is obtained by establishing a formula for calculating the liquid holdup rate of shale gas wells. L The formula for calculating the liquid holdup of shale gas wells is:

[0079]

[0080] v R =(-0.468×In(v) sg )+5.069)×(0.301×v sl +0.802)×(0.818×D+0.316);

[0081] Among them, v R The defined speed ratio; v sl The apparent flow rate of the liquid phase is expressed in m / s.

[0082] Based on the calculation formula f of the circulation coefficient m =f r f ns Obtain the friction coefficient f of the gas-liquid two-phase mixture m ; where f r The ratio of friction coefficients; f ns Let f be the coefficient of friction without slippage. The coefficient of friction without slippage, f, is obtained by establishing a formula for calculating the coefficient of friction. ns The formula for calculating the friction coefficient is:

[0083]

[0084] Among them, Re ns It is a no-slip Reynolds number; This represents the relative roughness of the pipe wall.

[0085] Determining the minimum gas injection rate for critical fluid carrying capacity: The inclination angle at which shale gas horizontal wells are most prone to fluid accumulation is determined through wellbore flow simulation experiments. Based on this determined inclination angle, the minimum gas injection rate required for critical fluid carrying capacity is obtained. Specifically, obtaining the minimum gas injection rate required for critical fluid carrying capacity includes the following steps:

[0086] Under the condition that the inclination angle of the most prone to liquid accumulation well meets the requirement that liquid droplets on the wellbore wall do not flow back, the calculation formula based on the apparent gas phase velocity is used. Calculate the apparent gas velocity; where ρ g This refers to the gas phase density, in kg / m³. 3 ;ρ l Liquid density, unit: kg / m³ 3 ;v sl The apparent fluid velocity is expressed in m / s.

[0087] The critical liquid-carrying gas capacity of a gas well is obtained by multiplying the apparent gas velocity by the cross-sectional area of ​​the wellbore.

[0088] The minimum injection volume required to meet the critical liquid carrying capacity is obtained by subtracting the gas production of the gas well (the gas production of the gas well is based on the average production data of the gas well over a recent period (usually 10 days)).

[0089] Determine the minimum gas injection rate for reservoir-well coupling: Under the known reservoir and gas well production characteristics, obtain the minimum gas injection rate to achieve continuous and stable gas well production, i.e., the minimum gas injection rate for reservoir-well coupling.

[0090] Determine the circulating gas lift injection parameters: Under the known reservoir and gas well production characteristics, select the maximum value among the three factors: the optimal gas injection rate with the minimum wellbore energy loss, the minimum gas injection rate with critical fluid carrying capacity, and the minimum gas injection rate coupled with the reservoir as the final circulating gas lift injection parameters.

[0091] Example 6

[0092] This embodiment discloses a method for designing circulating gas lift injection parameters in a shale gas horizontal well, as a preferred embodiment of the present invention, such as... Figure 1 As shown, it includes:

[0093] Determine the optimal gas injection rate that minimizes wellbore energy loss: Based on the relationship between different gas injection rates and bottom-hole flowing pressure of the gas well, establish the corresponding bottom-hole flowing pressure function relationship. Under known gas well production characteristics, obtain the bottom-hole flowing pressure value at different gas injection rates based on the bottom-hole flowing pressure function relationship. Select the gas injection rate at which the bottom-hole flowing pressure is the minimum as the optimal gas injection rate that minimizes wellbore energy loss.

[0094] Determine the minimum gas injection rate for critical fluid carrying: Determine the inclination angle at which shale gas horizontal wells are most prone to fluid accumulation through wellbore flow simulation experiments, and obtain the minimum gas injection rate required for critical fluid carrying based on the determined inclination angle.

[0095] Determining the minimum gas injection rate for reservoir-well coupling: Under known reservoir and gas well production characteristics, obtain the minimum gas injection rate required to achieve continuous and stable gas well production, i.e., the minimum gas injection rate for reservoir-well coupling. This includes the following steps:

[0096] Given the production characteristics of a gas well, the corresponding bottom-hole flowing pressure curves are plotted based on the bottom-hole flowing pressure function relationship of the gas well according to different gas injection rates.

[0097] Obtaining the dynamic inflow curve of shale gas horizontal wells involves, under the condition of known current average reservoir pressure and gas production index, determining the gas production function based on different bottomhole flowing pressures. Plot the corresponding gas well production curve; where q is the gas production rate, in units of 10. 4 m 3 / d; J is the gas production index, in units of 10. 4 m 3 / d / MPa; p represents the average formation pressure, in MPa. wf Bottom hole flowing pressure, in MPa;

[0098] By placing the bottom-hole flowing pressure curve and the gas well production curve together, the point of tangency between the two curves is the minimum gas injection rate that satisfies the reservoir's production capacity and allows the gas well to maintain continuous and stable production, i.e., the minimum gas injection rate for reservoir-well coupling.

[0099] Determine the circulating gas lift injection parameters: Under the known reservoir and gas well production characteristics, select the maximum value among the three factors: the optimal gas injection rate with the minimum wellbore energy loss, the minimum gas injection rate with critical fluid carrying capacity, and the minimum gas injection rate coupled with the reservoir as the final circulating gas lift injection parameters.

[0100] Example 7

[0101] This embodiment discloses a method for designing circulating gas lift injection parameters in a shale gas horizontal well. As a preferred embodiment of the present invention, it includes:

[0102] Determining the optimal gas injection rate that minimizes wellbore energy loss: Based on the relationship between different gas injection rates and bottom hole flowing pressure, establish the corresponding bottom hole flowing pressure function formula. Under known gas well production characteristics, the bottom-hole flowing pressure values ​​for different injection rates are obtained based on the bottom-hole flowing pressure function relationship. The injection rate at which the bottom-hole flowing pressure is minimized is the optimal injection rate that minimizes wellbore energy loss. Here, p is the average pressure in the wellbore (MPa); z is the axial flow distance (m); and g is the acceleration due to gravity (m / s²). 2 θ is the angle between the wellbore and the horizontal, i.e., the well inclination angle; f m ρ is the friction coefficient of the gas-liquid two-phase mixture; m Density of a gas-liquid two-phase mixture, in kg / m³ 3 ;v m The velocity of a gas-liquid two-phase mixture is expressed in m / s; v sg , where is the apparent velocity of the gas phase change, in m / s; D is the outer diameter of the oil pipe, in mm.

[0103] Furthermore, obtaining the optimal gas injection rate that minimizes wellbore energy loss includes obtaining the corresponding calculation parameters in the bottom-hole flowing pressure function formula of the gas well, namely:

[0104] Based on formula ρ m =H L ρ l +(1-H L )ρ g Obtain the density ρ of the gas-liquid two-phase mixture m , where H L ρ is the liquid holdup; l Liquid density, unit: kg / m³ 3 ;ρ g This refers to the gas phase density, in kg / m³. 3 Among them, the liquid holdup rate H is obtained by establishing a formula for calculating the liquid holdup rate of shale gas wells. L The formula for calculating the liquid holdup of shale gas wells is:

[0105]

[0106] v R=(-0.468×In(v) sg )+5.069)×(0.301×v sl +0.802)×(0.818×D+0.316);

[0107] Among them, v R The defined speed ratio; v sl The apparent flow rate of the liquid phase is expressed in m / s.

[0108] Based on the calculation formula f of the circulation coefficient m =f r f ns Obtain the friction coefficient f of the gas-liquid two-phase mixture m ; where f r The ratio of friction coefficients; f ns Let f be the coefficient of friction without slippage. The coefficient of friction without slippage, f, is obtained by establishing a formula for calculating the coefficient of friction. ns The formula for calculating the friction coefficient is:

[0109]

[0110] Among them, Re ns It is a no-slip Reynolds number; This represents the relative roughness of the pipe wall.

[0111] Determining the minimum gas injection rate for critical fluid carrying: First, determine the inclination angle of the shale gas horizontal well most prone to fluid accumulation. This parameter (the inclination angle of the shale gas horizontal well most prone to fluid accumulation) is mainly determined through wellbore flow simulation experiments. That is, by setting different well inclination angles, applying similarity criteria to design flow parameters, and experimentally observing to determine the inclination angle of the shale gas horizontal well most prone to fluid accumulation, the experimental results show that the distribution range of the inclination angle of the shale gas horizontal well most prone to fluid accumulation is 52° to 63°. Then, based on the determined well inclination angle, obtain the minimum gas injection rate required for critical fluid carrying. Obtaining the minimum gas injection rate required for critical fluid carrying specifically includes the following steps:

[0112] In the later stages of shale gas well production, the flow is mainly annular. Given the known production characteristics of gas wells, to avoid backflow of liquid droplets from the wellbore wall, it is only necessary to ensure that backflow of liquid droplets does not occur at the inclination angle of the well most prone to liquid accumulation. This can be calculated using the formula for the apparent gas velocity. Where, ρ g This refers to the gas phase density, in kg / m³. 3 ;ρ l Liquid density, unit: kg / m³ 3 ;v sl The apparent liquid velocity is expressed in m / s; the apparent gas velocity can be calculated using this formula.

[0113] The critical liquid-carrying gas capacity of a gas well is obtained by multiplying the apparent gas velocity by the cross-sectional area of ​​the wellbore.

[0114] The minimum injection volume required to meet the critical liquid carrying capacity is obtained by subtracting the gas production of the gas well from the critical liquid carrying capacity of the gas well.

[0115] Determining the minimum gas injection rate for reservoir-well coupling: Under known reservoir and gas well production characteristics, obtain the minimum gas injection rate required to achieve continuous and stable gas well production, i.e., the minimum gas injection rate for reservoir-well coupling. This includes the following steps:

[0116] Given the production characteristics of a gas well, the corresponding bottom-hole flowing pressure curves are plotted based on the bottom-hole flowing pressure function relationship of the gas well according to different gas injection rates.

[0117] Obtaining the dynamic inflow curve of shale gas horizontal wells involves, under the condition of known current average reservoir pressure and gas production index, determining the gas production function based on different bottomhole flowing pressures. Plot the corresponding gas well production curve; where q is the gas production rate, in units of 10. 4 m 3 / d; J is the gas production index, in units of 10. 4 m 3 / d / MPa; p represents the average formation pressure, in MPa. wf Bottom hole flowing pressure, in MPa;

[0118] By placing the bottom-hole flowing pressure curve and the gas well production curve together, the point of tangency between the two curves is the minimum gas injection rate that satisfies the reservoir's production capacity and allows the gas well to maintain continuous and stable production, i.e., the minimum gas injection rate for reservoir-well coupling.

[0119] Determine the circulating gas lift injection parameters: Under the known reservoir and gas well production characteristics, select the maximum value among the three factors: the optimal gas injection rate with the minimum wellbore energy loss, the minimum gas injection rate with critical fluid carrying capacity, and the minimum gas injection rate coupled with the reservoir as the final circulating gas lift injection parameters.

Claims

1. A method for designing circulating gas lift injection parameters in a shale gas horizontal well, characterized in that, include: Determine the optimal gas injection rate that minimizes wellbore energy loss: Based on the relationship between different gas injection rates and bottom-hole flowing pressure of the gas well, establish the corresponding bottom-hole flowing pressure function relationship. Under known gas well production characteristics, obtain the bottom-hole flowing pressure value at different gas injection rates based on the bottom-hole flowing pressure function relationship. Select the gas injection rate at which the bottom-hole flowing pressure is the minimum as the optimal gas injection rate that minimizes wellbore energy loss. The bottom-hole pressure function relationship of the gas well is as follows: ;in, for Average pressure in the wellbore, in MPa; The distance of axial flow, in meters; Acceleration due to gravity, unit: m / s² 2 ; The angle between the wellbore and the horizontal, i.e., the well inclination angle; The friction coefficient of a gas-liquid two-phase mixture; Density of a gas-liquid two-phase mixture, in kg / m³ 3 ; The velocity of the gas-liquid two-phase mixture is expressed in m / s. The apparent velocity of the gas phase change is expressed in m / s. for Oil pipe outer diameter, unit mm; Determining the minimum gas injection rate for critical fluid carrying: The inclination angle of the shale gas horizontal well most prone to fluid accumulation is determined through wellbore flow simulation experiments. Based on this determined inclination angle, the minimum gas injection rate required for critical fluid carrying is obtained. Obtaining the minimum gas injection rate for critical fluid carrying includes the following steps: Under the condition that the inclination angle of the most prone to fluid accumulation satisfies the condition that droplets on the wellbore wall do not experience backflow, the calculation is based on the apparent gas velocity formula... Calculate the apparent gas velocity; multiply the apparent gas velocity by the wellbore cross-sectional area to obtain the critical liquid-carrying capacity of the gas well; subtract the gas production rate from the critical liquid-carrying capacity to obtain the minimum injection rate required to meet the critical liquid-carrying capacity; where... This refers to the gas phase density, in kg / m³. 3 ; Liquid density, unit: kg / m³ 3 ; The apparent fluid velocity is expressed in m / s. Determine the minimum gas injection rate for reservoir-well coupling: Under known gas well production characteristics, plot the corresponding bottom-hole flowing pressure curves based on the bottom-hole flowing pressure function relationship for different gas injection rates; obtain the dynamic inflow curve of shale gas horizontal wells, that is, under the condition of known current average reservoir pressure and gas production index, plot the corresponding bottom-hole flowing pressure curves based on the gas production function relationship for different bottom-hole flowing pressures. Plot the corresponding gas well production curves; place the bottom hole flowing pressure curve and the gas well production curve together, and the point of tangency between the two curves is the minimum gas injection rate that satisfies the reservoir's production capacity and allows the gas well to maintain continuous and stable production, i.e., the minimum gas injection rate for reservoir-well coupling; where, Gas production, in units of 10 4 m 3 / d; This is the gas production index, in units of 10. 4 m 3 / d / MPa; The mean formation pressure is expressed in MPa. Bottom hole flowing pressure, in MPa; Determine the circulating gas lift injection parameters: Under the known reservoir and gas well production characteristics, select the maximum value among the three factors: the optimal gas injection rate with the minimum wellbore energy loss, the minimum gas injection rate with critical fluid carrying capacity, and the minimum gas injection rate coupled with the reservoir as the final circulating gas lift injection parameters.

2. The method for designing circulating gas lift injection parameters in a shale gas horizontal well as described in claim 1, characterized in that: The production characteristics of the gas well are determined by characteristic parameters, including liquid-to-gas ratio, oil pressure, casing pressure, and daily gas production.

3. The method for designing circulating gas lift injection parameters in a shale gas horizontal well as described in claim 1, characterized in that: The process of obtaining the optimal gas injection rate that minimizes wellbore energy loss includes obtaining the corresponding calculation parameters in the bottom-hole flowing pressure function formula of the gas well, namely: Based on formula Obtaining the density of a gas-liquid two-phase mixture ,in, Liquid holdup; Liquid density, unit: kg / m³ 3 ; This refers to the gas phase density, in kg / m³. 3 ; Based on the calculation formula of the circulation coefficient Obtain the friction coefficient of a gas-liquid two-phase mixture ;in, The ratio of friction coefficients; It is the coefficient of friction without slippage.

4. The method for designing circulating gas lift injection parameters in a shale gas horizontal well as described in claim 3, characterized in that: In the process of obtaining the corresponding calculation parameters in the bottom-hole flowing pressure function relationship of the gas well, the non-slip friction coefficient is obtained by establishing the friction coefficient calculation formula. The formula for calculating the friction coefficient is: ； in, It is a no-slip Reynolds number; This represents the relative roughness of the pipe wall.

5. The method for designing circulating gas lift injection parameters in a shale gas horizontal well as described in claim 3, characterized in that: In the process of obtaining the corresponding calculation parameters in the bottom-hole flowing pressure function relationship of the gas well, the liquid holdup rate is obtained by establishing the liquid holdup rate calculation formula for shale gas wells. The formula for calculating the liquid holdup of shale gas wells is: ； in, The speed ratio is defined; The apparent flow rate is in m / s.

6. The method for designing circulating gas lift injection parameters in a shale gas horizontal well as described in claim 1, characterized in that: The inclination angle of the shale gas horizontal well most prone to fluid accumulation is 52°~63°.

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