Method for Determining Foam Drainage Agent Concentration in Gas Wellbore Based on Wellbore Multiphase Flow Calculation

Abstract

This invention provides a method for determining the concentration of foaming agents in gas wellbore based on multiphase flow calculations in the wellbore, belonging to the field of oil and gas field development technology. The method includes: collecting dynamic parameters of the gas well, and using commonly used empirical formulas for gas well productivity in engineering to calculate the formation inflow curve; based on the two-phase flow Mukherjee & Brill model, introducing a foaming agent concentration coefficient to obtain the frictional pressure drop and liquid holdup models, establishing a new wellbore pressure drop model for foaming wells, and calculating the wellbore outflow curve; combining nodal system analysis to determine the stable production points of the gas well under different foaming agent concentrations, obtaining the curve of the relationship between the foaming agent concentration coefficient and gas production, and determining the optimal foaming agent concentration for injection, providing theoretical support for on-site foam drainage gas production technology.

Description

TECHNICAL FIELD

[0001] The present invention belongs to the technical field of oil and gas field development, and specifically relates to a method for determining foam drainage agent concentration in a gas wellbore based on wellbore multiphase flow calculation.BACKGROUND

[0002] Gas wells in the late production stage are characterized by low gas production and low liquid production. As gas wells continue to produce, formation energy gradually decreases, the gas's liquid-carrying capacity weakens, and a large amount of liquid accumulates in the wellbore, which can easily cause water flooding and production shutdown. To effectively prevent and delay the liquid loading phenomenon in gas wells, foam drainage gas recovery technology has become the preferred solution for on-site liquid loading problems due to its advantages of low cost, quick results, and convenient operation. This process injects foam drainage agents into the tubing through the wellhead, mixes with gas and liquid in the wellbore to form stable foam, and utilizes the high liquid-carrying capacity of foam to reduce liquid slippage and lower flow resistance. However, in actual field applications, traditional methods for determining foam drainage agent concentration have serious drawbacks: most rely on experience from old wells for injection, lacking specificity.

[0003] In the gas well production process, accurately predicting the wellbore mixed fluid flow pressure drop is crucial for the dynamic optimization of foam drainage gas recovery well process parameters. The core issue is that existing wellbore pressure drop models are disconnected from actual field operating conditions. In multiphase flow systems, foam drainage agent concentration directly affects gas-liquid interfacial tension, thereby significantly changing friction resistance pressure drop and liquid holdup. However, traditional models are derived based on gas-water two-phase flow and do not couple the dynamic influence of foam drainage agent concentration, resulting in large deviations between calculated results and field measurements. Therefore, developing a model that can accurately reflect the influence of foam drainage agent concentration on wellbore pressure drop and precisely match well conditions to determine the optimal injection concentration is of great significance for optimizing foam drainage gas recovery processes.

[0004] The present invention provides a method for determining foam drainage agent concentration in a gas wellbore based on wellbore multiphase flow calculation. According to commonly used gas well productivity formulas in engineering, a formation inflow curve is drawn. Based on the two-phase flow Mukherjee & Brill model, a foam drainage agent concentration parameter is introduced to establish friction resistance pressure drop and liquid holdup models, forming a new calculation method for foam drainage gas recovery wellbore pressure drop, and then drawing a wellbore outflow curve. Combined with nodal system analysis, a relationship curve between foam drainage agent concentration coefficient and gas production rate is obtained, thereby determining the optimal foam drainage agent injection concentration and providing guidance for on-site foam drainage gas recovery processes.SUMMARY

[0005] The present invention aims to provide a method for determining foam drainage agent concentration in a gas wellbore based on wellbore multiphase flow calculation, providing key theoretical support for the optimal design of on-site foam drainage gas recovery processes.

[0006] Step 1: Collect gas wellbore structure data and production data from target well historical logging data and wellhead real-time monitoring equipment, including pipe inclination angle, tubing inner diameter, wellhead oil pressure, temperature, gas production rate, liquid production rate, liquid density, average formation pressure, foam drainage agent usage concentration, and foam drainage agent critical micelle concentration.

[0007] Step 2: Draw the formation inflow curve. Select the commonly used gas well productivity empirical formula in engineering:QSC=J⁡(pr2-pwf2)(1)

[0008] Where QSC is the gas production rate, m3 / d; J is the gas productivity index, m3 / (d·MPa); pr is the average formation pressure, MPa; pwf is the bottomhole flowing pressure, MPa.

[0009] Based on gas well production data, use the least squares method to fit and obtain the productivity index J. Combined with the gas production rate parameter range, calculate the bottomhole flowing pressure according to the gas well productivity empirical formula to obtain the formation inflow curve showing the relationship between bottomhole flowing pressure and gas production rate.

[0010] Step 3: Draw the wellbore outflow curve. Based on the wellbore structure data and production data obtained in Step 1, establish a foam drainage wellbore pressure drop model. Combined with the gas production rate parameter range, given the wellhead oil pressure, calculate the bottomhole flowing pressure according to the foam drainage wellbore pressure drop to obtain the wellbore outflow curve showing the relationship between bottomhole flowing pressure and gas production rate.

[0011] The model establishment process is as follows:

[0012] a. Based on continuous production data from a gas well over a period of time, including gas and liquid production data recorded by on-site production monitoring equipment, calculate the friction resistance pressure drop under foam drainage conditions-d⁢pd⁢z<semantics definitionURL="">❘<annotation encoding="Mathematica">"\[RightBracketingBar]"< / annotation>< / semantics>f=(c1⁢vSLc2-fm)⁢ρns(vm-vcf)22⁢D⁢(1+c3⁢αc4)(2)

[0013] where-d⁢pd⁢z<semantics definitionURL="">❘<annotation encoding="Mathematica">"\[RightBracketingBar]"< / annotation>< / semantics>fis the friction resistance pressure drop, in Pa / m; vSL is the liquid phase superficial velocity, in m / s; fm is the friction resistance coefficient, dimensionless; ρns is the no-slip mixture density, in kg / m3; vm is the gas-liquid mixed phase superficial velocity, in m / s; vcf is the gas-liquid two-phase liquid film reversal critical gas velocity, in m / s; D is the tubing inner diameter, in m; c1, c2, c3, c4 are polynomial coefficients obtained from experimental fitting; and a is the foam drainage agent concentration coefficient, dimensionless.Based on the foam drainage agent type and on-site implementation dosage, calculate the foam drainage agent concentration coefficient expression as:α=CvCMC(3)Where Cv is the foam drainage agent usage concentration, mg / L; CMC is the foam drainage agent critical micelle concentration, mg / L.

[0016] The no-slip mixture density is:ρns=(1-λLns)⁢ρG+λLns⁢ρL(4)

[0017] Where ρG is the gas density, kg / m3; ρL is the liquid density, kg / m3; and λLns is the no-slip liquid holdup, dimensionless.

[0018] The no-slip liquid holdup is:λLns=vSLvm(5)

[0019] The gas density under different pressure conditions is:ρG=pMZ⁢R⁢T(6)

[0020] Where ρG is the gas density, kg / m3; p is the pressure, MPa; M is the relative molecular mass of natural gas, g / mol; T is the temperature, K; R is the ideal gas constant (0.008314 atm·m3 / (kmol·K)); Z is the deviation factor, dimensionless.

[0021] Based on on-site gas production data, calculate the gas phase superficial velocity as:vSG=QSC⁢ρSCρG⁢A(7)

[0022] Based on on-site gas production data, calculate the liquid phase superficial velocity as:vS⁢L=QSLA(8)

[0023] The gas-liquid mixed phase superficial velocity is:vm=vSG+vSL(9)

[0024] Where vSG is the gas phase superficial velocity, m / s; vSL is the liquid phase superficial velocity, m / s; vm is the gas-liquid mixed phase superficial velocity, m / s; QSC is the gas production rate, m3 / d; QSL is the liquid production rate, m3 / d; ρSC is the gas density at standard conditions, kg / m3; A is the pipe cross-sectional area, m2.

[0025] The gas-liquid two-phase liquid film reversal critical gas velocity expression is:vcf={c5[gD⁡(ρL-ρG)ρG]0.25+c6(ρL⁢ρG⁢vSL2)0.25}2(10)

[0026] Where ρG is the gas density, kg / m3; ρL is the liquid density, kg / m3; vSL is the liquid phase superficial velocity, m / s; g is the gravitational acceleration, m / s2; D is the tubing inner diameter, m; c5 and c6 are polynomial coefficients obtained from experimental fitting.

[0027] The calculation of the friction resistance coefficient is based on the Mukherjee & Brill model friction relationship:fm={64RensRens≤2300[1.14-2⁢lg⁡(kD+21.25Rens0.9)]-2Rens>2300(11)

[0028] Where k / D is the relative wall roughness, dimensionless; Rens is the no-slip Reynolds number, dimensionless.

[0029] The no-slip Reynolds number is:Rens=vm⁢ρns⁢Dμns(12)

[0030] Where vm is the gas-liquid mixed phase superficial velocity, m / s; ρns is the no-slip mixture density, kg / m3; D is the tubing inner diameter, m; μns is the no-slip mixture viscosity, Pa·s.

[0031] The no-slip mixture viscosity is:μns=(1-λLns)⁢μG+λLns⁢μL(13)

[0032] Where μG is the gas phase viscosity, taken as 2×10−5 Pa·s; μL is the liquid phase viscosity, taken as 8×10−4 Pa·s.

[0033] b. Establish foam drainage liquid holdup Hfoam

[0034] Based on the two-phase flow Mukherjee & Brill model liquid holdup formula, establish a liquid holdup model that considers foam drainage agent concentration, with the expression:Hfoam=HL(b1+b2⁢FGα+1+b3(α+1)2)(14)

[0035] Where Hfoam is the foam drainage liquid holdup defined in the present invention, %; HL is the Mukherjee & Brill model two-phase liquid holdup, %; FG is the gas phase superficial velocity converted using the Froude number, m / s; b1, b2, b3 are coefficients obtained from experimental fitting.

[0036] The Mukherjee & Brill model two-phase liquid holdup is:HL=exp[f⁡(θ)*⁢g⁡(Nvg) / k(Nvl)](15)

[0037] Where:{f⁢(θ)=a1+a2⁢ sin⁢ θ+a3⁢ sin2⁢θ+a4⁢NL2g⁢{Nvg)=Nvga5k⁢{Nvl)=Nvla6Nvl=vSL(ρLg⁢σ)0.25Nvg=vSG(ρGg⁢σ)0.25NL=μL(gρL⁢σ3)0.25(16)

[0038] Where f(θ) is the function for fitting pipe inclination angle; Nvg is the gas phase velocity number, dimensionless; Nv is the liquid phase velocity number, dimensionless; NL is the liquid phase viscosity number, dimensionless; σ is the gas-liquid surface tension, N / m, taken as 0.06; a1, a2, a3, a4, a5, a6 are polynomial coefficients obtained from fitting.

[0039] The gas phase superficial velocity converted using the Froude number is:FG=ρG⁢vSG2gD⁡(ρL-ρG)(17)

[0040] c. Establish foam drainage wellbore pressure drop model

[0041] The wellbore pressure drop model under the influence of foam drainage agent concentration, with the expression:dpdz=-[(cl⁢vSLc2⁢fm)⁢ρns(vm-vef)22⁢D⁢(1+c3⁢αc4)+ρm⁢g⁢ sin⁢ θ](18)

[0042] Where θ is the pipe inclination angle, °; ρm is the mixture density, kg / m3.

[0043] The mixture density is a function of liquid holdup, with the expression:ρm=ρL⁢Hfoam+ρG(1-Hfoam)(19)

[0044] Where Hfoam is the foam drainage liquid holdup, %; ρL is the liquid density, kg / m3; ρG is the gas density, kg / m3.

[0045] Step 4: Based on the formation inflow curve and wellbore outflow curve obtained in Steps 2 and 3, and using nodal system analysis, draw the relationship curve between foam drainage agent concentration coefficient and gas production rate to determine the optimal foam drainage agent injection concentration. The specific process is:

[0046] Through on-site implementation of different foam drainage agent dosages, given different foam drainage agent concentrations, different foam drainage agent concentration coefficients are calculated to obtain wellbore outflow curves showing bottomhole flowing pressure versus gas production rate under different foam drainage agent concentrations. From the calculation results, it can be seen that the variation patterns of wellbore outflow curves under different foam drainage agent concentrations are consistent, with bottomhole flowing pressure first decreasing and then increasing as gas production rate increases. Based on nodal system analysis, when the formation inflow curve and wellbore outflow curve intersect, this is the stable production point of the gas well. According to the gas production rates corresponding to stable production points under different foam drainage agent concentration coefficients, a relationship curve between foam drainage agent concentration coefficient and gas production rate can be drawn. The foam drainage agent concentration corresponding to the stable production point with the highest gas production rate is the optimal foam drainage agent injection concentration for the gas well. A foam drainage agent injection amount based on the current liquid production rate can be calculate, and the foam drainage agent can be injected into the tubing using an on-site electric high-pressure injection pump to improve resource yields and operational efficiency.BRIEF DESCRIPTION OF DRAWINGS

[0047] FIG. 1: Technical flow chart of a method for determining foam drainage agent concentration in a gas wellbore based on wellbore multiphase flow calculation;

[0048] FIG. 2: Formation inflow / wellbore outflow curve diagram;

[0049] FIG. 3: Relationship curve diagram between foam drainage agent concentration coefficient and gas production rate.DETAILED DESCRIPTION

[0050] In order to make the purpose and calculation process of the present invention clearer, the following provides a further detailed description of the present invention in conjunction with the accompanying drawings to highlight the advantages of the present invention.

[0051] As shown in FIG. 1, FIG. 1 is the technical flow chart of the present invention. The present invention provides a method for determining foam drainage agent concentration in a gas wellbore based on wellbore multiphase flow calculation. First, real-time production data and wellbore structure data are collected through wellhead and downhole monitoring equipment, and the formation inflow curve is calculated according to the gas well productivity empirical formula. Then, the critical gas flow rate for gas-liquid two-phase liquid film reversal vcf is calculated, a foam drainage friction resistance pressure drop formula is established, and based on the two-phase flow Mukherjee & Brill model liquid holdup formula, a new liquid holdup model Hfoam is established. A gas well pressure drop formula considering the influence of foam drainage agent concentration is obtained for drawing the wellbore outflow curve. Based on nodal system analysis, when the formation inflow curve and wellbore outflow curve intersect, it is the stable production point of the gas well. Stable production points of the gas well under different foam drainage agent concentrations are obtained. According to the gas production rate corresponding to the stable production point, a relationship curve between the foam drainage agent concentration coefficient and gas production rate is drawn, and the foam drainage agent concentration corresponding to the stable production point with the highest gas production rate is the optimal foam drainage agent injection concentration for the gas well.

[0052] The core of the present invention lies in establishing a foam drainage wellbore pressure drop model.

[0053] (1) According to continuous production data of the gas well over a period of time, including gas and liquid production data recorded by on-site production monitoring equipment, calculate the friction resistance pressure drop under foam drainage conditions-dpdz❘f=(cl⁢vSLc2⁢fm)⁢ρns(νm-vcf)22⁢D⁢(1+c3⁢αc4)(1)

[0054] where-d⁢pdz❘fis the friction resistance pressure drop, in Pa / m; vSL is the liquid phase superficial velocity, in m / s; fm is the friction resistance coefficient, dimensionless; ρns is the no-slip mixture density, in kg / m3; vm is the gas-liquid mixed phase superficial velocity, in m / s; vcf is the gas-liquid two-phase liquid film reversal critical gas velocity, in m / s; D is the tubing inner diameter, in m; c1, c2, c3, c4 are polynomial coefficients obtained from experimental fitting; and a is the foam drainage agent concentration coefficient, dimensionless.Through the type of foam drainage agent and the on-site implementation dosage, the expression for calculating the foam drainage agent concentration coefficient is:α=CvCMC(2)Where Cv is the foam drainage agent usage concentration, mg / L; CMC is the foam drainage agent critical micelle concentration, mg / L.

[0057] The no-slip mixture density is:ρns=(1-λLns)⁢ρG+λLns⁢ρL(3)

[0058] Where ρG is the gas density, kg / m3; ρL is the liquid density, kg / m3; and λLns is the no-slip liquid holdup, dimensionless.

[0059] The no-slip liquid holdup is:λLns=vSLvm(4)

[0060] The gas density under different pressure conditions is:ρG=pMZRT(5)

[0061] Where ρG is the gas density, kg / m3; p is the pressure, MPa; M is the relative molecular mass of natural gas, g / mol; T is the temperature, K; R is the ideal gas constant (0.008314 atm·m3 / (kmol·K)); Z is the deviation factor, dimensionless.

[0062] Calculate the gas phase superficial velocity based on on-site gas production data:vSG=QSC⁢ρSCρG⁢A(6)

[0063] Calculate the liquid phase superficial velocity based on on-site gas production data:vSL=QSLA(7)

[0064] The gas-liquid mixed phase superficial velocity is:vm=vSG+vSL(8)

[0065] Where vSG is the gas phase superficial velocity, m / s; vSL is the liquid phase superficial velocity, m / s; vm is the gas-liquid mixed phase superficial velocity, m / s; QSC is the gas production rate, m3 / d; QSL is the liquid production rate, m3 / d; ρSC is the gas density at standard conditions, kg / m3; A is the pipe cross-sectional area, m2.

[0066] The expression for the critical gas flow rate for gas-liquid two-phase liquid film reversal is:vcf={c5[gD⁡(ρL-ρG)ρG]0.25+c6(ρL⁢ρG⁢vSL2)0.25}2(9)

[0067] Where ρG is the gas density, kg / m3; ρL is the liquid density, kg / m3; vSL is the liquid phase superficial velocity, m / s; g is the gravitational acceleration, m / s2; D is the tubing inner diameter, m; c5 and c6 are polynomial coefficients obtained from experimental fitting.

[0068] The calculation of the friction resistance coefficient is based on the Mukherjee & Brill model friction relationship:fm={64RensRens≤2300[1.14-2⁢ lg(kD+21.25Rens0.9)]-2Rens>2300(10)

[0069] Where, k / D is the relative roughness of the pipe wall, dimensionless; Rens is the no-slip Reynolds number, dimensionless.

[0070] The no-slip Reynolds number is:Rens=vm⁢ρns⁢Dμns(11)

[0071] Where vm is the gas-liquid mixed phase superficial velocity, m / s; ρns is the no-slip mixture density, kg / m3; D is the tubing inner diameter, m; μns is the no-slip mixture viscosity, Pa·s.

[0072] The no-slip mixture viscosity is:μns=(1-λLns)⁢μG+λLns⁢μL(12)

[0073] Where ρG is the gas phase viscosity, taken as 2×10−5 Pa·s; μL is the liquid phase viscosity, taken as 8×10−4 Pa·s.

[0074] (2) Based on the two-phase flow Mukherjee & Brill model liquid holdup formula, establish a liquid holdup model considering foam drainage agent concentration, with the expression:Hfoam=HL(b1+b2⁢FGα+1+b3(α+1)2)(13)

[0075] Where Hfoam is the foam drainage liquid holdup defined in the present invention, %; HL is the Mukherjee & Brill model two-phase liquid holdup, %; FG is the gas phase superficial velocity converted using the Froude number, m / s; b1, b2, b3 are coefficients obtained from experimental fitting.

[0076] The Mukherjee & Brill model two-phase liquid holdup is:HL=exp[f⁡(θ)*g⁡(Nrg) / k⁡(Nvi)](14)

[0077] Where:{f⁡(θ)=a1+a2⁢sin⁢θ+a3⁢sin2⁢θ+a4⁢NL2g⁡(Nvg)=Nvga5k⁡(Nvl)=Nvla5Nvl=vSL(ρLg⁢σ)0.25Nvg=vSG(ρGg⁢σ)0.25NL=μL(gρL⁢σ3)0.25(15)

[0078] Where f(θ) is the function for fitting pipe inclination angle; Nvg is the gas phase velocity number, dimensionless; Nv is the liquid phase velocity number, dimensionless; NL is the liquid phase viscosity number, dimensionless; σ is the gas-liquid surface tension, N / m, taken as 0.06; a1, a2, a3, a4, a5, a6 are polynomial coefficients obtained from fitting.

[0079] The gas phase superficial velocity converted using Froude number is:FG⁢ρG⁢vSG2gD⁡(ρL-ρG)(16)

[0080] Finally, the wellbore pressure drop model under the influence of foam drainage agent concentration is obtained, with the expression:dpdz=-[(c1⁢vSLc2⁢fm)⁢ρns(vm-vcf)22⁢D⁢(1+c3⁢αc4)+ρm⁢g⁢ sin⁢ θ](17)

[0081] Where, θ is the pipe inclination angle, °; ρm is the mixture density, kg / m3.

[0082] The mixture density is a function of liquid holdup, with the expression:ρm=ρL⁢Hfoam+ρG(1-Hfoam)(18)

[0083] Where Hfoam is the foam drainage liquid holdup, %; ρL is the liquid density, kg / m3; ρG is the gas density, kg / m3.

[0084] As shown in FIG. 2, the formation inflow / wellbore outflow curves are plotted. The commonly used empirical formula for gas well productivity in engineering is selected:QSC=J⁡(pr2-pwf2)(19)

[0085] Where, QSC is the gas production rate, m3 / d; J is the gas productivity index, m3 / (d·MPa); pr is the average formation pressure, MPa; pwf is the bottomhole flowing pressure, MPa.

[0086] Based on the measured data from gas well productivity testing, the least squares method is used to fit and obtain the productivity index J Combined with the gas production rate parameter range, the bottomhole flowing pressure is calculated according to the gas well productivity empirical formula, and the formation inflow curve showing the relationship between bottomhole flowing pressure and gas production rate is obtained.

[0087] Through different foam drainage agent dosages implemented on-site and different set foam drainage agent concentrations, different foam drainage agent concentration coefficients α1, α2, α3 are calculated. Through the wellhead oil pressure data obtained from the wellhead production tree pressure gauge, the foam drainage wellbore pressure drop model is used to calculate the wellbore outflow curve showing the relationship between bottomhole flowing pressure and gas production rate under different foam drainage agent concentrations. Based on nodal system analysis, the stable production point of the gas well is identified when the formation inflow and wellbore outflow curves intersect. Stable production points X1, X2, X3 of the gas well under different foam drainage agent concentration coefficients α1, α2, and α3 are then obtained.

[0088] As shown in FIG. 3, according to the gas production rates Q1, Q2, Q3 corresponding to the stable production points X1, X2, X3, the relationship curve between the foam drainage agent concentration coefficient and gas production rate can be drawn. The foam drainage agent concentration corresponding to the point Q1 with the highest gas production rate is the optimal foam drainage agent injection concentration for the gas well. The foam drainage agent injection amount is determined according to the current liquid production rate, and the foam drainage agent is injected into the tubing using an on-site electric high-pressure injection pump.

[0089] Compared with the shortcomings and deficiencies of the existing technology, the present invention has the following beneficial effects:

[0090] (1) Under foam drainage gas recovery process conditions, fully considering the influence of foam drainage agent concentration, a new gas well wellbore pressure drop formula under foam drainage conditions is implemented.

[0091] (2) Combined with nodal system analysis, based on the formation inflow / wellbore outflow curve, the relationship curve between foam drainage agent concentration coefficient and gas production rate may be drawn to determine the foam drainage agent injection concentration, providing guidance for on-site foam drainage gas recovery processes.

[0092] Obviously, the above description is only the research approach of the present invention and is not intended to limit the present invention. Any modifications, equivalent replacements, and improvements made within the spirit and principles of the present invention shall be included within the protection scope of the present invention.

Claims

1. A method for determining foam drainage agent concentration in a gas wellbore based on wellbore multiphase flow calculation, characterized in that it comprises the following steps:Step 1: Collect gas well wellbore structure data and production data including tubing inclination angle, tubing inner diameter, wellhead oil pressure, temperature, gas production rate, liquid production rate, liquid density, average formation pressure, foam drainage agent usage concentration, and foam drainage agent critical micelle concentration;Step 2: Plot the formation inflow curve, using the commonly used gas well productivity empirical formula in engineering:QSC=J⁡(pr2-pwf2)where QSC is the gas production rate, m3 / d; J is the gas productivity index, m3 / (d·MPa); pr is the average formation pressure, MPa; pwf is the bottomhole flowing pressure, MPa;based on the gas well production data, use the least squares method to fit and obtain the productivity index J, combine with the gas production rate parameter range, calculate the bottomhole flowing pressure according to the gas well productivity empirical formula, and obtain the formation inflow curve showing the relationship between bottomhole flowing pressure and gas production rate;Step 3: Plot the wellbore outflow curve, establish a foam drainage wellbore pressure drop model based on the wellbore structure data and production data obtained in Step 1; combine with the gas production rate parameter range, given the wellhead oil pressure, calculate the bottomhole flowing pressure according to the foam drainage wellbore pressure drop, and obtain the wellbore outflow curve showing the relationship between bottomhole flowing pressure and gas production rate;Step 4: Based on the formation inflow curve and wellbore outflow curve obtained in Steps 2 and 3, using nodal system analysis, plot the relationship curve between foam drainage agent concentration coefficient and gas production rate, and determine the optimal foam drainage agent injection concentration.

2. The method for determining foam drainage agent concentration in a gas wellbore based on wellbore multiphase flow calculation according to claim 1, characterized in that, in Step 3, calculate the friction resistance pressure drop under foam drainage conditions:-dpdz❘f=(c1⁢vSLc2⁢fm)⁢ρns(vm-vcf)22⁢D⁢(1+c3⁢αc4)where-dpdz❘f is the friction resistance pressure drop, in Pa / m; vSL is the liquid phase superficial velocity, in m / s; fm is the friction resistance coefficient, dimensionless; ρns is the no-slip mixture density, in kg / m3; vm is the gas-liquid mixed phase superficial velocity, in m / s; vcf is the gas-liquid two-phase liquid film reversal critical gas velocity, in m / s; D is the tubing inner diameter, in m; c1, c2, c3, c4 are polynomial coefficients obtained from experimental fitting; and a is the foam drainage agent concentration coefficient, dimensionless;wherein the expression for the gas-liquid two-phase liquid film reversal critical gas velocity is:vcf={c5[gD⁡(ρL-ρG)ρG]0.25+c6(PL⁢PG⁢vSL2)0.25}2where ρG is the gas density, in kg / m3; ρL is the liquid density, in kg / m3; vSL is the liquid phase superficial velocity, in m / s; g is the gravitational acceleration, in m / s2; D is the tubing inner diameter, in m; c5 and c6 are polynomial coefficients obtained from experimental fitting.

3. The method for determining foam drainage agent concentration in a gas wellbore based on wellbore multiphase flow calculation according to claim 1, characterized in that Step 3 comprises establishing the foam drainage liquid holdup Hfoam:based on the two-phase flow Mukherjee & Brill model liquid holdup formula, establish a liquid holdup model considering foam drainage agent concentration, the expression is:Hfoam=HL(b1+b2⁢FGα+1+b3(α+1)2where Hfoam is the foam drainage liquid holdup, in %; HL is the Mukherjee & Brill model two-phase liquid holdup, in %; FG is the gas phase superficial velocity converted using Froude number, in m / s; b1, b2, b3 are coefficients obtained from experimental fitting; and C* is the foam drainage agent concentration coefficient, dimensionless.

4. The method for determining foam drainage agent concentration in a gas wellbore based on wellbore multiphase flow calculation according to claim 1, characterized in that, Step 4 determines the optimal foam drainage agent injection concentration, the specific process is:combine Step 2 to use the gas well productivity empirical formula to calculate and obtain the formation inflow curve showing the relationship between bottomhole flowing pressure and gas production rate; combine Step 3 to use the foam drainage wellbore pressure drop model to calculate the wellbore outflow curve showing the relationship between bottomhole flowing pressure and gas production rate, given different foam drainage agent concentrations, calculate and obtain different foam drainage agent concentration coefficients, and obtain wellbore outflow curves showing the variation of bottomhole flowing pressure with gas production rate under different foam drainage agent concentrations; from the calculation results, it can be seen that the variation patterns of wellbore outflow curves under different foam drainage agent concentrations are consistent, with bottomhole flowing pressure first decreasing and then increasing as gas production rate increases; based on nodal system analysis, when the formation inflow curve and wellbore outflow curve intersect, it is the stable production point of the gas well; according to the gas production rates corresponding to the stable production points under different foam drainage agent concentration coefficients, plot the relationship curve between foam drainage agent concentration coefficient and gas production rate, and the foam drainage agent concentration corresponding to the stable production point with the highest gas production rate is the optimal foam drainage agent injection concentration for the gas well.

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