Method for Determining Gas Well Drainage and Gas Production Process

TECHNICAL FIELD

[0001]The present invention belongs to the field of oil and gas field development technology, and mainly relates to a method for determining gas well drainage and gas production process.

BACKGROUND OF THE INVENTION

[0002]In onshore and offshore gas field production, optimal selection of drainage and gas production processes is crucial for efficient gas well production; with the continuous development of natural gas resources, gas wells generally face liquid loading problems during production, which not only seriously affects gas well production, but also aggravates tubing corrosion and causes wellhead pressure fluctuations, reducing production stability. Different gas wells have differences in geological conditions, wellbore structure, and fluid properties, and the applicable drainage and gas production processes are also different.

[0003]Traditional methods for selecting drainage and gas production processes often rely on empirical judgment and lack systematic quantitative analysis. These approaches, when facing complex gas well production situations, have difficulty in accurately evaluating the applicability and effectiveness of different processes; in some gas wells, due to insufficient understanding of the relationship between formation energy and wellbore flow characteristics, the selected drainage and gas production process cannot effectively function, not only failing to increase gas well production, but also potentially increasing production costs and operational difficulty.

[0004]Patent (CN106570273A) optimizes the calculation model for critical liquid-carrying flow rate of natural gas, establishes a three-dimensional model of daily gas production, water-gas ratio, and well depth, and can simply and quickly determine gas well drainage and gas production processes based on production parameters such as gas well daily gas production, water-gas ratio, and well depth. However, the weight system determination method in this patent model is not detailed enough, and the calculation of economic benefits is not comprehensive enough; Patent (CN115221666A) comprehensively considers the production limits applicable to pressure and the production limits applicable to liquid carrying, quantitatively determines the applicable limits of drainage and gas production processes, and quantitatively determines drainage and gas production processes, but it mainly targets conventional gas-containing wells and does not comprehensively consider some special gas wells; Patent (CN117905419A) provides a process selection method and system based on wellbore liquid accumulation distribution, quickly selects the best drainage and gas production process measures by establishing a drainage and gas production process model. This patent divides liquid level depth, well deviation, liquid discharge rate, and gas-liquid ratio into limited levels, but actual gas well conditions are complex and variable, and this simple classification may not accurately cover all well conditions, making it difficult to determine the most suitable process, resulting in insufficient precision in process selection; Currently, although there are some studies on gas well production processes, comprehensive quantitative determination methods for drainage and gas production processes still need to be improved; Some studies only focus on the improvement of a single process or application under specific working conditions, and fail to comprehensively consider the comprehensive comparison and scientific selection of multiple processes under different gas well conditions from an overall perspective; This makes the decision-making for gas well drainage and gas production processes in actual production lack scientific basis, making it difficult to achieve maximum gas well production benefits.

[0005]Therefore, the present invention is committed to proposing a method for determining gas well drainage and gas production processes based on quantitative analysis, systematically collecting gas well data through field equipment, establishing precise models, and a comprehensive quantitative evaluation system, providing strong support for the reasonable selection of gas well drainage and gas production processes, thereby improving gas well production efficiency and economic benefits.

SUMMARY OF THE INVENTION

[0006]The present invention aims to provide a method for determining gas well drainage and gas production processes, through unified quantitative parameters to quantitatively analyze key indicators of different processes, using a weighted scoring system to achieve scientific determination of processes, providing theoretical basis for determining drainage and gas production processes.

[0011]For wellhead pressurization process, according to the calculation formula in Step S2, by reducing the wellhead oil pressure to the compressor inlet pressure, given a series of gas production rates, calculate the corresponding bottomhole flowing pressure, obtain the outflow curve showing the variation of bottomhole flowing pressure with gas production rate, under the condition that the gas productivity index remains unchanged, based on the current formation pressure, reduce the formation pressure, let P_rCO1 equal the current formation pressure P_r, given a series of formation pressures from P_rCO1 to P_rCO, obtain inflow curves showing the variation of gas production rate with bottomhole flowing pressure under different formation pressure conditions; find the gas production rate values corresponding to the intersection points of inflow curves with outflow curves under different formation pressure conditions, the gas production rate at the intersection point is the gas well production rate under the corresponding formation pressure for the wellhead pressurization process, the minimum gas production rate corresponding to the wellhead pressurization process is q_gminCO, the maximum gas production rate corresponding to the wellhead pressurization process is q_gmaxCO, if there is no intersection point, the gas production rate is determined to be 0; further plot the variation curve of intersection gas production rate with formation pressure, the maximum formation pressure when gas production rate is 0 is the formation pressure corresponding to when the inflow and outflow curves are just tangent, which is also the lower limit of applicable formation pressure P_rminCO for the wellhead pressurization process;

$\frac{\Delta q_g}{\Delta p_r},$

and the gas production area per unit formation pressure

[0017]Further, the expression of the comprehensive decision-making model for drainage and gas production is:

$M=\eta K+\lambda \left(1-K\right)$

[0018]Where M is the comprehensive decision-making score for drainage and gas production, points; η is the technical score of the process, points; λ is the economic score of the process, points; k is the weight of technical score, dimensionless;

[0019]Where the first-level indicators are divided into technical part and economic part, the weight of the technical part is 0.6, and the weight of the economic part is 0.4; the second-level indicators in the technical part are maximum gas production, formation pressure range Δp_r, gas production rate decrease per unit formation pressure

$\frac{\Delta q_g}{\Delta p_r},$

gas production area S, gas production area per unit formation pressure,

$\frac{S}{\Delta p_r}.$

and lower limit of formation pressure, with weights of 0.8, 0.8, 1, 1, 1, 1 respectively, the second-level indicators in the economic part are one-time investment and annual maintenance cost, with weights of 0.5, 0.5 respectively, then according to the parameters obtained in Step S6, perform weighted calculation and normalization processing, finally obtain the score, and define the process with the highest score as the optimal process.

[0020]The present invention provides a systematic and comprehensive method for determining drainage and gas production processes, comprehensively considers technical and economic factors, improves the scientificity and accuracy of process selection; through quantitative analysis of performance indicators of different processes, can intuitively compare the advantages and disadvantages of each process under different production conditions, providing reliable basis for field operations; the establishment of weighted scoring system makes the process determination process more objective and reasonable, helps to improve gas well production efficiency and economic benefits, and reduces production costs.

BRIEF DESCRIPTION OF THE DRAWINGS

[0021]FIG. 1 is a process flow diagram;

[0022]FIG. 2 is a schematic diagram of the optimized tubing process;

[0023]FIG. 3 is a schematic diagram of the pressurization process;

[0024]FIG. 4 is a schematic diagram of the gas lift process;

[0025]FIG. 5 is a schematic diagram of the foam drainage process;

[0026]FIG. 6 is a schematic diagram of the plunger process.

DETAILED DESCRIPTION OF THE INVENTION

[0027]The present invention will be described in detail below in conjunction with specific embodiments.

[0028]In order to make the purpose and calculation process of the present invention clearer, the present invention will be further described in detail below in conjunction with the drawings to highlight the advantages of the present invention;

Embodiment 1

[0029]As shown in FIG. 1, FIG. 1 is a process determination flow diagram of the present invention, the present invention provides a method for determining gas well drainage and gas production process; collect gas well downhole tubing data and production data, including wellbore structure, well inclination angle θ, pipe diameter D, obtain in real time through gas well field monitoring equipment the gas-liquid ratio GLR, oil pressure p_t, wellhead temperature T₀, gas productivity index J, current formation pressure P_r, sample and test the wellhead produced fluid to obtain its physical property parameters, gas phase relative density γ_g and liquid phase relative density γ_L, etc. during target gas well production; calculate gas phase superficial velocity and liquid phase superficial velocity, use Mukherjee-Brill model to calculate bottomhole flowing pressure, calculate bottomhole flowing pressure based on drift model for foam drainage well wellbore pressure drop model, and calculate wellbore pressure drop after plunger process, plot inflow/outflow dynamic curves after implementing each process respectively, obtain the maximum gas production rate, and the lower limit of formation pressure corresponding to each process; calculate to obtain the gas production area S, the formation pressure range Δp_r is the difference between the current formation pressure and the lower limit of applicable pressure for each process, the gas production range Δq_g is the difference between the maximum gas production rate and the minimum gas production rate for each process, the gas production rate decrease per unit formation pressure

$\frac{\Delta q_g}{\Delta p_r},$

and the gas production area per unit formation pressure

$\frac{\Delta q_g}{\Delta p_r},$

finally perform unified quantitative analysis, perform weighted scoring on each process, and determine the process with the highest score.

[0030]The gas-liquid mixture superficial velocity expression is:

$\begin{array}{cc}{\text{?}}_{\mathrm{SG}}=\frac{4Q\text{?}B\text{?}}{\pi D\text{?}};& \left(1\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0031]The mixture density is a function of liquid holdup, and its expression is:

$\begin{array}{cc}{\text{?}}_{\mathrm{SL}}=\frac{4Q\text{?}}{\pi D\text{?}};& \left(2\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0032]Where D is the pipe diameter, m; Q_g is the gas well production rate, m³/d, obtained in real time by field monitoring equipment; Q₁ is the liquid production rate, m³/s, obtained in real time by field monitoring equipment; B_g is the volume coefficient, dimensionless;

[0033]The expression for the volume coefficient is:

$\begin{array}{cc}{B}_g=3.447\times {10}^{-4}\frac{Z_{g}T}{p};& \left(3\right)\end{array}$

[0034]Since the gas well bottom layer is a high-temperature and high-pressure environment, the density of natural gas and formation liquid will change significantly with temperature and pressure. It is necessary to collect real-time temperature and pressure data through field detection devices, combine with the equation of state, convert the measured density to standard conditions, and ensure the accuracy of gas and liquid density values. The gas and liquid phase density expressions are:

$\begin{array}{cc}{\rho }_g=\frac{3484.1{\gamma }_{g}p}{Z_{g}T}& \left(4\right)\end{array}$$\begin{array}{cc}{\rho }_l=1000{\gamma }_L& \left(5\right)\end{array}$

[0035]Where ρ_g and ρ_i are the gas and liquid phase densities, kg/m³; p is the pressure, MPa; γ_g is the gas phase relative density, dimensionless, taken as 0.65; γ_L is the liquid phase relative density, dimensionless, taken as 1.02; Z_g is the natural gas deviation factor, dimensionless, taken as 0.94; T is the temperature, K.

[0036](2) Plot the inflow/outflow dynamic curves under current production conditions;

[0037]Use the commonly used gas well productivity empirical formula in engineering to calculate gas well productivity under each process, then use the friction coefficient in the Mukherjee-Brill model to calculate wellbore pressure drop; based on all data collected in Step S1, given a series of gas production rates, calculate the corresponding bottomhole flowing pressure, obtain the outflow curve showing the variation of bottomhole flowing pressure with gas production rate; given a series of bottomhole flowing pressures, calculate the corresponding gas production rate, obtain the inflow curve showing the variation of gas production rate with bottomhole flowing pressure; determine whether the inflow/outflow curves intersect, if there is an intersection point, it indicates that stable production is currently possible; otherwise stable production is not possible;

[0038]Further, through all data collected in Step S1, use the commonly used gas well productivity empirical formula in engineering:

$\begin{array}{cc}{Q}_g=J\left(p_r^2-p_{\mathrm{wf}}^2\right);& \left(6\right)\end{array}$

[0039]Where J is the gas productivity index, m³/(d·MPa₂); p_r is the average formation pressure, MPa; p_wf is the bottomhole flowing pressure, MPa;

[0040]The wellbore pressure drop model expression is

$\begin{array}{cc}\frac{\mathrm{dp}}{\mathrm{dz}}=-\left({\rho }_{m}g\sin \theta +f\frac{{\rho }_m{\text{?}}_m^2}{2D}\right)& \left(7\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0041]Where z is the depth, m; ρ_m is the mixture density, kg/m³; g is the gravitational acceleration, m/s²; θ is the well deviation angle, ∪; f is the friction coefficient, dimensionless; v_m is the gas-liquid mixture superficial velocity, m/s;

[0042]The expression for the apparent velocity of a gas-liquid mixture is:

$\begin{array}{cc}{\text{?}}_m={\text{?}}_{\mathrm{SG}}+{\text{?}}_{\mathrm{SL}}& \left(8\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0043]Where v_SG is the superficial gas velocity, m/s, obtained by converting the gas production rate obtained in real time by field monitoring equipment; v_SL is the superficial liquid velocity, m/s, obtained by converting the gas production rate obtained in real time by field monitoring equipment;

[0044]The mixture density is a function of the liquid holdup, and its expression is:

$\begin{array}{cc}{\rho }_m={\rho }_L{H}_L+{\rho }_G\left(1-H_L\right);& \left(9\right)\end{array}$

[0045]Where H_L is the liquid holdup, %; ρ_L is the liquid density, kg/m³; ρ_G is the gas density, kg/m³;

[0046]The liquid holdup H_L model calculation expression is:

$\begin{array}{cc}\{\begin{array}{c}{H}_L=0.84252\times m_1\left({\text{?}}_{\mathrm{SG}}\right)\times m_2\left(D\right)\times m_3\left({\text{?}}_{\mathrm{SL}}\right)\\ m_1\left({\text{?}}_{\mathrm{SG}}\right)=-0.211\ln \left({\text{?}}_{\mathrm{SG}}\times {\rho }_G^{0.5}\right)+0.7\\ m_2\left(D\right)=11.4D+0.53\\ m_3\left({\text{?}}_{\mathrm{SL}}\right)=0.67{\text{?}}_{\mathrm{SL}}+0.61\end{array}& \left(10\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0047]The friction coefficient f uses the calculation method in the Mukherjee-Brill model:

$\begin{array}{cc}f={\left[1.14-2lg\left(\frac{e}{D}+\frac{21.25}{N_{Re}^{0.9}}\right)\right]}^{-2};& \left(11\right)\end{array}$

[0048]Where e is the absolute roughness, m; N_Re is the no-slip Reynolds number, dimensionless, and its expression is:

$\begin{array}{cc}{N}_{Re}=\frac{{\text{?}}_m{\rho }_{m}D}{{\mu }_m};& \left(12\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0049]Where ρ_ns is the no-slip mixture density, kg/m³; μ_ns is the no-slip mixture viscosity, Pa·s.

[0050](3) Perform performance analysis for optimized tubing, wellhead pressurization, and gas lift processes;

[0051]Further, for optimized tubing measures, according to the calculation formula in Step S2, by changing the tubing inner diameter, given a series of gas production rates, calculate the corresponding bottomhole flowing pressure, obtain the outflow curve showing the variation of bottomhole flowing pressure with gas production rate, under the condition that the gas productivity index remains unchanged, based on the current formation pressure, reduce the formation pressure, let P_rTO1 equal the current formation pressure P_r, given a series of formation pressures from P_rTO1 to P_rTO, calculate and obtain inflow curves showing the variation of gas production rate with bottomhole flowing pressure under different formation pressure conditions; as shown in FIG. 2, find the gas production rate values corresponding to the intersection points of inflow curves with outflow curves under different formation pressure conditions, the gas production rate at the intersection point is the gas well production rate under the corresponding formation pressure for the optimized tubing process, if there is no intersection point, the gas production rate is determined to be 0; further plot the variation curve of intersection gas production rate with formation pressure, the minimum gas production rate corresponding to the optimized tubing process is q_gminTO, the maximum gas production rate corresponding to the optimized tubing process is q_gmaxTO, the maximum formation pressure when gas production rate is 0 is the formation pressure corresponding to when the inflow and outflow curves are just tangent, which is also the lower limit of applicable formation pressure P_rminTO for the optimized tubing process;

[0052]For wellhead pressurization process, according to the calculation formula in Step S2, by reducing the wellhead oil pressure to the compressor inlet pressure, given a series of gas production rates, calculate the corresponding bottomhole flowing pressure, obtain the outflow curve showing the variation of bottomhole flowing pressure with gas production rate, under the condition that the gas productivity index remains unchanged, based on the current formation pressure, reduce the formation pressure, let P_rCO1 equal the current formation pressure P_r, given a series of formation pressures from P_rCO1 to P_rCO, obtain inflow curves showing the variation of gas production rate with bottomhole flowing pressure under different formation pressure conditions; as shown in FIG. 3, find the gas production rate values corresponding to the intersection points of inflow curves with outflow curves under different formation pressure conditions, the gas production rate at the intersection point is the gas well production rate under the corresponding formation pressure for the wellhead pressurization process, the minimum gas production rate corresponding to the wellhead pressurization process is q_gminCO, the maximum gas production rate corresponding to the wellhead pressurization process is q_gmaxCO, if there is no intersection point, the gas production rate is determined to be 0; further plot the variation curve of intersection gas production rate with formation pressure, the maximum formation pressure when gas production rate is 0 is the formation pressure corresponding to when the inflow and outflow curves are just tangent, which is also the lower limit of applicable formation pressure P_rminCO for the wellhead pressurization process;

[0053]For gas lift process, according to the calculation formula in Step S2, given a series of gas production rates and add the gas injection rate of gas lift respectively, according to the gas-liquid ratio GLR provided in Step S1 and the given gas production rate to calculate the liquid production rate, thereby calculate the corresponding bottomhole flowing pressure, obtain the outflow curve showing the variation of bottomhole flowing pressure with gas production rate, under the condition that the gas productivity index remains unchanged, based on the current formation pressure, reduce the formation pressure, let P_rGL1 equal the current formation pressure P_r, given a series of formation pressures from P_rGL1 to P_rGL, obtain inflow curves showing the variation of gas production rate with bottomhole flowing pressure under different formation pressure conditions; as shown in FIG. 4, find the gas production rate values corresponding to the intersection points of inflow curves with outflow curves under different formation pressure conditions, the gas production rate at the intersection point is the gas well production rate under the corresponding formation pressure for the gas lift process, the minimum gas production rate corresponding to the gas lift process is q_gminGL, the maximum gas production rate corresponding to the gas lift process is q_gmaxGL, if there is no intersection point, the gas production rate is determined to be 0; further plot the variation curve of intersection gas production rate with formation pressure, the maximum formation pressure when gas production rate is 0 is the formation pressure corresponding to when the inflow and outflow curves are just tangent, which is also the lower limit of applicable formation pressure P_rminGL for the gas lift process.

[0054](4) For foam drainage process, given a series of gas production rates and foam agent injection concentration coefficient x, calculate the bottomhole flowing pressure; Further, the bottomhole flowing pressure calculation expression for foam drainage well:

$\begin{array}{cc}\frac{\mathrm{dp}}{\mathrm{dz}}=-\left[{\rho }_{m}g\sin \theta +\left(a_1{f}_m+a_2\ln {\text{?}}_{\mathrm{SL}}+{\alpha }_{3}x+a_4\right)\frac{{{\rho }_m\left(\text{?}-\text{?}\right)}^2}{2D}\right];& \left(13\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0055]Where f_m is the gas-liquid two-phase friction coefficient in the Mukherjee-Brill model, dimensionless; x is the foam agent concentration coefficient, dimensionless; v_cfoam is the foam film reversal critical gas velocity, m/s; a₁, a₂, a₃, a₄ represent the polynomial coefficients obtained from experimental fitting;

[0056]The gas-liquid phase mixture density expression is:

$\begin{array}{cc}{\rho }_m=\rho \text{?}\left(1-\alpha \right)+\rho \text{?}\alpha ;& \left(14\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0057]Where α is the gas holdup, %;

[0058]The implicit equation expression for calculating the gas holdup α in the wellbore is:

$\begin{array}{cc}\frac{\text{?}}{\alpha }=\left[\frac{2-\alpha \text{?}}{1+{\left(Re/1000\right)}^2}+\frac{1.2-0.15\sqrt{\rho \text{?}/\rho \text{?}}}{1+{\left(1000/Re\right)}^2}\times \left(1-e\text{?}\right)\right]\left(1.74-0.0038\sigma \right)\text{?}+1.45\text{?}+\left[1.31\cos \theta +1.78(\frac{\sigma g\Delta \rho }{\rho \text{?}}\sin \theta \right]\sqrt{gD}\left(1-\alpha \right)\text{?};& \left(15\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0059]Where Δρ is the difference between gas and liquid densities, kg/m³;

[0060]The Reynolds number calculation formula is:

$\begin{array}{cc}\mathrm{Re}={\rho }_m{v}_{m}D/{\mu }_m;& \left(16\right)\end{array}$

[0061]The surface tension calculation formula is:

$\begin{array}{cc}\sigma =41.31/\left[1+{\left(\frac{C_v}{6.679}\right)}^{0.906}\right]+24.53;& \left(17\right)\end{array}$

[0062]Where R^e is the Reynolds number, dimensionless; σ is the surface tension, mN/m; μ_m is the dynamic viscosity, Pa·s;

[0072]The foam agent concentration coefficient expression is:

$\begin{array}{cc}x=\frac{C_v}{\mathrm{CMC}};& \left(18\right)\end{array}$

[0073]Where C_v is the foam agent concentration, mg/L; CMC is the critical micelle concentration of the foam agent, mg/L;

[0074]The gas-liquid two-phase liquid film reversal critical velocity expression is:

$\begin{array}{cc}{v}_{\mathrm{cf}}={\left\{{c_1\left[\frac{\mathrm{gD}\left(\text{?}-\text{?}\right)}{\text{?}}\right]}^{0.25}+{c_2\left(\text{?}\right)}^{0.25}\right\}}^2;& \left(19\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0075]Where v_cf is the gas-liquid two-phase liquid film reversal critical velocity, m/s; C₁, C₂ represent the polynomial coefficients obtained from experimental fitting;

[0076]The foam film reversal critical gas velocity expression is:

$\begin{array}{cc}\frac{\text{?}}{v_{\mathrm{cf}}}=\left(b_1+\frac{b_2}{x+1}+\frac{b_3}{{\left(x+1\right)}^2}\right);& \left(20\right)\end{array}$$\text{?}\text{indicates text missing or illegible when filed}$

[0077]Where b₁, b₂, b₃ represent the polynomial coefficients obtained from experimental fitting;

[0078]Based on the calculated bottomhole flowing pressure, obtain the outflow curve showing the variation of bottomhole flowing pressure with gas production rate for the foam drainage well, under the condition that the gas productivity index remains unchanged, based on the current formation pressure, reduce the formation pressure, let P_rFL1 equal the current formation pressure P_r, given a series of formation pressures from P_rFL1 to P_rFL, obtain inflow curves showing the variation of gas production rate with bottomhole flowing pressure under different formation pressure conditions; as shown in FIG. 5, find the gas production rate values corresponding to the intersection points of inflow curves with outflow curves under different formation pressure conditions, the gas production rate at the intersection point is the gas well production rate under the corresponding formation pressure for the foam drainage process, the minimum gas production rate corresponding to the foam drainage process is q_gminFL, the maximum gas production rate corresponding to the foam drainage process is q_gmaxFL, if there is no intersection point, the gas production rate is determined to be 0; further plot the variation curve of intersection gas production rate with formation pressure, the maximum formation pressure when gas production rate is 0 is the formation pressure corresponding to when the inflow and outflow curves are just tangent, which is also the lower limit of applicable formation pressure P_rminFD for the foam drainage process.

[0079](5) For plunger gas lift process, given the minimum gas production rate applicable to plunger process as q_gminPL; according to the inflow/outflow curves plotted in Step S2, keeping the gas productivity index J unchanged, increase or decrease the formation pressure and plot the inflow curve under formation pressure conditions, as shown in FIG. 6, so that the inflow curve is tangent to the outflow curve, connect the tangent point with the coordinate origin to obtain line L, based on the current formation pressure, reduce the formation pressure, let P_rPL1 equal the current formation pressure P_r, given a series of formation pressures from P_rPL1 to P_rPL, obtain inflow curves showing the variation of gas production rate with bottomhole flowing pressure under different formation pressure conditions, find the gas production rate values corresponding to the intersection points of inflow curves with line L under different formation pressure conditions; the gas production rate at the intersection point of the inflow curve with line L under current formation pressure conditions is the maximum gas production rate q_gmaxPL corresponding to the plunger process, and the formation pressure corresponding to the lower limit of applicable gas production rate for the given plunger process is the lower limit of applicable formation pressure P_rminPL for the plunger process.

[0080](6) Normalize different processes to the inflow/outflow dynamic curves under optimal process conditions, obtain the operating production rates of each process under different formation pressure conditions, and then perform unified comparison; from the inflow/outflow dynamic curves of each process in Steps S3 to S5, obtain the maximum gas production rate, the lower limit of formation pressure corresponding to each process, and the minimum gas production rate after adopting each process; calculate to obtain the gas production area S, the formation pressure range Δp_r is the difference between the current formation pressure and the lower limit of applicable pressure for each process, the gas production range Δq_g is the difference between the maximum gas production rate and the minimum gas production rate for each process, the gas production rate decrease per unit formation pressure

$\frac{\Delta \text{?}}{\Delta p_r},$$\text{?}\text{indicates text missing or illegible when filed}$

and the gas production area per unit formation pressure

$\frac{S}{\Delta p_r}.$

[0081](7) Based on the set comparison processes, including optimized tubing, wellhead pressurization, gas lift, foam drainage, and plunger, customize scoring system and weighting system;

[0082]Further, the expression of the comprehensive decision-making model for drainage and gas production is:

$\begin{array}{cc}M=\eta K+\lambda \left(1-K\right);& \left(21\right)\end{array}$

[0083]Where M is the comprehensive decision-making score for drainage and gas production, points; η is the technical score of the process, points; λ is the economic score of the process, points; k is the weight of technical score, dimensionless;

[0084]Where the first-level indicators are divided into technical part and economic part, the weight of the technical part is 0.6, and the weight of the economic part is 0.4; the second-level indicators in the technical part are maximum gas production rate, formation pressure range Δp_r, gas production rate decrease per unit formation pressure

$\frac{\Delta \text{?}}{\Delta p_r},$$\text{?}\text{indicates text missing or illegible when filed}$

gas production area S, gas production area per unit formation pressure

$\frac{S}{\Delta p_r},$

and lower limit of formation pressure, with weights of 0.8, 0.8, 1, 1, 1, 1 respectively, the second-level indicators in the economic part are one-time investment and annual maintenance cost, with weights of 0.5, 0.5 respectively, then according to the parameters obtained in Step S6, perform weighted calculation and normalization processing, finally obtain the score, and define the process with the highest score as the optimal process.

[0089]The above description is only the research approach of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of the present invention shall be included within the protection scope of the present invention.