A method for determining a gas well water drainage and gas production process

Abstract

The present invention belongs to the technical field of oil and gas field development and relates to a method for determining a gas well drainage gas production process. Aiming at the problems that traditional methods rely on empirical judgment, lack quantitative analysis, and are difficult to accurately evaluate the applicability and effect of the process, the present invention collects the downhole string and production data of the gas well, calculates parameters such as the apparent velocities and densities of the gas phase and liquid phase; draws the inflow / outflow dynamic curve to judge whether the gas well can produce stably; then performs performance analysis on the preferred string, wellhead pressurization, gas lift, foam drainage, and plunger processes respectively to determine the lower limit of action of each process and unify the quantitative parameters; finally, a scoring and weighting system is customized, and a score is obtained through the comprehensive decision-making model for drainage gas production, and the process with the highest score is the optimal process. Compared with the existing methods, this method improves the scientificity and accuracy of process selection, helps to improve the gas well production efficiency and economic benefits, and reduces costs.

Description

Technical Field

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

[0002] In the field of oil and gas field development, the reasonable selection of the gas well water drainage and gas production process is crucial for the efficient production of gas wells; with the continuous development of natural gas resources, gas wells generally face the problem of liquid accumulation during the production process, which seriously affects the gas well production and production stability; due to differences in geological conditions, wellbore structures, and fluid properties, etc., different gas wells have different applicable water drainage and gas production processes.

[0003] Traditional methods for selecting water drainage and gas production processes often rely on empirical judgment and lack systematic quantitative analysis; in the face of complex gas well production situations, it is difficult to accurately evaluate the applicability and effects of different processes using this method; in some gas wells, due to insufficient understanding of the relationship between formation energy and wellbore flow characteristics, the selected water drainage and gas production process cannot effectively play its role, not only unable to increase the gas well production, but also may increase production costs and operation difficulties.

[0004] The invention patent (CN106570273A) established a three-dimensional model of daily gas production, water-gas ratio, and well depth by optimizing the calculation model of the critical liquid-carrying flow rate of natural gas. According to production parameters such as the daily gas production, water-gas ratio, and well depth of the gas well, the gas well water drainage and gas production process can be simply and quickly determined. However, the method for determining the weight system in this patent model is not detailed enough, and the calculation of economic benefits is not comprehensive enough; the invention patent (CN115221666A) comprehensively considers the production limit applicable to pressure and the production limit applicable to liquid carrying, quantitatively determines the applicable limit of the water drainage and gas production process, and quantitatively determines the water drainage and gas production process, but it mainly targets conventional gas wells and does not consider some special gas wells comprehensively; the invention patent (CN117905419A) provides a process selection method and system based on the distribution of wellbore liquid accumulation. By establishing a water drainage and gas production process model, the best water drainage and gas production process measures can be quickly selected. This patent divides the liquid level depth, well deviation, liquid drainage volume, and gas-liquid ratio into limited levels. However, the actual gas well conditions are complex and changeable, and this simple classification may not accurately cover all well conditions, making it difficult to determine the most suitable process, resulting in inaccurate process selection; currently, although there are some studies on gas well production processes, the comprehensive quantitative determination method for the water drainage and gas production process still needs to be improved; some studies only focus on the improvement of a single process or the application under specific working conditions, and do not consider the comprehensive comparison and scientific selection of multiple processes under different gas well conditions as a whole; this makes the decision-making of the gas well water drainage and gas production process lack a scientific basis in actual production and is difficult to maximize the production benefits of gas wells.

[0005] To this end, the present invention is dedicated to proposing a method for determining the gas well drainage gas production process based on quantitative analysis. By systematically collecting gas well data, establishing an accurate model, and a comprehensive quantitative evaluation system, it provides strong support for the rational selection of the gas well drainage gas production process, thereby improving the production efficiency and economic benefits of gas wells. Summary of the Invention

[0006] The present invention aims to provide a method for determining the gas well drainage gas production process. By uniformly quantifying parameters and quantitatively analyzing the key indicators of different processes, and using a weighted scoring system to scientifically determine the process, it provides a theoretical basis for determining the drainage gas production process.

[0007] To achieve the above object, a method for determining the gas well drainage gas production process according to the present invention includes the following steps:

[0008] Step S1: Collect the downhole string data and production data of the gas well, including wellbore structure, well inclination angle θ, pipe diameter D, gas-liquid ratio GLR, oil pressure p t , wellhead temperature T0, natural gas physical properties parameters, gas production index J, current formation pressure P r , gas phase relative density γ g and liquid phase relative density γ L ; Calculate the gas phase apparent velocity and the liquid phase apparent velocity.

[0009] Step S2: Draw the inflow / outflow dynamic curve under the current production conditions; Select the commonly used gas well productivity empirical formula in the engineering to calculate the gas well productivity under each process, and then use the friction coefficient in the Mukherjee-Brill model to calculate the wellbore pressure drop; Based on all the data collected in Step S1, given a series of gas production rates, calculate the corresponding bottom-hole flowing pressure, and obtain the outflow curve of the bottom-hole flowing pressure changing with the gas production rate; Given a series of bottom-hole flowing pressures, calculate the corresponding gas production rates, and obtain the inflow curve of the gas production rate changing with the bottom-hole flowing pressure; Judge whether the inflow / outflow curves intersect. If there is an intersection point, it indicates that stable production can be achieved currently, otherwise stable production cannot be achieved; Further, through all the data collected in Step S1, select the commonly used gas well productivity empirical formula in the engineering to calculate the gas well productivity, and use the Mukherjee-Brill model to calculate the wellbore pressure drop.

[0010] Step S3: Conduct performance analysis on the optimized string, wellhead pressurization, and gas lift processes; Further, for the optimized string 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 bottom-hole flowing pressure, and obtain the outflow curve of the bottom-hole flowing pressure changing with the gas production rate. On the premise of ensuring that the gas production index remains unchanged, taking the current formation pressure as the benchmark, reduce the formation pressure, and make P rTO1 equal to the current formation pressure P r , given a series of formation pressures PrTO1 to P rTO Calculate the inflow curve of gas production varying with the bottom-hole flowing pressure under different formation pressure conditions; find the gas production values corresponding to the intersection points of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection point is the gas well production of the optimized string technology under the corresponding formation pressure. If there is no intersection point, the gas production is determined to be 0. Further plot the curve of the gas production at the intersection point varying with the formation pressure. The minimum gas production corresponding to the optimized string technology is q gminTO and the maximum gas production corresponding to the optimized string technology is q gmaxTO . The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the case where the inflow and outflow curves are just tangent, which is also the lower limit P of the applicable formation pressure of the optimized string technology rminTO ;

[0011] For the wellhead boosting technology, according to the calculation formula in step S2, by reducing the wellhead oil pressure to the inlet pressure of the compressor, given a series of gas production rates, calculate the corresponding bottom-hole flowing pressure to obtain the outflow curve of the bottom-hole flowing pressure varying with the gas production rate. On the premise of ensuring that the gas production index remains unchanged, taking the current formation pressure as the reference, reduce the formation pressure and let P rCO1 be equal to the current formation pressure P r . Given a series of formation pressures P rCO1 to P rCO , calculate the inflow curve of gas production varying with the bottom-hole flowing pressure under different formation pressure conditions; find the gas production values corresponding to the intersection points of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection point is the gas well production of the wellhead boosting technology under the corresponding formation pressure. The minimum gas production corresponding to the wellhead boosting technology is q gminCO and the maximum gas production corresponding to the wellhead boosting technology is q gmaxCO . If there is no intersection point, the gas production is determined to be 0. Further plot the curve of the gas production at the intersection point varying with the formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the case where the inflow and outflow curves are just tangent, which is also the lower limit P of the applicable formation pressure of the wellhead boosting technology rminCO ;

[0012] For the gas lift technology, according to the calculation formula in step S2, given a series of gas production rates and adding the injection gas volume of the gas lift respectively, calculate the liquid production volume according to the gas-liquid ratio GLR provided in step S1 and the given gas production rate, so as to calculate the corresponding bottom-hole flowing pressure to obtain the outflow curve of the bottom-hole flowing pressure varying with the gas production rate. On the premise of ensuring that the gas production index remains unchanged, taking the current formation pressure as the reference, reduce the formation pressure and let P rGL1 be equal to the current formation pressure P r . Given a series of formation pressures P rGL1 to P rGL, get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure of the gas lift process. The minimum gas production corresponding to the gas lift process is q gminGL , the maximum gas production corresponding to the gas lift process is q gmaxGL If there is no intersection, the gas production is considered to be 0; further draw the curve of the intersection gas production and formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the inflow and outflow curves being just tangent, which is also the lower limit of the applicable formation pressure P of the gas lift process. rminGL .

[0013] Step S4: For the foaming process, given a series of gas production and the concentration coefficient x of the foaming agent, the bottom hole flow pressure is calculated; then the critical velocity of gas-liquid two-phase liquid film reversal and the critical velocity of foam film reversal are calculated by changing the foaming agent concentration; further, based on the calculated bottom hole flow pressure, the outflow curve of the bottom hole flow pressure of the foaming well corresponding to the change of gas production can be obtained, and under the condition that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P is set. rFL1 Equal to the current formation pressure P r , given a series of formation pressures P rFL1 To P rFL , get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure of the bubble drainage process. The minimum gas production corresponding to the bubble drainage process is q gminFL The maximum gas production corresponding to the bubble discharge process is q gmaxFL If there is no intersection, the gas production is considered to be 0; further draw the curve of the intersection gas production and formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the inflow and outflow curves just tangent to each other, which is also the lower limit of the applicable formation pressure P of the bubble drainage process. rminFD .

[0014] Step S5: For the plunger gas lift process, the minimum gas production applicable to the given plunger process is q gminPL According to the inflow / outflow curve drawn in step S2, keep the gas production index J unchanged, increase or decrease the formation pressure and draw the inflow curve under the formation pressure condition, so that the inflow curve is tangent to the outflow curve, connect the tangent point and the coordinate origin to obtain a straight line L, take the current formation pressure as the reference, reduce the formation pressure, and let P rPL1 Equal to the current formation pressure P r , given a series of formation pressures P rPL1 To P rPL, the inflow curves of gas production varying with the bottom-hole flowing pressure under different formation pressure conditions are obtained, and the gas production values corresponding to the intersection points of the inflow curves and the straight line L under different formation pressure conditions are found; the gas production at the intersection point of the inflow curve and the straight line L under the current formation pressure condition is the maximum gas production q corresponding to the plunger gas lift process gmaxPL , the formation pressure corresponding to the lower limit of the applicable gas production of the given plunger process is the lower limit of the formation pressure P that the plunger process can act on rminPL .

[0015] Step S6: Normalize different processes to the inflow / outflow dynamic curves under the optimal process conditions to obtain the operating gas production of each process under different formation pressure conditions, and then make a unified comparison; further, the maximum gas production, the lower limit of the formation pressure corresponding to each process, and the minimum gas production after adopting each process are obtained from the inflow / outflow dynamic curves of each process in steps S3 to S5; calculate the gas production area S and the formation pressure range Δp r is the difference between the current formation pressure and the lower limit of the applicable pressure of each process, and the gas production range Δq g is the difference between the maximum gas production and the minimum gas production of each process, and the gas production decrease per unit formation pressure , the gas production area per unit formation pressure .

[0016] Step S7: Customize a scoring system and a weighting system according to the set comparison processes, including optimized pipe strings, wellhead pressurization, gas lift, foam drainage, and plunger

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

[0018]

[0019] In the formula, M is the comprehensive decision-making score for gas drainage and production, in points; η is the technical score of the process, in points; λ is the economic score of the process, in points; k is the weight of the technical score, dimensionless;

[0020] Among them, the first-level indicators are divided into technical and economic parts. 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 , the gas production decrease per unit formation pressure , gas production area S, gas production area per unit formation pressure , the lower limit of the 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 and 0.5 respectively. Then, according to the parameters obtained in step S6, weighted calculation and normalization processing are carried out, and finally the score is obtained. The process with the highest score is defined as the optimal process.

[0021] The present invention provides a systematic and comprehensive method for determining the gas drainage and production process, which comprehensively considers technical and economic factors, improves the scientificity and accuracy of process selection; by quantitatively analyzing the performance indicators of different processes, it can intuitively compare the advantages and disadvantages of each process under different production conditions, providing a reliable basis for on-site operation; the establishment of a weighted scoring system makes the process determination more objective and reasonable, helps to improve the gas well production efficiency and economic benefits, and reduces production costs. BRIEF DESCRIPTION OF THE DRAWINGS

[0022] Figure 1 is a process flow chart;

[0023] Figure 2 is a schematic diagram of the preferred pipe string process;

[0024] Figure 3 is a schematic diagram of the boosting process;

[0025] Figure 4 is a schematic diagram of the gas lift process;

[0026] Figure 5 is a schematic diagram of the foam drainage process;

[0027] Figure 6 is a schematic diagram of the plunger process. DETAILED DESCRIPTION OF THE 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 with reference to the accompanying drawings to highlight the advantages of the present invention;

[0029] As Figure 1 shown, Figure 1 is the process determination flow chart of the present invention. The present invention provides a method for determining the gas drainage and production process of a gas well; first, collect the downhole pipe string data and production data of the gas well, including wellbore structure, well inclination θ, pipe diameter D, gas-liquid ratio GLR, oil pressure p t , wellhead temperature T0, natural gas physical property parameters, gas production index J, current formation pressure P r , gas phase relative density γ g and liquid phase relative density γ L ; then calculate the gas phase apparent velocity, liquid phase apparent velocity, gas phase density, liquid phase density, calculate the bottom hole flowing pressure using the Mukherjee-Brill model, calculate the bottom hole flowing pressure using the foam drainage wellbore pressure drop model based on the drift model, and calculate the wellbore pressure drop after the plunger process, respectively draw the inflow / outflow dynamic curves after the implementation of each process, obtain the maximum gas production, and the lower limit of the formation pressure corresponding to each process; calculate the gas production area S and the formation pressure range Δp r is the difference between the current formation pressure and the lower limit of the available pressure for each process, and the gas production range Δqg It is the difference between the maximum gas production and the minimum gas production of each process, and the gas production decreases under the unit formation pressure , the gas production area under the unit formation pressure , finally, a unified quantitative analysis is carried out, a weighted score is given to each process, and the process with the highest score is determined.

[0030] (1) The expression of the gas-phase superficial velocity is:

[0031] (1);

[0032] The expression of the liquid-phase superficial velocity is:

[0033] (2);

[0034] In the formula, D is the pipe diameter, m; Q g is the gas well production, m 3 / d; Q l is the liquid production, m 3 / s; B g is the volume coefficient, dimensionless;

[0035] Among them, the expression of the volume coefficient is:

[0036] (3);

[0037] The expressions of the gas and liquid phase densities are:

[0038] (4);

[0039] (5);

[0040] In the formula, ρ g , ρ l are the gas and liquid phase densities, kg / m 3 ; p is the pressure, MPa; γ g is the gas-phase relative density, dimensionless, taking 0.65; γ L is the liquid-phase relative density, dimensionless, taking 1.02; Z g is the natural gas deviation coefficient, dimensionless, taking 0.94; T is the temperature, K.

[0041] (2) Draw the inflow / outflow performance curve under the current production conditions;

[0042] Select the empirical gas well productivity formula commonly used in engineering to calculate the gas well productivity under each process, and then use the friction factor in the Mukherjee-Brill model to calculate the wellbore pressure drop; based on all the data collected in step S1, given a series of gas production rates, calculate the corresponding bottom-hole flowing pressure, and obtain the outflow curve of the bottom-hole flowing pressure varying with the gas production rate; given a series of bottom-hole flowing pressures, calculate the corresponding gas production rate, and obtain the inflow curve of the gas production rate varying with the bottom-hole flowing pressure; determine whether the inflow / outflow curves intersect. If there is an intersection point, it indicates that stable production can be achieved currently; otherwise, stable production cannot be achieved.

[0043] Further, through all the data collected in step S1, select the empirical gas well productivity formula commonly used in engineering:

[0044] (6);

[0045] In the formula, J is the gas production index, m 3 / (d·MPa 2 ); p r is the average formation pressure, MPa; p wf is the bottom-hole flowing pressure, MPa;

[0046] The expression of the wellbore pressure drop model is

[0047] (7);

[0048] In the formula, z is the depth, m; ρ m is the mixed density, kg / m 3 ; g is the acceleration of gravity, m / s 2 ; θ is the well deviation angle, °; f is the friction factor, dimensionless; v m is the apparent velocity of the gas-liquid mixture, m / s;

[0049] The expression of the apparent velocity of the gas-liquid mixture is:

[0050] (8);

[0051] In the formula, v SG is the apparent gas velocity, m / s; v SL is the apparent liquid velocity, m / s;

[0052] The mixed density is a function of the liquid holdup, and its expression is:

[0053] (9);

[0054] In the formula, H L is the liquid holdup, %; ρ L is the liquid density, kg / m 3 ; ρ Gis the gas density, kg / m 3 ;

[0055] The liquid holdup H L The model calculation expression is:

[0056] (10);

[0057] The friction factor f adopts the calculation method in the Mukherjee - Brill model:

[0058] (11);

[0059] In the formula, e is the absolute roughness, m; N Re is the no - slip Reynolds number, dimensionless, and its expression is:

[0060] (12);

[0061] In the formula, ρ ns is the no - slip mixture density, kg / m 3 ; μ ns is the no - slip mixture viscosity, Pa·s.

[0062] (3) Perform performance analysis on the optimized string, wellhead pressurization and gas lift process;

[0063] Furthermore, for the optimized string measure, according to the calculation formula in step S2, by changing the tubing inner diameter, a series of gas production rates are given, and the corresponding bottom - hole flowing pressure is calculated to obtain the outflow curve of the bottom - hole flowing pressure varying with the gas production rate. On the premise of keeping the gas production index unchanged, taking the current formation pressure as the benchmark, the formation pressure is reduced, let P rTO1 be equal to the current formation pressure P r , a series of formation pressures P rTO1 to P rTO are given, and the inflow curve of the gas production rate varying with the bottom - hole flowing pressure under different formation pressure conditions is calculated; as Figure 2 shown, find out the gas production rate values corresponding to the intersection points of the inflow curve and the outflow curve under different formation pressure conditions. The gas production rate at the intersection point is the gas well gas production rate of the optimized string process under the corresponding formation pressure. If there is no intersection point, the gas production rate is determined to be 0; further draw the curve of the intersection point gas production rate varying with the formation pressure. The minimum gas production rate corresponding to the optimized string process is q gminTO , the maximum gas production rate corresponding to the optimized string process is q gmaxTO , and the maximum formation pressure when the gas production rate is 0 is the formation pressure corresponding to the tangent point of the inflow and outflow curves, which is also the lower limit of the applicable formation pressure P rminTO ;

[0064] For the wellhead pressurization process, according to the calculation formula in step S2, by reducing the wellhead oil pressure to the inlet pressure of the compressor, a series of gas production is given, and the corresponding bottom hole flow pressure is calculated to obtain the outflow curve of the bottom hole flow pressure corresponding to the gas production. Under the condition that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P is set. rCO1 Equal to the current formation pressure P r , given a series of formation pressures P rCO1 To P rCO , we can get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; Figure 3 As shown in the figure, find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure by the wellhead boosting process. The minimum gas production corresponding to the wellhead boosting process is q gminCO , the maximum gas production corresponding to the wellhead boosting process is q gmaxCO If there is no intersection, the gas production is considered to be 0; further draw the curve of the intersection gas production and formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the inflow and outflow curves just tangent to each other, which is also the lower limit of the effective formation pressure P of the wellhead boosting process. rminCO ;

[0065] For the gas lift process, according to the calculation formula in step S2, a series of gas production is given and the gas injection volume of the gas lift is added respectively. The liquid production is calculated according to the gas-liquid ratio GLR provided in step S1 and the given gas production, so as to calculate the corresponding bottom hole flow pressure, and obtain the outflow curve of the bottom hole flow pressure corresponding to the change of gas production. Under the condition of ensuring that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P is set. rGL1 Equal to the current formation pressure P r , given a series of formation pressures P rGL1 To P rGL , we can get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; Figure 4 As shown in the figure, find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure of the gas lift process. The minimum gas production corresponding to the gas lift process is q gminGL , the maximum gas production corresponding to the gas lift process is q gmaxGL If there is no intersection, the gas production is considered to be 0; further draw the curve of the intersection gas production and formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the inflow and outflow curves being just tangent, which is also the lower limit of the applicable formation pressure P of the gas lift process. rminGL .

[0066] For the foam drainage process, given a series of gas production rates and the concentration coefficient x of the foam agent injection, calculate the bottom-hole flowing pressure;

[0067] Furthermore, the calculation expression for the bottom-hole flowing pressure of a foam drainage well:

[0068] (13);

[0069] In the formula, f m is the gas-liquid two-phase friction resistance coefficient in the Mukherjee-Brill model, dimensionless; x is the foam agent concentration coefficient, dimensionless; v cfoam is the critical gas flow velocity for foam film inversion, m / s; a1, a2, a3, a4 represent the coefficients of the polynomial obtained by experimental fitting;

[0070] The expression for the gas-liquid mixture density is:

[0071] (14);

[0072] In the formula, α is the gas holdup, %;

[0073] The implicit equation expression for calculating the gas holdup α in the wellbore is:

[0074] (15);

[0075] In the formula, Δρ is the difference between the gas and liquid densities, kg / m 3 ;

[0076] The calculation formula for the Reynolds number is:

[0077] (16);

[0078] The calculation formula for the surface tension is:

[0079] (17);

[0080] In the formula, Re is the Reynolds number, dimensionless; σ is the surface tension, mN / m, μ m is the dynamic viscosity, Pa·s;

[0081] The specific solution process is as follows:

[0082] 1) Input the known parameters: pipe diameter D, oil pressure pt, gas flow velocity v SG , liquid flow velocity v SL , pipe inclination angle θ, foam agent concentration C v ;

[0083] 2) Select an appropriate calculation step ΔL and divide the pipe section into n segments;

[0084] 3) Assume the gas holdup αest ;

[0085] 4) Calculate the mixed Reynolds number Re by formula (16), and calculate the surface tension σ by formula (17);

[0086] 5) Reynolds number Re, gas-liquid flow rate v SG With v SL , gas-liquid density ρ g and ρ l , inclination angle θ, and surface tension σ are substituted into formula (15) and the gas void fraction is calculated using the Newton iteration method, that is, α cal =α est -f(α est ) / f'(α est ), where f(α est ) is the gas content calculated in the last cycle, f'(α est ) is the rate of change of the calculated gas holdup after the last cycle with the assumed gas holdup, i.e., Δα cal / Δα est ; Set α est With α cal For comparison, if |α cal -α est | / α cal <0.001, the accuracy requirement is met, and the gas content α is output cal , otherwise α cal The value of α is assigned to est , repeat steps 4) to 5) until the accuracy requirements are met;

[0087] 6) Calculate the pressure drop gradient dp / dz of the micro-element segment by formula (13);

[0088] 7) Calculate the pressure change Δp of the micro-element segment cal =(dp / dz)ΔL;

[0089] 8) Set the pressure p at the outlet of the current cycle step t +1=p t +Δp cal As the input parameter of the next calculation unit, repeat the above steps until the calculation is completed;

[0090] The expression of foaming agent concentration coefficient is:

[0091] (18);

[0092] In the formula, C v is the concentration of foaming agent, mg / L; CMC is the critical micelle concentration of foaming agent, mg / L;

[0093] The expression of the critical velocity of gas-liquid two-phase liquid film reversal is:

[0094] (19);

[0095] wherein, v cf is the critical flow velocity for the inversion of the gas-liquid two-phase liquid film, in m / s; c1 and c2 represent the coefficients of the polynomial obtained by experimental fitting;

[0096] The expression for the critical gas flow velocity for the inversion of the foam film is:

[0097] (20);

[0098] wherein, b1, b2, and b3 represent the coefficients of the polynomial obtained by experimental fitting;

[0099] Based on the calculated bottom-hole flowing pressure, the outflow curve of the bottom-hole flowing pressure of the foam drainage well varying corresponding to the gas production rate can be obtained. On the condition of ensuring that the gas production index remains unchanged, taking the current formation pressure as the benchmark, reducing the formation pressure, making P rFL1 equal to the current formation pressure P r , given a series of formation pressures P rFL1 to P rFL , the inflow curve of the gas production rate varying corresponding to the bottom-hole flowing pressure under different formation pressure conditions is obtained; as Figure 5 shown, find out the gas production rate values corresponding to the intersection points of the inflow curve and the outflow curve under different formation pressure conditions. The gas production rate at the intersection point is the gas production rate of the gas well for the foam drainage process under the corresponding formation pressure. The minimum gas production rate corresponding to the foam drainage process is q gminFL , and the maximum gas production rate corresponding to the foam drainage process is q gmaxFL . If there is no intersection point, it is determined that the gas production rate is 0; further plot the curve of the gas production rate at the intersection point varying with the formation pressure. The maximum formation pressure when the gas production rate is 0 is the formation pressure corresponding to when the inflow and outflow curves are just tangent, and it is also the lower limit of the applicable formation pressure P rminFD of the foam drainage process.

[0100] (5) For the plunger gas lift process, the given minimum gas production rate applicable to the plunger process is q gminPL ; according to the inflow / outflow curves plotted in step S2, keeping the gas production index J unchanged, increasing or decreasing the formation pressure and plotting the inflow curve under the formation pressure condition, as Figure 6 shown, making the inflow curve tangent to the outflow curve, connecting the tangent point and the origin of coordinates to obtain the straight line L. Taking the current formation pressure as the benchmark, reducing the formation pressure, making P rPL1 equal to the current formation pressure P r , given a series of formation pressures P rPL1 to P rPL, the inflow curves of gas production varying with the bottom-hole flowing pressure under different formation pressure conditions are obtained, and the gas production values corresponding to the intersection points of the inflow curves and the straight line L under different formation pressure conditions are found; the gas production at the intersection point of the inflow curve and the straight line L under the current formation pressure condition is the maximum gas production q corresponding to the plunger process. gmaxPL , the formation pressure corresponding to the lower limit of the applicable gas production of the given plunger process is the lower limit P of the applicable formation pressure of the plunger process. rminPL .

[0101] (6) Normalize different processes to the inflow / outflow dynamic curves under the optimal process conditions to obtain the operating gas production of each process under different formation pressure conditions, and then conduct a unified comparison; the maximum gas production obtained from the inflow / outflow dynamic curves of each process in steps S3 to S5, the lower limit of the formation pressure corresponding to each process, and the minimum gas production after adopting each process; calculate the gas production area S and the formation pressure range Δp. r is the difference between the current formation pressure and the lower limit of the applicable pressure of each process, and the gas production range Δq. g is the difference between the maximum gas production and the minimum gas production of each process, and the gas production decline per unit formation pressure. , the gas production area per unit formation pressure. .

[0102] (7) According to the set comparison processes, including optimized tubing string, wellhead boosting, gas lift, foam drainage, and plunger, customize the scoring system and weighting system.

[0103] Further, the expression of the comprehensive decision-making model for gas drainage and production is:

[0104] (21);

[0105] In the formula, M is the comprehensive decision-making score for gas drainage and production, in points; η is the technical score of the process, in points; λ is the economic score of the process, in points; k is the weight of the technical score, dimensionless.

[0106] Among them, 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 secondary indicators in the technical part are the maximum gas production, the formation pressure range Δp. r , the gas production decline per unit formation pressure. , the gas production area S, the gas production area per unit formation pressure. , the lower limit of the formation pressure, with weights of 0.8, 0.8, 1, 1, 1, 1 respectively. The secondary indicators in the economic part are the one-time investment and the annual maintenance cost, with weights of 0.5 and 0.5 respectively. Then, according to the parameters obtained in step S6, conduct weighted calculation and normalization processing, and finally obtain the score. Define the process with the highest score as the optimal process.

[0107] Compared with the existing methods for determining gas drainage and production processes, the advantages of the present invention are as follows:

[0108] (1) By quantitatively analyzing the performance indicators of different processes, it is possible to intuitively compare the advantages and disadvantages of each process under different production conditions.

[0109] (2) By comprehensively considering technical and economic factors, the scientificity and accuracy of process selection are improved.

[0110] (3) The establishment of the weighted scoring system makes the process determination more objective and reasonable, helps to improve the exploitation efficiency and economic benefits of gas wells, and reduces production costs.

[0111] The above description is only the research idea of the present invention and is not intended to limit the present invention. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

Claims

1. A method for determining a gas well drainage gas production process, characterized in that: The following steps are involved: Step S1: Collect the downhole pipe string data and production data of the gas well, including wellbore structure, well inclination angle θ, pipe diameter D, gas-liquid ratio GLR, oil pressure p t , wellhead temperature T0, natural gas physical parameters, gas production index J, current formation pressure P r , gas phase relative density γ g and liquid relative density γ L ; Calculate gas phase superficial velocity and liquid phase superficial velocity; Step S2: draw the inflow / outflow dynamic curve under the current production conditions, use the gas well productivity empirical formula commonly used in engineering to calculate the gas well productivity under each process, and then use the friction coefficient in the Mukherjee-Brill model to calculate the wellbore pressure drop. Based on all the data collected in step S1, a series of gas production is given, the corresponding bottom hole flow pressure is calculated, and the outflow curve of the bottom hole flow pressure changing with the gas production is obtained. A series of bottom hole flow pressures are given, and the corresponding gas production is calculated to obtain the inflow curve of the gas production changing with the bottom hole flow pressure. It is determined whether the inflow / outflow curves intersect. If there is an intersection, it indicates that stable production is currently possible, otherwise it cannot be stably produced. Further, based on all the data collected in step S1, the gas well productivity empirical formula commonly used in engineering is used to calculate the gas well productivity, and the Mukherjee-Brill model is used to calculate the wellbore pressure drop. Step S3: Perform performance analysis on the optimal tubing string, wellhead pressurization and gas lift process; Step S4: for the foaming process, given a series of gas production and a concentration coefficient x of the foaming agent, the critical velocity of gas-liquid two-phase liquid film reversal is calculated, and the critical gas velocity of the foam film reversal is calculated based on the critical velocity of the gas-liquid two-phase liquid film reversal and the concentration coefficient x of the foaming agent, and then the bottom hole flow pressure is calculated based on the critical gas velocity of the foam film reversal; Step S5: For the plunger gas lift process, the minimum gas production applicable to the given plunger process is q gminPL According to the inflow / outflow curve drawn in step S2, keep the gas production index J unchanged, increase or decrease the formation pressure and draw the inflow curve under the formation pressure condition, so that the inflow curve is tangent to the outflow curve, connect the tangent point and the coordinate origin to obtain a straight line L, take the current formation pressure as the reference, reduce the formation pressure, and let P rPL1 Equal to the current formation pressure P r , given a series of formation pressures P rPL1 To P rPL , obtain the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions, and find out the gas production value corresponding to the intersection of the inflow curve and the straight line L under different formation pressure conditions; At present, the gas production at the intersection of the inflow curve and the straight line L under formation pressure conditions is the maximum gas production q corresponding to the plunger process gmaxPL The formation pressure corresponding to the lower limit of the applicable gas production of the given plunger process is the lower limit of the applicable formation pressure of the plunger process P rminPL ; Step S6: normalize different processes to the inflow / outflow dynamic curve with the optimal process conditions, obtain the operating output of each process under different formation pressure conditions, and then make a unified comparison; Step S7: Customize the scoring system and weighting system according to the set comparison process, including the optimal tubing string, wellhead pressurization, gas lift, bubble drainage, and plunger.

2. A method for determining a gas well drainage and gas production process according to claim 1, characterized in that: In step S6, the maximum gas production, the lower limit of the gas layer pressure corresponding to each process, and the minimum gas production after adopting each process are obtained from the inflow / outflow dynamic curves of each process in steps S3 to S5 by unifying the quantitative parameters; The gas production area S and gas layer pressure range Δp are calculated. r That is, the difference between the current formation pressure and the lower limit of the applicable pressure of each process, and the gas production range Δq g It is the difference between the maximum gas production and the minimum gas production of each process. The gas production decreases under unit gas layer pressure. , gas production area per unit gas layer pressure .

3. A method for determining a gas well drainage and gas production process according to claim 1, characterized in that: In step S7, the scoring system and weighting system are customized, and the expression of the comprehensive decision-making model for drainage and gas production is: Where, M is the comprehensive decision-making score of 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 the technical score, dimensionless; The first-level index is divided into technical part and economic part, with the weight of the technical part being 0.6 and the weight of the economic part being 0.4; The secondary indicators in the technical part are the maximum gas production and the gas layer pressure range Δp r , gas production decreases under unit gas layer pressure , gas production area S, gas production area under unit gas layer pressure , the lower limit of gas layer pressure, with weights of 0.8, 0.8, 1, 1, 1, 1 respectively. The secondary indicators in the economic part are one-time investment and annual maintenance cost, with weights of 0.5 and 0.5 respectively. Then, according to the parameters obtained in step S6, weighted calculation and normalization are performed to finally obtain a score, and the process with the highest score is defined as the optimal process.

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