Method for calculating liquid holdup of wellbore of high-pressure gas well

Abstract

The invention provides a high-pressure gas well wellbore liquid holdup calculation method, which comprises the following steps of: based on a drift flux model, introducing a dimensionless phase apparent velocity in a Farude similar quasi form to carry out pressure scaling; and the change rule of the liquid holdup along with the apparent velocity of the dimensionless phase is accurately represented through fitting of normal-pressure experimental test data in a wide gas-liquid velocity range, so that an effective method suitable for calculating the liquid holdup of the shaft of the high-pressure gas well is formed. According to the method, the key parameter is the multiplication coefficient of the dimensionless gas phase apparent velocity, and the distribution rule of gas-liquid two-phase flow in a wide liquid velocity range can be accurately captured, so that the method does not need complex drift parameter implicit calculation and gas-liquid two-phase flow pattern judgment on the basis of ensuring the high-low pressure pipe flow calculation precision, and the calculation accuracy of the high-low pressure pipe flow is improved. The method is simple in form and convenient to operate, provides a convenient and efficient gas well shaft liquid holdup prediction means for field operators and engineering technicians in the field of oil and gas field development, and has potential popularization and application value.

Description

TECHNICAL FIELD

[0001] The application belongs to the field of gas reservoir drainage gas recovery, and particularly relates to a high-pressure gas well wellbore liquid holdup calculation method. TECHNICAL BACKGROUND

[0002] Wellbore liquid holdup refers to the proportion of liquid in the wellbore of the target well section under the production state of the water-producing gas well to the total volume thereof, and is one of important parameters for gas-liquid two-phase pipe flow pressure drop calculation. Accurate prediction of the liquid holdup is the core technology for optimizing the production system and drainage and recovery process parameters of the gas well. During the development of oil and gas fields, there are a large number of wellbore gas-liquid two-phase flows of high-pressure gas wells, and it is difficult to measure the real liquid holdup. Large-scale physical simulation experiments are often used to measure the liquid holdup under normal pressure flow conditions by relying on conductivity probes, wire mesh sensors, electrical capacitance or resistance tomography, fast valve flow sampling and other technologies. Limited by the two-phase flow experimental simulation size, equipment pressure-bearing capacity and operation safety and other factors, it is also difficult to obtain high-pressure test data of the gas-liquid two-phase pipe flow with equal proportions or large scales. However, the existing high-pressure liquid holdup calculation methods directly apply normal pressure experimental data or use high-pressure numerical simulation results to fit parameters, and the obtained liquid holdup calculation correlations cannot represent high-pressure flow or need to carry out complex flow pattern classification and modeling calculation respectively, and the implicit iteration also increases the engineering application difficulty of the model.

[0003] The invention patent (CN113685165B) relates to a liquid holdup calculation formula for a low gas-liquid ratio high-pressure gas well, which is a function of gas-liquid ratio and gas deviation factor. Since the gas deviation factor involves complex pressure and temperature iterative calculation, and the method needs to judge the flow state, there is a large subjective error, and it is difficult to promote and apply in the field. The invention patent (CN120046544B) provides a high temperature and high pressure wellbore liquid holdup calculation method, which divides the flow into bubbly flow, slug flow, churn flow and annular flow, involves three relatively complex flow pattern transition boundaries and corresponds to four liquid holdup calculation expressions. In essence, it uses the conventional drift model calculation method, fixes the distribution coefficient and uses high-pressure numerical simulation results to fit four drift velocities, but the confidence of the Fluent software simulation results is not high. The invention patent (CN117371345A) discloses a gas well liquid holdup calculation method, which has a similar model form to the Hagedorn & Brown (1965) model commonly used in the field of oil and gas field development engineering. The model fitting coefficients are as many as 20, and there is a relatively complex high-order polynomial. In addition, the invention patent (CN117332723B) relates to a liquid holdup expression based on experimental gas-liquid apparent velocity fitting, the invention patent (CN117454063B) proposes a set of liquid holdup calculation related expressions for the six flow patterns in oil-gas-water three-phase flow, and the invention patent (CN114818535B) provides a three-parameter liquid holdup iterative calculation related expression based on flow pattern transition boundaries, which is only related to gas flow velocity. These methods all have problems such as pressure limitation, narrow application range or complex form.

[0004] Therefore, the present application provides a high-pressure gas well wellbore liquid holdup calculation method, which is based on the drift flux model, introduces the dimensionless phase apparent velocity in the form of the Froude similarity criterion, and is fitted by normal pressure experimental test data in a wide range of gas-liquid flow velocity to accurately represent the variation of liquid holdup with dimensionless phase apparent velocity. An effective method for calculating the wellbore liquid holdup of high-pressure gas wells is formed. This method ensures the accuracy of high and low pressure pipe flow calculation without complex drift parameter implicit calculation and gas-liquid two-phase flow state judgment, and has simple form and convenient operation. It provides a convenient and efficient gas well wellbore liquid holdup prediction means for field operators and engineering and technical personnel in the field of oil and gas field development, and has potential application value. SUMMARY

[0005] The purpose of the present application is to solve the problems of difficult acquisition of high-pressure gas well wellbore liquid holdup data and lack of theoretical calculation method or difficulty in engineering promotion and application, and to provide a simple method for calculating the wellbore liquid holdup of high-pressure gas wells, which provides a convenient and efficient gas well wellbore liquid holdup prediction means for field operators and engineering and technical personnel in the field of oil and gas field development.

[0006] The method for calculating the liquid holdup of a high-pressure gas well as described in this invention mainly includes the following steps: Step 1: Collect dynamic production parameters of the target gas well, identify the well pressure, temperature, gas production, and liquid production parameters, and calculate its wellbore fluid density and apparent velocity. The corresponding calculation formulas are as follows: (1.1) Formula for calculating gas density under different pressure conditions: , where ρ G Gas density (kg / m³) 3 ), γ g Let p be the relative density of natural gas (dimensionless), typically between 0.5 and 0.7; let Z be the natural gas deviation factor (dimensionless); and let R be the ideal gas constant (0.008314 MPa·m). 3 / (kmol·K)), where T is the temperature (K); (1.2) Calculation of apparent velocity of fluid in gas wellbore: apparent velocity of gas phase (v SG Calculation formula: Apparent flow rate of liquid phase (v) SL Calculation formula: , where v SG v SL These represent the apparent flow rates of the gas phase and the liquid phase (m / s), respectively. SC Q SL These are the gas production and liquid production of the gas well, respectively (m³). 3 / d), ρ SC Density of gas at normal pressure (kg / m³) 3 A is the cross-sectional area of ​​the pipe (m²) 2 ); Step 2: Using the proposed Froude similarity number, parameters such as phase density and pipe diameter are introduced to calculate the dimensionless phase velocity: Dimensionless apparent gas velocity (N GV Calculation formula: Dimensionless apparent flow rate of liquid phase (N) LV Calculation formula: Dimensionless gas phase true velocity (N) RGV Calculation formula: , where v G The actual gas flow rate is (m / s). H L ρ is the liquid holdup of the vertical section or cross-section (dimensionless); L Liquid density (1000 kg / m³) 3 g is the acceleration due to gravity (m / s²). 2 D is the inner diameter of the pipe (m).

[0007] Step 3: Construct the relationship between the dimensionless real airflow velocity and the dimensionless phase apparent velocity: ,in a, b, and c are experimental fitting coefficients (dimensionless).

[0008] Step 4: Based on the drift flux model, combine the relationships from Step 2 and Step 3 to obtain the formula for calculating the liquid holdup in the vertical section of the high-pressure gas well: .

[0009] Step 5: Add an angle correction term to the liquid holdup formula in Step 4 to calculate the liquid holdup at a specific inclination angle for a high-pressure gas well or horizontal pipeline: , where H θ Let c1, c2, and c3 be the liquid holdup (dimensionless) under a certain tilt angle θ (angle along the horizontal direction), and c1, c2, and c3 be the experimental fitting coefficients (dimensionless). Attached Figure Description

[0010] Figure 1 This is a technical roadmap of the present invention; Figure 2 The dimensionless true airflow velocity N RGV With dimensionless apparent gas velocity N GV A schematic diagram of the changing relationship; Figure 3 The dimensionless true airflow velocity N RGV With dimensionless liquid apparent flow rate N LV A diagram illustrating the changing relationships. Detailed Implementation

[0011] To make the objectives, technical solutions, and advantages of this invention clearer, the invention will be further described in detail below with reference to the accompanying drawings.

[0012] like Figure 1 As shown, Figure 1 This is a technical roadmap for the present invention. The present invention provides a method for calculating the liquid holdup of high-pressure gas wells, mainly based on a drift flux model, introducing flow similarity criteria, and constructing a new liquid holdup calculation model by combining the patterns of atmospheric pressure experimental test data. The core of this method is to construct a relationship between dimensionless real gas flow velocity and dimensionless apparent phase flow velocity based on experimental data covering a wide range of gas-liquid flow velocities. The experimental fitting coefficients involved can be determined through targeted experimental tests based on the gas well parameters of the target oil and gas field block. The model is then refitted based on the experimental test results to improve its adaptability to gas wells in specific production blocks and to increase calculation accuracy. Specifically, the method includes the following steps: (1) Collect the production parameters of the target gas well, determine the given average pressure and average temperature of the well section to be calculated, and calculate the gas density ρ. G Apparent flow rates v in the gas and liquid phasesSG v SL The liquid density here is assumed to be a fixed value of 1000 kg / m³, assuming that the gas well water is an incompressible fluid. 3 ; (2) Convert the calculated apparent velocities of the gas and liquid phases into dimensionless forms, and apply the basic two-phase flow relationship. Substitute into the dimensionless real airflow velocity expression After simplification, we can obtain the dimensionless form of the liquid holdup relationship. ; (3) Construct the relationship between dimensionless real air velocity and dimensionless phase apparent velocity: ,in a, b, and c are experimental fitting coefficients (dimensionless); (4) Substitute the dimensionless true gas flow rate expression constructed in step (3) into the liquid holdup relationship in step (2) to obtain the formula for calculating the liquid holdup of the vertical section of the high-pressure gas well: ; (5) Add an angle correction term to the liquid holdup formula in step (4) to calculate the liquid holdup under a specific inclination angle of the high-pressure gas well or horizontal pipeline: , where H θ Let c1, c2, and c3 be the liquid holdup (dimensionless) under a certain tilt angle θ (angle along the horizontal direction), and c1, c2, and c3 be the experimental fitting coefficients (dimensionless).

[0013] like Figure 2 As shown, Figure 2 The dimensionless true gas flow velocity NRGV varies with the dimensionless apparent gas flow velocity N. GV A schematic diagram showing the relationship between N and its variation. The experimental results show that N... RGV With N GV There are two possible relationships: one is that under lower fluid flow rates, N RGV With N GV It exhibits a clear quadratic relationship; secondly, under higher liquid flow rates, N RGV With N GV This exhibits a linear relationship. Therefore, a dimensionless real airflow velocity N was constructed. RGV The expression for the dimensionless apparent gas velocity (NGV) coefficient A in the relation consists of two terms. The first term captures the quadratic variation under low liquid flow rate conditions, and the second term captures the linear variation under high liquid flow rate conditions. The denominators of each term in the expression for parameter A are actually weighting coefficients for the liquid flow rate. At a given liquid flow rate, only one term in A plays a decisive role. The vertical axis N in the figure... RGV -N GV This makes the above-mentioned relationships more intuitive, and during the modeling process, -N GVThe terms can be moved to the quadratic terms or linear relationships that play a major role, such that N RGV With N GV The pattern of change remains unchanged.

[0014] like Figure 3 As shown, Figure 3 The dimensionless true airflow velocity N RGV With dimensionless liquid apparent flow rate N LV A schematic diagram showing the relationship between N and its variation. Under given airflow velocity conditions, N... RGV With N LV The relationship is quadratic, thus yielding the dimensionless true airflow velocity N. RGV The variation law of apparent flow rate of dimensionless liquid phase.

[0015] Compared with the shortcomings and deficiencies of existing technologies, the present invention has the following beneficial effects: (1) The liquid holdup calculation formula proposed in this invention achieves pressure scaling through the Froude similarity number, and is applicable to a wide range of gas-liquid flow velocities, which can characterize the wellbore flow conditions of high-pressure gas wells.

[0016] (2) The new liquid holdup calculation formula proposed in this invention does not require complex implicit calculation of drift parameters and judgment of gas-liquid two-phase flow pattern. It is simple in form and easy to operate.

[0017] (3) The key parameter A in this invention is related to the dimensionless phase apparent velocity, which can accurately capture the distribution law of gas-liquid two-phase flow in a wide liquid velocity range, avoid the iterative calculation of complex drift parameters in the drift model, and improve the model calculation accuracy.

[0018] Obviously, the above description is only an implementation idea 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 should be included within the protection scope of the present invention.

Claims

1. A method for calculating the liquid holdup rate of a high-pressure gas well, characterized in that, Includes the following steps: Step 1: Collect dynamic production parameters of the target gas well, identify the well pressure, temperature, gas production, and liquid production parameters, and calculate its wellbore fluid density and apparent velocity. The corresponding calculation formulas are as follows: (1.1) Formula for calculating gas density under different pressure conditions: , where ρ G Gas density (kg / m³) 3 ), γg is the relative density of natural gas (dimensionless), generally taken between 0.5 and 0.7, p is the pressure (MPa), Z is the natural gas deviation factor (dimensionless), and R is the ideal gas constant (0.008314 MPa·m). 3 / (kmol·K)), where T is the temperature (K); (1.2) Calculation of apparent velocity of fluid in gas wellbore: apparent velocity of gas phase (v SG Calculation formula: Apparent flow rate of liquid phase (v) SL Calculation formula: , where v SG v SL These represent the apparent flow rates of the gas phase and the liquid phase (m / s), respectively. SC Q SL These are the gas production and liquid production of the gas well, respectively (m³). 3 / d), ρ SC Density of gas at normal pressure (kg / m³) 3 A is the cross-sectional area of ​​the pipe (m²) 2 ); Step 2: Using the proposed Froude similarity number, parameters such as phase density and pipe diameter are introduced to calculate the dimensionless phase velocity: Dimensionless apparent gas velocity (N GV Calculation formula: ; Dimensionless apparent flow rate of liquid phase (N) LV Calculation formula: Dimensionless gas phase true velocity (N) RGV Calculation formula: , where v G The actual gas flow rate is (m / s). H L ρ is the liquid holdup of the vertical section or cross-section (dimensionless); L Liquid density (1000 kg / m³) 3 g is the acceleration due to gravity (m / s²). 2 D is the inner diameter of the pipe (m); Step 3: Construct the relationship between the dimensionless real airflow velocity and the dimensionless phase apparent velocity: ,in a, b, and c are experimental fitting coefficients (dimensionless); Step 4: Based on the drift flux model, combine the relationships from Step 2 and Step 3 to obtain the formula for calculating the liquid holdup in the vertical section of the high-pressure gas well: ; Step 5: Add an angle correction term to the liquid holdup formula in Step 4 to calculate the liquid holdup at a specific inclination angle for a high-pressure gas well or horizontal pipeline: , where H θ Let c1, c2, and c3 be the liquid holdup (dimensionless) under a certain tilt angle θ (angle along the horizontal direction), and c1, c2, and c3 be the experimental fitting coefficients (dimensionless).

Images