A calculation method, device and medium for determining a leakage position of an oil pipe of an ultra-deep gas well

Abstract

The present application relates to the technical field of oil production engineering, in particular to a kind of calculation method, equipment and medium for determining the leakage position of oil pipe of superdeep gas well.The method includes first calculating the temperature and pressure distribution in wellbore according to wellbore gas flow model.Secondly, calculate the gas leakage rate using the gas leakage equation, and obtain a series of pressure change curves of different leakage point positions and leakage hole areas by combining with the continuous casing pressure calculation model.Thirdly, use the logarithmic function to fit the pressure change curve, and establish the relationship chart between the leakage point position and the fitting coefficient;Logarithmic fitting is carried out on the actual pressure curve to obtain the actual fitting coefficient.Finally, in the relationship chart, find the leakage point position corresponding to the actual fitting coefficient to complete the identification of the leakage position of oil pipe.The method has the characteristics of simple operation and rapid identification, and provides effective guidance for determining the leakage position of oil pipe.

Description

Technical Field

[0001] This invention relates to the field of oil production engineering technology, specifically to a calculation method, equipment, and medium for determining the location of leaks in ultra-deep gas well tubing. Background Technology

[0002] Tubing is a crucial channel for transporting oil and gas from the bottom of the well to the surface. However, during production, tubing is inevitably subjected to high temperatures, high pressures, and highly corrosive media in the wellbore, leading to corrosion, perforation, stress cracking, and other damage. When the integrity of the tubing is compromised, normally transporting high-pressure gas will leak into the tubing-casing annulus through the failure site, accumulating at the wellhead and causing an increase in annular pressure, posing a serious threat to the safety and economics of oil and gas extraction.

[0003] Currently, various methods for detecting oil pipe leaks have been proposed and applied. For example, non-destructive testing techniques, including ultrasonic, noise, and isotope detection, can comprehensively inspect oil pipes to find potential leak points. However, these methods all require the insertion of corresponding testing tools into the wellbore, affecting the normal production of the gas well.

[0004] Monitoring casing pressure data is a routine operation in oil and gas production. Gas leakage is closely related to changes in casing pressure. Therefore, if we can determine whether there is a leak in the oil pipe and locate the leak by analyzing casing pressure data, it will help improve the efficiency of oil and gas extraction and reduce operating costs.

[0005] Therefore, there is an urgent need for a calculation method, equipment, and medium to determine the location of leaks in ultra-deep gas well tubing. Summary of the Invention

[0006] To avoid the aforementioned problems in the prior art, the purpose of this invention is to provide a calculation method, equipment, and medium for determining the location of leaks in ultra-deep gas well tubing.

[0007] The invention provides the following technical solution: a calculation method for determining the location of a leak in an ultra-deep gas well tubing, comprising the following steps:

[0008] S1: Collect basic and production data from gas wells;

[0009] S2: Establish a wellbore gas flow model based on the gas well's basic and production data, and calculate the pressure and temperature distribution within the wellbore;

[0010] S3: Based on the pressure and temperature inside the wellbore, a continuous casing pressure model is established. Using the gas leakage equation, assuming different leakage locations and leakage orifice areas, a series of pressure change curves with different leakage locations and leakage orifice areas are obtained.

[0011] S4: Use a logarithmic function to fit the pressure change curve obtained in step S3, and establish a graph showing the relationship between the leak location and the fitting coefficient.

[0012] S5: Perform logarithmic fitting on the actual pressure curve to obtain the actual fitting coefficients;

[0013] S6: In the relationship diagram, find the location of the leak point corresponding to the actual fitting coefficient and identify the location of the oil pipe leak.

[0014] The present invention is further configured such that, in step S2, the wellbore gas flow model is:

[0015]

[0016] In the formula, P f T represents the pressure of the gas inside the oil pipe, in MPa; f v represents the temperature of the gas inside the oil pipe, in °C. f The velocity of the gas inside the oil pipe is m / s; g is the acceleration due to gravity, m / s². 2 θ is the well inclination angle, in rad; f w It is the frictional force between the gas and the pipe wall, N; C JF It is the Joule-Thomson coefficient, K / Pa; c pf q is the specific heat capacity of the gas, J / (kg·K); q is the heat flux density, W / m³. 3 ;ρ f The density of the gas inside the oil pipe, kg / m 3 .

[0017] The present invention is further configured such that step S3 specifically involves establishing a continuous casing pressure model under leakage conditions based on the general calculation formula for annular pressure:

[0018]

[0019] Among them, △P an The annular pressure, which manifests as continuous casing pressure under leakage conditions, is measured in MPa; ΔV L m is the change in fluid volume. 3 k represents the compressibility of the fluid, in MPa. -1 V L m is the fluid volume. 3 ;

[0020] The gas leakage rate is calculated using the gas leakage equation, and the continuous casing pressure model is solved; the leakage location h is used as the starting point for each step. d and leakage hole area A o Using the variable as the variable, establish the relationship curves between annular pressure and leakage location, and between annular pressure and leakage orifice area.

[0021] The present invention is further configured such that the utilization of the gas leakage equation specifically refers to:

[0022]

[0023] Where, m g It is the mass flow rate of the gas leak, kg / s; C d It is the flow coefficient, dimensionless; A o It is the area of ​​the leak hole, m 2 ;P fd and P ad The pressure at the leak inlet and outlet is MPa; ρ g It is the gas density at the leak point, kg / m³ 3 γ is the gas adiabatic index, dimensionless; CRE is the critical flow pressure ratio of the gas, dimensionless.

[0024] In the initial state, P ad This corresponds to the annular liquid column pressure at the leak location; during a gas leak, P ad The increase will be due to the ongoing gas leak and the duration of the leak:

[0025]

[0026] In the formula, ρ L It is the density of the annular fluid, kg / m³ 3 h d t is the location of the leak, m; t is the time of gas leakage, d.

[0027] Based on the law of conservation of mass, the mass flow rate of the gas at the leak location is converted into the volume accumulated at the wellhead, ΔV. L It is expressed as follows:

[0028]

[0029] Where R is the gas constant, J / (kg·℃); M g T is the molar mass of a gas, in g / mol. an is the annular temperature, ℃; solve the continuous casing pressure model under leakage conditions according to the above formula.

[0030] The present invention is further configured such that, in step S4, the pressure change curve at the leakage location and the pressure change curve at the leakage hole area obtained in step S3 are fitted by a function according to the following formula to obtain the fitting coefficients corresponding to different leakage locations, and a relationship curve chart is drawn.

[0031] △P an =A p lnt+B p

[0032] Among them, A p and B p These are the correlation coefficients in the logarithmic function.

[0033] The present invention also includes an electronic device, the electronic device comprising:

[0034] Memory, which stores executable instructions;

[0035] A processor that executes the executable instructions in the memory to implement the above-described calculation method for determining the location of a leak in an ultra-deep gas well tubing.

[0036] A computer-readable storage medium storing a computer program that, when executed by a processor, implements a calculation method for determining the location of a leak in an ultra-deep gas well tubing.

[0037] In summary, the beneficial effects of the above-mentioned technical solution of the present invention are as follows:

[0038] This invention addresses the issue of tubing leakage in ultra-deep gas wells. Based on a predictive model of annular pressure caused by leakage, it calculates annular pressure curves for different leakage locations and areas, establishes a leakage location relationship chart, and finally uses casing pressure monitoring data to pinpoint the leakage location in the tubing. This helps improve efficiency and reduce operating costs in the oil and gas extraction process. Attached Figure Description

[0039] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0040] Figure 1 Flowchart of the calculation method for determining the location of leaks in ultra-deep gas well tubing.

[0041] Figure 2 This is a profile of the temperature distribution inside the wellbore.

[0042] Figure 3 This is a profile of the pressure distribution inside the wellbore.

[0043] Figure 4 This relates the location of the tubing leak to the continuous casing pressure.

[0044] Figure 5 This represents the relationship between the leakage area of ​​the oil pipe and the continuous casing pressure.

[0045] Figure 6 This is a monitoring curve of the tubing-casing annular pressure.

[0046] Figure 7 This is a graph showing the fitting coefficient relationship between the leakage location and leakage area obtained in Example 1. Detailed Implementation

[0047] To enable those skilled in the art to better understand the technical solutions of the present invention, the technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings. Based on the embodiments of the present invention, other similar embodiments obtained by those skilled in the art without creative effort should all fall within the scope of protection of the present invention.

[0048] The present invention will be further described below with reference to the accompanying drawings and preferred embodiments.

[0049] Example 1:

[0050] like Figure 1 As shown in the preferred embodiment of the present invention, a calculation method for determining the location of a leak in an ultra-deep gas well tubing includes the following steps:

[0051] S1: Collect basic and production data for the gas well. Basic data mainly includes the depth and inner / outer diameters of the tubing, casing, and cement sheath, as well as the location of the packer. Production parameters mainly include temperature, pressure, and production rate.

[0052] S2: Based on the gas well's basic and production data, establish a wellbore gas flow model to calculate the pressure and temperature distribution within the wellbore; and verify the model using measured data. The results are as follows: Figures 2-3 As shown.

[0053] The wellbore gas flow model is as follows:

[0054]

[0055] In the formula, P f T represents the pressure of the gas inside the oil pipe, in MPa; f v represents the temperature of the gas inside the oil pipe, in °C. f The velocity of the gas inside the oil pipe is m / s; g is the acceleration due to gravity, m / s². 2 θ is the well inclination angle, in rad; f w It is the frictional force between the gas and the pipe wall, N; C Jf It is the Joule-Thomson coefficient, K / Pa; c pf q is the specific heat capacity of the gas, J / (kg·K); q is the heat flux density, W / m³. 3 ;ρ f The density of the gas inside the oil pipe, kg / m 3 .

[0056] S3: Based on the pressure and temperature inside the wellbore, a continuous casing pressure model is established. Using the gas leakage equation, assuming different leakage locations and leakage orifice areas, a series of pressure change curves with different leakage locations and leakage orifice areas are obtained.

[0057] Based on the general formula for calculating annular pressure, a continuous casing pressure model under leakage conditions is established:

[0058] The general calculation method for annular pressure is shown in the following formula:

[0059]

[0060] Where α and k represent the coefficients of thermal expansion of the fluid, respectively, in °C. -1 Compression coefficient, MPa -1 ;ΔP an ΔT an , ΔV ann and ΔV L These represent: annular pressure (MPa); annular temperature (°C); and annular volume (m³). 3 Fluid volume change, m 3 ;

[0061] It can be seen that the main influencing factors of annular pressure include annular temperature, annular volume, and annular fluid volume. When the well barrier is intact, the annulus between the tubing and casing is a closed space, and the change in annular fluid volume is zero. Therefore, the annular pressure is mainly caused by the thermal expansion effect of the fluid, manifesting as annular thermal expansion pressure. This paper addresses the tubing leakage problem, i.e., the well barrier integrity is compromised, the tubing and casing are connected, and the annulus becomes an open space, making it difficult to maintain the thermal expansion effect of the fluid. At the same time, high-pressure gas from the tubing enters the annulus, causing a change in the annular fluid volume, and the annular pressure manifests as continuous casing pressure. Therefore, the above formula can be simplified to:

[0062]

[0063] Among them, △P an The annular pressure, which manifests as continuous casing pressure under leakage conditions, is measured in MPa; ΔV L m is the change in fluid volume. 3 k represents the compressibility of the fluid, in MPa. -1 V L m is the fluid volume. 3 ;

[0064] The source of the annular fluid volume change is the high-pressure gas that leaks into the annulus from the tubing; therefore, obtaining the gas leakage rate is crucial for the calculation. The method for calculating the gas leakage rate is as follows:

[0065]

[0066] Where, m g It is the mass flow rate of the gas leak, kg / s; C d It is the flow coefficient, dimensionless; A o It is the area of ​​the leak hole, m 2 ;P fd and P ad The pressure at the leak inlet and outlet is MPa; ρ g It is the gas density at the leak point, kg / m³ 3 γ is the gas adiabatic index, which is dimensionless; CRE is the pressure at which the gas reaches critical flow, which is dimensionless.

[0067] Once the leak location is determined, P fd It can be obtained according to the formula in step S2. In the initial state, P ad This corresponds to the annular liquid column pressure at the leak location; during a gas leak, P ad The increase will be due to the ongoing gas leak and the duration of the leak:

[0068]

[0069] In the formula, ρ L It is the density of the annular fluid, kg / m³ 3 h d t is the location of the leak, m; t is the time of gas leakage, d.

[0070] Based on the law of conservation of mass, the mass flow rate of the gas at the leak location is converted into the volume accumulated at the wellhead, ΔV. L It is expressed as follows:

[0071]

[0072] Where R is the gas constant, J / (kg·℃); M g T is the molar mass of a gas, in g / mol. an The annular temperature is ℃. The continuous casing pressure model under leakage conditions is solved using the above formula, but there are two fundamental unknowns in the formula: the leakage location h in the tubing. d and leakage area A o Therefore, assuming a series of different leakage locations and leakage areas, the relationship curves between annular pressure (continuous casing pressure) and the two were obtained, as shown in the figure. Figures 4-5 As shown.

[0073] S4: Fit the pressure change curve obtained in step S3 using a logarithmic function to establish a graph showing the relationship between the leak location and the fitting coefficients; for example... Figure 7 As shown.

[0074] According to the following formula, the pressure change curve at the leakage location and the pressure change curve at the leakage hole area obtained in step S3 are fitted by a function to obtain the fitting coefficients corresponding to different leakage locations, and the relationship curve is plotted.

[0075] △P an =A p lnt+B p

[0076] Among them, A p and B p These are the correlation coefficients in the logarithmic function.

[0077] S5: As Figure 6 As shown, a logarithmic fit was performed on the actual pressure curve to obtain the actual fit coefficient A. P =6.56, R 2 =0.9791.

[0078] △P an =6.56lnt + 2.19

[0079] S6: In the relationship diagram, find the location of the leak point corresponding to the actual fitting coefficient, and identify the location h of the oil pipe leak. d =4866m.

[0080] Example 2:

[0081] The present invention also includes an electronic device, the electronic device comprising:

[0082] Memory, which stores executable instructions;

[0083] A processor that executes the executable instructions in the memory to implement the above-described calculation method for determining the location of a leak in an ultra-deep gas well tubing.

[0084] Example 3:

[0085] A computer-readable storage medium storing a computer program that, when executed by a processor, implements the aforementioned calculation method for determining the location of a leak in an ultra-deep gas well tubing.

[0086] The above description is merely a preferred embodiment of the present invention. The scope of protection of the present invention is not limited to the above embodiments. All technical solutions falling within the scope of the present invention's concept are within the scope of protection of the present invention. It should be noted that for those skilled in the art, any improvements and modifications made without departing from the principles of the present invention should also be considered within the scope of protection of the present invention.

Claims

1. A calculation method for determining the location of a leak in an ultra-deep gas well tubing, characterized in that, Includes the following steps: S1: Collect basic and production data from gas wells; S2: Establish a wellbore gas flow model based on the gas well's basic and production data, and calculate the pressure and temperature distribution within the wellbore; S3: Based on the pressure and temperature inside the wellbore, a continuous casing pressure model is established. Using the gas leakage equation, assuming different leakage locations and leakage hole areas, a series of pressure change curves with different leakage locations and leakage hole areas are obtained. S4: Use a logarithmic function to fit the pressure change curve obtained in step S3, and establish a graph showing the relationship between the leak location and the fitting coefficient. S5: Perform logarithmic fitting on the actual pressure curve to obtain the actual fitting coefficients; S6: In the relationship diagram, find the location of the leak point corresponding to the actual fitting coefficient and identify the location of the oil pipe leak.

2. The calculation method for determining the location of a leak in an ultra-deep gas well tubing according to claim 1, characterized in that, In step S2, the wellbore gas flow model is as follows: In the formula, P f T represents the pressure of the gas inside the oil pipe, in MPa; f v represents the temperature of the gas inside the oil pipe, in °C. f The velocity of the gas inside the oil pipe is m / s; g is the acceleration due to gravity, m / s². 2 θ is the well inclination angle, in rad; f w It is the frictional force between the gas and the pipe wall, N; C JF It is the Joule-Thomson coefficient, K / Pa; c pf q is the specific heat capacity of the gas, J / (kgVK); q is the heat flux density, W / m³. 3 ;ρ f It is the density of the gas inside the oil pipe, kg / m³ 3 .

3. The calculation method for determining the location of a leak in an ultra-deep gas well tubing according to claim 2, characterized in that, Step S3 specifically involves establishing a continuous casing pressure model under leakage conditions based on the general calculation formula for annular pressure: Among them, △P an ΔV is the annular pressure, MPa; L m is the change in fluid volume. 3 k represents the fluid's compressibility coefficient, in MPa. -1 V L m is the fluid volume. 3 ; The gas leakage rate is calculated using the gas leakage equation, and the continuous casing pressure model is solved; the leakage location h is used as the starting point for each step. d and leakage hole area A o Using the variable as the variable, establish the relationship curves between annular pressure and leakage location, and between annular pressure and leakage orifice area.

4. The calculation method for determining the location of a leak in an ultra-deep gas well tubing according to claim 3, characterized in that, The specific application of the gas leakage equation is as follows: Where, m g It is the mass flow rate of the gas leak, kg / s; C d It is the flow coefficient, dimensionless; A o It is the area of ​​the leak hole, m 2 ;P fd and P ad The pressure at the leak inlet and outlet is MPa; ρ g It is the gas density at the leak point, kg / m³ 3 γ is the gas adiabatic index, dimensionless; CRE is the critical flow pressure ratio of the gas, dimensionless. In the initial state, P ad This corresponds to the annular liquid column pressure at the leak location; during a gas leak, P ad The increase will be due to the ongoing gas leak and the duration of the leak: In the formula, ρ L It is the density of the annular fluid, kg / m³ 3 h d The location of the leak is m; t is the time of gas leakage, d; Based on the law of conservation of mass, the mass flow rate of the gas at the leak location is converted into the volume accumulated at the wellhead, ΔV. L It is expressed as follows: Where R is the gas constant, J / (kg·℃); M g T is the molar mass of a gas, in g / mol. an is the annular temperature, ℃; solve the continuous casing pressure model under leakage conditions according to the above formula.

5. The calculation method for determining the location of a leak in an ultra-deep gas well tubing according to claim 4, characterized in that, In step S4, the pressure change curve at the leakage location and the pressure change curve at the leakage hole area obtained in step S3 are fitted with a function according to the following formula to obtain the fitting coefficients corresponding to different leakage locations, and the relationship curve is plotted. △P an =A p lnt+B p Among them, A p and B p These are the correlation coefficients in the logarithmic function.

6. An electronic device, characterized in that, The electronic device includes: Memory, which stores executable instructions; A processor that executes the executable instructions in the memory to implement a calculation method for determining the location of a leak in an ultra-deep gas well tubing, as described in any one of claims 1-5.

7. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores a computer program that, when executed by a processor, implements a calculation method for determining the location of a leak in an ultra-deep gas well tubing, as described in any one of claims 1-5.

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