A method for predicting the kinetics of natural gas hydrate growth rate

Abstract

This invention discloses a kinetic prediction method for the growth rate of natural gas hydrates. The method includes: acquiring basic parameters such as temperature, pressure, salinity, water content, and fluid composition; establishing a high-precision equation of state to calculate the fugacity coefficients of each gas component; determining the activity coefficients of each gas component; calculating the chemical potential difference between free water and the empty hydrate cage, and between the hydrate and the empty hydrate cage, based on the fugacity and activity coefficients; calculating the hydrate growth rate based on the chemical potential difference; calculating the remaining sealing time based on the hydrate growth rate, and prompting the administrator to take tiered response measures. This invention constructs a comprehensive diffusion coefficient model that considers droplet diameter distribution, Reynolds number, and temperature field, achieving quantitative prediction of the hydrate growth rate in oil-water emulsion systems.

Description

Technical Field

[0001] This invention relates to the field of natural gas extraction technology, and in particular to a kinetic prediction method for the growth rate of natural gas hydrates. Background Technology

[0002] With the global demand for environmental protection and energy, natural gas hydrates have gradually gained attention as a new energy source. The high-pressure, low-temperature environment during natural gas production can easily generate large amounts of hydrates, leading to accidents such as blockages in natural gas extraction and transportation pipelines. Therefore, the prediction of natural gas hydrates is crucial in natural gas extraction and pipeline transportation. Existing technology 1 (ZL202111409499.8) designs equipment specifically for the detection and control of wellbore hydrates, while existing technology 2 (ZL 2024 10033413.3) predicts the growth range of wellbore hydrates. However, not only is the monitoring and prediction of the range of wellbore hydrates crucial, but the prediction of the hydrate growth rate is also essential. This determines the allowable time window from hydrate formation to blockage, providing important reference for oil and gas extraction engineers to adopt appropriate measures. Summary of the Invention

[0003] To address the shortcomings of existing methods, the present invention aims to provide a kinetic prediction method for the growth rate of natural gas hydrates.

[0004] To achieve the above technical objectives, the present invention adopts the following technical solution.

[0005] On the one hand, the present invention provides a kinetic prediction method for the growth rate of natural gas hydrates, comprising the following steps: Step 1: Obtain basic parameters; Step 2: Establish a high-precision equation of state to calculate the fugacity coefficients of each component gas. ; Step 3: Calculate the activity coefficients of each gas component. ; Step 4: Based on the fugacity coefficients of each component gas calculated in Step 2 and the activity coefficients of each gas component calculated in step three. Calculate the chemical potential difference between free water and the empty hydrate cage. And the chemical potential difference between hydrates and empty-shell hydrates. ; Step 5: Based on the chemical potential difference between free water and the empty hydrate cage And the chemical potential difference between hydrates and empty-shell hydrates. Calculate the growth rate of the hydrate; Step 6: Based on the hydrate growth rate, calculate the remaining time for the hydrate to completely seal the pipeline and prompt the administrator to take appropriate measures.

[0006] Furthermore, in step one, the basic parameters obtained include: obtaining the temperature, pressure, salinity, water content, mole fraction of fluid components (including CH4, C2H6, CO2, H2S, etc.), and pipe diameter of the target area (such as oil and gas well casing or natural gas pipeline) through on-site testing equipment, and obtaining the critical temperature and critical pressure of each gas component.

[0007] Furthermore, in step two, the gas fugacity coefficient The calculation model is as follows: ; Among them, the comparison volume V ir The calculation formula is as follows: ; In the formula, a i Z is a constant. i V is the gas compressibility factor. ir For comparison of volume, T ir For temperature comparison, T ic Critical temperature, K, P ic Critical pressure, MPa; V represents volume, m³. 3 .

[0008] Furthermore, in step three, the activity coefficient The calculation model is as follows: ; In the formula, and The two parameters and the three parameters are both functions of temperature and pressure.

[0009] Furthermore, in step four, the chemical potential difference between free water and the Airbus hydrate cage... The calculation method is as follows: ; ; In the formula: a w Let a be the activity of water in a water-rich liquid phase. In a system without inhibitors, the activity of water is approximately equal to that of water. When the temperature is below the freezing point, the activity of water, a... w =1; According to thermodynamic formulas, the molar enthalpy difference Δh between water in a completely empty hydrate lattice and the pure aqueous phase is... w The difference in specific heat capacity between water in a completely empty hydrate lattice and the pure aqueous phase It is expressed as follows: ; In the formula: The molar enthalpy difference between water in a completely empty hydrate lattice and the pure aqueous phase at time T0, in J / mol; denoted as T0, where is the difference in specific heat capacity between the completely empty hydrate lattice and the pure water phase, in J / (kg·K); b is the temperature coefficient of specific heat capacity. , , , Both b and b must be obtained through regression analysis of experimental data, and have different values ​​for different hydrate structures; Chemical potential difference between hydrates and empty-shell hydrates The calculation method is as follows: ; In the formula: R is the gas constant, taken as 8.314 J / (K·mol); T is the temperature, K; v i The number of type I pores for each water molecule; θ i The percentage of type I cavities occupied by guest molecules: ; In the formula: C i f is the Langmuir gas adsorption constant for guest molecules in type i holes; g (T, p) represents the gas fugacity (Pa) at temperature T and pressure p, which can be calculated using the above equation of state.

[0010] Empirical formula for calculating the Langmuir constant: ; In the formula: A i B i Empirical parameters for fitting experimental data.

[0011] Furthermore, in step five, the growth rate of the hydrate is calculated as follows: ; In the formula, This represents the molar volume of the hydrate. K i The overall diffusion coefficient is derived from the geometric diffusion coefficient k. d Dynamic diffusion coefficient k r and temperature diffusion coefficient k t The composition satisfies the following relationship: ; rad represents the experimental stirring speed; ; dw - remaining droplet diameter, d - initial droplet diameter; The relationship between Reynolds number Re and experimental stirring speed rad is as follows: ; Acr is the effective contact area between the hydrate and liquid water; its calculation method is as follows: ; is the normal distribution function of the nucleation diameter of hydrates, reflecting the number and rate of nucleation on the surface of water droplets.

[0012] Furthermore, this invention provides a kinetic prediction method for the growth rate of oil-water-gas natural gas hydrates, and also includes an experimental verification step.

[0013] Specifically, the prediction model for hydrate growth rate was validated through oil-water emulsion experiments.

[0014] Specifically, the gas-water interface experiment was used to verify the predictive model for hydrate growth rate.

[0015] Furthermore, in step six, based on the predicted hydrate growth rate and remaining time window for plugging according to the present invention, managers can take tiered preventative or remedial measures according to the specific value of the time window. When the predicted plugging time window is greater than 2 hours, there is ample time, and measures with less impact on production can be prioritized. These measures include injecting thermodynamic inhibitors (such as methanol or ethylene glycol, with an injection concentration typically of 10% to 60% by mass) or kinetic inhibitors (such as polyvinylpyrrolidone, with an injection concentration typically of 0.1% to 2% by mass) into the wellbore or pipeline to reduce the hydrate phase equilibrium temperature or delay crystal nucleus growth. Simultaneously, production system optimization methods such as adjusting oil and gas production or changing water cut can be combined to reduce the risk of hydrate formation at the source. When the predicted plugging time window is between 0.5 and 2 hours, the risk level increases, requiring rapid response measures. These include activating electric heating or hot water circulation systems (the heating power must ensure the pipe section temperature rises to 5-10°C above the hydrate phase equilibrium temperature within 30 minutes), or reducing the system pressure below the hydrate phase equilibrium pressure within 15-30 minutes through throttling, venting, etc. If a hydrate layer has formed but is not completely blocked, a pig can be immediately dispatched for mechanical removal, or a high-concentration solvent (such as methanol concentration above 80%) can be injected for chemical soaking and cleaning. When the predicted plugging time window is less than 0.5 hours and the risk is extremely high, emergency measures should be taken immediately, including emergency well shutdown, rapid venting and pressure reduction, activation of the emergency plan, and notification of upstream and downstream stakeholders to prepare for emergency repairs to ensure production safety. The above measures can be used individually or in combination, providing a flexible and operable emergency response plan for on-site operations.

[0016] In addition, a method for calculating hydrate distribution in wellbore is provided, including: Step 1: Input the production rate of the oil and gas well, the trajectory of the oil and gas well, the water cut, the temperature and pressure curve of the wellbore, the time step and the spatial step. Discretize the wellbore trajectory according to the spatial step and discretize the entire wellbore into multiple nodes. Step 2: Interpolate and calculate the temperature and pressure at each node of the wellbore; Step 3: Using the kinetic prediction method for the growth rate of oil-water-gas natural gas hydrates described in Example 1, calculate the hydrate growth and liquid water consumption at the bottom of the well within one time step. Step 4: Update the hydrate thickness of this node and the water content of the next node; Step 5: Determine if hydrates are blocking the wellbore. If yes, end the calculation and output the hydrate distribution in the wellbore. If no, return to Step 3 and calculate the hydrate growth of the next node from the bottom of the well upwards until the wellhead node is calculated. Step 6: Return to Step 3 and perform the next time step calculation until the preset time calculation is completed; In step five, determining whether hydrates are clogging the wellbore can be replaced by determining whether the thickness of the hydrates reaches a preset blocking threshold.

[0017] The beneficial technical effects of this invention are: (1) A comprehensive diffusion coefficient model with multi-factor coupling was constructed, which significantly improved the prediction accuracy. This invention constructs a comprehensive diffusion coefficient by coupling the geometric diffusion coefficient, dynamic diffusion coefficient, and temperature diffusion coefficient. It can simultaneously consider the synergistic effect of multiple factors such as droplet diameter distribution, stirring speed (Reynolds number), temperature field, and pressure field, overcoming the shortcomings of existing models that only consider a single factor or simple linear superposition. This model can more realistically reflect the complex dynamic process of hydrate growth in oil-water emulsions, and the prediction deviation can be controlled within 2%~8%, which is far superior to the prediction accuracy of traditional empirical models.

[0018] (2) Quantitative prediction of hydrate growth rate in oil-water two-phase systems has been achieved. Most existing hydrate kinetic models are designed for pure water-gas systems or porous media systems, and are difficult to apply directly to oil-water emulsion systems commonly found in oil and gas extraction and pipeline transportation. This invention enables a quantitative description of hydrate growth rate in water-in-oil or oil-in-water emulsions.

[0019] (3) It provides a quantitative basis for the hydrate blockage time window. This invention not only calculates the growth rate of hydrates, but also, in conjunction with the pipeline geometry, calculates the allowable time window from hydrate formation to pipeline blockage. This time window provides a quantitative basis for oil and gas extraction engineers to formulate inhibitor injection timing, pressure reduction plans, and mechanical cleaning plans, and can effectively avoid production stoppage accidents caused by hydrate blockage.

[0020] (4) The stability and reliability of the prediction results of this prediction method under different water content, different stirring speed and different temperature and pressure were verified by oil-water emulsion experiments. The gas-water interface experiments verified that this prediction method can be applied to both oil-water emulsion systems and wall growth systems, providing a unified technical tool for hydrate risk management in various engineering scenarios such as oil and gas wellbore, pipeline, and subsea production tree.

[0021] (5) Spatial distribution prediction of hydrate thickness in wellbore is achieved. This invention combines the prediction method with a wellbore discretization algorithm. By inputting actual engineering parameters such as oil and gas production, wellbore trajectory, temperature field, and pressure field, it can calculate the hydrate growth and hydrate layer thickness at different depths in the wellbore, forming a hydrate thickness distribution curve along the wellbore. This distribution information can provide a basis for accurately locating high-risk hydrate zones and optimizing inhibitor injection points.

[0022] (6) Dynamic tracking and early warning of hydrate growth are achieved. This invention uses a time-step iterative algorithm to dynamically track the growth process of hydrates over time and update the hydrate thickness and remaining water content at each node in real time. When the hydrate thickness reaches the preset blocking threshold, the system automatically outputs early warning information, giving on-site operators valuable emergency response time. Attached Figure Description

[0023] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0024] Figure 1 This is a flowchart illustrating the kinetic prediction process for the growth rate of natural gas hydrates in this invention.

[0025] Figure 2 This is a schematic diagram of the hydrate growth model in this invention.

[0026] Figure 3 This is a graph showing the growth rate of hydrates at different water contents (droplet sizes) in the embodiments of the present invention.

[0027] Figure 4 This is a graph showing the growth rate of hydrates at different Reynolds numbers (stirring speeds) in the embodiments of the present invention.

[0028] Figure 5 This is a growth rate diagram of hydrates at the gas-water interface in an embodiment of the present invention.

[0029] Figure 6 This is a flowchart illustrating the calculation of hydrate distribution in the wellbore in an embodiment of the present invention.

[0030] Figure 7 This is a diagram showing the thickness distribution of hydrates in the wellbore of a certain marine well in an embodiment of the present invention. Detailed Implementation

[0031] The details of the present invention can be more clearly understood by referring to the accompanying drawings and the description of specific embodiments. However, the specific embodiments of the present invention described herein are for illustrative purposes only and should not be construed as limiting the invention in any way. Under the teachings of this invention, those skilled in the art can conceive of any possible modifications based on the invention, and these should all be considered to fall within the scope of the invention.

[0032] Example 1 A kinetic prediction method for the growth rate of natural gas hydrates, the specific prediction steps are as follows: Step 1: Obtain basic parameters; Specifically, this includes obtaining the temperature, pressure, salinity, water content, mole fraction of fluid components (including CH4, C2H6, CO2, H2S, etc.), pipeline diameter, critical temperature of gas components, and critical pressure of the target area (such as oil and gas well shafts or natural gas pipelines) through on-site testing equipment.

[0033] Step 2: Establish a high-precision equation of state to calculate the fugacity coefficients of each component gas. ; Gas fugacity coefficient The calculation model is as follows: ; Among them, the comparison volume V ir The calculation formula is as follows: ;

[0034] In the formula, a i The constant Z takes values ​​as shown in Table 1. i V is the gas compressibility factor. ir For comparison of volume, T ir For temperature comparison, T ic Critical temperature, K, P ic Critical pressure, MPa; V represents volume, m³. 3 .

[0035] Table 1. Constant a i Value ; Step 3: Calculate the activity coefficients of each gas component. ; Activity coefficient The calculation model is as follows: ; In the formula, and The two parameters and the three parameters are both functions of temperature and pressure.

[0036] Specifically, based on the common components of natural gas, the activity coefficients of each gas component are calculated and expressed as follows: ; In formulas (4)-(8), C i The recommended values ​​are shown in Table 2.

[0037] Table 2 C i Recommended Values ​​Table ; Step 4: Based on the fugacity coefficients of each component gas calculated in Step 2 and the activity coefficients of each gas component calculated in step three. Calculate the chemical potential difference between free water and the empty hydrate cage. And the chemical potential difference between hydrates and empty-shell hydrates. .

[0038] Chemical potential difference between free water and Airbus hydrate cage The calculation method is as follows: ; In the formula: a w Let be the activity of water in the water-rich liquid phase. In a system without inhibitors, the activity of water is approximately equal to that of water. When the temperature is below the freezing point, the activity of water, 'a'... w =1.

[0039] According to thermodynamic formulas, the molar enthalpy difference Δh between water in a completely empty hydrate lattice and the pure aqueous phase is... w It can be represented as follows: ; In the formula: The molar enthalpy difference between water in a completely empty hydrate lattice and the pure aqueous phase at time T0, in J / mol; denoted as T0, where is the difference in specific heat capacity between the completely empty hydrate lattice and the pure water phase, in J / (kg·K); b is the temperature coefficient of specific heat capacity. , , , Both b and b must be obtained through regression analysis of experimental data, and have different values ​​for different hydrate structures, as shown in Table 3.

[0040] Table 3 Regression constants , , , and the value of b ; Chemical potential difference between hydrates and empty-shell hydrates The calculation method is as follows: ; In the formula: R is the gas constant, taken as 8.314 J / (K·mol); T is the temperature, K; v i The number of type I pores for each water molecule; θ i The percentage of type I cavities occupied by guest molecules: ; In the formula: C i f is the Langmuir gas adsorption constant for guest molecules in type i holes; g (T, p) represents the gas fugacity (Pa) at temperature T and pressure p, which can be calculated using the equation of state.

[0041] Empirical formula for calculating the Langmuir constant: ; In the formula: A i B i The empirical parameters for fitting the experimental data are shown in Table 4.

[0042] Table 4 Calculation of Langmuir constant C i The empirical constant (260~300 K) ; Step 5: Based on the chemical potential difference between free water and the empty hydrate cage And the chemical potential difference between hydrates and empty-shell hydrates. Calculate the growth rate of the hydrate; The growth rate of hydrates is calculated as follows: ; In the formula, This represents the molar volume of the hydrate. K i The overall diffusion coefficient is derived from the geometric diffusion coefficient k. d Dynamic diffusion coefficient k r and temperature diffusion coefficient k t The composition satisfies the following relationship: ; rad represents the experimental stirring speed; ; dw - remaining droplet diameter, d - initial droplet diameter.

[0043] The relationship between Reynolds number Re and experimental stirring speed rad is as follows: ; Acr is the effective contact area between the hydrate and liquid water; its calculation method is as follows: ; is the normal distribution function of the nucleation diameter of hydrates, reflecting the number and rate of nucleation on the surface of water droplets.

[0044] Step 6: Based on the hydrate growth rate, calculate the remaining time for the hydrate to seal the entire pipeline and prompt the administrator to take appropriate measures.

[0045] Example 2 The growth rate of hydrates was verified through oil-water emulsion experiments.

[0046] The experimental procedure is as follows: a three-phase mixture of gas, water, and oil is stirred to form a stable suspension emulsion. By controlling the temperature and allowing the system to be under a certain initial pressure, hydrates are induced to form. The amount of gas consumed is recorded, and the relationship between the amount of hydrates formed and time is calculated. The experimental data is then compared with the model data to correct the model.

[0047] Specifically, for three-phase mixtures of gas, water, and oil with different water contents, stable suspensions of different diameters are formed after thorough stirring. The growth rate of hydrates is determined by measuring the diameter distribution of different droplets, and the experimental data are compared with model data.

[0048] Specifically, the mixture was thoroughly stirred at the same water content to form a stable suspension. During hydrate formation, the growth of the hydrate was disturbed by stirring at different speeds to create different disturbance conditions. The growth rate of the hydrate was recorded. Different stirring speeds can be converted into different Reynolds number conditions. The growth rate of the hydrate was then calculated and compared with the experimental data.

[0049] Example 3 The growth rate of hydrates was verified by air-water interface experiments.

[0050] Through gas-water interface experiments, the amount of gas consumed during hydrate growth was measured under different temperatures and pressures, thereby calculating the amount of hydrate generated. The result was then compared with the hydrate generation calculated by the model to validate the model.

[0051] Example 4 A method for calculating hydrate distribution in wellbore, such as Figure 6 As shown.

[0052] Step 1: Input the production rate of the oil and gas well, the trajectory of the oil and gas well, the water cut, the temperature and pressure curve of the wellbore, the time step and the spatial step. Discretize the wellbore trajectory according to the spatial step and discretize the entire wellbore into multiple nodes.

[0053] Step 2: Interpolate and calculate the temperature and pressure at each node of the wellbore.

[0054] Step 3: Using the kinetic prediction method for natural gas hydrate growth rate in Example 1, calculate the hydrate growth and liquid water consumption at the bottom of the well within one time step.

[0055] Step 4: Update the hydrate thickness of this node and the water content of the next node.

[0056] Step 5: Determine if hydrates are blocking the wellbore. If so, end the calculation and output the hydrate distribution in the wellbore. If not, return to Step 3 and calculate the hydrate growth of the next node from the bottom of the well upwards until the wellhead node is calculated.

[0057] Step 6: Return to Step 3 and perform the next time step calculation until the preset time calculation is completed.

[0058] Specifically, in step five, determining whether hydrates are blocking the wellbore can be replaced by determining whether the thickness of the hydrates reaches a preset blocking threshold.

[0059] Furthermore, the preset blocking threshold can be 2 / 3 or 4 / 5 of the pipe's inner diameter.

[0060] Specifically, the production of a certain well in a certain sea area is 120m³. 3 / d, the calculation results of its wellbore hydrate distribution are as follows Figure 7 As shown.

[0061] Although specific embodiments of the present invention have been described in detail with reference to the accompanying drawings, this should not be construed as limiting the scope of protection of this patent. Various modifications and variations that can be made by those skilled in the art without inventive effort within the scope described in the claims still fall within the scope of protection of this patent.

Claims

1. A kinetic prediction method for the growth rate of natural gas hydrates, characterized in that, Includes the following steps: Step 1: Obtain basic parameters; Step 2: Establish a high-precision equation of state to calculate the fugacity coefficients of each component gas. ; Step 3: Calculate the activity coefficients of each gas component. ; Step 4: Based on the fugacity coefficients of each component gas calculated in Step 2 and the activity coefficients of each gas component calculated in step three. Calculate the chemical potential difference between free water and the empty hydrate cage. And the chemical potential difference between hydrates and empty-shell hydrates. ; Step 5: Based on the chemical potential difference between free water and the empty hydrate cage And the chemical potential difference between hydrates and empty-shell hydrates. Calculate the growth rate of the hydrate; Step 6: Based on the hydrate growth rate, calculate the remaining time for the hydrate to completely seal the pipeline and prompt the administrator to take appropriate measures.

2. The prediction method according to claim 1, characterized in that: In step one, the basic parameters obtained include: temperature, pressure, mineralization, water content, mole fraction of fluid components, pipe diameter, critical temperature and critical pressure of each gas component in the target area, obtained through on-site testing equipment.

3. The prediction method according to claim 1, characterized in that: Gas fugacity coefficient The calculation model is as follows: ； Among them, the comparison volume V ir The calculation formula is as follows: ； In the formula, a i Z is a constant. i V is the gas compressibility factor. i,r For comparison of volume, T i,r For temperature comparison, T ic Critical temperature, K, P ic Critical pressure, MPa; V represents volume, m³. 3 .

4. The prediction method according to claim 1, characterized in that: In step three, the activity coefficient The calculation model is as follows: ； In the formula, and The two parameters and the three parameters are both functions of temperature and pressure.

5. The prediction method according to claim 1, characterized in that: In step four, the chemical potential difference between free water and the Airbus hydrate cage... The calculation method is as follows: ； In the formula: a w The activity of water in a water-rich liquid phase is given by α, where the activity of water in a system without inhibitors is approximately equal to that of water. When the temperature is below the freezing point, the activity of water, α, is... w =1; The molar enthalpy difference Δh between water in a completely empty hydrate lattice and the pure aqueous phase w The difference in specific heat capacity between water in a completely empty hydrate lattice and the pure aqueous phase It is expressed as follows: ； In the formula: The molar enthalpy difference between water in a completely empty hydrate lattice and the pure aqueous phase at time T0, in J / mol; denoted as T0, representing the difference in specific heat capacity between the completely empty hydrate lattice and the pure water phase, in J / (kg·K); b is the temperature coefficient of specific heat capacity. Chemical potential difference between hydrates and empty-shell hydrates The calculation method is as follows: ； In the formula: R is the gas constant, taken as 8.314 J / (K·mol); T is the temperature, K; v i The number of type I pores for each water molecule; θ i The percentage of type I cavities occupied by guest molecules: ； In the formula: C i Let be the Langmuir gas adsorption constant of the guest molecule in type i holes; f g (T, p) represents the gas fugacity (Pa) at temperature T and pressure p, calculated directly using the equation of state.

6. The prediction method according to claim 1, characterized in that: In step five, the growth rate of the hydrate is calculated as follows: ； In the formula, This represents the molar volume of the hydrate. K i The overall diffusion coefficient is derived from the geometric diffusion coefficient k. d Dynamic diffusion coefficient k r and temperature diffusion coefficient k t The composition satisfies the following relationship: ； rad represents the experimental stirring speed; ； dw - remaining droplet diameter, d - initial droplet diameter; The relationship between Reynolds number Re and experimental stirring speed rad is as follows: ； Acr is the effective contact area between the hydrate and liquid water; its calculation method is as follows: ； is the normal distribution function of the nucleation diameter of hydrates, reflecting the number and rate of nucleation on the surface of water droplets.

7. The prediction method according to claim 1, characterized in that: In step six, the remaining time for the hydrate to block the entire pipeline is calculated based on the hydrate growth rate, and the administrator is prompted to take corresponding measures, including: injecting thermodynamic or kinetic inhibitors into the wellbore or pipeline, starting an electric heating or hot water circulation system, mechanically removing the hydrate, and injecting high-concentration solvents for chemical soaking and cleaning, based on the predicted blocking time window.

8. The prediction method according to claim 1, characterized in that: It also includes experimental verification steps, which verify the method for predicting the growth rate of hydrates through oil-water emulsion experiments.

9. The prediction method according to claim 1, characterized in that: It also includes experimental verification steps, which verify the method for predicting hydrate growth rate through air-water interface experiments.

10. A method for calculating the distribution of hydrates in a wellbore, characterized in that, Including the following steps: Step 1: Input the production rate of the oil and gas well, the trajectory of the oil and gas well, the water cut, the temperature and pressure curve of the wellbore, the time step and the spatial step. Discretize the wellbore trajectory according to the spatial step and discretize the entire wellbore into multiple nodes. Step 2: Interpolate and calculate the temperature and pressure at each node of the wellbore; Step 3: Calculate the amount of hydrate growth and the amount of liquid water consumed at the bottom of the well within one time step using the kinetic prediction method for the growth rate of natural gas hydrate as described in any one of claims 1-7. Step 4: Update the hydrate thickness of this node and the water content of the next node; Step 5: Determine if hydrates are blocking the wellbore. If yes, end the calculation and output the hydrate distribution in the wellbore. If no, return to Step 3 and calculate the hydrate growth of the next node from the bottom of the well upwards until the wellhead node is calculated. Step 6: Return to Step 3 and perform the next time step calculation until the preset time calculation is completed.

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