Method for preventing formation of natural gas hydrate

Abstract

The invention discloses a method for preventing formation of natural gas hydrates, which comprises the following steps: calculating corresponding wellhead pressures when different water quantities are added for production under a production allocation condition; calculating corresponding wellhead temperatures when different water quantities are added for production under the production allocation condition; calculating hydrate generation temperatures corresponding to different wellhead pressures; and when the corresponding wellhead temperature under the same wellhead pressure is greater than the hydrate generation temperature, the water quantity corresponding to the wellhead pressure is the water quantity required to be injected into the production well, and then the required water quantity is injected into the production well. The pressure of a gas well production wellhead is reduced in the mode that water is added from the ground in an annular space, the temperature of the wellhead can be increased, the wellhead temperature is higher than the hydrate forming temperature by analyzing the wellhead pressure-temperature after different water amounts are added and the hydrate forming temperature corresponding to the wellhead pressure, and therefore the purpose of preventing hydrate is achieved.

Description

Technical Field

[0001] The invention relates to the field of oil and gas production engineering in the petroleum industry, and in particular to a method for preventing the formation of natural gas hydrates. Background Art

[0002] The formation of natural gas hydrates is a very important engineering problem in water-containing natural gas systems. The formation of hydrates during gas well production brings serious harm to gas well production and also brings many difficulties to the scientific management of gas wells. For example, the formation of natural gas hydrates will cause blockages to oil pipes, metering orifices, and ground pipelines, and hinder the heat conduction of equipment, which will seriously affect the production of gas wells and even endanger the safety of people and equipment. Therefore, the prediction and prevention of hydrate formation conditions are of great significance.

[0003] (1) In the field of oil extraction, many gas wells will generate hydrates in the early stage of production, affecting production.

[0004] (2) In the field of oil extraction, hydrate prevention on the ground mainly adopts ground water jacket furnace heating or electric blanket to prevent hydrate, but this requires a large amount of power or burning natural gas.

[0005] (3) In the field of oil extraction, hydrate prevention work can be carried out in production wells. Through rope operations, a downhole choke is inserted into the production well to throttle and reduce pressure. Then the natural gas absorbs geothermal heat before reaching the wellhead to achieve the purpose of preventing hydrates. However, downhole throttling requires rope operations. Some gas wells, such as tight gas, obtain production capacity through large-scale fracturing. In the early stage, there will be sand and other dirt, which will block the choke, affect the choke's fixation and salvage, and seriously cause salvage failure and well repair. Summary of the invention

[0006] The technical problem to be solved by the present invention is the above-mentioned problem existing in the existing method for preventing natural gas hydrate.

[0007] The present invention aims to provide a method for preventing the formation of natural gas hydrates by adding water to the production well.

[0008] The amount of water added is obtained by the following steps, comprising:

[0009] Calculate the corresponding wellhead pressure when adding different water volumes under production allocation conditions;

[0010] Calculate the corresponding wellhead temperature when adding different water volumes under production allocation conditions;

[0011] Calculate the hydrate formation temperature corresponding to different wellhead pressures;

[0012] When the wellhead temperature corresponding to the same wellhead pressure is greater than the hydrate formation temperature, the amount of water corresponding to the wellhead pressure is the amount of water that needs to be injected into the production well, and then the required amount of water is injected into the production well.

[0013] As a possible design, the hydrate formation temperature corresponding to different wellhead pressures is calculated by the Ponomarev method, the Chart regression method or statistical thermodynamics.

[0014] As a possible design, the required amount of water is injected into the production well, which is specifically achieved by the following methods: pump injection method and / or capillary injection gravity siphon method.

[0015] As a possible design, the pump injection method specifically includes: using a water pump to inject water into the production well through the annulus of the gas well.

[0016] As a possible design, the water injected into the production well comes from the water obtained by separation in the separator.

[0017] As a possible design, the capillary-enhanced gravity siphon method includes:

[0018] A capillary is hung on the annulus of the gas well, filled with water, and the water is injected into the production well by utilizing the siphon effect of the capillary.

[0019] As a possible design, the length and inner diameter of the capillary are determined as follows:

[0020] S1. Calculate the bottom hole flow pressure by using the formation inflow equation based on the production under the production allocation system, and then calculate the corresponding pressure at each depth of the gas well annulus;

[0021] S2. Calculate the pressure at each depth when the required amount of water flows in capillaries with different inner diameters;

[0022] When the pressure obtained in step S1 is equal to the pressure obtained in step S2, the inner diameter of the corresponding capillary is the required inner diameter, and the length of the corresponding capillary is the minimum length.

[0023] As a possible design, the actual capillary length is greater than the minimum length by 300 to 600 m.

[0024] Beneficial effects of the present invention:

[0025] 1. Adding water from the ground into the annulus of the gas well can reduce the wellhead pressure of the gas well production and increase the wellhead temperature; by analyzing the wellhead pressure-temperature after adding different amounts of water, and the wellhead pressure corresponding to the hydrate formation temperature, the wellhead temperature is made higher than the hydrate formation temperature, thereby achieving the purpose of preventing hydrates.

[0026] 2. The present invention makes full use of formation heat to achieve the purpose of energy saving and consumption reduction, and to prevent hydrates. It also solves the problem that a large amount of natural gas is required for water jacket furnace heating to prevent hydrates, and solves the problem that downhole throttling requires frequent maintenance, and failure leads to gas well production failure. BRIEF DESCRIPTION OF THE DRAWINGS

[0027] In order to more clearly illustrate the technical solutions of the exemplary embodiments of the present invention, the following briefly introduces the drawings required for use in the embodiments. It should be understood that the following drawings only illustrate certain embodiments of the present invention and should not be regarded as limiting the scope. For those of ordinary skill in the art, other relevant drawings can be obtained based on these drawings without creative work. In the drawings:

[0028] Figure 1 It is a schematic diagram of the state of oil, gas and water mixture flowing through pore throats;

[0029] Figure 2 It is a schematic diagram of a choke (throttle nozzle) in multiphase flow;

[0030] Figure 3 is a corresponding diagram of water injection volume and wellhead pressure in an embodiment of the present invention;

[0031] Figure 4 is a corresponding diagram of water injection volume and wellhead temperature in an embodiment of the present invention;

[0032] Figure 5 is a corresponding diagram of the wellhead pressure and the temperature required for hydrate formation in an embodiment of the present invention;

[0033] Figure 6 This is a schematic diagram of water being added by a water pump in an embodiment of the present invention;

[0034] Figure 7 4 is a corresponding diagram of capillary length and pressure in an embodiment of the present invention. DETAILED DESCRIPTION

[0035] In order to make the objectives, technical solutions and advantages of the present invention more clearly understood, the present invention is further described in detail below in conjunction with embodiments and drawings. The exemplary embodiments of the present invention and their description are only used to explain the present invention and are not intended to limit the present invention.

[0036] Under certain temperature and pressure conditions, some gas components in natural gas can form hydrates with liquid water. Natural gas hydrates are white crystalline solids that look like loose ice or dense snow, with a density of 0.88 to 0.90 g / cm 3 .

[0037] Natural gas hydrate is a cage-shaped lattice inclusion complex, that is, water molecules are hydrogen-bonded to form a cage-shaped lattice, and gas molecules are enclosed in the cage-shaped pores of the lattice under the action of van der Waals forces. In hydrates, the number of water molecules combined with one gas molecule is not constant, which is related to factors such as the size and properties of the gas molecules and the degree to which the pores in the lattice are filled by gas molecules. Hydrocarbons above pentane and hexane generally do not form hydrates.

[0038] Hydrates have two typical crystal structures: Type I structure: a body-centered cubic lattice composed of methane, ethane and hydrogen sulfide; Type II structure: a diamond lattice composed of larger molecules such as propane and isobutane.

[0039] Natural gas hydrates are crystals formed under a certain pressure when the temperature of natural gas is higher than the freezing point of water. The temperature at which hydrates are formed is called the "hydration temperature". When the temperature of natural gas is equal to or lower than the dew point temperature under a certain pressure, free water will condense from the natural gas. This condensed water is an indispensable condition for the formation of hydrates.

[0040] The main conditions for the formation of natural gas hydrates are summarized as follows:

[0041] ⑴ The temperature of natural gas must be equal to or lower than the dew point temperature of water vapor in natural gas, and there is condensed water in natural gas;

[0042] (2) Under certain pressure and natural gas composition conditions, the natural gas temperature is lower than the hydration temperature;

[0043] ⑶ High operating pressure will cause the hydration temperature to rise to the operating temperature;

[0044] ⑷The following factors will promote and accelerate the formation of hydrates:

[0045] High air velocity, or strong agitation or pressure fluctuations when the air flows through the oil pipe, throttling devices, surface pipelines and equipment;

[0046] ⑸The presence of tiny hydrate crystals "seed crystals";

[0047] ⑹The presence of H2S and CO2 contributes to the formation of hydrates because these acidic gases are more easily soluble in water than hydrocarbons.

[0048] The current methods for preventing the formation of natural gas hydrates include increasing temperature, reducing pressure, adding inhibitors, and drying gas. Increasing temperature and adding inhibitors are commonly used in mines.

[0049] The inhibitor method is as follows:

[0050] Under certain operating conditions, in order to prevent the formation of natural gas hydrates, the method of injecting hydrate inhibitors is usually adopted to reduce the hydrate formation temperature, thereby achieving the purpose of preventing hydrate formation; after the inhibitor is added, the water in the gas flow will dissolve in the inhibitor, changing the interaction between water molecules, thereby reducing the water vapor partial pressure on the surface, achieving the purpose of inhibiting the formation of hydrates, so that the gas flow does not form hydrates at a lower temperature (-30 to -50 ° C). There are many types of inhibitors, including organic inhibitors (methanol, ethanol, ethylene glycol, diethylene glycol, etc.) and inorganic inhibitors (sodium chloride, magnesium chloride and calcium chloride, etc.), and ethylene glycol is commonly used in gas production.

[0051] The results of the hydrate formation temperature reduction experiment using methanol and ethylene glycol as two inhibitors under the same conditions show that for two inhibitors with the same mass concentration, methanol is more effective than ethylene glycol.

[0052] Methanol can be used at any operating temperature. Since methanol has a low boiling point and high vapor pressure, it is more suitable for lower operating temperatures. If it is used at higher temperatures, the evaporation loss will be greater. Methanol has a moderate degree of toxicity and can enter the human body through the respiratory tract, esophagus and skin. The toxic dose of methanol to humans is 5 to 10 ml, and the lethal dose is 30 ml. When the methanol content in the air reaches 39 to 65 ml / m 3 When the concentration is too high, people will be poisoned within 30 to 60 minutes. Therefore, when using methanol as an inhibitor, appropriate safety measures should be taken.

[0053] Glycol inhibitors are non-toxic, have a higher boiling point than methanol, have a lower evaporation loss, and can generally be recycled and reused. Glycol is suitable for antifreeze treatment of gas wells and gas gathering stations with large gas volumes. Glycol inhibitors have a high viscosity and will increase the system pressure drop after injection. Especially in the presence of liquid hydrocarbons, too low an operating temperature will make it difficult to separate the glycol solution from the liquid hydrocarbons, and increase the dissolution loss and carryover loss in the liquid hydrocarbons.

[0054] Regarding the calculation method of the generation temperature drop, although there is now a more rigorous statistical thermodynamic model for estimation, it can actually only be applied to methanol as a substance, which has great limitations and is difficult to meet actual needs.

[0055] The essence of the heating method is to raise the temperature of the gas flow to a level above the temperature at which hydrates are formed. Steam heating and water-jacketed furnace heating are commonly used. The former uses steam generated by the boiler to heat the natural gas, while the latter is indirect heating using water and steam as the heat transfer medium.

[0056] Using Downhole Throttling to Reduce Wellhead Pressure of Gas Wells

[0057] Installing downhole chokes in gas wells to reduce the wellhead pressure and gas transmission pressure can not only prevent the formation of hydrates in the gas wells, but also increase the flow rate of natural gas in the production wells, which is helpful for gas well drainage.

[0058] There are two types of downhole chokes for gas wells: movable downhole chokes and fixed downhole chokes. At present, this technology has been successfully applied in multiple gas wells in gas fields such as Sichuan, Shengli, Zhongyuan, Qinghai, Xinjiang, and Changqing. However, due to certain difficulties in tripping the tools, it has not been widely promoted and applied at present.

[0059] The flow of oil, gas, and water mixture through the choke nozzle belongs to nozzle flow. The dynamic parameters of the mixture before entering the choke nozzle are: pressure (P1), temperature (T1), specific volume (V1), and flow velocity (W1); the dynamic parameters at the outlet are: P2, T2, V2, and W2. Throttling is generally considered an isentropic (adiabatic) expansion process, that is, the pressure drops (P2 < P1), the flow velocity increases (W2 > W1), and in the presence of gas, the temperature drops (T2 < T1). The throttling pressure ratio is:

[0060]

[0061] Figure 1 As shown in the schematic diagram of the state flowing through the pore throat, the purpose of throttling is to convert pressure energy into kinetic energy to obtain an increase in flow velocity. The higher the upstream pressure and the smaller the pore throat, the greater the velocity increment obtained downstream. However, this is not endless. When the ratio of upstream and downstream pressures reaches a certain value, the flow velocity of the fluid through the choke will approach the speed of sound (a). At this time, no matter how much the downstream pressure is reduced, the flow velocity (W2) will no longer increase and will maintain the speed of sound wave or pressure wave propagation. This is the so-called critical flow state of the nozzle.

[0062] There are many disadvantages in surface throttling of high-pressure gas wells. For example, the wellhead and part of the surface pipeline before throttling still bear high pressure. Switching the pressure regulating valve will generate harmful agitation to the bottom hole during production. The liquid-carrying capacity of the gas flow is relatively low. Seriously, throttling pressure reduction will cause temperature reduction, which is easy to form ice blockage at the throttling point, seriously affecting production. Therefore, high-pressure gas wells usually use a pressure regulating valve for multi-stage pressure reduction and heat preservation production on the surface. And surface heat preservation and heating will waste a lot of natural gas resources and require corresponding management personnel.

[0063] Through the research on downhole throttling technology and hydrate prevention technology for gas wells, it is possible to cancel the surface water jacket heating furnace for a single well, simplify the surface process of the well site, reduce the management personnel and labor intensity at the well site, improve the automatic management level of gas wells, and have significant economic and social benefits.

[0064] In terms of the throttling control mechanism, there is not much difference between the surface choke nozzle and the downhole choke nozzle. In other words, placing the surface choke nozzle with changed dimensions at an appropriate position downhole is the downhole choke nozzle. However, the former is on the surface and the latter is downhole, and there are indeed certain differences between them. These differences are:

[0065] ⑴ The upstream and downstream pressures of the surface throttle nozzle are restricted by the wellhead pressure and the horizontal (undulating) pipe flow pressure gradient; the upstream and downstream pressures of the downhole throttle nozzle are restricted by the flow pressure at the depth and the vertical pipe flow pressure gradient.

[0066] ⑵Because the two are in different positions, such as Figure 2 As shown, the geothermal conditions available to them are different, so their functions are also different.

[0067] ⑶The methods and difficulty of installing and replacing the throttle nozzles are slightly different.

[0068] As early as the 1940s, people proposed to use bottom hole throttle nozzles in self-flowing wells to eliminate the excitement intervals of oil wells or reduce the degree of excitement intervals. However, since the replacement of bottom hole throttle nozzles and the change of nozzle size require the lifting of oil pipes, this method has not been widely used. Later, the US oil fields used a special easy-to-bend pipe string to convey the adjustment of the bottom hole throttle nozzle size, but due to poor results, ground throttle nozzles were still used to control the production rate of the well. It was not until the 1980s that the downhole throttle nozzles attracted attention from the mining industry again after being "idle" for nearly 40 years. Only a small number of reports on downhole throttling devices have been seen abroad (such as OTIS Company in the United States). There are few reports on the application mechanism of downhole throttle nozzles and the throttle nozzle models used for design calculations.

[0069] In China, the movable choke developed by the gas production institute in the late 1980s has been successfully used in many gas wells in Sichuan, Shengli, Zhongyuan, Qinghai, Xinjiang and Changqing gas fields. However, due to the difficulty in raising and lowering the tool, it has not yet been widely promoted and applied.

[0070] In view of the above-mentioned deficiencies of the existing means for preventing the formation of natural gas hydrates, the inventors found that when the gas well produces a large amount of water, hydrates will not be formed due to the low wellhead pressure and high temperature. It can be seen that the wellhead pressure of the gas well production can be reduced by adding water from the ground through the annulus, and the temperature of the wellhead can be increased. By analyzing the wellhead pressure-temperature after adding different amounts of water, and the wellhead pressure corresponding to the hydrate formation temperature, the wellhead temperature is made higher than the hydrate formation temperature. Thus, the purpose of preventing hydrates is achieved. Therefore, an embodiment of the present invention provides a method for preventing the formation of natural gas hydrates, adding water to the production well, wherein the amount of water added is obtained by the following steps:

[0071] S1. Calculate the corresponding wellhead pressure when adding different water volumes under production allocation conditions. The calculation method can adopt the production well multiphase flow calculation method (HBDR method);

[0072] For example: the production allocation condition is 5×10 4 m 3 / d, then the corresponding diagram of water volume and wellhead pressure is as follows Figure 3 As shown by Figure 3 It can be seen that there is a linear relationship between the amount of water and the wellhead pressure. The more water is added, the lower the wellhead pressure.

[0073] S2. Calculate the corresponding wellhead temperature when adding different water volumes under the production allocation conditions. The calculation method can adopt the production well multiphase flow calculation method (HBDR method);

[0074] For example: the production allocation condition is 5×10 4 m 3 / d, then the corresponding diagram of water volume and wellhead temperature is as follows Figure 4 As shown by Figure 4 It can be seen that there is a linear relationship between the amount of water and the wellhead temperature. The more water added, the higher the wellhead temperature.

[0075] S3. Calculate the hydrate formation temperature corresponding to different wellhead pressures;

[0076] There are three methods for calculating hydrate formation temperature, namely, Bononarev method, Chart regression method and statistical thermodynamics; the correspondence between the wellhead pressure and hydrate formation temperature calculated by the three methods Figure 5 As shown in Table 1, Figure 5 It can be seen that the higher the wellhead pressure, the higher the hydrate formation temperature. Therefore, by injecting water into the well, the wellhead pressure can be reduced, thereby reducing the temperature required for hydrate formation.

[0077] Table 1 Hydrate formation temperature ℃

[0078] - Pressure(MPa) Ponomarev Chart Regression Statistical Thermodynamics 1 17.5118 23.90 21.69 20.03 2 14.1361 22.18 20.79 18.59 3 13.0437 21.53 20.46 18.05 4 12.273 21.04 20.20 17.64 5 11.6636 20.64 19.99 17.30 6 11.5533 20.56 19.95 17.24 7 11.6793 20.65 20.00 17.31 8 11.8508 20.76 20.06 17.41 9 12.0029 20.87 20.11 17.50 10 12.1008 20.93 20.15 17.55 11 11.8571 20.77 20.06 17.41 12 11.6291 20.61 19.98 17.28 13 11.4146 20.46 19.90 17.16 14 11.2118 20.32 19.83 17.04 15 11.0191 20.18 19.75 16.92 16 10.8355 20.04 19.68 16.81

[0079] S4. When the wellhead temperature corresponding to the same wellhead pressure is greater than the hydrate formation temperature, the amount of water corresponding to the wellhead pressure is the amount of water that needs to be injected into the production well, and then the required amount of water is injected into the production well.

[0080] According to the relationship diagram obtained in steps S1, S2 and S3, the amount of water corresponding to the wellhead pressure under the same wellhead pressure and satisfying that the wellhead temperature is greater than the hydrate formation temperature is taken as the amount of water that needs to be added to the production well, and the high temperature downhole is used to heat the water, thereby increasing the temperature of the wellhead, saving energy consumption, and simplifying the operation.

[0081] As shown in Table 2, the correspondence between water injection rate, wellhead pressure, wellhead temperature and the temperature required for hydrate formation.

[0082] Table 2

[0083] <![CDATA[Water volume m 3 / d]]> Wellhead pressure MPa Wellhead temperature ℃ Hydrate formation℃ 0 17.5 19.9 23.9 2 14.1 19.6 22.2 4 13.0 19.9 21.5 6 12.3 20.3 21.0 8 11.7 20.8 20.6 10 11.6 21.4 20.6 12 11.7 22.0 20.6 14 11.9 22.7 20.8 16 12.0 23.4 20.9 18 12.1 24.1 20.9 20 11.9 24.6 20.8 22 11.6 25.2 20.6 24 11.4 25.8 20.5 26 11.2 26.4 20.3 28 11.0 27.0 20.2 30 10.8 27.6 20.0

[0084] It can be seen from Table 2 that when the injected water volume is greater than or equal to 8m 3 / d and the wellhead pressure is less than or equal to 11.7MPa, the wellhead temperature is higher than the hydrate formation temperature, so the injection water volume is controlled at 8m 3 / d and above, the formation of hydrates can be effectively controlled.

[0085] In step S4, water is added by water pump filling and / or capillary filling.

[0086] Among them, the water pump filling is as follows:

[0087] The amount of water required to be injected each day is determined according to the method for determining the amount of water to be injected to prevent hydrate formation, and then added to the production well through a water pump.

[0088] The water can come from the water separated by the ground separator during the production of the gas well that will form hydrates, which is conducive to saving water resources. In the early stage of filling, if the separator does not separate water, external water can be introduced for initial use.

[0089] like Figure 6 Shown is a schematic diagram of water pump filling.

[0090] Capillary filling is as follows:

[0091] By hanging a capillary (such as 1 / 4 inch, 1 / 2 inch, etc.) in the annulus, after the capillary is filled with water, the water on the ground is injected into the production well by using the siphon effect of the capillary. The size and length of the capillary are determined according to the capillary tube parameter determination method. The suction injection volume is controlled by the ground valve.

[0092] The size and length of the capillary are determined as follows:

[0093] 1) The bottom hole flow pressure is calculated by using the formation inflow equation (IPR equation) based on the production under the production allocation conditions, and then the corresponding pressure at each depth of the production well annulus is calculated. Since the formation inflow equation (IPR equation) is an existing method, it will not be elaborated here.

[0094] 2) The pressure corresponding to each depth of the required injection water flowing in the capillary tubes with different inner diameters is calculated by the multiphase flow calculation method of the production well. The multiphase flow calculation method of the production well is a prior art method and will not be elaborated in detail here.

[0095] 3) When the pressures calculated in 1) and 2) are equal, according to Figure 7 Get the minimum length of the corresponding capillary.

[0096] In actual application, some margin can be reserved. Generally, the margin is 300 to 600 m.

[0097] It can be seen from the above embodiments that when the gas well produces a large amount of water, hydrates will not be formed due to the low wellhead pressure and high temperature. Based on this, the wellhead pressure of the gas well production can be reduced by adding water from the ground through the annulus, and the temperature of the wellhead can be increased. By analyzing the wellhead pressure-temperature after adding different amounts of water, and the wellhead pressure corresponding to the hydrate formation temperature, the wellhead temperature is made higher than the hydrate formation temperature, thereby achieving the purpose of preventing hydrates.

[0098] The present invention makes full use of formation heat to achieve the purpose of energy saving and consumption reduction and hydrate prevention, and solves the problem that a large amount of natural gas is required for water jacket furnace heating to prevent hydrates, and solves the problem that downhole throttling requires frequent maintenance and failure leads to gas well production failure.

[0099] The specific implementation methods described above further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above description is only a specific implementation method of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A method for preventing the formation of natural gas hydrates, characterized in that: Add water to the production well.

2. The method for preventing the formation of natural gas hydrate according to claim 1, characterized in that: The amount of water added is calculated as follows: Calculate the corresponding wellhead pressure when adding different water volumes under production allocation conditions; Calculate the corresponding wellhead temperature when adding different water volumes under production allocation conditions; Calculate the hydrate formation temperature corresponding to different wellhead pressures; When the wellhead temperature corresponding to the same wellhead pressure is greater than the hydrate formation temperature, the amount of water corresponding to the wellhead pressure is the amount of water that needs to be injected into the production well, and then the required amount of water is injected into the production well.

3. The method for preventing the formation of natural gas hydrate according to claim 1, characterized in that: The hydrate formation temperature corresponding to different wellhead pressures is calculated by the Ponomarev method, the chart regression method or statistical thermodynamics.

4. The method for preventing the formation of natural gas hydrate according to claim 1, characterized in that: The corresponding wellhead pressure when different water volumes are added to production under production allocation conditions is calculated through multiphase flow calculation of the production well.

5. The method for preventing the formation of natural gas hydrate according to claim 1, characterized in that: The corresponding wellhead temperature when different water volumes are added to the production well under the multiphase flow calculation and production allocation conditions.

6. The method for preventing the formation of natural gas hydrate according to claim 1, characterized in that: The required amount of water is added to the production well by the following methods: pump injection and / or capillary gravity siphon method.

7. The method for preventing the formation of natural gas hydrate according to claim 6, characterized in that: The pump injection method specifically includes: using a water pump to inject water into the production well through the annulus of the gas well.

8. The method for preventing the formation of natural gas hydrate according to claim 6, characterized in that: The capillary-enhanced gravity siphon method comprises: A capillary is hung on the annulus of the gas well, filled with water, and the water is injected into the production well by utilizing the siphon effect of the capillary.

9. The method for preventing the formation of natural gas hydrate according to claim 8, characterized in that: The length and inner diameter of the capillary are determined as follows: S1. Calculate the bottom hole flow pressure by using the formation inflow equation based on the production under the production allocation system, and then calculate the corresponding pressure at each depth of the gas well annulus; S2. Calculate the pressure at each depth when the required injection water flows in capillaries with different inner diameters through multiphase flow in the production well; When the pressure obtained in step S1 is equal to the pressure obtained in step S2, the inner diameter of the corresponding capillary is the required inner diameter, and the length of the corresponding capillary is the minimum length.

10. The method for preventing the formation of natural gas hydrate according to claim 9, characterized in that: The actual capillary length is 300 to 600 m greater than the minimum length.

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