Ultra-deep water shaft hydrate unblocking device and method based on multi-method cooperation

Abstract

The invention relates to an ultra-deepwater shaft hydrate unblocking device and method based on multi-method cooperation, and belongs to the technical field of deepwater oil and gas resource development. The device comprises a production oil pipe, a continuous oil pipe, an agent injection control device and a real-time monitoring and processing device, the continuous oil pipe is arranged in the production oil pipe, the top of the continuous oil pipe is connected with a driving mechanism used for driving the continuous oil pipe to ascend, descend and rotate, and the upper portion of a connecting oil pipe is connected with the agent injection control device. The agent injection control device and the connecting oil pipe are each provided with a real-time monitoring and processing device, and the real-time monitoring and processing devices and the agent injection control device are both connected with a control center. According to the comprehensive hydrate plug removal method comprehensively utilizing continuous oil pipe milling, self-heat-generation heating and pressure reduction, the plug removal efficiency and safety of natural gas hydrate plug in the ultra-deep water wellbore can be effectively improved, and guarantee is provided for multi-phase flow safety in the ultra-deep water wellbore.

Description

Technical Field

[0001] The present invention relates to a hydrate plugging removal device and method for a super-deepwater wellbore based on multi-method collaboration, belonging to the technical field of deepwater oil and gas resource development. Background Art

[0002] Internationally, the sea area with a water depth exceeding 1500 meters is called ultra-deep water. In recent years, China's deepwater oil and gas exploration and development have gradually advanced into ultra-deep water areas and are gradually moving towards deeper water depths. Ultra-deep water areas have characteristics such as low seabed temperature and high pressure, which are high-risk areas for hydrate formation. During the oil and gas drilling and production process in ultra-deep water areas, hydrate formation and blockage accidents are extremely likely to occur.

[0003] Common hydrate plugging removal methods mainly include chemical agent injection method, heating method, and pressure reduction method. Different from hydrate prevention, the chemical agents used in hydrate plugging removal are thermodynamic inhibitors, which can lower the temperature and increase the pressure required for hydrate stability, thereby causing the hydrate blockage in the pipe string to decompose. Commonly used thermodynamic inhibitors include alcohol inhibitors (such as methanol, ethylene glycol, etc.) and salt inhibitors (such as sodium chloride, potassium chloride, etc.). The heating method is to heat the hydrate blockage position, so that the temperature at the hydrate blockage increases and the hydrate decomposes. Commonly used heating methods mainly include electric heating, electromagnetic heating, etc. The pressure reduction method is to relieve pressure at one end of the hydrate blockage position to cause the hydrate to decompose. Since hydrate decomposition is an endothermic reaction, when the hydrate blockage in the pipe string decomposes, the temperature in the wellbore will decrease significantly, and in severe cases, the water generated by hydrate decomposition may even freeze directly, blocking the flow channel in the pipe string again. Therefore, in order to quickly and efficiently remove the hydrate blockage in the super-deepwater wellbore, it is necessary to form a fast and efficient hydrate plugging removal technology to ensure the flow safety of the wellbore.

[0004] As can be seen from the above, there is currently a lack of an efficient plugging removal device for natural gas hydrate blockage in super-deepwater wellbores, which is also the key difficulty restricting the flow safety guarantee of the wellbore in ultra-deepwater oil and gas development. Therefore, the present invention is proposed. Summary of the Invention

[0005] Aiming at the deficiencies of the prior art, especially problems such as easier icing and low efficiency during the decomposition of hydrate blockage in super-deepwater wellbores, the present invention provides a hydrate plugging removal device and method for a super-deepwater wellbore based on multi-method collaboration. In view of the complex environment and wellbore characteristics of ultra-deep water, by comprehensively using the integrated hydrate plugging removal method of coiled tubing milling, self-generated heat heating, and pressure reduction, the efficiency and safety of removing natural gas hydrate blockage in super-deepwater wellbores can be effectively improved, providing a guarantee for realizing the multiphase flow safety in super-deepwater wellbores.

[0006] The technical solution of the present invention is as follows:

[0007] A hydrate plugging removal device in a ultra-deep wellbore based on multi-method collaboration, comprising a production tubing, a coiled tubing, a chemical injection control device and a real-time monitoring and processing device. Among them, the coiled tubing is arranged inside the production tubing. The top of the coiled tubing is connected with a driving mechanism for driving the coiled tubing to lift and rotate. The upper part of the connecting tubing is connected with the chemical injection control device. The chemical injection control device and the connecting tubing are both provided with real-time monitoring and processing devices. The real-time monitoring and processing device and the chemical injection control device are both connected with a control center;

[0008] The chemical injection control device includes a storage tank A, a storage tank B, a mixing tank and a chemical injection pump. The storage tank A and the storage tank B are both connected with the mixing tank. The mixing tank is connected with the coiled tubing through the chemical injection pump. The mixing tank is connected with the control center through a signal receiving end.

[0009] Preferably according to the present invention, a riser is sleeved outside the production tubing, and the annulus fluid is filled in the gap between the riser and the production tubing.

[0010] Preferably according to the present invention, the storage tank A is filled with anhydrous ethylene glycol, and the storage tank B is filled with self-heating materials. The self-heating materials are selected from ammonium chloride or calcium chloride that can be dissolved in anhydrous ethylene glycol, etc.

[0011] Preferably according to the present invention, the real-time monitoring and processing device includes a monitoring sensor A and a monitoring sensor B. The monitoring sensor A is arranged on the coiled tubing for real-time monitoring of parameters such as the force, flow rate and acceleration of the coiled tubing, and is fed back to the control center in real time through the signal transmission cable B to provide data parameters for the control of the coiled tubing. A drain pipe is arranged at the top of the production tubing, and the monitoring sensor B is arranged on the drain pipe for real-time monitoring of parameters such as the flow rate, temperature and pressure of the liquid discharged from the coiled tubing, and is fed back to the control center in real time through the signal transmission cable A to provide real-time parameters for the optimization of the hydrate plugging removal plan.

[0012] Preferably according to the present invention, a control valve A is arranged on the injection pipeline between the chemical injection pump and the coiled tubing, and a control valve B is arranged on the drain pipe.

[0013] The plugging removal method of the above-mentioned hydrate plugging removal device in the ultra-deep wellbore based on multi-method collaboration is as follows:

[0014] (1) Installation of the plugging removal device. A cementing cement ring and a subsea blowout preventer are arranged at the bottom of the wellbore, and then the production tubing and the riser are inserted. The annulus fluid is filled between the production tubing and the riser. The top of the coiled tubing is connected with the driving mechanism and the chemical injection control device;

[0015] (2) Predict the location of hydrate blockage:

[0016] According to the basic parameters of ultra-deepwater oil and gas wells and the multiphase flow parameters before plugging, using multiphase flow theory and hydrate formation and deposition theory, calculate the hydrate formation rate and deposition rate under multiphase flow conditions in the wellbore, determine the specific location of hydrate plugging in the wellbore, obtain the temperature and pressure conditions required for the stable existence of hydrates at the plugging location, and verify the accuracy through the measured parameters during the plugging process, providing a basis for formulating a plug removal plan;

[0017] (3) Formulate a hydrate plug removal plan:

[0018] According to the predicted hydrate plugging location, determine the key parameters such as the wellhead pressure reduction amplitude, the dosage of thermodynamic hydrate inhibitors and self-heating materials, and the milling rate of coiled tubing required for hydrate plug removal, providing a basis for safely and efficiently carrying out hydrate plug removal operations;

[0019] (4) Remove the hydrate plug.

[0020] Preferably according to the present invention, in step (2), the hydrate formation rate is affected by factors such as temperature, pressure, and gas-liquid contact area. According to the temperature and pressure distribution and gas-liquid flow conditions in the wellbore, the hydrate formation rate is calculated by the following formula:

[0021]

[0022] In the formula, R hf is the hydrate formation rate, kg·s -1 ; u is a parameter characterizing mass transfer and heat transfer, related to the specific flow system; k1 and k2 are intrinsic kinetic parameters, with k1 = 2.608×10 16 kg·m -2 ·K -1 ·s -1 and k2 = 13600K; M h is the molar molecular mass of the hydrate, kg·mol -1 ; M g is the molar molecular mass of the gas, kg·mol -1 ; A s is the gas-liquid contact area, m 2 ; T eq is the hydrate phase equilibrium temperature, K; T is the wellbore fluid temperature, K;

[0023] Under the gas-water two-phase flow conditions in the wellbore, as part of the free water forms solid hydrate particles, the gas-water two-phase flow will transform into a gas-liquid-solid (hydrate) three-phase flow. During the three-phase flow process, for the hydrates formed from the liquid film on the pipe wall, the hydrate deposition rate is equal to the formation rate, as shown in the following formula:

[0024]

[0025] where r te is the effective inner diameter of the pipe string, in m;

[0026] The hydrate particles formed from droplets in the gas phase deposit as the droplets in the gas phase deposit, and the deposition process is affected by factors such as gas flow and liquid film atomization on the pipe wall. Considering the above factors comprehensively, the deposition rate of hydrate particles in the gas phase is shown by the following formula:

[0027]

[0028] where R dp represents the deposition rate of hydrate particles in the gas phase, in kg·s -1 ; C he represents the concentration of hydrate particles in the gas phase, in kg·m -3 ; C le represents the concentration of droplets in the gas phase, in kg·m -3 ; R dl represents the deposition rate of droplets in the gas phase, in kg·m -2 .s -1 ; S d represents the effective deposition coefficient of hydrate particles in the gas phase, dimensionless;

[0029] As hydrate formation and deposition occur, the hydrate layer formed on the inner wall of the pipe string will grow continuously, and the effective inner diameter of the pipe string will gradually decrease. Based on the obtained calculation formula for the hydrate deposition rate on the inner wall of the pipe string, the dynamic growth process of the hydrate deposition layer at different times and positions is calculated, and then the dynamic distribution of the thickness of the hydrate deposition layer is obtained:

[0030]

[0031] where ρ h is the hydrate density, in kg / m 3 ; t is time, in s; L is the length of the pipe string, in m; r ti is the initial inner diameter of the pipe string, in m; δ h is the thickness of the hydrate deposition layer, in m;

[0032] The thickness of the hydrate deposition layer on the inner wall of the pipe string is made dimensionless to obtain:

[0033]

[0034] where δ hd is the dimensionless thickness of the hydrate deposition layer;

[0035] Through the above calculations, the non-uniform distribution of the hydrate deposition thickness in the wellbore is obtained. When the hydrate deposition thickness at a certain position under a certain time condition exceeds the blockage critical thickness (δ hd <δ c ), it indicates that this position is the most dangerous position for hydrate blockage, and hydrate blockage may occur in the nearby areas. After obtaining the hydrate blockage position in the wellbore, according to the temperature and pressure conditions at this position and in combination with the natural gas hydrate phase equilibrium conditions, the conditions for the stable existence of hydrates are determined. Furthermore, the temperature and pressure conditions required for decomposing the hydrates here can be obtained. Considering the influence of prediction errors, the conditions required for hydrate decomposition are taken with a safety margin of 3°C, that is, the temperature requirement is increased by 3°C under the temperature conditions of the natural gas hydrate phase equilibrium.

[0036] According to the preferred embodiment of the present invention, in step (3), the most effective method for hydrate decomposition is to reduce the pressure. Under the condition of wellbore temperature monitoring, the hydrate phase equilibrium pressure distribution is obtained, and then the pressure is reduced below the hydrate phase equilibrium pressure. The wellhead pressure reduction amplitude = the pressure at the blockage position - the hydrate phase equilibrium pressure. On the one hand, in order to avoid the temperature dropping below zero due to the too fast heat absorption rate during hydrate decomposition, resulting in the directly converted water into ice and hindering the plugging removal process; on the other hand, in order to avoid too large pressure difference at both ends of the hydrate blockage position causing the blockage position to move towards the wellhead at a high speed and damaging the wellhead, it is recommended that the wellhead pressure should not be reduced too much. The hydrate decomposition driving force at the hydrate blockage position can be set to 2 - 5°C, that is:

[0037] 2°C ≤ T - T eq ≤ 5°C (7)

[0038]

[0039] In the formula, P eq is the hydrate phase equilibrium pressure, MPa; T eq is the hydrate phase equilibrium temperature, K; ΔT d is the temperature reduction of the hydrate equilibrium caused by the hydrate inhibitor, K; a n is an empirical parameter, dimensionless;

[0040] The more anhydrous ethylene glycol containing self-heating material in the injected string, the greater the hydrate decomposition rate. However, at the same time, with the injection of anhydrous ethylene glycol containing self-heating material, the liquid column pressure at the blockage position will increase, which will lead to a decrease in the hydrate decomposition rate. Therefore, to ensure the pressure requirement for hydrate decomposition, the pressure of the injected anhydrous ethylene glycol containing self-heating material satisfies the condition that the hydrate decomposition driving force is 2 - 5°C (formulas (7) and (8)). Based on this, the injection volume V1 of anhydrous ethylene glycol is obtained, and according to the saturated solubility of the self-heating material in anhydrous ethylene glycol, the injection volume of the self-heating material can be obtained:

[0041] V2 = V1×C b (9)

[0042] Wherein, V2 is the injection volume required for the self - heating material, m 3 ; C b The saturated solubility of the self - heating material in anhydrous ethylene glycol, L / L;

[0043] In addition, by milling the hydrate plugging slug with a coiled tubing, the decomposition surface area of the hydrate is increased, thereby accelerating the hydrate decomposition rate. The milling rate of the coiled tubing for milling the hydrate plugging is:

[0044] V = πDn / 1000 (10)

[0045] Wherein, V is the coiled tubing milling rate, m / min; D is the inner diameter of the tubing, i.e., the diameter of the hydrate plugging, m; n is the spindle speed, r / min.

[0046] According to the preference of the present invention, in step (4), according to the formulated hydrate plugging removal plan, control the coiled tubing to be lowered to the position of the hydrate plugging in the production tubing. Then, reduce the wellhead pressure to the designed value (the wellhead pressure can be reduced by opening the control valve B. The greater the valve opening, the more the wellhead pressure is reduced), and inject an anhydrous ethylene glycol solution containing a self - heating material into the plugging through the coiled tubing. Rotate the coiled tubing at a certain milling rate to mill the hydrate plugging position, and mill the hydrate plugging into fine hydrate debris. Under the combined action of pressure reduction + coiled tubing milling and crushing + hydrate inhibitor decomposition + self - heating material heat generation, gradually remove the hydrate plugging in the wellbore. At the same time, during the hydrate plugging removal process, monitor different parameters such as flow rate, temperature, and pressure in real time, and analyze the hydrate plugging removal status in real time. Since during the gradual decomposition of the hydrate plugging, the pressure in the wellbore gradually increases due to the accumulation of decomposition gas, which will cause the hydrate decomposition driving force to gradually decrease (the hydrate decomposition driving force = fluid temperature - hydrate phase equilibrium temperature. When the gas accumulates and the pressure increases, the hydrate phase equilibrium temperature will also increase, so the hydrate decomposition driving force decreases), that is, the hydrate decomposition rate gradually decreases. Accordingly, the wellhead pressure reduction amplitude, the injection rate of the thermodynamic hydrate inhibitor solution, and the coiled tubing milling rate should be adjusted in real time (to reduce the problem of the decrease in the hydrate decomposition rate caused by the decrease in the hydrate decomposition driving force, the wellhead pressure reduction amplitude should be appropriately reduced, the injection rate of the thermodynamic hydrate inhibitor solution should be increased, and the coiled tubing milling rate should be increased) to ensure safe and efficient plugging removal operations. When the plugging removal is completed, gradually lift the coiled tubing to the wellhead and restore the original operating conditions.

[0047] The beneficial effects of the present invention are as follows:

[0048] 1. By combining different methods such as pressure reduction decomposition, hydrate inhibitor decomposition, heat generation by self - heating materials, and milling and crushing by coiled tubing, the present invention can give full play to the advantages of different methods. Pressure reduction and injection of hydrate inhibitors can change the temperature and pressure conditions for hydrate stability. Milling and crushing by coiled tubing can increase the decomposition area of hydrates and accelerate decomposition. Self - heating materials generate heat when encountering water, which can supplement the heat absorbed during hydrate decomposition. This technology can not only ensure the rapid decomposition of hydrate blockages but also avoid icing phenomena caused by a rapid decrease in temperature due to a large amount of heat absorption during the rapid decomposition of hydrates, thereby improving the efficiency and safety of hydrate plug removal.

[0049] 2. By real - time monitoring of parameters such as temperature, pressure, and gas - liquid flow rate during the process of hydrate plug removal, the present invention can grasp the situation of hydrate plug removal in the wellbore in real time, and accordingly adjust key parameters such as wellbore pressure reduction, injection of inhibitors and self - heating materials, and milling power of coiled tubing, ensuring the safe and efficient removal of hydrate blockages in the wellbore and providing technical support for the safety of multiphase flow in ultra - deep wellbores. BRIEF DESCRIPTION OF THE DRAWINGS

[0050] Figure 1 is a schematic structural diagram of the present invention;

[0051] Wherein: 1. Control center; 2. Signal transmission cable A; 3. Signal transmission cable B; 4. Drain pipe; 5. Signal receiving end; 6. Storage tank A; 7. Storage tank B; 8. Mixing tank; 9. Chemical injection pump; 10. Control valve A; 11. Injection pipeline; 12. Coiled tubing; 13. Driving mechanism; 14. Monitoring sensor A; 15. Monitoring sensor B; 16. Control valve B; 17. Riser; 18. Production tubing; 19. Annular fluid; 20. Subsea blowout preventer; 21. Hydrate blockage location; 22. Seawater; 23. Shallow subsea layer; 24. Cement sheath; 25. Pay zone. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0052] The present invention will be further described below through examples in combination with the drawings, but is not limited thereto.

[0053] Example 1:

[0054] As Figure 1As shown in the figure, this embodiment provides a hydrate plugging removal device in a ultra-deep wellbore based on multi-method collaboration, which includes a production tubing 18, a coiled tubing 12, a chemical injection control device, and a real-time monitoring and processing device. Among them, the coiled tubing 12 is arranged inside the production tubing 18. The top of the coiled tubing 12 is connected with a driving mechanism 13 for driving the coiled tubing to lift and rotate. The upper part of the connecting tubing 12 is connected with a chemical injection control device. Both the chemical injection control device and the connecting tubing are provided with a real-time monitoring and processing device. Both the real-time monitoring and processing device and the chemical injection control device are connected to a control center 1. The driving mechanism is an existing device for driving the coiled tubing to lift and rotate. Figure 1 For illustration.

[0055] The chemical injection control device includes a storage tank A6, a storage tank B7, a mixing tank 8, and a chemical injection pump 9. Both the storage tank A6 and the storage tank B7 are connected to the mixing tank 8. The mixing tank 8 is connected to the coiled tubing 12 through the chemical injection pump 9. The mixing tank is an existing device with a stirring mechanism for mixing inside. The mixing tank 8 is connected to the control center 1 through a signal receiving end 5.

[0056] An outer casing pipe 17 is sleeved outside the production tubing 18. The gap between the outer casing pipe 17 and the production tubing 18 is filled with an annulus fluid 19.

[0057] The storage tank A6 is filled with anhydrous ethylene glycol, and the storage tank B7 is filled with a self-heating material. The self-heating material is selected from ammonium chloride or calcium chloride that can be dissolved in anhydrous ethylene glycol, etc.

[0058] The real-time monitoring and processing device includes a monitoring sensor A14 and a monitoring sensor B15. The monitoring sensor A14 is arranged on the coiled tubing 12 for real-time monitoring of parameters such as the force, flow rate, and acceleration of the coiled tubing 12, and is fed back to the control center in real time through a signal transmission cable B3 to provide data parameters for the control of the coiled tubing. A drain pipe 4 is arranged at the top of the production tubing 18. The monitoring sensor B15 is arranged on the drain pipe 4 for real-time monitoring of parameters such as the flow rate, temperature, and pressure of the liquid discharged from the coiled tubing, and is fed back to the control center 1 in real time through a signal transmission cable A2 to provide real-time parameters for the optimization of the hydrate plugging removal scheme.

[0059] A control valve A10 is arranged on the injection pipeline 11 between the chemical injection pump 9 and the coiled tubing 12, and a control valve B16 is arranged on the drain pipe 4.

[0060] The plugging removal method of the above-mentioned hydrate plugging removal device in the ultra-deep wellbore based on multi-method collaboration is as follows:

[0061] (1) Installation of plug removal device: Set the cement sheath 24 at the bottom of the wellbore and the subsea blowout preventer 20, then insert the production tubing 18 and the riser 17. The annulus fluid is filled between the production tubing 18 and the riser 17. The top of the coiled tubing 12 is connected to the driving mechanism and the chemical injection control device;

[0062] (2) Prediction of hydrate plugging location:

[0063] According to the basic parameters of the ultra-deepwater oil and gas well and the multiphase flow parameters before plugging, using the multiphase flow theory and the hydrate formation and deposition theory, calculate the hydrate formation rate and deposition rate under the multiphase flow conditions in the wellbore, and judge the specific location of hydrate plugging in the wellbore, obtain the temperature and pressure conditions required for the stable existence of hydrate at the plugging location, and verify the accuracy through the measured parameters monitored during the plugging process, providing a basis for the formulation of the plug removal plan;

[0064] The hydrate formation rate is affected by factors such as temperature, pressure, and gas-liquid contact area. According to the temperature and pressure distribution and gas-liquid flow conditions in the wellbore, the hydrate formation rate is calculated by the following formula:

[0065]

[0066] In the formula, R hf is the hydrate formation rate, kg·s -1 ; u is the parameter characterizing mass transfer and heat transfer, related to the specific flow system; k1 and k2 are the intrinsic kinetic parameters, with k1 = 2.608×10 16 kg·m -2 ·K -1 ·s -1 and k2 = 13600K; M h is the molar molecular mass of the hydrate, kg·mol -1 ; M g is the molar molecular mass of the gas, kg·mol -1 ; A s is the gas-liquid contact area, m 2 ; T eq is the hydrate phase equilibrium temperature, K; T is the wellbore fluid temperature, K;

[0067] Under the gas-water two-phase flow conditions in the wellbore, as part of the free water forms solid hydrate particles, the gas-water two-phase flow will transform into a gas-liquid-solid (hydrate) three-phase flow. During the three-phase flow process, for the hydrate formed from the liquid film on the pipe wall, the hydrate deposition rate is equal to the formation rate, as shown in the following formula:

[0068]

[0069] In the formula, r teis the effective inner diameter of the pipe string, m;

[0070] The hydrate particles generated from droplets in the gas phase deposit as the droplets in the gas phase deposit, and the deposition process is affected by factors such as gas flow and liquid film atomization on the pipe wall. Considering the above factors comprehensively, the deposition rate of hydrate particles in the gas phase is shown by the following formula:

[0071]

[0072] In the formula, R dp represents the deposition rate of hydrate particles in the gas phase, kg·s -1 ; C he represents the concentration of hydrate particles in the gas phase, kg·m -3 ; C le represents the concentration of droplets in the gas phase, kg·m -3 ; R dl represents the deposition rate of droplets in the gas phase, kg·m -2 .s -1 ; S d represents the effective deposition coefficient of hydrate particles in the gas phase, dimensionless;

[0073] As hydrate formation and deposition occur, the hydrate layer formed on the inner wall of the pipe string will grow continuously, and the effective inner diameter of the pipe string will gradually decrease. Based on the obtained calculation formula for the hydrate deposition rate on the inner wall of the pipe string, the dynamic growth process of the hydrate deposition layer at different times and positions is calculated, and then the dynamic distribution of the thickness of the hydrate deposition layer is obtained:

[0074]

[0075]

[0076] In the formula, ρ h is the hydrate density, kg / m 3 ; t is time, s; L is the length of the pipe string, m; r ti is the initial inner diameter of the pipe string, m; δ h is the thickness of the hydrate deposition layer, m;

[0077] After dimensionless treatment of the thickness of the hydrate deposition layer on the inner wall of the pipe string, we get:

[0078]

[0079] In the formula, δ hd is the dimensionless thickness of the hydrate deposition layer;

[0080] Through the above calculation, the non-uniform distribution of the hydrate deposition thickness in the wellbore is obtained. When the hydrate deposition thickness at a certain position under a certain time condition exceeds the critical blockage thickness (δhd <δ c ) indicates that this position is the most dangerous position for hydrate blockage, and hydrate blockage may occur in the nearby areas. After obtaining the position of hydrate blockage in the wellbore, according to the temperature and pressure conditions at this position and combined with the natural gas hydrate phase equilibrium conditions, the conditions for the stable existence of hydrates are determined. Furthermore, the temperature and pressure conditions required for decomposing the hydrates here can be obtained. Considering the influence of prediction errors, a safety margin of 3°C is taken for the conditions required for hydrate decomposition, that is, the temperature requirement is increased by 3°C under the temperature conditions of natural gas hydrate phase equilibrium.

[0081] (3) Develop a hydrate plug removal plan:

[0082] Based on the predicted hydrate blockage position, determine the key parameters such as the wellhead pressure reduction amplitude, the dosage of thermodynamic hydrate inhibitors and self - heating materials, and the milling rate of coiled tubing required for hydrate plug removal, providing a basis for safely and efficiently carrying out hydrate plug removal operations;

[0083] The most effective method for hydrate decomposition is to reduce the pressure. Under the condition of monitoring the wellbore temperature, the hydrate phase equilibrium pressure distribution is obtained, and then the pressure is reduced below the hydrate phase equilibrium pressure. The wellhead pressure reduction amplitude = the pressure at the blockage - the hydrate phase equilibrium pressure. On the one hand, in order to avoid the temperature dropping below zero due to the too - fast heat absorption rate during hydrate decomposition, resulting in the directly converted water into ice and hindering the plug removal process; on the other hand, in order to avoid too large a pressure difference at both ends of the hydrate blockage position, causing the blockage position to move rapidly towards the wellhead and damaging the wellhead, it is recommended that the wellhead pressure should not be reduced too much. Set the driving force for hydrate decomposition at the hydrate blockage position to 2 - 5°C, that is:

[0084] 2°C ≤ T - T eq ≤ 5°C (7)

[0085]

[0086] In the formula, P eq is the hydrate phase equilibrium pressure, MPa; T eq is the hydrate phase equilibrium temperature, K; ΔT d is the temperature reduction of hydrate equilibrium caused by the hydrate inhibitor, K; a n is an empirical parameter, dimensionless;

[0087] In view of the environmental protection requirements for offshore oil and gas development, anhydrous ethylene glycol is selected as the thermodynamic inhibitor, and self - generating heat materials such as ammonium chloride and calcium chloride that can be dissolved in anhydrous ethylene glycol can be selected. First, the self - generating heat materials are dissolved in anhydrous ethylene glycol in advance in a mixing tank to make the anhydrous ethylene glycol solution reach the saturation condition. Then, according to the chemical injection instruction issued by the control center, the injection rate of the chemical injection pump is automatically adjusted, and the anhydrous ethylene glycol solution containing the self - generating heat materials is injected into the coiled tubing through the chemical injection pipeline and reaches the hydrate blockage position. The injected ethylene glycol is a thermodynamic hydrate inhibitor, which helps to reduce the temperature required for the secondary formation of hydrates while accelerating the hydrate decomposition rate, and prevents the decomposed natural gas and water from forming hydrates again; the injected self - generating heat materials will release heat when encountering the water generated by the hydrate decomposition, which helps to quickly restore the temperature reduced by the endothermic decomposition of the hydrates and improve the hydrate decomposition efficiency at the blockage position.

[0088] The more anhydrous ethylene glycol containing self - generating heat materials in the injected string, the greater the hydrate decomposition rate. However, at the same time, with the injection of anhydrous ethylene glycol containing self - generating heat materials, the liquid column pressure at the blockage will increase, which will lead to a decrease in the hydrate decomposition rate. Therefore, to ensure the pressure requirement for hydrate decomposition, the pressure of the injected anhydrous ethylene glycol containing self - generating heat materials meets the condition that the hydrate decomposition driving force is 2 - 5 °C (Formulas (7) and (8)). Based on this, the injection volume V1 of anhydrous ethylene glycol is obtained, and according to the saturated solubility of the self - generating heat materials in anhydrous ethylene glycol, the injection volume of the self - generating heat materials can be obtained:

[0089] V2 = V1×C b (9)

[0090] In the formula, V2 is the required injection volume of the self - generating heat materials, m 3 ; C b is the saturated solubility of the self - generating heat materials in anhydrous ethylene glycol, L / L;

[0091] In addition, by milling the hydrate blockage slug with the coiled tubing, the hydrate decomposition surface area is increased, thereby accelerating the hydrate decomposition rate. The milling rate of the coiled tubing for milling the hydrate blockage is:

[0092] V = πDn / 1000 (10)

[0093] In the formula, V is the coiled tubing milling rate, m / min; D is the inner diameter of the tubing, that is, the diameter of the hydrate blockage, m; n is the spindle speed, r / min.

[0094] (4) Remove hydrate blockage. According to the formulated hydrate blockage removal plan, control the coiled tubing to be lowered to the hydrate blockage position inside the production tubing. Then, reduce the wellhead pressure to the designed value (the wellhead pressure can be reduced by opening control valve B. The greater the valve opening, the more the wellhead pressure is reduced), and inject an anhydrous ethylene glycol solution containing self-heating materials into the blockage through the coiled tubing. Rotate the coiled tubing at a certain milling rate to mill the hydrate blockage position, milling the hydrate blockage into small hydrate debris, and gradually remove the hydrate blockage in the wellbore under the combined action of pressure reduction + coiled tubing milling and crushing + decomposition of hydrate inhibitor + heat generation of self-heating materials. At the same time, during the hydrate blockage removal process, monitor different parameters such as flow rate, temperature, and pressure in real time, and analyze the hydrate blockage removal status in real time. Since during the gradual decomposition of the hydrate blockage, the pressure in the wellbore gradually increases due to the accumulation of decomposition gas, which will cause the hydrate decomposition driving force to gradually decrease (hydrate decomposition driving force = fluid temperature - hydrate phase equilibrium temperature. When the pressure increases after gas accumulation, the hydrate phase equilibrium temperature will also increase, so the hydrate decomposition driving force decreases), that is, the hydrate decomposition rate gradually decreases. Based on this, the wellhead pressure reduction amplitude, the injection rate of the thermodynamic hydrate inhibitor solution, and the coiled tubing milling rate should be adjusted in real time (to reduce the problem of the decrease in the hydrate decomposition rate caused by the decrease in the hydrate decomposition driving force, the wellhead pressure reduction amplitude should be appropriately reduced, the injection rate of the thermodynamic hydrate inhibitor solution should be increased, and the coiled tubing milling rate should be increased) to ensure safe and efficient plug removal operations. When the plug removal is completed, gradually lift the coiled tubing to the wellhead and resume the original operating conditions.

Claims

1. A hydrate plugging removal device in a ultra-deep water wellbore based on multi-method collaboration, characterized in that, It includes a production tubing, a coiled tubing, a chemical injection control device, and a real-time monitoring and processing device. Among them, the coiled tubing is arranged inside the production tubing. The top of the coiled tubing is connected to a driving mechanism for driving the lifting and rotation of the coiled tubing. The upper part of the connecting tubing is connected to the chemical injection control device. The chemical injection control device and the connecting tubing are both provided with real-time monitoring and processing devices. The real-time monitoring and processing device and the chemical injection control device are both connected to a control center; The chemical injection control device includes storage tank A, storage tank B, a mixing tank, and a chemical injection pump. Storage tank A and storage tank B are both connected to the mixing tank. The mixing tank is connected to the coiled tubing through the chemical injection pump. The mixing tank is connected to the control center through a signal receiving end.

2. The hydrate plugging removal device in the ultra-deep water wellbore based on multi-method collaboration according to claim 1, wherein, An outer casing pipe is sleeved outside the production tubing. The gap between the outer casing pipe and the production tubing is filled with an annulus fluid.

3. The hydrate plugging removal device in the ultra-deep wellbore based on multi-method collaboration according to claim 2, wherein, Storage tank A is filled with anhydrous ethylene glycol, and storage tank B is filled with a self-heating material.

4. The hydrate plugging removal device in the ultra-deep water wellbore based on multi-method collaboration according to claim 3, wherein, The real-time monitoring and processing device includes monitoring sensor A and monitoring sensor B. Monitoring sensor A is arranged on the coiled tubing for real-time monitoring of the force, flow rate, and acceleration of the coiled tubing. A drain pipe is arranged at the top of the production tubing. Monitoring sensor B is arranged on the drain pipe for real-time monitoring of the flow rate, temperature, and pressure of the liquid discharged from the coiled tubing.

5. The hydrate plug removal device in the ultra-deep wellbore based on multi-method collaboration according to claim 4, characterized in that, A control valve A is arranged on the injection pipeline between the chemical injection pump and the coiled tubing, and a control valve B is arranged on the drain pipe.

6. The plugging removal method of the plugging removal device for hydrates in the ultra-deep water wellbore based on multi-method collaboration according to claim 5, characterized in that, The steps are as follows: (1) Installation of the plug removal device. A cementing cement ring and a subsea blowout preventer are set at the bottom of the wellbore. Then, the production tubing and the outer casing pipe are inserted. The gap between the production tubing and the outer casing pipe is filled with an annulus fluid. The top of the coiled tubing is connected to the driving mechanism and the chemical injection control device; (2) Predict the hydrate plugging location: According to the basic parameters of the ultra-deepwater oil and gas well and the multiphase flow parameters before plugging, using the multiphase flow theory and the hydrate formation and deposition theory, calculate the hydrate formation rate and deposition rate under the multiphase flow conditions in the wellbore, and judge the specific location of hydrate plugging in the wellbore. Obtain the temperature and pressure conditions required for the stable existence of hydrates at the plugging location, and verify the accuracy through the measured parameters monitored during the plugging process; (3) Develop a hydrate plug removal plan: According to the predicted hydrate plugging location, determine the wellhead pressure reduction amplitude required for hydrate plug removal, the dosage of thermodynamic hydrate inhibitors and self-heating materials, and the milling rate of the coiled tubing; (4) Remove the hydrate plug.

7. The plugging removal method of the plugging removal device for hydrates in the ultra-deep water wellbore based on multi-method collaboration according to claim 6, characterized in that, In step (2), according to the temperature and pressure distribution and gas-liquid flow conditions in the wellbore, the hydrate formation rate is calculated by the following formula: where R hf is the hydrate formation rate, kg·s -1 ; u is a parameter characterizing mass and heat transfer; k1 and k2 are intrinsic kinetic parameters; M h is the molar molecular mass of the hydrate, kg·mol -1 ; M g is the molar molecular mass of the gas, kg·mol -1 ; A s is the gas-liquid contact area, m 2 ; T eq is the hydrate phase equilibrium temperature, K; T is the wellbore fluid temperature, K; Under the gas-water two-phase flow conditions in the wellbore, as part of the free water forms solid hydrate particles, the gas-water two-phase flow will transform into a gas-liquid-solid three-phase flow. During the three-phase flow process, for the hydrates formed by the liquid film on the pipe wall, the hydrate deposition rate is equal to the formation rate, as shown in the following formula: where r te is the effective inner diameter of the pipe string, in m; The hydrate particles formed by the liquid droplets in the gas phase are deposited as the liquid droplets in the gas phase are deposited. The deposition rate of the hydrate particles in the gas phase is shown in the following formula: where, R dp represents the deposition rate of hydrate particles in the gas phase, kg·s -1 ; C he represents the concentration of hydrate particles in the gas phase, kg·m -3 ; C le represents the concentration of droplets in the gas phase, kg·m -3 ; R dl represents the deposition rate of droplets in the gas phase, kg·m -2 .s -1 ; S d Denotes the effective deposition coefficient of hydrate particles in the gas phase, dimensionless; As hydrate formation and deposition occur, the hydrate layer formed on the inner wall of the pipe string will continue to grow, and the effective inner diameter of the pipe string will gradually decrease. Based on the calculated formula for the hydrate deposition rate on the inner wall of the pipe string, the dynamic growth process of the hydrate deposition layer at different times and positions is calculated, and then the dynamic distribution of the thickness of the hydrate deposition layer is obtained: where ρ h is the hydrate density, kg / m 3 ; t is the time, s; L is the length of the pipe string, m; r ti is the initial inner diameter of the pipe string, m; δ h is the thickness of the hydrate deposition layer, m; The thickness of the hydrate deposition layer on the inner wall of the pipe string is dimensionless processed to obtain: where δ hd is the dimensionless thickness of the hydrate deposit layer; Through the above calculations, the non-uniform distribution of the hydrate deposition thickness in the wellbore is obtained. When the hydrate deposition thickness at a certain position under a certain time condition exceeds the critical blocking thickness, it indicates that this position is the most dangerous position for hydrate blockage, and hydrate blockage may occur in the nearby areas.

8. The plugging removal method of the plugging removal device for hydrates in the ultra-deep water wellbore based on multi-method collaboration according to claim 6, characterized in that, In step (3), the most effective method for hydrate decomposition is to reduce the pressure. Under the condition of wellbore temperature monitoring, the hydrate phase equilibrium pressure distribution is obtained, and then the pressure is reduced below the hydrate phase equilibrium pressure. The wellhead pressure reduction amplitude = the pressure at the blockage - the hydrate phase equilibrium pressure. It is sufficient to set the hydrate decomposition driving force at the hydrate blockage position to 2 - 5 °C, that is: 2 °C ≤ T - T eq ≤ 5 °C (7) Wherein, P eq is the hydrate phase equilibrium pressure, MPa; T eq is the hydrate phase equilibrium temperature, K; ΔT d is the temperature decrease of hydrate equilibrium caused by the hydrate inhibitor, K; a n is an empirical parameter, dimensionless; The pressure of the anhydrous ethylene glycol containing the self-heating material injected satisfies the condition that the hydrate decomposition driving force is 2 - 5 °C. Based on this, the injection volume V1 of anhydrous ethylene glycol is obtained, and according to the saturated solubility of the self-heating material in anhydrous ethylene glycol, the injection volume of the self-heating material can be obtained: V2 = V1 × C b (9) where V2 is the injection amount required for the self - heating material, m 3 ; C b is the saturated solubility of the self - heating material in anhydrous ethylene glycol, L / L; In addition, by milling the hydrate blockage slug with a coiled tubing, the hydrate decomposition surface area is increased, and thus the hydrate decomposition rate is accelerated. The milling rate of the coiled tubing for milling the hydrate blockage is: V = πDn / 1000(10) In the formula, V is the coiled tubing milling rate, m / min; D is the inner diameter of the tubing, that is, the diameter of the hydrate blockage, m; n is the spindle speed, r / min.

9. The plugging removal method of the plugging removal device for hydrates in the ultra-deep wellbore based on multi-method collaboration according to claim 6, characterized in that, In step (4), according to the formulated hydrate blockage removal plan, control the coiled tubing to be lowered to the hydrate blockage position in the production tubing. Then, reduce the wellhead pressure to the designed value, and inject an anhydrous ethylene glycol solution containing a self-heating material into the blockage through the coiled tubing. Rotate the coiled tubing at a certain milling rate to mill the hydrate blockage position, and mill the hydrate blockage into small hydrate debris. The hydrate blockage in the wellbore is gradually removed under the combined action of pressure reduction + coiled tubing milling and crushing + hydrate inhibitor decomposition + self-heating material heat generation. At the same time, during the hydrate blockage removal process, the flow rate, temperature, and pressure parameters are monitored in real time, and the hydrate blockage removal status is analyzed in real time. Since during the gradual decomposition of the hydrate blockage, the pressure in the wellbore gradually increases due to the accumulation of decomposition gas, which will cause the hydrate decomposition driving force to gradually decrease, that is, the hydrate decomposition rate gradually decreases. Accordingly, the wellhead pressure reduction amplitude, the injection rate of the thermodynamic hydrate inhibitor solution, and the coiled tubing milling rate should be adjusted in real time to ensure safe and efficient plug removal operations. When the plug removal is completed, gradually lift the coiled tubing to the wellhead and resume the original operating conditions.

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