A deep-sea natural gas hydrate foam exploitation process system and a collaborative guarantee method

Abstract

The present invention relates to a deep - sea natural gas hydrate foam exploitation process system and a collaborative guarantee method, belonging to the technical field of deep - sea natural gas hydrate pressure - reduction exploitation technology. The system includes a chemical injection and control system, an underwater production and platform treatment system, and a hydrate foam exploitation wellbore production string system. Among them, the chemical injection and control system is connected to the underwater production and platform treatment system, the underwater production and platform treatment system is connected to the hydrate foam exploitation wellbore production string system, and the hydrate foam exploitation wellbore production string system is arranged in the wellbore on the seabed. The present invention makes full use of the unique fluid properties and flow characteristics of the foam system to collaboratively meet the flow guarantee requirements such as pressure control - anti - hydrate - drainage - sand carrying of the deep - sea natural gas hydrate exploitation process system, and guarantees the normal production of deep - sea natural gas hydrate exploitation wells.

Description

Technical Field

[0001] The present invention relates to a deep-sea natural gas hydrate foam exploitation process system and a collaborative guarantee method, belonging to the technical field of deep-sea natural gas hydrate pressure reduction exploitation technology. Background Art

[0002] The natural gas hydrate resources in the South China Sea are abundant and are important potential natural gas resources. In 2020, the second trial production of natural gas hydrate in the South China Sea was successfully completed, realizing the leap from exploratory trial production to experimental trial production, and proving the technical feasibility of exploiting the largest shale silt type hydrate reservoir with the "pressure reduction method + horizontal well". The shale silt type hydrate system in the South China Sea is a system composed of hydrates, pore water, sediments, etc. This system itself is widely distributed and has large reserves as a whole, but its resource quality is poor and the aggregation degree is weak. The hydrate reservoir is weakly cemented and non-diagenetic. During the pressure reduction exploitation process, under the set bottom hole pressure, the hydrate decomposition gas, hydrate decomposition water and free water, micron-sized shale silt below the sand control accuracy, etc. all enter the wellbore from the reservoir, forming a gas-water-sand multiphase flow system. The transport capacity of this multiphase flow system itself is weak: the fluctuations of the multiphase flow system hydraulic parameters affect the precise control of the bottom hole pressure within the pressure reduction range, and the system temperature and pressure distribution overlap with the hydrate phase equilibrium thermodynamic conditions, resulting in the secondary formation of gas hydrates, thus blocking the wellbore. The gas-liquid slippage in the system causes water accumulation in the wellbore, and the liquid-solid slippage in the system causes sand grains to settle in the wellbore, etc.

[0003] From trial production to commercial production, the production capacity increases by 2-3 orders of magnitude. The contradiction between the weak transport capacity of the multiphase flow system and the strict requirements for the flow guarantee of hydrate exploitation will be exponentially amplified with the production capacity. Therefore, the weak transport capacity of the multiphase flow system has become the bottleneck of the safe, efficient and low-carbon exploitation technology of hydrates.

[0004] The artificial regulation of the transport capacity of the multiphase flow system depends on the exploitation process. At present, the trial production of hydrates in the sea area is generally gas-water separate production: gas is produced through the gas production pipe string, and water and sand enter the drainage pipe string through the electric submersible pump. At this time, the solutions to different flow guarantee problems are not very coordinated or even contradictory to each other, significantly increasing the complexity of the overall trial production process system: sand passing through the electric submersible pump causes pump wear and shortens the pump maintenance cycle; the carrying effect of water on the produced sand is poor, especially in the horizontal wellbore, which is prone to sand settling accidents; gas-water separate production causes an increase in the number of hydrate risk pipelines, increasing the prevention and control difficulty, and the electric submersible pump boosting leads to an increase in hydrate risk; the large amount of thermodynamic inhibitor used for hydrate prevention increases the risk of liquid accumulation in the production wellbore; the presence of micron-sized sand grains affects the evolution characteristics of hydrate formation risk; the coupling of hydrates and sand grains increases the risk of pipeline blockage, etc.

[0005] The resource economic recoverability of deep-sea hydrates is poor under the existing technical conditions. To achieve the safe, efficient, and low-carbon commercial development of deep-sea hydrates, on the one hand, the single-well production needs to be increased (from the current trial production of 30,000 cubic meters per day to at least 200,000 cubic meters per day), and the well type of hydrates develops from vertical wells to complex structure wells with horizontal wells as the basic feature. The increase in production (gas production + water production + sand production), and the complex wellbore structure (the size and change of the wellbore inclination; multi-branch wells) bring greater challenges to the realization of the goals of mining process technologies such as "pressure control, anti-hydrate, drainage, and sand carrying". On the other hand, deep-sea natural gas hydrates, shallow gas, and deep-seated oil and gas have the coexistence in space and symbiosis in the same basin. The hydrate development mode has the objective conditions to be upgraded from the single development of hydrates to the three-gas combined production (hydrates, shallow gas, and conventional gas) stereoscopic development. It can not only realize the sharing of engineering facilities, but also the adjacent conventional deep-water gas reservoirs provide high-pressure gas sources for the hydrate mining process system. Therefore, there is an urgent need for a deep-sea natural gas hydrate mining process suitable for the above two changes, to provide an effective way for the coordinated guarantee of "pressure control - anti-hydrate - drainage - sand carrying" in the deep-sea natural gas hydrate mining, and to achieve the safe, efficient, and low-carbon commercial mining of deep-sea natural gas hydrates. Summary of the Invention

[0006] Aiming at the deficiencies of the existing technology, the present invention provides a deep-sea natural gas hydrate foam mining process system, which makes full use of the unique fluid properties and flow characteristics of the foam system to coordinately meet the flow guarantee requirements of the deep-sea natural gas hydrate mining process system such as pressure control - anti-hydrate - drainage - sand carrying, and guarantees the normal production of deep-sea natural gas hydrate production wells.

[0007] The present invention also provides a coordinated guarantee method for the above deep-sea natural gas hydrate foam mining process system.

[0008] The technical solution of the present invention is as follows:

[0009] A deep-sea natural gas hydrate foam mining process system includes a chemical injection and control system, an underwater production and platform treatment system, and a hydrate foam mining wellbore production string system. Among them, the chemical injection and control system is connected to the underwater production and platform treatment system, the underwater production and platform treatment system is connected to the hydrate foam mining wellbore production string system, and the hydrate foam mining wellbore production string system is arranged in the wellbore on the seabed.

[0010] Preferably according to the present invention, the chemical injection and control system includes a control station, an optical terminal unit, a platform umbilical terminal, a first storage tank, a first reciprocating pump, a second storage tank, a second reciprocating pump, a subsea umbilical terminal, and a subsea distribution control module. The control station and the optical terminal unit are respectively connected to the platform umbilical terminal. The first storage tank is connected to the platform umbilical terminal through the first reciprocating pump. The second storage tank is connected to the platform umbilical terminal through the second reciprocating pump. The platform umbilical terminal is connected to the subsea umbilical terminal through an umbilical cable. The subsea umbilical terminal is connected to the subsea distribution control module through an electro-hydraulic flying lead. The subsea distribution control module is further connected to a subsea production and platform processing system.

[0011] Further preferably according to the present invention, a first flowmeter is provided on the connecting pipeline between the first reciprocating pump and the platform umbilical terminal, and a second flowmeter is provided on the connecting pipeline between the second reciprocating pump and the platform umbilical terminal.

[0012] Preferably according to the present invention, the subsea production and platform processing system includes a subsea manifold, a third storage tank, a third reciprocating pump, a mixer, a separator, a subsea bundle pipe, and a subsea wellhead. One end of the subsea manifold is connected to a subsea pipeline, and the other end is connected to the subsea distribution control module through a jumper pipe. The third storage tank is connected to the mixer through the third reciprocating pump. One end of the separator is connected to a gas pipeline, and the other end is connected to the mixer. The mixer is connected to the subsea distribution control module through a riser. The subsea distribution control module is connected to the subsea bundle pipe. The subsea bundle pipe is connected to a connection stub through a subsea bundle pipe terminal. The connection stub is connected to the subsea wellhead. A hydrate foam production wellbore production string system is provided in the wellbore below the subsea wellhead. The subsea bundle pipe terminal is a docking structure between the subsea bundle pipe and the connection stub, which is a common structure for pipeline connection.

[0013] Further preferably according to the present invention, the subsea bundle pipe includes an outer pipe, and an air injection pipe, an optical fiber, a chemical agent pipeline, a gas production pipe, and an electric heating tape are arranged inside the outer pipe. The air injection pipe is connected to the jumper pipe through the subsea distribution control module. The optical fiber, the chemical agent pipeline, and the electric heating tape are connected to the electro-hydraulic flying lead through the subsea distribution control module. The gas production pipe is connected to the riser through the subsea distribution control module.

[0014] Preferably according to the present invention, a third flowmeter is provided on the pipeline between the third reciprocating pump and the mixer.

[0015] Preferably according to the present invention, the hydrate foam production wellbore production string system includes a coiled tubing, a fiber Bragg grating pressure sensor, a nozzle, and a downhole oil pipe. Among them, the downhole oil pipe and the coiled tubing are respectively arranged below the subsea wellhead. The fiber Bragg grating pressure sensor and the nozzle are sequentially arranged below the coiled tubing. The fiber Bragg grating pressure sensor is connected to the subsea wellhead through a downhole optical cable.

[0016] Further preferably according to the present invention, a check valve is provided between the fiber Bragg grating pressure sensor and the coiled tubing, and a downhole safety valve is provided on the lower side of the downhole tubing.

[0017] The collaborative guarantee method for the above deep-sea natural gas hydrate foam exploitation process system is as follows:

[0018] S1. Design of the collaborative guarantee plan for deep-sea natural gas hydrate foam exploitation. According to the requirements of flow assurance such as pressure control, hydrate prevention, drainage, and sand carrying in the wellbore and pipeline during the exploitation of deep-sea natural gas hydrates, design the safety production operation parameters for deep-sea natural gas hydrate foam exploitation, including the injection volume, injection rate, gas injection volume, and heating power of the foaming agent.

[0019] The pressure control plan is related to the hydraulic parameters of the foam flow system, including the density, viscosity, flow velocity, etc. of the foam fluid, and depends on production operation parameters such as the gas injection volume, foaming agent formula, and injection rate; the hydrate prevention plan is related to the pressure and temperature distribution of the foam flow system and the thermodynamic parameters of the hydrate phase equilibrium of the produced substances, including the pressure profile, temperature profile, and thermodynamic conditions of the hydrate phase equilibrium of the produced substances in the flow channel, and depends on production operation parameters such as the gas injection volume, type and injection rate of the hydrate thermodynamic inhibitor, and heating power; the drainage plan is related to the flow velocity, gas content rate of the foam, and structural stability of the foam system, and depends on production operation parameters such as the gas injection volume, foaming agent formula and injection rate, defoaming agent formula and injection rate; the sand carrying plan is related to the flow velocity, foam structure, and viscosity of the foam fluid of the foam flow system, and depends on production operation parameters such as the gas injection volume, foaming agent formula and injection rate.

[0020] S2. The chemical injection and control system realizes the regulation of the gas injection volume near the gas reservoir, the quantitative regulation of the electric heating power, the monitoring of the temperature along the way, and the quantitative injection of chemicals:

[0021] The subsea pipeline is connected to the nearby gas reservoir, and the nearby gas reservoir is connected to the underwater distribution control module through a crossover pipe. The control station adjusts the opening degree of the corresponding valve in the underwater distribution control module in sequence through the platform umbilical cable terminal, the underwater umbilical cable terminal, and the electro-hydraulic flying wire according to the gas injection volume regulation plan, so as to realize the regulation of the injection gas flow rate of the nearby gas reservoir. The high-temperature natural gas from the nearby gas reservoir is used as a natural heat source to provide a natural heating means for the subsea bundle pipe of the nearby underwater distribution control module.

[0022] The control station changes the electric heating power of the electric heating tape according to the electric heating power quantitative regulation plan to realize the regulation of the electric heating power in the subsea flow channel for hydrate exploitation, providing an artificial heating means for preventing hydrates in the underwater production system and removing hydrate blockages under accidental conditions.

[0023] The optical terminal realizes the emission, reception, and processing of pulsed optical signals, thereby obtaining the temperature distribution measurement results within the fiber optic layout range, providing temperature monitoring data for the flow assurance of the underwater production system;

[0024] Quantitative chemical injection, including the quantitative injection of foaming agent and hydrate thermodynamic inhibitor. The foaming agent is stored in the first storage tank, and the injection rate is regulated by the first reciprocating pump, and the injection rate is monitored by the first flowmeter. The hydrate thermodynamic inhibitor is stored in the second storage tank, the injection rate is regulated by the second reciprocating pump, and the injection rate is monitored by the second flowmeter. The foaming agent and the hydrate thermodynamic inhibitor are successively transported through the platform umbilical terminal, underwater umbilical terminal, electro-hydraulic flying lead, underwater distribution control module, subsea bundle pipe, connecting spool, and underwater wellhead to the coiled tubing in the wellbore, and then enter the production wellbore through the fiber Bragg grating pressure sensor and the nozzle, so as to realize the mixing with the multiphase flow system in the hydrate production wellbore. The fiber Bragg grating pressure sensor realizes the measurement of the bottom hole pressure and transmits the data through the downhole optical cable. The nozzle ensures that the injected gas and foaming agent uniformly enter the production wellbore from the coiled tubing, improving the mixing and foaming effect;

[0025] S3. The underwater production and platform processing system realizes the transportation of gas injection from the adjacent gas reservoir to the underwater wellhead of the hydrate production well from the conventional gas reservoir, the foam transportation of the produced fluid from the underwater wellhead of the hydrate production well to the central platform, the platform processing of the foam system, and the flow assurance of the underwater production system;

[0026] The foaming agent and the injected gas enter the wellbore and mix with the produced substances in the wellbore to form a foam flow system. The foam flow system is transported from underwater to the central platform on the sea surface. The foam flow system is successively transported to the mixer through the downhole tubing, underwater wellhead, connecting spool, subsea bundle pipe terminal, gas production pipeline in the subsea bundle pipe, underwater distribution control module, and riser;

[0027] Platform processing of the foam system. The defoaming agent is stored in the third storage tank, the injection rate is regulated by the third reciprocating pump, and the injection rate is monitored by the third flowmeter. The defoaming agent is injected into the mixer and mixed with the foam flow system in the mixer to atomize the defoaming agent. The foam flow system injected with the defoaming agent gradually defoams during the flow in the separator inlet pipeline and turns into a gas-liquid two-phase flow system, and then enters the separator to realize gas-liquid separation. The separated gas phase enters the natural gas processing system of the central platform through the gas pipeline.

[0028] The beneficial effects of the present invention are as follows:

[0029] (1) In the present invention, the foam production process system has a simple structure, does not require gas and water separation pipelines and their respective supporting artificial lift equipment, and significantly reduces the system complexity.

[0030] (2) In the present invention, the foam production collaborative guarantee method is safe, efficient, and low-carbon. The flow path is simple, and the system monitoring and control functions are perfect and reliable, meeting safety requirements; based on the foam flow system, it collaboratively addresses all the flow guarantee safety problems of "pressure control - hydrate prevention - drainage - sand carrying", meeting the high-efficiency requirements; by utilizing the energy of adjacent gas reservoirs and low-dose chemical agents, the low-carbon goal is achieved.

[0031] (3) In the present invention, the cost reduction and efficiency increase are remarkable. The foam production process system fully relies on the central platform and subsea production system used in the development of adjacent conventional deep-water gas reservoirs, jointly develops deep-sea hydrate reservoirs and conventional gas reservoirs, reducing engineering investment; the structure of the foam production process system is simple, shortening the installation period and reducing the installation operation cost; the foam production collaborative guarantee method is safe and efficient, reducing the frequency of pigging operations and the production operation cost.

[0032] (4) In the present invention, core equipment such as subsea bundle pipes and coiled tubing can be recycled and reused. The production characteristics of the composite hydrate well with a short production cycle are suitable for the implementation of rolling development and other schemes.

[0033] (5) In the present invention, the system and method have the ability to respond to dangerous scenarios such as hydrate blockage and have various hydrate plug removal methods. Brief Description of the Drawings

[0034] Figure 1 It is a schematic diagram of the deep-sea natural gas hydrate foam production process system in the embodiment of the present invention.

[0035] Figure 2 It is a schematic diagram of the subsea bundle pipe in the embodiment of the present invention.

[0036] The reference numerals in the above-mentioned drawings respectively represent: 1 - control station; 2 - control cable; 3 - optical terminal unit; 4 - platform optical cable; 5 - platform umbilical cable terminal; 6 - first storage tank; 7 - first reciprocating pump; 8 - first flowmeter; 9 - first chemical agent pipeline; 10 - second storage tank; 11 - second reciprocating pump; 12 - second flowmeter; 13 - second chemical agent pipeline; 14 - umbilical cable; 15 - subsea umbilical cable terminal; 16 - electro-hydraulic flying lead; 17 - subsea distribution control module; 18 - subsea pipeline; 19 - subsea manifold; 20 - jumper pipe; 21 - riser; 22 - mixer; 23 - third storage tank; 24 - third reciprocating pump; 25 - third flowmeter; 26 - third chemical agent pipeline; 27 - separator inlet pipeline; 28 - separator; 29 - gas pipeline; 30 - subsea bundle pipe; 31 - subsea bundle pipe terminal; 32 - connecting nipple; 33 - subsea wellhead; 34 - downhole tubing; 35 - downhole safety valve; 36 - downhole optical cable; 37 - coiled tubing; 38 - check valve; 39 - fiber Bragg grating pressure sensor; 40 - nozzle; 41 - central platform; 42 - sea surface; 43 - seabed; 44 - wellbore.

[0037] 301 - External pipeline; 302 - Gas injection pipeline; 303 - Optical fiber; 304 - Chemical agent pipeline; 305 - Gas production pipeline; 306 - Electric tracing tape. Specific embodiments

[0038] The present invention will be further described below by way of examples in conjunction with the accompanying drawings, but is not limited thereto.

[0039] Example 1:

[0040] As Figure 1 and Figure 2 shown, this example provides a deep - sea natural gas hydrate foam exploitation process system, including a chemical agent injection and control system, an underwater production and platform processing system, and a hydrate foam exploitation wellbore production string system. Among them, the chemical agent injection and control system is connected to the underwater production and platform processing system, the underwater production and platform processing system is connected to the hydrate foam exploitation wellbore production string system, and the hydrate foam exploitation wellbore production string system is arranged in the wellbore 44 on the seabed.

[0041] Preferably according to the present invention, the chemical agent injection and control system includes a control station 1, an optical terminal 3, a platform umbilical cable terminal 5, a first storage tank 6, a first reciprocating pump 7, a second storage tank 10, a second reciprocating pump 11, an underwater umbilical cable terminal 15, and an underwater distribution control module 17. The control station 1 and the optical terminal 3 are respectively connected to the platform umbilical cable terminal 5 through a control cable 2 and a platform optical cable 4. The first storage tank 6 is connected to the platform umbilical cable terminal 5 through the first reciprocating pump 7 and a first chemical agent pipeline 9. The second storage tank 10 is connected to the platform umbilical cable terminal 5 through the second reciprocating pump 11 and a second chemical agent pipeline 13. The platform umbilical cable terminal 5 is connected to the underwater umbilical cable terminal 15 through an umbilical cable 14. The underwater umbilical cable terminal 15 is connected to the underwater distribution control module 17 through an electro - hydraulic flying lead 16, and the underwater distribution control module 17 is also connected to the underwater production and platform processing system.

[0042] A first flowmeter 8 is arranged on the first chemical agent pipeline 9 between the first reciprocating pump 7 and the platform umbilical cable terminal 5, and a second flowmeter 12 is arranged on the second chemical agent pipeline 13 between the second reciprocating pump 11 and the platform umbilical cable terminal 5.

[0043] The subsea production and platform processing system includes a subsea manifold 19, a third storage tank 23, a third reciprocating pump 24, a mixer 22, a separator 28, a subsea umbilical 30 and a subsea wellhead 33. One end of the subsea manifold 19 is connected to a subsea pipeline 18, and the other end is connected to a subsea distribution control module 17 through a jumper pipe 20. The third storage tank 23 is connected to the mixer 22 through the third reciprocating pump 24 and a third chemical agent pipeline 26. One end of the separator 28 is connected to a gas pipeline 29, and the other end is connected to the mixer 22. The mixer 22 is connected to the subsea distribution control module 17 through a riser pipe 21. The subsea distribution control module 17 is connected to the subsea umbilical 30. The subsea umbilical 30 is connected to a connecting spool 32 through a subsea umbilical termination 31. The connecting spool 32 is connected to the subsea wellhead 33. Inside the wellbore 44 below the subsea wellhead 33, a hydrate foam production wellbore string system is provided. The subsea umbilical termination is a docking structure between the subsea umbilical and the connecting spool, which is a common structure for pipeline connection.

[0044] The subsea umbilical 30 includes an outer pipeline 301. Inside the outer pipeline 301, there are an injection gas pipeline 302, an optical fiber 303, a chemical agent pipeline 304, a gas production pipeline 305 and an electric tracing tape 306. The injection gas pipeline 302 is connected to the jumper pipe 20 through the subsea distribution control module 17. The optical fiber 303, the chemical agent pipeline 304 and the electric tracing tape 306 are connected to an electro-hydraulic flying lead 16 through the subsea distribution control module 17. The gas production pipeline 305 is connected to the riser pipe 21 through the subsea distribution control module. The subsea umbilical and the connecting spool have the same structure.

[0045] A third flowmeter 25 is provided on the third chemical agent pipeline 26 between the third reciprocating pump 24 and the mixer 22.

[0046] The hydrate foam production wellbore string system includes a coiled tubing 37, a fiber Bragg grating pressure sensor 39, a spray head 40 and a downhole tubing 34. Among them, the downhole tubing 34 and the coiled tubing 37 are respectively arranged below the subsea wellhead 33. Below the coiled tubing 37, the fiber Bragg grating pressure sensor 39 and the spray head 40 are successively arranged. The fiber Bragg grating pressure sensor 39 is connected to the subsea wellhead 33 through a downhole optical cable 36. The optical fiber inside the subsea umbilical is connected to the downhole optical cable 36 through the subsea wellhead 33. The injection gas pipeline 302 and the chemical agent pipeline 304 are connected to the coiled tubing 37 through the subsea wellhead 33. The gas production pipeline 305 is connected to the downhole tubing 34.

[0047] The underwater distribution control module 17 is composed of valves, optical fiber lines, cable lines, flow pipelines, and a supporting frame. Among them, the valve opening is adjustable to achieve the regulation of gas-liquid flow; the optical fiber line realizes the connection between the optical fibers in the electro-hydraulic flying wire 16 and the optical fibers in the subsea umbilical tube 30; the cable line realizes the connection between the cables in the electro-hydraulic flying wire 16 and the electric tracing tape in the subsea umbilical tube 30; the flow pipeline realizes the connection of the upstream and downstream pipelines of the underwater distribution module 17. For example, the connection between the jumper pipe 20 and the gas injection pipeline 302 in the subsea umbilical tube 30, the connection between the chemical agent pipeline in the electro-hydraulic flying wire 16 and the chemical agent pipeline 304 in the subsea umbilical tube 30, the connection between the gas production pipeline 305 in the subsea umbilical tube 30 and the riser 21. The underwater distribution control module 17 is an integration of existing valves, lines, and pipelines, which is convenient for connection and use.

[0048] A check valve 38 is arranged between the fiber Bragg grating pressure sensor 39 and the coiled tubing 37, and a downhole safety valve 35 is arranged on the lower side of the downhole tubing 34.

[0049] The collaborative guarantee method for the above deep-sea natural gas hydrate foam exploitation process system is as follows:

[0050] S1. Design of the collaborative guarantee plan for deep-sea natural gas hydrate foam exploitation. According to the requirements of flow guarantee such as pressure control, hydrate prevention, drainage, and sand carrying in the wellbore and pipelines during deep-sea natural gas hydrate exploitation, design the safety production operation parameters for deep-sea natural gas hydrate foam exploitation, including the injection amount of foaming agent, injection rate, gas injection volume, and heating power.

[0051] The pressure control plan is related to the hydraulic parameters of the foam flow system, including foam fluid density, viscosity, flow velocity, etc., and depends on production operation parameters such as gas injection volume, foaming agent formula, and injection rate; the hydrate prevention plan is related to the pressure and temperature distribution of the foam flow system and the thermodynamic parameters of the hydrate phase equilibrium of the produced substances, including the pressure profile, temperature profile, and thermodynamic conditions of the hydrate phase equilibrium of the produced substances in the flow channel, and depends on production operation parameters such as gas injection volume, type and injection rate of hydrate thermodynamic inhibitor, and heating power; the drainage plan is related to the flow velocity of the foam flow system, foam gas content, and structural stability of the foam system, and depends on production operation parameters such as gas injection volume, foaming agent formula and injection rate, defoaming agent formula and injection rate; the sand carrying plan is related to the flow velocity of the foam flow system, foam structure, and viscosity of the foam fluid, and depends on production operation parameters such as gas injection volume, foaming agent formula and injection rate.

[0052] S2. The chemical agent injection and control system realizes the regulation of gas injection volume near the gas reservoir, the quantitative regulation of electric heating power, the monitoring of temperature along the way, and the quantitative injection of chemical agents:

[0053] The subsea pipeline is connected to the adjacent gas reservoir. The adjacent gas reservoir is connected to the underwater distribution control module through a crossover pipe. According to the injection gas volume regulation plan, the control station sequentially changes the opening degree of the corresponding valves in the underwater distribution control module through the platform umbilical cable terminal, the underwater umbilical cable terminal, and the electro-hydraulic flying lead, so as to realize the regulation of the injection gas flow rate of the adjacent gas reservoir. The high-temperature natural gas from the adjacent gas reservoir is used as a natural heat source to provide a natural heating means for the subsea bundle pipe 30 of the adjacent underwater distribution control module 17;

[0054] The control station changes the electric heating power of the electric heating tape 306 according to the electric heating power quantitative regulation plan, so as to realize the regulation of the electric heating power in the subsea flow path for hydrate production, and provide an artificial heating means for preventing hydrates and removing hydrate blockages under accidental conditions in the underwater production system;

[0055] The optical terminal realizes the emission, reception, and processing of pulsed optical signals, so as to obtain the temperature distribution measurement results within the range of the optical fiber layout, and provide temperature monitoring data for the flow assurance of the underwater production system;

[0056] Quantitative injection of chemicals includes the quantitative injection of foaming agent and the quantitative injection of hydrate thermodynamic inhibitor. The foaming agent is stored in the first storage tank 6, and the injection rate is regulated by the first reciprocating pump 7. The first flowmeter 8 monitors the injection rate. The hydrate thermodynamic inhibitor is stored in the second storage tank 10, and the injection rate is regulated by the second reciprocating pump 11. The second flowmeter 12 monitors the injection rate. The foaming agent and the hydrate thermodynamic inhibitor are sequentially transported through the platform umbilical cable terminal 5, the underwater umbilical cable terminal 15, the electro-hydraulic flying lead 16, the underwater distribution control module 17, the subsea bundle pipe, the connecting nipple, and the underwater wellhead to the coiled tubing in the wellbore, and then enter the production wellbore through the fiber Bragg grating pressure sensor 39 and the nozzle 40, so as to realize the mixing with the multiphase flow system in the hydrate production wellbore. The fiber Bragg grating pressure sensor 39 realizes the measurement of the bottom hole pressure and transmits the data through the downhole optical cable 36. The nozzle 40 ensures that the injection gas and the foaming agent uniformly enter the production wellbore from the coiled tubing 37, improving the mixing and foaming effect;

[0057] S3. The underwater production and platform processing system realizes the transportation of the injection gas from the adjacent gas reservoir to the underwater wellhead of the hydrate production well, the foam transportation of the produced fluid from the underwater wellhead of the hydrate production well to the central platform, the platform processing of the foam system, and the flow assurance of the underwater production system;

[0058] The foaming agent and the injection gas enter the wellbore and are mixed with the produced substances in the wellbore to form a foam flow system. The foam flow system is transported underwater to the central platform 41 on the sea surface 42. The foam flow system is sequentially transported to the mixer 22 through the downhole tubing 34, the underwater wellhead 33, the connecting nipple 32, the subsea bundle pipe terminal 31, the gas production pipeline 305 in the subsea bundle pipe 30, the underwater distribution control module 17, and the riser 21;

[0059] Treatment of the foam system platform: The defoamer is stored in the third storage tank 23. The third reciprocating pump 24 regulates the injection rate, and the third flowmeter 25 monitors the injection rate. The defoamer is injected into the mixer 22 and mixed with the foam flow system in the mixer 22 to atomize the defoamer and inject it into the foam flow system with the defoamer. Along with the flow in the separator inlet pipeline 27, defoaming is gradually achieved. After transforming into a gas-liquid two-phase flow system, it enters the separator 28 to achieve gas-liquid separation. The separated gas phase enters the central platform natural gas treatment system through the gas pipeline 29.

[0060] Flow assurance of the subsea production system: The optical fiber 303 in the subsea bundle pipe 30 can realize the distributed measurement of the temperature of the subsea bundle pipe 30, thereby providing temperature data for flow assurance of the subsea production system; the chemical agent pipeline 304 in the subsea bundle pipe 30 provides a channel for injecting the chemicals required for flow assurance of the subsea production system; the gas injection pipeline 302 in the subsea bundle pipe 30 uses the high-temperature natural gas from the conventional deep-water gas reservoir as a natural heat source to provide a natural heating means for the subsea bundle pipe 30 within a certain range near the subsea distribution control module 17; the electric heating tape 306 in the subsea bundle pipe 30 provides an artificial heating means for preventing hydrates in the subsea production system and removing hydrate blockages under accidental conditions.

[0061] The production string system for hydrate foam production realizes the transformation of the multiphase flow system in the hydrate production wellbore into a foam flow system, the transportation of the foam flow system from the bottom of the well to the wellhead, and the flow assurance of the production wellbore.

[0062] The transformation of the multiphase flow system in the hydrate production wellbore into a foam flow system is to inject the injection gas and foaming agent from the subsea production and platform treatment subsystem into the production wellbore and mix them with the produced fluid to form a foam flow system; the injection gas and foaming agent both enter the production wellbore through the coiled tubing 37, check valve 38, fiber Bragg grating pressure sensor 39, and nozzle 40 in sequence, so as to realize the mixing with the multiphase flow system in the hydrate production wellbore; the size and running depth of the coiled tubing 37 are designed according to the gas injection-foam drainage production plan for the hydrate production wellbore; the check valve 38 prevents the fluid in the wellbore from entering the coiled tubing 37; the fiber Bragg grating pressure sensor 39 realizes the measurement of the bottom hole pressure and transmits the data through the downhole optical cable 36; the nozzle 40 ensures that the injection gas and foaming agent uniformly enter the production wellbore from the coiled tubing 37, improving the mixing and foaming effects.

[0063] The foam flow system is transported from the bottom of the well to the wellhead, i.e., the foam flow system formed at the bottom of the well is lifted from the bottom of the well to the wellhead. The foam flow system contains all the production outputs of the hydrate reservoir, including gas, water, sand, etc.; the foam flow system flows in the annulus of the coiled tubing 37 in the production wellbore, passes through the downhole safety valve 35, enters the downhole tubing 34, and then enters the underwater production and platform processing system; the setting depth of the downhole tubing 34 is designed based on the principle of being the shortest.

[0064] During implementation, the subsea manifold 30, subsea manifold terminal 31, connecting spool 32, underwater wellhead 33 in the underwater production and platform processing system, and the downhole tubing 34, downhole safety valve 35, downhole optical cable 36, coiled tubing 37, check valve 38, fiber Bragg grating pressure sensor 39, and nozzle 40 in the production string subsystem of the hydrate foam production wellbore can be reapplied to a newly built hydrate production well after the production of a hydrate production well is completed, solving the problem of the shared production system caused by the significantly shorter production cycle of the hydrate production well than that of a conventional gas well, and facilitating the implementation of more economical schemes such as the rolling development of deep-sea hydrates.

[0065] The above embodiments are only used to illustrate the technical solutions of the present invention and not to limit them. Although the present invention has been described in detail with reference to the preferred embodiments, those of ordinary skill in the art should understand that the technical solutions of the present invention can be modified or equivalently replaced without departing from the spirit and scope of the technical solutions of the present invention, and they should all be covered within the scope of the claims of the present invention.

Claims

1. A deep-sea natural gas hydrate foam exploitation process system, characterized in that, It includes a chemical injection and control system, an underwater production and platform processing system, and a hydrate foam production string system for wellbores. Among them, the chemical injection and control system is connected to the underwater production and platform processing system, the underwater production and platform processing system is connected to the hydrate foam production string system for wellbores, and the hydrate foam production string system for wellbores is arranged in the wellbore on the seabed; The chemical injection and control system includes a control station, an optical terminal unit, a platform umbilical terminal, a first storage tank, a first reciprocating pump, a second storage tank, a second reciprocating pump, an underwater umbilical terminal, and an underwater distribution control module. The control station and the optical terminal unit are both connected to the platform umbilical terminal. The first storage tank is connected to the platform umbilical terminal through the first reciprocating pump. The second storage tank is connected to the platform umbilical terminal through the second reciprocating pump. The platform umbilical terminal is connected to the underwater umbilical terminal through an umbilical cable. The underwater umbilical terminal is connected to the underwater distribution control module through an electro-hydraulic flying lead. The underwater distribution control module is also connected to the underwater production and platform processing system; The underwater production and platform processing system includes an underwater manifold, a third storage tank, a third reciprocating pump, a mixer, a separator, a subsea bundle pipe, and an underwater wellhead. One end of the underwater manifold is connected to a subsea pipeline, and the other end is connected to the underwater distribution control module through a jumper pipe. The third storage tank is connected to the mixer through the third reciprocating pump. One end of the separator is connected to a gas pipeline, and the other end is connected to the mixer. The mixer is connected to the underwater distribution control module through a riser. The underwater distribution control module is connected to the subsea bundle pipe. The subsea bundle pipe is connected to a connecting spool through a subsea bundle pipe terminal. The connecting spool is connected to the underwater wellhead. The hydrate foam production string system for wellbores is arranged in the wellbore below the underwater wellhead; The subsea bundle pipe includes an outer pipe, and an air injection pipe, an optical fiber, a chemical agent pipeline, a gas production pipe, and an electric tracing tape are arranged in the outer pipe. The air injection pipe is connected to the jumper pipe through the underwater distribution control module. The optical fiber, the chemical agent pipeline, and the electric tracing tape are connected to the electro-hydraulic flying lead through the underwater distribution control module. The gas production pipe is connected to the riser through the underwater distribution control module; The hydrate foam production string system for wellbores includes a coiled tubing, a fiber Bragg grating pressure sensor, a nozzle, and a downhole tubing. Among them, the downhole tubing and the coiled tubing are respectively arranged below the underwater wellhead. The fiber Bragg grating pressure sensor and the nozzle are sequentially arranged below the coiled tubing. The fiber Bragg grating pressure sensor is connected to the underwater wellhead through a downhole optical cable.

2. The deep-sea natural gas hydrate foam exploitation process system according to claim 1, wherein A first flowmeter is arranged on the pipeline between the first reciprocating pump and the platform umbilical terminal. A second flowmeter is arranged on the pipeline between the second reciprocating pump and the platform umbilical terminal.

3. The deep-sea natural gas hydrate foam exploitation process system according to claim 2, wherein A third flowmeter is arranged on the pipeline between the third reciprocating pump and the mixer.

4. The deep-sea natural gas hydrate foam exploitation process system according to claim 3, characterized in that A check valve is arranged between the fiber Bragg grating pressure sensor and the coiled tubing. A downhole safety valve is arranged below the downhole tubing.

5. The collaborative guarantee method for the deep-sea natural gas hydrate foam exploitation process system according to claim 4, characterized in that, The steps are as follows: S1. Design of the collaborative guarantee scheme for deep-sea natural gas hydrate foam exploitation. According to the requirements of pressure control, hydrate prevention, drainage, and sand-carrying flow guarantee in the wellbore and pipeline during deep-sea natural gas hydrate exploitation, design the safe production operation parameters for deep-sea natural gas hydrate foam exploitation, including the injection volume, injection rate, gas injection volume, and heating power of the foaming agent. S2. The agent injection and control system realizes the regulation of the gas injection volume of the adjacent gas reservoir, the quantitative regulation of the electric heating power, the temperature monitoring along the way, and the quantitative injection of the agent: The subsea pipeline is connected to the adjacent gas reservoir, and the adjacent gas reservoir is connected to the underwater distribution control module through a crossover pipe. According to the gas injection volume regulation scheme, the control station sequentially changes the opening degree of the corresponding valve in the underwater distribution control module through the platform umbilical cable terminal, underwater umbilical cable terminal, and electro-hydraulic flying lead, realizing the regulation of the injected gas flow rate of the adjacent gas reservoir. The high-temperature natural gas from the adjacent gas reservoir is used as a natural heat source to provide a natural heating means for the subsea bundle pipe near the underwater distribution control module. The control station changes the electric heating power of the electric heating tape according to the electric heating power quantitative regulation scheme, realizing the regulation of the electric heating power in the subsea flow path during hydrate exploitation, providing an artificial heating means for hydrate prevention in the underwater production system and removing hydrate blockages under accidental conditions. The optical terminal unit obtains the temperature distribution measurement results within the range of the optical fiber layout, providing temperature monitoring data for the flow guarantee of the underwater production system. Quantitative injection of the agent, including the quantitative injection of the foaming agent and the thermodynamic inhibitor for hydrates. The foaming agent is stored in the first storage tank, and the injection rate is regulated by the first reciprocating pump, and the injection rate is monitored by the first flowmeter. The thermodynamic inhibitor for hydrates is stored in the second storage tank, and the injection rate is regulated by the second reciprocating pump, and the injection rate is monitored by the second flowmeter. The foaming agent and the thermodynamic inhibitor for hydrates are sequentially transported through the platform umbilical cable terminal, underwater umbilical cable terminal, electro-hydraulic flying lead, underwater distribution control module, subsea bundle pipe, connecting nipple, and underwater wellhead to the coiled tubing in the wellbore, and then enter the exploitation wellbore through the fiber Bragg grating pressure sensor and the nozzle, thus realizing the mixing with the multiphase flow system in the hydrate exploitation wellbore. The fiber Bragg grating pressure sensor realizes the measurement of the bottom hole pressure and transmits the data through the downhole optical cable. The nozzle ensures that the injected gas and the foaming agent enter the exploitation wellbore evenly from the coiled tubing. S3. The underwater production and platform processing system realizes the transportation of the gas injection from the adjacent gas reservoir to the underwater wellhead of the hydrate exploitation well, the foam transportation of the produced fluid from the underwater wellhead of the hydrate exploitation well to the central platform, the platform processing of the foam system, and the flow guarantee of the underwater production system. The foaming agent and the injected gas enter the wellbore and mix with the produced substances in the wellbore to form a foam flow system. The foam flow system is transported from underwater to the central platform on the sea surface. The foam flow system is sequentially transported to the mixer through the downhole tubing, underwater wellhead, connecting nipple, terminal of the subsea bundle pipe, gas production pipeline in the subsea bundle pipe, underwater distribution control module, and riser. Treatment of the foam system platform. The defoamer is stored in the third storage tank. The third reciprocating pump regulates the injection rate. The third flowmeter monitors the injection rate. The defoamer is injected into the mixer and mixed with the foam flow system in the mixer to atomize the defoamer. The foam flow system with the defoamer injected undergoes defoaming gradually along with the flow in the separator inlet pipeline. After being transformed into a gas-liquid two-phase flow system, it enters the separator to achieve gas-liquid separation. The separated gas phase enters the central platform natural gas treatment system.

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