A system and process for recovering natural gas hydrate in offshore horizontal wells

Abstract

The present invention provides a system and a process method for the segmented recovery of marine natural gas hydrate horizontal wells. The segmented recovery subsystem realizes sequential recovery of the corresponding stages in spatial positions from the toe end to the root end of the horizontal section in accordance with the recovery sequence through a mobile recovery system. The foam lifting subsystem injects high-pressure gas and foaming agent into the production wellbore to realize the transformation of the flow system in the production wellbore into a foam flow system. The platform processing subsystem processes the output of the production wellbore to realize the separation of gas, liquid and solid. According to the stage division of the horizontal section of the marine natural gas hydrate horizontal well, the production capacity of the production stage, risk monitoring and analysis, sand cleaning of the production system and return to the adjacent upstream stage of production, and the complete recovery and evaluation optimization of the production system, the process method realizes the fine processing of the heterogeneity of the hydrate reservoir in space, and the coordinated processing of the production capacity and risk in time, thereby significantly reducing costs and increasing efficiency.

Description

Technical Field

[0001] The present invention relates to the technical field of resource exploitation systems, and in particular to a system and a process method for recovering marine natural gas hydrates in horizontal wells. Background Art

[0002] The offshore hydrate well production system is a necessary system for lifting the gas, water, sand, etc. produced by the decomposition of the hydrate reservoir from the bottom of the well to the central platform. The existing offshore natural gas hydrate pilot production technology takes the gas and water production system as the starting point, and separately designs solutions for the process links such as drainage, pressure control, water hydrate prevention, and sand carrying. The pilot production system structure is complex, and the corresponding process methods are cumbersome and even conflicting. The main technical difficulties are as follows:

[0003] (1) In terms of safety, the sand production in the hydrate reservoir leads to the risk of sand burial in the production string of the hydrate well production system. The longer the production time of the hydrate well, the more serious the sand production and material loss in the reservoir, the higher the risk of sand burial, and even the reservoir collapses and damages the production casing. Horizontal wells lead to a large amount of sand production in the production wellbore in the entire horizontal section. The longer the horizontal well section, the greater the impact of the heterogeneity of the hydrate reservoir. Sand burial at any position will affect the entire production system. Horizontal wells also lead to poor sand carrying capacity in the wellbore, which is easy to cause sand to settle and accumulate in the well, thus forming a blockage. Hydrate secondary generation blocks the production string of the hydrate well production system. In the gas-water production system, the gas and liquid in the well cannot be completely separated, resulting in the gas and liquid two-phase system in the gas production string and the water production string. However, due to the different gas content, the risk of secondary hydrate generation in the system is different. Horizontal wells change the direction of the production string, affecting the transport characteristics of the gas-liquid two-phase flow system in the production string, making it more difficult to prevent and control the secondary production risk of hydrates in the production system.

[0004] (2) In terms of efficiency, horizontal wells increase the contact area between the wellbore and the hydrate reservoir, improving production efficiency; the longer the horizontal section, the larger the contact area, but at the same time, the problems of hydrate reservoir heterogeneity and the maximum length of horizontal well production are more prominent. The existing gas-water production system relies on the downhole electric submersible pump to control the production pressure difference in the production wellbore. The control effect is significantly affected by the separation efficiency of the downhole gas-liquid separator. Horizontal wells increase the difficulty of downhole gas-liquid separation, thereby affecting the control of the production pressure difference by the electric submersible pump. In addition, solid impurities such as sand particles in the production string cause wear of the electric submersible pump, shorten the maintenance cycle, and reduce mining efficiency; the degree of sediment blockage of the sand control medium increases over time, increasing the inflow resistance and reducing the gas production rate of the hydrate well.

[0005] (3) In terms of economy, the changes of gas production rate of hydrate reservoir over time include rising stage, rapid decline stage and slow decline stage, and the stable production time of reservoir is short. The existing hydrate reservoir production system has complex structure and process, resulting in high capital expenditure and operating cost, which increases cumulatively with the extension of horizontal wellbore length.

[0006] (4) In terms of low carbon, the core equipment for artificial lift in existing hydrate well gas and water production systems is the electric submersible pump, which consumes a lot of energy. The gas-liquid two-phase inlet conditions and the increase in head caused by the increase in horizontal wellbore length further increase the energy consumption of the electric submersible pump. The prevention and control of secondary hydrate formation requires a large amount of thermodynamic inhibitor loss and a large energy consumption in the regeneration system, which does not meet the low carbon requirements.

[0007] In summary, the current inadequacies of the production system and process technology of offshore natural gas hydrate wells in terms of safety, efficiency, economy, and low carbon have constrained its industrialization to the commercial exploitation stage, and horizontal wells have made the above-mentioned inadequacies more prominent. Therefore, there is an urgent need for a safe, efficient, economical, and low-carbon production system and method specifically for offshore natural gas hydrate horizontal wells. Summary of the invention

[0008] In view of the above-mentioned technical deficiencies, the purpose of the present invention is to provide a staged recovery system and process method for marine natural gas hydrate horizontal wells, which can eliminate pressure fluctuations, improve pressure control accuracy, reduce maintenance frequency, improve mining efficiency, have a simple and recyclable structure, reduce capital expenditures, and achieve low-carbon drainage.

[0009] To achieve the above object, the present invention adopts the following technical solution:

[0010] A staged recovery system for marine natural gas hydrate horizontal wells comprises a staged recovery subsystem, a foam lifting subsystem and a platform processing subsystem; the top of the staged recovery subsystem is respectively connected to the foam lifting subsystem and the platform processing subsystem; the staged recovery subsystem is used for moving the mining system, corresponding to each stage in spatial position from the toe end to the root end of the horizontal section in the recovery sequence; the foam lifting subsystem is used for injecting high-pressure gas and foaming agent into the production wellbore to realize the transformation of the flow system in the production wellbore into the foam flow system; the platform processing subsystem is used for processing the output of the production wellbore, eliminating foam and realizing the separation of gas, liquid and solid.

[0011] Preferably, the staged recovery subsystem includes a production pipeline, a slotted casing, a head repeatable sealing packer, a double-layer coiled tubing telescopic connector, a sand control screen, an internal tubing, an internal tubing centralizer, a check valve, a downhole pressure thermometer, a connecting nipple, a bottom repeatable sealing packer, a guide centralizer, a double-layer coiled tubing wellhead device, a double-layer coiled tubing, a double-layer coiled tubing drum, and a dual-channel drum shaft rotating head;

[0012] The part of the double-layer continuous oil tubing at the upstream of the double-layer continuous oil tubing wellhead device is wound on the double-layer continuous oil tubing drum, and the part at the downstream of the double-layer continuous oil tubing wellhead device is located inside the production pipeline and the slotted casing; the top of the double-layer continuous oil tubing is connected to the double-channel drum shaft rotating head; the bottom of the double-layer continuous oil tubing is connected to the double-layer continuous oil tubing telescopic connector, the sand screen, the connecting short section, the bottom repeatable sealing packer, and the guide stabilizer in sequence; the head repeatable sealing packer is installed in the annulus between the double-layer continuous oil tubing and the slotted casing, and is located upstream of the double-layer continuous oil tubing telescopic connector; the built-in oil tubing is located inside the sand screen; the built-in oil tubing is aligned with the upstream end of the sand screen; the built-in oil tubing centralizer is located in the annulus between the built-in oil tubing and the sand screen; the bottom of the built-in oil tubing is installed with a single flow valve and a downhole pressure thermometer in sequence from upstream to downstream.

[0013] Preferably, the double-layer continuous oil tubing includes an outer layer continuous oil tubing and an inner layer continuous oil tubing; an annulus is formed between the outer layer continuous oil tubing and the inner layer continuous oil tubing; the dual-channel drum shaft rotating head provides dual channels, one channel corresponds to the internal flow channel of the inner layer continuous oil tubing, and the other channel corresponds to the annulus formed by the outer layer continuous oil tubing and the inner layer continuous oil tubing; the length of the built-in oil tubing is 0.5m shorter than the sand control screen.

[0014] Preferably, the foam lifting subsystem includes a conventional gas reservoir gas pipeline, a first pressure gauge, a first gas storage tank, a first valve, a second pressure gauge, a first gas flow meter, a gas injection pipeline, a double-layer coiled tubing inner layer pipe valve, a first chemical storage tank, a first injection pump, a first liquid flow meter, a first electric control valve, and a first chemical pipeline;

[0015] The first gas storage tank is connected to the conventional gas reservoir gas transmission pipeline upstream and the gas injection pipeline downstream; the first pressure gauge is installed on the conventional gas reservoir gas transmission pipeline; the first valve, the second pressure gauge, the first gas flow meter, and the inner pipe valve of the double-layer continuous oil pipe are installed on the gas injection pipeline in sequence from upstream to downstream; the gas injection pipeline is connected to the inner layer continuous oil pipe through a dual-channel drum shaft rotating head; the first injection pump is connected to the first chemical storage tank downstream; the first injection pump is connected to the gas injection pipeline through the first chemical dosing pipeline; the first liquid flow meter and the first electric control valve are installed on the first chemical pipeline in sequence from upstream to downstream.

[0016] Preferably, the platform processing subsystem includes a double-layer coiled tubing annulus channel valve, a wellhead production pipeline, a second chemical storage tank, a second injection pump, a second liquid flow meter, a second electric control valve, a second chemical pipeline, a second valve, a third pressure gauge, a three-phase separator, a second gas flow meter, a second gas storage tank, a fourth pressure gauge, a third valve, and a gas pipeline;

[0017] The upstream of the wellhead production pipeline is connected to the annulus formed by the outer layer continuous oil pipe and the inner layer continuous oil pipe through the double-channel drum shaft rotating head; the downstream of the second chemical storage tank is connected to the second injection pump; the second injection pump is connected to the wellhead production pipeline through the second chemical pipeline; the second liquid flow meter and the second electric control valve are installed on the second chemical pipeline from upstream to downstream; the second liquid flow meter is used to monitor the injection flow of the defoaming agent solution; the second electric control valve is used to accurately control the flow of the defoaming agent solution; the downstream of the wellhead production pipeline is connected to the three-phase separator; the second valve and the third pressure gauge are installed on the wellhead production pipeline from upstream to downstream; the downstream of the three-phase separator is connected to the second gas flow meter and the second gas storage tank in sequence; the downstream of the second gas storage tank is connected to the gas transmission pipeline; the fourth pressure gauge and the third valve are installed on the gas transmission pipeline from upstream to downstream.

[0018] A method for recovering natural gas hydrate in a horizontal well in offshore area by stages, comprising the following steps:

[0019] S1. Stage division of horizontal section of offshore natural gas hydrate horizontal wells:

[0020] According to the heterogeneous distribution of hydrate reservoirs in the planned mining area, with the help of the foam flow equation in the horizontal wellbore and the horizontal well productivity equation of the hydrate reservoir, the influence of the flow pressure drop of the foam system in each stage on the productivity of the stage is analyzed in sequence from the toe end to the root end of the horizontal section according to the mining sequence, and the limit length of the horizontal wellbore production wellbore is reasonably divided into the lengths of each stage.

[0021] S2. Production capacity, risk monitoring and analysis during the mining phase:

[0022] With the help of the offshore natural gas hydrate horizontal well platform processing subsystem, the gas production rate, liquid production rate, and sand production rate in the mining stage are monitored in real time. With the help of the segmented recovery subsystem, the bottom hole flow pressure and wellhead pressure parameters are detected in real time to determine the production capacity, time curve, and corresponding reservoir risk and time curve of this stage; the change characteristics of the two types of curves are analyzed to determine the reagent injection flow rate of the segmented recovery subsystem, the gas injection pressure of the foam lifting subsystem, and the shutdown time of this mining stage;

[0023] S3, mining system sand removal and back to the adjacent upstream stage of mining:

[0024] With the help of the foam lifting subsystem of the offshore natural gas hydrate horizontal well, the injection gas pressure is increased to realize the flow of the foam system from the inside of the production system to its annulus, and the sand control screen is cleared until the bottom hole pressure is restored to the original pressure of the hydrate reservoir; with the help of the staged recovery subsystem, the double-layer coiled tubing is lifted to move the sand control screen to the adjacent upstream stage; with the help of the foam lifting subsystem, the injection gas pressure is reduced to reduce the bottom hole flow pressure to the design pressure, and the production of this stage is started;

[0025] S4. Complete recovery and evaluation optimization of the mining system:

[0026] Complete the mining of each stage in sequence from the toe end to the root end of the horizontal section, and use the segmented mining subsystem to completely lift the double-layer coiled tubing to achieve complete recovery of the mining system; evaluate the structural and functional integrity of the mining system, and optimize the mining system for application in the next hydrate mining horizontal well based on the overall deployment and design of the hydrate reservoir development plan for this block.

[0027] Compared with the prior art, the present invention has the following beneficial effects:

[0028] (1) The offshore natural gas hydrate horizontal well segmented recovery system provided by the present invention has a simple and recyclable structure, which reduces capital expenditures. It effectively utilizes nearby conventional gas reservoirs, natural gas reservoirs, and high-pressure gas reservoirs as gas lift sources to replace high-energy-consuming electric submersible pumps and achieve low-carbon drainage; through the combination of foaming agents and gas lift, the hydraulically unstable gas-liquid two-phase flow system in the production wellbore is transformed into a hydraulically stable foam flow system, realizing the transformation of the bottom hole flow pressure control mode from the electric submersible pump controlling the hydrostatic pressure of the liquid column to the foam controlling the friction resistance along the way, which not only eliminates the pressure volatility, but also improves the pressure control accuracy; the foam system reduces the thermodynamic risk area of ​​hydrates by changing the pressure and temperature conditions in the production wellbore, and cooperates with hydrate inhibitors to achieve hydraulic and thermal coupling prevention and control of hydrates in the production channel; the length of the sand control screen is The length of the horizontal section is reduced to the stage length, and it can pass through the deflection section and the horizontal section more smoothly and be lowered into the designed reservoir position; the sand screen has a self-cleaning function, which can restore the permeability of the sand screen and realize the reuse of the sand screen in various stages; reduce the frequency of maintenance; the foam system is directly used for cleaning the sand screen, and there is no need to replace it with a special sand flushing fluid. The completed mining stage provides space for sand particles, and there is no need to flush sand particles to the platform, which reduces the displacement of sand flushing fluid and avoids well leakage problems; the foam system has a strong ability to carry solid particles, which effectively solves the sedimentation and blockage problems of sand particles, hydrate particles, etc. in the horizontal section; the above technical advantages effectively reduce the operating cost of the offshore hydrate mining system.

[0029] (2) The segmented recovery process method for offshore natural gas hydrate horizontal wells provided by the present invention divides the recovery object from the entire horizontal section into stages, which not only realizes the fine treatment of the heterogeneity of the hydrate reservoir in space, but also realizes the coordinated treatment of production capacity and risk in time, significantly improves the efficiency of hydrate recovery, avoids the risk caused by material depletion of the hydrate reservoir, and significantly reduces costs and increases efficiency; the wellbore structure design of the hydrate horizontal well is freed from the constraint of the maximum length of the horizontal well production wellbore, and only needs to consider the extension length of the horizontal well drilling wellbore of the hydrate reservoir; the design of the hydrate horizontal well working system is innovative, which not only includes the determination of a reasonable production pressure difference, but also includes the division of stages and the formulation of a recovery plan. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] Figure 1 It is a structural schematic diagram of a staged recovery system for marine natural gas hydrate horizontal wells in an embodiment of the present invention;

[0031] Figure 2 It is a flowchart of a process method for staged recovery of marine natural gas hydrate in horizontal wells in an embodiment of the present invention;

[0032] Figure 3 Schematic diagram of the staged recovery process of marine natural gas hydrate horizontal wells in an embodiment of the present invention;

[0033] Figure 4 It is a schematic diagram of the principle of staged recovery of marine natural gas hydrate in horizontal wells in an embodiment of the present invention.

[0034] in:

[0035] 1. Sea level; 2. Overlying strata; 3. Hydrate reservoir; 4. Underlying strata; 5. Conventional gas reservoir pipeline; 6. First pressure gauge; 7. First gas storage tank; 8. First valve; 9. Second pressure gauge; 10. First gas flow meter; 11. Gas injection pipeline; 12. Double-layer coiled tubing inner pipe valve; 13. First chemical storage tank; 14. First injection pump; 15. First liquid flow meter; 16. First electric control valve; 17. First chemical pipeline; 18. Production pipeline; 19. Slit casing; 20. Outer layer coiled tubing; 21. Inner layer coiled tubing; 22. Head repeatable packer; 23. Double-layer coiled tubing telescopic connector; 24. Sand control screen; 25. Internal tubing; 26. Internal tubing centralizer; 27. Check valve; 28. Downhole pressure and temperature gauge; 29. ​​Connecting nipple; 30. Bottom repeatable sealing packer; 31. Guide centralizer; 32. Double-layer coiled tubing wellhead device; 33. Double-layer coiled tubing; 34. Double-layer coiled tubing drum; 35. Dual-channel drum shaft rotating head; 36. Double-layer coiled tubing annulus channel valve; 37. Wellhead production pipeline; 38. Second chemical storage tank; 39. Second injection pump; 40. Second liquid flowmeter; 41. Second electric control valve; 42. Second chemical pipeline; 43. Second valve; 44. Third pressure gauge; 45. Three-phase separator; 46. Second gas flowmeter; 47. Second gas storage tank; 48. Fourth pressure gauge; 49. Third valve; 50. Gas pipeline; 51. Center platform. DETAILED DESCRIPTION

[0036] The present invention will be further described below in conjunction with the accompanying drawings.

[0037] like Figure 1As shown, a staged recovery system for marine natural gas hydrate horizontal wells includes a staged recovery subsystem, a foam lifting subsystem, and a platform processing subsystem; the top of the staged recovery subsystem is connected to the foam lifting subsystem and the platform processing subsystem respectively;

[0038] The segmented mining subsystem is used to move the mining system, which corresponds to each stage in spatial position in the mining sequence from the toe end to the root end of the horizontal segment;

[0039] The staged recovery subsystem includes a production pipeline 18, a slotted casing 19, an outer layer coiled tubing 20, an inner layer coiled tubing 21, a head repeatable packer 22, a double-layer coiled tubing telescopic connector 23, a sand control screen 24, an internal tubing 25, an internal tubing centralizer 26, a check valve 27, a downhole pressure thermometer 28, a connecting nipple 29, a bottom repeatable packer 30, a guide centralizer 31, a double-layer coiled tubing wellhead device 32, a double-layer coiled tubing 33, a double-layer coiled tubing drum 34, and a dual-channel drum shaft rotating head 35;

[0040] The bottom end of the production pipeline 18 is connected to the slotted casing 19, and the slotted casing 19 is located at the production layer of the hydrate reservoir 3 above the underlying formation 4; the production pipeline 18 and the slotted casing 19 pass through the overlying formation 2 to jointly realize the connection between the central platform 51 and the hydrate reservoir 3, and provide installation space for the segmented recovery subsystem; the slotted casing 19 realizes the connection between the hydrate reservoir 3 and the segmented recovery subsystem, so that the gas, water and sand generated by the decomposition of the hydrate reservoir 3 can smoothly enter the slotted casing 19 through the slots on the slotted casing 19;

[0041] The double-layer coiled tubing 33 is composed of an outer coiled tubing 20 and an inner coiled tubing 21; the inner coiled tubing 21 provides a channel for artificial gas injection, foaming agent, and hydrate inhibitor; the annulus formed by the outer coiled tubing 20 and the inner coiled tubing 21 provides a gas production channel; the annulus formed by the outer coiled tubing 20, the production pipeline 18, and the slotted casing 19 provides a channel for pressure control of downhole tools;

[0042] The part of the double-layer coiled tubing 33 located upstream of the double-layer coiled tubing wellhead device 32 is wound on the double-layer coiled tubing drum 34, and the part located downstream of the double-layer coiled tubing wellhead device 32 is located inside the production pipeline 18 and the slotted casing 19; as the production is recovered in sequence at each stage, the lifted double-layer coiled tubing 33 is wound on the double-layer coiled tubing drum 34; the double-layer coiled tubing wellhead device 32 realizes the sealing of the wellhead on the central platform 51 and provides support for the double-layer coiled tubing 33;

[0043] The top of the double-layer coiled tubing 33 is connected to a double-channel drum shaft rotating head 35; the double-channel drum shaft rotating head 35 provides double channels, one channel corresponds to the internal flow channel of the inner layer coiled tubing 21, and the other channel corresponds to the annular channel formed by the outer layer coiled tubing 20 and the inner layer coiled tubing 21; the double-channel drum shaft rotating head 35 can eliminate the influence of the rotation process of the double-layer coiled tubing drum 34 on the effective connection between the double channels and the pipelines on the central platform 51;

[0044] The bottom end of the double-layer continuous tubing 33 is connected in sequence to the double-layer continuous tubing telescopic connector 23, the sand screen 24, the connecting short section 29, the bottom repeatable sealing packer 30, and the guide centralizer 31; the double-layer continuous tubing telescopic connector 23 realizes the connection between the double-layer continuous tubing 33 and the sand screen 24, ensuring that the outer layer continuous tubing 20 is connected to the sand screen 24, and the inner layer continuous tubing 21 is connected to the built-in tubing 25; the length of the sand screen 24 is matched with the stage to achieve effective sand control in the stage production process; the connecting short section 29 realizes the connection between the sand screen 24 and the bottom repeatable sealing packer 30; the bottom repeatable sealing packer 30 can be set and unsealed by controlling the pressure in the wellbore, and the setting is to achieve the sealing between the intended mining stage and the downstream completed mining stage, and the unsealing is to achieve the lifting movement of the segmented recovery subsystem; the guide centralizer 31 is located at the end of the segmented recovery subsystem to ensure the smooth lowering of the segmented recovery subsystem;

[0045] The head repeatable set packer 22 is installed in the annulus between the double-layer coiled tubing 33 and the slotted casing 19, and is located upstream of the double-layer coiled tubing telescopic connector 23; the head repeatable set packer 22 can be set and unset by controlling the pressure in the wellbore. Setting is used to achieve the style between the current production stage and the upstream unproduction stage, and unsetting is used to achieve the lifting movement of the staged recovery subsystem;

[0046] The internal oil pipe 25 is located inside the sand control screen 24; the internal oil pipe 25 is 0.5 m shorter than the sand control screen 24;

[0047] The internal tubing 25 is aligned with the upstream end of the sand control screen 24; the internal tubing 25 is a continuation of the inner layer coiled tubing 21, and provides a flow channel for artificial gas injection, foaming agent, and hydrate inhibitor;

[0048] The built-in tubing centralizer 26 is located in the annulus between the built-in tubing 25 and the sand control screen 24; the built-in tubing centralizer 26 supports the built-in tubing 25 to ensure the central arrangement of the built-in tubing 25;

[0049] A check valve 27 and a downhole pressure thermometer 28 are installed at the bottom of the built-in oil pipe 25 in sequence from upstream to downstream; the check valve 27 ensures the one-way flow of the fluid from upstream to downstream; the downhole pressure thermometer 28 realizes real-time measurement of the bottom hole flow pressure and bottom hole temperature;

[0050] The foam lifting subsystem is used to inject high-pressure gas and foaming agent into the production wellbore, and is arranged on the central platform 51 above the sea level 1 to realize the transformation of the flow system in the production wellbore into the foam flow system;

[0051] The foam lifting subsystem includes a conventional gas reservoir gas pipeline 5, a first pressure gauge 6, a first gas storage tank 7, a first valve 8, a second pressure gauge 9, a first gas flow meter 10, a gas injection pipeline 11, a double-layer coiled tubing inner layer valve 12, a first chemical storage tank 13, a first injection pump 14, a first liquid flow meter 15, a first electric control valve 16, and a first chemical pipeline 17;

[0052] The first gas storage tank 7 is connected to the conventional gas reservoir gas transmission pipeline 5 upstream and the gas injection pipeline 11 downstream; the conventional gas reservoir gas transmission pipeline 5 provides a flow channel for the high-pressure gas from the adjacent conventional gas reservoir; the first gas storage tank 7 provides storage space for the high-pressure gas and eliminates the flow and pressure fluctuations that may occur in the incoming high-pressure gas; the gas injection pipeline 11 provides a flow channel for artificial gas injection, foaming agent, and hydrate inhibitor;

[0053] A first pressure gauge 6 is installed on the conventional gas reservoir gas transmission pipeline 5; the first pressure gauge 6 is used to monitor the residual pressure after the high-pressure gas from the adjacent conventional gas reservoir reaches the central platform 51;

[0054] The first valve 8, the second pressure gauge 9, the first gas flow meter 10, and the double-layer coiled tubing inner layer pipe valve 12 are installed on the gas injection pipeline 11 from upstream to downstream in sequence; the gas injection pipeline 11 is connected to the inner layer coiled tubing 21 through the dual-channel drum shaft rotating head 35; the first valve 8 realizes the regulation of the pressure and flow of artificial gas injection; the second pressure gauge 9 is used to monitor the pressure of artificial gas injection; the first gas flow meter 10 is used to monitor the flow of artificial gas injection; the double-layer coiled tubing inner layer pipe valve 12 is used to open or close the connection between the gas injection pipeline 11 and the inner layer coiled tubing 21, thereby realizing the connection or closing between the foam lifting subsystem and the staged recovery subsystem;

[0055] The first reagent storage tank 13 is connected to the first injection pump 14 downstream; the first injection pump 14 is connected to the gas injection pipeline 11 through the first dosing pipeline 17; the first reagent storage tank 13 is used to store the solution containing the foaming agent and the hydrate inhibitor; the first injection pump 14 is used to pump the foaming agent and the hydrate inhibitor solution, and can adjust the injection flow rate and pressure in real time according to the production status;

[0056] A first liquid flow meter 15 and a first electric control valve 16 are installed on the first reagent pipeline 17 from upstream to downstream in sequence; the first liquid flow meter 15 is used to monitor the injection flow of the solution containing the foaming agent and the hydrate inhibitor; the first electric control valve 16 is used to accurately control the flow of the foaming agent and the hydrate inhibitor solution;

[0057] The platform processing subsystem is arranged on the central platform 51 above the sea level 1, and is used to process the output of the production wellbore, eliminate foam and thus achieve separation of gas, liquid and solid;

[0058] The platform processing subsystem includes a double-layer coiled tubing annulus channel valve 36, a wellhead production pipeline 37, a second chemical storage tank 38, a second injection pump 39, a second liquid flow meter 40, a second electric control valve 41, a second chemical pipeline 42, a second valve 43, a third pressure gauge 44, a three-phase separator 45, a second gas flow meter 46, a second gas storage tank 47, a fourth pressure gauge 48, a third valve 49, and a gas pipeline 50;

[0059] The upstream of the wellhead production pipeline 37 is connected to the annulus formed by the outer layer coiled tubing 20 and the inner layer coiled tubing 21 through the double-channel drum shaft rotating head 35; the wellhead production pipeline 37 provides a flow channel for the production wellbore output to enter the platform processing subsystem for subsequent processing; the double-layer coiled tubing annulus channel valve 36 is used to open or close the connection between the wellhead production pipeline 37 and the annulus formed by the outer layer coiled tubing 20 and the inner layer coiled tubing 21, thereby realizing the connection or closing between the segmented recovery subsystem and the platform processing subsystem;

[0060] The second reagent storage tank 38 is connected to the second injection pump 39 downstream; the second injection pump 39 is connected to the wellhead output pipeline 37 through the second reagent pipeline 42; the second reagent storage tank 38 is used to store the solution containing the defoaming agent; the second injection pump 39 is used to pump the defoaming agent solution, and the injection flow rate can be adjusted according to the production conditions;

[0061] A second liquid flow meter 40 and a second electric control valve 41 are installed on the second reagent pipeline 42 from upstream to downstream in sequence; the second liquid flow meter 40 is used to monitor the injection flow of the defoaming agent solution; the second electric control valve 41 is used to accurately control the flow of the defoaming agent solution;

[0062] The downstream of the wellhead production pipeline 37 is connected to the three-phase separator 45; the three-phase separator 45 realizes the separation of gas, liquid and solid;

[0063] A second valve 43 and a third pressure gauge 44 are installed on the wellhead production pipeline 37 from upstream to downstream in sequence; the second valve 43 is used to adjust the flow rate and pressure of the flow from the production wellbore to meet the performance condition requirements of the three-phase separator 45; the third pressure gauge 44 is used to monitor the inlet pressure of the three-phase separator 45;

[0064] The downstream of the three-phase separator 45 is connected in sequence to a second gas flow meter 46 and a second gas storage tank 47; the second gas flow meter 46 is used to monitor the flow of the separated gas; the second gas storage tank 47 is used to temporarily store the separated gas and eliminate pressure fluctuations;

[0065] The second gas storage tank 47 is connected to the gas pipeline 50 downstream; the fourth pressure gauge 48 and the third valve 49 are installed on the gas pipeline 50 from upstream to downstream; the gas pipeline 50 provides an external transmission channel for the separated gas; the fourth pressure gauge 48 is used to monitor the outlet pressure of the second gas storage tank 47; the third valve 49 is used to adjust the external transmission flow of the separated gas.

[0066] The working principle of a staged recovery system for marine natural gas hydrate horizontal wells is further described below in conjunction with the accompanying drawings and specific implementation methods:

[0067] The staged recovery subsystem is lowered to stage 1; the gas, water and sand produced by the decomposition of the hydrate reservoir within the stage 1 under the set bottom hole pressure enter the staged recovery subsystem to form a gas-water-sand three-phase flow system; the gas-water-sand three-phase flow system is mixed with the artificial gas injection, foaming agent and hydrate inhibitor from the foam lifting subsystem, and the gas phase and the liquid phase are mixed to form foam under the action of hydrodynamic force, and the gas-water-sand three-phase flow system is transformed into a gas-water-sand three-phase foam flow system; the gas-water-sand three-phase foam flow system flows from the bottom of the hole to the platform processing subsystem through the staged recovery subsystem; the platform processing subsystem transforms the gas-water-sand three-phase foam flow system into separated gas phase, liquid phase and solid phase through defoaming and gas-liquid-solid separation; Figure 3 As shown, each stage of mining is completed in sequence from the toe end to the root end of the horizontal section: after the mining of stage 1 is completed, the sub-stage mining subsystem is lifted up to stage 2; after the mining of stage 2 is completed, the sub-stage mining subsystem is lifted up to stage 3; after the mining of stage 3 is completed, the sub-stage mining subsystem is lifted up for recovery.

[0068] by Figure 3 Taking the exploitation of stage 1 as an example, the working principle of a staged recovery system for offshore natural gas hydrate horizontal wells in a single stage of exploitation is further described:

[0069] The gas, water and sand produced by the decomposition of the hydrate reservoir 3 under the set bottom hole pressure pass through the slits on the slit casing 19 and enter the inside of the slit casing 19 to form a gas-water-sand three-phase flow system; the gas-water-sand three-phase flow system passes through the sand screen 24 and enters the annulus between the built-in oil pipe 25 and the sand screen 24; the foam lifting subsystem injects lifting gas, foaming agent and hydrate inhibitor through the inner layer continuous oil pipe 21, and enters the annulus between the built-in oil pipe 25 and the sand screen 24 at the tail end of the built-in oil pipe 25. The gas-water-sand three-phase flow system is mixed with the gas-water-sand three-phase flow system to transform the gas-water-sand three-phase flow system into a gas-water-sand three-phase foam flow system; the gas-water-sand three-phase foam flow system in the annulus formed by the outer layer coiled tubing 20 and the inner layer coiled tubing 21 passes through the double-layer coiled tubing wellhead device 32 and enters the annulus of the double-layer coiled tubing 33; the gas-water-sand three-phase foam flow system in the annulus of the double-layer coiled tubing 33 passes through the double-channel drum shaft rotating head 35 and enters the wellhead production pipeline 37;

[0070] After the high-pressure gas is pressure-detected by the first pressure gauge 6 from the conventional gas reservoir gas transmission pipeline 5, it enters the first gas storage tank 7 for storage, and the flow and pressure fluctuation of the high-pressure gas are eliminated; the high-pressure gas in the first gas storage tank 7 enters the gas injection pipeline 11 after the injection pressure and flow are detected by the second pressure gauge 9 and the first gas flow meter 10; the foaming agent and hydrate inhibitor solution in the first reagent storage tank 13 are pumped to the gas injection pipeline 11 by the first injection pump 14; the first liquid flow meter 15 and the first electric control valve 16 on the first reagent pipeline 17 detect and control the flow of the foaming agent and hydrate inhibitor solution; after the artificial injection gas and the foaming agent and hydrate inhibitor solution are mixed in the gas injection pipeline 11, they pass through the double-channel drum shaft rotating head 35 and enter the inner layer continuous oil pipe 21;

[0071] The defoamer solution in the second reagent storage tank 38 is pumped to the wellhead production pipeline 37 by the second injection pump 39; the second liquid flow meter 40 and the second electric control valve 41 on the second reagent pipeline 42 detect and control the flow of the defoamer solution; the defoamer solution is mixed with the gas-water-sand three-phase foam flow system in the wellhead production pipeline 37 to defoam, and then enters the three-phase separator 45 to separate the gas, liquid and solid three phases; the separated gas in the three-phase separator 45 enters the second gas storage tank 47 to temporarily store the gas and eliminate the pressure fluctuation of the separated gas; the separated gas in the second gas storage tank 47 enters the gas transmission pipeline 50 after the pressure of the separated gas is detected and the flow is controlled by the fourth pressure gauge 48 and the third valve 49.

[0072] A method for recovering natural gas hydrate in offshore horizontal wells by stages, such as Figure 2 As shown, the steps include:

[0073] (1) Stage division of horizontal sections of offshore natural gas hydrate horizontal wells

[0074] Considering the heterogeneous distribution of hydrate reservoirs in the proposed mining area, with the help of the foam flow equation in the horizontal wellbore and the productivity equation of the horizontal well in the hydrate reservoir, the influence of the flow pressure drop of the foam system in each stage on the productivity of the stage is analyzed in sequence from the toe end to the root end of the horizontal section according to the mining sequence, and the limit length of the horizontal wellbore production wellbore is reasonably divided into the lengths of each stage; Figure 3 As shown, in this embodiment, the horizontal section is divided into stage 1, stage 2, and stage 3 from the toe end to the root end;

[0075] (2) Production capacity, risk monitoring and analysis during the mining phase

[0076] With the help of the offshore natural gas hydrate horizontal well platform processing subsystem, the gas production rate, liquid production rate, and sand production rate in the exploitation stage are monitored in real time. With the help of the segmented recovery subsystem, the bottom hole flow pressure and wellhead pressure parameters are detected in real time to determine the production capacity and time curve of this stage, as well as the corresponding reservoir risk and time curve of this stage; the change characteristics of the two types of curves are analyzed to determine the reagent injection flow rate of the segmented recovery subsystem, the gas injection pressure of the foam lifting subsystem, and the shutdown time of this exploitation stage; Figure 3 As shown in the embodiment, in the production of each of the stages 1, 2 and 3, the head repeatable packer 22 and the bottom repeatable packer 30 are set to isolate the single production stage; the production capacity, time curve, reservoir risk corresponding to each stage, and time curve of each stage 1, 2 and 3 are as shown in FIG. Figure 4 As shown in the figure, when the production capacity of a stage is lower than the critical value or the corresponding reservoir risk of the stage exceeds the critical value, the production of that stage is stopped. The stopping time of stage 1 is t 1 , the mining stop time in stage 2 is t 2 , the mining stop time in stage 1 is t 3 ;

[0077] (3) Sand removal from the mining system and return to the adjacent upstream stage of mining

[0078] With the help of the foam lifting subsystem of the offshore natural gas hydrate horizontal well, the injection gas pressure is increased to realize the flow of the foam system from the inside of the production system to its annulus, and the sand control screen 24 is cleared until the bottom hole pressure is restored to the original pressure of the hydrate reservoir; with the help of the staged recovery subsystem, the double-layer coiled tubing 33 is lifted to move the sand control screen 24 to the adjacent upstream stage; the injection gas pressure is reduced to reduce the bottom hole flow pressure to the design pressure, and the production of this stage is started; Figure 3 and Figure 4 As shown, t 1 The production of stage 1 is completed at the moment, and then the sand control screen 24 is restored to permeability by cleaning the sand, and the sand control screen 24 is moved back to the upstream stage 2, t 2 The production of stage 2 is completed at all times, and then the sand control screen 24 is restored to permeability by sand cleaning, and the sand control screen 24 is moved back to the upstream stage 3;

[0079] (4) Complete recovery and evaluation optimization of the mining system

[0080] After all stages of production are completed in sequence from the toe end to the root end of the horizontal section, the double-layer coiled tubing 33 is completely lifted up to achieve complete recovery of the production system; the structural and functional integrity of the production system is evaluated, and according to the overall deployment and design of the hydrate reservoir development plan of this block, the production system is optimized for application in the next hydrate production horizontal well; Figure 3 and Figure 4As shown, in this embodiment, t 3 The last stage 3 of production is completed at all times, and then the double-layer coiled tubing 33 is completely lifted up to achieve complete recovery of the production system.

Claims

1. A marine natural gas hydrate horizontal well staged recovery system, characterized in that: It includes a segmented mining subsystem, a foam lifting subsystem and a platform processing subsystem; the top of the segmented mining subsystem is connected to the foam lifting subsystem and the platform processing subsystem respectively; the segmented mining subsystem is used to move the mining system, and corresponds to each stage in spatial position from the toe end to the root end of the horizontal section according to the mining sequence; the foam lifting subsystem is used to inject high-pressure gas and foaming agent into the production wellbore to realize the transformation of the flow system in the production wellbore into a foam flow system; the platform processing subsystem is used to process the output of the production wellbore, eliminate foam and realize the separation of gas, liquid and solid; The staged recovery subsystem comprises a production pipeline (18), a slotted casing (19), a head re-sealable packer (22), a double-layer coiled tubing telescopic connector (23), a sand control screen (24), an internal tubing (25), an internal tubing centralizer (26), a check valve (27), a downhole pressure and temperature gauge (28), a connecting nipple (29), a bottom re-sealable packer (30), a guide centralizer (31), a double-layer coiled tubing wellhead assembly (32), a double-layer coiled tubing (33), a double-layer coiled tubing drum (34), and a dual-channel drum shaft rotating head (35); The portion of the double-layer coiled tubing (33) located upstream of the double-layer coiled tubing wellhead device (32) is wound on the double-layer coiled tubing drum (34), and the portion located downstream of the double-layer coiled tubing wellhead device (32) is located inside the production pipeline (18) and the slotted casing (19); the top of the double-layer coiled tubing (33) is connected to the double-channel drum shaft rotating head (35); the bottom end of the double-layer coiled tubing (33) is sequentially connected to the double-layer coiled tubing telescopic connector (23), the sand control screen (24), the connecting short section (29), the bottom repeatable sealing packer (30), the guide support The invention relates to a straightener (31); a head re-sealable packer (22) is installed in the annulus between the double-layer continuous tubing (33) and the slotted casing (19), and is located upstream of the double-layer continuous tubing telescopic connector (23); the built-in tubing (25) is located inside the sand control screen (24); the built-in tubing (25) is aligned with the upstream end of the sand control screen (24); the built-in tubing straightener (26) is located in the annulus between the built-in tubing (25) and the sand control screen (24); a check valve (27) and a downhole pressure thermometer (28) are installed at the bottom end of the built-in tubing (25) in sequence from upstream to downstream.

2. A marine natural gas hydrate horizontal well staged recovery system according to claim 1, characterized in that: The double-layer continuous oil tubing (33) includes an outer layer continuous oil tubing (20) and an inner layer continuous oil tubing (21); an annulus is formed between the outer layer continuous oil tubing (20) and the inner layer continuous oil tubing (21); a dual-channel drum shaft rotating head (35) provides dual channels, one channel corresponds to the internal flow channel of the inner layer continuous oil tubing (21), and the other channel corresponds to the annulus formed by the outer layer continuous oil tubing (20) and the inner layer continuous oil tubing (21); the length of the internal oil tubing (25) is 0.5m shorter than the sand control screen (24).

3. A marine natural gas hydrate horizontal well staged recovery system according to claim 2, characterized in that: The foam lifting subsystem comprises a conventional gas reservoir gas transmission pipeline (5), a first pressure gauge (6), a first gas storage tank (7), a first valve (8), a second pressure gauge (9), a first gas flow meter (10), a gas injection pipeline (11), an inner layer pipe valve of a double-layer coiled tubing (12), a first chemical storage tank (13), a first injection pump (14), a first liquid flow meter (15), a first electric control valve (16), and a first chemical pipeline (17); The first gas storage tank (7) is connected to a conventional gas reservoir gas transmission pipeline (5) upstream and to a gas injection pipeline (11) downstream; a first pressure gauge (6) is installed on the conventional gas reservoir gas transmission pipeline (5); a first valve (8), a second pressure gauge (9), a first gas flow meter (10), and a double-layer continuous oil pipe inner layer valve (12) are installed on the gas injection pipeline (11) in sequence from upstream to downstream; the gas injection pipeline (11) is connected to the inner layer continuous oil pipe (21) through a double-channel roller shaft rotating head (35); the first chemical storage tank (13) is connected to a first injection pump (14) downstream; the first injection pump (14) is connected to the gas injection pipeline (11) through a first chemical dosing pipeline; a first liquid flow meter (15) and a first electric control valve (16) are installed on the first chemical pipeline (17) in sequence from upstream to downstream.

4. A marine natural gas hydrate horizontal well staged recovery system according to claim 2, characterized in that: The platform processing subsystem includes a double-layer coiled tubing annulus channel valve (36), a wellhead production pipeline (37), a second chemical storage tank (38), a second injection pump (39), a second liquid flow meter (40), a second electric control valve (41), a second chemical pipeline (42), a second valve (43), a third pressure gauge (44), a three-phase separator (45), a second gas flow meter (46), a second gas storage tank (47), a fourth pressure gauge (48), a third valve (49), and a gas transmission pipeline (50); The upstream of the wellhead production pipeline (37) is connected to the annulus formed by the outer layer coiled tubing (20) and the inner layer coiled tubing (21) through a dual-channel roller shaft rotating head (35); the downstream of the second chemical storage tank (38) is connected to the second injection pump (39); the second injection pump (39) is connected to the wellhead production pipeline (37) through the second chemical pipeline (42); a second liquid flow meter (40) and a second electric control valve (41) are installed on the second chemical pipeline (42) from upstream to downstream; the second liquid flow meter (40) is used to monitor the injection flow rate of the defoaming agent solution; The second electric control valve (41) is used to accurately control the flow rate of the defoaming agent solution; the wellhead output pipeline (37) is connected to the three-phase separator (45) downstream; the second valve (43) and the third pressure gauge (44) are installed on the wellhead output pipeline (37) in sequence from upstream to downstream; the second gas flow meter (46) and the second gas storage tank (47) are connected to the downstream of the three-phase separator (45); the gas transmission pipeline (50) is connected to the downstream of the second gas storage tank (47); the fourth pressure gauge (48) and the third valve (49) are installed on the gas transmission pipeline (50) in sequence from upstream to downstream.

5. A method for recovering natural gas hydrates in offshore areas by horizontal well segmentation, characterized in that: The following steps are involved: S1. Stage division of horizontal section of offshore natural gas hydrate horizontal wells: Based on the heterogeneous distribution of the hydrate reservoir in the proposed mining area, the foam flow equation in the horizontal wellbore and the productivity equation of the horizontal well in the hydrate reservoir are used to analyze the impact of the foam system flow pressure drop in each stage on the productivity of the stage from the toe end to the root end of the horizontal section according to the mining sequence. The maximum production wellbore length of the horizontal well is reasonably divided into different length stages. S2. Production capacity, risk monitoring and analysis during the mining phase: The offshore natural gas hydrate horizontal well platform processing subsystem monitors the gas, liquid, and sand production rates during the production phase in real time. The staged recovery subsystem detects bottomhole flow pressure and wellhead pressure parameters in real time to determine the production capacity and time curve for that phase, as well as the corresponding reservoir risk and time curve for that phase. By analyzing the changing characteristics of the two types of curves, the reagent injection flow rate for the staged recovery subsystem, the gas injection pressure for the foam lift subsystem, and the production stoppage time for that phase are determined. S3, mining system sand removal and back to the adjacent upstream stage of mining: Using the offshore natural gas hydrate horizontal well foam lift subsystem, the injected gas pressure is increased to enable the foam system to flow from the production system to its annulus, thereby clearing the sand control screen until the bottomhole pressure returns to the original pressure of the hydrate reservoir. Using the staged recovery subsystem, the double-layer coiled tubing is lifted, allowing the sand control screen to move to the adjacent upstream stage. Using the foam lift subsystem, the injected gas pressure is reduced, lowering the bottomhole flow pressure to the design pressure, and starting the current stage of production. S4. Complete recovery and evaluation optimization of the mining system: The mining process was completed in sequence from the toe to the root of the horizontal section. The double-layer coiled tubing was fully lifted with the help of the staged recovery subsystem to achieve complete recovery of the mining system. The structural and functional integrity of the mining system was evaluated and, based on the overall deployment and design of the hydrate reservoir development plan for this block, the mining system was optimized for application in the next hydrate mining horizontal well.

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