CN116867954A

CN116867954A - System and method for hydrate production

Info

Publication number: CN116867954A
Application number: CN202280015286.3A
Authority: CN
Inventors: C·刘易斯; T·格洛姆萨克; I·马丁内斯; S·霍西
Original assignee: Baker Hughes Energy Technology UK Ltd
Current assignee: Baker Hughes Energy Technology UK Ltd
Priority date: 2021-02-25
Filing date: 2022-02-17
Publication date: 2023-10-10
Also published as: GB202313997D0; GB202102679D0; WO2022179751A1; JP2024510716A; GB2619231A; GB2605561A

Abstract

A system (10) for hydrate production configured to separate a water component (W) from a multiphase gas and water mixture (M) present in a wellbore (12), the system (10) being configured such that the separation occurs within the wellbore (12). The system (10) comprises a first flow line (14) provided in the wellbore (12) and arranged such that an inlet (16) of the first flow line (14) is provided in the water component (W) and receives the water component (W) for separating the water component (W) from the multiphase gas and water mixture. The control system (50) is configured to receive an output signal indicative of a water level from a sensor device of the system (10) and to control the flow control device (18) based on the water level so as to control the flow of the water component (W) through the first flow line (14).

Description

System and method for hydrate production

Technical Field

The present invention relates to systems and methods for hydrate production, such as methane hydrate production.

Background

Methane hydrate is an ice-like solid comprising methane gas and water in the ice phase. Methane hydrate layers are known to contain large amounts of methane and are therefore an important source of natural gas.

Methane hydrate production involves drilling a wellbore ("wellbore") from the surface and then laying a metal wellbore liner, commonly referred to as casing, therein. After the wellbore is completed, production fluids (including methane gas, water, and entrained solids such as sand, among other things in the case of methane production) are allowed to enter the wellbore where they are transported to the surface.

To control production from a given wellbore, a flow control device, including a valve device known as a tree, is typically located at the wellhead. The valve arrangement includes a plurality of flow control valves and relief valves configured to control production fluid flow and/or facilitate well isolation. The valve arrangement also controls the entry of tools, equipment and fluids into the wellbore.

Many significant challenges are involved in methane hydrate production.

For example, extraction of methane hydrate requires local depressurization of the methane hydrate layer. If the production rate is too high, excessive water and sand are generated in a short time. This can lead to slugging and wear problems in the tubing, pumps, separators and other production equipment downstream of the production well. In addition, the flow rate and well pressure need to be carefully controlled and monitored to ensure that the flow rate is not too high to cause the well to collapse.

Methane hydrates will readily reform at ambient pressures and temperatures found in typical water depths in subsea well systems. If the pressure and temperature should be returned to the pressure and temperature at which the hydrate forms, for example due to any flow disturbances, the solid methane hydrate will re-form in the production facility. While chemical and/or heating systems have been proposed to prevent methane hydrate formation, the use of such chemicals and systems has brought significant costs to operators, such that the well may not be economically viable.

Designing a large full field system to produce multiple wells simultaneously would need to ensure that the separator operates as far as possible in laminar flow. Undersized systems with high fluid velocities will create turbulence and pull gas along with the water. Keeping the fluid velocity low would require a very large volume separator or separators, resulting in increased complexity and cost.

Designing a system to accommodate a wide range of gas-water ratios from multiple wells and maintaining production at optimal flow rates is particularly challenging.

Disclosure of Invention

According to a first aspect, there is provided a system for hydrate production, wherein the system is configured to separate water components from a multiphase gas and water mixture present in a wellbore, the system being configured such that the separation occurs within the wellbore, wherein the system comprises:

a first flow line disposed in the wellbore, the flow line being arranged such that an inlet of the first flow line is disposed in and receives a water component of the multiphase gas and water mixture to separate the water component from the multiphase gas and water mixture;

A flow control device disposed on or operatively associated with the first flow line;

a sensor device comprising one or more sensors configured to detect a water level of the water component in the wellbore and output an output signal indicative of the water level; and

a control system configured to receive an output signal from the sensor device indicative of the water level and to control the flow control device based on the water level so as to control the flow of the water component through the first flow line.

This system provides a number of significant benefits over conventional devices and methods.

For example, the system utilizes the hydrate-producing wellbore itself to separate liquid components (particularly water) from gases and solids, thereby eliminating or at least reducing the need to further separate the phases downstream of the wellbore (or the wellbore in the case of a well system comprising multiple wellbores).

Furthermore, conventional apparatus and methods involve transporting a multiphase mixture to the surface, which, as described above, can reform hydrates under pressure and temperature conditions typically found on the seabed. In contrast, in the present system, separation occurs within the wellbore such that the risk of hydrate reformation is eliminated or at least significantly reduced. This in turn improves the availability and/or efficiency of the hydrate production system, as well as reduces downtime associated with workover operations and the like and/or reduces or eliminates the need to use chemical hydrate inhibitors, heating equipment, or other hydrate mitigation agents.

The provision of a system for separation in a wellbore eliminates or at least alleviates problems of slugs and wear in production equipment such as pipes, pumps, separators that might otherwise be caused by excessive water and/or sand production, as greater control can be achieved when handling single phase fluid flows compared to current multiphase fluid flows. Furthermore, while conventional systems require equipment capable of handling multiphase fluids, the present system may utilize equipment designed for handling single phase fluids. In addition to being simpler to implement and generally lower in cost, such single phase devices provide a greater degree of control over the flow of liquid at the well, thereby reducing the risk of wellbore collapse.

Furthermore, hydrate wells are sensitive to high flow rates, so the present system advantageously facilitates control of flow rates using flow control devices on the first flow line.

The system may include or take the form of a system for natural gas hydrate production, wherein the system is configured to separate a water component from a multiphase natural gas and water mixture present in the wellbore. In particular, the system may include or take the form of a system for methane hydrate production, wherein the system is configured to separate a water component from a multiphase methane gas and water mixture present in the wellbore.

As described above, the system includes a first flow line disposed in the wellbore, the flow line being arranged such that an inlet of the first flow line is disposed in the multiphase gas and water mixture and receives a water component of the multiphase gas and water mixture.

The inlet of the first flow line may form a distal end of the first flow line.

Alternatively, the inlet may comprise one or more lateral flow ports in the first flow line.

The system may be configured such that the inlet of the first flow line is disposed below the hydrate layer. Advantageously, this facilitates the ingress of water rather than multiphase gas and water mixtures.

The first flow line may be defined as a water flow line.

The system may include a single first flow line.

Alternatively, the system may comprise a plurality of first flow lines.

As described above, the system includes a flow control device disposed on or operatively associated with the first flow line.

The flow control means may comprise or take the form of a variable flow control means.

The flow control device may include or take the form of a flow resistor.

The flow control device may include or take the form of a variable flow resistor.

The system may include a pump.

The pump may be coupled or operatively associated with the first flow line.

The pump may be configured to pump water components of the multiphase gas and water mixture present in the wellbore through the first flow line.

The pump may be configured to pump the water component of the multiphase gas and water mixture toward the surface.

In some cases, the system may be configured such that the pump directs the water component of the multiphase gas and water mixture to the surface.

In other cases, the system may be configured such that the pump directs the water component of the multiphase gas and water mixture to the sea floor or other location.

The pump may comprise or take the form of a single-phase pump, i.e. a pump configured to process a single-phase fluid. The pump may comprise or take the form of a pump configured to process a liquid.

Advantageously, the system is configured to separate the water components of the multiphase gas and water mixture within the wellbore, and thus may utilize a single phase pump that provides greater control over the fluid flow through the first flow line.

However, it should be understood that the pump may alternatively comprise or take the form of a multiphase pump, i.e. a pump configured to process multiphase fluid.

The pump may comprise or take the form of a centrifugal pump.

The pump may comprise or take the form of a mixing pump.

The pump may comprise or take the form of a vertical pump.

The pump may comprise an Electric Submersible Pump (ESP) or take the form of an ESP.

The control system may be configured to control the pump. The control system may be configured to communicate with the pump control system.

A flow control device, such as a flow resistor, may be provided at the inlet of the pump. Flow control devices, such as flow restrictors, may be provided at the discharge of the pump.

The pump may be located on the seabed. The pump may be located below the seabed. The pump may be located on at least one of the platform, the vessel and/or at an intermediate position between the seabed and the ground, such as in a riser.

The pump may form the flow control device, or form part of the flow control device. The pump may comprise a motor. The motor speed may be varied based on the water level and/or the position of a flow control device disposed on or operatively associated with the first flow line to control the flow of the water component through the first flow line.

The system may include one or more isolation valves disposed on or operatively associated with the first flow line. At least one of the isolation valves may comprise or take the form of a gate valve. At least one of the isolation valves may be configured to be operated by an ROV.

The system may include a second flow line. A second flow line may be disposed in the wellbore, the second flow line being arranged such that an inlet of the second flow line is disposed in and receives a gas component of the multiphase gas and water mixture.

The inlet of the second flow line may form a distal end of the second flow line.

Alternatively, the inlet may comprise one or more lateral flow ports in the second flow line.

The system may include a flow control device disposed on or operatively associated with the second flow line.

The flow control device may include or take the form of a flow resistor.

The system may include one or more isolation valves disposed on or operatively associated with the second flow line. At least one of the isolation valves may comprise or take the form of an annular isolation valve.

As described above, the system includes a sensor device including one or more sensors configured to detect a water level of the water component in the wellbore and output an output signal indicative of the water level.

The sensor device may include one or more sensors configured to detect a minimum water level. The sensor device may include one or more sensors configured to detect a maximum water level.

The sensor means may comprise one or more digital sensors. The one or more digital sensors may be configured to detect a water level of the water component in the wellbore. The sensor means may comprise one or more analogue sensors. One or more analog sensors may be configured to detect the water level of the water component in the wellbore. The sensor means may comprise one or more optical sensors, for example fibre optic sensors. The one or more optical sensors may be configured to detect a water level of the water component in the wellbore. The one or more fiber optic sensors may, for example, be configured to measure changes in temperature. The sensor device may comprise a Distributed Temperature Sensing (DTS) sensor device. The DTS sensor device may be configured to detect the water level of the water component in the wellbore.

The sensor means may comprise one or more pressure and/or temperature sensors. One or more pressure and/or temperature sensors may be configured to detect the level of the water component in the wellbore. In particular, the sensor device may comprise a plurality (i.e. two or more) of pressure and/or temperature sensors. Pressure and/or temperature sensors may include or take the form of downhole pressure and temperature (DHPT) meters. The system may be configured to measure the pressure at two or more of the plurality of pressure and/or temperature sensors. Since the distance between the sensors is known, the water level can be easily determined.

The sensor means may comprise one or more erosion sensors.

The sensor means may comprise one or more flow sensors.

The sensor device may include one or more position sensors, such as a choke position sensor, disposed on or in operative association with the first flow line.

The system may include one or more check valves. At least one of the check valves may comprise or take the form of a gravity check valve. At least one of the check valves may comprise or take the form of a ball valve.

At least one of the check valves may be disposed on the first flow line. The check valve disposed on the first flow line may be configured to prevent or limit backflow of water through the first flow line, i.e., back toward the inlet.

A check valve may be interposed between the inlet of the first flow line and a flow control device disposed on or operatively associated with the first flow line.

The check valve may be disposed downstream of a flow control device disposed on or operatively associated with the first flow line.

At least one of the check valves may be disposed on the second flow line. The check valve disposed on the second flow line may be configured to prevent or limit backflow of gas through the second flow line, i.e., back toward the inlet. A check valve may be interposed between the inlet of the second flow line and a flow control device disposed on or operatively associated with the second flow line.

The check valve may be disposed on or in operative association with the second flow line downstream of a flow control device.

The system may include a wellhead. The first flow line may be disposed through the wellhead. A second flow line may be disposed through the wellhead.

The system may include a tubing hanger. Tubing hangers may be disposed on and/or supported by the wellhead. The first flow line may be disposed through a tubing hanger. A second flow line may be provided through the tubing hanger.

The system may include a cover. The cover may comprise a tree, may form part of a tree, or may take the form of a tree, such as a Christmas tree or the like. The cap may be coupled to and/or mounted on the wellhead. The first flow line may be disposed through the cap. A second flow line may be disposed through the cap.

The system may include one or more control and/or communication lines. For example, the system may include one or more hydraulic lines. Alternatively or in addition, the system may include one or more power lines. Alternatively or in addition, the system may include one or more fiber optic lines. Control and/or communication lines may be provided to supply power and/or to communicate with tools and equipment disposed in and/or forming a portion of the wellbore.

One or more control and/or communication lines may be provided through the tubing hanger, wellhead and/or cover.

One or more control and/or communication lines may be provided through the tubing hanger coupler.

One or more control and/or communication lines may be provided through a Vertical Clamp Connection System (VCCS) (e.g., VCCS seal plate) or other device.

The system may include a manifold.

The first flow line (or at least one of the first flow lines in the case where the system includes a plurality of first flow lines) may be coupled to a manifold.

The second flow line (or at least one of the second flow lines in the case of a system comprising a plurality of first flow lines) may be coupled to a manifold.

The control system may form or form part of a subsea well control system.

The control system may comprise a control module, in particular but not exclusively a subsea control module.

The control system, in particular the subsea control module, may be configured and/or operable to monitor the water level and control the flow rate in order to maintain an optimal water level.

The control system, in particular the subsea control module, may be configured to receive sensor data from one or more water level sensors.

The control system, in particular the subsea control module, may be configured to receive sensor data from one or more erosion sensors.

The control system, in particular the subsea control module, may be configured to receive sensor data from one or more flow sensors.

The control system, specifically an underwater control module, may be configured to receive sensor data from one or more choke position sensors.

The control system, in particular the subsea control module, may be configured to receive sensor data from one or more pressure and/or temperature sensors.

The control system, in particular the subsea control module, may be configured to:

processing sensor data received from one or more sensors of the sensor device; and

one or more command signals are output to a position controller and/or an actuation mechanism of a flow control device disposed on or operatively associated with the first flow line to control the position of the flow control device.

For example, a control system, in particular an underwater control module, may be configured to:

processing sensor data received from at least one of the one or more water level sensors; and at least one erosion sensor of the one or more erosion sensors; one or more flow sensors, one or more position sensors disposed on or in operative association with the first flow line; and/or one or more pressure and/or temperature sensors; and

Alternatively or in addition, the control system, in particular the subsea control module, may be configured to:

one or more command signals are output to a position controller and/or an actuation mechanism of at least one of the isolation valves disposed on or operatively associated with the first flow line to control the position of the isolation valve.

The system may include, be coupled to, or be in communication with a master control station or module.

The master control station or module may form part of the control system of the system or may take the form of a separate system in communication with the control system.

The control module may be configured to communicate with a master control station or module.

The master control station may be configured to receive information from one or more upper layer systems or modules.

For example, the master control station may be configured to receive information from an Emergency Shutdown (ESD) system or module.

For example, the master control station may be configured to receive information from a system traffic demand system or module.

The control system, specifically a master control station or module, may be configured to process information from one or more upper level systems or modules (e.g., at least one of an emergency shutdown module and a system flow demand module) and output one or more command signals to a controller of the pump, specifically a speed controller.

The system may comprise, be coupled to or in communication with a pump control system, in particular an underwater pump control system.

The pump control system may include a pump control module. The pump control system may include or take the form of a processor.

The pump control system may include one or more sensors associated with control of the pump.

The pump control system may include one or more actuators associated with control of the pump.

The pump control module may be in communication with a speed controller of the pump.

The pump control module may be in communication with at least one of the one or more sensors associated with control of the pump and the one or more actuators associated with control of the pump.

The flow control device may be located in a wellbore. The flow control device may be located on the seabed. The flow control device may be coupled to or form part of the cap. The flow control device may be coupled to or form part of a wellhead. The flow control device may be located upstream of the wellhead, for example on a flowline disposed between the wellhead and the surface.

As described above, the system may include a flow control device disposed on or operatively associated with the second flow line.

According to a second aspect, there is provided a well system comprising the system for hydrate production of the first aspect.

The well system may comprise a subsea well system.

The well system may include a plurality of wellbores.

A third aspect relates to the use of a system for hydrate production according to the first aspect or a well system according to the second aspect for separating water components from a multiphase gas and water mixture present in a wellbore, the system being configured such that the separation takes place within the wellbore.

The method may include the step of depressurizing the hydrate from a solid state to a multiphase gas and water mixture.

Alternatively or in addition, the method may comprise the step of heating and or injecting a medium that allows the gas to dissociate.

The invention is defined by the appended claims. However, for the purposes of this disclosure, it is to be understood that any of the features defined above or described below may be used alone or in combination. For example, features described above with respect to one of the above aspects or below with respect to the following detailed description may be used in any other aspect or together form new aspects.

Drawings

These and other aspects will now be described, by way of example only, with reference to the accompanying drawings, in which:

FIG. 1 shows a schematic diagram of a system for hydrate production;

FIG. 2 shows another schematic diagram of the system shown in FIG. 1;

FIG. 3 illustrates a cap assembly of the system shown in FIG. 1;

FIG. 4 illustrates a manifold for a flow line of the system of FIG. 1;

FIG. 5 is a schematic diagram of a control system of the system shown in FIG. 1;

FIG. 6 illustrates an alternative system for hydrate production, the system comprising a plurality of wellbores;

FIG. 7 is a logic diagram showing how the system of FIG. 6 would operate; and is also provided with

Fig. 8 illustrates a well system including the system for hydrate production shown in fig. 6.

Detailed description of the drawings

Referring first to fig. 1 and 2 of the drawings, a schematic diagram of a system 10 for hydrate production is shown. The system 10 is shown for methane hydrate production.

In use, and as will be described further below, the system 10 is configured to separate the water component W from the multiphase methane gas and water mixture M present in the wellbore 12, the system 10 being configured such that the separation occurs within the wellbore 12.

As shown in fig. 1, the system includes a first flow line 14 disposed in the wellbore 12, the first flow line 14 being arranged such that an inlet 16 of the first flow line 14 is disposed in the water component W and receives the water component W to separate the water component W from the multiphase methane gas and water mixture M.

In the system 10 shown in fig. 1, the inlet 16 of the first flow line 14 forms the distal end of the first flow line 14.

However, it should be understood that the inlet may alternatively or additionally include one or more lateral flow ports in the first flow line 14, for example. Further, while the system 10 includes a single flow line 14, the system 10 may alternatively include a plurality of first flow lines 14.

As shown in fig. 1, the system 10 further includes a flow control device 18 disposed on or operatively associated with the first flow line 14.

In the illustrated system 10, the flow control device 18 takes the form of a variable flow control device, and more particularly a variable flow resistor.

The system 10 also includes a check valve 20. In the illustrated system 10, the check valve 20 comprises or takes the form of a ball valve.

A check valve 20 is disposed on the first flow line 14 and is configured to prevent or limit backflow of the water component W through the first flow line 14, i.e., back toward the inlet 16. In the illustrated system 10, a check valve 20 is interposed between the inlet 16 of the first flow line 14 and the flow control device 18.

The system 10 also includes a sensor arrangement including sensors 22, 24 configured to detect the level of the water component W in the wellbore 12 and output an output signal indicative of the level.

In the illustrated system 10, the sensors 22, 24 each take the form of a downhole pressure and temperature (DHPT) meter. The sensor 22 measures pressure and/or temperature at the first wellbore location. The sensor 24 measures pressure and/or temperature at the second wellbore location. Since the distance between the sensors 22, 24 is known, the water level can be easily determined. However, it should be appreciated that other suitable sensors for measuring water level may be employed.

As shown in fig. 1, the system 10 includes a pump 26 coupled or operatively associated with the first flow line 14.

The pump 26 is configured to draw the water component W from the wellbore 12 through the first flow line 14.

In the illustrated system 10, the pump 26 comprises or takes the form of a single-phase centrifugal pump, i.e., a pump configured to process single-phase fluid.

Advantageously, the system 10 is configured to separate the water component W of the multiphase water and methane gas mixture M within the wellbore 12, and thus may utilize a single phase pump, such as pump 26, that provides greater control over the fluid flow through the first flow line 14.

As shown in fig. 1, the system 10 includes a second flow line 28. A second flow line 28 is disposed in the wellbore 12 and is arranged such that an inlet 30 of the second flow line 28 is disposed in the multiphase methane gas and water mixture M and receives the methane gas component G.

In the illustrated system 10, the inlet 30 of the second flow line 28 forms the distal end of the second flow line 28.

However, it should be understood that the inlet 30 may alternatively or additionally include one or more lateral flow ports in the second flow line 28, for example. Further, while the system 10 includes a single flow line 28, the system 10 may alternatively include a plurality of second flow lines 28.

As shown in fig. 1, the system 10 includes a flow control device 32 disposed on or operatively associated with the second flow line 28. In the illustrated system 10, the flow control device 32 takes the form of a variable flow control device, and more particularly a variable flow resistor.

The system 10 also includes an isolation valve 34 disposed on or operatively associated with the second flow line 28. In the illustrated system 10, the isolation valve 34 takes the form of an annular isolation valve.

As shown in fig. 1 and referring now also to fig. 2 and 3 of the drawings, the system 10 further includes a cover 36. The cap 36 is coupled to and/or mounted on a wellhead 38 (shown in fig. 2), and as can be seen in fig. 2, in the illustrated system 10, the first and second flowlines 14, 28 are disposed through the wellhead 38.

As shown in fig. 2, the system 10 further includes a tubing hanger 40. Tubing hanger 40 is disposed on and/or supported by wellhead 38. The first and second flowlines 14, 28 are disposed through a tubing hanger 40.

As shown in fig. 3 of the drawings, the system 10 includes a flow meter 42, which in the illustrated system 10 takes the form of a single phase flow meter.

As shown in fig. 2 and 3, the system 10 further includes a valve 44 adapted to open and close the first flow line 14, which valve takes the form of an ROV-operable gate valve in the illustrated system 10.

As shown in fig. 4 of the drawings, the system 10 further includes a manifold 48. As shown in fig. 4, the first flow line 14 flows into a water production header 47 and the second flow line 28 flows into a gas production header 49.

Referring now to FIG. 5 of the drawings, a schematic diagram of a control system 50 of the system 10 of FIG. 1 is shown.

The control system 50 is configured to receive an output signal from the sensor device indicative of the water level and to control the flow control device 18 based on the water level in order to control the flow of the water component W through the first flow line 14. In the illustrated system 10, the control system 50 forms or is part of a subsea well control system.

As shown in fig. 5, the control system 50 includes a control module 52, which in the illustrated control system 50 takes the form of a subsea control module.

The subsea control module 52 is configured to process sensor data received from at least one of the sensors of the sensor device (and/or any other input of the subsea control module 52) and output one or more command signals to the position controller 60 of the choke 18 to control the position of the choke 18, and to the position controller 62 of the isolation valve 46 to control the position of the isolation valve 46. In the illustrated system 10, the subsea control module 52 is configured to process sensor data received from one or more water level sensors 22, 24, one or more erosion sensors 54, one or more flow sensors (such as the flow meter 42), one or more choke position sensors 56, one or more pressure and/or temperature sensors 58.

As shown in fig. 5, the control system 50 includes a main control station or module 64. The control module 52 is configured to communicate with a master control station or module 64 and vice versa.

The master control station or module 64 is configured to receive information from one or more upper level systems or modules. In the illustrated system 10, a main control station or module 64 is configured to receive information from an Emergency Shutdown (ESD) system or module 66 and a system flow demand system or module 68. However, it should be understood that the main control station or module 64 may receive one or more inputs from various other sources in addition to, or in lieu of, the Emergency Shutdown (ESD) system or module 66 and the system flow demand system or module 68.

The main control station or module 64 is configured to process information (and/or any other inputs to the main control station or module 64) from one or more upper layer modules (e.g., the emergency shutdown module 66 and the system flow demand module 68) and to output one or more command signals to a controller 70 (specifically, a speed controller) of the pump 28 (shown in fig. 1).

The control system 50 includes, is coupled to, or in communication with a pump control system 72, which in the illustrated system 10 takes the form of a subsea pump control system.

The pump control system 72 includes a pump control module. The pump control system 72 includes or takes the form of a processor.

The pump control module 74 communicates with one or more sensors associated with control of the pump and one or more actuators (collectively indicated as reference numeral 76 in fig. 6) associated with control of the pump.

The system 10 provides a number of significant benefits over conventional devices and methods.

For example, the system 10 utilizes the methane hydrate production wellbore 12 itself to separate the water component W from the gas, thereby eliminating or at least reducing the need for further separation of the phases downstream of the wellbore 12.

Furthermore, conventional apparatus and methods involve transporting a multiphase mixture to the surface, which, as described above, can reform hydrates under pressure and temperature conditions typically found on the seabed. In contrast, in the present system, separation occurs within the wellbore such that the risk of hydrate reformation is eliminated or at least significantly reduced. This in turn improves the availability and/or efficiency of the methane hydrate production system, as well as reduces downtime associated with workover operations and the like and/or reduces or eliminates the need to use chemical hydrate inhibitors, heating equipment, or other hydrate mitigation agents.

Furthermore, methane hydrates are sensitive to high flows, and thus the present system advantageously facilitates the use of flow control devices on the first flow line to control flow.

It will be appreciated that various modifications may be made without departing from the scope of the invention as defined in the claims.

For example, fig. 6 shows an alternative system 110 for methane hydrate production that includes a plurality of wellbores 112a, 112b. The illustrated system 110 shows two wellbores 112a, 112b. However, it should be understood that the system 110 may include any number of wellbores 112a, 112b, 112#.

As shown in fig. 6, the system 110 includes two flow lines 114a, 114b disposed in respective wellbores 112a, 112b, the flow lines 114a, 114b being arranged such that inlets 116a, 116b of the flow lines 114a, 114b are disposed in the water components Wa, wb and receive the water components to separate the water components Wa, wb from the multiphase methane gas and water mixtures Ma, mb.

In the illustrated system 110 shown in fig. 6, the inlets 116a, 116b form distal ends of the first flow lines 114a, 114b.

However, it should be understood that the inlets 116a, 116b may alternatively or additionally include one or more lateral flow ports in the flow lines 114a, 114b, for example. Further, while the system 110 includes a single flow line 114a, 114b per wellbore 112a, 112b, the system 110 may alternatively include multiple flow lines 114a, 114b per wellbore 112a, 112 b.

As shown in fig. 6, the system 110 also includes flow control devices 118a, 118b disposed on or operatively associated with the flow lines 114a, 114b.

In the illustrated system 10, the flow control device 118 takes the form of a variable flow control device, and more particularly a variable flow resistor.

The system 110 also includes check valves 120a, 120b. In the illustrated system 110, the check valves 120a, 120b comprise or take the form of ball valves.

Check valves 120a, 120b are disposed on the flow lines 114a, 114b and are configured to prevent or limit backflow of the water components Wa, wb through the respective flow lines 114a, 114 b. In the illustrated system 110, check valves 120a, 120b are interposed between the inlets 116a, 116b of the first flow lines 114a, 114b and the flow control devices 118a, 118 b.

The system 110 also includes a sensor arrangement including sensors 122a, 122b, 124a, 124b configured to detect the water level of the water components Wa, wb in the wellbores 112a, 112b and output an output signal indicative thereof.

In the illustrated system 110, the sensors 122a, 122b, 124a, 124b each take the form of a downhole pressure and temperature (DHPT) meter. The sensors 122a, 122b measure pressure and/or temperature at respective first wellbore locations in the wellbores 112a, 112 b. The sensors 124a, 124b measure pressure and/or temperature at respective second wellbore locations in the wellbores 112a, 112 b. Since the distance between the sensors 122a, 122b is known and the distance between the sensors 1224, b is known, the water level can be easily determined. However, it should be appreciated that other suitable sensors for measuring water level may be employed.

As shown in fig. 6, the system 110 includes a pump 126 coupled or operatively associated with the flow lines 114a, 114 b.

The pump 126 is configured to draw the water components Wa, wb from the wellbores 112a, 112b through the flow lines 114a, 114 b.

In the illustrated system 110, the pump 26 comprises or takes the form of a single-phase vertical centrifugal pump, i.e., a pump configured to process single-phase fluid.

Advantageously, the system 110 is configured to separate the water components Wa, wb of the multiphase water and methane gas mixtures Ma, mb within the wellbores 112a, 112b, and thus may utilize a single phase pump, such as pump 126, that provides greater control over the fluid flow through the flow lines 114a, 114 b.

As shown in fig. 6, the system 110 includes flow lines 128a, 128b. The flow lines 128a, 128b are disposed in the wellbores 112a, 112b and are arranged such that the inlets 130a, 130b of the flow lines 128a, 128b are disposed in and receive the methane gas components Ga, gb of the multiphase methane gas and water mixtures Ma, mb.

In the illustrated system 110, the inlets 130a, 130b of the flow lines 128a, 128b form distal ends of the second flow lines 128a, 128b.

However, it should be understood that the inlets 130a, 130b may alternatively or additionally include one or more lateral flow ports in the flow lines 128a, 128b, for example. Further, while the system 110 includes a single flow line 128a, 128b per wellbore 112a, 112b, the system 110 may alternatively include multiple flow lines 128a, 128b per wellbore 112a, 112 b.

As shown in fig. 6, the system 10 includes flow control devices 132a, 132b disposed on or operatively associated with the flow lines 128a, 128 b.

In the illustrated system 10, the flow control devices 132a, 132b take the form of variable flow control devices, and more particularly, variable flow resistors.

The system 110 also includes isolation valves 134a, 134b disposed on or operatively associated with the flow lines 128a, 128 b.

Fig. 7 shows an exemplary logic diagram of how the system of fig. 6 may operate. As described above, while the system 110 includes two wellbores 112a, 112b, the system 110 may include any number of wellbores. The other well bore is indicated by # in figure 7.

Fig. 8 shows a well system 1000 comprising the system 110 for methane hydrate production shown in fig. 6 coupled to a vessel V via a riser R.

This written description uses examples to disclose the invention, including the preferred embodiments, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. Aspects from the various embodiments described, as well as other known equivalents for each such aspect, may be mixed and matched by one of ordinary skill in this art to construct additional embodiments and techniques in accordance with principles of this invention.

Claims

1. A system for hydrate production, wherein the system is configured to separate water components from a multiphase gas and water mixture present in a wellbore, the system being configured such that the separation occurs within the wellbore, wherein the system comprises:

a first flow line disposed in the wellbore, the flow line arranged such that an inlet of the first flow line is disposed in the water component of the multiphase gas and water mixture and receives the water component of the multiphase gas and water mixture to separate the water component from the multiphase gas and water mixture;

a control system configured to receive the output signal indicative of the water level from the sensor device and to control the flow control device based on the water level so as to control the flow of the water component through the first flow line.

2. The system of claim 1, wherein the flow control device comprises or takes the form of a variable flow control device.

3. The system of claim 1 or 2, wherein the flow control device comprises or takes the form of a flow resistor.

4. The system of claim 1, 2, or 3, comprising a pump coupled or operatively associated with the first flow line, wherein the pump is configured to pump the water component of the multiphase gas and water mixture present in the wellbore through the first flow line.

5. The system of claim 4, wherein the pump comprises or takes the form of one of:

a single-phase pump; or alternatively

A multiphase pump.

6. The system of claim 4 or 5, wherein the control system is configured to control the pump.

7. A system according to any preceding claim, comprising a second flow line disposed in the wellbore, the second flow line being arranged such that an inlet of the second flow line is disposed in and receives the gas component of the multiphase gas and water mixture.

8. The system of claim 7, comprising a flow control device disposed on or operatively associated with the second flow line.

9. The system of claim 8, wherein the flow control device comprises or takes the form of a variable flow control device.

10. The system of claim 8 or 9, wherein the flow control device comprises or takes the form of a flow resistor.

11. The system of any preceding claim, wherein the sensor device further comprises at least one of:

one or more erosion sensors;

one or more flow sensors;

one or more position sensors of the flow control device disposed on or operatively associated with the first flow line; and

one or more pressure and/or temperature sensors.

12. The system of any preceding claim, wherein the control system comprises a control module, wherein the control module is configured to:

processing sensor data received from at least one of the sensors of the sensor device; and at least one of:

Outputting one or more command signals to a position controller and/or an actuation mechanism of the flow control device disposed on or operatively associated with the first flow line to control the position of the flow control device; and/or

One or more command signals are output to a position controller and/or an actuation mechanism of at least one isolation valve disposed on or operatively associated with the first flow line to control the position of the isolation valve.

13. The system of any preceding claim, wherein the control system comprises, is coupled to, or communicates with a master control station or module.

14. The system of claim 13 when dependent on claim 4, wherein the master control station or module is configured to:

processing information from at least one upper layer system or module; and is also provided with

One or more command signals are output to a controller of the pump.

15. The system of any preceding claim, wherein the control system comprises, is coupled to, or communicates with a pump control system.

16. The system of any preceding claim, wherein the system comprises or takes the form of a system for natural gas hydrate production, wherein the system is configured to separate a water component from a multiphase natural gas and water mixture present in a wellbore.

17. The system of any preceding claim, wherein the system comprises or takes the form of a system for methane hydrate production, wherein the system is configured to separate a water component from a multiphase methane gas and water mixture present in a wellbore.

18. A well system comprising the system for hydrate production according to any one of claims 1 to 17.

19. The well system of claim 18, comprising a plurality of wellbores.

20. Use of the system for hydrate production according to any one of claims 1 to 17 or the well system according to claim 18 or 19 to separate water components from a multiphase gas and water mixture present in a wellbore, the system being configured such that the separation occurs within the wellbore.