Subsea tree valve testing

Abstract

A method for testing a valve of a subsea Christmas tree is provided. The method includes closing the valve to be tested, fluidically isolating an isolatable region of the subsea Christmas tree directly adjacent to the valve to be tested, depressurizing or pressurizing the isolatable region using a pressure manipulation device positioned at the subsea after being isolated to a pressure that is less than ambient subsea pressure, monitoring the pressure of the isolatable region after being depressurized, and determining whether the valve to be tested is operating correctly based on the monitoring.

Description

Technical Field

[0001] This invention relates to a method for testing valves of a subsea wellhead and a system comprising a subsea wellhead and valve testing components. Background Technology

[0002] Subsea wells, such as production and injection wells, are used in the oil and gas production sector during the extraction of hydrocarbon fluids from reservoirs. Subsea wells can also be used for carbon capture and storage (CCS) to facilitate the injection of CO2 into underground formations. Subsea wells are typically equipped with a Christmas tree, which includes an arrangement of valves and conduits for regulating the inflow or outflow of fluids from the well. The Christmas tree is usually installed at the wellhead of the subsea well.

[0003] In traditional systems, the service line connects the subsea production tree fluid to the surface chemical storage system. The purpose of this service line is to supply the necessary chemicals (such as MEG) to the subsea well and also to perform all required well integrity tests. Service lines are typically provided as a separate line or integrated as part of the control cable.

[0004] It is important to regularly test the operation of valves in the wellhead to detect any leaks or malfunctions. Various test sequences are performed to test each valve in the wellhead sequentially. To test whether a valve is operating correctly, a pressure differential typically in the range of 30 to 70 bar is created across the valve, and fluid leaks are checked.

[0005] When testing valves on high-pressure pipelines, this pressure differential can be generated by venting fluid from the downstream pipeline back to the service pipeline, thereby reducing pressure on the downstream side of the valve. However, due to the weight of the fluid in the service pipeline, the minimum downstream pressure achievable using this technique is approximately equal to ambient pressure (i.e., approximately the pressure of the surrounding ocean at the depth of the wellhead). If this is insufficient to achieve the desired pressure differential, for example, if the pressure on the upstream side of the valve is too close to ambient pressure, it is necessary to artificially increase the pressure in the upstream region, for example, by injecting chemicals from an onshore chemical storage system into the wellhead via the service pipeline.

[0006] Pressurizing the wellhead in this manner can be dangerous due to the required high pressure, and may also require the injection of large amounts of fluid. In some cases, such as when the upstream fluid of the valve is connected to the annulus of a well that is normally under relatively low pressure, valve testing may require artificially increasing the pressure throughout the annulus, which further increases the risks involved. Summary of the Invention

[0007] It is proposed to provide a method and system for testing valves in subsea production trees that is safe and relatively simple to perform.

[0008] From a first aspect, the present invention provides a method for testing a valve of a subsea wellhead, the subsea wellhead being arranged to control the inflow or outflow of fluid into or out of a subsea well, the method comprising: closing the valve to be tested; fluid isolation of an isolable region of the subsea wellhead directly adjacent to the valve to be tested; after isolation, depressurizing the isolable region to a pressure below the ambient underwater pressure or pressurizing the isolable region using a pressure manipulator positioned underwater; monitoring the pressure of the isolable region after depressurization or pressurization; and determining, based on the monitoring, whether the valve to be tested is operating correctly.

[0009] Because the pressure control unit is located underwater rather than above water, it may no longer be necessary to provide a service pipeline to connect the subsea production tree to the surface system, since the pressure control unit is located underwater.

[0010] Furthermore, the minimum pressure achievable in the isolable zone is not limited by the weight of the fluid in the service pipeline. Therefore, in some embodiments, the isolable zone can be depressurized to below ambient pressure. As a result, the system can achieve the target pressure differential across the valve to be tested without first pressurizing one side of the valve, even if that side has a relatively low pressure. This minimizes the hazards associated with artificially generated high pressure in the system. Therefore, this method can provide improved safety compared to existing systems.

[0011] The invention also extends to related systems. Therefore, from a second aspect, the invention provides a system comprising: a subsea production tree for controlling fluid inflow or outflow from a subsea well, the subsea production tree including a valve to be tested, wherein the system is configured such that an isolable region of the subsea production tree directly adjacent to the valve to be tested can be fluid-isolated during valve testing operations; a pressure control device positioned underwater and connected to the subsea production tree, such that the pressure control device can depressurize the fluid in the isolable region to a pressure below ambient underwater pressure or pressurize the fluid in the isolable region during valve testing operations; and a sensing device arranged to measure the pressure in the isolable region to determine the correct operation of the valve to be tested.

[0012] The system of the second aspect can be used to execute the method of the first aspect. The system of the second aspect may include a controller configured to operate the system using the method of the first aspect.

[0013] The system and method may also include any of the features described herein.

[0014] Subsea production trees can be used to control the inflow or outflow of fluids into any suitable subsea well, such as hydrocarbon fluid production wells (e.g., oil or gas production wells), liquid injection wells (e.g., water or liquid CO2 injection wells), gas injection wells (e.g., CO2 injection wells), etc. Injection wells can be used to inject gas or liquid during oil / gas production, or alternatively for gaseous or liquid CO2 injection in the case of CCS. Subsea production trees can be installed at the wellhead of the subsea well.

[0015] In addition to the valves to be tested, the subsea production tree preferably includes one or more other valves. The valves to be tested and / or any one or more other valves may include gate valves, annular main valves (AMV), annular isolation valves (AIV), annular suction valves (ASV), annular wing valves (AWV), annular vent valves (AVV), gas injection valves (GIV), production main valves (PMV), production suction valves (PSV), production wing valves (PWV), surface-controlled subsea surface safety valves (SCSSV; also known as downhole safety valves), service injection valves (SIV), etc. The flow of fluids entering the well (e.g., water or gas for injection) or leaving the well (e.g., produced hydrocarbons) during normal well operation is preferably controlled by operating one or more valves within the fluid flow path of the subsea production tree.

[0016] An isolable region directly adjacent to the valve to be tested preferably means that there are no other components between the isolable region and the valve to be tested, i.e., the valve to be tested itself forms the boundary of the isolable region. In addition to the valve to be tested, the isolable region may also include one or more other valves of the subsea tree and one or more portions of the pipelines interconnecting said valves. These portions of the pipelines may include parts of production lines, annulus lines, chemical injection lines, water or gas injection lines, etc. The isolable region of the subsea tree can be fluidly isolated by closing the valves defining the isolable region (except for closing the valve to be tested), thereby sealing the interconnecting pipelines. Therefore, after isolation is performed, any fluid within the isolable region is contained within the isolable region before depressurization or pressurization is performed.

[0017] In embodiments where the isolable region is depressurized, the isolable region of the wellhead is preferably a region directly downstream of the valve to be tested, because valves are typically tested such that higher pressure is on the upstream side of the valve and lower pressure is on the downstream side, as this most closely corresponds to their normal operating conditions. However, the isolable region can alternatively be a region directly upstream of the valve.

[0018] In embodiments where the separable region is pressurized, the separable region of the wellhead is preferably the region directly upstream of the valve to be tested. However, the separable region can also be the region directly downstream of the valve.

[0019] The terms “downstream” and “upstream” refer to the direction in which fluid flows through the subsea production tree during normal operation, such as when the well is producing or injection is taking place.

[0020] Sensing devices, such as pressure sensors, are arranged to measure the pressure in an isolable area. The system may include additional pressure sensors arranged to monitor the pressure in other areas of the system, such as annular crossings, production crossings, annulus, etc. Signals from one or more pressure sensors can be used to determine the pressure differential across a valve to be tested. The pressure differential is the pressure difference between the upstream and downstream sides of the valve and may be referred to as "delta pressure."

[0021] Preferably, a pressure-operated device is used to depressurize or pressurize the isolable area, thereby achieving a desired or target pressure differential across the valve to be tested. The target pressure differential can be determined based on, for example, the valve's specifications or requirements that the valve must meet. The target pressure differential can be at least 10 bar, and preferably at least 20 bar. In a preferred embodiment, the target pressure differential is in the range of 30 to 70 bar. Signals from pressure sensors(s) can be used to control the pressure-operated device, for example, to stop the pressure-operated device once the target pressure differential is reached.

[0022] The pressure control device can be any suitable device capable of underwater deployment and can be configured to depressurize the isolable area of ​​the production tree to a pressure below ambient underwater pressure and / or pressurize the isolable area of ​​the production tree during valve test operations. Ambient pressure is the pressure of the surrounding sea area at the depth of the subsea production tree (e.g., at 1000m below sea level, the ambient pressure may be approximately 100 bar (g)).

[0023] The pressure control device can perform pressurization and depressurization as described herein.

[0024] In some embodiments, the pressure manipulation device may include a controllable volume, such as a chamber whose volume can be controllably increased and decreased. The controllable volume is preferably in fluid communication with the isolable region via a conduit (e.g., a service line). The fluid flow path defined by the conduit can be opened and closed by the operation of one or more valves (e.g., service line valves). Thus, when the service line valve is opened, fluid in the isolable region flows into the controllable volume through the conduit. The volume of the controllable volume can then be adjusted, for example, using a suitable controller and / or actuator, until a desired pressure or differential pressure is achieved. Therefore, depressurizing the isolable region may include opening the service line valve and increasing the volume of the controllable volume. Conversely, pressurizing the isolable region may include opening the service line valve and decreasing the volume of the controllable volume. Thus, the same controllable volume can be used to pressurize and depressurize the isolable region as needed to achieve a valve test differential pressure.

[0025] In other embodiments, the pressure manipulation device may include other means, such as a pump or the like, for depressurizing or pressurizing an isolable area.

[0026] The pressure control device may optionally include a heater. Applying heating in the pressure control device can prevent the formation of hydrates, which can be a problem in both production wells and injection wells (including CO2 injection wells).

[0027] The pressure manipulation device is preferably located near the subsea production tree, for example, within approximately 20 m, 10 m, 5 m, or 2 m of the subsea production tree. In some embodiments, the pressure manipulation device may be mounted on or integrated with the subsea production tree. This allows for a relatively short interconnecting conduit between the pressure manipulation device and the subsea production tree, improving the ease with which pressure in the isolable area can be manipulated due to the relatively low volume of the manipulated fluid (i.e., compared to a long conduit). The pressure manipulation device is preferably located at or near the same subsea depth as the subsea production tree, such that the weight of the fluid within the interconnecting conduit does not unduly limit the minimum pressure achievable by the pressure manipulation device in the isolable area. For example, the pressure manipulation device may be located at a depth of less than 20 m above and / or below the depth of the valve to be tested, preferably less than 10 m above and / or below, more preferably less than 5 m above and / or below.

[0028] The pressure actuation device can be driven (e.g., controlled or actuated) by a suitable drive unit (such as a hydraulic power unit or an electric actuator). The drive unit is preferably also located underwater. The drive unit can be configured to adjust the volume of the controllable volume of the pressure actuation device, thereby controlling the pressure in the isolable area during valve test operations. The drive unit can, for example, control the position of the wall of the controllable volume, where the position of the wall affects the size of the controllable volume. The drive unit can change the position of the wall by hydraulic operation, motorized movement, or any other suitable technique.

[0029] In a preferred embodiment, the pressure actuation device includes a hydraulic piston driven by a subsea hydraulic power unit. The hydraulic piston preferably includes a working chamber and at least one drive chamber connected by a piston rod. The wall of the working chamber may be formed by the end of the piston rod. The working chamber may be fluidly connected to an insulated area of ​​the subsea tree via a service line. The working chamber and drive chamber may be configured such that when the piston rod moves in a first direction, the volume of the working chamber increases, while the volume of the drive chamber decreases, and vice versa.

[0030] In such an embodiment, the position of the piston rod (and thus the volume of the working chamber) can be controlled using the hydraulic circuit of the underwater power unit. The hydraulic circuit can be fluidly connected to the drive chamber and can be configured such that hydraulic fluid can be injected into or extracted from the drive chamber to move the piston rod accordingly. The underwater hydraulic power unit preferably includes a pump configured for this purpose. The pump can be connected to the drive chamber via a directional control valve (DCV) configured to allow fluid to flow through two or more different paths. The DCV can be switched between multiple positions to pump fluid into or out of the drive chamber as needed, thereby driving the piston rod in a first or second direction (i.e., expanding or contracting the working chamber). The hydraulic circuit may include one or more hydraulic accumulators (such as high-pressure accumulators and / or low-pressure accumulators) to temporarily store hydraulic fluid and return it to the circuit when needed.

[0031] In an alternative embodiment, the pressure manipulation device may include a piston driven by an electric actuator. The piston may include a working chamber, the volume of which can be adjusted by actuation of a piston rod controlled by the electric actuator. The working chamber may be fluidly connected to the isolable area of ​​the subsea tree via a service line. The electric actuator may include a rotating element whose rotational motion can be converted into linear motion of the piston rod, for example, using a ball screw. Electric actuators are advantageous because they can have variable speeds and stop at precise locations, enabling precise control of pressure in the isolable area, and they are generally less expensive than hydraulic actuators.

[0032] When the subsea well is a production well, embodiments including a hydraulic piston and a subsea hydraulic power unit may be preferred because more force is required from the drive unit. However, an electric actuator may be able to provide sufficient force for a production well, thus allowing for more precise position control and reduced costs in this case. When the subsea well is an injection well, embodiments including a piston and an electric unit may be preferred because less force is required from the drive unit, and therefore a simpler electric actuator is sufficient for pressure manipulation.

[0033] Pressure-operated devices may include fluid accumulators (such as accumulators) configured to receive and temporarily store fluid from the chambers of the pressure-operated device. Accumulators can help generate rapid delta pressure across the valve to be tested, achieving a good seal, which is crucial during valve pressure testing. When the fluid contained in the accumulator is a hydrocarbon fluid, the accumulator can be adequately insulated to prevent the formation of hydrates or waxes. The accumulator and / or its controlled volume can also be heated for this purpose, as previously described.

[0034] The volume of a controllable volume, such as the position of a piston rod, can be controlled using a suitable controller. The controller can be configured to control the volume of the controllable volume until a target pressure differential has been reached. The controller can receive signals from one or more pressure sensors in the system (particularly pressure sensors that monitor pressure in the insulated area and / or the controllable volume), allowing the controller to determine when the target pressure differential has been reached.

[0035] In some embodiments, the upstream side of the valve to be tested can be fluidly connected to the well's annulus during valve testing operations. Therefore, the pressure directly upstream of the valve during testing operations can be the annulus pressure. In such embodiments, the testing operation can be performed while the well is producing. The advantages of the described method are particularly appreciated in these embodiments because annulus pressure tends to decrease over the well's lifetime. Therefore, as annulus pressure decreases towards the end of the well's lifetime, the pressure differential between the annulus pressure and ambient pressure may be insufficient for well valve testing purposes (e.g., the pressure differential may be less than the minimum target pressure differential). In this case, conventional systems would require pressurizing the annulus first, which carries the previously mentioned safety risks. According to the described method, by artificially increasing the annulus pressure, the downstream pressure can be reduced to below ambient pressure using a pressure manipulation device. Therefore, the target pressure differential for valve testing can still be achieved without increasing the annulus pressure.

[0036] Once the target pressure differential has been achieved, the isolable area can be fluidly isolated again, for example by closing the fluid connection between the isolable area and the pressure control device that was opened during the depressurization or pressurization step.

[0037] Monitoring the pressure in the isolable zone after depressurization or pressurization can be performed for a predetermined period of time (e.g., 10 minutes). If the valve being tested is operating correctly and without leakage, the pressure in the isolable zone should remain unchanged or change very little during this period. If the valve being tested is faulty, some fluid from the relatively pressurized side of the valve may leak to the relatively low-pressure side, thus altering the pressure in the isolable zone. This will also cause the pressure differential to decrease as the pressures on both sides of the valve become equal. Therefore, if the isolable zone is depressurized, an increase in pressure in the isolable zone and / or a decrease in the pressure differential across the valve being tested during the predetermined period can indicate a leak in the valve, i.e., the valve is not operating correctly. Similarly, if the isolable zone is pressurized, a decrease in pressure in the isolable zone and / or a decrease in the pressure differential across the valve being tested during the predetermined period can indicate a leak in the valve.

[0038] While it is ideal to have no fluid leakage on either side of the valve being tested during testing, some acceptable leakage rate may exist on both sides. Therefore, if the pressure in the isolable area increases or decreases at a rate higher than a predetermined threshold during monitoring, it can be determined that the valve being tested is not operating correctly. Similarly, if the pressure in the isolable area increases or decreases at a rate lower than a predetermined threshold during monitoring, it can be determined that the valve being tested is operating correctly. The predetermined threshold may correspond to an acceptable leakage rate and can be determined based on specific parameters of the subsea tree and subsea well.

[0039] The conduit connecting the pressure control device and the subsea production tree can be flushed after a valve testing sequence to prepare the system for normal operation or for further valve testing sequences of other valves on the subsea production tree. Flushing the conduit may include pumping chemicals from a chemical storage system or from a service line connected to the surface via the conduit. Depending on the type of subsea well associated with the system, the chemicals used for flushing may include MEG, methanol, water, etc. The chemical storage system is preferably also located underwater to avoid the need for a chemical supply line connecting the subsea production tree to the surface chemical storage system. Therefore, the system may include a subsea chemical storage system fluidly connected to the conduit, and may further include pumps for pumping chemicals from the subsea chemical storage system via the conduit.

[0040] Multiple valve test sequences can be executed sequentially to test various valves in the subsea production tree. Some test sequences may test multiple valves simultaneously, such as by testing a ring cross or production cross. In this case, if a leak is detected, further operations may be required to identify which of the multiple valves being tested is leaking.

[0041] As mentioned above, subsea wells can also be used for carbon capture and storage by facilitating CO2 injection into underground formations. Such subsea wells typically also use valve trees to regulate fluids (i.e., CO2). Therefore, the subsea production tree valve testing method and system of the present invention can also be applied to this situation.

[0042] CO2 can be injected in liquid or gaseous form. With liquid CO2 injection, in the valve tree, if the CO2 pressure becomes too low, the CO2 may undesirably change from a liquid phase to a mixture of liquid and gas phases. Therefore, in these embodiments, the pressure control device can preferably be configured to depressurize the isolable region to a minimum pressure above 45 bar absolute pressure, so that the liquid CO2 does not change phase. Attached Figure Description

[0043] Some preferred embodiments of the invention will now be described by way of example only, with reference to the following figures, in which:

[0044] Figure 1 A schematic diagram of the system according to the first embodiment is shown;

[0045] Figure 2 It shows Figure 1 A close-up view of the system's pressure control device;

[0046] Figure 3 The first test configuration is shown. Figure 1 Valve arrangement of the system;

[0047] Figure 4 The second test configuration is shown. Figure 1 Valve arrangement of the system;

[0048] Figure 5 The third test configuration is shown. Figure 1 Valve arrangement of the system;

[0049] Figure 6 A schematic diagram of the system according to the second embodiment is shown; and

[0050] Figure 7 It shows Figure 6 A close-up view of the system's pressure control device. Detailed Implementation

[0051] A schematic diagram of system 1 according to the first embodiment is shown below. Figure 1As shown. System 1 includes a subsea production tree 2, which includes multiple valves 4a to 4m and pipelines 6a to 6c for controlling fluid inflow and outflow from the subsea production well. The subsea production tree 2 is connected to a production pipe 3 extending into the subsea production well. Valves 4a to 4m include annular main valve (AMV) 4a, annular isolation valve (AIV) 4b, annular suction valve (ASV) 4c, annular wing valve (AWV) 4d, annular vent valve (AVV) 4e, gas injection valve (GIV) 4f, production main valve (PMV) 4g, production suction valve (PSV) 4h, production wing valve (PWV) 4i, switching valve (XOV) 4j, surface-controlled subsea safety valve (SCSSV) 4k, service injection valve (SIV) 4l, and production throttle valve (PCV) 4m. Chemical injection lines 6b and 6c are configured to inject chemicals into production line 6a via valves 10a to 10f. Subsea tree 2 is fluidly connected to the annulus 8 and production line 3 of the subsea well. Flow control module 22, indicated by dashed lines, controls the fluid flow rate. A multiphase flow meter (MPFM) measures the fluid flow rate in flow control module 22.

[0052] The area of ​​subsea production tree 2 defined by GIV 4f, AVV 4e, ASV 4c, SIV 4l, XOV 4j, and AMV 4a (and interconnecting pipelines) is called the annular cross 5. The area of ​​subsea production tree 2 defined by PSV 4h, PMV 4g, XOV 4j, PWV 4i, and valves 10c and 10d (and interconnecting pipelines) is called the production cross 7.

[0053] System 1 also includes a hydraulic piston 12 for manipulating the pressure in the area of ​​the subsea tree 2. The hydraulic piston 12 is fluidly connected to the subsea tree 2 via a service line 14. A first service line valve 16a is configured to control the fluid flow between the service line 14 and the hydraulic piston 12, and a second service line valve 16b is configured to control the fluid flow between the service line 14 and the subsea tree 2. The service line 14 is also fluidly connected to a chemical storage system 18, wherein the fluid flow into and out of the chemical storage system 18 can be controlled via a third service line valve 16c. The chemical storage system 18 includes a pump (not shown).

[0054] Multiple pressure sensors 20a to 20e are located throughout system 1. The first pressure sensor 20a is arranged to measure the pressure in production cross 7. The second pressure sensor 20b is arranged to measure the pressure in annular cross 5. The third pressure sensor 20c is arranged to measure the pressure in the production pipe upstream of SCSSV 4k. The fourth pressure sensor 20d is arranged to measure the pressure in flow control module 22. The fifth pressure sensor 20e is arranged to measure the pressure in hydraulic piston 12.

[0055] System 1 also includes an underwater hydraulic power unit 24 configured to drive the hydraulic piston 12.

[0056] exist Figure 2 The structure of the hydraulic piston 12 and the underwater hydraulic power unit 24 can be seen more clearly in the image.

[0057] The hydraulic piston 12 includes a working chamber 26. The wall of the working chamber 26 is defined by a first end 28a of a piston rod 28. Actuation of the piston rod 28 in a linear direction changes the position of the first end 28a, thereby adjusting the volume of the working chamber 26. The working chamber 26 is fluidly connected to a service line 14 and includes a pressure sensor 20e and a heater 30. The heater 30 is used to prevent the formation of hydrates and / or wax in the working chamber 26 of the hydraulic piston 12, as the working chamber 26 is exposed to the generated fluid.

[0058] The hydraulic piston 12 also includes two drive chambers 32, 38. The wall between the first drive chamber 32 and the second drive chamber 38 is defined by a second end 28b of the piston rod 28. Actuation of the piston rod 28 in a linear direction changes the position of the second end 28b, thereby adjusting the volume of the drive chambers 32, 38. A neutral chamber 36 is defined between a partition 34 and a first end 28a of the piston rod 28. The working chamber 26 and the neutral chamber 36 are collectively referred to as the working cylinder 40. Similarly, the first drive chamber 32 and the second drive chamber 38 are collectively referred to as the drive cylinder 42. The working cylinder 40 and the drive cylinder 42 are fluidly isolated from each other by a partition 34 through which the piston rod 28 extends. A heater 30 may be configured to heat the working cylinder 40 (i.e., the neutral chamber 36 and the working chamber 26). The drive cylinder 42 may not require heating because it contains hydraulic fluid rather than a production fluid, and therefore there is no risk of hydrate formation.

[0059] The hydraulic piston 12 includes an accumulator 44 fluidly connected to a neutral chamber 36. Thus, when the piston rod 28 moves to the right, fluid in the first neutral chamber 36 enters and is stored in the accumulator 44, and when the piston rod 28 moves to the left, fluid leaves the accumulator 44 and enters the first neutral chamber 36. Although the movement of the piston rod is described herein as “left” and “right,” it should be understood that these terms are relative and are merely convenient labels to describe the opposite linear directions of movement of the piston rod 28.

[0060] The underwater hydraulic power unit 24 is configured to drive piston rod 28 and includes pump 46, a low-pressure accumulator 48 upstream of pump 46, and a high-pressure accumulator 50 downstream of pump 46. Pump 46 is operated to maintain the pressure difference between the upstream (low-pressure) side and the downstream (high-pressure) side of pump 46. A directional control valve (DCV) 52 is disposed between drive cylinder 42 and pump 46 and controls the fluid connection between them.

[0061] DCV 52 has three different positions or configurations. In the first position of DCV 52, the second drive chamber 38 is connected to the low-pressure side of pump 46, while the first drive chamber 32 is connected to the high-pressure side of pump 46. Therefore, piston 28 will move to the left, thereby reducing the volume of working chamber 26. In the second position of DCV 52, drive cylinder 42 is not in fluid communication with any accumulators 48, 50 of hydraulic power unit 24. Therefore, the volume of working chamber 26 remains constant. In the third position of DCV 52, the second drive chamber 38 is connected to the high-pressure side of pump 46, while the first drive chamber 32 is connected to the low-pressure side of pump 46. Therefore, piston 28 will move to the right, and the volume of working chamber 26 will increase.

[0062] Therefore, the hydraulic power unit 24 is configured to drive the piston rod 28 to the right or left by pumping fluid into either the first drive chamber 32 or the second drive chamber 38, depending on the configuration of the DCV 52. When the piston rod 28 is actuated to the left, fluid in the working chamber 26 is forced out of the hydraulic piston 12 and into the service line 14 (if the first service line valve 16a is open). Conversely, when the piston rod 28 is actuated to the right, fluid is drawn from the service line 14 into the working chamber 26 (if the first service line valve 16a is open). In this way, the underwater hydraulic power unit 24 actuates the hydraulic piston 12 to pressurize or depressurize the fluid in the working chamber 26, and thus the fluid in the service line 14.

[0063] return Figure 1 System 1 can be used to perform valve testing operations to test the operation of one or more valves 4a to 4m in the subsea production tree 2. The sequence of steps in the valve testing operation will vary depending on whether one or more valves 4a to 4m are being tested. See below for reference. Figures 3 to 5 Some example test operations are described.

[0064] refer to Figure 3 The illustration shows the first example valve test sequence used to test the AMV 4a. The AMV 4a was tested under stable flow and temperature conditions, while a subsea well was in production.

[0065] In the initial configuration, GIV 4f, AVV 4e, ASV 4c, AWV 4d, SIV 4l, and XOV 4j are closed, while AMV 4a is open. The upstream fluid of AMV 4a is connected to annulus 8, and therefore the pressure directly upstream of AMV 4a is under the pressure of annulus 8.

[0066] The shut-in pressure in annulus 8 was measured and recorded using the second pressure sensor 20b. Then, AMV 4a was closed and AWV 4d was opened. During this phase of the test operation, the valve configuration of subsea production tree 2 was as follows: Figure 3 As shown, open valves are represented by hollow valve symbols, while closed valves are represented by solid valve symbols. For simplicity, Figure 3 Only a portion of System 1 is shown.

[0067] Therefore, the isolable region 54 of the subsea production tree 2 is defined by valves GIV 4f, AVV 4e, ASV 4c, AMV 4a, SIV 4l, and XOV 4j, and is fluidly isolated by closing said valves 4a, 4c, 4e, 4f, 4j, and 4l. The direct pressure in the isolable region 54 after fluid isolation can be approximated as the annular pressure.

[0068] Next, the isolable zone 54 is depressurized according to the following steps. During this stage, service line valves 16a, 16b, and 16c should be closed. SIV 4l is opened, allowing fluid to flow from the isolable zone 54 into service line 14 to release pressure from the isolable zone 54 (i.e., depressurize). This initiates a pressure differential across AMV 4a. If the pressure differential at this point is less than the target pressure differential of 30 to 70 bar, the hydraulic piston 12 operates as follows.

[0069] Valve 16b is opened to release the pressure in service line 14. Then, when the pressure in service line 14 and the pressure downstream of PCV 4m are measured to be the same, valve 16b is closed. DCV 52 is set to the second position (i.e., isolating drive cylinder 42 from hydraulic power unit 24), and the required stop pressure (for the pressure measured by pressure sensor 20e) is set in the control software of pump 46.

[0070] Then, valve 16a is opened, and DCV 52 is set to the third position. This causes the hydraulic power unit 24 to draw fluid from the first drive chamber 32 and supply pressurized fluid to the second drive chamber 38, thereby actuating the piston rod 28 to the right as previously described. The volume of the working chamber 26 thus increases, and fluid from the isolable region 54 is drawn into the working chamber 26 via the service line 14, thereby depressurizing the isolable region 54.

[0071] When the stop pressure is reached, close valve 16a and return DCV 52 to the second position. Close SIV4l.

[0072] Then, the pressure in the insulated area 54, measured by pressure sensor 20b, is monitored for 10 minutes, although other time periods specified in the relevant test standards may be used for the specific design of the AMV 4a to be tested. The results are recorded, and the monitoring results are used to determine whether the AMV 4a is operating correctly or incorrectly.

[0073] Once the valve test has been performed, follow these procedures to prepare the subsea production tree 2 for normal use again.

[0074] First, ensure that SIV 4l and valves 16a, 16b, and 16c are closed. DCV 52 is initially set to the second position. Switch DCV 52 to the first position and open valves 16b and 16a. This will cause high-pressure fluid from the high-pressure accumulator 50 to enter the first drive chamber 32, thereby actuating piston rod 28 to the left. Since valves 16a and 16b are open, fluid will be re-injected into production line 6a. When piston rod 28 has reached its end position, set DCV 52 to its second position and close valve 16a.

[0075] Then open valve 16c and flush the fluid from chemical storage system 18 through valve 16b for a short period of time. Then close valve 16b. If necessary, also flush service line 14.

[0076] The system is now working properly.

[0077] The above description is an exemplary well test sequence for testing the operation of AMV 4a using this system and method. As mentioned above, this system and method can also be used to test other valves in the subsea production tree 2.

[0078] Now for reference Figure 4 The second well test sequence can be executed on system 1 to test PMV 4g. For the sake of brevity, Figure 4 Only a portion of System 1 is shown.

[0079] PMV 4g was tested under stable flow and temperature conditions. The following steps apply to systems without gas lift. It is assumed that the PMV 4g test was conducted after Production Cross 7 had already been tested (the testing process is not described in detail here). Therefore, it is assumed that chemical injection into the well has been stopped, and that PCV 4m, PWV 4i, XOV 4j, and PMV 4g are closed. During this phase of the test operation, the valve configuration of Subsea Production Tree 2 is as follows... Figure 4 As shown.

[0080] Close AWV 4d. Ensure valves 16a, 16b, 16c and SIV 4l are closed. Set the pressure of the pump in chemical storage system 18 and start the pump. Open valve 16c, then open SIV 4l. The MEG or methanol stored in chemical storage system 18 is injected into the subsea tree 2 upstream of XOV 4j through service line 14, thus equalizing the pressure on both sides of XOV 4j.

[0081] The isolable zone 56 of the subsea well is defined by valves PSV 4h, PMV 4g, XOV 4j, PWV 4i, 10c, and 10d (i.e., in this example, production cross 7 is the isolable zone). Therefore, the isolable zone 56 is fluidly isolated by closing these valves 4g, 4h, 4i, and 4j. The isolable zone 56 is then depressurized as follows.

[0082] Open XOV 4j and SIV 4l. The pressure in the isolable zone 56 is released via XOV 4j through service line 14. This continues until a pressure differential is established across PMV 4g. If the pressure differential at this point is less than the target pressure differential of 30 to 70 bar, the hydraulic piston 12 operates in the same manner as described in the first example test sequence to depressurize the isolable zone to below ambient pressure until the target pressure differential is reached.

[0083] Then shut down XOV 4j. Inject MEG or methanol from the chemical storage system 18 via service line 14 to pressurize the differential pressure across XOV 4j to 30 bar. Then monitor the pressure in the insulated zone 56, measured by pressure sensor 20a, for 10 minutes. Record the results and determine whether PMV 4g is operating correctly or incorrectly based on the monitoring results.

[0084] Once the valve test has been performed, the isolable area 56 is flushed with MEG or methanol in a manner similar to that described in the first example test sequence to prepare System 1 for normal use again. System 1 is now ready for normal use.

[0085] A similar test sequence can be performed to test the downhole safety valve (SCSSV) 4k. Figure 5 The valve configuration during the test operation of SCSSV 4k is shown. In this example, the isolable area 58 is defined by valves XOV 4j, PSV 4h, PWV 4i, 10c, 10d, and SCSSV 4k. The difference from the second test sequence is that PMV 4g is open while SCSSV 4k is closed, creating a target pressure differential across SCSSV 4k and testing its operation.

[0086] The System 1 and exemplary test sequence described above are for production wells. However, as previously stated, the described test methods can also be applied to injection wells.

[0087] Figure 6 System 200 according to a second embodiment is shown. System 200 includes a subsea production tree 2, the schematic of which is similar to that of the subsea production tree 2 in System 1. Therefore, the same reference numerals are used to indicate the same elements. The difference between subsea production tree 2 and subsea production tree 202 is that, in the flow control module 222 of subsea production tree 202, since the well associated with subsea production tree 202 is an injection well rather than a production well, the choke valve 204m is installed in the opposite manner compared to the choke valve 4m in System 1. Subsea production tree 202 is connected to injection pipe 203 instead of production pipe 3. Furthermore, a multiphase flow meter (MPFM) is not required in subsea production tree 202, and the main pipeline is injection line 206 instead of production line 6a. The flow rate of single-phase flow in the injection well can be verified using a single-phase flow meter such as a venturi tube (not shown).

[0088] Apart from the differences mentioned above, the pressure control device used to depressurize the isolable area of ​​the subsea production tree 202 is a piston 212 driven by an electric actuator 224, rather than a hydraulic piston 12 driven by a hydraulic power unit 24.

[0089] Figure 7 Detailed views of the piston 212 and electric actuator 224 of system 200 are shown. Piston 212 includes a working chamber 226, which is fluidly connected to service line 14 via a first service line valve 216a. Piston 212 also includes a neutral chamber 236, wherein the working chamber 226 and the neutral chamber 236 together form a working cylinder 240. Working chamber 226 includes a pressure sensor 220e. Unlike the hydraulic piston 12 of system 1, a heater is not required in working chamber 226. This is because hydrate formation is not a problem of the injection well, as the fluid is water / gas rather than hydrocarbons. Piston 212 includes a piston rod 228, which is arranged to adjust the volume of working chamber 226 via linear movement of the piston rod 228.

[0090] Piston 212 includes an accumulator 244 connected to neutral chamber 236. Thus, when piston rod 228 moves to the right, fluid in neutral chamber 236 enters and is stored in accumulator 244, and when piston rod 228 moves to the left, fluid leaves accumulator 244 and enters neutral chamber 236.

[0091] The piston rod 228 is driven by an electric actuator 224. The electric actuator 224 includes a rotating element (not shown) configured to undergo rotational motion. The rotational motion of the rotating element is converted into linear motion of the piston rod 228 via a ball screw mechanism (not shown). Therefore, the electric actuator 224 can change the speed of the piston rod 228 and also stop the piston rod 228 at a precise position to provide very precise control over the release pressure in the isolable region.

[0092] Aside from the operation of the devices used to manipulate the pressure in the isolated area, the valve testing sequence for testing the valves in subsea production tree 202 is similar to that used for subsea production tree 2. An example test sequence for testing AMV 4a is described below.

[0093] AMV 4a was tested under stable flow and temperature conditions.

[0094] Close valve 216b and open valve 216a. Record the shut-in pressure in the annulus 8 as measured by pressure sensor 20b. Close AMV 4a and open AWV 4d. The isolable area in this example is defined by GIV 4f, AVV 4e, ASV 4c, SIV 4l, XOV 4j, and AMV 4a.

[0095] The isolable region is then depressurized by opening SIV 4l, which creates a pressure differential across AMV 4a. To further depressurize the isolable region below ambient pressure to achieve a target pressure differential of 30 to 70 bar across AMV 4a, the electric actuator 224 operates as follows.

[0096] The electric actuator 224 is operated to drive the piston rod 228 to the right, thereby expanding the volume of the working chamber 226. Fluid can then flow from the isolable region to the working chamber 226 via the service line 14, thereby depressurizing the isolable region. Once a delta pressure of 30 to 70 bar is reached on both sides of AMV 4a, the electric actuator 224 is stopped. SIV 4l is then shut off.

[0097] Then, pressure is monitored in the isolable area for 10 minutes, measured by pressure sensor 20b. The results are recorded, and the AMV 4a is determined to be operating correctly or incorrectly based on the monitoring results.

[0098] After the valve test, valve 216a is closed and valve 216b is opened. The electric actuator 224 is operated to reduce the volume of the working chamber 226. The actuator 224 stops when the piston rod 228 is in the end position. Therefore, the fluid that entered the piston 212 during the valve test is subsequently reinjected into the injection line 206.

[0099] Then System 200 is ready to proceed with normal operation or further valve testing.

[0100] It will be readily understood that, similar to the test sequence described in Reference System 1, System 200 can be used to perform further test sequences to test other valves of the subsea production tree 202, such as PMV 4g and SCSSV 4k. Further test sequences can be performed using different sequences of valve opening and closing to test other valves of the subsea production tree 202, or multiple valves can be tested simultaneously, for example, by testing the production cross 7 or the annular cross 5.

[0101] Although the above embodiments have described depressurization of the isolable region, it should be understood that the pressure control device can alternatively be used to pressurize the isolable region to achieve the required valve test differential pressure.

[0102] For example, refer to again Figures 1 to 3 The following steps can be performed to pressurize the isolable region 54 (instead of depressurizing as previously described).

[0103] First, service line valves 16a, 16b, and 16c should be closed. Then, open SIV 4l to allow fluid to flow between service line 14 and the separable zone 54. Next, the hydraulic piston 12 should be operated as follows.

[0104] Open valve 16b to equalize the pressure within service line 14. When the pressure in service line 14 is measured to be the same as the pressure downstream of PCV4m, close valve 16b. Set DCV 52 to the second position (i.e., isolate drive cylinder 42 from hydraulic power unit 24), and set the desired stop pressure (for the pressure measured by pressure sensor 20e) in the control software of pump 46.

[0105] Then, valve 16a is opened, and DCV 52 is set to the first position. This causes the hydraulic power unit 24 to draw fluid from the second drive chamber 38 and supply pressurized fluid to the first drive chamber 32, thereby actuating the piston rod 28 to the left. As a result, the volume of the working chamber 26 decreases, and the fluid from the working chamber 26 is forced into the isolable region 54 via the service line 14, thereby pressurizing the isolable region 54.

[0106] When the stop pressure is reached, close valve 16a and return DCV 52 to the second position. Close SIV4l. Pressure monitoring can then be performed as previously described to check the operation of the tested valve.

[0107] If an electric actuator is used instead of a hydraulic actuator, for example, as previously referenced... Figure 6 and Figure 7As described, the isolable region can be pressurized as follows. After SIV 4l has been opened, the electric actuator 224 can be operated to drive the piston rod 228 to the left (instead of to the right, as previously described) to reduce the volume of the working chamber 226. Fluid is then forced to flow from the working chamber 226 to the isolable region via the service line 14, thereby pressurizing the isolable region.

[0108] If necessary, the position of piston rod 28 or piston rod 228 can be set before the pressure manipulation process begins, depending on whether the isolable region is to be pressurized or depressurized. For example, if depressurization of the isolable region is desired, piston rod 28 or 228 can be initially set to the left before opening valves 16a or 216a. Conversely, if pressurization of the isolable region is desired, piston rod 28 or 228 can be initially set to the right before opening valves 16a or 216a. This provides a greater range of motion for the piston rods to pressurize or depressurize the isolable region.

Claims

1. A method for testing valves in a subsea wellhead, the subsea wellhead being arranged to control fluid inflow or outflow from a subsea well, the method comprising: Close the valve to be tested; Fluid isolation is performed on the separable area directly adjacent to the valve to be tested in the subsea production tree; After isolation, the isolable area is depressurized to a pressure below the ambient underwater pressure or pressurized using a pressure maneuvering device positioned underwater, wherein the pressure maneuvering device is capable of performing pressurization and depressurization. The pressure in the insulated area is monitored after depressurization or pressurization; as well as The monitoring is used to determine whether the valve to be tested is operating correctly.

2. The method according to claim 1, wherein, Depressurizing or pressurizing the isolable region includes expanding or contracting the controllable volume of the pressure manipulation device, the controllable volume being in fluid communication with the isolable region.

3. The method according to claim 1 or 2, wherein, The pressure-operated device includes a piston.

4. The method according to any of the preceding claims, comprising using an underwater hydraulic power unit or an underwater electric actuator to drive the pressure manipulation device.

5. The method according to any of the preceding claims, wherein, The subsea wells include hydrocarbon production wells, liquid injection wells, or gas injection wells.

6. The method according to any of the preceding claims, wherein, The upstream fluid of the valve to be tested is connected to the annulus of the subsea well, such that during the test operation, the pressure directly upstream of the valve to be tested is under the pressure of the annulus.

7. The method according to any of the preceding claims, wherein, The pressure in the isolable area is reduced or increased to a certain level so that the pressure difference across the valve to be tested is in the range of 30 to 70 bar.

8. The method according to any of the preceding claims, wherein, If the pressure in the isolable region increases at a rate higher than a predetermined threshold after being depressurized, or if the pressure in the isolable region decreases at a rate higher than a predetermined threshold after being pressurized, then the valve to be tested is determined to be not operating correctly.

9. A system comprising: A subsea production tree for controlling fluid inflow or outflow from a subsea well, the subsea production tree including a valve to be tested, wherein the system is configured such that an isolable area of ​​the subsea production tree directly adjacent to the valve to be tested can be fluidly isolated during valve testing operations. A pressure control device, positioned underwater and connected to the subsea tree, is provided such that the pressure control device is capable of depressurizing or pressurizing the fluid in the isolable area to a pressure below the ambient underwater pressure during valve test operations, wherein the pressure control device is capable of performing pressurization and depressurization. as well as A sensing device is arranged to measure the pressure in the isolable area to determine the correct operation of the valve to be tested.

10. The system according to claim 9, wherein, The pressure manipulation device includes a controllable volume in fluid communication with the isolable region and is configured to depressurize the isolable region by expanding the controllable volume or to pressurize the isolable region by contracting the controllable volume.

11. The system according to claim 9 or 10, wherein, The pressure-operated device includes a piston.

12. The system according to any one of claims 9 to 11, comprising an underwater hydraulic power unit or an underwater electric actuator configured to drive the pressure manipulation device.

13. The system according to any one of claims 9 to 12, wherein, The subsea wells include hydrocarbon production wells, liquid injection wells, or gas injection wells.

14. The system according to any one of claims 9 to 13, wherein, The upstream side of the valve to be tested is connected to the annulus of the subsea well, such that the pressure directly upstream of the valve to be tested during the valve test operation is the pressure of the annulus.

15. The system according to any one of claims 9 to 14, wherein, The subsea production tree includes a plurality of valves, the plurality of valves including the valve to be tested, and wherein, when closed, the plurality of valves fluidly isolate the insulated area of ​​the subsea production tree.

16. The system according to any one of claims 9 to 15, wherein, The pressure control device is configured to depressurize or pressurize the isolable area such that the pressure difference across the valve to be tested is in the range of 30 to 70 bar.

Images