Patent Application
20240068332
The present invention relates generally to strategies for reducing the amount of environmentally unfriendly gaseous components in the atmosphere. Especially, the invention relates to a buoy configured to accomplish a fluid connection from a vessel on the water surface to a subsea template on the seabed, such that fluids can be transported for long term storage into a subterranean void under the seabed via said fluid connection. The invention also relates to a method for disconnecting the fluid connection between the vessel and the buoy.
Carbon dioxide is an important heat-trapping gas, a so-called greenhouse gas, which is released through certain human activities such as deforestation and burning fossil fuels. However, also natural processes, such as respiration and volcanic eruptions generate carbon dioxide.
Today's rapidly increasing concentration of carbon dioxide, CO2, in the Earth's atmosphere is problem that cannot be ignored. Over the last 20 years, the average concentration of carbon dioxide in the atmosphere has increased by 11 percent; and since the beginning of the Industrial Age, the increase is 47 percent. This is more than what had happened naturally over a 20000 year period—from the Last Glacial Maximum to 1850.
Various technologies exist to reduce the amount of carbon dioxide produced by human activities, such as renewable energy production. There are also technical solutions for capturing carbon dioxide from the atmosphere and storing it on a long term/permanent basis in subterranean reservoirs.
For practical reasons, most of these reservoirs are located under mainland areas, for example in the U.S.A. and in Algeria, where the In Salah CCS (carbon dioxide capture and storage system) was located. However, there are also a few examples of offshore injection sites, represented by the Sleipner and Snøhvit sites in the North Sea. At the Sleipner site, CO2 is injected from a bottom fixed platform. At the Snøhvit site, CO2 from LNG (Liquefied natural gas) production is transported through a 153 km long 8 inch pipeline on the seabed and is injected from a subsea template into the subsurface below a water bearing reservoir zone as described inter alia in Shi, J-Q, et al., “Snøhvit CO2 storage project: Assessment of CO2 injection performance through history matching of the injection well pressure over a 32-months period”, Energy Procedia 37 (2013) 3267-3274. The article, Eiken, O., et al., “Lessons Learned from 14 years of CCS Operations: Sleipner, In Salah and Snøhvit”, Energy Procedia 4 (2011) 5541-5548 gives an overview of the experience gained from three CO2 injection sites: Sleipner (14 years of injection), In Salah (6 years of injection) and Snøhvit (2 years of injection).
The Snøhvit site is characterized by having the utilities for the subsea CO2 wells and template onshore. This means that for example the chemicals, the hydraulic fluid, the power source and all the controls and safety systems are located remote from the place where CO2 is injected. This may be convenient in many ways. However, the utilities and power must be transported to the seabed location via long pipelines and high voltage power cables respectively. The communications for the control and safety systems are provided through a fiber-optic cable. The CO2 gas is pressurized onshore and transported through a pipeline directly to a well head in a subsea template on the seabed, and then fed further down the well into the reservoir. This renders the system design highly inflexible because it is very costly to relocate the injection point should the original site fail for some reason. In fact, this is what happened at the Snøhvit site, where there was an unexpected pressure build up, and a new well had to be established.
As an alternative to the remote-control implemented in the Snøhvit project, the prior art teaches that CO2 may be transported to an injection site via surface ships in the form of so-called type C vessels, which are semi refrigerated vessels. Type C vessels may also be used to transport liquid petroleum gas, ammonia, and other products.
In a type C vessel, the pressure varies from 5 to 18 Barg. Due to constraints in tank design, the tank volumes are generally smaller for the higher pressure levels. The tanks used have a cold temperature as low as −55 degrees Celsius. The smaller quantities of CO2 typically being transported today are held at 15 to 18 Barg and −22 to −28 degrees Celsius. Larger volumes of CO2 may be transported by ship under the conditions: 6 to 7 Barg and −50 degrees Celsius, which enables use of the largest type C vessels. See e.g. Haugen, H. A., et al., “13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18—November 2016, Lausanne, Switzerland Commercial capture and transport of CO2 from production of ammonia”, Energy Procedia 114 (2017) 6133-6140.
In the existing implementations, it is generally understood that a stand-alone offshore injection site requires a floating installation or a bottom fixed marine installation. Such installations provide utilities, power and control systems directly to the wellhead platforms or subsea wellhead installations. It is not unusual, however, that power is provided from shore via high-voltage AC cables.
The prior art displays various solutions for connecting a vessel to a subterranean aquifer, or a gas or oil reservoir, which may either be depleted or contain hydrocarbons.
US 2019/0162336 shows a flexible pipe system that includes an unbonded flexible pipe connected to a floating vessel and a sensor system with an optical fiber integrated in the unbonded flexible pipe. Interrogating equipment transmits optical signals into the fiber, receives optical signals reflected from the fiber and detects a parameter of the unbonded flexible pipe. A turret connects the flexible pipe rotationally to the floating vessel via a swivel device that provides a fluid transfer passage between the turret and the vessel. The interrogating equipment is arranged on the turret and is further configured to transfer signals indicative of the detected parameter to receiving equipment on the floating vessel. In this way, optical signals reflected from the fiber can reach the interrogating equipment without distortion in the swivel, so that parameters can be detected with sufficient quality also for floating vessels equipped with a turret mooring system.
U.S. Pat. No. 7,793,725 discloses overpressure protection systems and methods for use on a production system for transferring hydrocarbons from a well on the seafloor to a vessel floating on the surface of the sea. The production system includes a subsea well in fluid communication with a turret buoy through a production flowline and riser system. The turret buoy is capable of connecting to a swivel located on a floating vessel. The overpressure protection device is positioned upstream of the swivel, to prevent overpressure of the production swivel and downstream components located on the floating vessel. The device may include one or more shut down valves, one or more sensors, an actuator assembly, and a control processor. Each shut down valve and sensor is coupled to a production flowline. Each of the sensors is capable of generating a signal based upon a pressure sensed within the production flow line. The actuator assembly is connected to each of the shut-down valves for operating the shut-down valves. The control processor, which may be a programmable logic controller, receives a signal from the sensors and sends a valve control signal to the actuator assembly for operating the shut-down valves in response to the received signals.
U.S. Pat. No. 10,370,962 teaches a system for monitoring a mooring line, umbilical, pipeline, or riser connected to an offshore structure including a control processor located on the offshore structure, a wireless network comprising a plurality of communication nodes positioned along the line, and a plurality of measurement devices embedded within the communication nodes. When the line is being monitored, the output of each of the measurement devices is in continuous wireless communication with the wireless network via at least one of the communication nodes positioned along the line and the wireless network is in continuous communication with the control processor.
Thus, different solutions are known for creating a fluid connection between a vessel and a subsea location, typically to extract hydrocarbons. However, there is yet no efficient, safe and reliable means of controlling an offloading process for injecting environmentally unfriendly fluids like carbon dioxide into subterranean reservoirs using a vessel-to-buoy connection.
The object of the present invention is therefore to offer a solution that mitigates the above problems and offers an improved offloading of environmentally harmful fluids for long term storage in subterranean voids.
According to one aspect of the invention, the object is achieved by a buoy configured to accomplish a fluid connection, via at least one riser, from a vessel on a water surface to a subsea template located on a seabed, so as to enable transport of fluid from the vessel to the subsea template for injection of the fluid into a subterranean void via a drill hole from the subsea template to the subterranean void. The buoy contains at least one valve configured to allow or shut off a passage of fluid from the vessel to the at least one riser. The buoy also contains a primary communication interface configured to be connected to an external site and receive commands from the external site, for example in the form of optical signals transmitted via a fiber optic cable. In response to the received commands, the buoy is configured to control the at least one valve to either allow or shut off the passage of fluid from the vessel to the at least one riser.
The proposed buoy is advantageous because it requires a minimal amount of technical and local personnel resources on the vessel. This, in turn, is beneficial from an overall cost point-of-view.
According to one embodiment of this aspect of the invention, the buoy has a secondary communication interface, e.g. inductive, configured to be connected to the vessel and receive commands from the vessel. In response to the received commands, the buoy is configured to control the at least one valve to either allow or shut off the passage of fluid from the vessel to the at least one riser. Thereby, the vessel is provided with an alternative means of communication to the buoy, which vouches for redundancy and enhanced reliability.
According to another embodiment of this aspect of the invention, the at least one valve is configured to automatically shut off the passage of fluid from the vessel to the at least one riser, if a fluid-transporting conduit from the vessel is disconnected while the at least one valve is set in a position allowing the passage of fluid through the at least one valve. Thus, in case of an emergency situation or if the vessel is unexpectedly disconnected for other reasons, there is no risk that the fluid escapes into the water and/or the atmosphere.
According to yet another embodiment of this aspect of the invention, the buoy contains at least one pressure sensor configured to register a respective pressure level of the fluid in the at least one riser between the buoy and the subsea template. Preferably, the buoy further contains a control unit, which is communicatively connected to the at least one pressure sensor. The control unit is configured to control the at least one valve in response to the respective pressure level registered by the at least one pressure sensor in such a manner that a particular valve of the at least one valve is only allowed to be opened if the registered pressure level in the riser controlled by the particular valve lies within a predefined pressure range. Consequently, initiating the injection of fluid into the risers can be made very safe.
According to still another embodiment of this aspect of the invention, the buoy contains at least one swivel connector, which is configured to allow a relative rotation between a fluid-transporting output from the vessel and the at least one riser, such that a geo stationary connection is maintainable between the buoy and the at least one riser while a stationary connection is maintained between the buoy and the fluid-transporting output from the vessel irrespective of any rotation movements of the vessel relative to the at least one riser while the vessel is connected to the buoy via the fluid-transporting output. Thereby, a highly reliable vessel-to-buoy connection can be maintained during the entire offloading process.
According to another embodiment of this aspect of the invention, each of the at least one swivel connector contains at least one connection port to the fluid-transporting output from the surface vessel. Each of the at least one connection port includes a replaceable sealing surface, the position of which is variable along a frustrum-shaped connector member. Alternatively, or additionally, a position of the replaceable sealing surface may be varied on a mating connector member of the at least one connection port adapted to cooperate with the frustrum-shaped connector member. Thus, varying degrees of wear on the frustrum-shaped connector member may be handled efficiently.
Preferably, the at least one valve is arranged downstream of the at least one swivel connector with respect to a flow direction of the fluid output from the vessel.
According to yet another embodiment of this aspect of the invention, the buoy contains a battery configured to provide electric power for operating the at least one valve. Preferably, the power interface is configured to receive electric power from an external site, and the battery is arranged to be charged by the electric power received via the power interface. Thereby, it is ensured that the at least one valve can be operated as intended also if the buoy would suffer from a temporary power outage.
According to another aspect of the invention, the object is achieved by a method for connecting a passage for a fluid from a vessel on a water surface to a subsea template located on a seabed. The connection is here effected via a buoy and at least one riser connected between the buoy and the subsea template. The subsea template is configured to inject the fluid further into a subterranean void via a drill hole. The method involves the steps:
This method is advantageous because it minimizes the risk of fluid leakage in the vessel-to-template connection.
According to yet another aspect of the invention, the object is achieved by a method for disconnecting a passage for a fluid from a vessel on a water surface to a subsea template located on a seabed. The template is configured to inject the fluid further into a subterranean void via a drill hole. Also here, the vessel is in fluid connection with the template by means of a buoy and at least one interconnecting riser. The method involves the steps:
This method is advantageous because it minimizes the risk of fluid leakage when the vessel is disconnected from the buoy.
Further advantages, beneficial features and applications of the present invention will be apparent from the following description and the dependent claims.
The invention is now to be explained more closely by means of preferred embodiments, which are disclosed as examples, and with reference to the attached drawings.
In
The system includes at least one offshore injection site 100, which is configured to receive fluid, e.g. in a liquid phase, from at least one fluid tank 115 of a vessel 110. The offshore injection site 100, in turn, contains a subsea template 120 arranged on a seabed/sea bottom 130. The subsea template 120 is located at a wellhead for a drill hole 140 to the subterranean void 150. The subsea template 140 also contains a utility system configured to cause the fluid from the vessel 110 to be injected into the subterranean void 150 in response to control commands Ccmd. In other words, the utility system is not located onshore, which is advantageous for logistic reasons. For example therefore, in contrast to the above-mentioned Snøhvit site, there is no need for any umbilicals or similar kinds of conduits to provide supplies to the utility system.
The utility system in the subsea template 120 may contain at least one storage tank. The at least one storage tank holds at least one assisting liquid, which is configured to facilitate at least one function associated with injecting the fluid into the subterranean void 150. The at least one assisting liquid contains a de-hydrating liquid and/or an anti-freezing liquid.
In particular, the at least one storage tank may hold Monoethylene Glycol (MEG). The MEG may be heated in the subsea template 120, and be injected into the subterranean void 150 prior to injecting the fluid, for instance in the form of CO2 in the liquid phase. The heated MEG removes any CO2 hydrates in at least one injection riser 171 and 172 connecting the subsea template 120 to a buoy 170, which buoy 170 and risers 171 and 172 are configured to transport the fluid from the vessel 110 to the subsea template 120. Formation of CO2 hydrates is detrimental because it can lead to blockages in the risers, which, in turn cause overpressure therein. Eventually the risers may burst, and CO2 will leak into the sea. This has negative environmental effects, leads to replacement cost and forces an interruption in the operation of the injection site 100.
Additionally, MEG held in the at least one storage tank may be used in the subsea template 120 for valve testing, injecting MEG over a valve when starting up after a shut-down and/or flushing.
The injection, e.g. of CO2, vaporizes formation water which typically surrounds the subsea template 120 and its wellhead into the dry CO2, especially near the injection wellbore. This increases formation water salinity locally, leading to supersaturation and subsequent salt precipitation. The process is aggravated by capillary and, in some cases, gravity backflow of brine into the dried zone. The accumulated precipitated salt reduces permeability around the injection well, and may cause unacceptably high injection pressures, and consequently reduced injection. The effect depends on formation water salinity and composition, and formation permeability. A MEG injection system of the subsea template 120 preferably contains a storage tank, an accumulator tank an at least one chemical pump.
The above is an issue particularly for an early injection period, before establishing a significant CO2 plume around the injection well, when formation water backflow during injection stops (it) is more likely to occur.
In
In order to enable remote control from the control site 160, the subsea template 120 contains a communication interface 120c that is communicatively connected to the control site 160. The subsea template 120 is also configured to receive the control commands Ccmd via the communication interface 120c.
Depending on the channel(s) used for forwarding the control commands Ccmd between the control site 160 and the offshore injection site 100, the communication interface 120c may be configured to receive the control commands Ccmd via a submerged fiber-optic and/or copper cable 165, a terrestrial radio link (not shown) and/or a satellite link (not shown). In the latter two cases, the communication interface 120c includes at least one antenna arranged above the water surface 111.
Preferably, the communicative connection between the control site 160 and the subsea template 120 is bi-directional, so that for example acknowledge messages Cack may be returned to the control site 160 from the subsea template 120.
According to the invention, the offshore injection site 100 includes a buoy 170, for instance of submerged turret loading (STL) type. When inactive, the buoy 170 may be submerged to 30-50 meters depth, and when the vessel 110 approaches the offshore injection site 100 to offload fluid, the buoy 170 and at least one injection riser 171 and 172 connected thereto are elevated to the water surface 111. After that the vessel 110 has been positioned over the buoy 170, this unit is configured to be connected to the vessel 110 and receive the fluid from the vessel's fluid tank(s) 115, for example via a swivel assembly in the buoy 170. The buoy 170 is preferably anchored to the seabed 130 via one or more hold-back clamps 181, 182, 183 and 184, which enable the buoy 170 to elevated and lowered in the water.
Each of the injection risers 171 and 172 respectively is configured to forward the fluid from the buoy 170 to the subsea template 120, which, in turn, is configured to pass the fluid on via the wellhead and the drill hole 140 down to the subterranean void 150.
According to one embodiment of the invention, the subsea template 120 contains a power input interface 120p, which is configured to receive electric energy PE for operating the utility system and/or operating various functions in the buoy 170. The power input interface 120p may be also configured to receive the electric energy PE to be used in connection with operating a well at the wellhead, a safety barrier element of the subsea template 120 and/or a remotely operated vehicle (ROV) stationed on the seabed 130 at the subsea template 120.
The subsea template 120 contains a valve system that is configured to control the injection of the fluid into the subterranean void 150. The valve system, as such, may be operated by hydraulic means, electric means or a combination thereof. The subsea template 120 preferably also includes at least one battery configured to store electric energy for use by the valve system as a backup to the electric energy PE received directly via the power input interface 120p. More precisely, if the valve system is hydraulically operated, the subsea template 120 contains a hydraulic pressure unit (HPU) configured to supply pressurized hydraulic fluid for operation of the valve system. For example, the HPU may supply the pressurized hydraulic fluid through a hydraulic small-bore piping system. The at least one battery is here configured to store electric backup energy for use by the hydraulic power unit and the valve system.
Alternatively, or additionally, the valve operations may also be operated using an electrical wiring system and electrically controlled valve actuators. In such a case, the subsea template 120 contains an electrical wiring system configured to operate the valve system by means of electrical control signals. Here, the at least one battery is configured to store electric backup energy for use by the electrical wiring system and the valve system.
Consequently, the valve system may be operated also if there is a temporary outage in the electric power supply to the offshore injection site. This, in turn, increases the overall reliability of the system.
Locating the utility system at the subsea template 120 in combination with the proposed remote control from the control site 160 avoids the need for offshore floating installations as well as permanent offshore marine installations. The invention allows direct injection from relatively uncomplicated maritime vessels 110. These factors render the system according to the invention very cost efficient.
According to the invention, further cost savings can be made by avoiding the complex offshore legislation and regulations. Namely, a permanent offshore installation acting as a field center for an offshore field development is bound by offshore legislation and regulations. There are strict safety requirements related to well control especially. For instance, offshore Norway, it is stipulated that floating offshore installations, permanent or temporary, that control well barriers must satisfy the dynamic positioning level 3 (DP3) requirement. This involves extensive requirements in to ensure that the floater remains in position also during extreme events like engine room fires, etc. Nevertheless, the vessel 110 according to the invention does not need to provide any utilities, well or barrier control, for the injection system. Consequently, the vessel 110 may operate under maritime legislation and regulations, which are normally far less restrictive than the offshore legislation and regulations.
The buoy 170 has at least one pressure sensor, here represented by 221, 222, 223, 224, 225, 226, 227 and 228 arranged in an upper section of a respective riser 171, 172, 173, 174, 175, 176, 177 and 178 connected between the buoy 170 and the subsea template 120 on the seabed 130. The pressure sensors 221, 222, 223, 224, 225, 226, 227 and 228 are configured to register a respective pressure level of the fluid F in the riser 171, 172, 173, 174, 175, 176, 177 and 178 respectively. Preferably, the buoy 170 contains a control unit 210 that is communicatively connected to each of the at least one pressure sensor 221, 222, 223, 224, 225, 226, 227 and 228, for example via a bus cable or a set of individual lines to each respective pressure sensor.
Referring now to
The control unit 210 is configured to control each of the valves 511, 512, 513 and 514 in response to the respective pressure level registered by the pressure sensors 221, 222, 223, 224, 225, 226, 227 and 228 in such a manner that a particular valve is only allowed to be opened if the registered pressure level in the supervised riser being controlled by the particular valve lies within a predefined pressure range.
In
The buoy 170 has a primary communication interface 231, which is configured to be connected to an external site 160, for example as shown in
According to one embodiment of the invention, the primary communication interface 231 is configured to receive the communication commands Ccmd in the form of optical signals transmitted via a fiber optic cable from the external site 160.
According to another embodiment of the invention, the buoy 170 also has a secondary communication interface 232, which is configured to be connected to the vessel 110. The secondary communication interface 232 is configured to receive commands Ccmd from the vessel 110. Analogously, in response to the received commands Ccmd, the buoy 170 is configured to control the valves 511, 512, 513 and 514 to either allow or shut off the passage of fluid F from the vessel 110 to the at least one riser 171, 172, 173, 174, 175, 176, 177 and 178. Consequently, the secondary communication interface 232 provides an alternative and parallel means of controlling the valves 511, 512, 513 and 514 in the buoy 170.
As a safety measure, each of the valves 511, 512, 513 and 514 is preferably configured to automatically shut off the passage of fluid F from the vessel 110 to the risers 171, 172, 173, 174, 175, 176, 177 and 178 if a fluid-transporting conduit from the vessel 110 is disconnected while at least one of the valves 511, 512, 513 and/or 514 is set in a position allowing the passage of fluid F through the valve.
Preferably, the valves 511, 512, 513 and 514 are arranged downstream of the swivel connectors 321, 322, 323, 324, 325 and 326 with respect to a flow direction of the fluid F output from the vessel 110. Namely, this renders it possible to efficiently cutoff the fluid flow on the buoy side whenever needed.
According to one embodiment of the invention, the buoy 170 contains at least one battery 520, which is configured to provide electric power for operating the valves 511, 512, 513 and 514. Thereby, operation of the valves can be ensured also if an external energy supply to the buoy 170 is broken, for example from an onshore power source 180 providing electric power PE via a power line 185.
It is further advantageous if the buoy 170 contains a power interface 240 configured to receive electric power PE from an external site, e.g. as illustrated in
The connection port 600 has a replaceable sealing surface 611 whose position is variable along a frustrum-shaped connector member 610 of the connection port 600.
Now, with reference to the flow diagrams in
In
In a subsequent step 720, at least one respective pressure level is measured in each of the risers. Thereafter, in a step 730, a respective equalization pressure is determined based on the at least one respective pressure level in the risers. For example, a first respective pressure level may be measured in an upper section of each riser—near the buoy, and a second respective pressure level may be measured in an lower section of each riser—near the subsea template 120. The respective equalization pressure for each of the at least one riser may then be determined as an average value of the first and second respective pressure levels.
After that, in a step 740, each of the at least one output pipe in the vessel 110 is pressurized to the respective equalization pressure determined in step 730. A step 750 thereafter checks if the equalization pressure has been reached. If so, a step 760 follows; and otherwise, the procedure loops back and stays in step 750. This adapts the vessel's pressure level to that of the risers, and minimizes the risk of undesired pressure transients when opening the valves between the vessel and the buoy.
In step 760, at least one valve, e.g. 511, 512, 513 and 514 in the buoy 170 to the risers is opened so that the fluid may pass out from the vessel and into the risers.
Finally, in a step 770, at least one valve in the subsea template 120 is opened to each of the risers. Thus, the fluid F may be injected into the subterranean void 150, and the procedure ends.
The procedure described with reference to
While the fluid F is being passed from the vessel 110 and further down into the subterranean void 150, in a step 820 parallel to step 810, at least one assisting liquid injecting into each of the risers. The assisting liquid may be represented by heated chemicals that for example are stored in the vessel 110 and/or in the subsea template 120. The at least one assisting liquid may be adapted to maintain CO2 in a liquid phase in the risers. This is important for several reasons, for example to maintain a stable density of the fluid F in the risers, to reduce fatigue loads therein, and thus extend their expected lifetime. Maintaining liquid-phase CO2 and thus pressure in the risers is important for preserving a high water solubility in the CO2 and thus avoid free water in the riser. Namely, free water may here lead to the creation of CO2 hydrates, which, in turn, may lead to the occurrence of slug flow in the risers as well as any fatigue loads resulting there from. The at least one assisting liquid may contain MEG, Diethylene Glycol (DEG) and/or Triethylene Glycol (TEG).
After having injected the at least one assisting liquid, and while the fluid F continues to be passed into the subterranean void 150, in a step 830, the passage of fluid F from the vessel 110 to the risers is shut off by closing a respective at least one valve, e.g. 511, 512, 513 and 514 in the buoy 170. For instance, the at least one valve may be closed in response to commands Ccmd received in the buoy 170 from an external site 160.
It is further advantageous that the at least one valve 511, 512, 513 and/or 514 is closed automatically if the buoy 170 becomes disconnected—unintentionally—from the vessel 110 while the fluid F is being passed out from the vessel 110 and into the risers. Namely, otherwise, personnel on the vessel 110 might become injured and/or environmental issues may occur.
A respective pressure level in each of the risers is measured while the fluid F from the risers continues to be injected into the subterranean void 150 via the subsea template 120. During this process, the pressure level in each of the risers is measured; and in a step 840, it is checked if the pressure level has reached an equalization level. If so, a step 850 follows; and otherwise, the procedure loops back and stays in step 840.
In step 850, a respective valve in the subsea template 120 to each of the risers is closed. Thereafter the procedure ends.
Preferably, the at least one valve in the subsea template 120 is closed automatically in response the pressure level in the respective riser having reached the equalization level.
Variations to the disclosed embodiments can be understood and effected by those skilled in the art in practicing the claimed invention, from a study of the drawings, the disclosure, and the appended claims.
The term “comprises/comprising” when used in this specification is taken to specify the presence of stated features, integers, steps or components. The term does not preclude the presence or addition of one or more additional elements, features, integers, steps or components or groups thereof. The indefinite article “a” or “an” does not exclude a plurality. In the claims, the word “or” is not to be interpreted as an exclusive or (sometimes referred to as “XOR”). On the contrary, expressions such as “A or B” covers all the cases “A and not B”, “B and not A” and “A and B”, unless otherwise indicated. The mere fact that certain measures are recited in mutually different dependent claims does not indicate that a combination of these measures cannot be used to advantage. Any reference signs in the claims should not be construed as limiting the scope.
It is also to be noted that features from the various embodiments described herein may freely be combined, unless it is explicitly stated that such a combination would be unsuitable.
The invention is not restricted to the described embodiments in the figures, but may be varied freely within the scope of the claims.
| Number | Date | Country | Kind |
|---|---|---|---|
| 21160935.9 | Mar 2021 | EP | regional |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/EP2022/055218 | 3/2/2022 | WO |
