Patent Description:
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, CO<NUM>, in the Earth's atmosphere is problem that cannot be ignored. Over the last <NUM> years, the average concentration of carbon dioxide in the atmosphere has increased by <NUM> percent; and since the beginning of the Industrial Age, the increase is <NUM> percent. This is more than what had happened naturally over a <NUM> year period - from the Last Glacial Maximum to <NUM>.

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. 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, CO<NUM> is injected from a bottom fixed platform. At the Snøhvit site, CO<NUM> from LNG (Liquefied natural gas) production is transported through a <NUM> long <NUM> 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 <NPL>. The article, <NPL> gives an overview of the experience gained from three CO<NUM> injection sites: Sleipner (<NUM> years of injection), In Salah (<NUM> years of injection) and Snøhvit (<NUM> years of injection).

The Snøhvit site is characterized by having the utilities for the subsea CO<NUM> 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 CO<NUM> 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 CO<NUM> 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 Snø-hvit project, the prior art teaches that CO<NUM> 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 <NUM> to <NUM> 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 -<NUM> degrees Celsius. The smaller quantities of CO<NUM> typically being transported today are held at <NUM> to <NUM> Barg and -<NUM> to -<NUM> degrees Celsius. Larger volumes of CO<NUM> may be transported by ship under the conditions: <NUM> to <NUM> Barg and -<NUM> degrees Celsius, which enables use of the largest type C vessels. See e.g. <NPL>.

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.

<CIT> 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.

<CIT> 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.

<CIT> 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.

In <FIG>, we see a schematic illustration of a system according to one embodiment of the invention for long term storage of fluids, e.g. carbon dioxide, in a subterranean void or other accommodation space <NUM>, which typically is a subterranean aquifer. However, according to the invention, the subterranean void <NUM> may equally well be a reservoir containing gas and/or oil, a depleted gas and/or oil reservoir, a carbon dioxide storage/disposal reservoir, or a combination thereof. These subterranean accommodation spaces are typically located in porous or fractured rock formations, which for example may be sandstones, carbonates, or fractured shales, igneous or metamorphic rocks.

The system includes at least one offshore injection site <NUM>, which is configured to receive fluid, e.g. in a liquid phase, from at least one fluid tank <NUM> of a vessel <NUM>. The offshore injection site <NUM>, in turn, contains a subsea template <NUM> arranged on a seabed/sea bottom <NUM>. The subsea template <NUM> is located at a wellhead for a drill hole <NUM> to the subterranean void <NUM>. The subsea template <NUM> also contains a utility system configured to cause the fluid from the vessel <NUM> to be injected into the subterranean void <NUM> 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 <NUM> 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 <NUM>. 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 <NUM>, and be injected into the subterranean void <NUM> prior to injecting the fluid, for instance in the form of CO<NUM> in the liquid phase. The heated MEG removes any CO<NUM> hydrates in at least one injection riser <NUM> and <NUM> connecting the subsea template <NUM> to a buoy <NUM>, which buoy <NUM> and risers <NUM> and <NUM> are configured to transport the fluid from the vessel <NUM> to the subsea template <NUM>. Formation of CO<NUM> hydrates is detrimental because it can lead to blockages in the risers, which, in turn cause overpressure therein. Eventually the risers may burst, and CO<NUM> 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 <NUM>.

Additionally, MEG held in the at least one storage tank may be used in the subsea template <NUM> for valve testing, injecting MEG over a valve when starting up after a shut-down and/or flushing.

The injection, e.g. of CO<NUM>, vaporizes formation water which typically surrounds the subsea template <NUM> and its wellhead into the dry CO<NUM>, 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 <NUM> 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 CO<NUM> plume around the injection well, when formation water backflow during injection stops (it) is more likely to occur.

In <FIG>, a control site, generically identified as <NUM>, is adapted to generate the control commands Ccmd for controlling the flow of fluid from the vessel <NUM> and down into the subterranean void <NUM>. For example, the control commands Ccmd may relate to opening and closure of valves when the vessel <NUM> connects to and disconnects from the buoy <NUM>. The control site <NUM> is positioned at a location geographically separated from the offshore injection site <NUM>, for example in a control room onshore. However, additionally or alternatively, the control site <NUM> may be positioned at an offshore location geographically separated from the offshore injection site, for example at another offshore injection site. Consequently, a single control site <NUM> can control multiple offshore injection sites <NUM>. There is also large room for varying which control site <NUM> controls which offshore injection site <NUM>. Communications and controls are thus located remote from the offshore injection site <NUM>. However, as will be discussed below, the offshore injection site <NUM> may be powered locally, remotely or both.

In order to enable remote control from the control site <NUM>, the subsea template <NUM> contains a communication interface 120c that is communicatively connected to the control site <NUM>. The subsea template <NUM> 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 <NUM> and the offshore injection site <NUM>, the communication interface 120c may be configured to receive the control commands Ccmd via a submerged fiber-optic and/or copper cable <NUM>, 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 <NUM>.

Preferably, the communicative connection between the control site <NUM> and the subsea template <NUM> is bi-directional, so that for example acknowledge messages Cack may be returned to the control site <NUM> from the subsea template <NUM>.

According to the invention, the offshore injection site <NUM> includes a buoy <NUM>, for instance of submerged turret loading (STL) type. When inactive, the buoy <NUM> may be submerged to <NUM> - <NUM> meters depth, and when the vessel <NUM> approaches the offshore injection site <NUM> to offload fluid, the buoy <NUM> and at least one injection riser <NUM> and <NUM> connected thereto are elevated to the water surface <NUM>. After that the vessel <NUM> has been positioned over the buoy <NUM>, this unit is configured to be connected to the vessel <NUM> and receive the fluid from the vessel's fluid tank(s) <NUM>, for example via a swivel assembly in the buoy <NUM>. The buoy <NUM> is preferably anchored to the seabed <NUM> via one or more hold-back clamps <NUM>, <NUM>, <NUM> and <NUM>, which enable the buoy <NUM> to elevated and lowered in the water.

Each of the injection risers <NUM> and <NUM> respectively is configured to forward the fluid from the buoy <NUM> to the subsea template <NUM>, which, in turn, is configured to pass the fluid on via the wellhead and the drill hole <NUM> down to the subterranean void <NUM>.

According to one embodiment of the invention, the subsea template <NUM> 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 <NUM>. 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 <NUM> and/or a remotely operated vehicle (ROV) stationed on the seabed <NUM> at the subsea template <NUM>.

<FIG> illustrates a generic power source <NUM>, which is configured to supply the electric power PE to the power input interface 120p. It is generally advantageous if the electric power PE is supplied via a cable <NUM> from the power source <NUM> in the form of low-power direct current (DC) in the range of 200V - 1000V, preferably around 400V. The power source <NUM> may either be co-located with the offshore injection site <NUM>, for instance as a wind turbine, a solar panel and/or a wave energy converter; and/or be positioned at an onshore site and/or at another offshore site geographically separated from the offshore injection site <NUM>. Thus, there is a good potential for flexibility and redundancy with respect to the energy supply for the offshore injection site <NUM>.

The subsea template <NUM> contains a valve system that is configured to control the injection of the fluid into the subterranean void <NUM>. The valve system, as such, may be operated by hydraulic means, electric means or a combination thereof. The subsea template <NUM> 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 <NUM> 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 <NUM> 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 <NUM> in combination with the proposed remote control from the control site <NUM> avoids the need for offshore floating installations as well as permanent offshore marine installations. The invention allows direct injection from relatively uncomplicated maritime vessels <NUM>. 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 <NUM> (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 <NUM> according to the invention does not need to provide any utilities, well or barrier control, for the injection system. Consequently, the vessel <NUM> may operate under maritime legislation and regulations, which are normally far less restrictive than the offshore legislation and regulations.

<FIG> shows a buoy <NUM>, which is connected to a vessel <NUM> according to one embodiment of the invention.

The buoy <NUM> has at least one pressure sensor, here represented by <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> arranged in an upper section of a respective riser <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> connected between the buoy <NUM> and the subsea template <NUM> on the seabed <NUM>. The pressure sensors <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> are configured to register a respective pressure level of the fluid F in the riser <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> respectively. Preferably, the buoy <NUM> contains a control unit <NUM> that is communicatively connected to each of the at least one pressure sensor <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM>, for example via a bus cable or a set of individual lines to each respective pressure sensor.

Referring now to <FIG>, we see a buoy <NUM> with a set of swivel connectors <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM>. Preferably, the number of swivel connectors is equal to the number of risers connected to the buoy <NUM>. Thus, if for example, there are eight risers interconnecting the buoy <NUM> and the subsea template <NUM>, it is advantageous if the buoy <NUM> also has eight swivel connectors. It is further preferable if the buoy <NUM> contains one valve for each riser and each swivel connector. For reasons of clarity, however, <FIG> only shows four valves <NUM>, <NUM>, <NUM> and <NUM> respectively and six of swivel connectors <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> even though eight risers <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> are illustrated.

The control unit <NUM> is configured to control each of the valves <NUM>, <NUM>, <NUM> and <NUM> in response to the respective pressure level registered by the pressure sensors <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> 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 <FIG>, the buoy <NUM> is in fluid connection with the subsea template <NUM> located on the seabed <NUM> via each of the risers <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM>. The buoy <NUM> is further in fluid connection with the vessel <NUM> on the water surface <NUM>. Thereby, fluid F may be transported from the vessel <NUM> to the subsea template <NUM> for injection of the fluid F into the subterranean void <NUM> via the drill hole <NUM> from the subsea template <NUM> to the subterranean void <NUM>. The buoy <NUM> contains at least one valve, for example as illustrated by <NUM>, <NUM>, <NUM> and <NUM> in <FIG>, each of which valve is configured to allow or shut off a passage of fluid F from the vessel <NUM> to the at least one riser <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM>.

The buoy <NUM> has a primary communication interface <NUM>, which is configured to be connected to an external site <NUM>, for example as shown in <FIG>. The primary communication interface <NUM> is configured to receive commands Ccmd from the external site <NUM>. In response to the received commands Ccmd, the buoy <NUM> is configured to control the valves <NUM>, <NUM>, <NUM>, and <NUM> to either allow or shut off the passage of fluid F from the vessel <NUM> to each of the risers <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM>. In <FIG>, the hold-back clamps <NUM>, <NUM>, <NUM> and <NUM> for the buoy <NUM> are also shown.

According to one embodiment of the invention, the primary communication interface <NUM> is configured to receive the communication commands Ccmd in the form of optical signals transmitted via a fiber optic cable from the external site <NUM>.

According to another embodiment of the invention, the buoy <NUM> also has a secondary communication interface <NUM>, which is configured to be connected to the vessel <NUM>. The secondary communication interface <NUM> is configured to receive commands Ccmd from the vessel <NUM>. Analogously, in response to the received commands Ccmd, the buoy <NUM> is configured to control the valves <NUM>, <NUM>, <NUM> and <NUM> to either allow or shut off the passage of fluid F from the vessel <NUM> to the at least one riser <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM>. Consequently, the secondary communication interface <NUM> provides an alternative and parallel means of controlling the valves <NUM>, <NUM>, <NUM> and <NUM> in the buoy <NUM>.

As a safety measure, each of the valves <NUM>, <NUM>, <NUM> and <NUM> is preferably configured to automatically shut off the passage of fluid F from the vessel <NUM> to the risers <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> if a fluid-transporting conduit from the vessel <NUM> is disconnected while at least one of the valves <NUM>, <NUM>, <NUM> and/or <NUM> is set in a position allowing the passage of fluid F through the valve.

Preferably, the valves <NUM>, <NUM>, <NUM> and <NUM> are arranged downstream of the swivel connectors <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> with respect to a flow direction of the fluid F output from the vessel <NUM>. 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 <NUM> contains at least one battery <NUM>, which is configured to provide electric power for operating the valves <NUM>, <NUM>, <NUM> and <NUM>. Thereby, operation of the valves can be ensured also if an external energy supply to the buoy <NUM> is broken, for example from an onshore power source <NUM> providing electric power PE via a power line <NUM>.

It is further advantageous if the buoy <NUM> contains a power interface <NUM> configured to receive electric power PE from an external site, e.g. as illustrated in <FIG>. The battery <NUM> is further arranged to be charged by the electric power PE, which is received via the power interface <NUM>. This arrangement is beneficial because it reduces the risk that the battery <NUM> becomes discharged.

<FIG> shows details of how the buoy <NUM> is connected to the vessel <NUM> according to one embodiment of the invention. Here, buoy locking devices <NUM> secure the buoy <NUM> to a platform <NUM> in the vessel <NUM>. A swivel handling arm <NUM> is configured to handle at least one swivel connector <NUM> of the buoy <NUM>. A rope guide <NUM> is configured to steer various conduits and pipes to the buoy <NUM>. A traction winch <NUM> and a heave compensator <NUM> are arranged to assist in connecting the conduits and pipes to the buoy <NUM>. Preferably, a ventilation duct <NUM> reaches down to the buoy <NUM>, so that any gaseous fluids can be led away in a convenient manner.

<FIG> shows the swivel connector <NUM> according to one embodiment of the invention in somewhat further detail. Here, a first pipe connector <NUM> is configured to be connected to a fluid-transporting output from the vessel <NUM>. A second pipe connector <NUM> is configured to be connected to the buoy <NUM>, and further to at least one and of the risers <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM>. The swivel connector <NUM> is configured to allow a relative rotation between the fluid-transporting output from the vessel <NUM> and said at least one riser. In other words, the first pipe connector <NUM> may be rotated freely in relation to the second pipe connector <NUM>. Specifically, this rotation is possible while the fluid F flows around a circumference <NUM> of an interior member in the swivel connector <NUM> and enters into a cavity <NUM> connected to the second pipe connector <NUM> as illustrated by the arrows. Consequently, it is possible to maintain a geo stationary connection between the buoy <NUM> and the risers <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM>; and at the same time, allow arbitrary rotation movements of the fluid-transporting output from the vessel <NUM> irrespective of any rotation movements of the relative to the risers while the vessel <NUM> is connected to the buoy <NUM> via the fluid-transporting output.

<FIG> illustrates a replaceable sealing surface <NUM> of a connection port <NUM> according to one embodiment of the invention. In this embodiment, each of the above-described swivel connectors <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> contains the connection port <NUM>, which is configured to be connected to the fluid-transporting output from the vessel <NUM>.

The connection port <NUM> has a replaceable sealing surface <NUM> whose position is variable along a frustrum-shaped connector member <NUM> of the connection port <NUM>. <FIG> illustrates four different positions P1, P2, P3 and P4 respectively at which the replaceable sealing surface <NUM> can be arranged to seal the frustrum-shaped connector member <NUM> to a mating connector member <NUM> of the connection port <NUM>, which mating connector member <NUM> has an inverted frustrum-shape configured to cooperate with the frustrum-shaped connector member <NUM>. The positions P1, P2, P3 and P4 may be located on the frustrum-shaped connector member <NUM> and/or on the mating connector member <NUM>. In any case, the different positions P1, P2, P3 and P4 make it possible to adjust for varying degrees of wear on the frustrum-shaped connector member <NUM> and/or on the mating connector member <NUM>. Thus, as the connection port <NUM> is worn down, the sealing surface <NUM> may gradually be moved from one of the positions P1, P2, P3 and P4 to another.

Now, with reference to the flow diagrams in <FIG>, we will describe methods according to embodiments of the invention for connecting and disconnecting the vessel <NUM> to and from the buoy <NUM> respectively in order to discharge a fluid F, for example containing CO<NUM>, into a subterranean void <NUM>. Both methods presume that the buoy <NUM> is connected to a subsea template <NUM> located on a seabed <NUM> via a at least one riser, e.g. <NUM> and <NUM>, between the buoy <NUM> and the subsea template <NUM>; and that the subsea template <NUM> is configured to inject the fluid F further into the subterranean void <NUM> via the drill hole <NUM>.

In <FIG>, in a first step <NUM>, at least one output pipe in the vessel <NUM> is connected at least to at least one respective swivel connector, such as <NUM>, <NUM>, <NUM>, <NUM>, <NUM> and <NUM> in the buoy <NUM>.

In a subsequent step <NUM>, at least one respective pressure level is measured in each of the risers. Thereafter, in a step <NUM>, 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 <NUM>. 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 <NUM>, each of the at least one output pipe in the vessel <NUM> is pressurized to the respective equalization pressure determined in step <NUM>. A step <NUM> thereafter checks if the equalization pressure has been reached. If so, a step <NUM> follows; and otherwise, the procedure loops back and stays in step <NUM>. 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 <NUM>, at least one valve, e.g. <NUM>, <NUM>, <NUM> and <NUM> in the buoy <NUM> to the risers is opened so that the fluid may pass out from the vessel and into the risers.

Finally, in a step <NUM>, at least one valve in the subsea template <NUM> is opened to each of the risers. Thus, the fluid F may be injected into the subterranean void <NUM>, and the procedure ends.

The procedure described with reference to <FIG> continues where the above-described procedure ended. This means that, in a first step <NUM>, the fluid F is being passed from the at least one riser and into the subterranean void <NUM>. Indeed, is further presumed that the fluid F enters the risers from the vessel <NUM>.

While the fluid F is being passed from the vessel <NUM> and further down into the subterranean void <NUM>, in a step <NUM> parallel to step <NUM>, 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 <NUM> and/or in the subsea template <NUM>. The at least one assisting liquid may be adapted to maintain CO<NUM> 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 CO<NUM> and thus pressure in the risers is important for preserving a high water solubility in the CO<NUM> and thus avoid free water in the riser. Namely, free water may here lead to the creation of CO<NUM> 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 <NUM>, in a step <NUM>, the passage of fluid F from the vessel <NUM> to the risers is shut off by closing a respective at least one valve, e.g. <NUM>, <NUM>, <NUM> and <NUM> in the buoy <NUM>. For instance, the at least one valve may be closed in response to commands Ccmd received in the buoy <NUM> from an external site <NUM>.

It is further advantageous that the at least one valve <NUM>, <NUM>, <NUM> and/or <NUM> is closed automatically if the buoy <NUM> becomes disconnected - unintentionally - from the vessel <NUM> while the fluid F is being passed out from the vessel <NUM> and into the risers. Namely, otherwise, personnel on the vessel <NUM> 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 <NUM> via the subsea template <NUM>. During this process, the pressure level in each of the risers is measured; and in a step <NUM>, it is checked if the pressure level has reached an equalization level. If so, a step <NUM> follows; and otherwise, the procedure loops back and stays in step <NUM>.

In step <NUM>, a respective valve in the subsea template <NUM> to each of the risers is closed. Thereafter the procedure ends.

Preferably, the at least one valve in the subsea template <NUM> 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.

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.

Claim 1:
A buoy (<NUM>) configured to accomplish a fluid connection, via at least one riser (<NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>), from a vessel (<NUM>) on a water surface (<NUM>) to a subsea template (<NUM>) located on a seabed (<NUM>), so as to enable transport of fluid (F) from the vessel (<NUM>) to the subsea template (<NUM>) for injection of the fluid (F) into a subterranean void (<NUM>) via a drill hole (<NUM>) from the subsea template (<NUM>) to the subterranean void (<NUM>), the buoy (<NUM>) comprising:
at least one electric powered valve (<NUM>, <NUM>, <NUM>, <NUM>) configured to allow or shut off a passage of fluid (F) from the vessel (<NUM>) to the at least one riser (<NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>), characterized in that the buoy (<NUM>) comprises a primary communication interface (<NUM>) configured to:
be connected to an external site (<NUM>) positioned at a location being geographically separated from an offshore injection site <NUM> containing the subsea template (<NUM>), and
receive commands (Ccmd) from the external site (<NUM>), wherein in response to the received commands (Ccmd), the buoy (<NUM>) is configured to control the at least one valve (<NUM>, <NUM>, <NUM>, <NUM>) to either allow or shut off the passage of fluid (F) from the vessel (<NUM>) to the at least one riser (<NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>).