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 Snohvit sites in the North Sea. At the Sleipner site, CO<NUM> is injected from a bottom fixed platform. At the Snrahvit 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 Snohvit (<NUM> years of injection).

The Snrahvit 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 Snrahvit 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 Snohvit 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.

As exemplified below, the prior art displays various solutions for interconnecting subsea units to enable transport of fluid between these units.

<CIT> shows a connector for connecting components of a subsea conduit system extending between a wellhead and a surface structure, for example, a riser system. Male and female components are provided, and a latching device to releasably latch the male and female components together when the two are engaged. The male and female components incorporate a main sealing device to seal the male and female components together to contain the high pressure wellbore fluids passing between them when the male and female components are engaged. The latching device also incorporates a second sealing device configured to contain fluids when the male and the female components are disengaged, so that during disconnection, any fluids escaping the inner conduit are contained.

<CIT> discloses a connector for a riser equipped with an external locking collar. Here, a locking collar cooperates with a male flange of a male connector element and a female flange of a female connector element by means of a series of tenons. A riser including several sections assembled by a connector is also disclosed.

<CIT> teaches a riser system including: at least one riser for extending from infrastructure on a sea bed and each riser having a riser termination; an end support restrained above and relative to the sea bed and having attachment means to couple each riser termination for storage and decouple each riser termination for coupling to a floating vessel; and an intermediate support supporting an intermediate portion of the riser to define a catenary bend between the intermediate support and the riser termination device.

<CIT> teaches methods and apparatuses which can be used to remove a plug that is present within a subsea structure such as a production system pipeline, riser, subsea well equipment, or the like.

Thus, different solutions are known, which enable vessels to create fluid connections with various subsea units. However, there is yet no efficient, safe and reliable means of connecting risers between an offloading buoy and a template on the seabed, such that environmentally unfriendly fluids can be offloaded from a vessel at the buoy, and be transported via the risers to the template for injection into a subterranean reservoir beneath the seabed.

The object of the present invention is therefore to offer a solution that mitigates the above problems and offers an efficient and reliable system for injecting environmentally harmful fluids for long term storage in subterranean voids beneath the seabed.

According to one aspect of the invention, the object is achieved by a method of removing obstructing fluid plugs from a base section of a riser, which base section extends between a receiving end connected to an upright section of the riser and an emitting end of the riser connected to a subsea template located on a seabed, which subsea template is further connected to a wellhead for a drill hole to a subterranean void into which fluid received via the riser is to be injected from the subsea template. The method involves:.

This method is advantageous because it provides efficient removal of any obstructing fluid plugs in the base section of a riser.

According to one embodiment of this aspect of the invention, the base section of the riser contains a low-point section between the receiving end and the emitting end. The low-point section constitutes a geometrically lowermost part of the base section, which will tend to accumulate any undesired components in the fluid flow, e.g. CO<NUM> hydrates formed therein. The base section of the riser also includes a container connector configured to receive an output nozzle of the storage container for the at least one heated assisting liquid. The container connector represents one of the at least one injection point in the base section and is arranged upstream of the low-point section relative to a direction of a fluid flow into an injection valve tree for the wellhead. The method further involves feeding the at least one heated assisting liquid from the storage container via the low-point section into the injection valve tree. Thereby, any undesired components will be removed from the riser in an efficient and straightforward manner.

According to another embodiment of this aspect of the invention, the base section contains first and second temperature sensors. The first temperature sensor is arranged downstream of the container connector and upstream of the low-point section relative to the direction of the fluid flow. The first temperature sensor is configured to register a first temperature signal. The second temperature sensor is arranged downstream of the low-point section relative to the direction of the fluid flow. The second temperature sensor s configured to register a second temperature signal. The method further involves determining if there is a fluid plug in the low-point section based on how the second temperature signal varies over time compared to how the first temperature signal varies over time in response to feeding the at least one heated assisting liquid from the storage container into the base section. Thus, the existence of undesired components can be detected in a reliable manner.

Preferably, if it is determined there is a fluid plug in the low-point section a flow rate at which the at least one heated assisting liquid is fed from the storage container into the base section is reduced, or stopped, at least temporarily.

According to another aspect, not forming part of the present invention, the object is achieved by a method of removing obstructing fluid plugs from a base section of a riser, which base section extends between a receiving end connected to an upright section of the riser and an emitting end of the riser connected to a subsea template located on a seabed, which subsea template is further connected to a wellhead for a drill hole to a subterranean void into which fluid received via the riser is to be injected from the subsea template. The subsea template contains a heating unit that is arranged to heat at least one portion of the base section. The method involves:.

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> may also contain 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 Snrahvit 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 <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> preferably 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> according to one embodiment of the invention that is configured to enable a vessel, e.g. <NUM> shown in <FIG>, to connect to the fluid-transporting riser <NUM>, which, in turn, is connected to the subsea template <NUM> in further fluid connection with the subterranean void <NUM>.

Referring again to <FIG>, we see a fluid injection system arranged to receive fluid, e.g. containing CO<NUM>, from the vessel <NUM>. The fluid injection system contains the buoy <NUM> configured to be connected with the vessel <NUM> and receive the fluid therefrom. The system also contains the subsea template <NUM>, which is located on the seabed <NUM> at the wellhead for the drill hole <NUM> to the subterranean void <NUM>.

Moreover, the system includes at least one riser, here exemplified by <NUM> and <NUM> respectively, which interconnect the buoy <NUM> and the subsea template <NUM>. Each of the at least one riser <NUM> and <NUM> is configured to transport the fluid from the buoy <NUM> to the subsea template <NUM>. Specifically, each of the at least one riser <NUM> and <NUM> is detachably connected to a bottom surface of the buoy <NUM> by means of a connector arrangement <NUM>. <FIG> illustrates the connector arrangement <NUM> according to one embodiment of the invention, which connector arrangement <NUM> is configured to connect the riser <NUM> to the buoy <NUM>. Naturally, although not illustrated in <FIG>, any additional risers attached to the buoy <NUM> will be connected in an analogous manner.

The connector arrangement <NUM> includes a buoy guide member <NUM> configured to automatically steer a connector member <NUM> towards the buoy guide member <NUM> when the connector member <NUM> is moved towards the buoy guide member <NUM>. The connector member <NUM> is attached in a head end <NUM> of the riser <NUM> to be connected to the buoy <NUM>. The connector arrangement <NUM> further includes a mating member <NUM>, for example embodied as so-called fingers, configured to attach a first sealing surface S70 of the connector member <NUM> to a second sealing surface S10 of the buoy guide member <NUM> when said head end <NUM> has been moved such that the connector member <NUM> contacts the buoy guide member <NUM>. Additionally, the connector arrangement <NUM> includes a locking member <NUM> configured to lock the first and second sealing surfaces S70 and S10 to one another when these surfaces are aligned with one another.

Preferably, the connector arrangement <NUM> contains one collet connector for each riser to be connected to the buoy <NUM>. In addition to the elements mentioned above, the collet connector typically also includes a seal gasket <NUM>, which is arranged between the first and second sealing surfaces S70 and S10 to further reduce the risk of leakages.

<FIG> illustrate how a riser <NUM> is connected to a buoy <NUM> according to one embodiment of the invention.

Here, the head end <NUM> of the riser <NUM> to be connected contains a plug member <NUM> covering the first sealing surface S70. Thus, water is and prevented from entering into the riser <NUM> before the riser <NUM> has been connected to the buoy <NUM>. In addition to that, the head end <NUM> of the riser <NUM> to be connected preferably includes a drag-eye member <NUM>, which facilitates connecting a winch wire to the head end <NUM> and pulling the riser <NUM> up to the buoy <NUM> as described below.

As illustrated in <FIG>, according to one embodiment of the invention, the plug member <NUM> is configured to encircle the riser <NUM> to be connected to the buoy <NUM>. After that the plug member <NUM> has been disconnected from the head end <NUM> of the riser <NUM>, the plug member <NUM> is further configured to be transported by gravity G down along said riser <NUM> towards the subsea template <NUM>.

Referring now to <FIG>, according to one embodiment of the invention, the fluid injection system contains a winch unit <NUM>, which is arranged on the seabed <NUM>. The winch unit <NUM> is configured to pull up the head end <NUM> of the riser <NUM> to be connected to the buoy <NUM> via a winch wire <NUM> connected between the head end <NUM> of the riser <NUM> and the winch unit <NUM>. The which wire <NUM> runs via the buoy <NUM> to the winch unit <NUM>. Preferably, the winch wire <NUM> is led through the buoy <NUM> and via at least one sheave wheel <NUM> on the buoy <NUM> as illustrated in <FIG>.

Preferably, the fluid injection system includes an ROV <NUM> that is configured to be remote controlled to attach the winch wire <NUM> to the head end <NUM> of the riser <NUM>. Further preferably, the ROV <NUM> is configured to disconnect the plug member <NUM> from the first sealing surface S70 of the connector member <NUM> in the head end <NUM> of the riser <NUM>; and thereafter, connect the riser <NUM> to the buoy <NUM>.

Referring now to the flow diagram of <FIG>, we will describe a method for connecting the riser <NUM> to the buoy <NUM> by using the ROV <NUM> according to one embodiment of the invention.

In a first step <NUM>, the ROV <NUM> is controlled to attach the winch wire <NUM> to the head end <NUM> of the riser <NUM>.

Then, in a step <NUM>, the ROV <NUM> is controlled to lead the winch wire <NUM> via the buoy <NUM> to the winch unit <NUM> on the seabed <NUM> below the buoy <NUM>.

Subsequently, in a step <NUM>, the winch unit <NUM> is controlled to pull up the head end <NUM> of the riser (<NUM>) to a bottom side of the buoy <NUM>.

Finally, in a step <NUM> thereafter, the ROV <NUM> is controlled to connect the head end <NUM> of the riser <NUM> to the connector arrangement <NUM> in the bottom of the buoy <NUM>.

<FIG> schematically illustrates an interior of a subsea template <NUM> according to one embodiment of the invention. Here, an exemplary riser <NUM> is shown, which has a base section <NUM> and an upright section <NUM>. The upright section <NUM> constitutes an uppermost part, which is further connected to the buoy <NUM>. The base section <NUM> constitutes a lowermost part of the riser <NUM>, which, in a receiving end <NUM>, is connected to the upright section <NUM>; and in an emitting end <NUM>, is connected to the subsea template <NUM>.

As illustrated in <FIG>, it is desirable if each of the risers <NUM> and <NUM> contains a holdback clamp 17C, which is configured to hold the base section <NUM> of the riser in a desired position via a restraining riser 17R attached to the seabed <NUM>.

According to one embodiment of the invention, the subsea template <NUM> contains an injection valve tree <NUM>, which is in fluid connection with the wellhead <NUM> for the drill hole <NUM>. The subsea template <NUM> also contains a sleeve member <NUM> having penetration means <NUM>, e.g. represented by a pipe-piece extending substantially orthogonally relative to an extension of the sleeve member <NUM>, which penetration means <NUM> is configured to penetrate the riser <NUM> in the emitting end <NUM> of the base section <NUM>. As a result, when the emitting end <NUM> of the base section <NUM> is inserted into the sleeve member <NUM> the penetration means <NUM> will create an opening in the riser <NUM>. This opening, in turn, is connectable to the injection valve tree <NUM>.

Preferably, a vertical connector extending from the penetration means <NUM> has a relatively large tolerance for deviation, say allowing up to <NUM>-<NUM> degrees misalignment. Namely, this allows for a useful flexibility when installing the riser <NUM> in the subsea template <NUM>. Tolerance budgets are estimated based upon accuracy of fabrication, assembly and installation, and flexibility in the piping and misalignment acceptance in the connectors used.

It is preferable if the sleeve member <NUM> contains, or is associated with, at least one guide member, which is exemplified by <NUM> in <FIG>. The guide member <NUM> is shaped and arranged relative to the penetration means <NUM> so as to steer the emitting end <NUM> of the base section <NUM> towards the penetration means <NUM> to allow the emitting end <NUM> of the base section <NUM> to land down at a certain speed and provide a finer and finer alignment with the penetration means <NUM>. Thus, for example, the guide member <NUM> may have a general funnel shape converging towards the penetration means <NUM>. Thereby, the guide member <NUM> is configured to steer the emitting end <NUM> of the base section <NUM> towards the sleeve member when the emitting end <NUM> of the base section <NUM> is brought towards the subsea template <NUM>.

Referring now to the flow diagram of <FIG>, we will describe a method for connecting the riser <NUM> to the subsea template <NUM> according to one embodiment of the invention by using the ROV <NUM>.

In a first step <NUM>, the ROV <NUM> is controlled to steer the emitting end <NUM> of the base section <NUM> of the riser <NUM> to the template guide member <NUM> on the subsea template <NUM>.

Thereafter, in a step <NUM>, the ROV <NUM> is controlled to feed the emitting end <NUM> of the base section <NUM> of the riser <NUM> via the template guide member <NUM> to the sleeve member <NUM>, which has penetration means <NUM> configured to penetrate the riser <NUM>. Consequently, when the second end <NUM> of the base section <NUM> is fed into the sleeve member <NUM>, the penetration means <NUM> is caused to penetrate the riser <NUM> in the second end <NUM> and create an opening in the riser <NUM>.

Finally, in a subsequent step <NUM>, the ROV <NUM> is controlled to connect the sleeve member <NUM> to the injection valve tree <NUM> in the subsea template <NUM>.

According to one embodiment of the invention, the subsea template <NUM> contains a jumper pipe <NUM> having a general U-shape, which is configured to establish a fluid connection between the opening in the riser <NUM> and the injection valve tree <NUM>. An advantage with the jumper pipe <NUM> exclusively being a pipe element is that can be made flexible enough to meet the tolerance requirements for making successful connection.

However, the jumper pipe <NUM> may also act as a "injection choke bridge. " This means that the jumper pipe <NUM> includes a choke valve and instrumentation for controlling the injection of the fluid. The jumper pipe <NUM> is designed with such design tolerances that it is attachable both onto the vertical connector extending from the penetration means <NUM> and the valve tree <NUM>. Preferably, this connection also includes a valve <NUM>, e.g. of ball or gate type, such that a rate of the fluid flow into the injection valve tree <NUM> can be regulated, and shut off if needed. It is advantageous if the valve <NUM> is configured to be operable by the ROV <NUM>.

It is further preferable if the subsea template <NUM> contains at least one heating unit. In <FIG>, a generic heating unit <NUM> is illustrated, which is configured to heat the fluid received from the riser <NUM> before the fluid is being injected into the subterranean void <NUM>. Thus, for example obstructing fluid plugs can be removed from the base section <NUM> of the riser <NUM> in a straightforward manner.

Referring now to the flow diagram of <FIG>, we will describe such a method. As mentioned above, the base section <NUM> extends between the receiving end <NUM> and the emitting end <NUM> of the riser <NUM>, where the receiving end <NUM> is connected to the upright section <NUM> of the riser <NUM> and the emitting end <NUM> of the riser <NUM> is connected to the subsea template <NUM>. The subsea template <NUM> is further connected to the wellhead (<NUM>) for a drill hole <NUM> to the subterranean void <NUM> into which fluid received via the riser <NUM> is to be injected from the subsea template <NUM>.

In a first step <NUM>, the heating unit <NUM> is controlled to heat at least one portion of the base section <NUM>. A subsequent step <NUM> checks if the least one portion of the base section <NUM> has reached a predetermined temperature. If so, a step <NUM> follows; and otherwise, the procedure loops back to step <NUM>.

In step <NUM>, the heating unit <NUM> is controlled to maintain a temperature level above or equal to the predetermined temperature in the at least one section of the base section.

Thereafter, a step checks if a heating period has expired. If so, the procedure ends; and otherwise, the procedure loops back to step <NUM>.

Referring again to <FIG>, according to one embodiment of the invention, the subsea template <NUM> contains a power interface 120p that is configured to receive electric power PE via an electric power line <NUM> on the seabed <NUM>, for example from an onshore power source <NUM>. It is also advantageous if the subsea template <NUM> contains at least one battery <NUM> configured to provide electric power to at least one unit in the subsea template <NUM>, for instance the heating unit <NUM>, the valve <NUM> and/ or the injection valve tree <NUM>.

Naturally, it is preferable if also the at least one battery <NUM> is configured to be charged by electric power PE received via the power interface 120p.

In addition to the tasks mentioned above, the ROV <NUM> is preferably configured to be controlled to effect at least one procedure in connection with controlling the valve <NUM> in the subsea template <NUM>, controlling one or more valves in the buoy <NUM> and/or performing maintenance of the fluid injection system.

<FIG> illustrates, by means of a flow diagram, a method for removing obstructing fluid plugs in the riser <NUM>, which is an alternative to the method described above with reference to <FIG>.

In a first step <NUM>, at least one assisting liquid is heated to a predetermined temperature in the vessel <NUM>.

Thereafter, in a step <NUM>, at least one container holding the at least one heated assisting liquid is/are forwarded from the vessel <NUM> to a storage container in the subsea template <NUM>.

In a subsequent step <NUM>, the at least one heated assisting liquid is/are injected from the storage container into at least one injection point in the base section <NUM> of the riser <NUM>, and from the vessel <NUM> into at least one injection point in the upright section <NUM> of the riser <NUM>.

Then, in a step <NUM>, it is checked if the plugs in the riser <NUM> have melted away. If so, the procedure ends; and otherwise, the procedure loops back to step <NUM>.

Referring now to <FIG>, we see a schematic illustration of the base section <NUM> of the riser <NUM> in the subsea template <NUM> according to one embodiment of the invention.

Here, the base section <NUM>, which may be represented by a pipeline or a so-called spool, is typically around <NUM> to <NUM> meters long, has a low-point section <NUM> between the receiving end <NUM> and the emitting end <NUM>. The low-point section <NUM> constitutes a geometrically lowermost part of the base section <NUM>. Thus, if the fluid being fed through the riser <NUM> into the subterranean void <NUM> contains CO<NUM>, any undesired CO<NUM> hydrates formed in the riser <NUM> will gather in the low-point section <NUM>. The CO<NUM> hydrates may form under certain conditions, for example at particular combinations of pressure and temperature, due to water content in the CO<NUM> composition and/or due to impurities therein. Nevertheless, the concentration of the CO<NUM> hydrates low-point section <NUM> facilitates dissolution of these components before they are transformed into obstructing fluid plugs in the riser <NUM>.

According to one embodiment of the invention, the above-mentioned container holding at least one heated assisting liquid is represented by a storage container <NUM> with heated MEG (Mono-Ethylene Glycol) brought to the subsea template <NUM> from the vessel <NUM> by means of the ROV <NUM>. Further, a container connector <NUM> is provided on the base section <NUM>. The container connector <NUM> is configured to receive an output nozzle of the storage container <NUM> so as to enable the at least one heated assisting liquid in the storage container <NUM> to be fed into the base section <NUM>, for instance via a valve <NUM>. Hence, the container connector <NUM> represents one of the at least one injection point in the base section <NUM> referred to above. The container connector <NUM> is arranged upstream of the low-point section <NUM> relative to a direction F of a fluid flow into an injection valve tree <NUM> for the wellhead <NUM>.

Moreover, the method specifically involves feeding the at least one heated assisting liquid from the storage container <NUM> via the low-point section <NUM> into the injection valve tree <NUM>. Preferably, a pump <NUM> and/or a valve <NUM> is arranged between the container connector <NUM> and the base section <NUM>, such that a flow rate of heated assisting liquid being fed into the base section <NUM> may be controlled; and if needed, be shut off completely.

According to another embodiment of the invention, the base section <NUM> contains first and second temperature sensors <NUM> and <NUM> respectively. The first temperature sensor <NUM> is arranged downstream of the container connector <NUM> and upstream of the low-point section <NUM> relative to the direction F of the fluid flow in the base section <NUM> of the riser <NUM>. The first temperature sensor <NUM> is configured to register a first temperature signal T1. The second temperature sensor <NUM> is arranged downstream of the low-point section <NUM> relative to the direction F of the fluid flow. The second temperature sensor <NUM> is configured to register a second temperature signal T2.

Through thermal convection through the wall of the pipe of the base section <NUM> the presence of the heated flow of at least one heated assisting liquid from the storage container <NUM> can traced. Whether or not there is an obstructing fluid plug <NUM> in the low-point section <NUM> this may be detected by studying the first and second temperature signals T1 and T2. If no obstructing plug is present, the second temperature signal T2 will follow the first temperature signal T1 relatively closely both with respect to temporal behavior and magnitude. If, however, there is an obstructing fluid plug <NUM> in the low-point section <NUM>, the second temperature signal T2 will be much less similar to the first temperature signal T1. The method therefore preferably involves determining if there is a fluid plug <NUM> in the low-point section <NUM> based on how the second temperature signal T2 varies over time compared to how the first temperature signal T1 varies over time in response to feeding the at least one heated assisting liquid from the storage container <NUM> into the base section <NUM> via the container connector <NUM>.

If the base section <NUM> of the riser <NUM> is obstructed, there is a risk of over pressuring causes damages. Consequently, if it is determined there is a fluid plug <NUM> in the low-point section <NUM>, the method further involves reducing, at least temporarily, a flow rate at which the at least one heated assisting liquid is fed from the storage container <NUM> into the base section <NUM> via the container connector <NUM>. Of course, this reduction may also include stopping the flow of the at least one heated assisting liquid to avoid the buildup of an excessive pressure.

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 method of removing obstructing fluid plugs from a base section (<NUM>) of a riser (<NUM>), which base section (<NUM>) extends between a receiving end (<NUM>) connected to an upright section (<NUM>) of the riser (<NUM>) and an emitting end (<NUM>) of the riser (<NUM>) connected to a subsea template (<NUM>) located on a seabed (<NUM>), which subsea template (<NUM>) is further connected to a wellhead (<NUM>) for a drill hole (<NUM>) to a subterranean void (<NUM>) into which fluid received via the riser (<NUM>) is to be injected from the subsea template (<NUM>), the method comprising:
(A) heating at least one assisting liquid to a predetermined temperature, the heating being effected in a vessel (<NUM>),
(B) forwarding at least one transport container holding the at least one heated assisting liquid from the vessel (<NUM>) to a storage container (<NUM>) in the subsea template (<NUM>),
(C) injecting the at least one heated assisting liquid from the storage container into at least one injection point in the base section (<NUM>),
(D) injecting, from the vessel (<NUM>) at least one heated assisting liquid in the upright section (<NUM>) of the riser (<NUM>), and
(E) repeat steps (A) through (D) until any plugs in the riser (<NUM>) have melted away.