TECHNICAL FIELD

The present invention relates generally to strategies for redu cing the amount of environmentally unfriendly gaseous compo nents in the atmosphere. Especially, the invention relates to a fluid injection system for injecting fluid from a vessel on a water surface into a subterranean void beneath a seabed via a subsea template on the seabed. Thus, environmentally unfriendly fluids can be long-term stored in the subterranean void. The invention also relates to various methods for installing and servicing the proposed fluid injection system.

BACKGROUND

Carbon dioxide is an important heat-trapping gas, a so-called greenhouse gas, which is released through certain human activi ties such as deforestation and burning fossil fuels. However, al so 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 di oxide 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 dioxi de produced by human activities, such as renewable energy pro duction. There are also technical solutions for capturing carbon dioxide from the atmosphere and storing it on a long term/per manent basis in subterranean reservoirs. For practical reasons, most of these reservoirs are located un der 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 Snohvit sites in the North Sea. At the Sleipner site, CO2 is injected from a bottom fixed platform. At the Snohvit site, CO2 from LNG (Li quefied 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 . , “Snohvit CO2 sto rage 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 Ope rations: Sleipner, In Salah and Snohvit”, 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 Snohvit (2 years of injection). The Snohvit site is characterized by having the utilities for the subsea CO2 wells and template onshore. This means that for ex ample 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 sa fety 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 Snohvit 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 Sno- hvit 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 smal- ler for the higher pressure levels. The tanks used have a cold temperature as low as -55 degrees Celsius. The smaller quanti ties 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”, En- ergy 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 plat- forms or subsea wellhead installations. It is not unusual, howe ver, that power is provided from shore via high-voltage AC cab les.

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

US 9,631 ,438 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 to- gether to contain the high pressure wellbore fluids passing bet ween 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 com ponents are disengaged, so that during disconnection, any fluids escaping the inner conduit are contained.

US 9,784,044 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 al so disclosed.

US 2011/0017465 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 ri ser termination for coupling to a floating vessel; and an interme diate support supporting an intermediate portion of the riser to define a catenary bend between the intermediate support and the riser termination device.

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 sea- bed, 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. SUMMARY

The object of the present invention is therefore to offer a solu tion 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 recei ving 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: (A) heating at least one assisting liquid to a predetermined tem perature, the heating being effected in a vessel;

(B) forwarding at least one transport container holding the at least one heated assisting liquid from the vessel to a storage container in the subsea template; (C) injecting the at least one heated assisting liquid from the storage container into at least one injection point in the base section;

(D) injecting, from the vessel at least one heated assisting liquid in the upright section of the riser; and (E) repeat steps (A) through (D) until any plugs in the riser have melted away.

This method is advantageous because it provides efficient remo val 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. CO2 hydrates formed therein. The base section of the riser also includes a container connector configured to re ceive 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 assis ting liquid from the storage container via the low-point section into the injection valve tree. Thereby, any undesired compo- nents will be removed from the riser in an efficient and straight forward 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 con- tainer 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 tempe rature 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 assis- ting liquid is fed from the storage container into the base section is reduced, or stopped, at least temporarily.

According to another aspect of the invention, the object is achie ved by a method of removing obstructing fluid plugs from a base section of a riser, which base section extends between a recei- ving 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 invol ves:

-controlling the heating unit to heat the at least one portion of the base section to a predetermined temperature, and

-controlling the heating unit to maintain a temperature level above or equal to the predetermined temperature in the at least one section of the base section during a heating period.

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

Further advantages, beneficial features and applications of the present invention will be apparent from the following description and the dependent claims.

BRIEF DESCRIPTION OF THE DRAWINGS

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.

Figure 1 schematically illustrates a system for long term storage of fluids in a subterranean void according to one embodiment of the invention;

Figure 2 shows a buoy configured to connect a vessel to a fluid-transporting riser according to one embodi ment of the invention;

Figures 3a-c illustrate how a riser is connected to a buoy ac cording to one embodiment of the invention;

Figure 4 schematically illustrates an interior of a subsea template according to one embodiment of the in- vention;

Figure 5 illustrates a connector arrangement for connecting the riser to the buoy according to one embodiment of the invention; Figure 6 illustrates, by means of a flow diagram a method according to one embodiment of the invention for connecting a riser to a buoy;

Figure 7 illustrates, by means of a flow diagram a method according to one embodiment of the invention for connecting a riser to a subsea template;

Figures 8-9 illustrate, by means of flow diagrams, methods ac cording to first and second embodiments of the in vention for removing obstructing fluid plugs in a ri ser; and Figure 10 schematically illustrates the base section of the ri ser according to one embodiment of the invention.

DETAILED DESCRIPTION

In Figure 1 , we see a schematic illustration of a system accor ding to one embodiment of the invention for long term storage of fluids, e.g. carbon dioxide, in a subterranean void or other ac commodation space 150, which typically is a subterranean aqui fer. However, according to the invention, the subterranean void 150 may equally well be a reservoir containing gas and/or oil, a depleted gas and/or oil reservoir, a carbon dioxide storage/dis- posal reservoir, or a combination thereof. These subterranean accommodation spaces are typically located in porous or frac tured 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 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 injec tion site 100, in turn, contains a subsea template 120 arranged on a seabed/sea bottom 130. The subsea template 120 is loca ted at a wellhead for a drill hole 140 to the subterranean void 150. The subsea template 140 may also contain 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 there fore, in contrast to the above-mentioned Snohvit 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 Figure 1 , a control site, generically identified as 160, is adap ted to generate the control commands C _cmd for controlling the flow of fluid from the vessel 110 and down into the subterranean void 150. For example, the control commands C _cmd may relate to opening and closure of valves when the vessel 110 connects to and disconnects from the buoy 170. The control site 160 is posi tioned at a location geographically separated from the offshore injection site 100, for example in a control room onshore. Howe- ver, additionally or alternatively, the control site 160 may be positioned at an offshore location geographically separated from the offshore injection site, for example at another offshore in jection site. Consequently, a single control site 160 can control multiple offshore injection sites 100. There is also large room for varying which control site 160 controls which offshore injection site 100. Communications and controls are thus located remote from the offshore injection site 100. However, as will be discus sed below, the offshore injection site 100 may be powered lo cally, remotely or both. In order to enable remote control from the control site 160, the subsea template 120 preferably contains a communication inter face 120c that is communicatively connected to the control site 160. The subsea template 120 is also configured to receive the control commands C _cmd via the communication interface 120c.

Depending on the channel(s) used for forwarding the control commands C _cmd between the control site 160 and the offshore injection site 100, the communication interface 120c may be configured to receive the control commands C _cmd via a submer- ged 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 C _ack may be returned to the control site 160 from the subsea template 120.

According to the invention, the offshore injection site 100 inclu des 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 posi- tioned 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 confi gured to forward the fluid from the buoy 170 to the subsea tem plate 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 tem plate 120 contains a power input interface 120p, which is confi- gured to receive electric energy PE for operating the utility sys tem and/or operating various functions in the buoy 170. The po wer 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.

Figure 1 illustrates a generic power source 180, which is confi gured to supply the electric power PE to the power input inter face 120p. It is generally advantageous if the electric power PE is supplied via a cable 185 from the power source 180 in the form of low-power direct current (DC) in the range of 200V - 1000V, preferably around 400V. The power source 180 may either be co-located with the offshore injection site 100, for ins tance as a wind turbine, a solar panel and/or a wave energy converter; and/or be positioned at an onshore site and/or at an other offshore site geographically separated from the offshore injection site 100. Thus, there is a good potential for flexibility and redundancy with respect to the energy supply for the offshore injection site 100. The subsea template 120 contains a valve system that is confi gured to control the injection of the fluid into the subterranean void 150. The valve system, as such, may be operated by hyd raulic means, electric means or a combination thereof. The sub sea 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 con trolled 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 com bination 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 di rect 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. Na mely, a permanent offshore installation acting as a field center for an offshore field development is bound by offshore legisla tion 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 tem porary, that control well barriers must satisfy the dynamic posi tioning level 3 (DP3) requirement. This involves extensive re quirements 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 pro vide any utilities, well or barrier control, for the injection system. Consequently, the vessel 110 may operate under maritime leg is- lation and regulations, which are normally far less restrictive than the offshore legislation and regulations.

Figure 2 shows a buoy 170 according to one embodiment of the invention that is configured to enable a vessel, e.g. 110 shown in Figure 1 , to connect to the fluid-transporting riser 171 , which, in turn, is connected to the subsea template 120 in further fluid connection with the subterranean void 150.

Referring again to Figure 1 , we see a fluid injection system ar ranged to receive fluid, e.g. containing CO2, from the vessel 110. The fluid injection system contains the buoy 170 configured to be connected with the vessel 111 and receive the fluid there from. The system also contains the subsea template 120, which is located on the seabed 130 at the wellhead for the drill hole 140 to the subterranean void 150.

Moreover, the system includes at least one riser, here exempli- fied by 171 and 172 respectively, which interconnect the buoy

170 and the subsea template 120. Each of the at least one riser

171 and 172 is configured to transport the fluid from the buoy 170 to the subsea template 120. Specifically, each of the at least one riser 171 and 172 is detachably connected to a bottom surface of the buoy 170 by means of a connector arrangement 210. Figure 5 illustrates the connector arrangement 210 accor ding to one embodiment of the invention, which connector arran gement 210 is configured to connect the riser 171 to the buoy 170. Naturally, although not illustrated in Figure 2, any additional risers attached to the buoy 170 will be connected in an analo gous manner.

The connector arrangement 210 includes a buoy guide member 510 configured to automatically steer a connector member 570 towards the buoy guide member 510 when the connector mem ber 570 is moved towards the buoy guide member 510. The con nector member 570 is attached in a head end 300 of the riser 171 to be connected to the buoy 170. The connector arrange- ment 210 further includes a mating member 550, for example embodied as so-called fingers, configured to attach a first sea ling surface S70 of the connector member 570 to a second sea ling surface S10 of the buoy guide member 510 when said head end 300 has been moved such that the connector member 570 contacts the buoy guide member 510. Additionally, the connec tor arrangement 210 includes a locking member 560 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 210 contains one collet connector for each riser to be connected to the buoy 170. In addition to the elements mentioned above, the collet connector typically also includes a seal gasket 530, which is arranged bet ween the first and second sealing surfaces S70 and S10 to further reduce the risk of leakages. Figures 3a, 3b and 3c illustrate how a riser 171 is connected to a buoy 170 according to one embodiment of the invention.

Here, the head end 300 of the riser 171 to be connected con tains a plug member 317 covering the first sealing surface S70. Thus, water is and prevented from entering into the riser 171 be- fore the riser 171 has been connected to the buoy 170. In addi tion to that, the head end 300 of the riser 171 to be connected preferably includes a drag-eye member 305, which facilitates connecting a winch wire to the head end 300 and pulling the riser 171 up to the buoy 170 as described below. As illustrated in Figure 3c, according to one embodiment of the invention, the plug member 317 is configured to encircle the ri ser 171 to be connected to the buoy 170. After that the plug member 317 has been disconnected from the head end 300 of the riser 171 , the plug member 317 is further configured to be transported by gravity G down along said riser 171 towards the subsea template 120.

Referring now to Figure 3a, according to one embodiment of the invention, the fluid injection system contains a winch unit 330, which is arranged on the seabed 130. The winch unit 330 is con figured to pull up the head end 300 of the riser 171 to be con nected to the buoy 170 via a winch wire 320 connected between the head end 300 of the riser 171 and the winch unit 330. The which wire 320 runs via the buoy 170 to the winch unit 330. Pre ferably, the winch wire 320 is led through the buoy 170 and via at least one sheave wheel 325 on the buoy 170 as illustrated in Figures 3a and 3b.

Preferably, the fluid injection system includes an ROV 350 that is configured to be remote controlled to attach the winch wire 320 to the head end 300 of the riser 171. Further preferably, the ROV 350 is configured to disconnect the plug member 317 from the first sealing surface S70 of the connector member 570 in the head end 300 of the riser 171 ; and thereafter, connect the riser 171 to the buoy 170.

Referring now to the flow diagram of Figure 6, we will describe a method for connecting the riser 171 to the buoy 170 by using the ROV 350 according to one embodiment of the invention.

In a first step 610, the ROV 350 is controlled to attach the winch wire 320 to the head end 300 of the riser 171.

Then, in a step 620, the ROV 350 is controlled to lead the winch wire 320 via the buoy 170 to the winch unit 330 on the seabed 130 below the buoy 170.

Subsequently, in a step 630, the winch unit 330 is controlled to pull up the head end 300 of the riser (171) to a bottom side of the buoy 170. Finally, in a step 640 thereafter, the ROV 350 is controlled to connect the head end 300 of the riser 171 to the connector ar rangement 210 in the bottom of the buoy 170.

Figure 4 schematically illustrates an interior of a subsea templa- te 220 according to one embodiment of the invention. Here, an exemplary riser 171 is shown, which has a base section 410 and an upright section 420. The upright section 420 constitutes an uppermost part, which is further connected to the buoy 170. The base section 410 constitutes a lowermost part of the riser 171 , which, in a receiving end 411 , is connected to the upright sec tion 420; and in an emitting end 412, is connected to the subsea template 120.

As illustrated in Figure 1 , it is desirable if each of the risers 171 and 172 contains a holdback clamp 17C, which is configured to hold the base section 410 of the riser in a desired position via a restraining riser 17R attached to the seabed 130.

According to one embodiment of the invention, the subsea tem plate 120 contains an injection valve tree 460, which is in fluid connection with the wellhead 470 for the drill hole 140. The sub- sea template 120 also contains a sleeve member 440 having pe netration means 441 , e.g. represented by a pipe-piece extending substantially orthogonally relative to an extension of the sleeve member 440, which penetration means 441 is configured to pe netrate the riser 171 in the emitting end 412 of the base section 410. As a result, when the emitting end 412 of the base section 410 is inserted into the sleeve member 440 the penetration means 441 will create an opening in the riser 171. This opening, in turn, is connectable to the injection valve tree 460.

Preferably, a vertical connector extending from the penetration means 441 has a relatively large tolerance for deviation, say al lowing up to 5-10 degrees misalignment. Namely, this allows for a useful flexibility when installing the riser 171 in the subsea template 120. Tolerance budgets are estimated based upon ac- curacy of fabrication, assembly and installation, and flexibility in the piping and misalignment acceptance in the connectors used.

It is preferable if the sleeve member 440 contains, or is asso ciated with, at least one guide member, which is exemplified by 432 in Figure 4. The guide member 440 is shaped and arranged relative to the penetration means 441 so as to steer the emitting end 412 of the base section 410 towards the penetration means 441 to allow the emitting end 412 of the base section 410 to land down at a certain speed and provide a finer and finer align- ment with the penetration means 441. Thus, for example, the guide member 432 may have a general funnel shape converging towards the penetration means 441. Thereby, the guide member 432 is configured to steer the emitting end 412 of the base section 410 towards the sleeve member when the emitting end 412 of the base section 410 is brought towards the subsea tem plate 120.

Referring now to the flow diagram of Figure 7, we will describe a method for connecting the riser 171 to the subsea template 120 according to one embodiment of the invention by using the ROV 350.

In a first step 710, the ROV 350 is controlled to steer the emit ting end 412 of the base section 410 of the riser 171 to the tem plate guide member 432 on the subsea template 120.

Thereafter, in a step 720, the ROV 350 is controlled to feed the emitting end 412 of the base section 410 of the riser 171 via the template guide member 432 to the sleeve member 440, which has penetration means 441 configured to penetrate the riser 171. Consequently, when the second end 412 of the base sec tion 410 is fed into the sleeve member 440, the penetration means 441 is caused to penetrate the riser 171 in the second end 412 and create an opening in the riser 171.

Finally, in a subsequent step 730, the ROV 350 is controlled to connect the sleeve member 440 to the injection valve tree 460 in the subsea template 120.

According to one embodiment of the invention, the subsea tem plate 120 contains a jumper pipe 450 having a general U-shape, which is configured to establish a fluid connection between the opening in the riser 171 and the injection valve tree 460. An ad vantage with the jumper pipe 450 exclusively being a pipe ele ment is that can be made flexible enough to meet the tolerance requirements for making successful connection.

However, the jumper pipe 450 may also act as a “injection choke bridge.” This means that the jumper pipe 450 includes a choke valve and instrumentation for controlling the injection of the fluid. The jumper pipe 450 is designed with such design toleran ces that it is attachable both onto the vertical connector exten ding from the penetration means 441 and the valve tree 460. Preferably, this connection also includes a valve 445, e.g. of ball or gate type, such that a rate of the fluid flow into the injection valve tree 460 can be regulated, and shut off if needed. It is ad vantageous if the valve 445 is configured to be operable by the ROV 350. It is further preferable if the subsea template 120 contains at least one heating unit. In Figure 4, a generic heating unit 480 is illustrated, which is configured to heat the fluid received from the riser 171 before the fluid is being injected into the subter ranean void 150. Thus, for example obstructing fluid plugs can be removed from the base section 410 of the riser 171 in a straightforward manner.

Referring now to the flow diagram of Figure 9, we will describe such a method. As mentioned above, the base section 410 ex tends between the receiving end 411 and the emitting end 412 of the riser 171 , where the receiving end 411 is connected to the upright section 420 of the riser 171 and the emitting end 412 of the riser 171 is connected to the subsea template 120. The sub sea template 120 is further connected to the wellhead (470) for a drill hole 140 to the subterranean void 150 into which fluid re ceived via the riser 171 is to be injected from the subsea tem plate 120.

In a first step 910, the heating unit 480 is controlled to heat at least one portion of the base section 410. A subsequent step 920 checks if the least one portion of the base section 410 has reached a predetermined temperature. If so, a step 930 follows; and otherwise, the procedure loops back to step 910.

In step 930, the heating unit 480 is controlled to maintain a tem- perature 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 930. Referring again to Figure 4, according to one embodiment of the invention, the subsea template 120 contains a power interface 120p that is configured to receive electric power PE via an elec tric power line 185 on the seabed 130, for example from an on shore power source 180. It is also advantageous if the subsea template 120 contains at least one battery 490 configured to provide electric power to at least one unit in the subsea tem plate 120, for instance the heating unit 480, the valve 445 and / or the injection valve tree 460.

Naturally, it is preferable if also the at least one battery 490 is configured to be charged by electric power PE received via the power interface 120p.

In addition to the tasks mentioned above, the ROV 350 is prefer ably configured to be controlled to effect at least one procedure in connection with controlling the valve 445 in the subsea tem- plate 120, controlling one or more valves in the buoy 170 and/or performing maintenance of the fluid injection system. Figure 8 illustrates, by means of a flow diagram, a method for re moving obstructing fluid plugs in the riser 171 , which is an alter native to the method described above with reference to Figure 9.

In a first step 810, at least one assisting liquid is heated to a predetermined temperature in the vessel 110.

Thereafter, in a step 820, at least one container holding the at least one heated assisting liquid is/are forwarded from the ves sel 110 to a storage container in the subsea template 120.

In a subsequent step 830, the at least one heated assisting li- quid is/are injected from the storage container into at least one injection point in the base section 410 of the riser 171 , and from the vessel 110 into at least one injection point in the upright section 420 of the riser 171.

Then, in a step 840, it is checked if the plugs in the riser 171 ha- ve melted away. If so, the procedure ends; and otherwise, the procedure loops back to step 810.

Referring now to Figure 10, we see a schematic illustration of the base section 410 of the riser 171 in the subsea template 420 according to one embodiment of the invention. Here, the base section 410, which may be represented by a pi peline or a so-called spool, is typically around 60 to 100 meters long, has a low-point section 1030 between the receiving end 411 and the emitting end 412. The low-point section 1030 cons titutes a geometrically lowermost part of the base section 410. Thus, if the fluid being fed through the riser 171 into the subter ranean void 150 contains CO2, any undesired CO2 hydrates for med in the riser 171 will gather in the low-point section 1030. The CO2 hydrates may form under certain conditions, for examp le at particular combinations of pressure and temperature, due to water content in the CO2 composition and/or due to impurities therein. Nevertheless, the concentration of the CO2 hydrates low-point section 1030 facilitates dissolution of these compo- nents before they are transformed into obstructing fluid plugs in the riser 171.

According to one embodiment of the invention, the above-men tioned container holding at least one heated assisting liquid is represented by a storage container 1040 with heated MEG (Mo no-Ethylene Glycol) brought to the subsea template 120 from the vessel 110 by means of the ROV 350. Further, a container connector 1047 is provided on the base section 410. The con tainer connector 1047 is configured to receive an output nozzle of the storage container 1040 so as to enable the at least one heated assisting liquid in the storage container 1040 to be fed into the base section 410, for instance via a valve 1045. Hence, the container connector 1047 represents one of the at least one injection point in the base section 410 referred to above. The container connector 1047 is arranged upstream of the low-point section 1030 relative to a direction F of a fluid flow into an injec tion valve tree 460 for the wellhead 470.

Moreover, the method specifically involves feeding the at least one heated assisting liquid from the storage container 1040 via the low-point section 1030 into the injection valve tree 460. Preferably, a pump 1050 and/or a valve 1055 is arranged bet ween the container connector 1047 and the base section 410, such that a flow rate of heated assisting liquid being fed into the base section 410 may be controlled; and if needed, be shut off completely.

According to another embodiment of the invention, the base sec tion 410 contains first and second temperature sensors 1010 and 1020 respectively. The first temperature sensor 1010 is ar ranged downstream of the container connector 1047 and up- stream of the low-point section 1030 relative to the direction F of the fluid flow in the base section 410 of the riser 171. The first temperature sensor 1010 is configured to register a first tempe rature signal T1. The second temperature sensor 1020 is arran ged downstream of the low-point section 1030 relative to the di- rection F of the fluid flow. The second temperature sensor 1020 is configured to register a second temperature signal T2.

Through thermal convection through the wall of the pipe of the base section 410 the presence of the heated flow of at least one heated assisting liquid from the storage container 1040 can tra ced. Whether or not there is an obstructing fluid plug 1035 in the low-point section 1030 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 obst ructing fluid plug 1035 in the low-point section 1030, the second temperature signal T2 will be much less similar to the first tem perature signal T1. The method therefore preferably involves de- termining if there is a fluid plug 1035 in the low-point section 1030 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 as sisting liquid from the storage container 1040 into the base sec- tion 410 via the container connector 1047.

If the base section 410 of the riser 171 is obstructed, there is a risk of over pressuring causes damages. Consequently, if it is determined there is a fluid plug 1035 in the low-point section 1030, 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 1040 into the base section 410 via the container connector 1047. Of course, this reduction may also include stopping the flow of the at least one heated assis ting 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 in vention, 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, inte- gers, steps or components or groups thereof. The indefinite ar ticle "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.