Conditioning method for carbon dioxide storage in a subterranean reservoir

Abstract

The present invention relates to a method for subterranean CO2 storage, the method successively comprising: a) a conditioning step of flowing liquid CO2 in a closed subsea loop, from an inlet of a first subsea flow line to an outlet of the first subsea flow line, and back to the inlet of the first subsea flow line through at least one second subsea flow line, the liquid CO2 being heated by a heater positioned on the first subsea flow line; b) an injection step of flowing liquid CO2 from a CO2 storage tank, through the first subsea flow line, to an injection well, and injecting the liquid CO2 into the injection well, the liquid CO2 being heated by the heater. The invention also relates to an installation for subterranean CO2 storage.

Description

[0001] CONDITIONING METHOD FOR CARBON DIOXIDE STORAGE IN A SUBTERRANEAN RESERVOIR

[0002] Technical field

[0003] The present invention relates to the field of CO2 storage, and more specifically to a method for subterranean CO2 storage. The invention also relates to an installation for subterranean CO2 storage.

[0004] Technical background

[0005] Carbon storage projects often use subterranean formations as storage candidates for CO2. These subterranean formations may comprise existing depleted oil and / or gas subterranean reservoirs, depleted meaning that the pressure in the subterranean reservoir has diminished to a certain level. CO2 is stored following CO2 capture to address the increasing demand for minimizing impacts on climate change.

[0006] There is an advantage in using existing subterranean depleted reservoirs as they are already proven to be capable of storing gas / oil for a long time, their storage size is known and they are already penetrated with a number of wells. Re-use of wells and / or surface equipment may be particularly beneficial given that subterranean formations with such reservoirs are often offshore, meaning considerable effort is often involved in providing them with the necessary equipment. However, it is generally difficult to make further use of existing equipment as when the CO2 is supplied to the subterranean reservoir it can undergo a phase change, resulting in a temperature drop that brings the temperature of the equipment below its original design temperature. This effect of thermal shock may damage the equipment, resulting in a leak or damage in the well. The thermal shock may additionally and / or alternatively create a fracture in the reservoir itself or the formation above the reservoir.

[0007] FIG. 1 provides an example of a method for subterranean CO2 storage according to the prior art. A CO2 storage tank 102 containing liquid CO2 is provided on a floating storage unit, such as a vessel (or floater or tanker) 100. A pump 104 and heater 106 are located along a subsea injection line 107 fluidically connecting the storage tank to an injection well 124 and subterranean reservoir 116. The heater 106 heats the CO2 as it leaves the storage tank, and as the liquid CO2 flows through the flow line 107 (which lies mostly in the seawater 112, and toward the seabed 114) toward the injection well 124 and rig 122, it experiences a temperature drop due to the cold seawater, and so is heated a second time at the injection well 124 by a second heater 111. The second heater 1 11 therefore allows for the CO2 to be at a desired condition for facilitating injection. Such a process however, can use a lot of energy (being for example, a 5 MW heater may be necessary), and can make the possibility of an unmanned injection operation challenging.

[0008] Document KR101915855B1 relates to a system of service for carbon dioxide injection and process using seawater heat source and compressor heat source and a corresponding method of carbon dioxide injection.

[0009] Within this context, there is still a need to provide a method for storing CO2 in a subterranean formation in an efficient manner.

[0010] Summary of the invention

[0011] It is therefore the object of this invention to provide a method for subterranean CO2 storage, the method successively comprising: a) a conditioning step of flowing liquid CO2 in a closed subsea loop, from an inlet of a first subsea flow line to an outlet of the first subsea flow line, and back to the inlet of the first subsea flow line through at least one second subsea flow line, the liquid CO2 being heated by a heater positioned on the first subsea flow line; b) an injection step of flowing liquid CO2 from a CO2 storage tank, through the first subsea flow line, to an injection well, and injecting the liquid CO2 into the injection well, the liquid CO2 being heated by the heater.

[0012] According to some embodiments, heating the liquid CO2 comprises heating the liquid CO2 to a temperature above that of a desired injection temperature, for example, a temperature greater than or equal to 35 °C, for a desired injection temperature lying from 10 °C to 50 °C.

[0013] According to some embodiments, liquid CO2 is injected into multiple injection wells via a first manifold fluid ically connecting the first subsea flow line to multiple first injection line, each first injection line being connected to a respective injection well.

[0014] According to some embodiments, the pressure in at least one of the first injection lines is different from the pressure in the other first injection lines. According to some embodiments, the injection step further comprises flowing liquid CO2 from the CO2 storage tank, through the second subsea flow line, to one or more additional injection wells, and injecting the liquid CO2 into the additional injection well(s).

[0015] According to some embodiments, the injection step comprises flowing some of the heated liquid CO2 from the first subsea flow line to the second subsea flow line, and then to the additional injection well(s).

[0016] According to some embodiments, liquid CO2 is injected into multiple additional injection wells via a second manifold fluid ically connecting the second subsea flow line to multiple second injection lines, each second injection line being connected to a respective injection well.

[0017] According to some embodiments, the pressure in at least one of the second injection lines is different from the pressure in the other injection lines.

[0018] According to some embodiments, the method comprises taking temperature measurements along the first subsea flow line and / or second subsea flow line and / or at the injection well.

[0019] According to some embodiments, the method comprises taking pressure measurements at the injection well.

[0020] According to some embodiments, the injection well has a pressure from 4 MPa to 40 MPa.

[0021] According to some embodiments, a distance from 20 m to 10 km, for example from 1 km to 5 km, lies between the storage tank and the at least one injection well.

[0022] According to some embodiments, the liquid CO2 exiting the storage tank initially has a temperature from -50 °C to -20°C.

[0023] According to some embodiments, the liquid CO2 exiting the storage tank initially has a pressure from 1 .5 MPa to 3 MPa.

[0024] According to some embodiments, the method comprises taking flow rate measurements along the first subsea flow line and / or second subsea flow line and / or at the injection well.

[0025] According to some embodiments, the storage tank is part of a floating storage unit, preferably part of a vessel.

[0026] According to some embodiments, the heater is on the floating storage unit, and wherein preferably there is no heater out of the floating storage unit.

[0027] Another object of the invention is an installation for subterranean CO2 storage, the installation comprising at least one first subsea flow line having an inlet and an outlet, at least one second subsea flow line, a heater positioned on the first subsea flow line and a pump positioned on the first subsea flow line, wherein: the inlet of the first subsea flow line is flu id ical ly connected to a CO2 storage tank; the outlet of the first subsea flow line is fluidically connected to an injection well; the second subsea flow line fluidically connects the outlet of the first subsea flow line to the inlet of the first subsea flow line.

[0028] According to some embodiments, the installation comprises a first manifold fluidically connecting the first subsea flow line to multiple first injection lines, each first injection line being connected to a respective injection well.

[0029] According to some embodiments, the at least one second subsea flow line is fluidically connected to an additional injection well.

[0030] According to some embodiments, the installation comprises a flow line branch comprising a branch inlet fluidically connected to the first flow line, and a branch outlet fluidically connected to the second flow line.

[0031] According to some embodiments, the installation comprises a first injection line fluidically connecting the first subsea flow line to the injection well and a second injection line fluidically connecting the second subsea flow line to the additional injection well.

[0032] According to some embodiments, the installation comprises a second manifold fluidically connecting the second subsea flow line to multiple second injection lines, each second injection line being fluidically connected to a respective additional injection well.

[0033] According to some embodiments, the installation comprises at least one temperature sensor configured to take temperature measurements along the first subsea flow line and / or second subsea flow line and / or at the injection well and / or additional injection well.

[0034] According to some embodiments, the installation comprises at least one pressure sensor configured to take pressure measurements at the injection well and / or additional injection well.

[0035] According to some embodiments, a distance from 20 m to 10 km, for example from 1 km to 5 km, lies between the storage tank and the injection well.

[0036] According to some embodiments, the installation comprises at least one flow meter configured to take flow rate measurements along the first subsea flow line and / or second subsea flow line. According to some embodiments, the installation is configured to control a flow rate and a pressure of the CO2 by adjusting at least one valve along the first subsea flow line and / or second subsea flow line.

[0037] According to some embodiments, the storage tank is part of a floating storage unit, preferably part of a vessel.

[0038] According to some embodiments, the heater is in the floating storage unit, and / or wherein there is no heater out of the floating storage unit.

[0039] The present invention makes it possible to address the need mentioned above. In particular, the method provides a method for storing CO2 in a subterranean formation in an efficient manner.

[0040] This is achieved by the method successively comprising a conditioning step and an injection step.

[0041] The conditioning step of flowing liquid CO2 in a closed subsea loop allows for the CO2 to be in an optimal state before starting the injection into the injection well. The liquid CO2 flows from an inlet of a first subsea flow line to an outlet of the first subsea flow line, and back to the inlet of the first subsea flow line through at least one second subsea flow line. Each subsea flow line may be more briefly designated below as simply a flow line. The liquid CO2 is heated by a heater positioned on the first subsea flow line. Therefore, as the liquid flows back to the inlet, it can be reheated by the heater before flowing once more to the outlet and then back to the inlet so as to be heated once again. This heating can allow the liquid CO2 within the first subsea flow line (and optionally the second subsea flow line) to reach a temperature that is suitable for injection. Thereby, the first subsea flow line (and optionally the second subsea flow line) are warmed up to a temperature above the sea temperature before the injection starts. This enables avoiding a subzero CO2 in the injection well. This assists in the prevention of phase change or the effects of phase change. This minimizes the temperature drop in the injection well (to a temperature below the design temperature of the well, the well being for example an old well and / or a well originally designed for another purpose), enabling existing equipment to continue to function at the desired operating temperature. In particular, phase change of the CO2 in the injection well may thus be prevented or limited. The method can therefore allow for a correct operability of the CO2 for injection, for example during a CO2 storage system start-up phase.

[0042] The method may make it possible to do without a heater at the injection site, such as at the injection well. Advantageously, the system comprises a single heater associated with the CO2 storage tank. Without the conditioning step, when injection begins the liquid CO2 initially reaching the injection well would be too cold, due to the distance between the heater and the injection well and to the subsea environment.

[0043] The method may also therefore be able to function without the replacement of existing equipment and / or use of an additional heater. This in turn improves the efficiency and cost-effectiveness of storing CO2.

[0044] The method may also therefore facilitate an unmanned injection operation at a rig of an injection well or in the case of direct subsea injection.

[0045] Advantageously and according to some embodiments the method can heat the liquid CO2 to a temperature above that of a desired injection temperature. This can allow for accounting for any temperature drops that may occur in the liquid CO2 between the location at which it was last heated by the heater and the point of injection ( / .e. the wellhead).

[0046] Additionally or alternatively, according to some embodiments, the method may allow for the conditioning of liquid CO2 for injection into multiple different injection wells, for example simultaneously and / or under different injection conditions. This allows for a method that is both efficient, and versatile, as it can be adapted according to the particular needs of a given subterranean formation for CO2 storage.

[0047] Brief description of the drawings

[0048] Non-limiting examples will now be described in reference to the accompanying drawings, where:

[0049] FIG. 1 shows an example of a method for subterranean CO2 storage according to the prior art.

[0050] FIG. 2 shows an example of the method for subterranean CO2 storage according to the present invention, wherein the well is placed on a jacket.

[0051] FIG. 3 shows another example of the method for subterranean CO2 storage according to the present invention, wherein the well is placed subsea.

[0052] FIG. 4 shows an example of the method for subterranean CO2 storage, according to a closed-in system state.

[0053] FIG. 5 shows an example of the method for subterranean CO2 storage, according to a conditioning state.

[0054] FIG. 6 shows an example of the method for subterranean CO2 storage, according to a conditioned CO2 injection state.

[0055] Detailed description

[0056] The invention will now be described in detail without limitation in the following description. It is provided a method for subterranean CO2 storage. The method successively (i.e. one step after the other) comprises a conditioning step and an injection step. The conditioning step comprises flowing liquid CO2 in a closed subsea loop. The liquid CO2 flows from an inlet of a first subsea flow line to an outlet of the first subsea flow line, and back to the inlet of the first subsea flow line through at least one second subsea flow line. The liquid CO2 is heated by a heater positioned on the first subsea flow line. The injection step comprises flowing liquid CO2 from a CO2 storage tank, through the first subsea flow line, to an injection well, and injecting the liquid CO2 into the injection well. The liquid CO2 is heated by the heater.

[0057] The conditioning step prepares the first subsea flow line (and optionally the second subsea flow line) to be in a suitable condition for injection of the liquid CO2 into the injection well. By flowing liquid CO2 in a closed subsea loop, the liquid CO2 can pass, at least once (for example, multiple times), by the heater so that the heater can heat the liquid CO2 as often as is necessary, so that the liquid CO2 can attain a predetermined temperature value.

[0058] The liquid CO2 flows from an inlet of a first subsea flow line to an outlet of the first subsea flow line and back to the inlet of the first subsea flow line through at least one second subsea flow line. In other words, during the conditioning, the first flow line and at least one second flow line can together circulate the CO2. The first flow line and the at least one second subsea flow line therefore together form the closed loop.

[0059] The liquid CO2 is heated by a heater positioned on the first subsea flow line. The heater may for example be an electric heater, or for example a fired heater (e.g. gas burner or diesel burner). The heater may be positioned, close to the inlet of the first subsea flow line. The heater may be positioned close to the CO2 storage tank, for example less than 500 m, or less than 100 m, or less than 50 m, or less than 20 m, or less than 10 m from the CO2 storage tank.

[0060] The injection step is after the conditioning step. In other words, the injection can follow once the subsea flow line(s) is(are) conditioned to a desired temperature (above sea temperature) for injection. In this step, liquid CO2 flows from a CO2 storage tank, through the first subsea flow line, to an injection well.

[0061] The injection well is one leading to a subterranean storage reservoir. By subterranean CO2 storage, it is meant the storing of CO2 in a subterranean reservoir. A subterranean reservoir may be a hydrocarbon reservoir within a subterranean formation. This hydrocarbon reservoir may be partly, substantially or fully depleted - i.e. the hydrocarbons in the reservoir may have been previously produced at the time the method of the invention is implemented. A reservoir is an underground portion wherein a fluid such as CO2 or hydrocarbons can be contained without substantially diffusing to neighboring portions. In this respect, the reservoir can be considered as a geological enclosure within a subterranean formation. For example, the neighboring portions may be made of rock material having a lower porosity than the rock material of the reservoir itself. In some variations, a layer of clay may be present above the reservoir. In some variations, a water-containing layer may be present below the reservoir. In some variations, the reservoir may be partly delimited by a crack creating a porosity discontinuity through which a fluid may not easily flow.

[0062] The reservoir may be of an elongated shape, with for example, a height of from 20 to 300 m and / or a lateral dimension of from 2 km to 15 km, for example from 3 to 10 km. The reservoir, if positioned offshore, may be found at a depth below sea level that is, for example, greater than 1 km such as from 2 km to 4 km or of such order.

[0063] A “subterranean formation" is defined in relation to the nature of the rock from which it is formed. A subterranean formation may comprise multiple reservoirs. Reservoirs may belong to different types of subterranean formation, such as but not limited to those of different materials, for example, limestone or sandstone. The reservoirs mentioned herein may belong to a same subterranean formation or to different subterranean formations. In any case, they are separated from each other by a boundary so that fluid may not flow between reservoirs.

[0064] FIG. 2 and FIG. 3 each provide an example of the method and installation according to respective embodiments. As seen in FIG. 2 an injection well 124 may be connected topside to a subterranean reservoir 116 with the support of a jacket 122, the point of injection thereby being above the surface of the seawater 112. Meanwhile, as seen in FIG. 3, the injection well 124 may not extend higher than the seabed 114, meeting a subsea wellhead 123. The subterranean reservoir 116 may be a depleted pressure or partially depleted pressure oil or gas reservoir.

[0065] The installation 150 comprises at least one first subsea flow line 108 having an inlet 132 and an outlet 130. The second subsea flow line 110 fluidically connects the outlet 130 of the first subsea line 108 to the inlet 132 of the first subsea line 108. For the conditioning step, liquid CO2 flows in a closed subsea loop from the inlet 132 of the first subsea flow line 108 to the outlet 130 of the first subsea flow line. In both examples of FIG. 2 and FIG. 3, the closed subsea loop is figuratively represented by loop 120. The liquid CO2 flows back to the inlet of the first subsea flow line through at least one second subsea flow line 110.

[0066] The examples of FIG. 2 and FIG. 3 illustrate use of one second subsea flow line. However, the installation may comprise more than one second subsea flow line 110, the method comprising flowing the liquid CO2 back through each of second subsea flow line 110 to the inlet of the first flow lie 108.

[0067] Alternatively, there can be more than one first subsea flow line 108, which may be associated with a single second subsea flow line 110; or which may each be associated with a respective second subsea flow line 110.

[0068] The liquid CO2 is heated by a heater 106 positioned on the first subsea flow line 108. The heater 106 may for example be a heater with a power lying from 2 MW to 20 MW, for example 5 MW heater. The heater 106 may be a gas heater. The heater 106 may heat the liquid CO2 to a predetermined temperature.

[0069] The conditioning step is continued until the temperature at one or more points of the first subsea flow line and / or second subsea flow line has increased to a sufficient level. This may then allow for injection to start, the temperature of the liquid CO2 in the line(s) being considered to be high enough for injection. Fresh liquid CO2 flowing from the storage tank during the injection phase may also be heated by the heater which continues to operate, so that the liquid CO2 is at a temperature for which it is suitable for injection. Implementing of the conditioning step may therefore only be for a startup procedure or sequence.

[0070] During the conditioning step, the CO2 may flow from the inlet 132 of the first subsea flow line 108 to the outlet 130 of the first subsea flow line 108, and back to the inlet 132 of the first subsea flow line 108 through the at least one second subsea flow line 110, a number of times (e.g. repeatedly). The CO2 may continue to flow through the closed subsea loop (i.e. may continue to undergo the conditioning step) until, by repeatedly passing the heater, it reaches a desired temperature equal than or greater to an injection temperature at one or more points along the line(s).

[0071] The injection step comprises flowing liquid CO2 from a CO2 storage tank 102, through the first subsea flow line 108, to an injection well 124. The injection well 124 may have a pressure lying from 4 MPa to 40 MPa, or for example from 7 MPa to 35 MPa. The pressure may be greater than or equal to a pressure below which the CO2 becomes a vapor. This pressure may vary as the pressure may build up in the reservoir 116 during injection. The inlet 132 of the first subsea flow line 108 is fluidically connected to the CO2 storage tank 102. The outlet 130 of the first subsea flow line 108 is fluidically connected to the injection well 124. The method comprises injecting the liquid CO2 into the injection well 124. The heater 106 heats the liquid CO2 during the injection step, so that the liquid CO2 reaches a predetermined target injection temperature at the injection well, although the liquid CO2 tends to cool down when flowing from the heater to the injection well. The heating may thus comprise overheating the liquid CO2 to a temperature above that of a desired injection temperature, for example, a temperature greater than or equal to 35 °C, for a desired injection temperature lying from 10 °C to 50 °C, or for example from 20 °C to 30 °C.

[0072] The Installation comprises a pump 104 positioned on the first subsea flow line 108. During the conditioning step, the pump 104 may force the liquid CO2 through the first flow line 108 and at least one second flow line 110, or the closed loop as represented by the loop 120. During the injection step, the pump 104 may force liquid CO2 from the storage tank and through at least the first flow line.

[0073] The storage tank 102 may be part of a floating storage unit 100. The pump 104 may be located in the floating storage unit 100. The heater 106 may also be located in the floating storage unit 100.

[0074] In preferred embodiments, the installation 150 does not comprise any heater outside of the floating storage unit 100.

[0075] In preferred embodiments, the heater 106 is the only heater of the linked to the closed subsea loop, as represented by the loop 120. In other words, the heater 106 may be the only heater along both the first flow line 108 and the at least one second flow line 110.

[0076] Alternatively, according to some embodiments, there may be more than one heater 106, the heaters 106 being positioned at the same location on the first flow line 108. There may for example be two heaters 106 positioned at the same location on the first flow line 108. The heaters 106 positioned at the same location may be only heaters along both the first flow line 108 and the at least one second flow line 110. When two or more heaters are present, they may be all located within a distance of less than 20 m, or less than 10 m, or less than 5 m for example.

[0077] The floating storage unit 100 may be a part of a vessel that transports the liquid CO2 from the mainland or a location at which CO2 was captured, the vessel ferrying the liquid CO2 to within a certain proximity from the injection well 124.

[0078] According to some embodiments, a distance lying from 20 m to 10 km, for example from 500 m to 8 km, for example from 1 to 5 km or from 2 to 4 km, may lie between the storage tank 102 (for example, as part of a floating storage unit 100 of a vessel) and the at least one injection well 124. The distance may be a geometrical distance (or a distance as the crow flies between the storage tank 102 and the at least one injection well 124). A greater distance (for example from 3 km to 4 km, or from 2 to 3 km, or even up to 10 km) may lie between the storage tank 102 and the at least one injection well 124 if offloading (the liquid CO2) to an installation 150 wherein the well 124 is placed on a jacket 122 (as illustrated in FIG. 2). This may for example allow for accounting for a safety distance between the storage tank 102 and the jacket 122. Alternatively, a smaller distance (for example from 20 m to 1 km) may lie between the storage tank 102 and the at least one injection well 124 if offloading to a subsea installation 150 (as illustrated in FIG. 3).

[0079] The temperature of the liquid CO2 within the storage tank 102 may be from -50 °C to -20°C. The liquid CO2 exiting the storage tank 102 may initially be from -50 °C to -20°C. The liquid CO2 within the storage tank 102 may have a pressure from 1.5 MPa to 3 MPa, for example 2 MPa. The liquid CO2 exiting the storage tank may initially have a pressure from 1.5 MPa to 3 MPa, for example 2 MPa. The tank 102 may be selected taking into consideration the pressure and temperature of the liquid CO2. Liquid CO2 of a higher temperature may lead to a higher pressure which may lead to more complex and expensive tanks. Lower temperature of the liquid CO2 may lead to waste of energy.

[0080] Each of the first flow line 108 and the at least one second flow line 110 are subsea flow lines. Therefore, each line 108, 110, is at least partially below water 112. The sea 112 may have a temperature lying from 1 °C to 23 °C, for example from 4 °C to 20 °C.

[0081] According to some embodiments, the at least one second flow line 110 may comprise two second flow lines 110. One manifold may connect the multiple second flow lines 110 to the inlet 132 of the first flow line 108, and another manifold may connect the multiple second flow lines 110 to the outlet 130 of the first flow line 108.

[0082] According to some embodiments, the first flow line 108 and / or the second flow line 110 may be insulated. The first flow line 108 and second flow line 110 may be arranged as a pipe-in-pipe, the inner pipe being for example the first flow line and the outer piper being for example the second flow line.

[0083] Although only one injection well is shown on FIG. 2 and FIG. 3, a plurality of injection wells may be present. In this case the first flow line 108 may be connected to the plurality of injection wells via respective injection lines branching out from the first flow line 108, for example using a manifold. The plurality of injection wells may arranged within a same reservoir and / or within different reservoirs. The pressure in one injection lines may be different from the pressure in the other injection line(s). This can enable a versatile method for which each injection line can cater to the environmental conditions of the respective well to which it is fluidically connected. For example, the reservoir of one injection well may be a sandstone reservoir, while another reservoir of another injection well may be a chalk reservoir, each reservoir having different pressure conditions. Additionally or alternatively for example, part of one injection well may be tighter or broader than a part of another injection well, and therefore may have different need a higher or lower injection pressure than the other injection well.

[0084] FIG. 4 to FIG. 6 provide examples according to different phases throughout the method, according to some embodiments. FIG. 4 provides an example of the installation in a closed-in system state. FIG. 5 provides an example of the same installation during the conditioning step. FIG. 6 provides an example of the same installation during the injection step.

[0085] These embodiments have similar features to those of FIG. 2 and FIG. 3. Therefore, the above description of FIG. 2 and FIG. 3 applies similarly to the embodiments of FIG. 4 to FIG. 6 unless it is modified or superseded by the description below.

[0086] The installation 150 of FIG. 4 to FIG. 6 differs from the installation of FIG. 2 and FIG. 3 in that it is configured to inject CO2 into an injection well 124a and an additional injection well 124b. Besides, although the second flow line 110 may in some embodiments be used only for the conditioning step, and not for the injection step, in the installation shown in FIG. 4 to FIG. 6, the second flow line 110 is also used for the injection step.

[0087] The installation 150 may comprise a flow line branch 144 fluidically connecting the first flow line 108 to the second flow line 110. The flow line branch 144 may have a flow line branch inlet 142a at the junction with the first flow line 108 and a flow line branch outlet 142b at the junction with the second flow line 110. The junction with the first flow line 108 is between the inlet 132 and the outlet 130 of the first flow line. It preferably lies distally from the pump 104 and heater 106 (the term proximal meaning towards the CO2 storage tank 102 and the term distal meaning towards the injection well 124a). The junction with the second flow line 110 is preferably closer to the inlet 132 of the first flow line than to the outlet 130 of the first flow line.

[0088] A first injection line 146 may be fluidically connected to the first flow line 108, at a junction which is preferably between the inlet 132 and the outlet 130, and more preferably closer to the outlet 130. The first injection line 146 may also be fluidically connected to the injection well 124a.

[0089] A second injection line 140 may be fluidically connected to the second flow line 110. For example, it may be fluidically connected to the outlet 130 of the first flow line (where the second flow line 110 meets the first flow line 108). The second injection line 140 may be fluidically connected to the additional injection well 124b.

[0090] The installation 150 may comprise valves 118a, 118b, 118c, 118d, 118e, 118f, 118g, 118h, 118i at different locations along the installation to allow for the controlling of both the conditioning and injection steps. For example, a first injection valve 118c may be present along the first injection line 146.

[0091] A second injection valve 118e may be present along the second injection line 140.

[0092] A first loop valve 118d may be present on the second flow line, between the flow line branch outlet 142b and the inlet 132 of the first flow line.

[0093] A second loop valve 118h may be present on the first flow line, between the junction with the first injection line 146 and the outlet 130 of the first flow line.

[0094] A branch valve 118g may be present on the flow line branch 144.

[0095] One or more first flow line valves 118f , 118a may be present on the first flow line, between the flow line branch inlet 142a and the junction with the first injection line 146. One first flow line valve 118f may be an adjustable valve as will be described below. Another or the other flow line valves 118a may be an on-off valve.

[0096] One or more second flow line valves 118b, 118i may be present on the second flow line, between the outlet 130 of the first flow line and the flow line branch outlet 142b. One second flow line valve 118i may be an adjustable valve as will be described below. Another or the other flow line valves 118b may be an on-off valve.

[0097] For the closed-in state of FIG. 4, all of the valves 118a, 118b, 118c, 118d, 118e, 118f , 118g, 118h, 118i may be closed. FIG. 4 may represent the state of the installation after an installation 150 shutdown and / or prior to a startup phase. This may therefore illustrate a scenario prior to the conditioning and injecting of the method. For such a scenario, most or all of the flowlines 108, 110 (and therefore any CO2 within the lines 108, 110) may be substantially at seawater temperature. The square 114 may represent the seawater in which (the major part of) each flow line 108, 110 may lie.

[0098] The conditioning step may represent a startup phase for injection. The conditioning step may begin after a system or installation shutdown (i.e. a period during which there is no injection).

[0099] At the start of a conditioning step, the method may comprise opening some valves. That is to say, the method may comprise opening valves along the closed subsea loop, including at least one valve along the first flow line 108 and at least one valve along the at least one second flow line 110. In the illustrated embodiment, the first flow line valves 118f, 118a, the second flow line valves 118b, 118 i, the first loop valve 118d and the second loop valve 118h are opened. The branch valve 118g, the first injection valve 118c and the second injection valve 118e remain closed. The arrow 115 represents the direction of flow of the CO2 during the conditioning step.

[0100] When the pump is operated, liquid CO2 (which has previously already filled the lines) flows from the inlet 132 of the first flow line, through the first flow line 108 to the outlet of the first flow line, then through the second flow line 110 and back to the inlet 132 of the first flow line. The liquid CO2 may flow back to the inlet 132 via the tank 102 ( / .e. the liquid CO2 may flow from the second flow line 110 back to the tank 102 and then from the tank back to the inlet 132 of the first flow line 108 - not shown on the drawings). Alternatively, the liquid CO2 may directly flow back to the inlet 132 of the first flow line 108 without going through the tank 102 as illustrated, for example in FIG. 2, FIG. 3 and FIG. 5.

[0101] The above valves are kept open during the conditioning step, until the temperature of the liquid CO2 reaches a temperature high enough for passing to the injection step.

[0102] For the injecting step, some valves are kept open, others are opened and others are closed.

[0103] In the illustrated embodiment, the first flow line valves 1 18f, 118a and the second flow line valves 118b, 118i are kept open. The first loop valve 118d and the second loop valve 118h are closed. And the branch valve 118g, the first injection valve 118c and the second injection valve 118e are opened.

[0104] When the pump is operated, liquid CO2 flows from storage tank 102 through the first flow line 108. Part of the flow is diverted to the second flow line 110 via the flow line branch 144. The liquid CO2 flows from the first flow line 108 to the first injection line 146 and the injection well 124a, as schematically indicated by the arrow 117; and concurrently from the second flow line 110 to the second injection well 124b.

[0105] As can be seen in each figure FIG. 4 to FIG. 6, the method may comprise taking flow rate measurements along the first flow line 108 and / or second flow line 110. A flow meter 128a may take flow rate measurements along the first flow line 108. A flow meter 128b may take flow rate measurements along the second flow line 110. The first flow line 108 may further comprise an adjustable valve 118f . The adjustable valve 118f may be at least partially (for example, fully) open during the condition and injecting. The second flow line 110 may further comprise an adjustable valve 118i. The adjustable valve 118f may be at least partially (for example, fully) open during the condition and, according to some embodiments, the injecting. Each flow meter 128a, 128b and each adjustable valve 118f , 118i may be part of a respective flow control unit. The control unit may lie on the vessel / tanker / floater. The control unit can allow for adjusting the flow rate along either or both line(s) 108, 110. Depending on the measured flow rate, the method may comprise adjusting either or both the adjustable valve(s) 118f, 118i so as to adjust the flow rate within the respective line 108, 110.

[0106] The method may comprise taking temperature measurements along the first flow line 108 and / or along the second flow line 110. The first flow line 108 may comprise at least one temperature sensor 136a, 136c for taking the temperature measurements along the first flow line 108. At least one temperature sensor 136a may be positioned in proximity to and after the heater 106, so that the temperature of the liquid CO2 can be monitored just after heating. Additionally or alternatively, the first flow line 108 may comprise another temperature sensor 136c for taking the temperature measurements along the first flow line 108. The other temperature sensor 136c may be positioned close to the outlet 130, such as between the junction with the first injection line 146 and the outlet 130. This can allow for monitoring the temperature of the liquid CO2 during the conditioning step before it flows back towards the inlet 132 of the first flow line 108.

[0107] The second flow line 110 may comprise at least one temperature sensor 136b for taking the temperature measurements along the second flow line 110.

[0108] At least one temperature sensor 136a of the first flow line 108 and / or at least one temperature sensor 136b of the second flow line 110 may lie on the floating storage unit. The method may for example comprise constantly measuring the temperature of the liquid CO2 during the conditioning step until a stabilized temperature is achieved. If this stabilized temperature is high enough (i.e. reaches a predetermined temperature value), the installation may be considered to be in a suitable condition for passing to the injection step. Once the conditioning step is completed (for example, as a startup step), the heater 106 may be able to compensate for any temperature drops experienced by the liquid CO2 in the installation 150 downstream for the heater

[0109] The method may comprise taking temperature measurements at the injection well 124a (for example along the first injection line 146) and / or the additional injection well 124b (for example along the second injection line 140). A temperature sensor 136d, 136e may be positioned at each respective well 124a, 124b. This can allow for monitoring of the temperature of the liquid CO2 at or close to the injection point during the injection step.

[0110] The method may comprise taking pressure measurements along the first flow line, for example during the conditioning step. This may be done owing to a pressure sensor 138c positioned between the junction with the first injection line 146 and the outlet 130 of the first flow line 108. Additionally or alternatively, the method may comprise taking pressure measurements at the injection well 124a (for example along the first injection line 146) and / or the additional injection well 124b (for example along the second injection line 140). A pressure sensor 138a, 138b may be positioned at each respective well 124a, 124b or on each respective injection line 146, 140. This can allow for monitoring of the pressure of the liquid CO2 during the injection step.

[0111] The flow rate, temperature and pressure measurements mentioned above may be used as input to a control unit configured for controlling the installation. The control unit may for example adjust the operation of the pump, of the heater, and may control the state of the various valves, so as to command the transition from the conditioning step to the injection step, and to control the performance of each of these steps.

[0112] As described above in connection with FIG. 2 and FIG. 3, also in the installation of FIG. 4 to 6 a plurality of injection wells may be present instead of the single injection well 124a and / or instead of the single additional injection well 124b described above. In this case, the first injection line 146 may be replaced by a plurality of first injection lines, and / or the second injection line 140 may be replaced by a plurality of second injection lines. A respective manifold as a connector between the first flow line 108 and the various first injection lines, and between the second flow line 110 and the various second injection lines.

[0113] Thus, the injection step may comprise flowing liquid CO2 from the CO2 storage tank 102, through the first subsea flow line 108, to multiple injection wells 124a (not shown), and injecting the liquid CO2 into the multiple injection well(s) 124a.The injection step may comprise flowing liquid CO2 from the CO2 storage tank 102, through the second subsea flow line 110, to multiple additional injection wells 124b (not shown), and injecting the liquid CO2 into the multiple additional injection well(s) 124b.

Claims

Claims1. A method for subterranean CO2 storage, the method successively comprising: a) a conditioning step of flowing liquid CO2 in a closed subsea loop, from an inlet of a first subsea flow line to an outlet of the first subsea flow line, and back to the inlet of the first subsea flow line through at least one second subsea flow line, the liquid CO2 being heated by a heater positioned on the first subsea flow line; b) an injection step of flowing liquid CO2 from a CO2 storage tank, through the first subsea flow line, to an injection well, and injecting the liquid CO2 into the injection well, the liquid CO2 being heated by the heater.

2. The method according to claim 1 , wherein heating the liquid CO2 comprises heating the liquid CO2 to a temperature above that of a desired injection temperature, for example, a temperature greater than or equal to 35 °C, for a desired injection temperature lying from 10 °C to 50 °C.

3. The method according to claim 1 or 2, wherein liquid CO2 is injected into multiple injection wells via a first manifold fluidically connecting the first subsea flow line to multiple first injection line, each first injection line being connected to a respective injection well.

4. The method according to any one of claims 1 to 3, wherein the pressure in at least one of the first injection lines is different from the pressure in the other first injection lines.

5. The method according to any one of claims 1 to 4, wherein the injection step further comprises flowing liquid CO2 from the CO2 storage tank, through the second subsea flow line, to one or more additional injection wells, and injecting the liquid CO2 into the additional injection well(s).

6. The method according to claim 5, wherein the injection step comprises flowing some of the heated liquid CO2 from the first subsea flow line to the second subsea flow line, and then to the additional injection well(s).

7. The method according to claim 5 or 6, wherein liquid CO2 is injected into multiple additional injection wells via a second manifold fluidically connecting the second subsea flow line to multiple second injection lines, each second injection line being connected to a respective injection well.

8. The method according to claim 7, wherein the pressure in at least one of the second injection lines is different from the pressure in the other injection lines.

9. The method according to any one of claims 1 to 8, comprising taking temperature measurements along the first subsea flow line and / or second subsea flow line and / or at the injection well.

10. The method according to any one of claims 1 to 9, comprising taking pressure measurements at the injection well.

11. The method according to any one of claims 1 to 10, wherein the injection well has a pressure from 4 MPa to 40 MPa.

12. The method according to any one of claims 1 to 11 , wherein a distance from 20 m to 10 km, for example from 1 km to 5 km, lies between the storage tank and the at least one injection well.

13. The method according to any one of claims 1 to 12, wherein the liquid CO2 exiting the storage tank initially has a temperature from -50 °C to - 20°C.

14. The method according to any one of claims 1 to 13, wherein the liquid CO2 exiting the storage tank initially has a pressure from 1 .5 MPa to 3 MPa.

15. The method according to any one of claims 1 to 14, wherein the method comprises taking flow rate measurements along the first subsea flow line and / or second subsea flow line and / or at the injection well.

16. The method according to any one of claims 1 to 15, wherein the storage tank is part of a floating storage unit, preferably part of a vessel.

17. The method according to claim 16, wherein the heater is on the floating storage unit, and wherein preferably there is no heater out of the floating storage unit.

18. An installation for subterranean CO2 storage, the installation comprising at least one first subsea flow line (108) having an inlet (132) and an outlet (130), at least one second subsea flow line (110), a heater (106) positioned on the first subsea flow line (108) and a pump (104) positioned on the first subsea flow line (108), wherein:- the inlet (132) of the first subsea flow line (108) is fluidically connected to a CO2 storage tank (102);- the outlet (130) of the first subsea flow line (108) is fluidically connected to an injection well (124);- the second subsea flow line (110) fluidically connects the outlet (130) of the first subsea flow line (108) to the inlet (132) of the first subsea flow line (108).

19. The installation according to claim 18, comprising a first manifold fluidically connecting the first subsea flow line (108) to multiple first injection lines, each first injection line being connected to a respective injection well.

20. The installation according to any one of claims 18 to 19, wherein the at least one second subsea flow line (110) is fluidically connected to an additional injection well (124b).

21. The installation according to claim 20, comprising a flow line branch (144) comprising a branch inlet (142a) fluidically connected to the first flow line (108), and a branch outlet (142b) fluidically connected to the second flow line (110).

22. The installation according to claim 20 or 21 , comprising a first injection line (146) fluidically connecting the first subsea flow line (108) to the injection well (124a) and a second injection line (140) fluidically connecting the second subsea flow line (110) to the additional injection well (124b).

23. The installation according to any one of claims 20 to 22, comprising a second manifold fluidically connecting the second subsea flow line(110) to multiple second injection lines, each second injection line being fluidically connected to a respective additional injection well.

24. The installation according to any one of claims 18 to 23, wherein the installation comprises at least one temperature sensor configured to take temperature measurements along the first subsea flow line and / or second subsea flow line and / or at the injection well and / or additional injection well.

25. The installation according to any one of claims 18 to 24, wherein the installation comprises at least one pressure sensor configured to take pressure measurements at the injection well and / or additional injection well.

26. The installation according to any one of claims 18 to 25, wherein a distance from 20 m to 10 km, for example from 1 km to 5 km, lies between the storage tank (102) and the injection well (124).

27. The installation according to any one of claims 18 to 26, wherein the installation comprises at least one flow meter configured to take flow rate measurements along the first subsea flow line (108) and / or second subsea flow line (110).

28. The installation according to any one of claims 18 to 27, wherein the installation is configured to control a flow rate and a pressure of the CO2 by adjusting at least one valve along the first subsea flow line and / or second subsea flow line.

29. The installation according to any one of claims 18 to 28, wherein the storage tank (102) is part of a floating storage unit (100), preferably part of a vessel.

30. The installation of claim 29, wherein the heater (106) is in the floating storage unit (100), and optionally wherein there is no heater out of the floating storage unit (100).

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