WO2023175364A1

WO2023175364A1 - Method for carbon dioxide injection into a subterranean reservoir

Info

Publication number: WO2023175364A1
Application number: PCT/IB2022/000117
Authority: WO
Inventors: Søren Mylius DAVIDSEN
Original assignee: Totalenergies One Tech
Priority date: 2022-03-15
Filing date: 2022-03-15
Publication date: 2023-09-21

Abstract

The present invention relates to a method for CO₂ storage, the method comprising injecting a CO₂ composition into a well of a subterranean reservoir, wherein the CO₂ composition is formed by combining a stream of vapor CO₂ and a stream of liquid CO₂ at a vapor CO₂ to liquid CO₂ ratio, wherein the vapor CO₂ to liquid CO₂ ratio varies over time. The invention also relates to an installation for CO₂ storage.

Description

METHOD FOR CARBON DIOXIDE INJECTION INTO A SUBTERRANEAN RESERVOIR

Technical field

The present invention relates to the field of CO2 storage, and more specifically to a method for CO2 storage, the method comprising injecting a CO2 composition into a well of a subterranean reservoir and varying the vapor CO2 to liquid CO2 ratio of the composition over time.

Technical background

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. 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 in the well. The thermal shock may additionally and/or alternatively create a fracture in the reservoir itself or the formation above the reservoir.

What’s more, injection well bottomhole pressure is subject to a lot of variation over the course of injection, making it difficult to continuously provide CO2 in a manner that allows for accurately overcoming the bottomhole pressure. These pressure fluctuations result in an unstable well flow during CO2 injection. This in turn can also lead to fractures in the well and may result in hydrate formation near the well, which may plug CO2 flow paths. Even if a method of applying constant high pressure injection to the well was adopted as a means to overcome the bottomhole pressure, drawbacks are also faced as there is also a danger that a constant high pressure will too result in reservoir fractures. In addition, from a purely operational point of view, unstable flow results in a number of injection start and stop challenges, which can lead to significant delays in CO2 injection and increased costs overall. A number of efforts have been made to overcome some of these shortcomings, such as preheating the CO2, employing only continuous injection modes, recompleting the well via a friction tube, a downhole choke and/or making use of low temperature equipment.

Document US 2012/0038174 A1 relates to the coupling of CO2 geological storage with methane and/or heat production (geothermal energy) from geopressured-geothermal aquifers. The production of energy from the extracted brine is used to offset the cost of capture, pressurization and injection and the subsequent injection of brine containing carbon dioxide back into the aquifer.

Document JP 5267810 B2 relates to determining the mass ratio of undissolved carbon dioxide to be mixed into water saturated with carbon dioxide through a number of steps so that a first storage zone for storing undissolved carbon dioxide together with water saturated with carbon dioxide is formed around the circumference of an injection well in an aquifer and a second storage zone for exclusively storing water saturated with carbon dioxide is roughly concentrically formed in a manner of surrounding the first storage zone in the aquifer respectively, under a condition of storing/isolating water saturated with carbon dioxide as well as undissolved carbon dioxide.

The article of Fabian Moller et al. (Injection of CO2 at ambient temperature conditions - Pressure and temperature results of the “cold injection” experiment at the Ketzin pilot site), 2014 (doi: 10.1016/j.egypro.2014.11 .660) relates to a “cold injection” experiment carried out between March and July 2013 to study the effects of lower pre-conditioning temperature and effects of potential two-phase flow on the injection process. The injection wellhead temperature was decreased stepwise from 40 °C down to 10 °C. Below 20 °C two-phase flow developed in the surface installations and in the injection well down to the reservoir and a mixture of gaseous and liquid CO2 was injected.

Within this context, there is still a need to provide a method for storing CO2 in a controlled and efficient manner.

Summary of the invention It is therefore an object of this invention to provide a method for CO2 storage, the method comprising injecting a CO2 composition into a well of a subterranean reservoir, wherein the CO2 composition is formed by combining a stream of vapor CO2 and a stream of liquid CO2 at a vapor CO2 to liquid CO2 ratio, wherein the vapor CO2 to liquid CO2 ratio varies over time.

According to some embodiments, the method comprises a step of measuring a flow rate of the stream of liquid CO2 and/or a flow rate of the stream of vapor CO2 during injection into the subterranean reservoir and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

According to some embodiments, the method comprises a step of initially injecting only a stream of vapor CO2 into the well.

According to some embodiments, the vapor CO2 to liquid CO2 ratio gradually decreases over time.

According to some embodiments, the method comprises a subsequent step of injecting only liquid CO2 into the well.

According to some embodiments, the topside pressure of the CO2 composition during injection, at the inlet of the injection well, initially lies between 3 MPa and 7 MPa, for example between 3.5 MPa and 4.5 MPa.

According to some embodiments, the topside temperature of the CO2 composition, at the inlet of the injection well, lies between 0 °C and 30°C, for example between 5°C and 10°C.

According to some embodiments, the subterranean reservoir is at an initial pressure between 2 MPa and 20 MPa, in particular between 2 MPa and 7 MPa.

According to some embodiments, adjustments to the vapor CO2 to liquid CO2 ratio are made in real-time.

According to some embodiments, the method comprises a step of directly measuring the bottomhole pressure in the well and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

According to some embodiments, the method comprises a step of measuring a topside temperature and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

According to some embodiments, the method comprises a step of measuring a topside pressure in the well and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

According to some embodiments, the vapor CO2 is obtained by evaporating liquid CO2 by means of an evaporator.

According to some embodiments, the well has a length that lies between 100 m and 5 km, for example between 2 km and 4 km. According to some embodiments, the CO2 composition comprises other compounds, such as nitrogen or hydrocarbons, for example, methane, ethane, propane and/or heavier hydrocarbons in addition to CO2 .

According to some embodiments, the subterranean reservoir is onshore or offshore.

Another object of the invention is an installation for CO2 storage, the installation comprising:

- an injection well in a subterranean reservoir;

- a liquid CO2 injection line connected to an inlet of the injection well;

- a vapor CO2 injection line connected to an inlet of the injection well;

- a flow meter and an adjustable valve positioned along either or both of the liquid CO2 injection line and vapor CO2 injection line;

- a control unit configured to modify a ratio of vapor CO2 to liquid CO2 fed to the injection well.

According to some embodiments, at least one pressure sensor is positioned along the well and/or at at least one bottomhole location.

According to some embodiments, at least one temperature sensor is positioned along the well and/or at at least one bottomhole location.

According to some embodiments, an evaporator is positioned along the vapor CO2 injection line, configured to evaporate liquid CO2 into vapor CO2 .

The present invention makes it possible to address the need mentioned above. In particular, the invention provides a method for CO2 storage that is controlled and efficient.

This is achieved by varying the vapor CO2 to liquid CO2 ratio for making the injected CO2 composition over time. Vapor CO2 and liquid CO2 each provide different characteristics that result in different CO2 flow properties.

The vapor phase in the composition initially adds compression heat towards the well head. Heat is also released to the well as the vapor starts to condense. As the composition moves through the well, the vapor further adds friction heat to the well. The vapor phase reduces the static pressure in the well and hence the bottomhole pressure.

Meanwhile the liquid phase increases the pressure in the well and hence the flow rate. It also reduces the temperature compared to vapor in the well due to its lower compressibility. As the composition moves further through the well, the liquid may start to evaporate, reduce the injection velocity and increase friction with the well. However overall, the liquid phase increases the static gradient and hence the downhole pressure. Therefore, by varying the vapor CO2 to liquid CO2 ratio when making the CO2 composition to be injected, the correct balance can be achieved in matching or indeed overcoming a given bottomhole pressure.

Given that the vapor CO2 to liquid CO2 ratio can be varied over time, for example to continuously overcome the bottomhole pressure, sub-zero temperature conditions in the well can be avoided, the risk of the formation of hydrates near the well can be eliminated or significantly reduced, and the occurrence of fractures in the well due to high pressure injection can be mitigated. The method also therefore allows for the same equipment to be re-used without the need for new equipment. In addition, as the CO2 composition can be varied so as to only be injected at pressures necessary to overcome bottom pressure, the overall energy consumption of the system is reduced and additional substances are not needed to be mixed with the CO2 composition to assist injection.

Advantageously and according to some embodiments, the method may comprise a step of measuring a CO2 flow rate during injection into the subterranean reservoir and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement. As flow rate can be used to calculate pressure in the well and bottomhole pressure, flow can be easily controlled via adjustments made to the vapor CO2 to liquid CO2 ratio which may, for example, be made in real-time and without the need of additional pressure sensors in the well or downstream of the well. Close control of the well facilitates stable flow, and so challenges regarding regular injection start, stop and batch modes can be overcome.

Brief description of the drawings

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

FIG. 1 shows an illustration of an example of an installation according to an embodiment.

FIG. 2 shows pressure (Y-axis, in kPa) as a function of well length (X-axis, in m) for a range of vapor CO2 to liquid CO2 ratios. The percentages indicate the CO2 liquid fraction in the CO2 composition.

FIG. 3 shows temperature (Y-axis, in °C) as a function of well length (X- axis, in m) for a range of vapor CO2 to liquid CO2 ratios. The percentages indicate the CO2 liquid fraction in the CO2 composition.

FIG. 4 schematically shows a typical evolution of the fraction of liquid CO2 flow rate relative to the total of liquid and vapor CO2 flow rates (Y-axis) over a start to stop operation (X-axis). The symbols V, L and V+L indicate the vapor CO2 phase, liquid CO2 phase and two-phase CO2 respectively along the injection well.

Detailed description

The invention will now be described in more detail without limitation in the following description.

The method of the present invention is implemented by injecting a CO2 composition into a well (injection well) of a subterranean reservoir. The composition is formed by combining a stream of vapor CO2 and a stream of liquid CO2 at a vapor CO2 to liquid CO2 ratio. The vapor CO2 to liquid CO2 ratio varies over time.

A “CO2 composition" refers to a fluid comprising CO2. The composition may comprise one or more phases of CO2, selected from a liquid phase, a gaseous phase and a supercritical phase. The physical state of the CO2 composition may change along the injection well, between the point where it is formed by combining the streams and the bottom of the well. Thus, the CO2 composition may comprise a liquid CO2 phase and a gaseous CO2 phase. The CO2 composition may alternatively comprise a liquid CO2 phase and a supercritical CO2 phase. The CO2 composition may alternatively comprise a gaseous CO2 phase and a supercritical CO2 phase. The CO2 composition may alternatively comprise a gaseous CO2 phase, a liquid CO2 phase and a supercritical CO2 phase.

The CO2 composition may consist essentially of CO2, or even consist of CO2. Alternatively, the CO2 composition may additionally comprise other compounds, such as nitrogen or hydrocarbons, for example, methane, ethane, propane and/or heavier hydrocarbons in addition to CO2. Preferably, the weight proportion of CO2 in the CO2 composition is at least 80%, more preferably at least 90%, even more preferably at least 95%.

A “stream of vapor CO2 and a “stream of liquid CO2 refer to a respective run or flow of a fluid in a particular direction, the direction being towards the head of the injection well. The two streams are separate before being combined. The CO2 vapor stream and the CO2 liquid stream may be obtained from the same source. Alternatively, the streams may be obtained from different sources. Both streams may originate from the same initial stream wherein one or both of the streams undergo a step or steps of preconditioning before becoming the stream of vapor CO2 and the stream of liquid CO2. For example, if the initial stream contains only liquid CO2, a portion of the liquid may be diverted and evaporated to form a separate stream of vapor CO2. Similarly, if the initial stream contains only vapor CO2, a portion of the vapor may be diverted and condensed to form a separate stream of liquid CO2.

A “vapor CO2 to liquid CO2 ratio" refers to the weight ratio of the stream of vapor CO2 relative to the stream of liquid CO2 in the combination.

The CO2 composition itself, when formed, may be for example liquid, or vapor, or a biphasic liquid/vapor mixture. The stream of vapor CO2 and the stream of liquid CO2 may be in different conditions of temperature and pressure prior to combining. In this case, upon combining the streams, there may be a rapid transition to equilibrium, and the relative proportion of liquid and vapor may change. The state of the CO2 composition at the top of the injection well is thus dictated by the pressure and temperature at this point.

The subterranean reservoir may be offshore or onshore, or partly offshore and partly onshore.

The subterranean reservoir may in particular refer to a hydrocarbon reservoir. 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.

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.

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 subterranean reservoir may have an initial pressure between 2 MPa and 20 MPa (in particular between 2 MPa and 7 MPa) and an initial temperature between 70°C and 200°C. By “initial” it is meant before the method according to the invention is implemented, since the implementation of the method may modify the pressure and temperature within the subterranean reservoir. The temperature of the reservoir may decrease with the addition of the injected CO2 composition when the method of the invention is implemented, and then may increase again up to its initial value (due to the conditions of the surrounding area of the reservoir). The pressure of the reservoir may increase with the addition of the injected CO2 composition, when the method of the invention is implemented, optionally up to the pressure value that the reservoir had prior to hydrocarbon depletion, such as, for example, a value lying between 10 MPa and 70 MPa after a filling period of 2 to 20 years, or of such order. Preferably, the injection of the CO2 composition is stopped when the pressure in the reservoir reaches the pressure value prior to hydrocarbon depletion, in order to avoid damaging the reservoir.

Referring to an embodiment as illustrated in FIG. 1 , a CO2 composition is injected into a subterranean reservoir 100 by combining a stream of liquid CO2 and a stream of vapor CO2. Both streams may be supplied from the same source 102, for example in the form of liquid CO2, before being transported (for example, by means of a pump 104) along a vapor injection line 106 and a liquid injection line 107 to an inlet of the injection well 110. Both the vapor injection line 106 and the liquid injection line 107 may branch out from a common injection line 103. The pump 104 may be provided on the common injection line 103.

In the event of the CO2 for vapor injection being initially in the form of a liquid (in the common injection line), the vapor injection line 106 may first pass the fluid through an evaporator 112 to vaporize the liquid. According to some embodiments the method may include a step of initially injecting only a stream of vapor CO2 into the well.

The vapor injection line 106 may be equipped with a first flow meter 114 and a first adjustable valve 118. The first flow meter 114 may measure a flow rate of the stream of vapor CO2 during injection into the subterranean reservoir 100. The rate of flow itself of the stream of vapor CO2 may be adjusted via operation of the first adjustable valve 118 which may be positioned after the first flow meter 114. Flow may then be guided to the inlet of the injection well 110. The first flow meter 114 may be a Coriolis flow meter or another type of flow meter.

The liquid CO2 injection line may be equipped with a second flow meter 116 and a second adjustable valve 120. The second flow meter 116 may measure a flow rate of the stream of liquid CO2 during injection into the subterranean reservoir 100. The rate of flow itself of the stream of liquid CO2 may be adjusted via operation of the second adjustable valve 120 which may be positioned after the second flow meter 116. Flow may then be guided to the inlet of the injection well 110. The second flow meter 116 may be a Coriolis flow meter or another type of flow meter.

Additionally or alternatively to the implementation of at least one of the above flow meters 114, 116 pressure and/or temperature may be monitored by one or more pressure and/or temperature sensors 122 that may be provided topside (the term “topside" meaning located above ground or above sea level), along the well and/or at at least one bottomhole location. In particular, a temperature sensor may be incorporated in or associated with each of the first flow meter 114 and second flow meter 116 (as a temperature measurement may be required for an accurate measurement of flow rate). The method may comprise a step of measuring a topside temperature and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement. Likewise, the method may comprise a step of measuring a topside pressure in the well and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

A control unit may be present to control the first adjustable valve 118 and the second adjustable valve 120 and therefore to adjust the vapor CO2 to liquid CO2 ratio. Said adjustment may be a partial or full adjustment according to a preset schedule (/.e. the adjustment may depend on the total amount of CO2 composition injected in the past). Additionally or alternatively, the adjustment may depend on input data fed to the control unit. In particular, data from the first flow meter 114 and/or the second flow meter 116 may be processed in the control unit to adjust the vapor CO2 to liquid CO2 ratio.

The sensor(s) 122 may supply measurements to the control unit, that may alternatively be used as a basis for control of at least one or both of the first adjustable valve 118 and the second adjustable valve 120. Alternatively, these measurements may be used in addition to measurements provided by the first flow meter 114 and/or second flow meter 116.

The control unit may be operated in a partly or fully automated manner. The control unit may be operated partly or fully based on input from an operator.

When both streams of liquid CO2 and vapor CO2 arrive at the injection well 110, they are combined to form the CO2 composition. The flow rate of the liquid CO2 stream may comprise between 0% and 100% of the total flow rate of the liquid CO2 stream plus vapor CO2 stream, such as between 5% and 15 %, such as approximately 10%, or between 15% and 25%, such as approximately 20%, or between 25% and 35%, such as approximately 30%, or between 35% and 45%, such as approximately 40%, or between 45% and 55%, such as approximately 50%, or between 55% and 65%, such as approximately 60%, or between 65% and 75%, such as approximately 70%, or between 75% and 85%, such as approximately 80%, or between 85% and 95%, such as approximately 90%. All proportions are given by weight.

In some steps of the method, only the stream of vapor CO2 may be provided, or only the stream of liquid CO2 may be provided. In particular, in an initial phase of the method, only the stream of vapor CO2 may be provided. In particular, in a non-initial phase of the method, only the stream of liquid CO2 may be provided. This can be obtained by keeping the second adjustment valve 120 shut or by keeping the first adjustment valve 118 shut.

In some embodiments, the pressure of the CO2 composition during injection, at the inlet of the injection well, initially lies between 3 MPa and 7 MPa, for example between 3.5 MPa and 4 MPa. Additionally or alternatively, the temperature of the CO2 composition, at the inlet of the injection well, lies between 0 °C and 30°C, for example between 5°C and 15°C, or for example between 5 °C and 10 °C.

The relative proportion of the stream of liquid CO2 and of the stream of vapor CO2 varies over time. In addition, the total flow rate of the CO2 composition in the injection well varies over time. Generally, the lower the vapor CO2 to liquid CO2 ratio is, the larger the total flow rate is.

If desired, the method may include a determination of the bottomhole pressure via a flow rate, topside pressure and/or temperature measurement. The vapor CO2 to liquid CO2 ratio may then be adjusted depending on the determined bottomhole pressure. Alternatively, bottomhole pressure may be directly measured via a measurement made by a sensor positioned at the bottomhole. The vapor CO2 to liquid CO2 ratio may then be adjusted as a result of this measurement.

FIG. 2 displays the variation in pressure as a function of well length for pure vapor CO2, for CO2 compositions of varying vapor CO2 to liquid CO2 ratios and for pure liquid CO2, injected at a pressure at the inlet of the injection well of 4 MPa and a temperature at the inlet of the injection well of 5 °C. Pure vapor CO2 and CO2 compositions with lower liquid fractions can be seen to operate at lower pressures with a smaller pressure gradient for increased well length compared to pure liquid and CO2 compositions with higher liquid CO2 fractions. The opposite trend can be seen in FIG. 3 where pure vapor CO2 and CO2 compositions with higher liquid fractions can be seen to operate at higher temperatures for increased well length compared to pure liquid CO2 and CO2 compositions with higher vapor fractions. It can be seen how a combination of these characteristics may be harnessed by using CO2 compositions of different vapor CO2 to liquid CO2 ratios to influence the flow properties of CO2 during injection. For example, a CO2 composition containing 80% vapor CO2 and 20% liquid CO2 may be of use in cases where a lower pressure closer to the well head is desired, but a more dramatic pressure increase closer to the end of the well is needed.

FIG. 4 shows a typical evolution of injection from start to stop operations. The top of each bar represents the wellhead (inlet of the injection well) and the bottom of each bar represents the bottom end of the well (i.e. entry to the reservoir 100). At bar 1 , in an initial stage, the liquid CO2 injection line 107 may be shut and only CO2 vapor may be supplied to the well. Subsequently, from bar 2 to bar 7, liquid CO2 is injected, wherein the proportion of liquid CO2 combined with the vapor CO2 gradually increases. From bar 2 to bar 6, a stream of liquid CO2 and a stream of vapor CO2 are combined. At bar 7, the vapor CO2 injection line 106 may be shut, and only the stream of liquid CO2 is injected.

In some variations, the gradual decrease in the vapor CO2 to liquid CO2 ratio over time makes it possible to maintain the total flow rate of CO2 injection substantially constant over time, as the bottomhole pressure gradually increases. On the other hand, directly injecting only liquid CO2, or a biphasic composition having a high proportion of liquid CO2 at the beginning of the process is undesirable as, due to the low bottomhole pressure, this would generate low temperatures along the well, as described above. Therefore the method may comprise a subsequent step of injecting only liquid CO2 into the well. A stream of only liquid CO2 may be used late in the injection timeline when the reservoir has reached a high enough pressure. In some variations, the total flow rate may increase over time, and be maximal when only liquid CO2 is injected.

Variations in the vapor CO2 to liquid CO2 ratio over time may be incremental / stepwise, or may be continuous.

Instead of starting at bar 1 with only vapor CO2 injection, a mixed vapor CO2 / liquid CO2 injection may be used, if appropriate in view of the bottomhole pressure. Instead of reaching at bar 7 only liquid CO2 injection, a mixed vapor CO2 / liquid CO2 injection may be used, if appropriate in view of the bottomhole pressure. Therefore:

- The method may start with combining a stream of vapor CO2 and a stream of liquid CO2 at an initial vapor CO2 to liquid CO2 ratio, and progressively decreasing the vapor CO2 to liquid CO2 ratio over time down to a final vapor CO2 to liquid CO2 ratio.

- Or the method may start with injecting only a stream of vapor CO2 and no stream of liquid CO2, and then combining a stream of vapor CO2 and a stream of liquid CO2 at a vapor CO2 to liquid CO2 ratio, and progressively decreasing the vapor CO2 to liquid CO2 ratio over time down to a final vapor CO2 to liquid CO2 ratio.

- Or the method may start with combining a stream of vapor CO2 and a stream of liquid CO2 at an initial vapor CO2 to liquid CO2 ratio, and progressively decreasing the vapor CO2 to liquid CO2 ratio over time, and then discontinuing the flow of the stream of vapor CO2 so as to inject only the stream of liquid CO2.

- Or the method may start with injecting only the stream of vapor CO2 and no stream of liquid CO2, and then combining a stream of vapor CO2 and a stream of liquid CO2 at a vapor CO2 to liquid CO2 ratio, and progressively decreasing the vapor CO2 to liquid CO2 ratio over time, and then discontinuing the injection of the stream of vapor CO2SO as to inject only the stream of liquid CO2.

Each of the four evolutions noted above may span over a period of time of several months or years.

When the CO2 composition is formed (topside) at the inlet of the well, it may be monophasic (liquid or gas) or biphasic. For example, as shown in FIG.4, in bars 1 , 2, 3, the CO2 composition, when formed, is in the gas phase. In bar 4, it is biphasic. In bars 5, 6, and 7 , it is in the liquid phase.

Therefore, in some embodiments, the method of the invention may start with injecting a CO2 composition in the vapor phase (topside), followed by injecting a CO2 composition in a biphasic state (topside), followed by injecting a CO2 composition in the liquid phase. This evolution may span over a period of time of several months or years.

When the CO2 composition travels down the injection well, its physical state may change. From topside to bottom hole, the vapor CO2 to liquid CO2 ratio may increase or decrease, as liquid CO2 evaporates or as vapor CO2 condenses. CO2 may also be in the supercritical state along the injection well.

For example, as shown in FIG.4, in bar 1 , the CO2 composition remains in the vapor phase from top to bottom. In bars 2 and 3, the CO2 composition is initially in the vapor phase (top) and partially condenses to a mixed vapor/liquid state (bottom). In bar 4, the CO2 composition remains in a mixed vapor/liquid state from top to bottom. In bars 5 and 6, the CO2 composition is initially in the liquid phase (top) and partially evaporates to a mixed vapor/liquid state (bottom). In bar 7, the CO2 composition remains in the liquid phase from top to bottom.

Therefore, in some embodiments, the method of the invention may successively comprise: - injecting a CO2 composition which remains in the vapor phase from the top to the bottom of the injection well;

- injecting a CO2 composition which is in the vapor phase at the top of the injection well and which turns into a mixed vapor/liquid state along the injection well;

- injecting a CO2 composition which remains in a mixed vapor/liquid state along the injection well;

- injecting a CO2 composition which is in a mixed vapor/liquid state at the top of the injection well and which turns into a liquid state along the injection well;

- injecting a CO2 composition which remains in a liquid state along the injection well.

These successive steps may span over a period of time of several months or years.

When the flow of CO2 composition in the injection well is to be stopped, it is generally desirable to increase the vapor CO2 to liquid CO2 ratio and preferably transition to injecting only the stream of vapor CO2, (this can be referred to as the pre-stopping stage) before stopping the injection. Indeed, if the injection well is filled with liquid CO2 when the injection stops, the issues of sharp temperature decrease noted above may arise. The pre-stopping stage may be the final stage of the method, if the pressure in the reservoir has reached an appropriate level and no additional CO2 is to be injected; or it may be an intermediate or intermittent stage, as the injection may have to be transiently interrupted for example for servicing.

An example of a pre-stopping stage is represented from bar 8 to bar 13 on FIG. 4.

The duration of the pre-stopping stage may be from a few seconds to a few days. Preferably, it is from 1 min to 12 hours, more preferably from 2 min to 1 hour.

Although FIG. 4 shows a general tendency of typical evolution of vapor CO2 to liquid CO2 ratio over time, this ratio may also be adapted in real-time and may thus fluctuate. The evolution of the ratio may be a function of one or more of the following parameters:

- topside pressure (measured at the top of the injection well, either in real time or during interruptions of CO2 injection);

- bottomhole pressure (measured at the bottom of the injection well);

- flow rate of the stream of liquid CO2;

- flow rate of the stream of vapor CO2; - temperature (such as ambient temperature or temperature measured at the top of the injection well).

The measurement of ambient temperature is especially useful if the installation is on shore, as opposed to off-shore, as fluctuations in ambient temperature are much more significant on-shore than subsea.

By way of example, if the overall flow rate is below a setpoint and/or tends to decrease, the vapor CO2 to liquid CO2 ratio can be decreased, in order to increase the overall flow rate.

In another example, variations of topside pressure or temperature may require adjusting the vapor CO2 to liquid CO2 ratio, owing to the control unit. This may lead to fluctuations of the vapor CO2 to liquid CO2 ratio (i.e. increase followed by decrease or decrease followed by increase) over a period of time ranging from 1 min to several days, or from 10 min from 1 day, or from 1 hour to 12 hours.

Claims

1. A method for CO2 storage, the method comprising injecting a CO2 composition into a well of a subterranean reservoir, wherein the CO2 composition is formed by combining a stream of vapor CO2 and a stream of liquid CO2 at a vapor CO2 to liquid CO2 ratio, wherein the vapor CO2 to liquid CO2 ratio varies over time.

2. The method according claim 1 , comprising a step of measuring a flow rate of the stream of liquid CO2 and/or a flow rate of the stream of vapor CO2 during injection into the subterranean reservoir and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

3. The method according to claim 1 or 2, comprising a step of initially injecting only a stream of vapor CO2 into the well.

4. The method according to any one of claims 1 to 3, wherein the vapor CO2 to liquid CO2 ratio gradually decreases over time.

5. The method according to any one of claims 1 to 4, comprising a subsequent step of injecting only liquid CO2 into the well.

6. The method according to any one of claims 1 to 5, wherein the pressure of the CO2 composition during injection, at the inlet of the injection well, initially lies between 3 MPa and 7 MPa, for example between 3.5 MPa and 4.5 MPa.

7. The method according to any one of claims 1 to 6, wherein the temperature of the CO2 composition, at the inlet of the injection well, lies between 0 °C and 30°C, for example between 5°C and 10°C.

8. The method according to any one of claims 1 to 7, wherein the subterranean reservoir is at an initial pressure between 2 MPa and 20 MPa.

9. The method according to any one of claims 1 to 8, wherein adjustments to the vapor CO2 to liquid CO2 ratio are made in realtime.

10. The method according to any one of claims 1 to 9, comprising a step of directly measuring the bottomhole pressure in the well and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

11. The method according to any one of claims 1 to 10, comprising a step of measuring a topside temperature and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

12. The method according to any one of claims 1 to 11 , comprising a step of measuring a topside pressure in the well and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

13. The method according to any one of claims 1 to 12, wherein the vapor CO2 is obtained by evaporating liquid CO2 by means of an evaporator.

14. The method according to any one of claims 1 to 13, wherein the well has a length that lies between 100 m and 5 km, for example between 2 km and 4 km.

15. The method according to any one of claims 1 to 14, wherein the CO2 composition comprises other compounds, such as nitrogen or hydrocarbons, for example, methane, ethane, propane and/or heavier hydrocarbons in addition to CO2.

16. The method according to any one of claims 1 to 15, wherein the subterranean reservoir is onshore or offshore.

17. An installation for CO2 storage, the installation comprising:

- an injection well (110) in a subterranean reservoir (100);

- a liquid CO2 injection line (107) connected to an inlet of the injection well (110);

- a vapor CO2 injection line (106) connected to an inlet of the injection well (110);

- a flow meter (114, 116) and an adjustable valve (118, 120) positioned along either or both of the liquid CO2 injection line (107) and vapor CO2 injection line (106); a control unit configured to modify a ratio of vapor CO2 to liquid CO2 fed to the injection well (110). The installation according to claim 17, wherein at least one pressure sensor (122) is positioned along the well and/or at at least one bottomhole location. The installation according to claim 17 or 18, wherein at least one temperature sensor (122) is positioned along the well and/or at at least one bottomhole location. The installation according to any one of claims 17 to 19, wherein an evaporator (112) is positioned along the vapor CO2 injection line, configured to evaporate liquid CO2 into vapor CO2. The installation according to any one of claims 17 to 20, wherein the subterranean reservoir is onshore or offshore.