The present invention concerns an installation for injecting a carbon containing compound into a geological formation, the installation comprising at least one well extending to the geological formation, the installation comprising a well completion in the at least one well and a carbon containing compound injection system connected to the at least one well completion; the well completion having at least an inner tubing and at least an injection casing defining with the inner tubing an intermediate space.

The installation according to the invention is aimed at providing an efficient carbon capture and storage into geological depleted hydrocarbon reservoir, aquifer or any geological formation.

The objective of the invention is to transport for example carbon dioxide (thereafter CO2) in particular from onshore facilities to existing onshore or offshore facilities to store the CO2 into the depleted hydrocarbon reservoir or aquifer.

This solution offers a second life for oil and gas installations and a clean development way to new ones.

The CO2 is transported by a pipeline, typically the pipeline used for oil and/or gas export before the reservoir’s deletion, or by boat or by new pipes dedicated to carbon transport and storage.

The CO2 can either be in liquid/dense/supercritical phase for example 4°C, which is the deep sea bottom temperature and pipeline temperature and 100 bars or any combination of pressure and temperature to stay in liquid phase or in supercritical phase. Alternatively, the CO2 can be transported to the offshore facilities by ship.

Preferably, the CO2 is kept in liquid or supercritical phase during the injection process into the geological formation.

The reservoir depth can be more than 2000 m deep. The density of liquid CO2 is around 1 in some pressure and temperature conditions (seabed water temperature and 100 bars pipe pressure). In such wells, the hydrostatic pressure at bottom is greater than 200 bar for wells deeper than 2000 m. The liquid CO2 arrives with a 100 bars pressure, which means the pressure at the bottom of the reservoir shall be in the order of 300 bars.

Unfortunately, reservo ir/aqu if er pressure may be much lower than hydrostatic pressure plus incoming pipe pressure, being for example 20 bars. At the bottom of the reservoir, a CO2 expansion may occur which will cause a low temperature that could damage the geological formation and/or damage the well completion due to thermal expansion on concrete and/or steel tubing.

Another issue is the operability of moving parts like safety valves that are not rated for such low temperatures.

Hence, the injection may only be safely and efficiently operated at specific ranges of injections rates, these ranges depending in particular on the well setup and on the actual pressure in the reservoir.

Other problems which need to be solved for carrying out such an injection is the use of existing well architecture to limits investment costs and make the installation profitable.

The completion has to be able to cope with initial low CO2 injection rates (~0,5 million ton per annum or “MTPA”) while being able afterwards to increase rates as demands mandate, or in other words, have the widest injection range possible.

Once the installation is operating, work-overs are to be avoided as much as possible due to economical constraints.

In addition, impurities within the CO2 have a big impact on well injection performance, hence completion designs must be capable to adjust their performance as composition changes.

Seasons, in particular winter and summer, have also a significant effect on well injection performance. Hence completion design must be capable to adjust their performances as surface ambient temperature changes the fluid injection temperature at wellhead (from highest “Summer” to lowest “Winter” temperature ).

Additionally, Inflow Performance Relationship (IPR) from reservoir are generally estimated before the startup of the installation. However, no field data is available to validate simulations. Thermal fracture is an additional uncertainty through the life of the wells. Hence completion design must adjust to cope as much as possible with these uncertainties.

The installation should also minimize Joule-Thomson effect, such that temperatures remain inside the operating envelope of available commercial completion materials.

The installation should be as simple as possible to target a cost/effective, easy access well intervention, reduced complexity in moving parts and mechanisms and use today’s commercially available components “on the shelf” and rely as less as possible in future equipment developments.

One aim of the invention is to provide a carbon containing compound injection installation, which meets the above-mentioned requirements, in particular, which is able to maximize the injection range/coverage during its injection life, without having to replace the completion as a consequence of reservoir pressure increase, target rate changes or carbon containing compound injection demand evolution. To this aim, the subject matter of the invention is an installation as described above characterized in that the well completion comprises a wellhead equipped with flow control devices able to operate between a first injection configuration in which the carbon containing compound is injected only in the inner tubing, a second injection configuration in which the carbon containing compound is injected only in the intermediate space between the inner tubing and the injection casing, and a third injection configuration in which the carbon containing compound is injected in both the inner tubing and the intermediate space.

In the installation according to the invention, the well completion is configured to apply a variable pressure drop along the well. The pressure drop is controlled by selecting variable pathways for the injected fluid with the flow control devices to provide different pressure drops distributed along the well.

This is contrary to punctual pressure drops, as the classic approach using either variable/fix chokes or restriction orifices.

This option enables adjusting the pressure drop as needed as the gravity component in the well increases.

The installation according to the invention may comprise one or more of the following feature(s), taken solely or according to any technical feasible combination:

- the well completion is configured to generate a variable pressure drop in the well to avoid any punctual temperature drop at any point along the well from a wellhead choke to a sand face;

- it comprises a controller able to selectively control the opening of the flow control devices to switch between the first injection configuration, the second injection configuration and the third injection configuration;

- a bottom opening of the inner tubing emerges uphole of a bottom opening of the injection casing;

- it comprises a safety flow control device configured to control the total flow of carbon containing compound injected in the geological formation, the safety flow control device being located in the injection casing, downhole of the bottom opening of the inner tubing;

- the wellhead is equipped with an extra spool allowing a non-exclusive diversion of the injected fluid in a first path to the inner tubing or in a second path to the intermediate space, the first injection path and the second injection path being able to be simultaneously open;

- it comprises a carbon containing compound buffer, interposed between a source of carbon containing compound and the at least one well completion, the installation comprising a flow controller configured to control the carbon containing compound delivered to the at least one well completion from the buffer ; - the well completion is configured to define at least partially disjoint carbon containing compound allowable injection rate ranges having between them inaccessible injection rates, each allowable injection rate range being defined in a particular injection configuration among the first injection configuration, the second injection configuration and the third injection configuration, the flow controller being configured to control the carbon containing compound delivered to the at least one well from the buffer, such that when a carbon containing compound target injection rate falls between a lower allowable injection rate range and an upper allowable injection rate range, in at least a first storage phase, the carbon containing compound is injected at a first injection rate in the lower allowable injection rate range, the first injection rate being smaller than the target injection rate, and an excess rate of carbon containing compound between the target injection rate and the first injection rate is stored in the buffer, and in at least a second emptying phase, the carbon containing compound is injected at a second injection rate in the upper allowable injection rate range by complementing the difference between the target injection rate and the second injection rate with carbon containing compound from the buffer ;

- the carbon containing compound injection system is able to receive carbon containing compound from a source providing the carbon containing compound in a cryogenic state, in batches or continuously or/and from a source providing the carbon containing compound as a gas, the installation comprising a compressor able to compress the gas to condense the gas upstream of the carbon containing compound injection system to inject the condensed gas in the well completion, and advantageously a connector to mix the condensed gas with carbon containing compound in a cryogenic state upstream of the carbon containing compound injection system;

- the carbon containing compound is CO2 or is a gas mixture containing CO2.

The invention also relates to a process for injecting a carbon containing compound into a geological formation, via an installation, the installation comprising at least one well extending to the geological formation, the installation comprising a well completion in the at least one well and a carbon containing compound injection system connected to the at least one well completion; the well completion having at least an inner tubing and at least an injection casing defining with the inner tubing an intermediate space, characterized in that the well completion comprises a wellhead equipped with flow control devices, the process comprising operating the flow control devices between a first injection configuration in which the carbon containing compound is injected only in the inner tubing, a second injection configuration in which the carbon containing compound is injected only in the intermediate space between the inner tubing and the injection casing, and a third injection configuration in which the carbon containing compound is injected in both the inner tubing and the intermediate space.

The invention also relates to a fluid production installation for producing a fluid from a geological formation, the installation comprising at least one production well extending to the geological formation, the installation comprising a well completion in the at least one production well and a fluid recovery system connected to the at least one well completion; the well completion having at least an inner tubing and at least a production casing defining with the inner tubing an intermediate space, characterized in that the well completion comprises a wellhead equipped with flow control devices able to operate between a first production configuration in which the produced fluid only flows in the inner tubing, a second production configuration in which the produced fluid only flows in the intermediate space between the inner tubing and the injection casing, and a third injection configuration in which the produced fluid flows in both the inner tubing and the intermediate space; and/or the installation comprising at least one injection well extending to the geological formation, the installation comprising a well completion in the at least one injection well and a fluid injection system connected to the at least one well completion; the well completion having at least an inner tubing and at least an injection casing defining with the inner tubing an intermediate space, characterized in that the well completion comprises a wellhead equipped with flow control devices able to operate between a first injection configuration in which the injected fluid is injected only in the inner tubing, a second injection configuration in which the injected fluid is injected only in the intermediate space between the inner tubing and the injection casing, and a third injection configuration in which the injected fluid is injected in both the inner tubing and the intermediate space.

Preferably the fluid contains at least one of hydrocarbons, water, gas, steam.

The invention will be better understood, based on the following description, taken solely as an example, and made in reference to the following drawings, in which:

- Figure 1 is a schematic view of a first installation for injecting a carbon containing compound in a geological formation according to the invention; - Figure 2 is a schematic cross section of the lower end of a well containing a first well completion adapted to receive a carbon containing compound and to carry it to the geological formation, the first well completion defining a first range of injection rates of the carbon containing compound through the well completion;

- Figure 3 is a view similar to figure 2, of another well containing a second well completion defining a second range of injection rates of the carbon containing compound through the well completion;

- Figure 4 is a view similar to figure 2, in which the well completion is concentric and comprises several flow control devices able to be operated to provide different ranges of injection rates of the carbon containing compound through the well completion;

- Figure 5 is a schematic view of another well completion, in which the wellhead has flow control devices adapted to create different ranges of injection rates through the well completion;

- Figure 6 is a curve depicting several injection rate ranges as a function of reservoir pressure evolution for three injection configurations defined by well completions and at constant well head temperature;

- Figure 7 is a view of a particular zone of figure 6, showing the actual injection rate in a well when carrying out a first injection process according to the invention;

- Figure 8 is a view showing a buffering time window in a variant of the process according to the invention, when the target injection rate is close to a lower injection rate range;

- Figure 9 is a view similar to figure 8, in which the target injection rate is in between a lower injection rate range and a higher injection rate range;

- Figure 10 is a view similar to figure 8, in which the target injection rate is close to the higher injection rate range;

- Figure 11 is a view similar to figure 4, in which the well completion comprises more flow control devices implemented on the same inner tubing;

- Figure 12 is a schematic view of the well completion of figure 1 1 illustrating several operating conditions of the flow control devices along the well completion, generating several injection rate ranges; and

- Figure 13 is a curve similar to the curve of figure 6, showing a continuous aggregate range of injection rate ranges in the completion of figure 1 1 .

A first installation 10 for injecting a carbon containing compound into a geological formation 12 for storage of the carbon containing compound is illustrated schematically in figure 1. The installation 10 receives a quantity of carbon containing compound from at least a source 14, to inject the carbon containing compound in the geological formation 12.

The installation 10 is intended in particular for carbon transport and storage.

The geological formation 12 for example comprises a producing or/and a nonproducing hydrocarbon reservoir 16. In a variant, the geological formation 12 is another formation such as an aquifer.

The carbon containing compound is preferably carbon dioxide (CO2). In a variant, the carbon containing compound is a gas mixture containing CO2 and for example, but not restricted to, at least one of carbon oxide, methane, water, nitrogen, oxygen, hydrogen, helium, argon, hydrogen sulfide, nitrogen oxides such nitrogen oxide or dioxide, sulfur dioxide, alcohols such as methanol, hydrogen cyanide, hydrocarbons such as ethane, propane, butane, or C5+ hydrocarbons.

The CO2 content in the carbon containing compound injected in the geological formation 12 is greater than 95 mol%, preferentially greater than 97 mol%.

The sources 14 of carbon containing compound preferably comprise at least a source 14 of liquefied cryogenic carbon containing compound. The liquefied cryogenic carbon containing compound source 14 for example comprises ships 18 having tanks containing liquefied carbon containing compound. The ships 18 are able to travel to the installation 10, and the contents of their tanks are offloaded to the installation 10.

In a variant or in addition, the liquefied cryogenic carbon containing compound is supplied to the installation 10 via a pipeline.

The sources 14 of carbon containing compound may also comprise at least a direct producer source 14 in gas phase, advantageously from factories 20, for example from steel and cement factories.

The carbon containing compound is carried in a gas phase to the installation 10. The gaseous carbon containing compound may then be compressed without cooling down and supplied in addition to a liquefied carbon containing compound stream for a joint injection in the geological formation 12. The carbon containing compound may then be in condensed form when it is added to the liquefied carbon containing compound stream, but is not at cryogenic temperatures.

Within a long term window of for example more than one month, preferentially more than six months, for example of one year, the supply of carbon containing compound has a defined target injection rate, which depends on the predefined supply rate of each source 14. The target injection rate is preferentially a target mass rate generally calculated in Million ton per annum (MTPA). The target injection rate is generally comprised between 0.5 MTPA and 20 MTPA. The fluctuations of the instantaneous rate supplied by at least one source 14 are generally comprised between +/- 0.1 MTPA and 2 MTPA for example +/- 0.1 , 0.5, 1 or 2 MTPA..

As illustrated in figure 1 , the installation 10 comprises a plurality of wells 24, and for one or for a plurality of wells 24, a least a surface installation 26, the well 24 being connected at wellhead to the surface installation 26, and at bottomhole to the geological formation 12.

The installation 10 further comprises a well completion 28 equipping each well 24 and a carbon containing compound injection system 30 connected to the well completion 28 of each well 24.

As shown in figure 1 , the installation 10 further comprises an upstream facility 32 advantageously having at least a buffer 34, interposed between at least a source 14 of carbon containing compound and the carbon containing compound injection system 30 and when needed, a compression station 36.

The installation 10 also comprises a piping 38 connecting the upstream facility 32 and/or the source 14 of carbon containing compound to the or each surface installation 26 and thus to each well completion 28 within a well 24, via the carbon containing compound injection system 30.

In the example of figure 1 , the surface installation 26 is located offshore, at the surface of a body of water 37. In a variant, the surface installation 26 is located onshore.

The wells 24 are bored through the geological formations of the ground to reach a reservoir 16.

The wells 24 have for example vertical sections, and potentially inclined or/and horizontal sections to reach the reservoir 16.

The depth of each well 24 is generally greater than 2000 m and for example comprised between 1500 m and 5000 m.

The wells 24 are for example former or operating production wells which were drilled to produce hydrocarbon from the reservoir 16 or/and injection wells to inject a fluid in the reservoir 16 to enhance production through another well 24.

In the example of figure 1 , several wells 24 each having a well completion 28 are connected to the carbon containing compound injection system 30, advantageously through one or more surface installation 26.

Several examples of well completions 28 are depicted in figures 2 to 5.

Each well completion 28 generally comprises an inner tubing 40, and an injection casing 42 located around the inner tubing 40 and defining with the inner tubing 40 an intermediate space 44. The intermediate space is annular. The well completion 28 is equipped at the ground surface (which can be at the bottom of a body of water 37 if the surface installation 26 is offshore) with a wellhead 46 closing the inner tubing 40, the injection casing 42 and the intermediate space 44.

The well completion 28 further comprises at least a flow control unit 48 able to control the flow of carbon containing compound injected in the geological formation 12 through the well completion 28.

The inner tubing 40 is the most interior tubing of the well completion 28. It is connected to the injection system 30 through the wellhead 46 and potentially through other tubings.

The inner tubing 40 has a bottom opening 49, which opens preferentially in the vicinity of the reservoir 16. The bottom opening 49 is in fluid communication with the reservoir 16 at the bottom of the well 24.

The well completion 28 is for example an existing well completion, which has been used for producing hydrocarbons from the reservoir 16, or is a partly or totally replaced completion, which has been reinstalled in the well 24 after removing the completion used to produce hydrocarbons.

Each well completion 28 as shown in figure 2 or 3 is able to allow the injection of carbon containing compound in a liquid phase or in a supercritical phase in at least a given predefined injection range 50A, 50B, 50C, shown for example in figure 6.

Each injection range 50A, 50B, 50C is delimited as a function of reservoir pressure between an upper injection rate curve 52A, 52B, 52C defining the maximum injection rate at which a carbon containing compound can be injected in the well completion 28 in a particular configuration of the well completion 28 and a lower injection rate curve 54A, 54B, 54C, being the minimal injection rate curve at which the carbon containing compound can be injected in the well completion 28 in the particular configuration of the completion 28.

The upper injection rate curve 52A, 52B, 52C for each well completion 28 configuration is obtained by assuming the maximum allowed wellhead flowing pressure. Symmetrically, the lower injection rate limit curve 54A, 54B, 54C are obtained by assuming the lowest allowable wellhead flowing pressure.

Both the upper and lower injection rate limit curves are dependent on wellhead injection temperature. An average yearly fluid temperature might be used to obtain a good estimate of the curves. Nonetheless, the true yearly maximum injection rate would be attained at the lowest yearly temperature at wellhead 46. Conversely, the lowest yearly injection rate would be attained at the highest yearly temperature at wellhead 46.

The upper and lower injection rate limit curves decrease with increasing reservoir pressures (and hence injection time) in the reservoir 16. The well completions 28 placed in a well 24 or/and in different wells 24, as described in Figures 2 to 5 are configured to generate several at least partially disjointed injection ranges 50A, 50B, 50C and between each pair of adjacent disjointed ranges 50A, 50B; 50B, 50C, areas 51 A, 51 B, 51 C of inaccessible injection rates.

In particular, the injection rates below the lowest injection range (area 51 C in figure 6) and above the largest injection range (area 51 A in figure 6) are inaccessible.

For example, the well completion 28 of a first well 24 shown in figure 2 is able to generate a first lower injection range 50B at least partially disjoint (except for very large reservoir pressures) from a second upper injection range 50A generated by the well completion 28 of at least a second well 24 shown in figure 3.

The first injection range 50B and the second injection range 50C are also at least partially disjoint from at least a third injection range (not shown) which is defined when the well completion 28 of the first well 24 and the well completion 28 of at least one second well 24 are jointly connected to the injection system 30. In the third injection range, the injection in the first well 24 is carried out at an injection rate comprised in the first injection range 50B and the joint injection in the second well 24 is carried out at an injection rate comprised in the second injection range 50B.

In this example, the inside passage area of the inner tubing 40 of the well completion 28 of figure 2 is smaller than the inside passage area of the inner tubing 40 of the well completion 28 of figure 3.

The injection system 30 is able to selectively inject carbon containing compound in a liquid or supercritical phase to the well completion 28 of the first well 24, or to the well completion 28 of the second well 24 or jointly to the well completions 28 of the first and second wells 24, hence producing different injection configurations in different injection ranges.

In an embodiment, a well completion 28 in a single well 24 is also able to generate several partially disjointed injection ranges 50A, 50B, 50C

In the example of concentric completion of figure 4, the flow control unit 48 of the well completion 28 comprises at least one, preferentially several flow control devices 60A, 60B, 60C located on the inner tubing 40 to selectively connect the inner tubing 40 with the intermediate space 44 defined between the inner tubing 40 and the casing 42 and a controller 62 able to control the selective opening of each flow control device 60A, 60B, 60C.

It advantageously comprise at least a wellhead valve 61 A, potentially a subsurface safety valve (not shown) and an inflow control device 61 B placed in the inner tubing 40, preferentially below the flow control devices 60A, 60B, 60C. In this example, the intermediate space 44 emerges downwardly through a communication passage 64, which also communicates with the geological formation 12 at the bottom of the well 24. Any carbon containing compound flow introduced in the intermediate space 44 from any of the flow control devices 60A, 60B, 60C is able to flow downhole to the communication passage 64 and is able to join the flow emerging from the bottom opening 49 of the inner tubing 40, before reaching the geological formation 12.

Each flow control device 60A, 60B, 60C is here formed of a sliding side door (SSD) which can be operated by the controller 62. The controller 62 is able to selectively open each of the flow control devices 60A, 60B, 60C, solely or according to any combination of flow control devices 60A, 60B, 60C.

If the number of flow control devices 60A, 60B, 60C is equal to N, the controller 62 is able to selectively open a number of flow control devices 60A, 60B, 60C equal to each integer between 0 and N from the bottom of the well completion 28 to the top of the well completion 28.

In the example of figure 4, the controller is able to let all the flow control devices 60A to 60C closed in a first injection configuration, to selectively open only the lowest flow control device 60C in a second injection configuration, only the two lowest flow control devices 60C and 60B in a third injection configuration and all flow control devices 60C, 60B, 60A in a fourth injection configuration. Other injection configurations can also be obtained by selectively controlling the opening of each flow control device 60A, 60B, 60C.

The well completion 28 is therefore able to produce a plurality of injection configurations within the same well 24.

Each opening/closing configuration of the flow control devices 60A, 60B, 60C hence defines a particular injection configuration with a specific injection range 50A, 50B, 50C having an upper injection rate curve 52A, 52B, 52C and a lower injection rate curve 54A, 54B, 54C as defined above.

This type of completion 28 thus offers several injection configurations allowing a larger range of injection rates when compared to a single tubing concept such as disclosed in figures 2 and 3.

The use of SSD communicating different sections of the inner tubing 40 with the intermediate space 44 allows modifying the well performance (well outflow) without changing the inner tubing 40 size. The pressure drop across the well completion 28 is controlled by the accessible fluid path along the well completion 28 (taking into account the selective opening of flow control devices 60A, 60B, 60C from surface to bottom) and not by a single point pressure drop as it would be done normally by either a restriction or variable choke (such as an inflow control valve). In another variant, shown in figure 5, the wellhead 46 is equipped with several flow control devices 60L, 60M. In this example, the flow control device 60M of the wellhead 46 is able to control the flow of carbon containing compound injected in the central inner tubing 40. The flow control device 60L is able to control the flow of carbon containing compound injected in the intermediate space 44 between the inner tubing 40 and the injection casing 42.

The wellhead 46 is for example equipped with an extra spool allowing non-exclusive diversion of the injected fluid to the inner tubing 40 or to the intermediate space 44. Since the diversion system is independent, both injection paths are able to be open at the same time

In the example of figure 5, the bottom opening 49 of the inner tubing 40 emerges uphole of the bottom opening 63 of the injection casing 42. A safety flow control device 60N is located in the casing 42, downhole of the bottom opening 49 of the inner tubing 40.

The controller 62 of the flow control unit 48 is able to control the flow control devices 60L, 60M to define three injection configurations.

A first injection configuration is defined with the flow control device 60M opened, to allow an injection of carbon containing compound through the inner tubing 40, the flow control device 60L being closed, preventing injection of carbon containing compound through the intermediate space 44.

A second injection configuration is defined with the flow control device 60L opened, to allow injection of carbon containing compound in the intermediate space 44, the flow control device 60M being closed to prevent injection of carbon containing compound through the inner tubing 40.

A third injection configuration is defined with both flow control devices 60D and 60E opened, in which carbon containing compound is injected through both the inner tubing 40 and the intermediate space 44.

Each of these injection configurations defines a specific injection range 50A, 50B, 50C having an upper injection rate curve 52A, 52B, 52C and a lower injection rate curve 54A, 54B, 54C as defined above.

In the well 24, the inner tubing 40 has a length L and internal diameter d. The intermediate space 44 has an internal diameter D. The proportion d/D determines the injection rate range relationship between the first and second injection configurations. Depending on the choice of d and D, either the first or second injection configurations could be lowest injection rate configuration.

The length L is chosen to shift up and down injection rate ranges. Reducing the length of the inner tubing 40 removes friction from all injection configurations. With less friction, the injection rate ranges become wider when compared with equivalent injection ranges achieved with longer tubing and larger internal diameter.

The injection rate range of the third injection configuration is determined once the parameters L, d and D are fixed.

The safety flow control device 60N is a Sub Surface Safety Valve (SSSV). The certified depth of the available SSSVs defines the limit of the inner tubing 40 length L.

The well completion 28 of figure 5 provides injection rate flexibility with a durable robust completion, with no internal moving parts, that is operated from the surface. The cost of such a well completion 28 is negligible when compared to the cost of drilling a new well 24 or of a workover for recompletion.

The completion in figure 5 could very well be combined with a reduced diameter segment of any length or variable diameter below the SSSV, if need be to further control de pressure at bottom hole.

The variant of figure 5 is very easy to implement in an existing well completion, by modifying the wellhead 46 to add the flow control device 60L allowing the injection in the intermediate space 44.

Selection of the different injection configurations does not require a downhole operation since the flow control devices 60M, 60N are not located in the well 24.

As shown in figure 1 , the buffer 34, when present, is located on the upstream facility 32 which can be located onshore, or offshore.

The buffer 34 is for example formed of at least one cryogenic tank 70, able to temporarily store carbon containing compound as a liquid.

Preferentially, each tank 70 is configured to be operated between -20°C and 20 bars absolute and -26°C and 17 bars absolute with fluid densities comprised between 990 kg/m ³ and 1100 kg/m ³ , depending on the pressure and temperature.

Each tank 70 is for example capable of loading more than 5*10 ⁶ kg of liquid carbon containing compound, preferentially more than 10 ⁷ kg of liquid carbon containing compound.

The volume of each tank 70 is for example comprised between 5000 m ³ and 10000 m ³ , for example between 7000 m ³ and 9000 m ³ .

The number of tanks 70 in the buffer 34 is advantageously between 1 and 10, in particular between 3 and 5. Preferentially, the total buffer volume is greater than between 0.5% and 1% of the target flow rate multiplied by one year.

In case at least part of the carbon containing compound provided by the source 14 is in a gas phase, the upstream facility 32 may comprise a compression station 36. The compression station 36 is able to condense the gaseous carbon containing compound to provide it as a non cryogenic liquefied or supercritical carbon containing compound flow to the injection system 30 to be injected jointly with a cryogenic carbon containing compound flow provided from the tanks 70.

Advantageously, the condensation of the carbon containing compound may allow an elimination of undesired compounds it may contain, like water, hydrogen, helium or methane and also the partition with the indissolubles in liquid CO2.

Preferentially, the concentration in each of these compounds in the liquid or supercritical carbon containing compound produced from the compression station 36 is reduced to less than 3 mol%.

In another variant, the upstream facility 32 may comprise a liquefying unit (not shown) to supply the carbon containing compound in a cryogenic liquid phase.

The liquefaction of the carbon containing compound in cryogenic conditions allows a more in depth purification to eliminate undesired compounds it may contain.

Preferentially, the concentration in each of these compounds in the cryogenic carbon containing compound produced from the liquefying unit is reduced to less than 1 mol%.

In operation, the different injection configurations defined by the well completions 28 in several wells 24 (as in figure 2 and 3) or within a well 24 (as in figures 4 and 5) allow a carbon containing compound injection to be carried out at various injection flow rates. Each injection flow rate in a particular well 24 is comprised in an injection rate range 50A, 50B, 50C, defined by a particular well completion 28 under a particular injection configuration.

This allows coping with fluctuations which can occur in the provision of carbon containing compound from the source 14, due to the various reasons explained above.

Thanks to the presence of at least one buffer 34, a process according to the invention can be also carried out to compensate the fluctuations, especially when the target injection rate falls in an area 51 A, 51 B, 51 C between two injections ranges 50A, 50B, 50C, or below the lowest possible injection range 50C.

A target average injection rate is defined in a long term time window, for example being of at least a month, more preferentially at least 6 months, more preferentially at least one year.

The target injection rate depends on the capacities of the source(s) 14 to provide a flow rate of carbon containing compound. It is for example comprised between 0.5 MTPA and 15 MTPA.

In the example of figure 7, initially, in a first injection period 102, the target flow rate 100 is in a lower injection rate range 50B corresponding to a particular injection configuration of well completions 28 of several wells 24, or of a particular injection configuration of a well completion 28 into a well 24.

This lower injection rate range 50B is located below an upper injection rate range 50A corresponding to another injection configuration of a well completion 28 of another well 24 or another injection configuration of the same well completion 28 within a well 24, as explained above.

The constant target injection rate 100 is therefore smaller than an upper injection rate curve 52B of the injection range 50B, and is also smaller than the lower injection rate curve 54A of injection range 50A.

During the first injection period 102, carbon containing compound is injected into the geological formation 12 using the first injection configuration of the well completion 28 corresponding to the lower injection rate range 50B. The injection rate is the target injection rate 100, or potentially a rate below the target injection rate 100 in some instances.

As time passes, pressure in the geological formation 12 increases due to the injection of carbon containing compound, resulting the upper injection rate curve 52B of the injection range 50B decreasing.

When the target injection rate 100 crosses the upper injection rate curve 52B of the lower injection range 50B, injection at the target injection rate 100 is no longer possible.

At this time 103, in a carbon containing compound storage phase, the injection device 30 is therefore controlled to inject carbon containing compound in the geological formation 12 at an actual injection rate smaller or equal to the upper injection rate curve 52B of the lower injection rate range 50B and also smaller than the target injection rate 100.

The excess flow rate corresponding to the difference between the actual injection rate and the target injection rate 100 is stored in the buffer 34.

The buffer 34 thus fills up with the excess flow rate of carbon containing compound not injected in the geological formation 12.

At time 104, when a filling threshold is reached within the buffer 34, for example corresponding to more than 80% of the volume of the buffer 34, and/or after a predetermined filling time period, a carbon containing compound emptying phase is triggered.

A second injection configuration corresponding to the upper injection rate range 50A is set up by the carbon containing compound injection system 30 and/or by the flow control unit 48 of each well completion 28.

The carbon containing compound injection system 30 modifies the carbon containing compound injection rate in the geological formation 12 to be equal or above the lower injection rate curve 54A of the upper injection rate range 50A. The actual injection flow rate is formed from injecting the carbon containing compound from the source 14 advantageously at the target injection rate 100, and by supplementing it with carbon containing compound previously stored in the buffer 34 to provide the excess rate to reach at least the lower injection rate curve 54A.

The buffer 34 progressively empties until a time 106 at which a minimal predefined threshold of carbon containing compound in the buffer 34 is reached and/or a predetermined emptying period has elapsed.

The injection system 30 and/or the flow control unit 48 of a particular well completion 28 switches again to the first injection configuration and another carbon containing compound storage phase starts.

The previous storing and emptying phases are repeated alternatively, until the target flow rate 100 intersects with the lower injection rate curve 54A of the upper injection rate range 50A.

Indeed, as time passes, the pressure in the geological formation 12 increases due to the injection of carbon containing compound, resulting the lower injection rate curve 54A of the injection range 50A decreasing.

At the intersection point, in phase 108, the injection rate is set up again to the target injection rate 100.

In a variant (not shown), when the target average rate 100 is in the area 51 C below the lowest possible injection range 50C, no injection is initially carried out and the whole flow of carbon containing compound is stored in the buffer 34 until the tanks 70 are full.

Then, a carbon containing compound emptying phase is triggered with the target injection rate 100 from the source 14 being complemented with carbon containing compound from the buffer 34, to reach an injection rate greater than the lower injection rate curve 54C of the lowest possible injection range 50C.

In a particular embodiment, shown in figures 8, 9 and 10, the target injection rate 100 is between the lower injection rate range 50B and the upper injection rate range 50A. The process then comprises a succession of buffering time windows 1 18 comprising a commutation between the first injection configuration in the lower injection range 50B and the second injection configuration in the upper injection range 50A.

Each buffering time window 118 has a duration which is shorter than the duration of the long term time window. The duration of each buffering time window 1 18 is for example less than 0.5 year, for example is equal to one month.

The average target injection flow rate of carbon containing compound in each buffering time window is set to be equal to the average target flow rate in the long term window defined above. In each buffering time window 118, at least one initial time period 120 is dedicated to carbon containing compound storage with injection of carbon containing compound in the geological formation at an actual injection rate smaller or equal to the upper injection rate curve 52B of the lower injection range 50B.

At least a final time period 122 is dedicated to buffer emptying, with injection of carbon containing compound in the geological formation at an actual injection rate equal to or greater than the lower injection rate curve 54A of the upper injection range 50A.

An intermediate time period 124 is defined between the first time period 120 and the second time period 122. The intermediate time period 124 comprises a single commutation between the first injection configuration and the second injection configuration at an adjustable time which can be at between 0% and 100% of the duration of the intermediate time period 124.

The duration of each of the initial time period 120 and of the final time period 122 exceeds 10% of the total duration of the buffering time window 1 18. The duration of each of the initial time period 120 and of the final time period 122 is generally comprised between 20% and 40% of the duration of the buffering time window 118. Preferentially, the time periods 120 and 122 have equal durations.

In the intermediate time period 124, the commutation time 104 is chosen as a function of the difference between the target injection rate 100 and each of the upper injection rate curve 52B of the lower injection rate range 50B and the lower injection rate curve 54A of the upper injection rate range 50A.

In the example of figure 8, the target injection rate 100 is close to the upper injection rate curve 52B of the lower injection rate range 50B. A storage phase occurs in the initial time period 120 and also in the entire intermediate phase 124. The injection system 30 advantageously injects the carbon containing compound at or below the upper injection rate 52B of the lower injection rate range 50B. The excess rate to the target flow rate 100 is stored in the buffer 34.

The commutation time 104 is at 100% of the duration of the intermediate time period 124.

An emptying phase of the buffer 34 occurs only in the final time period 122. Carbon containing compound is injected at the lower injection rate 54A of the upper injection range 50A or above, the excess rate being supplied from emptying the buffer 34.

As shown in Figure 9, when the target injection rate 100 finds itself at a nearly centered relative position between the upper injection rate curve 52B of the lower injection range 50B and the lower injection rate curve 54A of the upper injection range 50A, a storage phase occurs during the initial time period 120 and during part of the intermediate time period 124. At the commutation time 104, the injection configuration is modified to the second injection configuration in the upper injection rate range 50A. An emptying phase is then carried out during part of the intermediate time period 124 and during the entire final time period 122.

As shown in figure 10, when the target injection rate 100 finds itself at a higher relative position, closer to the lower injection rate curve 54A of the upper injection range 50A, the emptying phase is carried out during the entire intermediate time period 124 and the entire final time period, the commutation time 104 being at 0% of the duration of the intermediate time period 124.

The sequential storage and emptying phases in the time periods 120, 124, 122 of each successive short time window 118 avoid too frequent fluctuations between the lower injection rate range 50B and the upper injection rate range 50A thanks to the definition of minimal storage and emptying times respectively in time period 120 and in time period 122.

The duration of the time periods 120 and 122 is given by the minimal allowed period to open and close a well. This minimal time between consecutive interaction in a well comes given by its integrity and the time to start and stabilize a target injection rate. Therefore, the duration of the intermediate period 124 is just the duration of the buffering window minus the durations of periods 120 and 122.

The commutation time choice between 0% and 100% of the duration of the intermediate period 124, is the result of a minimization of the storage volume needed under the constraint that the average injection rate over the entire buffering window 1 18 duration must be equal to the average target flow rate of the long-term time window.

For such a calculation, three values are chosen simultaneously: the injection rate in the injection range 50B at a value smaller than the upper injection rate curve 52B in time period 120, the injection rate in the injection range 50A at a value greater than the lower injection rate curve 54A in time period 122 and the commutation time, such that the average injection rate in the short term window 118 equals the average target rate. This condition implies that no carry over of stored fluid is done from one buffering window 1 18 to the next, allowing the repetition of the process without loss of storage capacity.

In a variant, the buffer 34 can be simultaneously filled up by carbon containing compound for example arising from the offloading of a ship and emptied to inject carbon containing compound in the geological formation 12 at a flow rate corresponding to an injection range in a well 24.

In another variant, shown in figure 11 and 12, the number N of flow control device 60A to 60E set up between the inner tubing 40 and the intermediate space 44 is greater than 3, and is for example greater or equal to 5. N is for example equal to 5 in the example of figure 12.

In that case, the number N+1 of possible injection rate ranges 50A to 50F is defined by the selective cumulative opening of 0, 1 , 2, ...to N flow control devices 60A to 60E from the lowest flow control device 60E to the most upper flow control device 60A, as represented schematically in Figure 12.

As shown in figure 12, the pressure drop by friction decreases from left to right with an increasing length of passage of the carbon containing flow in the intermediate space 44, resulting from the successive opening of flow control devices 60E to 60A from bottom to top.

As shown in figure 13, the resulting injection ranges 50A to 50F overlap and thus define a continuous injection rate range. In some instances, this may alleviate the need of using alternate phases of storing in a buffer 34 and emptying the buffer 34.

Generally speaking, the well completions 28 of figure 5 allow a change in the fluid pathway, between at least less frictional path and at least a more frictional path, hence changing the pressure drop along the well, by selectively manipulating (closing/opening) the flow control devices 60L and 60M.

The well completion 28 can also be applied in the production of hydrocarbons, for any type of fluid injector well or producer well. In a prior art installation, as producer wells evolve in time, typically the tubing is replaced (or velocity string is installed through workover) at a later stage to achieve higher velocities required to lift the stagnated condensate/water at the bottom of the well, leading to the killing of the well due to the increase bottom hole pressure exerted by the stagnated fluid hydrostatic column.

Using the well completion 28 according to figure 5 only requires operating a flow control device to reduce the pathway sectional area, hence to increase the flow velocity or to increase the pathway sectional area, hence reducing the fluid velocity.

In any case, the well completion 28 is not necessarily connected to a buffer 34.