Method for injecting carbon dioxide into underground reservoirs

Abstract

The present invention relates to a method for CO2 storage, comprising the step of injecting a CO2 composition into a well of an underground reservoir, the CO2 composition being formed by combining a stream of vapor CO2 and a stream of liquid CO2 in a ratio of vapor CO2 to liquid CO2 that varies over time. The present invention also relates to an installation for CO2 storage.

Description

[Technical field]

[0001] The present invention relates to the field of CO2 storage, and more particularly to a method of CO2 storage, which comprises injecting a CO2 composition into a well of an underground reservoir and varying the vapor CO2 to liquid CO2 ratio of the composition over time. [Background technology]

[0002] Carbon storage projects often utilize underground formations as potential storage sites for CO2. Such underground formations may include existing depleted oil and / or gas underground reservoirs. Depletion means that the pressure in the underground reservoir has been reduced to a certain level. Following CO2 capture, the CO2 is stored to meet the growing demand for minimizing the impact on climate change. There is an advantage to utilizing existing underground depleted reservoirs because they have already proven their ability to store gas / oil for long periods, the storage size is known, and many wells have already been penetrated. Since underground formations containing such reservoirs are often located offshore and it often requires a great deal of effort to provide the necessary equipment, reusing well and / or surface equipment is particularly beneficial. However, when CO2 is delivered to an underground reservoir, it can undergo phase changes, which can result in the temperature of the equipment decreasing below its original design temperature, making it generally difficult to further utilize existing equipment. Such thermal shock can damage the equipment and cause well leaks. Thermal shock may additionally and / or alternatively cause fractures in the reservoir itself or in the formations above the reservoir.

[0003] Furthermore, the bottom-hole pressure of the injection well fluctuates widely during the course of injection, making it difficult to continuously supply CO2 in a manner that precisely overcomes the bottom-hole pressure. Such pressure fluctuations result in unstable wellbore flow during CO2 injection. This can also cause fractures in the wellbore and the formation of hydrates in the vicinity of the wellbore that block the flow path of CO2. Even if constant high pressure is employed as a means to overcome the bottom-hole pressure, it also has drawbacks, as constant high pressure may also cause reservoir fractures. Also, from a purely operational perspective, unstable flow can pose many challenges in starting and stopping injection, which can lead to significant delays in CO2 injection and an overall increase in costs. Many efforts have been made to overcome these drawbacks, including preheating CO2, employing only continuous injection modes, re-injecting the wellbore through friction tubes or downhole chokes, and / or utilizing cryogenic equipment.

[0004] US Patent Application No. 2012 / 0038174A1 relates to the coupling of CO2 geological storage with methane and / or heat production (geothermal energy) from geothermal aquifers. Energy production from extracted brine is used to offset the costs of capturing, pressurizing, injecting, and then injecting the brine containing carbon dioxide into the aquifer.

[0005] Patent Publication No. 5267810B2 relates to a method for determining the mass ratio of undissolved carbon dioxide to be mixed into carbon dioxide saturated water. As a result, a first reservoir zone that stores undissolved carbon dioxide together with carbon dioxide saturated water is formed around an injection well in an aquifer, and a second reservoir zone that stores only carbon dioxide saturated water is formed in the aquifer, surrounding the first reservoir zone, through several stages, approximately concentrically, under conditions for storing and separating the carbon dioxide saturated water and undissolved carbon dioxide.

[0006] The paper by Fabian Moller et al. (Injection of CO2at 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) describes a “cold injection” experiment carried out between March and July 2013 to study the effect of lowering pretreatment temperatures and potential two-phase flow on the injection process. The injection wellhead temperature was reduced in stages from 40°C to 10°C. Below 20°C, two-phase flow occurred in the surface installation and in the injection well down to the reservoir, injecting a mixture of gas and liquid CO2.

[0007] In this context, there remains a need to provide a method for storing CO2 in a controlled and efficient manner. Summary of the Invention

[0008] It is therefore an object of the present invention to provide a method for CO2 storage, comprising the step of injecting a CO2 composition into a well of an underground reservoir, the CO2 composition being formed by combining a stream of vapor CO2 and a stream of liquid CO2 in a vapor CO2 to liquid CO2 ratio that varies over time.

[0009] According to some embodiments, the method includes measuring the flow rate of liquid CO2 and / or the flow rate of vapor CO2 during injection into the underground reservoir and adjusting the liquid to vapor CO2 ratio as a result of this measurement.

[0010] According to some embodiments, the method includes initially injecting only a stream of steam CO2 into the well.

[0011] According to some embodiments, the vapor CO2 to liquid CO2 ratio is gradually decreased over time.

[0012] According to some embodiments, the method includes a subsequent step of injecting only liquid CO2 into the well.

[0013] According to some embodiments, the head pressure of the CO2 composition during injection at the entrance of the injection well is initially in the range of 3 MPa to 7 MPa, such as in the range of 3.5 MPa to 4.5 MPa.

[0014] According to some embodiments, the head temperature of the CO2 composition at the entrance of the injection well is in the range of 0°C to 30°C, such as in the range of 5°C to 10°C.

[0015] According to some embodiments, the initial pressure of the underground reservoir is in the range of 2 MPa to 20 MPa, in particular in the range of 2 MPa to 7 MPa.

[0016] According to some embodiments, adjustments to the vapor CO2 to liquid CO2 ratio are made in real time.

[0017] According to some embodiments, the method includes the step of directly measuring the bottom hole pressure of the well and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

[0018] According to some embodiments, the method includes measuring the top end temperature and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

[0019] According to some embodiments, the method includes measuring the top end pressure in the well and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement.

[0020] According to some embodiments, vapor CO2 is obtained by evaporating liquid CO2 by means of an evaporator.

[0021] According to some embodiments, the length of the well is between 100m and 5km, for example between 2km and 4km.

[0022] According to some embodiments, the CO2 composition includes, in addition to CO2, other compounds such as nitrogen or hydrocarbons, for example methane, ethane, propane and / or heavier hydrocarbons.

[0023] According to some embodiments, the underground reservoir is onshore or offshore.

[0024] Another object of the present invention is to provide a facility for CO2 storage, the facility comprising: an injection well in an underground reservoir; a liquid CO2 injection line connected to the entrance of the injection well; A steam CO2 injection line connected to the entrance of the injection well; a flow meter and an adjustable valve disposed along either or both of the liquid and vapor CO2 injection lines; a control unit configured to vary the ratio of steam CO2 to liquid CO2 supplied to the injection well; Includes.

[0025] According to some embodiments, at least one pressure sensor is positioned along the wellbore and / or at at least one bottom hole location.

[0026] According to some embodiments, at least one temperature sensor is positioned along the wellbore and / or at at least one bottom hole location.

[0027] According to some embodiments, an evaporator is disposed along the vapor CO2 injection line and configured to evaporate liquid CO2 into vapor CO2.

[0028] According to some embodiments, the underground reservoir is onshore or offshore.

[0029] The present invention makes it possible to address the above-mentioned needs, in particular by providing a controlled and efficient method for storing CO2.

[0030] This is accomplished by varying the vapor to liquid CO ratio over time to create the injected CO composition. Vapor and liquid CO have different properties, which result in different flow characteristics for the CO.

[0031] The vapor phase in the composition initially applies compression heat toward the wellhead. As the vapor begins to condense, heat is also released down the well. As the composition travels down the well, the vapor applies additional frictional heat to the well. The vapor phase reduces the static pressure in the well, which in turn reduces the bottomhole pressure.

[0032] On the other hand, the liquid phase increases the pressure in the wellbore, thus increasing the flow rate. It is also less compressible, so it cools less than the vapor in the wellbore. As the composition moves further down the wellbore, the liquid may begin to evaporate, slowing the injection rate and increasing friction with the wellbore. Overall, however, the liquid phase increases the static gradient and thus the downhole pressure. Thus, by varying the vapor CO2 to liquid CO2 ratio when crafting the CO2 composition to be injected, the right balance can be achieved in matching or indeed overcoming a given bottomhole pressure.

[0033] The vapor CO2 to liquid CO2 ratio can be changed over time, for example, to continuously overcome bottom hole pressure, thus avoiding sub-freezing temperature conditions in the well, eliminating or greatly reducing the risk of hydrate formation near the well, and mitigating the occurrence of fractures in the well due to high pressure injection. The method also does not require new equipment, and allows the same equipment to be reused. Furthermore, the composition of the CO2 can be changed so that it is injected only at the pressure required to overcome the bottom hole pressure, reducing the overall energy consumption of the system and eliminating the need to mix additional materials into the CO2 composition to aid injection.

[0034] Advantageously, according to some embodiments, the method may include measuring the CO2 flow rate during injection into the underground reservoir and adjusting the vapor CO2 to liquid CO2 ratio as a result of this measurement. The flow rate may be used to calculate the pressure in the wellbore and the bottom hole pressure, so that the flow rate can be easily controlled, for example, by adjusting the vapor CO2 to liquid CO2 ratio, which can be done in real time without additional pressure sensors in the wellbore or downstream of the wellbore. Tight control of the wellbore promotes a steady flow, thus overcoming challenges with periodic start, stop, and batch modes of injection. [Brief description of the drawings]

[0035] Non-limiting examples of the present invention will now be described with reference to the accompanying drawings. [Figure 1] FIG. 1 is an explanatory diagram illustrating an installation according to an embodiment. [Diagram 2] FIG. 1 shows pressure (Y-axis, kPa) as a function of well length (X-axis, m) for a range of vapor CO2 to liquid CO2 ratios. % indicates the liquid fraction of CO2 in the CO2 composition. [Diagram 3] FIG. 1 shows temperature (Y-axis, °C) as a function of well length (X-axis, m) for a range of vapor CO2 to liquid CO2 ratios. % indicates the liquid fraction of CO2 in the CO2 composition. [Figure 4] Figure 1 shows a schematic of a typical change in the ratio of liquid CO2 flow rate to the sum of liquid and vapor CO2 flow rates (Y-axis) from start-up to shutdown (X-axis). The symbols V, L and V+L represent the vapor CO2, liquid CO2 and two-phase CO2 along the injection well, respectively. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0036] The invention will now be described in more detail without, however, being limited thereto.

[0037] The method of the invention is carried out by injecting a CO2 composition into an underground reservoir well (injection well). The composition is formed by combining a stream of vapor CO2 and a stream of liquid CO2 in a ratio of vapor CO2 to liquid CO2 that varies over time.

[0038] "CO2 composition" refers to a fluid that includes CO2. The composition may include one or more phases of CO2 selected from a liquid phase, a gas phase, and a supercritical phase. The physical state of the CO2 composition may change along the injection well. Thus, the CO2 composition may include a liquid CO2 phase and a gaseous CO2 phase. Alternatively, the CO2 composition may include a liquid CO2 phase and a supercritical CO2 phase. Alternatively, the CO2 composition may include a gaseous CO2 phase and a supercritical CO2 phase. Alternatively, the CO2 composition may include a gaseous CO2 phase, a liquid CO2 phase, and a supercritical CO2 phase.

[0039] The CO2 composition may consist essentially of CO2 or may consist of CO2. Alternatively, the CO2 composition may additionally contain other compounds in addition to CO2, such as nitrogen or hydrocarbons, e.g. methane, ethane, propane and / or heavier hydrocarbons. Preferably, the weight percentage of CO2 in the CO2 composition is at least 80%, more preferably at least 90%, even more preferably at least 95%.

[0040] "Vapor CO2 stream" and "liquid CO2 stream" refer to the respective flow or flow of a fluid in a particular direction, which direction is toward the wellhead of an injection well. The two streams are separated before being combined. The vapor stream of CO2 and the liquid stream of CO2 may be obtained from the same source. Alternatively, these streams may be obtained from different sources. Both streams may originate from the same initial stream. In that case, one or both streams undergo a pre-treatment step before becoming the vapor CO2 stream and the liquid CO2 stream. 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.

[0041] "Vapor CO2 to liquid CO2 ratio" refers to the weight ratio of vapor CO2 flow to liquid CO2 flow in a combination.

[0042] The CO2 composition itself, when formed, may be, for example, liquid, vapor, or a two-phase liquid / vapor mixture. The vapor and liquid CO2 streams may be at different temperatures and pressures before being combined. In such a case, combining the two streams may rapidly move to equilibrium and change the relative proportions of liquid and vapor. The state of the CO2 composition at the top of the injection well is therefore determined by the pressure and temperature at this point.

[0043] The underground reservoir may be offshore or onshore, or partly offshore and partly onshore.

[0044] Subterranean reservoirs may refer specifically to hydrocarbon reservoirs. The hydrocarbon reservoirs may be partially depleted, substantially depleted, or completely depleted. That is, at the time the method of the present invention is carried out, the hydrocarbons in the reservoir may have been previously produced. A reservoir is a subterranean portion in which fluids, such as CO2 or hydrocarbons, may be contained without substantial diffusion to adjacent portions. In this regard, a reservoir may be considered a geological enclosure within a subterranean formation. For example, the adjacent portions may be made of rock material having a lower porosity than the rock material of the reservoir itself. In some variations, a clay layer may exist above the reservoir. In some variations, a water-bearing layer may exist below the reservoir. In some variations, the reservoir may be partially bounded by cracks that form discontinuities in porosity that are difficult for fluids to flow through.

[0045] The reservoir may be elongated in shape, for example with heights of 20 m to 300 m, and / or lateral dimensions of 2 km to 15 km, for example 3 km to 10 km. If located offshore, the reservoir may be found at depths of more than 1 km below sea level, for example 2 km to 4 km, or to such an extent.

[0046] The reservoirs may belong to different types of subsurface formations, for example but not limited to, those of different materials such as limestone and sandstone.

[0047] The underground reservoir may have an initial pressure in the range of 2 MPa to 20 MPa (particularly in the range of 2 MPa to 7 MPa) and an initial temperature in the range of 70 ° C to 200 ° C. "Initial" means before the method according to the invention is carried out, which may change the pressure and temperature in the underground reservoir by carrying out the method. The temperature of the reservoir may decrease due to the addition of the injected CO2 composition when the method according to the invention is carried out, and may then increase again to the initial value (depending on the conditions around the reservoir). The pressure of the reservoir may optionally increase due to the addition of the injected CO2 composition when the method according to the invention is carried out to the pressure value that the reservoir had before the hydrocarbon depletion, for example a value in the range of 10 MPa to 70 MPa after a charging period of 2 to 20 years, or to such an extent. Preferably, in order to avoid damage to the reservoir, the injection of the CO2 composition is stopped when the pressure in the reservoir reaches the pressure value before the hydrocarbon depletion.

[0048] With reference to the embodiment as shown in Figure 1, the CO2 composition is injected into the subterranean reservoir 100 by combining a stream of liquid CO2 and a stream of vapor CO2. Both streams may be provided from the same source 102, e.g., in the form of liquid CO2, before being transported (e.g., by pump 104) along a steam injection line 106 and a liquid injection line 107 to the entrance of an injection well 110. Both the steam injection line 106 and the liquid injection line 107 may branch off from a common injection line 103. The pump 104 may be provided on the common injection line 103.

[0049] If the CO2 for steam injection is initially in liquid form (in a common injection line), the steam injection line 106 may first pass the liquid through an evaporator 112 to evaporate the liquid. According to some embodiments, the method may include initially injecting only a stream of steam CO2 into the well.

[0050] Steam injection line 106 may include a first flow meter 114 and a first adjustable valve 118. First flow meter 114 may measure the flow rate of the steam CO2 during injection into subterranean reservoir 100. The flow rate of the steam CO2 itself may be adjusted by operation of a first adjustable valve 118 positioned after first flow meter 114. The flow may then be directed to the inlet of injection well 110. First flow meter 114 may be a Coriolis flow meter or other type of flow meter.

[0051] The liquid CO2 injection line may include a second flow meter 116 and a second adjustable valve 120. The second flow meter 116 may measure the flow rate of the liquid CO2 during injection into the subterranean reservoir 100. The flow rate of the liquid CO2 itself may be adjusted by operation of a second adjustable valve 120 located after the second flow meter 116. The flow may then be directed to the inlet of the injection well 110. The second flow meter 116 may be a Coriolis flow meter or other type of flow meter.

[0052] Additionally or alternatively to at least one implementation of the flow meters 114, 116 described above, pressure and / or temperature may be monitored by one or more pressure and / or temperature sensors 122 that may be provided at the top end (the term "top end" means located above ground or sea level), along the wellbore, and / or at at least one bottom hole location. In particular, a temperature sensor may be incorporated into or associated with each of the first flow meter 114 and the second flow meter 116 (as accurate measurement of flow rate may require temperature measurement). The method may include measuring the top end temperature and adjusting the steam CO2 to liquid CO2 ratio as a result of this measurement. Similarly, the method may include measuring the top end pressure in the wellbore and adjusting the steam CO2 to liquid CO2 ratio as a result of this measurement.

[0053] A control unit may be present to control the first adjustable valve 118 and the second adjustable valve 120, and thus adjust the vapor CO2 to liquid CO2 ratio. This adjustment may be adjusted partially or entirely according to a pre-set schedule (i.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 provided 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.

[0054] The sensor 122 may provide measurements to the control unit, which may alternatively be used as the 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 the second flow meter 116.

[0055] The control unit may operate in a partially or fully automated manner. The control unit may operate in a partially or fully operated manner based on input from an operator.

[0056] When both the liquid and vapor CO2 streams arrive at the injection well 110, they are combined to form the CO2 composition. The flow rate of the liquid CO2 may be in the range of 0%-100% of the total flow rate of the liquid and vapor CO2, such as in the range of 5%-15%, such as about 10%, or in the range of 15%-25%, such as about 20%, or in the range of 25%-35%, such as about 30%, or in the range of 35%-45%, such as about 40%, or in the range of 45%-55%, such as about 50%, or in the range of 55%-65%, such as about 60%, or in the range of 65%-75%, such as about 70%, or in the range of 75%-85%, such as about 80%, or in the range of 85%-95%, such as about 90%. All ratios are by weight.

[0057] In some steps of the method, only a flow of vapor CO2 may be provided or only a flow of liquid CO2 may be provided. In particular, in an initial stage of the method, only a flow of vapor CO2 may be provided. In particular, in a non-initial stage of the method, only a flow of liquid CO2 may be provided. This can be obtained by keeping the second regulating valve 120 closed or by keeping the first regulating valve 118 closed.

[0058] In some embodiments, the pressure of the CO2 composition at the inlet of the injection well during injection is initially in the range of 3 MPa to 7 MPa, such as in the range of 3.5 MPa to 4 MPa. Additionally or alternatively, the temperature of the CO2 composition at the inlet of the injection well is in the range of 0°C to 30°C, such as in the range of 5°C to 15°C, or such as in the range of 5°C to 10°C.

[0059] The relative proportions of liquid and vapor CO2 flows change over time, and the total flow rate of the CO2 composition in the injection well changes over time. In general, the lower the vapor to liquid CO2 ratio, the higher the total flow rate.

[0060] Optionally, the method may include determining the bottom hole pressure via flow rate, top pressure and / or temperature measurements. The vapor CO2 to liquid CO2 ratio may then be adjusted in response to the determined bottom hole pressure. Alternatively, the bottom hole pressure may be measured directly via measurements with a sensor located at the bottom hole. The vapor CO2 to liquid CO2 ratio may be adjusted as a result of this measurement.

[0061] Figure 2 shows the change in pressure as a function of well length for pure vapor CO2, CO2 compositions with different vapor CO2 to liquid CO2 ratios, and pure liquid CO2 injected at an inlet pressure of 4 MPa at the injection well and an inlet temperature of 5 °C at the injection well. It can be seen that pure vapor CO2 and CO2 compositions with low liquid fractions operate at lower pressures with a smaller pressure gradient as the well length increases compared to pure liquid and CO2 compositions with high liquid CO2 fractions. The opposite trend can be seen in Figure 3, where pure vapor CO2 and CO2 compositions with high liquid fractions operate at higher temperatures as the well length increases compared to pure liquid CO2 and CO2 compositions with high vapor fractions. It can be seen how the combination of these properties can be exploited by using CO2 compositions with different vapor CO2 to liquid CO2 ratios to affect the flow characteristics of the CO2 during injection. For example, a CO2 composition containing 80% vapor CO2 and 20% liquid CO2 may be utilized where low pressure is desired near the wellhead, but a more dramatic pressure increase is required near the end of the well.

[0062] FIG. 4 shows a typical progression from start to stop of injection. The top of each bar represents the wellhead (entrance to the injection well) and the bottom of each bar represents the bottom of the well (i.e. the entrance to the reservoir 100). In bar 1, in the initial stage, the liquid CO2 injection line 107 was shut off and only CO2 vapor was fed to the well. Then, from bar 2 to bar 7, liquid CO2 was injected and the proportion of liquid CO2 combined with the vapor CO2 was gradually increased. From bar 2 to bar 6, the liquid CO2 flow was combined with the vapor CO2 flow. In bar 7, the vapor CO2 injection line 106 was shut off and only liquid CO2 was injected.

[0063] In some variations, the gradual decrease in the vapor CO2 to liquid CO2 ratio over time allows the total flow rate of CO2 injection to remain substantially constant over time as the bottom hole pressure gradually increases. On the other hand, direct injection of only liquid CO2, or a biphasic composition with a high proportion of liquid CO2, at the beginning of the process is undesirable because the bottom hole pressure is low, which would generate low temperatures along the wellbore as described above. Therefore, the method may include a subsequent step of injecting only liquid CO2 into the wellbore. When the reservoir reaches a sufficiently high pressure, a flow of only liquid CO2 may be used later in the injection timeline. In some variations, the total flow rate may increase over time and may be maximum when only liquid CO2 is injected.

[0064] The change in vapor CO2 to liquid CO2 ratio over time may be incremental / stepwise or continuous.

[0065] Instead of starting with injection of only vapor CO2 at rod 1, a mixed vapor CO2 / liquid CO2 injection may be used if appropriate given the bottom hole pressure. Instead of injecting only liquid CO2 at rod 7, a mixed vapor CO2 / liquid CO2 may be used if the bottom hole pressure is appropriate. Thus, the method comprises: Start by combining a vapor CO2 stream and a liquid CO2 stream at an initial vapor CO2 to liquid CO2 ratio and gradually decrease the vapor CO2 to liquid CO2 ratio over time to a final vapor CO2 to liquid CO2 ratio, or Alternatively, starting by injecting only vapor CO2 streams and no liquid CO2 streams, combining vapor CO2 streams and liquid CO2 streams in a vapor CO2 to liquid CO2 ratio, gradually decreasing the vapor CO2 to liquid CO2 ratio over time until a final vapor CO2 to liquid CO2 ratio; Alternatively, combine vapor CO stream 2 and liquid CO stream 2 at an initial vapor CO2 to liquid CO2 ratio and gradually reduce the vapor CO2 to liquid CO2 ratio over time, after which the vapor CO2 flow is stopped and only the liquid CO2 flow is injected; or Alternatively, starting by injecting only vapor CO2 streams and no liquid CO2 streams, combining vapor CO2 streams and liquid CO2 streams in a vapor CO2 to liquid CO2 ratio, gradually decreasing the vapor CO2 to liquid CO2 ratio over time, stopping the injection of vapor CO2 streams and injecting only liquid CO2 streams.

[0066] Each of the four changes above could take anywhere from a few months to a few years.

[0067] When the CO2 composition is formed at the entrance of the well (top end), it may be monophasic (liquid or gas) or biphasic. For example, as shown in Figure 4, in bars 1, 2, and 3, the CO2 composition when formed is in the gas phase; in bar 4, it is biphasic; and in bars 5, 6, and 7, it is in the liquid phase.

[0068] Thus, in some embodiments, the method of the present invention may begin by injecting the CO2 composition in the vapor phase (top), followed by injecting the CO2 composition in a biphasic state (top), followed by injecting the CO2 composition in the liquid phase, which may take a period of months to years.

[0069] As the CO2 composition travels down the injection well, its physical state may change. From the top to the bottom of the hole, the vapor CO2 to liquid CO2 ratio may increase or decrease as liquid CO2 evaporates and vapor CO2 condenses. CO2 may become supercritical along the injection well.

[0070] 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 vapor / liquid mixture (bottom). In bar 4, the CO2 composition remains in the vapor / liquid mixture from top to bottom. In bars 5 and 6, the CO2 composition is initially in the liquid phase (top) and partially evaporates to a vapor / liquid mixture (bottom). In bar 7, the CO2 composition remains in the liquid phase from top to bottom.

[0071] Thus, in some embodiments, the method of the present invention comprises the steps of: injecting a CO2 composition that remains in the gas phase from the top of an injection well to the bottom of the well; injecting a CO2 composition that is in a vapor phase at the top of the injection well and changes to a vapor / liquid mixture along the injection well; injecting a CO2 composition along an injection well, the CO2 composition remaining in a vapor / liquid mixture; injecting a CO2 composition that is in a vapor / liquid mixed state at the top of the injection well and changes to a liquid state along the injection well; injecting a CO2 composition that remains in a liquid state along an injection well; may include:

[0072] These successive steps can span a period of months to years.

[0073] When stopping the flow of the CO2 composition in the injection well, it is generally desirable to increase the vapor CO2 to liquid CO2 ratio before stopping the injection, preferably moving to an injection of only vapor CO2 flow (this can be called the pre-shutdown phase). Indeed, if the injection well is filled with liquid CO2 when the injection is stopped, the problem of the sudden temperature drop mentioned above may occur. The pre-shutdown phase may be the final phase of the method, if the pressure in the reservoir has reached an appropriate level and no additional CO2 is to be injected. Alternatively, it may be an intermediate or intermittent phase, if the injection needs to be temporarily interrupted, for example for maintenance.

[0074] Bars 8 to 13 in FIG. 4 are an example of the pre-stop phase.

[0075] The pre-termination phase may last from a few seconds to several days, preferably from 1 minute to 12 hours, more preferably from 2 minutes to 1 hour.

[0076] 4 shows the general trend of a typical change in vapor CO2 to liquid CO2 ratio over time, but this ratio may be adapted and therefore varied in real time. The change in ratio may be a function of one or more of the following parameters: Head pressure (measured at the top of the injection well, either in real time or during interruptions in CO2 injection); Bottom hole pressure (measured at the bottom of the injection well); Liquid CO2 flow rate, Flow rate of steam CO2, and · Temperature (e.g., ambient temperature or temperature measured at the top of the injection well).

[0077] Ambient temperature measurements are particularly useful for onshore installations rather than offshore, since ambient temperature variations are much greater onshore than underwater.

[0078] For example, if the overall flow rate is below a set value and / or is trending downward, the vapor CO2 to liquid CO2 ratio can be decreased to increase the overall flow rate.

[0079] In another example, a change in head pressure or temperature may require the control unit to adjust the vapor CO2 to liquid CO2 ratio, which may result in fluctuations in the vapor CO2 to liquid CO2 ratio (i.e., an increase followed by a decrease, or a decrease followed by an increase) over a period ranging from 1 minute to several days, or from 1 day to 10 minutes, or from 1 hour to 12 hours.

Claims

1. CO ２ A method for storing CO ２ injecting the composition into a well of an underground reservoir; ２ The composition is vapor CO ２ Flow of liquid CO ２ and the flow of steam CO ２ Liquid CO ２ and forming said vapor CO by combining said vapor in a ratio of ２ Liquid CO ２ The ratio changes over time.

2. During injection into the underground reservoir, the liquid CO ２ and / or the flow rate of said vapor CO ２ and as a result of this measurement, the flow rate of the liquid CO ２ Steam CO ２ The method of claim 1 including the step of adjusting the ratio.

3. First, the vapor CO ２ The method of claim 1 or 2, comprising injecting only a flow of

4. The vapor CO ２ Liquid CO ２ The method of any one of claims 1 to 3, wherein the ratio is gradually decreased over time.

5. The liquid CO ２ The method of any one of claims 1 to 4, comprising the subsequent step of injecting chisel into the well.

6. CO injection at the entrance of the well ２ A method according to any one of the preceding claims, wherein the pressure of the composition is initially in the range of from 3 MPa to 7 MPa, such as in the range of from 3.5 MPa to 4.5 MPa.

7. CO at the entrance of the well ２ The method according to any one of claims 1 to 6, wherein the temperature of the composition is in the range of from 0°C to 30°C, such as in the range of from 5°C to 10°C.

8. The method according to any one of claims 1 to 7, wherein the initial pressure of the underground reservoir is in the range of 2 MPa to 20 MPa.

9. The vapor CO ２ Liquid CO ２ The method according to any one of claims 1 to 8, wherein the adjustment of the ratio is performed in real time.

10. The bottom hole pressure of the well is directly measured, and the steam CO ２ Liquid CO ２ The method of any one of claims 1 to 9, comprising the step of adjusting the ratio.

11. The top end temperature is measured, and the steam CO ２ Liquid CO ２ The method of any one of claims 1 to 10, comprising the step of adjusting the ratio.

12. The top pressure in the well is measured, and the steam CO ２ Liquid CO ２ The method of any one of claims 1 to 11, comprising adjusting the ratio.

13. The vapor CO ２ The liquid CO is evaporated by an evaporator. ２ The method according to any one of claims 1 to 12, wherein the sol is obtained by evaporating

14. The method according to any one of the preceding claims, wherein the length of the well is between 100m and 5km, for example between 2km and 4km.

15. The CO ２ The composition is CO ２ The process according to any one of claims 1 to 14, which in addition to the above comprises other compounds such as nitrogen or hydrocarbons, for example methane, ethane, propane and / or heavier hydrocarbons.

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

17. CO ２ A storage facility comprising: an injection well (110) in the underground reservoir (100); liquid CO2 connected to the inlet of said injection well (110); ２ An infusion line (107); steam CO connected to the entrance of said injection well (110); ２ an infusion line (106); The liquid CO ２ Injection line (107) and the vapor CO ２ flow meters (114, 116) and adjustable valves (118, 120) disposed along either or both of the injection lines (106); steam CO supplied to the injection well; ２ Liquid CO ２ a control unit (110) configured to vary the ratio; Including, facilities.

18. The system of claim 17 , wherein at least one pressure sensor (122) is positioned along the wellbore and / or at at least one bottom hole location.

19. 19. The installation of claim 17 or 18, wherein at least one temperature sensor (122) is positioned along the wellbore and / or at at least one bottom hole location.

20. liquid CO ２ is evaporated to produce vapor CO ２ a vaporizer (112) configured to convert the vaporized CO ２ Equipment according to any one of claims 17 to 19, arranged along an infusion line.

21. 21. The facility of any one of claims 17 to 20, wherein the underground reservoir is onshore or offshore.

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