NO338616B1 - Apparatus and method for storing carbon dioxide in underground geological formations - Google Patents

Description

Device for injecting C02 into an underground geological formation and method for storing C02 in an underground geological formation.

Field of the invention

The invention relates to a method and a device for storing carbon dioxide (C02) in underground geological formations. In particular, the invention relates to a device and a method that maximizes the amount of CO2 that can be stored in a specific formation, thereby increasing the usable capacity of a respective reservoir.

Background

Several studies indicate that C02 and other "greenhouse gases" are responsible for global climate change, which i.a. includes an increase in the average ambient temperature. This phenomenon is commonly referred to as "global warming". In order to prevent or reduce global warming, extensive research is conducted to identify strategies to reduce net carbon dioxide emissions. This includes the search for more efficient power plants, vehicles and aircraft, but also includes the concept of carbon dioxide sequestration in underground geological formations, such as in depleted oil and gas reservoirs and disused or non-minable coal deposits. One also envisages permanent C02 storage in aquifers, such as e.g. water-saturated underground formations of porous rock. It is generally believed that permanent storage of C02 in underground geological formations can make an important contribution to the reduction of C02 concentration in the atmosphere.

A comprehensive review of the existing technology is given in the IPCC Special Report on Carbon Dioxide Capture and Storage (IPCC, 2005, Bert Metz et al. (Eds.), Cambridge University Press, UK; also available from http:// www. ipcc. ch/ publications and data/ publications and data reports carbo n dioxi de.htm).

C02 storage in underground geological formations has been carried out in several industrial-scale projects, all of which are reviewed in the IPCC publication above. These projects use, to a large extent, conventional drilling and completion technology to inject large amounts of C02 (1 to 10 MtC02per year) into underground reservoirs.

C02 injection into an underground geological formation for Enhanced Oil Recovery (EO R) has been applied at the Rangely EO R project in Colorado, USA. A sandstone oil reservoir has been flooded with C02 using a WAG (alternating water and gas) process since 1986. In this project, C02 is used in a supercritical state to extract additional oil from the otherwise depleted oil fields in a tertiary oil recovery process. At the end of 2003, 248 active injectors, of which 160 are used for C02 injection, and 348 active producers were in use in the Rangely field. Injection of C02 takes place through slits in multiple vertical wells. Vertical wells have a relatively low injection capacity, and therefore there is a need for very many such wells. This technology is therefore labor-intensive and expensive.

The Sleipner project, operated by Statoil in the North Sea, is a commercial-scale project for the storage of C02 in an underground aquifer. C02 is stored in a supercritical state 250 km from the Norwegian coast. Approximately one million tonnes of C02 is removed annually from produced natural gas and then injected underground. C02 injection began in October 1996, and by 2008 more than ten million tons of C02 had been injected at a rate of approximately 2,700 tons per day. The formation into which the C02 is injected is a brine-saturated unconsolidated sandstone approximately 800-1000 m below the seabed. A shallow long-reach well is used to transport the C02 2.4 km away from the producing wells and platform area. The injection site is located under a local dome in the upper Utsira Formation. Since all C02 is injected approximately at the terminal end of the long-distance well, the C02 is not efficiently distributed over large areas of the receiving Utsira Formation. Thus, the capacity of the underground geological formation is not utilized to the full extent.

The In Salah CCS project is an onshore project for the production of natural gas from a gas reservoir located in an underground aquifer. The aquifer is located in the Sahara desert. The reservoir is in a coal-bearing sandstone formation, 2000 m deep. It is only 20 m thick and generally has low permeability. Natural gas containing up to 10% C02 is produced. C02 is separated and then reinjected into the water-filled parts of the reservoir. The project uses four production and three injection wells. Three long-distance horizontal wells with gap intervals over 1 km are used to inject 1 MtC02per year. The amount of C02 injected through the fissure intervals is dependent on the local permeability of the formation at the respective fissure intervals. Since the permeability is not constant, more CO2 is injected through the gap intervals in some areas (which have higher permeability than others) than through the gap intervals in other areas. This thus results in an uneven distribution of the injected mass flow. Furthermore, this uneven distribution of C02 injection leads to a significant pressure drop inside the injection well in these areas. This in turn leads to an even lower injection rate in the (more distal) areas with low permeability in the geological formation. This adds to the uneven distribution of C02 injection in the horizontal length of the well.

US 5,503,226 mentions injection of fluid into geological formations. It discloses a process for recovering hydrocarbons from a subterranean formation having low permeability matrix blocks and high permeability matrix blocks. Hot light gas (in one embodiment C02 gas) is injected through an injection well into the formation to heat the matrix blocks and to form and enlarge a gas mantle in a fracture network and ultimately to release significant portions of the hydrocarbons contained in the matrix blocks with low permeability. In one embodiment, an injection/production well comprising a vertical part and a horizontal part is used. The vertical part is lined, while the horizontal part is completed open hole. C02 is injected into the horizontal open hole section through the terminal opening of a tubing string placed inside the well. No means for providing an even distribution of CO 2 injection into the formation along the longitudinal extent of the well is provided. This thus results in an uneven distribution of (local) C02 injection.

WO 2009/088293 Al deals with a method for injecting fluid into geological formations. WO 2009/088293 deals with a method for self-adjustment of the fluid flow through multiple injection valves in an oil production process.

US 2010/126720 Al describes a method for injecting steam into a hydrocarbon-bearing formation. In this method, the injection openings are located according to the permeability of the formation around the horizontal part of the well.

US 5435393 A relates to a method for injecting fluids into an oil or gas reservoir. For this purpose, a drainage pipe is used, which pipe includes one or more devices to limit inflow.

The prior art has not identified the uneven distribution of CO 2 injectivity along the horizontal extent of the injection well as being problematic. Until now, the uneven distribution, especially the large injectivity in areas of high permeability, has only been considered to be an advantage, since this maximizes the flow of C02 into the formation.

Simulations performed by the present inventors have now shown that the non-uniform distribution of CO 2 injection into the formation has negative effects on the overall utilization of the storage capacity of the formation. Without wishing to be bound by theory, it is believed that the uneven distribution of the injected amount of C02 leads to a situation where large amounts of C02 are stored in the areas of high permeability of the formation, while the areas of low permeability in reality remain unused. Furthermore, it has been shown that a significant pressure drop in areas with high permeability leads to ineffective injection through the more distal parts of the injection well.

In light of the shortcomings of the known technique discussed above, it is now an object of the present invention to provide devices and methods for the permanent storage of C02i underground formations, which devices and methods enable a more complete utilization of the formation's available storage capacity. One purpose of the present invention is to provide devices and methods for storing a larger amount of C02 in a formation of a certain size and capacity. One purpose of the present invention is to provide methods and devices that effectively utilize the storage capacity of geological formations that have significant differences in permeability at various locations within the formation. As will be apparent from the description of the invention below, methods and devices according to the present invention are to a certain extent dependent on hardware components and technology that have already been used in other technical contexts, for various technical purposes within the drilling industry.

Such methods and such technology will now be briefly described.

GB 2 325 949 describes a method for achieving equalized production from deviated production wells comprising a plurality of separate flow control units. Each control unit includes a flow valve and control units to control the inflow of oil to the production well. The fluid from different zones is drawn in a way that empties the reservoir evenly along the entire length of the production well. GB 2 325 949 currently does not relate to the injection of fluids, especially C02, into geological formations. The use of flow control devices for injection of fluids into formations is not imagined or implied. There are also no indications that the mentioned flow control units would be suitable for injection, in particular for C02 injection.

GB 2 376 488 describes an apparatus and a method for controlling fluid production in a diverted production well comprising a plurality of control valves for inflow. The valves are self-regulating or selectively controllable, and they maintain a substantially constant pressure drop between the outside and inside of the flow pipe. Use of the C02 injection control units, or suitability of the inflow control valves, is not shown or implied.

US 5,141,054 describes a well completion method for steam stimulation of vertical and horizontal oil production wells. Steam is injected through multiple perforations of controlled size and is used to reduce the viscosity of the viscous hydrocarbon fluids near the horizontal well. The method seeks to achieve uniform heating along a desired length of the horizontal well. Storage of the injected fluid, not to mention increasing the storage capacity of the formation for such fluids, is not imagined or taught.

US 5,826,655 describes a method and an apparatus for improved extraction of viscous oil. A horizontal well is drilled through a formation with viscous oil, and a specially designed injection pipe, with multiple holes, is used to inject the steam evenly into an external cavity in the horizontal wellbore. The multiple holes in the steam injection pipe are all equipped with a sacrificial deflection band to prevent steam hitting the strainer tube directly, thus preventing early erosion of the strainer tube. Steam does not enter the geological formation through these multiple holes, but through the slots in the conventional strainer pipe, placed around the injection pipe. Since the steam can move freely in the annular cavity, laterally out of the injection pipe and laterally into the screening pipe, there is nothing to prevent the steam from entering the geological formation, preferably in parts of the formation that have a high permeability to steam.

WO 2008/092241 describes a method for improved oil recovery, a method in which steam is distributed and injected through perforations into an annulus between an inner tube and an outer screen tube in a horizontal injection well. The steam is then injected from the annulus into the oil-bearing geological formation through slits in the conventional strainer tube. The inner tube string is equipped with multiple ports that have a selected distribution and geometry. This causes the steam to be injected into the annulus in a defined manner. Injection of steam into the geological formation is additionally controlled by varying the cross-sectional area of the annulus between the inner tube and the sieve tube, so that the axial flow resistance in the annulus is controlled. In one embodiment, the perforated pipe is placed directly in an open hole borehole. Methods of injecting C02 into underground formations, not to mention methods of increasing the available storage capacity of underground reservoirs, are not envisioned. It is also not anticipated that injecting fluids uniformly along the entire horizontal extent of an injection well would maximize the amount of C02 that can be stored in a particular formation.

US 2 009 008 092 Al discusses various inflow control units for use in oil production. The inflow control devices include a plurality of orifices each providing a flow path to the interior of the production pipe. It is not mentioned that the mentioned units can be used in the reversed flow directions, nor is it likely that they are suitable for controlling the flow of less viscous fluids, such as CO2.

Brief description of the invention

The present invention relates to a device for injecting C02 into a supercritical state in an underground geological formation, where said device comprises a conduit pipe having a proximal part and a distal part, where at least parts of said distal part run in a substantially horizontal direction ; multiple openings provided in said distal portion of said conduit for injection of CO 2 into said geological formation; wherein said multiple openings are equipped with outflow limiting means to limit the flow rate of CO2 through respective said opening into said geological formation; and

where the distance between every two adjacent outflow limiting bodies is reduced along the length of said conduit in the direction towards the distal end, and where said outflow limiting bodies comprise at least one capillary tube which fluidly connects an internal cavity in said conduit with said geological formation.

In a preferred embodiment, said multiple openings are provided in a lateral surface of said conduit.

In a further preferred embodiment, the strength of the outflow limiting means is reduced by reducing the outflow between every two adjacent outflow limiting members along the length of said conduit in the direction towards the distal end.

In a further preferred embodiment, the distance between every two adjacent outflow limiting members is reduced along the length of said conduit in the direction towards the distal end.

In a further preferred embodiment, at least one of said outflow limiting members is adjustable.

In a further preferred embodiment, said conduit is a branched conduit comprising a primary branch and at least one secondary branch. The at least one secondary branch preferably exits from said primary branch in a branch point, where said branch point is provided with branch flow controlling means to limit the flow of CO 2 into the respective secondary branch. In this embodiment, it is preferred that at least one secondary conduit is substantially horizontal.

In a further preferred embodiment, said secondary conduit which branches off from said primary branch at a branch point near a distal end of said main conduit can remain as an open hole.

In preferred devices according to the invention, the conduit is closed at its distal ends. Alternatively, a distal end portion of the conduit may remain open hole.

In a preferred embodiment, said device comprises pressure-producing means to produce a pressure in said conduit which is sufficient for injection of C02 in a supercritical state into said geological formation. The device may comprise a source for C02.

The pressure-producing means can e.g. be a pump, a C02 pressure vessel or a C02 pressure pipeline.

In a further preferred embodiment, said outflow limiting means comprise at least one capillary tube which fluidly connects an inner cavity in said conduit pipe with said geological formation.

In a further preferred embodiment, said capillary tube opens at its proximal end towards an internal cavity in said conduit pipe and opens at its distal end into the geological formation.

In a further preferred embodiment, said capillary tube is a helical capillary tube, coiled around, and laterally outward, an inner surface of said conduit tube.

In a further preferred embodiment, said capillary tube has a circular, triangular, rectangular or square cross-sectional area. The capillary tube preferably has a cross-sectional area of 10 mm<2> to 500 mm<2>. Preferably, the capillary tube has a length of from 10 cm to 500 m, from 10 cm to 200 m or preferably from 1 m to 100 m. Preferably, the length of the capillary tube is more than 5 times, 10 times, 20 times, 100 times or 1000 times greater than the largest diameter of the capillary tube. Preferably, the length of the capillary tube is more than 5 times, 10 times, 20 times, 100 times or preferably 1000 times greater than the square root of the largest cross-sectional area of the capillary tube.

Preferably, the geological formation is an aquifer or a closed aquifer or a closed aquifer.

In a further preferred embodiment, said device for permanent storage of C02 is said geological formation.

The present invention also relates to the use of devices according to the invention for C02 injection in underground geological formations.

The present invention also relates to methods for storing C02 in underground geological formations using the devices described above.

The invention thus also relates to a method for storing C02 in an underground geological formation, where said method comprises: introducing C02 into a conduit which has a proximal part and a distal part, where at least parts of said distal part run in a substantially horizontal direction; and uniformly injecting said CO 2 in a supercritical state through multiple openings into said geological formation,

where said multiple openings are placed in said distal part of said conduit and each is equipped with flow-limiting means

to limit the flow rate of C02 through each of said multiple openings into said geological formation and where said organs comprise at least one capillary tube which fluidly connects an inner cavity in said conduit with said geological formation.

In preferred methods according to the present invention, a device as described above is used.

Brief description of the figures

Figure 1 shows a first embodiment of the invention.

Figure 2 shows a second embodiment of the invention.

Figure 3 shows flow limiting members according to one aspect of the present invention.

Detailed description of the invention

The present invention relates to a method and a device for the permanent storage of CO2 in underground geological formations.

An "aquifer", within the context of the present invention, is to be understood as a subsoil layer of water-bearing permeable rock or unconsolidated materials (gravel, sand, silt or clay). An aquifer may be sealed by an aquitard or aquiclude at an upper or lower boundary. Such aquifers will henceforth be called "closed aquifers". An aquifer can also be sealed at both the upper and lower boundaries. Such aquifers will henceforth be called "closed aquifers". Preferred aquifers, according to the invention, are upward convex aquifers or downward convex aquifers. The "aquifer" may, within the context of the present invention, also be called the "reservoir".

"Flow limiting means" shall, within the context of the present invention, be understood to be any means suitable for limiting the mass flow of fluid through an opening or conduit, preferably in a defined manner. Preferred flow limiting means comprise elongated conduits of a relatively small diameter, e.g. a capillary tube. Preferred capillary tubes have a circular, elliptical, rectangular or square cross-sectional area.

A "capillary tube" shall, within the context of the present invention, be understood to be an elongated conduit tube. The use of the term "capillary tube" should not imply that the capillary tube transmits its pressure-reducing effect completely by so-called "capillary forces". A pressure drop along the length of a capillary tube according to the present invention preferably originates from the friction of fluids moving along the capillary tube's extended conduit.

An "open hole", or a "well completed open hole", shall be understood as relating to an unlined part of a well, i.e. the well in a state where it has been drilled, without casing, pipe or similar placed at the outer circumference.

The "permeability" of a formation, within the context of the present invention, is the ability of the formation to transmit fluids in response to an imposed pressure differential. Permeability is usually measured in darcy or millidarcy. [Converted to SI units, 1 darcy is equivalent to 9.869233x10-13 m<2>or 0.9869233 (u m)<2>. This conversion can be approximated as 1 (u m)<2>.] Formations that readily transmit fluids, such as sandstone, are described as permeable and tend to have many large, well-connected pores. Impermeable formations, such as shale and siltstone, tend to be finer grained or have a mixed grain larger I se, with smaller, fewer or less interconnected pores.

"Substantially horizontal", within the context of the present invention, shall mean at an angle of between 45°-135° or 80°-100° or 85°-95° or 90° from vertical.

"Substantially vertical", within the context of the present invention, shall mean at an angle of less than 45°, less than 20°, less than 10°, less than 5° or 0° from vertical.

The present invention is based on the unexpected finding that a geological formation's available storage capacity for C02 can be utilized most efficiently if the C02 is injected from multiple injection points along the length of a long-distance horizontal well in such a way that the mass flow of C02 into the formation is approximately constant along the entire the length of the horizontal well. While there has previously been a common desire in the art to inject large amounts of C02 in as short a time as possible, the inventors of the present invention have used a very different approach. By limiting the radial mass flow of C02 to a certain maximum value, the present invention produces a substantially even distribution of the radial mass flow over large parts of the horizontal extent of the injection well. This leads to a reduced radial mass flow [kg/s] into the formation, but this obstacle is more than offset by the fact that the total amount of C02 that can be stored in a given formation is dramatically increased. Figure 1 generally shows a device according to the present invention. Device 1 is used to inject large amounts of C02 into the underground formation for permanent storage of C02deri. For this purpose, a conduit 3 has been provided which extends from a point above the surface down into formation 2 where the C02 is to be stored. The geological formation can e.g. be a depleted oil field, a depleted gas field or an aquifer. The aquifer is preferably a closed aquifer or a closed aquifer. The geological formation is preferably more than 500 m underground. The geological formation is preferably 5 to 1000 m, preferably 20 to 200 m thick.

Conduit 3 comprises a proximal end part 4 and a distal end part 5. The distal end part 5 comprises a generally horizontal part. The horizontal (distal) part is preferably provided in the form of a long-running horizontal well and is preferably between 100 m and 2000 m long. This enables CO2 to be injected into the formation at multiple injection points along the entire length of the conduit. C02 storage is thus distributed over a large area/volume in the reservoir formation.

The device comprises pressure-producing organs 10, e.g. a pump, to inject C02 into the geological formation. In other preferred embodiments of the invention, the pressure producing means may be a CO 2 pressure vessel or a CO 2 pressure pipeline. The CO 2 , when injected, is preferably in a supercritical state. Thus, all components in the device must be correctly designed and constructed so that they are able to withstand the demanding conditions surrounding their use. Materials must be chosen correctly to withstand the very high pressures and corrosion, especially when the C02 that is injected is not pure C02, but contains e.g. water and/or other corrosive contaminants, such as O2 or SO2. Pressure producing means are preferably capable of producing pressures of more than 73, 100, 200, 500 or 1000 bar.

Conduit 3 comprises multiple openings 6a-6z in a distal part, through which openings C02 is injected into the formation. At least one, but preferably all openings are equipped with outflow limiting means 7a-7z. The outflow restricting means 7a-7z serve to reduce the radial mass flow of CO 2 through the individual openings 6a-6z. The radial mass flow is most effectively reduced in areas of the formation that have high permeability. This is due to the fact that the radial mass flow in these areas - without outflow limiting devices - would be very large. In areas of the formation that have low permeability to C02, the mass flow into the formation is low from the start. Flow-limiting devices have little effect in these areas. As a result of the more effective flow restriction in highly permeable areas, a substantially uniform mass flow distribution along the entire horizontal length of the injection well is achieved. In other words, the mass of C02 injected per unit time and per unit length of the conduit is approximately constant.

It is this uniform distribution of the radial mass flow rate that is believed to produce the unforeseen effect of the invention, namely that the available CO 2 storage capacity in the formation can be used to a much greater extent than without radial flow limitation.

Figure 2 shows a second embodiment of the invention. In this embodiment, conduit 3 is a branched conduit. Secondary branch 9 starts from primary branch 8 at branch point 10. Multiple secondary branches 9 can be provided. In one embodiment (not shown), conduit 3 comprises further tertiary branches or branches of an even higher degree, which proceed from the respective branches of a lower degree.

In order to be able to control the mass flow of CO 2 into the secondary branches 9, branch flow controlling means 13 can be provided. Branch flow controlling means 13 can be in the form of a damper or a valve, preferably a controllable valve.

Outflow limiting means 7a-7z may be in the form of an extended capillary tube. Preferred capillary tubes have a circular, elliptical, rectangular or square cross-sectional area. They preferably have a cross-sectional area of from 10 mm<2> to 500 mm<2> and, independently, a preferred length of from 10 cm to 500 m, from 10 cm to 200 m or from 1 m to 100 m. Preferred capillary tubes according to the invention is helically coiled.

Capillary tubes according to the present invention are preferably designed so that, under operating conditions, they produce a pressure drop along the length of the capillary tube of from 0.5 bar to 5 bar.

According to another preferred embodiment of the present invention, the outflow limiting means 7a-7z may be modified "inflow control devices" (ICDs), e.g. of the type mentioned in US 2 009 008 092 Al. It must be stated at the outset that these ICDs used for oil production are usually not suitable and need significant modification to be useful in the context of the present invention. This is due, among other things, to the fact that the direction of the fluid flow through the units is reversed. Furthermore, the viscosity of fluids in oil production is generally higher than that of C02, e.g. in a supercritical condition. Thus, the cross-sectional area and/or the length of the lead pipes in the ICDs must be changed in the correct way. In addition, the relevant pressure system is different in methods according to the present invention compared to oil production. In methods according to the present invention, the pressure inside the injection well can be selected with an overlay, e.g. of the correct pressure producing means, whereas in oil production the pressure driving the fluid transport is usually determined by the pressure naturally occurring in the reservoir.

It should also be noted that the known inflow control devices would not ordinarily be suitable for use in the devices and methods of the present invention without significant modification, due to the extremely corrosive nature of the supercritical CO2 (at least when impurities such as as water or other corrosive gases are also present). Therefore, outflow limiting devices according to the present invention must be made of highly corrosion-resistant materials.

Outflow limiting members 7a-7z may be provided in the form of an extended conduit or an extended capillary tube 12. Flow limiting members 7a-7z may be adjustable. Adjustment of the outflow limiting effect can be achieved by controlling (reducing or increasing) the cross-sectional area of the elongated conduits or capillary tubes. The flow through flow limiting members 7a-7z can also be adjusted by e.g. to control the effective length of the extended lead pipes or capillary tubes. Alternatively, the flow through flow-limiting members 7a-7z can be adjusted by changing the shape of the cross-sectional area of conduit tubes or capillary tubes in flow-limiting members 7a-7z.

In the embodiment shown in Figure 3, the flow-limiting means 7 are in the form of a helical capillary tube 12, twisted around, and placed radially outward, an inner surface of conduit tube 3. Capillary tube 12 opens at a first (proximal) end 19 into the inner cavity 18 in conduit 3. A second (distal) end 20 of capillary tube 12 opens into formation 2. Second end 20 can also be opened into a sand filter or a permeable tube (not shown) which is provided radially outward from conduit 3. Conduit 3 is thus preferably in close contact with the permeable tube. The permeable pipe is preferably in close contact with the formation.

Extended conduit tubes or capillary tubes 12 of a certain length are, in contrast to simple holes, capable of effectively controlling the mass flow of fluid at relatively modest pressures. Therefore, pumps with lower performance and price can be used. Furthermore, use under lower pressure also reduces erosion of the system's components, thereby increasing the lifetime of the system.

Outflow restrictors 7a-7z generally produce a significant pressure drop between their respective first and second ends. Because of this, the pressure required in conduit 4 to induce a sufficient radial mass flow is significantly higher than with conventional slotted wells. In order to be able to build a sufficiently high pressure in conduit 3, a plug 17 is preferably provided at a distal end of the conduit. In other embodiments, the distal ends of conduit 3 are not provided with a plug. They can be open hole wells. The latter embodiments may be appropriate in situations where the formation has low permeability at the distal ends of conduit 3, or where the horizontal portion 5 is very long.

As illustrated in Figure 3, conduit 3 may comprise multiple impermeable segments 15 and multiple outflow segments 16, where the multiple openings 6a-6z are only provided in the outflow segments 16 (ie not in impermeable segments 15). Multiple openings 6a-6z, or multiple helical capillary tubes 12, may be provided per outflow segment 16. Outflow segments 16 and impermeable segments 15 are preferably provided with a male connector at one end and a female connector at the other end. Impermeable segments 15 can be connected to each other and to outflow segments 16. Similarly, outflow segments 16 can be connected to each other and can be connected to impermeable segments 15. A seal 14 is preferably provided between any two interconnected impermeable segments 15 and/or outflow segments 16. Conduit 3 can therefore have a modular construction.

Outflow segments 16 (and preferably also impermeable segments 15) are preferably in direct contact with the formation, i.e. there is preferably no annular opening or annulus between the outflow segment and the reservoir material. This is useful to avoid significant axial flow of C02 radially beyond conduit 3. In other words, the outer surface of outflow segment 16 (and preferably also the outer surface of impermeable segment 15) is in contact with formation 2.

Alternatively, it can radially outward from conduit 3, e.g. radially outward from outflow segments 16 and/or impermeable segments 15, a sand filter or a permeable pipe (not shown) is placed. The sand filter or permeable pipe is preferably in contact with the conduit and the formation, so that significant axial mass flow of CO 2 is prevented. The permeable tube is preferably of a material having a permeability in the radial direction (to CO 2 ) equal to, or greater than, its permeability to CO 2 in the axial direction.

Reference number

Claims (10)

1. Device (1) for injecting C02 in a supercritical state into an underground geological formation (2), characterized in that said device comprises: a conduit pipe (3) which has a proximal part (4) and a distal part (5), where as a minimum parts of said distal part (5) run in a substantially horizontal direction; multiple openings (6a-6z) which are placed in said distal part (4) of said conduit (3) for injection of CO2 into said geological formation (2); wherein said multiple openings (6a-6z) are equipped with outflow limiting means (7) to limit the flow rate of CO2 through respective said opening (6a-6z) into said geological formation (2); and where the distance between every two adjacent outflow limiting bodies (7) is reduced along the length of said conduit in the direction towards the distal end, and where said outflow limiting bodies (7) comprise at least one capillary tube (12) which fluidly connects an inner cavity (18) in said conduit (3) with said geological formation. 2. Device according to claim 1, characterized in that said capillary tube (12) opens at its proximal end (19) towards an inner cavity (18) in said conduit (3) and opens at its distal end (20) into the geological formation. 3. Device according to claim 1, characterized in that said conduit (3) is a branched conduit comprising a primary branch (8) and at least one secondary branch (9). 4. Device according to claim 2, characterized in that said at least one secondary branch (8) exits from said primary branch (9) in a branch point (10), where said branch point (10) is equipped with branch flow controlling means (14) to limit the flow of C02 into the respective secondary branch (9). 5. Device according to any one of the preceding claims, characterized in that said conduit (3) is closed at its distal ends. 6. Device according to any one of claims 1 to 4, characterized in that a distal end part of said conduit (3) is an open hole. 7. Device according to any one of the preceding claims, characterized in that said device comprises pressure-producing means (11) to produce a pressure in said conduit pipe (3) which is sufficient for injection of C02 in a supercritical state into said geological formation (2). 8. Device according to any one of the preceding claims, characterized in that said geological formation (2) is an aquifer. 9. Method for storing C02 in an underground geological formation, characterized in that said method comprises: introducing C02 into a conduit pipe (3) which has a proximal part (4) and a distal part (5), where at least parts of said distal part (5) runs in a substantially horizontal direction; and uniform injection of said C02 in a supercritical state through multiple openings (6a-6z) into said geological formation (2), where said multiple openings (6a-6z) are placed in said distal part (4) of said conduit pipe (3) and each is equipped with flow limiting means (7) to limit the flow rate of C02 through each of said multiple openings (6a-6z) into said geological formation (2) and where said means (7) comprises at least one capillary tube (12) as on a fluid way connects an inner cavity (18) in said conduit (3) with said geological formation. 10. Method according to claim 9, characterized in that said CO 2 is injected through a device according to any one of claims 1-8.