CA2807194A1 - Methods and arrangements for carbon dioxide storage in subterranean geological formations - Google Patents
Methods and arrangements for carbon dioxide storage in subterranean geological formations Download PDFInfo
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- 230000015572 biosynthetic process Effects 0.000 title claims abstract description 95
- 238000000034 method Methods 0.000 title claims abstract description 34
- 238000003860 storage Methods 0.000 title claims abstract description 24
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 title description 188
- 229910002092 carbon dioxide Inorganic materials 0.000 title description 94
- 239000001569 carbon dioxide Substances 0.000 title description 94
- 238000005755 formation reaction Methods 0.000 title description 82
- 238000002347 injection Methods 0.000 claims abstract description 42
- 239000007924 injection Substances 0.000 claims abstract description 42
- 230000000670 limiting effect Effects 0.000 claims abstract description 40
- 230000003247 decreasing effect Effects 0.000 claims description 3
- 230000035699 permeability Effects 0.000 description 21
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- 230000001965 increasing effect Effects 0.000 description 6
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 6
- 239000000463 material Substances 0.000 description 5
- 239000011159 matrix material Substances 0.000 description 4
- 238000011084 recovery Methods 0.000 description 4
- 230000001603 reducing effect Effects 0.000 description 4
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 4
- 230000000694 effects Effects 0.000 description 3
- 239000003345 natural gas Substances 0.000 description 3
- 238000010793 Steam injection (oil industry) Methods 0.000 description 2
- 238000005260 corrosion Methods 0.000 description 2
- 230000007797 corrosion Effects 0.000 description 2
- 238000005553 drilling Methods 0.000 description 2
- 230000003628 erosive effect Effects 0.000 description 2
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 150000002430 hydrocarbons Chemical class 0.000 description 2
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- 238000010792 warming Methods 0.000 description 2
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 235000015076 Shorea robusta Nutrition 0.000 description 1
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- 238000006243 chemical reaction Methods 0.000 description 1
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- 239000003245 coal Substances 0.000 description 1
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- 238000010438 heat treatment Methods 0.000 description 1
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- 238000004088 simulation Methods 0.000 description 1
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Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
- E21B41/005—Waste disposal systems
- E21B41/0057—Disposal of a fluid by injection into a subterranean formation
- E21B41/0064—Carbon dioxide sequestration
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
- E21B41/0035—Apparatus or methods for multilateral well technology, e.g. for the completion of or workover on wells with one or more lateral branches
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/162—Injecting fluid from longitudinally spaced locations in injection well
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/164—Injecting CO2 or carbonated water
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/30—Specific pattern of wells, e.g. optimising the spacing of wells
- E21B43/305—Specific pattern of wells, e.g. optimising the spacing of wells comprising at least one inclined or horizontal well
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
- Y02C20/00—Capture or disposal of greenhouse gases
- Y02C20/40—Capture or disposal of greenhouse gases of CO2
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
- Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells
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- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Physics & Mathematics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Chemical & Material Sciences (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Physical Or Chemical Processes And Apparatus (AREA)
- Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
- Carbon And Carbon Compounds (AREA)
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Abstract
The invention concerns an arrangement (1) for injecting CO2 in a supercritical state into a subterranean geological formation (2), said arrangement comprising: a conduit (3) having a proximal portion (4) and a distal portion (5), at least part of said distal portion (5) extending in a substantially horizontal direction; multiple openings (6a-6z) being provided in said distal portion (4) of said conduit (3) for injection of CO2 into said geological formation (2);wherein said multiple openings (6a-6z) are provided with outflow limiting means (7) for limiting the flow rate of CO2 through respective said opening (6a-6z) into said geological formation (2). The invention also concerns a method for storage of CO2 by said arrangement.
Description
Methods and arrangements for carbon dioxide storage in subterranean geological formations Field of the invention The invention relates to methods and arrangements for carbon dioxide (CO2) storage in subterranean geological formations. In particular, the invention relates to arrangements and methods which maximize the amount of CO2 storable in a particular formation, thus increasing the usable capacity of a respective reservoir.
Background Several studies indicate that CO2 and other "greenhouse gases" are responsible for the global climate change, which i.a. includes an increase of the average ambient temperature. This phenomenon is generally referred to as "global warming". To prevent or reduce global warming, extensive research is conducted for identifying strategies of reducing net carbon dioxide emissions. This includes the search for more energy efficient power plants, vehicles and airplanes, but also includes the concept of carbon dioxide sequestration in subterranean geological formations, such as in depleted oil, gas reservoirs, and abandoned or non minable coal deposits. Permanent CO2 storage is also envisioned in aquifers, such as, e.g., water-saturated underground porous rock formations. It is generally believed that the permanent storage of CO2 in subterranean geological formations can make an important contribution to the reduction the concentration in the atmosphere.
An extensive review of the existing technology is provided in the "[VC 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 carbon dioxi de.htm).
CO2 storage in subterranean geological formations has been practiced in several industrial scale projects, all reviewed in the above "[VC publication. These projects employ, to a large extent, conventional drilling and completion technology to inject large quantities of CO2 (1 to 10 MtCO2 per year) into subterranean reservoirs.
CO2 injection into a subterranean geological formation for Enhanced Oil Recovery (E0R) has been applied in the Rangely EOR project, Colorado, USA. A sandstone oil reservoir has been flooded with CO2 by a water-alternating-gas (WAG) process since 1986. In this project, CO2 in a supercritical state is used to extract additional amounts of oil from the otherwise exhausted oil fields in a tertiary oil recovery process. By the end of 2003, 248 active injectors of which 160 are used for CO2 injection and 348 active producers were in use in the Rangely field. Injection of CO2 occurs through slots in multiple vertical wells. Vertical wells have a relatively low injection capacity; therefore a great number of such wells are needed. This technology is thus laborious and expensive.
The Sleipner Project, operated by Statoil in the North Sea, is a commercial scale project for the storage of CO2 in a subterranean aquifer. CO2 is stored in supercritical state 250 km off the Norwegian coast. About one million tons of CO2 is removed from produced natural gas and subsequently injected underground, annually. CO2 injection started in October 1996 and by 2008, more than ten million tons of CO2 had been injected at a rate of approximately 2700 tons per day. The formation into which the CO2 is injected is a brine-saturated unconsolidated sandstone about 800-1000 m below the sea floor.
A
shallow long-reach well is used to take the CO2 2.4 km away from the producing wells and platform area. The injection site is placed beneath a local dome of the top Utsira formation. Since all CO2 is injected at approximately the terminal end of the long reach well, the CO2 is not efficiently distributed over large areas of the receiving Utsira Formation. Thus the capacity of the subterranean geological formation is not used to its full extent.
The In Salah CCS Project is an onshore project for the production of natural gas from a gas reservoir located in a subterranean aquifer. The aquifer is located in the Sahara desert. The reservoir is in a carboniferous sandstone formation, 2000 m deep.
It is only 20 m thick, and of generally low permeability. Natural gas containing up to 10% of CO2 is produced. CO2 is separated, and subsequently re-injected into the water-filled parts of the reservoir. The project uses four production and three injection wells.
Three long-reach horizontal wells with slotted intervals over 1 km are used to inject 1 MtCO2 per year. The amount of CO2 injected through the slotted intervals depends from the local permeability of the formation at the respective slotted intervals. Since the permeability is not constant, more CO2 is injected through slotted intervals in some areas (having higher permeability than others) than through the slotted intervals in other areas. Hence, an uneven distribution of the injected mass flow results. Furthermore, this uneven distribution of CO2 injection leads to a significant pressure drop at the interior of the injection well in these areas. This, in turn leads to an even lower rate of injection at the (more distal) regions of low permeability of the geological formation. This adds to the uneven distribution of CO2 injection of 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, CO2 gas) is injected through an injection well into the formation to heat the matrix blocks, and to create and enlarge a gas cap in a fracture network, and ultimately to liberate significant portions of the hydrocarbons present in the low permeability matrix blocks. In one embodiment an injection/production well is used which comprises a vertical section and a horizontal section. The vertical section is cased, while the horizontal section is completed open hole. CO2 is injected into the horizontal open hole section through the terminal opening of a tubing string disposed within the well. No means for providing an even distribution of CO2 injection into the formation over the longitudinal extent of the well is provided. Hence, an uneven distribution of (local) CO2 injection results.
The prior art has not identified the uneven distribution of the CO2 injectivity over the horizontal extent of the injection well as being problematic. Until to date, the uneven distribution, in particular the large injectivity at regions of high permeability, was merely seen as an advantage, because this maximizes the current flow of CO2 into the formation.
Background Several studies indicate that CO2 and other "greenhouse gases" are responsible for the global climate change, which i.a. includes an increase of the average ambient temperature. This phenomenon is generally referred to as "global warming". To prevent or reduce global warming, extensive research is conducted for identifying strategies of reducing net carbon dioxide emissions. This includes the search for more energy efficient power plants, vehicles and airplanes, but also includes the concept of carbon dioxide sequestration in subterranean geological formations, such as in depleted oil, gas reservoirs, and abandoned or non minable coal deposits. Permanent CO2 storage is also envisioned in aquifers, such as, e.g., water-saturated underground porous rock formations. It is generally believed that the permanent storage of CO2 in subterranean geological formations can make an important contribution to the reduction the concentration in the atmosphere.
An extensive review of the existing technology is provided in the "[VC 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 carbon dioxi de.htm).
CO2 storage in subterranean geological formations has been practiced in several industrial scale projects, all reviewed in the above "[VC publication. These projects employ, to a large extent, conventional drilling and completion technology to inject large quantities of CO2 (1 to 10 MtCO2 per year) into subterranean reservoirs.
CO2 injection into a subterranean geological formation for Enhanced Oil Recovery (E0R) has been applied in the Rangely EOR project, Colorado, USA. A sandstone oil reservoir has been flooded with CO2 by a water-alternating-gas (WAG) process since 1986. In this project, CO2 in a supercritical state is used to extract additional amounts of oil from the otherwise exhausted oil fields in a tertiary oil recovery process. By the end of 2003, 248 active injectors of which 160 are used for CO2 injection and 348 active producers were in use in the Rangely field. Injection of CO2 occurs through slots in multiple vertical wells. Vertical wells have a relatively low injection capacity; therefore a great number of such wells are needed. This technology is thus laborious and expensive.
The Sleipner Project, operated by Statoil in the North Sea, is a commercial scale project for the storage of CO2 in a subterranean aquifer. CO2 is stored in supercritical state 250 km off the Norwegian coast. About one million tons of CO2 is removed from produced natural gas and subsequently injected underground, annually. CO2 injection started in October 1996 and by 2008, more than ten million tons of CO2 had been injected at a rate of approximately 2700 tons per day. The formation into which the CO2 is injected is a brine-saturated unconsolidated sandstone about 800-1000 m below the sea floor.
A
shallow long-reach well is used to take the CO2 2.4 km away from the producing wells and platform area. The injection site is placed beneath a local dome of the top Utsira formation. Since all CO2 is injected at approximately the terminal end of the long reach well, the CO2 is not efficiently distributed over large areas of the receiving Utsira Formation. Thus the capacity of the subterranean geological formation is not used to its full extent.
The In Salah CCS Project is an onshore project for the production of natural gas from a gas reservoir located in a subterranean aquifer. The aquifer is located in the Sahara desert. The reservoir is in a carboniferous sandstone formation, 2000 m deep.
It is only 20 m thick, and of generally low permeability. Natural gas containing up to 10% of CO2 is produced. CO2 is separated, and subsequently re-injected into the water-filled parts of the reservoir. The project uses four production and three injection wells.
Three long-reach horizontal wells with slotted intervals over 1 km are used to inject 1 MtCO2 per year. The amount of CO2 injected through the slotted intervals depends from the local permeability of the formation at the respective slotted intervals. Since the permeability is not constant, more CO2 is injected through slotted intervals in some areas (having higher permeability than others) than through the slotted intervals in other areas. Hence, an uneven distribution of the injected mass flow results. Furthermore, this uneven distribution of CO2 injection leads to a significant pressure drop at the interior of the injection well in these areas. This, in turn leads to an even lower rate of injection at the (more distal) regions of low permeability of the geological formation. This adds to the uneven distribution of CO2 injection of 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, CO2 gas) is injected through an injection well into the formation to heat the matrix blocks, and to create and enlarge a gas cap in a fracture network, and ultimately to liberate significant portions of the hydrocarbons present in the low permeability matrix blocks. In one embodiment an injection/production well is used which comprises a vertical section and a horizontal section. The vertical section is cased, while the horizontal section is completed open hole. CO2 is injected into the horizontal open hole section through the terminal opening of a tubing string disposed within the well. No means for providing an even distribution of CO2 injection into the formation over the longitudinal extent of the well is provided. Hence, an uneven distribution of (local) CO2 injection results.
The prior art has not identified the uneven distribution of the CO2 injectivity over the horizontal extent of the injection well as being problematic. Until to date, the uneven distribution, in particular the large injectivity at regions of high permeability, was merely seen as an advantage, because this maximizes the current flow of CO2 into the formation.
However, simulations conducted by the present inventors have now shown that the non-uniform distribution of CO2 injection into the formation has negative effect on the overall usage 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 CO2 leads to a situation in which large amounts of CO2 are stored in the high permeability regions of the formation, while the low permeability regions remain effectively unused.
Furthermore, a significant pressure drop in areas of high permeability has shown to lead to inefficient injection through the more distal parts of the injection well.
1 o In view of the above discussed shortcomings of the prior art technology, it is now an object of the present invention to provide arrangements and methods for the permanent storage of CO2 in subterranean formations, which arrangements and methods allow for a more complete use of the available storage capacity of the formation. It is an object of the present invention to provide arrangements and methods for storing a greater amount of CO2 in a formation of a given size and capacity. It is an object of the present invention to provide methods and arrangements which efficiently use of the storage capacity of geological formations having significant differences in the permeability at different locations within the formation.
As will be apparent from the description of the invention hereinbelow, methods and arrangements of the present invention rely, to some extent, on hardware components and technology which has already been applied in other technical contexts, for different technical purposes within the drilling industry.
Such methods and technology will now briefly be described.
GB 2325949 discloses a method for obtaining equalized production from deviated production wells comprising a plurality of spaced apart flow control devices.
Each control device includes a flow valve and control units to control inflow of oil into the production well. The fluid from various zones are drawn in a manner that depletes the reservoir uniformly along the entire length of the production well. GB
2325949, however, is not concerned with the injection of fluids, in particular CO2, into geological formations. The use of flow control devices for the injection of fluids into formations is not envisaged or suggested. Nor is there any indication that the disclosed flow control devices would be suitable for injection, in particular for CO2 injection.
GB 2376488 discloses an apparatus and method for controlling fluid production in a deviated production well which comprises a plurality of inflow control valves.
The valves are self regulating or selectively controllable, and they maintain a substantially constant pressure drop between the exterior and the interior of the flow pipe.
Application of the controlling devices for CO2 injection, or the suitability of the inflow 1 o control valves, is not shown or suggested.
US 5,141,054 discloses a well completion method for steam stimulation of vertical and horizontal oil production wells. Steam is injected through multiple perforations of controlled size, and used for lowering the viscosity of the viscous hydrocarbonaceous fluids in the vicinity of the horizontal well. The method seeks to achieve a uniform heating along a desired length of the horizontal well. Storage of the injected fluid, let alone, increasing the storage capacity of the formation for such fluids, is not envisaged or taught.
US 5,826,655 discloses a method and an apparatus for enhanced viscous oil recovery. A
horizontal well is drilled through a viscous oil formation, and a specially designed steam injection tube, with multiple holes, is used to evenly inject the steam into an outer lumen of the horizontal wellbore. The multiple holes in the steam injection tube are each provided with a sacrificial impingement strap, in order to avoid direct impingement of steam on the slotted liner, and thus, to prevent early erosion of the slotted liner. Steam enters the geological formation not through these multiple holes, but through the slots of the conventional slotted liner, provided around the injection tube.
Since the steam can freely move in the annular lumen, laterally outward the injection tube and laterally inward the slotted liner, nothing prevents the steam to enter the geological formation preferentially in parts of the formation having high permeability for steam.
Furthermore, a significant pressure drop in areas of high permeability has shown to lead to inefficient injection through the more distal parts of the injection well.
1 o In view of the above discussed shortcomings of the prior art technology, it is now an object of the present invention to provide arrangements and methods for the permanent storage of CO2 in subterranean formations, which arrangements and methods allow for a more complete use of the available storage capacity of the formation. It is an object of the present invention to provide arrangements and methods for storing a greater amount of CO2 in a formation of a given size and capacity. It is an object of the present invention to provide methods and arrangements which efficiently use of the storage capacity of geological formations having significant differences in the permeability at different locations within the formation.
As will be apparent from the description of the invention hereinbelow, methods and arrangements of the present invention rely, to some extent, on hardware components and technology which has already been applied in other technical contexts, for different technical purposes within the drilling industry.
Such methods and technology will now briefly be described.
GB 2325949 discloses a method for obtaining equalized production from deviated production wells comprising a plurality of spaced apart flow control devices.
Each control device includes a flow valve and control units to control inflow of oil into the production well. The fluid from various zones are drawn in a manner that depletes the reservoir uniformly along the entire length of the production well. GB
2325949, however, is not concerned with the injection of fluids, in particular CO2, into geological formations. The use of flow control devices for the injection of fluids into formations is not envisaged or suggested. Nor is there any indication that the disclosed flow control devices would be suitable for injection, in particular for CO2 injection.
GB 2376488 discloses an apparatus and method for controlling fluid production in a deviated production well which comprises a plurality of inflow control valves.
The valves are self regulating or selectively controllable, and they maintain a substantially constant pressure drop between the exterior and the interior of the flow pipe.
Application of the controlling devices for CO2 injection, or the suitability of the inflow 1 o control valves, is not shown or suggested.
US 5,141,054 discloses a well completion method for steam stimulation of vertical and horizontal oil production wells. Steam is injected through multiple perforations of controlled size, and used for lowering the viscosity of the viscous hydrocarbonaceous fluids in the vicinity of the horizontal well. The method seeks to achieve a uniform heating along a desired length of the horizontal well. Storage of the injected fluid, let alone, increasing the storage capacity of the formation for such fluids, is not envisaged or taught.
US 5,826,655 discloses a method and an apparatus for enhanced viscous oil recovery. A
horizontal well is drilled through a viscous oil formation, and a specially designed steam injection tube, with multiple holes, is used to evenly inject the steam into an outer lumen of the horizontal wellbore. The multiple holes in the steam injection tube are each provided with a sacrificial impingement strap, in order to avoid direct impingement of steam on the slotted liner, and thus, to prevent early erosion of the slotted liner. Steam enters the geological formation not through these multiple holes, but through the slots of the conventional slotted liner, provided around the injection tube.
Since the steam can freely move in the annular lumen, laterally outward the injection tube and laterally inward the slotted liner, nothing prevents the steam to enter the geological formation preferentially in parts of the formation having high permeability for steam.
WO 2008/092241 discloses a method for enhanced oil recovery, in which method steam is distributed and injected through perforations into an annular space between an inner tubing and an outer slotted liner in a horizontal injection well. The steam is then injected from the annular space into the oil containing geological formation through slots in the conventional slotted liner. The inner tubing string is provided with multiple ports having a selected distribution and geometry. This causes the steam to be injected into the annular space in a defined manner. Injection of steam into the geological formation is additionally controlled by varying the cross sectional area of the annular space between the inner tubing and slotted liner, such that the axial flow resistance in the annular space is controlled. In one embodiment, the perforated tubing is placed directly in an open hole well bore. Methods for injecting CO2 into subterranean formations, let alone methods for increasing the available storage capacity of subterranean reservoirs, are not envisaged. It is likewise not foreseen that injecting fluids evenly over the entire horizontal extent of an injection well would maximize the amount of CO2 storable in a particular formation.
US2009008092 Al discloses various inflow control devices for use in oil production.
The inflow control devices include a plurality of openings that each provide a flow path to the interior of the production tube. It is not disclosed that the disclosed devices 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.
WO 2009/088293 discloses a method for self-adjusting the flow of fluid through a valve or flow control device in injectors in oil production.
US 5435393 A discloses a method for production of oil or gass from an oil or gas reservoir and a production pipe for injection of fluids into an oil or gas reservoir.
Summary of the invention The present invention relates to a arrangement for injecting CO2 in a supercritical state into a subterranean geological formation, said arrangement comprising a conduit having a proximal portion and a distal portion, at least part of said distal portion extending in a substantially horizontal direction; multiple openings being provided in said distal portion of said conduit for injection of CO2 into said geological formation;
wherein at least one, or all, of said multiple openings is/are provided with outflow limiting means for limiting the flow rate of CO2 through the respective opening into 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 in reducing the outflow between each two neighboring outflow limiting means is decreasing along the length of said conduit in the direction towards the distal end.
In a further preferred embodiment the distance between each two neighboring outflow limiting means is decreasing along the length of said conduit in the direction towards the distal end.
In a further preferred embodiment at least one said outflow limiting means 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 branches off said primary branch in a branch point, said branch point being provided with branch-flow controlling means for limiting the flow of CO2 into the respective secondary branch. In this embodiment, it is preferred that said at least one secondary conduit is substantially horizontal.
In a further preferred embodiment said secondary conduit that branches off said primary branch in a branch point near a distal end of the said main conduit can be left as open hole.
In preferred arrangements of the invention the conduit is closed at its distal ends.
Alternatively, a distal end portion of the conduit is left as open hole.
US2009008092 Al discloses various inflow control devices for use in oil production.
The inflow control devices include a plurality of openings that each provide a flow path to the interior of the production tube. It is not disclosed that the disclosed devices 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.
WO 2009/088293 discloses a method for self-adjusting the flow of fluid through a valve or flow control device in injectors in oil production.
US 5435393 A discloses a method for production of oil or gass from an oil or gas reservoir and a production pipe for injection of fluids into an oil or gas reservoir.
Summary of the invention The present invention relates to a arrangement for injecting CO2 in a supercritical state into a subterranean geological formation, said arrangement comprising a conduit having a proximal portion and a distal portion, at least part of said distal portion extending in a substantially horizontal direction; multiple openings being provided in said distal portion of said conduit for injection of CO2 into said geological formation;
wherein at least one, or all, of said multiple openings is/are provided with outflow limiting means for limiting the flow rate of CO2 through the respective opening into 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 in reducing the outflow between each two neighboring outflow limiting means is decreasing along the length of said conduit in the direction towards the distal end.
In a further preferred embodiment the distance between each two neighboring outflow limiting means is decreasing along the length of said conduit in the direction towards the distal end.
In a further preferred embodiment at least one said outflow limiting means 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 branches off said primary branch in a branch point, said branch point being provided with branch-flow controlling means for limiting the flow of CO2 into the respective secondary branch. In this embodiment, it is preferred that said at least one secondary conduit is substantially horizontal.
In a further preferred embodiment said secondary conduit that branches off said primary branch in a branch point near a distal end of the said main conduit can be left as open hole.
In preferred arrangements of the invention the conduit is closed at its distal ends.
Alternatively, a distal end portion of the conduit is left as open hole.
In a preferred embodiment, said arrangement comprises pressure producing means for producing a pressure in said conduit sufficient for injection of CO2 in a supercritical state into said geological formation. The arrangement may comprise a source of CO2.
The pressure producing means may be, e.g., a pump, a pressurized CO2 container, or a pressurized CO2 pipeline.
In a further preferred embodiment said outflow limiting means comprises at least one capillary fluidly connecting an inner lumen of said conduit with said geological formation.
1 o In a further preferred embodiment said capillary opens at its proximal end towards an inner lumen of said conduit, and opens at its distal end into the geological formation.
In a further preferred embodiment said capillary is a helical capillary, coiled around, and laterally outward, an inner surface of said conduit.
In a further preferred embodiment said capillary has a circular, a triangular, a rectangular or a quadratic cross sectional area. The capillary has preferably a cross sectional area of 10 mm2 to 500 mm2. Preferably, the capillary 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 is more than 5 times, 10 times, 20 times, 100 times, or 1000 times larger than the largest diameter of the capillary. Preferably, the length of the capillary is more than 5 times, 10 times, 20 times, 100 times, or preferably 1000 times larger than the square root of the largest cross-sectional area of the capillary.
Preferably, the geological formation is an aquifer, or a confined aquifer, or a closed aquifer.
In a further preferred embodiment said arrangement is for the permanent storage of CO2 in said geological formation.
The present invention also relates to the use of arrangements of the invention for CO2 injection into subterranean geological formations.
The pressure producing means may be, e.g., a pump, a pressurized CO2 container, or a pressurized CO2 pipeline.
In a further preferred embodiment said outflow limiting means comprises at least one capillary fluidly connecting an inner lumen of said conduit with said geological formation.
1 o In a further preferred embodiment said capillary opens at its proximal end towards an inner lumen of said conduit, and opens at its distal end into the geological formation.
In a further preferred embodiment said capillary is a helical capillary, coiled around, and laterally outward, an inner surface of said conduit.
In a further preferred embodiment said capillary has a circular, a triangular, a rectangular or a quadratic cross sectional area. The capillary has preferably a cross sectional area of 10 mm2 to 500 mm2. Preferably, the capillary 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 is more than 5 times, 10 times, 20 times, 100 times, or 1000 times larger than the largest diameter of the capillary. Preferably, the length of the capillary is more than 5 times, 10 times, 20 times, 100 times, or preferably 1000 times larger than the square root of the largest cross-sectional area of the capillary.
Preferably, the geological formation is an aquifer, or a confined aquifer, or a closed aquifer.
In a further preferred embodiment said arrangement is for the permanent storage of CO2 in said geological formation.
The present invention also relates to the use of arrangements of the invention for CO2 injection into subterranean geological formations.
The present invention also relates to methods for storing CO2 in subterranean geological formations using the arrangements described above.
The invention thus also relates to a method for storage of CO2 in a subterranean geological formation, said method comprising: introducing CO2 into a conduit having a proximal portion and a distal portion, at least part of said distal portion extending in a substantially horizontal direction; wherein multiple openings are provided in said distal portion of said conduit, each provided with flow limiting means for limiting the flow '0 rate of CO2 through each said multiple openings into said geological formation, and injecting said CO2 in a supercritical state through said multiple openings into said geological formation.
In preferred methods of the present invention, an arrangement as described hereinabove is used.
Short 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 means according to one aspect of the current invention.
Detailed description of the invention The present invention relates to methods and arrangements for the permanent storage of CO2 in subterranean geological formations.
An "aquifer", within the context of the present invention shall be understood as being an underground 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 are hereinafter referred as "confined aquifers".
An aquifer may also be sealed at both the upper and lower boundary. Such aquifers are hereinafter referred to as "closed aquifers". Preferred aquifers, according to the invention, are upwardly convex aquifers, or downwardly convex aquifers. The "aquifer", within the context of the present invention, may also be referred to as the "reservoir".
"Flow limiting means", in the context of the present invention, shall be understood as being any means that is 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.
Preferred capillaries have a circular, elliptic, rectangular, or quadratic cross-sectional area.
1 o A "capillary", according to the present invention, shall be understood as being an elongated channel. The use of the expression "capillary" is not to imply that the capillary confers its pressure reducing effect entirely by so-called "capillary forces". A
pressure drop along the length of a capillary of the present invention preferably stems from the friction of fluids moving along the elongated channel of the capillary.
An "openhole", or a "well completed open hole", shall be understood to relate an uncased portion of a well, i.e., the well in a state when it is drilled, with no casing, liner, or similar, provided at its outer circumference.
"Permeability" of a formation, in the context of the present invention, is the property of the formation to transmit fluids in response to an imposed pressure difference.
Permeability is typically measured in darcies or millidarcies. [Converted to SI units, 1 darcy is equivalent to 9.869233x10-13 m2 or 0.9869233 (m)2. This conversion may be approximated as 1 (i.tm)2.1 Formations that transmit fluids readily, such as sandstones, are described as permeable and tend to have many large, well-connected pores.
Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain size, with smaller, fewer, or less interconnected pores.
"Substantially horizontal", in the context of the present invention, shall mean at an angle of between 45 -135 , or 80 -100 , or 85 -95 , or 90 from the vertical.
The invention thus also relates to a method for storage of CO2 in a subterranean geological formation, said method comprising: introducing CO2 into a conduit having a proximal portion and a distal portion, at least part of said distal portion extending in a substantially horizontal direction; wherein multiple openings are provided in said distal portion of said conduit, each provided with flow limiting means for limiting the flow '0 rate of CO2 through each said multiple openings into said geological formation, and injecting said CO2 in a supercritical state through said multiple openings into said geological formation.
In preferred methods of the present invention, an arrangement as described hereinabove is used.
Short 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 means according to one aspect of the current invention.
Detailed description of the invention The present invention relates to methods and arrangements for the permanent storage of CO2 in subterranean geological formations.
An "aquifer", within the context of the present invention shall be understood as being an underground 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 are hereinafter referred as "confined aquifers".
An aquifer may also be sealed at both the upper and lower boundary. Such aquifers are hereinafter referred to as "closed aquifers". Preferred aquifers, according to the invention, are upwardly convex aquifers, or downwardly convex aquifers. The "aquifer", within the context of the present invention, may also be referred to as the "reservoir".
"Flow limiting means", in the context of the present invention, shall be understood as being any means that is 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.
Preferred capillaries have a circular, elliptic, rectangular, or quadratic cross-sectional area.
1 o A "capillary", according to the present invention, shall be understood as being an elongated channel. The use of the expression "capillary" is not to imply that the capillary confers its pressure reducing effect entirely by so-called "capillary forces". A
pressure drop along the length of a capillary of the present invention preferably stems from the friction of fluids moving along the elongated channel of the capillary.
An "openhole", or a "well completed open hole", shall be understood to relate an uncased portion of a well, i.e., the well in a state when it is drilled, with no casing, liner, or similar, provided at its outer circumference.
"Permeability" of a formation, in the context of the present invention, is the property of the formation to transmit fluids in response to an imposed pressure difference.
Permeability is typically measured in darcies or millidarcies. [Converted to SI units, 1 darcy is equivalent to 9.869233x10-13 m2 or 0.9869233 (m)2. This conversion may be approximated as 1 (i.tm)2.1 Formations that transmit fluids readily, such as sandstones, are described as permeable and tend to have many large, well-connected pores.
Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain size, with smaller, fewer, or less interconnected pores.
"Substantially horizontal", in the context of the present invention, shall mean at an angle of between 45 -135 , or 80 -100 , or 85 -95 , or 90 from the vertical.
"Substantially vertical", in 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 the vertical.
The present invention is based on the unexpected finding that the available storage capacity of a geological formation for CO2 can most effectively be used, if the CO2 is injected from multiple injection points along the length of a long-reach horizontal well in such a way that the mass flow of CO2 into the formation is approximately constant over the entire length of the horizontal well. While previously, a common wish in the art has been to inject large amounts of CO2 in as short a time period as possible, the inventors of the present invention have taken a very different approach. By limiting the radial mass flow of CO2 to a certain maximum value, the present invention produces a substantially even distribution of the radial mass flow over major 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 outweighed by the fact that the total amount of CO2, which can be stored in a particular formation, is dramatically increased.
Figure 1 generally shows an arrangement of the present invention. Arrangement 1 is used to inject large amounts of CO2 in the subterranean formation for permanent storage of CO2 therein. For this purpose, there is provided a conduit 3 which extends from a point above surface down into formation 2 in which the CO2 is to be stored.
The geological formation can be, e.g., a depleted oil field, a depleted gas field, or an aquifer.
The aquifer is preferably a closed aquifer, or a confined aquifer. The geological formation is preferably more than 500 m under ground. The geological formation is preferably 5 to 1000 m, preferably 20 to 200 m thick.
Conduit 3 comprises a proximal end portion 4 and a distal end portion 5. The distal end portion 5 comprises a generally horizontal portion. The horizontal (distal) portion is preferably provided in form of a long-reach horizontal well, and is preferably between 100 m and 2000 m long. This allows CO2 to be injected into the formation at multiple injection points over the entire length of the conduit. CO2 storage is thereby distributed over a large area/volume of the reservoir formation.
The present invention is based on the unexpected finding that the available storage capacity of a geological formation for CO2 can most effectively be used, if the CO2 is injected from multiple injection points along the length of a long-reach horizontal well in such a way that the mass flow of CO2 into the formation is approximately constant over the entire length of the horizontal well. While previously, a common wish in the art has been to inject large amounts of CO2 in as short a time period as possible, the inventors of the present invention have taken a very different approach. By limiting the radial mass flow of CO2 to a certain maximum value, the present invention produces a substantially even distribution of the radial mass flow over major 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 outweighed by the fact that the total amount of CO2, which can be stored in a particular formation, is dramatically increased.
Figure 1 generally shows an arrangement of the present invention. Arrangement 1 is used to inject large amounts of CO2 in the subterranean formation for permanent storage of CO2 therein. For this purpose, there is provided a conduit 3 which extends from a point above surface down into formation 2 in which the CO2 is to be stored.
The geological formation can be, e.g., a depleted oil field, a depleted gas field, or an aquifer.
The aquifer is preferably a closed aquifer, or a confined aquifer. The geological formation is preferably more than 500 m under ground. The geological formation is preferably 5 to 1000 m, preferably 20 to 200 m thick.
Conduit 3 comprises a proximal end portion 4 and a distal end portion 5. The distal end portion 5 comprises a generally horizontal portion. The horizontal (distal) portion is preferably provided in form of a long-reach horizontal well, and is preferably between 100 m and 2000 m long. This allows CO2 to be injected into the formation at multiple injection points over the entire length of the conduit. CO2 storage is thereby distributed over a large area/volume of the reservoir formation.
The arrangement comprises pressure producing means 10, e.g., a pump, for injecting CO2 into the geological formation. In other preferred embodiments of the invention, the pressure producing means may be a pressurized CO2 container, or a pressurized pipeline. The CO2, when injected, is preferably in a supercritical state.
Thus, all components of the arrangement must be appropriately designed and constructed such as to be able to sustain the harsh conditions of its operation. Materials must be appropriately chosen to resist the very high pressures and the corrosion, in particular, when the CO2 injected is not pure CO2, but contains, e.g., water and/or other corrosive contaminants, such as 02 or SO2. Pressure producing means preferably are able to '0 produce pressures of more than 73, 100, 200, 500, or 1000 bar.
Conduit 3 comprises multiple openings 6a-6z in a distal portion, through which openings CO2 is injected into the formation. At least one, but preferably all openings are provided with outflow limiting means 7a-7z. The outflow limiting means 7a-7z serve to reduce the radial mass flow of CO2 through the individual openings 6a-6z. The radial mass flow is most efficiently reduced in areas of the formation having high permeability. This is due to the fact that the radial mass flow in these areas - without outflow limiting means - would be very large. In areas of the formation having a low permeability for CO2, the mass flow into the formation is low from the outset.
Flow limiting means have little effect in these areas. As a result of the more efficient flow limitation in highly permeable areas, a substantially even mass flow distribution over the entire horizontal length of the injection well is achieved. In other words, the mass of CO2 injected per unit time and per unit length of the conduit is approximately constant.
It is this even distribution of the radial mass flow rate that is believed to produce the unforeseen inventive effect, namely that the available CO2 storage capacity of the formation can be used to a far 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 branches off primary branch 8 in branch point 10. Multiple secondary branches 9 may be provided. In one embodiment (not shown), conduit 3 further comprises tertiary branches, or even higher order branches, branching off the respective lower order branches.
Thus, all components of the arrangement must be appropriately designed and constructed such as to be able to sustain the harsh conditions of its operation. Materials must be appropriately chosen to resist the very high pressures and the corrosion, in particular, when the CO2 injected is not pure CO2, but contains, e.g., water and/or other corrosive contaminants, such as 02 or SO2. Pressure producing means preferably are able to '0 produce pressures of more than 73, 100, 200, 500, or 1000 bar.
Conduit 3 comprises multiple openings 6a-6z in a distal portion, through which openings CO2 is injected into the formation. At least one, but preferably all openings are provided with outflow limiting means 7a-7z. The outflow limiting means 7a-7z serve to reduce the radial mass flow of CO2 through the individual openings 6a-6z. The radial mass flow is most efficiently reduced in areas of the formation having high permeability. This is due to the fact that the radial mass flow in these areas - without outflow limiting means - would be very large. In areas of the formation having a low permeability for CO2, the mass flow into the formation is low from the outset.
Flow limiting means have little effect in these areas. As a result of the more efficient flow limitation in highly permeable areas, a substantially even mass flow distribution over the entire horizontal length of the injection well is achieved. In other words, the mass of CO2 injected per unit time and per unit length of the conduit is approximately constant.
It is this even distribution of the radial mass flow rate that is believed to produce the unforeseen inventive effect, namely that the available CO2 storage capacity of the formation can be used to a far 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 branches off primary branch 8 in branch point 10. Multiple secondary branches 9 may be provided. In one embodiment (not shown), conduit 3 further comprises tertiary branches, or even higher order branches, branching off the respective lower order branches.
In order to be able to control the mass flow of CO2 into the secondary branches 9, branch-flow controlling means 13 may be provided. Branch-flow controlling means 13 may be in form of a throttle or a valve, preferably a controllable valve.
Outflow limiting means 7a-7z may be in form of an elongated capillary.
Preferred capillaries have a circular, elliptic, rectangular, or quadratic cross-sectional area. They preferably have a cross sectional area of from 10 mm2 to 500 mm2, 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.
lo Preferred capillaries of the invention are helically coiled.
Capillaries of the present invention are preferably designed such that, under operating conditions, they produce a pressure drop along the length of the capillary of from 0.5 bar to 5 bar.
According to another preferred embodiment of the present invention, the outflow limiting means 7a-7z can be modified "inflow control devices" (ICDs), e.g., of the type disclosed in US2009008092 Al. It must, however be noted that those ICDs used for oil production are normally not suitable, and need significant modification in order to be useful in the context of the present invention. This is, i.a., due to the fact that the direction of fluid flow through the devices is reversed. Furthermore, the viscosity of fluids in oil production is generally higher than the one of CO2, e.g., in a supercritical state. Thus, the cross sectional area and/or length of conduits of the ICDs must be appropriately changed. Also the applicable pressure regime is different in methods of the present inventions as compared to oil production. While in methods of the present invention, the pressure in interior of the injection well can be deliberately chosen, e.g., by the appropriate pressure producing means, in oil production the pressure driving the fluid transport is normally determined by the pressure naturally occurring in the reservoir.
It must also be mentioned that the known inflow control devices would normally not be suitable for use in devices and methods of the present invention without significant modification, because of the extremely corrosive nature of the supercritical CO2 (at least when impurities, such as water or other corrosive gasses are also present).
Hence, outflow limiting means of the present invention must be made of highly corrosion resistant materials.
Outflow limiting means 7a-7z may be provided in form of an elongated channel or capillary 12. Flow limiting means 7a-7z can be adjustable. Adjustment of the outflow limiting effect can be achieved by controlling (reducing or increasing) the cross-sectional area of the elongated channels or capillaries. The flow through flow limiting means 7a-7z can also be adjusted by, e.g., controlling the effective length of the elongated channels or capillaries. Alternatively, the flow through flow limiting means 7a-7z can be adjusted by changing the shape of the cross-sectional area in channels or capillaries of flow limiting means 7a-7z.
In the embodiment shown in Figure 3, the flow limiting means 7 are in form of a helical capillary 12, wound around, and disposed radially outward, an inner surface of conduit 3. Capillary 12 opens at a first (proximal) end 19 into inner lumen 18 of conduit 3. A
second (distal) end 20 of capillary 12 opens into formation 2. Second end 20 may also open into a sand screen or pervious liner (not shown) provided radially outward of conduit 3. Conduit 3 is thus preferably in close contact with the pervious liner. The pervious liner is preferably in close contact with the formation.
Elongated channels or capillaries 12 of a certain length, as opposed to simple holes, are able to effectively control the mass flow of fluid at relatively modest pressures.
Therefore, pumps of lower performance and price can be used. Furthermore, operation under lower pressure also reduces erosion of the system's components, thus, the lifetime of the system is increased.
Outflow limiting means 7a-7z generally produce a significant pressure drop between their respective first and second ends. For this reason, the pressure required in conduit 4 for inducing 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 in a distal end of the conduit. In other embodiments, the distal ends of conduit 3 are not provided with a plug. They may be open-hole wells.
The latter embodiments may be suitable 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 depicted in Figure 3, conduit 3 may comprise multiple impervious segments 15 and multiple outflow segments 16, wherein the multiple openings 6a-6z are provided only in the outflow segments 16 (i.e., not in impervious segments 15). There may be provided multiple openings 6a-6z, or multiple helical capillaries 12, per outflow segment 16.
Outflow segments 16 and impervious segments 15 are preferably provided with a male fitting at one end and with female fitting at the other end. Impervious segments 15 can be fitted to each other, and to outflow segments 16. Likewise, outflow segments 16 can be fitted to each other, and can be fitted to impervious segments 15. A seal 14 is preferably provided between any two connected impervious segments 15 and/or outflow segments 16. Conduit 3 may thus be of modular construction.
Outflow segments 16 (and preferably also impervious segments 15) are preferably in direct contact with the formation, i.e., there is preferably no annular gap or space between the outflow segment and the reservoir material. This is useful for avoiding significant axial flow of CO2 radially outward conduit 3. In other words, the outer surface of outflow segment 16 (and preferably also the outer surface of impervious segment 15) contacts formation 2.
Alternatively, radially outward conduit 3, e.g., radially outward of outflow segments 16 and/or impervious segments 15, there may be provided a sand-screen or a pervious liner (not shown). The sand-screen or pervious liner preferably contacts the conduit and the formation, such as to prevent significant axial mass flow of CO2. The pervious liner is preferably of a material having a permeability in the radial direction (for CO2) which is equal to, or greater than, its permeability for CO2 in the axial direction.
Outflow limiting means 7a-7z may be in form of an elongated capillary.
Preferred capillaries have a circular, elliptic, rectangular, or quadratic cross-sectional area. They preferably have a cross sectional area of from 10 mm2 to 500 mm2, 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.
lo Preferred capillaries of the invention are helically coiled.
Capillaries of the present invention are preferably designed such that, under operating conditions, they produce a pressure drop along the length of the capillary of from 0.5 bar to 5 bar.
According to another preferred embodiment of the present invention, the outflow limiting means 7a-7z can be modified "inflow control devices" (ICDs), e.g., of the type disclosed in US2009008092 Al. It must, however be noted that those ICDs used for oil production are normally not suitable, and need significant modification in order to be useful in the context of the present invention. This is, i.a., due to the fact that the direction of fluid flow through the devices is reversed. Furthermore, the viscosity of fluids in oil production is generally higher than the one of CO2, e.g., in a supercritical state. Thus, the cross sectional area and/or length of conduits of the ICDs must be appropriately changed. Also the applicable pressure regime is different in methods of the present inventions as compared to oil production. While in methods of the present invention, the pressure in interior of the injection well can be deliberately chosen, e.g., by the appropriate pressure producing means, in oil production the pressure driving the fluid transport is normally determined by the pressure naturally occurring in the reservoir.
It must also be mentioned that the known inflow control devices would normally not be suitable for use in devices and methods of the present invention without significant modification, because of the extremely corrosive nature of the supercritical CO2 (at least when impurities, such as water or other corrosive gasses are also present).
Hence, outflow limiting means of the present invention must be made of highly corrosion resistant materials.
Outflow limiting means 7a-7z may be provided in form of an elongated channel or capillary 12. Flow limiting means 7a-7z can be adjustable. Adjustment of the outflow limiting effect can be achieved by controlling (reducing or increasing) the cross-sectional area of the elongated channels or capillaries. The flow through flow limiting means 7a-7z can also be adjusted by, e.g., controlling the effective length of the elongated channels or capillaries. Alternatively, the flow through flow limiting means 7a-7z can be adjusted by changing the shape of the cross-sectional area in channels or capillaries of flow limiting means 7a-7z.
In the embodiment shown in Figure 3, the flow limiting means 7 are in form of a helical capillary 12, wound around, and disposed radially outward, an inner surface of conduit 3. Capillary 12 opens at a first (proximal) end 19 into inner lumen 18 of conduit 3. A
second (distal) end 20 of capillary 12 opens into formation 2. Second end 20 may also open into a sand screen or pervious liner (not shown) provided radially outward of conduit 3. Conduit 3 is thus preferably in close contact with the pervious liner. The pervious liner is preferably in close contact with the formation.
Elongated channels or capillaries 12 of a certain length, as opposed to simple holes, are able to effectively control the mass flow of fluid at relatively modest pressures.
Therefore, pumps of lower performance and price can be used. Furthermore, operation under lower pressure also reduces erosion of the system's components, thus, the lifetime of the system is increased.
Outflow limiting means 7a-7z generally produce a significant pressure drop between their respective first and second ends. For this reason, the pressure required in conduit 4 for inducing 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 in a distal end of the conduit. In other embodiments, the distal ends of conduit 3 are not provided with a plug. They may be open-hole wells.
The latter embodiments may be suitable 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 depicted in Figure 3, conduit 3 may comprise multiple impervious segments 15 and multiple outflow segments 16, wherein the multiple openings 6a-6z are provided only in the outflow segments 16 (i.e., not in impervious segments 15). There may be provided multiple openings 6a-6z, or multiple helical capillaries 12, per outflow segment 16.
Outflow segments 16 and impervious segments 15 are preferably provided with a male fitting at one end and with female fitting at the other end. Impervious segments 15 can be fitted to each other, and to outflow segments 16. Likewise, outflow segments 16 can be fitted to each other, and can be fitted to impervious segments 15. A seal 14 is preferably provided between any two connected impervious segments 15 and/or outflow segments 16. Conduit 3 may thus be of modular construction.
Outflow segments 16 (and preferably also impervious segments 15) are preferably in direct contact with the formation, i.e., there is preferably no annular gap or space between the outflow segment and the reservoir material. This is useful for avoiding significant axial flow of CO2 radially outward conduit 3. In other words, the outer surface of outflow segment 16 (and preferably also the outer surface of impervious segment 15) contacts formation 2.
Alternatively, radially outward conduit 3, e.g., radially outward of outflow segments 16 and/or impervious segments 15, there may be provided a sand-screen or a pervious liner (not shown). The sand-screen or pervious liner preferably contacts the conduit and the formation, such as to prevent significant axial mass flow of CO2. The pervious liner is preferably of a material having a permeability in the radial direction (for CO2) which is equal to, or greater than, its permeability for CO2 in the axial direction.
Reference numerals 1 - arrangement 2 - geological formation 3 - conduit 4 - proximal portion 5 - distal portion 6a-6z - multiple openings 7a-7z - outflow limiting means 1 o 8 - primary conduit 9 - secondary conduit - branch point 11 - pressure producing means 12 - capillary 13 - branch-flow controlling means 14 - seal 15 - impervious segment 16 - outflow segment 17 - plug 18 - inner lumen 19 - first opening 20 - second opening
Claims (12)
1. An arrangement (1) for injecting CO2 in a supercritical state into a subterranean geological formation (2), said arrangement comprising:
a conduit (3) having a proximal portion (4) and a distal portion (5), at least part of said distal portion (5) extending in a substantially horizontal direction;
multiple openings (6a-6z) being provided in said distal portion (4) of said conduit (3) for injection of CO2 into said geological formation (2);
wherein said multiple openings (6a-6z) are provided with outflow limiting means (7) for limiting the flow rate of CO2 through respective said opening (6a-6z) into said geological formation (2).
a conduit (3) having a proximal portion (4) and a distal portion (5), at least part of said distal portion (5) extending in a substantially horizontal direction;
multiple openings (6a-6z) being provided in said distal portion (4) of said conduit (3) for injection of CO2 into said geological formation (2);
wherein said multiple openings (6a-6z) are provided with outflow limiting means (7) for limiting the flow rate of CO2 through respective said opening (6a-6z) into said geological formation (2).
2. Arrangement of claim 1, wherein the distance between each two neighboring outflow limiting means (7) is decreasing along the length of said conduit in the direction towards the distal end.
3. Arrangement of any one of the preceding claims, wherein said conduit (3) is a branched conduit comprising a primary branch (8) and at least one secondary branch (9).
4. Arrangement of claim 3, wherein said at least one secondary branch (8) branches off said primary branch (9) in a branch point (10), said branch point (10) being provided with branch-flow controlling means (14) for limiting the flow of CO2 into the respective secondary branch (9).
5. Arrangement of any one of the preceding claims, wherein said conduit (3) is closed at its distal ends.
6. Arrangement of any one of claims 1 to 4, wherein a distal end portion of said conduit (3) is open hole.
7. Arrangement of any one of the preceding claims, wherein said arrangement comprises pressure producing means (11) for producing a pressure in said conduit (3) sufficient for injection of CO2 in a supercritical state into said geological formation (2).
8. Arrangement of any one of the preceding claims, wherein said outflow limiting means (7) comprises at least one capillary (12) fluidly connecting an inner lumen (18) of said conduit (3) with said geological formation.
9. Arrangement of claim 8, wherein said capillary (12) opens at its proximal end (19) towards an inner lumen (18) of said conduit (3), and opens at its distal end (20) into the geological formation.
10. Arrangement of any one of the above claims, wherein said geological formation (2) is an aquifer.
11. A method for storage of CO2 in a subterranean geological formation, said method comprising:
introducing CO2 into a conduit (3) having a proximal portion (4) and a distal portion (5), at least part of said distal portion (5) extending in a substantially horizontal direction;
and injecting said CO2 in a supercritical state through multiple openings (6a-6z) into said geological formation (2), wherein said multiple openings (6a-6z) are provided in said distal portion (4) of said conduit (3), and are each provided with flow limiting means (7) for limiting the flow rate of CO2 through each said multiple openings (6a-6z) into said geological formation (2).
introducing CO2 into a conduit (3) having a proximal portion (4) and a distal portion (5), at least part of said distal portion (5) extending in a substantially horizontal direction;
and injecting said CO2 in a supercritical state through multiple openings (6a-6z) into said geological formation (2), wherein said multiple openings (6a-6z) are provided in said distal portion (4) of said conduit (3), and are each provided with flow limiting means (7) for limiting the flow rate of CO2 through each said multiple openings (6a-6z) into said geological formation (2).
12. Method of claim 11, wherein said CO2 is injected through an arrangement of any one of claims 1-10.
Applications Claiming Priority (3)
Application Number | Priority Date | Filing Date | Title |
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NO20101106A NO338616B1 (en) | 2010-08-04 | 2010-08-04 | Apparatus and method for storing carbon dioxide in underground geological formations |
NO20101106 | 2010-08-04 | ||
PCT/EP2011/063370 WO2012017010A1 (en) | 2010-08-04 | 2011-08-03 | Methods and arrangements for carbon dioxide storage in subterranean geological formations |
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CA2807194A1 true CA2807194A1 (en) | 2012-02-09 |
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CA2807194A Pending CA2807194A1 (en) | 2010-08-04 | 2011-08-03 | Methods and arrangements for carbon dioxide storage in subterranean geological formations |
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US (1) | US20130223935A1 (en) |
EP (1) | EP2601376A1 (en) |
AU (1) | AU2011287564A1 (en) |
BR (1) | BR112013003678A2 (en) |
CA (1) | CA2807194A1 (en) |
NO (1) | NO338616B1 (en) |
WO (1) | WO2012017010A1 (en) |
Cited By (1)
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US10421611B2 (en) * | 2017-08-25 | 2019-09-24 | Korea Advanced Institute Of Science And Technology | Geological storage system of carbon dioxide and process for geological storage of carbon dioxide |
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NO20210146A1 (en) | 2018-07-27 | 2021-02-05 | Baker Hughes Holdings Llc | Distributed fluid injection system for wellbores |
WO2023111613A1 (en) * | 2021-12-14 | 2023-06-22 | Totalenergies Onetech | An installation for injecting a carbon containing compound into a geological formation, comprising a concentric completion and related process |
CN114278257B (en) * | 2021-12-24 | 2023-12-15 | 中海石油(中国)有限公司 | Synchronization device and method for offshore oilfield exploitation and supercritical carbon dioxide sequestration |
CN115059437B (en) * | 2022-06-16 | 2023-10-31 | 西南石油大学 | CO containing multiple impurities 2 Method for improving recovery ratio of depleted gas reservoir and effective sealing and storing method thereof |
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US8256992B2 (en) * | 2008-02-29 | 2012-09-04 | Seqenergy, Llc | Underground sequestration system and method |
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- 2010-08-04 NO NO20101106A patent/NO338616B1/en not_active IP Right Cessation
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- 2011-08-03 EP EP11749778.4A patent/EP2601376A1/en not_active Withdrawn
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Publication number | Priority date | Publication date | Assignee | Title |
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US10421611B2 (en) * | 2017-08-25 | 2019-09-24 | Korea Advanced Institute Of Science And Technology | Geological storage system of carbon dioxide and process for geological storage of carbon dioxide |
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NO20101106A1 (en) | 2012-02-06 |
EP2601376A1 (en) | 2013-06-12 |
WO2012017010A1 (en) | 2012-02-09 |
NO338616B1 (en) | 2016-09-12 |
BR112013003678A2 (en) | 2016-09-06 |
AU2011287564A1 (en) | 2013-02-28 |
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