Note: Descriptions are shown in the official language in which they were submitted.
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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
CO2
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
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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
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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.
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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
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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.
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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
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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.
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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.
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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
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"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.
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"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.
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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
CO2
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.
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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
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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
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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.
CA 02807194 2013-01-31
WO 2012/017010 PCT/EP2011/063370
16
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
