Note: Descriptions are shown in the official language in which they were submitted.
CA 02915661 2015-12-21
MULTILATERAL WELL COMPLETIONS TO IMPROVE
INDIVIDUAL BRANCH CONTROL
Field of the Invention
The present invention relates to thermal hydrocarbon recovery techniques, and
particularly to the
=
use of multilateral wells in hydrocarbon recovery.
Background of the Invention
Heavy oil is a term commonly applied to describe oils having a specific
gravity less than about
degrees API. These oils, which include bitumen, are not readily producible by
conventional
techniques. Their viscosity is so high that the oil cannot easily be mobilized
and driven to a
production well by a pressure drive. Therefore, a recovery process is required
to reduce the
15 viscosity and then produce the oil.
Thermal recovery methods as applied in heavy oil have the common objective of
accelerating the
recovery process. Raising the temperature of the host formation reduces the
heavy oil viscosity
allowing the near solid material at original temperature to flow as a liquid.
For heavy oil
20 reservoirs, steam injection from the surface into the formation is used
as a conventional method
to heat the heavy oil in situ, reducing its viscosity to a level where the oil
is amenable to
displacement. Typical methods of recovering oil from an oil sands reservoir
include cyclic
steam stimulation (CSS) and steam assisted gravity drainage (SAGD).
Electromagnetic (EM)
heating, or EMH, has also been considered as a viable alternative to steam-
based thermal
processes.
The effective drilling and completion of a well consisting of a single
parent/main bore with a
junction leading to two or more lateral branches, also known as a multilateral
well, can provide a
further improvement in thermal recovery in appropriate situations. These wells
can be vertical,
horizontal or slanted in orientation. The junction can be placed at a variety
of depths and in a
variety of azimuthal directions, thus allowing the subsequent branches to
reach different depths
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and in different directions. The significant advantage in applying this
junction technology is to
reduce the surface footprint thereby reducing cost, affected land area, and
environmental
disturbance.
The use of multilateral wells may provide improved recovery of heavy oil
resources, but there
are various challenges facing their implementation. In particular, controlling
the performance of
a single well can be difficult depending on the contextual specifics, but
adding in one or more
lateral branching wells complicates the system even further and makes
performance control far
more challenging.
Summary of the Invention
The present invention therefore seeks to provide completion mechanisms for use
with
multilateral wells in thermal hydrocarbon recovery operations. Specifically,
the following
techniques are disclosed in the context of multilateral well systems:
= The use of mechanical restrictions such as steam splitters for injection
wells and inflow
control devices for production wells
= The use of multilateral tubing strings following the path of the
multilateral branches
= The use of more than one pump to provide separate pressure points in the
branches
= The use of blank liners selected so as to restrict injection and/or
production of fluid
According to a first broad aspect of the present invention, there is provided
a method for
producing hydrocarbon from a subsurface reservoir, the method comprising the
steps of:
drilling a production well from surface to the reservoir;
drilling an injection well from the surface to the reservoir;
drilling at least one lateral well off of the injection well;
determining an optimal local fluid flow level for regions along the injection
well and the at least
one lateral well;
providing flow control devices in each of the injection well and the at least
one lateral well for
positioning adjacent the regions, each of the flow control devices selected to
allow the optimal
fluid flow therethrough for the respective region;
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injecting a fluid through the injection well and the at least one lateral well
through the flow
control devices and into the reservoir;
allowing the fluid to mobilize the hydrocarbon; and
producing the hydrocarbon to the surface through the production well.
In some exemplary embodiments, the at least one lateral well is a plurality of
lateral wells.
The step of determining the optimal local fluid flow level for the regions
preferably comprises
assessing the regions of the reservoir along the injection well and the at
least one lateral well
where fluid injection requires enhancement or restriction to optimize
mobilization of the
hydrocarbon.
The flow control devices are preferably steam splitters.
The fluid may be steam, a steam-solvent mixture or a non-condensable gas.
According to a second broad aspect of the present invention, there is provided
a system for
producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the injection well; and
flow control devices in each of the injection well and the at least one
lateral well for allowing
passage of an injected fluid therethrough, the flow control devices selected
to allow an optimal
fluid flow therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of
lateral wells.
The flow control devices are preferably steam splitters.
According to a third broad aspect of the present invention, there is provided
a method for
producing hydrocarbon from a subsurface reservoir, the method comprising the
steps of:
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drilling a production well from surface to the reservoir;
drilling an injection well from the surface to the reservoir;
drilling at least one lateral well off of the production well;
determining an optimal local fluid flow level for regions along the production
well and the at
least one lateral well;
providing inflow control devices in each of the production well and the at
least one lateral well
for positioning adjacent the regions, each of the inflow control devices
selected to allow the
optimal fluid flow therethrough for the respective region;
injecting a fluid through the injection well into the reservoir;
allowing the fluid to mobilize the hydrocarbon; and
producing the hydrocarbon to the surface through the inflow control devices
and the production
well and the at least one lateral well.
In some exemplary embodiments, the at least one lateral well is a plurality of
lateral wells.
The step of determining the optimal local fluid flow level for the regions
preferably comprises
assessing the regions along the production well and the at least one lateral
well where production
requires enhancement or restriction.
The fluid may be steam, a steam-solvent mixture or a non-condensable gas.
According to a fourth broad aspect of the present invention, there is provided
a system for
producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and
inflow control devices in each of the production well and the at least one
lateral well for allowing
passage of a produced fluid therethrough, the inflow control devices selected
to allow an optimal
fluid flow therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of
lateral wells.
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According to a fifth broad aspect of the present invention, there is provided
a system for
producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and
a tubing string in each of the production well and the at least one lateral
well for allowing
passage of a produced fluid therethrough, the tubing string in the at least
one lateral well
connected to the tubing string in the production well by a tubing junction
tool to form a unitary
production tubing string.
In some exemplary embodiments, the at least one lateral well is a plurality of
lateral wells. Each
tubing string preferably comprises an associated packer assembly.
According to a sixth broad aspect of the present invention, there is provided
a system for
producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and
a pump assembly in each of the production well and the at least one lateral
well for pumping
produced fluid, the pump assembly in the at least one lateral well comprising
at least two pumps.
In some exemplary embodiments, the at least one lateral well is a plurality of
lateral wells. The
at least two pumps of each pump assembly may run on separate individual tubing
strings, or
alternatively may run in series.
Each pump assembly may further comprise variable pumping rate means, which
means
preferably comprises a variable frequency drive.
According to a seventh broad aspect of the present invention, there is
provided a system for
producing hydrocarbon from a subsurface reservoir, the system comprising:
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an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the injection well; and
at least one blank liner in each of the injection well and the at least one
lateral well for restricting
passage of an injected fluid therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of
lateral wells.
According to an eighth broad aspect of the present invention, there is
provided a system for
producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and
at least one blank liner in each of the production well and the at least one
lateral well for
restricting passage of a produced fluid therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of
lateral wells.
One skilled in the art will also realize that the installation of electrical
cables into the various
branches of a well can be used to individually control the amount of energy
deployed into each
branch and section of a branch.
A detailed description of exemplary embodiments of the present invention is
given in the
following. It is to be understood, however, that the invention is not to be
construed as being
limited to these embodiments.
Brief Description of the Drawings
In the accompanying drawings, which illustrate exemplary embodiments of the
present
invention:
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Figure 1 is a schematic elevation view of a prior art injector well showing
the use of
steam splitters;
Figure 2a is a schematic elevation view of a prior art well with flow control
devices;
Figure 2b is a schematic elevation view of a multilateral well configuration
according to
the present invention with flow control devices in both wells;
Figure 3a is a schematic elevation view of a prior art well with inflow
control devices;
Figure 3b is a schematic elevation view of a multilateral well configuration
according to
the present invention with inflow control devices in both wells;
Figure 4a is a schematic elevation view of prior art wells with pumps; and
Figure 4b is a schematic elevation view of a multilateral well configuration
according to
the present invention with two pumps in series in a wellbore.
Exemplary embodiments of the present invention will now be described with
reference to the
accompanying drawings.
Detailed Description of Exemplary Embodiments
Throughout the following description specific details are set forth in order
to provide a more
thorough understanding to persons skilled in the art. However, well known
elements may not
have been shown or described in detail to avoid unnecessarily obscuring the
disclosure. The
following description of examples of the invention is not intended to be
exhaustive or to limit the
invention to the precise forms of any exemplary embodiment. Accordingly, the
description and
drawings are to be regarded in an illustrative, rather than a restrictive,
sense.
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As was stated above, it is believed that the use of multilateral well
techniques may provide
advantages for hydrocarbon recovery, including in the field of thermal
recovery of heavy oil
from subsurface reservoirs. The exemplary embodiments of the present invention
are directed to
improvements related to the use of multilateral wells in thermal hydrocarbon
recovery
operations, and specifically to completion technologies in the context of
multilateral well
arrangements.
Exemplary methods and systems will now be disclosed in sufficient detail to
allow someone
skilled in the art to determine the best technique or combination of
techniques for their individual
reservoir and well configuration. It is well known to those skilled in the art
that the specific
completions techniques employed must be selected for the particular context
including the nature
of the reservoir.
The present invention involves the use of completion techniques to improve
individual branch
control in a multilateral well arrangement. While multilateral well
arrangements are known in
the art, the various lateral wells or branches are conventionally treated in
the same manner as the
main well. The present invention is directed to ways to provide enhanced
control of the lateral
wells or branches in an attempt to improve overall performance of the
hydrocarbon production
operation.
The description, including the drawings, is directed to a single lateral well,
but it is understood
that an individual main well could have several lateral wells extending
therefrom.
Use of Flow Control Devices
According to a first broad aspect of the present invention, there is provided
a method for
producing hydrocarbon from a subsurface reservoir comprising the use of flow
control devices.
In one exemplary embodiment, the flow control devices are steam splitters
connected to an
injection well of a SAGD well pair and one or more lateral wells or branches
extending from the
injection well.
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Steam splitters are known for use in SAGD hydrocarbon recovery operations to
direct steam to
various target areas of a reservoir adjacent the well pair. For example, the
use of steam splitters
as part of an injection well is shown in Figure 1, which illustration is taken
from a 2015 Annual
Performance Presentation to the Alberta Energy Regulator for the present
applicant's Sunrise
Thermal Project, available at the time of the present application filing date
at:
http iwww. aer. c aido cuments/oi lsandsinsitu-
presentati o ns12015 A thab as calluskyS unri s eS AGD 10419 p d f. The steam
splitter is labelled as a
"port" in Figure 1. A further example of flow control devices in a SAGD
context is found in
United States Patent Application Publication No. 2013/0213652, which teaches
the use of inflow
control devices in the improvement of conventional straight SAGD wells.
To control the distribution of steam in a single SAGD well as illustrated in
Figure 1, engineers
and geoscientists conventionally make a determination as to the most desirable
steam placement
by considering the geological parameters of porosity, water saturation, pay
and permeability,
with further consideration given to the kinematic viscosity of the oil, and
hydraulic parameters of
injecting steam into the well.
However, to control the distribution of steam in a branched SAGD well,
engineers and
geoscientists would have a much more complicated set of variables to consider,
including steam
distribution to a larger area, and hydraulics of the branched system including
the potential for
elevation changes between branches. The present invention provides a method
and system
enabling a desirable level of control over individual branches in an effort to
improve overall
operation performance.
Turning to Figure 2a, a prior art system 10 is illustrated. The prior art
system 10 comprises a
wellbore having a liner 12, with tubing 14 extending therethrough. The tubing
14 is provided
with flow control devices 16 at spaced-apart locations along the horizontal
leg of the tubing 14.
Turning now to Figure 2b, an exemplary system 20 according to the present
invention comprises
a well pair ¨ an injection well 22 and a production well (not shown) from the
surface to the
reservoir ¨ and one lateral well 24 off of the injection well 22. In some
embodiments there may
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be a number of lateral wells branching off of the injection well, although
this will depend on the
operation requirements as determinable by the skilled person. The wells 22, 24
are provided
with liners 28a,b in a conventional manner. The system 20 further comprises
flow control
devices 26 in both the injection well 22 and the lateral well 24 for allowing
passage of an
injected fluid therethrough, the flow control devices 26 individually
adjustable to allow a
variable fluid flow therethrough. The flow control devices 26 are preferably
controlled from
surface using technology known to the skilled person.
As indicated above, these flow control devices 26 are preferably steam
splitters, and the sizing of
individual steam splitters would be dictated by the reservoir and operational
context, which
sizing may vary from one steam splitter to another along the length of the
well.
In an exemplary method, the production well would be drilled from the surface
to the reservoir,
and the injection well 22 would also be drilled from the surface to the
reservoir, the production
well situated below the injection well 22 in a conventional SAGD arrangement.
Using
multilateral well drilling techniques, the lateral well or branch 24 would be
drilled off of the
injection well 22. The skilled person would determine an optimal local fluid
flow level for each
of the regions of the reservoir along the well, and the flow control devices
26 would be selected
accordingly based primarily on flowthrough passage size but also potentially
other factors
depending on the particular device design. To determine the optimal local
fluid flow level for
each of the flow control devices 26, the skilled worker would preferably
assess the regions of the
reservoir along the injection well 22 and the lateral well 24 where fluid
injection requires
enhancement or restriction to optimize mobilization of the hydrocarbon. The
selected flow
control devices 26 would then be provided in each of the injection well 22 and
the lateral well 24
to allow the optimal fluid flow therethrough. Alternatively, in the event that
flow control devices
are available that allow an adjustable flowthrough passage, such could be used
with the present
invention and controlled from surface, as would be clear to one skilled in the
art.
With the flow control devices 26 in place, a fluid ¨ which could be steam, a
steam-solvent
mixture or a non-condensable gas ¨ would be injected from surface down through
the injection
well 22 and the lateral well 24, and through the flow control devices 26. The
injected fluid is
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then allowed to mobilize the hydrocarbon in a conventional manner, and the
target hydrocarbon
can be produced to the surface through the production well.
By providing flow control devices ¨ steam splitters in the exemplary
embodiment ¨ at various
points on both the main injection well and the lateral well or wells, the
operator can better
control steam distribution throughout the entire branched injection system.
For example, the
operator can consider the geology of the reservoir and adjust the steam
injection accordingly.
Where, for example, a branched injection system is present in an area where
shale layers
predominate, the operator could use the steam splitters to limit steam
injection in those areas by
having a smaller steam splitter at that point on the tubing string. In an area
with thick pay, in
contrast, the operator could use a larger steam splitter to enable greater
volume of steam injection
in those areas. The operator is also better able to consider the vertical
placement of the multiple
branches so that the hydraulic weight of the fluid to be dispersed can be
included in an
appropriate design.
Use of Inflow Control Devices
While the above exemplary aspect of the present invention addressed a system
and method for
controlling fluid injection into a branched SAGD operation, a multilateral
well arrangement
would also benefit from improved controls for production.
It is known in the art to provide variable production along the length of a
production well using
inflow control devices, such as for example the ResFlowTm devices available
from
Sehlumberger. The inflow control devices are selected by the person skilled in
the art to accept
flow from the various areas along the well which are determined to be
beneficial for the
distribution of flow along the entire well. Some considerations that an
operator normally
considers are the pay thickness above the production well, the offset distance
between the
injection well and production well, and the local reservoir properties
including vertical
permeability, water saturation and the presence, or lack of presence, of
heterogeneities.
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Turning to Figure 3a, a prior art production well 30 provided with a liner 32
is illustrated, with
production tubing 34 extending therethrough. The production tubing 34 is
provided with inflow
control devices 36 and packers 38 to isolate the regions along the well 30.
Figure 3b illustrates an exemplary embodiment of the present invention, in
which a production
system 40 comprises a main production well 42 and a lateral well 44 extending
off of the
production well 42, the production well 42 and the lateral well 44 housed
within conventional
liners 46a,b. As will be clear, more than one lateral well 44 may be run off
the production well
42. The SAGD system would also include an injection well, not shown.
Production tubing 48 is
run through the production well 42 and the lateral well 44.
The production tubing 48 in both the production well 42 and the lateral well
44 is provided with
a plurality of inflow control devices 50, with packers 52 at appropriate
locations as selected by
the skilled person.
To enable enhanced control of the branched system, the system 40 positions the
inflow control
devices 50 in each of the production well 42 and the lateral well 44 for
allowing passage of a
produced fluid therethrough, such as for example oil and emulsion. The inflow
control devices
50 are selected as a specific desirable size based on the determined optimal
production
flowthrough, as described below, but where inflow control devices having an
adjustable
flowthrough passage are available they may also be individually adjustable to
a number of
positions, between fully open and fully closed, from surface to allow a
variable fluid flow
therethrough.
In an exemplary method according to the present invention, the production well
42 and the
injection well would be drilled from surface to the reservoir, and at least
one lateral well 44
drilled off of the production well 42. The operator would determine an optimal
local production
flow for regions along the wells, and inflow control devices 50 would be
selected accordingly.
The inflow control devices 50 would then be provided in both the production
well 42 and the
lateral well or wells 44 adjacent the respective regions.
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With the inflow control devices 50 in place adjacent their respective regions,
a fluid ¨ which
could be steam, a steam-solvent mixture or a non-condensable gas ¨ would be
injected from
surface down through the injection well and allowed to mobilize the
hydrocarbon in a
conventional manner. The target hydrocarbon can then be produced to the
surface through the
inflow control devices 50 and both the production well 42 and the lateral well
or wells 44.
The operator can consider the production well and the lateral well as a single
system and give
further attention to such considerations as the heterogeneity and geology
throughout the system.
A further complicating factor in a multilateral system is the vertical
displacement of the main
production well and the lateral well. The hydraulic head of the production
fluid must be factored
into the determination of the appropriate placement for the packers and inflow
control devices
within this branched system.
The inflow control devices can be operated so as to distribute the inflow of
emulsion from the
production well and lateral wells as desired by the operator. One skilled in
the art will realize
that the single lateral well illustrated in Figure 3b for simplification can
be extended to a
multitude of branches.
Use of Multi-Branched Tubing Strings
Turning now to Figures 2b and 3b, a yet further aspect of the present
invention is illustrated,
namely using multi-branched tubing strings to further enhance control of
lateral wells in a
multilateral well system.
According to the illustrated embodiments, the system comprises a well pair,
namely an injection
well and a production well, and at least one lateral well extending from
either the injection well
or the production well. In Figure 2b there is an injection well 22 (the
production well not shown)
and a lateral well 24 run off of the injection well 22. In Figure 3b there is
a production well 42
(the injection well not shown) and a lateral well 44 run off of the production
well 42.
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In each of those illustrations, the tubing string in the main well (either an
injector or a producer)
is connected to the tubing string in the lateral well. This connection is
preferably by means of a
tubing junction tool, and various types of such tools would be within the
knowledge of the
skilled person and clear based on the within teaching.
By connecting the tubing string in the lateral wells with the tubing string in
the main well from
which the laterals branch off, a unitary system is created for passage of
fluid ¨ either injected
fluid (such as steam) or produced fluid (such as oil).
Each tubing string preferably comprises an associated packer assembly where
considered
necessary by the operator.
Use of Multiple Pumps
It is known in the art to use pumping equipment to control the inflow of
production fluids.
Figure 4a illustrates a prior art system 60 comprising a main production well
62 and lateral well
64, the production well 62 having a liner 66 and the lateral well 64 having a
liner 68. Production
tubing 70, 72 is run into the liners 62, 64, and each of the tubing strings
70, 72 have a pump
74a,b.
However, in the context of multilateral well systems greater control may be
achieved if a
different pump arrangement is employed. According to another exemplary
embodiment of the
present invention, a system is provided for producing hydrocarbon from a
subsurface reservoir,
wherein pump assemblies are present in each of the main production well and
the lateral branch
well or wells, and the pump assembly in the lateral branch well comprises at
least two pumps,
thus allowing greater control of the individual lateral wells.
Turning to Figure 4b, an exemplary system 80 comprises an injection well (not
shown) and a
production well 82, with a lateral well 84 off of the production well 82. The
production well 82
is provided with a liner 86 and the lateral well 84 is provided with a liner
88. A production
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tubing string 90 is run into the liner 86 of the production well 82, and a
production tubing string
92 is run into the liner 88 of the lateral well 84.
The production tubing string 90 of the production well 82 is provided with a
pump 94 to aid in
producing fluid from the main production well 82. However, the production
tubing string 92 of
the lateral well 84 is provided with two pumps 96a,b in series.
While the pumps 96a,b are shown as running in series on a single tubing string
92, it is also
possible to run each of the pumps on separate strings.
Also, each pump assembly may further comprise variable pumping rate means,
which would
preferably comprise a variable frequency drive.
This novel arrangement of pumps can be used to allow for the production of
greater volumes of
emulsion. Also, the operator can control the rates of the various pumps within
the system by
changing the current through a variable frequency drive, allowing for more
flexibility in the
system to account for changing operating characteristics.
Although only shown with respect to the lateral well, multiple pumps could
also be employed
within the production well.
Use of Blank Liners
In a yet further exemplary embodiment of the present invention, blank liners
are provided in the
injection/production well and the lateral well to restrict the flow of
injection/production fluids.
As described above with respect to flow control devices such as steam
splitters (on an injection
well and associated lateral well(s)) and inflow control devices (on a
production well and
associated lateral well(s)), restricting flow of injection fluid into a
reservoir or flow of production
fluid out of a reservoir may be advantageous to an operator. It is known to
use blank liners in
injection and production wells to substantially block flow of fluids.
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However, it is not known to use such blank liners as part of a system for
providing enhanced
individual control of lateral wells in a multilateral branched well system.
According to a further exemplary embodiment of the present invention, a system
comprises an
injector-producer well pair, and at least one lateral well off of the
injection well. One or more
blank liners are provided in each of the injection well and the lateral
well(s) for restricting
passage of an injected fluid therethrough. The blank liner would be positioned
at a desirable
location in the wells by the operator based on conventional knowledge and
techniques.
According to a further exemplary embodiment of the present invention, a system
comprises an
injector-producer well pair, and at least one lateral well off of the
production well. One or more
blank liners are provided in each of the production well and the lateral
well(s) for restricting
passage of a produced fluid therethrough. The blank liner would be positioned
at a desirable
location in the wells by the operator based on conventional knowledge and
techniques.
Both the main well (the injector or the producer, as the case may be) and the
lateral well or wells
can be configured with one, two or another specific number of blank liner
joints to prevent steam
from being injected or fluids from being produced. This might be useful, for
example, in a
production well that has been drilled along the base of geological pay to
produce cellar oil.
During the steam stimulation phase, an operator does not want steam to reach
the production
well. In these sections, one or more blank liner joints could be placed.
As will be clear from the above, those skilled in the art would be readily
able to determine
obvious variants capable of providing the described functionality, and all
such variants and
functional equivalents are intended to fall within the scope of the present
invention.
Specific examples have been described herein for purposes of illustration.
These are only
examples. The technology provided herein can be applied to contexts other than
the exemplary
contexts described above. Many alterations, modifications, additions,
omissions and
permutations are possible within the practice of this invention. This
invention includes
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variations on described embodiments that would be apparent to the skilled
person, including
variations obtained by: replacing features, elements and/or acts with
equivalent features,
elements and/or acts; mixing and matching of features, elements and/or acts
from different
embodiments; combining features, elements and/or acts from embodiments as
described herein
with features, elements and/or acts of other technology; and/or omitting
combining features,
elements and/or acts from described embodiments.
The foregoing is considered as illustrative only of the principles of the
invention. The scope of
the claims should not be limited by the exemplary embodiments set forth in the
foregoing, but
should be given the broadest interpretation consistent with the specification
as a whole.
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