Note: Descriptions are shown in the official language in which they were submitted.
SYSTEMS AND METHODS FOR UTILIZING LATE LIFE IN SITU RESERVOIRS
TECHNICAL FIELD
[0001] The following generally relates to the utilization of late life in
situ reservoirs, for
example to recover heat, and/or to temporarily store water or hydrocarbons,
and/or to
permanently store a waste product.
BACKGROUND
[0002] Oil sands are a natural mix of sand, clay, water, and bitumen.
Bitumen is
considerably viscous and does not flow like conventional crude oil. As such,
bitumen is
recovered from oil sands using either surface mining techniques or in situ
techniques. In
surface mining, overburden is removed to access the underlying bitumen
reservoir, and the oil
sands are transported to an extraction facility to separate the bitumen from
the other
components of the oil sands (i.e. tailings). For in situ techniques, the
bitumen reservoir is
heated and the bitumen within flows into one or more horizontal production
wells, leaving the
formation rock in the bitumen reservoir in place. In such techniques, the
bitumen in the bitumen
reservoir is often emulsified to enhance recovery. Both surface mining and in
situ processes
produce a bitumen product that is subsequently sent to an upgrading and/or
refining facility, to
be refined into one or more petroleum products.
[0003] Bitumen reservoirs that are too deep to feasibly permit bitumen
recovery by mining
techniques are typically accessed by drilling wellbores into the bitumen
reservoir and
implementing an in situ technology. There are various in situ technologies
available that use
thermal methods to liberate bitumen from the reservoir with heated fluids,
e.g., steam,
hydrocarbon solvent vapour, or steam and solvent in combination. In many
conventional
thermal in situ techniques, the heated fluids can be injected into the
reservoir. However, in
newer techniques, e.g., electrically resistive heating, EM radio frequency,
and induction, heated
fluids can be generated from fluids present in the reservoir.
[0004] Common in situ techniques include Steam Assisted Gravity Drainage
(SAGD) and
Cyclic Steam Stimulation (CSS). In SAGD, a pair of horizontally oriented wells
are drilled into
the bitumen reservoir, such that the pair of horizontal wells are vertically
aligned with respect to
each other and separated by a relatively small distance, typically in the
order of several meters.
The well installed closer to the surface and above the other well is generally
referred to as an
injection well, and the well positioned below the injection well is referred
to as a production well.
The injection well and the production well are then connected to various
subsurface equipment,
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such as electric submersible pumps (ESPs) and sensors, and to equipment
installed at a
surface site. The injection well facilitates steam injection into the
reservoir. The injected steam
propagates vertically and laterally into the reservoir to develop what is
referred to as a steam
chamber. Latent heat released by the injected steam mobilizes the bitumen by
lowering its
viscosity. The bitumen, in turn, drains due to gravity and is produced, along
with condensed
water, by the production well. Typically, multiple well pairs are drilled
substantially parallel to
each other (e.g., from approximately 50 to greater than 120 m apart) to create
what is referred
to as a well pad.
[0005] In CSS, a single, vertical, production/injection well extending into
a bitumen reservoir
can be used for both steam injection and production. CSS typically involves
three main phases,
namely an injection phase, a shut in phase, and a production phase. During the
injection
phase, steam is injected through the production/injection well into the
bitumen reservoir. Next,
the bitumen reservoir is shut in to allow heat from the steam to reduce the
viscosity of the
bitumen in the reservoir. The bitumen of reduced viscosity can then be
produced through the
production/injection well, and the three-phase cycle can be repeated.
[0006] The production wells at in situ well pads tend to decline over time.
When
approaching "late life", these wells may require pad maintenance, reservoir
pressure
maintenance, blow down, and eventual abandonment strategies for the wells and
the
surrounding reservoir. These strategies are often not fully understood or
optimized.
[0007] It would be advantageous to provide a system and method for late
stage reservoir
usage.
SUMMARY
[0008] Provided herein are systems and methods for utilizing late life in
situ reservoirs to
recover heat, store fluids, recover hydrocarbons left behind, or permanently
store waste,
according to various strategies.
[0009] In one aspect, provided herein is a method of a method of
controlling fluid migration
from a first hydrocarbon reservoir, the method comprising: creating a first
fluid migration barrier
between the first hydrocarbon reservoir and a second hydrocarbon reservoir by
injecting a
plugging material into a surrounding formation via at least one well
positioned in the first
hydrocarbon reservoir.
[0010] In another aspect, there is provided a system for controlling fluid
migration from a
first hydrocarbon reservoir, the system comprising: a first fluid migration
barrier between the first
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hydrocarbon reservoir and a second hydrocarbon reservoir created by injecting
a plugging
material into a surrounding formation via at least one well positioned in the
first hydrocarbon
reservoir.
[0011] In an implementation, the method can include placing a first packer
at one end of the
at least one well; and injecting the plugging material through at least one
port in the first packer.
The one end of the at least one well can include a toe of the at least one
well, the plugging
material being injected through the toe of the at least one well into the
surrounding formation.
The one end of the at least one well can also comprise a heel of the at least
one well, the
plugging material being injected through the heel of the at least one well
between the first
packer and an obstruction. The obstruction can include a leading packer placed
ahead of the
first packer positioned at the heel of the at least one well. The leading
packer and the first
packer can be connected.
[0012] In an implementation, the plugging material can be injected by
tubing extending to
the first packer in the at least one well.
[0013] In an implementation, the method can include creating a second fluid
migration
barrier between the first hydrocarbon reservoir and a third hydrocarbon
reservoir by injecting the
plugging material into a surrounding formation at a position spaced from first
fluid migration
barrier. In an implementation, the method can further include placing a second
packer at
another end of the at least one well; and injecting the plugging material
through at least one port
in the second packer. The other end of the at least one well can include a toe
of the at least one
well, the plugging material being injected through the toe of the at least one
well into the
surrounding formation. The other end of the at least one well can also include
a heel of the at
least one well, the plugging material being injected through the heel of the
at least one well
between the second packer and an obstruction. The obstruction can include a
leading packer
placed ahead of the second packer positioned at the heel of the at least one
well. The leading
packer and the second packer can be connected.
[0014] In an implementation, the plugging material can be injected by
tubing extending to
the second packer in the at least one well.
[0015] In an implementation the plugging material can be injected through a
slotted liner, a
perforated liner, or one or more openings in a liner of the at least one well.
[0016] In an implementation, the plugging material can comprise mature fine
tailings
(MFTs).
[0017] In an implementation, the plugging material can comprise mining
tailings.
[0018] In an implementation, the plugging material can comprise a cement
squeeze
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product.
[0019] In an implementation, gas wells can be positioned along at least one
side of the first
hydrocarbon reservoir to buffer the at least one well in the first hydrocarbon
reservoir from at
least one active reservoir adjacent the first hydrocarbon reservoir using the
gas wells.
[0020] In an implementation, the first hydrocarbon reservoir can comprise a
late life in situ
reservoir (LLISR). The LLISR can be used for fluid storage. The LLISR can also
be used for
fluid disposal. The LLISR can also be used for heat recovery from the first
hydrocarbon
reservoir.
[0021] In yet another aspect, there is provided a method of controlling
fluid migration into an
actively producing hydrocarbon reservoir, the method comprising: injecting
fluid into a first late
life in situ reservoir (LLISR) that is adjacent to the actively producing
reservoir, to a first level
that is at or below a first threshold level; and injecting fluid into a second
LLISR that is adjacent
to the first LLISR, to a second level that is above the first threshold level
and at or below an
upper formation barrier in second LLISR, wherein the first LLISR is positioned
between the
actively producing reservoir and the second LLISR.
[0022] In yet another aspect, there is provided a system of controlling
fluid migration into an
actively producing hydrocarbon reservoir, the method comprising: a first late
life in situ reservoir
(LLISR) that is adjacent to the actively producing reservoir, comprising fluid
injected to a first
level that is at or below a first threshold level; and a second LLISR that is
adjacent to the first
LLISR, comprising fluid injected to a second level that is above the first
threshold level and at or
below an upper formation barrier in second LLISR, wherein the first LLISR is
positioned
between the actively producing reservoir and the second LLISR.
[0023] In an implementation, the method can further include injecting fluid
into the first
LLISR to a third level that is above the first threshold level, as the
actively producing
hydrocarbon reservoir transitions to being a third LLISR, wherein the third
LLISR is adjacent to
another actively producing hydrocarbon reservoir; and injecting fluid into the
third LLISR to a
fourth level that is at or below the first threshold level.
[0024] In an implementation, gas wells can be positioned along at least one
side of the first
LLISR to buffer at least one well in the first LLISR from the actively
producing reservoir adjacent
the first LLISR, using the gas wells. Gas wells positioned between the first
LLISR and the
second LLISR can be decommissioned as the second LLISR transitions from being
an actively
producing reservoir.
[0025] In an implementation, the first LLISR can receive overflow fluids
from the second
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LLISR to act as a buffer against flooding into the actively producing
reservoir.
[0026] In an implementation, the fluid can be injected into a plurality of
well pairs in each of
the first and second LLISRs, each well pair comprising an injection well and a
production well
positioned below the injection well.
[0027] In an implementation, the first LLISR can be used for heat recovery
using the
injected fluid.
[0028] In an implementation, the second LLISR can be used for heat recovery
using the
injected fluid. The fluid can comprise water.
[0029] In an implementation, at least one of the first and second LLISR has
been subjected
to a steam assisted gravity drainage (SAGD) process prior to injecting the
water for heat
recovery.
[0030] In an implementation, at least one of the first and second LLISR has
been subjected
to an expanding solvent SAGD (ES-SAGD) process prior to injecting the water
for heat
recovery.
[0031] In an implementation, at least one of the first and second LLISR has
been subjected
to a thermal solvent recovery process prior to injecting the water for heat
recovery.
[0032] In an implementation, at least one of the first and second LLISR has
been subjected
to a cyclic steam stimulation (CSS) process prior to injecting the water for
heat recovery.
[0033] In an implementation, at least one of the first and second LLISR has
been subjected
to a steam flood process prior to injecting the water for heat recovery.
[0034] In an implementation, at least one of the first and second LLISR has
been subjected
to an in situ combustion process prior to injecting the water for heat
recovery.
[0035] In an implementation, at least one of the first and second LLISR has
been subjected
to an electromagnetically assisted solvent extraction (EASE) process prior to
injecting the water
for heat recovery.
[0036] In an implementation, at least one of the first and second LLISR has
been subjected
to an electrical heating process prior to injecting the water for heat
recovery.
[0037] In an implementation, at least one of the first and second LLISR has
been subjected
to an electromagnetic spectrum heating process prior to injecting the water
for heat recovery.
[0038] In an implementation, at least one of the first and second LLISR has
been subjected
to a radio frequency heating process prior to injecting the water for heat
recovery.
[0039] In an implementation, at least one of the first and second LLISR has
been subjected
to a thermal solvent recovery process prior to injecting the water for heat
recovery.
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[0040] The above strategies for using late stage reservoirs can include
making use of empty
pore space and a heated formation to temporarily or permanently store fluids,
extract heat for
use in other applications, and reduce consumption of water, combustion gases,
steam, etc.
BRIEF DESCRIPTION OF THE DRAWINGS
[0041] Embodiments will now be described with reference to the appended
drawings
wherein:
[0042] FIG. la is schematic diagram of an integrated strategy for using a
late life in situ
reservoir (LLISR) to extract benefits for mining or in situ operations,
external markets, or an
electrical grid.
[0043] FIG. lb is a schematic diagram illustrating a series of alternative
phased strategies
for using an LLISR.
[0044] FIG. lc, ld and le illustrate a vertical well configuration for heat
recovery as an
example of one of the phased strategies for using an LLISR.
[0045] FIG. 2 is a block diagram of a multi-phase process applied to an
LLISR.
[0046] FIG. 3 is a flow chart illustrating a process for utilizing an LLISR
in which water is
temporarily stored prior to permanently storing a waste product in the LLISR.
[0047] FIG. 4a illustrates a first stage of the process shown in FIG. 3.
[0048] FIG. 4b illustrates a second stage of the process shown in FIG. 3.
[0049] FIG. 5 is a flow chart illustrating a process for utilizing an LLISR
in which a heat
recovery stage is applied prior to temporary water storage and permanent waste
disposal
stages.
[0050] FIG. 6a illustrates a first stage of the process shown in FIG. 5.
[0051] FIG. 6b illustrates a second stage of the process shown in FIG. 5.
[0052] FIG. 6c illustrates a third stage of the process shown in FIG. 5.
[0053] FIG. 7 is a flow chart illustrating a process for utilizing an LLISR
in which water
migration is mitigated during a water storage stage by using gas injection
wells.
[0054] FIG. 8a illustrates a first stage of the process shown in FIG. 7.
[0055] FIG. 8b illustrates a second stage of the process shown in FIG. 7.
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[0056] FIG. 9a is a schematic diagram of a first configuration for
implementing the process
shown in FIG. 7.
[0057] FIG. 9b is a schematic diagram of an alternative to the first
configuration for
implementing the process shown in FIG. 7.
[0058] FIG. 10 is a schematic diagram of a second configuration for
implementing the
process shown in FIG. 7.
[0059] FIG. 11a is a schematic cross-sectional view of a portion of the
configuration shown
in FIGS. 9 and 10.
[0060] FIG. llb is a schematic cross-sectional view of the portion of the
configuration
shown in FIGS. 9 and 10 with a variation to the water mound.
[0061] FIGS. 11c and 11d are schematic cross-sectional views similar to
FIG. 11b, with a
solid, semisolid and/or liquid boundary to retain injected wastewater for
energy recovery by
injecting into either or both the injection and production wells.
[0062] FIG. 12 is a process flow diagram for a temporary or permanent water
storage
system using an LLISR.
[0063] FIG. 13 is a process flow diagram for a temporary hydrocarbon
storage system
using an LLISR.
[0064] FIG. 14 is a process flow diagram for a brine storage system using
an LLISR.
[0065] FIG. 15 is a process flow diagram for a heat recovery system using
an LLISR in a
direct use to mine operations.
[0066] FIG. 16 is a process flow diagram for a heat recovery system using
an LLISR in a
direct use at an in situ operation.
[0067] FIG. 17 is a process flow diagram for a heat recovery system using
an LLISR in an
electricity production application.
[0068] FIG. 18 is a process flow diagram for storing mature fine tailings
or fine froth tailings
using an LLISR.
[0069] FIG. 19 is a process flow diagram for storing mature fine tailings
or fine froth tailings
using an LLISR in an alternative configuration.
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[0070] FIG. 20 is a schematic cross-sectional view of an overburden
formation heat
recovery process.
[0071] FIGS. 21a to 21f illustrate heating of, and recovery of heat from,
an underburden of
an LLISR.
[0072] FIG. 22a is a schematic diagram illustrating a water migration
barrier between
adjacent well pads in series, with the boundary created at the toes of the
wells in an LLISR.
[0073] FIG. 22b is a schematic diagram illustrating a water migration
barrier between
adjacent well pads in series, with the boundary created at the heels of the
wells in an LLISR.
[0074] FIG. 22c is a schematic diagram illustrating water migration
barriers between
adjacent well pads in series, with the boundaries created at both the toes and
the heels of the
wells in an LLISR.
[0075] FIG. 23a is a schematic cross-sectional view of a heel of a well in
which a water
migration barrier has been established.
[0076] FIG. 23b is a schematic cross-sectional view of a toe of a well in
which a water
migration barrier has been established.
[0077] FIGS. 24a to 24d are schematic diagrams illustrating a water
injection strategy for
providing a buffer reservoir between actively producing reservoirs and high
water LLISRs.
[0078] FIG. 25 is a side-by-side graphical model showing water migration
adjacent an
actively producing reservoir.
DETAILED DESCRIPTION
[0079] The following provides an integrated strategy for executing, in
parallel and/or in
series, methods of utilizing LLISRs. In an implementation, an LLISR can be
used to store water,
hydrocarbons (e.g., dilbit), tailings and brine. Additionally, a heat sweeping
or other working
fluid of water and/or hydrocarbons and/or non-hydrocarbons and/or gas phases,
with any range
of additives in the solid, liquid or gas phases, can be circulated through an
LLISR to recover
heat remaining from thermal bitumen recovery processes. Such heat can be used
in, e.g.,
power generation, oil sands mining, and in situ recovery operations.
[0080] In an implementation, the order and selection of LLISR operations
can be
determined based on LLISR maturity. For example, a recently shut in (or
immature) LLISR can
be considerably hot and thus can be suitable for a heat recovery operation
after injecting a
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working fluid to capture heat from the LLISR. The LLISR can also be used for
temporary water
or hydrocarbon storage, and subsequently used for disposal of wastewater,
brine and/or
tailings.
[0081] In another implementation, the integrated strategy can in part
include a method of
storing water in an LLISR. For example, water generated from various
hydrocarbon recovery
operations can be stored while water is in abundance, such that the water can
be saved for
when such operations are "water short". The LLISR usage strategy can also be
implemented in
depleted reservoirs around, near, or adjacent active hydrocarbon producing
reservoirs. In such
scenarios, water migration from the LLISR towards the active reservoir can be
mitigated by
surrounding the well through which water is injected into the LLISR, with a
number of water
production wells and gas injection wells surrounding the water production
wells. In this way, the
water producers can draw out water migrating away from the water injection
well, and the water
can be recycled back into the LLISR through the injection well. The gas
injection wells on the
perimeter of the LLISR can provide pressure control to limit such migration.
[0082] It will be understood that the term "LLISR" as used herein can mean
any
hydrocarbon bearing reservoir having a hydrocarbon depleted zone therein
formed from a
thermal recovery process. Accordingly, when it is stated that a fluid is
stored in, injected into,
drawn from, or produced from an LLISR, it will be understood that such fluid
is stored in,
injected into, drawn from, or produced from the hydrocarbon depleted pay zone
(i.e., storage
volume) in the LLISR.
[0083] Turning now to the figures, FIG. la schematically illustrates an
example of an
integrated strategy for utilizing an LLISR 12, in this example a late life
SAGD reservoir. It can
be appreciated that the LLISR 12 can include one or more wells configured to
implement an in
situ hydrocarbon recovery process. The one or more wells can be located at one
or more well
pads or other in situ "sites". It can also be appreciated that the LLISR 12
can be situated
adjacent, between or otherwise relative to one or more active in situ sites,
such as wells
positioned in pay regions that are at an earlier stage. For example, the LLISR
12 can be
positioned adjacent sites actively injecting steam, solvent, or steam plus
solvent, and/or
producing a hydrocarbon from the site(s). The LLISR 12 can have been subjected
to various
advanced in situ hydrocarbon recovery processes prior to being used as herein
described.
These hydrocarbon recovery processes can include, without limitation, SAGD,
CSS, expanding
solvent SAGD (ES-SAGD), steam flood, in situ combustion, electromagnetically
assisted solvent
extraction (EASE), thermal solvent recovery, electrical, electromagnetic,
radio frequency, etc.
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[0084] The LLISR 12 can be utilized for temporary storage of a substance,
material or
"product" 14; and/or circulation of same for heat recovery or additional
hydrocarbon recovery;
and/or permanent storage and closure of the well(s) associated with the LLISR
12. The LLISR
12 therefore can be characterized by having pore space left behind from prior
hydrocarbon
recovery and can have some energy such as heat remaining that can be extracted
from the
LLISR 12 and/or surrounding formation. FIG. la illustrates several example
products 14 that
can be circulated through, or temporarily or permanently stored in the LLISR
12, including
without limitation, water (including wastewater), hydrocarbons, tailings, and
brine. FIG. 1 also
illustrates that other products 14 can be recovered from the LLISR 12 and/or
surrounding
formation, including without limitation, geothermal power and geothermal heat
introduced by an
earlier process such as hydrocarbon recovery.
[0085] The strategy illustrated in FIG. la can include one or more
operations or applications
that either provide or receive one or more of the products 14. In this
example, mine operations
16, in situ operations 18 (e.g., active in situ sites), external markets 22,
and an electrical grid 24
are shown. Each of these operations or applications can use or provide
products 14 that utilize
and leverage the pore space and/or remaining energy left behind in the LLISR
12.
[0086] FIG. lb illustrates numerous possible strategies for utilizing an
LLISR 12 in phases.
In this example, Phase 1 can include water injection (e.g., for mining or in
situ disposal),
followed by a subsequent phase. For example, a Phase 2 can include heat
recovery and,
optionally, a Phase 3 with brine or mature fine tailings (M FT) disposal as a
permanent closure
operation. It can be appreciated that such disposal could also or instead
include drilling mud,
treated or partially treated dewatered tailings, e.g., the disposal of PASS
slurry or dewatered
M FT from a centrifuge. In one example, this can include dewatering, e.g., 30%
M FT to 50-70%
solids before injection. The Phase 3 can also include further water injection,
e.g., for mining or in
situ disposal operations as discussed in greater detail below. FIG. lb also
illustrates that Phase
3 can also be implemented after Phase 1, e.g., by executing a permanent
closure operation
such as brine, drilling mud, MFT (or other waste) storage in the LLISR 12. In
one
implementation, this can include the disposal of a brine concentrate from a
tailings water
treatment process to avoid the cost associated with creating a solid waste.
[0087] FIGS. lc, 1 d and le illustrate an example of a phased strategy in
which vertical wells
are used for a heat recovery operation. In this example a vertical injection
well 60 and a vertical
production well 62 are drilled through the overburden and caprock into an
LLISR 12 as shown in
FIG. lc. Typically, the reservoir would be warm and gas filled due to it being
a late-life reservoir.
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In a first phase, the LLISR 12 can be filled with waste water as shown in FIG.
1d. In a second
phase, shown in FIG. le, the waste water that has been added to the LLISR 12
has been
heated by the warm reservoir and can be produced and cycled using the vertical
wells 60, 62 to
recover energy. This recovered energy can be used for various purposes as
discussed below. It
can be appreciated that the example configuration shown in FIGS. 1c-le can be
applied to any
of the configurations and staged strategies discussed herein. Similarly,
horizontal wells or
closed loop wells (either vertical, L-shaped or U-shaped closed loops) may be
used in any of the
configurations and strategies discussed herein.
[0088] FIG. 2 illustrates an example of an integrated multi-phase strategy
for using an
LLISR 12. In this example a first phase (Phase 1) includes a water flood
process. The water
flood process includes filling the LLISR 12 with a water source 30 to achieve
additional
hydrocarbon recovery 32 when producing the water back from the LLISR 12. Phase
1 is
typically under 2 years for a single well pair. A wider range of water sources
can be used,
including once through steam generator (OTSG) blowdown and/or produced water
as the water
source 30. The objective of the water flood process is to increase the
hydrocarbon recovery
factor from depleted well(s) associated with the LLISR 12.
[0089] A second phase (Phase 2) includes a heat recovery process. The heat
recovery
process in this example includes circulating water (e.g., the water source 30)
through the LLISR
12 to recover heat from the LLISR 12. As noted above, it can be appreciated
that for heat
recovery phase, any heat sweeping or other working fluid of water and/or
hydrocarbons and/or
non-hydrocarbons and/or gas phases, with any range of additives in the solid,
liquid or gas
phases can be used. A heat exchanger 34 can be used to recover geothermal heat
from the
circulated water (that has been heated by the LLISR 12) for use in an
application 36 such as to
pre-heat boiler water. More than one application 36 can benefit from the
extracted geothermal
heat, by cascading the heated water from higher to lower temperature
applications, such as
electricity production, heat trace applications, and/or direct use at low
temperatures. The
extracted geothermal heat can also, or instead, be used directly by an
application 38. For
example, the heated water can be used for a mineable bitumen recovery process
instead of
using natural gas- or coke-fired steam boilers. In this implementation,
pipelines to and from in
situ facilities and primary extraction plants can be provided. Phase 2 can
last for a relatively
longer time than Phase 1, for example, approximately 5-20 years.
[0090] A third phase (Phase 3) in this example includes a permanent fill
process. The
permanent fill process includes obtaining or receiving a waste product 40 from
a disposal
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source, which is injected into the LLISR 12 for permanent disposal or closure
of the well(s)
associated with the LLISR 12. The permanent fill process can last
approximately 2-3 years and
can involve the injection of various waste products 40 such as high chloride
brine streams, or
fluids containing small clay and/or sand particles, e.g., M FT (raw and/or
treated), froth treatment
tailings (FTT) (raw and/or treated) from a mining or in situ site, or drilling
waste.
[0091] As illustrated in FIG. 2, the strategy can include moving from a
current LLISR 12
(LLISRN) to a next LLISR 12 (LLISRN,i).
[0092] The phases shown in FIG. 2 are illustrative and certain ones of
these phases can be
implemented alone or in combination and incorporate desired applications as
depicted in the
integrated strategy shown in FIG. 1. FIG. 3 is a flow chart for implementing a
storage and
disposal process using an LLISR 12. In this example, water, hydrocarbons, or
multi-component
emulsions including hydrocarbons are injected or otherwise fed into the LLISR
12 at step 50 and
kept in the LLISR 12 for a period of time. This can be done to store water
generated from a
process that can be utilized later rather than disposed of, or to store a
hydrocarbon such as
diluted bitumen (dilbit) to take advantage of potentially large storage
volumes to mitigate lost
profits incurred by production curtailments, seasonal hydrocarbon price
fluctuations and storage
limitations in general. The period of time can therefore vary based on various
environmental,
production, or market factors, and when the period of time has lapsed, the
water or
hydrocarbons can be produced from the LLISR 12. Producing the water or
hydrocarbons can
be implemented using any applicable production techniques, such as artificial
lift (e.g., pumps),
using a production well or any well positioned in the LLISR 12 in fluid
communication with the
stored volume of water or hydrocarbons. After the water or hydrocarbons have
been removed
from the LLISR 12, a waste product 40 can be injected into the LLISR 12 for
permanent storage
at step 52. As discussed in greater detail below, the waste product 40 can
include, for example,
wastewater, brine, MFT, FTT, treated tailings, or drilling waste.
[0093] FIGS. 4a and 4b illustrate the steps in FIG. 3 schematically. In the
example shown,
the LLISR 12 includes at least one injection well 60 and at least one
production well 62. The
injection well 60 can be used in Stage 1 to inject the water or hydrocarbons
into the LLISR 12
for temporary storage after which the water or hydrocarbons can be removed
from storage
using the production well 62. In Stage 2, the injection well 60 can be used to
inject the waste
product 40 for permanent storage. However, as shown in dashed lines, it can be
appreciated
that for Stage 2 both the injection well 60 and the production well 62 can be
used to inject the
waste product 40 for permanent storage.
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Date Recue/Date Received 2021-03-04
[0094] FIG. 5 is a flow chart for implementing another strategy for using
an LLISR 12 in this
case wherein heat is first recovered from the LLISR 12 before using the LLISR
12 for temporary
or permanent storage (or both as illustrated in FIG. 5). At step 72, heat is
recovered from the
LLISR 12, e.g., by circulating a fluid such as water through the LLISR 12 to
have the LLISR 12
heat that fluid and thereby extract heat from the LLISR 12 and surrounding
formation. As noted
above, it can be appreciated that for heat recovery phase, any heat sweeping
or other working
fluid of water and/or hydrocarbons and/or non-hydrocarbons and/or gas phases,
with any range
of additives in the solid, liquid or gas phases can be used. The process of
recovering heat from
the LLISR 12 at step 72 can be performed until the temperature of the LLISR
12, measured at
step 74, falls to a predetermined threshold temperature. The heat recovery
stage (Stage 1) is
illustrated in FIG. 6a in which a temperature measurement 90 is taken using a
temperature
measurement device 92 positioned in a the LLISR 12. A heat recovery fluid 94
such as water
can be injected into the injection well 60 and produced via the production
well 62 to generate a
heated fluid 96.
[0095] The LLISR 12 can be used, in an example implementation, to store
water or
hydrocarbons at step 78 and the water or hydrocarbons produced from the LLISR
12 at step 80,
e.g., as described above. The water or hydrocarbons are therefore temporarily
stored in the
LLISR 12 after the heat has been recovered and prior to permanent storage of a
waste material
at step 82. It can be appreciated that, as shown in FIG. 1 b, the stages
exemplified herein can be
implemented independently and in different combinations. For example, a
temporary storage
phase can be followed by a waste disposal stage without any heat recovery in
other
implementations. FIGS. 6b and 6c illustrate Stages 2 and 3 of the example
process illustrated
in FIG. 5.
[0096] An LLISR 12 that is available for further use according to a
strategy outlined herein
can be located between, adjacent or otherwise near an actively producing
reservoir. When in
proximity of such an actively producing reservoir, migration of stored fluids
such as water,
hydrocarbons or waste from the LLISR 12 can lead to fluid loss and/or
contamination of the
actively producing reservoir. FIG. 7 is a flow chart for implementing yet
another strategy for
using an LLISR 12 that mitigates such migration of stored fluids. Migration
can be mitigated by
surrounding an injection well 60 with a number of production wells 62, and a
number of gas
injection wells 63 (see also FIG. 8a) surrounding the production wells 62. At
step 100, water
can be injected into the LLISR 12 and the injected water stored in the LLISR
12 for a period of
time at step 102. During storage of this water at step 102, at least some of
the water that
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Date Recue/Date Received 2021-03-04
migrates towards the production well(s) 62 can be drawn out of the LLISR 12 by
monitoring
what fluid drains to the production well(s) 62 and cycling fluid using the
production wells 62 at
step 104. The water that is drawn out of the production well(s) 62 can be
returned to the LLISR
12 via the injection well 60. At the same time or after determining that some
migration has
occurred (e.g., via presence in the production well(s) 62), a gas can be
injected through gas
injection wells 63 that surround the production wells 62 at step 106. The gas
wells 63 provide a
buffer between the injection/production wells 60, 62 and any adjacent or
nearby actively
producing reservoirs, further details of which are provided below. Optionally,
as shown in
dashed lines, at least a portion of the water stored in the LLISR 12 can be
produced at step 108.
[0097] The gas injection wells 63 can also be used for short-, medium-, and
long-term
sequestration of a gas, such as 002. That is, the gas used to provide a buffer
between an
LLISR 12 and nearby active reservoirs can be one where a temporary or long-
term storage is
desired. For example, CO2 to be sequestered can first be used as the buffer
gas described
above and then subsequently left behind after the operations involving the
LLISR 12 are
complete. It can be appreciated that there can also be gas co-injected with an
injected water
stream and thus injecting gas into the LLISR 12 should not be limited to gas
injection wells 63. It
can also be appreciated that the gas left behind in the gas injection wells 63
can be pressurized
to a maximum allowable pressure to avoid the liquid water from flashing into
steam, considering
that as reservoir temperature drops so can the pressurization of gas.
Similarly, the CO2 or other
gas that is injected into the gas injection wells 63 can be produced back up
to surface at a later
time if the gas is needed in another process.
[0098] FIGS. 8a and 8b illustrate the stages associated with the process
shown in FIG. 7.
As shown in FIG. 8a, water can be injected into the LLISR 12 via an injection
well 60 that is
surrounded by production wells 62 on either side thereof. The production wells
62 are
positioned to enable water that migrates away from the injection well 60 to be
drawn out of the
LLISR 12 and potentially injected back into the LLISR 12 via the injection
well 60 or used in an
application. Gas wells 63 are positioned to surround the production wells 62
and can be
injected with a pressure control fluid, i.e., fluids that are injected into
subsurface formations for
the purposes of, e.g., pressure control or controlling hydrocarbon movement
within and/or
between reservoirs. Pressure control fluids can be, for example, non-
condensable gases
(NCGs), e.g., N2, CO2, or methane or vaporized condensable gases (e.g.,
naphtha, pentane).
[0099] The pressure controlled fluid (gas being shown for illustrative
purposes) is used to
create a buffer, i.e. a "wall" or "fence" to prevent or at least mitigate the
injection wells 60 and/or
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Date Recue/Date Received 2021-03-04
production wells 62 in the LLISR 12 from pulling in steam or other fluids from
a nearby active
reservoir. Stage 2 shown in FIG. 8b illustrates that during storage, the gas
can be injected into
the gas wells 63 and, if needed, water can be drawn out of the LLISR 12 via
the production
wells 62 that surround the injection well 60. As shown in dashed lines, the
water drawn out of
the production wells 62 can be reinjected to the LLISR 12 via the injection
well 60.
[00100] FIG. 9a provides an aerial schematic view of an area comprising an
LLISR 12 that is
positioned between actively producing reservoirs 110. In this example, the
actively producing
reservoirs 110 include at least one active well 130 that injects steam into
the reservoir 110. The
LLISR 12 includes a number of wells or well pairs from one or more depleted
well pads
associated with the LLISR 12, which can be repurposed as water injection wells
60, water
production wells 62 or gas injection wells 63. Referring to the legend in FIG.
9a, in this
example, two injection wells 60 are positioned with production wells 62 on
either side to enable
water that migrates away from the injection wells 60 to be drawn out of the
LLISR 12 during
storage of the fluid. Surrounding the outer production wells 62 are perimeter
gas injection wells
63 that provide the buffer between the LLISR 12 and the actively producing
reservoirs 110. The
perimeter gas injection wells 63 effectively create a gas fence or wall around
the LLISR 12 by
maintaining a higher pressure than the injection and production wells 60, 62
they contain, while
being at a slightly lower pressure than the neighboring active wells 130. For
example, if the
LLISR 12 is operated at a pressure of 1495 kPa or lower, and the active wells
130 are operated
at approximately 1500 kPa, the gas injection wells 63 can be operated at
approximately 1495
kPa to mitigate any outward migration from the LLISR 12 while only allowing a
relatively small
amount of steam to trickle towards the gas injection wells 63. In the example
shown in FIG. 9a
the wells associated with the LLISR 12 are shown perpendicular to the active
wells 130,
however, it can be appreciated that such wells can also be positioned parallel
thereto (or in any
other relative orientation that was employed). Moreover, while active wells
130 are shown on
two sides of the LLISR 12, other active wells 130 can exist adjacent or nearby
the other sides.
FIG. 9b illustrates an alternative configuration in which the upper actively
producing reservoir
110 includes a steam injection well 130 adjacent a gas injection well 63 that
is adjacent a
production well 62 that can be used to produce water driven out of the area by
the gas injection
well 63. As such, it can be appreciated that various perimeter well
configurations can be
implemented between an LLISR 12 and a nearby actively producing reservoir 110.
[00101] FIG. 10 is an aerial schematic view of an area comprising an LLISR
12 in yet another
configuration. In this other configuration, the LLISR 12 is adjacent a cold
reservoir 140, which
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Date Recue/Date Received 2021-03-04
may include a depleted or cold bitumen reservoir or another type of formation
that does not
include any actively producing reservoirs 110. In this example, multiple rows
of injection and
production wells 60, 62 are positioned between the cold reservoir 140 and an
actively producing
reservoir 110 in which steam is being injected. Similar to the configuration
in FIG. 9, the LLISR
12 shown in FIG. 10 is buffered against the active reservoir 110 by
positioning gas injection
wells 63 in between. The bottom row in FIG. 10 includes an injection well 60
adjacent the cold
reservoir 140 to illustrate that the wells to that side of the LLISR 12 can be
configured in either
order.
[00102] FIG. 11a provides a cross-sectional view of a set of wells 60, 62,
63, 64 in an LLISR
12. In the configuration shown in FIG. 11a, a series of adjacent well pairs
155 are repurposed
for heat recapture, temporary storage and/or permanent storage in the LLISR
12. This
configuration can be achieved using existing wells in an LLISR 12. However, it
can be
appreciated that the principles discussed herein can also be implemented using
newly drilled
wells. The well pairs 155 in this example can be existing SAGD well pairs 155
wherein the
upper one of the well pair 155 was used as a steam injection well, and the
lower one of the well
pair 155 was used as a SAGD production well. For ease of illustration, the
wells 60, 62, 63 are
identified using different cross-hatching or fills according to a legend
provided in FIG. 11a. It
can be seen that in this example, five well pairs 155 are repurposed in the
LLISR 12 to further
utilize the pore space and potentially to extract heat in the surrounding
formation. The central
one of the well pairs 155 is configured to provide an injection well 60 in the
upper well and the
lower well of the well pair 155 is closed off to become an inactive well 64.
On each side of the
central well pair 155, the lower ones of those well pairs 155 are used as
production wells 62 and
the upper ones of the well pairs 155 closed off as inactive wells 64. On each
side of the central
three well pairs 155 is a pair of gas injection wells 63. It can be
appreciated that either one or
the other of the outer well pairs 155 can be used as a gas injection well 63
rather than using
both as illustrated.
[00103] FIG. lla illustrates water, hydrocarbons, or multi-component
emulsions including
hydrocarbons being injected from the centrally located injection well 60 and
an example of a
fluid mound 150 that can form below the injection well 60 and around the
production wells 62.
The gas wells 63 are operated to mitigate migration of the injected fluid from
the LLISR 12 and
into adjacent formations, which can include cold or active reservoirs. As
indicated above, when
used for temporary storage, fluids can be drawn out of the LLISR 12 using the
production wells
62 and the drawn-out fluids can be re-injected into the LLISR 12 through the
injection well 60.
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Date Recue/Date Received 2021-03-04
FIG. llb illustrates another example of a fluid mound 150 illustrating that
the fluid being injected
from the centrally located injection well 60 may descend more rapidly towards
the production
wells 62, e.g., where the formation is relatively more permeable when compared
to the fluid
mound 150 shown in FIG. 11a.
[00104] Turning now to FIG. 11c, the cross-sectional view of FIGS. ha and lib
can be used
to illustrate that a solid, semisolid and/or liquid boundary (shown using grey
zones surrounding
what may be referred to herein as boundary wells 165) can be used to retain
injected
wastewater for energy recovery, by injecting into either or both the injector
and production wells
60, 62. It can be appreciated that these barriers can be on either or both
sides of the well pad,
or on either or both sides of the edge gas wells 63 (e.g., on both sides as
shown in FIG. 11c).
The boundary wells 165 can also take the place of gas injection well(s) 63,
and can enable
liquid level build up by withdrawing the water before it seeps over into the
next active well pad to
increase the water in the heat recovery pad due to the reduced risk of
seepage. The boundary
wells 165 can be created using various mechanisms, such as cement squeeze, or
using a
material such as a non-Newtonian MFTs (or treated MFTs), a specific gravity
(SG) > 1 material,
a hydrophobic material, etc.
[00105] FIG. lid also uses the cross-sectional views of FIGS. lla and llb
to illustrate an
effect of using boundary mechanisms. In this example, it can be appreciated
that the gas barrier
provides an opposing pressure to steam. The entire LLISR 12 can effectively
become a NCG-
filled chamber wherein the NCG comes from the gas injection wells 63 at the
boundary edge of
the LLISR 12. In the example shown in FIG. 11d, the boundary wells 165
illustrated in FIG. 11c
are also included. It can be appreciated that the water injection process
illustrated in FIG. lid is
gravity dominated, meaning that the liquid water tends to move to the bottom
of the reservoir.
Since gas is orders of magnitude less dense than water, one would not assume
that gas would
displace water at the bottom of the reservoir. Gas injection is thus used to
inhibit steam from
migrating from an active well pad to the LLISR 12 and to maintain pressure in
the reservoir to
ensure that the hot liquid water does not, for example, flash to steam because
of a drop in
pressure. The production well(s) 62 can be used to limit the migration of
injected liquid water
over to the active well pad(s). That is, in the absence of a physical barrier
(e.g., oil wedge, MFT
barrier, cement squeeze, etc.), the production well 62 would potentially be
both the first and last
line of defense. As such, the production well(s) 62 can be in substantially
constant production
for both heat recovery and to lower the water head at the edge of the LLISR
pad.
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Date Recue/Date Received 2021-03-04
[00106] It can also be appreciated from FIG. 11d that the gas injection
well(s) 62 can be
positioned in various locations depending on the permeability of the LLISR 12.
For example, in
an LLISR 12 with a relatively high permeability the gas injection well(s) 62
can be located
anywhere in the LLISR 12 and not necessarily on the edges.
[00107] FIG. 12 illustrates further detail for an example for implementing
a water circulation
or storage strategy using an LLISR 12. Using SAGD as an example, a typical
water cycle at a
SAGD facility already uses the heat from the reservoir. The fluid produced
from the SAGD wells
can be transported to a central processing facility (CPF), where the water and
bitumen can be
cooled via heat exchangers using treated water, then separated. Alternatively,
the water and
bitumen can be separated to avoid heat exchanger fouling and then the heat
recovered. The
water is then treated and recycled with the addition of make-up water. This
treated water
passes through a heat exchanger with the original hot fluid, increasing the
temperature, e.g.,
back up to 140-170 C. As fresh boiler feed water the heated water moves to a
steam
generation system, where it is heated back into steam. The water is then re-
injected as steam
into the SAGD well. When it comes to steam generation, OTSGs 213 produce a
boiler
blowdown waste stream of concentrated impurities. Injecting this blowdown into
an LLISR 12
can provide at least two advantages. First, the amount of blowdown being
turned into solid
waste can be reduced, which would otherwise require landfill; or can reduce
the load on the
disposal wells currently used. Second, the volume of disposable OTSG blowdown
can be
increased, which can improve the quality of boiler feedwater by allowing the
operation to flush
out more of the impurities and organics. The increased removal of impurities
can enable
operations to improve steam quality to the well pads, which can drive down
operating costs.
Additionally, organics removal is considered increasingly important due to
fouling, which can
damage downstream pipelines and drive up maintenance and chemical costs.
Improved water
quality can thus help to avoid steam header issues of erosion, corrosion, and
flow accelerated
corrosion.
[00108] In the example shown in FIG. 12, a water source, such as produced
water 202 or a
disposal source 204 such as blowdown delivered using a pipeline 206 can be
provided to a
filtration stage 208 at the LLISR 12 well pad. It can be appreciated that
process water
blowdown can encompass water streams such as connate water, tailings treatment
release
water (i.e. from mine tailings processed using the advanced dewatering (ADVV)
process), dyke
seepage, or mine depressurization water, which can be categorized as total
dissolved solids
(TDS) of <4000 mg/L and TDS >4000 mg/L. The filtration stage 208 can be used
to extract
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Date Recue/Date Received 2021-03-04
solids from the water source prior to injecting same into the LLISR 12 via the
injection well 60.
Water that is drawn out, produced or circulated through the LLISR 12 via the
production well 62
can be directed to a gas/emulsion separator 210 to obtain any produced gas
from the emulsion.
The emulsion can be fed to a water/hydrocarbon separator stage 214 to separate
the produced
hydrocarbons from the produced water 202. Since the LLISR 12 may retain some
heat, a heat
recovery stage 212 can be used to extract heat from the produced water 202,
e.g., to preheat
boiler feed water before feeding the boiler feed water to an OTSG 213 or other
steam
generating unit to generate steam. The produced water 202 from the LLISR 12
can be fed back
to the filtration stage 208 and re-injected into the LLISR 12 via the
injection well 60. The
injection/circulation of the water source can be used in a water flooding
phase as shown in FIG.
2, in a temporary water storage phase, in a heat recovery phase, or in a
permanent storage
phase for wastewater. As such, while the produced water 202 from the LLISR 12
is shown as
being re-injected, this produced water 202 can also be redirected to another
application when
desired. The produced hydrocarbon can be sent to a pipeline, transport channel
or to storage.
It can be appreciated that the storage can include storage in an LLISR 12, as
shown in FIG. 13.
[00109] Turning now to FIG. 13, the LLISR 12 in this example is equipped to
permit the
storage and recovery of a hydrocarbon such as diluted bitumen (dilbit) or
other hydrocarbon
emulsions or products such as emulsified bitumen, froth, or upgraded products.
Operational
constraints such as curtailment or changes in seasonal demand can mean that
produced
hydrocarbons such as dilbit in some circumstances enter the market at less
than ideal
conditions. Temporarily storing dilbit in an LLISR 12 can enable producers to
produce back and
sell an increased volume of hydrocarbons once a curtailment ends or at another
time when
more profitable. In this way, interruptions to production can be mitigated. It
may be noted that
the increased mobility of hydrocarbons such as dilbit at lower temperatures as
compared to
bitumen enables the injected dilbit to be produced back when desired or
required. Depending
on the nature of the LLISR 12, considerations should be taken to eliminate
contaminate of
residual connate and/or ground water by applying a chloride treatment.
Moreover, pressure
controls should be implemented since inadequate reservoir pressure controls
could allow the
dilbit to rise above its boiling point in a high temperature LLSR 12, allowing
the naphtha to
vaporize in situ, increasing the reservoir pressure while returning the dilbit
to bitumen.
Furthermore, it is appreciated that dilbit is lighter than connate water so
can be driven upwards
in the reservoir and lost while only connate water is produced.
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Date Recue/Date Received 2021-03-04
[00110] The hydrocarbon, such as dilbit, can be fed via a pipeline 206 to
the well pad
associated with the LLISR 12 and injected via the injection well 60. NCG can
be added to the
hydrocarbon at the point of injection. When the hydrocarbon is retrieved it is
produced via the
production well 62 and fed to a gas/emulsion separator 210 to separate
produced gas from the
emulsion. The emulsion can then be subjected to an optional heat recovery
stage 212 (as
illustrated in dashed lines) and a water/hydrocarbon separate stage 214 as
discussed above.
The produced hydrocarbons can be fed to a pipeline or transport channel or
storage. The
produced fluids from the separator 214 can be fed into a water treatment stage
224 to extract
skimmed oil and generate produced water 202 that can be used in any suitable
application,
including storage in an LLISR 12 as shown in FIG. 12.
[00111] The produced gas can be fed to a light end separator/condenser stage
220 to extract
diluent, if present, for storage in a storage tank 222. The diluent from the
storage tank 222 can
be reclaimed and used elsewhere or fed back into the separated emulsion to be
mixed with the
hydrocarbons that are separated in stage 214.
[00112] FIG. 14 illustrates a disposal strategy for an LLISR 12 for the
permanent disposal of
brine, in which produced water 202 is fed to a desalinator 230 (or brine
concentration system
that utilizes natural or enhanced evaporation to create a concentrated saline
solution), to
separate clean water from a brine component. It may be noted that tailings
could also be treated
with desalination to produce a brine and enable the discharge of clean water.
The desalinator
230 (or brine concentration system) can be part of a water treatment facility
that can be used to
treat the water to ensure that the clean stream can be returned to the water
source such as a
river or other body of water. For example, brine process water is a component
of in situ
produced water blowdown and has been found to have a concentration of salt
that is already too
high to be returned to a water source such as a river. Disposing of
concentrated brine into an
LLISR 12 as shown in FIG. 14 can be an effective water quality strategy to
control this problem
associated with the relatively high concentration of salt in the blowdown.
Water treatment can
be implemented since, with brine injection, there is a possibility of
premature reservoir plugging
due to the presence of particulates, precipitates and/or secondary reactions.
[00113] The brine component resulting from the water treatment desalinator 230
can be fed
to a pipeline 206 via a pumping stage 232 and applied to a filtration stage
208 to extract solids
prior to injecting the brine into the LLISR 12 for disposal. Fluids that are
drawn out or otherwise
returned via the production wells 62 can be processed to separate gas and
hydrocarbons using
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Date Recue/Date Received 2021-03-04
stages 210, 214 as discussed above. The produced water 202 resulting from the
separation
stages 210, 214 can be returned to the LLISR 12.
[00114] FIG. 15 illustrates a strategy for extracting heat from an LLISR 12
and directly using
the heated water in mining operations. It may be noted that the heated LLISR
water can be kept
separate from the extraction fluid by using heat exchangers for the transfer
of heat and the
configuration shown is for illustrative purposes. In some estimates, a base
mining plant can use
as much as 160 gallons of 85 C water to process 1 ton of ore, which in turn
produces 0.65 bbls
of oil. A combination of heat recovery, coke and natural gas combustion can
raise 61,000 US
gal/min (13,855 m3/hr) of water from ambient tailings pond temperature to 85
C. One way to
provide 85 C water to a base plant is to pipe higher temperature LLISR water
and dilute it with
cooler tailings water. Assuming that current waste heat recovery at the base
plant raises the
tailings water to 50 C, and an average LLISR hot water temperature of 140 C,
the base plant
could operate for several years on several LLISR wells, while reducing 002,
coke or natural gas
consumption. Moreover, the LLISR hot water could be piped straight to the base
plant and
would not require filtration prior to being used in a mining process. Also,
any entrained bitumen
could be produced in the base plant extraction process.
[00115] In this example, water from a water pond 240 can be extracted by a
pumping stage
232 and then fed to a pipeline 206 for transport to a filtration stage 208 at
the well pad
associated with the LLISR 12. The filtration stage 208 can be used to remove
solids from the
water source prior to being injected into the LLISR 12 via the injection well
60. The water
produced via the production well 62 is heated by the LLISR 12 and fed to a
gas/emulsion
separator 210 to extract produced gas from a low bitumen emulsion. The low
bitumen emulsion
can be pumped via a second pumping stage 242 to second pipeline 244 that is
coupled to a
primary extraction stage 246 used in the mine operations. The primary
extraction stage 246 in
this example can add make-up water from the water pond 240 to cool the heated
LLISR water.
Tailings water generated by the primary extraction process can be returned to
the water pond
240. It can be appreciated that the first and second pipelines 206, 244 can be
implemented
using a two-way pipeline between the well pad associated with the LLISR 12 and
the mine site.
It can be appreciated that since non-aqueous extraction (NAE) processes (e.g.,
using solvents)
require heat and thus the water can be used to heat a future process fluid or
solvent to prepare
it for use in such an NAE or other process.
[00116] FIG. 16 illustrates a strategy for extracting heat from an LLISR 12
and directly using
the heated water in an in situ operation, e.g., to replace natural gas
consumption for steam
-21 -
Date Recue/Date Received 2021-03-04
production and/or for a heat trace operation. In this example, disposal make-
up water 250 can
be transported to the well pad associated with the LLISR 12 via a pipeline 206
and fed to a
filtration stage 208 to extract solids prior to being injected into the LLISR
12 via the injection well
60. The filtered water that is injected into the LLISR 12 is heated by way of
geothermal heating
and when produced via the production well 62 can be used to offset natural gas
combustion. In
the example shown in FIG. 16, after being fed through a gas/emulsion separator
210 the heated
water can be coupled to a heat exchanger 212 and glycol loop steam pre-heat
stage 252 to
recover heat. The pre-heat stage 252 can also be coupled to a glycol loop heat
trace 254.
[00117] The emulsion from the separator 210 can be fed to a water/hydrocarbon
separator
214 to separate produced water from the hydrocarbons in the emulsion, which
can be fed to a
pipeline, transport channel or storage.
[00118] FIG. 17 illustrates a strategy for extracting heat from an LLISR 12
and using the
extracted heat to generate electricity that can be fed into an electrical
grid. In this example,
disposal make-up water can be transported to the well pad associated with the
LLISR 12 via a
pipeline 206 and fed to a filtration stage 208 to extract solids prior to
being injected into the
LLISR 12 via the injection well 60. The filtered water that is injected into
the LLISR 12 is heated
by way of geothermal heating and when produced via the production well 62 can
be used to
generate electricity. In the example shown in FIG. 17, after being fed through
a gas/emulsion
separator 210 the heated water can be coupled to a heat exchanger 212 and
optional glycol
loop steam pre-heat stage 252 (as shown in dashed lines) to recover heat. The
pre-heat stage
252 can also be coupled to an organic Rankin cycle (ORC) unit 260 to convert
the heat to
electricity that can be exported to an electrical grid.
[00119] As indicated above, the LLISR 12 can be used in a process for
permanent M FT
and/or FTT storage. The injection of untreated MFT and FTT into an LLISR pore
space can
contribute to plugging the reservoir. FIG. 18 illustrates a configuration for
an MFT/FTT
permanent storage strategy that includes tailings treatment operations prior
to injecting the
tailings into the LLISR 12. Tailings from a tailings pond can be extracted by
applying a dredge
operation 270 with some dredge recycling being fed back to the tailings pond.
The dredge can
be fed to a screen unit 272 to prevent plugging and remove debris 274. The
screened tailings
can be subjected to a coarse cyclone process 275, which removes construction
materials 278
via an underflow; followed by a fine screen process 280 (e.g. using a rotating
drum or pusher
centrifuge) to extract further debris 282. It can be appreciated that the
coarse and fine screening
stages can be combined into a single unit with a two-stage screen at stage
272, as shown in the
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Date Recue/Date Received 2021-03-04
alternative configuration in FIG. 19. The fine screened tailings can then be
subjected to a fine
cyclone 284 where the larger particles (debris 285) are removed by the
underflow and sent back
to the tailings pond for tailings treatment 286. The overflow from the fine
cyclone can be
examined for particle size such that only treated tailings with a particle
size at or below a
predetermined threshold are fed to a pipeline 206. Tailings with larger
particle sizes can be fed
to a blunge stage 290 and returned to the fine cyclone 284 for further
processing.
[00120] Segregating the MFT/FTT can use a two-stage cyclone process as shown
schematically in FIGS. 18 and 19, with a fine pusher type centrifuge 280 and a
blunger 290 to
segregate the streams into larger construction sized particles (-<44 pin),
intermediate clay
particles (>5 pin but <44 pin), and the < 5 pm stream for injection well 60
deposit. The coarse
particles in the finer fractions can be substantially clays which could be
disaggregated with
blunging, namely a clay process involving high intensity mixing. Blunging of
the coarse fraction
of the final product promotes a controlled top size for downhole injection. To
address any
potential issues with viscosity, for injection, the MFT/FTT could be diluted
with other waste
waters for injection. It is also possible to use a centrifuge in place of a
cyclone for the the M FT
separation process.
[00121] The pipeline 206 can carry the treated tailings to a well pad
associated with the
LLISR 12 and injected into the LLISR 12 via the injection well 60. Fluids
produced from the
production well 62 can be fed to a gas/emulsion separator 210 and
water/hydrocarbon
separator 212 as described above. The produced water from the separate 212 can
be sent to a
next well pad (if applicable), wherein secondary water streams with thin MFT
generated at that
well pad can be fed back to the LLISR 12 for permanent storage.
[00122] When an in situ hydrocarbon recovery process, such as SAGD, has been
implemented for an extended period of time, it has been found that through
conduction there
can be substantial heat stored in the overburden formation. This heat can also
be recovered, as
illustrated in FIG. 20. As shown in FIG. 20, injection and production wells
60, 62 can be drilled
into the overburden formation (fm2) that is positioned above the caprock
overlying the reservoir
formation (fm1). It can be appreciated that such an overburden heat recovery
process from fm2
can be performed either in parallel with a heat recovery process applied to
fm1 (e.g., as
described above), or prior to fm1 becoming an LLISR 20. That is, the
overburden heat recovery
process shown in FIG. 20 can be implemented at any suitable time where there
is sufficient heat
in fm2 to recover energy therefrom.
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Date Recue/Date Received 2021-03-04
[00123] In
the example shown in FIG. 20, cold water is injected into the injection well
60 and
heated water is recovered via the production well 62. Using the upper
formation (fm2)
independently or in conjunction with the lower formation (fm1) creates
additional options for heat
recovery. When compared to the techniques described above, this overburden
heat recovery
process occurs above the caprock. This means that the two reservoirs (fm1,
fm2) are
hydraulically isolated from each other, implying that there is likely not a
need for the gas
injection techniques described above to maintain reservoir pressure or to
mitigate the risk of
fluid communication with active SAGD pads. It may be noted that this
configuration is not
thermally isolated as the heat originates (i.e. is conducted up) from the SAGD
reservoir below.
The overburden heat recovery process shown in FIG. 20 could be implemented
using sealed
pipes that run in a closed loop through the artificially heated overburden, or
in the same manner
as described above, where water is driven between horizontal or vertical
injector and production
wells 60, 62.
[00124] Turning now to FIG. 21a, a reservoir that will become an LLISR 12
subsequent to a
hydrocarbon recovery process is shown. In this example, a SAGD process is
being
implemented at the reservoir, in which steam is injected into the reservoir
adding heat to the
formation. During this process, heat is transferred throughout the reservoir
by conduction,
convection and, to a lesser extent, radiation. Similarly, heat is transferred
to the overburden
160 and the underburden 170 by conduction and, to a lesser extent, radiation,
as shown in FIG.
21a. That is, the heat that is added to the reservoir during active production
and up to the point
that the reservoir becomes an LLISR 12, the LLISR 12 can act as a source of
heat to both the
overburden 160 and underburden 170. Similar to the process illustrated in FIG.
20, heat can
also be recovered from the underburden 170 as illustrated in FIGS. 21b and
21c.
[00125] One way to recover heat from the underburden 170 is shown in FIG. 21b,
in which a
similar configuration as that shown in FIG. 20 is implemented by drilling an
injection well 60 and
a production well 62 into the underburden 170. Water can then be cycled
through the injection
and production wells 60, 62 to recover heat in the underburden 170. As shown
using dashed
lines in FIG. 21b, recovering heat from the underburden 170 using the wells
60, 62 can also be
implemented while the hydrocarbon recovery process (SAGD in this example)
remains active,
i.e., before becoming an LLISR 12. The configuration shown in FIG. 21b could
also be
implemented using sealed pipes that run in a closed loop through the
artificially heated
overburden, for example, U-shaped, vertical, or L-shaped as shown in FIGS. 21c-
21e
respectively.
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Date Recue/Date Received 2021-03-04
[00126] Another way to recover heat from the underburden 170 can occur during
the heat
recovery process described above as shown, for example, in FIG. 21f. Referring
now to FIG.
21f, it may be noted that heat recovery through water injection into an LLISR
12 as discussed
above, is a gravity dominated process, which means that the injected water
should preferentially
follow along and remain at the base of the reservoir. Since conduction is
expected to provide
the majority of the heating of the underburden, conduction is also expected to
be the
mechanism by which heat is recovered from the underburden by the water in the
LLISR 12. As
shown in FIG. 21f, the water flows parallel to the interface of the LLISR 12
and the top of the
underburden 170 and substantially perpendicular to the heat flux vector.
[00127] As discussed above, strategies can be employed to mitigate horizontal
migration
between laterally adjacent or "parallel" well pads (i.e., parallel actively
producing reservoirs
110), such as in the configuration shown in FIG. 10, by including gas
injection wells 63 between
active well pads and the LLISR 12. Turning now to FIGS. 22a-22c, fluids such
as water can also
flow between well pads that are longitudinally adjacent or in "series" with
each other. This issue
can be particularly prevalent if the injection and production wells 60, 62
from one pad overlap a
pad in series, and if no natural boundary or bitumen wedge exists. In the
example shown in FIG.
22a, it is assumed that an adjacent actively producing reservoir 110 (having
one or more well
pads each including a set of injection and production wells 60, 62 and shown
below the LLISR
12 in the figure) is an actively producing reservoir 110 implementing a SAGD
process. To
enable the LLISR 12 to be filled with a fluid such as water (e.g., for heat
recovery, disposal, etc.
as discussed herein) and to mitigate or avoid migration into the adjacent
actively producing
reservoir 110 that is aligned in series with the LLISR 12, a plugging material
such as MFTs, or a
commercially available cement squeeze product, etc., can be injected into the
toe 302 of the
injection wells 60, production wells 62, and gas wells 63 associated with the
LLISR 12 to create
a fluid migration barrier 300. This configuration also assumes that the wells
60, 62, 63 are
drilled in the same direction such that the toes 302 of those wells 60, 62, 63
extend in
substantially the same direction, as illustrated in FIG. 22a.
[00128] As shown in FIG. 22b, assuming the same orientation for the wells 60,
62, 63 in the
LLISR 12, a fluid migration barrier 304 can be implemented at or substantially
near the heels
306 of the injection wells 60, production wells 62, and gas wells 63 of the
LLISR 12, again
assuming that the wells 60, 62, 63 are drilled in the same direction. As such,
it can be
appreciated that the fluid migration barriers 300, 304 can be implemented at
either or both ends
of the LLISR 12 as illustrated in the configuration shown in FIG. 22c.
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Date Recue/Date Received 2021-03-04
[00129] It may be noted that in FIG. 22a, an actively producing reservoir
110 is shown
opposite the LLISR 12 and beyond the fluid migration barrier 300, whereas the
actively
producing reservoir shown in FIG. 22b is shown opposite the LLISR 12 and
beyond the fluid
migration barrier 304. FIG. 22c illustrates that both barriers 300, 304 can be
implemented to
inhibit or prevent fluid migration from the LLISR 12 to actively producing
reservoirs 110
positioned relative to the LLISR 12, in any direction.
[00130] FIGS. 23a and 23b illustrate cross-sectional schematic diagrams of
the fluid
migration barriers 304 and 300 respectively. Referring first to FIG. 23a, when
creating the fluid
migration barrier 304 at the heel 306 of the injection, production, and gas
wells 60, 62, 63 a
leading packer 310 can be placed ahead of a trailing packer 310 connected to
injection tubing
312 to enable a plugging slurry of MFTs, cement squeeze product, etc., can be
pumped down
into the void between the packers 310 and through the slotted liner,
perforated liner, or other
passages into the surrounding area of the formation, to create the barrier
304. The plugging
slurry would typically progress outwardly into the formation following the
permeability of the
formation, however, a localized perforation or dilation can be used to
initially guide the plugging
slurry in a particular direction. It can be appreciated that a variety of
packers 310 can be used,
for example, straddle packers (wherein the packers 310 are connected in a
single unit ¨ as
shown with dashed lines in FIG. 23a - with expanding sections to plug off the
well), wireline
packers, mechanical packers, inflatable packers, etc. These types of packers
310 allow fluid to
pass through them via one or more ports. While a plug or other obstruction
could be used for
the leading packer 310 (and later drilled out or retrieved, packers 310
permitting fluid to flow
through ports therein are particularly efficient in this implementation.
[00131] In the configuration shown in FIG. 23b, a packer 310 can be placed
near the toe 302
of the wells 60, 62, 63 and connected to injecting tubing 312 to enable the
plugging slurry to be
pumped down into the toe 302 and then into the surrounding area of the
formation via a slotted
liner, perforated liner, or other passages as illustrated.
[00132] Referring now to FIGS. 24a-24d, when storing fluids such as water
in an LLISR 12
(whether permanently or temporarily), fluid flow rates and fluid levels can be
varied over time to
both mitigate fluid migration to adjacent actively producing reservoirs 110
and, when being used
to recover heat from the formation, enable more heat to be harvested from a
reservoir by having
certain LLISRs 12 filled to the top of the reservoir and, for example, be
heated by way of
conduction through less permeable (or impermeable) overburden and underburden
layers
above and below the reservoir.
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Date Recue/Date Received 2021-03-04
[00133] FIG. 24a illustrates a first stage in which a depleted reservoir,
namely an LLISR 12
as described herein, is adjacent actively producing reservoirs 110 to either
side. The LLISR 12
can be isolated by gas wells 63 as described above and shown using solid
barriers denoted by
numeral 63 in FIG. 24a. Since the LLISR 12 is directly adjacent the actively
producing reservoirs
110, water is injected into the LLISR 12, via injection wells 60, to a low
water threshold, e.g.,
1.5-2m above the adjacent producer wells 62. By filling the adjacent LLISR 12
to the low water
threshold, the risk of disposal water spilling into the adjacent actively
producing reservoir 110
can be reduced. Heat can be recovered from the reservoir using water injected
up to the low
water threshold, but significant amounts of the heat in the upper portion of
the reservoir would
not be recovered because the low water level would not reach the upper
portion.
[00134] When two parallel well pads or reservoirs are depleted and can both be
utilized as
LLISRs 12 as herein described, the LLISR 12a that is next to the actively
producing reservoir
110 can be filled to the low water threshold and become a buffer for the next
LLISR 12b as
shown in FIG. 24b. In FIG. 24b, LLISR 12b can also be filled with water up to
the low water
threshold and, with LLISR 12a acting as a buffer between it and the actively
producing reservoir
110, can be filled beyond that threshold, to a high water level, by increasing
the disposal
injection rate to further mound the water up to the top of the reservoir, as
shown using a darker
shade in FIG. 24cf0r LLISR 12b. This can be done since the risk of flooding
the actively
producing reservoir 110 is mitigated or even eliminated by having the buffer
LLISR 12a to
absorb any water migrating towards the actively producing reservoir 110.
[00135] FIG. 24d illustrates that this water level variation strategy can
be employed in a
staged implementation throughout an oil recovery site as reservoirs become
depleted and are
repurposed as LLISRs 12.
[00136] The high water LLISRs 12b are advantageous since by filling more of
the reservoir,
additional heat can be harvested, e.g., by conduction via the overburden and
underburden or
other impermeable layer. Moreover, the high water LLISR 12b can reduce the
amount of gas
being used by driving the gas used in the gas wells 63 (to maintain the
pressure), into the
adjacent buffer LLISR 12a. The high water LLISR 12b can also accelerate the
availability of the
disposal volume by enabling more water to be disposed of earlier in time,
rather than waiting
until the entire interconnected reservoir is depleted..
[00137] If LLISR 12b was in operation longer than LLISR 12a, the
temperature would be
likely be lower in LLISR 12b. In that case, cold water could be injected into
LLISR 12b, enabling
the lower temperature reservoir to heat the cold water to an intermediate or
"medium"
- 27 -
Date Recue/Date Received 2021-03-04
temperature. Then, such medium temperature water would flow over to the hotter
LLISR 12a
allowing for hotter water to be brought to surface. If water was only pumped
to surface from
LLISR 12a this would improve the efficiency of the heat recovery process
because hotter water
could be brought to surface for a longer period of time. This strategy employs
the same
principles as a counter flow heat exchanger, thus driving the efficiency of
the heat exchange
process between the reservoir and flowing water towards the maximum.
[00138] FIG. 25 illustrates the progression of water mounding in the buffer
LLISR 12a and
high water LLISR 12b from an end view perspective wherein the well pairs 60,
62 are shown
spaced through the LLISRs 12a, 12b. It can be seen that the buffer LLISR 12a
can
accommodate an migration from the high water LLISR 12b and over time prevents
or
substantially mitigates migration and flooding into the actively producing
reservoir 110.
[00139] For simplicity and clarity of illustration, where considered
appropriate, reference
numerals may be repeated among the figures to indicate corresponding or
analogous elements.
In addition, numerous specific details are set forth in order to provide a
thorough understanding
of the examples described herein. However, it will be understood by those of
ordinary skill in the
art that the examples described herein may be practiced without these specific
details. In other
instances, well-known methods, procedures and components have not been
described in detail
so as not to obscure the examples described herein. Also, the description is
not to be
considered as limiting the scope of the examples described herein.
[00140] The examples and corresponding diagrams used herein are for
illustrative purposes
only. Different configurations and terminology can be used without departing
from the principles
expressed herein. For instance, components and modules can be added, deleted,
modified, or
arranged with differing connections without departing from these principles.
[00141] The steps or operations in the flow charts and diagrams described
herein are just for
example. There may be many variations to these steps or operations without
departing from the
principles discussed above. For instance, the steps may be performed in a
differing order, or
steps may be added, deleted, or modified.
[00142] Although the above principles have been described with reference to
certain specific
examples, various modifications thereof will be apparent to those skilled in
the art as outlined in
the appended claims.
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