Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
1
SYSTEM AND METHOD FOR ESTABLISHING SUBSURFACE BARRIERS
TECHNICAL FIELD
[0001] The following generally relates to establishing subsurface barriers,
including by
disposing of a waste stream such as waste water or mature fine tailings or a
permeability
reducing agent, for example to provide thief zone abatement.
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 recovery technology. There are various in situ
recovery 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 recovery techniques, the heated fluids can be
injected into the
reservoir. However, in newer techniques, e.g., electric resistive heating, EM
radio frequency,
and induction, reservoir fluids can be heated in situ. There are also various
in situ recovery
technologies available that use non-thermal methods, e.g., solvent injection.
[0004] Common in situ recovery 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
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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, 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.
[0005] In CSS, a single, vertical or horizontal, 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] Heavy oil more generally differs from light crude oil by having a
higher viscosity and
specific gravity, as well as a heavier molecular composition. In situ recovery
techniques used in
heavy oil reservoirs can include in situ cold flow recovery techniques such as
Cold Heavy Oil
Production with Sand (CHOPS). In CHOPS, heavy oil production is implemented
through the
deliberate initiation of sand influx into a perforated oil well, maintenance
of sand influx during the
productive life of the well, separation of the sand from the oil, and the
disposal of the sand.
CHOPS is typically implemented without sand exclusion devices (e.g., screens,
liners, gravel
packs, etc.) being used in wellbores, and no filters, cyclones, or high-
pressure separators are
used at the surface. As such, the sand is produced with the oil, water and
gas, and separated
from the oil by settling. CHOPS can be practiced in unconsolidated sand
reservoirs containing
viscous oil. These reservoirs are typically shallow. Production of sand
results in formation of
elongated, open or partially open channels emanating from the perforations in
casing. These
channels are commonly referred to as "wormholes" and can create communication
channels
between distant wellbores. High pressure gradients lead to sand liquefaction
with advancement
that penetrates into the reservoir to form enhanced permeability zones.
Wormholes tend to grow
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in preferred layers within the formation and wormhole networks can enable sand
production to
be continuous and substantial in volume.
[0007] The creation of such wormhole networks can be problematic. CHOPS
wells are
characterized by quick pressure depletion and decline in production rates.
Despite
demonstrating sustained low production rates for extended periods of time,
CHOPS wells rarely
recover more than 10-15% of the oil originally in place. Maximizing recovery
factors from
CHOPS fields requires implementing secondary and tertiary recovery techniques.
However,
wormhole networks can serve as short circuits between injection and production
wells, resulting
in fast breakthrough of injected water, polymer or steam and reducing the
sweep efficiency and
thermal efficiency. Wormhole networks result in fast dissipation of pressure
and leak off of
injected fluids, rendering application of cyclic solvent and cyclic steam
methods ineffective.
Essentially, wormholes represent a secondary porosity and permeability in the
formation, not
unlike a fracture network. However, the morphology of wormhole networks is a
lot less
predictable than fracture networks.
[0008] In bitumen reservoirs, a thief zone or a lean zone can occur as
result of effects on
fluid saturation, wherein a lower initial bitumen saturation leads to a higher
gas or water
saturation, which leads to higher relative permeability to steam. Thief zones
may be a naturally
occurring region of the reservoir, such as layers and fractures associated
with a geological
process. Other examples can include high water-saturated zones, high gas-
saturated zones,
regional pressure trends that promote flow in undesirable directions (i.e.,
towards a receptor),
etc. However, thief zones can also be manmade, for example, a depleted or
otherwise late life
reservoir from which bitumen or heavy oil has been extracted.
[0009] The presence of thief zones can introduce certain challenges to
hydrocarbon
extraction. For example, thief zones can increase the risk of a production
well in an active
reservoir or reservoir zone producing large volumes of water, if such thief
zones connect the
production well to an aquifer. Thief zones are also known to be detrimental to
the sweep
efficiency. When a fluid is injected into the reservoir from an injection well
to mobilize bitumen or
heavy oil it is instead partially or wholly consumed by the thief zone.
Thief/lean zones can also
provide a more direct connection, creating a short-circuit between production
and injection wells
of a depleted or late life reservoir. In these aspects, wormholes can be
likened to thief zones.
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SUMMARY
[0010] Systems and methods are described herein that can be used to create
subsurface
barriers by injecting waste streams such as fine tailings or waste water
streams into a formation,
for example, using existing and/or newly drilled wells in hydrocarbon-bearing
reservoirs,
including late life, unused or previously unexploited reservoirs (e.g., prior
to production). In this
way, one can both dispose of the waste streams and create preferential
subsurface barriers to
cordon off portions of the formation, such as a hydrocarbon-bearing reservoir,
and abate thief
zones to improve the sweep efficiency of adjacent and active reservoirs. The
subsurface
barriers can also be used for other purposes, such as in implementing water
shut off in
conventional wells, plugging high permeability zones such as in salt caverns,
and for various
flow mitigation purposes subsurface. Systems and methods are also described
herein that use
the injection of such waste streams to plug portions of wormhole networks
created during a
primary extraction process such as CHOPS to facilitate the implementation of a
secondary
extraction process. Also described herein is a process to separate such waste
streams at a fine
particle size of problematic tailings streams, to produce a fine tailings
stream or fines fraction
and a coarse fraction for terrestrial deposition.
[0011] In one aspect, there is provided a method of creating subsurface
barriers in a
formation, the method comprising: injecting a waste stream and/or permeability
reducing agent
into at least one well to create a subsurface barrier in the formation by
reducing permeability of
at least a portion of the formation.
[0012] In an implementation, the method further includes drilling one or
more of the at least
one well. At least one additional well can be drilled adjacent to a first
well, and wherein injecting
the waste stream and/or permeability reducing agent can include injecting the
waste stream into
the first well and injecting the waste stream into the at least one additional
well to create the
subsurface barrier in the formation.
[0013] In an implementation, one or more of the at least one well can be an
existing well
that has been used in a hydrocarbon production process in the formation.
[0014] In an implementation, one or more of the at least one well can be a
new well drilled
into the formation.
[0015] In an implementation, the at least one additional well can be
drilled from the first well.
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[0016] In an implementation, the at least one additional well can be
drilled adjacent to the
first well after completing injection of the waste stream into the first well.
The method can further
include setting a bridge plug after completing injection of the waste stream
into the first well. The
waste stream can be injected in to the first well until at least one injection
criterion has been
met. The at least one injection criterion can include detecting a loss of
injectivity of the waste
stream. The at least one injection criterion can include establishing a target
area for the barrier.
[0017] In an implementation, a plurality of additional wells can be drilled
sequentially at a
distance from the first well or a previously drilled additional well after
injecting the waste stream
into the first well or the previously drilled well. The method can further
include setting a bridge
plug after completing injection of the waste stream into the first well or
previously drilled
additional well.
[0018] In an implementation, the at least one additional well can be
drilled from a build
section of the first well.
[0019] In an implementation, the waste stream comprises fine tailings. The
fine tailings can
include mature fine tailings. The fine tailings can include thin fluid
tailings. The method can
further include selecting fine tailings that swell in the presence of fresh
water downhole. The fine
tailings in the presence of the water downhole can form clay and/or scale at
high temperature
and subsequently swells. The water and/or fine tailings can be treated by
adding new chemicals
or minerals or by increasing a concentration of existing chemicals and/or
minerals to trigger a
desired plugging reaction in the formation. The fine tailings in the presence
of the water
downhole can form smectite.
[0020] In an implementation, the waste stream can include a disposal water
stream which
reduces the permeability of the formation by forming subsurface clays and/or
scales as a result
of reactions between the injected disposal water stream and formation water
and/or formation
rock.
[0021] In an implementation, the subsurface barrier can be created in or
adjacent to a
hydrocarbon-producing reservoir. The hydrocarbon-producing reservoir can be a
thermally
depleted reservoir. The hydrocarbon-producing reservoir can be a non-thermally
depleted
reservoir. The subsurface barrier can be created in a late life in situ
reservoir (LLISR). The
LLISR can be located in a bitumen reservoir.
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[0022] In an implementation, the formation can be located adjacent an
active reservoir, the
subsurface barrier creating a preferential barrier to abate a thief zone. The
thief zone can
include any one or more of a bottom water zone, a lean zone or a gas zone.
[0023] In an implementation, the subsurface barrier can be created in or
adjacent to a heavy
oil reservoir. The heavy oil reservoir can have been subjected to an in situ
cold flow recovery
technique with sand as a primary extraction process. The waste stream can be
injected prior to
initiating at least one additional extraction process. The primary extraction
process can include
cold heavy oil production with sand (CHOPS). The waste stream can be injected
to plug at least
one wormhole created by implementing the CHOPS process. The waste stream can
be injected
to plug at least one portion of a wormhole network created by implementing the
CHOPS
process. The waste stream can be injected to plug at least one wormhole
network created by
implementing the CHOPS process.
[0024] In an implementation, the method can further include isolating a
first interval of a
CHOPS well; and injecting the waste stream via the first isolated interval to
plug wormholes
intersecting with the isolated interval.
[0025] In an implementation, the method can further include isolating at
least one second
interval; and injecting the waste stream via the at least one second isolated
interval to plug
wormholes intersecting with the at least one second isolated interval.
[0026] In an implementation, the subsurface barrier can be formed to
counteract flow
towards a receptor due to a pressure gradient subsurface. The subsurface
barrier can be
formed to mitigate contaminated groundwater flow to limit spread of
contaminants towards the
receptor.
[0027] In an implementation, the subsurface barrier can be formed in or
adjacent to a salt
cavern to mitigate losses to the salt cavern.
[0028] In an implementation, the subsurface barrier can be formed in or
adjacent to a
conventional oil reservoir to implement bottom water shut off.
[0029] In an implementation, the subsurface barrier can be formed prior to
implementing a
hydrocarbon recovery process in the formation.
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[0030] In an implementation, the method can further include preparing the
waste stream for
injection into the formation by: separating a source fraction into a fines
fraction that is relatively
smaller that a coarse fraction; and providing the fines fraction to injection
equipment to inject the
fines fraction into the formation.
[0031] In an implementation, the method can further include repeating the
method to form a
plurality of subsurface barriers.
[0032] In an implementation, a plurality of first additional wells can be
drilled into the
formation to form a first barrier and at least one plurality of second
additional wells are drilled
into the formation to form at least one second barrier. The first barrier can
be formed from wells
drilled in alignment with a first originating well and the at least one second
barrier is formed from
wells drilled in alignment with at least one second originating well.
[0033] In an implementation, the wells are substantially horizontal wells.
[0034] In an implementation, the wells are substantially vertical wells.
[0035] In an implementation, the wells can include at least one
substantially horizontal well
and at least one substantially vertical well.
[0036] In another aspect, there is provided a method of facilitating heavy
oil production from
a heavy oil reservoir, comprising: injecting a waste stream into a well in the
heavy oil reservoir
to plug wormholes or preferential paths created by a previously implemented
primary extraction
process to facilitate a secondary or tertiary extraction process in the heavy
oil reservoir.
[0037] In an implementation, the method can include implementing the
secondary or tertiary
extraction process. The primary extraction process can include an in situ cold
flow process with
sand that has created wormholes. The primary extraction process can include
cold heavy oil
production with sand (CHOPS). The primary extraction process can include one
that does not
include sand production but creates preferential flow paths.
[0038] In another aspect, there is provided a method of preparing a waste
stream for
injection to a formation to form a subsurface barrier, the method comprising:
separating a
source fraction into a fines fraction that is relatively smaller that a coarse
fraction; and providing
the fines fraction to injection equipment to inject the fines fraction into
the formation.
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[0039] In an implementation, the source fraction can be separated using a
fine particle
separator. The fine particle separator can include a fine diameter cyclone.
The fine particle
separator can include a centrifuge.
[0040] In another aspect, there is provided a system for creating
subsurface barriers in a
formation, the system comprising: injection equipment configured to inject a
waste stream
and/or permeability reducing agent into at least one well to create a
subsurface barrier in the
formation by reducing permeability of at least a portion of the formation.
[0041] In another aspect, there is provided a system for facilitating heavy
oil production from
a heavy oil reservoir, comprising: injection equipment configured to inject a
waste stream into a
well in the heavy oil reservoir to plug wormholes or preferential paths
created by a previously
implemented primary extraction process to facilitate a secondary or tertiary
extraction process in
the heavy oil reservoir.
[0042] In another aspect, there is provided a system for preparing a waste
stream for
injection to a formation to form a subsurface barrier, the system comprising:
a separator
configured to separate a source fraction into a fines fraction that is
relatively smaller that a
coarse fraction; wherein the fines fraction is provided to injection equipment
to inject the fines
fraction into the formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0043] Embodiments will now be described with reference to the appended
drawings
wherein:
[0044] FIG. 1 is a schematic cross-sectional end view of a series of
reservoirs in a bitumen
reservoir.
[0045] FIG. 2a is a schematic cross-sectional end view of the reservoirs
shown in FIG. 1
with a subsurface barrier created in a late life in situ reservoir (LLISR)
adjacent an active
reservoir.
[0046] FIG. 2b is a schematic cross-sectional end view of the reservoirs
shown in FIG. 1
with a pair of subsurface barriers created in a pair of late life in situ
reservoirs (LLISRs) adjacent
the active reservoir.
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[0047] FIGS. 3a-3d are schematic cross-sectional side views of a LLISR in a
bitumen
reservoir that has been injected with fine tailings to create a subsurface
barrier using an original
substantially horizontal well or well pair and a series of substantially
horizontal lateral wells
drilled from the original well or well pair.
[0048] FIG. 4 is a cross-sectional end view of an original well pair and a
series of well pair
laterals drilled above the original well pair in creating a subsurface
barrier.
[0049] FIG. 5 is a schematic cross-sectional side view of an LLISR in a
bitumen reservoir
that has been injected with fine tailings to create a subsurface barrier using
an original
substantially vertical well and a series of additional substantially vertical
wells drilled from the
original vertical well.
[0050] FIG. 6 is a schematic cross-sectional side view of an LLISR in a
bitumen reservoir
that has been injected with fine tailings to create a subsurface barrier using
an original
substantially vertical well and a series of substantially horizontal lateral
wells drilled from the
original vertical well.
[0051] FIG. 7 is a schematic perspective view of a series of LLISRs in a
bitumen reservoir
that have been injected with fine tailings to create a set of subsurface
barriers using one or
more original substantially vertical wells and a series of substantially
horizontal lateral wells
drilled from each of the original vertical wells.
[0052] FIG. 8 is a flowchart illustrating operations performed in creating
a subsurface
barrier by injecting an original well or well pair with fine tailings and
subsequent lateral or
additional wells drilled from the original well or well pair.
[0053] FIG. 9a is a schematic diagram of a wormhole network adjacent a well
having
perforation intervals, with a first perforation interval being used to inject
fine tailings into
wormholes connected thereto.
[0054] FIG. 9b is a schematic diagram of the wormhole network and well
shown in FIG. 9a,
with a second perforation interval being used to inject fine tailings into
wormholes connected
thereto.
[0055] FIG. 10 is a block diagram of a fine particle size separation
process.
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[0056] FIG. lla is a schematic cross-sectional view of a heel of a well in
which a water
migration barrier has been established.
[0057] FIG. 11b is a schematic cross-sectional view of a toe of a well in
which a water
migration barrier has been established.
DETAILED DESCRIPTION
[0058] Processes are described herein to inject waste streams such as fine
tailings into
existing and/or newly drilled wells in late life, unused or unexploited
reservoirs to both dispose of
the waste streams and create preferential subsurface barriers to cordon off
such late life,
unused or previously unexploited reservoirs and abate thief zones to improve
the sweep
efficiency of adjacent and active reservoirs. It can be appreciated that the
principles described
herein can also be applied using a permeability reducing agent with or instead
of a waste
stream.
[0059] Processes are also described herein that use the injection of such
waste streams to
plug portions of wormhole networks created during a primary extraction process
such as
CHOPS to facilitate the implementation of a secondary extraction process. For
example,
perforated intervals of a well can be selectively isolated to inject such
waste streams into
adjacent areas of the formation and wormhole networks that intersect or are
otherwise near the
isolated perforated interval.
[0060] Also described herein is a process to separate such waste streams at
a fine particle
size of problematic tailings streams, to produce a fine tailings stream or
fines fraction and a
coarse fraction for terrestrial deposition.
[0061] Turning now to the figures, FIG. 1 illustrates an example of a SAGD
production site
at a bitumen reserve or reservoir, referred to herein as the "pay" 10. In this
example, a series of
SAGD well pairs 22, 24 are drilled from a surface location 14 towards the pay
10 and each well
pair 22, 24 is associated with a reservoir, which can be considered a portion,
area, region or
zone of the pay 10. In the illustrated example, the well pairs 22, 24 include
an injection well 22
positioned above a production well 24. As will be appreciated, the injector
well 22 is configured
to inject steam into the pay 10 and the producer well 24 is configured to
recover a bitumen-
containing fluid that has been mobilized by the injected steam during the
typical SAGD
production stage. The injector well 22 is typically located about 4 to 6
meters above the
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producer well 24 to define an inter-well region therebetween, however, other
relative distances
between the wells are possible. The SAGD well-pairs 22, 24 are drilled
vertically into an
overburden 12 towards and into the underlying pay 10, and as they are drilled
become oriented
substantially horizontal, such that the producer well 24 is above but near a
formation 16
underlying the pay 10 (hereinafter the "underlying formation 16"). The one or
more SAGD well
pairs 22, 24 are operated using a surface equipment (not shown) as is known in
the art.
[0062] In the example shown in FIG. 1, an active reservoir 18 is shown
adjacent to two late
life in situ reservoirs (LLISRs) 20. It will be understood that the term LLISR
20 as used herein
can mean any hydrocarbon bearing reservoir having a hydrocarbon depleted zone
therein
formed from an in situ recovery process. It can be appreciated that "late
life" as used herein can
mean pressure-depleted, but still with high oil saturation (e.g., post CHOPS).
Heavy oil
reservoirs can have top gas or bottom water zones with wormholes connecting
these thief
zones to the production wells. Late life can therefore also mean watered-out
wells in that
context. Other types of reservoirs applicable to the principles discussed
herein can include cold
heavy oil reservoirs without sand production having preferential flow paths.
For example,
horizontal wells in heavy oil may not produce sand or apply CHOPS if completed
with sand
controls in place, but such wells often result in depleting the reservoir
unevenly along the length
of a well. As such, subsequent water flooding or other secondary or tertiary
recovery techniques
that rely on any form of displacement can suffer from poor sweep efficiency
and would benefit
from plugging the preferential flow paths using the injection techniques
described herein.
Additionally, the principles discussed herein can be applied to creating
subsurface barriers in
any formation for a variety of purposes, including green field development for
thief zone
mitigation prior to hydrocarbon production in a reservoir, water shut off in
conventional
reservoirs, and to plug high permeability formations such as salt caverns,
which can be a cause
of lost circulation during drilling operations. The subsurface barriers can
also be used in
groundwater locations to mitigate contaminated groundwater flow towards
receptors.
[0063] When it is stated that a fluid is stored in, injected into, or
produced from an LLISR
20, it will be understood that such fluid is stored in, injected into, or
produced from the
hydrocarbon depleted pay zone (i.e., storage volume) in the LLISR 20. It can
be appreciated
that the LLISR 20 can be situated adjacent, between or otherwise positioned
relative to one or
more active in situ sites, such as wells positioned in pay regions that are at
an earlier stage ¨ for
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example active reservoir 18 shown in FIG. 1. The LLISR 20 can be positioned
adjacent to site(s)
actively injecting steam, solvent, or steam plus solvent, and/or producing a
hydrocarbon from
the site(s).
[0064] The active reservoir 18 includes a first well pair 22, 24 that in
this example depicts
the implementation of a SAGD production process. The LLISRs 20 similarly
include well pairs
22, 24 that in this example depict prior application of a SAGD production
process. However, it
will be appreciated that either or both the active reservoir 18 and LLISR(s)
20 can be currently
implementing or have implemented other hydrocarbon recovery processes such as
CSS,
expanding solvent SAGD (ES-SAGD), steam flood, in situ combustion,
electromagnetically
assisted solvent extraction (EASE), thermal solvent recovery, electrical,
electromagnetic, radio
frequency, etc.
[0065] While FIG. 1 illustrates a pair of LLISRs 20 adjacent one active
reservoir 18 this is
for illustrative purposes. For example, another active reservoir 18 or yet
another LLISR 20 can
be adjacent the rightmost LLISR 20. Either or both of the LLISRs in this
example can be or
become thief zones relative to the active reservoir 18 due to their relatively
higher permeability.
As discussed above, such thief zones can reduce the sweep efficiency of the
active reservoir
18, including attempts to target the inter-well pair regions by way of infill
or step-out wells (not
shown) or otherwise having a production chamber migrate towards unswept
regions.
[0066] It can be appreciated that while the example shown in FIG. 1
includes an active
reservoir 18 and LLISR reservoirs 20 associated with bitumen recovery using a
SAGD
production process, the principles discussed herein equally apply to other in
situ bitumen
recovery techniques such as CSS, as well as to any unused or previously
unexploited reservoir,
including heavy oil reservoirs such as those implementing or having
implemented in situ cold
flow techniques (e.g., CHOPS).
[0067] To abate or otherwise inhibit or control the impact of thief zones
created by LLISRs
20 being adjacent active reservoirs 18 as shown in FIG. 1, fine tailings such
as mature fine
tailings (MFTs) or thin fluid tailings (TFTs) can be injected into the
LLISR(s) 20 to create a
subsurface barrier 30 as shown in FIG. 2a. The barrier 30 in this example is
formed by first
injecting such fine tailings into the original well pair 22, 24 and drilling
additional lateral wells 34
at locations spaced from the original well pair 22, 24 and continuing to
inject additional fine
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tailings sequentially. In the example shown in FIG. 2a, the barrier 30 can be
created between
the active reservoir 18 and what could have been a thief zone in the central
region that was an
LLISR 20 and in the LLISR 20 located on the other side of the barrier 30. The
barriers 30 can be
created by plugging pores in the reservoir 18, 20 with particles suspended in
the injected
material (e.g., waste streams such as slurries, MFTs, TFTs, etc.)
[0068] While the examples described herein are provided making reference to
fine tailings
as mentioned above, the principles described herein can be equally applied to
other streams for
(separation and/or) disposal in LLISRs 20, such as other waste streams from
extraction,
upgrading, refinery or other wastes resulting from the upstream or downstream
production of
hydrocarbons. This could include streams such as slurried coke fines,
precipitates, dusts, and
other fine particle streams.
[0069] Referring to FIG. 2b, it can be appreciated that the fine tailings
can also be injected
into the remaining LLISR 20 to create a further barrier 30 (or a larger
barrier). Similarly,
additional wells such as an infill well 26 can be used to inject additional
fine tailings between the
barriers 30. Additional wells (not shown) can also be drilled above the infill
well 26 to create an
intermediate barrier 30. By injecting the fine tailings such as MFTs or TFTs
into the LLISRs 20
(and/or inter-reservoir regions), not only can preferential barriers 30 be
created to provide thief
zone abatement or to otherwise cordon off depleted portions of the pay 10, but
such fine tailings
can be disposed of in the storage volume of the LLISR 20.
[0070] Since the radius of invasion of the fine tailings is expected to be
limited and/or
variable, the preferential barrier 30 created by injecting such tailings can
be created by utilizing
existing wells or creating new wells as a starting point and drilling multiple
lateral or otherwise
additional wells adjacent or near the existing or newly created well(s). That
is, lateral or
additional wells can be drilled from originating wells (e.g., SAGD producer,
injector, or infill/step-
out wells) in any pattern deemed sufficient to create a desired barrier. This
can include
additional wells that are vertically or laterally offset in any direction from
the original wells as
explained in greater detail below. In this way, the barrier 30 can be created
to achieve a desired
fine tailings saturation vertically and aerially throughout the target region
of the LLISR 20. The
creation of additional or more extensive barriers 30 also provides the added
advantage of
disposing of a greater amount of the tailings, which can avoid the need to
apply additional
processing and disposal processes. It can be appreciated that a set of
originating wells,
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14
including a partial set (e.g., a first half followed by a second half) or a
complete set of all wells
used to create the barrier(s) 30 can also be drilled prior to injecting the
waste stream(s).
[0071] Referring now to FIGS. 3a-3d an example of a process for
sequentially creating a
subsurface barrier 30 is shown, beginning with one or more originating (e.g.,
new or existing
well(s)), in this example an existing SAGD well pair 22, 24. As illustrated in
FIG. 3a, fine tailings
such as MFTs can be injected into the existing well pair 22, 24 until an
injection criterion is met,
such as when reaching a point when all injectivity is lost. At this point, the
base of the barrier 30
has been created in which the fine tailings that have been injected have
filled the wells 22, 24
and invaded the surrounding formation of the LLISR 20 to a particular radius.
A bridge plug 32
can then be set in the build section at the end of the injected volume. It can
be appreciated that
as the barriers 30 are created by filling the LLISR 20, fluids that are
present in the injected
stream can migrate to neighbouring wells. Such fluids can be produced back to
surface 14,
using existing wells or additional wells if necessary, while the reservoir
effectively filters the
fluids by holding onto the fines/solids in the fluids to create the barrier
30.
[0072] A first additional lateral well 34a can then be drilled from a point
along the build
section of one or more of the wells 22, 24 as shown in FIG. 3b. For ease of
illustration, numeral
34a in FIG. 3 can represent a single additional lateral well drilled from one
of the injection well
22 and the production well 24 or a pair of additional lateral wells drilled
from same. Furthermore,
numeral 34a can also represent any other number of first additional laterals
wells that are drilled
from either or both the injection well 22 and the production well 24. For
example, a series of
first additional lateral wells 34a can be drilled such that each is vertically
offset from the well pair
22, 24 and horizontally offset from each other to widen the barrier 30. The
first additional later
well(s) 34a are then injected with fine tailings until an injection criterion
is met, in the same way
as with the original well pair 22, 24.
[0073] As with the original well pair 22, 24, a bridge plug 32 can be set
in the first lateral
well(s) 34a and a second lateral well 34b can be drilled vertically (and
possibly horizontally)
offset from the first later well 34b as shown in FIG. 3c. It can be
appreciated that the second
lateral well 34b shown in FIG. 3c can also represent any one or more
additional wells that are
drilled from the build section and are vertically offset from the first
additional later well(s) 34a.
Again, fine tailings can be injected in the second additional lateral well(s)
34b until an injection
criterion is met at which point a bridge plug 32 can be set and the process
repeated. When
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comparing FIG. 3a to FIG. 3b and then to FIG. 3c, it can be seen that the
barrier 30 continues to
expand vertically towards the top of the pay region in the LLISR 20. FIG. 3d
illustrates a third
additional lateral well 34c that expands the barrier 30 to the top of the pay
region. A bridge plug
32 can be set after injectivity is lost or any other injection criterion is
met, such as reaching a
target zone area, in this example reaching the top of the pay.
[0074] As noted above, while FIGS. 3a-3c illustrate a sequential creation
of the subsurface
barrier 30, the injection of the fine tailings (or other waste streams) can
also be done after
having drilled multiple ones of the wells 22, 24, include after a set of wells
22, 24 or after all
wells 22, 24 used to create the subsurface barrier 30 have been drilled.
Moreover, as also noted
above, the originating wells 22, 24 (e.g., as shown in FIG. 3a) can be newly
drilled or existing
wells 22, 24.
[0075] FIG. 4 illustrates an end view of a barrier 30 created by drilling
pairs of additional
laterals 34a1, 34a2, 34b1, 34b2, 34c1, 34c2 from an originating injection well
22 that is both
horizontally and vertically offset from an originating production well 24 to
illustrate that any
desired pattern of additional lateral wells 34 can be used to adapt the height
and width of the
barrier 30 to a desired target zone area. In this way, barriers 30 can be
created while disposing
of fine tailings between later life or unused and early stage reservoirs to
section off areas of the
reservoir and cordon off the late stage or unused reservoirs that would
otherwise act as thief
zones as noted above.
[0076] FIG. 5 illustrates another well pattern for creating a barrier 30.
In this example, an
existing, new or otherwise originating vertical well 40 is first injected with
fine tailings as with the
configurations described above, and multiple additional vertical wells 42a,
42b, and 42c are
successively drilled from the build section of the originating vertical well
40 to be offset from the
originating vertical well 40 or previously drilled additional vertical well 42
to achieve the desired
target area for the barrier 30.
[0077] FIG. 6 illustrates yet another well pattern for creating a barrier
30a, 30b that also
begins with an originating vertical well 40. In this example, after injecting
fine tailings into the
originating vertical well 40 to create a first barrier 30a, multiple lateral
wells 34a, 34b, 34c, 34d
are drilled from the build section of the originating vertical well 40 to
create a second barrier 30b
in the way shown in FIGS. 3a-3d described above.
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[0078] Referring now to FIG. 7, a perspective view is shown in which
multiple first barriers
30a1, 30a2, 30a3 are created from a set of originating vertical wells 40
(e.g., new or existing).
After injecting fine tailings into these originating vertical wells, multiple
lateral wells 34 are used
in this example to create multiple second barriers 30b1, 30b2, 30b3. From this
schematic view it
can be appreciated that any combination of vertical and lateral wells can be
drilled from any one
or more originating wells, which can be substantially vertically or
substantially horizontally
oriented relative to surface 14 to create subsurface barriers 30. It can be
appreciated that the
number and type of wells used to create the subsurface barriers 30 can vary
depending on the
nature of the originating wells, the radius of invasion expected from the type
of fine tailings
being injected, the amount of fine tailings to be disposed of, among other
factors specific to the
application and environment.
[0079] The barriers 30 shown in FIGS. 2-7 can be created only along
selected portions of
the well 34, 40 by selectively plugging sections of the well 34, 40 as shown
in FIGS. 11a and
11 b. FIGS. ha and lib illustrate cross-sectional schematic diagrams of fluid
migration barriers
304 and 300 respectively. Referring first to FIG. 11a, when creating the fluid
migration barrier
304 at the heel 306 of the wells 30, 40 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. ha -
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.
[0080] In the configuration shown in FIG. 11b, a packer 310 can be placed
near the toe
302 of the wells 34, 40 and connected to injecting tubing 312 to enable the
plugging slurry to be
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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.
[0081] Referring now to FIG. 8, example operations that can be performed in
creating a
subsurface barrier 30 using a sequential drilling process, are shown. At 50, a
new, existing or
otherwise originating well is created or identified for fine tailings
injection. This can include a
single well (e.g., infill well, CSS well, etc.) or a SAGD well pair 22, 24 as
illustrated herein.
Tailings such as MFTs or TFTs are injected into the originating well at 52.
Upon completion of
the tailings injection, e.g., when injectivity is lost, the well into which
tailings are being injected is
plugged or otherwise abandoned at 54, e.g., using a bridge plug 32. The first
or next lateral well
34, 42 is then drilled from the previous or originating well and tailings are
injected at 56. This is
done until the particular target is met at 58, which can include reaching the
top of the pay
region, an impermeable (or largely impermeable) barrier, or achieving the
target area of the
barrier 30. The target can also include a metric such as an amount of fine
tailings that is to be
disposed of. The process continues until the target is met at 58 and ends at
60. It can be
appreciated that the process shown in FIG. 8 can be reconfigured to have sets
of wells or all
wells used to create the preferential barrier 30 to be drilled or identified
prior to injecting the fine
tailings such that block 56 would include targeting the next lateral well
rather than requiring a
sequential drilling operation.
[0082] The fine tailings injection process used herein to dispose of fine
tailings and/or
create a preferential subsurface barrier 30 or barriers 30 can also be applied
to other reservoirs
such as heavy oil reservoirs that create wormhole networks 70 as a result of
an in situ cold flow
technique such as CHOPS. One example implementation is shown in FIGS. 9a and
9b in which
perforated intervals in a well are isolated to enable waste streams such as
fine tailings to be
injected into intervals as they are isolated, to plug wormholes that connect
to the isolated
interval of the well.
[0083] As discussed above, the creation of such wormhole networks 70 can be
problematic. For example, since the recovery factors in CHOPS are typically
quite low, CHOPS
used as a primary extraction process can create difficulties in implementing a
subsequent
secondary or tertiary extraction process. That is, CHOPS wells are
characterized by quick
pressure depletion and decline in production rates. Despite demonstrating
sustained low
production rates for extended periods of time, CHOPS wells rarely recover more
than 10-15%
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18
of the oil originally in place. Maximizing recovery factors from CHOPS fields
requires
implementing secondary and tertiary recovery techniques. However, wormhole
networks 70 can
serve as short circuits between injection and production wells, resulting in
fast breakthrough of
injected water, polymer or steam and reducing the sweep efficiency and thermal
efficiency.
Wormhole networks 70 result in fast dissipation of pressure and leak off of
injected fluids,
rendering application of cyclic solvent and cyclic steam methods ineffective.
Essentially,
wormholes 72 represent a secondary porosity and permeability in the formation,
not unlike a
fracture network. However, the morphology of wormhole networks 70 is a lot
less predictable
than fracture networks. The injection of fine tailings as described above can
therefore be used
to plug portions of wormhole networks 70 created during a primary extraction
process such as
CHOPS to facilitate the implementation of a secondary or tertiary extraction
process.
[0084] Wormhole networks 70 created in a heavy oil reservoir can create
problems with
applying a secondary or tertiary recovery process by making it more difficult
to maintain
pressure in the reservoir due to leakage into the reservoir via the wormholes
72 of the wormhole
network 70. Disposal of the fine tailings as discussed herein can be applied
to such wormhole
networks 70 to plug the wormholes 72. This can be done without the need to
correctly model or
determine the pattern or sizes of the wormholes, which are known to be
difficult or impossible to
model with any accuracy. That is, while the progression of wormholes is
difficult to track, the
origin is not, meaning that the processes described herein can be implemented
in wormhole
networks 70 by injecting fine tailings where they are presumed to originate or
by drilling a well
that is adjacent to where the wormholes 72 are presumed to exist. That is, the
fine tailings can
be injected into producer wells in a heavy oil reservoir since wormholes 72
originate at the
perforation of a producer well while that well produces heavy oil with sand
from the
unconsolidated formation. When a new injection well is drilled for a new
recovery scheme, such
injection wells can intersect one or more wormholes 72. In such a scenario, it
is advantageous
to be able to plug the wormholes 72 (e.g., by injecting fine tailings) before
the drilling is
completed.
[0085] Moreover, by plugging the wormholes 72 with fine tailings and
creating a first barrier
30a as shown in FIG. 9a, losses to that area as a thief zone can be avoided to
improve the
recovery rate. As illustrated in FIG. 9a, a CHOPS well 62 can include multiple
perforated
intervals 64 (64a and 64b shown for illustrative purposes). Each of these
intervals 64a, 64b can
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19
be isolated (e.g., temporarily with packers or permanently with cement plugs)
such that the fine
tailings injected through the perforated interval 64a can plug wormholes 72 of
the wormhole
network 70 that connect to that internal 64a. By having multiple perforated
intervals 64a, 64b,
multiple barriers 30a, 30b can be created in the wormhole network 70 by
targeting different
regions of the network 70 that connect to or are otherwise adjacent or near
the perforated
intervals 64a, 64b, as shown in FIG. 9b.
[0086] An aspect of the disposal of fine tailings as described herein is
that, depending on
proportion of clays and water in the stream being used, one can keep the
tailings moving once
they are moving (recognizing the non-Newtonian behaviour of clays). Once below
a critical
velocity (which is a function of concentration, etc.), the tailings become
harder to move. This is
an advantage because you can pump in the tailings and, as the radius
increases, velocity slows
such that the clays will slow the process and start to set. For any of the
above processes
described (e.g., for injecting into LLISRs 20 or wormhole networks 70), one
can filter out certain
sizes by centrifugation or cyclones. The process can then filter low enough so
that injection can
occur without, for example, plugging wormholes 72 immediately (i.e., around
the wellbore).
Smaller particles can travel through the bores, whereas the larger sizes can
plug the bore. As
such, the injection process used herein should use small enough particles.
Also, the smaller
tailings particles can be considered the most challenging to settle out and
separate from water
in disposal or reclamation processes requiring more time and/or more chemicals
to settle, and
thus disposing of them is an added benefit.
[0087] It can be appreciated that the processes described herein can also
include selecting
waste streams such as fine tailings with particular types of clays, such as
swelling clays that
react with steam conditions (e.g., kaolin). These swelling clays can be
injected and, when
interacting with steam, can help formulate permeability barriers 30. Such
swelling clays may
have been mined from different areas and have different properties (e.g., clay
type and
concentrations). Certain clays can also be manipulated to swell downhole,
e.g., in the LLISR 20
or wormhole network 70. The swelling can be triggered downhole by changing the
chemistry of
the clay. For example, kaolinite plus aqueous quartz plus aqueous Ca and/or Mg
and/or Fe from
the injected water forms smectite at high temperature and subsequently swells
in the presence
of fresh water. Similarly, waste streams such as MFTs can be selected which
includes fluids
that react with formation water or formation rock to form clays and/or scales
that reduce
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20
permeability in the formation. The processes described herein can also include
selecting any
disposal water (e.g., a waste water stream) that reacts with the formation
water or the formation
rock to form clays and/or scales that reduce permeability.
[0088] Referring now to FIG. 10, fine particle separation process 80 is
shown that can be
applied to a source or input fraction 82 corresponding to or comprising a
tailings stream for the
processes described herein. The process 80 can be applied to separate the
source fractions 82
at a fine particle size, e.g., of nominally minus 10 microns (or less) of
problematic tailings
streams such as MFTs or TFTs, to produce a fine tailings stream or fines
fraction 86 at, e.g.,
nominally minus 10 micron for injection and a, e.g., plus 10 micron coarse
fraction 88 for
terrestrial deposition in a terrestrial deposition process 92. It is
advantageous to adequately
separate at these fine sizes of these particular source fractions 82. Since
the separated fines
fraction 86 would be non-settling, they could be pipelined from a base site to
the locations of the
wells used in the LLISRs 20 or other unused or previously unexploited
reservoirs discussed
herein.
[0089] It is also advantageous to be able to dispose of the separated fines
fraction 86
through injection into such reservoirs using injection equipment 90 at that
site. It is expected
that after some effective period of injection, these fine fractions 86 would
act to effectively seal
the reservoir in proximity to the wellbores, thereby ultimately reaching end
of life with a
reduction in adverse outcomes for closure associated with these wells 22, 24
and/or in this
example, LLISRs 20. It is also expected that the separated coarse fraction 88
would have
unique properties for forming rapid deposits beneficial for more amenable
closure and
reclamation options.
[0090] To perform the separation of fine tailings at these fine particle
sizes (e.g., nominally
microns or less) it is recognized that separation at these fine sizes has been
carried out
commercially with other finely sized materials such as clays and calcium
carbonate for the
purposes of producing products with unique properties. Such approaches can be
used in the
process shown in FIG. 10 for separating the fine fractions 86 of select fine
tailings streams
(source fraction 82) using, for example, fine diameter cyclones or centrifuges
as the fine particle
separator 84, to achieve a separation at these fine particle sizes. If the
viscosity of these
streams poses a challenge to performing the separation, dilution water can be
added to effect
these separations.
CPST Doc: 383052.1
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[0091] Advantages of applying the process 80 shown in FIG. 10 can include
that an
alternate disposal method for the finest fractions of fine tailings streams 82
can be achieved,
considering that such fine fractions 86 are considered to be problematic for
settling in either
aquatic or terrestrial deposits. Moreover, the co-disposal of stored tailings
waters contained in
these fine fractions 86, which can contain contaminants of potential concern
for either release to
the environment (and may alternatively require ongoing treatment during and
after closure), can
also be advantageous. The separation of a coarser fraction 88 from the fine
tailings stream or
source fraction 82, which is likely to be comparatively fast settling and more
readily amenable
for terrestrial deposits, can be ready for closure in less time than
alternative methods. As noted
above, the LLISRs 20 and the wells 22, 24 in those reservoirs can be leveraged
and reused for
disposal of a problematic waste stream. Also, the clay components of the
injected waste
streams could eventually bring these wellbores to a sealed end of life state
in which there would
be little or no residual concerns.
[0092] It can be appreciated that the processes of creating subsurface
barriers 30 provides
an attractive alternative to other approaches of disposing of fine tailings
such as MFTs, by
disposing of problematic fractions of fine tailings in a manner that does not
require treatment
and settling deposits. Also, co-disposing of tailings contaminated waters
decreases the
inventory of waters to be dealt with during closure and/or during reclamation.
Moreover, utilizing
and effectively ending the life of available LLISR wells 22, 24, which would
otherwise also
represent a concern or liability for closure.
[0093] 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.
[0094] It will be appreciated that 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
CPST Doc: 383052.1
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22
added, deleted, modified, or arranged with differing connections without
departing from these
principles.
[0095] 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.
[0096] 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.
CPST Doc: 383052.1
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