Note: Descriptions are shown in the official language in which they were submitted.
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DEWATERING LEAN ZONES WITH NCG INJECTION USING PRODUCTION AND
INJECTION WELLS
FIELD
[0001] The technical field generally relates to in situ hydrocarbon recovery,
and more
particularly, to dewatering of lean bitumen zones.
BACKGROUND
[0002] In heavy hydrocarbon-bearing reservoirs, top zones that are hydrocarbon
lean
and water rich are considered challenging for recovery using techniques such
as Steam-
Assisted Gravity Drainage (SAGD). In conventional oil recovery, water tends to
be less
dense than the conventional oil such that the oil tends to be located above
water rich
zones. SAGD is an enhanced hydrocarbon recovery technology for producing heavy
hydrocarbons, such as heavy oil and/or bitumen, from heavy hydrocarbon-bearing
reservoirs. Typically, a pair of horizontal wells is drilled into a reservoir,
such as an oil
sands reservoir, and steam is injected into the reservoir via the upper
injection well to
heat and reduce the viscosity of the heavy hydrocarbons. The mobilized
hydrocarbons
drain into the lower production well and are recovered to the surface. Over
time, a steam
chamber forms above the injection well and extends upward and outward within
the
reservoir as the mobilized hydrocarbons flow toward the production well.
[0003] Conventional SAGD operated in reservoirs with top water-saturated,
hydrocarbon-lean zones (e.g., lean bitumen zones) can lead to an elevated
Steam-to-Oil
Ratio (SOR) and low hydrocarbon recovery rates. Once the steam chamber
intercepts
the lean bitumen zone, heat and steam can be lost to the overlying water-rich
zone
resulting in a poor performance due to the fact that significant steam energy
can be
wasted in heating the lean bitumen zone. The high heat capacity of water and
tendency
of the steam to flow into the lean bitumen zone pose challenges to heavy
hydrocarbon
recovery from reservoirs with a water-saturated, hydrocarbon-lean zone.
[0004] Some conventional solutions have been proposed in an attempt to enhance
the
hydrocarbon recovery rate in such lean zones. A first method includes
decreasing the
well spacing to promote higher production of bitumen before the steam chamber
intercepts the top lean bitumen zone. However, this method increases the
capital cost of
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the operation because of the greater number of wells to be drilled for a given
reservoir
volume. A second method includes co-injecting non-condensable gas (NCG) with
steam
during SAGD recovery, with the intention of reducing fluid losses and
improving the
thermal efficiency of the recovery process. The size of the lean bitumen zone
can be a
relevant factor in the selection of the proper water-depletion method. When
the size of
the lean bitumen zone is small and limited, the above-mentioned methods can be
utilized successfully. However, when the size of lean bitumen zone is larger,
such
methods have noteworthy drawbacks in developing such reservoirs.
[0005] There are various challenges related to hydrocarbon recovery from
reservoirs
that are proximate to water-saturated, hydrocarbon lean zones.
SUMMARY
[0006] In some implementations, there is provided a process for Steam-Assisted
Gravity
Drainage (SAGD) recovery of bitumen, comprising;
identifying a subterranean water-saturated hydrocarbon-lean zone having a
lower
hydrocarbon content than an underlying bitumen-rich reservoir, having high
water
saturation, having a thickness of more than 5 meters, being located above and
in
fluid communication with the bitumen-rich reservoir, and being part of a
geologically-contained water-saturated formation;
dewatering the hydrocarbon-lean zone, comprising:
producing water from the hydrocarbon-lean zone via water production
wells located at a low elevation in the hydrocarbon-lean zone and
operating under a gravity-dominated mechanism, thereby reducing the
water saturation and pressure in the hydrocarbon-lean zone;
injecting non-condensable gas (NCG) via an injection well located at a
higher elevation compared to the water production wells and regulated
such that the NCG is injected at a pressure and a rate sufficient to re-
pressurize the hydrocarbon-lean zone while avoiding substantial
channeling of the NCG toward the water production wells;
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after reaching a target water-saturation reduction in the hydrocarbon-lean
zone and thereby forming a gas-enriched lean zone, converting the water
production wells to corresponding NCG injection wells and injecting NCG
there-through to inhibit water migration into the gas-enriched lean zone;
operating SAGD wells in the bitumen-rich reservoir below the gas-enriched lean
zone, thereby forming a SAGD steam chamber; and
maintaining the gas-enriched lean zone at a lean zone pressure between 0 kPa
and 400 KPa below an underlying SAGD steam chamber pressure, thereby
providing overlying NCG insulation and pressurization for the SAGD steam
chamber.
[0007] In some implementations, there is provided a process for dewatering a
subterranean water-saturated, hydrocarbon-lean zone located above and having a
lower
hydrocarbon content than a hydrocarbon-bearing reservoir, comprising:
producing water via a production well provided in the hydrocarbon-lean zone;
injecting a gas via a primary injection well provided in the hydrocarbon-lean
zone
to form a gas-enriched region; and
once injected gas reaches or has advanced proximate to the production well,
converting the production well into a secondary injection well for injecting
additional gas into the hydrocarbon-lean zone to inhibit water migration from
outside of the gas-enriched lean zone.
[0008] In some implementations, the primary injection well is substantially
vertical.
[0009] In some implementations, the production well is substantially vertical.
[0010] In some implementations, the process further comprises: monitoring
advancement of the gas within the lean zone so as to identify when the
injected gas
reaches or has advanced proximate to the production well.
[0011] In some implementations, the monitoring comprises: measuring dissolved
gas
content in the water produced by the production well. In some implementations,
the
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monitoring comprises: obtaining information from an observation well located
in the lean
zone.
[0012] In some implementations, the gas is injected via the primary injection
well at a
pressure and a rate sufficient to re-pressurize the lean zone while avoiding
substantial
channeling of the gas past the water toward the production well.
[0013] In some implementations, the step of converting the production well is
performed
once the lean zone has reached a target water-saturation reduction.
[0014] In some implementations, the target water-saturation reduction is at
least about
25% volume.
[0015] In some implementations, the target water-saturation reduction is at
least about
50% volume.
[0016] In some implementations, the process further includes producing water
via a
plurality of production wells arranged in spaced relation from each other and
around the
primary injection well; and once injected gas reaches or has advanced
proximate to the
production wells, respectively converting the production wells into
corresponding
secondary injection wells for injecting additional gas into the reservoir to
inhibit water
migration from outside of the gas-enriched lean zone.
[0017] In some implementations, the production wells are substantially
vertical.
[0018] In some implementations, the gas comprises a non-condensable gas (NCG).
In
some implementations, the gas consists of a NCG.
[0019] In some implementations, the water-saturated, hydrocarbon-lean zone
overlies a
main pay zone of a hydrocarbon-bearing reservoir, and the process further
comprises:
forming the gas-enriched lean zone prior to operating in situ recovery wells
within the
main pay zone.
[0020] In some implementations, the in situ recovery wells comprise a Steam-
Assisted
Gravity Drainage (SAGD) well pair.
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[0021] In some implementations, the process further includes: maintaining the
gas-
enriched lean zone at a lean zone pressure between 0 kPa and 400 KPa below an
underlying in situ recovery pressure in the main pay zone.
[0022] In some implementations, the primary injection well comprises an
injection
section located at a high elevation in the lean zone, the high elevation being
above a
mid-way point of the lean zone, above a three-quarters point of the lean zone,
above a
seven-eighths point of the lean zone, or adjacent to an upper limit of the
lean zone.
[0023] In some implementations, the production well comprises a production
section
located at a low elevation in the lean zone, the low elevation being below a
mid-way
point of the lean zone, below a one-quarter point of the lean zone, below a
one-eighth
point of the lean zone, or adjacent to the hydrocarbon-bearing reservoir.
[0024] In some implementations, the gas injection rate via the primary
injection well and
the water production rate via the production well are provided at least in
part based on
the relative permeability of the gas and water in the porous media of the lean
zone.
[0025] In some implementations, the process further includes: determining
permeability
characteristics of the lean zone; and providing the gas injection rate and the
water
production rate at least in part based on the permeability characteristics.
[0026] In some implementations, the step of determining permeability
characteristics of
the lean zone comprises analyzing core samples of the lean zone and/or
performing
simulation modelling.
[0027] In some implementations, the gas injection pressure via the primary
injection well
is sufficiently low to inhibit premature gas breakthrough at the production
well and
promote gravity drainage of water toward the production wells.
[0028] In some implementations, the lean zone has a thickness of at least 5
meters. In
some implementations, the lean zone has a thickness of at least 10 meters.
[0029] In some implementations, the lean zone is part of a geologically-
contained water-
saturated formation.
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[0030] In some implementations, the production well has a pump located in a
sump
below the lean zone.
[0031] In some implementations, the hydrocarbon-bearing reservoir comprises
heavy oil
and/or bitumen.
[0032] In some implementations, there is provided a process for recovering
hydrocarbons from a hydrocarbon-bearing reservoir located below and in fluid
communication with a subterranean water-saturated hydrocarbon-lean zone,
comprising:
producing water via a production well provided in the hydrocarbon-lean zone;
injecting a gas via a primary injection well provided in the hydrocarbon-lean
zone
to form a gas-enriched region;
monitoring the advancement of the gas within the lean zone;
once injected gas reaches or has advanced proximate to the production well,
converting the production well into a secondary injection well for injecting
additional gas into the reservoir to inhibit water migration from outside of
the gas-
enriched lean zone; and
operating an in situ recovery operation in the hydrocarbon-bearing reservoir
such
that the gas-enriched lean zone provides overlying insulation and
pressurization.
[0033] In some implementations, the in situ recovery operation comprises a
thermal in
situ recovery operation. In some implementations, the thermal in situ recovery
operation
comprises a Steam-Assisted Gravity Drainage (SAGD) operation. In some
implementations, the above process includes one or more features as defined in
other
paragraphs and/or the description or drawings.
[0034] In some implementations, there is provided a process for Steam-Assisted
Gravity
Drainage (SAGD) recovery of bitumen, comprising:
dewatering a first hydrocarbon-lean zone that is located above a first bitumen-
rich pay zone and adjacent to and fluidly communicating with a second
hydrocarbon-lean zone, the dewatering comprising:
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producing water from the first lean zone; and
injecting gas into the first lean zone, to provide a first gas-enriched lean
zone;
operating a first array of SAGD well pairs in the first pay zone, to produce
bitumen and form steam chambers having overlying insulation and pressurization
provided by the first gas-enriched zone;
dewatering the second lean zone located above a second bitumen-rich pay zone,
the dewatering comprising:
producing water from the second lean zone; and
injecting gas into the second lean zone, to provide a second gas-enriched
lean zone;
operating a second array of SAGD well pairs in the second pay zone, to produce
bitumen and form steam chambers having overlying insulation and pressurization
from the second gas-enriched zone.
[0035] In some implementations, the process also includes converting water
production
wells located in the first lean zone into gas injection wells to inhibit water
migration from
outside the first lean zone.
[0036] In some implementations, the process also includes converting water
production
wells located in the second lean zone into gas injection wells to inhibit
water migration
from outside the second lean zone.
[0037] In some implementations, the dewatering of the first lean zone is
performed until
a first target water-saturation reduction and first target lean zone pressure
are achieved,
prior to operating the first array of SAGD well pairs in the first pay zone;
and the
dewatering of the second lean zone is performed until a second target water-
saturation
reduction and second target lean zone pressure are achieved, prior to
operating the
second array of SAGD well pairs in the first pay zone.
[0038] In some implementations, the first and second target water-saturation
reductions
are at least about 25% volume.
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[0039] In some implementations, the first and second target lean zone
pressures are
between 0 kPa and 400 KPa below an underlying SAGD steam chamber pressure.
[0040] In some implementations, the above process includes one or more
features as
defined in other paragraphs and/or the description or drawings herein.
[0041] In some implementations, there is provided a process for in situ
recovery of
bitumen, comprising:
dewatering a first hydrocarbon-lean zone that is located above a first bitumen-
rich pay zone and adjacent to and fluidly communicating with a second
hydrocarbon-lean zone, the dewatering comprising:
producing water from the first lean zone; and
injecting gas into the first lean zone, to provide a first gas-enriched lean
zone;
operating a first array of well pairs in the first pay zone, to produce
bitumen and
form mobilization chambers having overlying insulation and pressurization
provided by the first gas-enriched zone;
dewatering the second lean zone located above a second bitumen-rich pay zone,
the dewatering comprising:
producing water from the second lean zone; and
injecting gas into the second lean zone, to provide a second gas-enriched
lean zone;
operating a second array of well pairs in the second pay zone, to produce
bitumen and form mobilization chambers having overlying insulation and
pressurization from the second gas-enriched zone.
[0042] In some implementations, the in situ recovery comprises a thermal in
situ
recovery operation. In some implementations, the thermal in situ recovery
operation
comprises Steam-Assisted Gravity Drainage (SAGD).
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[0043] In some implementations, the first array of well pairs comprises SAGD
well pairs,
and the corresponding mobilization chambers comprise steam chambers. In some
implementations, the second array of well pairs comprises SAGD well pairs, and
the
corresponding mobilization chambers comprise steam chambers.
[0044] In some implementations, the process also includes converting water
production
wells located in the first lean zone into gas injection wells to inhibit water
migration from
outside the first lean zone.
[0045] In some implementations, the process also includes converting water
production
wells located in the second lean zone into gas injection wells to inhibit
water migration
from outside the second lean zone.
[0046] In some implementations, the dewatering of the first lean zone is
performed until
a first target water-saturation reduction and first target lean zone pressure
are achieved,
prior to operating the first array of well pairs in the first pay zone; and
the dewatering of
the second lean zone is performed until a second target water-saturation
reduction and
second target lean zone pressure are achieved, prior to operating the second
array of
well pairs in the first pay zone.
[0047] In some implementations, the first and second target water-saturation
reductions
are at least about 25% volume.
[0048] In some implementations, the first and second target lean zone
pressures are
between 0 kPa and 400 KPa below an underlying mobilization chamber pressure.
[0049] In some implementations, there is provided a system for dewatering a
subterranean water-saturated, hydrocarbon-lean zone located above and having a
lower
hydrocarbon content than a hydrocarbon-bearing reservoir, cornprising:
a production well provided in the hydrocarbon-lean zone and configured to
produce water;
a primary injection well provided in the hydrocarbon-lean zone and configured
to
inject a gas via to form a gas-enriched region; and
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a conversion assembly coupled to the production well and configured to convert
the production well into a secondary injection well once injected gas reaches
or
has advanced proximate to the production well, such that the secondary
injection
well is configured for injecting additional gas into the hydrocarbon-lean zone
to
inhibit water migration from outside of the gas-enriched lean zone.
[0050] In some implementations, there is provided a system for in situ
recovery of
bitumen, comprising:
a first production well provided in a first hydrocarbon-lean zone that is
located
above a first bitumen-rich pay zone and adjacent to and fluidly communicating
with a second hydrocarbon-lean zone, the first production well being
configured
to produce water from the first hydrocarbon-lean zone;
a first injection well provided in the first hydrocarbon-lean zone and being
configured to inject gas into the first lean zone, to provide a first gas-
enriched
lean zone, the first production and injection wells being configured and
operable
to dewater the first hydrocarbon-lean zone;
a first array of well pairs provided in the first pay zone and configured to
produce
bitumen and form mobilization chambers having overlying insulation and
pressurization provided by the first gas-enriched zone;
a second production well provided in the second hydrocarbon-lean zone that is
located above a second bitumen-rich pay zone, the second production well being
configured to produce water from the second hydrocarbon-lean zone;
a second injection well provided in the second hydrocarbon-lean zone and being
configured to inject gas into the second lean zone, to provide a second gas-
enriched lean zone, the second production and injection wells being configured
and operable to dewater the second hydrocarbon-lean zone; and
a second array of well pairs provided in the second pay zone and configured to
produce bitumen and form mobilization chambers having overlying insulation and
pressurization from the second gas-enriched zone.
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[0051] In some implementations, the systems further comprise one or more
components
and/or features as defined in paragraphs above or in the description or
drawings herein.
BRIEF DESCRIPTION OF DRAWINGS
[0052] Fig 1 is a vertical cross-sectional view schematic of a lean zone
located above a
main pay zone, with a gas injection well and water production wells located in
the lean
zone.
[0053] Fig 2 is a top plan view schematic of water production wells
distributed around a
gas injection well.
[0054] Fig 3 is a perspective view schematic of a lean zone with a gas
injection well and
water production wells located in the lean zone, and an observation passing
through the
lean zone.
[0055] Fig 4 is a vertical cross-sectional view schematic of a lean zone with
a gas
injection well and water production wells located in the lean zone during a
first
dewatering phase.
[0056] Figs 5A to 5D are vertical cross-sectional view schematics illustrating
gas
injection and water production in a lean zone during a first phase, and
conversion of
production wells into injection wells during a second phase of the dewatering
process.
[0057] Figs 6A and 6B are top plan view schematics illustrating dewatering
well
arrangements, where a first stage includes a first arrangement of wells and a
second
stage includes a second arrangement of wells provided adjacent to the first
arrangement
of wells.
[0058] Figs 7A to 7G are vertical cross-sectional view schematics illustrating
dewatering
of lean zones above SAGD operations.
[0059] Fig 8 is a perspective view schematic of a dewatering operation
performed with
substantially horizontal wells provided in a lean zone.
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[0060] Fig 9 is a vertical cross-sectional view schematic of a plurality of
adjacent lean
zones with corresponding dewatering well arrangements in each lean zone.
[0061] Fig 10 is a vertical cross-sectional view schematic of a SAGD operation
with a
steam chamber at PGAGD and an overlying dewatered gas-enriched zone at PG.
[0062] Fig 11 is a vertical cross-sectional view schematic of a reservoir
including a
plurality of lean zones within a high water-saturation formation that is
geologically
contained and located above a bitumen-rich reservoir.
[0063] Fig 12 is a flowchart for a dewatering and hydrocarbon recovery
process.
[0064] Fig 13 is a vertical cross-sectional view schematic including a lean
zone with a
gas injection well and water production wells.
[0065] Fig 14 is a graph of average lean zone pressure versus time.
[0066] Fig 15 is a graph of gas injection rates versus time.
[0067] Fig 16 is a graph of water recovery factor versus time.
DETAILED DESCRIPTION
[0068] The proposed techniques generally relate to dewatering of a water-
saturated,
hydrocarbon-lean zone and hydrocarbon recovery from a reservoir located below
such a
lean zone. Water is produced from the lean zone and gas, such as non-
condensable gas
(NCG), is injected into the lean zone in order to modify the saturation of the
lean zone
and form a gas-enriched zone overlying a main pay zone in which an in situ
recovery
operation. In some implementations, the in situ recovery operation is a
thermal
operation, e.g., Steam-Assisted Gravity Drainage (SAGD). Gas injection into
the lean
zone can also increase the pressure of the lean zone to a level close to SAGD
operating
pressures, particularly once the SAGD steam chambers reach the lean zone. The
overlying gas-enriched zone provides insulation and pressurization above the
thermal in
situ recovery operation to reduce heat and fluid losses. In some
implementations, water
is produced from the lean zone via production wells provided around a primary
gas
injection well located in the lean zone. The water production and gas
injection can be
controlled to promote gravity-drainage of the water and re-pressurization of
the zone by
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the gas, while avoiding substantial channeling of the gas past the water
toward the
production wells. As the injected gas reaches or approaches one or more of the
production wells, the respective production wells can be shut in or have their
production
rate decreased dramatically, so as to promote gravity drainage rather than
displacement
and gas coning. The water production wells operate in production mode during a
first
phase of the dewatering process. In a second phase of the process, the
production wells
can be converted to become secondary gas injection wells to aid in maintaining
the gas-
enriched zone and inhibiting water and gas migration into the lean zone during
the
thermal in situ recovery operation.
[0069] The dewatering and pressurization of the lean zone leads to a more
energy-
efficient hydrocarbon recovery process. Dewatering and injecting NCG into the
lean
zone can facilitate increasing the fluid pressure in the lean zone and thus
reducing the
differential pressure between the lean zone and the main pay zone.
Consequently, heat
and steam loss to the lean zone is reduced, which in turn can improve the
Steam-to-Oil
Ratio (SOR), for example.
[0070] In some implementations, the dewatering and hydrocarbon production
techniques can be performed in reservoirs that include a main hydrocarbon-
containing
zone (i.e., a main pay zone) and a lean zone that has high water saturation,
which would
tend to reduce performance of hydrocarbon production from the main pay zone,
due to
the high heat capacity of water and/or lower pressure of the lean zone
compared to the
pressures of the recovery operation (e.g., SAGD). Various techniques that are
described
herein enable enhanced thermal in situ recovery operations by dewatering and
re-
pressurizing the lean zone with gas.
[0071] Some of the drawings and implementations refer to a SAGD operation.
However, it should be understood that other configurations can be used that
may or may
not involve the use of steam. For example, an injection well may be used to
inject a
solvent or other chemical that can be used to modify the viscosity of the
hydrocarbons in
the formation, so that hydrocarbons can be produced by gravity flow to the
production
well, and steam may not be used in such a configuration. In other
configurations, a
source of thermal energy other than steam, e.g., electric heat, radio
frequency energy,
etc., can be used to heat the formation and again modify the viscosity of the
hydrocarbon to facilitate production by gravity drainage. The in situ recovery
techniques
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may include steam as a primary mobilizing fluid injected into the formation;
other
mobilizing fluids, such as hydrocarbon-based solvent, that may be at ambient
or higher
temperatures, and are injected into the formation alone, co-injected with
steam or
injected in an alternating manner with steam to help mobilize the
hydrocarbons; or other
heating methods can be used, alone or in combination with mobilizing fluid
injection, to
help mobilize the hydrocarbons for gravity drainage. The implementations
described
below in the context of SAGO are not intended to be limited to SAGD
applications.
Lean zones for dewatering and pressurization
[0072] Referring to Fig 1, the dewatering and gas injection are performed on a
water-
saturated, hydrocarbon-lean zone 10 (also referred to herein as a "lean
bitumen zone" or
"lean zone" in some implementations). The lean zone 10 can be part of an
overall
formation 12 that includes various fluids, solid media and lithological
properties. The lean
zone 10 is located above a hydrocarbon-rich reservoir 14 (also referred to
herein as a
"main pay zone") in which thermal in situ hydrocarbon recovery wells can be
located. In
some alternative implementations, the lean zone may be located beside or below
the
main pay zone, and the dewatering techniques may be adapted accordingly to
account
for the different characteristics, such as an underlying lean zone having
higher
pressures.
[0073] It should be understood that lean zones 10 are regions of a formation
that have
higher water-saturation and/or lower pressure compared to a proximate (e.g.,
adjacent
or overlying) main pay zone, such that performance of an in situ hydrocarbon
recovery
process operating in the main pay zone can be reduced due to heat and/or fluid
loss to
the lean zone. For example, when steam-assisted in situ hydrocarbon recovery
operations are employed in the main pay zone, the steam chamber pressure can
be
higher than the pressure of the lean zone leading to steam loss to the lean
zone leading
to higher heat transfer from the steam to the water in the lean zone. It
should
nevertheless be noted that some in situ hydrocarbon recovery operations can
use other
fluids, such as hydrocarbon solvents, in which case the fluid loss may be of
more
concern than heat loss in terms of efficient operation.
[0074] Referring to Fig 9, lean zones 10 may vary in thickness and elevation
depending
on various factors. In some implementations, lean zones more than 5 meters or
more
15
that 10 meters in thickness (h) are candidates for dewatering and pressurizing
according
to techniques described herein. It should also be noted that candidate lean
zones for
dewatering can also be identified using a number of techniques and can be
based on
various characteristics of the lean zone and the pay zone, and economic
analyses. A lean
zone may be one or a few square kilometers, for example, and may have bitumen
saturation below 50%, high water saturation, low pressure, and may be
relatively thick.
Lean zone characteristics such as size, bitumen saturation, water saturation
and pressure
can be identified in order to determine whether the dewatering process would
be
economical.
[0075] Referring to Fig 11, in some implementations, the lean zone 10 or
multiple lean
zones are part of a geologically-contained water-saturated formation 122,
where
geological barriers 11 substantially contain the water, rather than being in
substantial fluid
communication with an aquifer for example. Implementing the process in
geologically-
contained water-saturated formations can facilitate both the dewatering and
maintenance
of a gas-enriched zone, as water migration into the dewatered lean zone is
reduced.
Character 124 in Fig 11 indicates a bitumen-rich reservoir.
[0076] Referring back to Fig 1, it should be understood that the main pay
zones 14 are
regions that include hydrocarbons, such as heavy oil or bitumen, that are
economically
recoverable using an in situ recovery technique in which a mobilizing fluid is
injected into
the main pay zone. SAGD is one such technique. Other techniques include Cyclic
Steam
Stimulation (CSS), in situ combustion, steam flooding, and solvent-assisted
methods.
Production wells and injection well within lean zone
[0077] Referring to Fig 1, in some implementations, production wells 16 are
provided in
the lean zone 10 and are configured for producing water 18. At least one
injection well 20
is also provided in the lean zone 10 and is configured for injecting gas 22,
such as NCG,
into the lean zone 10. The production wells 16 can be vertical having a lower
extremity
located at a lower elevation of the lean zone 10, and the injection well 20
can be vertical
having a lower end at or near the top of the lean zone 10. This well
configuration can aid
in water production under gravity-dominated mechanism while avoiding gas
channeling to
the production wells 16.
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[0078] Referring still to Fig 1, there is fluid and pressure communication
between lean
zone 10 and the main pay zone 14 rich in bitumen. In some implementations, the
production wells 16 have a lower end that is located at the bottom of the lean
zone, for
instance within the lean zone proximate to a boundary region 24 that separates
the lean
zone 10 and the main pay zone 14. Alternatively, as shown in Fig 13, the
production
wells 16 can pass through the lean zone 10 and into the upper part of the main
pay zone
14. To enhance water production, the production wells 16 can have a lower
portion
penetrating the main pay zone 14. This lower portion can include a perforated
liner or
screen to inhibit sand and heavy hydrocarbon production. In some
implementations, the
portion of the production well 16 that fluidly communicates with the lean zone
10 and thus
allows flow of water into the production well 16 can be located at a lower
elevation within
the lean zone to promote the gravity drainage mechanism. Referring to Fig 13,
in some
implementations, the production wells can be provided within sumps or drainage
pits 26.
The sumps 26 may be formed as the end of the wellbore drilled into the upper
part of the
main pay zone. Referring to Fig 8, in some implementations, one or more of the
production
wells 16 can be horizontal, slanted and/or directionally drilled to follow the
contour of the
boundary region 24 of the lean zone 10 or to follow another desired
trajectory. In Fig 13,
character 126 indicates a unit that can receive information from producers (T,
P, etc.).
[0079] In some scenarios, the boundary region is defined by the region having
high
saturation of heavy hydrocarbons that forms a substantial barrier to gas
injection at the
low gas injection pressures used to inject the gas into the lean zone. Gas
that may reach
the boundary region is impeded from passing into the main pay zone and thus
advances
laterally within the lean zone.
[0080] Referring to Fig 8, the injection well 20 can also be provided as a
horizontal well,
which may extend in a substantially parallel manner with the production wells,
or may be
at other orientations. The horizontal section of the injection well 20 can be
provided at a
higher elevation compared to the horizontal sections of the production wells
16. Both the
injection and production wells can be provided with suitable apertures,
perforations or
other means of fluid communication with the lean zone in order to allow gas
injection and
water production.
[0081] The production and injection wells can have completions according to
various
characteristics of the lean zone. For example, slotted liners or screens may
be used in
CA 2899805 2017-06-15
CA 02899805 2015-08-04
,µ
17
the production wells in the event that sand production or blockage are
potential
problems.
[0082] Referring now to Figs 2 and 3, in some implementations, the well
arrangement
can include at least one primary gas injection well 20 and multiple spaced-
apart
production wells 16 located around the central injection well 20. Various well
patterns
may be employed, including five-spot, seven-spot and/or nine-spot patterns,
variants
thereof, with one or multiple injection wells 20 located at a generally
central location. The
well patterns can also be provided depending on the size, shape and geological
properties of the lean zones and surrounding formation properties. More
regarding well
patterns and operation of the wells will be described further below.
Operation of the production and injection wells
[0083] Referring to Figs 5A to 5D, the general operation of the production and
injection
wells will be described. In general, the production wells 16 are operated to
produce
water and the injection well 20 is operated to inject NCG into the lean zone,
to dewater
and pressurize the lean zone. The production and injection are operated to
promote
gravity drainage of the water. While water production can have a displacement
component, which can vary depending on the stage of the dewatering process,
the wells
are spaced, located and operated to promote gravity drainage. The injection
and
production are controlled so that gas breakthrough in the production wells is
delayed for
a significant period of time. Thus, the gas injection is controlled in
accordance with the
water production as well as the permeability properties of the lean zone.
Permeability
properties can be determined, for example, based on core samples, simulation
modelling, calculations and/or empirical experimentation.
[0084] Referring to Fig 5A, water removal begins as the production wells 16
are used to
produce water. Artificial or mechanical lift devices, such as pumps, can also
be used to
help produce water. Providing the production wells 16 so that the portion that
received
the flow of water from the lean zone is located at the bottom of the lean zone
facilitates
this gravity drainage of the water. To further enhance such gravity drainage,
the portion
that received the flow of water can be located in a sump below the lean zone,
as
illustrated in Fig 13. A sump pump can be provided to facilitate production,
where the
pump intake is located within the sump. It should be noted that the dewatering
can be
CA 02899805 2015-08-04
18
done well before the steam chamber approaches the lean zone and even before
the
SAGD operation is started up in the main pay zone. Various different kinds of
pumps can
be used, such as Electric Submersible Pumps (ESP) or Progressive Cavity Pumps
(PCP).
[0085] Referring still to Fig 5A, produced water 18 is recovered at the
surface at can be
processed, reused and/or disposed of by various methods depending on the
quality and
quality of the produced water. In some scenarios, the produced water 18 is
relatively
high quality, for example to typical aqueous streams that are separated from
SAGD
production fluids, and thus can be used in steam generation for SAGD or other
purposes. In some scenarios, the produced water 18 can be supplied to other
processing units, such as oil sands primary extraction units. The produced
water 18 can
also be stored in holding ponds or sent to local rivers if quality permits.
[0086] In some implementations, the produced water 18 or a portion thereof is
monitored for gas content in order to determine whether injected gas has
advanced
through the lean zone so as to be produced via the production wells. A gas
detector 28
can be installed to perform this detection. It should be noted that gas
detection in
general can be performed by other methods, such as observation wells 30
provided
through the lean zone 10, as illustrated in Fig 3, the observation wells being
equipped
with appropriate devices for directly and/or indirectly detecting gas and
relaying the
information so that certain appropriate actions can be taken. More regarding
gas
detection will be discussed further below, particularly in the context of
ceasing water
production and converting production wells to gas injection wells.
[0087] Referring now to Figure 5B, gas 22 is injected through the primary
injection well
20 into the lean zone 10. In some implementations, the gas injection starts
after water
production has been conducted. For example, the gas injection can be initiated
once
water production has begun to decline, once a certain pressure reduction has
occurred
due to water production, or after a certain amount of water has been produced
via the
production wells. Gas injection has the objectives of facilitating sustained
water
production via the production wells 14 and replacing water with gas in the
lean zone 10.
The gas injection can be regulated by a gas injection controller 32, for
example to
provide an injection rate to avoid early breakthrough of the gas past the
water toward the
production wells 14 while still re-pressurizing the lean zone 10. The gas re-
CA 02899805 2015-08-04
19
pressurization can be done to achieve a pressure that is comparable to SAGD
operation
pressure provided that the lean zone pressure does not exceed the fracture
pressure or
the steam chamber pressure. In some implementations, the gas re-pressurization
is
conducted to achieve an increased average pressure in the lean zone compared
to its
initial pressure. While gas pressurization would ideally increase the pressure
as close as
possible to the pressures of the thermal in situ recovery operation, gas
injection should
not be conducted at a rate to cause substantial and pre-mature channeling and
breakthrough of the gas through the water-saturated regions of the lean zone,
which
could lead to gas breakthrough at the production wells. The gas injection rate
can thus
be controlled so as to be relatively low, and coordinated with the water
production and
permeability of the lean zone, to facilitate water removal and pressurization
that will
provide insulation and pressurization for the subsequent thermal in situ
recovery
operation. Gas injection rates can be controlled based on a number of factors,
including
the water production rate, characteristics of the lean zone including the
permeability of
the solid media in the lean zone, the water-saturation and distribution within
the lean
zone, as well as location and orientation of the injection and production
wells. As shown
in Fig 5B, the gas injection forms a gas-enriched region 34 that expands
outwardly from
the injection well 20.
[0088] Referring to Figure 5C, as gas 22 is injected into the lean zone 10 the
gas-
enriched region expands outwardly and downwardly. In some implementations, the
gas
that is injected has low gas solubility in water at the temperature and
pressure conditions
of the lean zone. In some implementations, when the gas is injected proximate
to cap
rock defining an upper generally-impermeable gas barrier, part of the gas-
enriched
region 34 grows in a generally outward direction toward the surrounding
production wells
16. The gas-enriched region 34 can expand outwardly and eventually reach upper
parts
of the production wells that may not fluidly communicate with the lean zone
10, as
illustrated in Fig 5C, and the gas can expand downwardly as well toward the
lower
portion of the production well 16 in fluid communication with the lean zone
10. As water
is produced from the bottom of the production wells 16, the gas tends to fill
the upper
part of the lean zone 10 and then gradually expand downwardly. The gas
injection can
provide some gas drive to aid in promoting water displacement toward the
production
wells 16; but in order to achieve enhanced dewatering performance gravity
drainage is
CA 02899805 2015-08-04
promoted. It should be noted that the gas injection can be modulated over time
depending on the progression of the gas-enriched region 34 within the lean
zone 10.
[0089] In some scenarios, the lean zone may include existing gas-saturated
zones,
resulting in higher compressibility. In such scenarios, the water production
wells can be
located away from the existing gas-saturated zones, and more gas can be
injected via
the injection well in order to increase the lean zone pressure.
[0090] Referring briefly to Fig 5D, in some implementations, after water
production and
gas injection have led to the formation of a gas-enriched lean zone, one or
more of the
production wells 16 can be converted into a secondary injection well 36. This
conversion
is referred to herein as the beginning of the second phase of the dewatering
process.
Gas injection via the secondary injection wells 36 is performed to inhibit
water migration
from outside of the gas-enriched lean zone. Gas injection can continue through
all of the
injection wells in order to maintain the gas-enriched lean zone at a lean zone
pressure,
which can be provided based on the underlying thermal in situ recovery
operation
pressures (e.g., SAGO steam chamber pressures), thereby providing overlying
gas
insulation and pressurization for the recovery operation. More regarding the
conversion
of the production wells 16 into secondary gas injection wells 36 will be
discussed further
below.
[0091] In some implementations, the central injection wells can inject NCG
while the
surrounding water production wells are monitored for production of gas (e.g.,
by
monitoring the gas/water ratio in the production stream, by detecting the gas
when the
injected gas is not native to the lean zone, etc.). Once the gas is detected
in the
production fluids of a surrounding water production well, the well can be
converted to a
secondary NCG injection well. Eventually, all of the surrounding water
production wells
can be converted into NCG injection wells. In some implementations, once a
certain
amount of the water has been removed from the lean zone, e.g. 25%, 30%, 35%,
40%,
45% or 50% of the estimated water volume, recovery of hydrocarbons in the main
pay
zone can start. Alternatively, recovery of hydrocarbons in the main pay zone
can begin
prior to dewatering to the target depletion level.
[0092] Referring briefly to Figs 7C and 7D, in some implementations, after the
dewatering and gas pressurization of the lean zone 10, the thermal in situ
recovery
CA 02899805 2015-08-04
21
operation (e.g., SAGD) is commenced in the main pay zone 14. Fig 7C
illustrates the
formation of SAGD steam chambers, and Fig 7D illustrates the growth of the
SAGD
steam chambers toward the gas-enriched lean zone. More regarding the
dewatering and
SAGD operations will be discussed further below.
[0093] In some implementations, tracking methods can be used in order to
detect
various parameters of the process. For example, a tracer chemical can be
included in
the NCG injected into the lean zone via the injection wells, so that NCG
breakthrough at
the production wells can be observed by detecting the presence of the tracer
chemical in
the production fluid. A tracer chemical can be injected in various ways, such
as co-
injected with the NCG via one, more or all of the injection wells, or other
injection means.
The tracer chemical can be pre-injected into water present in the reservoir
and/or lean
zone in order to better determine the location and origin of the water being
displaced and
produced (e.g., from native water in the reservoir or from injected fluid in
the form of
condensed steam). Tracers can thus be used in connection with various aspects
of the
dewatering operations described herein, for various purposes, such as
detecting gas
breakthroughs, detecting and tracking water displacement and production, and
so on.
Dewatering and thermal in situ recovery implementations
[0094] Referring to Figs 7A to 7G, the dewatering and gas pressurization can
be
conducted on a lean zone 10 above a main pay zone 14 in which SAGD occurs. In
some
implementations, the gas-enriched lean zone 10 is formed well before potential
heat or
fluid losses from the SAGD could occur. However, it should be noted that
various timing
strategies can be used for the dewatering and gas pressurization and the SAGD
operation. For example, the dewatering and gas pressurization can be commenced
prior
to drilling the SAGD wells or prior to start-up of the SAGD wells.
Alternatively, the
dewatering and gas pressurization can begin after start-up of the SAGD wells,
ideally as
long as the growth of the SAGD steam chambers is such that that the gas-
enriched lean
zone is formed before the SAGD steam chambers reach the lean zone.
[0095] Referring to Figs 7A and 7B, the production wells 16 and injection well
20 can be
operated to establish a gas-enriched lean zone 10 prior to operating SAGD in
the
underlying main pay zone 14.
CA 02899805 2015-08-04
22
[0096] Referring to Fig 7C, the production wells 14 can be converted to
secondary
injection wells to inject gas to maintain and in some cases further expand the
gas-
enriched region. At some stage, SAGD wells are drilled, completed, and started
up. As
mentioned above, the timing of drilling, completion and start-up activities
can depend on
a number of factors. Fig 7C illustrates SAGD well pairs each including a SAGD
production well 38 and a SAGD injection well 40. After startup of the SAGD
well pairs to
establish fluid communication between each pair, steam chambers 42 are formed
above
respective SADG well pairs. In some scenarios, by the time steam chambers 42
begin to
form and grow upward, the gas-enriched lean zone has been formed and is being
maintained.
[0097] Referring to Fig 7D, eventually the steam chambers 42 approach the
lower part
of the lean zone 10. It should be noted that there is some heat conducted
upward from
the upper edge of the steam chambers 42 and can reach the lean zone before the
steam
chambers 42 themselves. As heat and steam reach the lean zone 10, the gas-
enriched
lean zone provides insulation and pressurization to reduce heat and fluid
losses. By way
of example, the heat savings and fluid loss savings can be considerable for
scenarios
where the lean zone above a SAGD well pad has had approximately 50% of its
water
removed and replaced by NCG, and the NCG has pressurized the lean zone to
reduce
the average pressure difference between the lean zone and the SAGD steam
chamber
pressures. Of course, it should be noted that the water removal factor and the
pressure
difference can be in different ranges for providing enhanced insulation and/or
pressurization.
[0098] Figs 7A to 7D illustrate the dewatering and pressurization process
above an
array of SAGD well pairs. An array of SAGD well pairs can include various
numbers of
well pairs that typically extend from a single well pad located at the
surface. Typically, a
bitumen reservoir is developed in stages, where a first array of SAGD wells is
provided
and operated in a first portion of the reservoir as a first stage of reservoir
development,
and then a second array of SAGD wells is provided and operated in another
portion of
the reservoir as a subsequent stage of reservoir development. The first and
second
arrays of SAGD wells can be located adjacent to each other, and the arrays can
be
generally parallel to each other or at various angles, depending on the
reservoir geology.
The dewatering and pressurization process can also be applied in stages in
order to
CA 02899805 2015-08-04
23
prepare the lean zones overlying different arrays of SAGD wells. Figs 7E to 7G
illustrate
such staged operation, which will be discussed further below.
[0099] Referring to Fig 10, during early steam chamber development, the gas-
enriched
region 34 can be maintained at a pressure (PG) between 0 kPa and 400 kPa below
the
underlying SAGD steam chamber pressures (PsAGD). The pressure difference (AP)
that is
achieved can depend on various factors, such as the geology of the lean zone
and the
economics of gas injection and heat loss for the given in situ hydrocarbon
recovery
operation. The pressures PG and PSAGD can both be monitored and adjusted so
that the
AP is within a desired range. In some implementations, 1400 kPa PG 5. 1800
kPa,
when PSAGD is approximately 1800 kPa. It should be noted that conventionally
the
pressure difference between a lean zone and SAGD steam chambers could be
modified
by adjusting the SAGD steam injector. When gas injectors are provided for
pressurizing
the lean zone, the pressure difference can be adjusted using two levers, i.e.,
the lean
zone gas injectors and the SAGD steam injector, which facilitates additional
options for
process control.
[0100] The gas injection wells can be operated to maintain a pressurized lean
zone
when the steam chambers come into fluid communication with the lean zone. As
the
SAGD operation continues and reaches maturity, the steam chambers can
eventually
expand into the lean zone, heating bitumen that is contained in the lean zone
and
pressurizing the lean zone to P
SAGO. The gas pressurization of the lean zone can help
delay the development of the steam chambers into the lean zone and encourage
improved conformance of steam chamber development into the lean zone.
[0101] In addition, the gas-saturated lean zone can encourage lateral growth
of the
steam chambers within the main pay zone. This promoted lateral growth of steam
chambers can also delay the steam chambers expanding into the lean zone and
increase hydrocarbon recovery and production rates since higher saturations of
hydrocarbons are typically found in such lateral directions within a main pay
zone.
Conversion of production well(s) to injection well(s)
[0102] As mentioned above in reference to Figs 5D and 70, one or more of the
production wells 16 can be converted to secondary injection wells 36 at the
appropriate
time. It should be noted that the conversion of production wells to injection
wells can
CA 02899805 2015-08-04
24
depend on various factors, and is generally performed in accordance with the
development of the gas-enriched region and gas content in the produced water
or
proximate the given production well.
[0103] In some implementations, a production well 16 is converted to an
injection well
36 after reaching a target water-saturation reduction in the lean zone 10. In
the case of
multiple production wells 16, each can be converted into a corresponding
injection well
36 after the region surrounding the production well 16 reaches a target water-
saturation
reduction. In some implementations, one or more of the production well can be
converted based on gas detection. For instance, conversion can be initiated
upon
detecting gas in the produced water and/or near the production well. Gas
detection can
include detecting gas in the produced water once recovered to surface,
detecting the
presence of gas directly by means of a detection device deployed downhole
within the
production well 16 or within an observation well 30, and/or detecting the
presence of gas
indirectly (eg., by measuring other parameters such as pressure changes and
the like)
by means of a detection device deployed downhole within the production well 16
or
within an observation well 30. Detecting the gas can also be done by detecting
a tracer
chemical that has been introduced into the gas prior to or upon injection. In
addition, in
some implementations, different tracer chemicals can be used for respective
injection
wells such that gas breakthrough at a production well can be uniquely linked
to a specific
injection well, and thus appropriate adjustment of the injection well can be
taken. The
observation well 30 can be a separate well drilled in a selected location of
the reservoir
for the dedicated purpose of observing parameters, such as fluid levels, and
gas content
and pressure within the reservoir. The observation well 30 can be an existing
well that is
equipped with appropriate instrumentation to provide suitable data. In
addition, the
conversion can be based on a gas content threshold in the produced water or
the water
proximate the production well or on another parameter that is an indicator of
gas
content. For example, the gas content threshold can be a gas concentration or
a gas-
water ratio. Referring to Fig 4, in some implementations, the gas detector 28
is installed
in-line or off-line with respect to the produced water pipe. In some
implementations, the
injected gas is different from existing gases that may be native to the
reservoir such as
H2S and 002. For example, N2 can be chosen as the injection gas which can
facilitate
gas detection by detecting N2 in the production fluids. A mixture of injection
gases may
CA 02899805 2015-08-04
also be provided so that at least one component of the gas mixture is non-
native to the
reservoir.
[0104] Monitoring the production fluids can also include analyzing the
composition of
produced water, for example the salinity of the water. Water present in the
lean zone
may have a certain salinity range such that an operator can confirm production
of the
lean zone water based on salt content measurements in the production fluid.
Steam
injected into the reservoir, for example via a SAGD injection well, contains
no salt and
therefore a drop in salinity in the fluids produced by the water production
wells can
indicate that condensed water from steam injection is being produced.
Therefore, the
composition of the produced water can be used to determine when to initiate
the second
phase of the process and convert a production well to a secondary injection
well.
[0105] In some implementations, conversion of the production well 16 includes
ceasing
production, fluidly coupling the well head to a gas source, and then providing
gas
pressure to inject the gas downhole. The gas injection can be regulated so as
to
maintain the gas-enriched lean zone at or above a specific water recovery
factor, which
may be 25% or 50% for example. The gas pressure and flow rate for the
secondary
injection wells 36 can be similar or different compared to each other and
compared to
the primary injection well 20. The gas injection via the converted well should
be high
enough to inhibit water migration from outside the gas-enriched lean zone 10,
and thus
can depend on the water pressures and permeability properties outside the gas-
enriched
lean zone 10. The injection pressure of the converted wells can be controlled
according
to current conditions, including the pressure of the lean zone and the
pressure of the
steam chambers at the time of conversion.
[0106] When multiple production wells 16 are provided, as illustrated in Fig 2
for
example, the gas-enriched region can expand toward the production wells 16 at
different
rates. In such scenarios, the conversion of some production wells 16 can occur
before
others. The monitoring of the gas and conversion of the wells can thus be
performed on
a per-well basis. It should also be noted that the target gas threshold can be
different
from different production wells 16 and can depend on the stage of the overall
dewatering
operation. For example, for the last production well to be converted, the gas
content
threshold in the produced water can be lower since the dewatering operation is
relatively
CA 02899805 2015-08-04
26
advanced and the gas-enriched region has expanded significantly within the
lean zone
of interest so as to achieve the target water removal.
[0107] When multiple production wells 16 are arranged in spaced relation and
around
one or more primary injection wells 20, once all of the production wells 16
are converted
into secondary injection wells 36, the gas-enriched region 34 occupies a
volume of the
lean zone that is beyond the perimeter formed by the production wells 16 and
maintains
the gas perimeter at a pressure to inhibit water migration.
[0108] In some implementations, the conversion of the production wells 16 can
also
include a step of creating new apertures or perforations in the well to enable
gas
injection at desired locations. For instance, when the well is vertical and
operating in
production mode, the main apertures in fluid communication with the lean zone
are
located at the lower extremity of the well; but when the well is converted
into an injection
well it can be desirable to inject gas at different elevations and thus new
apertures can
be provided or opened along the length of the well. In some scenarios, the
lower
extremity aperture is closed, for example by using a sliding sleeve, and new
apertures at
a higher elevation are used for the gas injection in the converted well.
Alternatively,
conversion of the production wells can include injection of the gas through
the same
apertures as in production mode, for instance at the bottom of the well such
that the gas
enters a lower part of the lean zone and migrates upward due to density
differences.
Lean zone injection gases
[0109] In some implementations, the fluid that is injected into the primary
injection well
20 and in the secondary injection wells 36 can include or consist of NCG. NCG
remains
in gaseous phase, has lower heat capacity properties compared to water, and
can
facilitate insulation and pressurization of the lean zone. Due to lower
densities, NCG
remains within the lean zone rather than substantially sinking downward into
the main
pay zone. The NCG can include various gases, such as methane, carbon dioxide,
nitrogen, air, natural gas and flue gas. The NCG can be at least partly
derived from the
hydrocarbon recovery operation, for instance carbon dioxide or flue gas
produced during
steam generation. The NCG can penetrate into higher-permeability layers, sandy
hydrocarbon-bearing layers as well as water-saturated layers, depending on
location
CA 02899805 2015-08-04
27
and rate of injection. The NCG can be selected according to process economics
and/or
desired effects within the lean zone.
[0110] In some implementations, the gas is pre-treated at surface prior to
being injected
into the lean zone. Pre-treatments can include heat exchange (heating or
cooling),
purification, and the like. The pre-treatment of the gas to be injected can be
based on
permeability properties of the gas through water and porous media of the lean
zone. The
gas or gas mixture can be selected to avoid acid gases, such as H2S. The gas
or gas
mixture can also be provided to prevent hydrate formation, by selecting
certain gas types
and/or by providing appropriate heat to thereby prevent pipe blockage due to
hydrate
formation.
[0111] In some implementations, different gases can be injected at different
times and
different locations. For example, a first NCG can be injected via the
injection well 20, and
a second NCG can be injected via the secondary injection wells 36 once
converted from
production. In addition, an initial NCG can be injected into all of the
injection wells during
an initial period of time (e.g., to establish a gas-enriched lean zone), and
then a different
NCG can be injected at a later time (e.g., to maintain the gas-enriched lean
zone). The
timing and location of types of gas to inject can be done according to the
properties of
the gas and desired effects within the lean zone.
[0112] In some implementations, the injection fluid is not a NCG but is a
fluid that has
lower heat capacity than that of water and can enable increasing the pressure
of the
lean zone to be closer to the pressure of the SAGD steam chamber pressures or
the
pressures encountered in the in situ recovery operation.
Staged implementations of dewatering and hydrocarbon recovery
[0113] As briefly mentioned above, in situ hydrocarbon recovery operations can
be
undertaken in a staged fashion to develop a hydrocarbon-bearing reservoir. The
dewatering operation can also be conducted in a staged fashion in combination
with
staged hydrocarbon recovery operations, as will be described in more detail
below.
[0114] Referring to Figs 6A and 6B, 7A to 7G, 9, 11, and 12, it can be
appreciated that
adjacent, contiguous or proximate lean zones can overly several main pay zones
that
make up an overall hydrocarbon-bearing reservoir that can be developed in
stages.
CA 02899805 2015-08-04
28
[0115] Referring now to Figs 6B and 7E to 7G, a first stage includes
dewatering a first
lean zone 10, which is located above a first bitumen-rich pay zone 14 and
adjacent to
and fluidly communicating with a second lean zone 110. The second lean zone
110 is
located above a second pay zone 114. The first lean zone 10 is dewatered by
producing
water from the first lean zone; injecting gas into the first lean zone, to
provide a first gas-
enriched lean zone; and inhibiting water migration from the second lean zone
into the
first lean zone. This may include using dewatering and pressurization
techniques as
described above. The first pay zone 14 is exploited by operating a first array
of SAGD
well pairs in the first pay zone, to produce bitumen and form steam chambers
having
overlying insulation and pressurization from the first gas-enriched zone. In a
second
stage, the second lean zone is dewatered by producing water from the second
lean
zone; injecting gas into the second lean zone, to provide a second gas-
enriched lean
zone; and inhibiting water migration from outside the second lean zone. The
second pay
zone 114 is then exploited by operating a second array of SAGD well pairs in
the second
pay zone114, to produce bitumen and form steam chambers having overlying
insulation
and pressurization from the second gas-enriched zone.
[0116] In some implementations, the step of inhibiting water migration from
the second
lean zone into the first lean zone 10 includes converting water production
wells 16
located in the first lean zone into gas injection wells 36. The second lean
zone 110 can
have production wells 116 provided for producing water 118, and an injection
well 120
for injection of gas, in a similar manner as can be done for the first lean
zone 10. The
step of inhibiting water migration from outside the second lean zone 110 can
include
converting the water production wells 116 located in the second lean zone 110
into
corresponding gas injection wells. The wells in the first and second lean
zones can be
located and operated in order to form a coalesced gas-enriched region within
both
zones.
[0117] Referring now to Fig 12, in some implementations, the staged process
can
include the following steps:
producing water (200) from a first lean zone, for instance via one or more
production wells provided in the lean zone according to a dewatering process
driven by a gravity-dominated mechanism, as described above;
CA 02899805 2015-08-04
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injecting gas (202) into the lean zone, either simultaneously or subsequently
to
step (200), for instance via a primary injection well provided in the lean
zone 10
to form a gas-enriched region;
for a certain amount of time, simultaneously producing water and injecting gas
(204), while monitoring the water saturation reduction and/or gas advancement
in
the lean zone;
reaching a target water-saturation reduction (206), which may be 25% or 50%
and can be detected and/or estimated (optionally, the production wells can all
be
converted to injection wells at some point);
initiating SAGD (208) or another in situ hydrocarbon recovery operation in the
main pay zone below the dewatered lean zone, from a first SAGD pad and/or a
first SAGD array of well pairs;
maintaining the gas-enriched lean zone (210) by regulating the gas injection
via
the injection well and converting the production wells into secondary
injection
wells, to inhibit water migration from outside of the gas-enriched regions;
adjacent to the first SAGD pad, producing water from a second lean zone (212)
in a similar manner as the first lean zone using a second arrangement of water
production wells;
injecting gas into the second lean zone injecting gas (214), either
simultaneously
or subsequently to step (212), in a similar manner as the first lean zone
using a
second injection well;
for a certain amount of time, simultaneously producing water and injecting gas
(216) in the second lean zone, while monitoring the water saturation reduction
and/or gas advancement in the second lean zone;
reaching a target water-saturation reduction (218), which may be 25% or 50%
and can be detected and/or estimated;
=
CA 02899805 2015-08-04
initiating SAGD (220) or another in situ hydrocarbon recovery operation in the
second main pay zone below the dewatered second lean zone, from a second
SAGD pad and/or a second SAGD array of well pairs; and
maintaining the gas-enriched first and second lean zones (222) by regulating
the
gas injection via the injection wells and converting the production wells in
the
second lean zone into secondary injection wells, to inhibit water migration
from
outside of both zones.
[0118] It should be noted that this general staged process can be continued
for
subsequent lean zones and pay zones within an overall hydrocarbon-bearing
reservoir
to be developed. Fig 9 illustrates an example of a series of lean zones having
different
thicknesses in which staged dewatering can be implemented, using injection and
production wells that are located in accordance with the given geology and
thickness of
each lean zone. Fig 11 illustrates the combined lean zone, which is made up of
several
lean zones 10, and is geologically-contained. In some implementations, the
dewatering
process described herein can be replicated over various portions of a
reservoir as the
underlying pay zones are developed. Multiple stages can be pre-designed prior
to
implementing a series of stages, or each subsequent stage can be designed
based on
characteristics of the previous stage.
[0119] In terms of timescale, in some implementations the dewatering is
initiated two
months to three years prior to the in situ hydrocarbon operation. As the gas
injection is
relatively slow in order to avoid premature gas channeling and breakthrough at
production wells, early initiation of the dewatering process can be
beneficial.
[0120] When a SAGD array reaches maturity in a given pay zone, NCG injection
or
NCG-steam co-injection can be conducted via the SAGD injection well. An
adjacent
SAGD array may not yet be at maturity and thus it may be desirable to maintain
the
pressure in the mature SAGD chambers to prevent the steam and heat from the
adjacent SAGD chamber from being lost. In some implementations, NCG injection
can
be conducted in both a lean zone and an underlying main pay zone to form a
coalesced
NCG zone having a pressure that is close the adjacent SAGD steam chamber
pressures.
TESTS AND RESULTS
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31
[0121] Simulations were conducted to assess the dewatering and gas
pressurization of
a water-saturated lean zone. The simulations included two central injection
wells and
surrounding production wells. Fig 14 shows results in terms of increasing the
average
pressure in the lean zone to a desired level; Fig 15 shows results in terms of
the gas
injection rates over time; and Fig 16 shows the increase in water recovery
factor over
time in the lean zone.
[0122] Additional results indicated that the impact of fluid loss to a water-
saturated low
pressure lean zone increased SOR from 2.5 to 5 or 6, while the impact of heat
loss due
to the elevated heat capacity of water in the lean zone increased SOR from 2.5
to 2.7,
showing that hot fluid loss has a significantly higher impact on SOR compared
to heat
loss. This illustrates that pressurization of the dewatered lean zone to
inhibit fluid loss to
a lower pressure zone can facilitate lower SOR levels.
