Note: Descriptions are shown in the official language in which they were submitted.
1
PRESSURIZATION OF LEAN ZONES WITH NCG INJECTION
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 the
operation
because of the greater number of wells to be drilled for a given reservoir
volume. A second
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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;
after reaching a target water-saturation reduction in the hydrocarbon-lean
zone and thereby forming a gas-enriched lean zone, converting the water
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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
monitoring comprises: obtaining information from an observation well located
in the lean
zone.
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[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.
[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.
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[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.
[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.
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[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:
producing water from the first lean zone; and
injecting gas into the first lean zone, to provide a first gas-enriched lean
zone;
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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.
[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.
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[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).
[0043] In some implementations, the first array of well pairs comprises SAGD
well pairs,
and the corresponding mobilization chambers comprise steam chambers. In some
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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, comprising:
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
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
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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.
[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.
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[0052] In some implementations, there is provided a process for in situ
recovery of
bitumen, comprising:
injecting gas into a first hydrocarbon-lean zone located above a first bitumen-
rich
pay zone and adjacent to and fluidly communicating with a second hydrocarbon-
lean zone located above a second bitumen-rich pay zone and dewatering the
first
hydrocarbon-lean zone, to provide a first gas-enriched lean zone;
operating a first array of well pairs in the first bitumen-rich pay zone, to
produce
bitumen and form mobilization chambers having overlying insulation and
pressurization provided by the first gas-enriched zone;
injecting gas into the second hydrocarbon-lean zone and dewatering the second
hydrocarbon-lean zone, to provide a second gas-enriched lean zone; and
operating a second array of well pairs in the second bitumen-rich pay zone, to
produce bitumen and form mobilization chambers having overlying insulation and
pressurization from the second gas-enriched zone.
[0053] In some implementations, there is provided a system for in situ
recovery of
bitumen, comprising:
a first set of gas injection wells 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 set of gas
injection
wells being configured and operable to pressurize the first hydrocarbon-lean
zone,
to provide a first gas-enriched lean zone;
a first array of well pairs provided in the first bitumen-rich 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 set of gas injection wells provided in the second hydrocarbon-lean
zone
that is located above a second bitumen-rich pay zone, the second gas injection
well being configured and operable to pressurize the second hydrocarbon-lean
zone, to provide a second gas-enriched lean zone; and
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a second array of well pairs provided in the second bitumen-rich pay zone and
configured to produce bitumen and form mobilization chambers having overlying
insulation and pressurization from the second gas-enriched zone.
[0054] In some implementations, there is provided a process for in situ
recovery of
bitumen, comprising:
pressurizing a first hydrocarbon-lean zone located above a first bitumen-rich
pay
zone and adjacent to and fluidly communicating with a second hydrocarbon-lean
zone located above a second bitumen-rich pay zone, wherein the pressurizing
comprises injecting a non-condensable gas into the first hydrocarbon-lean zone
to
provide a first gas-enriched lean zone;
operating a first array of well pairs in the first bitumen-rich pay zone, to
produce
bitumen and form mobilization chambers having overlying insulation and
pressurization provided by the first gas-enriched zone;
pressurizing the second hydrocarbon-lean zone comprising injecting a non-
condensable gas into the second hydrocarbon-lean zone, to provide a second gas-
enriched lean zone; and
operating a second array of well pairs in the second bitumen-rich pay zone, to
produce bitumen and form mobilization chambers having overlying insulation and
pressurization from the second gas-enriched zone.
BRIEF DESCRIPTION OF DRAWINGS
[0055] 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.
[0056] Fig 2 is a top plan view schematic of water production wells
distributed around a
gas injection well.
[0057] 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.
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[0058] 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.
[0059] 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.
[0060] 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.
[0061] Figs 7A to 7G are vertical cross-sectional view schematics illustrating
dewatering
of lean zones above SAGD operations.
[0062] Fig 8 is a perspective view schematic of a dewatering operation
performed with
substantially horizontal wells provided in a lean zone.
[0063] 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.
[0064] Fig 10 is a vertical cross-sectional view schematic of a SAGD operation
with a
steam chamber at PSAGD and an overlying dewatered gas-enriched zone at PG.
[0065] 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.
[0066] Fig 12 is a flowchart for a dewatering and hydrocarbon recovery
process.
[0067] Fig 13 is a vertical cross-sectional view schematic including a lean
zone with a gas
injection well and water production wells.
[0068] Fig 14 is a graph of average lean zone pressure versus time.
[0069] Fig 15 is a graph of gas injection rates versus time.
[0070] Fig 16 is a graph of water recovery factor versus time.
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DETAILED DESCRIPTION
[0071] 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 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.
[0072] 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.
[0073] In some implementations, the dewatering and hydrocarbon production
techniques
can be performed in reservoirs that include a main hydrocarbon-containing zone
(i.e., a
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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.
[0074] 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 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 SAGD are not
intended
to be limited to SAGD applications.
Lean zones for dewatering and pressurization
[0075] 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.
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[0076] 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.
[0077] 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 that
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.
[0078] Referring to Fig 11, in some implementations, the lean zone 10 or
multiple lean
zones are part of a geologically-contained water-saturated formation, 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.
[0079] 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
CA 2998423 2018-03-19
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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
[0080] 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.
[0081] 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.
[0082] 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
CA 2998423 2018-03-19
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the boundary region is impeded from passing into the main pay zone and thus
advances
laterally within the lean zone.
[0083] 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.
[0084] 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 the
production wells in the event that sand production or blockage are potential
problems.
[0085] 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
[0086] 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
CA 2998423 2018-03-19
19
example, based on core samples, simulation modelling, calculations and/or
empirical
experimentation.
[0087] 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 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).
[0088] 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.
[0089] 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.
CA 2998423 2018-03-19
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[0090] 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-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.
[0091] 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
CA 2998423 2018-03-19
21
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 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.
[0092] 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.
[0093] 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., SAGD 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.
[0094] 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
CA 2998423 2018-03-19
22
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.
[0095] 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
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.
[0096] 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
[0097] 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
CA 2998423 2018-03-19
23
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.
[0098] 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.
[0099] 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.
[0100] 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.
[0101] 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
CA 2998423 2018-03-19
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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 prepare
the lean zones overlying different arrays of SAGD wells. Figs 7E to 7G
illustrate such
staged operation, which will be discussed further below.
[0102] 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 5 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.
[0103] 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 PSAGD. 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.
[0104] 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
CA 2998423 2018-03-19
25
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)
[0105] As mentioned above in reference to Figs 5D and 7C, 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 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.
[0106] 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 (e.g., 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,
CA 2998423 2018-03-19
26
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 CO2.
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 also be provided so
that at least
one component of the gas mixture is non-native to the reservoir.
[0107] 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.
[0108] 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.
[0109] 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
CA 2998423 2018-03-19
27
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
advanced and
the gas-enriched region has expanded significantly within the lean zone of
interest so as
to achieve the target water removal.
[0110] 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.
[0111] 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
[0112] 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
CA 2998423 2018-03-19
28
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 and rate of injection.
The NCG can
be selected according to process economics and/or desired effects within the
lean zone.
[0113] 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.
[0114] 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.
[0115] 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
[0116] 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.
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[0117] 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.
[0118] 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.
[0119] 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 migrationfrom 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.
[0120] Referring now to Fig 12, in some implementations, the staged process
can include
the following steps:
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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;
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;
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reaching a target water-saturation reduction (218), which may be 25% or 50%
and
can be detected and/or estimated;
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.
[0121] 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.
[0122] 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.
[0123] 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.
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TESTS AND RESULTS
[0124] 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.
[0125] 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.
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