Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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LEAN ZONE PRESSURIZATION AND MANAGEMENT FOR UNDERLYING
HYDROCARBON RECOVERY OPERATIONS
TECHNICAL FIELD
[0001] The technical field generally relates to in-situ hydrocarbon recovery,
and more
particularly, to injection of gas into hydrocarbon-lean zones that overly
hydrocarbon-rich
reservoirs.
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). 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 mainly due to
gravity forces
and are recovered to the surface. Over time, a steam chamber having a steam
chamber
pressure 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-containing,
hydrocarbon-lean zones (e.g., lean bitumen zones) can lead to an elevated
Steam-to-Oil
Ratio (SOR) and low hydrocarbon recovery rates, since heat and steam can be
lost to the
overlying water-rich zone due to lower pressures in the lean zone and high
heat capacity
due to high water content in the lean zone. This can result in poor
performance in terms
of oil production and efficiency due to the fact that significant steam energy
can be wasted
in heating the hydrocarbon-lean zone, which becomes more important once the
steam
chamber intercepts the hydrocarbon-lean zone which is generally at a lower
pressure than
the steam chamber pressure. The high heat capacity of water and tendency of
the steam
to flow into the lean bitumen zone due to the pressure differential between
the
hydrocarbon-lean zone and the hydrocarbon-rich reservoir pose challenges to
heavy
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hydrocarbon recovery from reservoirs with a water-saturated, hydrocarbon-lean
zone. In
addition to an elevated SOR, water production from hydrocarbon-lean zones also
has the
potential to limit the emulsion treatment capacity of SAGD plant and to reduce
bitumen
production capacity because of the high water cut.
[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
recovery 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 and may not work if the thickness of the heavy hydrocarbon-rich
reservoir is
uneven. A second method includes co-injecting non-condensable gas (NCG) with
steam
into the SAGD injection well 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 may 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 one aspect, a process for recovering hydrocarbons is provided. The
process
includes injecting non-condensable gas via a gas injection well having an
injection portion
located in a subterranean hydrocarbon-lean zone containing water and having a
lower
hydrocarbon content than an underlying hydrocarbon-rich reservoir, the
hydrocarbon-lean
zone being located above and in fluid communication with the hydrocarbon-rich
reservoir,
the non-condensable gas being injected at a gas injection rate sufficient to
form a gas-
enriched region within the hydrocarbon-lean zone, pressurize the hydrocarbon-
lean zone
to a lean zone pressure and to displace at least a portion of the water
contained therein;
operating in-situ recovery wells within the hydrocarbon-rich reservoir
including an injection
well to inject a mobilizing fluid into the hydrocarbon-rich reservoir and a
production well to
recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the
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hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber
pressure;
monitoring the hydrocarbon-lean zone to determine at least one property of the
hydrocarbon-lean zone; and controlling the injection of the non-condensable
gas
according to the at least one property of the hydrocarbon-lean zone. The gas-
enriched
region reduces fluid leakage and heat loss from the mobilizing fluid chamber
into the
hydrocarbon-lean zone and the water is displaced away from a region of the
hydrocarbon-
lean zone that overlies the mobilizing fluid chamber formed in the hydrocarbon-
rich zone.
[0007] In another aspect, there is provided a process for recovering
hydrocarbons. The
process includes: injecting non-condensable gas via a gas injection well
having an
injection portion located in a subterranean hydrocarbon-lean zone containing
water and
having a lower hydrocarbon content than an underlying hydrocarbon-rich
reservoir, the
hydrocarbon-lean zone being located above and in fluid communication with the
hydrocarbon-rich reservoir, the non-condensable gas being injected at a gas
injection rate
sufficient to form a gas-enriched region within the hydrocarbon-lean zone,
pressurize the
hydrocarbon-lean zone to a lean zone pressure and displace at least a portion
of the water
contained therein; operating in-situ recovery wells within the hydrocarbon-
rich reservoir,
including an injection well to inject a Mobilizing fluid at a mobilizing fluid
injection rate into
the hydrocarbon-rich reservoir and a production well to recover hydrocarbons
therefrom
while forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir,
the mobilizing
fluid chamber having a chamber pressure; monitoring the lean zone pressure and
the
chamber pressures; and controlling a pressure differential between the lean
zone pressure
and the chamber pressures over time to remain within a pressure differential
between
about 0 kPa and about 200 kPa by adjusting at least one of the gas injection
rate and the
mobilizing fluid injection rate. The gas-enriched region reduces fluid leakage
and heat loss
from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water
is
displaced away from a region of the hydrocarbon-lean zone that overlies the
mobilizing
fluid chamber formed in the hydrocarbon-rich zone.
[0008] In another aspect, there is provided a process for producing a
recovered non-
condensable gas. The process includes: injecting non-condensable gas via a gas
injection
well having an injection portion located in a subterranean hydrocarbon-lean
zone
containing water and having a lower hydrocarbon content than an underlying
hydrocarbon-
rich reservoir, the hydrocarbon-lean zone being located above and in fluid
communication
with the hydrocarbon-rich reservoir, the non-condensable gas being injected at
a gas
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injection rate sufficient to form a gas-enriched region within the hydrocarbon-
lean zone,
pressurize the hydrocarbon-lean zone and displace at least a portion of the
water
contained therein; operating in-situ recovery wells within the hydrocarbon-
rich reservoir
including an injection well to inject a mobilizing fluid into the hydrocarbon-
rich reservoir
and a production well to recover hydrocarbons therefrom while forming a
mobilizing fluid
chamber in the hydrocarbon-rich reservoir, the mobilizing fluid chamber having
a chamber
pressure; and after recovery from the hydrocarbon-rich reservoir enters a
mature phase
in which chamber pressure and hydrocarbon recovery performance decrease over
time,
recovering at least a portion of the non-condensable gas from the hydrocarbon-
lean zone.
The gas-enriched region reduces fluid leakage and heat loss from the
mobilizing fluid
chamber into the hydrocarbon-lean zone and the water is displaced away from a
region
of the hydrocarbon-lean zone that overlies the mobilizing fluid chamber formed
in the
hydrocarbon-rich zone.
[0009] In another aspect, there is provided a process for recovering
hydrocarbons. The
process includes: injecting non-condensable gas via a plurality of gas
injection wells
spaced-apart from one another and each having an injection portion located in
a
subterranean hydrocarbon-lean zone containing water and having a lower
hydrocarbon
content than an underlying hydrocarbon-rich reservoir, the hydrocarbon-lean
zone being
located above and in fluid .communication with the hydrocarbon-rich reservoir,
the non-
condensable gas being injected through the plurality of gas injection wells at
respective
gas injection rates sufficient to form corresponding gas-enriched regions
within the
hydrocarbon-lean zone, pressurize the hydrocarbon-lean zone to a lean zone
pressure
and displace at least a portion of the water contained therein; controlling at
least one of
the respective gas injection rates of the non-condensable gas into the
plurality of injection
wells and selecting relative positions of the gas injection wells to avoid
coalescence of
adjacent gas-enriched regions; and operating in-situ recovery wells within the
hydrocarbon-rich reservoir including an injection well to inject a mobilizing
fluid into the
hydrocarbon-rich reservoir and a production well to recover hydrocarbons
therefrom while
forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir, the
mobilizing fluid
chamber having a chamber pressure. The corresponding gas-enriched regions
reduce
fluid leakage and heat loss from the mobilizing fluid chamber into the
hydrocarbon-lean
zone and the water is displaced away from a region of the hydrocarbon-lean
zone that
overlies the mobilizing fluid chamber formed in the hydrocarbon-rich zone.
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[0010] In another aspect, there is provided a process for recovering
hydrocarbons. The
process includes: positioning a gas injection well having an injection portion
located in a
subterranean hydrocarbon-lean zone containing water and having a lower
hydrocarbon
content than an underlying hydrocarbon-rich reservoir according to a shape of
the
hydrocarbon-lean zone, the hydrocarbon-lean zone being located above and in
fluid
communication with the hydrocarbon-rich reservoir, the non-condensable gas
being
injected at a gas injection rate sufficient to form a gas-enriched region
within the
hydrocarbon-lean zone, pressurize the hydrocarbon-lean zone to a lean zone
pressure
and displace at least a portion of the water contained therein; injecting non-
condensable
gas via a gas injection well; operating in-situ recovery wells within the
hydrocarbon-rich
reservoir including an injection well to inject a mobilizing fluid at a
mobilizing fluid injection
rate into the hydrocarbon-rich reservoir and a production well to recover
hydrocarbons
therefrom while forming a mobilizing fluid chamber in the hydrocarbon-rich
reservoir, the
mobilizing fluid chamber having a chamber pressure, and controlling gas
injection along
a length of the gas injection well to inhibit gas breakthrough into at least
one of the in-situ
recovery wells. The gas-enriched region reduces fluid leakage and heat loss
from the
mobilizing fluid chamber into the hydrocarbon-lean zone and the water is
displaced away
from a region of the hydrocarbon-lean zone that overlies the mobilizing fluid
chamber
formed in the hydrocarbon-rich zone.
[0011] In another aspect, there is provided a process for recovering
hydrocarbons. The
process includes: injecting non-condensable gas via a gas injection well
having an
injection portion located in a first hydrocarbon-lean zone containing water
and having a
lower hydrocarbon content than a first region of a hydrocarbon-rich reservoir,
the first
hydrocarbon-lean zone being located above and in fluid communication with the
first
region of the hydrocarbon-rich reservoir, the non-condensable gas being
injected at a gas
injection rate sufficient to form a gas-enriched region within the first
hydrocarbon-lean
zone, pressurize the first hydrocarbon-lean zone to a lean zone pressure and
displace at
least a portion of the water contained therein; operating a first set of in-
situ recovery wells
within the first region of the hydrocarbon-rich reservoir to inject a first
mobilizing fluid into
the first hydrocarbon-rich reservoir and to recover hydrocarbons therefrom
while forming
a first mobilizing fluid chamber in the first region; after hydrocarbon
recovery from the first
set of in-situ recovery wells enters a mature phase resulting in a mature
overall formation
in which chamber pressures and hydrocarbon recovery performance decrease over
time,
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continuing injection of the non-condensable gas to form a combined gas-
enriched region
comprising the non-condensable gas and the first mobilizing fluid to
pressurize the overall
mature formation; and operating a second set of in-situ recovery wells within
a second
region of the hydrocarbon-rich reservoir adjacent to the first region of the
hydrocarbon-
rich reservoir to inject a second mobilizing fluid into the second region of
the hydrocarbon-
rich reservoir and to recover hydrocarbons therefrom while forming a second
mobilizing
fluid chamber in the second region. The combined gas-enriched region reduces
fluid
leakage and heat loss from the second mobilizing fluid chamber into the mature
overall
formation.
[0012] In another aspect, there is provided a process for recovering
hydrocarbons. The
process includes: injecting non-condensable gas via a gas injection well
having an
injection portion located in a subterranean hydrocarbon-lean zone containing
water and
having a lower hydrocarbon content than an adjacent hydrocarbon-rich
reservoir, the
hydrocarbon-lean zone being in fluid communication with the hydrocarbon-rich
reservoir,
the non-condensable gas being injected at a gas injection rate sufficient to
form a gas-
enriched region within the hydrocarbon-lean zone, pressurize the hydrocarbon-
lean zone
to a lean zone pressure and to displace at least a portion of the water
contained therein;
operating in-situ recovery wells within the hydrocarbon-rich reservoir
including an injection
well to inject a mobilizing fluid into the hydrocarbon-rich reservoir and a
production well to
recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the
hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber
pressure;
monitoring the hydrocarbon-lean zone to determine at least one property of the
hydrocarbon-lean zone; and controlling the injection of the non-condensable
gas
according to the at least one property of the hydrocarbon-lean zone. The gas-
enriched
region reduces fluid leakage and heat loss from the mobilizing fluid chamber
into the
hydrocarbon-lean zone and the water is displaced away from a region of the
hydrocarbon-
lean zone that is adjacent to the mobilizing fluid chamber formed in the
hydrocarbon-rich
zone.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] Fig 1 is a vertical cross-sectional view schematic of a hydrocarbon-
lean zone
located above a main pay zone, with a gas injection well located in the lean
zone.
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[0014] Fig 2 is a perspective view schematic of hydrocarbon-lean zone with a
gas injection
well located in the hydrocarbon-lean zone, and an observation passing through
the
hydrocarbon-lean zone.
[0015] Figs 3A to 3D are vertical cross-sectional view schematics illustrating
gas injection
and formation of a gas-enriched region within the hydrocarbon-lean zone.
[0016] Figs 4A to 4D are vertical cross-sectional view schematics illustrating
gas injection
and formation of a gas-enriched region within the hydrocarbon-lean zone above
SAGD
operations.
[0017] Fig 5 is a perspective view schematic of a horizontal gas injection
well provided in
a hydrocarbon-lean zone.
[0018] Fig 6 is a vertical cross-sectional view schematic of a plurality of
adjacent
hydrocarbon-lean zones each having a different thickness and a corresponding
gas
injection well in each one of the plurality of hydrocarbon-lean zones.
[0019] Fig 7 is a vertical cross-sectional view schematic of a SAGD operation
with a steam
chamber at PSAGD and an overlying dewatered gas-enriched region at PG.
[0020] Fig 8 is a vertical cross-sectional view schematic of a reservoir
including a plurality
of hydrocarbon-lean zones within a high water-saturation formation that is
geologically
contained and located above a bitumen-rich reservoir.
[0021] Fig 9 is a vertical cross-sectional view schematic of a hydrocarbon-
lean zone
located above a main pay zone, with a gas injection well converted in a
production well.
[0022] Fig 10 is a graph showing simulation results for a hydrocarbon-lean
zone having a
dome structure versus a hydrocarbon-lean zone having a flat structure.
[0023] Figs 11A to 11E are top plan view schematics of various well
arrangements for gas
injection wells and an array of underlying in-situ recovery wells extending
from a well pad.
[0024] Figs 12A to 12D are vertical cross-sectional view schematics of gas
injection wells
positioned in hydrocarbon-lean zones having different shapes or geologies.
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[0025] Fig 13 is a top view schematic of an area including a hydrocarbon-lean
zone having
multiple lean regions with different thicknesses.
[0026] Figs 14A to 14E are vertical cross-sectional views schematics of gas
injections
wells positioned in hydrocarbon-lean zones having different shapes, and in
particular, a
tapered shape.
[0027] Figs 15A to 15E are vertical cross-sectional views schematics of gas
injections
wells and pairs of SAGD wells in two adjacent overall formations, including
respective gas-
enriched regions and mobilizing fluid chambers, as well as a pressurized
overall formation.
[0028] Figs 16A to 16D are vertical cross-sectional views schematics of gas
injections
wells showing different configurations of gas injection sections and isolation
packers.
[0029] Fig 17 is a graph depicting the effect of changes water saturation
levels, in %, on
the capillary pressure for different hydrocarbon-lean zones and hydrocarbon-
rich
reservoirs.
[0030] Figs 18A and 18B are graphs depicting pressure variations in a
hydrocarbon-lean
zone as a function of time.
[0031] Fig 19 is a graph depicting pressure transient analysis data and log-
log diagnostic
plots to assess size increase of a gas-enriched region in a lean zone after a
given period
of time.
[0032] Fig 20 is a graph depicting variations in gas injection rate over time
in a
hydrocarbon-lean zone and cumulative gas injection over time, as well as the
corresponding impact on pressurization of the hydrocarbon-lean zone, according
to results
from numerical reservoir simulations.
DETAILED DESCRIPTION
[0033] The proposed techniques generally relate to the injection of a gas into
a water-
containing, hydrocarbon-lean zone a zone where
the hydrocarbon saturation is less
than the typical saturation of a hydrocarbon-rich reservoir located below such
a
hydrocarbon-lean zone), to enhanced hydrocarbon recovery from the hydrocarbon-
rich
reservoir, and to the optional recovery of the injected gas. Various
techniques are
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described for controlling gas injection into the hydrocarbon lean zone and
facilitating
enhanced performance of lean zone pressurization, hydrocarbon recovery, and/or
overall
process efficiency.
[0034] Gas, such as non-condensable gas (NCG), is injected into the
hydrocarbon-lean
zone to increase the gas saturation of the hydrocarbon-lean zone and to form a
gas-
enriched region overlying a main pay zone in which an in-situ recovery
operation is
conducted. In some implementations, the in-situ recovery operation is a
thermal operation,
e.g., Steam-Assisted Gravity Drainage (SAGD). The in-situ recovery operation
can also
be a solvent assisted gravity drainage process, a solvent-assisted SAGD
process where
steam and solvent are injected as mobilizing fluids, or other in-situ recovery
processes
that include the injection of a mobilizing fluid to increase the mobility of
hydrocarbons to
facilitate production.
[0035] Gas injection into the hydrocarbon-lean zone can displace water
contained therein
to surrounding areas and form a gas-enriched region in which the pressure is
increased
to a level that is ideally closer to operating pressures of the in-situ
recovery operation (e.g.,
SAGD), particularly once the corresponding mobilizing fluid chambers (e.g.,
SAGD steam
chambers) reach the hydrocarbon-lean zone. The overlying gas-enriched region
can
provide an insulation layer and pressurization above thermal in-situ recovery
operations
to reduce heat and fluid losses to the hydrocarbon-lean zone. Depending on the
operating
conditions of the underlying in-situ recovery operation, which can vary based
on the
injected mobilizing fluid (e.g., steam versus solvent), the gas injection can
be adjusted in
terms of injection rate, gas-enriched region pressure, nature of the gas that
is injected,
temperature of the gas, and so on.
[0036] In some implementations, gas injection into the hydrocarbon-lean zone
is
performed without any production of water from the lean-zone via water
production wells.
Water is therefore displaced by the injected gas but is not produced via
dedicated water
production wells. Multiple gas injection wells can be provided according to
various patterns
or configurations to facilitate gas pressurization of the lean zone.
Alternatively, water could
be produced from the hydrocarbon-lean zone via one or more water production
wells,
which could be provided around a primary gas injection well located in the
hydrocarbon-
lean zone.
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[0037] A number of variables related to the gas injection can be monitored to
promote
pressurization of the hydrocarbon-lean zone by the gas, as well as
displacement of water
from the hydrocarbon-lean zone and corresponding reduction of water
saturation, such as
the injection rate of the gas, the locations of the gas injection wells and
the volume of gas
injected, as will be discussed in further detail below.
[0038] In some implementations, hydrocarbon production processes can be
performed in
reservoirs that include a main hydrocarbon-containing zone (i.e., a main pay
zone) and a
hydrocarbon-lean zone that has high water saturation, such as at least 30% to
50% vol.
water saturation, such hydrocarbon-lean zones having a tendency to reduce
performance
of hydrocarbon production from the main pay zone, due to the high heat
capacity of water
contained in the hydrocarbon-lean zone and/or lower pressure of the
hydrocarbon-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 pressurizing the hydrocarbon-lean zone with gas, or by pressurizing a
mature overall
formation adjacent a newer overall formation through the hydrocarbon-lean
zone.
[0039] The pressurization of the hydrocarbon-lean zone can facilitate a more
energy-
efficient hydrocarbon recovery process. Injecting NCG into the hydrocarbon-
lean zone can
facilitate increasing the fluid pressure in the hydrocarbon-lean zone as the
gas remains
substantially trapped therein, thus reducing the differential pressure between
the
hydrocarbon-lean zone and the main pay zone. Consequently, heat and steam loss
to the
hydrocarbon-lean zone is reduced, which in turn can improve the steam-to-oil
ratio (SOR),
and the bitumen recovery factor.
[0040] In some implementations, the gas injection techniques described herein
are used
to pressurize a mature overall formation that includes a hydrocarbon-lean zone
overlying
a hydrocarbon-rich reservoir, the mature overall formation being proximate a
newer overall
formation, for example adjacent or contiguous, where an in-situ recovery
operation is
taking place. In such implementations, the gas injection is performed into the
hydrocarbon-
lean zone, so that the gas-enriched region extends downward into the
underlying reservoir
from which hydrocarbons have been recovered. Hence, pressure maintenance in
the
mature overall formation (including both the lean zone and the underlying
mature pay
zone) can prevent heat and steam losses from the newer overall formation to
the
proximate mature overall formation, which can improve the process efficiency
of the newer
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overall formation. Gas injection through the hydrocarbon-lean zone can thus
have the
potential to be used as a wind-down strategy to manage mature overall
formations. In
addition, it can be advantageous to inject NCG via the gas injection wells
located in the
lean zone rather than through the SAGD injection wells located in the pay zone
during or
after wind-down. It is noted that the SAGD wells can be gradually throttled as
gas injection
is affected via the gas injection wells, and the SAGD wells can eventually be
shut in. It is
also noted that the gas injection wells and at least one of the SAGD well can
both be
operated to inject NCG in the context of such wind-down operations.
[0041] It is to be noted that even though some of the drawings and
implementations refer
to a SAGD operation, 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 modify the
viscosity of the
hydrocarbons 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 (e.g., paraffinic or
aromatic
solvents), that may be at ambient or higher temperatures, can also be injected
into the
formation alone, co-injected with steam, or injected in an alternating manner
with steam
to help mobilize the hydrocarbons. In addition, other heating methods can be
used, alone
or in combination with mobilizing fluid injection, to help mobilize the
hydrocarbons for
gravity drainage. Furthermore, the in-situ recovery process can be implemented
using a
well pair that includes an overlying injection well and an underlying
production well;
however, other well configurations are possible, such as a single horizontal
well setup that
has injection and production capabilities (e.g., single-well SAGD). Typically,
a lean zone
that is pressurized will overly a main pay zone that has multiple wells or
well pairs deployed
and operating, e.g., forming an array of well pairs with horizontal portions
extending
substantially parallel to each other and being fluidly connected to a well pad
at surface.
The implementations described below in the context of SAGD or referring to
SAGD are
thus not intended to be limited to SAGD applications.
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Characterization of hydrocarbon-lean zones
[0042] Referring to Fig 1, the gas injection is performed into a water-
containing,
hydrocarbon-lean zone 10 (also referred to herein as a "lean bitumen zone" or
"lean
zone"). 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 in-
situ hydrocarbon
recovery wells can be located. It should be understood that the main pay zones
14 are
regions that include higher saturation of hydrocarbons, such as heavy oil or
bitumen, than
the lean zone 10, and that the hydrocarbons 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, which can include only steam injection or steam and
solvent
injection. Other techniques include cyclic steam stimulation (CSS), in-situ
combustion,
steam flooding, and solvent-assisted methods.
[0043] In some alternative implementations, the lean zone 10 may be located
beside or
below the main pay zone, and the gas injection techniques may be adapted
accordingly
to account for the different characteristics of the overall formation 12, such
as an
underlying lean zone would could have higher pressures. A lean zone may be one
or
several square kilometers, for example, and may have bitumen saturation below
50%,
high water saturation, and low pressure. In some implementations, the lean
zone has less
than approximately 8% to 10% bulk mass fraction of oil and less than about 10%
to 30%
vol. of clay.
[0044] It should be understood that lean zones are regions of an overall
formation that
generally have higher water-saturation and/or lower pressure compared to a
proximate
(e.g., adjacent, overlying or underlying) 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, which can lead to
steam loss
to the lean zone and 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.
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[0045] Referring to Fig 8, 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 the pressurization and
maintenance of
a gas-enriched region, as water migration into the lean zone is reduced.
Character 124 in
Fig 8 indicates a bitumen-rich reservoir.
[0046] Candidate lean zones for pressurizing can also be identified using a
number of
techniques and can be based on various characteristics of the lean zone and
the
underlying pay zone, as well as economic analyses. Lean zone characteristics
such as
size, structure type, bitumen saturation, water saturation and pressure can be
identified in
order to determine whether the gas injection process would be economical. For
instance,
a lean zone having a dome structure may require less gas injection wells to
reach a
desired pressure, in contrast to a lean zone having a flat structure (see Fig
10 showing
simulation results for dome versus flat geologies).
[0047] Referring to Fig 6, for example, lean zones 10 may vary in thickness
and elevation.
A lean zone 10 can also include regions having different thicknesses. In some
scenarios,
a lean zone can have a tapered shape. Lean zones typically having a thickness
(h) ranging
between about 3 meters and about 20 meters are candidates for pressurizing
according
to techniques described herein. These different thicknesses can influence the
number of
wells in a particular region, as well as the distance between the gas
injection wells. For
instance, for a region having a relatively small thickness, such as a
thickness between
about 5 to about 10 meters, a lower number of gas injection wells may be
provided to
reach the desired pressurization since the lean zone has a smaller volume to
receive the
injected gas compared to a region of the lean zone that has a larger
thickness. Similarly,
the gas injection wells in a lean zone having a small thickness may be
positioned further
apart from each other, since a single gas injection well can provide a
sufficient amount of
gas to pressurize that region of the lean zone compared to a region of the
lean zone that
has a larger thickness. Fig 6 illustrates an example of a series of lean zones
having
different thicknesses and gas injection wells that are located in accordance
with the given
geology and thickness of each lean zone.
CA 2988709 2017-12-13
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[0048] Fig 8 illustrates a combined lean zone, which is made up of several sub
lean zones
10, and is geologically-contained. In some implementations, the gas injection
process
described herein can be replicated over various portions of a reservoir as the
underlying
pay zones are developed. For instance, gas injection wells can be added as new
portions
of a reservoir are being operated to produce hydrocarbons and/or are
approaching the
overlying lean zone, while other gas injection wells become further away from
active
production areas of the reservoir and can be shut down or run at a reduced gas
injection
rate. The gas injection wells can therefore be managed depending on the status
and
maturity of the underlying in-situ recovery wells and the corresponding
pressures in the
mobilized chambers in the main pay zones.
Pressurization and displacement of water from hydrocarbon-lean zone
[0049] Referring to Fig 1, a gas injection well 20 is provided in the lean
zone 10 and is
configured for injecting gas 22, such as NCG, into the lean zone 10 to form a
gas-enriched
region, or gas cap. It is to be understood that the gas cap can also be
referred to as a
secondary gas cap, as known in the art. The secondary gas cap is a gas cap
that is formed
following gas injection, in contrast to a primary gas cap that would be
naturally occurring.
In Fig 1, the gas injection well 20 is a vertical well having a lower end near
the top of the
lean zone 10. Referring to Fig 5, the gas injection well 20 can also include a
vertical portion
having an upper end and a lower end, and a horizontal portion extending from
the lower
end of the vertical portion, thus forming a substantially L-shape gas
injection well with a
heel and a toe, which can also be referred to as a horizontal gas injection
well. The gas
injection well 20 can also be at other orientations, such as slanted and/or
directionally
drilled based on the shape and geology of the lean zone, e.g., flat versus
domed versus
slanted, to follow the contour of the boundary region 24 of the lean zone 10
or to follow
another desired trajectory (see Figs 12A to 12D). Figs 14A to 14E depict other
examples
of gas injection wells having an orientation at least in part based on the
shape of the lean
zone. It should also be noted that in implementations where a lean zone is
located above
a hydrocarbon-rich reservoir, the lean zone is not necessarily a zone that
includes the
boundary region with the ground surface as shown illustratively in Figs 1, 4A-
4D, 7 and 9.
Indeed, there would often be at least one other zone located above the lean
zone before
ground level is reached.
CA 2988709 2017-12-13
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[0050] Referring to Figs 11A to 11E, various well arrangements are illustrated
for gas
injection wells and underlying in-situ recovery wells. The gas injection wells
can be
horizontal and arranged to be perpendicular or slanted with respect to the in-
situ recovery
wells. The gas injection wells can be positioned closer to the heels or toes
or the middle
of the in-situ recovery wells. The gas injection wells can be multilateral
wells that have
branches extending over the area of the lean zone. The gas injection wells can
be parallel
with respect to the in-situ recovery wells, and can be located in between two
adjacent in-
situ recovery wells or directly above and aligned with corresponding in-situ
recovery wells.
The gas injection wells can also include a combination of horizontal and
vertical wells.
[0051] The gas injection wells 20 can be provided with suitable apertures,
perforations,
screens or other means of fluid communication with the lean zone in order to
allow gas
injection. The gas injection well 20 can also have completions according to
various
characteristics of the lean zone. For example, slotted liners or screens may
be used in the
gas injection well 20 in the event that sand production or blockage are
potential problems.
[0052] When water is displaced from a certain region of the lean zone due to
gas injection,
it can be said that the region has been "dewatered", although water has not
been produced
from the formation. In other cases, when a water production well is used, the
lean zone
can be dewatered by removal of water from the lean zone via the water
production well.
[0053] Referring still to Fig 1, the lean zone 10 is in fluid and pressure
communication
with the hydrocarbon-rich reservoir 14. In some implementations, the gas
injection wells
20 have a lower end that is located in a bottom section of the lean zone 10,
for instance
within the lean zone 10 proximate to a boundary region 24 that separates the
lean zone
and the hydrocarbon-rich reservoir 14. In some scenarios, the boundary region
24 is
defined by the region having a high saturation of heavy hydrocarbons, the
region forming
a substantial barrier to gas injection at the gas injection pressures used to
inject the gas
into the lean zone 10, for instance due to a low mobility of the heavy
hydrocarbons at initial
conditions. Gas that may reach the boundary region 24 is impeded from passing
into the
hydrocarbon-rich reservoir 14 and thus advances laterally within the lean zone
10 and
forms a gas cap over the hydrocarbon-rich reservoir 14. In other
implementations, the
lower end of the gas injection well is located in a middle or an upper section
of the lean
zone 10. Yet in other implementations, the lower end of the gas injection well
extends
beyond the boundary region 24.
CA 2988709 2017-12-13
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[0054] With reference to Figs 16A to 16D, whether the gas injection well
extends along
an entire thickness of the lean zone, or only along a portion thereof, the
apertures,
perforations, screens or other means of fluid communication with the lean zone
can be
provided along different injection sections of the gas injection well. In such
implementations, the injection sections can be delimited for instance with
isolations
packers 52 or blanks. Fig 16A shows an example of a gas injection well
extending beyond
the boundary region that includes an isolation packer positioned near the
boundary region
24 such that the injected gas remains injected within the lean zone 10. Figs
16B to 16D
show examples of a gas injection well 20 extending along substantially an
entire thickness
of the lean zone 10, with apertures provided throughout the height of the gas
injection well
20 (Fig 16B) or along portions thereof (Figs 16C and 16D). These Figs
illustrate different
possible configurations for apertures provided along a vertical gas injection
well, and can
be located depending on geological characteristics of the lean zone, evolution
of the gas
injection, and various other factors.
[0055] With reference to Fig 14D, two injection sections are provided along a
horizontal
gas injection well in regions of higher thickness of the lean zone compared to
a middle
section thereof having a smaller thickness. The positioning of the gas
injection along the
height, or thickness, of the lean zone 10 can be determined according to the
characteristics of the lean zone 10, as will be described in more detail
below.
[0056] Referring back to Figs 14A to 14C, in some implementations, the lean
zone 10 has
a tapered shape, similar to a pinch out reservoir. The tapered lean zone
includes a thinner
portion at the toe and a thicker portion at the heel. When the tapered lean
zone is located
above a hydrocarbon-rich reservoir 14 also having a tapered shape such that
both
narrower portions of the tapered lean zone and of the hydrocarbon-rich
reservoir are
superposed, an end portion 54 of the gas injection well 20 may end up being in
close
proximity to the end portion 56 of the SAGD well pair. With such superposition
of the lean
zone 10 and of the underlying tapered hydrocarbon-rich reservoir 14 is
present, care has
to be taken to prevent the gas injected through the gas injection well from
being short-
circuited through the production well of the SAGD well pair and produced back
without
having contributed to pressurizing the lean zone. Indeed, since the gas is
injected in close
proximity of the boundary region 24 between the tapered lean zone and the
tapered
hydrocarbon-rich reservoir, as the hydrocarbons are being pumped out of the
production
well of the SAGD well pair, there is a possibility that the injected gas
reaches the
CA 2988709 2017-12-13
17
hydrocarbon-rich reservoir 14, and is then pumped up with hydrocarbons through
the
production well 40. Isolation packers can be provided at various locations
along the gas
injection well, for instance in the end portion 54 thereof, so that the gas is
injected
upstream of the end portion 54, in a region of the lean zone 10 that is
thicker, thereby
contributing to prevent such short-circuit. With reference to Fig 14B, the gas
injection well
20 can also be provided with a different orientation so that it remains within
the thicker
portion of the lean zone and that gas is injected into a thicker region of the
lean zone 10.
[0057] In some implementations, the number of gas injection wells, their
position through
the thickness of the lean zone and their layout in relation to one another is
determined at
least in part according to information gathered from numerical reservoir
simulation results,
which can permit estimating the size of a resulting gas cap following gas
injection with a
given number of gas injection wells disposed in a particular layout, and for a
given period
of time, based on the thickness of the lean zone and properties of the lean
zone such as
its permeability, porosity and water saturation level. Hence, gas injection
well layouts can
be provided depending on the size, structure and geological properties of the
lean zone
and surrounding formation properties. For instance, for a lean zone having a
thickness
between about 10 meters and about 15 meters, gas injection wells can be about
200
meters to about 400 meters away from one another so that sufficient gas can be
injected
in relatively close proximity to form respective gas enriched-regions that
contribute to
increase the pressure in the lean zone 10. In some scenarios, for a lean zone
having a
thickness above about 15 meters, the gas injection wells can be positioned
closer to each
other so that a desired pressure in the lean zone can be reached, whereas for
a lean zone
having a thickness below about 10 meters, the gas injection wells can be
positioned further
away from each other.
[0058] In another example, for a lean zone having a thickness between about 10
meters
and about 15 meters, one to three gas injection wells may be required to
achieve lean
zone pressurization, the gas injection wells being about 200 meters to about
400 meters
apart when more than one injection wells are present. The number of gas
injection wells
can also vary depending on their characteristics, for instance whether the gas
injection
wells are horizontal or vertical. For example, for a given lean zone, one to
three vertical
gas injection wells may be provided to pressurize the lean zone, compared to
one to two
horizontal gas injection wells for the same lean zone.
CA 2988709 2017-12-13
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[0059] It is to be noted that it is generally advantageous not to position gas
injection wells
too close to one another to avoid the gas-enriched regions to coalesce into a
single
combined gas-enriched region. Gas region coalescence can cause the injected
gas to
tend to move upwardly, which can reduce the efficiency of the pressurization
of the lean
zone and the contribution of the injected gas to displace water, compared to
gas-enriched
regions that remain distinct from each other. On the other hand, it is also
generally
desirable that the gas injection wells are positioned not too far away from
one another, for
instance more than about 2 kilometers apart, such that the pressurization of
the lean zone
becomes less efficient.
[0060] In addition, it is to be understood that once a particular gas
injection well number,
positioning and layout has been determined to be operational or advantageous
for a given
lean zone, it may be desirable to revise that particular configuration as time
passes and
hydrocarbon production is occurring, for instance to adapt to various changes
that could
occur over time in the overall formation 12, such that some gas injection
wells can
eventually be shut down, and new gas injection wells can be drilled and
operated. For
example, in some scenarios, two adjacent gas injection wells can be operated
for a period
of time, and then a third infill gas injection well can be deployed in between
the two initial
gas injection wells to provide gas and corresponding pressurization
therebetween.
[0061] In some implementations, the fluid that is injected into the gas
injection well 20 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 10. Due to lower densities, NCG remains within the lean zone 10 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 also
be a
produced gas from a SAGD operation. The NCG can penetrate into higher-
permeability
layers, sandy hydrocarbon-bearing layers as well as water-saturated layers
within the lean
zone, depending on location and rate of injection. The NCG can be selected
according to
process economics, gas inventories, existing infrastructure, and/or desired
effects within
the lean zone.
CA 2988709 2017-12-13
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[0062] In some implementations, the gas is methane or natural gas that is
available
proximate to the surface facilitates for the in-situ hydrocarbon recovery
operation. For
example, when high pressured natural gas from a pipeline is used as a fuel for
steam
generation (e.g., using a once through steam generator (OTSG), direct contact
steam
generator (DCSG), or another type of boiler or steam generator), the same
source of
natural gas used for fuel can also be used as a source of gas for lean zone
injection. Thus,
existing pipelines, tankage, and other infrastructure can be leveraged for
lean zone gas
injection operations using natural gas or other types of light hydrocarbon
fuels that may
be used.
[0063] In some implementations, the injected gas is different from existing
gases that may
be native to the reservoir such as native 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 (e.g., a mixture of N2 and CO2, a
mixture of CH4
and H2, or N2 and natural gas). In some implementations, the mixture of CH4
and H2 is a
lean gas mixture coming from a bitumen upgrader facility, and contains up to
about 10%
vol. of H2.
[0064] In some implementations, the gas is pre-treated at surface prior to
being injected
into the lean zone. Pre-treatments can include 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.
[0065] In some implementations, different gases can be injected at different
times and/or
different locations. For example, referring to Figs 3D and 4D, a first NCG can
be injected
via the gas injection well 20, and a second NCG can be injected via a
secondary gas
injection wells 36. In addition, an initial NCG can be injected into all of
the gas 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 or modify
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.
CA 2988709 2017-12-13
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[0066] In some implementations, the injection fluid is not an 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.
Operation of the gas injection wells
[0067] Referring to Figs 3A to 3D, the general operation and monitoring of the
gas
injection wells will be described. The gas injection well 20 is operated to
inject NCG into
the lean zone 10 to increase the lean zone pressure, for instance close to
SAGD operating
pressures, and displace water therefrom, thus reducing steam leak-off and heat
loss from
the steam chamber to the lean zone 10 by forming a pressurized gas cap over
the
hydrocarbon-rich reservoir 14.
[0068] In some implementations, the water saturation in the lean zone is about
45 vol%.
In such implementations, the injection of gas in the lean can advantageously
reduce the
water saturation to between about 20 vol% and about 25 vol%, with a gas
saturation of
between about 15 vol% and about 20 vol%. In some implementations, an injection
of gas
corresponding to approximately twice the pore volume leads to a displacement
of up to
about 60% of the mobile water. The pressure in the lean zone prior to gas
injection can
be in the range of about 50 kPa to about 1000 kPa whereas the target pressure
in the
hydrocarbon-rich reservoir 14 can range, for example, from about 1500 kPa to
about 3500
kPa. The initial pressure of the lean zone can be measured using pressure
transient
analysis (PTA) by installing pressure gauges across the lean zone. This aspect
will be
described in further detail below. Increasing the pressure in the lean zone to
values close
to the pressure in the hydrocarbon-rich reservoir 14 can mitigate steam flow
from the
hydrocarbon-rich reservoir 14 to the lean zone 10. In some scenarios, the
pressure in the
lean zone 10 is within about 100 to about 200 kPa of the pressure in the
hydrocarbon-rich
reservoir 14. In other scenarios, the pressure in the lean zone 10 is up to
within about 700
kPa of the pressure in the hydrocarbon-rich reservoir 14. As mentioned above,
various
factors can influence the pressurization (e.g., the speed of pressurization)
of the lean zone
10, such as the permeability of the geological structure, its porosity and the
original water
saturation level. Permeability properties can be determined, for example,
based on core
samples, simulation modelling, well tests calculations and/or empirical
experimentation.
More regarding this aspect will be described in further detail below.
CA 2988709 2017-12-13
21
[0069] Referring now to Fig 3B, gas 22 is injected through the gas injection
well 20 into
the lean zone 10. The gas injection can be regulated by a gas injection
controller 32. It
should be mentioned that various flow control devices can be deployed at
surface and/or
downhole to regulate the gas injection rate via the injection well. The
downhole flow control
devices can facilitate gas injection into target areas of the lean zone by
opening or closing
or throttling certain devices along the injection well. For example, if
additional gas is
desired in the lower part of the lean zone, flow control devices in the upper
part can be
closed and flow control devices in a lower part can be opened.
[0070] As mentioned above, the gas pressurization can be done to achieve a
pressure
that is similar 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 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 10.
[0071] As shown in Fig 3B, the gas injection forms a gas-enriched region 34
that expands
outwardly from the gas injection well 20. The injection rate of the gas into
the lean zone
is performed at a rate that allows the formation of a gas-enriched region
having certain
characteristics. In some implementations, the gas injection rate varies
according to
pressurization stages in the lean zone, which can include for instance an
initial injection
stage and a maintenance stage. Gas injection rates can be determined based on
a
number of factors, including characteristics of the lean zone such as the
absolute
permeability of the porous medium in the lean zone 10, and the water
saturation and
distribution within the lean zone 10. Based on the water saturation level, the
effective water
mobility of the lean zone is influenced by the relative permeability of the
water phase and
the absolute permeability of the porous medium. For instance, the gas can
initially be
injected at an initial rate to allow buildup of the gas in the lean zone 10,
such as between
about 100 E3m3/d and about 300 E3m3/d. In some scenarios, the initial rate is
limited at
least in part by the fracture pressure and the capacity of the injection
valves or sprinklers.
Once pressures are balanced between the lean zone and the steam chamber, the
gas
can subsequently be injected at a pressure maintenance rate, which can be
similar or
CA 2988709 2017-12-13
22
different from the initial rate. In some implementations, the pressure
maintenance rate is
between about 10 E3m3/d and about 50 E3m3/d, which may be sufficient to
mitigate steam
leak-off from the steam chamber to the lean zone 10. Thus, in these
implementations, the
pressure maintenance injection rate is controlled to be relatively low, and
coordinated with
permeability of the lean zone, to facilitate pressurization that will provide
insulation and
pressurization for the thermal in-situ recovery operation. In some scenarios,
up to about
500 E3m3/d of gas can be injected in the lean zone 10, which over a period of
about 7 to
months, can lead to a lean zone including about 2.5 BCF to about 3.5 BCF.
[0072] It can be desirable to inject gas at different elevations through the
gas injection
well and thus new apertures can be provided or opened along the length of the
gas
injection well. In some implementations, the interval between the apertures
along the gas
injection well is determined according to the heterogeneity of the lean zone
and to the
vertical to horizontal permeability relationship. In some implementations,
perforations are
provided along substantially the entire length or height of the gas injection
well, depending
whether the gas injection well is vertical or horizontal, to facilitate an
even distribution of
the injected gas over the whole height of the lean zone or over a larger
radius, respectively,
which in turn can contribute to minimize gas override and increase volumetric
sweep
efficiency. In some scenarios, the lower extremity aperture of the gas
injection well is
closed, for example by using a sliding sleeve, and new apertures at a higher
elevation are
used for the gas injection in the gas injection well. Alternatively, the
injection of the gas
can be performed through apertures 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.
[0073] Referring to Fig 3C, as gas 22 is injected into the lean zone 10, the
gas-enriched
region expands outwardly and upwardly. In some implementations, the gas 22
that is
injected has low gas solubility in water at the temperature and pressure
conditions of the
lean zone 10. In some implementations, when the gas is injected proximate to a
cap rock
defining an upper generally-impermeable gas barrier, part of the gas-enriched
region 34
grows in a generally outward direction. 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. In some scenarios, the lean zone 10 can include existing gas-
saturated
zones, resulting in higher compressibility. In such scenarios, more gas can be
injected via
the gas injection well 20 in order to increase the lean zone pressure.
CA 2988709 2017-12-13
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[0074] Referring briefly to Fig 3D, in some implementations, after gas
injection has led to
the formation of a gas-enriched lean zone and displacement of water, secondary
gas
injection wells 36 can be added and gas injection can continue through all of
the gas
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.
[0075] In some implementations, once a given pressurization of the lean zone
10 is
reached, recovery of hydrocarbons in the main pay zone can start.
Alternatively, recovery
of hydrocarbons in the main pay zone can begin prior to gas pressurizing to
the target
pressure level, for instance when the hydrocarbon-rich reservoir is
particularly thick and
steam leak-off is expected to occur only after large steam chambers have been
generated.
Referring briefly to Figs 4C and 4D, in some implementations, following the
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 4C illustrates the formation of SAGD
steam
chambers, and Fig 4D illustrates the growth of the SAGD steam chambers toward
the gas-
enriched lean zone.
Monitoring of gas injection operations
[0076] The pressurization of the lean zone 10 can be monitored according to
various
techniques. A first technique based on mathematical relationships between flow
rate,
pressure and time, called pressure transient analysis (PTA), allows estimation
of the size
and shape of the gas-enriched region around a gas injection well. In an
implementation of
the PTA technique, a gas injection well 20 is shut in and the rate of pressure
fall-off is
measured. The gas injection well can be equipped with pressure sensing
instrumentation
that is downhole and may be distributed along the relevant section of the
injection well
within the lean zone. Surface pressure sensors can also be used. The rate of
pressure
fall-off obtained is indicative of the size of the gas-enriched region
surrounding that
particular gas injection well. Performing this type of technique at multiple
locations in the
lean zone 10 can facilitate the mapping of the gas-enriched region. By having
a better
overview of the shape and size of the gas-enriched region, decisions can be
made
regarding the operation of the gas injection wells, such as whether to add
more gas
CA 2988709 2017-12-13
24
injection wells at given locations or to shut in gas injection wells at other
given locations,
adjust the gas injection rate, and so on.
[0077] In some implementations, the water contained in the lean zone 10 or a
portion
thereof is monitored for gas content in order to determine whether injected
gas has
advanced through the lean zone 10. A gas detector 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 2, the observation wells 30 being equipped with appropriate devices for
directly
and/or indirectly detecting gas and relaying the information so that certain
appropriate
actions 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,
such as pressure data. In an example scenario, an observation well is equipped
with
pressure gauges to monitor the extent of the gas-enriched region. A first
pressure gauge
is installed in an upper region of the lean zone and a second pressure gauge
is installed
in a lower region of the lean zone, at a predetermined distance from the first
pressure
gauge. It can then be inferred from the pressure differential between the
first and the
second pressure gauges whether a water or gas column is present in the lean
zone at the
location of a given observation well. For instance, for a distance of 10
meters between the
first and the second pressure gauges, if the pressure differential is
approximately 100 kPa
(the pressure at the bottom of the observation well being higher than the
pressure at the
top thereof), it can be indicative that water is present in the observation
well. However, if
the pressure differential is lower than what would be dictated by the presence
of water
only, it can be indicative that gas is also present in the observation well.
[0078] Volumetric estimates can also be performed, such as measurement of the
volumetric sweep efficiency, which evaluates the mobility of fluids by
determining the
proportion of the volume of the lean zone that has been contacted with the
injected gas.
In some implementations, a 10% to 15% volumetric sweep efficiency in a lean
zone having
a radius of about 1.2 kilometers and a thickness of about 2 meters or more can
be
obtained. Different volumetric sweep efficiencies can be obtained depending on
the
operating conditions of the gas injection wells and reservoir parameters such
as
permeability, thickness and structure.
CA 2988709 2017-12-13
25
[0079] Reservoir saturation logs can be used to characterize the geological
formation
penetrated by a gas injection well or an observation well, and provide
insights into certain
profiles along the depth of the gas injection well or the observation well by
evaluating
parameters such as the density, the porosity, and the resistivity log
responses. For
instance, in an overall formation, a low resistivity can be associated with a
high water
saturation and thus be indicative of the presence of a lean zone. In contrast,
a higher
resistivity can be indicative of a region having higher saturations of
bitumen. In some
implementations, several saturation logs are obtained over a period of time to
monitor the
gas and water displacements, which can facilitate the process of mapping the
gas cap
and the monitoring of the gas leaks off of the lean zone.
[0080] Time lapsed seismic, also referred to as 4D seismic, is another
technique that can
be used to monitor the water saturation level in the lean zone and evaluate
the size of the
lean zone, by evaluating the changes in the acoustic and elastic properties of
the
geological formation. In such 4D seismic analysis, changes in amplitude and
velocity are
compared with baseline seismic interpretation, and maps are then generated to
monitor
the size, or extent, of the gas cap.
[0081] 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 10 via the gas injection wells 20. The tracer
chemical can be
injected in various ways, such as co-injected with the NCG via one, more or
all of the gas
injection wells, or other injection means. Tracer chemicals can be for gas
phase, water
phase or oil phase tracing. 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). Tracer chemicals can thus be
used in
connection with various aspects of the operations described herein, for
various purposes,
such as detecting gas breakthroughs, detecting and tracking water
displacement, and so
on.
Managing thermal in-situ operations and lean zone interactions
[0082] Referring to Figs 4A to 40, the gas pressurization can be conducted on
a lean
zone 10 above a main pay zone 14 in which SAGO occurs. In some
implementations, the
CA 2988709 2017-12-13
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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 gas pressurization and the SAGD operation. For example, the gas
pressurization
can be commenced prior to drilling the SAGD wells or prior to start-up of the
SAGD wells.
Alternatively, the 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.
[0083] Referring to Figs 4A and 4B, the gas injection well 20 is operated to
establish a
gas-enriched lean zone 10 prior to operating SAGD in the underlying main pay
zone 14.
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 4C illustrates SAGD well pairs each including 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.
[0084] Referring to Fig 4D, 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.
[0085] Figs 4A to 4D illustrate the 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 and hydrocarbon
distribution in the pay zones. As new arrays of SAGD wells are provided and
operated,
CA 2988709 2017-12-13
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new gas injection wells can also be provided in close proximity thereto to
form a gas-
enriched region that follows the SAGD operations.
[0086] Referring to Fig 7, the pressures PG and P
= SAGO can both be monitored and adjusted
so that the AP is within a desired range. For instance, during early steam
chamber
development, the pressure difference (AP) between the pressure of the gas-
enriched
region 34 (PG) and the pressure of the underlying SAGD steam chamber pressures
(PsAGD)
can be maintained within 200 kPa. 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. 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 10, 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.
[0087] As mentioned above, the gas pressurization of the lean zone provides an
insulation
layer and pressurization above the thermal in-situ recovery operation to
reduce heat and
fluid losses to the hydrocarbon-lean zone due to advection and to help delay
the
development of the steam chambers into the lean zone. In addition, a
pressurized lean
zone 10 can encourage lateral growth of the steam chambers 42 within the main
pay zone
14. This promoted lateral growth of steam chambers 42 can also delay the steam
chambers 42 expanding into the lean zone 10 and increase hydrocarbon recovery
and
production rates since higher saturations of hydrocarbons are typically found
in such
lateral directions within a main pay zone 14.
Recovery of injected gas after in-situ recovery operations
[0088] Referring to Fig 9, when an in-situ recovery operation has reached
maturity, and/or
a desired hydrocarbon recovery factor has been achieved in a given pay zone, a
portion
of the gas that has been injected into the lean zone can be produced back and
recycled
in various other processes. In some implementations, it can be advantageous to
produce
back the injected gas for re-injection into a formation, for injection into
another
hydrocarbon-lean zone, or for use in an enhanced oil recovery (EOR) process.
In addition,
when the non-condensable gas comprises a light hydrocarbon, such as methane,
the
CA 2988709 2017-12-13
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recovered non-condensable gas component can be used as a fuel for steam
generation
or heating processes.
[0089] As shown in Fig 9, producing back the non-condensable gas can include
recovering a mixture 44 comprising a portion of non-condensable gas and water
from the
hydrocarbon-lean zone. The mixture can also include other components that are
present
in the lean zone, such as oil. Once the mixture is produced to the surface, it
can be
processed in various ways. For example, the mixture can be separated according
to
known methods of gas-liquid separation, thus producing a recovered non-
condensable
gas component and a water component.
[0090] In some implementations, the gas injection well can be converted to a
production
well 46 to produce back the injected gas. Alternatively, new wells can be
drilled and
operated for producing the mixture. The gas production wells can be operated
in various
ways to enhance gas recovery from the lean zone, for example by using flow
control
devices to promote flow of gas from certain parts of the lean zone with high
gas saturation
and low water saturation. The composition of the mixture can be monitored over
time to
assess gas content, and once the gas content notably decreases the production
can be
ceased or adjusted. In other implementations, the gas injection well can also
be converted
to produce bitumen and/or water present in the lean zone.
[0091] In addition, in some cases, the presence of the gas in the lean zone
can alter
properties of various components in the lean zone, and such changes can later
be
leveraged advantageously. For example, some NCG such as CO2 and methane can
reduce the viscosity of heavier hydrocarbons, such as bitumen, particularly
when allowed
to remain in contact with the bitumen over longer periods of time. Thus, when
the lean
zone includes heavy oil or bitumen that has been mobilized due to contact with
the injected
gas, the mixture 44 that is produced can include mobilized hydrocarbons from
the
reservoir that can be recovered. In such cases, the mixture can be subjected
to a
separation process at surface to produce a hydrocarbon enriched component for
further
processing or transportation, and a hydrocarbon depleted component. In some
implementations, the mixture 44 is fed into a gas separator to recover gas,
and then is fed
into a water-hydrocarbon separator to recover a hydrocarbon enriched
component. The
resulting produced water component can be recycled in various ways, e.g.,
supplied to a
water treatment facility prior to being used as boiler feed water in an OTSG,
or supplied
CA 2988709 2017-12-13
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directly to a DCSG. In some cases, the mixture can be directly supplied to a
DCSG such
that the water, gas, and recovered hydrocarbons produce a steam-and-0O2
mixture that
can be used for SAGD or other thermal in-situ recovery applications.
Managing mature overall formation through gas injection
[0092] Referring now to Figs 15A to 15E, there is shown a first mature overall
formation
12 adjacent to a second newer overall formation 112. The mature overall
formation 12 can
be for instance a formation that has reached a decrease in hydrocarbon
production and/or
an increase in SOR, and wind-down strategies are thus put into place to
maximize the
presence of the mobilizing fluid chambers, in particular in terms of heat and
pressure
already provided by the presence of the mobilizing fluid. In a first stage of
the wind-down
strategy, gas is injected into the hydrocarbon-lean zone 10 of the mature
overall formation
12 that includes a first array of SAGD well pairs 38, 40 through gas injection
wells 20, and
provides an insulation layer and pressurization above the hydrocarbon-rich
reservoir 14.
It should be noted that the gas injection wells can be operated as per other
methods
described herein while the SAGD well pairs are operating normally, to form a
gas-enriched
lean zone. Once the SAGD well pairs become inefficient or uneconomical, wind-
down can
be initiated.
[0093] The second overall formation 112 is exploited by operating a second
array of
SAGD well pairs 138, 140 in the hydrocarbon-rich reservoir 114. The drilling,
completion
and operation of the recovery wells in the second overall formation 112 can
occur several
years after recovery from the first overall formation 12 has been initiated,
although
sequential timing is not necessarily required. The main concept is that the
recovery
process in the first overall formation is entering wind-down while the
recovery operation in
the second overall formation is still operational or will be operational at
higher pressures
than the first. The lean zone gas injection wells in the first overall
formation can thus be
leveraged to pressurize the first overall formation in order to reduce
pressure differential
with-respect to the second overall formation.
[0094] Still referring to Figs 15A to 15D, additional gas injection wells 120
can be provided
in the overlying hydrocarbon-lean zone 110 to pressurize the lean zone. These
gas
injection wells can be operated in a similar manner as the gas injection wells
20 in the first
lean zone when the recovery process operating in the first pay zone was in
normal
CA 2988709 2017-12-13
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operation (prior to wind-down). In a second stage of the wind-down strategy,
gas continues
to be injected in the mature overall formation 12 such that the mobilizing
fluid chambers
42 and the injected gas form a combined gas-enriched region 148 that
pressurizes the
mature overall formation 12 and provides an insulation layer along the newer
overall
formation 112 (see in particular Fig 15C). In addition to forming this
adjacent gas region,
the gas injection wells 120 above the newer overall formation 112 can be
operated to
inject gas into the corresponding lean zone 110 above the hydrocarbon-rich
reservoir 114
provide an insulation layer above the hydrocarbon-rich reservoir 114. Thus, as
shown in
Fig 15C, the newer hydrocarbon recovery process can be operated in a pay zone
that is
surrounded by gas-enriched pressurized regions to reduce heat and fluid loss.
Each
adjacent or proximate gas-enriched region can be pressurized to a pressure
near the
operating pressures of the recovery operation. It is noted that a given newer
recovery
operation can be surrounded on several sides by gas-enriched regions
corresponding to
natural lean zones (e.g., overlying lean zones) or process-affected lean zones
(e.g., with
a mature recovery system in wind-down).
[0095] In addition, as the newer overall formation 112 is operated and
recovery of
hydrocarbons starts to decrease, the newer overall formation 112 can then
become a
mature overall formation itself. As shown in Figs 15D and 15E, the combination
of both
mature formations can then become a single pressurized overall formation 150
that is
pressurized by gas injection via the gas injection wells 20, 120 in the
original lean zones.
It is noted that the pressurizing fluid in the formation is a mixture 152
comprising the
injected gas and the mobilizing fluid, and depending on the management of the
formation
the mixture can change over time (e.g., steam originally present would
eventually
condense as the temperature decreases and the gas content would thus
increase).
[0096] Similar to what is described hereinabove regarding the recovery of gas
injected in
a lean zone, a portion of the mixture 152 can be produced back from the single
pressurized
overall formation 150 and recycled in other applications (see Fig 15E with a
gas mixture
G being produced via one or more of the existing wells in the formation). For
instance, the
mixture 152 can be fed to a gas separator to recover gas, and then fed to a
water-
hydrocarbon separator to recover a hydrocarbon enriched component. The mixture
152
can be produced back by converting gas injection wells 20, 120 in production
wells to
produce back the mixture, and/or by operating one or more SAGD well as a
production
well. This wind-down strategy can be used for instance as hydrocarbon recovery
CA 2988709 2017-12-13
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operations are sequentially initiated and extended within a large formation,
with new
recovery wells being provided and operated. Thus, as the recovery operation
moves from
one region of a hydrocarbon-rich reservoir to another, the depleted zones can
be
pressurized to enhance operations.
RESULTS & SIMULATIONS
[0097] Various simulations were conducted to assess gas injection into
hydrocarbon-lean
zones.
[0098] With reference to Table 1 below, special core analysis laboratory
(SCAL)
experiments were performed to evaluate the potential effect of gas injection
into a
hydrocarbon-lean zone on the displacement of the gas and/or water contained
therein.
The SCAL tests were conducted on core samples taken from lean zone intervals.
The
core samples were first initialized to a saturation level representative of
the lean zone, and
then gas injection was started at a low rate to mimic the gas injection
process in the
reservoir. The results included in Table 1 suggest that with close to twice
the pore volume
of gas injection, the maximum fractional flow of gas can be reached.
Table
CUMULATIVE CUMULATIVE END-FACE
GAS WATER FRACTIONAL
INJECTED, RECOVERED, FLOW GAS-WATER
fraction Vp fraction Vp OF GAS RATIO
0.000 0.000 0.0000 0.00
0 020 0.016 0 0000 0 00
0.046 0.042 0.7592 3.15
0.074 0.068 0.9275 12.8
0.100 0.095 0.9556 21.5
0.130 0.122 0.9707 33.2
0.168 0.149 0.9811 52.0
0.200 0.176 0.9855 67.9
0.219 0.183 0.9874 78.5
0.253 0.186 0.9885 85.8
0.319 0.192 0.9902 101
0.449 0.200 0.9920 124
0.709 0.219 0.9940 166
1.21 0.241 0.9955 221
1.97 0.268 0.9968 315
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[0099] With reference to Fig 17, there is shown an example of the effect of
changes in
water saturation levels on the capillary pressure for different hydrocarbon-
lean zones and
hydrocarbon-rich reservoirs. In this context, capillary pressure refers the
pressure required
to be forced out of the porous media in which it is contained. Thus, the
pressure of injected
gas has to be high enough to overcome this capillary pressure before a
displacement
process can happen. The graph suggests that for these experiments, at minimum,
more
than half of the water contained in the hydrocarbon-lean zones is not affected
by the
capillary pressure, and thus can be mobilized.
[0100] With reference to Figs 18A and 18B, graphs illustrating pressure
variations in a
hydrocarbon-lean zone as a function of time are presented. In particular, Fig
18A shows
pressure variations with a depth correction for a pressure gradient of 10 kPa,
whereas Fig
18B shows pressure variations with a depth correction for a pressure gradient
of 1 kPa.
Figs 18A and 18B show that displacement of water due to gas injection changes
the
mobile fluid column, and thus changes the vertical pressure gradient measured
in an
observation well.
[0101] With reference to Fig 19, there is shown a graph depicting variations
in normalized
gas potential as a function of time with data points obtained from PTA. The
log-log
diagnostic plots are used to evaluate the change in the mobility of the gas
zones. The
comparison of the first data set (orange) with the second data set (blue)
shows an increase
in the size of gas zone over time. The first data set shows that the area
close to the
injection well has higher mobility, and after a certain radius R1, the
mobility is reduced due
to reduction of gas saturation and the thickness of gas zone. For the second
data set, this
phenomenon has occurred on a later date, i.e. the inflexion point is further
right on the
time scale, suggesting an increase in R1 and showing the progress of gas-
enriched region
in the lean zone.
[0102] With reference to Fig 20, there is shown a graph illustrating an
example of gas
injection rate over time in a hydrocarbon-lean zone and the cumulative gas
injection over
time, as well as the corresponding impact on pressurization of the hydrocarbon-
lean zone,
according to results from numerical reservoir simulations.
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