Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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A SYSTEM FOR CONFINING STEAM INJECTED INTO A HEAVY OIL RESERVOIR
TECHNICAL FIELD
[001] The present disclosure relates generally to in situ hydrocarbon recovery
and
particularly to increasing in situ recovery of hydrocarbons from Steam
Assisted Gravity
Drainage (SAGD) operations by reducing the flow of fluid between SAGD steam
chambers at various stages of maturity.
BACKGROUND
[002] Heavy oil and extra-heavy oil resources such as bitumen present
significant
technical and economic recovery challenges due to their high viscosities at
reservoir
temperature. Bitumen occurs within a subsurface hydrocarbon bearing zone of a
hydrocarbon reservoir as a semi-solid phase having a viscosity greater than
100,000
centipoise.
[003] An example of an in situ steam injection-based heavy oil recovery
process
which is effective at extracting oil from oil-containing reservoirs by
reducing viscosity of
the oil via steam injection is steam assisted gravity drainage (SAGD). A SAGD
system
includes at least one steam injection well and one oil production well (a
"well pair"). In
a well pair generally located in a bottom portion of the hydrocarbon bearing
zone of the
reservoir, an upper, generally horizontal injection well is used for injecting
a fluid such
as steam into the reservoir. The injected steam rises from the generally
horizontal
injection well and permeates the reservoir to form a vapor chamber which grows
over
time within the hydrocarbon bearing zone thereby increasing the temperature of
the
reservoir. The resultant mobilized bitumen and condensate will drain downward
through the reservoir under gravity and flow into a generally horizontal
production well
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disposed below the injection well from which the bitumen is produced. Several
well
pairs can be arranged within the reservoir to form a well pattern or a pad.
[004] SAGD generally involves four operational stages: start up, ramp up,
plateau
and wind down. In the start up stage, steam is circulated in both the
injection and
production wells for about two to four months to heat up the reservoir, which
results in
the creation of a "steam chamber". The term "steam chamber" relates to a
region in
the reservoir in which hydrocarbons, steam, steam condensate, and associated
non-
condensate gases are in communication with the injection wells. During start
up, as
the steam chamber grows from the injection wells, the hydrocarbons are heated
and
mobilized to subsequently drain into the production wells. In the ramp up
stage of
SAGD, the injection and production rates increase as the steam chamber grows
to the
top of the reservoir, which can take about six to eighteen months depending on
operating conditions and reservoir characteristics. In the plateau stage, the
steam
chamber has reached the top of the reservoir and begins to expand within the
reservoir, including lateral migration. This stage is characterized by peak
production
rates, which can last anywhere from eighteen to sixty months depending on
reservoir
quality and thickness. During the plateau stage, the steam chamber can be
considered
a generally undepleted immature operating steam chamber. The final wind down
stage
of SAGD occurs when steam chambers of adjacent well pairs begin to coalesce.
Bitumen production decreases because the majority of oil has been drained out
of the
SAGD chamber. For example, in the case of an Underground Test Facility (UTF),
the
wind down stage has been estimated to occur when bitumen recovery reaches
about
50-60%.
[005] Thermal efficiency of the SAGD process is measured by the cumulative
steam-
to-oil ratio ("cSOR"), which is the ratio of the cumulative volume of steam
injected to
the cumulative volume of oil produced. The higher the cSOR, the higher the
steam
usage, which means more natural gas is combusted per unit volume of produced
oil,
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and consequently the process is less economical. Conversely, a lower cSOR
implies a
more economical process. As the oil content in the SAGD operating steam
chamber
naturally declines, the cSOR increases. When, for example, the SAGD
operational
cost begins to out weigh the oil production value, it can no longer be
economically
viable to continue steam injection for the SAGD operation, at which time steam
injection can be reduced or discontinued for the pads or selected well pairs.
At this
stage, the steam chamber is referred to as partially depleted, substantially
depleted,
"mature" or "matured", depending on the degree of bitumen depletion, and is
generally
associated with a bitumen recovery factor above about 55 %.
[006] In commercial SAGD developments, groups of well pairs or pads are
initially
drilled and placed on production in a sufficient number so as to fill the
plant capacity.
When SAGD operations for one pad reach the wind down stage, oil production
from
the reservoir naturally begins to decline, and as the productivity of the
operational
wells decreases, additional SAGD well pairs in adjoining geographical areas
can be
added in the reservoir, which eventually can cover the entire reservoir field.
[007] A reservoir field as a whole will typically include pads or well pairs
at different
operational stages. For example, the reservoir field can include one or more
operating
pads from which hydrocarbon recovery is effective in proximity to one or more
matured
pads depleted in hydrocarbons to various degrees. When the pads or well pairs
reach
the stage of a desired level of depletion in hydrocarbons (i.e., become
"mature" or
"matured"), injection of steam into such pads or well pairs can cease to be
economical,
and can be stopped. Typically, steam injection is continued into immature
operating
pads or well pairs located adjacent the partially or substantially depleted
mature pads
or well pairs.
[008] When steam injection is reduced or discontinued in the partially or
substantially
depleted matured pad(s), the pressure in the chamber falls as the system
cools.
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Eventually, the mature chambers in such pads become "thief zones" for future
SAGD
operations in pads generally adjacent to the matured pads. The pressure within
the
matured pad(s) drops naturally to a level below the temperature and pressure
of the
generally immature operating pads, which creates a driving force for fluid
cross-flow
(e.g., cross-flow of steam) from the immature operating chambers into the
generally
adjacent matured chambers. The matured pad generally adjacent the immature
operating pad acts as a scavenger of steam and a heat sink for the adjacent
immature
operating pad, which reduces the effectiveness and productivity of the
operating pad.
[009] Several approaches have been proposed for alleviating the above-
mentioned
operational challenges. Examples of such approaches include cold water
injection with
stop steam injection, injection of non-condensable gases (NCGs) such as
natural gas
or nitrogen, co-injection of natural gas as a mixture in certain volumetric or
molar
proportions, blow-down or stage blow-down approaches, or injection of oxygen-
comprising gas. Another approach involves leaving a reservoir buffer zone
between
the operating steam chambers and the matured steam chambers. This buffer zone
approach effectively isolates or creates a physical barrier between the
chambers.
[0010] The prior art approaches have several disadvantages. For example,
injection of
NCGs or co-injection of NCGs with steam can cause a significant reduction in
the
temperature of the matured steam chamber. As a result, further injection of
costly
NCGs can be required to maintain the desired chamber pressure. Cold water
injection
reduces the temperature of the matured steam chamber more rapidly, and can
create
a low temperature heat sink within the reservoir. Furthermore, cold water
injection
does not utilize the heat stored in the matured steam chamber, and high water
mobility
can also impair the performance of adjacent operating steam chambers and
wells. The
blow down method leaves the matured steam chamber to cool, and with the
decrease
in temperature, the pressure drops, which results in the matured chamber
acting as a
pressure sink for adjacent operating chambers. The buffer zone approach
generally
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results in areas of the reservoir that will not be recovered. Moreover, using
the buffer
zone approach can result in more cost for additional steam and produced fluids
piping
to later re-develop the unrecovered buffer areas.
[0011] Therefore, increasing in situ oil recovery from hydrocarbon-containing
reservoirs
using thermal processes such as SAGD and improving the economic performance of
such processes remains challenging.
SUMMARY
[0012] There is provided a process for in situ processing of a hydrocarbon
reservoir. In
various aspects, the process includes selecting in the hydrocarbon reservoir a
first
steam chamber and a second steam chamber generally adjacent to the first steam
chamber, the first and second steam chambers having been processed using steam
assisted gravity drainage (SAGD) or undergoing or being capable of undergoing
further SAGD processing, the first and second steam chambers each having a
hydrocarbon content and an initial temperature, and the first steam chamber
having an
initial pressure lower than a pressure in the second steam chamber; selecting
a first
injection well in fluid communication with the first steam chamber, the first
injection well
being generally adjacent to the second steam chamber; selecting a second
injection
well in fluid communication with the first steam chamber, the second injection
well
being disposed away from the first injection well; injecting a non-oxidizing
gas through
the first injection well to form a pressurized non-oxidizing buffer zone
between the first
and second steam chambers to reduce a fluid flow between the first and second
steam
chambers; and injecting an oxygen-comprising gas through the second injection
well
to increase a pressure in the first steam chamber relative to the initial
pressure.
[0013] In various aspects, the method further includes sustaining combustion
in the
first steam chamber wherein production of hydrocarbons from the second steam
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chamber is increased relative to production of hydrocarbons recoverable from
the
second steam chamber without combustion of the oxygen-comprising gas into the
first
steam chamber.
[0014] In various aspects, forming the pressurized non-oxidizing buffer zone
can
increase production of hydrocarbons from the second steam chamber relative to
production of hydrocarbons recoverable from the second steam chamber without
formation of the pressurized non-oxidizing buffer zone.
[0015] In various aspects, the oxygen-comprising gas can be injected
concurrently with
the non-oxidizing gas.
[0016] In various aspects, the oxygen-comprising gas can be injected before
the non-
oxidizing gas.
[0017] In various aspects, injecting the non-oxidizing gas and the oxygen-
comprising
gas can be cyclical.
[0018] In various aspects, the first steam chamber can be at a later stage of
maturity
than the second steam chamber.
[0019] In various aspects, a boundary can exist between the first steam
chamber and
the second steam chamber.
[0020] In various aspects, a pressure difference between the first steam
chamber and
the second steam chamber following injection of the non-oxidizing gas and the
oxygen-comprising gas can be about 200 kPa or less.
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[0021] In various aspects, the second injection well can be vertically offset
from the
first injection well.
[0022] In various aspects, the fluid flow can comprise a flow of flue gas, a
flow of the
oxygen-comprising gas, a flow of steam, or a combination thereof.
[0023] In various aspects, a hydrocarbon content of the first steam chamber
can be
lower than a hydrocarbon content of the second steam chamber.
[0024] In various aspects, hydrocarbons can be produced from the first steam
chamber, the second steam chamber or both the first and second steam chambers.
[0025] In various aspects, the first and second injection wells may have been
previously used for fluid injection.
[0026] In various aspects, the first injection well or the second injection
well has been
previously used for steam injection.
[0027] In various aspects, the non-oxidizing gas, the oxygen-comprising gas or
both
can be injected proximate a lower portion of the reservoir.
[0028] In various aspects, a concentration of oxygen in the oxygen-comprising
gas can
range from about 5% to about 100%.
[0029] In various aspects, the oxygen-comprising gas can be air, oxygen-
enriched air,
or a combination thereof.
[0030] In various aspects, the oxygen-enriched air can comprise a
concentration of
oxygen above about 21%.
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[0031] In various aspects, the non-oxidizing gas can be methane, nitrogen,
carbon
dioxide, or a combination thereof.
[0032] In various aspects, the non-oxidizing gas, the oxygen-comprising gas or
both
can be wet or dry.
[0033] In various aspects, more than one injection well can be selected as the
first
injection well, the second injection well or both.
[0034] In various aspects, an in situ process for treating a hydrocarbon
reservoir
includes selecting in the hydrocarbon reservoir a first steam chamber and a
second
steam chamber generally adjacent to the first steam chamber, the second steam
chamber situated so that a boundary exists between the first steam chamber and
the
second steam chamber, the first and second steam chambers having been
processed
using steam assisted gravity drainage (SAGD) and undergoing or being capable
of
undergoing further SAGD processing, the first and second steam chambers each
having a hydrocarbon content and an initial temperature, and the first steam
chamber
having an initial pressure lower than a pressure in the second steam chamber;
selecting a first injection well in fluid communication with the first steam
chamber; and
injecting an oxygen-comprising gas through the first injection well and
sustaining
combustion in the first steam chamber to increase a pressure in the first
steam
chamber relative to the initial pressure and reduce a fluid flow between the
first and
second steam chambers, wherein production of hydrocarbons from the boundary is
increased relative to production of hydrocarbons recoverably from the boundary
without injection of the oxygen-comprising gas into the first steam chamber.
[0035] In various aspects, the first steam chamber can be at a later stage of
maturity
than the second steam chamber.
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[0036] In various aspects, a pressure difference between the first steam
chamber and
the second steam chamber following injection of the oxygen-comprising gas can
be
about 200 kPa or less.
[0037] In various aspects, the fluid flow can comprise a flow of flue gas, a
flow of the
oxygen-comprising gas, a flow of steam, or a combination thereof.
[0038] In various aspects, a hydrocarbon content of the first steam chamber
can be
lower than a hydrocarbon content of the second steam chamber.
[0039] In various aspects, hydrocarbons can be produced from one or more of
the first
steam chamber, the second steam chamber and the boundary.
[0040] In various aspects, the first injection well may have been previously
used for
fluid injection. In various implementations, the fluid is steam.
[0041] In various aspects, the oxygen-comprising gas can be injected proximate
a
lower portion of the reservoir.
[0042] In various aspects, a concentration of oxygen in the oxygen-comprising
gas can
range from about 5% to about 100%.
[0043] In various aspects, the oxygen-comprising gas can be air, oxygen-
enriched air,
or a combination thereof.
[0044] In various aspects, the oxygen-enriched air can comprise a
concentration of
oxygen above about 21%.
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[0045] In various aspects, the oxygen-comprising gas can be wet or dry.
[0046] In various aspects, more than one injection well can be selected as the
first
injection well.
[0047] The methods as described herein can reduce a fluid cross-flow between
operating
and matured steam chambers.
BRIEF DESCRIPTION OF THE DRAWINGS
[0048] In accompanying drawings which illustrate implementations of the
invention,
[0049] Fig. 1A illustrates a three dimensional schematic diagram showing a
configuration
of multi-pad patterns of well pairs for SAGD operations, including a matured
steam
chamber generally adjacent an operating steam chamber;
[0050] Fig. 18 illustrates a three dimensional schematic diagram showing a
configuration
of multi-pad patterns of well pairs for SAGD operations, including a matured
steam
chamber generally adjacent an operating steam chamber;
[0051] Fig. IC illustrates a three dimensional schematic diagram showing a
configuration
of multi-pad patterns of well pairs for SAGD operations, including a matured
steam
chamber generally adjacent an operating steam chamber;
[0052] Fig. 2 illustrates a schematic diagram of a well pair and injection of
an oxygen-
comprising gas through a selected horizontal portion of a former SAGD
horizontal steam
injection well configured for injection of the oxygen-comprising gas, upward
and lateral
propagation of a hot temperature front, and production of fluids (combustion
gas,
hydrocarbons) through a former SAGD production well;
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[0053] Fig. 3 illustrates a schematic diagram of a well pair and injection of
an oxygen-
comprising gas through a selected vertical portion of a former SAGD horizontal
steam
injection well configured for injection of the oxygen-comprising gas,
propagation of a hot
front from a heel of the injection well toward a toe of the injection well,
and production of
fluids (combustion gas, hydrocarbons) through a horizontal portion of a former
SAGD
production well;
[0054] Fig. 4 illustrates simulation results for two SAGD pads, Pad 1
including a matured
steam chamber and Pad 2 including an operating steam chamber, with four SAGD
well
pairs per pad;
[0055] Fig. 5 illustrates simulation results showing leaking of steam injected
into Pad 2 to
Pad 1 after steam injection was terminated in Pad 1;
[0056] Fig. 6 illustrates simulation results showing a comparison of the steam
chambers
subjected to and not subjected to injection of an oxygen-comprising gas (e.g.,
air) into
Pad 1 while steam is injected into Pad 2;
[0057] Fig. 7 illustrates a well layout of the non-oxidizing gas injectors and
a gas vent well
in Pad 1 and the SAGD operation wells in Pad 2;
[0058] Fig. 8 illustrates simulation results for combustion or oxidation
reactions occurring
within the matured SAGD chamber in Pad 1 after the oxygen-comprising gas is
injected
into Pad 1;
[0059] Fig. 9 illustrates simulation results showing mole fraction of methane
(the non-
oxidizing gas) staying in the area between the operating SAGD chamber in Pad 2
and
the top of the matured SAGD chamber in Pad 1; and
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[0060] Fig. 10 illustrates simulation results showing mole fraction of CO2
staying in the
area of the matured SAGD chamber in Pad 1.
DETAILED DESCRIPTION
[0061] In various aspects, methods for increasing in situ recovery of
hydrocarbons from
Steam Assisted Gravity Drainage (SAGD) operations by reducing a fluid flow
between
generally adjacent or generally proximate SAGD chambers at various stages of
maturity
or depletion (e.g., between a generally undepleted immature operating chamber
and a
partially depleted matured chamber, a substantially depleted matured chamber
or a
combination thereof) in a hydrocarbon-containing reservoir field are
described. In various
implementations, steam is injected into and confined within the operating
chamber,
reducing fluid cross-flow between generally adjacent or proximate chambers at
various
stages of maturity. In various implementations, the present process and
apparatus is
applicable to existing SAGD developments when the production at SAGD well(s)
in such
a development declines. In various implementations, new wells can be added
into the
reservoir.
[0062] In various implementations, the term "hydrocarbon" relates to mixtures
of varying
compositions including hydrocarbons in the gaseous, liquid or solid states,
which can be
in combination with other fluids (liquids and gases) that are not
hydrocarbons. The terms
"heavy oil", "extra heavy oil", and "bitumen" refer to hydrocarbons occurring
in semi-solid
or solid form having a viscosity in the range of about 100,000 to over
1,000,000 centipoise
(mPa.$) measured at original in situ deposit temperature. The terms
"hydrocarbon", "oil"
and "bitumen" are used interchangeably.
[0063] Heavy oil can be defined as any liquid petroleum hydrocarbon having an
API
gravity less than about 20 , specific gravity greater than about 0.933 (g/mt),
and
CPS I Doc. 284778
Date Recue/Date Received 2020-09-28
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viscosity greater than 100 centipoise (mPa.$). Oil can be defined as a
hydrocarbon
mobile at reservoir conditions. Extra heavy oil from the Orinoco region, for
example, can
be defined as having a viscosity of over 100 centipoise (mPa.$) and about 10
API
gravity. The API gravity of bitumen ranges from about 12 > API > about 7 and
the
viscosity is greater than about 10,000 centipoise (mPa.$). Bitumen is
generally non-
mobile at original reservoir conditions.
[0064] In various implementations, the term "reservoir" refers to a
hydrocarbon-
containing formation that can include a single formation or one or more
formations having
varying characteristics, which can also be viewed as individual "reservoirs".
A SAGD
reservoir is a formation which has been or is being processed using SAGD. The
SAGD
reservoir as a whole can include regions undergoing various stages of SAGD
operations
(e.g., operating immature steam chambers in ramp up and plateau stages,
partially or
substantially depleted matured steam chambers and coalesced steam chambers).
[0065] In various implementations, the terms "chamber", "steam chamber" or
"SAGD
chamber" generally relate to a region within the reservoir, and in particular
a hydrocarbon-
bearing zone of the reservoir, where reservoir fluids are in communication
with a
particular well or wells. In various implementations, the term "steam chamber"
relates to
the volume of the reservoir in which injected or mobile steam exists for an
extended
period of time. Within the steam chamber, rock temperature rises to a point at
which
steam vapor can be sustained at reservoir pressure conditions. In SAGD, the
steam
chamber is a region in which bitumen, steam condensate, and associated non-
condensate gases in the reservoir are in communication with a steam injection
well and
where mobilized hydrocarbons primarily drain into a production well. With
time, the steam
chamber can expand to cover an entire area of a pad development ("Thermal
Recover
of Oil & Bitumen", Roger
CPS I Doc. 284778
Date Recue/Date Received 2020-09-28
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M.Butler, 1991, ISBN 013-914953-8, pp.287-289, Prentice Hall, Englewood
Cliffs, New
Jersey 07632).
[0055] In various implementations, the steam chamber in the SAGD reservoir has
generally uniform temperature and pressure. Depending on the stage of a
particular
SAGD process, the steam chamber can be a relatively high pressure steam
chamber
such as, for example, the operating steam chamber from which production of
hydrocarbons occurs, or a relatively lower pressure steam chamber such as, for
example, the matured steam chamber generally depleted of hydrocarbons to a
varying
degree. In various implementations, the operating steam chamber can have a
pressure in the range from about 1000 kPa to about 6500 kPa, and a temperature
in
the range from about 180 C to over 270 C. In SAGD, when the operating steam
chamber nears depletion and steam injection is discontinued, steam vapor
condenses
and the reservoir pressure drops, at which point the steam chamber becomes
matured. in various implementations, in the wind down stage of SAGD, the
matured
steam chamber can have, for example, a pressure in the range of about 700 kPa
to
about 2500 kPa and a temperature in the range of about 160 C to about 225 C,
about
162 C to about 223 C, or about 165 C to about 223 C. In particular
implementations,
the temperature can be, for example, about 162 C, about 180 C or about 200 C.
[0067] In various implementations, the term "operating steam chamber" broadly
relates
to a steam chamber in an undepleted or partially depleted in situ hydrocarbon
reservoir, into which steam or other fluid has been injected through one or
more
injection wells, and from which economic production of oil (e.g., production
where RF>
about 55%) can be obtained through one or more corresponding production wells
using, for example, SAGD. In the SAGD reservoir, a steam chamber or a
reservoir
region can be considered as "immature" or "operating" when it has been
operating for
about eighteen to about sixty months since the start up or circulation stage
up to a
point when the economic benefits of oil production are outweighed by the
costs.
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[0068] In various implementations, the term "matured steam chamber" broadly
relates
to a steam chamber in a hydrocarbon-containing reservoir that has been
partially or
substantially depleted in hydrocarbons through previous in situ operations.
For example,
in SAGD, a steam chamber or a reservoir region can be considered "matured"
when it
has reached a stage where greater than about 55% of the original hydrocarbon
content
in the reservoir has been recovered and where the steam-to-oil ratio is above
a value
which indicates that it can no longer be economical to produce residual oil as
compared
to the operating steam chamber.
[0069] Referring to Fig. 1, schematic diagrams of a reservoir with operating
pads (100)
(e.g., including operating steam chambers) and partially or substantially
matured pads
(150) (e.g., including matured steam chambers) according to various
implementations
are shown. As is indicated in the various implementations shown in Fig. 1, a
matured
steam chamber is generally adjacent to an operating steam chamber. In various
implementations, there can be a buffer zone having variable width or thickness
between
the matured steam chamber and the operating steam chamber. The buffer zone
(200)
is also referred to as a boundary. In various implementations, the width or
thickness of
the buffer zone (200) (boundary) can vary with varying reservoir properties
such as, for
example, reservoir thickness, fluid properties and saturations (e.g.,
formation water and
bitumen), initial reservoir pressure, steam injection pressure and volume, and
steam
quality. The operating steam chamber, the matured steam chamber, or a
combination
thereof, are also referred to as steam chambers at various stages of maturity.
[0070] When multiple SAGD well pairs are present as pad(s) in the reservoir,
each pad
drains bitumen from the reservoir within its own region. As a result, there
can be little to
no flow from region to region within the reservoir (i.e., each pad can operate
within a
defined region of the reservoir). However, in various implementations, the
drainage
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areas can be dynamic in nature, and as steam is injected, the increase in heat
transfer
can cause some of the previous non-communicating regions of the reservoir to
become continuous. Accordingly, the boundary between the operating steam
chamber(s) and the matured steam chamber(s), in terms of both width and
permeability, can change.
[0071] In various implementations, the minimum distance of an "edge" well to
the
boundary or buffer zone of a pad can be about half the distance of the well
spacing of
an inner well pair. In various implementations the boundary or buffer zone can
have a
width ranging from about 50 to about 80 m, about 80 m to about 160 m, or about
160
to about 200 m (including for "T" type well configurations).
[0072] In various implementations, the boundary can be defined, for example,
by the
following physical characteristics:
1. any kind of fluid inflow (water, heated bitumen, steam, gas);
2. pressure;
3. temperature; or
4. a combination of the above factors.
[0073] In various implementations, if movement of fluid within an area of the
operating
steam chamber generally adjacent to or proximate the matured steam chamber is
detected, or if reservoir pressure and formation temperature rise or are
higher in a
certain area of the operating chamber, one can conclude that this area is
within the
boundary and can be regarded as forming the boundary. The properties of the
boundary, including its width, can vary in various implementations depending
on the
properties of the reservoir such as, for example, the reservoir thickness,
fluid content,
initial reservoir pressure, operating steam injection pressure, and steam
quality.
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[0074] In various implementations, criteria which can be used to determine
whether or
not the SAGD pad is matured or depleted include: the period of time over which
the
SAGD pad has been operated (e.g., for more than seven years), an indication of
whether the steam chambers of each SAGD well pair coalesce with each other
(i.e.,
whether fluid communication has been established), the extent of growth of the
steam
chamber (e.g., once matured, the steam chamber can exhibit no further growth
as
indicated by 4D seismic information or the existing temperature monitor
wells).
[0075] According to a first implementation, a non-oxidizing gas is injected
into a region
of the matured steam chamber which can be referred to as a first steam chamber
at a
first stage of maturity. The first steam chamber is generally adjacent to or
proximate to
an operating chamber which can be referred to as a second steam chamber at a
second stage of maturity. In various implementations, the matured steam
chamber can
also be generally adjacent to or proximate to another steam chamber having a
different level of depletion from which further hydrocarbons can be recovered.
[0076] In various implementations, the term "non-oxidizing gas" relates to any
gas that
does not oxidize under SAGD reservoir conditions and can include, for example,
methane, nitrogen, carbon dioxide or a combination thereof.
[0077] In various implementations, the non-oxidizing gas is injected to form a
pressurized non-oxidizing buffer zone generally at or within the boundary OF
at or
within a region of the matured steam chamber adjacent to the operating steam
chamber. In various implementations, the pressurized non-oxidizing buffer zone
has a
pressure sufficient to reduce a fluid cross-flow between the adjacent or
proximate
steam chambers (e.g., between the operating steam chamber(s) and the matured
steam chamber(s)). In various implementations, the fluid can be, for example,
combustion gas, free oxygen, steam or a combination thereof.
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[0078] In various implementations, at the same time injection of the non-
oxidizing gas
is being performed, an oxygen-comprising gas is injected into the matured
steam
chamber adjacent the region of injection of the non-oxidizing gas so as to
pressurize
the matured steam chamber by increasing a pressure in the first steam chamber
relative to its initial pressure. Diffusion of the oxygen-comprising gas to
the barrier can
be minimized by the pressurized non-oxidizing buffer zone. In other
implementations,
the oxygen-comprising gas is injected into the matured steam chamber prior to
the
injection of the non-oxidizing gas, depending on the spacing of the oxygen-
comprising
gas injection wells from the non-oxidizing gas injection wells and on the
permeability of
the reservoir between the wells. As the oxygen-comprising gas diffuses toward
the
barrier, injection of the non-oxidizing gas can then be performed. In
various
implementations, if the reservoir conditions (e.g. temperature, pressure,
oxygen
concentration) are appropriate, ignition or combustion can be initiated in the
matured
steam chamber which results in oxidation reactions between the oxygen in the
oxygen-comprising gas and the remaining residual hydrocarbons such as bitumen
which can have a concentration of about 5% or more.
[0079] In various implementations, the term "oxygen-comprising gas" relates to
a fluid,
such as air, enriched air, a non-condensable gas mixture, pure oxygen or a
combination thereof, which has an oxygen concentration of about 5% or more. In
various implementations, the concentration of oxygen in the oxygen-comprising
gas
can range from about 5% to about 100%, about 5% to about 40%, or about 7% to
about 40%. For example, the oxygen-comprising gas can be air, which comprises
about 21% oxygen. In various implementations, the oxygen-comprising gas has
the
capability of supporting in situ combustion, as described below. In particular
implementations, the amount of oxygen in the oxygen-comprising gas can be
tailored
to achieve a desired level of in situ combustion as a strategy for reducing
fluid leak
from the operating steam chamber into the adjacent matured steam chamber. The
combustion and heat generated in the matured steam chamber, in addition to the
CA 02942157 2016-09-16
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injection of the non-oxidizing gas generally at or within the boundary, can
help to
maintain the pressure generally within the matured steam chamber and support
the
development of the pressurized non-oxidizing buffer zone. In implementations
where
injection of the non-oxidizing gas is delayed or not performed, the combustion
and
heat generated in the matured steam chamber can help to maintain the pressure
generally within the matured steam chamber to reduce fluid cross-flow between
the
adjacent or proximate steam chambers.
[0080] In various implementations, it is the pressure difference between or
among the
generally adjacent or proximal chambers at varying stages of maturity that is
one of
the dominant factors resulting in fluid cross-flow through porous media in the
reservoir
(e.g., flue gas cross-flow, oxygen cross-flow, steam cross-flow). For example,
if the
injection of steam is stopped, the rate of pressure drop can range from about
1 to
about 3.9 kPaid within a SAGD chamber. If there is generally no pressure
difference
between the two adjacent or proximate steam chambers (e.g., the matured steam
chamber and the operating steam chamber), there would be generally no fluid
flow
between these chambers. Therefore, in various implementations, the pressure of
the
pressurized non-oxidizing buffer zone is increased until this pressure is
equal to or
greater than the pressure in the operating steam chamber, the matured steam
chamber or both. The selected pressure difference between the matured steam
chamber and within the boundary can range from 0 kPa to about 200 kPa, which
results in a reduction of the cross-flow of fluid such as steam between the
operating
steam chamber and the boundary and further between the adjacent or proximate
chambers. This pressure difference also minimizes diffusion of the oxygen-
comprising
gas to the barrier.
[0081] In another implementation, the non-oxidizing gas and the oxygen-
comprising
gas are injected into a region of the boundary and into the matured steam
chamber,
respectively, such that the pressure within the boundary and within the
matured steam
CA 02942157 2016-09-16
-20-
chamber can generally reach a value referred to as an "optimum pressure value"
(also
referred to as a "sufficient pressure value"). The sufficient pressure value
can be a
pressure value slightly lower than the pressure of the boundary relative to
the pressure
of the adjacent operating steam chamber. In various implementations, the
sufficient
pressure value can vary depending on the geology, operational conditions, the
degree
of depletion and the duration of depletion of the matured steam chamber. The
pressure difference between the matured steam chamber(s) or the boundary and
the
generally adjacent or proximate operating steam chamber(s) can be as low as
possible. In various implementations, a suitable pressure difference that
reduces or
avoids fluid cross-flow from the operating steam chamber into the adjacent
matured
steam chamber can be about 50 kPa.
[0082] In other implementations, the non-oxidizing gas is not injected or its
injection is
delayed until absolutely necessary, depending on the nature of the barrier
between the
operating steam chamber and the matured steam chamber. If the barrier between
the
operating steam chamber and the matured steam chamber is a wide region of
unproduced reservoir, for example, about 100m wide, then injection of the non-
oxidizing gas can be avoided. Following injection of the oxygen-comprising gas
into
the matured steam chamber and the initiation of combustion or oxidation in the
matured steam chamber, if the combustion front approaches the operating steam
chamber late in the life of the operating steam chamber then injection of the
non-
oxidizing gas can be avoided. The combustion front can warm the bitumen at the
barrier between the operating steam chamber and the matured steam chamber
which
can then flow to a production well in the operating steam chamber, increasing
the
recovery of hydrocarbons from the reservoir. If non-oxidizing gas is injected
into the
boundary region in these circumstances, the bitumen between the operating
steam
chamber and the matured steam chamber could be rendered unrecoverable due to
the
presence of the non-oxidizing gas.
- 21 -
[0083] In other implementations, injection of the non-oxidizing gas can be
delayed. As
the combustion front in the matured steam chamber and the steam chamber of the
operating steam chamber move towards each other in the absence of the non-
oxidizing
gas, they can connect with each other at the top of the reservoir, leaving an
area of
undepleted bitumen near the bottom of the reservoir. Using modeling and by
monitoring
the development of the steam chamber in the operating steam chamber and the
combustion front in the matured steam chamber, non-oxidizing gas can be
injected into
the top of the reservoir in the boundary and between the steam chamber of the
operating
steam chamber and the combustion front from the matured steam chamber to push
these fronts toward a bottom portion of the reservoir, allowing for the
recovery of further
bitumen from a bottom portion of the barrier.
These
implementations can also reduce the consumption of costly non-oxidizing gases,
thereby
increasing the efficiency of the process.
[0084] In various implementations, one or more of the former steam injectors
can be
converted into a non-oxidizing gas injector(s) (250), an oxygen-comprising gas
injector(s) (250) or a combination thereof. For example, in various
implementations, an
edge well pair or any well generally away from the edge well in the matured
steam
chamber which is generally adjacent or proximate to the operating steam
chamber can
be selected, so long as sufficient pressure (e.g., an optimum pressure value)
is
achieved within the matured steam chamber, generally at or within the boundary
or
both, relative to the pressure in the operating steam chamber to reduce the
cross-flow
of fluid from the operating chamber into the generally adjacent matured steam
chamber.
In various implementations, other previous steam injectors within the matured
SAGD
chamber not used for injection of the non-oxidizing gas or the oxygen-
comprising gas
can be converted into producers (270) to produce oil and gas. In various
implementations, injection of the non-oxidizing gas and the oxygen-comprising
gas
according to the implementations described above can be used as a strategy for
increasing the recovery of hydrocarbons from the reservoir as whole.
CA 2942157 2018-08-24
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[0085] In various implementations, the non-oxidizing gas and the oxygen-
comprising gas
are injected into the boundary and into the matured steam chamber,
respectively, through
former SAGD injection wells that are the closest to the generally adjacent
SAGD operating
well pairs (300, 302) (for example, the previous steam injector is converted
into an oxygen-
comprising gas injector), while the previous SAGD production wells remain open
to
producing further amounts of gas and oil. In various implementations, the
parameters for
those wells are set to meet the requirements for pressure maintenance under
the specific
operating conditions.
[0086] In various implementations, the non-oxidizing gas and the oxygen-
comprising
gas can be injected in various ways, including cyclical and intermittent
injection. For
example, as shown in the Figures, the oxygen-comprising gas can be continually
injected for three months, stopped for two months and then subsequently
resumed. The
original wells in the matured steam chamber and generally within or at the
boundary in
the SAGD reservoir can be modified in various ways. In various
implementations, the
spacing between the SAGD well pairs is generally about 100 m and the length of
the
horizontal well is generally about 500 m or more. The resultant surface area
is relatively
large and therefore, it can be more economical in some implementations to use
only a
portion of the well for perforation and injection of the non-oxidizing gas,
the oxygen-
comprising gas or both. Thus, in various implementations, in order to use the
minimum
non-oxidizing gas flux injection, the minimum oxygen-comprising gas flux
injection or
both, the non-oxidizing gas, the oxygen-comprising gas or both can be injected
via a
portion or several portions of the initial horizontal wellbore of the steam
injector. Figs.
2 and 3 show injection and production well pairs, wherein the injection well
(250) is
situated generally above the production well (270).
CA 2942157 2018-08-24
-2 3 -
[0087] In the implementation of Fig. 2, the injection well (250) is perforated
along
generally substantially all or a portion of the horizontal portion of the
former steam
injection well. In this implementation, if production of hydrocarbons is
desired, the
combustion front generated rises upwardly toward the upper portion of the
reservoir. The
mobilized hydrocarbon can be collected by the production well (270) situated
generally
below the injection well (250). In this respect, a packer can be used to
isolate the
horizontal wellbore section, and the oxygen-comprising gas such as air can be
injected
through the isolated portion.
[0088] In another implementation, a vertical section in the bitumen bearing
zone (280)
can be perforated and a dual completion system can be employed as is shown in
Fig.
3. Air can be injected into the formation through annuls and vent combustion
gas can
be vented through tubing along the horizontal well section of the original
steam injection
well.
[0089] In Fig. 3, the injection well (250) is perforated along generally
substantially all or
a portion of the vertical portion of the previous or former steam injection
well for injection
of the non-oxidizing gas, the oxygen-comprising gas or both. In various
implementations,
as is shown for example in Fig. 3, the combustion front (500) created by
injecting the
oxygen-comprising gas extends outwardly from the generally vertical portion of
the
injection well (i.e., from heel to toe), and the combustion gases drain into
the generally
horizontal portion of the injection well (250). As is shown in the
implementation in Fig. 3,
the mobilized hydrocarbons can drain into the generally horizontal portion of
the
production well (270).
[0090] In various implementations, the non-oxidizing gas injector is laterally
offset or
disposed away from the oxygen-comprising gas injector. Any other previous
steam
injectors can also be converted into flue gas vent wells and the corresponding
offset
previous bitumen producers can remain as liquid producers to collect heated
bitumen
CA 2942157 2018-08-24
CA 02942157 2016-09-16
-24-
and condensate of steam. These wells can be controlled to determine if they
are open
or shut based on oxygen concentration and fluid temperature from the well
(e.g., if the
temperature and oxygen concentration are high, the well can be shut in). As a
result,
combustion drive is initiated to maintain reservoir pressure in the matured
steam
chamber, support the development of the pressurized non-oxidizing buffer zone
and in
some implementations, to mobilize bitumen within the matured steam chamber.
[0091] In various implementations, the timing for beginning injection of the
non-
oxidizing gas and the oxygen-comprising gas can occur when fluid communication
between the operating SAGD pad or chamber and the matured SAGD pad or chamber
is either established or not yet established,
[0092] Although the wells in the matured steam chamber have been functionally
identified as production or injection wells, such identification does not
imply that the
wells are to be used exclusively for that particular purpose. The wells can
have one or
more functions (e.g., for injecting the non-oxidizing gas, injecting the
oxygen-
comprising gas and venting a combustion gas formed during pressurization of
the
matured steam chamber).
[0093] As was described above, after steam injection is terminated in a SAGD
operation, injection of the non-oxidizing gas, the oxygen-comprising gas or
both can
be initiated instead of steam. In various implementations, the injected non-
oxidizing
gas, the oxygen-comprising gas, or both, can be generally dry or generally
wet. For
example, if the oxidation reactions are high temperature oxidation reactions
or if
combustion dominates, more heat can be generated in situ. In such
implementations
where air can be used as the oxygen-comprising gas, water-air (wet air) co-
injection
can be used to utilize the heat generated from combustion. Liquid water can be
evaporated and became steam. However, in such implementations, wet combustion
can result in a lower peak temperature of combustion as compared with dry
CA 02942157 2016-09-16
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combustion. The injection of water with air improves the in situ combustion
process by
lowering fuel and air requirements and increasing front velocity. Both fuel
and air
requirements are reduced up to 20% at high water-to-air ratios (WAR), when
compared to dry combustion (VVAR=0). Because of its high heat capacity, water
scavenges most of the generated heat stored behind the burning front and
carries
superheated steam over the front to the steam plateau region where the oil
bank is
found in front of the combustion front. The water injected can be cold water,
hot water
or steam. (e.g., US Patent 4729431 - Oil recovery by quenched in situ
combustion).
The combustion front velocity increases with increases in WAR. But at very
high WAR
values, the water zone approaches the burning zone from behind the front.
[0094] In various implementations, once combustion has been initiated, an
adequate
supply of the oxygen-comprising gas is important in addition to the supply of
the non-
oxidizing gas. For example, once the combustion front has propagated a
sufficient
distance away from the wellbore to achieve a generally stabilized burn, it can
be
preferred, but not essential, to convert the dry combustion drive to a water
and
oxygen-comprising gas co-injection. This can be done by injecting water
concurrently
or alternately with the oxygen-comprising gas through the injection well(s).
In various
implementations, it can be preferred to initially inject water at a WAR of
about 50 to
about 500 bbls/MMCFair. After the combustion within the matured SAGD chamber
has
generally stabilized, the WAR can be increased.
[0095] In various implementations, the residual bitumen content in the matured
steam
chamber can range from about 0.05 % to about 5 % in order to achieve ignition
and
sustain combustion while avoiding the risk of an explosion.
[0096] Depending on the content of oxygen in the oxygen-comprising gas and the
residual hydrocarbon content in the matured steam chamber, the generation of
heat
and flue gases (e.g., N2 and CO2) through oxidation reactions occurring within
the
CA 02942157 2016-09-16
-26-
matured steam chamber can be modulated to obtain the desired conditions for
maximizing hydrocarbon recovery from the generally adjacent operating steam
chamber(s) and, in some implementations, simultaneous recovery of the residual
hydrocarbons from the matured steam chamber. In various implementations, the
pressure, temperature, oxygen concentration, rate of injection and volume of
the non-
oxidizing gas, the oxygen-comprising gas, or both, can all be modulated to
achieve a
certain degree of reduction in inter-chamber fluid flow, in situ combustion in
the
matured steam chamber and the desired level of pressurization of the matured
steam
chamber as a whole or generally within the boundary adjacent to or proximate
to the
operating steam chamber.
[0097] In various implementations, an artificial ignition source can be
required, which
can, for example, include auto-ignition. In some implementations, if the
temperature in
the matured steam chamber is below about 200 C, the artificial ignition source
can be
required to help initiate in situ combustion in the matured steam chamber. The
oxygen-
comprising gas can have a temperature in the range of about 180 C to about 270
C
and pressure in the range of about 1000 kPa to about 6500 kPa prior to
injection into
the matured steam chamber. The matured steam chamber can have a temperature
above 180 C and pressure about 200 kPa less than the pressure in the operating
steam chamber. The temperature of the matured steam chamber, the boundary, or
both, prior to injection of the oxygen-comprising gas and the non-oxidizing
gas can
vary depending on the production stages of the adjacent operating steam
chambers
and on reservoir properties. The volume of the oxygen-comprising gas required
can
vary depending on the operational conditions, and can be modulated during
injection
to achieve desired levels of combustion.
[0098] In various implementations, it is important to control the combustion
in the
matured steam chamber by controlling the rate of injection of the oxygen-
comprising
gas (e.g., air or air enriched with oxygen), the content of oxygen, or a
combination
CA 02942157 2016-09-16
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thereof. Injection of the non-oxidizing gas generally at or within the
boundary can
mitigate risks of either combustion gas or free oxygen flowing into the
operating SAGD
chamber, if fluid communication is established between the two pads.
[0099] For example, Nelson and McNeil (Nelson, T.W., and McNeil, J.S., How to
Engineer an In Situ Combustion Project; The Oil and Gas Journal, p. 58, June
5, 1961)
proposed that a minimum velocity required to sustain the propagation of a high
temperature combustion was 0.038m/day. The minimum oxygen flux (Ufõ) required
for
maintaining this velocity can be estimated based on the following
relationship:
= Ar x
where:
Ar: Oxygen-comprising gas requirement (m3(ST)/m3)
Ubm: Minimum burn front velocity (m/hour)
Urõ: Minimum oxygen flux (m3(ST)/m2-hour)
[0100] In various implementations, a flux of the oxygen-comprising gas can be
calculated from the oxygen gas flux based on the oxygen concentration within
the
oxygen-comprising gas, and is one parameter used to control the combustion and
thus
the temperature of the matured steam chamber. If air is used, oxygen gas flux
can be
called air flux. The flux of the oxygen-comprising gas allows for modulation
of the size
of the combustion front (R.G.Moore, C.J. Laureshen, S.A.Mehta, M.G. Ursenbach,
Observations and Design Consideratios for In Situ Combustion Projects, Journal
of
Canadian Petroleum Technology, Special Edition 1999, Vol.38, No.13, 1999).
Once
the air requirement is fixed, the air flux determines the velocity of
combustion front
movement within the reservoir. In various implementations, the rate of
injection of the
oxygen-comprising gas can be kept as low as possible, which allows the
combustion
front to propagate from the injector at a rate as low as about 0.038m/day.
CA 02942157 2016-09-16
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[0101] The minimum amount of the oxygen-comprising gas required (e.g., air) is
proportional to both the fuel deposition and heat loss (Partha Sarathi, S., In
Situ
Combustion Handbook ¨ Principles and Practices, National Petroleum Technology
Report, U.S. Department of Energy, Tulsa, Oklahoma, 1999). The higher the fuel
deposition, the more oxygen-comprising gas is required, resulting in higher
air flux.
Similarly, the higher the heat loss from the formation to overburden and
underburden,
the higher the oxygen-comprising gas (e.g. air) flux is needed. In various
implementations, the matured steam chamber is generally warm or hot, and can
have
a temperature of about 165 C or greater. When the formation is heated, heat
loss can
be smaller than is the case for conventional in situ combustion processes,
including
the THAI process. The fuel deposition can also be less than the post-SAGD case
(Partha Sarathi, S., In Situ Combustion Handbook ¨ Principles and Practices,
National
Petroleum Technology Report, U.S. Department of Energy, Tulsa, Oklahoma,
1999).
[0102] In various implementations, the temperature generally travels within
the
reservoir a much shorter distance than the pressure. In various
implementations, this
can be a consideration with regard to the volume of air or oxygen-comprising
gas
injected in combination with the non-oxidizing gas in order not to move the
high
temperature or combustion front too fast, which is controlled by the rate of
injection. In
various implementations, combustion gas or flue gas mainly comprising N2 and
CO2
are generated through the oxidation reactions in situ and fill the void space
of the
matured steam chamber.
[0103] By injecting the oxygen-comprising gas alone or in combination with the
non-
oxidizing gas according to various implementations, the pressure generally at
or within
the boundary, in the adjacent matured steam chamber or both, is maintained,
preventing the matured steam chamber from becoming a thief zone for future or
ongoing SAGD operations nearby.
CA 02942157 2016-09-16
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[0104] Injection of the oxygen-comprising gas or both the oxygen-comprising
gas and
the non-oxidizing gas can block fluid cross-flow between or among the chambers
and
can allow for increased oil production from adjacent operating steam chambers
in the
reservoir as a whole. Injection of the oxygen-comprising gas, the non-
oxidizing gas or
both can also result in mobilization of the residual oil (unrecovered or
remaining oil left
in place from previous in situ recovery such as, for example, SAGD) in the
matured
steam chamber. The recovery of residual oil in the matured steam chamber can
range
from about 55% to above about 80%.
[0105] To obtain improved performance of the operating steam chamber(s)
adjacent to
or proximate to the matured steam chamber, an optimum pressure can be
maintained
in the matured steam chamber as a whole and generally within the boundary
between
the matured steam chamber and the operating steam chamber to facilitate the
operations, which can be generally similar or up to about 200 kPa lower than
the
pressure in the adjacent or proximate operating steam chamber. The optimum
pressure can also depend on the properties of one or more pads surrounding the
matured steam chamber. For example, if the pads adjacent the matured steam
chamber include operating steam chambers at various stages of SAGD, the
pressure
required at or generally within the boundary (i.e., injection of the non-
oxidizing gas)
and the pressure required in the chamber (i.e., injection of the oxygen-
comprising gas)
to increase hydrocarbon production from several of the operating steam
chambers can
be different from the pressure required to reduce cross-flow and increase
hydrocarbon
production in instances where only one operating steam chamber is adjacent the
matured steam chamber.
[0106] In various implementations, parameters such as the pressure at or
within the
boundary, reservoir pressure, produced gas compositions, and temperature of
the
oxygen-comprising gas injector(s) and producer(s) in both the operating and
matured
steam chambers, can be monitored. These parameters can be used to determine
CA 02942157 2016-09-16
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optimal injection rates of the non-oxidizing gas, the oxygen-comprising gas,
or both, in
order to achieve a reduction in cross-flow of fluid between the chambers,
increased oil
production, or both, as compared to what can be achieved without injecting the
oxygen-comprising gas and the non-oxidizing gas.
[0107] In various implementations, the timing to commence the injection of the
non-
oxidizing gas, the oxygen-comprising gas or both into the matured steam
chamber can
be important to achieving suitable operational efficiencies. For example,
injection of
the non-oxidizing gas and the oxygen-comprising gas into the matured steam
chamber
can be performed cyclically, and the injection cycle can depend on the
properties and
layout of the adjacent operating steam chambers. For example, the non-
oxidizing gas
and the oxygen-comprising gas can be injected for a certain length of time and
then
shut in for a selected time interval. The injection rate and timing can be
adjusted for
each cycle based on the requirements for pressure maintenance design for
reducing
fluid cross-flow between the adjacent chambers and for target oil production.
[0108] The production of oil and combustion gases can also operate cyclically.
In
various implementations, free oxygen can be scrubbed from the matured steam
chamber through the oxidation reactions. Utilizing the residual heat in the
reservoir
after steam injection has been stopped can also assist with oxidation
reactions, and in
some implementations, can influence the amount and composition of the oxygen-
comprising gas to be injected into the matured steam chamber. In various
implementations, hydrocarbons can be recovered selectively from the operating
steam
chamber, the matured steam chamber, or from both chambers.
[0109] In various implementations, the number of wells required for injecting
the non-
oxidizing gas and the oxygen-comprising gas can vary based on operational
requirements. In various implementations, the physical arrangement of the
wells on
adjacent pads for injecting the non-oxidizing gas and the oxygen-comprising
gas can
CA 02942157 2016-09-16
-31-
vary. For example, the wells can have parallel-type side by side and toe-heel
series-
type side-by-side arrangements. In various implementations, the injection
wells in the
matured steam chamber can be configured such that the oxygen-comprising gas is
injected near the bottom of the reservoir to mobilize the residual
hydrocarbons in the
matured steam chamber for combustion, recovery or a combination thereof. In
various
implementations, one or more injection wells can be positioned in the
proximity of the
production well for injecting the oxygen-comprising gas or in the proximity of
the
boundary for injecting the non-oxidizing gas generally at or within the
boundary. In
various implementations, new injection wells can also be formed to achieve a
desired
configuration in the matured steam chamber for blocking fluid cross-flow
between the
generally adjacent chambers and for increasing the recovery of hydrocarbons.
[0110] In various implementations, infill wells can be put into the matured
steam
chamber. For example, an infill horizontal well can be selected for injecting
the
oxygen-comprising gas and the adjacent or offset previous SAGD well pairs can
be
converted into production wells. For example, the upper well can be mainly
used for
gas production and the lower well can be mainly used for liquid production. In
various
implementations, the injector of the oxygen-comprising gas can be a vertical
well that
can be drilled in the area of the matured steam chamber. Various flue gas
wells can be
set up in selected configurations relative to the wells for injecting the
oxygen-
comprising gas and relative to the wells for injecting the non-oxidizing gas
for
controlling combustion and for achieving and maintaining the pressure balance
for the
two or more generally adjacent or proximal SAGD pads. If hot fluid
communication is
established and the pressure balance between the two SAGD pads or chambers is
not
properly controlled, the flue gas can migrate from the portion of the
reservoir in the
matured SAGD pad into the operating SAGD pad, which in turn can jeopardize the
steam chamber growth and thus impair SAGD performance in the operating SAGD
chamber.
CA 02942157 2016-09-16
-32-
[0111] In various implementations, the extent of fluid communication between
the
immature operating chamber(s) and the matured steam chamber(s) can differ. The
following factors can affect the extent of fluid communication: initial steam
chamber
size and chamber development, steam injection temperature and pressure,
geological
conditions such as reservoir heterogeneity and pressure differences, injection
pressure for the non-oxidizing gas, injection pressure for the oxygen-
comprising gas,
cumulative oil produced, steam injected, and chamber cooling.
[0112] In various implementations, reservoir geology can be an important
consideration for maximizing oil recovery from the reservoir. For example, if
the
reservoir includes high permeability streaks or channels, channeling and early
steam,
flue gas and oxygen breakthrough can occur. There can be a potential risk that
the
oxygen-comprising gas injected into the matured steam chamber can be captured
by
the production wells in the matured steam chamber. If the free oxygen is not
consumed through oxidation or combustion, it can pose a safety concern,
[0113] Injection of the non-oxidizing gas generally at or within the boundary
and the
oxygen-comprising gas address the issue of channeling of steam by forming a
barrier.
Also, in various implementations, injection of the non-oxidizing gas reduces
the risk of
an explosion. To further reduce this kind of risk, monitoring the produced gas
compositions and the level of the non-oxidizing gas at or within the boundary
and the
oxygen-comprising gas in the matured steam chamber can be used as an
indication
for the integrity of the pressurized barrier generally within the boundary,
combustion
activity in the reservoir, and for moderating safety risks associated with gas
levels.
[0114] Injection of the non-oxidizing gas generally at or within the boundary
and the
oxygen-comprising gas into the matured steam chamber provides several economic
advantages. Unlike in the prior art, where, for example, a non-condensable gas
(NCG)
is injected into the chamber and often causes a significant reduction in the
CA 02942157 2016-09-16
-33-
temperature of the matured steam chamber, injection of the non-oxidizing gas
at or
within the boundary and the oxygen-comprising gas into the matured steam
chamber
does not have such an effect. Thus, injection of the non-oxidizing gas and the
oxygen-
comprising gas can allow for pressure to be generated and maintained not only
through injection of a suitable volume of the gases but also through heat
generation by
combustion with the residual hydrocarbons in the matured steam chamber.
[0115] The injection of the non-oxidizing gas generally within the boundary
between
the matured steam chamber and the adjacent or proximate operating steam
chamber
and the oxygen-comprising gas into the matured steam chamber can provide a
method of isolating the matured steam chamber or a pattern of matured steam
chambers from the adjacent or proximate operating steam chambers. The
injection of
the non-oxidizing gas and the oxygen-comprising gas allows for the maintenance
of
reservoir pressure and slows the temperature drop as the steam vapour in the
matured
steam chamber condenses. The non-oxidizing gas injection and the oxygen-
comprising gas injection can also reduce steam cross-flow and cross-flow of
combustion gas and free oxygen between the matured steam chamber and the
generally adjacent or proximate operating steam chamber. Therefore, the
performance of the operating steam chambers can be improved due to more
efficient
utilization of the steam, which can reflect a lower cSOR.
[0116] Duration of the injection of the non-oxidizing gas into the boundary
and the
injection of the oxygen-comprising gas into the matured steam chamber,
respectively,
can vary depending on the properties of the matured steam chamber prior to
injection
(e.g., temperature, pressure) and on the operational stages of the operating
steam
chambers proximal to or generally adjacent the matured steam chamber. For
example,
if the operating steam chambers are in the early stages of SAGD, the interval
for
injecting the non-oxidizing gas and the oxygen-comprising gas into the matured
steam
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chamber can be longer than in circumstances where the operating steam chambers
are in later stages of SAGD.
[0117] In various implementations, the various ranges and ratios described can
be
derived from laboratory experiments, computer simulations, or both, to mimic
the
particular in situ extraction process and system, reservoir properties,
effects of well
layout, and desired injection of the non-oxidizing gas and the oxygen-
comprising gas.
[0118] In various implementations, the maintained SAGD chamber pressure in
combination with the pressure maintained at the boundary can "blunt" the steam
chamber of the edge well(s) for the operating SAGD chamber(s) that are located
generally adjacent to the matured SAGD chamber(s), which lessens steam cross-
flow
(also referred to as steam leakage) from the operating SAGD chamber into the
generally adjacent matured chamber.
[0119] In various implementations, various previous steam injector(s) that are
located
in the matured steam chamber can be kept open to produce combustion gases and
hydrocarbon vapor gas and liquids (bitumen and water) while the producers
located in
the operating SAGD chamber can continually produce bitumen. Various parameters
associated with the injection and production wells in the matured and
operating
chambers such as, for example, minimum bottom pressure and maximum production
rate for liquid and gas, can be modulated/controlled based on the level of
pressure
maintenance desired under particular operating and reservoir conditions.
EXAMPLES
[0120] Various implementations presented in the Figures have been modeled in a
computer reservoir simulation, the Steam, Thermal, and Advanced Processes
Reservoir Simulator (STARS), provided by Computer Modelling Group (CMG), based
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on a selected location of the geology model. Parameters for the simulations
are
chosen to mimic the parameters for the particular reservoir and the operating
conditions for the operating and matured chambers in the reservoir.
[0121] The following parameters in Table 1 were used for the simulation model:
TABLE 1
Simulator CMG STARS 2009 version
Simulation Water, Bitumen (two pseudo components: Asphaltene and
components Maltene fractions), CO2, Oxygen, Nitrogen, and Coke
Fort McMurray type formation, the geology model for simulation
is similar to the one used as the previous ASOSTRA UTF
(Underground Test Facility)
Rich sand Lean Sand
Formation Horizontal Permeability (md) 8000- 10000 3890
properties Vertical Permeability (md) 3303 -5600 1945
Porosity (faction) 0.35 0.30
Oil saturation (fraction) 0.85 0.75
Initial temperature ( C) 9 9
Initial Pressure (kPa) 530-840 kPa
Gross formation thickness (m)-- 48m
Fluid Bitumen properties are taken as Athabasca bitumen, which are
properties accepted in the industry
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[0122] Figs. 1A to 1C illustrate schematic diagrams of three examples of
layout or
arrangement of wells for a SAGD pad development, showing a reservoir
comprising
matured steam chambers generally adjacent to operating steam chambers. As is
shown
in the Figures, there is a "boundary" (200) between the matured SAGD pad and
the
operating SAGD pad. The boundary (200) forms a separation between the
operating
SAGD well pair and the mature well pair which can be over and above the
nominal
drainage width of both well pairs. An edge well pair within a pad is disposed
to leave at
least half the distance of the inner well pair spacing to the boundary/edge of
a particular
approved development area.
[0123] In an implementation comprising two SAGD pads as shown in Figs. 2-10,
SAGD
operation is performed on Pad 1 until recovery of hydrocarbons from Pad 1
becomes
uneconomical, at which point steam injection is stopped and the operating
steam
chamber becomes "matured". One or more of the injection wells in Pad 1 are
then
modified for injecting the non-oxidizing gas generally at or within the
boundary and the
oxygen-comprising gas into the matured steam chamber. In various
implementations,
SAGD operation on Pad 2 comprising the operating chamber, generally adjacent
to
Pad 1, can be performed simultaneously with the injection of the non-oxidizing
gas and
the oxygen-comprising gas into Pad 1. The rate of injection of the non-
oxidizing gas
and the oxygen-comprising gas, and the duration for injection in Pad 1 can be
modulated based on, for example, the performance and operating conditions of
Pad 2,
the level of pressure to be maintained, the desired level of hydrocarbon
recovery from
Pad 1, Pad 2, or both, and the rate of fluid production (water, combustion
gases). In
various implementations, an injection strategy for injecting the non-oxidizing
gas and
the oxygen-comprising gas is important for operational control of the non-
oxidizing gas
injection wells, the oxygen-comprising gas injection wells and the generally
adjacent
SAGD operations.
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[0124] Figure 2 shows an example of the manner in which the oxygen-comprising
gas
(400) can be injected into the matured steam chamber. In this example, the
injection well
(250) is perforated along generally substantially all or a portion of the
horizontal portion of
the previous steam injection well. The combustion front (500) generated rises
upwardly
toward the upper portion of the reservoir. The mobilized hydrocarbon can be
collected by
the production well (270) situated generally below the oxygen-comprising gas
injection
well (250). In this respect, a packer can be used to isolate the horizontal
wellbore section,
and the oxygen-comprising gas such as air can be injected through the selected
portion.
[0125] Figure 3 illustrates another implementation showing injection of the
oxygen-
comprising gas (400) via the injector (250). A vertical section in the bitumen
bearing zone
can be perforated and a dual completion system can be employed to inject the
oxygen-
comprising gas. The combustion front (500) created extends outwardly from the
generally
vertical portion of the oxygen-comprising gas injection well (250) (i.e., from
heel to toe),
and the combustion gases (600) drain into the generally horizontal portion of
the injection
well. As is shown in the implementation of Figure 3, any mobilized
hydrocarbons can drain
into the generally horizontal portion of the production well (270) below.
[0126] In various implementations, the oxygen-comprising gas injector (air
injector in
this example) is a former steam injector and can be located anywhere in the
matured
steam chamber. For example, the air injector can be either close to or far
away from
the adjacent boundary. The air can be injected continuously via the air
injector or
cyclically. In various implementations, the non-oxidizing gas and the oxygen-
comprising gas having variable composition can be used for the various
cyclical stages
of injection.
[0127] For example, in the simulation model, Pad 1 was operated 7 years
earlier than Pad
2 and steam injection into Pad 1 was terminated after those 7 years. Pad 2 was
operated
in SAGD mode for 10 years. Water vapour mole fraction represents the
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steam chamber within the reservoir. As shown in Figure 4, Pad 1 contains a
well
developed steam chamber and no fluid cross-flow from Pad 2 into Pad 1. After
10
years of SAGD operation in Pad 2, steam from Pad 2 leaks into Pad 1, as shown
in
Figure 5. The reservoir pressures in Pad 1 and Pad 2 are equal.
[0128] A comparison of steam chambers illustrating the effect of injecting the
non-
oxidizing gas and the oxygen-comprising gas into Pad 1 is shown in Figure 6.
Without
injection of these gases, steam from Pad 2 continues to leak into Pad 1. In
contrast,
injecting the non-oxidizing gas and the oxygen-comprising gas into Pad 1 can
decrease the loss of steam injected into Pad 2 to Pad 1. In the simulation
model, air
was injected through the upper well of the second well pair (from left to
right) as the
oxygen-comprising gas and methane was injected through the upper well of the
first
well pair in Pad 1 as the non-oxidizing gas.
[0129] Figure 7 shows a layout of the wells for the simulation model which
includes a
non-oxidizing gas injector, an oxygen-comprising gas injector and gas vent
wells in
Pad 1. Pad 2 includes a well configuration for SAGD operations involving steam
injection wells and hydrocarbon production wells.
[0130] Combustion or oxidation reactions can occur in Pad 1 following
injection of the
oxygen-comprising gas. Simulation results showing a temperature profile in the
reservoir are illustrated in Figure 8. As temperature is dependent on
pressure,
increasing temperature in Pad 1 indicates that pressure in Pad 1 is also being
maintained at a higher value as compared to the pressure in Pad 1 prior to
injection of
the non-oxidizing gas and the oxygen-comprising gas. Maintaining pressure in
Pad 1
can prevent fluid cross-flow from Pad 2 into Pad 1.
[0131] Figure 9 shows that injection of the non-oxidizing gas and the oxygen-
comprising gas can create a methane buffer zone at the boundary between Pads 1
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and 2. In various implementations, the methane can stay in the area between
Pad 2
and the top of the matured steam chamber in Pad 1.
[0132] In various implementations, combustion products from the combustion or
oxidation of the oxygen-comprising gas injected into Pad 1 can stay within the
matured
steam chamber in Pad 1 as shown in Figure 10. The distribution of CO2
indicates that
the methane can act as a buffer that "pushes" the combustion products away
from the
boundary between Pads 1 and 2.
[0133] The various implementations of the apparatus and process allow use of
multi-
well pairs and multi-pad operations, and various non-oxidizing gas and oxygen-
comprising gas injector and producer configurations, as well as improvement in
the
SAGD performance of individual pads and of the reservoir undergoing SAGD as a
whole.
[0134] Although specific implementations have been described and illustrated,
such
implementations should not to be construed in a limiting sense. Various
modifications
of form, arrangement of components, steps, details and order of operations of
the
implementations illustrated will be apparent to persons skilled in the art
upon reference
to this description. It is therefore contemplated that the appended claims
will cover
such modifications and implementations. In the specification including the
claims,
numeric ranges are inclusive of the numbers defining the range.
