Note: Descriptions are shown in the official language in which they were submitted.
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
IN SITU COMBUSTION WITH A MOBILE FLUID ZONE
FIELD
[0001] The present disclosure relates to methods for recovery of viscous
hydrocarbons from oil sands deposits using in situ combustion.
BACKGROUND
[0002] A variety of processes are used to recover viscous hydrocarbons,
such as
heavy oils and bitumen, from oil sands deposits. Extensive deposits of viscous
hydrocarbons
exist around the world, including large deposits in the Northern Alberta oil
sands, that are not
susceptible to standard oil well production technologies. One problem
associated with
producing hydrocarbons from such deposits is that the hydrocarbons are too
viscous to flow
at commercially relevant rates at the temperatures and pressures present in
the reservoir.
[0003] In some cases, such deposits are mined using open-pit mining
techniques to
extract hydrocarbon-bearing material for later processing to extract the
hydrocarbons.
Alternatively, thermal techniques may be used to heat the oil sands reservoir
to mobilize the
hydrocarbons and produce the heated, mobilized hydrocarbons from wells.
[0004] One thermal method of recovering viscous hydrocarbons using two
vertically
spaced horizontal wells is known as steam-assisted gravity drainage (SAGD).
Various
embodiments of the SAGD process are described in Canadian Patent No. 1,304,287
and
corresponding U.S. Patent No. 4,344,485. In the SAGD process, steam is pumped
through
an upper, horizontal, injection well into a viscous hydrocarbon reservoir
while mobilized
hydrocarbons are produced from a lower, parallel, horizontal, production well
that is vertically
spaced and near the injection well. The injection and production wells are
located close to
the bottom of the hydrocarbon deposit to collect the hydrocarbons that flow
toward the
bottom.
[0005] The SAGD process is believed to work as follows. The injected
steam initially
mobilizes the hydrocarbons to create a steam chamber in the reservoir around
and above
the horizontal injection well. The term "steam chamber" is utilized to refer
to the volume of
the reservoir that is saturated with injected steam and from which mobilized
oil has at least
partially drained. As the steam chamber expands upwardly and laterally from
the injection
well, viscous hydrocarbons in the reservoir are heated and mobilized, in
particular, at the
1
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
margins of the steam chamber where the steam condenses and heats the viscous
hydrocarbons by thermal conduction. The mobilized hydrocarbons and aqueous
condensate
drain, under the effects of gravity, toward the bottom of the steam chamber,
where the
production well is located. The mobilized hydrocarbons are collected and
produced from the
production well. The rate of steam injection and the rate of hydrocarbon
production may be
modulated to control the growth of the steam chamber and ensure that the
production well
remains located at the bottom of the steam chamber in an appropriate position
to collect
mobilized hydrocarbons.
[0006] In Situ Combustion (ISC) may be utilized to recover hydrocarbons
from
underground oil sands reservoirs. ISC includes the injection of an oxidizing
gas into the
porous rock of a hydrocarbon-containing reservoir to ignite and support
combustion of the
hydrocarbons around the wellbore. ISC may be initiated using an artificial
igniter such as a
downhole heater or by pre-conditioning the formation around the wellbores and
promoting
spontaneous ignition. The ISC process, also known as fire flooding or
fireflood, is sustained
and the ISC fire front moves due to the continuous injection of the oxidizing
gas. The heat
generated by burning the heavy hydrocarbons in place produces hydrocarbon
cracking,
vaporization of light hydrocarbons and reservoir water in addition to the
deposition of heavier
hydrocarbons known as coke. As the fire moves, the burning front pushes a
mixture of hot
combustion gases, steam, and hot water, which in turn reduces oil viscosity
and the oil
moves toward the production well. Additionally, the light hydrocarbons and the
steam move
ahead of the burning front, condensing into liquids, facilitating miscible
displacement and hot
waterflooding, which contribute to the recovery of hydrocarbons.
[0007] Canadian Patent 2,096,034 to Kisman et al. and US Patent 5,211,230
to
Ostapovich et al. disclose a method of in situ combustion for the recovery of
hydrocarbons
from underground reservoirs, sometimes referred to as Combustion Split
production
Horizontal well Process (COSH) or Combustion Overhead Gravity Drainage (COGD).
The
disclosed processes include gravity drainage to a basal horizontal well in a
combustion
process. A horizontal production well is located in the lower portion of the
reservoir. A vertical
injection and one or more vertical vent wells are provided in the upper
portion of the
reservoir. Oxygen-enriched gas is injected down the injector well and ignited
in the upper
portion of the reservoir to create a combustion zone that reduces viscosity of
oil in the
reservoir as the combustion zone advances downwardly toward the horizontal
production
2
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
well. The reduced-viscosity oil drains into the horizontal production well
under the force of
gravity.
[0008] Canadian Patent 2,678,347 to Bailey discloses a pre-ignition heat
cycle
(PIHC) using cyclic steam injection and steam flood methods that improve the
recovery of
viscous hydrocarbons from a subterranean reservoir using an overhead in situ
combustion
process, referred to as combustion overhead gravity drainage (COGD). Bailey
discloses a
method where the reservoir well network includes one or more injection wells
and one or
more vent wells located in the top portion of the reservoir, and where the
horizontal drain is
located in the bottom portion of the reservoir.
[0009] The use of ISC as a follow up process to SAGD is disclosed in
Canadian
Patent 2,594,414 to Chhina et al. The disclosed hydrocarbon recovery processes
may be
utilized in oil sands reservoirs. Chhina discloses a process where a former
steam injection
well, used during the preceding SAGD recovery process, is used as an oxidizing
gas
injection well and where another former steam injection well, adjacent to the
oxidizing gas
injection well, is converted into a combustion gas production well. This
results in the
horizontal hydrocarbon production well being located below the horizontal
oxidizing gas
injection well and at least one combustion gas production well being spaced
from the
injection well by a distance that is greater than the spacing between
hydrocarbon production
well and the oxidizing gas injection well. Since the process disclosed by
Chhina uses at least
two wells pairs, ISC is initiated after the production well is sufficiently
depleted of
hydrocarbons to establish communication between the two well pairs.
[0010] Oil sands deposits may exist substantially in isolation, or may
also include
hydraulically contiguous mobile fluid zones that have relatively low bitumen
saturation, for
example they may have significant saturations of gas, water, or both. In such
deposits, these
mobile fluid zones can act as "thief zones" and have one or more undesirable
effects on
recovery methods. For example, oil sands deposits sometimes have a mobile
fluid zone
above the bitumen or heavy oils. In such deposits, the mobile fluid zone can
have a
significant saturation of gas which acts as the "thief zone" and when
recovering the bitumen
or heavy oils using a steam-based recovery process, a pressure in the gas zone
that is lower
than the steam pressure used in the recovery may be detrimental to the
recovery since a
flow of steam into the thief zone can lead to steam loss. As the steam chamber
approaches
the gas zone, and if the steam pressure is kept higher than the gas zone
pressure, steam
3
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
and possibly some of the oil may be pushed into the gas zone. Recovery of
natural gas, in
association with recovery of the bitumen or heavy oils, could also lower
reservoir pressure,
thereby reducing oil recovery, and may result in the recovery of oil being
economically
prohibitive. None of CA 1,304,287, US 4,344,485, CA 2,096,034, US 5,211,230,
or CA
2,594,414 teach recovery of heavy oil from reservoirs having a gas zone.
[0011] Canadian Patent Application No. 2,594,413, titled "In situ
Combustion in Gas
Over Bitumen Formations", relates to heavy oil recovery from reservoirs having
a gas zone.
In the disclosed process, air is injected into a gas zone which overlies an
oil sand, in situ
combustion is initiated within the gas zone, and the resulting combustion
gases horizontally
displace the natural gas to nearby production wells for recovery. The gas zone
may be in
pressure communication with the heavy oil and combustion gases may re-
pressurize the
natural gas reservoir, which may facilitate the recovery of the heavy oil
using SAGD.
[0012] Canadian Patent Application No. 2,692,204 to Sanmiguel et al.-
(2010) titled
"Gas-Cap Air Injection for Thermal Oil Recovery", relates to heavy oil
recovery from
reservoirs having a gas zone. The disclosed process produces bitumen or heavy
oil from a
subsurface oil sands reservoir that is in fluid communication with an
overlying gas zone. The
method includes: providing an in situ combustion process in the overlying gas
zone to create
or expand a combustion front within the overlying gas zone, providing a
thermal recovery
process in the oil sands reservoir to create or expand a rising hot zone
within the oil sands
reservoir, and selectively operating the thermal recovery process or the in
situ combustion
process or both such that the rising hot zone does not intersect the overlying
gas zone until
the combustion front has moved beyond that portion of the overlying gas zone
at the
intersection. As noted on page 6 of CA 2,692,204, "If the thermal recovery
process occurs
early and the rising heated fluid... enters the gas zone 30 before the
combustion front 90 has
passed... the in situ combustion process within the gas zone 30 will be
compromised or at
least negatively impacted."
[0013] U.S. Patent Applications No. 20120205096A1 and 20120205127A1 teach
a
method for displacing water from a porous geological formation where
pressurized gas is
injected into a zone and barrier wells are operated to achieve a hydraulic
pressure barrier
surrounding the zone. The gas displaces water downward within the zone such
that water is
produced at the water production wells.
4
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
SUMMARY
[0014] It is an object of the present disclosure to obviate or mitigate
at least one
disadvantage of previous processes that relate to heavy oil recovery from
reservoirs having a
mobile fluid zone above a bitumen zone.
[0015] According to one aspect, there is provided a process that
includes:
generating, in the bitumen zone and through a mobility enhancing process, a
mobilized zone
by recovering at least some of the original oil-in-place; injecting an
oxidizing gas through an
oxidizing gas injection well into the reservoir to support in situ combustion
in the reservoir;
generating fluid communication between the mobile fluid zone and the mobilized
zone; and
recovering hydrocarbons mobilized by the in situ combustion using a
hydrocarbon production
well that is in fluid communication with the mobile fluid zone and the
mobilized zone, the in
situ combustion propagating at least in the mobilized zone.
[0016] The mobility enhancing process may be a steam-assisted hydrocarbon
recovery process, such as steam-assisted gravity drainage.
[0017] The mobility enhancing process may generate the fluid
communication
between the mobile fluid zone and the mobilized zone. Alternatively, the
mobilized zone and
the mobile fluid zone may not be in fluid communication before the in situ
combustion
process is initiated, and the in situ combustion may generate the fluid
communication
between the mobile fluid zone and the mobilized zone.
[0018] The process may further include producing combustion gases through
a
combustion gas production well. The hydrocarbon production well and the
combustion gas
production well may be a generally horizontal well pair. The generally
horizontal well pair
may be used to generate the mobilized zone through the mobility enhancing
process.
[0019] Alternatively, the hydrocarbon production well and the oxidizing
gas injection
well may be a generally horizontal well pair. The generally horizontal well
pair may be used
to generate the mobilized zone through the mobility enhancing process. The
process may
further include producing combustion gases through a combustion gas production
well. The
combustion gas production well may be a former mobility enhancing process well
that is in
gaseous communication with the oxidizing gas injection well.
[0020] The oxidizing gas may be injected continuously or may be injected
intermittently.
[0021] Water may be injected in addition to the oxidizing gas.
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
[0022] The mobile fluid zone may be a gas zone. The oxidizing gas may be
injected
into the gas zone or into the mobilized zone. The in situ combustion may
propagate through
the mobilized zone and through the mobile fluid zone.
[0023] Alternatively, mobile fluid zone may be a water zone. The
oxidizing gas may
be injected into the mobilized zone. The in situ combustion may generate steam
from water
in the water zone and the generated steam may aid in the mobilization of
hydrocarbons in
the reservoir.
[0024] According to another aspect, there is provided a process for
hydrocarbon
recovery from an oil sands reservoir having a gas zone above a bitumen zone.
The process
includes: utilizing a generally horizontal well pair to generate, through
steam-assisted gravity
drainage, a steam chamber in the bitumen zone that is in gaseous communication
with the
gas zone. The generally horizontal well pair includes: a generally horizontal
segment of a
hydrocarbon production well, and a generally horizontal segment of a steam
injection well.
The process includes injecting an oxidizing gas into the gas zone through an
oxidizing gas
injection well that includes an oxidizing gas injection segment. The oxidizing
gas supports in
situ combustion in the reservoir and the in situ combustion propagates at
least in the steam
chamber. The process further includes recovering hydrocarbons mobilized by the
in situ
combustion using the hydrocarbon production well; and producing combustion gas
through
the steam injection well. The generally horizontal segment of the steam
injection well is
disposed generally parallel to and spaced vertically above the horizontal
segment of the
hydrocarbon production well, and the injection segment of the oxidizing gas
injection well is
spaced generally above the segment of the hydrocarbon production well and
generally above
the segment of the steam injection well.
[0025] According to a further aspect, there is provided a process for
hydrocarbon
recovery from an oil sands reservoir having a water zone above a bitumen zone.
The
process includes: generating, in the bitumen zone and through steam-assisted
gravity
drainage, a steam chamber in the bitumen zone that is in fluid communication
with the water
zone; injecting an oxidizing gas through an oxidizing gas injection well into
the steam
chamber to support in situ combustion in the reservoir and the in situ
combustion
propagating at least in the steam chamber; generating steam by heating water
in the water
zone through the in situ combustion, the generated steam aiding in mobilizing
hydrocarbons
in the reservoir; and recovering hydrocarbons mobilized by the in situ
combustion using a
6
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
hydrocarbon production well that is in fluid communication with the water zone
and the steam
chamber.
[0026] Other aspects and features of the present disclosure will become
apparent to
those ordinarily skilled in the art upon review of the following description
of specific
embodiments in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0027] Embodiments of the present disclosure will now be described, by
way of
example only, with reference to the attached Figures.
[0028] FIG. 1 is an illustration of an exemplary well configuration which
may be used
in a process according to the present disclosure.
[0029] FIG. 2 is an illustration of another exemplary well configuration
which may be
used in a process according to the present disclosure.
[0030] FIG. 3 is an illustration of yet another exemplary well
configuration which may
be used in a process according to the present disclosure.
[0031] FIG. 4 illustrates an exemplary well configuration used in a
computer
simulation model.
[0032] FIG. 5 shows a graph illustrating the cumulative oil and gas
production rates
for the simulation model.
[0033] FIG. 6 illustrates the oil saturation profile at the start of the
simulation.
[0034] FIG. 7 illustrates the temperature profile after one month of SAGD
operation of
the simulation.
[0035] FIG. 8 illustrates the temperature profile of the simulation model
after 8
months of air injection.
[0036] FIG. 9 illustrates the oil saturation in the simulation model
after 8 months of air
injection.
[0037] FIG. 10 illustrates the mole fraction of oxygen in the gas phase
after 8 months
of air injection.
[0038] FIG. 11 illustrates the temperature profile after 22 months of air
injection.
[0039] FIG. 12 illustrates the oil saturation in the simulation model
after 82 months of
air injection.
7
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
[0040] FIG. 13 illustrates the mole fraction of oxygen in the simulation
model after 88
months of air injection.
[0041] FIG. 14 illustrates the temperature profile in the simulation
model after 88
months of air injection.
DETAILED DESCRIPTION
[0042] For simplicity and clarity of illustration, reference numerals may
be repeated
among the figures to indicate corresponding or analogous elements. Numerous
details are
set forth to provide an understanding of the examples described herein. The
examples may
be practiced without these details. In other instances, well-known methods,
procedures, and
components are not described in detail to avoid obscuring the examples
described. The
description is not to be considered as limited to the scope of the examples
described herein.
[0043] Heavy oil recovery techniques, such as SAGD, create mobilized
zones in an
oil sands reservoir, from which at least some of the original oil-in-place has
been recovered.
Steam injection methods such as cyclic-steam stimulation (CSS) and steam
assisted gravity
drainage (SAGD) are, to date, the most commercially successful in situ heavy
oil and
bitumen recovery methods. However, continued improvements and reduction in
steam to oil
ratio (SOR) are desirable. A mobilized zone created using a SAGD process may
be
considered to be a mobile zone chamber.
[0044] In situ combustion (ISC) has been used in combination with steam-
based
recovery to reduce the overall SOR. However, in viscous heavy oil reservoirs,
such as oil
sands reservoirs, the heavy oil lacks of sufficient fluid mobility and
inhibits the injection of the
oxidizing gas into the reservoir at sufficiently high rate to create the
conditions for ignition and
propagation of a combustion front. That is, heavy oil reservoirs do not have
enough fluid
mobility for the heavy oils to be displaced when a gas expands into the heavy
oil reservoir.
[0045] One advantage of the process according to the present disclosure,
over a
process that uses ISC in combination with a mobility enhancing recovery
process in a
reservoir that does not include a mobile fluid zone, is that the presently
disclosed process
can be initiated earlier due to the presence of the mobile fluid zone above a
bitumen zone. It
is no longer required that the mobility enhancing recovery process reach a
stage of maturity
before switching to in situ combustion. This results in a faster process
compared to
reservoirs without a mobile fluid zone. For cases where the mobilized zone is
generated
8
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
using a steam-based mobility enhancing process, a faster switchover to in situ
combustion
may reduce the amount of water used to produce the same amount of
hydrocarbons.
[0046] Within the context of the present disclosure, reference is made to
zones or
regions, such as bitumen zones, gas zones, and water zones. It will be
understood by those
skilled in the art that this does not require that the reservoir within a
particular zone or region
be saturated with the recited component. For example, a "bitumen zone" may
contain both
bitumen and water distributed throughout the porous structure. In a particular
example of a
"bitumen zone", in a virgin rich oil sand, the pores may be 80 percent
saturated with bitumen
and 20 percent saturated with connate water.
[0047] In the context of the present disclosure, a "mobile fluid zone" is
a zone with
enough fluid mobility for at least some of the components of the zone to be
displaced when a
pressure differential is imposed into the mobile fluid zone. Mobile fluid
zones may be, for
example: gas zones and water zones. A mobile fluid zone may have less than 50%
bitumen
saturation. In an example, a mobile fluid zone may contain bitumen, water and
gas
distributed through the porous structure. In another example of a mobile fluid
zone, the pores
may contain predominantly gas with a relatively small bitumen saturation
distributed
throughout the porous medium. A mobile fluid zone may have sufficient
hydrocarbons to
support in situ combustion.
[0048] The present disclosure generally provides a process for
hydrocarbon recovery
from an oil sands reservoir having a mobile fluid zone above a bitumen zone.
The process
includes: generating, in the bitumen zone and through a mobility enhancing
process, a
mobilized zone by recovering at least some of the original oil-in-place;
injecting an oxidizing
gas through an oxidizing gas injection well into the mobile fluid zone or into
the mobilized
zone to support in situ combustion in the reservoir; generating fluid
communication between
the mobile fluid zone and the mobilized zone; and recovering hydrocarbons
mobilized by the
in situ combustion using a hydrocarbon production well that is in fluid
communication with the
mobile fluid zone and the mobilized zone, the in situ combustion propagating
at least in the
mobilized zone.
[0049] The mobility enhancing process may be a steam-assisted hydrocarbon
recovery process, such as steam-assisted gravity drainage. As used herein, the
term
"mobility enhancing process well" should be understood to refer to a well
which is used to
provide a mobility enhancer, such as heat, solvent, or both, to promote the
movement of the
9
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
hydrocarbons toward the production well. Examples of a mobility enhancer
include: steam,
hot water, methane, hydrocarbon solvents, a heat source, or combinations
thereof. An
example of a steam-assisted hydrocarbon recovery well pair includes: a SAGD
well pair. An
example of a steam-assisted hydrocarbon recovery well includes: cyclic-steam
stimulation
well. An example of a non-steam based recovery method includes:
electromagnetic heating.
[0050] The fluid communication between the mobile fluid zone and the
mobilized
zone may be generated by the mobility enhancing process before the in situ
combustion.
Alternatively, the in situ combustion may be started when the mobilized zone
and the mobile
fluid zone are not in fluid communication, and the fluid communication between
the mobile
fluid zone and the mobilized zone may be generated by the in situ combustion.
[0051] The in situ combustion propagates at least in the mobilized zone.
Since the in
situ combustion in the mobilized zone is fueled by residual hydrocarbons in
the oil sands
deposits, the hydrocarbons in the oil sands deposit may be un-depleted, or may
be partially
depleted prior to the process disclosed herein.
[0052] The hydrocarbon production well may be a generally horizontal
well, a
generally vertical well, or a generally inclined well. The hydrocarbon
production well may
have a combination of different segments which are independently generally
vertical,
generally inclined, or generally horizontal. The hydrocarbon production well
may be located
anywhere in fluid communication with the mobilized zone. For example, the
hydrocarbon
production well may be close to the bottom of the hydrocarbon deposit to
collect the
mobilized hydrocarbons that flow toward the bottom due to gravity.
[0053] The oxidizing gas injection well may be located such that an
oxidizing gas
injection segment is located in gaseous communication with the mobilized zone.
For
example, the oxidizing gas injection segment may be in the mobilized zone, or
may be in the
mobile fluid zone if the mobile fluid zone is a gas zone.
[0054] The oxidizing gas injection well may be a generally horizontal
well, a generally
vertical well, or a generally inclined well. The oxidizing gas injection well
may have a
combination of different segments which are independently generally vertical,
generally
inclined, or generally horizontal. The oxidizing gas injection well may be
completed with one
or more discrete injection locations. In some examples, the oxidizing gas
injection well injects
the oxidizing gas along the length of a generally horizontal production well.
This may be
accomplished, for example, by using a generally horizontal oxidizing gas
injection well that is
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
parallel to a generally horizontal production well and that has a plurality of
discrete oxidizing
gas injection locations; or by using a plurality of vertical oxidizing gas
injection wells aligned
along the length of a generally horizontal production well.
[0055] Combustion gases generated from the in situ combustion may be
produced
through a combustion gas production well, or through the hydrocarbon
production well. If a
combustion gas production well is used, it may be a generally horizontal well,
a generally
vertical well, or a generally inclined well. The combustion gas production
well may have a
combination of different segments which are independently generally vertical,
generally
inclined, or generally horizontal. The combustion gas production well may be
located in the
mobile fluid zone, or in the mobilized zone.
[0056] The hydrocarbon production well may be a well that is unrelated to
the well or
wells used to generate the mobilized zone. For example, a single well may be
used as a
mobility enhancing process well to generate the mobilized zone and a different
well may be
used as the hydrocarbon production well to recover hydrocarbons mobilized by
the in situ
combustion. In such an example, the mobility enhancing process well may be a
well used for
cyclic steam stimulation.
[0057] Alternatively, the hydrocarbon production well may be the
production well in a
well or wells used to generate the mobilized zone. For example, a single well
may be used to
generate the mobilized zone, for example using cyclic steam stimulation, and
that same well
may be used as the hydrocarbon production well to recover hydrocarbons
mobilized by the in
situ combustion. In another example, a well pair may be used to generate the
mobilized zone
where: (1) the former hydrocarbon production well from the well pair may be
used as the
hydrocarbon production well to recover the hydrocarbons mobilized by the in
situ
combustion, and (2) the former mobility enhancing process well from the well
pair may be
used as the oxidizing gas injection well or as the combustion gas production
well.
[0058] In examples where the former hydrocarbon recovery well pair is a
generally
horizontal well pair and the former mobility enhancing process well is used as
the
combustion gas production well, the oxidizing gas injection well may inject
the oxidizing gas
along the length of the generally horizontal well pair. This may be
accomplished, for
example, by using a generally horizontal oxidizing gas injection well that is
parallel to the
generally horizontal well pair and that has a plurality of discrete oxidizing
gas injection
11
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
locations; or by using a plurality of vertical oxidizing gas injection wells
aligned along the
length of the generally horizontal well pair.
[0059] In processes that use steam as the mobility enhancer, such as
SAGD, steam
is injected into the steam injection well to mobilize the hydrocarbons and
create a steam
chamber in the reservoir, around and above the generally horizontal segment.
It may be
beneficial if the oxidizing gas injection segment is located generally above
both the steam
injection well and the hydrocarbon production well. Wells having such a
configuration take
advantage of gravity segregation between the oxidizing gas and the liquids,
including the
hydrocarbons. By virtue of the density difference between gases and liquids,
the liquids,
including the hydrocarbons, tend to accumulate in the lower portion of the
chamber, inhibiting
fingering of the oxidizing gas into the hydrocarbon production wells. The
oxidizing gas is
generally consumed at the combustion front. Thus, travel of oxidizing gas
ahead of the
combustion front, into a colder region of the chamber, is inhibited. This is
beneficial as travel
of oxidizing gas ahead of the combustion front may induce low temperature
oxidation
reactions and cause blocking problems in the reservoir. A "blocking problem"
would be
understood to refer to non-mobile oil blocking the movement of oxidizing gases
to the
combustion front.
[0060] It should be understood that an oxidizing gas injection well being
disposed
"generally vertically above" or "generally above" a steam injection well
refers to the injection
segment of an oxidizing gas injection well being less than 75 from a vertical
line extending
through the steam injection well. In particular embodiments, the injection
segment of an
oxidizing gas injection well is less than about 60 from the vertical line. In
preferred
embodiments, the injection segment of an oxidizing gas injection well is less
than about 45
from the vertical line. The terms "directly vertically above" and "directly
above" refer to
embodiments where the injection segment of an oxidizing gas injection well is
less than
about 5 from a vertical line extending through the steam injection well. The
terms would
similarly denote the spatial relationship of any other two wells.
[0061] In processes that use steam as the mobility enhancer, such as
SAGD,
additional components may be added to the injected steam. For example: light
hydrocarbons, such as C3 through C10 alkanes, may optionally be injected with
the steam.
The volume of light hydrocarbons that are injected is relatively small
compared to the volume
of steam injected. The addition of light hydrocarbons is referred to as a
solvent-assisted
12
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
process (SAP). SAGD and SAP processes are both examples of mobility enhancing
processes. The SAGD or SAP processes may also be augmented or enhanced by
inclusion
of other substances, such as: non-condensing gases, for example: nitrogen or
oxygen;
surfactants; steam additives; or any combination thereof. Viscous hydrocarbons
in the
bitumen zone are heated and mobilized and the mobilized hydrocarbons drain,
under the
effects of gravity. The mobilized hydrocarbons are collected and produced from
the
hydrocarbon production well.
[0062] A mobility enhancing process may be performed for a period of time
until the
mobilized zone is in fluid communication with the mobile fluid zone. When the
mobility
enhancing process is SAGD, this may be achieved by injecting steam through a
steam
injection well and recovering oil until the steam chamber is in fluid
communication with the
mobile fluid zone. Sensors such as pressure and temperature sensors located in
the steam
injection well, in the hydrocarbon production well, in the oxidizing gas
injection well, or any
combination thereof, may be utilized to detect when the steam chamber is in
fluid
communication with the mobile fluid zone. Alternatively or additionally,
observation wells
drilled into the reservoir may be utilized to determine that the steam
injected is in fluid
communication with the mobile fluid zone. Steam front monitoring may also be
utilized to
determine that the injected steam is in fluid communication with the mobile
fluid zone.
Sensors and monitoring methods may also be used when the mobility enhancing
process is
a process other than SAGD.
[0063] Prior to ignition to start ISC in the oxidizing gas injection
well, steam may be
injected into the oxidizing gas injection wellbore to remove liquid
hydrocarbons surrounding
the wellbore. This injected steam raises the temperature of part of the
reservoir, for example,
to about 150 C. Alternatively, a volatile oil mixture may be added to the
formation and then
displaced by steam injection followed by injection of a non-condensing gas,
for example
nitrogen. For example, steam may be injected for about one day, followed by
nitrogen
injection for about one day. The steam, or steam and subsequent nitrogen, is
used to reduce
the amount of combustible materials from the immediate vicinity of the
oxidizing gas injection
wellbore and thereby reduce high temperature exposure and consequent damage to
the
steel.
[0064] ISC is carried out by injecting an oxidizing gas through the
oxidizing gas
injection well. The in situ combustion propagates at least in the mobilized
zone. The oxidizing
13
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
gas may be injected continuously for continuous combustion, or may be injected
intermittently. Combustion may be initiated utilizing an artificial igniter,
such as a downhole
heater, or by using spontaneous ignition. The oxidizing gas that is injected
may be, for
example, air, enriched air, diluted air, or any other suitable gas including
oxygen. The in situ
combustion may be managed to mobilize hydrocarbons in the heavy oil by
controlling: the
rate, the pressure, or both of oxidizing gas injected through the oxidizing
gas injection well;
the rate, the pressure, or both of production of combustion gases from the
former steam
injection well; the rate, the pressure, or both of hydrocarbon production from
the hydrocarbon
production well; or any combination thereof.
[0065] Optionally, water may be injected in addition to the oxidizing
gas. For
example, water may be injected at the same time as, or in sequence with, the
oxidizing gas.
The water may be injected through the same well as the oxidizing gas, or
through separate
wells. Injected water, water already present in the reservoir, or both may
result in a wet
combustion process and steam generation. The generated steam may facilitate
the flow of
heated hydrocarbons to the hydrocarbon production well since the generated
steam
promotes heat transfer in the oil sands reservoir.
[0066] In processes that use a former SAGD steam injection well as the
combustion
gas production well, the oxidizing gas is injected through the oxidizing gas
injection well and
into the reservoir. The generated combustion gases are produced from the
former steam
injection well, now the combustion gas production well, since they are driven
into the
generally horizontal segment of the steam injection well. The hydrocarbons
that are
mobilized as a result of the combustion process drain to the generally
horizontal segment
and are recovered through the hydrocarbon production well. Thus, the steam
injection well
and the hydrocarbon production well utilized in the SAGD process are utilized
in this example
of the process to collect the combustion gases and to produce the mobilized
hydrocarbons,
respectively. In this way, the SAGD well pair is advantageously re-utilized.
[0067] Infill producer wells, which may have been added as concurrent
supplements
to the SAGD process, are not required for the ISC process but may be used as
hydrocarbon
production wells.
[0068] A benefit to utilizing a combustion gas production well that is
separate from a
hydrocarbon production well, is that the hydrocarbons that are produced are
separated from
the combustion gases downhole, thereby reducing the chance of oxidizing gas
and
14
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
combustion gases communicating with the hydrocarbon production well. That is,
it reduces
the chance that oxidizing gases, combustion gases, or both will escape via the
hydrocarbon
production well. This reduction may result in the combustion front being more
easily
controlled. This reduction may additionally reduce high volumes of combustion
gases flowing
into the hydrocarbon production well, which could restrict the flow of
hydrocarbons into the
hydrocarbon production well. Corrosion of metals, such as well tubes, and
other well
apparatus, may be mitigated and surface facilities design may be facilitated
as the gases and
hydrocarbons are substantially separated downhole. Notwithstanding the
desirability of
collecting these fluid streams at separate wells, it should be understood that
the well which
collects the combustion gases may also produce some hydrocarbons.
Correspondingly, the
hydrocarbon production well may produce some combustion gases.
[0069] The ISC process that is carried out, referred to as top-down in
situ
combustion, takes advantage of gravity segregation between the oxidizing gas
and the
liquids, including the hydrocarbons. By virtue of the density difference
between gases and
liquids, the liquids, including the hydrocarbons, tend to accumulate in the
lower portion of the
chamber, inhibiting fingering of the oxidizing gas into the hydrocarbon
production wells. The
oxidizing gas is generally consumed at the combustion front. Thus, travel of
oxidizing gas
ahead of the combustion front, into a colder region of the chamber, is
inhibited. This is
beneficial as travel of oxidizing gas ahead of the combustion front may induce
low
temperature oxidation reactions and cause blocking problems in the reservoir.
A "blocking
problem" would be understood to refer to non-mobile oil blocking the movement
of oxidizing
gases to the combustion front.
[0070] For reservoirs where the mobile fluid zone is a gas zone, the gas
zone may
have sufficient hydrocarbons to support in situ combustion. The in situ
combustion may be
initiated once the mobilized zone is in gaseous communication with the gas
zone, or may be
initiated in order to generate gaseous communication between the mobilized
zone and the
gas zone. The in situ combustion may propagate in both the mobilized zone and
in the gas
zone. Since the in situ combustion in the gas zone is fueled by hydrocarbons
within the gas
zone, the gas zone may be un-depleted, or may be partially depleted prior to
the process
disclosed herein.
[0071] When the mobile fluid zone is a gas zone, the pressure in the gas
zone may
be greater than, about the same as, or less than the pressure of the gasses in
the mobilized
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
zone. It may be desirable to operate the mobility enhancing process at a
pressure lower than
the pressure of the gas in the gas zone in order to expedite gaseous
communication
between mobilized zone and the gas zone.
[0072] The oil sands deposit may have mobile fluid zones comprising non-
combustible gases, such as air zones, that are formed as a result of natural
depletion of the
hydrocarbons. The oil sands deposits may have mobile fluid zones that been
formed by
displacing one mobile fluid with another mobile fluid. For example a liquid,
such as water,
may be displaced from the mobile fluid zone using pressurized gas injected
into the mobile
fluid zone. Specific examples of methods of formation of such mobile fluid
zones are
described in U.S. Patent Applications No. 20120205096A1 and 20120205127A1.
[0073] In processes that use injected steam as the mobility enhancer and
the mobile
fluid zone is a gas zone, it may be preferable to drill the oxidizing gas
injection well prior to
the steam chamber being in gaseous communication with the oxidizing gas
injection well in
order to avoid drilling through a high temperature, high pressure reservoir.
For example, the
oxidizing gas injection well may be drilled into the gas zone before the steam
chamber is in
gaseous communication with the gas zone. In another example, the oxidizing
well may be
drilled into a portion of the reservoir that becomes a part of the steam
chamber.
[0074] For reservoirs where the mobile fluid zone is a water zone, the in
situ
combustion may be initiated once the mobilized zone is in fluid communication
with the water
zone. The in situ combustion may propagate primarily in the mobilized zone and
may
produce steam through heating water in the water zone. The produced steam may
aid in the
mobilization of hydrocarbons in the reservoir.
[0075] In one exemplary process according to the present disclosure, the
process
includes generating a steam chamber using a steam-assisted hydrocarbon
recovery process,
such as SAGD, in a bitumen zone that is below a gas zone. The generated steam
chamber
is in gaseous communication with the gas zone. Oxidizing gas is injected in
the gas zone to
support in situ combustion in the reservoir. The oxidizing gas is injected
using an oxidizing
gas injection well. In this example, the former steam injection well used in
the steam-assisted
hydrocarbon recovery process is used as the combustion gas production well,
and the former
hydrocarbon production well used in the steam-assisted hydrocarbon recovery
process is
used as the hydrocarbon production well for the in situ combustion. The in
situ combustion
propagates at least in the mobilized zone. In this example, the former steam
injection well
16
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
and the former hydrocarbon production well are a generally horizontal well
pair, and the
oxidizing gas injection well is a generally horizontal well that injects the
oxidizing gas along
the length of the generally horizontal well pair through a plurality of
discrete oxidizing gas
injection locations.
[0076] In another exemplary process according to the present disclosure,
the process
includes generating a steam chamber using a steam-assisted hydrocarbon
recovery process,
such as SAGD, in a bitumen zone that is below a water zone. The generated
steam chamber
is in fluid communication with the water zone. Oxidizing gas is injected in
the steam chamber
to support in situ combustion in the reservoir. The oxidizing gas is injected
using an oxidizing
gas injection well. The in situ combustion propagates at least in the steam
chamber. The in
situ combustion may produce steam through heating the water in the water zone.
The
produced steam may aid in the mobilization of hydrocarbons in the water zone,
in the
mobilized zone, or both. In this example, the former steam injection well used
in the steam-
assisted hydrocarbon recovery process is used as the combustion gas production
well, and
the former hydrocarbon production well used in the steam-assisted hydrocarbon
recovery
process is used as the hydrocarbon production well for the in situ combustion.
[0077] In still another example of a process according to the present
disclosure, the
mobile fluid zone is a gas zone and the process includes generating a
mobilized zone
through a mobility enhancing process, and injecting an oxidizing gas through
an oxidizing
gas injection well into the gas zone or into the mobilized zone, the oxidizing
gas supporting in
situ combustion in the reservoir. The process includes generating gaseous
communication
between the gas zone and the generated mobilized zone. The oxidizing gas is
injected using
a former mobility enhancing process well. Another former mobility enhancing
process well
that is in gaseous communication with the oxidizing gas injection well is used
as a
combustion gas production well. The in situ combustion propagates at least in
the mobilized
zone. Hydrocarbons mobilized through the in situ combustion are removed from
the bottom
of the reservoir using the former hydrocarbon production well used in the
mobility enhancing
process. Additional gas production wells may be drilled in the gas zone or in
the mobilized
zone.
[0078] In yet another example of a process according to the present
disclosure,
where the mobile fluid zone is a gas zone, the process includes: using a
generally horizontal
well pair to generate, through steam-assisted gravity drainage, a steam
chamber that is in
17
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
gaseous communication with the gas zone, where the generally horizontal well
pair includes:
a generally horizontal segment of a hydrocarbon production well, and a
generally horizontal
segment of a steam injection well; injecting an oxidizing gas into the gas
zone through an
oxidizing gas injection well including an oxidizing gas injection segment, the
oxidizing gas
supporting in situ combustion in the reservoir and the in situ combustion
propagating at least
in the steam chamber; recovering hydrocarbons mobilized by the in situ
combustion using
the hydrocarbon production well; and producing combustion gas through the
steam injection
well. In such an example, the generally horizontal segment of the steam
injection well is
disposed generally parallel to and spaced vertically above the horizontal
segment of the
hydrocarbon production well, and the injection segment of the oxidizing gas
injection well is
spaced generally above the segment of the hydrocarbon production well and
generally above
the segment of the steam injection well.
[0079] Although examples discussed above discuss a steam-assisted
hydrocarbon
recovery process, and specifically SAGD, being carried out before in situ
combustion, it
should be understood that mobility enhancing processes other than steam-
assisted recovery
may be used. For example, hot water, methane, hydrocarbon solvents, a heat
source, or
combinations thereof may alternatively be used to establish fluid
communication between the
oxidizing gas injection well and the hydrocarbon recovery well.
[0080] One specific example of a generally horizontal well pair which may
be used in
the process disclosed herein is illustrated in FIG. 1. Although the
illustration and
corresponding discussion relates specifically to SAGD, it should be understood
that other
mobility enhancing processes may be used and, accordingly, the discussed steam
injection
well may be substituted with another "mobility enhancing process well" and the
discussed
steam chamber would be a corresponding "mobilized zone". Further, although the
illustration
and corresponding discussion relates specifically to gas zones located above
the bitumen
zone, it should be understood that the process would be applicable in
reservoirs having other
mobile fluid zones.
[0081] As illustrated in FIG 1, the hydrocarbon production well includes
a generally
horizontal segment 10 that extends near the base or bottom of the bitumen
zone. The steam
injection well also includes a generally horizontal segment 16 that is
disposed generally
parallel to and is spaced generally vertically above the horizontal segment 10
of the
hydrocarbon production well.
18
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
[0082] The oxidizing gas injection well 18 is located with the gas
injection segment in
the gas zone 20 such that the segment extends generally parallel to the
generally horizontal
segments 16 of steam injection well. The illustration in FIG. 1 shows the
reservoir before
gaseous communication has been generated between the gas zone 20 and the steam
chamber 22.
[0083] It would be understood that an oxidizing gas injection well could
provide
oxidizing gas to mobilize hydrocarbons that are produced through more than one
hydrocarbon production well, as illustrated in FIG. 2. The illustration in
FIG. 2 shows the
reservoir before gaseous communication has been generated between the gas
zones 20 and
the steam chambers 22.
[0084] It would also be understood that a plurality of well pairs may be
utilized at
spaced-apart locations in the reservoir and a plurality of oxidizing gas
injection wells may be
utilized to provide oxidizing gas to mobilize hydrocarbons. It should be
understood that it is
not necessary to match the number of oxidizing gas injection wells to the
number of steam
injections wells. For example, two oxidizing gas injection wells may be used
in combination
with three steam injection well, as illustrated in FIG. 3. In this example,
three SAGD well
pairs and two oxidizing gas injection wells 18 located with the gas injection
segment in the
gas zone 20 such that the injection segment extends generally parallel to the
generally
horizontal segments 16 of steam injection well.
[0085] FIG. 3 illustrates the reservoir after gaseous communication has
been
generated between the gas zone 20 and the steam chambers 22. As illustrated,
the steam
chamber on the left and the steam chamber in the middle are both in direct
gaseous
communication with each other and are in direct gaseous communication with the
gas zone.
The steam chamber on the right is in direct gaseous communication with the gas
zone, and
is in gaseous communication with the other two steam chambers through the gas
zone.
Examples
Example 1.
[0086] A computer simulation was run to model an oil sands recovery
process where
two SAGD well pairs and one gas producer well were used to recover
hydrocarbons. In the
simulation, the two oxidizing gas injection wells were located directly
vertically above the two
19
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
SAGD well pairs and the gas producer well was located within the gas zone,
equally laterally
spaced apart from the two SAGD well pairs.
[0087] The configuration is illustrated in FIG. 4.
[0088] FIG. 5 shows a graph illustrating the cumulative oil and gas
production rates
for the simulation model.
[0089] FIG. 6 illustrates the oil saturation profile at the start of the
simulation (2000-
01-01). Original oil saturation in the gas zone is 20%, gas saturation is 60%
and connate
water is 20%. The initial reservoir temperature is 8 C.
[0090] FIG. 7 shows the temperature profile after one month of SAGD
operation
(2000-02-01). The reservoir has reached a maximum temperature of 170 C and
communication has been established between the mobilized zones created by the
SAGD
process and the overlying gas zone.
[0091] After one month of SAGD, the SAGD process is finalized and in situ
combustion is instigated in the reservoir by injecting air into the oxidizing
gas injection wells.
The previous steam injector is shut in and the gas producer in the gas zone
starts operating.
[0092] FIG. 8 shows the temperature profile at 2000-09-01 after 8 months
of air
injection. The combustion front has been ignited and is propagating towards
the hydrocarbon
producing wells as indicated by the elevated temperature profile.
[0093] FIG. 9 shows the oil saturation in the simulation model at 2000-09-
01. Oil
saturation around the air injector is preferably zero when the combustion
front is initiated as
the residual oil saturation is consumed as fuel during the in situ combustion
process.
[0094] FIG. 10 shows the mole fraction of oxygen in the gas phase at 2000-
09-01.
The oxygen has been consumed by the combustion process at the vicinity of the
oxidizing
gas injection wells.
[0095] FIG. 11 shows the temperature profile at 2001-12-01. The
combustion front is
advancing towards the gas producer and expanding both in the gas zone as well
as in the
heavy oil zone.
[0096] FIG. 12 shows the oil saturation for the simulation model at 2006-
12-01.
[0097] FIG. 13 shows the mole fraction of oxygen for the simulation model
at 2007-
06-01.
CA 02856914 2014-07-11
BLG Ref No. PAT 102389-1
[0098] FIG. 14 shows the temperature profile for the simulation model at
2007-06-01.
The figures illustrate that the combustion front has progressed significantly
into the heavy oil
zone.
[0099] The described examples are to be considered in all respects only
as
illustrative and not restrictive. The scope of the claims should not be
limited by the preferred
embodiments set forth in the examples, but should be given the broadest
interpretation
consistent with the description as a whole. All changes that come with meaning
and range of
equivalency of the claims are to be embraced within their scope.
21
