Note: Descriptions are shown in the official language in which they were submitted.
IN SITU HYDROCARBON RECOVERY FROM PAY ZONES BETWEEN LOW
PERMEABILITY LAYERS IN A STRATIFIED RESERVOIR REGION
TECHNICAL FIELD
[0001] The technical field generally relates to in situ recovery of
hydrocarbons and, more
particularly, to hydrocarbon recovery from pay zones defined between low
permeability
layers of a reservoir.
BACKGROUND
[0002] Steam-assisted gravity drainage (SAGD) is an enhanced hydrocarbon
recovery
technology for producing hydrocarbons, such as heavy oil and/or bitumen, from
subsurface reservoirs. Typically, a pair of horizontal wells is drilled into a
hydrocarbon-
bearing reservoir, such as an oil sands reservoir, and steam is continuously
injected into
the reservoir via the upper injection well to heat and reduce the viscosity of
the
hydrocarbons. The mobilized hydrocarbons drain into the lower production well
and are
recovered to the surface. Over time, a steam chamber forms above the injection
well
and extends upward and outward within the reservoir as the mobilized
hydrocarbons
flow toward the producer well.
[0003] Certain reservoirs, such as oil sands reservoirs, often include a main
pay zone
including relatively permeable matrices, such as sandy matrices, and can also
include
inclined heterolithic strata (IHS) or other regions characterized by spaced-
apart layers of
low permeability material. IHS are often located at an upper part of the
reservoir and
overlie the main pay zone. Generally speaking, IHS can be thought of as
heterogeneous
deposits that exhibit notable depositional dip, and include layers of higher
permeability
material (e.g., sandy oil-bearing layers) and lower permeability material
(e.g., shale
lamina and/or mud-dominated layers). IHS can be found, for example, in the
McMurray
formation in Alberta, Canada. Recovering hydrocarbons from IHS zones can be
relatively challenging due to the permeability barriers and baffles that are
present.
[0004] In the case of reservoirs including IHS, producing hydrocarbons by
gravity
drainage from the IHS can be difficult. The difficulties can be due to
challenges in
establishing a counter-current flow between the IHS and the main pay zone, and
due to
the low permeability of certain layers of the IHS. In a gravity drainage
process, an
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injected mobilizing fluid, such as steam, a surfactant, and/or a solvent,
moves upward
into and occupies the space previously occupied by hydrocarbons so that the
mobilized
hydrocarbons can drain downward toward the producer well. In a reservoir which
does
not include IHS, this counter-current flow phenomenon can occur more easily
throughout
the permeable pay zone of the reservoir. However, in a reservoir having an
interval
including IHS or other types of geological structures that include low
permeability layers,
heating the IHS as well as draining the hydrocarbons from the IHS can be
relatively slow
and inefficient at least partly because of the difficulty of establishing a
counter-current
flow between the main pay zone and the IHS.
[0005] Co-injection of non-condensable gas (NCG) and steam into a permeable
pay
zone via SAGD injection wells is known. However, co-injection of steam and NCG
via
the SAGD injection well can lead to NCG being produced to surface within the
production fluid instead of accumulating in the SAGD chamber as desired. In
the case of
reservoirs including a main pay zone and an overlying IHS, it may be difficult
for the co-
injected NCG to reach the interior of the IHS.
[0006] IHS and other reservoir regions that include spaced-apart low
permeability layers
can contain relevant quantities of hydrocarbons, which are relatively
challenging to
recover.
SUMMARY
[0007] In some implementations, there is provided a method for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic
strata (IHS), the method comprising:
operating a steam-assisted gravity drainage (SAGD) well pair in the main pay
zone which includes a steam chamber and producing hydrocarbons from the
main pay zone, the steam chamber extending upward within the main pay zone
toward the IHS;
providing a vertical well extending from the surface into the IHS and a top
region
of the main pay zone, the vertical well comprising:
an IHS well portion within the IHS; and
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a pay zone well portion extending from the IHS well portion into an upper
region of the main pay zone;
wherein the IHS well portion and the pay zone well portion comprise a
completion with perforations; and
injecting a non-condensable gas (NCG) via the vertical well through the
perforations into the IHS, forming an NCG-enriched zone in the IHS.
[0008] In some implementations, the NCG is further injected into the upper
region of the
main pay zone and the NCG-enriched zone extends into the top region of the
main pay
zone. In some implementations, injecting the NCG is performed so as to provide
gas
drive to promote displacement of hydrocarbons in the IHS downward into the
main pay
zone. In some implementations, the displacement of hydrocarbons in the IHS
downward
into the main pay zone comprises flowing from the IHS into the pay zone well
portion
through the perforations, and then out of an open end of the pay zone well
portion into
the main pay zone of the reservoir. In some implementations, injecting the NCG
is
performed so as to create a back pressure sufficient to reduce steam override
from the
steam chamber into the IHS.
[0009] In some implementations, the vertical well is located substantially
directly above
the SAGD well pair. In some implementations, the vertical well is located in
between two
adjacent SAGD well pairs.
[0010] In some implementations, the method further includes isolating the
vertical well
with an isolation packer so as to provide an upper injection segment for
injecting NCG
into the IHS, and a lower conduit segment for allowing fluids to flow from the
IHS through
the lower conduit segment into the main pay zone.
[0011] In some implementations, there is provided a method for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic
strata (INS), the method comprising:
operating a thermal in situ hydrocarbon recovery process including:
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injecting a mobilizing fluid into the main pay zone of the reservoir, and
producing
mobilized hydrocarbons from the main pay zone, thereby forming a hydrocarbon-
depleted zone; and
operating a vertical well section extending into the reservoir, the vertical
well
section comprising an IHS well portion within the IHS and having perforations
providing fluid communication between the vertical well section and
surrounding
permeable layers of the IHS, wherein the operating comprises injecting non-
condensable gas (NCG) via the vertical well section into the surrounding
permeable layers of the IHS.
[0012] In some implementations, injecting the NCG is performed so as to form
an NCG-
rich insulation layer above or at a top region of the main pay zone. In some
implementations, injecting the NCG is performed so as to provide gas drive to
promote
displacement of hydrocarbons in the IHS downward into the main pay zone. In
some
implementations, the vertical well section is a lateral branch section
extending from an
overlying or underlying horizontal well. In some implementations, the vertical
well section
is part of a single vertical well extending downward from the surface.
[0013] In some implementations, the thermal in situ hydrocarbon recovery
process
comprises SAGD. In some implementations, the thermal in situ hydrocarbon
recovery
process comprises cyclic steam stimulation (CSS).
[0014] In some implementations, there is provided a method for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic
strata (IHS), the method comprising:
injecting a mobilizing fluid into the main pay zone to obtain mobilized
hydrocarbons and pressurise the main pay zone at a pay zone pressure;
producing the mobilized hydrocarbons from the main pay zone, thereby forming a
hydrocarbon-depleted zone; and
operating an IHS well section extending into the IHS and having perforations
providing fluid communication between the IHS well section and surrounding
permeable layers of the IHS, wherein the operating comprises:
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injecting an injection fluid into an upper region of the IHS via the
perforations of the IHS well section, wherein the IHS well section is kept
at a well section pressure equal to or higher than the pay zone pressure;
and
allowing hydrocarbons to flow from a lower region of the IHS to the main
pay zone through a corresponding portion of the IHS well section.
[0015] In some implementations, the injection fluid comprises NCG. In some
implementations, the NCG provides gas drive to promote displacement of
hydrocarbons
in the IHS zone downward into the main pay zone. In some implementations, the
injection fluid further comprises at least one of a solvent and a surfactant.
[0016] In some implementations, the IHS well section is a vertical IHS well
section. In
some implementations, the vertical well section is a lateral branch section
extending
from an overlying or underlying horizontal well. In some implementations, the
vertical
well section is part of a single vertical well extending downward from the
surface.
[0017] In some implementations, there is provided a method for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic
strata (INS), the method comprising:
operating an IHS well section extending into the IHS, the IHS well section
comprising:
an outer liner comprising perforations providing fluid communication
between the IHS well section and surrounding permeable layers of the
IHS;
an inner tube located within the outer liner, the inner tube and the outer
liner forming an annulus therebetween;
an isolation packer located within the annulus to define an upper injection
segment isolated from the tube and a lower production segment in fluid
communication with the tube;
wherein the operating of the IHS well section comprises:
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injecting an injection fluid through the upper injection segment into an
upper region .of the IHS; and
producing hydrocarbons from a lower region of the IHS, such that the
hydrocarbons flow into the lower production segment and through the
tube for recovery at surface.
[0018] In some implementations, the IHS well section is a vertical IHS well
section. In
some implementations, the vertical well section is a lateral branch section
extending
from an overlying or underlying horizontal well. In some implementations, the
vertical
well section is part of a single vertical well extending downward from the
surface. In
some implementations, the outer liner comprises a slotted liner.
[0019] In some implementations, there is provided a method for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic
strata (IHS), the method comprising:
operating a multilateral IHS well comprising:
a main well section; and
multiple branch well sections extending from the main well section into the
IHS and being in fluid communication with surrounding permeable layers
of the IHS;
wherein the operating of the multilateral IHS well comprises:
injecting an injection fluid via the branch well sections into the surrounding
permeable layers of the IHS.
[0020] In some implementations, the main well section is a section of a
horizontal well.
In some implementations, the horizontal well is located in the IHS. In some
implementations, the horizontal well is located in the main pay zone. In some
implementations, the multiple branch sections are vertical branch sections. In
some
implementations, the injection fluid comprises NCG. In some implementations,
the
injection fluid further comprises at least one of a solvent and a surfactant.
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(0021] In some implementations, there is provided a system for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic
strata (IHS), the system comprising:
a SAGD well pair comprising:
an injection well located within the main pay zone for injecting a first
injection fluid therein; and
a producer well located within the main pay zone for producing production
fluids comprising the hydrocarbons; and
a vertical well provided with perforations and drilled through the IHS and
into an
upper region of the main pay zone, the vertical well having an IHS well
portion
and a pay zone well portion and being configured to inject a second injection
fluid
into the IHS.
[0022] In some implementations, the vertical well facilitates providing fluid
communication and equalization of the pressure between the IHS zone and the
main
pay zone. In some implementations, the second injection fluid comprises at
least one of
a NCG, a solvent and a surfactant. In some implementations, the first
injection fluid
comprises steam. In some implementations, the vertical well is provided with a
slotted
liner. In some implementations, the vertical well comprises a casing. In some
implementations, the casing is a thermal casing. In some implementations, the
vertical
well comprises a thermal wellhead. In some implementations, the vertical well
comprises
thermal cement. In some implementations, the vertical well allows the
hydrocarbons
from the IHS to flow from the IHS into part of the IHS well portion and
through the pay
zone well portion into the main pay zone. In some implementations, the
vertical well is
provided with an isolation packer in the IHS well portion, thereby separating
the IHS well
portion into an upper injection segment and a lower production segment. In
some
implementations, the second injection fluid is injected into the IHS via the
upper injection
segment.
[0023] In some implementations, the vertical well is located substantially
directly above
the SAGD well pair. In some implementations, the vertical well is located in
between two
adjacent SAGD well pairs.
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[0024] In some implementations, there system also includes additional vertical
wells
drilled through the IHS and into the upper region of the main pay zone, the
additional
vertical wells being configured to inject the second injection fluid into the
IHS for driving
hydrocarbons from the IHS to the main pay zone.
[0025] In some implementations, there is provided system for recovering
hydrocarbons
from a reservoir having a main pay zone and overlying inclined heterolithic
strata (IHS),
the system comprising:
a SAGD well pair comprising:
an injection well located within the main pay zone for injecting a first
injection fluid therein; and
a producer well located within the main pay zone for producing production
fluids comprising the hydrocarbons; and
a well drilled through the IHS and into an upper region of the main pay zone,
the
well having an IHS well portion and a pay zone well portion, the well
comprising:
an outer liner comprising perforations and providing fluid communication
between the well and surrounding permeable layers of the IHS;
an inner tube located within the outer liner, the inner tube and the outer
liner forming an annulus therebetween;
an isolation packer located within the annulus to define an upper injection
segment isolated from the tube and a lower production segment in fluid
communication with the tube;
wherein the well is configured to inject a second injection fluid through the
upper
injection segment into an upper region of the IHS; and produce the
hydrocarbons
from a lower region of the IHS, such that the hydrocarbons from the lower
region
of the IHS flow into the lower production segment and through the tube for
recovery at surface.
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[0026] In some implementations, there is provided method for recovering
hydrocarbons
from a pay zone located in between low permeability layers in a stratified
region of a
reservoir, the method comprising:
operating a well extending into the reservoir, the well comprising:
a casing surrounding the well, comprising a perforated portion provided
along at least part of the pay zone;
an inner tube located within the casing, the inner tube and the casing
forming an annulus therebetween, the inner tube being in fluid
communication with the pay zone via the perforated portion;
an isolation device located within the annulus, for isolating the inner tube,
the perforated portion and the pay zone from other parts of the well,
the operating of the well comprising:
injecting a mobilizing fluid into the pay zone through the inner tube via the
perforated portion, in order to obtain mobilized hydrocarbons in the low
permeability layer; and
producing the mobilized hydrocarbons via the well.
[0027] In some implementations, the isolation device comprises: a first
isolation packer
provided within the annulus, at the first end of the pay zone, and a second
isolation
packer provided within the annulus, at the second end of the pay zone.
[0028] In some implementations, injecting the mobilizing fluid and producing
the
mobilized hydrocarbons are performed cyclically. In some implementations,
injecting the
mobilizing fluid and producing the mobilized hydrocarbons is performed
simultaneously.
[0029] In some implementations, the inner tube is an injection inner tube for
injecting the
mobilizing fluids and the well further comprising a production inner tube for
producing the
mobilized hydrocarbons.
[0030] In some implementations, the mobilized hydrocarbons are produced via a
second
well extending into the reservoir and through the pay zone. In some
implementations,
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the well is a slanted well or a vertical well. In some implementations, the
well is a
converted segment of a pre-existing SAGD well, the converted segment being
perforated to obtain the perforated well portion.
[0031] In some implementations, the low permeability layers and the pay zone
are part
of inclined heterolithic strata (IHS). In some implementations, the IHS is
overlying a main
pay zone of the reservoir.
[0032] In some implementations, the mobilizing fluid comprises steam and a
steam
chamber is formed in the pay zone. In some implementations, the mobilizing
fluid further
comprises at least one of a non-condensable gas, a solvent and a surfactant.
[0033] In some implementations, there is provided a system for recovering
hydrocarbons from a reservoir comprising a stratified region comprising low
permeability
layers and a pay zone defined there-between, the system comprising a well
extending
into the reservoir through the pay zone, the well comprising:
a casing surrounding the well, comprising a perforated portion provided along
at
least part of the pay zone;
an inner tube located within the casing, the inner tube and the casing forming
an
annulus therebetween, the inner tube being in fluid communication with the pay
zone via the perforated portion;
a first isolation packer located within the annulus and provided at a top end
of the
pay zone; and
a second isolation packer located within the annulus and provided at a bottom
end of the pay zone, wherein the well is configured to:
inject a mobilizing fluid into the pay zone through the inner tube via the
perforated portion, in order to obtain mobilized hydrocarbons; and
produce the mobilized hydrocarbons.
[0034] In some implementations, the perforated portion of the casing comprises
injection
perforations for injecting the mobilizing fluid there-through, the injection
perforations
being located proximate to the top end of the pay zone. In some
implementations, the
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perforated portion of the casing comprises production perforations for
recovering
mobilized hydrocarbons there-through, the production perforations being
located
proximate to the bottom end of the pay zone. In some implementations, the
inner tube is
an injection inner tube for injecting the mobilizing fluids and the well
further comprising a
production inner tube for producing the mobilized hydrocarbons.
[0035] In some implementations, the production inner tube comprises a screen
for
screening solid material from produced fluids comprising the mobilized
hydrocarbons. In
some implementations, the screen comprises a sand screen. In some
implementations,
the screen is provided along the pay zone.
[0036] In some implementations, there is also a flow control device for
controlling a flow
of mobilizing fluid from the perforated portion to the pay zone and/or from
the perforated
portion to other portions of the well. In some implementations, there is also
a pump for
recovering the mobilized hydrocarbons.
[0037] In some implementations, the well is a slanted well or a vertical well.
[0038] In some implementations, the pay zone and the low permeability layers
are part
of inclined heterolithic strata (IHS) overlying a main pay zone of the
reservoir.
[0039] In some implementations, the well is a converted segment of a pre-
existing
SAGD well, the converted segment being perforated to obtain the perforated
portion of
the casing.
[0040] In some implementations, the mobilizing fluid comprises steam and a
steam
chamber is formed in the pay zone. In some implementations, the mobilizing
fluid further
comprises at least one of a non-condensable gas, a solvent and a surfactant.
[0041] In some implementations, there is provided a system for recovering
hydrocarbons from a reservoir comprising a stratified region comprising low
permeability
layers and a pay zone defined there-between, the system comprising:
an injection well extending into the reservoir through the pay zone, the
injection
well comprising:
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a casing surrounding the injection well, comprising a perforated injection
portion
provided along at least part of the pay zone;
an inner tube located within the casing, the inner tube and the casing forming
an
annulus therebetween, the inner tube being in fluid communication with the pay
zone via the perforated portion;
a first isolation packer located within the annulus and provided at a top end
of the
pay zone; and
a second isolation packer located within the annulus and provided at a bottom
end of the pay zone, wherein the injection well is configured to inject a
mobilizing
fluid into the pay zone through the inner tube via the perforated injection
portion,
in order to obtain mobilized hydrocarbons; and
a production well extending into the reservoir through the pay zone, the
production
well comprising a perforated production portion provided along at least part
of the
pay zone for allowing fluid communication between the pay zone and the
production
well, wherein the production well is configured to produce the mobilized
hydrocarbons through the perforated production portion.
[0042] In some implementations, the perforated injection portion of the
injection well is
located proximate to the top end of the pay zone. In some implementations, the
perforated production portion of the production well is located proximate to
the bottom
end of the pay zone.
[0043] In some implementations, the production well comprises a screen for
screening
solid material from produced fluids comprising the mobilized hydrocarbons. In
some
implementations, the screen comprises a sand screen. In some implementations,
the
screen is provided along pay zone.
[0044] In some implementations, the injection well further comprises a flow
control
device for controlling a flow of mobilizing fluid from the perforated portion
to the pay zone
and/or from the perforated portion to other portions of the well.
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[0045] In some implementations, the injection well is a slanted injection well
or a vertical
injection well. In some implementations, the production well is a slanted
production well
or a vertical production well.
[0046] In some implementations, the low permeability layers and the pay zone
are part
of inclined heterolithic strata (IHS) overlying a main pay zone of the
reservoir.
[0047] In some implementations, the injection well and the production well are
each a
converted segment of a pre-existing SAGD well, the converted segment being
perforated to obtain the respective perforated injection portion and
perforated production
portion.
[0048] In some implementations, the mobilizing fluid comprises steam and a
steam
chamber is formed in the pay zone. In some implementations, the mobilizing
fluid further
comprises at least one of a non-condensable gas, a solvent and a surfactant.
[0049] In some implementations, there is provided a method for recovering
hydrocarbons from a stratified region of a reservoir, the stratified region
comprising low
permeability layers and pay zones located between corresponding adjacent pairs
of the
low permeability layers, the pay zones comprising at least a first pay zone
and a second
pay zone, the first pay zone being located above the second pay zone, the
method
corn prising:
operating a well extending into the reservoir, the well comprising:
a first perforated well portion extending through the first pay zone and in
fluid communication with the first pay zone; and
a second perforated well portion downstream of the first perforated well
portion, extending through the second pay zone and in fluid
communication with the second pay zone;
wherein operating the well comprises:
injecting a mobilizing fluid comprising steam into the first perforated well
portion, via the well;
dividing the mobilizing fluid of the first perforated well portion,
comprising:
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directing a first portion of the mobilizing fluid into the first pay zone,
so as to form a first steam chamber therein and obtain mobilized
hydrocarbons in the first pay zone; and
directing a second portion of the mobilizing fluid into the second
perforated well portion;
directing at least part of the second portion of the mobilizing fluid into the
second pay zone, so as to form a second steam chamber in the second
pay zone and obtain mobilized hydrocarbons in the second pay zone;
isolating an interior of the first perforated well portion from to the second
perforated well portion and other portions of the well; and
isolating an interior of the second perforated well portion from the first
perforated well portion and the other portions of the well; and
producing the mobilized hydrocarbons of the first pay zone and the mobilized
hydrocarbons of the second pay zone.
[0050] In some implementations, there is provided a method for recovering
hydrocarbons from a pay zone located in between low permeability layers in a
stratified
region of a reservoir, the method comprising:
operating an injection well extending into the reservoir, the injection well
comprising:
a casing surrounding the injection well, comprising a perforated injection
portion provided along at least part of the pay zone;
an inner tube located within the casing, the inner tube and the casing
forming an annulus therebetween, the inner tube being in fluid
communication with the pay zone via the perforated injection portion;
an isolation device located within the annulus, for isolating the inner tube,
the perforated injection portion and the pay zone from other parts of the
well,
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the operating of the injection well comprising:
injecting a mobilizing fluid into the pay zone through the inner tube via the
perforated injection portion, in order to obtain mobilized hydrocarbons in
the pay zone; and
operating a production well for producing the mobilized hydrocarbons, the
production
well extending into the reservoir through the pay zone, and comprising a
perforated
production well portion in fluid communication with the pay zone.
[0051] In some implementations, the perforated injection well portion is
located at a
higher level than the perforated production well portion. In some
implementations,
operating the production well comprises: draining the mobilized hydrocarbons
from the
pay zone into the perforated production well portion; and displacing the
mobilized
hydrocarbons from the perforated production well portion to surface. In some
implementations, draining the mobilized hydrocarbons is predominantly
performed by
gravity draining.
[0052] In some implementations, method for recovering hydrocarbons from a pay
zone
located in between low permeability layers in a stratified region of a
reservoir, the
method comprising:
providing a well extending into the reservoir, the well comprising a
perforated well
portion extending from a first end of the pay zone to a second end of the pay
zone, the perforated well portion being in fluid communication with the pay
zone;
injecting a mobilizing fluid into the pay zone via the well through the
perforated
well portion, in order to obtain mobilized hydrocarbons; and
producing the mobilized hydrocarbons.
[0053] In some implementations, the method includes isolating the perforated
well
portion. In some implementations, isolating the perforated well portion
comprises
providing an interior of the well with: a first isolation packer at the first
end of the pay
zone, and a second isolation packer at the second end of the pay zone.
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[0054] In some implementations, injecting the mobilizing fluid and producing
the
mobilized hydrocarbons is performed cyclically. In some implementations,
injecting the
mobilizing fluid and producing the mobilized hydrocarbons is performed
simultaneously.
[0055] In some implementations, the mobilized hydrocarbons are produced via
the well.
In some implementations, the mobilized hydrocarbons are produced via a second
well
extending into the reservoir and through the pay zone.
[0056] In some implementations, the well is a slanted well or a vertical well.
In some
implementations, the well is a converted segment of a pre-existing SAGD well,
the
converted segment being perforated to obtain the perforated well portion.
[0057] In some implementations, the low permeability layers and the pay zone
are part
of inclined heterolithic strata (IHS). In some implementations, the IHS is
overlying a main
pay zone of the reservoir.
[0058] In some implementations, the mobilizing fluid comprises steam and a
steam
chamber is formed in the pay zone. In some implementations, the mobilizing
fluid further
comprises at least one of a non-condensable gas, a solvent and a surfactant.
[0059] In some implementations, the pay zone is at least one meter thick, or
between
one and ten meters thick. In some scenarios, the pay zone has a thickness
preventing
economic recovery using conventional SAGO methods with horizontal well
sections
accessing the pay zone.
[0060] In some implementations, method for recovering hydrocarbons from a
reservoir
having a main pay zone and overlying inclined heterolithic strata (IHS), the
method
comprising:
operating a gravity drainage well pair in the main pay zone which includes a
mobilized chamber and producing hydrocarbons from the main pay zone, the
mobilized chamber extending upward within the main pay zone toward the IHS;
providing a vertical well extending from the surface into the IHS and a top
region
of the main pay zone, the vertical well comprising:
an IHS well portion within the IHS; and
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a pay zone well portion extending from the IHS well portion into an upper
region of the main pay zone;
wherein the IHS well portion and the pay zone well portion comprise a
completion with perforations; and
injecting a non-condensable gas (NCG) via the vertical well through the
perforations into the IHS, forming an NCG-enriched zone in the IHS.
[0061] In some implementations, the gravity drainage well pair is a SAGD well
pair
injecting steam into the main pay zone to form a steam chamber as the
mobilized
chamber. In some implementations, the gravity drainage well pair comprises a
solvent
injection well for injecting solvent into the main pay zone to form a solvent-
mobilized
chamber as the mobilized chamber. In some implementations, the solvent is
injected as
a vapour into the main pay zone and condenses within the solvent-mobilized
chamber.
In some implementations, the solvent comprises propane, butane, pentane or a
combination thereof.
[0062] In some implementations, the method includes the step of pre-heating a
region of
the main pay zone prior to and/or during start-up of the gravity drainage well
pair. In
some implementations, the pre-heating comprises electromagnetic heating. In
some
implementations, the pre-heating comprises electric heating. In some
implementations,
the pre-heating comprises radio-frequency heating. In some implementations,
the pre-
heating comprises circulation of solvent through at least one of the wells of
the well pair.
In some implementations, heating the main pay zone and/or a region of the IHS
using
electromagnetic heating during normal operation. The pre-heating can be part
of a well
pair start-up operation.
[0063] In some implementations, method for recovering hydrocarbons from a
reservoir
having a main pay zone and overlying inclined heterolithic strata (IHS), the
method
comprising:
establishing fluid communication between a well pair in the main pay zone,
including circulating or injection a solvent, the well pair including an
injection well
and a production well;
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CA 3006750 2018-05-29
operating the well pair in the main pay zone under solvent-assisted gravity
drainage, comprising:
injecting solvent in vapour phase through the injection well to form a
solvent-mobilized chamber in the main pay zone, the solvent-mobilized
chamber extending upward within the main pay zone toward the IHS; and
producing hydrocarbons from the main pay zone;
providing a vertical well extending from the surface into the IHS and a top
region
of the main pay zone, the vertical well comprising:
an IHS well portion within the IHS; and
a pay zone well portion extending from the IHS well portion into an upper
region of the main pay zone;
wherein the IHS well portion and the pay zone well portion comprise a
completion with perforations; and
injecting a non-condensable gas (NCG) via the vertical well through the
perforations into the IHS, forming an NCG-enriched zone in the IHS.
[00641 In some implementations, there is provided a method for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic
strata (INS), the method comprising:
establishing fluid communication between a well pair in the main pay zone,
including circulating or injection a solvent and heating with radio-frequency
energy, the well pair including an injection well and a production well;
operating the well pair in the main pay zone under solvent-assisted gravity
drainage while providing radio-frequency energy to heat the main pay zone,
comprising:
injecting solvent through the injection well to form a solvent-mobilized
chamber in the main pay zone, the solvent-mobilized chamber extending
upward within the main pay zone toward the IHS; and
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CA 3006750 2018-05-29
producing hydrocarbons from the main pay zone;
providing a vertical well extending from the surface into the IHS and a top
region
of the main pay zone, the vertical well comprising:
an IHS well portion within the IHS; and
a pay zone well portion extending from the IHS well portion into an upper
region of the main pay zone;
wherein the INS well portion and the pay zone well portion comprise a
completion with perforations; and
injecting a non-condensable gas (NCG) via the vertical well through the
perforations into the IHS, forming an NCG-enriched zone in the IHS.
[0065] In some implementations, there is provided a method for recovering
hydrocarbons from a pay zone located in between low permeability layers in a
stratified
region of a reservoir, the method comprising:
operating a well extending into the reservoir, the well comprising:
a casing surrounding the well, comprising a perforated portion provided
along at least part of the pay zone;
an inner tube located within the casing, the inner tube and the casing
forming an annulus therebetween, the inner tube being in fluid
communication with the pay zone via the perforated portion;
an isolation device located within the annulus, for isolating the inner tube,
the perforated portion and the pay zone from other parts of the well,
the operating of the well comprising:
injecting a solvent in vapour phase into the pay zone through the inner
tube via the perforated portion such that the solvent condenses within the
pay zone, in order to obtain mobilized hydrocarbons in the low
permeability layer; and
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CA 3006750 2018-05-29
producing a mixture comprising condensed solvent and the mobilized
hydrocarbons via the well.
[0066] In some implementations, there is provided a method for recovering
hydrocarbons from a stratified region of a reservoir, the stratified region
comprising low
permeability layers and pay zones located between corresponding adjacent pairs
of the
low permeability layers, the pay zones comprising at least a first pay zone
and a second
pay zone, the first pay zone being located above the second pay zone, the
method
comprising:
operating a well extending into the reservoir, the well comprising:
a first perforated well portion extending through the first pay zone and in
fluid communication with the first pay zone; and
a second perforated well portion downstream of the first perforated well
portion, extending through the second pay zone and in fluid
communication with the second pay zone;
wherein operating the well comprises:
injecting a solvent in vapour phase into the first perforated well portion,
via
the well;
dividing the solvent of the first perforated well portion, comprising:
directing a first portion of the solvent into the first pay zone, so as
to form a first solvent chamber therein and obtain mobilized
hydrocarbons in the first pay zone, the first portion of the solvent
condensing within the first pay zone; and
directing a second portion of the solvent into the second perforated
well portion;
directing at least part of the second portion of the solvent into the second
pay zone, so as to form a second solvent chamber in the second pay
zone and obtain mobilized hydrocarbons in the second pay zone, the
second portion of the solvent condensing within the second pay zone;
CA 3006750 2018-05-29
isolating an interior of the first perforated well portion from to the second
perforated well portion and other portions of the well; and
isolating an interior of the second perforated well portion from the first
perforated well portion and the other portions of the well; and
producing the mobilized hydrocarbons and condensed solvent from the first pay
zone, and the mobilized hydrocarbons and condensed solvent from the second
pay zone.
[0067] In some implementations, there is provided a method for recovering
hydrocarbons from a pay zone located in between low permeability layers in a
stratified
region of a reservoir, the method comprising:
operating an injection well extending into the reservoir, the injection well
comprising:
a casing surrounding the injection well, comprising a perforated injection
portion provided along at least part of the pay zone;
an inner tube located within the casing, the inner tube and the casing
forming an annulus therebetween, the inner tube being in fluid
communication with the pay zone via the perforated injection portion;
an isolation device located within the annulus, for isolating the inner tube,
the perforated injection portion and the pay zone from other parts of the
well,
the operating of the injection well comprising:
injecting a solvent in vapour phase into the pay zone through the inner
tube via the perforated injection portion, in order to obtain mobilized
hydrocarbons in the pay zone; and
operating a production well for producing the mobilized hydrocarbons and
condensed solvent, the production well extending into the reservoir through
the pay
zone, and comprising a perforated production well portion in fluid
communication
with the pay zone.
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CA 3006750 2018-05-29
[0068] In some implementations, there is provided a method for recovering
hydrocarbons from a pay zone located in between low permeability layers in a
stratified
region of a reservoir, the method comprising:
providing a well extending into the reservoir, the well comprising a
perforated well
portion extending from a first end of the pay zone to a second end of the pay
zone, the perforated well portion being in fluid communication with the pay
zone;
injecting a solvent in vapour phase into the pay zone via the well through the
perforated well portion such that the solvent condenses within the pay zone,
in
order to obtain mobilized hydrocarbons; and
producing the mobilized hydrocarbons and condensed solvent.
[0069] In some implementations, there is provided a method for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic
strata (IHS), the method comprising:
establishing fluid communication between a well pair in the main pay zone,
including heating with radio-frequency energy, the well pair including an
injection
well and a production well;
operating the well pair in the main pay zone under solvent-assisted gravity
drainage, comprising:
injecting solvent through the injection well to form a solvent-mobilized
chamber in the main pay zone, the solvent-mobilized chamber extending
upward within the main pay zone toward the IHS;
heating the main pay zone with radio-frequency energy; and
producing hydrocarbons from the main pay zone;
providing a vertical well extending from the surface into the IHS and a top
region
of the main pay zone, the vertical well comprising:
an IHS well portion within the IHS; and
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CA 3006750 2018-05-29
a pay zone well portion extending from the IHS well portion into an upper
region of the main pay zone;
wherein the IHS well portion and the pay zone well portion comprise a
completion with perforations; and
injecting a non-condensable gas (NCG) via the vertical well through the
perforations into the IHS, forming an NCG-enriched zone in the IHS.
[0070] In some implementations, there is provided a method for recovering
hydrocarbons from a pay zone located in between low permeability layers in a
stratified
region of a reservoir, the method comprising:
operating a well extending into the reservoir, the well comprising:
a casing surrounding the well, comprising a perforated portion provided
along at least part of the pay zone;
an inner tube located within the casing, the inner tube and the casing
forming an annulus therebetween, the inner tube being in fluid
communication with the pay zone via the perforated portion;
an isolation device located within the annulus, for isolating the inner tube,
the perforated portion and the pay zone from other parts of the well,
the operating of the well comprising:
injecting a solvent into the pay zone through the inner tube via the
perforated portion and heating the pay zone with radio-frequency energy,
in order to obtain mobilized hydrocarbons in the pay zone; and
producing a mixture comprising solvent and the mobilized hydrocarbons via the
well.
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CA 3006750 2018-05-29
[0071] In some implementations, there is provided a method for recovering
hydrocarbons from a stratified region of a reservoir, the stratified region
comprising low
permeability layers and pay zones located between corresponding adjacent pairs
of the
low permeability layers, the pay zones comprising at least a first pay zone
and a second
pay zone, the first pay zone being located above the second pay zone, the
method
comprising:
operating a well extending into the reservoir, the well comprising:
a first perforated well portion extending through the first pay zone and in
fluid communication with the first pay zone; and
a second perforated well portion downstream of the first perforated well
portion, extending through the second pay zone and in fluid
communication with the second pay zone;
wherein operating the well comprises:
injecting a solvent into the first perforated well portion, via the well;
dividing the solvent of the first perforated well portion, comprising:
directing a first portion of the solvent into the first pay zone, so as
to form a first solvent chamber therein and obtain mobilized
hydrocarbons in the first pay zone; and
directing a second portion of the solvent into the second perforated
well portion;
directing at least part of the second portion of the solvent into the second
pay zone, so as to form a second solvent chamber in the second pay
zone and obtain mobilized hydrocarbons in the second pay zone,;
isolating an interior of the first perforated well portion from to the second
perforated well portion and other portions of the well; and
isolating an interior of the second perforated well portion from the first
perforated well portion and the other portions of the well; and
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CA 3006750 2018-05-29
producing the mobilized hydrocarbons and solvent from the first pay zone, and
the mobilized hydrocarbons and condensed solvent from the second pay zone.
[0072] In some implementations, there is provided a method for recovering
hydrocarbons from a pay zone located in between low permeability layers in a
stratified
region of a reservoir, the method comprising:
operating an injection well extending into the reservoir, the injection well
comprising:
a casing surrounding the injection well, comprising a perforated injection
portion provided along at least part of the pay zone;
an inner tube located within the casing, the inner tube and the casing
forming an annulus therebetween, the inner tube being in fluid
communication with the pay zone via the perforated injection portion;
an isolation device located within the annulus, for isolating the inner tube,
the perforated injection portion and the pay zone from other parts of the
well,
the operating of the injection well comprising:
injecting a solvent into the pay zone through the inner tube via the
perforated injection portion and heating the pay zone with radio-frequency
energy, in order to obtain mobilized hydrocarbons in the pay zone; and
operating a production well for producing the mobilized hydrocarbons and
solvent,
the production well extending into the reservoir through the pay zone, and
comprising a perforated production well portion in fluid communication with
the pay
zone.
[0073] In some implementations, there is provided a method for recovering
hydrocarbons from a pay zone located in between low permeability layers in a
stratified
region of a reservoir, the method comprising:
CA 3006750 2018-05-29
providing a well extending into the reservoir, the well comprising a
perforated well
portion extending from a first end of the pay zone to a second end of the pay
zone,
the perforated well portion being in fluid communication with the pay zone;
injecting a solvent into the pay zone via the well through the perforated well
portion
and heating the pay zone with radio-frequency energy, in order to obtain
mobilized
hydrocarbons; and
producing the mobilized hydrocarbons and condensed solvent.
[0073a] In some implementations, there is provided a method for recovering
hydrocarbons
from a reservoir having a main pay zone and overlying inclined heterolithic
strata (IHS),
the method comprising:
injecting a mobilizing fluid into the main pay zone to obtain mobilized
hydrocarbons and
pressurise the main pay zone at a pay zone pressure;
producing the mobilized hydrocarbons from the main pay zone, thereby forming a
hydrocarbon-depleted zone; and
operating an INS well section extending into the IHS and having perforations
providing fluid communication between the IHS well section and surrounding
permeable layers of the IHS, wherein the operating comprises:
injecting an injection fluid into an upper region of the IHS via the
perforations of
the IHS well section provided in an upper portion thereof, wherein the IHS
well
section is kept at a well section pressure equal to or higher than the pay
zone
pressure; and
allowing hydrocarbons to flow from a lower region of the IHS to the main pay
zone through a corresponding lower portion of the IHS well section.
[00731)] In some implementations, there is provided a system for recovering
hydrocarbons
from a reservoir having a main pay zone and overlying inclined heterolithic
strata (IHS),
the system comprising:
26
CA 3006750 2019-09-04
a well pair comprising:
an injection well located within the main pay zone for injecting a first
injection fluid therein; and
a producer well located within the main pay zone for producing production
fluids comprising the hydrocarbons, the producer well being located
vertically below the injection well and being aligned therewith; and
a well provided with perforations and drilled through the IHS and into an
upper
region of the main pay zone, the well having an IHS well section and a pay
zone
well section extending into the main pay zone, and being configured to inject
a
second injection fluid into an upper region of the IHS via the IHS well
section and
to allow flow of hydrocarbons from a lower region of the IHS to the main pay
zone
through a corresponding portion of the well.
[0073c] In some implementations, there is provided a method for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic strata (IHS), the method comprising:
operating an IHS well section extending into the IHS, the IHS well section
comprising:
an outer liner comprising perforations providing fluid communication
between the IHS well section and surrounding permeable layers of the
IHS;
an inner tube located within the outer liner, the inner tube and the outer
liner forming an annulus therebetween;
an isolation packer located within the annulus to define an upper injection
segment isolated from the inner tube and a lower production segment in
fluid communication with the inner tube;
wherein the operating of the IHS well section comprises:
26a
CA 3006750 2019-09-04
injecting an injection fluid through the upper injection segment into an
upper region of the IHS; and
producing hydrocarbons from a lower region of the IHS, such that the
hydrocarbons flow into the lower production segment and through the
inner tube for recovery at surface.
[0073d] In some implementations, there is provided a system for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic strata (IHS), the system comprising:
a well pair comprising:
an injection well located within the main pay zone for injecting a first
injection fluid therein; and
a producer well located within the main pay zone for producing production
fluids comprising the hydrocarbons; and
a well drilled into the IHS and having an IHS well section comprising:
an outer liner comprising perforations and providing fluid communication
between the well and surrounding permeable layers of the IHS;
an inner tube located within the outer liner, the inner tube and the outer
liner forming an annulus therebetween;
an isolation packer located within the annulus to define an upper injection
segment isolated from the inner tube and a lower production segment in
fluid communication with the inner tube;
wherein the well is configured to inject a second injection fluid through the
upper injection segment into an upper region of the IHS, and produce
mobilized hydrocarbons from a lower region of the IHS, such that the
26b
CA 3006750 2019-09-04
mobilized hydrocarbons from the lower region of the IHS flow into the
lower production segment and through the inner tube for recovery at
surface.
[0074] It should also be noted that various aspects, implementations, features
or steps
described or illustrated herein can be combined with other aspects,
implementations,
features or steps.
BRIEF DESCRIPTION OF THE DRAWINGS
[0075] Figure 1 is a cross-sectional view of a steam-assisted gravity drainage
(SAGD)
operation and part of a vertical well provided through inclined heterolithic
strata (IHS).
[0076] Figure 2 is a cross-sectional view of part of a vertical well provided
through IHS
and including an isolation packer.
[0077] Figure 3 is a cross-sectional view of part of a vertical well provided
through IHS,
and showing the co-injection of NCG and another injection fluid.
[0078] Figure 4 is a cross-sectional view of part of a vertical well provided
through IHS,
and including additional tubing for injecting fluids.
[0079] Figure 5 is cross-sectional view of part of a vertical well provided
through IHS, and
including additional tubing for producing hydrocarbons.
[0080] Figure 6 is a cross-sectional view of a SAGD operation and part of a
vertical well
extending through IHS.
[0081] Figure 7 is a cross-sectional view of a SAGD operation and part of a
multilateral
IHS well having a horizontal section and several vertical branch sections
extending into
the IHS.
IIIEEEEIII
26c
CA 3006750 2019-09-04
[0082] Figure 8 is a cross-sectional view of a SAGD operation where multiple
discrete
vertical wells are provided through the IHS.
[0083] Figure 9 is another cross-sectional view of a SAGD operation and a
vertical well
provided through IHS.
[0084] Figure 10 is a top plan view schematic of a SAGD operation including a
well pad,
an array of well pairs, and a configuration of vertical wells.
[0085] Figure 11 is a top plan view schematic of a SAGD operation including a
well pad,
an array of well pairs, and another configuration of vertical wells.
[0086] Figure 12 is cross-sectional view of part of a vertical well drilled in
IHS, including
additional tubing for producing hydrocarbons.
[0087] Figure 13 is a cross-sectional view of part of a SAGD well extending
through low
permeability layers of a reservoir, and including two isolation packers.
[0088] Figure 14 is a cross-sectional view of part of a well extending through
low
permeability layers of a reservoir.
[0089] Figure 15 is a cross-sectional view of part of a hydrocarbon recovery
system
including an injection well and a production well provided through low
permeability layers
of a reservoir.
[0090] Figure 16 is a cross-sectional view of part of a well provided through
several low
permeability layers of a reservoir.
[0091] Figure 17 is a cross-sectional view of part of a well provided through
low
permeability layers of a reservoir and configured to facilitate simultaneous
injection and
production.
[0092] Figure 18 is a cross-sectional view of part of a well including flow
control devices
provided through low permeability layers of a reservoir and configured to
facilitate
simultaneous injection and production.
[0093] Figure 19 is a cross-sectional view of part of a well including flow
control devices
provided through several low permeability layers of a reservoir.
27
CA 3006750 2018-05-29
[0094] Figure 20 is a cross-sectional view of part of a hydrocarbon recovery
system
including an injection well and a production well, each including flow control
devices and
provided through low permeability layers of a reservoir.
[0095] Figure 21 is a cross-sectional view of part of a well provided through
several low
permeability layers of a reservoir.
[0096] Figure 22 is a cross-sectional view schematic of part of a well pair
provided
through several low permeability layers of a reservoir.
[0097] Figures 23A to 23E are cross-sectional view schematics of part of a
well provided
through several low permeability layers of a reservoir with different dip
angles and well
inclinations.
[0098] Figure 24 is a partial perspective view schematic of a well having a
horizontal
section and a vertical section located relative to low permeability layers.
DETAILED DESCRIPTION
[0099] Various techniques are described herein for enhancing hydrocarbon
mobilization
and recovery from a stratified region of a reservoir that includes pay zones
defined in
between low permeability layers. In some scenarios, the stratified region
includes
inclined heterolithic strata (IHS) where the pay zones have thicknesses that
are
centimetre-scale or smaller, e.g., each IHS pay zone has a thickness that is
below 100
centimetres or below ten centimetres. In other scenarios, the stratified
region has thicker
pay zones have meter-scale thicknesses, e.g., between one meter and ten
meters.
Depending on the type and location of stratified region, the reservoir
properties, and/or
any proximate recovery system that may be operated, different techniques can
be used
to mobilize and recovery hydrocarbons from the pay zones.
[0100] Some techniques that are described herein enable enhanced thermal in
situ
recovery operations, such as steam-assisted gravity drainage (SAGD), by
leveraging the
use of a well, which can be a vertical well, extending through IHS located
above a main
pay zone of the reservoir. An injection fluid, such as non-condensable gas
(NCG) and/or
steam, can be injected through the well into the IHS. The NCG can penetrate
into
higher-permeability layers, sandy hydrocarbon-bearing layers, of the IHS in
order to
mobilize IHS hydrocarbons. The NCG injection can further penetrate into the
main pay
28
CA 3006750 2018-05-29
zone of the reservoir to provide a NCG-enriched zone at the top of the
reservoir so as to
enhance the thermal in situ recovery operation.
[0101] The well (also referred to as an IHS well) can be vertical and can be
provided
above a SAGD operation in order to inject NCG. However, other implementations
can
include alternate IHS well configurations, thermal in situ recovery
operations, and
injection fluids. For instance, the IHS well can be slanted, the IHS well can
be provided
in a reservoir which does not include a SAGD operation, and/or the reservoir
may not
necessarily include a main pay zone and the hydrocarbons may be mainly present
between the low permeability layers of the IHS. Some implementations of the
technology
will be described in greater detail below.
In situ hydrocarbon recovery operation implementations
[0102] Referring to Figure 1, in some implementations, there is provided a
method for
recovering hydrocarbons from a reservoir 10 having a main pay zone 12 and an
overlying interval including IHS 14, where a vertical IHS well 24 is provided
to enhance
certain aspects of the process. In some scenarios, the IHS 14 has an
inclination of
between about 5 and 15 . In some implementations, one or more SAGD well pairs
are
provided in the main pay zone 12. Each well pair includes a SAGD injection
well 16 and
a SAGD producer well 18. In some implementations, the well pair is located
near the
bottom of the main pay zone 12, and the injection well 16 and the producer
well 18 are
spaced approximately five metres apart with the injection well 16 being placed
above the
producer well 18. It is understood that the main pay zone 12 can include one
SAGD well
pair, two SAGD well pairs (as shown in Figure 1), or several SAGD well pairs.
In some
implementations, the SAGD well pairs can extend from a common well pad. For
example, the subsurface orientation of the SAGD well pairs (i.e., the well
pattern) can be
such that the SAGD well pairs are arranged in a generally parallel relation to
one
another. In some implementations, the SAGD well pair is operated to form a
steam
chamber 20 above the injection well 16 and to produce hydrocarbons 22 from the
reservoir via the producer well 18 disposed in the main pay zone 12. The
injection well
16 injects a mobilizing fluid including steam 21 into the main pay zone 12, so
as to form
the steam chamber 20, which extends upward and outward within the main pay
zone 12
and toward the IHS zone 14. This results in the mobilization of hydrocarbons
(e.g.,
bitumen and/or heavy oil) within the main pay zone 12, which can then drain
along with
29
CA 3006750 2018-05-29
steam condensate to the producer well 18 and be recovered to the surface as a
produced fluid, by mechanical or artificial lift techniques. The produced
fluid stream can
contain the hydrocarbons 22 as well as other materials such as condensed
water, gases
and various solids/minerals in dissolved or suspended form. As the mobilizing
fluid
approaches the IHS zone 14, heat transfer can enable heating of the
hydrocarbons of
the IHS zone.
[0103] Depending on the geological properties and configuration of the
reservoir 10,
some degree of counter-current flow 23 can occur between the IHS zone 14 and
the
main pay zone 12 as the mobilizing fluid approaches the IHS zone. The counter-
current
flow 23 enables a small portion of the heated hydrocarbons 22 from the IHS
zone 14 to
flow downward to the main pay zone 12 while steam 21 moves upward from the
main
pay zone 12 into the IHS zone 14. Such counter-current flow 23 between the IHS
zone
14 and the main pay zone 12 can account for some degree of the production of
hydrocarbons 22 from the reservoir, but is usually limited or sometimes
nonexistent in a
reservoir having IHS zones due to impermeable layers or low permeability
layers present
in the IHS zone.
[0104] It should also be noted that there may be different IHS zones within a
given
reservoir, occurring at different locations and elevations. In some scenarios,
a primary
dominant IHS zone is present overlying the main pay zone and extends
substantially
over the in situ hydrocarbon recovery wells, which can include multiple SAGD
well pairs
that can cover one or more square kilometres.
[0105] Referring briefly to Figure 9, the IHS zone can include low
permeability layers
(which can also be referred to as low permeability lamina, lenses or baffles)
having
different orientations, thicknesses and compositions, which form tortuous
paths that
generally discourage fluid flow. In some scenarios, vertical movement of
steam,
hydrocarbons and/or water is prevented or limited between low permeability
layers, but
fluids such as steam, hydrocarbons and/or water are typically able to diffuse
or
otherwise be displaced within each of the high permeability layers defined
between low
permeability layers and in which deposits of oil sands can be present.
[0106] While various implementations are described herein in relation to SAGD,
other in
situ hydrocarbon recovery operations can be used. For instance, cyclic steam
CA 3006750 2018-05-29
stimulation (CSS), in situ combustion, solvent-enhanced methods (e.g., gravity
drainage
techniques that use solvent(s) alone or in combination with steam in a single
well or well-
pair configuration), and/or other recovery processes can be used in order to
recover
hydrocarbons and form a hydrocarbon-depleted chamber within a main pay zone of
the
reservoir having an upper IHS zone or other types of stratified region. In
general, in situ
hydrocarbon recovery operations utilizing a mobilizing fluid to facilitate
hydrocarbon
recovery can have difficulty accessing IHS zones due to poor fluid
permeability into and
out of the IHS zones. As will be described further below, by providing and
operating what
may be called an "IHS well", such as a vertical or a slanted well extending
through the
IHS zone for injection of mobilizing fluid such as NCG and/or steam,
hydrocarbon
recovery operations can be enhanced.
Vertical MS well implementations
[0107] Still referring to Figure 1, in some implementations, a vertical well
24 can be
provided to enhance hydrocarbon recovery. The vertical well 24 extends from
the
surface, past the cap rock 26, and into the IHS zone 14 and a top region 28 of
the main
pay zone 12. The vertical well 24 includes an IHS well portion 30 and a pay
zone well
portion 32. In some implementations, completion of the vertical well 24 is
performed to
enable fluid injection into the IHS zone. For example, the vertical well can
have a casing,
be provided with perforations and/or be provided with a slotted or wire-
wrapped liner, or
other suitable configurations that allow flow of fluid. The perforations 34
can be provided
along the IHS and pay zone well portions 30, 32.
[0108] The expression "vertical well" refers to a well which is drilled
substantially
vertically with respect to the surface. In some scenarios, the IHS well can
have a certain
degree of deviation and may be inclined to some degree and still be considered
a
"vertical well" in this application. A "vertical well" is a well which can be
drilled without
using directional or slant drilling, although such drilling techniques can be
used to drill a
vertical well section that can be an IHS well as described herein.
[0109] It should be understood that the term "completion" can refer to
processes of
readying a well for injection and/or production and can also refer to
equipment that is
deployed within the well for such a purpose. As such, "completion" can involve
preparing
the well to required specifications, running into the well production and/or
injection
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CA 3006750 2018-05-29
tubing, deploying instrumentation down the well, cementing the well casing,
providing
perforations and/or slotted liner, as desired. In some implementations, the
vertical well
also includes a thermal wellhead, a thermal casing and/or thermal cement. The
thermal
completion components of the well are provided in order to enable injection
and/or
production of hot fluids and maintain fluid isolation of the targeted zone(s).
[0110] Still referring to Figure 1, in some implementations, NCG 36 is
injected via the
vertical well 24 into the IHS zone 14, to form an NCG-enriched zone above the
steam
chamber 20. Optionally, and depending on the NCG injection
pressure/conditions, as
well as the configuration of the vertical well 24, the NCG 36 can also be
injected via the
vertical well 24 into the top region 28 of the main pay zone 12. In some
scenarios, the
NCG injection is performed into the IHS zone after the steam chamber has
developed
sufficiently so as to approach or reach the lower part of the IHS zone. The
NCG-
enriched zone can facilitate prevention of heat loss and also encourage
lateral growth of
the steam chamber within the main pay zone 12. It should also be noted that
the NCG
injection conditions can be provided and controlled at different stages of the
in situ
hydrocarbon recovery operation, for example to increase or decrease NCG
injection
pressure or to add other injection fluids, to enable various recovery
conditions.
[0111] In some scenarios, NCG injection into the top region 28 of the main pay
zone 12
can facilitate maintaining reservoir pressure. More specifically, during the
later
production life of the reservoir, there is typically less demand for steam in
the depleted
reservoir and NCG can replace the steam for maintaining the pressure. Thus,
during
mature SAGD operations, the NCG can be injected at pressures and rates that
provide a
desired pressurizing effect within the reservoir. Further, the NCG-enriched
zone can
form an insulating layer in the general area between the IHS zone 14 and the
main pay
zone 12, thereby reducing the heat transfer from the main pay zone 12 to the
IHS zone
14. Such an insulating layer can be used to reduce heat loss, for example when
the IHS
is depleted of hydrocarbons.
[0112] In some scenarios, the injection of NCG 36 can provide gas drive to
promote
displacement of hydrocarbons in the IHS zone 14 downward into the main pay
zone 12.
In some scenarios, the gas drive can increase the direct transfer of
hydrocarbons from
the IHS zone 14 downward into the main pay zone 12, and/or promote
displacement of
hydrocarbons in the IHS zone 14 into part of the vertical well 24 and then
into the main
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CA 3006750 2018-05-29
pay zone 12. In the latter case, the vertical well 24 can thus act as a
conduit for
hydrocarbons in the IHS zone to bypass low permeability baffles and flow into
the main
pay zone from which the hydrocarbons can drain and eventually be recovered by
the
SAGD producer well.
[0113] In some scenarios, the injection of NCG 36 from the vertical well 24
into the IHS
14 and the top region 28 of the main pay zone 12 can also create a
backpressure (i.e.,
the NCG creates a pressurized zone above the steam chamber that discourages
upward
growth of the steam chamber and encourages lateral growth) for the rising
steam
chamber 20, thereby reducing steam override in the reservoir 10. This can have
the
effect of promoting lateral growth or "widening" of the steam chamber 20 for
improved
steam coverage and hydrocarbon mobilization within the main pay zone 12, which
can
lead to greater hydrocarbon recovery and production rates. In the event that
the IHS
includes a high permeability fissure that would allow substantial steam loss,
the NCG
pressurization within the fissure can help in reducing steam loss. It should
also be noted
that techniques described above can also be applicable in solvent-based
gravity
drainage processes where solvent is used in addition to or instead of steam as
the
mobilizing fluid.
[0114] In some scenarios, the drilling of the vertical well 24 into the IHS
zone 14 and
main pay zone 12, and the perforation of the vertical well 24 along the IHS
and pay zone
portions 30, 32 can facilitate providing fluid communication and equalization
of the
pressure between the IHS zone 14 and the main pay zone 12.
Pressure management implementations
[0115] In some scenarios, injection pressures of the NCG 36 in the IHS well 24
and of
the mobilizing fluid 21 in the main pay zone 12 are selected such that the
pressure in the
IHS well 24 is equal to or greater than the pressure of the steam chamber in
the main
pay zone 12, which can help reduce steam loss from the steam chamber 20 to the
IHS
zone 14. For example, the injection pressures can be selected such that a
pressure
gradient in the IHS well 24 allows for the NCG 36 to flow out of the IHS well
24 from a
top portion of the IHS well 24 and for the hydrocarbons of the IHS to flow
into the IHS
well 24, down the lower end of the well, and then out of the lower well
opening. It is
understood that the injection pressures are selected to be below the maximum
operating
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pressure at the injection zone. In other words, the operating pressures are
selected such
that the cap rock integrity is not compromised.
IHS well isolation implementations
[0116] Now referring to Figure 2, in some implementations, the interior of the
IHS well
24 can be provided with an isolation packer 38 in order to facilitate certain
functionalities.
The packer 38 can enable the IHS 24 well to be divided into an injection
section through
which NCG 36 or other fluids can be injected out, and a flow conduit section
through
which fluids are allowed to flow into the IHS well, down the lower end of the
well, and
then out of the lower well opening. In some implementations, the isolation
packer 38 can
be installed at a packer depth in the IHS portion 30 of the IHS well 24. For
example, the
packer 38 can be installed several metres above the main pay zone, such as
about five
to ten metres above the main pay zone. The packer 38 can allow the NCG 36 to
flow out
of the IHS 24 and into the IHS zone 14 from an NCG region 30A of the IHS
portion 30 of
the IHS well 24. Similarly, the packer 38 can allow for hydrocarbons to flow
down to the
main pay zone via a producer region 30B of the IHS portion 30 of the IHS well
24. In
addition, isolating the injection region can facilitate controlled injection
of NCG, in terms
of injection pressures and injection locations.
IHS injection fluid implementations
[0117] In some implementations, various injection fluids can be injected into
the IHS in
order to provide a desired effect on the process conditions. While NCG is
discussed in
detail with respect to injection via the IHS well, other fluids can be
injected alone, co-
injected with each other or co-injected with NCG.
[0118] Referring to Figures 3 and 4, in some implementations, an injection
fluid can be
injected into the IHS and/or the top region of the main pay zone from the IHS
well. The
injection fluid can include NCG, as described above, and can further include
other
injection fluids such as mobilizing agents 40. Examples of such mobilizing
agents 40
include steam, solvents and/or other chemicals (e.g., surfactants). In some
scenarios,
injection fluids that do not include NCGs can be injected in the IHS well 24
as desired.
The NCG 36 and the mobilizing agents 40 can be injected together from the IHS
well 24
into the IHS zone 14 and top region 28 of the main pay zone 12 (as seen in
Figure 3), or
separately using a tubing 42 inserted into the casing of the IHS well 24 from
the surface
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CA 3006750 2018-05-29
26 down to the pay zone portion 32 (as seen in Figure 4) thus enabling
injection of
different fluids into different regions of the reservoir.
[0119] Referring to Figure 4, a packer 38 can be installed in the IHS well 24
for
controlling the portion of the IHS well 24 from which NCG 36 and/or mobilizing
agents 40
can be injected into the IHS zone 14 and/or the top region 28 of the main pay
zone 12.
The tubing 42 and packer 38 can have various configurations and positions in
order to
enable different fluid injection strategies.
INS well production implementations
[0120] Now referring to Figure 5, in some implementations, the IHS well 24 is
configured
to produce hydrocarbons 22 from the IHS zone 14 to the surface. In the
exemplary
configuration shown, the IHS well 24 is provided with a tubing 42 and a packer
38. The
tubing 42 extends from the surface through the IHS zone 14. A packer 38 is
provided
inside the IHS well 34, as described above. NCG 36 is injected into the IHS
zone 14 via
an annulus formed outside of the tubing 42 and through the perforations 34
located
above the packer 38. Hydrocarbon fluids 22 from the IHS zone 14 can be
recovered up
to the surface via the tubing 42, using for example a pump (not shown)
connected to the
tubing 42. Hydrocarbon fluids can enter the tubing 42 via perforations 34A
provided in
the tubing 42 below the packer 38, or via the end opening of the tubing
located at a
depth below the packer 38.
[0121] In terms of operating the IHS well 24, in a first stage, NCG 36 can be
injected into
the upper part of the IHS zone in order to pressurize the area, drive some
hydrocarbons
downward into the lower part of the IHS zone and/or the main pay zone, and
also
partially dissolve into hydrocarbons to enhance mobility. In a second stage,
production
can be initiated from tubing 42 of the IHS well 24 in order to recover
hydrocarbons
and/or depressurize the IHS zone. The recovery can be facilitated by
mobilization of the
hydrocarbons and gas drive facilitated by NCG injection as well as heating
from the
underlying steam chamber. In some scenarios, the production and/or
depressurization
via the IHS well 24 can be performed when the hydrocarbons cannot drain
downward
into the steam chamber. In some scenarios, production via the IHS well 24 can
be
performed prior to the steam chamber reaching the IHS zone, thereby depleting
IHS
CA 3006750 2018-05-29
zone of hydrocarbons and facilitating injection of additional NCG into the
upper region of
the reservoir.
IHS well arrangements and configurations
[0122] Now referring to Figures 1 and 6, the IHS well 24 can be located
substantially
directly above the SAGD well pair (as shown in Figure 6), or between two
separate well
pairs (as shown in Figure 1). Providing the IHS well 24 directly above a
corresponding
SAGD well pair can result in formation of the NCG-enriched zone expanding
outward
from a similar overlying position as the steam chamber, and can also enable
hydrocarbons to drain from the IHS zone via the IHS well into a central part
of the steam
chamber. Providing the IHS well 24 in an offset position, for instance in
between two
adjacent SAGD well pairs, can result in the NCG-enriched zone extending to
overly both
SAGD well pairs, and can also enable hydrocarbons to drain from the IHS zone
via the
IHS well into a lateral part of the steam chamber.
[0123] Referring to Figures 8 and 10, in some implementations, multiple IHS
wells 24
can be provided for an array of SAGD well pairs that extend from a common well
pad.
For instance, each IHS well 24 can be located in between two adjacent well
pairs. For
each adjacent pair of SAGD wells, a series of IHS wells 24 (e.g., three IHS
wells) can be
provided along the length of the SAGD wells. In each series, the IHS wells can
be
spaced apart from each other by about 200 metres to about 400 metres, for
example.
Various other configurations of IHS wells can be provided based on the SAGD
well pair
configuration, the steam chamber(s) of the SAGD operation, and/or the
geological
properties of the reservoir. Figure 11 illustrates one of many alternative
configurations
for the IHS wells 24. In some scenarios, a geometric placing of the IHS wells
24 can be
used during the early production life of the reservoir, and a placing of the
IHS wells 24
above a hot zone or a thick IHS zone can be desirable at during the later
production life
of the reservoir.
Multilateral IHS well implementations
[0124] The IHS wells 24 described above have been illustrated as single IHS
wells that
extend from the surface into the IHS and main pay zones. Alternatively, the
IHS wells
can be provided as well sections that are part of a multilateral well, as will
be further
described below.
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CA 3006750 2018-05-29
[0125] Referring to Figure 7, in some implementations, a multilateral well 42
having at
least one IHS well section 44 is provided to access the IHS zone 14. The
multilateral
well 42 includes a vertical section 46 connected to a main well section 24A
from which
multiple branch well sections 44 extend into the IHS zone. The branch well
sections 44
can be substantially vertical well sections and can have various features of
the IHS wells
24 as described herein. The main well section 24A can be horizontal or
slanted,
depending on the orientation of the IHS and/or other properties of the
reservoir. The
main well section 24A can also be drilled above, within or below the IHS zone.
In some
implementations, the branch well sections 44 include at least one vertical
well section
extending downward from the main well section 46.
[0126] In some implementations, the branch well sections 44 can include at
least one
downwardly inclined branch well section. For example, the branch well sections
44 can
include several inclined branch well sections directed outwardly (i.e.,
directed towards
the main pay zone and on either side of the main horizontal well section 24A).
In other
words, the branch well sections 44 can extend radially from the main well
section 24A,
towards the main pay zone and on either side of the main well section 24A.
[0127] The multilateral well 42 can be oriented such that the main well
section 24A
extends in parallel, perpendicular or in oblique relation to underlying SAGD
well pairs.
One or more multilateral wells 42 can be provided for a given array of SAGD
wells. The
multilateral well 42 can be operated for NCG injection or injection of one or
more other
fluids into the IHS zone, and can be completed for production capability as
well.
NCG implementations
[0128] In some implementations, the NCG is selected from the group consisting
of
methane, carbon dioxide, nitrogen, air, natural gas and flue gas. The NCG can
be
selected according to process economics and/or desired effects.
IHS heating implementations
[0129] As discussed above, heating of the IHS zone 14 and mobilization of the
hydrocarbons of the IHS zone can be achieved by heat transfer from the main
pay zone
12, as the mobilizing fluid rises up from the injection well 16 to the upper
region 28 of the
main pay zone 12. In some implementations, heat can be provided to the IHS
zone 14
37
CA 3006750 2018-05-29
by electrical heating or radio-frequency (RF) by antennas provided in the IHS
well 24 or
in the main pay zone 12. In some implementations, such heat is supplemental
heat (i.e.,
additional heat to complement heating by heat transfer from the mobilizing
fluid in the
main pay zone 12). In some implementations, electrical heating or RF heating
is the
main source of heating, for example during the later production life of the
reservoir when
less steam is needed.
Non-continuous INS well implementations
[0130] Referring to Figure 12, in some implementations, the IHS well 24 is
provided in
the IHS zone 14 but is not continuous with the main pay zone 12. The recovery
of the
hydrocarbons can be done by directly producing the hydrocarbons of the IHS
zone 14 to
the surface, and the recovery can be facilitated by mobilizing the
hydrocarbons of the
IHS using heat conduction from the underlying main pay zone 12, and/or
electrical or RF
heating in the IHS well 24, as described above. In some scenarios, the non-
continuous
IHS well is specifically designed and built as a non-continuous IHS well. In
other
scenarios, the non-continuous IHS well 24 is obtained by sealing the bottom of
an IHS
well initially built through the IHS zone 14.
Production chamber implementations in stratified regions
[0131] Referring to Figures 14 and 15, in some implementations, a method for
recovering hydrocarbons from a stratified region is shown. The stratified
region includes
pay zones, such as pay zone 14B, located in between low permeability layers
14X. The
method includes providing a well 24 for recovering hydrocarbons from the
stratified
region, in particular from the pay zones 14B. As explained above, the pay
zones 14B are
defined by low permeability layers 14X, which are layers which limit or
prevent vertical
movement of fluids. The well 24 includes a perforated well portion 24B
extending from a
first end of a pay zone 14B to a second end of the pay zone 14B, i.e., between
two
spaced-apart low permeability layers 14X. The perforated well portion 24B is
provided
with perforations 34 which provide fluid communication between the perforated
well
portion 24B and the pay zone 14B. In some implementations, the method includes
injecting a mobilizing fluid 40, which can include steam, into the well 24,
and allowing at
least a portion 40B of the mobilizing fluid 40 to flow into the pay zone 14B
through the
perforations 34 of the perforated well portion 24B. The mobilizing fluid 40B
injected into
38
CA 3006750 2018-05-29
the pay zone 14B can form a steam chamber 120B in the pay zone 14B, for
mobilizing
hydrocarbons present in the pay zone 14B. The mobilized hydrocarbons 22B can
then
be produced, for instance, via the well 24 as shown in Figure 14, or by using
a separate
production well 25 extending through the pay zone 14B, as shown in Figure 15.
It is
understood that the mobilizing fluid 40 can include at least one of steam, a
non-
condensable gas, a solvent and a surfactant, and is suitable for mobilizing
the
hydrocarbons within the pay zone. It is also understood that when "steam" is
referred to
herein, non-condensable gas, solvent and/or surfactants can be used in
conjunction with
or as a replacement of the steam.
[0132] It is understood that the scenarios shown on Figures 14 and 15 show
examples
of hydrocarbon recovery from one pay zone 14B within a reservoir 10. However,
the
reservoir 10 can include several pay zones each being defined by corresponding
low
permeability layers which can have various configurations, shapes,
thicknesses, and
positioning (e.g., strike and dip) within the reservoir 10 and with respect to
one another.
In some implementations, the well 24 can feature a perforated well portion for
several or
all pay zones of a stratified region through which the well 24 extends, and
from which it
can be desired to produce hydrocarbons.
[0133] For example, a possible scenario featuring several pay zones and
corresponding
low permeability layers 14X in a reservoir is shown in Figure 16. The well 24
extends
into the reservoir 10 through pay zones 14A, 14B, 14C which are separated by
low
permeability layers 14X. The pay zones 14A, 14B, 140 can be part of an IHS or
another
type of stratified region 14Y, and vertical movement of fluid between the pay
zones 14A,
14B, 14C is limited or prevented by the low permeability layers 14X. The low
permeability layers 14X can have various compositions and sizes. The pay zones
14A,
14B, 14C can also have different configurations, spacing, and sizes. For
instance, pay
zone 14A is separated from pay zone 14B by a notable distance (e.g., by a
thick low
permeability layer), while pay zone 14B is separated from pay zone 14C by a
relatively
thin low permeability layer. In some scenarios, the thickness of the low
permeability layer
can determine the packer configuration (e.g., a single packer can be used when
a given
ow permeability layer is sufficiently thin, as illustrated for pay zones 14B
and 140).
[0134] Still referring to Figure 16, the mobilizing fluid 40 is injected into
the well 24, and
a first portion 40A of the mobilizing fluid 40 is allowed to flow into the pay
zone 14A,
39
CA 3006750 2018-05-29
while a second portion 40AB of the mobilizing fluid 40 is allowed to flow
further
downward in the well 24, towards the pay zone 14B. Similarly, a first portion
40B of the
mobilizing fluid 40AB is allowed to flow into the pay zone 14B, while a second
portion
40BC of the mobilizing fluid 40AB is allowed to flow further downward in the
well 24,
towards the pay zone 14C. Similarly, a first portion 40C of the mobilizing
fluid 40BC can
be allowed to flow into the pay zone 14C, while a second portion of the
mobilizing fluid
40BC can be allowed to flow further downward in the well 24. The mobilizing
fluid 40A,
40B and 40C injected into the pay zones 14A, 14B and 14C, can respectively
form
steam chambers 120A, 120B and 120C which aid in the mobilization of the
hydrocarbons 22A, 22B and 22C in the respective of the low permeability layers
14A,
14B and 14C. The mobilized hydrocarbons 22A, 22B, 22C can then be extracted
from
the respective pay zones.
[0135] Still referring to Figure 16, the pay zones 14A, 14B and 14C can be
mobilized or
produced simultaneously or independently of one another. In some scenarios,
injecting
mobilizing fluid into each one of the pay zones 14A, 14B, 14C can be done at
the same
time by perforating the well 24 at various locations and simultaneously
injecting and
mobilizing hydrocarbons in each one of the pay zones 14A, 14B, 14C. In other
scenarios, the mobilizing fluid can be selectively injected in one or a
limited number of
the pay zones, for example by controlling the flow of steam using flow control
devices,
by selectively perforating the well 24 to provide fluid communication between
the well 24
and the selected pay zone(s) to be produced. Similarly, the well 24 can be
operated in
production mode to produce hydrocarbons simultaneously from all pay zones or
from
one or more selected pay zones.
[0136] In some implementations, pay zones can be identified through various
methods,
such as seismic or other geological surveying techniques, in order to
determine
advantageous location of perforations, packers and/or flow control devices.
For example,
pay zones having certain thicknesses (e.g., above a minimum thickness
threshold, such
as above 1, 2, 5 or 10 meters) can be identified for a given stratified region
prior to
drilling or for a given existing well that passes through a stratified region
for retrofitting.
The pay zones that are selected for isolation and hydrocarbon recovery can
have a
minimum thickness threshold, minimum hydrocarbon content, and/or can be
defined by
low permeability layers having certain characteristics (e.g., thickness and/or
inclination).
CA 3006750 2018-05-29
Once target pay zones have been identified, the well can be completed and
operated so
as to recover hydrocarbons from those target pay zones.
[0137] Referring back to Figures 14 and 15, in some implementations, the well
24
includes a casing 48 which surrounds the well 24 (i.e., an outer casing). The
perforations
34A, 34B, 34C can be provided in the casing 48, along at least part of the pay
zones
14A, 14B, 140. In some implementations, the well further includes an inner
tube 50
located within the casing 48, such that an annulus 52 is formed between the
casing 48
and the inner tube 50. The inner tube 50 is in fluid communication with the
perforated
well portion so as to allow injection of mobilizing fluids from the inner tube
into the pay
zone via the perforated well portion and/or to allow production of mobilized
hydrocarbons
from the pay zone into the inner tube via the perforated well portion. In some
implementations, the method further includes isolating at least one of the
perforated well
portions 24A, 24B, 240. For instance, isolating a perforated well portion can
include
providing a first isolation packer 38 within the annulus 52, at a top end of
the
corresponding pay zone, and providing a second isolation packer 38 within the
annulus
52, at a bottom end of the pay zone. In some instances, the packers 38 can be
located
adjacent to the low permeability layers that define a given pay zone. In some
scenarios,
isolating the pay zones can reduce diffusion of mobilizing fluids from one of
the pay
zones 14A, 14B, 14C to another one of the pay zones 14A, 14B, 140 via the well
24.
[0138] Now referring to Figure 16, the isolation packer 38 provided at the
bottom of the
pay zone 14B can be used as the isolation packer provided at the top of the
pay zone
14C. This can be advantageous when the low permeability layer in between two
pay
zones is relatively thin, e.g., having a similar thickness to the isolation
device itself.
[0139] Referring to Figures 14 to 16, in some implementations, the method
further
includes controlling a flow of mobilizing fluid from one of the perforated
well portion 24A,
24B, 240, to the corresponding one of the pay zones 14A, 14B, 14C, and/or to
another
one of the perforated well portions 24A, 24B, 24C. This can be done, for
example, by
providing at least one flow control device 54 in corresponding perforated well
portions
24A, 24B, 240. For instance, as shown on Figure 16, each one of the perforated
well
portions 24A, 24B, 240 includes a flow control device 54 located on the inner
tube 50.
However, it should be noted that the flow control devices can be provided on
other parts
of the well, depending on the well completion configuration that is used. In
some
41
CA 3006750 2018-05-29
implementations, the flow control devices can include a sliding or protection
sleeve, an
inflow control device, a plugging system, a valve, or another type. More
regarding flow
control devices in the context of single-well and multi-well configurations as
well as cyclic
and simultaneous operating modes will be described below.
[0140] Referring to Figures 14 and 16, in some implementations, injecting the
mobilizing
fluid and producing the mobilized hydrocarbons is performed cyclically. The
well 24 can
operate as an injection well (i.e., in injection mode) for a certain period of
time (such as
several days, weeks or months), and can, after the hydrocarbons are mobilized,
operate
as a production well (i.e, in production mode) for another period of time. In
other words,
the mode of operation of the well 24 can be switched from an injection mode to
a
production mode. The mode of operation can be switched, for example, when the
steam
chamber inside at least one of the low permeability layers 14A, 14B, 14C has
developed
or matured to a desired extent; when all the steam chambers 120A, 120B, 120C
of the
low permeability layers 14A, 14B, 14C have matured; and/or when a producible
amount
of hydrocarbons has been mobilized, for example.
[0141] Now referring to Figure 17, in some implementations, injecting the
mobilizing fluid
and producing the mobilized hydrocarbons are performed simultaneously. The
well 24
can concurrently operate as an injection well and a producer well. In other
words,
hydrocarbons of the pay zone can be produced as they are being mobilized by
the
mobilizing fluid. As illustrated, at least two inner tubes are used (one
injection inner tube
50A and one production inner tube 506) when the well 24 operates
simultaneously as an
injection well and a producer well. In some implementations, at least one pump
(e.g.,
downhole pump or surface pump) can be used for producing the mobilized
hydrocarbons
via the inner production tube 50B. Two annuli 52A, 52B can be formed in
between the
casing and outer tube 50A and in between the outer tube 50A and the inner tube
50B,
respectively; and third annulus 52C can be formed in between the inner tube
50B and
the casing. In some implementations, producing the mobilized hydrocarbons is
performed using gas lift or by pressure differential. It should be noted that
other tubular
configurations could be used in order to simultaneously inject and produce.
The injection
tube could also be located within the production tube with an appropriate
isolation
arrangement. It should also be noted that while co-centric tubes are
illustrated in Figure
17, parallel or adjacent tubes could also be implemented with appropriate
isolation and
completion arrangements.
42
CA 3006750 2018-05-29
[0142] Referring back to Figures 14 to 16, the inner tube 50 can include a
screen 60 for
screening solid material from the produced fluids which include the mobilized
hydrocarbons. As the hydrocarbons of the pay zones are typically mixed with
oily sands,
such solid material can often be produced back with the mobilized
hydrocarbons. Using
a screen 60, such as a sand screen, in the inner tube 50 of the well 24 can
therefore
allow removing part of the solid material from the produced fluids. Other
solids removal
devices could also be used. In certain scenarios, solids removal devices can
have the
advantage of purifying to some extent the produced fluids, and/or of limiting
mechanical
damage to the inner tube 50. In some implementations, the screen 60 is
provided along
the pay zone. A screen can be provided in each of the perforated well portions
that are
adjacent to pay zones.
[0143] Referring back to Figure 15, in some implementations, the perforations
34B used
for injecting mobilizing fluid 40B into the low permeability layer 14B are
located
proximate to the top end of the corresponding pay zone 14B. In some
implementations,
the perforations 35B of the producer well 25, used for producing mobilized
hydrocarbons
22B are located proximate to the bottom end of the pay zone 14B. In such case,
the
mobilizing fluid 40B can be injected into the low permeability layer 14B from
a top region
of the layer 14B, and the mobilized hydrocarbons can flow by gravity towards
the
perforations 35B located at a lower level than the perforations 34A.
[0144] Referring now to Figure 21, the well 24 can have perforations 34 that
are
provided on one side of the well to facilitate orientation of the injected
mobilizing fluid
toward a desired region of the pay zone 14A, 14B. For example, when the pay
zones
14A, 14B are defined by inclined low permeability layers 14X, it may be
advantageous to
inject in the direction in which the low permeability layer extends upward
(i.e., away from
the dip direction). Directional perforations may be used to facilitate such
techniques.
[0145] Referring to Figures 18 to 20, flow control devices (FCDs) 54 can be
provided to
enhance or control the distribution of steam and/or the production of fluids.
FCDs can be
designed and operated to partially or fully restrict injection and/or
production so that that
flow distribution can be matched to the deliverability of steam into and
hydrocarbons out
of each of the pay zones being accessed. The type of FCD device 54 can include
holes
drilled in the tubes, orifices, nozzles, or any device for flow control.
Particular FCDs may
be used depending on the phase of the fluid (e.g., gas, liquid), the
composition of the
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fluid (e.g., solids-containing) and/or other fluid properties (e.g.,
temperature, pressure,
viscosity). FCDs can be provided along an entire length of a given section of
the well or
tube, or can be provided at particular injection and/or production locations.
For example,
injection FCDs can be located higher than production FCDs, an example of which
is
illustrated on Figure 20. Various FCD designs and configurations can be used
and
operated based on different principles in order to facilitate blocking steam
production
and controlling distribution of the flow and pressure of fluids.
[0146] For injection, a purpose of the FCDs is to control the rate of steam
injection into
each zone when there are multiple zones in which steam can enter the
reservoir. It
should be noted that the zones into which the mobilizing fluid enters can be
any of the
pay zones of the stratified region as well as the main pay zone that may be
located
below the stratified region, as would be the case when the well 24 is a SAGD
injection
well that has a horizontal section through which steam is injected into the
main pay
zone.
[0147] For production, the FCDs can be operated to preferentially block steam
from
being produced and to allow liquids to be produced. This is especially useful
when trying
to prevent the short circuiting of steam from the location of injection to the
location of
production.
[0148] Figure 18 illustrates a single-well with simultaneous production-
injection where
FCDs can be used at different locations. FCDs can be provided to control the
production
fluid flow and/or the injection fluid flow. For example, the production FCDs
can be
operated to completely close in the event of steam breakthrough, and then re-
opened
once liquid hydrocarbons have sufficiently accumulated and can be produced
without
steam breakthrough. The injection FCDs could also be operated to stop or
reduce steam
injection in the event of steam breakthrough into the produced fluids. Steam
breakthrough monitoring techniques can be used to detect or predict steam
breakthrough and thus be used in the control of the FCDs.
[0149] Fig 19 illustrates a single-well employing cyclic operation where FCDs
can be
used at multiple locations corresponding to different pay zones. For example,
since the
pay zones are at different depths, the pressure at each depth may be different
such that
the FCDs can be controlled to provide sufficient pressure difference at each
pay zone.
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[0150] Fig 20 illustrates a two-well configuration with simultaneous
production-injection.
It should be noted that two wells could also be operated with a cyclic mode.
In some
scenarios, FCDs can be used only in the injection well or in both the
injection and
production well.
[0151] Referring now to Fig 22, when a pair of well sections, such as the
slanted or
vertical well sections of a SAGD well pair, extend through a stratified region
such that
the injection well is updip from the production well, the injection of
mobilizing fluid can
form a mobilization chamber (e.g., steam chamber 120A, 120B) that expands
updip
away from the production well. In this context, "updip" means that the
injection well is
located up the slope of the dipping strata relative to the production well,
which is
downdip, at the relevant section of the wells being exploited. Such a scenario
can be
advantageous for various reasons. For instance, the risk of steam breakthrough
at the
production well can be reduced due to the tendency of chamber growth to occur
updip,
which can mean that FCDs can be avoided for the production well. In addition,
the
natural dip of the low permeability layers is leveraged in order to facilitate
flow of
mobilized hydrocarbons toward the production well. Prior to deploying the
completion for
accessing the pay zones in a stratified region for exiting SAGD wells, there
can be a
preliminary method of selecting certain SAGD well pairs where the injection
well is updip
to the production well. Other criteria related to the pay zones and other
parameters can
also be considered, as discussed further above. FCDs may also be used in the
production well and operated so as to ensure that hydrocarbons are produced
form the
inter-well region at a rate sufficient to prevent blockage or flooding of the
injection well
with mobilized hydrocarbons.
[0152] Alternatively, when the injection well is downdip from the production
well, a
different flow control strategy can be implemented to reduce steam
breakthrough at the
production well. Thus, FCDs can be advantageously used in such scenarios. It
is also
noted that the optional updip location of the injection well relative to the
production well
is particularly suitable for continuous operation, while cyclic operations may
be less
impacted by the well locations.
[0153] Various other factors can be considered in the selection of existing
wells for
recompletion or the determination of drilling and completion of new wells. In
some
scenarios, existing wells (e.g., injection and/or production well in a SAGD
well pair, an
CA 3006750 2018-05-29
infill well, a step-out well, etc.) showing poor performance can be selected
for
recompletion in stratified regions of the vertical or inclined sections of the
wells. For
example, the existing wells may be underperforming due to various geological
barriers
located relative to the horizontal section. For instance, when a horizontal
section has
been drilled generally along the strike of the reservoir rather than the dip
of the reservoir,
the horizontal section may be isolated from certain pay zones; however, the
vertical or
inclined section of such wells can generally pass through stratified layers
and provide
access such that the well can be recompleted and operated to improve its
performance.
Figure 24 provides an illustration of a horizontal section of a well that
follows the strike
while the vertical section of the well passes through multiple pay zones. In
some
formations, there may be complex depositional features, such as multiple stack
points,
resulting in greater difficulty for a horizontal section to access
hydrocarbons in certain
regions of the reservoir. In such cases, techniques described herein can be
used to
access isolated hydrocarbons.
[0154] In some implementations, new SAGD well pairs can be planned and drilled
with a
view of producing from both the lower main pay zone and any number of thin pay
zones
of a stratified region through which the vertical or inclined sections pass.
In some
implementations, the well is selected for recompletion based on certain
features of the
stratified region through which it passes, e.g., steeper dip, higher
temperatures, greater
thicknesses of the pay zones, and so on. Thus, when considering a number of
potential
candidate wells for implementation of techniques described herein, the wells
and/or
sections of wells can be selected based on well characteristics (e.g.,
inclination, current
hydrocarbon recovery performance, existing completion, trajectory relative to
dip and
strike, etc.) as well as geological characteristics (e.g., dip, thickness of
pay zones,
permeability and composition of pay zones, temperature of pay zones, spacing
of pay
zones relative to each other, and so on).
Well conversion implementations
[0155] In some scenarios, the well 24 is a well which is drilled for the
purpose of
injecting mobilizing fluids into low permeability layers of a reservoir. In
other scenarios,
as shown in Figure 13 for example, the well 24 is a pre-existing SAGD well
including well
portion 30 passing through a stratified region 14Y and a horizontal well
portion 56
extending through the main pay zone 12 of the reservoir. The SAGD well can be
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completed or re-completed to enable injection of mobilizing fluids into pay
zones defined
between low permeability layers of the reservoir. In some implementations, the
SAGD
well 24 can be converted so as to allow injection of mobilizing fluid into the
pay zones,
without operating the main pay zone 12 of the reservoir. This can occur for
mature
SAGD wells that have reached the end of their economic life with respect to
the main
pay zone. In some implementations, the well portion 30 can be isolated from
the
horizontal well portion 56. Isolating of the well portion 30 can be performed,
for example,
by using an isolation device 58 such as an isolation packer, which can be
located at
various levels in the SAGD well 24. For instance, and as shown on Figure 13,
the
isolation device 58 can be located at the top of the main pay zone 12 and
below the pay
zone 14C. In some implementations, the SAGD well 24 is converted by providing
perforations 34 in the outer casing of the well portion 30, so as to provide
fluid
communication between the well portion 30 and the stratified region 14Y (e.g.,
INS 14).
It is understood that the perforations 34 can be provided along certain
regions or layers
of the stratified region, while other regions or layers may be kept isolated
from the well
portion 30. This can allow to selectively injecting mobilizing fluids 40 into
certain regions
or layers of the stratified region. Perforations can be provided only along
pay zone
locations, or provided along a length of well section that is adjacent to both
pay zones a
low permeability layers (e.g., the latter being potentially the case in IHS
type stratified
regions, where the pay zones are centimetre-scale and thus multiple pay zones
can be
accessed by perforating along a stretch of the well spanning both high and low
permeability zones). In other implementations, the well portion 30 is not
isolated from the
horizontal well portion 56, and mobilizing fluid 40 can be injected into
certain pay zones
14A, 14B, 14C of the reservoir 10 at the same time as regular SAGD operations
are
being performed via the horizontal well portion 56. Thus, steam can be
injected into the
thin pay zones 14A, 14B, 14C as well as the main pay zone. Similarly, the SAGD
well 24
can be converted so as to allow production of the mobilized hydrocarbons. The
production can be performed concurrently with the injection of mobilizing
fluid, or
cyclically, depending on the completion as described above. The operation
within the
stratified region can be independent of other operations in the reservoir; the
configuration can be provide such that there is no requirement to be connected
to any
other production interval or steam chamber.
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[0156] In some implementations, a SAGD well pair including a SAGD injection
well and
a SAGD production well can be converted into and/or used as a stratified
region well pair
including an injection well section and a production well section. In other
words, a
section of the SAGD injection well can be used to inject into pay zones of the
stratified
region, and a section of the SAGD production well can be used to produce from
pay
zones in the stratified region. The SAGD wells can be recompleted and
retrofitted for this
purpose. In some implementations, the SAGD injection and production wells can
therefore keep their respective modes of operation (i.e., injection and
production) after
being converted to allow injection of mobilizing fluid into the stratified
region and allow
production of the mobilized hydrocarbons from the stratified region,
respectively. In
some scenarios, converting injection and production wells can be more economic
or
efficient than drilling new wells, or than converting injection or production
wells to cyclic
stimulation wells.
[0157] It should also be noted that the wells of a SAGD well pair may be
recompleted at
different times and can change operating modes over time. For instance, the
SADG
injection well may be recompleted first and operated to inject mobilizing
fluid into the
stratified region, and then the SAGD production well can be recompleted at a
later time
so that it can begin operating once sufficient heating has occurred via the
injector.
Solvent-assisted gravity drainage techniques
[0158] While various implementations have been described and illustrated
herein in
relation to SAGD, it should be noted that various solvent assisted processes
can be
used instead of SAGD. For example, in some implementations, a well pair is
provided
and can use solvent at various stages of the recovery process, including start-
up, ramp-
up, normal operation, and/or wind-down. During start-up, the horizontal
sections of the
well pair can be operated to establish fluid communication between the well
pair, which
may be done by injection or circulation of solvent, steam and/or hot water;
and/or by
using a heating device such as an electric heater, resistive heater string, an
electromagnetic heater (e.g., an antenna assembly configured to emit radio
frequency
RF waves to heat the reservoir) or another type of heater. Start-up can be
performed to
establish fluid communication between pairs of wells, where solvent is
provided through
one of the wells (e.g., injection well) while a pressure sink is provided by
the production
well (e.g., via a pump) to encourage flow of the injected solvent through the
inter-well
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region toward the production well. For single well configurations (e.g.,
infill or step-out
wells), other start-up types of processes can be implemented and may also
include
heating with fluids, electrical heaters, and/or electromagnetic heaters.
[0159] During normal operation, the solvent-assisted process can include the
injection of
a solvent in liquid or vapour phase. Injection of the solvent as a vapor into
the reservoir
can induce the solvent to condense within the reservoir and be recovered with
the
production fluids. The vapour phase solvent may enter the mobilization chamber
and
condense at the walls of the chamber to heat and dissolve into the heavy oil
or bitumen.
The solvent can be alkane, aromatic and/or a blend of solvents. Different
solvents or the
same solvent can be used for different stages of the recovery process (e.g.,
for start-up,
normal operation, etc.). A few example solvents that can be used include
propane,
butane, pentane, naphtha, and diesel. Heavier solvents can be used for start-
up while
lighter solvents can be used for normal operation, particularly where the
lighter solvents
are to be injected in the vapour phase. The solvent can be injected as a
substantially
pure solvent without impurities such as water, heavier hydrocarbons, etc. The
solvent-
containing production fluid that is recovered to the surface can be processed
in order to
recover solvent from the production fluid, so that the solvent can be
reinjected into the
reservoir as pure solvent or as a mobilization fluid that includes a portion
of solvent.
Make-up solvent can be added prior to re-injection.
[0160] In some implementations, other mobilization techniques can be used
concurrently with fluid-based mobilization techniques at one or more stages of
the
recovery process. For example, electromagnetic heating (e.g., via RF) can be
employed
along with solvent and/or steam injection during start-up and/or normal
operation. The
electromagnetic heating technique can also be modified for different stages of
the
process, for example by providing RE energy at a higher level during start-up
compared
to normal operation.
[0161] In some implementations, the heater devices can be configured or
adapted to
heat the stratified region. The heater devices can be dedicated for heating
the stratified
region, or can be provided principally for heating the main pay zone.
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Description of system implementations
[0162] Referring to Figure 1, in some implementations there is provided a
system for
enhancing hydrocarbon recovery from a reservoir 10 having a main pay zone 12
and an
overlying IHS 14 including permeable layers. In some scenarios, the system
allows for
the recovery of hydrocarbons from the IHS 14 located in a reservoir. The
system
includes a SAGD well pair 16, 18 located in the main pay zone, the SAGD well
pair
including an injection well 16 for injecting a first injection fluid in the
main pay zone 12,
and a producer well 18 for producing production fluids. The system also
includes a
vertical well 24 having an IHS well portion 30 and a pay zone well portion 32.
The
vertical well 24 is drilled through the IHS 14 and into an upper region 28 of
the main pay
zone 12. The vertical well 24 is configured to inject a second injection fluid
into the IHS
14 for driving hydrocarbons from the IHS 14 to the main pay zone 12.
[0163] The first injection fluid can include steam. In some implementations,
the first
injection fluid can also include other fluids such as NCG, solvents and/or
surfactant.
[0164] The second injection fluid includes at least one of a NCG, a solvent,
water and a
surfactant. For example, the NCG can include methane, carbon dioxide,
nitrogen, air,
natural gas or flue gas. For example, the solvent can include diluent,
toluene, xylene,
diesel, propane, butane, pentane, hexane, heptane and/or naphtha, or other
suitable
solvents for co-injection with the steam.
[0165] Referring to Figure 13, in some implementations there is provided a
system for
recovering hydrocarbons from a stratified region of a reservoir. In some
scenarios, the
reservoir includes a main pay zone and a stratified region comprising low
permeability
layers and pay zones there-between. In other scenarios, the reservoir includes
a
stratified region and does not necessarily include a main pay zone. The system
includes
a well extending into the reservoir through at least one pay zone of the
stratified region.
In some implementations, the well includes a casing surrounding the injection
well, and
including a perforated portion. The perforated injection portion can be
provided along at
least part of the pay zone and allows fluid communication between the pay zone
and the
well. In some implementations, the well also includes an inner tube which is
located
within the casing, such that an annulus is formed between the inner tube and
the casing.
In some implementations, the well also includes a first isolation packer
located within the
CA 3006750 2018-05-29
annulus and provided at a top end of the pay zone, and a second isolation
packer
located within the annulus and provided at a bottom end of the pay zone. In
some
implementations, the well is configured to inject a mobilizing fluid which
includes steam
into the pay zone, through the perforated portion of the casing, in order to
form a steam
chamber in the pay zone and mobilize the hydrocarbons of the low permeability
layer. In
some implementations, the well can be an injection well and a producer well.
Depending
on the configuration of the well, the injection and production operations can
be
performed either cyclically or simultaneously. In other implementations, there
are at least
two spaced-apart wells, one operated as an injection well and the other
operated as a
producer well.
[0166] While Figures 14 to 20 schematically illustrate the well sections as
substantially
vertical, and the pay zones and the low permeability layers of the stratified
region as
substantially horizontal, it should be noted that the well sections can be
inclined and the
pay zones and the low permeability layers have a dip. The dip may be between
about 3
and about 8 , for example. Implementing techniques described herein with well
sections
located in stratified regions having a dip can leverage the impact of the dip
on the
hydrocarbon recovery and other fluid transfer phenomena occurring in the pay
zones.
Thus, the configurations illustrated in Figures 14 to 20 can be implemented in
scenarios
illustrated in Figures 23A to 23E, which illustrate different well
inclinations and dip
steepness.
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