Note: Descriptions are shown in the official language in which they were submitted.
CA 02889598 2015-04-23
IN SITU HYDROCARBON RECOVERY WITH INJECTION OF FLUID INTO IHS
AND UPPER PAY ZONE VIA VERTICAL WELL
FIELD
[0001]The technical field generally relates to in situ recovery of
hydrocarbons
and, more particularly, to hydrocarbon recovery operations employing the
injection of a fluid, such as non-condensable gas (NCG).
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 (INS). IHS are often located at an
upper
part of the reservoir and overly 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.
1
CA 02889598 2015-04-23
[0004]In the case of reservoirs including IHS, producing hydrocarbons by
gravity
drainage from the IHS zone overlying a main pay zone can be difficult. The
difficulties can be due to challenges in establishing a counter-current flow
between the IHS zone and the main pay zone. In a gravity drainage process, an
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, 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 zone.
[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
intended. 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
zone.
[0006]IHS zones can also 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
2
CA 02889598 2015-04-23
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.
[00013]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.
[0009]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.
[0010]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.
[0011]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.
[0012]In some implementations, the vertical well is located substantially
directly
above the SAGD well pair.
[0013]1n some implementations, the vertical well is located in between two
adjacent SAGD well pairs.
[0014]In some implementations, the method further includes: isolating the
vertical well with an isolation packer so as to provide an upper injection
segment
3
CA 02889598 2015-04-23
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.
[0015]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) is provided, the method including: operating a
thermal in
situ hydrocarbon recovery process including: 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
including 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 includes injecting non-condensable
gas
(NCG) via the vertical well section into the surrounding permeable layers of
the
IHS.
[0016]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.
[0017]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.
[0018]In some implementations, the vertical well section is a lateral branch
section extending from an overlying or underlying horizontal well.
[0019]In some implementations, the vertical well section is part of a single
vertical well extending downward from the surface.
[0020]In some implementations, the thermal in situ hydrocarbon recovery
process includes SAGD.
[0021]In some implementations, the thermal in situ hydrocarbon recovery
process includes cyclic steam stimulation (CSS).
4
CA 02889598 2015-04-23
[0022]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 including: 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 INS, wherein the operating includes: 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.
[00231In some implementations, the injection fluid includes NCG.
[0024]In some implementations, the NCG provides gas drive to promote
displacement of hydrocarbons in the IHS zone downward into the main pay zone.
[0025]In some implementations, the injection fluid further includes at least
one of
a solvent and a surfactant.
[0026]In some implementations, the IHS well section is a vertical IHS well
section.
[0027]In some implementations, the vertical well section is a lateral branch
section extending from an overlying or underlying horizontal well.
[0028]In some implementations, the vertical well section is part of a single
vertical well extending downward from the surface.
[0029]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 including: operating an IHS well section
CA 02889598 2015-04-23
extending into the IHS, the IHS well section including: an outer liner
including
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 includes:
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.
[0030]In some implementations, the IHS well section is a vertical IHS well
section.
[0031]In some implementations, the vertical well section is a lateral branch
section extending from an overlying or underlying horizontal well.
[0032]In some implementations, the vertical well section is part of a single
vertical well extending downward from the surface.
[0033]In some implementations, the outer liner includes a slotted liner.
[0034]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 including: operating a multilateral IHS
well
including: 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 includes: injecting an injection fluid via the branch
well
sections into the surrounding permeable layers of the IHS.
[0035]In some implementations, the main well section is a section of a
horizontal
well.
6
CA 02889598 2015-04-23
[003611n some implementations, the horizontal well is located in the IHS.
[003711n some implementations, the horizontal well is located in the main pay
zone.
[00381In some implementations, the multiple branch sections are vertical
branch
sections.
[0039]In some implementations, the injection fluid includes NCG.
[0040]In some implementations, the injection fluid further includes at least
one of
a solvent and a surfactant.
[0041]In some implementations, there is provided a system for recovering
hydrocarbons from a reservoir having a main pay zone and overlying inclined
heterolithic strata (INS), the system including: a SAGD well pair including:
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 including 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.
[0042]In some implementations, the vertical well facilitates providing fluid
communication and equalization of the pressure between the IHS zone and the
main pay zone.
[0043]In some implementations, the second injection fluid includes at least
one
of a NCG, a solvent and a surfactant.
[0044]In some implementations, the first injection fluid includes steam.
[0045]In some implementations, the vertical well is provided with a slotted
liner.
[0046]In some implementations, the vertical well includes a casing.
7
CA 02889598 2015-04-23
[0047]In some implementations, the casing is a thermal casing.
[0048]In some implementations, the vertical well includes a thermal wellhead.
[0049]In some implementations, the vertical well includes thermal cement.
[0050]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.
[0051]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.
[0052]In some implementations, the second injection fluid is injected into the
IHS
via the upper injection segment.
[0053]In some implementations, the vertical well is located substantially
directly
above the SAGD well pair.
[005411n some implementations, the vertical well is located in between two
adjacent SAGD well pairs.
[0055]In some implementations, the system further 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.
[0056]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 including: a SAGD well pair including:
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 including 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
8
CA 2889598 2017-05-19
portion and a pay zone well portion, the well including: an outer liner
including
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.
[0056a] 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 including: 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
including: 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 include 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0057] Figure 1 is a cross-sectional view of a steam-assisted gravity drainage
(SAGD) operation and part of a vertical well drilled through inclined
heterolithic
strata (IHS).
[0058] Figure 2 is a cross-sectional view of part of a vertical well provided
through
IHS and including an isolation packer.
9
CA 2889598 2017-05-19
[0059] Figure 3 is a cross-sectional view of part of a vertical well drilled
through
IHS, and showing the co-injection of NCG and another injection fluid.
[0060] Figure 4 is a cross-sectional view of part of a vertical well drilled
through
IHS, and including additional tubing for injecting fluids.
[0061] Figure 5 is cross-sectional view of part of a vertical well drilled
through IHS,
and including additional tubing for producing hydrocarbons.
[0062] Figure 6 is a cross-sectional view of a SAGD operation and part of a
vertical well drilled through IHS.
9a
CA 02889598 2015-04-23
[0063]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.
[00641Figure 8 is a cross-sectional view of a SAGD operation where multiple
discrete vertical wells are drilled through the IHS.
[0065]Figure 9 is a cross-sectional view of a SAGD operation.
[0066]Figure 10 is a top plan view schematic of a SAGD operation including a
well pad, an array of well pairs, and a vertical well configuration.
[0067]Figure 11 is a top plan view schematic of a SAGD operation including a
well pad, an array of well pairs, and another vertical well configuration.
[0068]Figure 12 is cross-sectional view of part of a vertical well drilled in
IHS,
and including additional tubing for producing hydrocarbons.
DETAILED DESCRIPTION
[0069]Various techniques that are described herein enable enhanced thermal in
situ recovery operations, such as steam-assisted gravity drainage (SAGD),
including the use of a well, which can be a vertical well, extending through
inclined heterolithic strata (IHS) located above a main pay zone of the
reservoir.
An injection fluid, such as non-condensable gas (NCG) 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 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.
[0070]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
CA 02889598 2015-04-23
recovery operations, and injection fluids. Some implementations of the
technology will be described in greater detail below.
In situ hydrocarbon recovery operation implementations
[0071]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, 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 within the main pay zone 12, which can then
drain along with 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. As the mobilizing
11
CA 02889598 2015-04-23
=
fluid approaches the IHS zone 14, heat transfer can enable heating of the
hydrocarbons of the IHS zone.
[0072]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 present in the INS zone.
[0073]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.
Referring briefly to Figure 9, the IHS zone can include low permeability
layers
(also referred to as low permeability lamina, lenses or baffles) having
different
orientations, thicknesses and compositions, which form tortuous paths that
generally discourage fluid flow.
[0074]While various implementations are described herein in relation to SAGD,
other in situ hydrocarbon recovery operations can be used. For instance,
cyclic
steam stimulation (CSS), in situ combustion, solvent-enhanced methods, 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. 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
12
CA 02889598 2015-04-23
described further below, by providing and operating what may be called an "IHS
well", such as a vertical well extending through the IHS zone for injection of
NCG,
hydrocarbon recovery operations can be enhanced.
Vertical IHS well implementations
[0075]Still referring to Figure 1, in some implementations, a vertical well 24
is
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.
[0076]The expression "vertical well" refers to a well which is drilled
substantially
vertically with respect to the surface. In some scenarios, a 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.
[00771It 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 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.
13
CA 02889598 2015-04-23
[0078]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 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.
[0079]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.
[0080]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 pay zone 12. In the latter case,
the
14
CA 02889598 2015-04-23
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.
[0081]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
back
pressure (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.
[00821In 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
[0083]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 (this allows for the steam of the steam
chamber 20 to not be lost 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
CA 02889598 2015-04-23
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
[0084]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 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 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
[008511n 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 or co-injected with NCG.
[00861Referring 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.,
16
CA 02889598 2015-04-23
,
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 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.
[0087]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.
IHS well production implementations
[0088]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.
[0089]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.
17
CA 02889598 2015-04-23
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 zone
of
hydrocarbons and facilitating injection of additional NCG into the upper
region of
the reservoir.
IHS well arrangements and configurations
[0090]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.
[0091]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
18
CA 02889598 2015-04-23
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
[0092]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.
[0093]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.
[0094]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
19
CA 02889598 2015-04-23
from the main well section 24A, towards the main pay zone and on either side
of
the main well section 24A.
[0095]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
[0096]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
[0097]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 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 IHS well implementations
[0098]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
CA 02889598 2015-04-23
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.
Description of system implementations
[009911n 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.
[0100]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.
[0101]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.
21
