CA3087645C - In situ hydrocarbon recovery from pay zones between low permeability layers in a stratified reservoir region - Google Patents

In situ hydrocarbon recovery from pay zones between low permeability layers in a stratified reservoir region Download PDF

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CA3087645C
CA3087645C CA3087645A CA3087645A CA3087645C CA 3087645 C CA3087645 C CA 3087645C CA 3087645 A CA3087645 A CA 3087645A CA 3087645 A CA3087645 A CA 3087645A CA 3087645 C CA3087645 C CA 3087645C
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well
pay zone
ihs
zone
hydrocarbons
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CA3087645A1 (en
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Hong Zhu
Robert Wayne King
Martin Lastiwka
Richard Chan
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Suncor Energy Inc
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Suncor Energy Inc
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2406—Steam assisted gravity drainage [SAGD]
    • E21B43/2408—SAGD in combination with other methods
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
    • E21B43/168—Injecting a gaseous medium

Abstract

Techniques are described for recovering hydrocarbons from a stratified region, such as inclined heterolithic strata (IHS), which includes pay zones defined between low permeability layers. Some techniques include providing a well extending into the stratified region and operated to inject a mobilizing fluid, and then producing the mobilized hydrocarbons. A steam-assisted gravity drainage (SAGD) well pair can be re- completed to enable injection and production in the slanted well segments that pass through the stratified region. Some techniques include operating SAGD in a main pay zone underlying an IHS zone, and then operating a vertical well extending from the surface into the IHS and a top region of the main pay zone to inject non- condensable gas (NCG) into the IHS to form an NCG-enriched zone in the IHS and provide drainage from the IHS into the main pay zone.

Description

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 Date Recue/Date Received 2020-07-22 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 Date Recue/Date Received 2020-07-22 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 (IHS), the method comprising:
operating a thermal in situ hydrocarbon recovery process including:

Date Recue/Date Received 2020-07-22 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:

Date Recue/Date Received 2020-07-22 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 (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 tube and a lower production segment in fluid communication with the tube;
wherein the operating of the IHS well section comprises:
Date Recue/Date Received 2020-07-22 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.

Date Recue/Date Received 2020-07-22
[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.

Date Recue/Date Received 2020-07-22
[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.

Date Recue/Date Received 2020-07-22
[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, Date Recue/Date Received 2020-07-22 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 Date Recue/Date Received 2020-07-22 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:

Date Recue/Date Received 2020-07-22 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.

Date Recue/Date Received 2020-07-22
[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 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 mobilizing fluid comprising steam into the first perforated well portion, via the well;
dividing the mobilizing fluid of the first perforated well portion, comprising:

Date Recue/Date Received 2020-07-22 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, Date Recue/Date Received 2020-07-22 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.
Date Recue/Date Received 2020-07-22
[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 SAGD 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 Date Recue/Date Received 2020-07-22 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;

Date Recue/Date Received 2020-07-22 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.
[0064] 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 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 Date Recue/Date Received 2020-07-22 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.
[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 Date Recue/Date Received 2020-07-22 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;
Date Recue/Date Received 2020-07-22 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.

Date Recue/Date Received 2020-07-22
[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 Date Recue/Date Received 2020-07-22 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.

Date Recue/Date Received 2020-07-22
[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 Date Recue/Date Received 2020-07-22 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:
Date Recue/Date Received 2020-07-22 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.
[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.

Date Recue/Date Received 2020-07-22
[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.

Date Recue/Date Received 2020-07-22
[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 Date Recue/Date Received 2020-07-22 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 Date Recue/Date Received 2020-07-22 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 Date Recue/Date Received 2020-07-22 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 IHS 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 Date Recue/Date Received 2020-07-22 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 Date Recue/Date Received 2020-07-22 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 Date Recue/Date Received 2020-07-22 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 Date Recue/Date Received 2020-07-22 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.
IHS 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
Date Recue/Date Received 2020-07-22 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.

Date Recue/Date Received 2020-07-22
[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 Date Recue/Date Received 2020-07-22 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
[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 Date Recue/Date Received 2020-07-22 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, 14C 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 14C).
[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, Date Recue/Date Received 2020-07-22 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).
Date Recue/Date Received 2020-07-22 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 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, 14C. 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, 24C. 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, 14C 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, 24C, 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, 24C. For instance, as shown on Figure 16, each one of the perforated well portions 24A, 24B, 24C 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 Date Recue/Date Received 2020-07-22 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 50B) 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.

Date Recue/Date Received 2020-07-22
[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 Date Recue/Date Received 2020-07-22 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.

Date Recue/Date Received 2020-07-22
[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 Date Recue/Date Received 2020-07-22 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 Date Recue/Date Received 2020-07-22 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., IHS 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.

Date Recue/Date Received 2020-07-22
[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 Date Recue/Date Received 2020-07-22 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 RF 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.

Date Recue/Date Received 2020-07-22 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 Date Recue/Date Received 2020-07-22 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.

Date Recue/Date Received 2020-07-22

Claims (84)

1. 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 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.
2. The method of claim 1, wherein 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.
3. The method of claim 1 or 2, wherein 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.
4. The method of claim 3, wherein 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.

Date Recue/Date Received 2022-10-24
5. The method of any one of claims 1 to 4, wherein injecting the NCG is performed so as to create a back pressure sufficient to reduce steam override from the steam chamber into the IHS.
6. The method of any one of claims 1 to 5, wherein the vertical well is located substantially directly above the SAGD well pair.
7. The method of any one of claims 1 to 6, wherein the vertical well is located in between two adjacent SAGD well pairs.
8. The method of any one of claims 1 to 7, further comprising:
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.
9. A method for recovering hydrocarbons from a reservoir having a main pay zone and overlying inclined heterolithic strata (IHS), the method comprising:
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 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.
10. The method of claim 9, wherein 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.

Date Recue/Date Received 2022-10-24
11. The method of claim 9 or 10, wherein 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.
12. The method of any one of claims 9 to 11, wherein the vertical well section is a lateral branch section extending from an overlying or underlying horizontal well.
13. The method of any one of claims 9 to 11, wherein the vertical well section is part of a single vertical well extending downward from the surface.
14. The method of any one of claims 9 to 13, wherein the thermal in situ hydrocarbon recovery process comprises SAGD.
15. The method of any one of claims 9 to 13, wherein the thermal in situ hydrocarbon recovery process comprises cyclic steam stimulation (CSS).
16. 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.
17. The system of claim 16, wherein the vertical well facilitates providing fluid communication and equalization of the pressure between the IHS zone and the main pay zone.
18. The system of claim 16 or 17, wherein the second injection fluid comprises at least one of a NCG, a solvent and a surfactant.

Date Recue/Date Received 2022-10-24
19. The system of any one of claims 16 to 18, wherein the first injection fluid comprises steam.
20. The system of any one of claims 16 to 19, wherein the vertical well is provided with a slotted liner.
21. The system of any one of claims 16 to 20, wherein the vertical well comprises a casing.
22. The system of claim 21, wherein the casing is a thermal casing.
23. The system of any one of claims 16 to 22, wherein the vertical well comprises a thermal wellhead.
24. The system of any one of claims 16 to 23, wherein the vertical well comprises thermal cement.
25. The system of any one of claims 16 to 24, wherein 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.
26. The system of any one of claims 16 to 25, wherein 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.
27. The system of claim 26, wherein the second injection fluid is injected into the IHS via the upper injection segment.
28. The system of any one of claims 16 to 27, wherein the vertical well is located substantially directly above the SAGD well pair.
29. The system of any one of claims 16 to 28, wherein the vertical well is located in between two adjacent SAGD well pairs.
30. The system of any one of claims 16 to 29, further comprising 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.
Date Recue/Date Received 2022-10-24
31. 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 mobilizing fluid comprising steam into the first perforated well portion, via the well;
dividing the mobilizing fluid of the first perforated well portion, comprising:
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 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 Date Recue/Date Received 2022-10-24 producing the mobilized hydrocarbons of the first pay zone and the mobilized hydrocarbons of the second pay zone.
32. A 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 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.
33. The method of claim 32, wherein the gravity drainage well pair is a Steam-assisted gravity drainage (SAGD) well pair injecting steam into the main pay zone to form a steam chamber as the mobilized chamber.
34. The method of claim 32, wherein 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.
35. The method of claim 34, wherein the solvent is injected as a vapour into the main pay zone and condenses within the solvent-mobilized chamber.
36. The method of claim 34 or 35, wherein the solvent comprises propane, butane, pentane or a combination thereof.

Date Recue/Date Received 2022-10-24
37. The method of any one of claims 32 to 36, further comprising 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.
38. The method of claim 37, wherein the pre-heating comprises electromagnetic heating.
39. The method of claim 37, wherein the pre-heating comprises electric heating.
40. The method of claim 37, wherein the pre-heating comprises radio-frequency heating.
41. The method of claim 37, wherein the pre-heating comprises circulation of solvent through at least one of the wells of the well pair.
42. The method of any one of claims 32 to 41, further comprising heating the main pay zone and/or a region of the IHS using electromagnetic heating during normal operation.
43. A method for recovering hydrocarbons from a reservoir having a main pay zone and overlying inclined heterolithic strata (IFIS), 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;
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 Date Recue/Date Received 2022-10-24 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.
44. 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 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 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 Date Recue/Date Received 2022-10-24 injecting a non-condensable gas (NCG) via the vertical well through the perforations into the 1HS, forming an NCG-enriched zone in the IHS.
45. 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 a pay zone well portion extending from the IHS well portion into an upper region of the main pay zone;
wherein the 1HS 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 1HS, forming an NCG-enriched zone in the IHS.
Date Recue/Date Received 2022-10-24
46. 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.
47. 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 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 Date Recue/Date Received 2022-10-24 producing the mobilized hydrocarbons and condensed solvent.
48. The method of claim 47, wherein the stratified region comprises inclined heterolithic strata (IHS).
49. The method of claim 47 or 48, wherein injecting the solvent and heating with the radio-frequency energy are performed concurrently.
50. The method of any one of claims 47 to 49, wherein the radio-frequency energy is provided by an antenna located in the well.
51. The method of any one of claims 47 to 49, wherein the radio-frequency energy is provided by an antenna provided in the pay zone.
52. The method of any one of claims 47 to 51, wherein the radio-frequency energy provides supplemental heat in addition to heat provided by the solvent injected into the pay zone.
53. The method of any one of claims 47 to 52, wherein the radio-frequency energy is a main source of heat provided to the pay zone.
54. The method of any one of claims 47 to 53, wherein injecting the solvent and heating with the radio-frequency energy are performed during a later production life of the reservoir when less steam is needed compared to an earlier production phase.
55. The method of any one of claims 47 to 54, wherein the well is vertical.
56. The method of claim 31, wherein the stratified region comprises inclined heterolithic strata (IHS).
57. The method of claim 31 or 56, wherein the well comprises an inner tube located inside a casing and defining an annulus therebetween.
58. The method of claim 57, wherein the mobilizing fluid is injected down the inner tube.
59. The method of claim 57 or 58, wherein the isolating comprises providing at least one packer in the annulus.

Date Recue/Date Received 2022-10-24
60. The method of claim 57 or 58, wherein the at least one packer is a single packer that isolates the annuls of the first perforated well portion from that of the second perforated well portion.
61. The method of claim 57 or 58, wherein the isolating comprises providing a first packer in the annulus proximate an upper part of the low permeability layer separating the first pay zone and the second pay zone, and providing a second packer in the annulus proximate a lower part of the low permeability layer separating the first pay zone and the second pay zone.
62. The method of any one of claims 57 to 61, wherein producing the mobilized hydrocarbons from the first pay zone and producing the mobilized hydrocarbons from the first pay zone are performed simultaneously.
63. The method of any one of claims 57 to 61, wherein producing the mobilized hydrocarbons from the first pay zone and producing the mobilized hydrocarbons from the first pay zone are performed independently.
64. The method of any one of claims 57 to 63, wherein injecting the mobilizing fluid into the first pay zone and the second pay zone is performed selectively using flow control devices that are provided in the first perforated well portion and the second perforated well portion.
65. The method of claim 64, wherein the flow control devices are provided on the inner tube.
66. The method of claim 64 or 65, wherein the flow control devices comprise sliding sleeves.
67. The method of claim 64 or 65, wherein the flow control devices comprise a valve.
68. The method of any one of claims 31 or 56 to 63, further comprising controlling a flow of the mobilizing fluid from the first perforated well portion to the first pay zone or from the second perforated well portion to the second pay zone, or both.

Date Recue/Date Received 2022-10-24
69. The method of claim 68, wherein the controlling of the flow of the mobilizing fluid is performed using flow control devices that are provided in the first perforated well portion and the second perforated well portion.
70. The method of any one of claims 64 to 67 or 69, wherein the flow control devices respectively located at the in the first perforated well portion and the second perforated well portion are provided to account for pressure differences between the first pay zone and the second pay zone.
71. The method of any one of claims 31 or 56 to 70, wherein injecting the mobilizing fluid and producing the mobilized hydrocarbons is performed cyclically in alternating injection and production modes.
72. The method of any one of claims 31 or 56 to 71, wherein the first perforated well portion and the second perforated well portion include perforations that are provided on only one side of the well to provide orientation of the mobilizing fluid injected into the first and second pay zones.
73. The method of claim 72, wherein the low permeability layers are inclined to define a dip direction, and the perforations are provided to face away from the dip direction.
74. The method of any one of claims 31 or 56 to 72, wherein the pay zones further comprise a third pay zone located below the second pay zone; the well further comprises a third perforated well portion downstream of the second perforated well portion and extending through the third pay zone and in fluid communication with the third pay zone; a third portion of the mobilizing fluid is directed into the third pay zone via the third perforated well portion to form mobilized hydrocarbons; and the mobilized hydrocarbons of the third pay zone are produced.
75. The method of any one of claims 31 or 56 to 74, wherein the well is vertical.
76. The method of any one of claims 31 or 56 to 74, wherein the well is inclined.
77. The method of claim 76, wherein the well is inclined in a low permeability layer dip direction.

Date Recue/Date Received 2022-10-24
78. The method of any one of claims 43 to 45, wherein 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.
79. The method of any one of claims 43 to 45 or 78, wherein 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.
80. The method of claim 79, wherein 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.
81. The method of any one of claims 43 to 45, 79 or 80, wherein injecting the NCG is performed so as to create a back pressure sufficient to reduce solvent override from the solvent-mobilized chamber into the I HS.
82. The method of any one of claims 43 to 45 or 79 to 81, wherein the vertical well is located substantially directly above the well pair.
83. The method of any one of claims 43 to 45 or 79 to 81, wherein the vertical well is located in between two adjacent well pairs.
84. The method of any one of claims 43 to 45 or 79 to 83, further comprising isolating the vertical well with an isolation packer so as to provide an upper injection segment for injecting the 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.
Date Recue/Date Received 2022-10-24
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