CA2899805C

CA2899805C - Dewatering lean zones with ncg injection using production and injection wells

Info

Publication number: CA2899805C
Application number: CA2899805A
Authority: CA
Inventors: Hussain Sheikha; Govinder Singh Parmar; Hossein Aghabarati; Heather Lynn Macdonald
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2015-08-04
Filing date: 2015-08-04
Publication date: 2018-05-01
Anticipated expiration: 2035-08-04
Also published as: CA2998423A1; CA2998423C; CA2899805A1

Abstract

Recovery of bitumen can include dewatering a water-saturated hydrocarbon-lean zone and producing hydrocarbons from an underlying bitumen-rich reservoir. The dewatering can include producing water via water production wells, and injecting non- condensable gas (NCG) via an injection well such that NCG is injected to re-pressurize the hydrocarbon-lean zone while avoiding substantial channeling of NCG toward the water production wells. After reaching a target water-saturation reduction in the lean zone and forming a gas-enriched zone, the water production wells can be converted to corresponding NCG injection wells to inhibit water migration into the gas- enriched zone. In situ wells, such as SAGD wells, located in the bitumen-rich reservoir below the gas- enriched zone can be operated to form a chamber, such as a steam chamber, and the gas-enriched zone is maintained at a pressure close to the underlying chamber pressure, providing overlying NCG insulation and pressurization for the chamber and hydrocarbon recovery operation.

Description

DEWATERING LEAN ZONES WITH NCG INJECTION USING PRODUCTION AND
INJECTION WELLS
FIELD
[0001] The technical field generally relates to in situ hydrocarbon recovery, and more particularly, to dewatering of lean bitumen zones.
BACKGROUND

[0002] In heavy hydrocarbon-bearing reservoirs, top zones that are hydrocarbon lean and water rich are considered challenging for recovery using techniques such as Steam-Assisted Gravity Drainage (SAGD). In conventional oil recovery, water tends to be less dense than the conventional oil such that the oil tends to be located above water rich zones. SAGD is an enhanced hydrocarbon recovery technology for producing heavy hydrocarbons, such as heavy oil and/or bitumen, from heavy hydrocarbon-bearing reservoirs. Typically, a pair of horizontal wells is drilled into a reservoir, such as an oil sands reservoir, and steam is injected into the reservoir via the upper injection well to heat and reduce the viscosity of the heavy 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 production well.

[0003] Conventional SAGD operated in reservoirs with top water-saturated, hydrocarbon-lean zones (e.g., lean bitumen zones) can lead to an elevated Steam-to-Oil Ratio (SOR) and low hydrocarbon recovery rates. Once the steam chamber intercepts the lean bitumen zone, heat and steam can be lost to the overlying water-rich zone resulting in a poor performance due to the fact that significant steam energy can be wasted in heating the lean bitumen zone. The high heat capacity of water and tendency of the steam to flow into the lean bitumen zone pose challenges to heavy hydrocarbon recovery from reservoirs with a water-saturated, hydrocarbon-lean zone.

[0004] Some conventional solutions have been proposed in an attempt to enhance the hydrocarbon recovery rate in such lean zones. A first method includes decreasing the well spacing to promote higher production of bitumen before the steam chamber intercepts the top lean bitumen zone. However, this method increases the capital cost of the operation because of the greater number of wells to be drilled for a given reservoir volume. A second method includes co-injecting non-condensable gas (NCG) with steam during SAGD recovery, with the intention of reducing fluid losses and improving the thermal efficiency of the recovery process. The size of the lean bitumen zone can be a relevant factor in the selection of the proper water-depletion method. When the size of the lean bitumen zone is small and limited, the above-mentioned methods can be utilized successfully. However, when the size of lean bitumen zone is larger, such methods have noteworthy drawbacks in developing such reservoirs.

[0005] There are various challenges related to hydrocarbon recovery from reservoirs that are proximate to water-saturated, hydrocarbon lean zones.
SUMMARY

[0006] In some implementations, there is provided a process for Steam-Assisted Gravity Drainage (SAGD) recovery of bitumen, comprising;
identifying a subterranean water-saturated hydrocarbon-lean zone having a lower hydrocarbon content than an underlying bitumen-rich reservoir, having high water saturation, having a thickness of more than 5 meters, being located above and in fluid communication with the bitumen-rich reservoir, and being part of a geologically-contained water-saturated formation;
dewatering the hydrocarbon-lean zone, comprising:
producing water from the hydrocarbon-lean zone via water production wells located at a low elevation in the hydrocarbon-lean zone and operating under a gravity-dominated mechanism, thereby reducing the water saturation and pressure in the hydrocarbon-lean zone;
injecting non-condensable gas (NCG) via an injection well located at a higher elevation compared to the water production wells and regulated such that the NCG is injected at a pressure and a rate sufficient to re-pressurize the hydrocarbon-lean zone while avoiding substantial channeling of the NCG toward the water production wells;

after reaching a target water-saturation reduction in the hydrocarbon-lean zone and thereby forming a gas-enriched lean zone, converting the water production wells to corresponding NCG injection wells and injecting NCG
there-through to inhibit water migration into the gas-enriched lean zone;
operating SAGD wells in the bitumen-rich reservoir below the gas-enriched lean zone, thereby forming a SAGD steam chamber; and maintaining the gas-enriched lean zone at a lean zone pressure between 0 kPa and 400 KPa below an underlying SAGD steam chamber pressure, thereby providing overlying NCG insulation and pressurization for the SAGD steam chamber.

[0007] In some implementations, there is provided a process for dewatering a subterranean water-saturated, hydrocarbon-lean zone located above and having a lower hydrocarbon content than a hydrocarbon-bearing reservoir, comprising:
producing water via a production well provided in the hydrocarbon-lean zone;
injecting a gas via a primary injection well provided in the hydrocarbon-lean zone to form a gas-enriched region; and once injected gas reaches or has advanced proximate to the production well, converting the production well into a secondary injection well for injecting additional gas into the hydrocarbon-lean zone to inhibit water migration from outside of the gas-enriched lean zone.

[0008] In some implementations, the primary injection well is substantially vertical.

[0009] In some implementations, the production well is substantially vertical.

[0010] In some implementations, the process further comprises: monitoring advancement of the gas within the lean zone so as to identify when the injected gas reaches or has advanced proximate to the production well.

[0011] In some implementations, the monitoring comprises: measuring dissolved gas content in the water produced by the production well. In some implementations, the monitoring comprises: obtaining information from an observation well located in the lean zone.

[0012] In some implementations, the gas is injected via the primary injection well at a pressure and a rate sufficient to re-pressurize the lean zone while avoiding substantial channeling of the gas past the water toward the production well.

[0013] In some implementations, the step of converting the production well is performed once the lean zone has reached a target water-saturation reduction.

[0014] In some implementations, the target water-saturation reduction is at least about 25% volume.

[0015] In some implementations, the target water-saturation reduction is at least about 50% volume.

[0016] In some implementations, the process further includes producing water via a plurality of production wells arranged in spaced relation from each other and around the primary injection well; and once injected gas reaches or has advanced proximate to the production wells, respectively converting the production wells into corresponding secondary injection wells for injecting additional gas into the reservoir to inhibit water migration from outside of the gas-enriched lean zone.

[0017] In some implementations, the production wells are substantially vertical.

[0018] In some implementations, the gas comprises a non-condensable gas (NCG).
In some implementations, the gas consists of a NCG.

[0019] In some implementations, the water-saturated, hydrocarbon-lean zone overlies a main pay zone of a hydrocarbon-bearing reservoir, and the process further comprises:
forming the gas-enriched lean zone prior to operating in situ recovery wells within the main pay zone.

[0020] In some implementations, the in situ recovery wells comprise a Steam-Assisted Gravity Drainage (SAGD) well pair.

[0021] In some implementations, the process further includes: maintaining the gas-enriched lean zone at a lean zone pressure between 0 kPa and 400 KPa below an underlying in situ recovery pressure in the main pay zone.

[0022] In some implementations, the primary injection well comprises an injection section located at a high elevation in the lean zone, the high elevation being above a mid-way point of the lean zone, above a three-quarters point of the lean zone, above a seven-eighths point of the lean zone, or adjacent to an upper limit of the lean zone.

[0023] In some implementations, the production well comprises a production section located at a low elevation in the lean zone, the low elevation being below a mid-way point of the lean zone, below a one-quarter point of the lean zone, below a one-eighth point of the lean zone, or adjacent to the hydrocarbon-bearing reservoir.

[0024] In some implementations, the gas injection rate via the primary injection well and the water production rate via the production well are provided at least in part based on the relative permeability of the gas and water in the porous media of the lean zone.

[0025] In some implementations, the process further includes: determining permeability characteristics of the lean zone; and providing the gas injection rate and the water production rate at least in part based on the permeability characteristics.

[0026] In some implementations, the step of determining permeability characteristics of the lean zone comprises analyzing core samples of the lean zone and/or performing simulation modelling.

[0027] In some implementations, the gas injection pressure via the primary injection well is sufficiently low to inhibit premature gas breakthrough at the production well and promote gravity drainage of water toward the production wells.

[0028] In some implementations, the lean zone has a thickness of at least 5 meters. In some implementations, the lean zone has a thickness of at least 10 meters.

[0029] In some implementations, the lean zone is part of a geologically-contained water-saturated formation.

[0030] In some implementations, the production well has a pump located in a sump below the lean zone.

[0031] In some implementations, the hydrocarbon-bearing reservoir comprises heavy oil and/or bitumen.

[0032] In some implementations, there is provided a process for recovering hydrocarbons from a hydrocarbon-bearing reservoir located below and in fluid communication with a subterranean water-saturated hydrocarbon-lean zone, comprising:
producing water via a production well provided in the hydrocarbon-lean zone;
injecting a gas via a primary injection well provided in the hydrocarbon-lean zone to form a gas-enriched region;
monitoring the advancement of the gas within the lean zone;
once injected gas reaches or has advanced proximate to the production well, converting the production well into a secondary injection well for injecting additional gas into the reservoir to inhibit water migration from outside of the gas-enriched lean zone; and operating an in situ recovery operation in the hydrocarbon-bearing reservoir such that the gas-enriched lean zone provides overlying insulation and pressurization.

[0033] In some implementations, the in situ recovery operation comprises a thermal in situ recovery operation. In some implementations, the thermal in situ recovery operation comprises a Steam-Assisted Gravity Drainage (SAGD) operation. In some implementations, the above process includes one or more features as defined in other paragraphs and/or the description or drawings.

[0034] In some implementations, there is provided a process for Steam-Assisted Gravity Drainage (SAGD) recovery of bitumen, comprising:
dewatering a first hydrocarbon-lean zone that is located above a first bitumen-rich pay zone and adjacent to and fluidly communicating with a second hydrocarbon-lean zone, the dewatering comprising:

producing water from the first lean zone; and injecting gas into the first lean zone, to provide a first gas-enriched lean zone;
operating a first array of SAGD well pairs in the first pay zone, to produce bitumen and form steam chambers having overlying insulation and pressurization provided by the first gas-enriched zone;
dewatering the second lean zone located above a second bitumen-rich pay zone, the dewatering comprising:
producing water from the second lean zone; and injecting gas into the second lean zone, to provide a second gas-enriched lean zone;
operating a second array of SAGD well pairs in the second pay zone, to produce bitumen and form steam chambers having overlying insulation and pressurization from the second gas-enriched zone.

[0035] In some implementations, the process also includes converting water production wells located in the first lean zone into gas injection wells to inhibit water migration from outside the first lean zone.

[0036] In some implementations, the process also includes converting water production wells located in the second lean zone into gas injection wells to inhibit water migration from outside the second lean zone.

[0037] In some implementations, the dewatering of the first lean zone is performed until a first target water-saturation reduction and first target lean zone pressure are achieved, prior to operating the first array of SAGD well pairs in the first pay zone;
and the dewatering of the second lean zone is performed until a second target water-saturation reduction and second target lean zone pressure are achieved, prior to operating the second array of SAGD well pairs in the first pay zone.

[0038] In some implementations, the first and second target water-saturation reductions are at least about 25% volume.

[0039] In some implementations, the first and second target lean zone pressures are between 0 kPa and 400 KPa below an underlying SAGD steam chamber pressure.

[0040] In some implementations, the above process includes one or more features as defined in other paragraphs and/or the description or drawings herein.

[0041] In some implementations, there is provided a process for in situ recovery of bitumen, comprising:
dewatering a first hydrocarbon-lean zone that is located above a first bitumen-rich pay zone and adjacent to and fluidly communicating with a second hydrocarbon-lean zone, the dewatering comprising:
producing water from the first lean zone; and injecting gas into the first lean zone, to provide a first gas-enriched lean zone;
operating a first array of well pairs in the first pay zone, to produce bitumen and form mobilization chambers having overlying insulation and pressurization provided by the first gas-enriched zone;
dewatering the second lean zone located above a second bitumen-rich pay zone, the dewatering comprising:
producing water from the second lean zone; and injecting gas into the second lean zone, to provide a second gas-enriched lean zone;
operating a second array of well pairs in the second pay zone, to produce bitumen and form mobilization chambers having overlying insulation and pressurization from the second gas-enriched zone.

[0042] In some implementations, the in situ recovery comprises a thermal in situ recovery operation. In some implementations, the thermal in situ recovery operation comprises Steam-Assisted Gravity Drainage (SAGD).

s.

[0043] In some implementations, the first array of well pairs comprises SAGD
well pairs, and the corresponding mobilization chambers comprise steam chambers. In some implementations, the second array of well pairs comprises SAGD well pairs, and the corresponding mobilization chambers comprise steam chambers.

[0044] In some implementations, the process also includes converting water production wells located in the first lean zone into gas injection wells to inhibit water migration from outside the first lean zone.

[0045] In some implementations, the process also includes converting water production wells located in the second lean zone into gas injection wells to inhibit water migration from outside the second lean zone.

[0046] In some implementations, the dewatering of the first lean zone is performed until a first target water-saturation reduction and first target lean zone pressure are achieved, prior to operating the first array of well pairs in the first pay zone; and the dewatering of the second lean zone is performed until a second target water-saturation reduction and second target lean zone pressure are achieved, prior to operating the second array of well pairs in the first pay zone.

[0047] In some implementations, the first and second target water-saturation reductions are at least about 25% volume.

[0048] In some implementations, the first and second target lean zone pressures are between 0 kPa and 400 KPa below an underlying mobilization chamber pressure.

[0049] In some implementations, there is provided a system for dewatering a subterranean water-saturated, hydrocarbon-lean zone located above and having a lower hydrocarbon content than a hydrocarbon-bearing reservoir, cornprising:
a production well provided in the hydrocarbon-lean zone and configured to produce water;
a primary injection well provided in the hydrocarbon-lean zone and configured to inject a gas via to form a gas-enriched region; and a conversion assembly coupled to the production well and configured to convert the production well into a secondary injection well once injected gas reaches or has advanced proximate to the production well, such that the secondary injection well is configured for injecting additional gas into the hydrocarbon-lean zone to inhibit water migration from outside of the gas-enriched lean zone.

[0050] In some implementations, there is provided a system for in situ recovery of bitumen, comprising:
a first production well provided in a first hydrocarbon-lean zone that is located above a first bitumen-rich pay zone and adjacent to and fluidly communicating with a second hydrocarbon-lean zone, the first production well being configured to produce water from the first hydrocarbon-lean zone;
a first injection well provided in the first hydrocarbon-lean zone and being configured to inject gas into the first lean zone, to provide a first gas-enriched lean zone, the first production and injection wells being configured and operable to dewater the first hydrocarbon-lean zone;
a first array of well pairs provided in the first pay zone and configured to produce bitumen and form mobilization chambers having overlying insulation and pressurization provided by the first gas-enriched zone;
a second production well provided in the second hydrocarbon-lean zone that is located above a second bitumen-rich pay zone, the second production well being configured to produce water from the second hydrocarbon-lean zone;
a second injection well provided in the second hydrocarbon-lean zone and being configured to inject gas into the second lean zone, to provide a second gas-enriched lean zone, the second production and injection wells being configured and operable to dewater the second hydrocarbon-lean zone; and a second array of well pairs provided in the second pay zone and configured to produce bitumen and form mobilization chambers having overlying insulation and pressurization from the second gas-enriched zone.

[0051] In some implementations, the systems further comprise one or more components and/or features as defined in paragraphs above or in the description or drawings herein.
BRIEF DESCRIPTION OF DRAWINGS

[0052] Fig 1 is a vertical cross-sectional view schematic of a lean zone located above a main pay zone, with a gas injection well and water production wells located in the lean zone.

[0053] Fig 2 is a top plan view schematic of water production wells distributed around a gas injection well.

[0054] Fig 3 is a perspective view schematic of a lean zone with a gas injection well and water production wells located in the lean zone, and an observation passing through the lean zone.

[0055] Fig 4 is a vertical cross-sectional view schematic of a lean zone with a gas injection well and water production wells located in the lean zone during a first dewatering phase.

[0056] Figs 5A to 5D are vertical cross-sectional view schematics illustrating gas injection and water production in a lean zone during a first phase, and conversion of production wells into injection wells during a second phase of the dewatering process.

[0057] Figs 6A and 6B are top plan view schematics illustrating dewatering well arrangements, where a first stage includes a first arrangement of wells and a second stage includes a second arrangement of wells provided adjacent to the first arrangement of wells.

[0058] Figs 7A to 7G are vertical cross-sectional view schematics illustrating dewatering of lean zones above SAGD operations.

[0059] Fig 8 is a perspective view schematic of a dewatering operation performed with substantially horizontal wells provided in a lean zone.

[0060] Fig 9 is a vertical cross-sectional view schematic of a plurality of adjacent lean zones with corresponding dewatering well arrangements in each lean zone.

[0061] Fig 10 is a vertical cross-sectional view schematic of a SAGD operation with a steam chamber at PGAGD and an overlying dewatered gas-enriched zone at PG.

[0062] Fig 11 is a vertical cross-sectional view schematic of a reservoir including a plurality of lean zones within a high water-saturation formation that is geologically contained and located above a bitumen-rich reservoir.

[0063] Fig 12 is a flowchart for a dewatering and hydrocarbon recovery process.

[0064] Fig 13 is a vertical cross-sectional view schematic including a lean zone with a gas injection well and water production wells.

[0065] Fig 14 is a graph of average lean zone pressure versus time.

[0066] Fig 15 is a graph of gas injection rates versus time.

[0067] Fig 16 is a graph of water recovery factor versus time.
DETAILED DESCRIPTION

[0068] The proposed techniques generally relate to dewatering of a water-saturated, hydrocarbon-lean zone and hydrocarbon recovery from a reservoir located below such a lean zone. Water is produced from the lean zone and gas, such as non-condensable gas (NCG), is injected into the lean zone in order to modify the saturation of the lean zone and form a gas-enriched zone overlying a main pay zone in which an in situ recovery operation. In some implementations, the in situ recovery operation is a thermal operation, e.g., Steam-Assisted Gravity Drainage (SAGD). Gas injection into the lean zone can also increase the pressure of the lean zone to a level close to SAGD
operating pressures, particularly once the SAGD steam chambers reach the lean zone. The overlying gas-enriched zone provides insulation and pressurization above the thermal in situ recovery operation to reduce heat and fluid losses. In some implementations, water is produced from the lean zone via production wells provided around a primary gas injection well located in the lean zone. The water production and gas injection can be controlled to promote gravity-drainage of the water and re-pressurization of the zone by µ, the gas, while avoiding substantial channeling of the gas past the water toward the production wells. As the injected gas reaches or approaches one or more of the production wells, the respective production wells can be shut in or have their production rate decreased dramatically, so as to promote gravity drainage rather than displacement and gas coning. The water production wells operate in production mode during a first phase of the dewatering process. In a second phase of the process, the production wells can be converted to become secondary gas injection wells to aid in maintaining the gas-enriched zone and inhibiting water and gas migration into the lean zone during the thermal in situ recovery operation.

[0069] The dewatering and pressurization of the lean zone leads to a more energy-efficient hydrocarbon recovery process. Dewatering and injecting NCG into the lean zone can facilitate increasing the fluid pressure in the lean zone and thus reducing the differential pressure between the lean zone and the main pay zone.
Consequently, heat and steam loss to the lean zone is reduced, which in turn can improve the Steam-to-Oil Ratio (SOR), for example.

[0070] In some implementations, the dewatering and hydrocarbon production techniques can be performed in reservoirs that include a main hydrocarbon-containing zone (i.e., a main pay zone) and a lean zone that has high water saturation, which would tend to reduce performance of hydrocarbon production from the main pay zone, due to the high heat capacity of water and/or lower pressure of the lean zone compared to the pressures of the recovery operation (e.g., SAGD). Various techniques that are described herein enable enhanced thermal in situ recovery operations by dewatering and re-pressurizing the lean zone with gas.

[0071] Some of the drawings and implementations refer to a SAGD operation.
However, it should be understood that other configurations can be used that may or may not involve the use of steam. For example, an injection well may be used to inject a solvent or other chemical that can be used to modify the viscosity of the hydrocarbons in the formation, so that hydrocarbons can be produced by gravity flow to the production well, and steam may not be used in such a configuration. In other configurations, a source of thermal energy other than steam, e.g., electric heat, radio frequency energy, etc., can be used to heat the formation and again modify the viscosity of the hydrocarbon to facilitate production by gravity drainage. The in situ recovery techniques µ, may include steam as a primary mobilizing fluid injected into the formation;
other mobilizing fluids, such as hydrocarbon-based solvent, that may be at ambient or higher temperatures, and are injected into the formation alone, co-injected with steam or injected in an alternating manner with steam to help mobilize the hydrocarbons; or other heating methods can be used, alone or in combination with mobilizing fluid injection, to help mobilize the hydrocarbons for gravity drainage. The implementations described below in the context of SAGO are not intended to be limited to SAGD
applications.
Lean zones for dewatering and pressurization

[0072] Referring to Fig 1, the dewatering and gas injection are performed on a water-saturated, hydrocarbon-lean zone 10 (also referred to herein as a "lean bitumen zone" or "lean zone" in some implementations). The lean zone 10 can be part of an overall formation 12 that includes various fluids, solid media and lithological properties. The lean zone 10 is located above a hydrocarbon-rich reservoir 14 (also referred to herein as a "main pay zone") in which thermal in situ hydrocarbon recovery wells can be located. In some alternative implementations, the lean zone may be located beside or below the main pay zone, and the dewatering techniques may be adapted accordingly to account for the different characteristics, such as an underlying lean zone having higher pressures.

[0073] It should be understood that lean zones 10 are regions of a formation that have higher water-saturation and/or lower pressure compared to a proximate (e.g., adjacent or overlying) main pay zone, such that performance of an in situ hydrocarbon recovery process operating in the main pay zone can be reduced due to heat and/or fluid loss to the lean zone. For example, when steam-assisted in situ hydrocarbon recovery operations are employed in the main pay zone, the steam chamber pressure can be higher than the pressure of the lean zone leading to steam loss to the lean zone leading to higher heat transfer from the steam to the water in the lean zone. It should nevertheless be noted that some in situ hydrocarbon recovery operations can use other fluids, such as hydrocarbon solvents, in which case the fluid loss may be of more concern than heat loss in terms of efficient operation.

[0074] Referring to Fig 9, lean zones 10 may vary in thickness and elevation depending on various factors. In some implementations, lean zones more than 5 meters or more that 10 meters in thickness (h) are candidates for dewatering and pressurizing according to techniques described herein. It should also be noted that candidate lean zones for dewatering can also be identified using a number of techniques and can be based on various characteristics of the lean zone and the pay zone, and economic analyses. A lean zone may be one or a few square kilometers, for example, and may have bitumen saturation below 50%, high water saturation, low pressure, and may be relatively thick.
Lean zone characteristics such as size, bitumen saturation, water saturation and pressure can be identified in order to determine whether the dewatering process would be economical.

[0075] Referring to Fig 11, in some implementations, the lean zone 10 or multiple lean zones are part of a geologically-contained water-saturated formation 122, where geological barriers 11 substantially contain the water, rather than being in substantial fluid communication with an aquifer for example. Implementing the process in geologically-contained water-saturated formations can facilitate both the dewatering and maintenance of a gas-enriched zone, as water migration into the dewatered lean zone is reduced.
Character 124 in Fig 11 indicates a bitumen-rich reservoir.

[0076] Referring back to Fig 1, it should be understood that the main pay zones 14 are regions that include hydrocarbons, such as heavy oil or bitumen, that are economically recoverable using an in situ recovery technique in which a mobilizing fluid is injected into the main pay zone. SAGD is one such technique. Other techniques include Cyclic Steam Stimulation (CSS), in situ combustion, steam flooding, and solvent-assisted methods.
Production wells and injection well within lean zone

[0077] Referring to Fig 1, in some implementations, production wells 16 are provided in the lean zone 10 and are configured for producing water 18. At least one injection well 20 is also provided in the lean zone 10 and is configured for injecting gas 22, such as NCG, into the lean zone 10. The production wells 16 can be vertical having a lower extremity located at a lower elevation of the lean zone 10, and the injection well 20 can be vertical having a lower end at or near the top of the lean zone 10. This well configuration can aid in water production under gravity-dominated mechanism while avoiding gas channeling to the production wells 16.

[0078] Referring still to Fig 1, there is fluid and pressure communication between lean zone 10 and the main pay zone 14 rich in bitumen. In some implementations, the production wells 16 have a lower end that is located at the bottom of the lean zone, for instance within the lean zone proximate to a boundary region 24 that separates the lean zone 10 and the main pay zone 14. Alternatively, as shown in Fig 13, the production wells 16 can pass through the lean zone 10 and into the upper part of the main pay zone 14. To enhance water production, the production wells 16 can have a lower portion penetrating the main pay zone 14. This lower portion can include a perforated liner or screen to inhibit sand and heavy hydrocarbon production. In some implementations, the portion of the production well 16 that fluidly communicates with the lean zone 10 and thus allows flow of water into the production well 16 can be located at a lower elevation within the lean zone to promote the gravity drainage mechanism. Referring to Fig 13, in some implementations, the production wells can be provided within sumps or drainage pits 26.
The sumps 26 may be formed as the end of the wellbore drilled into the upper part of the main pay zone. Referring to Fig 8, in some implementations, one or more of the production wells 16 can be horizontal, slanted and/or directionally drilled to follow the contour of the boundary region 24 of the lean zone 10 or to follow another desired trajectory. In Fig 13, character 126 indicates a unit that can receive information from producers (T, P, etc.).

[0079] In some scenarios, the boundary region is defined by the region having high saturation of heavy hydrocarbons that forms a substantial barrier to gas injection at the low gas injection pressures used to inject the gas into the lean zone. Gas that may reach the boundary region is impeded from passing into the main pay zone and thus advances laterally within the lean zone.

[0080] Referring to Fig 8, the injection well 20 can also be provided as a horizontal well, which may extend in a substantially parallel manner with the production wells, or may be at other orientations. The horizontal section of the injection well 20 can be provided at a higher elevation compared to the horizontal sections of the production wells 16. Both the injection and production wells can be provided with suitable apertures, perforations or other means of fluid communication with the lean zone in order to allow gas injection and water production.

[0081] The production and injection wells can have completions according to various characteristics of the lean zone. For example, slotted liners or screens may be used in ,µ

the production wells in the event that sand production or blockage are potential problems.

[0082] Referring now to Figs 2 and 3, in some implementations, the well arrangement can include at least one primary gas injection well 20 and multiple spaced-apart production wells 16 located around the central injection well 20. Various well patterns may be employed, including five-spot, seven-spot and/or nine-spot patterns, variants thereof, with one or multiple injection wells 20 located at a generally central location. The well patterns can also be provided depending on the size, shape and geological properties of the lean zones and surrounding formation properties. More regarding well patterns and operation of the wells will be described further below.
Operation of the production and injection wells

[0083] Referring to Figs 5A to 5D, the general operation of the production and injection wells will be described. In general, the production wells 16 are operated to produce water and the injection well 20 is operated to inject NCG into the lean zone, to dewater and pressurize the lean zone. The production and injection are operated to promote gravity drainage of the water. While water production can have a displacement component, which can vary depending on the stage of the dewatering process, the wells are spaced, located and operated to promote gravity drainage. The injection and production are controlled so that gas breakthrough in the production wells is delayed for a significant period of time. Thus, the gas injection is controlled in accordance with the water production as well as the permeability properties of the lean zone.
Permeability properties can be determined, for example, based on core samples, simulation modelling, calculations and/or empirical experimentation.

[0084] Referring to Fig 5A, water removal begins as the production wells 16 are used to produce water. Artificial or mechanical lift devices, such as pumps, can also be used to help produce water. Providing the production wells 16 so that the portion that received the flow of water from the lean zone is located at the bottom of the lean zone facilitates this gravity drainage of the water. To further enhance such gravity drainage, the portion that received the flow of water can be located in a sump below the lean zone, as illustrated in Fig 13. A sump pump can be provided to facilitate production, where the pump intake is located within the sump. It should be noted that the dewatering can be done well before the steam chamber approaches the lean zone and even before the SAGD operation is started up in the main pay zone. Various different kinds of pumps can be used, such as Electric Submersible Pumps (ESP) or Progressive Cavity Pumps (PCP).

[0085] Referring still to Fig 5A, produced water 18 is recovered at the surface at can be processed, reused and/or disposed of by various methods depending on the quality and quality of the produced water. In some scenarios, the produced water 18 is relatively high quality, for example to typical aqueous streams that are separated from SAGD
production fluids, and thus can be used in steam generation for SAGD or other purposes. In some scenarios, the produced water 18 can be supplied to other processing units, such as oil sands primary extraction units. The produced water 18 can also be stored in holding ponds or sent to local rivers if quality permits.

[0086] In some implementations, the produced water 18 or a portion thereof is monitored for gas content in order to determine whether injected gas has advanced through the lean zone so as to be produced via the production wells. A gas detector 28 can be installed to perform this detection. It should be noted that gas detection in general can be performed by other methods, such as observation wells 30 provided through the lean zone 10, as illustrated in Fig 3, the observation wells being equipped with appropriate devices for directly and/or indirectly detecting gas and relaying the information so that certain appropriate actions can be taken. More regarding gas detection will be discussed further below, particularly in the context of ceasing water production and converting production wells to gas injection wells.

[0087] Referring now to Figure 5B, gas 22 is injected through the primary injection well 20 into the lean zone 10. In some implementations, the gas injection starts after water production has been conducted. For example, the gas injection can be initiated once water production has begun to decline, once a certain pressure reduction has occurred due to water production, or after a certain amount of water has been produced via the production wells. Gas injection has the objectives of facilitating sustained water production via the production wells 14 and replacing water with gas in the lean zone 10.
The gas injection can be regulated by a gas injection controller 32, for example to provide an injection rate to avoid early breakthrough of the gas past the water toward the production wells 14 while still re-pressurizing the lean zone 10. The gas re-pressurization can be done to achieve a pressure that is comparable to SAGD
operation pressure provided that the lean zone pressure does not exceed the fracture pressure or the steam chamber pressure. In some implementations, the gas re-pressurization is conducted to achieve an increased average pressure in the lean zone compared to its initial pressure. While gas pressurization would ideally increase the pressure as close as possible to the pressures of the thermal in situ recovery operation, gas injection should not be conducted at a rate to cause substantial and pre-mature channeling and breakthrough of the gas through the water-saturated regions of the lean zone, which could lead to gas breakthrough at the production wells. The gas injection rate can thus be controlled so as to be relatively low, and coordinated with the water production and permeability of the lean zone, to facilitate water removal and pressurization that will provide insulation and pressurization for the subsequent thermal in situ recovery operation. Gas injection rates can be controlled based on a number of factors, including the water production rate, characteristics of the lean zone including the permeability of the solid media in the lean zone, the water-saturation and distribution within the lean zone, as well as location and orientation of the injection and production wells. As shown in Fig 5B, the gas injection forms a gas-enriched region 34 that expands outwardly from the injection well 20.

[0088] Referring to Figure 5C, as gas 22 is injected into the lean zone 10 the gas-enriched region expands outwardly and downwardly. In some implementations, the gas that is injected has low gas solubility in water at the temperature and pressure conditions of the lean zone. In some implementations, when the gas is injected proximate to cap rock defining an upper generally-impermeable gas barrier, part of the gas-enriched region 34 grows in a generally outward direction toward the surrounding production wells 16. The gas-enriched region 34 can expand outwardly and eventually reach upper parts of the production wells that may not fluidly communicate with the lean zone 10, as illustrated in Fig 5C, and the gas can expand downwardly as well toward the lower portion of the production well 16 in fluid communication with the lean zone 10. As water is produced from the bottom of the production wells 16, the gas tends to fill the upper part of the lean zone 10 and then gradually expand downwardly. The gas injection can provide some gas drive to aid in promoting water displacement toward the production wells 16; but in order to achieve enhanced dewatering performance gravity drainage is promoted. It should be noted that the gas injection can be modulated over time depending on the progression of the gas-enriched region 34 within the lean zone 10.

[0089] In some scenarios, the lean zone may include existing gas-saturated zones, resulting in higher compressibility. In such scenarios, the water production wells can be located away from the existing gas-saturated zones, and more gas can be injected via the injection well in order to increase the lean zone pressure.

[0090] Referring briefly to Fig 5D, in some implementations, after water production and gas injection have led to the formation of a gas-enriched lean zone, one or more of the production wells 16 can be converted into a secondary injection well 36. This conversion is referred to herein as the beginning of the second phase of the dewatering process.
Gas injection via the secondary injection wells 36 is performed to inhibit water migration from outside of the gas-enriched lean zone. Gas injection can continue through all of the injection wells in order to maintain the gas-enriched lean zone at a lean zone pressure, which can be provided based on the underlying thermal in situ recovery operation pressures (e.g., SAGO steam chamber pressures), thereby providing overlying gas insulation and pressurization for the recovery operation. More regarding the conversion of the production wells 16 into secondary gas injection wells 36 will be discussed further below.

[0091] In some implementations, the central injection wells can inject NCG
while the surrounding water production wells are monitored for production of gas (e.g., by monitoring the gas/water ratio in the production stream, by detecting the gas when the injected gas is not native to the lean zone, etc.). Once the gas is detected in the production fluids of a surrounding water production well, the well can be converted to a secondary NCG injection well. Eventually, all of the surrounding water production wells can be converted into NCG injection wells. In some implementations, once a certain amount of the water has been removed from the lean zone, e.g. 25%, 30%, 35%, 40%, 45% or 50% of the estimated water volume, recovery of hydrocarbons in the main pay zone can start. Alternatively, recovery of hydrocarbons in the main pay zone can begin prior to dewatering to the target depletion level.

[0092] Referring briefly to Figs 7C and 7D, in some implementations, after the dewatering and gas pressurization of the lean zone 10, the thermal in situ recovery operation (e.g., SAGD) is commenced in the main pay zone 14. Fig 7C
illustrates the formation of SAGD steam chambers, and Fig 7D illustrates the growth of the SAGD
steam chambers toward the gas-enriched lean zone. More regarding the dewatering and SAGD operations will be discussed further below.

[0093] In some implementations, tracking methods can be used in order to detect various parameters of the process. For example, a tracer chemical can be included in the NCG injected into the lean zone via the injection wells, so that NCG
breakthrough at the production wells can be observed by detecting the presence of the tracer chemical in the production fluid. A tracer chemical can be injected in various ways, such as co-injected with the NCG via one, more or all of the injection wells, or other injection means.
The tracer chemical can be pre-injected into water present in the reservoir and/or lean zone in order to better determine the location and origin of the water being displaced and produced (e.g., from native water in the reservoir or from injected fluid in the form of condensed steam). Tracers can thus be used in connection with various aspects of the dewatering operations described herein, for various purposes, such as detecting gas breakthroughs, detecting and tracking water displacement and production, and so on.
Dewatering and thermal in situ recovery implementations

[0094] Referring to Figs 7A to 7G, the dewatering and gas pressurization can be conducted on a lean zone 10 above a main pay zone 14 in which SAGD occurs. In some implementations, the gas-enriched lean zone 10 is formed well before potential heat or fluid losses from the SAGD could occur. However, it should be noted that various timing strategies can be used for the dewatering and gas pressurization and the SAGD
operation. For example, the dewatering and gas pressurization can be commenced prior to drilling the SAGD wells or prior to start-up of the SAGD wells.
Alternatively, the dewatering and gas pressurization can begin after start-up of the SAGD wells, ideally as long as the growth of the SAGD steam chambers is such that that the gas-enriched lean zone is formed before the SAGD steam chambers reach the lean zone.

[0095] Referring to Figs 7A and 7B, the production wells 16 and injection well 20 can be operated to establish a gas-enriched lean zone 10 prior to operating SAGD in the underlying main pay zone 14.

[0096] Referring to Fig 7C, the production wells 14 can be converted to secondary injection wells to inject gas to maintain and in some cases further expand the gas-enriched region. At some stage, SAGD wells are drilled, completed, and started up. As mentioned above, the timing of drilling, completion and start-up activities can depend on a number of factors. Fig 7C illustrates SAGD well pairs each including a SAGD
production well 38 and a SAGD injection well 40. After startup of the SAGD
well pairs to establish fluid communication between each pair, steam chambers 42 are formed above respective SADG well pairs. In some scenarios, by the time steam chambers 42 begin to form and grow upward, the gas-enriched lean zone has been formed and is being maintained.

[0097] Referring to Fig 7D, eventually the steam chambers 42 approach the lower part of the lean zone 10. It should be noted that there is some heat conducted upward from the upper edge of the steam chambers 42 and can reach the lean zone before the steam chambers 42 themselves. As heat and steam reach the lean zone 10, the gas-enriched lean zone provides insulation and pressurization to reduce heat and fluid losses. By way of example, the heat savings and fluid loss savings can be considerable for scenarios where the lean zone above a SAGD well pad has had approximately 50% of its water removed and replaced by NCG, and the NCG has pressurized the lean zone to reduce the average pressure difference between the lean zone and the SAGD steam chamber pressures. Of course, it should be noted that the water removal factor and the pressure difference can be in different ranges for providing enhanced insulation and/or pressurization.

[0098] Figs 7A to 7D illustrate the dewatering and pressurization process above an array of SAGD well pairs. An array of SAGD well pairs can include various numbers of well pairs that typically extend from a single well pad located at the surface. Typically, a bitumen reservoir is developed in stages, where a first array of SAGD wells is provided and operated in a first portion of the reservoir as a first stage of reservoir development, and then a second array of SAGD wells is provided and operated in another portion of the reservoir as a subsequent stage of reservoir development. The first and second arrays of SAGD wells can be located adjacent to each other, and the arrays can be generally parallel to each other or at various angles, depending on the reservoir geology.
The dewatering and pressurization process can also be applied in stages in order to prepare the lean zones overlying different arrays of SAGD wells. Figs 7E to 7G
illustrate such staged operation, which will be discussed further below.

[0099] Referring to Fig 10, during early steam chamber development, the gas-enriched region 34 can be maintained at a pressure (PG) between 0 kPa and 400 kPa below the underlying SAGD steam chamber pressures (PsAGD). The pressure difference (AP) that is achieved can depend on various factors, such as the geology of the lean zone and the economics of gas injection and heat loss for the given in situ hydrocarbon recovery operation. The pressures PG and PSAGD can both be monitored and adjusted so that the AP is within a desired range. In some implementations, 1400 kPa PG 5. 1800 kPa, when PSAGD is approximately 1800 kPa. It should be noted that conventionally the pressure difference between a lean zone and SAGD steam chambers could be modified by adjusting the SAGD steam injector. When gas injectors are provided for pressurizing the lean zone, the pressure difference can be adjusted using two levers, i.e., the lean zone gas injectors and the SAGD steam injector, which facilitates additional options for process control.

[0100] The gas injection wells can be operated to maintain a pressurized lean zone when the steam chambers come into fluid communication with the lean zone. As the SAGD operation continues and reaches maturity, the steam chambers can eventually expand into the lean zone, heating bitumen that is contained in the lean zone and pressurizing the lean zone to P
SAGO. The gas pressurization of the lean zone can help delay the development of the steam chambers into the lean zone and encourage improved conformance of steam chamber development into the lean zone.

[0101] In addition, the gas-saturated lean zone can encourage lateral growth of the steam chambers within the main pay zone. This promoted lateral growth of steam chambers can also delay the steam chambers expanding into the lean zone and increase hydrocarbon recovery and production rates since higher saturations of hydrocarbons are typically found in such lateral directions within a main pay zone.
Conversion of production well(s) to injection well(s)

[0102] As mentioned above in reference to Figs 5D and 70, one or more of the production wells 16 can be converted to secondary injection wells 36 at the appropriate time. It should be noted that the conversion of production wells to injection wells can depend on various factors, and is generally performed in accordance with the development of the gas-enriched region and gas content in the produced water or proximate the given production well.

[0103] In some implementations, a production well 16 is converted to an injection well 36 after reaching a target water-saturation reduction in the lean zone 10. In the case of multiple production wells 16, each can be converted into a corresponding injection well 36 after the region surrounding the production well 16 reaches a target water-saturation reduction. In some implementations, one or more of the production well can be converted based on gas detection. For instance, conversion can be initiated upon detecting gas in the produced water and/or near the production well. Gas detection can include detecting gas in the produced water once recovered to surface, detecting the presence of gas directly by means of a detection device deployed downhole within the production well 16 or within an observation well 30, and/or detecting the presence of gas indirectly (eg., by measuring other parameters such as pressure changes and the like) by means of a detection device deployed downhole within the production well 16 or within an observation well 30. Detecting the gas can also be done by detecting a tracer chemical that has been introduced into the gas prior to or upon injection. In addition, in some implementations, different tracer chemicals can be used for respective injection wells such that gas breakthrough at a production well can be uniquely linked to a specific injection well, and thus appropriate adjustment of the injection well can be taken. The observation well 30 can be a separate well drilled in a selected location of the reservoir for the dedicated purpose of observing parameters, such as fluid levels, and gas content and pressure within the reservoir. The observation well 30 can be an existing well that is equipped with appropriate instrumentation to provide suitable data. In addition, the conversion can be based on a gas content threshold in the produced water or the water proximate the production well or on another parameter that is an indicator of gas content. For example, the gas content threshold can be a gas concentration or a gas-water ratio. Referring to Fig 4, in some implementations, the gas detector 28 is installed in-line or off-line with respect to the produced water pipe. In some implementations, the injected gas is different from existing gases that may be native to the reservoir such as H2S and 002. For example, N2 can be chosen as the injection gas which can facilitate gas detection by detecting N2 in the production fluids. A mixture of injection gases may also be provided so that at least one component of the gas mixture is non-native to the reservoir.

[0104] Monitoring the production fluids can also include analyzing the composition of produced water, for example the salinity of the water. Water present in the lean zone may have a certain salinity range such that an operator can confirm production of the lean zone water based on salt content measurements in the production fluid.
Steam injected into the reservoir, for example via a SAGD injection well, contains no salt and therefore a drop in salinity in the fluids produced by the water production wells can indicate that condensed water from steam injection is being produced.
Therefore, the composition of the produced water can be used to determine when to initiate the second phase of the process and convert a production well to a secondary injection well.

[0105] In some implementations, conversion of the production well 16 includes ceasing production, fluidly coupling the well head to a gas source, and then providing gas pressure to inject the gas downhole. The gas injection can be regulated so as to maintain the gas-enriched lean zone at or above a specific water recovery factor, which may be 25% or 50% for example. The gas pressure and flow rate for the secondary injection wells 36 can be similar or different compared to each other and compared to the primary injection well 20. The gas injection via the converted well should be high enough to inhibit water migration from outside the gas-enriched lean zone 10, and thus can depend on the water pressures and permeability properties outside the gas-enriched lean zone 10. The injection pressure of the converted wells can be controlled according to current conditions, including the pressure of the lean zone and the pressure of the steam chambers at the time of conversion.

[0106] When multiple production wells 16 are provided, as illustrated in Fig 2 for example, the gas-enriched region can expand toward the production wells 16 at different rates. In such scenarios, the conversion of some production wells 16 can occur before others. The monitoring of the gas and conversion of the wells can thus be performed on a per-well basis. It should also be noted that the target gas threshold can be different from different production wells 16 and can depend on the stage of the overall dewatering operation. For example, for the last production well to be converted, the gas content threshold in the produced water can be lower since the dewatering operation is relatively advanced and the gas-enriched region has expanded significantly within the lean zone of interest so as to achieve the target water removal.

[0107] When multiple production wells 16 are arranged in spaced relation and around one or more primary injection wells 20, once all of the production wells 16 are converted into secondary injection wells 36, the gas-enriched region 34 occupies a volume of the lean zone that is beyond the perimeter formed by the production wells 16 and maintains the gas perimeter at a pressure to inhibit water migration.

[0108] In some implementations, the conversion of the production wells 16 can also include a step of creating new apertures or perforations in the well to enable gas injection at desired locations. For instance, when the well is vertical and operating in production mode, the main apertures in fluid communication with the lean zone are located at the lower extremity of the well; but when the well is converted into an injection well it can be desirable to inject gas at different elevations and thus new apertures can be provided or opened along the length of the well. In some scenarios, the lower extremity aperture is closed, for example by using a sliding sleeve, and new apertures at a higher elevation are used for the gas injection in the converted well.
Alternatively, conversion of the production wells can include injection of the gas through the same apertures as in production mode, for instance at the bottom of the well such that the gas enters a lower part of the lean zone and migrates upward due to density differences.
Lean zone injection gases

[0109] In some implementations, the fluid that is injected into the primary injection well 20 and in the secondary injection wells 36 can include or consist of NCG. NCG
remains in gaseous phase, has lower heat capacity properties compared to water, and can facilitate insulation and pressurization of the lean zone. Due to lower densities, NCG
remains within the lean zone rather than substantially sinking downward into the main pay zone. The NCG can include various gases, such as methane, carbon dioxide, nitrogen, air, natural gas and flue gas. The NCG can be at least partly derived from the hydrocarbon recovery operation, for instance carbon dioxide or flue gas produced during steam generation. The NCG can penetrate into higher-permeability layers, sandy hydrocarbon-bearing layers as well as water-saturated layers, depending on location and rate of injection. The NCG can be selected according to process economics and/or desired effects within the lean zone.

[0110] In some implementations, the gas is pre-treated at surface prior to being injected into the lean zone. Pre-treatments can include heat exchange (heating or cooling), purification, and the like. The pre-treatment of the gas to be injected can be based on permeability properties of the gas through water and porous media of the lean zone. The gas or gas mixture can be selected to avoid acid gases, such as H2S. The gas or gas mixture can also be provided to prevent hydrate formation, by selecting certain gas types and/or by providing appropriate heat to thereby prevent pipe blockage due to hydrate formation.

[0111] In some implementations, different gases can be injected at different times and different locations. For example, a first NCG can be injected via the injection well 20, and a second NCG can be injected via the secondary injection wells 36 once converted from production. In addition, an initial NCG can be injected into all of the injection wells during an initial period of time (e.g., to establish a gas-enriched lean zone), and then a different NCG can be injected at a later time (e.g., to maintain the gas-enriched lean zone). The timing and location of types of gas to inject can be done according to the properties of the gas and desired effects within the lean zone.

[0112] In some implementations, the injection fluid is not a NCG but is a fluid that has lower heat capacity than that of water and can enable increasing the pressure of the lean zone to be closer to the pressure of the SAGD steam chamber pressures or the pressures encountered in the in situ recovery operation.
Staged implementations of dewatering and hydrocarbon recovery

[0113] As briefly mentioned above, in situ hydrocarbon recovery operations can be undertaken in a staged fashion to develop a hydrocarbon-bearing reservoir. The dewatering operation can also be conducted in a staged fashion in combination with staged hydrocarbon recovery operations, as will be described in more detail below.

[0114] Referring to Figs 6A and 6B, 7A to 7G, 9, 11, and 12, it can be appreciated that adjacent, contiguous or proximate lean zones can overly several main pay zones that make up an overall hydrocarbon-bearing reservoir that can be developed in stages.

[0115] Referring now to Figs 6B and 7E to 7G, a first stage includes dewatering a first lean zone 10, which is located above a first bitumen-rich pay zone 14 and adjacent to and fluidly communicating with a second lean zone 110. The second lean zone 110 is located above a second pay zone 114. The first lean zone 10 is dewatered by producing water from the first lean zone; injecting gas into the first lean zone, to provide a first gas-enriched lean zone; and inhibiting water migration from the second lean zone into the first lean zone. This may include using dewatering and pressurization techniques as described above. The first pay zone 14 is exploited by operating a first array of SAGD
well pairs in the first pay zone, to produce bitumen and form steam chambers having overlying insulation and pressurization from the first gas-enriched zone. In a second stage, the second lean zone is dewatered by producing water from the second lean zone; injecting gas into the second lean zone, to provide a second gas-enriched lean zone; and inhibiting water migration from outside the second lean zone. The second pay zone 114 is then exploited by operating a second array of SAGD well pairs in the second pay zone114, to produce bitumen and form steam chambers having overlying insulation and pressurization from the second gas-enriched zone.

[0116] In some implementations, the step of inhibiting water migration from the second lean zone into the first lean zone 10 includes converting water production wells 16 located in the first lean zone into gas injection wells 36. The second lean zone 110 can have production wells 116 provided for producing water 118, and an injection well 120 for injection of gas, in a similar manner as can be done for the first lean zone 10. The step of inhibiting water migration from outside the second lean zone 110 can include converting the water production wells 116 located in the second lean zone 110 into corresponding gas injection wells. The wells in the first and second lean zones can be located and operated in order to form a coalesced gas-enriched region within both zones.

[0117] Referring now to Fig 12, in some implementations, the staged process can include the following steps:
producing water (200) from a first lean zone, for instance via one or more production wells provided in the lean zone according to a dewatering process driven by a gravity-dominated mechanism, as described above;

injecting gas (202) into the lean zone, either simultaneously or subsequently to step (200), for instance via a primary injection well provided in the lean zone 10 to form a gas-enriched region;
for a certain amount of time, simultaneously producing water and injecting gas (204), while monitoring the water saturation reduction and/or gas advancement in the lean zone;
reaching a target water-saturation reduction (206), which may be 25% or 50%
and can be detected and/or estimated (optionally, the production wells can all be converted to injection wells at some point);
initiating SAGD (208) or another in situ hydrocarbon recovery operation in the main pay zone below the dewatered lean zone, from a first SAGD pad and/or a first SAGD array of well pairs;
maintaining the gas-enriched lean zone (210) by regulating the gas injection via the injection well and converting the production wells into secondary injection wells, to inhibit water migration from outside of the gas-enriched regions;
adjacent to the first SAGD pad, producing water from a second lean zone (212) in a similar manner as the first lean zone using a second arrangement of water production wells;
injecting gas into the second lean zone injecting gas (214), either simultaneously or subsequently to step (212), in a similar manner as the first lean zone using a second injection well;
for a certain amount of time, simultaneously producing water and injecting gas (216) in the second lean zone, while monitoring the water saturation reduction and/or gas advancement in the second lean zone;
reaching a target water-saturation reduction (218), which may be 25% or 50%
and can be detected and/or estimated;
=

initiating SAGD (220) or another in situ hydrocarbon recovery operation in the second main pay zone below the dewatered second lean zone, from a second SAGD pad and/or a second SAGD array of well pairs; and maintaining the gas-enriched first and second lean zones (222) by regulating the gas injection via the injection wells and converting the production wells in the second lean zone into secondary injection wells, to inhibit water migration from outside of both zones.

[0118] It should be noted that this general staged process can be continued for subsequent lean zones and pay zones within an overall hydrocarbon-bearing reservoir to be developed. Fig 9 illustrates an example of a series of lean zones having different thicknesses in which staged dewatering can be implemented, using injection and production wells that are located in accordance with the given geology and thickness of each lean zone. Fig 11 illustrates the combined lean zone, which is made up of several lean zones 10, and is geologically-contained. In some implementations, the dewatering process described herein can be replicated over various portions of a reservoir as the underlying pay zones are developed. Multiple stages can be pre-designed prior to implementing a series of stages, or each subsequent stage can be designed based on characteristics of the previous stage.

[0119] In terms of timescale, in some implementations the dewatering is initiated two months to three years prior to the in situ hydrocarbon operation. As the gas injection is relatively slow in order to avoid premature gas channeling and breakthrough at production wells, early initiation of the dewatering process can be beneficial.

[0120] When a SAGD array reaches maturity in a given pay zone, NCG injection or NCG-steam co-injection can be conducted via the SAGD injection well. An adjacent SAGD array may not yet be at maturity and thus it may be desirable to maintain the pressure in the mature SAGD chambers to prevent the steam and heat from the adjacent SAGD chamber from being lost. In some implementations, NCG injection can be conducted in both a lean zone and an underlying main pay zone to form a coalesced NCG zone having a pressure that is close the adjacent SAGD steam chamber pressures.
TESTS AND RESULTS

[0121] Simulations were conducted to assess the dewatering and gas pressurization of a water-saturated lean zone. The simulations included two central injection wells and surrounding production wells. Fig 14 shows results in terms of increasing the average pressure in the lean zone to a desired level; Fig 15 shows results in terms of the gas injection rates over time; and Fig 16 shows the increase in water recovery factor over time in the lean zone.

[0122] Additional results indicated that the impact of fluid loss to a water-saturated low pressure lean zone increased SOR from 2.5 to 5 or 6, while the impact of heat loss due to the elevated heat capacity of water in the lean zone increased SOR from 2.5 to 2.7, showing that hot fluid loss has a significantly higher impact on SOR compared to heat loss. This illustrates that pressurization of the dewatered lean zone to inhibit fluid loss to a lower pressure zone can facilitate lower SOR levels.

Claims

32

1. A process for Steam-Assisted Gravity Drainage (SAGD) recovery of bitumen, comprising.
identifying a subterranean water-saturated hydrocarbon-lean zone having a lower hydrocarbon content than an underlying bitumen-rich reservoir, having high water saturation, having a thickness of more than 5 meters, being located above and in fluid communication with the bitumen-rich reservoir, and being part of a geologically-contained water-saturated formation;
dewatering the hydrocarbon-lean zone, comprising.
producing water from the hydrocarbon-lean zone via water production wells located at a low elevation in the hydrocarbon-lean zone and operating under a gravity-dominated mechanism, thereby reducing the water saturation and pressure in the hydrocarbon-lean zone;
injecting non-condensable gas (NCG) via an injection well located at a higher elevation compared to the water production wells and regulated such that the NCG is injected at a pressure and a rate sufficient to re-pressurize the hydrocarbon-lean zone while avoiding substantial channeling of the NCG toward the water production wells, after reaching a target water-saturation reduction in the hydrocarbon-lean zone and thereby forming a gas-enriched lean zone, converting the water production wells to corresponding NCG
injection wells and Injecting NCG there-through to inhibit water migration into the gas-enriched lean zone;
operating SAGD wells in the bitumen-rich reservoir below the gas-enriched lean zone, thereby forming a SAGD steam chamber, and maintaining the gas-enriched lean zone at a lean zone pressure between 0 kPa and 400 KPa below an underlying SAGD steam chamber pressure, thereby providing overlying NCG insulation and pressurization for the SAGD steam chamber.

2. A process for dewatering a subterranean water-saturated, hydrocarbon-lean zone located above and having a lower hydrocarbon content than a hydrocarbon-bearing reservoir, comprising:
producing water via a production well provided in the hydrocarbon-lean zone;
injecting a gas via a primary injection well provided in the hydrocarbon-lean zone to form a gas-enriched region; and once injected gas reaches or has advanced proximate to the production well, converting the production well into a secondary injection well for injecting additional gas into the hydrocarbon-lean zone to inhibit water migration from outside of the gas-enriched lean zone.

3. The process of claim 2, wherein the primary injection well is substantially vertical.

4. The process of claim 2 or 3, wherein the production well is substantially vertical.

5. The process of any one of claims 2 to 4, further comprising:
monitoring advancement of the gas within the lean zone so as to identify when the injected gas reaches or has advanced proximate to the production well.

6. The process of claim 5, wherein the monitoring comprises:
measuring dissolved gas content in the water produced by the production well.

7. The process of claim 5, wherein the monitoring comprises:
obtaining information from an observation well located in the lean zone.

8. The process of any one of claims 2 to 7, wherein the gas is injected via the primary injection well at a pressure and a rate sufficient to re-pressurize the lean zone while avoiding substantial channeling of the gas past the water toward the production well.

9. The process of any one of claims 2 to 8, wherein the step of converting the production well is performed once the lean zone has reached a target water-saturation reduction.

10. The process of claim 9, wherein the target water-saturation reduction is at least about 25% volume.

11. The process of claim 9, wherein the target water-saturation reduction is at least about 50% volume.

12. The process of any one of claims 2 to 11, further comprising:
producing water via a plurality of production wells arranged in spaced relation from each other and around the primary injection well; and once injected gas reaches or has advanced proximate to the production wells, respectively converting the production wells into corresponding secondary injection wells for injecting additional gas into the reservoir to inhibit water migration from outside of the gas-enriched lean zone.

13. The process of claim 12, wherein the production wells are substantially vertical.

14. The process of any one of claims 2 to 13, wherein the gas comprises a non-condensable gas (NCG).

15. The process of any one of claims 2 to 13, wherein the gas consists of a NCG.

16. The process of any one of claims 2 to 15, wherein the water-saturated, hydrocarbon-lean zone overlies a main pay zone of a hydrocarbon-bearing reservoir, and the process further comprises:
forming the gas-enriched lean zone prior to operating in situ recovery wells within the main pay zone.

17. The process of claim 16, wherein the in situ recovery wells comprise a Steam-Assisted Gravity Drainage (SAGD) well pair.

18. The process of claim 16 or 17, further comprising:
maintaining the gas-enriched lean zone at a lean zone pressure between 0 kPa and 400 KPa below an underlying in situ recovery pressure in the main pay zone.

19. The process of any one of claims 2 to 18, wherein the primary injection well comprises an injection section located at a high elevation in the lean zone, the high elevation being above a mid-way point of the lean zone, above a three-quarters point of the lean zone, above a seven-eighths point of the lean zone, or adjacent to an upper limit of the lean zone.

20. The process of any one of claims 2 to 19, wherein the production well comprises a production section located at a low elevation in the lean zone, the low elevation being below a mid-way point of the lean zone, below a one-quarter point of the lean zone, below a one-eighth point of the lean zone, or adjacent to the hydrocarbon-bearing reservoir.

21. The process of any one of claims 2 to 20, wherein the gas injection rate via the primary injection well and the water production rate via the production well are provided at least in part based on the relative permeability of the gas and water in the porous media of the lean zone.

22. The process of claim 21, further comprising:
determining permeability characteristics of the lean zone; and providing the gas injection rate and the water production rate at least in part based on the permeability characteristics.

23. The process of claim 22, wherein the step of determining permeability characteristics of the lean zone comprises analyzing core samples of the lean zone and/or performing simulation modelling.

24. The process of any one of claims 2 to 23, wherein the gas injection pressure via the primary injection well is sufficiently low to inhibit premature gas breakthrough at the production well and promote gravity drainage of water toward the production wells

25. The process of any one of claims 2 to 24, wherein the lean zone has a thickness of at least 5 meters.

26 The process of any one of claims 2 to 24, wherein the lean zone has a thickness of at least 10 meters

27 The process of any one of claims 2 to 26, wherein the lean zone is part of a geologically-contained water-saturated formation.

28 The process of any one of claims 2 to 27, wherein the production well has a pump located in a sump below the lean zone

29. The process of any one of claims 2 to 28, wherein the hydrocarbon-bearing reservoir comprises heavy oil and/or bitumen

30 A process for recovering hydrocarbons from a hydrocarbon-bearing reservoir located below and in fluid communication with a subterranean water-saturated hydrocarbon-lean zone, comprising.
producing water via a production well provided in the hydrocarbon-lean zone;
injecting a gas via a primary injection well provided in the hydrocarbon-lean zone to form a gas-enriched region;
monitoring the advancement of the gas within the lean zone;
once injected gas reaches or has advanced proximate to the production well, converting the production well into a secondary injection well for injecting additional gas into the reservoir to inhibit water migration from outside of the gas-enriched lean zone; and operating an in situ recovery operation in the hydrocarbon-bearing reservoir such that the gas-enriched lean zone provides overlying insulation and pressurization.

31. The process of claim 30, wherein the in situ recovery operation comprises a thermal in situ recovery operation

32. The process of claim 31, wherein the thermal in situ recovery operation comprises a Steam-Assisted Gravity Drainage (SAGD) operation.

33. The process of any one of claims 30 to 32, wherein the hydrocarbon-bearing reservoir comprises heavy oil and/or bitumen.

34. A system for dewatering a subterranean water-saturated, hydrocarbon-lean zone located above and having a lower hydrocarbon content than a hydrocarbon-bearing reservoir, comprising.
a production well provided in the hydrocarbon-lean zone and configured to produce water;
a primary injection well provided in the hydrocarbon-lean zone and configured to inject a gas via to form a gas-enriched region; and a conversion assembly coupled to the production well and configured to convert the production well into a secondary injection well once injected gas reaches or has advanced proximate to the production well, such that the secondary injection well is configured for injecting additional gas into the hydrocarbon-lean zone to inhibit water migration from outside of the gas-enriched lean zone.

35. The system of claim 34, wherein the primary injection well is substantially vertical.

36 The system of claim 34 or 35, wherein the production well is substantially vertical.

37. The system of any one of claims 34 to 36, further comprising a monitoring unit for monitoring advancement of the gas within the lean zone so as to identify when the injected gas reaches or has advanced proximate to the production well.

38 The system of claim 37, wherein the monitoring unit is configured for measuring dissolved gas content in the water produced by the production well.

39. The system of claim 37, wherein the monitoring unit is configured for obtaining information from an observation well located in the lean zone

40. The system of any one of claims 34 to 39, wherein the primary injection well is configured to inject the gas at a pressure and a rate sufficient to re-pressurize the lean zone while avoiding substantial channeling of the gas past the water toward the production well

41. The system of any one of claims 34 to 40, wherein conversion assembly is configured to convert the production well once the lean zone has reached a target water-saturation reduction.

42. The system of claim 41, wherein the target water-saturation reduction is at least about 25% volume.

43. The system of claim 41, wherein the target water-saturation reduction is at least about 50% volume.

44. The system of any one of claims 34 to 43, comprising a plurality of production wells arranged in spaced relation from each other and around the primary injection well, and wherein the conversion assembly is configured to respectively convert the production wells into corresponding secondary injection wells once injected gas reaches or has advanced proximate to the production wells, the corresponding secondary injection wells being configured for injecting additional gas into the reservoir to inhibit water migration from outside of the gas-enriched lean zone.

45. The system of claim 44, wherein the production wells are substantially vertical

46. The system of any one of claims 34 to 45, wherein the gas comprises a non-condensable gas (NCG)

47 The system of claim 46, wherein the gas consists of a NCG

48 The system of any one of claims 34 to 47, wherein the water-saturated, hydrocarbon-lean zone overlies a main pay zone of a hydrocarbon-bearing reservoir, and the system is configured to form the gas-enriched lean zone prior to operating in situ recovery wells within the main pay zone.

49. The system of claim 48, wherein the in situ recovery wells comprise a Steam-Assisted Gravity Drainage (SAGD) well pair.

50. The system of claim 48 or 49, wherein the primary injection well and the production well are configured to maintaining the gas-enriched lean zone at a lean zone pressure between 0 kPa and 400 KPa below an underlying in situ recovery pressure in the main pay zone.

51. The system of any one of claims 34 to 50, wherein the primary injection well comprises an injection section located at a high elevation in the lean zone, the high elevation being above a mid-way point of the lean zone, above a three-quarters point of the lean zone, above a seven-eighths point of the lean zone, or adjacent to an upper limit of the lean zone.

52. The system of any one of claims 34 to 51, wherein the production well comprises a production section located at a low elevation in the lean zone, the low elevation being below a mid-way point of the lean zone, below a one-quarter point of the lean zone, below a one-eighth point of the lean zone, or adjacent to the hydrocarbon-bearing reservoir.

53. The system of any one of claims 34 to 52, wherein the primary injection well and the production well are configured to provide a gas injection rate and a water production rate, respectively, at least in part based on the relative permeability of the gas and water in the porous media of the lean zone.

54. The system of any one of claims 34 to 53, wherein the primary injection well is configured to provide a gas injection pressure that is sufficiently low to inhibit premature gas breakthrough at the production well and promote gravity drainage of water toward the production wells.

55. The system of any one of claims 34 to 54, wherein the lean zone has a thickness of at least 5 meters.

56. The system of any one of claims 34 to 55, wherein the lean zone has a thickness of at least 10 meters.

57. The system of any one of claims 34 to 56, wherein the lean zone is part of a geologically-contained water-saturated formation.

58. The system of any one of claims 34 to 57, wherein the production well has a pump located in a sump below the lean zone.

59. The system of any one of claims 34 to 58, wherein the hydrocarbon-bearing reservoir comprises heavy oil and/or bitumen.