CA2876765C

CA2876765C - A system for confining steam injected into a heavy oil reservoir

Info

Publication number: CA2876765C
Application number: CA2876765A
Authority: CA
Inventors: Jian Li; Calvin R. Coulter; James Fong
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2014-12-23
Filing date: 2014-12-23
Publication date: 2016-10-04
Anticipated expiration: 2034-12-23
Also published as: CA2876765A1; CA2942157A1; CA2942157C

Abstract

The invention provides for in situ processing of a hydrocarbon reservoir which includes selecting in the reservoir a matured steam chamber and an operating steam chamber generally adjacent to and in fluid communication with the matured steam chamber. The operating steam chamber is undergoing or is capable of undergoing SAGD processing. A non-oxidizing gas is injected into the matured steam chamber to form a pressurized non-oxidizing buffer zone between the matured and operating steam chambers. An oxygen-comprising gas is also injected into the matured chamber for maintaining pressure within the matured chamber so as to reduce or avoid fluid leaking or cross-flow from the operating chamber into the mature chamber while continually performing SAGD in the operating chamber.

Description

= . - . .

A SYSTEM FOR CONFINING STEAM INJECTED INTO A HEAVY OIL RESERVOIR
TECHNICAL FIELD
[001] The present disclosure relates generally to in situ hydrocarbon recovery and particularly to increasing in situ recovery of hydrocarbons from Steam Assisted Gravity Drainage (SAGD) operations by reducing the flow of fluid between SAGD steam chambers at various stages of maturity.
BACKGROUND

[002] Heavy oil and extra-heavy oil resources such as bitumen present significant technical and economic recovery challenges due to their high viscosities at reservoir temperature. Bitumen occurs within a subsurface hydrocarbon bearing zone of a hydrocarbon reservoir as a semi-solid phase having a viscosity greater than 100,000 centipoise.

[003] An example of an in situ steam injection-based heavy oil recovery process which is effective at extracting oil from oil-containing reservoirs by reducing viscosity of the oil via steam injection is steam assisted gravity drainage (SAGD). A SAGD
system includes at least one steam injection well and one oil production well (a "well pair"). In a well pair generally located in a bottom portion of the hydrocarbon bearing zone of the reservoir, an upper, generally horizontal injection well is used for injecting a fluid such as steam into the reservoir. The injected steam rises from the generally horizontal injection well and permeates the reservoir to form a vapor chamber which grows over time within the hydrocarbon bearing zone thereby increasing the temperature of the reservoir. The resultant mobilized bitumen and condensate will drain downward through the reservoir under gravity and flow into a generally horizontal production well . .

disposed below the injection well from which the bitumen is produced. Several well pairs can be arranged within the reservoir to form a well pattern or a pad.

[004] SAGD generally involves four operational stages: start up, ramp up, plateau and wind down. In the start up stage, steam is circulated in both the injection and production wells for about two to four months to heat up the reservoir, which results in the creation of a "steam chamber". The term "steam chamber" relates to a region in the reservoir in which hydrocarbons, steam, steam condensate, and associated non-condensate gases are in communication with the injection wells. During start up, as the steam chamber grows from the injection wells, the hydrocarbons are heated and mobilized to subsequently drain into the production wells. In the ramp up stage of SAGD, the injection and production rates increase as the steam chamber grows to the top of the reservoir, which can take about six to eighteen months depending on operating conditions and reservoir characteristics. In the plateau stage, the steam chamber has reached the top of the reservoir and begins to expand within the reservoir, including lateral migration. This stage is characterized by peak production rates, which can last anywhere from eighteen to sixty months depending on reservoir quality and thickness. During the plateau stage, the steam chamber can be considered a generally undepleted immature operating steam chamber. The final wind down stage of SAGD occurs when steam chambers of adjacent well pairs begin to coalesce.
Bitumen production decreases because the majority of oil has been drained out of the SAGD chamber. For example, in the case of an Underground Test Facility (UTF), the wind down stage has been estimated to occur when bitumen recovery reaches about 50-60%.

[005] Thermal efficiency of the SAGD process is measured by the cumulative steam-to-oil ratio ("cSOR"), which is the ratio of the cumulative volume of steam injected to the cumulative volume of oil produced. The higher the cSOR, the higher the steam usage, which means more natural gas is combusted per unit volume of produced oil, . . e.

and consequently the process is less economical. Conversely, a lower cSOR
implies a more economical process. As the oil content in the SAGD operating steam chamber naturally declines, the cSOR increases. When, for example, the SAGD
operational cost begins to out weigh the oil production value, it can no longer be economically viable to continue steam injection for the SAGD operation, at which time steam injection can be reduced or discontinued for the pads or selected well pairs.
At this stage, the steam chamber is referred to as partially depleted, substantially depleted, "mature" or "matured", depending on the degree of bitumen depletion, and is generally associated with a bitumen recovery factor above about 55 %.

[006] In commercial SAGD developments, groups of well pairs or pads are initially drilled and placed on production in a sufficient number so as to fill the plant capacity.
When SAGD operations for one pad reach the wind down stage, oil production from the reservoir naturally begins to decline, and as the productivity of the operational wells decreases, additional SAGD well pairs in adjoining geographical areas can be added in the reservoir, which eventually can cover the entire reservoir field.

[007] A reservoir field as a whole will typically include pads or well pairs at different operational stages. For example, the reservoir field can include one or more operating pads from which hydrocarbon recovery is effective in proximity to one or more matured pads depleted in hydrocarbons to various degrees. When the pads or well pairs reach the stage of a desired level of depletion in hydrocarbons (i.e., become "mature" or "matured"), injection of steam into such pads or well pairs can cease to be economical, and can be stopped. Typically, steam injection is continued into immature operating pads or well pairs located adjacent the partially or substantially depleted mature pads or well pairs.

[008] When steam injection is reduced or discontinued in the partially or substantially depleted matured pad(s), the pressure in the chamber falls as the system cools.

Eventually, the mature chambers in such pads become "thief zones" for future SAGD
operations in pads generally adjacent to the matured pads. The pressure within the matured pad(s) drops naturally to a level below the temperature and pressure of the generally immature operating pads, which creates a driving force for fluid cross-flow (e.g., cross-flow of steam) from the immature operating chambers into the generally adjacent matured chambers. The matured pad generally adjacent the immature operating pad acts as a scavenger of steam and a heat sink for the adjacent immature operating pad, which reduces the effectiveness and productivity of the operating pad.

[009] Several approaches have been proposed for alleviating the above-mentioned operational challenges. Examples of such approaches include cold water injection with stop steam injection, injection of non-condensable gases (NCGs) such as natural gas or nitrogen, co-injection of natural gas as a mixture in certain volumetric or molar proportions, blow-down or stage blow-down approaches, or injection of oxygen-comprising gas. Another approach involves leaving a reservoir buffer zone between the operating steam chambers and the matured steam chambers. This buffer zone approach effectively isolates or creates a physical barrier between the chambers.

[0010] The prior art approaches have several disadvantages. For example, injection of NCGs or co-injection of NCGs with steam can cause a significant reduction in the temperature of the matured steam chamber. As a result, further injection of costly NCGs can be required to maintain the desired chamber pressure. Cold water injection reduces the temperature of the matured steam chamber more rapidly, and can create a low temperature heat sink within the reservoir. Furthermore, cold water injection does not utilize the heat stored in the matured steam chamber, and high water mobility can also impair the performance of adjacent operating steam chambers and wells. The blow down method leaves the matured steam chamber to cool, and with the decrease in temperature, the pressure drops, which results in the matured chamber acting as a pressure sink for adjacent operating chambers. The buffer zone approach generally , = r .

results in areas of the reservoir that will not be recovered. Moreover, using the buffer zone approach can result in more cost for additional steam and produced fluids piping to later re-develop the unrecovered buffer areas.

[0011] Therefore, increasing in situ oil recovery from hydrocarbon-containing reservoirs using thermal processes such as SAGD and improving the economic performance of such processes remains challenging.
SUMMARY

[0012] There is provided a process for in situ processing of a hydrocarbon reservoir. In various aspects, the process includes selecting in the hydrocarbon reservoir a first steam chamber and a second steam chamber generally adjacent to the first steam chamber, the first and second steam chambers having been processed using steam assisted gravity drainage (SAGD) or undergoing or being capable of undergoing further SAGD processing, the first and second steam chambers each having a hydrocarbon content and an initial temperature, and the first steam chamber having an initial pressure lower than a pressure in the second steam chamber; selecting a first injection well in fluid communication with the first steam chamber, the first injection well being generally adjacent to the second steam chamber; selecting a second injection well in fluid communication with the first steam chamber, the second injection well being disposed away from the first injection well; injecting a non-oxidizing gas through the first injection well to form a pressurized non-oxidizing buffer zone between the first and second steam chambers to reduce a fluid flow between the first and second steam chambers; and injecting an oxygen-comprising gas through the second injection well to increase a pressure in the first steam chamber relative to the initial pressure.

[0013] In various aspects, the method further includes sustaining combustion in the first steam chamber wherein production of hydrocarbons from the second steam = 41 =

chamber is increased relative to production of hydrocarbons recoverable from the second steam chamber without combustion of the oxygen-comprising gas into the first steam chamber.

[0014] In various aspects, forming the pressurized non-oxidizing buffer zone can increase production of hydrocarbons from the second steam chamber relative to production of hydrocarbons recoverable from the second steam chamber without formation of the pressurized non-oxidizing buffer zone.

[0015] In various aspects, the oxygen-comprising gas can be injected concurrently with the non-oxidizing gas.

[0016] In various aspects, the oxygen-comprising gas can be injected before the non-oxidizing gas.

[0017] In various aspects, injecting the non-oxidizing gas and the oxygen-comprising gas can be cyclical.

[0018] In various aspects, the first steam chamber can be at a later stage of maturity than the second steam chamber.

[0019] In various aspects, a boundary can exist between the first steam chamber and the second steam chamber.

[0020] In various aspects, a pressure difference between the first steam chamber and the second steam chamber following injection of the non-oxidizing gas and the oxygen-comprising gas can be about 200 kPa or less.

[0021] In various aspects, the second injection well can be vertically offset from the first injection well.

[0022] In various aspects, the fluid flow can comprise a flow of flue gas, a flow of the oxygen-comprising gas, a flow of steam, or a combination thereof.

[0023] In various aspects, a hydrocarbon content of the first steam chamber can be lower than a hydrocarbon content of the second steam chamber.

[0024] In various aspects, hydrocarbons can be produced from the first steam chamber, the second steam chamber or both the first and second steam chambers.

[0025] In various aspects, the first and second injection wells may have been previously used for fluid injection.

[0026] In various aspects, the first injection well or the second injection well has been previously used for steam injection.

[0027] In various aspects, the non-oxidizing gas, the oxygen-comprising gas or both can be injected proximate a lower portion of the reservoir.

[0028] In various aspects, a concentration of oxygen in the oxygen-comprising gas can range from about 5% to about 100%.

[0029] In various aspects, the oxygen-comprising gas can be air, oxygen-enriched air, or a combination thereof.

[0030] In various aspects, the oxygen-enriched air can comprise a concentration of oxygen above about 21%.

= Aib =

[0031] In various aspects, the non-oxidizing gas can be methane, nitrogen, carbon dioxide, or a combination thereof.

[0032] In various aspects, the non-oxidizing gas, the oxygen-comprising gas or both can be wet or dry.

[0033] In various aspects, more than one injection well can be selected as the first injection well, the second injection well or both.

[0034] In various aspects, an in situ process for treating a hydrocarbon reservoir includes selecting in the hydrocarbon reservoir a first steam chamber and a second steam chamber generally adjacent to the first steam chamber, the second steam chamber situated so that a boundary exists between the first steam chamber and the second steam chamber, the first and second steam chambers having been processed using steam assisted gravity drainage (SAGD) and undergoing or being capable of undergoing further SAGD processing, the first and second steam chambers each having a hydrocarbon content and an initial temperature, and the first steam chamber having an initial pressure lower than a pressure in the second steam chamber;
selecting a first injection well in fluid communication with the first steam chamber; and injecting an oxygen-comprising gas through the first injection well and sustaining combustion in the first steam chamber to increase a pressure in the first steam chamber relative to the initial pressure and reduce a fluid flow between the first and second steam chambers, wherein production of hydrocarbons from the boundary is increased relative to production of hydrocarbons recoverably from the boundary without injection of the oxygen-comprising gas into the first steam chamber.

[0035] In various aspects, the first steam chamber can be at a later stage of maturity than the second steam chamber.

. . .

[0036] In various aspects, a pressure difference between the first steam chamber and the second steam chamber following injection of the oxygen-comprising gas can be about 200 kPa or less.

[0037] In various aspects, the fluid flow can comprise a flow of flue gas, a flow of the oxygen-comprising gas, a flow of steam, or a combination thereof.

[0038] In various aspects, a hydrocarbon content of the first steam chamber can be lower than a hydrocarbon content of the second steam chamber.

[0039] In various aspects, hydrocarbons can be produced from one or more of the first steam chamber, the second steam chamber and the boundary.

[0040] In various aspects, the first injection well may have been previously used for fluid injection. In various implementations, the fluid is steam.

[0041] In various aspects, the oxygen-comprising gas can be injected proximate a lower portion of the reservoir.

[0042] In various aspects, a concentration of oxygen in the oxygen-comprising gas can range from about 5% to about 100%.

[0043] In various aspects, the oxygen-comprising gas can be air, oxygen-enriched air, or a combination thereof.

[0044] In various aspects, the oxygen-enriched air can comprise a concentration of oxygen above about 21%.

,

[0045] In various aspects, the oxygen-comprising gas can be wet or dry.

[0046] In various aspects, more than one injection well can be selected as the first injection well.

[0047] The methods as described herein can reduce a fluid cross-flow between operating and matured steam chambers.
BRIEF DESCRIPTION OF THE DRAWINGS

[0048] In accompanying drawings which illustrate implementations of the invention,

[0049] Fig. 1A illustrates a three dimensional schematic diagram showing a configuration of multi-pad patterns of well pairs for SAGD operations, including a matured steam chamber generally adjacent an operating steam chamber;

[0050] Fig. 1B illustrates a three dimensional schematic diagram showing a configuration of multi-pad patterns of well pairs for SAGD operations, including a matured steam chamber generally adjacent an operating steam chamber;

[0051] Fig. 1C illustrates a three dimensional schematic diagram showing a configuration of multi-pad patterns of well pairs for SAGD operations, including a matured steam chamber generally adjacent an operating steam chamber;

[0052] Fig. 2 illustrates a schematic diagram of a well pair and injection of an oxygen-comprising gas through a selected horizontal portion of a former SAGD
horizontal steam injection well configured for injection of the oxygen-comprising gas, upward and lateral propagation of a hot temperature front, and production of fluids (combustion gas, hydrocarbons) through a former SAGD production well;

[0053] Fig. 3 illustrates a schematic diagram of a well pair and injection of an oxygen-comprising gas through a selected vertical portion of a former SAGD horizontal steam injection well configured for injection of the oxygen-comprising gas, propagation of a hot front from a heel of the injection well toward a toe of the injection well, and production of fluids (combustion gas, hydrocarbons) through a horizontal portion of a former SAGD
production well;

[0054] Fig. 4 illustrates simulation results for two SAGD pads, Pad 1 including a matured steam chamber and Pad 2 including an operating steam chamber, with four SAGD
well pairs per pad;

[0055] Fig. 5 illustrates simulation results showing leaking of steam injected into Pad 2 to Pad 1 after steam injection was terminated in Pad 1;

[0056] Fig. 6 illustrates simulation results showing a comparison of the steam chambers subjected to and not subjected to injection of an oxygen-comprising gas (e.g., air) into Pad 1 while steam is injected into Pad 2;

[0057] Fig. 7 illustrates a well layout of the non-oxidizing gas injectors and a gas vent well in Pad 1 and the SAGD operation wells in Pad 2;

[0058] Fig. 8 illustrates simulation results for combustion or oxidation reactions occurring within the matured SAGD chamber in Pad 1 after the oxygen-comprising gas is injected into Pad 1;

[0059] Fig. 9 illustrates simulation results showing mole fraction of methane (the non-oxidizing gas) staying in the area between the operating SAGD chamber in Pad 2 and the top of the matured SAGD chamber in Pad 1; and

[0060] Fig. 10 illustrates simulation results showing mole fraction of CO2 staying in the area of the matured SAGD chamber in Pad 1.
DETAILED DESCRIPTION

[0061] In various aspects, methods for increasing in situ recovery of hydrocarbons from Steam Assisted Gravity Drainage (SAGD) operations by reducing a fluid flow between generally adjacent or generally proximate SAGD chambers at various stages of maturity or depletion (e.g., between a generally undepleted immature operating chamber and a partially depleted matured chamber, a substantially depleted matured chamber or a combination thereof) in a hydrocarbon-containing reservoir field are described. In various implementations, steam is injected into and confined within the operating chamber, reducing fluid cross-flow between generally adjacent or proximate chambers at various stages of maturity. In various implementations, the present process and apparatus is applicable to existing SAGD developments when the production at SAGD well(s) in such a development declines. In various implementations, new wells can be added into the reservoir.

[0062] In various implementations, the term "hydrocarbon" relates to mixtures of varying compositions including hydrocarbons in the gaseous, liquid or solid states, which can be in combination with other fluids (liquids and gases) that are not hydrocarbons. The terms "heavy oil", "extra heavy oil", and "bitumen" refer to hydrocarbons occurring in semi-solid or solid form having a viscosity in the range of about 100,000 to over 1,000,000 centipose (Pa-s) measured at original in situ deposit temperature. The terms "hydrocarbon", "oil" and "bitumen" are used interchangeably.

[0063] Heavy oil can be defined as any liquid petroleum hydrocarbon having an API
gravity less than about 20 , specific gravity greater than about 0.933 (g/m1), and , =

viscosity greater than 100 centipoise (Pa-s). Oil can be defined as a hydrocarbon mobile at reservoir conditions. Extra heavy oil from the Orinoco region, for example, can be defined as having a viscosity of over 100 centipoise (Pa-s) and about gravity. The API gravity of bitumen ranges from about 12 > API > about 7 and the viscosity is greater than about 10,000 centipoise (Pa-s). Bitumen is generally non-mobile at original reservoir conditions.

[0064] In various implementations, the term "reservoir" refers to a hydrocarbon-containing formation that can include a single formation or one or more formations having varying characteristics, which can also be viewed as individual "reservoirs". A
SAGD reservoir is a formation which has been or is being processed using SAGD.
The SAGD reservoir as a whole can include regions undergoing various stages of SAGD
operations (e.g., operating immature steam chambers in ramp up and plateau stages, partially or substantially depleted matured steam chambers and coalesced steam chambers).

[0065] In various implementations, the terms "chamber", "steam chamber" or "SAGD
chamber" generally relate to a region within the reservoir, and in particular a hydrocarbon-bearing zone of the reservoir, where reservoir fluids are in communication with a particular well or wells. In various implementations, the term "steam chamber" relates to the volume of the reservoir in which injected or mobile steam exists for an extended period of time. Within the steam chamber, rock temperature rises to a point at which steam vapor can be sustained at reservoir pressure conditions. In SAGD, the steam chamber is a region in which bitumen, steam condensate, and associated non-condensate gases in the reservoir are in communication with a steam injection well and where mobilized hydrocarbons primarily drain into a production well. With time, the steam chamber can expand to cover an entire area of a pad development ("Thermal Recover of Oil & Bitumen", Roger . = .

M.Butler, 1991, ISBN 013-914953-8, pp.287-289, Prentice Hall, Englewood Cliffs, New Jersey 07632).

[0066] In various implementations, the steam chamber in the SAGD reservoir has generally uniform temperature and pressure. Depending on the stage of a particular SAGD process, the steam chamber can be a relatively high pressure steam chamber such as, for example, the operating steam chamber from which production of hydrocarbons occurs, or a relatively lower pressure steam chamber such as, for example, the matured steam chamber generally depleted of hydrocarbons to a varying degree. In various implementations, the operating steam chamber can have a pressure in the range from about 1000 kPa to about 6500 kPa, and a temperature in the range from about 180 C to over 270 C. In SAGD, when the operating steam chamber nears depletion and steam injection is discontinued, steam vapor condenses and the reservoir pressure drops, at which point the steam chamber becomes matured. In various implementations, in the wind down stage of SAGD, the matured steam chamber can have, for example, a pressure in the range of about 700 kPa to about 2500 kPa and a temperature in the range of about 160 C to about 225 C, about 162 C to about 223 C, or about 165 C to about 223 C. In particular implementations, the temperature can be, for example, about 162 C, about 180 C or about 200 C.

[0067] In various implementations, the term "operating steam chamber" broadly relates to a steam chamber in an undepleted or partially depleted in situ hydrocarbon reservoir, into which steam or other fluid has been injected through one or more injection wells, and from which economic production of oil (e.g., production where RF>
about 55%) can be obtained through one or more corresponding production wells using, for example, SAGD. In the SAGD reservoir, a steam chamber or a reservoir region can be considered as "immature" or "operating" when it has been operating for about eighteen to about sixty months since the start up or circulation stage up to a point when the economic benefits of oil production are outweighed by the costs.

l i

[0068] In various implementations, the term "matured steam chamber" broadly relates to a steam chamber in a hydrocarbon-containing reservoir that has been partially or substantially depleted in hydrocarbons through previous in situ operations.
For example, in SAGD, a steam chamber or a reservoir region can be considered "matured" when it has reached a stage where greater than about 55% of the original hydrocarbon content in the reservoir has been recovered and where the steam-to-oil ratio is above a value which indicates that it can no longer be economical to produce residual oil as compared to the operating steam chamber.

[0069] Referring to Fig. 1, schematic diagrams of a reservoir with operating pads (e.g., including operating steam chambers) and partially or substantially matured pads (e.g., including matured steam chambers) according to various implementations are shown.
As is indicated in the various implementations shown in Fig. 1, a matured steam chamber is generally adjacent to an operating steam chamber. In various implementations, there can be a buffer zone having variable width or thickness between the matured steam chamber and the operating steam chamber. The buffer zone is also referred to as a boundary. In various implementations, the width or thickness of the buffer zone (boundary) can vary with varying reservoir properties such as, for example, reservoir thickness, fluid properties and saturations (e.g., formation water and bitumen), initial reservoir pressure, steam injection pressure and volume, and steam quality. The operating steam chamber, the matured steam chamber, or a combination thereof, are also referred to as steam chambers at various stages of maturity.

[0070] When multiple SAGD well pairs are present as pad(s) in the reservoir, each pad drains bitumen from the reservoir within its own region. As a result, there can be little to no flow from region to region within the reservoir (i.e., each pad can operate within a defined region of the reservoir). However, in various implementations, the drainage , areas can be dynamic in nature, and as steam is injected, the increase in heat transfer can cause some of the previous non-communicating regions of the reservoir to become continuous. Accordingly, the boundary between the operating steam chamber(s) and the matured steam chamber(s), in terms of both width and permeability, can change.

[0071] In various implementations, the minimum distance of an "edge" well to the boundary or buffer zone of a pad can be about half the distance of the well spacing of an inner well pair. In various implementations the boundary or buffer zone can have a width ranging from about 50 to about 80 m, about 80 m to about 160 m, or about to about 200 m (including for "T" type well configurations).

[0072] In various implementations, the boundary can be defined, for example, by the following physical characteristics:
1. any kind of fluid inflow (water, heated bitumen, steam, gas);
2. pressure;
3. temperature; or 4. a combination of the above factors.

[0073] In various implementations, if movement of fluid within an area of the operating steam chamber generally adjacent to or proximate the matured steam chamber is detected, or if reservoir pressure and formation temperature rise or are higher in a certain area of the operating chamber, one can conclude that this area is within the boundary and can be regarded as forming the boundary. The properties of the boundary, including its width, can vary in various implementations depending on the properties of the reservoir such as, for example, the reservoir thickness, fluid content, initial reservoir pressure, operating steam injection pressure, and steam quality.

[0074] In various implementations, criteria which can be used to determine whether or not the SAGD pad is matured or depleted include: the period of time over which the SAGD pad has been operated (e.g., for more than seven years), an indication of whether the steam chambers of each SAGD well pair coalesce with each other (i.e., whether fluid communication has been established), the extent of growth of the steam chamber (e.g., once matured, the steam chamber can exhibit no further growth as indicated by 4D seismic information or the existing temperature monitor wells).

[0075] According to a first implementation, a non-oxidizing gas is injected into a region of the matured steam chamber which can be referred to as a first steam chamber at a first stage of maturity. The first steam chamber is generally adjacent to or proximate to an operating chamber which can be referred to as a second steam chamber at a second stage of maturity. In various implementations, the matured steam chamber can also be generally adjacent to or proximate to another steam chamber having a different level of depletion from which further hydrocarbons can be recovered.

[0076] In various implementations, the term "non-oxidizing gas" relates to any gas that does not oxidize under SAGD reservoir conditions and can include, for example, methane, nitrogen, carbon dioxide or a combination thereof.

[0077] In various implementations, the non-oxidizing gas is injected to form a pressurized non-oxidizing buffer zone generally at or within the boundary or at or within a region of the matured steam chamber adjacent to the operating steam chamber. In various implementations, the pressurized non-oxidizing buffer zone has a pressure sufficient to reduce a fluid cross-flow between the adjacent or proximate steam chambers (e.g., between the operating steam chamber(s) and the matured steam chamber(s)). In various implementations, the fluid can be, for example, combustion gas, free oxygen, steam or a combination thereof.

[0078] In various implementations, at the same time injection of the non-oxidizing gas is being performed, an oxygen-comprising gas is injected into the matured steam chamber adjacent the region of injection of the non-oxidizing gas so as to pressurize the matured steam chamber by increasing a pressure in the first steam chamber relative to its initial pressure. Diffusion of the oxygen-comprising gas to the barrier can be minimized by the pressurized non-oxidizing buffer zone. In other implementations, the oxygen-comprising gas is injected into the matured steam chamber prior to the injection of the non-oxidizing gas, depending on the spacing of the oxygen-comprising gas injection wells from the non-oxidizing gas injection wells and on the permeability of the reservoir between the wells. As the oxygen-comprising gas diffuses toward the barrier, injection of the non-oxidizing gas can then be performed. In various implementations, if the reservoir conditions (e.g. temperature, pressure, oxygen concentration) are appropriate, ignition or combustion can be initiated in the matured steam chamber which results in oxidation reactions between the oxygen in the oxygen-comprising gas and the remaining residual hydrocarbons such as bitumen which can have a concentration of about 5% or more.

[0079] In various implementations, the term "oxygen-comprising gas" relates to a fluid, such as air, enriched air, a non-condensable gas mixture, pure oxygen or a combination thereof, which has an oxygen concentration of about 5% or more. In various implementations, the concentration of oxygen in the oxygen-comprising gas can range from about 5% to about 100%, about 5% to about 40%, or about 7% to about 40%. For example, the oxygen-comprising gas can be air, which comprises about 21% oxygen. In various implementations, the oxygen-comprising gas has the capability of supporting in situ combustion, as described below. In particular implementations, the amount of oxygen in the oxygen-comprising gas can be tailored to achieve a desired level of in situ combustion as a strategy for reducing fluid leak from the operating steam chamber into the adjacent matured steam chamber. The combustion and heat generated in the matured steam chamber, in addition to the injection of the non-oxidizing gas generally at or within the boundary, can help to maintain the pressure generally within the matured steam chamber and support the development of the pressurized non-oxidizing buffer zone. In implementations where injection of the non-oxidizing gas is delayed or not performed, the combustion and heat generated in the matured steam chamber can help to maintain the pressure generally within the matured steam chamber to reduce fluid cross-flow between the adjacent or proximate steam chambers.

[0080] In various implementations, it is the pressure difference between or among the generally adjacent or proximal chambers at varying stages of maturity that is one of the dominant factors resulting in fluid cross-flow through porous media in the reservoir (e.g., flue gas cross-flow, oxygen cross-flow, steam cross-flow). For example, if the injection of steam is stopped, the rate of pressure drop can range from about 1 to about 3.9 kPaid within a SAGD chamber. If there is generally no pressure difference between the two adjacent or proximate steam chambers (e.g., the matured steam chamber and the operating steam chamber), there would be generally no fluid flow between these chambers. Therefore, in various implementations, the pressure of the pressurized non-oxidizing buffer zone is increased until this pressure is equal to or greater than the pressure in the operating steam chamber, the matured steam chamber or both. The selected pressure difference between the matured steam chamber and within the boundary can range from 0 kPa to about 200 kPa, which results in a reduction of the cross-flow of fluid such as steam between the operating steam chamber and the boundary and further between the adjacent or proximate chambers. This pressure difference also minimizes diffusion of the oxygen-comprising gas to the barrier.

[0081] In another implementation, the non-oxidizing gas and the oxygen-comprising gas are injected into a region of the boundary and into the matured steam chamber, respectively, such that the pressure within the boundary and within the matured steam chamber can generally reach a value referred to as an "optimum pressure value"
(also referred to as a "sufficient pressure value"). The sufficient pressure value can be a pressure value slightly lower than the pressure of the boundary relative to the pressure of the adjacent operating steam chamber. In various implementations, the sufficient pressure value can vary depending on the geology, operational conditions, the degree of depletion and the duration of depletion of the matured steam chamber. The pressure difference between the matured steam chamber(s) or the boundary and the generally adjacent or proximate operating steam chamber(s) can be as low as possible. In various implementations, a suitable pressure difference that reduces or avoids fluid cross-flow from the operating steam chamber into the adjacent matured steam chamber can be about 50 kPa.

[0082] In other implementations, the non-oxidizing gas is not injected or its injection is delayed until absolutely necessary, depending on the nature of the barrier between the operating steam chamber and the matured steam chamber. If the barrier between the operating steam chamber and the matured steam chamber is a wide region of unproduced reservoir, for example, about 100m wide, then injection of the non-oxidizing gas can be avoided. Following injection of the oxygen-comprising gas into the matured steam chamber and the initiation of combustion or oxidation in the matured steam chamber, if the combustion front approaches the operating steam chamber late in the life of the operating steam chamber then injection of the non-oxidizing gas can be avoided. The combustion front can warm the bitumen at the barrier between the operating steam chamber and the matured steam chamber which can then flow to a production well in the operating steam chamber, increasing the recovery of hydrocarbons from the reservoir. If non-oxidizing gas is injected into the boundary region in these circumstances, the bitumen between the operating steam chamber and the matured steam chamber could be rendered unrecoverable due to the presence of the non-oxidizing gas.

. .

[0083] In other implementations, injection of the non-oxidizing gas can be delayed. As the combustion front in the matured steam chamber and the steam chamber of the operating steam chamber move towards each other in the absence of the non-oxidizing gas, they can connect with each other at the top of the reservoir, leaving an area of undepleted bitumen near the bottom of the reservoir. Using modeling and by monitoring the development of the steam chamber in the operating steam chamber and the combustion front in the matured steam chamber, non-oxidizing gas can be injected into the top of the reservoir in the boundary and between the steam chamber of the operating steam chamber and the combustion front from the matured steam chamber to push these fronts toward a bottom portion of the reservoir, allowing for the recovery of further bitumen from a bottom portion of the barrier.
These implementations can also reduce the consumption of costly non-oxidizing gases, thereby increasing the efficiency of the process.

[0084] In various implementations, one or more of the former steam injectors can be converted into a non-oxidizing gas injector(s), an oxygen-comprising gas injector(s) or a combination thereof. For example, in various implementations, an edge well pair or any well generally away from the edge well in the matured steam chamber which is generally adjacent or proximate to the operating steam chamber can be selected, so long as sufficient pressure (e.g., an optimum pressure value) is achieved within the matured steam chamber, generally at or within the boundary or both, relative to the pressure in the operating steam chamber to reduce the cross-flow of fluid from the operating chamber into the generally adjacent matured steam chamber. In various implementations, other previous steam injectors within the matured SAGD
chamber not used for injection of the non-oxidizing gas or the oxygen-comprising gas can be converted into producers to produce oil and gas. In various implementations, injection of the non-oxidizing gas and the oxygen-comprising gas according to the implementations described above can be used as a strategy for increasing the recovery of hydrocarbons from the reservoir as whole.

[0085] In various implementations, the non-oxidizing gas and the oxygen-comprising gas are injected into the boundary and into the matured steam chamber, respectively, through former SAGD injection wells that are the closest to the generally adjacent SAGD operating well pairs (for example, the previous steam injector is converted into an oxygen-comprising gas injector), while the previous SAGD production wells remain open to producing further amounts of gas and oil. In various implementations, the parameters for those wells are set to meet the requirements for pressure maintenance under the specific operating conditions.

[0086] In various implementations, the non-oxidizing gas and the oxygen-comprising gas can be injected in various ways, including cyclical and intermittent injection. For example, as shown in the Figures, the oxygen-comprising gas can be continually injected for three months, stopped for two months and then subsequently resumed.
The original wells in the matured steam chamber and generally within or at the boundary in the SAGD reservoir can be modified in various ways. In various implementations, the spacing between the SAGD well pairs is generally about 100 m and the length of the horizontal well is generally about 500 m or more. The resultant surface area is relatively large and therefore, it can be more economical in some implementations to use only a portion of the well for perforation and injection of the non-oxidizing gas, the oxygen-comprising gas or both. Thus, in various implementations, in order to use the minimum non-oxidizing gas flux injection, the minimum oxygen-comprising gas flux injection or both, the non-oxidizing gas, the oxygen-comprising gas or both can be injected via a portion or several portions of the initial horizontal wellbore of the steam injector. Figs. 2 and 3 show injection and production well pairs, wherein the injection well is situated generally above the production well.

[0087] In the implementation of Fig. 2, the injection well is perforated along generally substantially all or a portion of the horizontal portion of the former steam injection well.
In this implementation, if production of hydrocarbons is desired, the combustion front generated rises upwardly toward the upper portion of the reservoir. The mobilized hydrocarbon can be collected by the production well situated generally below the injection well. In this respect, a packer can be used to isolate the horizontal wellbore section, and the oxygen-comprising gas such as air can be injected through the isolated portion.

[0088] In another implementation, a vertical section in the bitumen bearing zone can be perforated and a dual completion system can be employed as is shown in Fig.
3.
Air can be injected into the formation through annuls and vent combustion gas can be vented through tubing along the horizontal well section of the original steam injection well.

[0089] In Fig. 3, the injection well is perforated along generally substantially all or a portion of the vertical portion of the previous or former steam injection well for injection of the non-oxidizing gas, the oxygen-comprising gas or both. In various implementations, as is shown for example in Fig. 3, the combustion front created by injecting the oxygen-comprising gas extends outwardly from the generally vertical portion of the injection well (i.e., from heel to toe), and the combustion gases drain into the generally horizontal portion of the injection well. As is shown in the implementation in Fig. 3, the mobilized hydrocarbons can drain into the generally horizontal portion of the production well.

[0090] In various implementations, the non-oxidizing gas injector is laterally offset or disposed away from the oxygen-comprising gas injector. Any other previous steam injectors can also be converted into flue gas vent wells and the corresponding offset previous bitumen producers can remain as liquid producers to collect heated bitumen and condensate of steam. These wells can be controlled to determine if they are open or shut based on oxygen concentration and fluid temperature from the well (e.g., if the temperature and oxygen concentration are high, the well can be shut in). As a result, combustion drive is initiated to maintain reservoir pressure in the matured steam chamber, support the development of the pressurized non-oxidizing buffer zone and in some implementations, to mobilize bitumen within the matured steam chamber.

[0091] In various implementations, the timing for beginning injection of the non-oxidizing gas and the oxygen-comprising gas can occur when fluid communication between the operating SAGD pad or chamber and the matured SAGD pad or chamber is either established or not yet established.

[0092] Although the wells in the matured steam chamber have been functionally identified as production or injection wells, such identification does not imply that the wells are to be used exclusively for that particular purpose. The wells can have one or more functions (e.g., for injecting the non-oxidizing gas, injecting the oxygen-comprising gas and venting a combustion gas formed during pressurization of the matured steam chamber).

[0093] As was described above, after steam injection is terminated in a SAGD
operation, injection of the non-oxidizing gas, the oxygen-comprising gas or both can be initiated instead of steam. In various implementations, the injected non-oxidizing gas, the oxygen-comprising gas, or both, can be generally dry or generally wet. For example, if the oxidation reactions are high temperature oxidation reactions or if combustion dominates, more heat can be generated in situ. In such implementations where air can be used as the oxygen-comprising gas, water-air (wet air) co-injection can be used to utilize the heat generated from combustion. Liquid water can be evaporated and became steam. However, in such implementations, wet combustion can result in a lower peak temperature of combustion as compared with dry . , , .

combustion. The injection of water with air improves the in situ combustion process by lowering fuel and air requirements and increasing front velocity. Both fuel and air requirements are reduced up to 20% at high water-to-air ratios (WAR), when compared to dry combustion (VVAR=0). Because of its high heat capacity, water scavenges most of the generated heat stored behind the burning front and carries superheated steam over the front to the steam plateau region where the oil bank is found in front of the combustion front. The water injected can be cold water, hot water or steam. (e.g., US Patent 4729431 - Oil recovery by quenched in situ combustion).
The combustion front velocity increases with increases in WAR. But at very high WAR
values, the water zone approaches the burning zone from behind the front.

[0094] In various implementations, once combustion has been initiated, an adequate supply of the oxygen-comprising gas is important in addition to the supply of the non-oxidizing gas. For example, once the combustion front has propagated a sufficient distance away from the wellbore to achieve a generally stabilized burn, it can be preferred, but not essential, to convert the dry combustion drive to a water and oxygen-comprising gas co-injection. This can be done by injecting water concurrently or alternately with the oxygen-comprising gas through the injection well(s).
In various implementations, it can be preferred to initially inject water at a WAR of about 50 to about 500 bbls/MMCFair. After the combustion within the matured SAGD chamber has generally stabilized, the WAR can be increased.

[0095] In various implementations, the residual bitumen content in the matured steam chamber can range from about 0.05 % to about 5 % in order to achieve ignition and sustain combustion while avoiding the risk of an explosion.

[0096] Depending on the content of oxygen in the oxygen-comprising gas and the residual hydrocarbon content in the matured steam chamber, the generation of heat and flue gases (e.g., N2 and CO2) through oxidation reactions occurring within the . .
. .

matured steam chamber can be modulated to obtain the desired conditions for maximizing hydrocarbon recovery from the generally adjacent operating steam chamber(s) and, in some implementations, simultaneous recovery of the residual hydrocarbons from the matured steam chamber. In various implementations, the pressure, temperature, oxygen concentration, rate of injection and volume of the non-oxidizing gas, the oxygen-comprising gas, or both, can all be modulated to achieve a certain degree of reduction in inter-chamber fluid flow, in situ combustion in the matured steam chamber and the desired level of pressurization of the matured steam chamber as a whole or generally within the boundary adjacent to or proximate to the operating steam chamber.

[0097] In various implementations, an artificial ignition source can be required, which can, for example, include auto-ignition. In some implementations, if the temperature in the matured steam chamber is below about 200 C, the artificial ignition source can be required to help initiate in situ combustion in the matured steam chamber. The oxygen-comprising gas can have a temperature in the range of about 180 C to about 270 C
and pressure in the range of about 1000 kPa to about 6500 kPa prior to injection into the matured steam chamber. The matured steam chamber can have a temperature above 180 C and pressure about 200 kPa less than the pressure in the operating steam chamber. The temperature of the matured steam chamber, the boundary, or both, prior to injection of the oxygen-comprising gas and the non-oxidizing gas can vary depending on the production stages of the adjacent operating steam chambers and on reservoir properties. The volume of the oxygen-comprising gas required can vary depending on the operational conditions, and can be modulated during injection to achieve desired levels of combustion.

[0098] In various implementations, it is important to control the combustion in the matured steam chamber by controlling the rate of injection of the oxygen-comprising gas (e.g., air or air enriched with oxygen), the content of oxygen, or a combination . .
. , thereof. Injection of the non-oxidizing gas generally at or within the boundary can mitigate risks of either combustion gas or free oxygen flowing into the operating SAGD
chamber, if fluid communication is established between the two pads.

[0099] For example, Nelson and McNeil (Nelson, T.W., and McNeil, J.S., How to Engineer an In Situ Combustion Project; The Oil and Gas Journal, p. 58, June 5, 1961) proposed that a minimum velocity required to sustain the propagation of a high temperature combustion was 0.038m/day. The minimum oxygen flux (Ufm) required for maintaining this velocity can be estimated based on the following relationship:
Ufin = Ar xUbrn where:
Ar: Oxygen-comprising gas requirement (m3(ST)/m3) Ubm: Minimum burn front velocity (m/hour) Ufin: Minimum oxygen flux (m3(ST)/m2-hour)

[0100] In various implementations, a flux of the oxygen-comprising gas can be calculated from the oxygen gas flux based on the oxygen concentration within the oxygen-comprising gas, and is one parameter used to control the combustion and thus the temperature of the matured steam chamber. If air is used, oxygen gas flux can be called air flux. The flux of the oxygen-comprising gas allows for modulation of the size of the combustion front (R.G.Moore, C.J. Laureshen, S.A.Mehta, M.G. Ursenbach, Observations and Design Consideratios for In Situ Combustion Projects, Journal of Canadian Petroleum Technology, Special Edition 1999, Vol.38, No.13, 1999).
Once the air requirement is fixed, the air flux determines the velocity of combustion front movement within the reservoir. In various implementations, the rate of injection of the oxygen-comprising gas can be kept as low as possible, which allows the combustion front to propagate from the injector at a rate as low as about 0.038m/day.

[0101] The minimum amount of the oxygen-comprising gas required (e.g., air) is proportional to both the fuel deposition and heat loss (Partha Sarathi, S., In Situ Combustion Handbook ¨ Principles and Practices, National Petroleum Technology Report, U.S. Department of Energy, Tulsa, Oklahoma, 1999). The higher the fuel deposition, the more oxygen-comprising gas is required, resulting in higher air flux.
Similarly, the higher the heat loss from the formation to overburden and underburden, the higher the oxygen-comprising gas (e.g. air) flux is needed. In various implementations, the matured steam chamber is generally warm or hot, and can have a temperature of about 165 C or greater. When the formation is heated, heat loss can be smaller than is the case for conventional in situ combustion processes, including the THAI process. The fuel deposition can also be less than the post-SAGD case (Partha Sarathi, S., In Situ Combustion Handbook ¨ Principles and Practices, National Petroleum Technology Report, U.S. Department of Energy, Tulsa, Oklahoma, 1999).

[0102] In various implementations, the temperature generally travels within the reservoir a much shorter distance than the pressure. In various implementations, this can be a consideration with regard to the volume of air or oxygen-comprising gas injected in combination with the non-oxidizing gas in order not to move the high temperature or combustion front too fast, which is controlled by the rate of injection. In various implementations, combustion gas or flue gas mainly comprising N2 and are generated through the oxidation reactions in situ and fill the void space of the matured steam chamber.

[0103] By injecting the oxygen-comprising gas alone or in combination with the non-oxidizing gas according to various implementations, the pressure generally at or within the boundary, in the adjacent matured steam chamber or both, is maintained, preventing the matured steam chamber from becoming a thief zone for future or ongoing SAGD operations nearby.

[0104] Injection of the oxygen-comprising gas or both the oxygen-comprising gas and the non-oxidizing gas can block fluid cross-flow between or among the chambers and can allow for increased oil production from adjacent operating steam chambers in the reservoir as a whole. Injection of the oxygen-comprising gas, the non-oxidizing gas or both can also result in mobilization of the residual oil (unrecovered or remaining oil left in place from previous in situ recovery such as, for example, SAGD) in the matured steam chamber. The recovery of residual oil in the matured steam chamber can range from about 55% to above about 80%.

[0105] To obtain improved performance of the operating steam chamber(s) adjacent to or proximate to the matured steam chamber, an optimum pressure can be maintained in the matured steam chamber as a whole and generally within the boundary between the matured steam chamber and the operating steam chamber to facilitate the operations, which can be generally similar or up to about 200 kPa lower than the pressure in the adjacent or proximate operating steam chamber. The optimum pressure can also depend on the properties of one or more pads surrounding the matured steam chamber. For example, if the pads adjacent the matured steam chamber include operating steam chambers at various stages of SAGD, the pressure required at or generally within the boundary (i.e., injection of the non-oxidizing gas) and the pressure required in the chamber (i.e., injection of the oxygen-comprising gas) to increase hydrocarbon production from several of the operating steam chambers can be different from the pressure required to reduce cross-flow and increase hydrocarbon production in instances where only one operating steam chamber is adjacent the matured steam chamber.

[0106] In various implementations, parameters such as the pressure at or within the boundary, reservoir pressure, produced gas compositions, and temperature of the oxygen-comprising gas injector(s) and producer(s) in both the operating and matured steam chambers, can be monitored. These parameters can be used to determine , optimal injection rates of the non-oxidizing gas, the oxygen-comprising gas, or both, in order to achieve a reduction in cross-flow of fluid between the chambers, increased oil production, or both, as compared to what can be achieved without injecting the oxygen-comprising gas and the non-oxidizing gas.

[0107] In various implementations, the timing to commence the injection of the non-oxidizing gas, the oxygen-comprising gas or both into the matured steam chamber can be important to achieving suitable operational efficiencies. For example, injection of the non-oxidizing gas and the oxygen-comprising gas into the matured steam chamber can be performed cyclically, and the injection cycle can depend on the properties and layout of the adjacent operating steam chambers. For example, the non-oxidizing gas and the oxygen-comprising gas can be injected for a certain length of time and then shut in for a selected time interval. The injection rate and timing can be adjusted for each cycle based on the requirements for pressure maintenance design for reducing fluid cross-flow between the adjacent chambers and for target oil production.

[0108] The production of oil and combustion gases can also operate cyclically.
In various implementations, free oxygen can be scrubbed from the matured steam chamber through the oxidation reactions. Utilizing the residual heat in the reservoir after steam injection has been stopped can also assist with oxidation reactions, and in some implementations, can influence the amount and composition of the oxygen-comprising gas to be injected into the matured steam chamber. In various implementations, hydrocarbons can be recovered selectively from the operating steam chamber, the matured steam chamber, or from both chambers.

[0109] In various implementations, the number of wells required for injecting the non-oxidizing gas and the oxygen-comprising gas can vary based on operational requirements. In various implementations, the physical arrangement of the wells on adjacent pads for injecting the non-oxidizing gas and the oxygen-comprising gas can vary. For example, the wells can have parallel-type side by side and toe-heel series-type side-by-side arrangements. In various implementations, the injection wells in the matured steam chamber can be configured such that the oxygen-comprising gas is injected near the bottom of the reservoir to mobilize the residual hydrocarbons in the matured steam chamber for combustion, recovery or a combination thereof. In various implementations, one or more injection wells can be positioned in the proximity of the production well for injecting the oxygen-comprising gas or in the proximity of the boundary for injecting the non-oxidizing gas generally at or within the boundary. In various implementations, new injection wells can also be formed to achieve a desired configuration in the matured steam chamber for blocking fluid cross-flow between the generally adjacent chambers and for increasing the recovery of hydrocarbons.

[0110] In various implementations, infill wells can be put into the matured steam chamber. For example, an infill horizontal well can be selected for injecting the oxygen-comprising gas and the adjacent or offset previous SAGD well pairs can be converted into production wells. For example, the upper well can be mainly used for gas production and the lower well can be mainly used for liquid production. In various implementations, the injector of the oxygen-comprising gas can be a vertical well that can be drilled in the area of the matured steam chamber. Various flue gas wells can be set up in selected configurations relative to the wells for injecting the oxygen-comprising gas and relative to the wells for injecting the non-oxidizing gas for controlling combustion and for achieving and maintaining the pressure balance for the two or more generally adjacent or proximal SAGD pads. If hot fluid communication is established and the pressure balance between the two SAGD pads or chambers is not properly controlled, the flue gas can migrate from the portion of the reservoir in the matured SAGD pad into the operating SAGD pad, which in turn can jeopardize the steam chamber growth and thus impair SAGD performance in the operating SAGD
chamber.

. .
,

[0111] In various implementations, the extent of fluid communication between the immature operating chamber(s) and the matured steam chamber(s) can differ. The following factors can affect the extent of fluid communication: initial steam chamber size and chamber development, steam injection temperature and pressure, geological conditions such as reservoir heterogeneity and pressure differences, injection pressure for the non-oxidizing gas, injection pressure for the oxygen-comprising gas, cumulative oil produced, steam injected, and chamber cooling.

[0112] In various implementations, reservoir geology can be an important consideration for maximizing oil recovery from the reservoir. For example, if the reservoir includes high permeability streaks or channels, channeling and early steam, flue gas and oxygen breakthrough can occur. There can be a potential risk that the oxygen-comprising gas injected into the matured steam chamber can be captured by the production wells in the matured steam chamber. If the free oxygen is not consumed through oxidation or combustion, it can pose a safety concern.

[0113] Injection of the non-oxidizing gas generally at or within the boundary and the oxygen-comprising gas address the issue of channeling of steam by forming a barrier.
Also, in various implementations, injection of the non-oxidizing gas reduces the risk of an explosion. To further reduce this kind of risk, monitoring the produced gas compositions and the level of the non-oxidizing gas at or within the boundary and the oxygen-comprising gas in the matured steam chamber can be used as an indication for the integrity of the pressurized barrier generally within the boundary, combustion activity in the reservoir, and for moderating safety risks associated with gas levels.

[0114] Injection of the non-oxidizing gas generally at or within the boundary and the oxygen-comprising gas into the matured steam chamber provides several economic advantages. Unlike in the prior art, where, for example, a non-condensable gas (NCG) is injected into the chamber and often causes a significant reduction in the temperature of the matured steam chamber, injection of the non-oxidizing gas at or within the boundary and the oxygen-comprising gas into the matured steam chamber does not have such an effect. Thus, injection of the non-oxidizing gas and the oxygen-comprising gas can allow for pressure to be generated and maintained not only through injection of a suitable volume of the gases but also through heat generation by combustion with the residual hydrocarbons in the matured steam chamber.

[0115] The injection of the non-oxidizing gas generally within the boundary between the matured steam chamber and the adjacent or proximate operating steam chamber and the oxygen-comprising gas into the matured steam chamber can provide a method of isolating the matured steam chamber or a pattern of matured steam chambers from the adjacent or proximate operating steam chambers. The injection of the non-oxidizing gas and the oxygen-comprising gas allows for the maintenance of reservoir pressure and slows the temperature drop as the steam vapour in the matured steam chamber condenses. The non-oxidizing gas injection and the oxygen-comprising gas injection can also reduce steam cross-flow and cross-flow of combustion gas and free oxygen between the matured steam chamber and the generally adjacent or proximate operating steam chamber.
Therefore, the performance of the operating steam chambers can be improved due to more efficient utilization of the steam, which can reflect a lower cSOR.

[0116] Duration of the injection of the non-oxidizing gas into the boundary and the injection of the oxygen-comprising gas into the matured steam chamber, respectively, can vary depending on the properties of the matured steam chamber prior to injection (e.g., temperature, pressure) and on the operational stages of the operating steam chambers proximal to or generally adjacent the matured steam chamber. For example, if the operating steam chambers are in the early stages of SAGD, the interval for injecting the non-oxidizing gas and the oxygen-comprising gas into the matured steam chamber can be longer than in circumstances where the operating steam chambers are in later stages of SAGD.

[0117] In various implementations, the various ranges and ratios described can be derived from laboratory experiments, computer simulations, or both, to mimic the particular in situ extraction process and system, reservoir properties, effects of well layout, and desired injection of the non-oxidizing gas and the oxygen-comprising gas.

[0118] In various implementations, the maintained SAGD chamber pressure in combination with the pressure maintained at the boundary can "blunt" the steam chamber of the edge well(s) for the operating SAGD chamber(s) that are located generally adjacent to the matured SAGD chamber(s), which lessens steam cross-flow (also referred to as steam leakage) from the operating SAGD chamber into the generally adjacent matured chamber.

[0119] In various implementations, various previous steam injector(s) that are located in the matured steam chamber can be kept open to produce combustion gases and hydrocarbon vapor gas and liquids (bitumen and water) while the producers located in the operating SAGD chamber can continually produce bitumen. Various parameters associated with the injection and production wells in the matured and operating chambers such as, for example, minimum bottom pressure and maximum production rate for liquid and gas, can be modulated/controlled based on the level of pressure maintenance desired under particular operating and reservoir conditions.
EXAMPLES

[0120] Various implementations presented in the Figures have been modeled in a computer reservoir simulation, the Steam, Thermal, and Advanced Processes Reservoir Simulator (STARS), provided by Computer Modelling Group (CMG), based on a selected location of the geology model. Parameters for the simulations are chosen to mimic the parameters for the particular reservoir and the operating conditions for the operating and matured chambers in the reservoir.

[0121] The following parameters in Table 1 were used for the simulation model:

Simulator CMG STARS 2009 version Simulation Water, Bitumen (two pseudo components: Asphaltene and components Maltene fractions), CO2, Oxygen, Nitrogen, and Coke Fort McMurray type formation, the geology model for simulation is similar to the one used as the previous ASOSTRA UTF
(Underground Test Facility) Rich sand Lean Sand Formation Horizontal Permeability (md) 8000- 10000 3890 properties Vertical Permeability (md) 3303 -5600 1945 Porosity (faction) 0.35 0.30 Oil saturation (fraction) 0.85 0.75 Initial temperature ( C) 9 9 Initial Pressure (kPa) 530-840 kPa Gross formation thickness (m) 48m Fluid Bitumen properties are taken as Athabasca bitumen, which are properties accepted in the industry ' = .

[0122] Figs. 1A to 1C illustrate schematic diagrams of three examples of layout or arrangement of wells for a SAGD pad development, showing a reservoir comprising matured steam chambers generally adjacent to operating steam chambers. As is shown in the Figures, there is a "boundary" between the matured SAGD pad and the operating SAGD pad. The boundary forms a separation between the operating SAGD well pair and the mature well pair which can be over and above the nominal drainage width of both well pairs. An edge well pair within a pad is disposed to leave at least half the distance of the inner well pair spacing to the boundary/edge of a particular approved development area.

[0123] In an implementation comprising two SAGD pads as shown in Figs. 2-10, SAGD operation is performed on Pad 1 until recovery of hydrocarbons from Pad 1 becomes uneconomical, at which point steam injection is stopped and the operating steam chamber becomes "matured". One or more of the injection wells in Pad 1 are then modified for injecting the non-oxidizing gas generally at or within the boundary and the oxygen-comprising gas into the matured steam chamber. In various implementations, SAGD operation on Pad 2 comprising the operating chamber, generally adjacent to Pad 1, can be performed simultaneously with the injection of the non-oxidizing gas and the oxygen-comprising gas into Pad 1. The rate of injection of the non-oxidizing gas and the oxygen-comprising gas, and the duration for injection in Pad 1 can be modulated based on, for example, the performance and operating conditions of Pad 2, the level of pressure to be maintained, the desired level of hydrocarbon recovery from Pad 1, Pad 2, or both, and the rate of fluid production (water, combustion gases). In various implementations, an injection strategy for injecting the non-oxidizing gas and the oxygen-comprising gas is important for operational control of the non-oxidizing gas injection wells, the oxygen-comprising gas injection wells and the generally adjacent SAGD operations.

. ' ,

[0124] Figure 2 shows an example of the manner in which the oxygen-comprising gas can be injected into the matured steam chamber. In this example, the injection well is perforated along generally substantially all or a portion of the horizontal portion of the previous steam injection well. The combustion front generated rises upwardly toward the upper portion of the reservoir. The mobilized hydrocarbon can be collected by the production well situated generally below the oxygen-comprising gas injection well. In this respect, a packer can be used to isolate the horizontal wellbore section, and the oxygen-comprising gas such as air can be injected through the selected portion.

[0125] Figure 3 illustrates another implementation showing injection of the oxygen-comprising gas via the injector. A vertical section in the bitumen bearing zone can be perforated and a dual completion system can be employed to inject the oxygen-comprising gas. The combustion front created extends outwardly from the generally vertical portion of the oxygen-comprising gas injection well (i.e., from heel to toe), and the combustion gases drain into the generally horizontal portion of the injection well.
As is shown in the implementation of Figure 3, any mobilized hydrocarbons can drain into the generally horizontal portion of the production well below.

[0126] In various implementations, the oxygen-comprising gas injector (air injector in this example) is a former steam injector and can be located anywhere in the matured steam chamber. For example, the air injector can be either close to or far away from the adjacent boundary. The air can be injected continuously via the air injector or cyclically. In various implementations, the non-oxidizing gas and the oxygen-comprising gas having variable composition can be used for the various cyclical stages of injection.

[0127] For example, in the simulation model, Pad 1 was operated 7 years earlier than Pad 2 and steam injection into Pad 1 was terminated after those 7 years. Pad 2 was operated in SAGD mode for 10 years. Water vapour mole fraction represents the steam chamber within the reservoir. As shown in Figure 4, Pad 1 contains a well developed steam chamber and no fluid cross-flow from Pad 2 into Pad 1. After years of SAGD operation in Pad 2, steam from Pad 2 leaks into Pad 1, as shown in Figure 5. The reservoir pressures in Pad 1 and Pad 2 are equal.

[0128] A comparison of steam chambers illustrating the effect of injecting the non-oxidizing gas and the oxygen-comprising gas into Pad 1 is shown in Figure 6.
Without injection of these gases, steam from Pad 2 continues to leak into Pad 1. In contrast, injecting the non-oxidizing gas and the oxygen-comprising gas into Pad 1 can decrease the loss of steam injected into Pad 2 to Pad 1. In the simulation model, air was injected through the upper well of the second well pair (from left to right) as the oxygen-comprising gas and methane was injected through the upper well of the first well pair in Pad 1 as the non-oxidizing gas.

[0129] Figure 7 shows a layout of the wells for the simulation model which includes a non-oxidizing gas injector, an oxygen-comprising gas injector and gas vent wells in Pad 1. Pad 2 includes a well configuration for SAGD operations involving steam injection wells and hydrocarbon production wells.

[0130] Combustion or oxidation reactions can occur in Pad 1 following injection of the oxygen-comprising gas. Simulation results showing a temperature profile in the reservoir are illustrated in Figure 8. As temperature is dependent on pressure, increasing temperature in Pad 1 indicates that pressure in Pad 1 is also being maintained at a higher value as compared to the pressure in Pad 1 prior to injection of the non-oxidizing gas and the oxygen-comprising gas. Maintaining pressure in Pad 1 can prevent fluid cross-flow from Pad 2 into Pad 1.

[0131] Figure 9 shows that injection of the non-oxidizing gas and the oxygen-comprising gas can create a methane buffer zone at the boundary between Pads 1 and 2. In various implementations, the methane can stay in the area between Pad 2 and the top of the matured steam chamber in Pad 1.

[0132] In various implementations, combustion products from the combustion or oxidation of the oxygen-comprising gas injected into Pad 1 can stay within the matured steam chamber in Pad 1 as shown in Figure 10. The distribution of CO2 indicates that the methane can act as a buffer that "pushes" the combustion products away from the boundary between Pads 1 and 2.

[0133] The various implementations of the apparatus and process allow use of multi-well pairs and multi-pad operations, and various non-oxidizing gas and oxygen-comprising gas injector and producer configurations, as well as improvement in the SAGD performance of individual pads and of the reservoir undergoing SAGD as a whole.

[0134] Although specific implementations have been described and illustrated, such implementations should not to be construed in a limiting sense. Various modifications of form, arrangement of components, steps, details and order of operations of the implementations illustrated will be apparent to persons skilled in the art upon reference to this description. It is therefore contemplated that the appended claims will cover such modifications and implementations. In the specification including the claims, numeric ranges are inclusive of the numbers defining the range.

Claims

THE EMBODIMENTS OF THE INVENTION IN WHICH AN EXCLUSIVE
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:

1. An in situ process for treating a hydrocarbon reservoir, the process comprising:
(a) selecting in the hydrocarbon reservoir a first steam chamber and a second steam chamber generally adjacent to the first steam chamber, the first and second steam chambers having been processed using steam assisted gravity drainage (SAGD) or undergoing or being capable of undergoing further SAGD processing, the first and second steam chambers each having a hydrocarbon content and an initial temperature, and the first steam chamber having an initial pressure lower than a pressure in the second steam chamber, (b) selecting a first injection well in fluid communication with the first steam chamber, the first injection well being generally adjacent to the second steam chamber;
(c) selecting a second injection well in fluid communication with the first steam chamber, the second injection well being disposed away from the first injection well;
(d) injecting a non-oxidizing gas through the first injection well to form a pressurized non-oxidizing buffer zone between the first and second steam chambers to reduce a fluid flow between the first and second steam chambers; and (e) injecting an oxygen-comprising gas through the second injection well to increase a pressure in the first steam chamber relative to the initial pressure.

2. The method of claim 1, further comprising:
sustaining combustion in the first steam chamber, wherein production of hydrocarbons from the second steam chamber is increased relative to production of hydrocarbons recoverable from the second steam chamber without combustion of the oxygen-comprising gas into the first steam chamber.

3. The method of claim 1 or 2 wherein forming the pressurized non-oxidizing buffer zone increases production of hydrocarbons from the second steam chamber relative to production of hydrocarbons recoverable from the second steam chamber without formation of the pressurized non-oxidizing buffer zone.

4. The method of claim 1, 2 or 3 wherein the oxygen-comprising gas is injected concurrently with the non-oxidizing gas.

5. The method of claim 1, 2 or 3 wherein the oxygen-comprising gas is injected before the non-oxidizing gas.

6. The method of claim 1, 2 or 3 wherein injecting the non-oxidizing gas and the oxygen-comprising gas is cyclical.

7. The method of any one of claims 1 to 6 wherein the first steam chamber is at a later stage of maturity than the second steam chamber.

8. The method of any one of claims 1 to 7 wherein a boundary exists between the first steam chamber and the second steam chamber.

9. The method of any one of claims 1 to 8 wherein a pressure difference between the first steam chamber and the second steam chamber following injection of the non-oxidizing gas and the oxygen-comprising gas is about 200 kPa or less.

10. The method of any one of claims 1 to 9 wherein the second injection well is vertically offset from the first injection well.

11. The method of any one of claims 1 to 10 wherein the fluid flow comprises a flow of flue gas, a flow of the oxygen-comprising gas, a flow of steam, or a combination thereof

12. The method of any one of claims 1 to 11 wherein a hydrocarbon content of the first steam chamber is lower than a hydrocarbon content of the second steam chamber.

13. The method of any one of claims 1 to 12 further comprising producing hydrocarbons from the first steam chamber, the second steam chamber or both the first and second steam chambers.

14. The method of any one of claims 1 to 13 wherein the first and second injection wells have been previously used for fluid injection. .

15. The method of any one of claims 1 to 13 wherein the first injection well or the second injection well has been previously used for steam injection.

16. The method of any one of claims 1 to 15 wherein the non-oxidizing gas, the oxygen-comprising gas or both are injected proximate a lower portion of the reservoir.

17. The method of any one of claims 1 to 16 wherein a concentration of oxygen in the oxygen-comprising gas ranges from about 5% to about 100%.

18. The method of any one of claims 1 to 17 wherein the oxygen-comprising gas comprises air, oxygen-enriched air, or a combination thereof.

19. The method of claim 18 wherein the oxygen-enriched air comprises a concentration of oxygen above about 21%.

20. The method of any one of claims 1 to 19 wherein the non-oxidizing gas is methane, nitrogen, carbon dioxide, or a combination thereof.

21. The method of any one of claims 1 to 20 wherein the non-oxidizing gas, the oxygen-comprising gas or both are wet or dry.

22. The method of any one of claims 1 to 21 wherein selecting the first injection well, the second injection well or both comprises selecting more than one injection well.

23. The method of claim 8 wherein the boundary comprises unproduced hydrocarbons.

24. The method of any one of claims 1 to 23 wherein the first or the second injection well comprises a well previously used as an infill well.

25. An in situ process for treating a hydrocarbon reservoir having a first steam chamber and a second steam chamber, the second steam chamber generally adjacent to the first steam chamber, the first and second steam chamber having been processed using SAGD or undergoing or being capable of undergoing further SAGD processing and the first steam chamber having an initial pressure lower than a pressure in the second steam chamber, the process comprising:
(a) injecting a non-oxidizing gas through a first injection well in fluid communication with the first steam chamber to form a pressurized non-oxidizing buffer zone between the first and second steam chambers to reduce a fluid flow between the first and second steam chambers; and (b) injecting an oxygen-comprising gas through a second injection well in fluid communication with the first steam chamber to increase a pressure in the first steam chamber relative to the initial pressure.

26. A method for isolating a matured steam chamber from a generally adjacent operating steam chamber comprising:
(a) injecting a non-oxidizing gas at or within a boundary between the matured steam chamber and the adjacent operating steam chamber to form a pressurized non-oxidizing buffer zone between the matured steam chamber and the adjacent operating steam chamber to reduce a fluid flow between the matured steam chamber and the adjacent operating steam chamber; and (b) injecting an oxygen-comprising gas into the matured steam chamber.

27. The method of claim 26 wherein the boundary comprises unproduced hydrocarbons.

28. The method of any one of claims 25 to 27 wherein the oxygen-comprising gas comprises air, oxygen-enriched air, or a combination thereof.

29. The method of claim 28 wherein the oxygen-enriched air comprises a concentration of oxygen above about 21%.

30. The method of any one of claims 25 to 29 wherein the oxygen-comprising gas is wet or dry.

31. The method of any one of claims 25 to 30 wherein the oxygen-comprising gas is injected proximate a lower portion of the reservoir.

32. The method of any one of claims 26 to 31 wherein the injection well was previously used for fluid injection.

33. The method of any one of claims 26 to 31 wherein the injection well was previously used for steam injection.

34. The method of any one of claims 26 to 31 wherein the injection well comprises a well previously used as an infill well.

35. An in situ process for treating a hydrocarbon reservoir, the process comprising:
(a) selecting in the hydrocarbon reservoir a first steam chamber and a second steam chamber generally adjacent to the first steam chamber, the first and second steam chambers having been processed using a thermal recovery process or undergoing or being capable of undergoing further thermal recovery processing, the first and second steam chambers each having a hydrocarbon content and an initial temperature, and the first steam chamber having an initial pressure lower than a pressure in the second steam chamber, (b) selecting a first injection well in fluid communication with the first steam chamber, the first injection well being generally adjacent to the second steam chamber;
(c) selecting a second injection well in fluid communication with the first steam chamber, the second injection well being disposed away from the first injection well;
(d) injecting a non-oxidizing gas through the first injection well to form a pressurized non-oxidizing buffer zone between the first and second steam chambers to reduce a fluid flow between the first and second steam chambers; and (e) injecting an oxygen-comprising gas through the second injection well to increase a pressure in the first steam chamber relative to the initial pressure.

36. The method of claim 35 wherein the first and second injection wells have been previously used for fluid injection.

37. The method of claim 35 wherein the first injection well or the second injection well has been previously used for steam injection.

38. The method of claim 35 wherein the first or the second injection well comprises a well previously used as an infill well.

39. The method of any one of claims 35 to 38 wherein a concentration of oxygen in the oxygen-comprising gas ranges from about 5% to about 100%.

40. The method of any one of claims 35 to 39 wherein the oxygen-comprising gas comprises air, oxygen-enriched air, or a combination thereof

41. The method of claim 40 wherein the oxygen-enriched air comprises a concentration of oxygen above about 21%.

42. The method of any one of claims 35 to 41 wherein the oxygen-comprising gas is wet or dry.

43. The method of any one of claims 35 to 42 wherein the oxygen-comprising gas is injected proximate a lower portion of the reservoir.

44. The method of any one of claims 35 to 43 wherein the first steam chamber is at a later stage of maturity than the second steam chamber.

45. The method of claim 35 to 44 wherein a boundary exists between the first steam chamber and the second steam chamber.

46. The method of claim 45 wherein the boundary comprises unproduced hydrocarbons.

47. The method of any one of claims 35 to 46 wherein a hydrocarbon content of the first steam chamber is lower than a hydrocarbon content of the second steam chamber.

48. The method of any one of claims 35 to 47 further comprising producing hydrocarbons from the first steam chamber, the second steam chamber or both the first and second steam chambers.

49. The method of any one of claims 35 to 48 wherein the non-oxidizing gas is injected proximate a lower portion of the reservoir.

50. The method of any one of claims 35 to 49 wherein the non-oxidizing gas is methane, nitrogen, carbon dioxide, or a combination thereof.

51. The method of any one of claims 35 to 50 wherein the non-oxidizing gas is wet or dry.

52.
The method of any one of claims 35 to 51 wherein the fluid flow comprises a flow of flue gas, a flow of the oxygen-comprising gas, a flow of steam, or a combination thereof.