CA2953352A1

CA2953352A1 - Removal of non-condensing gas from steam chamber with co-injection of steam and convection-enhancing agent

Info

Publication number: CA2953352A1
Application number: CA2953352A
Authority: CA
Inventors: Ishan Deep S. Kochhar; Erin Lamb-Fauquier; Ryan Miller; Brent Donald Seib
Original assignee: Cenovus Energy Inc; Cenovus FCCL Ltd
Current assignee: Cenovus Energy Inc; FCCL Partnership
Priority date: 2015-12-31
Filing date: 2016-12-29
Publication date: 2017-06-30
Anticipated expiration: 2036-12-29
Also published as: CA2953352C

Abstract

In a method of removing non-condensing gases (NCGs) from a steam chamber in steam-assisted processes for hydrocarbon recovery from an oil sands reservoir, the reservoir is serviced by well(s) each configurable as an injection or production well, mediating fluid communication between a surface completion and the reservoir. Steam is injected into the reservoir through a well configured for injection, resulting in formation/expansion of the steam chamber and accumulation of NCGs in the steam chamber. A convection-enhancing agent (CEA) is injected, with steam, into a well for injection to promote convection of gases in the steam chamber so as to assist removal of the NCGs from the steam chamber. Gases are removed from the reservoir through a well configured for production of hydrocarbons drained downward from the steam chamber by gravity. The removed gases include NCGs descended from the steam chamber due to the convection of gases along with CEA.

Description

REMOVAL OF NON-CONDENSING GAS FROM STEAM CHAMBER WITH CO-INJECTION OF STEAM AND CONVECTION-ENHANCING AGENT
FIELD
[0001] The present disclosure relates generally to steam-assisted processes for hydrocarbon recovery and particularly to removal of non-condensing gas from a steam chamber in such a process.
BACKGROUND

[0002] Some subterranean reservoirs (also known as deposits or formations) of viscous hydrocarbons can be extracted in situ by lowering the viscosity of the hydrocarbons to mobilize the hydrocarbons so that they can be moved to, and recovered from, a production well. Such reservoirs may be referred to as reservoirs of heavy hydrocarbons, heavy oil, bitumen, bituminous sands, or oil sands. The in situ processes for recovering oil from oil sands typically involve the use of one or more wells drilled into the reservoir, and can be assisted or aided by injecting a heated fluid such as steam into the reservoir through one or more injection wells. Example processes include steam-assisted gravity drainage (SAGD) processes and cyclic steam stimulation (CSS) processes. In these and other processes, a solvent may also be used to reduce the viscosity of viscous hydrocarbons in the reservoir.

[0003] In a typical SAGD process, a steam injection well and a hydrocarbon production well (forming a well pair) penetrate into a reservoir formation of bituminous sands. Both wells have generally horizontal, perforated terminal sections. A
perforated section may have any type of opening in the wellbore for fluid communication with the reservoir, and may include slotted casing. The horizontal section of the injection well is typically located above the horizontal section of the production well, normally by a few meters. A fluid such as steam is injected into the reservoir through the injection well, to soften bitumen in the reservoir and reduce the viscosity of the bitumen. Heat is transferred from the injected steam to the reservoir formation, which softens the bitumen and results in condensation of steam. The softened bitumen and condensed steam (aqueous condensate) can flow and drain downward due to gravity, thus leaving behind a porous region, which is permeable to gas and steam and is referred to as the steam chamber. Subsequently injected steam rises from the injection well, permeates the steam chamber, and condenses at the edge of the steam chamber (often referred to as the steam chamber front), which is the interface area of the steam chamber and the bitumen in the formation. In the process, more heat is transferred to the bituminous sands and the steam chamber expands over time. Mobilized hydrocarbons and condensate drained downward under gravity are collected by the horizontal section of the production well, from which the hydrocarbons are produced or recovered.
Multiple well pairs may be arranged at a well pad or within the reservoir to form a well pattern.
Additional injection or production wells, such as a well drilled using Wedge WellTM
technology, may also be provided.

[0004] In a typical CSS process, a single well may be used to alternately inject steam into the reservoir and produce a fluid from the reservoir. The alternation may be repeated or cycled, hence known as cyclic steam stimulation. The single well may have a substantially horizontal or vertical section in fluid communication with the reservoir. A steam chamber may also develop in a CSS process.

[0005] In a SAGD or CSS process, as a steam chamber forms and expands, non-condensing gases (NCGs), mainly methane, but which may include other gases such as carbon dioxide or hydrogen sulfide, can be liberated or generated. If not removed, the NCGs will accumulate in the steam chamber. In particular, because the molar mass of methane is slightly less than the molar mass of water (steam), methane tends to rise up and accumulate at the top of the steam chamber. Other aspects of fluid dynamics in the steam-assisted process can also influence NCG movement in the steam chamber. For example, as injected steam migrates from the injection well towards the steam chamber front, the steam can in effect drag NCGs with it.
When steam transfers heat to the bitumen and condenses, which mainly occurs near the steam chamber front, the volume or partial pressure of steam is significantly reduced.
NGCs generally have higher vapour pressures, as compared to steam, at lower temperatures. These, and various other factors, contribute to creation of a region near the steam chamber front that draws and retains NCGs and the accumulation of NCGs at the steam chamber front.

[0006] NCGs accumulated in the steam chamber can be beneficial. For example, US Patent No. 8,596,357 teaches adding NCGs to injected steam, to increase accumulation of NCGs at the top of the steam chamber.

[0007] Accumulation of NCGs at the steam chamber front can also present challenges. For example, the accumulated NCGs may form a "blanket" and act as an insulator, which reduces or prevents heat transfer from steam to the bitumen at the steam chamber front. The accumulation of NCGs can also result in a lower partial pressure of steam at the steam chamber front, and a lower steam saturation temperature, thus limiting lateral growth of the steam chamber.

[0008] In principle, removal of NCGs from the steam chamber is expected to improve heat transfer efficiency and reduce the amount of steam required to expand the steam chamber. However, in practice, it has been found to be challenging to remove NCGs without incurring substantial equipment and operation costs and to achieve an overall lower steam to oil ratio (SOR) or cumulative SOR (CSOR) for the production process.

[0009] As is well known, SOR (or CSOR) is a benchmark metric for production efficiency and performance, as a lower SOR/CSOR generally indicates a more cost-effective oil production process. Some positive effects of a lower SOR/CSOR
include, as graphically illustrated in FIG. 16, reduced water usage for generating steam, reduced greenhouse gas GHG) emissions, smaller footprint of surface production facilities, lower capital expenditures (CAPEX), and increased overall revenue.

[0010] However, in a conventional SAGD operation, for example, it may be difficult to remove NCGs through a production well located at the bottom of the steam chamber. A number of potential problems can arise from attempting to remove NCGs from the reservoir by producing the NCGs through the production well. As an example, one proposed technique for moving NCGs downward into the production well is to apply sufficient fluid drawdown to drive the NCGs towards the production well, but such fluid drawdown often also moves a steam phase, or a hot water phase, with the NCG phase towards the production well. Hot water can flash to steam when it approaches the bottom of the steam chamber or the production well, as in the vicinity of the production well the pressure is typically lower and the temperature is typically higher. In any event, a large amount of steam may be produced through the production well, which is undesirable as this would increase the steam to oil ratio (SOR) for the production process.

[0011] Challenges thus remain in connection with removal of NCGs from steam chambers to decrease the overall SOR.
SUMMARY

[0012] Accordingly, in an aspect of the present disclosure, there is provided a method of removing non-condensing gas present in a steam chamber in a steam-assisted process for hydrocarbon recovery from an oil sands reservoir, wherein the reservoir is serviced by one or more wells each configurable as an injection well, a production well, or both an injection well and a production well, and wherein each of the one or more wells mediates fluid communication between a surface completion and the reservoir, and wherein steam is injected into the reservoir through at least one of the one or more wells configured for injection, resulting in formation and expansion of the steam chamber and accumulation of the non-condensing gas in the steam chamber. The method comprises injecting a convection-enhancing agent with steam into the at least one of the one or more wells configured for injection, to promote convection of gases in the steam chamber so as to assist removal of the non-condensing gas from the steam chamber; removing gases from the reservoir through at least one of the one or more wells configured for production of hydrocarbons conveyed downward from the steam chamber wherein the removed gases comprise the non-condensing gas descended from the steam chamber resulting from the convection of gases.

[0013] In selected embodiments, the one or more wells may comprise a well pair of an injection well and a production well. The one or more wells may comprise a single well configurable for either injection or production, and the method may comprise alternately injecting steam with the convection-enhancing agent into the steam chamber through the single well and producing a fluid and gases from the reservoir through the single well. The one or more wells may comprise a well that is configurable for injection or production. The one or more wells may comprise a well having a substantially horizontal terminal section in fluid communication with the reservoir. The one or more wells may comprise a well having a substantially vertical section in fluid communication with the reservoir. The steam-assisted process may be a steam-assisted gravity drainage (SAGD) process, or a cyclic steam stimulation (CSS) process. A mixture of the convection-enhancing agent and steam may be injected into the at least one well for injection, and wherein a temperature in the steam chamber is from about 152 C to about 286 C and a pressure in the steam chamber is from about 0.5 MPa to about 7 MPa. A temperature in the reservoir may be from about 234 C to about 328 C and a pressure in the reservoir may be from about 3 MPa to about 12.5 MPa. The convection-enhancing agent may be 0.1% to 10% of the steam by weight in the mixture, such as 1% to 3%, 1% to 5%, 3% to 5%, 3% to 8%, or 5% to 8%. The non-condensing gas may comprise methane, a carbon oxide such as carbon dioxide or carbon monoxide, a nitrogen oxide such as nitrogen dioxide, a sulfur oxide such as sulfur dioxide, hydrogen sulfide, or a combination thereof. The non-condensing gas may comprise methane. The convection-enhancing agent may be selected to increase a gas phase density in the steam chamber. The convection-enhancing agent may comprise an organic molecule having a moderate volatility such that a sufficient proportion of the convection-enhancing agent injected into the steam chamber can remain in the gas phase in the steam chamber for a sufficient period to ascend to a steam chamber front and to induce the convection of gases in the steam chamber, and can thereafter condense along the steam chamber front. Increasing gas phase density in the steam chamber may direct the non-condensing gas away from the front of the steam chamber and towards at least one of the one or more wells configured for production to remove the non-condensing gas. The method may comprise directing the non-condensing gas towards at least one of the one or more wells configured for production to inhibit steam loss, oil loss, or both steam loss and oil loss to a thief zone in the reservoir, wherein a thief zone is bottom water, a gas cap, or both bottom water and a gas cap. The convection-enhancing agent may comprise at least one of propane and butane. The organic molecule may comprise a non-polar molecule. The molar mass of the non-polar organic molecule may be from about g/mol to about 60 g/mol. The organic molecule may comprise a polar molecule.
The molar mass of the polar organic molecule may be from about 30 g/mol to about g/mol. The polar organic molecule may comprise formaldehyde. A molar mass of the convection-enhancing agent may be higher than a molar mass of the non-condensing gas. The convection-enhancing agent may be more volatile than water. The convection-enhancing agent may be more soluble in oil than in water.

[0014] In some selected embodiments, injection of the convection-enhancing agent may commence before the steam chamber has formed, or when hydrocarbon production from the reservoir through the one or more wells has commenced. In some selected embodiments, injection of the convection-enhancing agent may commence after the steam chamber has formed, or after a period of hydrocarbon production from the reservoir through the one or more wells. The period of hydrocarbon production may be about 12 months. Injection of the convection-enhancing agent may terminate after the steam chamber has coalesced with an adjacent steam chamber.
Injection of the convection-enhancing agent may terminate after about 36 months of hydrocarbon production from the reservoir through the one or more wells. The weight percentage of the convection-enhancing agent in the mixture may increase or decrease over time during injection of the convection-enhancing agent. The weight percentage of the convection-enhancing agent in the mixture may increase over time during injection of the convection-enhancing agent by 1 wt% to 3 wt%.

[0015] Other aspects, features, and embodiments of the present invention will become apparent to those of ordinary skill in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS

[0016] In the figures, which illustrate, by way of example only, embodiments of the present invention:

[0017] FIG. 1 is a schematic diagram illustrating a steam-assisted gravity drainage (SAGD) arrangement, according to an embodiment of the disclosure;

[0018] FIG. 2 is a three-dimensional (3D) graph showing simulation results of steam chamber development in the reservoir along the length of the well in the x-z plane after 2.1 years of SAGD operation;

[0019] FIG. 3 is a 3D graph showing simulation results of methane distribution in the reservoir after 2.1 years of SAGD operation;

[0020] FIG. 4 is a 3D graph showing simulation results of methane distribution in the reservoir after 4.7 years of SAGD operation;

[0021] FIG. 5A is a 3D graph showing simulation results of methane distribution in the reservoir after 4.9 years of SAGD operation;

[0022] FIG. 5B is a 3D graph showing simulation results of methane distribution in the reservoir after 4.9 years of SAGD operation with injection of propane at 5 wt% of steam;

[0023] FIG. 6 is a line graph showing simulation results of bitumen production rates over time for various butane and/or propane injection compositions;

[0024] FIG. 7 is a line graph showing simulation results of bitumen recovery factor over time for different injection compositions;

[0025] FIG. 8 is a line graph showing simulation results of methane removal rates over time for different injection compositions;

[0026] FIG. 9 is a line graph showing simulation results of methane removal factor over time for different injection compositions;

[0027] FIG. 10 is a line graph showing simulation results of cumulative steam to oil ratio (CSOR) over time for different injection compositions;

[0028] FIG. 11 is a line graph showing simulation results of bitumen production rates over time for various polar and non-polar injection compositions;

[0029] FIG. 12 is a line graph showing simulation results of bitumen recovery factor over time for injection of the different compositions of FIG. 11;

[0030] FIG. 13 is a line graph showing simulation results of methane removal rates over time for injection of the different compositions of FIG. 11;

[0031] FIG. 14 is a line graph showing simulation results of methane removal factor over time for injection of the different compositions of FIG. 11;

[0032] FIG. 15 is a line graph showing simulation results of CSOR over time for injection of the different compositions of FIG. 11;

[0033] FIG. 16 is a diagram illustrating the benefits of decreased SOR;

[0034] FIG. 17A is a two-dimensional (2D) simulated representation of a SAGD
steam chamber;

[0035] FIG. 17B is a 2D simulated representation of NCG distribution at the edges of the steam chamber of FIG. 17A;

[0036] FIG. 17C is a 2D simulated representation of a SAGD with convection-enhancing agent steam chamber;

[0037] FIG. 17D is a 2D simulated representation of NCG distribution in the steam chamber of FIG. 17C;

[0038] FIG. 17E is a 2D simulated representation of convection-enhancing agent distribution in the steam chamber of FIG. 17C;

[0039] FIG. 18 is a line graph showing simulation results of CSOR as a function of methane removal factor;

[0040] FIG. 19 is a line graph showing simulation results of CSOR as a function of bitumen recovery factor.

[0041] FIG. 20 is a line graph showing simulation results of CSOR as a function of bitumen recovery factor for various propane injection compositions with injection starting after 365 days of SAGD operation;

[0042] FIG. 21 is a line graph showing simulation results of CSOR as a function of methane recovery factor for various propane injection compositions with injection starting after 365 days of SAGD operation;

[0043] FIG. 22 is a line graph showing simulation results of bitumen recovery factor over time for various propane injection compositions with injection starting after 365 days of SAGD operation;

[0044] FIG. 23 is a line graph showing simulation results of methane removal factor over time for various propane injection compositions with injection starting after 365 days of SAGD operation;

[0045] FIG. 24A is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 365 days of SAGD operation;

[0046] FIG. 24B is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 450 days of SAGD operation;

[0047] FIG. 24C is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 550 days of SAGD operation;

[0048] FIG. 24D is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 650 days of SAGD operation;

[0049] FIG. 24E is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 730 days of SAGD operation;

[0050] FIG. 24F is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 1,096 days of SAGD operation;

[0051] FIG. 25A is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 450 days of SAGD operation including 85 days with injection of propane at 3 wt% of steam;

[0052] FIG. 25B is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 550 days of SAGD operation including 185 days with injection of propane at 3 wt% of steam;

[0053] FIG. 25C is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 650 days of SAGD operation including 285 days with injection of propane at 3 wt% of steam;

[0054] FIG. 25D is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 730 days of SAGD operation including 365 days with injection of propane at 3 wt% of steam;

[0055] FIG. 25E is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 1,096 days of SAGD operation including 730 days with injection of propane at 3 wt%
of steam;

[0056] FIG. 26A is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 450 days of SAGD operation including 85 days with injection of propane at 5 wt% of steam;

[0057] FIG. 26B is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 550 days of SAGD operation including 185 days with injection of propane at 5 wt% of steam;

[0058] FIG. 26C is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 650 days of SAGD operation including 285 days with injection of propane at 5 wt% of steam;

[0059] FIG. 26D is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 730 days of SAGD operation including 365 days with injection of propane at 5 wt% of steam;

[0060] FIG. 26E is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 1,096 days of SAGD operation including 730 days with injection of propane at 5 wt%
of steam;

[0061] FIG. 27A is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 450 days of SAGD operation including 85 days with injection of propane at 10 wt% of steam;

[0062] FIG. 27B is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 550 days of SAGD operation including 185 days with injection of propane at 10 wt% of steam;

[0063] FIG. 27C is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 650 days of SAGD operation including 285 days with injection of propane at 10 wt% of steam;

[0064] FIG. 27D is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 730 days of SAGD operation including 365 days with injection of propane at 10 wt% of steam;

[0065] FIG. 27E is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the x-z plane after 1,096 days of SAGD operation including 730 days with injection of propane at 10 wt%
of steam;

[0066] FIG. 28A is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 365 days of SAGD operation;

[0067] FIG. 28B is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 450 days of SAGD operation;

[0068] FIG. 28C is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 550 days of SAGD operation;

[0069] FIG. 28D is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 650 days of SAGD operation;

[0070] FIG. 28E is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 730 days of SAGD operation;

[0071] FIG. 28F is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 1,096 days of SAGD operation;

[0072] FIG. 29A is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 450 days of SAGD operation including 85 days with injection of propane at 3 wt% of steam;

[0073] FIG. 29B is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 550 days of SAGD operation including 185 days with injection of propane at 3 wt% of steam;

[0074] FIG. 29C is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 650 days of SAGD operation including 285 days with injection of propane at 3 wt% of steam;

[0075] FIG. 29D is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 730 days of SAGD operation including 365 days with injection of propane at 3 wt% of steam;

[0076] FIG. 29E is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 1,096 days of SAGD operation including 730 days with injection of propane at 3 wt%
of steam;

[0077] FIG. 30A is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 450 days of SAGD operation including 85 days with injection of propane at 5 wt% of steam;

[0078] FIG. 30B is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 550 days of SAGD operation including 185 days with injection of propane at 5 wt% of steam;

[0079] FIG. 30C is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 650 days of SAGD operation including 285 days with injection of propane at 5 wt% of steam;

[0080] FIG. 30D is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 730 days of SAGD operation including 365 days with injection of propane at 5 wt% of steam;

[0081] FIG. 30E is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 1,096 days of SAGD operation including 730 days with injection of propane at 5 wt%
of steam;

[0082] FIG. 31A is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 450 days of SAGD operation including 85 days with injection of propane at 10 wt% of steam;

[0083] FIG. 31B is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 550 days of SAGD operation including 185 days with injection of propane at 10 wt% of steam;

[0084] FIG. 31C is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 650 days of SAGD operation including 285 days with injection of propane at 10 wt% of steam;

[0085] FIG. 31D is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 730 days of SAGD operation including 365 days with injection of propane at 10 wt% of steam;

[0086] FIG. 31E is a 3D graph showing simulation results of methane distribution in the reservoir along the length of the well in the y-z plane after 1,096 days of SAGD operation including 730 days with injection of propane at 10 wt%
of steam;

[0087] FIG. 32 is a line graph showing simulation results of bitumen production rates over time for various propane injection compositions with injection at the start of a SAGD operation;

[0088] FIG. 33 is a line graph showing simulation results of bitumen recovery factor over time for various propane injection compositions with injection at the start of a SAGD operation;

[0089] FIG. 34 is a line graph showing simulation results of methane production rates over time for various propane injection compositions with injection at the start of a SAGD operation;

[0090] FIG. 35 is a line graph showing simulation results of methane removal factor over time for various propane injection compositions with injection at the start of a SAGD operation;

[0091] FIG. 36 is a line graph showing simulation results of CSOR as a function of bitumen recovery factor for various propane injection compositions with injection at the start of a SAGD operation; and

[0092] FIG. 37 is a line graph showing simulation results of CSOR as a function of methane removal factor for various propane injection compositions with injection at the start of a SAGD operation.

[0093]

DETAILED DESCRIPTION

[0094] In brief overview, it has now been recognized that co-injecting a small amount of a convection-enhancing agent (CEA) with steam into a steam chamber can assist removal of non-condensing gases (NCGs) from the steam chamber and significantly lower steam to oil ratio (SOR). The injected CEA is heated by steam and can travel or rise up to the steam front with steam. The CEA, being more volatile than steam, progresses ahead of the steam front and comes into contact with NCGs, which promotes convection of gases in the steam chamber and along the length of, for example, the horizontal section of a SAGD well pair, and particularly the descending gas flow from the steam chamber front. Without being limited to theory, the descending gas flow may carry or drag NCGs towards the bottom of the steam chamber. Thus, the NCGs can be conveniently removed from the steam chamber through an existing production well positioned at or near the bottom of the steam chamber. With careful selection of the convection-enhancing agent, the rate of NCG removal and reduction in SOR can be optimized. In the context of the present disclosure, convection of gases or convection flow of gases refer to the conveying or transport of gases. A
suitable convection-enhancing agent increases the gas phase density in the steam chamber, resulting in descending gas flow towards a production well for removal of NCGs from the steam chamber.

[0095] It has also been recognized that a number of factors are expected to impact the performance and economics of such a NCG removal technique.

[0096] One of such factors is the molar mass of the CEA. To provide effective or optimal NCG removal, the molar mass of the CEA should be higher than the molar mass of the NCG to be removed, but not too high. If the CEA is too light, it is expected to tend to remain above the NCG layer in the steam chamber and will not be effective for promoting convection of gases towards the bottom of the steam chamber. If the CEA is too heavy, it would be difficult for the injected CEA to rise up in the steam chamber to reach the steam front. In other words, when the CEA has a higher molar mass than steam and the NCG and is added to the gas phase in the steam chamber, the gas phase density is increased and the gas phase tends to descend, which helps removal of the NCG. However, the density factor needs to be balanced with other factors such as the volatility. For example, heavier organic molecules tend to be less volatile, and if a compound being injected is too heavy it may be less effective as a CEA for removing NCGs (see discussion below).

[0097] Another factor that should be considered when selecting the CEA is the volatility of the CEA at reservoir conditions. The volatility of the CEA in the steam chamber should be moderate such that CEA can remain in the gas phase (as a vapour) in the steam chamber. It is however beneficial if the CEA is not too volatile so that a substantial portion of the CEA can eventually condense in the steam chamber and dissolve in oil, which will conveniently have the effect of lowering the viscosity of the liquid phase in the steam chamber.

[0098] It is desirable that the CEA is more soluble in oil than in water.

[0099] Generally, it is expected that the vapour pressure of a suitable CEA is lower than the vapour pressure of water at the same temperature. Organic compounds with such low vapour pressures include ethane, propane, butane, pentane, hexane, or the like. However, it is noted that pentane and hexane have relatively high molar mass and low volatility. Therefore, these may be less effective for removing NCGs, as compared to the other lighter alkanes.

[00100] Simulation results show that butane and propane can meet the above criteria, and are suitable for use as CEAs in some applications to remove, e.g., methane, from the steam chamber. It is expected other alkanes or hydrocarbon solvents with 2 to 5 carbon atoms may also be suitable for removing methane, if they have molar masses, volatilities and oil solubilities comparable to those of butane and propane.

[00101] A liquefied petroleum gas (LPG) is a by-product of petroleum or natural gas refining and contains a mixture of hydrocarbon gases including propane and butane. In some embodiments, LPG may be used as a CEA. In different embodiments, one or more components of LPG may be separated or extracted from the mixture and be used as a CEA. Advantageously, using LPG or its components as a CEA may improve the efficiency of, or reduce the costs of, NCG removal in a steam-assisted process for hydrocarbon recovery.

[00102] However, hydrocarbon molecules with 6 or more carbon atoms are less likely to be suitable candidates for the CEA as such hydrocarbon molecules tend to have low volatility and are expected to dissolve in oil. Methane is itself a NCG and is thus not suitable for use as CEA in the present context.

[00103] A suitable CEA may have a molar mass from about 30 g/mol to about g/mol.

[00104] A further factor that can affect the performance and economics of NCG
removal is the amount of CEA injected into the steam chamber. A lower amount would mean lower cost and less post-production processing or treatment. In this regard, it is expected that compounds with lower molar masses are typically less expensive, and co-injecting a low concentration of CEA may only require limited, if any, surface processing or CEA recovery or recycling.

[00105] Computer model simulation results indicated that a small amount of the CEA would be sufficient to achieve effective removal of methane from a steam chamber in a typical steam-assisted gravity drainage (SAGD) process. Effective removal of NCGs such as methane may be achieved when steam and CEA are co-injected and the CEA in the injection stream is from about 0.1 % to about 10%
of steam by weight (i.e. about 0.1 wt% to about 10 wt%), such as about 1 wt% to about 5 wt%. It is expected that injection of about 1 wt% to about 3 wt% of CEA, for example, propane, with steam would be sufficient to significantly increase the rate of NCG
removal and can be implemented economically at an existing SAGD operation site.

[00106] Computer model simulation results also indicated that for NCG
removal, about 1 wt% of CEA (such as propane or butane) co-injection can be effective in some tested formation conditions, for example, achieving as high as about 29%
incremental NCG removal compared to a baseline case of SAGD. Increasing the CEA
concentration to above about 5 to 8 wt% may not further substantially improve overall NCG removal or allow for NCG removal at an economical cost under at least some formation and operation conditions, although the overall oil recovery and NCG
removal rate can still increase. Thus, for NCG removal, co-injection of CEA at about 1 to 3 wt%, about 3 to 5 wt%, or about 5 to 8 wt% may be effective and economical.

[00107] In comparison, a typical conventional solvent aided process (SAP) often involves injection of a solvent at much higher concentrations or ratios, such as above 20 wt% of steam, to achieve significant and economical reduction in SOR or CSOR.

[00108] Computer model simulation results also indicated that at low concentrations of CEA, such as about 1 to 3 wt%, about 3 to 5 wt%, or about 5 to 8 wt%, the effect of CEA co-injection and NCG removal after merging (also known as coalescence) of the steam chambers of adjacent SAGD well pairs may be significantly reduced. Thus, it may be more economical to terminate CEA co-injection once the steam chambers have coalesced. For example, depending on the nature of the reservoir formation and its conditions, steam chambers of SAGD well pairs that are spaced apart by about 100 m may coalesce after about 3 years of hydrocarbon (oil) production. In such cases, CEA co-injection may terminate after about 3 years of hydrocarbon production. Other well spacing may be suitable, for example, about m between SAGD well pairs.

[00109] Without being limited to any particular theory, it is expected that a low amount (e.g. about 1 to 8 wt%) of CEA co-injection is more or most effective during early stages of oil production as NCG removal during this period is expected to significantly improve steam chamber conformance, as compared to only steam injection. As can be understood by those skilled in the art, better or improved steam chamber conformance can improve hydrocarbon production performance, such as improved oil recovery rates or overall oil recovery factors (oil uplift).

[00110] Further, test results indicated that, while co-injection of CEA at about 1 wt% to about 8 wt% may be effective for NCG removal, CEA co-injection at the range of about 3 wt% to about 5 wt% can also improve hydrocarbon/oil production, and CEA
co-injection at the higher end of the range, e.g., about 5 wt% to about 8 wt%, can further significantly improve instantaneous steam to oil ration (ISOR) or CSOR
of the hydrocarbon recovery operation.

[00111] Without being limited to any specific theory, it is expected that the increased performance at higher co-injection concentrations of CEA may be due to reduction in bitumen fluid viscosity as the CEA condenses and dissolves in the formation fluid phase, particularly at the steam front. Further, it is expected that at lower concentrations of CEA co-injection, the main effect of the injected CEA
may be NCG removal, which may require additional steam to fill the void space remaining as NCGs are removed, and may result in faster steam chamber growth and a higher oil production rate. As the concentration of co-injected CEA is increased, more and more CEA may condense and dissolve in or mix with the formation fluid to improve bitumen mobility or viscosity, thus leading to increased oil production and, eventually, reduced ISOR or CSOR.

[00112] Even if the CSOR is not reduced, maintaining the level of CSOR
over a longer period of time would still provide a benefit as this would extend the economical period of oil production, resulting in increased overall production (bitumen recovery factor) for a given reservoir.

[00113] As can be understood by those skilled in the art, in practice, the weight percentage of an injected material such as CEA may be measured and controlled within a certain tolerance, in part because the measurement and control of the injection rate does not need to be absolutely precise, which is also not always impractical. For example, it may be sufficient that, at 1 wt% CEA, the error tolerance can be about 5%. That is, for a stated injection concentration of 1 wt%, the actual measured injection concentration may vary between 0.95 wt% to 1.05 wt%.

[00114] The amount of co-injected CEA may vary during injection. For example, the weight percentage of the co-injected CEA in the injection mixture may increase during injection, such as by about 1 to 3 wt%. In an embodiment, the initial weight percentage may be about 3 wt% and may be increased to 4 or 5 wt% by continual increase or by stepwise increments. In another embodiment, the initial weight percentage of CEA may be increased by a greater amount, for example, from about 3 wt% to about 8 wt%. Of course, in some embodiments, the weight percentage of the co-injected CEA in the injection mixture may also decrease or fluctuate during co-injection.
[001151 In selected embodiments, steam may be injected at a temperature from about 100 C to about 330 C and a pressure from about 0.1 MPa to about 12.8 MPa.
The steam may be injected through an injection well, and the fluid may be produced through a production well. The injection well and the production well may have terminal sections that are substantially horizontal, the substantially horizontal sections of the wells being substantially parallel. The substantially horizontal sections of the wells may be vertically spaced apart. The injection well and the production well may form a well pair for a steam-assisted gravity drainage (SAGD) process. A steam chamber may be formed in the reservoir due to steam injection, and a temperature in the steam chamber may be from about 152 C to about 286 C and a pressure in the steam chamber may be from about 0.5 MPa to about 7 MPa. A single well may be used to alternately inject steam into the reservoir and produce the fluid from the reservoir. The single well may have a substantially horizontal or vertical section in fluid communication with the reservoir. The single well may be used in a cyclic steam recovery process. With the use of the single well for injection and production, a temperature in the reservoir may be about 234 C to about 328 C and a pressure in the reservoir may be from about 0.5 MPa or about 3.0 MPa to about 12.5 MPa.
[00116] Embodiments disclosed herein relate to a method of hydrocarbon recovery from a reservoir of bituminous sands assisted by injection of steam and a convection-enhancing agent into the reservoir. Steam is injected into the reservoir to mobilize or liquefy the native bitumen therein, thus forming a fluid containing hydrocarbons and water (including aqueous condensate), which can be produced from the reservoir by an in-situ recovery process, such as steam-assisted gravity drainage (SAGD), or a cyclic steam recovery process such as cyclic steam stimulation (CSS).

As will be further detailed below, when steam is injected into the reservoir to heat the reservoir formation, non-condensing gases (NCGs) are liberated within the reservoir and can impede heat transfer from the steam to the bitumen. In various embodiments, the convection-enhancing agent is co-injected with steam to assist removal of the NCGs from the reservoir to permit more effective heat transfer from the steam to the bitumen. Advantageously, the convection-enhancing agent may also eventually dissolve in the oleic phase in the reservoir, thus enhancing mobility of the oleic phase in the reservoir by reducing the viscosity, which can result in increased liquid flow rate.
[00117] In various embodiments of the invention, the term "reservoir"
refers to a subterranean or underground formation comprising recoverable oil (hydrocarbons);
and the term "reservoir of bituminous sands" refers to such a formation wherein at least some of the hydrocarbons are viscous and immobile and are disposed between or attached to sands.
[00118] In various embodiments of the invention, the terms "oil", "hydrocarbons"
or "hydrocarbon" relate to mixtures of varying compositions comprising hydrocarbons in the gaseous, liquid or solid states, which may be in combination with other fluids (liquids and gases) that are not hydrocarbons. For example, "heavy oil", "extra heavy oil", and "bitumen" refer to hydrocarbons occurring in semi-solid or solid form and having a viscosity in the range of about 1,000 to over 1,000,000 centipoise (mPa.s or cP) measured at original in-situ reservoir temperature. In this specification, the terms "hydrocarbons", "heavy oil", "oil" and "bitumen" are used interchangeably.
Depending on the in-situ density and viscosity of the hydrocarbons, the hydrocarbons may comprise, for example, a combination of heavy oil, extra heavy oil and bitumen. Heavy crude oil, for example, may be defined as any liquid petroleum hydrocarbon having an American Petroleum Institute (API) Gravity of less than about 20 and a viscosity greater than 1,000 mPa.s. Oil may be defined, for example, as hydrocarbons mobile at typical reservoir conditions. Extra heavy oil, for example, may be defined as having a viscosity of over 10,000 mPa-s and about 100 API Gravity. The API Gravity of bitumen ranges from about 12 to about 7 and the viscosity is greater than about 1,000,000 mPa.s. Native bitumen is generally non-mobile at native reservoir conditions.

[00119] A person skilled in the art will appreciate that an immobile formation or reservoir at initial (or original) conditions (e.g., temperature or viscosity) means that the reservoir has not been treated with heat or other means. Instead, it is in its original condition, prior to the recovery of hydrocarbons. Immobile formation means that the formation has not been mobilized through the addition of heat or other means.
The hydrocarbons in a reservoir of bituminous sands occur in a complex mixture comprising interactions between sand particles, fines (e.g., clay), and water (e.g., interstitial water) which may form complex emulsions during processing. The hydrocarbons derived from bituminous sands may contain other contaminant inorganic, organic or organometallic species which may be dissolved, dispersed or bound within suspended solid or liquid material. Accordingly, it remains challenging to separate hydrocarbons from the bituminous sands in-situ, which may impede production performance of the in-situ process.
[00120] Production performance may be improved when a higher amount of oil is produced within a given period of time, or with a given amount of injected steam depending on the particular recovery technique used, or within the lifetime of a given production well (overall recovery), or in some other manner as can be understood by those skilled in the art. For example, production performance may be improved by increasing the amount of hydrocarbons recovered within the steam chamber, increasing drainage rate of the fluid or hydrocarbon from the steam chamber to the production well, or both.
[00121] Faster oil flow or drainage rates can lead to more efficient oil production, and the increase in the flow or drainage rate of reservoir fluids within the formation can be indirectly indicated or measured by the increase in the rate of oil production.
Techniques for measurement of oil production rates have been well developed and are known to those skilled in the art.
[00122] Conveniently, an embodiment disclosed herein can improve production performance.

[00123] The convection-enhancing agent may be used in various in-situ thermal recovery processes, such as SAGD or CSS, where steam is used and a steam chamber has been developed. Selected embodiments disclosed herein may be applicable to an existing hydrocarbon recovery process, such as after the hydrocarbon production rate in the recovery process has peaked.
[00124] For example, the technique disclosed herein may be employed in typical SAGD processes, such as those disclosed in Canadian Patent No. 1,130,201 issued on 24 August 1982. In an example of SAGD, two wells are drilled into the reservoir, one for injection of steam and one for production of oil and water. Steam is injected via the injection well to heat the formation. The steam condenses and gives up its latent heat to the formation, heating a layer of viscous hydrocarbons. The viscous hydrocarbons are thereby mobilized, and drain by gravity toward the production well with the condensed steam. In this way, the injected steam initially mobilizes the in-place hydrocarbon to create the "steam chamber" in the reservoir around and above the horizontal injection well. The term "steam chamber" may accordingly refer to any volume of the reservoir which is filled with, or saturated with, injected steam and from which mobilized oil has at least partially drained. Mobilized viscous hydrocarbons are recovered continuously through the production well. The conditions of steam injection and of hydrocarbon production may be modulated to control the growth of the steam chamber, to ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilized hydrocarbons.
[00125] The start-up stage of the SAGD process establishes thermal or hydraulic communication, or both, between the injection and production wells. At initial reservoir conditions, there is typically negligible fluid mobility between wells due to high bitumen viscosity. Communication is achieved when bitumen between the injector and producer is mobilized to allow for bitumen production (also referred to as bitumen recovery). A conventional start-up process involves establishing interwell communication by simultaneously circulating steam through each injector well and producer well. High-temperature steam flows through a tubing string that extends to the toe of each horizontal well. The steam condenses in the well, releasing heat and resulting in a liquid water phase which flows back up the casing-tubing annulus.
Alternative start-up techniques involve creating a high mobility inter-well path by the use of solvents or by application of pressures so as to dilate the reservoir sand matrix.
[00126] In the ramp-up stage of the SAGD process, after communication has been established between the injection and production wells during start-up (usually over a limited section of the well pair length), production begins from the production well. Steam is continuously injected into the injection well (usually at constant pressure) while mobilized bitumen and water are continuously removed from the production well (usually at constant temperature). During this period the zone of communication between the wells is expanded axially along the full well pair length and the steam chamber grows vertically up to the top of the reservoir. The reservoir top may be a thick shale (overburden) or some lower permeability facies that causes the steam chamber to stop rising. When the interwell region over the entire length of the well pair has been heated and the steam chamber that develops has reached the reservoir top, the bitumen production rate typically peaks and begins to decline while the steam injection rate reaches a maximum and levels off.
[00127] In conventional SAGD, after ramp-up, in an operational phase of production, the steam chamber has generally achieved full height (although it is typically still rising slowly through or spreading around lower permeability zones in some locations) and lateral or radial growth of the steam chamber along the longitudinal axis of the well pair becomes the dominant mechanism for recovering bitumen. Typically steam injection at the injector well is controlled so as to maintain a target steam chamber pressure during this phase. As the reservoir fluids drain to the production well, fluid withdrawal rates are controlled to ensure the well remains submerged in bitumen and aqueous condensate. Submergence prevents the steam that overlies the liquid zone from breaking through to the production well, which can short-circuit the SAGD process and potentially damage the wellbore. Moreover, this can lead to higher SOR and less efficient bitumen recovery. In certain instances, submergence is not achieved along the entire of length of the wellbore. This may be due to reservoir heterogeneity, such as pay, permeability or saturation differences, and wellbore hydraulic issues imposed by the trajectory or completion design.
[00128] A person of skill in the art would appreciate that different well completions (also called a completion design) may be utilized to achieve similar results. Well completions in an injection well, a production well, or both an injection well and a production well may be modified one or more times during the lifetime of a well to improve aspects such as, but not limited to, steam chamber conformance along the length of a well (or well pair), NCG production rate, or oil production rate.
[00129] As discussed above, a concomitant feature of a thermal recovery process applied to oil sands is that non-condensing (or non-condensable) gases are evolved and created. Non-condensing gases (NCGs) refer to gaseous substances with relatively low condensation (boiling) points. As examples, under standard conditions methane condenses at -161 C and nitrogen condenses at -196 C. NCGs include, but are not limited to air, nitrogen, nitrogen oxides such as nitrogen dioxide, carbon monoxide, carbon dioxide, hydrogen sulfide, sulfur oxides such as sulfur dioxide, methane, and other light hydrocarbons.
[00130] In a typical implementation of SAGD, there are a number of sources of NCGs within the steam chamber. One source is the evolution of solution gas dissolved in the bitumen. As the bitumen is heated, the solubility of the gas decreases as it becomes energized, resulting in its evolution from the bitumen into the steam chamber. A second major source involves the production of NCGs from reactions taking place between water and organic compounds at elevated temperatures and pressures. This process can for example include bitumen thermal cracking at elevated temperatures or low temperature oxidation. Other minor sources of NCGs may include the co-injection of gases with steam, for example as may be undertaken in order to prevent steam hammer or for the purpose of using the NCGs to facilitate measurements of the steam chamber pressure.
[00131] As explained above, NCGs tend to have low molar masses and therefore tend to be light and buoyant. As a result, any NCG that is liberated or generated lower in the steam chamber will tend to rise to a higher part of the steam chamber, and any NCG produced or released higher in the steam chamber will tend to remain in the upper elevations of the steam chamber.
[00132] As steam is continuously injected and flows outwardly toward the bituminous sands where it condenses, the steam effectively drags the NCGs with it.
The NCGs generally having much greater vapour pressures compared to steam at lower temperatures, and being non-condensing, tend to accumulate at the steam front along the steam chamber perimeters or walls. Over time, this accumulation of NCGs results in the formation of an insulating layer or blanket at the top of the steam chamber, reducing efficient contact between the hot steam and the colder bitumen surface. The insulating layer thus provides resistance to heat flow from steam to reservoir, impeding steam chamber expansion and ultimately jeopardizing production performance of the in-situ process.
[00133] FIG. 1 schematically illustrates a typical SAGD arrangement 100 in a reservoir 112 of bituminous sands. SAGD arrangement 100 includes a well pair, injection well 118 and production well 120. It can be understood that reservoir 112 is serviced by injection well 118 and production well 120, which mediate fluid communication between reservoir 112 and a surface completion.
[00134] In a typical SAGD operation, fluid communication between injection well 118 and production well 120 is established (known as the start-up stage) before normal oil production begins. During oil production, in cases where only steam is used, steam is injected into reservoir 112 through injection well 118. The injected steam heats up the reservoir formation, softens or mobilizes the bitumen in a region in the reservoir 112 and lowers bitumen viscosity such that the mobilized bitumen can flow.
As heat is transferred to the bituminous sands, steam condenses and a fluid mixture containing aqueous condensate and mobilized bitumen (oil) forms. The fluid mixture drains downward due to gravity, and a porous region 130, referred to as the "steam chamber," is formed in reservoir 112.

[00135] In an embodiment as illustrated in FIG. 1, a convection-enhancing agent 124 is co-injected with steam 116 into steam chamber 130 through injection well 118.
The injected steam 116 mobilizes the bitumen in reservoir 112. As a result, a reservoir fluid 114 comprising oil 122 and condensed steam (water) is formed in steam chamber 130. In selected embodiments, at least a portion of the condensed CEA 124 may dissolve in the reservoir fluid 114, which may also assist in mobilizing the bitumen.
Fluid 114 is drained by gravity along the edge of steam chamber 130 into production well 120 for recovery of oil 122.
[00136] The CEA 124 may be in the form of a solid, liquid, gas, liquid-vapour mixture, or an aqueous solution prior to mixing with the steam 116. The heat from the steam will vapourize at least a portion of the CEA if it is not already vapourized. As a portion of the convection-enhancing agent 124 will remain in the gas phase, when the CEA cools near the edge of steam chamber 130 the gas phase density will increase and the CEA will descend towards the bottom of steam chamber 130, resulting in convection of gases and particularly a descending flow of gases. This descending flow carries or drags with it some NCGs, such as methane, towards production well and the NCGs can be conveniently removed through production well 120.
[00137] A suitable convection-enhancing agent may comprise at least one non-polar organic molecule. The suitable convection-enhancing agent may be selected to increase the overall density of the gaseous phase in the reservoir, such that it may enhance the removal of NCGs from the reservoir. In selected embodiments, the convection-enhancing agent has a molar mass higher than the molar mass of steam and at least one of the NCGs, such as methane, to be removed.
[00138] A person skilled in the art would appreciate that if, at a given instant, the pressure and temperature in a region are constant, then the density of the gas phase in the region is directly proportional to the molar mass of the gas molecules in the gas phase. According to the ideal gas law, the density (p) of a gas can be calculated as:
p = p* MM / (RT).

where P is pressure, MM is molar mass and T is temperature. In some embodiments, the NCGs in the steam chamber include mainly methane. Steam and methane have similar molar masses, being 18 g/mol and 16 g/mol respectively. Thus, at the same temperature and pressure, methane has a density similar to that of steam.
[00139] Therefore, a convection-enhancing agent may be selected that has a molar mass greater than methane to increase the resultant gas phase density.
The resulting change in the gas density causes NCGs to be displaced away from the top of the steam chamber, thereby preventing formation of the insulating layer or blanket.
Increasing gas phase density in the reservoir also directs the non-condensing gas away from the front of the steam chamber and towards a production well, which may help prevent steam loss, oil loss, or both steam loss and oil loss to a thief zone, for example, bottom water, below the production well.
[00140] A suitable convection-enhancing agent should be sufficiently volatile so that the convection-enhancing agent can be vapourized by heating (by steam) under reservoir operating conditions and the convection-enhancing agent vapour can ascend within a mobile zone of the reservoir. The CEA may be a vapour prior to mixing with steam. Upon rising within the mobile zone, the convection-enhancing agent may cool and become denser. A suitable CEA also has a low enough volatility so that the CEA
is condensable at a lower temperature zone in the reservoir, and the condensed CEA
should be sufficiently miscible with oil or bitumen or sufficiently soluble in oil. The CEA
may be selected to prevent formation of an insulating blanket by NCGs that would hinder heat transfer from the steam to the hydrocarbons in the reservoir. In some embodiments, the convection-enhancing agent may have a boiling point that is less than the boiling point of water, but significantly higher the boiling point of methane, under the steam injection conditions, such that the CEA is sufficiently volatile to rise up with the injected steam in vapour form when penetrating the steam chamber, and can then condense at the edge or front of the steam chamber.
[00141] The front of the steam chamber is typically at a lower temperature, such as at about 12 to 150 C, as compared to the temperature at the center of the steam chamber or near the injection well. The condensed convection-enhancing agent may be soluble in or miscible with the hydrocarbons in the reservoir fluid, so as to increase the drainage rate of the hydrocarbons in the fluid through the reservoir formation.
[00142] As is known to those skilled in the art, with a gravity-dominated process, such as SAGD, a start-up process is required to establish communication between the injector and producer wells. A skilled person is aware of various techniques for start-up processes, such as for example hot fluid wellbore circulation, the use of selected solvents such as xylene (as for example described in CA 2,698,898 to Pugh, et al.), the application of geomechanical techniques such as dilation (as for example described in CA 2,757,125 to Abbate, etal.), or the use of one or more microorganisms to increase overall fluid mobility in a near-wellbore region in an oil sands reservoir (as for example in CA 2,831,928 to Bracho Dominguez, et al.).
[00143] Even if there is minimal NCG accumulation during SAGD start-up, CEA
injection may be beneficial during SAGD start-up in some situations due to other beneficial effects of the particular CEA used, for example, the effect of aiding bitumen viscosity reduction and improving fluid mobility between the injection well and production well of a SAGD well pair.
[00144] A suitable convection-enhancing agent may comprise at least one organic molecule. The organic molecule may be polar or non-polar.
Conveniently, the aqueous phase of the fluids produced from the reservoir, which may include aqueous condensate formed in the reservoir, may contain a suitable polar CEA, and the polar CEA may be separated from the aqueous condensate and re-used for co-injection into the reservoir. In contrast, while the oil phase of the fluids produced from the reservoir may contain a non-polar CEA, it may be more difficult to separate the non-polar CEA
from the oil phase. A polar CEA may also be useful during treatment of a water-oil emulsion in terms of reversing a water-in-oil to an oil-in-water emulsion, which may be separated more easily.
[00145] In selected embodiments, the convection-enhancing agent may be used to assist removal of NCGs and increase mobility of oil or the reservoir fluid in the reservoir, thus accelerating heat transfer and fluid flow from the steam chamber to the production well, as compared to a typical SAGD operation where only steam is used.
[00146] A common consideration for selecting the suitable convection-enhancing agent is cost versus benefits. When multiple CEAs are potentially suitable from the technical perspectives, the final selection may be based on performance, economic analysis, and other practical considerations.
[00147] It should be noted that in the context of this disclosure, the terms "light", "lighter", "heavy", or "heavier" refer to the relative molar mass of the compared gas molecules.
[00148] As is typical, the injection and production wells may have terminal sections that are substantially horizontal and substantially parallel to one another. A
person of skill in the art will appreciate that while there may be some variation in the vertical or lateral trajectory of the injection or production wells, causing increased or decreased separation between the welts, such wells for the purpose of this application will still be considered substantially horizontal and substantially parallel to one another.
Spacing, both vertical and lateral, between injectors and producers may be optimized for establishing start-up or based on reservoir conditions.
[00149] At the point of injection into the formation, or in the injection well 118, the injected steam may be at a temperature from about 152 C to about 286 C or about 328 C, and at a pressure from about 0.5 MPa to about 12.5 MPa. These conditions may be collectively referred to as steam injection conditions. A person skilled in the art will appreciate that steam injection conditions may vary in different embodiments depending on, for example, the type of hydrocarbon recovery process implemented (e.g., SAGD, CSS) or the convection-enhancing agent selected.
[00150] However, once the steam enters the reservoir, its temperature and pressure may drop under the reservoir conditions. The reservoir temperature will become colder in regions further away from injection well 118. Typically, during SAGD
operations, the reservoir conditions may vary. For example, the reservoir temperature may vary from about 10 C to about 235 C, or up to 328 C, and the reservoir pressure may vary from about 0.5 MPa to about 3 MPa, or up to 12.5 MPa, depending on the stage of operation. The reservoir conditions may vary in different embodiments.
[00151] As noted above, steam condenses in the reservoir and mixes with the mobilized bitumen to form reservoir fluids. It is expected that in a typical reservoir subjected to steam injection, the reservoir fluids include a stream of aqueous condensate and water originally present in the reservoir (or water, may also be referred to as water stream herein). The water stream may flow at a faster rate (referred to as the water flow rate herein) than a stream of mobilized bitumen containing oil (referred to as the oil stream herein), which may flow at a slower rate (referred to as the oil flow rate herein). The reservoir fluids can be drained to the production well by gravity. The mobilized bitumen may still be substantially more viscous than water, and may drain at a relatively low rate if only steam is injected into the reservoir.
[00152] A suitable CEA is delivered to the steam chamber 130 in addition to the steam, and at least a portion of the CEA will remain in the gas phase to promote convection of gases away from the steam front before being condensed, dispersed, and mixed with the reservoir fluid. A plurality of CEAs may be co-injected with steam, for example, a plurality of CEAs may comprise propane and butane.
[00153] It is expected that delivery of the CEA to steam chamber 130 may assist removal of NCGs from the steam chamber, and may optionally result in increased fluid flow rate and drainage rate of the oil stream, which may lead to improved oil production performance, such as increased oil production rate, reduced cumulative steam to oil ratio (CSOR), or improved overall hydrocarbon recovery factor.
[00154] The CEA may be heated. The CEA may be heated due to co-injection with steam, as the injected steam is at a relatively high temperature. As such, it is not necessary to separately heat the CEA before injection into the injection well 118. The CEA may be provided or distributed to one or more well pads or injection wells from a central facility, source, or pad, or from various facilities, sources or pads, for example, by way of a pipeline. The CEA may be provided or distributed to one or more well pads or injection wells in an aqueous fluid at a concentration higher than the intended co-injection concentration, even up to 100% CEA. The CEA fluid may be diluted with steam at the one or more well pads or injection wells to provide the CEA at the desired concentration of about 0.1 wt% to about 10 wt% of steam for injection into the reservoir.
[00155] The timing for commencing co-injection of the CEA may depend on various factors and considerations. Co-injection may start early in the production stage such as when the fluid/oil production has commenced or when the steam chamber has started to form and grow, but if the benefit of NCG removal at this stage is not significant enough to off-set the costs of co-injecting CEA, co-injection may be delayed until it becomes more economical.
[00156] For example, in selected embodiments, co-injection of CEA may commence at the ramp-up stage, coinciding with the start of oil production or immediately after the steam chamber has formed and started to grow.
[00157] One or more CEAs may be delivered to one or more wells at different times. For example, in selected embodiments, co-injection of a first CEA may commence at an initial time at one or more injection wells at a well pad or in a well pattern and then co-injection of the same or a different CEA may commence at a later time at one or more other injection wells at the well pad or in the well pattern. The difference between the initial and later time may be from days to years depending on, for example, the particular well pad, well pattern, reservoir, one or more CEAs, or a combination thereof.
[00158] As noted earlier, co-injection of CEA at a low concentration, such as up to 3 wt% during an early stage or stages of oil production or steam chamber growth, can be expected to effectively remove NCGs or reduce NCG accumulation at the steam front, which can result in better chamber conformance. When the steam chamber has grown to a certain extent, such as when the steam chambers at adjacent SAGD well pairs have coalesced, further CEA co-injection may become less effective for NCG removal and less economical. As an example, when the adjacent well pairs are spaced apart by about 100 m, the adjacent steam chambers may coalesce after about 3 years of oil production. However, it should be understood that the exact timing of chamber coalescence may vary depending on the well design and other reservoir properties or factors.
[00159] After the fluid 114 is removed from the reservoir, produced water, and optionally any condensed CEA, may be separated from oil in the produced fluids by a method known in the art depending on the particular organic molecule(s) used.
The separated water and CEA can be further processed by known methods, and recycled, heating as needed, to provide steam and CEA at the injection well 118.
[00160] In some embodiments, the CEA may be separated from the produced water before further treatment, re-injection into the reservoir or disposal.
In some embodiments, ease of handling and recovery in the liquid phase at surface conditions may be a consideration for selecting a suitable CEA.
[00161] In various embodiments, the co-injection of CEA may include a selected injection pattern. For example, the co-injection pattern may include simultaneous injection with the steam, alternate injection of steam and CEA at different times (in which case, the CEA may be separately heated), staged (e.g., sequential) injection at selected time intervals, or injection at selected locations within the SAGD
operation (e.g., across multiple well pairs in a SAGD well pad). The co-injection may be performed in various regions of a well pad, or at multiple well pads to create a target injection pattern to achieve target results at a particular location of the pad or pads. In various embodiments, the co-injection may be continuous or periodic. The co-injection may be performed through an injection well (e.g., injection well 118), and may involve injection at various intervals along a length of the well.
[00162] The CEA should be suitable for use under SAGD operating conditions, which include certain temperatures, pressures and chemical environments. For example, in various embodiments, the CEA may be selected such that it is chemically stable under the reservoir conditions and the steam injection conditions and therefore can remain effective after being injected into the steam chamber.
[00163] While some examples herein are discussed with regard to SAGD
operations, it can be appreciated that a CEA may be similarly used in another steam-assisted recovery process such as CSS.
[00164] In a CSS operation, a single well may be used to alternately inject steam into the reservoir and produce the fluid from the reservoir. The single well may have a substantially horizontal or vertical section in fluid communication with the reservoir.
The single well may be used in a cyclic steam recovery process. With the use of the single well for injection and production, a temperature in the reservoir may be about 234 C to about 328 C and a pressure in the reservoir may be from about 0.5 MPa or about 3.0 MPa to about 12.5 MPa.
[00165] In embodiments of the present disclosure, a single well may be used to form and expand the steam chamber and to produce oil and remove NCGs. In such an embodiment, and in other embodiments where multiple wells are used, a single well may be configured for injection and may be configured for production. The well may be reconfigurable repeatedly, to be used alternately as an injection well and a production well. The well(s) used in embodiments of the present disclosure may include horizontal wells, vertical wells, or directional wells (drilled by directional drilling), or a combination thereof. Therefore, it should be understood that a well is configurable for injection or production if the well can be alternatively configured to function as an injection well or as a production well. In some cases, a well may be completed for only injection, and another well may be completed for only production. In some embodiments, a well may have a first section completed for injection and a second section completed for production. In different well arrangements, three or more wells may be used to service one reservoir formation, and may be in fluid communication with the same steam chamber.
[00166] When selecting the suitable organic molecules, the information and test results included in the Examples to this disclosure may be considered. It may be beneficial to select a compound that not only can enhance convection of gases in the steam chamber but also can dissolve in the reservoir fluid to increase the mobility of oil in the region. The term "mobility" is used herein in a broad sense to refer to the ability of a substance to move about, and is not limited to the flow rate or permeability of the substance in the reservoir. For example, the mobility of oil may be increased when the oil becomes easier to detach from the sand it is attached to, or when the oil has become mobile, even if its viscosity or flow rate remains the same. The mobility of oil may also be increased when its viscosity is decreased or when its effective permeability through the bituminous sands is increased.
[00167] A skilled person may appreciate that the gas phase density in the steam chamber can continue to increase as the temperature decreases, until the saturation point of the CEA is reached, after which, the equilibrium balance favours CEA
being dissolved in the oleic or aqueous phase.
[00168] Using CEA to assist removal of NCGs from the steam chamber through a production well located at or near the bottom of the steam chamber can also have the added effect and benefit of mitigating oil loss to a bottom water zone below the production well. Density and viscosity reduction can be expected to reduce heat penetration ahead of the steam chamber front.
[00169] Some steam might be removed with NCGs and other gases due to increased convection flow of gases. However, the effect of such loss of steam would be off-set by other beneficial effects of a suitable co-injected CEA.
[00170] Other possible modifications and variations to the examples discussed above are also possible.
EXAMPLES
[00171] Example 1 ¨ Live Oil Simulations [00172] A live oil simulation study was conducted to understand the NCG
behavior with and without CEA co-injection in a SAGD process. A typical Christina Lake homogenous simulation was used to model SAGD with CEA injection processes.
Hot zone was used to simulate a start-up phase, but a blowdown phase was not considered in the simulations. The term "live oil" refers to bitumen saturated with methane at native reservoir conditions.
[00173] The simulation modeled a SAGD well pair in a homogeneous reservoir using a half element of symmetry along the x-axis. The model included an overburden and underburden which allowed for heat losses via conduction.
[00174] In accordance with various aspects of the disclosure, detailed computational simulations of reservoir behaviour were carried out. For purposes of illustrating embodiments described herein, a 'base case' model was constructed. For purposes of illustrating alternative embodiments, slight modifications to the base case (primarily with respect to the selected CEA and wt% of the CEA with respect to steam) were made when constructing the other models.
[00175] The modelled reservoir was divided into a grid of 26 x-axis units, 16 y-axis units, and 28 z-axis units. Each of the x-axis units 1 and 26 had a length of 1 m and each of the x-axis units 2-25 had a length of 2 m for a total x-axis length of 50 m.
Each of the 16 y-axis units had a length of 50 m. Each of the 28 z-axis units had a length of 1 m. The x-axis, y-axis, and z-axis represented directions into the plane of the page, along the plane of the page, and parallel to the plane of the page, respectively.
[00176] The following completion design was used in the simulations: three steam splitters in the injector: 8-hole at 150 m, 12-hole at 350 m and 32-hole at 600 m;
injection and production casing with outer and inner diameters of 177.8 mm and 159.4 mm, respectively; injection tubing with outer and inner diameters of 134.3 mm and 100.5 mm, respectively; no production tubing was used.

[00177] The oil, methane and reservoir properties used in the simulation were typical for Athabasca bitumen and the Christina Lake reservoir located in Northern Alberta, Canada, and some of the key properties are listed in Table I.
[00178] Injection pressure was controlled at 2.6 MPa and the producer (production well) was controlled to have an overall gas production rate of 15 t/d (half-model) in the simulations. Injection of a low concentration of CEA (1 wt% - 5 wt %) commenced after six months of standard SAGD operation, which served to provide the baseline. The Athabasca reservoir has small amounts of initial gas dissolved in the bitumen (¨ 15-20 mole %), and this was simulated in the model.
Table I. Simulation Reservoir Properties Property Value Units Solid Sand N/A
Initial reservoir temperature 12 C
Initial reservoir pressure 2.35 MPa Initial water saturation 0.2 N/A
Initial oil saturation 0.8 N/A
Initial methane fraction in oil 16 Mol%
Horizontal hydraulic permeability (KO 6 Vertical hydraulic permeability (Kv) 4.2 Steam chamber porosity 0.34 N/A
[00179] FIG. 2 shows the steam distribution along the length of the well in x-z plane. The gas saturation in the reservoir after 2.1 years of SAGD operation is shown to illustrate the steam chamber development. The vertical and horizontal steam chamber growth in the steam chamber is shown.

[00180] When steam was injected to heat the formation, some dissolved methane also came out of the liquid phase.
[00181] FIG. 3 shows methane accumulation along the steam chamber wall after 2.1 years of SAGD operation. The results indicated that methane, being lighter, rose to the top of the steam chamber and tried to achieve equilibrium along the edges of the steam chamber ahead of the steam front.
[00182] FIG. 4 shows the increased methane volume along the steam chamber after 4.7 years of SAGD operation.
[00183] Comparing Figures 3 and 4, it is evident that methane accumulation increased with time. The accumulated methane, which is non-condensable, would impede further steam chamber development. It formed a layer of insulation, which provided resistance to heat flow from steam to reservoir, eventually jeopardizing the ultimate recovery. Overall methane removal (also referred to as methane production or methane recovery) at the end of eight years of operation was 38.5%.
[00184] The effect and impact on methane distribution/accumulation by co-injection of 5 wt% of propane after 4.9 years of SAGD operation is shown in FIGS. 5A
and 5B. The results indicate that with added propane in the gas phase, the gas phase density was increased and this appears to have improved gas removal from the steam chamber.
[00185] With even just 1 wt% propane co-injection, the cumulative methane removal was 68.3 %, much higher than 38.5 % with pure steam injection.
[00186] The test results, including representative results shown in FIGS.
5A and 5B, indicate that propane injection at a lower concentration level can assist methane removal. In the case of pure steam injection, methane accumulation along the lateral edge of the steam chamber was relatively high, with local methane concentration in the range of 5 wt% to 60 wt%. With 5 wt% propane co-injection, the methane concentration was reduced to about 5 wt % to 8 wt%, which was expected to significantly improve heat transfer along the lateral edge of the steam chamber and reduce steam usage. Advantageously, propane injection could also improve oil production rates and the cumulative steam to oil ratio (CSOR) (as illustrated further and in Table ll below).
[00187] FIG. 6 is a plot of the oil production rates (half model) for different simulation scenarios. Co-injection of butane (at 5 wt%) resulted in the highest uplift in the oil rates. FIG. 7 is a plot of bitumen recovery factor (%) versus time for various CEA co-injection scenarios. FIG. 8 is a plot of methane removal rates (half-model) in t/d versus time for various CEA co-injection scenarios. FIG. 9 is a plot of methane removal factor (%) versus time for various CEA co-injection scenarios. FIG. 10 is a plot of CSOR versus time for various CEA co-injection scenarios.
[00188] The simulation results show that co-injection of propane at 1 wt%
concentration provided a 6 % cumulative uplift in oil production (FIG. 7) and about 30% uplift in cumulative methane removal (FIG. 9). Co-injection of butane at 3 wt%
resulted in about 5 % incremental original oil in place (00IP) recovery in comparison to co-injection of propane at 3 wt%.
[00189] As can be seen from FIG. 8, methane removal can be improved with CEA co-injection as compared to pure steam injection. This is confirmed by the impact on cumulative methane removal factor shown in FIG. 9.
[00190] The simulation results show that CSOR reductions were significant with more than 3 wt% CEA injection (see e.g. FIG. 10). CEA injection at 5 wt%
resulted in about 10 % to 12 % reduction in CSOR for each of propane, butane, or a mixture of propane and butane (hybrid CEA).
[00191] Simulation tests show that CEA co-injection can assist in methane removal by increasing the overall density of the gaseous phase, and hence descending convection flow of gases in the steam chamber. For a given amount of methane recovered, about 98% is expected to be removed in the gaseous phase, and the remaining 2% in the liquid phase at bottom hole conditions (P = ¨ 1.8 ¨
2.1 MPa and T = ¨ 160 ¨ 180 C). Under other conditions, all methane may flash and be produced to surface in the gas phase, for example, via a casing line when emulsion is produced from the reservoir using a pump, for example, an electrical submersible pump (ESP). Without being limited to any particular theory, it can be expected that the injected CEA, which was denser and less volatile than steam, would drag some of the methane with it when it descended in the steam chamber and condensed into the liquid phase. Therefore, with CEA co-injection a small amount of methane was removed in the liquid phase. Increasing the concentration of co-injected CEA
in the injection stream (from example from 1 wt% propane to 3 wt% propane) increased the cumulative bitumen recovery by 5 % to 7% (see FIG. 7).
[00192] Example 2 ¨ Live Oil Simulations [00193] Additional simulations were performed with co-injection of the following CEAs, each at a concentration of 2, 5, and 10 wt% of steam: n-propylamine, ammonia, formaldehyde, dipropyl ether, sodium propanolate, propyl ethyl ether, 1,5-pentane diol, dimethyl ether, tetrahydrofuran, toluene, glycerin and butane. SAGD conditions were used as a baseline from which to compare the simulations with CEAs. The same methodology, reservoir properties and conditions were used as described in Example 1 above.
[00194] Representative simulation results are shown in FIGS. 11, 12, 13, 14, and 15, illustrating the expected impact of various potential CEAs on bitumen production rate, bitumen recovery factor, methane removal rate, methane removal factor, and CSOR respectively.
[00195] FIG. 11 shows bitumen production rate (half model) vs. time for different polar and non-polar compounds at weight fractions of 2 wt%, 5 wt% and 10 wt%.
Acceleration of bitumen production can be seen from the co-injection of CEAs with superior performance compared to SAGD.
[00196] FIG. 12 shows cumulative bitumen recovered vs. time for different polar and non-polar compounds at weight fractions of 2 wt%, 5 wt% and 10 wt%. FIG.

shows that co-injecting ammonia or glycerin resulted in inferior performance compared to SAGD and these molecules may not act as preferred CEAs in comparison to other compounds.
[00197] FIG. 13 shows methane production rate (half model) vs. time for different polar and non-polar compounds at weight fractions of 2 wt%, 5 wt% and 10 wt%.
Increased methane production can be seen upon CEA injection resulting in formation of a dense gas phase.
[00198] FIG. 14 shows cumulative methane recovered vs. time for different polar and non-polar compounds at weight fractions of 2 wt%, 5 wt% and 10 wt%. The higher the methane recovery, the more efficient the volumetric sweep due to better convection of gases along the length of the well.
[00199] FIG. 15 shows cumulative steam to oil ratio (CSOR) vs. time for different polar and non-polar compounds at weight fractions of 2 wt%, 5 wt% and 10 wt%.
A
lower CSOR is an indicator of a more efficient oil recovery process.
[00200] The effect of the presence of gas phase CEA in the steam chamber on CSOR can also be understood based on the fact that less steam would be required when a portion of the gas phase volume in the steam chamber is occupied by a CEA
which has a higher molar mass and gas phase density than steam. For instance, according to the ideal gas law, the densities of steam, propane and butane at two different temperature/pressure conditions are as listed in Table II.
Table II. Density Comparison Density at Density at Molecule 101.325 kPa, 15.5 C 2600 kPa, 225 C
Steam 0.76 11.30 Propane 1.86 27.62 Butane 2.45 36.41 [00201] Assuming a sample pore block with a volume of 1 m3, from Table II
it can be seen that propane occupies 2.5 times more spatial volume than steam, and butane occupies almost 3 times more spatial volume than steam. Thus, injection of propane, butane, or propane and butane is expected to improve CSOR.
[00202] From the simulation results it may be expected that the CEA would be ahead of the steam front. That is, the gas volume in which gas phase density is increased and methane is accumulated is ahead of the steam front.
[00203] FIGS. 17A to 17E show simulated development of gas phase in a SAGD
steam chamber in different situations. FIG. 17A shows the gas phase distribution in the steam chamber without any injected CEA. FIG. 17C shows the gas phase in the steam chamber with injected CEA. As can be seen, the gas phase in FIG. 17A was not as well developed as in FIG.17C. FIG. 17B shows a higher percentage of NCGs (represented by the darker regions) with no CEA injection, as compared to FIG.

which shows a percentage of NCGs with CEA injection because in the latter case at least a portion of NCGs were more readily removed. FIG. 17E indicates that the gas phase CEA is positioned ahead of the steam front.
[00204] FIG. 18 is a plot of well performance CSOR as a function of methane recovery factor. With CEA injection, methane removal increased and CSOR
decreased as a higher amount of oil was produced.
[00205] FIG. 19 is a plot of well performance CSOR as a function of bitumen recovery factor. With CEA injection, methane recovery increased and CSOR
decreased as a higher amount of oil was produced. With 1 % CEA injection, CSOR

was almost the same as the base case of SAGD and there was about a 6-7%
increase in bitumen recovery factor. Any weight percentage higher than 1 wt%
contributed more significantly to CSOR reduction as well as uplift in bitumen recovery factor.
[00206] Example 3 ¨ Live Oil Simulations [00207] A further simulation study was conducted that was similar to the study discussed in Example 1 and included the following simulation parameters.
[00208] The simulated formation initially had at least 75% oil saturation (see Table III for range). A vertical permeability barrier (clasts) was positioned along the x-and y-axes. The barrier was varied along the z-axis and positioned 12 m above the heel, 9 m above the mid-section, and 16 m above the toe of the injector. The clast permeability was 0 D, 0 D and 0.02 D along the x-, y-, and z-axes, respectively. The initial formation temperature was 12.0 C and initial formation pressure was 3.0 MPa.
The dissolved solution gas was 16%.
[00209] The modelled reservoir was divided into a grid of 51 x-axis units, 12 y-axis units, and 32 z-axis units. Each of the x-axis units 1 and 51 had a length of 0.5 m and each of the x-axis units 2-50 had a length of 1 m for a total x-axis length of 50 m.
Each of the 12 y-axis units had a length of 50 m. Each of the 32 z-axis units had a length of 1 m.
[00210] A different completion design was used in the simulations. The injection pressure was controlled to be at 3.1 MPa. The production rate was controlled at a gas rate of 10 t/d (half element of symmetry).
[00211] The oil, methane and reservoir properties used in the simulation were typical for Athabasca bitumen and are listed in Table III.
[00212] Injection of different concentrations of CEA (1 wt% - 20 wt %) was simulated, commencing at different times/stages in a SAGD operation. As in Example 1, a standard SAGD process without CEA co-injection was used to provide the baseline reference.

Table III. Simulation Reservoir Properties Property Value Units Solid Sand N/A
Initial Reservoir Temperature 12 C
Initial Reservoir Pressure 3 MPa Initial Water Saturation 0.20-0.25 N/A
Initial Oil Saturation 0.75-0.80 N/A
Initial Methane Fraction in Oil 16 Mol%
Horizontal hydraulic 0-6 permeability (KH) Vertical hydraulic permeability 0-5 (Kv) Porosity 0-0.33 N/A
Solvent injection 3-20 wt%
Pay thickness 15-20 [00213] FIG. 20 shows the effects of propane injection at different concentrations on CSOR and oil recovery (indicated by bitumen recovery factor in percentage), all with co-injection of propane starting after 365 days of SAGD oil production and continuing for 2 years. FIG. 21 shows similar effects on CSOR and methane removal (indicated by methane recovery factor in percentage). The reference lines with no propane injection are labeled as "SAGD". As can be seen, the CSOR at the same oil recovery percentage is lower with increased propane injection. The maximum oil recovery factor obtainable below CSOR of about 3.2 is significantly higher with propane injection, as compared to without propane injection, but is not substantially affected by the amount of propane injection within the range of 3 wt% to 20 wt%.
Similarly, the maximum methane recovery factor obtainable below CSOR of about 3.2 increases significantly with propane injection, but remains substantially constant with 5 wt% to 20 wt% of propane injection.
[00214] FIG. 22 shows effects of propane injection at different concentrations on oil recovery (indicated by bitumen recovery factor in percentage), all with co-injection of propane starting after 365 days of SAGD production and continuing for 2 years. As can be seen, the bitumen recovery factor increased more rapidly when propane was injected, as compared to without propane injection. However, the impact was similar in the range of 3 wt% to 20 wt% propane injection. FIG. 23 shows similar effects on the methane removal factor.
[00215] FIGS. 24A to 24F show methane distribution in the simulated reservoir along the length of the well in the x-z plane, after 365, 450, 550, 650, 730, and 1,096 days of SAGD oil production operation, respectively, without propane injection. FIGS.
25A to 25E show corresponding methane distribution but with 3 wt% propane co-injection after 365 days of SAGD production. FIGS. 26A to 26E show corresponding methane distribution but with 5 wt% propane co-injection after 365 days of SAGD
production. FIG. 27A to 27E show corresponding methane distribution but with 10 wt%
propane co-injection after 365 days of SAGD production.
[00216] FIGS. 28A to 31E are similar to FIGS. 24A to 27E but show methane distribution along the length of the well in the y-z plane.
[00217] Example 4 ¨ Live Oil Simulations [00218] A further simulation study was conducted that was similar to the study discussed in Example 3 and included the following simulation parameters.
[00219] A different completion design was used in the simulations and modified during the lifetime of the simulated well pair. Some of the effects observed in the simulated reservoir may be attributed to the completions modification.
[00220] Some of the key oil, methane and reservoir properties used in this simulation study are listed in Table IV.

Table IV. Simulation Reservoir Properties Property Value Units Solid Sand N/A
Initial Reservoir Temperature 12 C
Initial Reservoir Pressure 3 MPa Initial Water Saturation 0.20 N/A
Initial Oil Saturation 0.80 N/A
Initial Methane Fraction in Oil 16 Mol%
Horizontal hydraulic 6 permeability (KH) Vertical hydraulic permeability 5 (Kv) Porosity 0.33 N/A
Solvent injection 1-5 wt%
Pay thickness 15 [00221] In this simulation study, propane was injected at the start of a SAGD oil production operation. Propane injection was terminated after 3 years of oil production in some cases, and after 10 years of oil production in other cases. The propane injection concentration was varied from 1 wt % to 5 wt%. A standard SAGD
operation without propane injection was used as the baseline reference.
[00222] FIG. 32 shows effects of propane injection at different concentrations and for different periods of time on bitumen (oil) production rates over time with co-injection of propane commencing at the start of a SAGD production operation (i.e.
immediately after communication or at the beginning of the ramp-up stage).
[00223] FIG. 33 shows a similar plot but for effects on bitumen recovery factor over time. As can be seen, propane injection improved bitumen production rate and bitumen recovery factor until about three years of oil production. After three years, the oil production rates with propane injection were similar or below the production rate without propane injection. Further, the improvement in oil production rate was similar within the range of 1 wt% to 5 wt% propane injection. Continued propane injection after three years, up to 10 years, did not show significant impact on the oil production rate. Similarly, the impact on bitumen recovery factor also dropped significantly after three years of oil production.
[00224] FIGS. 34 and 35 show similar plots as FIGS. 32 and 33 but for effects on methane production rates (indicating the rates of methane removal from the steam chamber) and methane production factor (indicating overall percentage of methane removal from the steam chamber), respectively. As can be seen, propane injection improved the methane removal rate and the methane removal factor more significantly within the first three years of oil production. Increasing the amount of propane injection from 1 wt% to 3 wt% and then 5 wt% also had some additional effects. Continued propane injection after three years also offered some limited additional improvement.
[00225] FIGS. 36 and 37 show effects of propane injection at different concentrations and for different periods of time on CSOR in relation to the bitumen recovery factor and the methane removal factor, respectively.
CONCLUDING REMARKS
[00226] Various changes and modifications not expressly discussed herein may be apparent and may be made by those skilled in the art based on the present disclosure. For example, while a specific example is discussed above with reference to a SAGD process, some changes may be made when other recovery processes, such as CSS, are used.
[00227] It will be understood that any range of values herein is intended to specifically include any intermediate value or sub-range within the given range, and all such intermediate values and sub-ranges are individually and specifically disclosed.

[00228] It will also be understood that the word "a" or "an" is intended to mean "one or more" or "at least one", and any singular form is intended to include plurals herein.
[00229] It will be further understood that the term "comprise", including any variation thereof, is intended to be open-ended and means "include, but not limited to,"
unless otherwise specifically indicated to the contrary.
[00230] When a list of items is given herein with an "or" before the last item, any one of the listed items or any suitable combination of two or more of the listed items may be selected and used.
[00231] Of course, the above described embodiments of the invention are intended to be illustrative only and in no way limiting. The described embodiments of the invention are susceptible to many modifications of form, arrangement of parts, details and order of operation. The invention, rather, is intended to encompass all such modification within its scope, as defined by the claims.

Claims

WHAT IS CLAIMED IS:

1. A method of removing non-condensing gas present in a steam chamber in a steam-assisted process for hydrocarbon recovery from an oil sands reservoir, wherein the reservoir is serviced by one or more wells each configurable as an injection well, a production well, or both an injection well and a production well, and wherein each of the one or more wells mediates fluid communication between a surface completion and the reservoir, and wherein steam is injected into the reservoir through at least one of the one or more wells configured for injection, resulting in formation and expansion of the steam chamber and accumulation of the non-condensing gas in the steam chamber, the method comprising:
injecting a convection-enhancing agent with steam into the at least one of the one or more wells configured for injection, to promote convection of gases in the steam chamber so as to assist removal of the non-condensing gas from the steam chamber;
removing gases from the reservoir through at least one of the one or more wells configured for production of hydrocarbons conveyed downward from the steam chamber, wherein the removed gases comprise the non-condensing gas descended from the steam chamber resulting from the convection of gases.

2. The method of claim 1, wherein the one or more wells comprise a well pair of an injection well and a production well.

3. The method of claim 1, wherein the one or more wells comprise a single well configurable for either injection or production, and the method comprises alternately injecting steam with the convection-enhancing agent into the steam chamber through the single well, and producing a fluid and gases from the reservoir through the single well.

4. The method of claim 1 or claim 2, wherein the one or more wells comprise a well that is configurable for injection or production.

5. The method of any one of claims 1 to 4, wherein the one or more wells comprise a well having a substantially-horizontal terminal section in fluid communication with the reservoir.

6. The method of any one of claims 1 to 5, wherein the one or more wells comprise a well having a substantially-vertical section in fluid communication with the reservoir.

7. The method of any one of claims 1 to 6, wherein the steam-assisted process is a steam-assisted gravity drainage (SAGD) process.

8. The method of any one of claims 1 to 6, wherein the steam-assisted process is a cyclic steam stimulation (CSS) process.

9. The method of any one of claims 1 to 8, wherein a mixture of the convection-enhancing agent and steam is injected into the at least one well for injection, and wherein a temperature in the steam chamber is from 152 °C to 286 °C and a pressure in the steam chamber is from 0.5 MPa to 7 MPa.

10.The method of any one of claims 1 to 8, wherein a temperature in the reservoir is from 234 °C to 328 °C and a pressure in the reservoir is from 3 MPa to 12.5 MPa.

11.The method of any one of claims 1 to 10, wherein the convection-enhancing agent is 0.1% to 10% of the steam by weight in the mixture.

12.The method of any one of claims 1 to 10, wherein the convection-enhancing agent is 1% to 5% of the steam by weight in the mixture.

13.The method of any one of claims 1 to 10, wherein the convection-enhancing agent is 3% to 5% of the steam by weight in the mixture.

14.The method of any one of claims 1 to 10, wherein the convection-enhancing agent is 5% to 8% of the steam by weight in the mixture.

15.The method of any one of claims 1 to 10, wherein the convection-enhancing agent is 1% to 3% of the steam by weight in the mixture.

16.The method of any one of claims 1 to 15, wherein the non-condensing gas comprises methane, a carbon oxide, a nitrogen oxide, a sulfur oxide, hydrogen sulfide, or a combination thereof.

17.The method of any one of claims 1 to 16, wherein the non-condensing gas comprises methane.

18.The method of any one of claims 1 to 17, wherein the convection-enhancing agent is selected to increase a gas phase density in the steam chamber.

19.The method of any one of claims 1 to 18, wherein the convection-enhancing agent comprises an organic molecule having a moderate volatility such that a sufficient proportion of the convection-enhancing agent injected into the steam chamber can remain in the gas phase in the steam chamber for a sufficient period to ascend to a steam chamber front and to induce the convection of gases in the steam chamber, and can thereafter condense along the steam chamber front.

20.The method of claim 19, wherein increasing gas phase density in the steam chamber directs the non-condensing gas away from the front of the steam chamber and towards at least one of the one or more wells configured for production to remove the non-condensing gas.

21.The method of claim 20, wherein directing the non-condensing gas towards at least one of the one or more wells configured for production inhibits steam loss, oil loss, or both steam loss and oil loss to a thief zone in the reservoir, wherein a thief zone is bottom water, a gas cap, or both bottom water and a gas cap.

22.The method of any one of claims 1 to 21, wherein the convection-enhancing agent comprises at least one of propane and butane.

23.The method of any one of claims 19 to 21, wherein the organic molecule comprises a non-polar molecule.

24.The method of claim 23, wherein the molar mass of the non-polar organic molecule is from 30 g/mol to 60 g/mol.

25. The method of any one of claims 19 to 21, wherein the organic molecule comprises a polar molecule.

26.The method of claim 25, wherein the molar mass of the polar organic molecule is from 30 g/mol to 105 g/mol.

27. The method of claim 25, wherein the polar molecule comprises formaldehyde.

28. The method of any one of claims 1 to 27, wherein a molar mass of the convection-enhancing agent is higher than a molar mass of the non-condensing gas.

29. The method of any one of claims 1 to 28, wherein the convection-enhancing agent is more volatile than water.

30.The method of any one of claims 1 to 29, wherein the convection-enhancing agent is more soluble in oil than in water.

31.The method of any one of claims 1 to 30, wherein injection of the convection-enhancing agent commences before the steam chamber has formed or when hydrocarbon production from the reservoir through the one or more wells has commenced.

32.The method of any one of claims 1 to 30, wherein injection of the convection-enhancing agent commences after the steam chamber has formed or after a period of hydrocarbon production from the reservoir through the one or more wells.

33.The method of claim 32, wherein the period of hydrocarbon production is 12 months.

34. The method of any one of claims 1 to 33, wherein injection of the convection-enhancing agent terminates after the steam chamber has coalesced with an adjacent steam chamber.

35. The method of any one of claims 1 to 33, wherein injection of the convection-enhancing agent terminates after 36 months of hydrocarbon production from the reservoir through the one or more wells.

36.The method of any one of claims 1 to 35, wherein the weight percentage of the convection-enhancing agent in the mixture increases over time during injection of the convection-enhancing agent by 1 wt% to 3 wt%.