CA2870794C

CA2870794C - Steam-assisted hydrocarbon recovery with steam-co2 separation

Info

Publication number: CA2870794C
Application number: CA2870794A
Authority: CA
Inventors: Todd Stewart Pugsley; Mark Chan; James Fong
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2014-11-13
Filing date: 2014-11-13
Publication date: 2017-05-09
Anticipated expiration: 2034-11-13
Also published as: CA2870794A1

Abstract

There is provided an in situ thermal recovery process for recovering hydrocarbons from a reservoir. The process includes providing an oxygen- enriched mixture, fuel and feedwater to a DCSG; operating the DCSG to obtain a combustion mixture including steam and CO2; separating all or part of the CO2 from the combustion mixture to obtain a CO2-depleted steam stream; injecting the CO2-depleted steam stream or a stream derived from the CO2-depleted steam stream into the reservoir to mobilize the hydrocarbons therein, thereby obtaining mobilized hydrocarbons; and producing the mobilized hydrocarbons.

Description

, SEPARATION
FIELD
[0001]The general technical field relates to in situ hydrocarbon recovery operations, and more particularly to steam-assisted hydrocarbon recovery operations.
BACKGROUND

[0002]Steam-assisted hydrocarbon recovery techniques are widely used to recover hydrocarbons such as heavy oil and/or bitumen from subsurface reservoirs. Steam-assisted gravity drainage (SAGD) is one of such techniques.
Typically, in a SAGD hydrocarbon recovery operation, a pair of horizontal wells is drilled into a hydrocarbon-bearing reservoir, such as an oil sands reservoir, and steam is continuously injected into the reservoir via the upper injection well to heat and reduce the viscosity of the hydrocarbons. The mobilized hydrocarbons drain into the lower production well and are recovered to surface.

[0003]The steam is typically generated by steam generators, such as Once-Through Steam Generators (OTSG) or drum boilers, which can be large, expensive, and require high quality feedwater to operate. Generation of steam and injection of steam into a hydrocarbon-bearing reservoir can therefore lead to various inefficiencies and costs if traditional steam generation is used. An alternative is to use Direct-Contact Steam generators (DCSG) which generate a steam-0O2 mixture as an outlet stream. However, while the steam-0O2 mixture can be injected into the reservoir, it can be difficult to control the steam to CO2 ratio to be injected.

[0004] Various challenges still exist in the area of in situ hydrocarbon recovery and steam generation.

SUMMARY

[0005]In some implementations, there is provided a process for Steam-Assisted Gravity Drainage (SAGD) recovery of hydrocarbons from a reservoir, including:
providing an oxygen-enriched mixture, fuel and feedwater to a direct-contact steam generator (DCSG); operating the DCSG to obtain a combustion mixture including steam and 002; separating a first portion of the combustion mixture into a CO2-depleted steam stream and a CO2-rich stream, wherein the separating includes: feeding the first portion of the steam-0O2 mixture into a separation unit including a separation membrane dividing the separation unit into a retentate region and a permeate region, the separation membrane being selectively permeable to steam over CO2; passing a sweep gas stream composed of a combustible mixture across the permeate region, to provide a driving force for transport of the steam across the separation membrane; and obtaining the 002-depleted steam stream including steam and the combustible mixture from the permeate region and the CO2-rich stream including CO2 from the retentate region; recirculating at least a portion of the CO2-depleted steam stream to the DCSG as part of the fuel and feedwater, thereby reducing the concentration of CO2 in the combustion mixture; injecting a second portion of the combustion mixture into the reservoir via a SAGD injection well to mobilize hydrocarbons in the reservoir; and recovering mobilized hydrocarbons as produced fluids from a SAGD production well.

[0006]In some implementations, an initial concentration of CO2 in the combustion mixture is equal to or greater than 6 wt%.

[0007]In some implementations, a reduced concentration of CO2 in the combustion mixture is equal to or less than 4 wt% when a continuous regime is reached.
[00081In some implementations, the separation membrane is a hollow fiber separation membrane.

[0009]In some implementations, the hollow fiber separation membrane is made of a ceramic material being more permeable to steam over 002.
[0010]In some implementations, the hollow fiber separation membrane is made of a polymer material being more permeable to steam over 002.
[0011]In some implementations, the polymer material includes a polyamide-imide, a polyimide or a polybenzimidazole.
[0012]In some implementations, the combustible mixture includes lower hydrocarbons.
[0013]In some implementations, the lower hydrocarbons include methane, ethane, propane, butane or a mixture thereof.
[0014]In some implementations, the combustible mixture includes natural gas and/or syngas.
[0015]In some implementations, the at least a portion of the 002-depleted steam stream recirculated to the DCSG is all of the CO2-depleted steam stream.
[0016]In some implementations, the process further includes separating the produced fluid into produced gas, produced non-gaseous hydrocarbons and produced water.
[0017]In some implementations, the process further includes using at least part of the produced gas as at least part of the fuel for the DCSG.
[0018]In some implementations, the process further includes using at least part of the produced water as at least part of the feedwater for the DCSG.
[0019]In some implementations, the reservoir is located below and in fluid communication with the thief zone, the process further including injecting the 002-rich stream via a CO2 injection well provided in the thief zone to form a enriched region providing heat insulation to the reservoir.

[0020]In some implementations, the process further includes producing at least part of the water from the thief zone via a water production well provided in the thief zone.
[0021]In some implementations, there is provided a system for SAGD recovery of hydrocarbons from a reservoir, including: a DCSG for receiving oxygen, fuel and feedwater and generating a combustion mixture therefrom, the combustion mixture including steam and CO2; a splitter for separating the combustion mixture into a first portion and a second portion; a steam-0O2 separation unit in fluid communication with the DCSG, the steam-0O2 separation unit being configured to receive the first portion of the combustion mixture and a sweep gas stream, for separating the first portion of the combustion mixture into a CO2-rich stream and a CO2-depleted steam stream; a recirculation line to recirculate at least a portion of the CO2-depleted steam stream to the DCSG as part of the fuel and feedwater, thereby reducing the concentration of CO2 in the combustion mixture;
a well pad supporting a SAGD well pair including: a SAGD injection well in fluid communication with the steam generator to receive the second portion of the combustion mixture; and a SAGD production well for recovering produced fluids from the reservoir; and a water-hydrocarbon separator in fluid communication with the SAGD production well to receive the produced fluids and separate the produce fluids into produced fluids.
[0022]In some implementations, the produced fluids include produced gas, produced water and produced non-gaseous hydrocarbons.
[0023]In some implementations, the system further includes a gas recirculation line for conveying at least a portion of the produced gas to the DCSG for use as at least part of the fuel for the DCSG.
[0024]In some implementations, the separation unit includes a separation membrane dividing the separation unit into a retentate region and a permeate region, the separation membrane being selectively permeable to steam over CO2 [0025]In some implementations, the separation membrane is a hollow fiber separation membrane.
[0026]In some implementations, the hollow fiber separation membrane is made of a ceramic material being more permeable to steam over CO2.
[0027]In some implementations, the hollow fiber separation membrane is made of a polymer material being more permeable to steam over CO2.
[0028]In some implementations, the polymer material includes a polyamide-imide, a polyimide or a polybenzimidazole.
[0029]In some implementations, the combustible mixture includes lower hydrocarbons.
[0030]In some implementations, the lower hydrocarbons include methane, ethane, propane, butane or a mixture thereof.
[0031]In some implementations, the combustible mixture includes natural gas and/or syngas.
[0032]In some implementations, there is provided an in situ thermal recovery process for recovering hydrocarbons from a reservoir, including: providing an oxygen-enriched mixture, fuel and feedwater to a DCSG; operating the DCSG to obtain a combustion mixture including steam and CO2; separating all or part of the CO2 from the combustion mixture to obtain a CO2-depleted steam stream;
injecting the CO2-depleted steam stream or a stream derived from the CO2-depleted steam stream into the reservoir to mobilize the hydrocarbons therein, thereby obtaining mobilized hydrocarbons; and producing the mobilized hydrocarbons.
[0033]In some implementations, the separating includes separating a first portion of the combustion mixture into the CO2-depleted steam stream and a CO2-rich stream.

[0034]In some implementations, the separating is performed using a separation membrane permeable to steam over CO2.
[0035]In some implementations, the reservoir is located below and in fluid communication with the thief zone, the process further including injecting the CO2-rich stream via a CO2 injection well provided in the thief zone to form a enriched region providing heat insulation to the reservoir.
[0036]In some implementations, the process further includes producing at least part of the water from the thief zone via a water production well provided in the thief zone.
[0037]In some implementations, there is provided a process for recovering hydrocarbons from a hydrocarbon-bearing reservoir located below and in fluid communication with a thief zone including water, the process including;
providing an oxygen-enriched mixture, fuel and feedwater to a DCSG; operating the DCSG
to obtain a combustion mixture including steam and 002; separating all or part of the CO2 from the combustion mixture to obtain a 002-depleted steam stream and a 002-rich stream; injecting at least part of the CO2-depleted steam stream or a stream derived therefrom into the reservoir to mobilize the hydrocarbons therein, thereby obtaining mobilized hydrocarbons; injecting at least part of the CO2-rich stream via a CO2 injection well provided in the thief zone to form a CO2-enriched region to pressurize the thief zone; and operating a thermal in situ recovery operation in the hydrocarbon-bearing reservoir.
[0038]In some implementations, the process further includes producing water via a water production well provided in the thief zone.
[0039]In some implementations, there is provided a method for generating steam, including: providing an oxygen-enriched mixture, fuel and feedwater to a DCSG; operating the DCSG to obtain a combustion mixture including steam and 002; separating at least a portion of the steam-0O2 mixture into a CO2-depleted stream and a CO2-rich stream, the separating including replacing the CO2 in the at least a portion of the steam-0O2 mixture with a sweep gas including a combustible mixture; and recirculating the CO2-depleted stream to the DCSG as at least part of the fuel and feedwater, thereby lowering the concentration of in the combustion mixture.
BRIEF DESCRIPTION OF DRAWINGS
(0040] Figure 1 is a process flow diagram of a system for generating steam.
[0041]Figure 2 is a process flow diagram of another system for generating steam.
[0042]Figure 3 is a schematic view of a membrane steam-0O2 separation unit.
[0043]Figure 4 is a schematic view of a single hollow fiber membrane used in a hollow fiber membrane steam-0O2 separation unit;
[0044]Figure 5 is a schematic view of a hollow fiber membrane separation module including multiple hollow fiber membranes, each being as the one shown on Figure 4.
[0045]Figure 6 is a process flow diagram of a SAGD operation including a steam-0O2 separation unit.
[0046]Figure 7 is a vertical cross-sectional view of a SAGD operation including a dewatering operation by the injection of CO2 in the top thief zone.
[0047]Figure 8 is a vertical cross-sectional view of a SAGD operation including the formation of a CO2 blanket between the steam chamber and the top thief zone.
DETAILED DESCRIPTION
[0048]Various techniques that are described herein enable thermal in situ recovery operations, such as steam-assisted gravity drainage (SAGD), including the use of a Direct-Contact Steam Generator (DCSG) for generating steam. The outlet stream generated by the DCSG is a combustion mixture, also referred to as a steam-0O2 mixture. While the combustion mixture can be directly injected into a hydrocarbon-bearing reservoir to mobilize the hydrocarbons therein, in some scenarios it can be desirable to reduce the concentration of CO2 in the combustion mixture prior to injecting. In order to reduce the concentration of in the combustion mixture, a steam-0O2 separation unit which can include a steam-0O2 separation membrane is used.
[0049]A DCSG generates steam by directly contacting feedwater with a hot combustion gas which is produced using fuel (for example, natural gas) and an oxidizing gas (for example, an oxygen-enriched gas mixture, such as purified oxygen). Depending on the oxidizing gas and fuel that are used, the combustion gas can include various amounts of carbon dioxide (CO2) as well as other gases such as carbon monoxide (CO), hydrogen (H2), nitrogen based compounds (N0x) such as nitric oxide (NO) and nitrogen dioxide (NO2) and/or sulfur based compounds (S0x) such as sulfur oxides. The fuel and oxidizing gas can be premixed prior to reaching a burner and a flame is generated in a combustion chamber, thereby forming the hot combustion gas. The feedwater is typically run down the combustion chamber in jacketed pipes and into an evaporation chamber, and the hot combustion gas evaporates the feedwater in the evaporation chamber, thereby generating the outlet stream (also referred to herein as a "combustion mixture" or a "steam-0O2 mixture") which includes steam and combustion gas.
[0050]The steam-0O2 separation unit including the steam-0O2 separation membrane is configured to receive at least a portion of the outlet stream of the DCSG, in order to lower the concentration of CO2 therein. Some implementations of the technology will be described in greater detail below.
Steam generation [0051]Referring to Figures 1 and 2, in some implementations, an oxygen-enriched mixture 10, fuel 12 and feedwater 14 are fed to a DCSG 16. The

8 oxygen-enriched mixture 10 can be oxygen-enriched air, or oxygen at different levels of purity. Optionally, high purity oxygen can be used. The DCSG 16 can operate using different types of fuel 12, such as be natural gas, syngas, refinery fuel gas, coke, asphaltenes or mixtures thereof. The flexibility in the types of fuel that can be used provides an advantage against escalating natural gas prices or natural gas supply interruptions. The DCSG 16 can operate effectively with low feedwater quality, and in some scenarios with feedwater quality that is considered unacceptable for use in an OTSG or drum boiler. The feedwater 14 can include fresh water, recycled produced water from a steam-assisted hydrocarbon recovery process or a mixture thereof. Recycled produced water can include high levels of contaminants and impurities (such as residual hydrocarbons, inorganic compounds and/or suspended solids).
[0052]Referring to Figures 1 and 2, the DCSG 16 is operated to obtain a combustion mixture 18. The combustion mixture 18 includes steam and CO2.
Depending on the type of fuel 12 and oxygen-enriched mixture 10, the combustion mixture 18 can also include various amounts of other gases, as explained above. It is noteworthy that the concentration of CO2 in an outlet stream of a DCSG which is not subjected to steam-0O2 separation can be up to 12 wt%, typically between 6 wt% and 12 wt%. In some scenarios, depending for example on the properties and geological layout of the reservoir, it can be desirable to lower the concentration of CO2 in the combustion mixture 18 to at most about 4 wt% for injection into the reservoir.
[0053]In some implementations, the combustion mixture 18 is split into at least two separate portions 18A and 18B, and the first portion 18A is supplied to a steam-0O2 separation unit 19. All or part of the CO2 can be separated from the first portion 18A in the steam-0O2 separation unit 19 to obtain a CO2-depleted steam stream 20 and a CO2-rich stream 22 (as shown in Figure 1). In some alternative configurations, all of the combustion mixture 18 can be supplied to a first steam-0O2 separation unit 19 (as shown in Figure 2) to obtain the 002-depleted steam stream 20 and CO2-rich stream 22.

9 [0054]In some implementations, the steam-0O2 separation unit 19 includes a membrane separation unit including at least one separation membrane suitable for separating at least part of the steam and at least part of the CO2 from a DCSG combustion mixture. Optionally, when a steam-0O2 membrane separation unit 19 is used, sweep gas 24 can be provided to the separation unit 19 for driving the separation. Examples of steam-0O2 separation units 19 will be described in further detail below. The sweep gas 24 can be composed of a combustible mixture which is suitable to (i) drive the separation of the steam and CO2 from the combustion mixture 18 and (ii) be used as fuel for a DCSG, for example when the CO2-depleted steam stream 20 is recycled back in to the DCSG 16. When fuel is used as the sweep gas 24, the CO2-depleted steam stream 20 mainly includes steam and sweep gas 24, and can also include a residual amount of CO2. For example, the sweep gas 24 can include natural gas or other combustible fuel gases such as lower hydrocarbons (e.g., methane, ethane, propane and/or butane), a synthetic fuel gas such as syngas, or a refinery fuel gas. For example, the concentration of steam in the CO2-depleted steam stream 20 can be up to 90 wt%, and the concentration of sweep gas in the CO2-depleted steam stream 20 can be up to 10 wt%. The concentration of residual CO2 in the CO2-depleted steam stream 20 can be up to 1 wt%.
[0055]In some implementations, the CO2-rich stream 22 is mainly composed of CO2. For example, the concentration of CO2 in the CO2-rich stream 22 can be up to 90 wt%, and the concentration of steam in the CO2-rich stream 22 can be up to 10 wt%. It should be understood that the concentration of CO2 in the CO2-rich stream depends on the type of separation unit 19 used and can change depending on various operating factors, such as the concentration of CO2 in the combustion mixture 18, the temperature and pressure at which the separation is effected and the nature and concentration of sweep gas 24 used.
[0056]In some implementations, at least part of the CO2-depleted steam stream 20 exiting the steam-0O2 separation unit 19 can be directly used for a desired application, such as injection into a hydrocarbon-bearing reservoir. In some implementations, the CO2-depleted steam stream 20 is further treated (e.g., reintroduced into the DCSG 16 or another DCSG) and a subsequently obtained stream (i.e., a stream derived from the CO2-depleted stream 20) can be used for the desired application. More regarding introducing the CO2-depleted steam stream 20 back into a DCSG will be discussed further below.
[0057]Referring to Figure 1, in some implementations, the CO2-depleted steam stream 20 is recycled back to the DCSG 16. As the CO2-depleted steam stream 20 includes mainly steam and sweep gas, the CO2-depleted steam stream 20 is suitable to be used as part of the feedwater and part of the fuel for the DCSG
16.
As the CO2-depleted steam stream 20 only includes a residual amount of CO2, recycling the CO2-depleted steam stream 20 back to the DCSG 16 facilitates gradually lowering the concentration of CO2 in the combustion mixture 18 until steady-state or quasi steady-state concentrations are reached. The combustion mixture 18 is split (e.g., using a splitter 25) into the first portion 18A
which is introduced into the steam-0O2 separation unit 19 and the second portion 18B
which can be used for the desired application, such as injection into a hydrocarbon-bearing reservoir. The amount of the combustion mixture 18 supplied to the steam-0O2 separation unit 19 (i.e., the first portion 18A) depends on the desired concentration of CO2 in the combustion mixture 18 when the generally steady-state regime is reached.
[0058]Now referring to Figure 2, in some implementations, the DCSG 16 is a first DCSG 16 and at least part of the CO2-depleted steam stream 20 is supplied to a second DCSG 26. Similarly as above, the CO2-depleted steam stream 20 is suitable to be used as part of the feedwater and part of the fuel for the second DCSG 26. As the CO2-depleted steam stream 20 only includes a residual amount of CO2, the concentration of CO2 in a second combustion mixture 28 produced by the second DCSG 26 is lower than the concentration of CO2 in the combustion mixture 18 of the first DCSG 16. The second combustion mixture 28 can be directly used for the desired application when the desired concentration of CO2 is reached. Alternatively, at least part of the second combustion mixture 28 can be introduced into a second steam-0O2 separation unit (not illustrated) for further purification. It should be understood that several DCSGs and steam-0O2 separation units can be used in series with a steam-0O2 separation unit being present between two DCSGs, so as to obtain a final combustion mixture with the desired reduced concentration of CO2. It should also be noted that when multiple DCSGs are used in series, various splitters may be used to split respective combustion mixtures so that portions of the combustion mixtures can be recycled back into an upstream DCSG.
Steam-0O2 separation [0059]Referring to Figure 3, in some implementations, there is provided a separation unit 19 for separating steam and CO2 from a steam-0O2 mixture. The separation unit 19 has a first end 19A and a second end 19B, and includes at least one separation membrane 30. The separation membrane 30 divides the separation unit 19 into a feed region (or a retentate region) 32 and a permeate region 34. The separation membrane 30 is selectively permeable to steam over CO2. In some implementations, the combustion mixture 18, 18A including steam and CO2 is fed into the retentate region 32 from the first end 19A of the separation unit 19, and the sweep gas 24 can be fed from the second end 19B
into the permeate region 34 of the separation unit 19. In some implementations, the flow of sweep gas 24 is a counter-current flow compared to the flow of combustion mixture 18, 18A. The sweep gas 24 drives the separation of steam 35 from the combustion mixture 18, 18A located in the feed region 32, across the separation membrane 30 and into the permeate region 34. The separation of the steam 35 from the combustion mixture 18, 18A facilitates recovering a CO2-rich stream 22 at the second end 198 of the separation unit 19 and a CO2-depleted steam stream 20 at the first end 19A of the separation unit 19.
[0060]It should be understood that "selectively permeable to steam over CO2"
means that the selectivity of steam over CO2 for the separation unit is high enough to obtain a CO2-depleted steam stream 20 which contains a reduced amount of CO2, the selectivity of steam over CO2 for a given separation membrane being defined as the ratio of the permeance of steam over the permeance of CO2. For example, with a selectivity equal to or greater than 50, the resulting CO2-depleted steam stream 20 would include only trace amounts of CO2 (i.e., the concentration of CO2 in the CO2-depleted steam stream would be wt% or lower).
[0061]Referring to Figures 4 and 5, in some implementations, the separation membrane 30 is a hollow fiber separation membrane. For example, the hollow fiber separation membrane 30 can have an elongated cylindrical shape and a diameter (D) of 200 pm to 1000 pm. Optionally, the membrane separation unit 19 includes several hollow fiber separation membranes 30 arranged substantially parallel to each other, the interior of each of the hollow fiber separation membranes 30 defining retentate regions 32, and the exterior of the hollow fiber separation membranes 30 and a surrounding housing defining the permeate region 34 (as shown in Figure 5). In some implementations, the membrane separation unit 19 is provided with a combustion mixture inlet 36 located at the first end 19A of the separation unit, for receiving the combustion mixture 18, 18A, the combustion mixture inlet 36 being in fluid communication with the retentate regions 32 (i.e., the interior of each of the hollow fiber separation membranes 30). The combustion mixture 18, 18A is thus introduced into a hollow fiber separation membrane 30 or several hollow fiber separation membranes 30. The combustion mixture 18, 18A passes through channels defined by the hollow fiber separation membranes 30 from a first end 30A to a second end 30B thereof, while steam 35 gradually permeates across a membrane wall 38 of the hollow fiber separation membranes 30. The CO2-rich stream 22 is obtained from a CO2-rich stream outlet 40 located at the second end 19B of the separation unit 19, the CO2-rich stream outlet 40 being in fluid communication with the retentate regions 32.
[0062]Still referring to Figures 4 and 5, in some implementations, a sweep gas inlet 42 is provided at the second end 19B of the separation unit 19 for introducing the sweep gas 24. The sweep gas 24 flows around the exterior of the hollow fiber separation membranes 30 and towards a CO2-depleted steam stream outlet 44 located at the first end 19A of the separation unit 19. The sweep gas 24 sweeps the steam 35, which has permeated through the membranes 30 from the retentate region 32 to the permeate region 34, out of the separation unit 19 and the CO2-depleted steam stream 20 is thus obtained. In some implementations, the combustion mixture 18, 18A and/or the sweep gas 24 are introduced into the separation unit 19 at a pressure of 100 psi to 500 psi or psi to 400 psi, and/or at a temperature of 200 C to 300 C. In some implementations, the sweep gas 24 is introduced into the separation unit 19 at lower pressure than the combustion mixture 18, 18A, thereby driving the separation of the steam with both a pressure differential effect and a sweep gas effect. In some implementations, the partial pressure of sweep gas 24 is higher towards the second end 19B of the separation unit 19 than toward the first end 19A. Similarly, in some implementations, the partial pressure of steam 35 in the permeate region 34 of the separation unit 19 is higher toward the first end than toward the second end 19B.
[0063]The hollow fiber separation membrane 30 can be made of ceramic and/or polymer materials, which have a higher permeability to steam than to CO2. In some implementations, the polymer can be a polyamide-imide such as Torlon-4000-T-LVTm, a polyimide such as Matrimid 52181m or VTec PI 080-051TM, or a polybenzimidazole such as DPSTM.
Steam-assisted hydrocarbon recovery with steam-0O2 separation [0064]In the case of steam-0O2 membrane separation for steam-assisted hydrocarbon recovery operations, the use of an inert sweep gas would have the effect of replacing the CO2 in the combustion mixture of the DCSG with another gas which, in some scenarios, can be undesirable for co-injection with the steam into a hydrocarbon-containing reservoir. For example, using a non-condensable gas (NCG), such as nitrogen, could be undesirable as a sweep gas as the nitrogen would replace the CO2 which is also a NCG. Furthermore, while using a pressure differential at the exterior of the membranes in order to drive the steam-002 separation is possible, providing the high pressure differential that would be required can lead to an increase in costs.
[0065]In some implementations, the method for generating steam and the steam-0O2 separation technology described above can be combined for implementing steam-assisted hydrocarbon recovery with steam-0O2 separation.
In the present section, the steam-assisted hydrocarbon recovery with steam-0O2 separation will be exemplified in the context of a SAGD operation, but it should be understood that the steam-assisted hydrocarbon recovery process with steam-0O2 separation is applicable to other steam-assisted hydrocarbon recovery operation, such as, for example, a hydrocarbon recovery operation using cyclic steam stimulation (CSS).
[0066]Referring to Figure 6, in some implementations, the steam-0O2 separation unit 19 is incorporated into a SAGD operation. Oxygen 10, fuel 12 and feedwater 14 are fed into a DCSG 16 for generating a combustion mixture 18 including steam and 002. A first portion 18A of the steam-0O2 mixture is introduced into a steam-0O2 separation unit 19, which can be similar to the steam-separation units described above. Sweep gas 24 can be introduced as needed into the steam-CO2 separation unit 19 for driving the separation. A CO2-rich stream 22 and a CO2-depleted steam stream 20 are obtained. In some implementations, the 002-rich stream 22 can be further purified in order to produce pure CO2, stored for later use, employed as an injection fluid into a reservoir, or disposed of by any suitable means. In some scenarios, the CO2-rich stream 22 can be injected into the same reservoir during other phases of the SAGD operation or injected into other portions of the reservoir, such as thief zones. Injection of the CO2-rich stream 22 into the reservoir will be described in greater detail below. In other scenarios, the CO2-rich stream 22 can be stored for injection into other reservoirs as needed. In some implementations, the CO2-depleted steam stream 20 is recycled back to the DCSG 16 to be used as feedwater and fuel for the DCSG

16. As explained above, this recycling process allows the concentration of CO2 in the combustion mixture 18 to be lowered, as the CO2-depleted steam stream 20 contains only trace amounts of CO2. A second portion 18B of the combustion mixture 18 is injected into a SAGD injection well 46 for mobilizing hydrocarbons contained in a subsurface reservoir.
[0067]As explained above, the proportion of the combustion mixture 18 sent to the steam-0O2 separation unit 19 as stream 18A depends on the desired concentration of CO2 in the combustion mixture 18 when the continuous or steady-state regime is reached. In some scenarios, a concentration of CO2 of less than 4 wt% can be desired in the combustion mixture 18, for injection into the SAGD injection well 46. If the initial concentration of CO2 in the outlet stream 18 of the DCSG 16 is about 6 wt%, then about 33% of the combustion mixture 18 can be sent to the steam-0O2 separation unit 19 and about 66% of the combustion mixture 18 can be used for injection into the reservoir. Similarly, if the initial concentration of CO2 in the outlet stream 18 of the DCSG 16 is about wt%, then about 66% of the combustion mixture 18 is sent to the steam-0O2 separation unit 19 and about 33% of the combustion mixture 18 can be used for injection into the reservoir. It is understood that the "initial concentration of CO2 in the outlet stream of the DCSG" means the concentration of CO2 in the outlet stream of the DCSG 16 at the beginning of the process, when the steam-CO2 separation unit 19 and the recycling have not yet affected the concentration of CO2 in the outlet stream of the DCSG 16.
[0068]Still referring to Figure 6, produced fluids 48 are recovered from a production well 50 that is part of the hydrocarbon recovery operation. The produced fluids 48 can be separated into produced gas 52, produced non-gaseous hydrocarbons 54 and produced water 56 (typically oily water which can contain some solid materials) in a water-hydrocarbon separator 57. The produced gas 52 can be sent back to a central processing facility for separating light hydrocarbons from unwanted compounds or can directly be used as part of the fuel for the DCSG 16. The produced non-gaseous hydrocarbons 54 can , include heavy oil and/or bitumen and are typically further processed or upgraded in a central processing facility. At least part of the produced water 56 can be recycled back to the DCSG 16 to be used as feedwater. In some implementations, makeup water 58 is added to the produced water 56 for use as DCSG feedwater. As there is little to no produced gas 52 and produced water 56 during SAGD startup operations, the feedwater 14 and the fuel 12 respectively mainly consist of the makeup water 40 and an external source of fuel supplied to the DCSG 16. As production from the SAGD operation begins to ramp up, produced gas 52 and produced water 56 can be obtained from the water-hydrocarbon separator 57 and respectively used as part of the fuel 12 and feedwater 14, thereby requiring less makeup water 58 and external fuel. When the SAGD operation reaches a normal operating stage, the feedwater 14 can mainly include produced water 56, with a varying amount of makeup water 58 added as required. In some implementations, very little makeup water 58 is required when the SAGD operation reaches a ramped-up continuous regime.
When the reservoir retains water, as is often the case in SAGD startup, the proportion of makeup water 58 to total feedwater 14 is higher. When more water is recovered from the produced fluids 48, the proportion of makeup water 58 to total feedwater 14 is lower. In some scenarios, more water is released from the reservoir than is injected. In such cases, no makeup water is needed and the excess water recovered can be stored for later use.
[0069]In some implementations, the method for generating steam shown in Figure 3 can be used for steam generation in a SAGD hydrocarbon recovery process. In such a case, the outlet stream of a first DCSG 16 can be sent into a steam-0O2 separation unit 19 for generating a CO2-depleted steam stream 20.
The CO2-depleted steam stream 20 is then fed into a second DCSG 26 which therefore produces an outlet stream 28 having a lowered concentration of 002, and which can be injected into the SAGD injection well 46.
[0070]In some implementations, there is provided a system for recovering hydrocarbons from a reservoir. The system includes a DCSG 16 for generating a , combustion mixture 18. The DCSG 16 has an oxygen inlet, a fuel inlet and a feedwater inlet respectively connected to an oxygen supply line, a fuel supply line and a feedwater supply line. The DCSG 16 is provided with a combustion mixture outlet, and is in fluid communication with the steam-0O2 separation unit 19.
The steam-0O2 separation unit 19 is provided with a combustion mixture inlet, a sweep gas inlet, a CO2-rich stream outlet and a CO2-depleted steam stream outlet. In some implementations, the combustion mixture outlet of the DCSG 16 is connected to the steam-0O2 separation unit 19 through a splitter 25, and the CO2-depleted steam stream outlet of the separation unit 19 is connected to the fuel inlet (or another dedicated CO2-depleted steam stream inlet) of the DCSG
16. The splitter 25 separates the combustion mixture 18 into first and second portions 18A, 18B. The system also includes a well pad supporting a SAGD well pair, the SAGD well pair including a SAGD injection well 46 and a SAGD
production well 50. The SAGD injection well 46 is in fluid communication with the DCSG 16 through the splitter 25 and receives the second portion 18B of the combustion mixture 18. The SAGD production well 50 allows for the recovery of the produced fluids 48 from the reservoir. The system also includes a water-hydrocarbon separator 57 in fluid communication with the SAGD production well 50 to receive the produced fluids 48. The water-hydrocarbon separator 57 produces produced gas 52, produced non-gaseous hydrocarbons 54 and produced water 56. The water-hydrocarbon separator 57 can be in fluid communication with the DCSG 16, for example to feed at least a portion of the produced water 56 as feedwater to the DCSG 16 or to feed at least a portion of the produced gas 52 as fuel to the DCSG 16.
CO2 injection into reservoirs containing thief zones [0071]In hydrocarbon-bearing reservoirs, top zones that are at a lower pressure compared to the recovery operation pressures and may also be hydrocarbon-lean and water-rich, are considered challenging for hydrocarbon recovery using techniques such as SAGD. Over time, as the steam chamber forms above the injection well and extends upward and outward within the reservoir, heat and , steam can be lost to the overlying low pressure zone, which can also be called a "thief zone", leading to reduced performance of the hydrocarbon recovery operation. Thus, there are various challenges related to hydrocarbon recovery from reservoirs that include a thief zone.
[0072]Referring to figure 7, in some implementations, when the thief zone 60 is water-rich and hydrocarbon-lean, a dewatering process can be conducted in the water-rich thief zone 60 where the thief zone 60 is overlying a main pay zone of a hydrocarbon bearing reservoir 64. In some implementations, a CO2-rich stream 22 obtained from the steam-0O2 separation unit 19 is injected into the thief zone 60 via a CO2 injection well 66. The dewatering process can also include producing water 72 via at least one production well 68 provided in the thief zone 60. In some scenarios, several production wells 68 are provided in the thief zone 60 for removing water which can be replaced by the injected 002.
The production wells 68 and/or the CO2 injection well 66 can be substantially vertical or horizontal wells. In some scenarios, the injection of CO2 into the thief zone and the dewatering process can allow for the formation of a CO2-rich region 74 within the thief zone 60.
[0073] In some implementations, as CO2 is injected in the thief zone 60, water contained therein is replaced by the CO2 which then pressurizes the thief zone.
Pressurizing the thief zone with 002, which is a non-condensable gas (NCG), can aid in reducing steam losses from the high pressure hydrocarbon recovery operation and providing insulation since CO2 has a lower heat capacity compared to water. The pressurized thief zone can have pressures that are close to the pressure in the main pay zone 62 in order to minimize fluid movement into the thief zone.
[0074]Still referring to Figure 7, the dewatering process can be followed by operating a thermal in situ hydrocarbon recovery operation within the main pay zone 62. In some scenarios, the in situ hydrocarbon recovery operation is a SAGD operation. As explained above, a portion of the combustion mixture 18B of a DCSG is injected into the reservoir via the injection well (or injection wells) 46 to heat and reduce the viscosity of the hydrocarbons contained in the main pay zone 62. The mobilized hydrocarbons then drain into the lower producer well (or producer wells) 50 and are recovered to the surface. Over time, a steam chamber 76 forms above the injection wells 46 and expands upward and outward within the main pay zone 62, as the mobilized hydrocarbons flow toward the producer wells 50.
[0075]The pressurized gas-enriched thief zone 60 can prevent heat losses, due to the insulating effect of the CO2, thereby reducing the heat transfer from the main pay zone 62 into the thief zone 60. This is due to the low heat capacity of the injected CO2 and the pressurization of the zone by the injected gas.
[0076]In some scenarios, the pressurized zone above the steam chamber 76 can discourage upward growth of the steam chamber 76 into the steam chamber and encourage lateral growth of the steam chamber 76 within the main pay zone 62 during the SAGD operation. This promoted lateral growth of the steam chamber 76 can improve the steam coverage and overall performance of the SAGD operation.
[0077]In some implementations, the CO2 injection conditions can be provided and controlled at different stages of the SAGD operation, for example, to increase or decrease the gas pressure in the CO2-enriched region in the thief zone or to add other injection fluids, to enable various recovery conditions.
The combination of all those features can lead to enhanced hydrocarbon recovery rates and lower steam to oil ratio (SOR). In some implementations, additional NCGs can be co-injected with the CO2 into the thief zone 60.
[0078]Now referring to figure 8, in some implementations, a steam-0O2 mixture 18B can be injected into the main pay zone 62 of a hydrocarbon bearing reservoir 64 via an injection well (or injection wells) 46. The concentration of CO2 in the steam-0O2 mixture 18B can be selected and regulated to encourage that the CO2 from the steam-0O2 mixture separates and migrates towards an upper level of the main pay zone 62. In some scenarios, the CO2 migrates toward the upper boundary 70 of the steam chamber 76, thereby forming a CO2 blanket 78 overlying the steam chamber 76. In some scenarios, the CO2 blanket 78 can provide an insulating effect and reduce the heat transfer from the main pay zone 62 to the thief zone 60.
[0079]In some implementations, the concentration of CO2 in the steam-0O2 mixture 18B injected into the main pay zone 62 can be varied depending on the stage of the SAGD life cycle. For example, during SAGD startup and ramp up, a very low concentration of CO2 in the steam-0O2 mixture can be used so as speed up heat introduction into the reservoir. Providing heat to the reservoir helps establish fluid communication between the SAGD well pair and the subsequent development and expansion of the steam chamber 76. During normal operations, the concentration of CO2 in the injection fluid can be increased gradually so that the total steam consumption can be reduced and/or to allow CO2 to migrate upward to form an insulation layer near the overburden as well as to promote lateral steam chamber growth. During SAGD wind down, the concentration of CO2 in the steam-0O2 mixture can be significantly increased, for example up to 90 wt % of 002, in order to keep the main pay zone 62 pressurized, while minimizing costs and loss of heat and water. In some implementations, CO2 can be injected during SAGD wind down with minimal or no steam injection.
[008011n some implementations, there is provided a process for recovering hydrocarbons from a hydrocarbon-bearing reservoir located below and in fluid communication with a thief zone including water, the process including:
providing an oxygen-enriched mixture, fuel and feedwater to a DCSG; operating the DCSG
to obtain a combustion mixture including steam and 002; injecting the combustion mixture into the reservoir to mobilize the hydrocarbons therein, thereby obtaining mobilized hydrocarbons; and allowing at least part of the to migrate towards the thief zone, thereby forming a CO2 blanket between the steam chamber and the thief zone to provide insulation to the thief zone; and operating a thermal in situ recovery operation in the hydrocarbon-bearing reservoir such that the CO2-enriched thief zone provides heat insulation thereto.
[0081]It should also be understood that each of the processes described and illustrated in Figures 7 and 8 can be performed alone or in combination, as necessary. CO2 derived from the DCSG and steam-0O2 separation unit can be injected into a thief zone for pressurization, co-injected with steam into the SAGD
injection well, and/or injected alone or in combination with other fluids into other parts of the reservoir. It should also be noted that the CO2 that is used for injection can come from various different streams depending on the desired purpose. For example, the CO2-rich stream 22 can be used for injection when substantially high concentration of CO2 is desired (e.g., for pressurizing a thief zone and/or for SAGD wind down operations), while the DCSG combustion gas can be injected when lower CO2 concentrations are desired (e.g., for co-injection with steam into a SAGD injection well during normal operations).
EXAMPLES
Example 1 Experiments were conducted to separate steam and CO2 using a TorIon dense film separation membrane.
Steam was generated by injecting water at a flow rate of 5 mL/min into a steam generator. CO2 (at a flow rate of 50 ccm) and the steam were injected into the retentate side of the Torlone separation membrane at 200 C. Sweep gas (argon at a flow rate of 25 ccm) was injected into the permeate side of the Torlone separation membrane. The differential pressure between the permeate side and the retentate side was 5 psid.
The permeance of the CO2 through the membrane was measured to be 0.52 GPU, and the permeance of the steam through the membrane was measured to be 67 GPU. The membrane showed a steam/CO2 selectivity of 129, and steam-002 separation through the separation membrane was therefore effected.

, It is noteworthy that other gases can be successfully used as sweep gas in order to drive the separation of steam and CO2. For example, methane, which has a permeance of 0.02 GPU through the TorIon separation membrane, can be used as sweep gas.

Claims

WHAT IS CLAIMED IS:

1. An in situ thermal recovery process for recovering hydrocarbons from a reservoir, comprising:
providing an oxygen-enriched mixture, fuel and feedwater to a DCSG;
operating the DCSG to obtain a combustion mixture comprising steam and CO2;
separating all or part of the CO2 from the combustion mixture to obtain a CO2-depleted steam stream;
injecting the CO2-depleted steam stream or a stream derived from the CO2-depleted steam stream into the reservoir to mobilize the hydrocarbons therein, thereby obtaining mobilized hydrocarbons; and producing the mobilized hydrocarbons.

2. The process of claim 1, wherein the separating comprises separating a first portion of the combustion mixture into the CO2-depleted steam stream and a CO2-rich stream.

3. The process of claim 1 or 2, wherein the reservoir is located below a thief zone and is in fluid communication with the thief zone, the process further comprising injecting the CO2-rich stream via a CO2 injection well provided in the thief zone to form a CO2-enriched region providing heat insulation to the reservoir.

4. The process of claim 3, further comprising producing at least part of the water from the thief zone via a water production well provided in the thief zone.

5. A process for recovering hydrocarbons from a hydrocarbon-bearing reservoir located below and in fluid communication with a thief zone comprising water, the process comprising:
providing an oxygen-enriched mixture, fuel and feedwater to a DCSG;
operating the DCSG to obtain a combustion mixture comprising steam and CO2;
separating all or part of the CO2 from the combustion mixture to obtain a CO2-depleted steam stream and a CO2-rich stream;
injecting at least part of the CO2-depleted steam stream or a stream derived therefrom into the reservoir to mobilize the hydrocarbons therein, thereby obtaining mobilized hydrocarbons;
injecting at least part of the CO2-rich stream via a CO2 injection well provided in the thief zone to form a CO2-enriched region to pressurize the thief zone; and operating a thermal in situ recovery operation in the hydrocarbon-bearing reservoir.

6. The process of claim 5, further comprising producing water via a water production well provided in the thief zone.