CA3222047A1

CA3222047A1 - Integration of in situ bitumen recovery operations with oil sands mining and extraction operations

Info

Publication number: CA3222047A1
Application number: CA3222047A
Authority: CA
Inventors: Christopher Edwards; Sean Glendenning; Vicente Buendia
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2021-12-23
Filing date: 2021-12-23
Publication date: 2023-06-23
Also published as: CA3143845A1

Abstract

In situ recover facilities can be integrated with mining and extraction facilities. Superheated steam can be de-superheated at the extraction facility and then pipelined to the in situ facility for injection into the reservoir. Produced emulsion can be pipelined from the in situ facility to one or more points of the extraction facility to leverage extraction assets for emulsion processing. Integration can facilitate enhancements in terms of material and heat utilization for bitumen production.

Description

INTEGRATION OF IN SITU BITUMEN RECOVERY OPERATIONS WITH OIL
SANDS MINING AND EXTRACTION OPERATIONS
TECHNICAL FIELD
[001] The technical field generally relates to processing and recovering bitumen, and particularly the integration between in situ recovery operations and oil sands surface mining and extraction operations.
BACKGROUND

[002] Bitumen-containing emulsions recovered from in situ operations, e.g., steam-assisted gravity drainage (SAGD) operations, mainly contain bitumen, water and some solids when steam based methods are used. In situ produced bitumen emulsions require further treatment, primarily involving removal of produced water, before the bitumen can be upgraded or sold.

[003] Usually, in situ produced bitumen emulsion is recovered to the surface and supplied to a surface facility at or near the in situ well site. At the surface facility, the bitumen is typically diluted with naphthenic diluent or natural gas condensate and water and solids are then removed from the emulsion, primarily via gravity separation. The diluted bitumen is then typically supplied to upgraders or directly sold to the market.

[004] Mined oil sands ore is processed in a mining and extraction facility where the ore is crushed, sized and mixed with hot water to produce a bitumen-containing slurry which is subjected to processing. The slurry is pipelined to a primary extraction facility where it is separated into two main streams, bitumen froth and tailings. The bitumen froth is then treated in a secondary extraction facility by adding a solvent or diluent to the bitumen froth in order to reduce the viscosity of the bitumen and enable effective separation between the bitumen phase and the water/solids phase. This secondary extraction process is often referred to as froth Date Recue/Date Received 2023-12-05 treatment. Two main types of froth treatment process are currently used in the oil sands: naphthenic froth treatment (NFT) and paraffinic froth treatment (PFT).

[005] There are various challenges in terms of efficient use of assets in the context of in situ recovery operations as well as mining and extraction operations.
For example, close to or at the end of the oil sands mine life, assets can become obsolete at the mining and extraction facility. There is a need for technologies to facilitate efficient use of assets for bitumen recovery and extraction.
SUMMARY

[006] In accordance with one aspect, there is provided a process for treating an emulsion comprising bitumen and water produced at an in situ recovery operation site, in an oil sands mining and extraction facility comprising a primary extraction facility and a secondary extraction facility, wherein the oil sands mining and extraction facility is concurrently operated to treat an oil sands slurry derived from a mined oil sands ore, the process comprising: degassing the emulsion to form a degassed emulsion stream; cooling the degassed emulsion stream at the oil sands mining and extraction facility to form a cooled degassed emulsion stream;
aerating the cooled degassed emulsion stream to form an aerated emulsion stream;
treating the aerated emulsion stream in the oil sands mining and extraction facility to recover a bitumen-containing product and separated water.

[007] In some implementations, degassing removes methane and/or H2S from the emulsion. In some implementations, the degassed emulsion stream has a methane concentration less than about 5 ppm. In some implementations, the degassed emulsion stream has a methane concentration less than about 1 ppm.
In some implementations, the degassed emulsion stream has an H2S
concentration less than about 4 ppm. In some implementations, the degassed emulsion stream has an H2S concentration less than about 0.5 ppm.
Date Recue/Date Received 2023-12-05

[008] In some implementations, degassing comprises flashing at least H2S and methane from the emulsion. In some implementations, flashing is performed at the in situ recovery operation site. In some implementations, the process further comprises scavenging dissolved H2S remaining in the emulsion after flashing.
In some implementations, H2S scavenging is performed by addition of a chemical scavenger comprising at least one amine to the emulsion. In some implementations, the chemical scavenger comprises an amine-aldehyde condensate or a triazine. In some implementations, scavenging is performed at the in situ recovery operation site. In some implementations, scavenging is performed at the oil sands mining and extraction facility. In some implementations, scavenging is performed before cooling. In some implementations, scavenging is performed after cooling.

[009] In some implementations, the cooled degassed emulsion stream has a temperature ranging from about 50 to about 85 C. In some implementations, the cooled degassed emulsion stream has a temperature ranging from about 55 to about 70 C.

[0010] In some implementations, cooling is performed in at least one heat exchanger by indirectly contacting the degassed emulsion with a cooling fluid thereby recovering a heated fluid. In some implementations, the cooling fluid comprises tailings pond effluent water (PEW) and hot PEW is recovered after the heat exchanger.

[0011] In some implementations, cooling is performed by indirectly contacting the degassed emulsion with a first cooling fluid comprising boiler feed water (BFW) in a first heat exchanger and with a second cooling fluid comprising PEW in a second heat exchanger, wherein hot BFW is recovered after the first heat exchanger and hot PEW is recovered after the second heat exchanger. In some implementations, the hot BFW is further sent to a steam generation unit to generate steam to be used at the in situ recovery operation site.
Date Recue/Date Received 2023-12-05

[0012] In some implementations, the process further comprises contacting the mined oil sands ore with the hot PEW to obtain the oil sands slurry to be supplied to the primary extraction facility.

[0013] In some implementations, the process further comprises mixing at least a portion of the hot PEW with the oil sands slurry to be supplied to the primary extraction facility.

[0014] In some implementations, the aerating comprises adding air into the cooled emulsion stream. In some implementations, the aerating comprises adding air into the cooled emulsion stream using an aeration nozzle, a sparger aeration nozzle, an eductor, as dissolved air, via inducing gas into the suction of a pump, or via addition of an aerated secondary fluid into the cooled emulsion stream.

[0015] In some implementations, treating the aerated emulsion stream comprises: combining the aerated emulsion stream with the oil sands slurry upstream the primary extraction facility to form a combined stream; supplying the combined stream to a primary separation vessel (PSV) of the primary extraction facility to produce a bitumen froth stream as overflow, a middlings stream, and a primary extraction tailings stream as underflow; treating the bitumen froth stream in the secondary extraction facility to recover the bitumen-containing product.

[0016] In some implementations, treating the aerated emulsion stream comprises: supplying the aerated emulsion stream to a primary separation vessel (PSV) of the primary extraction facility while concurrently feeding the oil sands slurry to the primary separation vessel to produce a bitumen froth stream as overflow, a middlings stream, and a primary extraction tailings stream as underflow; treating the bitumen froth stream in the secondary extraction facility to recover the bitumen-containing product.

[0017] In some implementations, the process further comprises: separating the middlings stream in a first flotation unit to recover a first flotation unit overflow Date Recue/Date Received 2023-12-05 stream comprising bitumen and a first flotation unit underflow stream; and recycling the first flotation unit overflow stream to the primary separation vessel.

[0018] In some implementations, the process further comprises: feeding the first flotation unit underflow stream and the primary extraction tailings stream to at least one cyclone to recover a cyclone overflow stream and a cyclone underflow stream;
separating the cyclone overflow stream in a second flotation unit to recover a second flotation unit overflow stream comprising bitumen and a second flotation unit underflow stream; combining the second flotation unit underflow stream and the cyclone underflow stream to form a combined tailings stream.

[0019] In some implementations, the process further comprises returning the second flotation unit overflow stream to the primary separation vessel.

[0020] In some implementations, the process further comprises disposing of the combined tailings stream in a tailings pond.

[0021] In some implementations, the aerating is performed by treating the cooled degassed emulsion stream in a flotation system. In some implementations, the flotation system comprises flotation cells, scavenger banks, column flotation vessels, an induced gas flotation system, a DAF system, or a microbubble flotation systems. In some implementations, the flotation cell system is a single stage flotation cell system. In some implementations, the flotation cell system is a two stage flotation cell system.

[0022] In some implementations, the aerating comprises: separating the cooled degassed emulsion stream in a first flotation unit to produce the aerated emulsion stream as a first flotation unit overflow stream and a first flotation unit underflow stream; supplying the first flotation unit underflow stream to a second flotation unit and producing a second flotation unit overflow stream comprising bitumen and a second flotation unit underflow stream comprising water.
Date Recue/Date Received 2023-12-05

[0023] In some implementations, the process further comprises returning the second flotation unit overflow stream to the first flotation unit.

[0024] In some implementations, the process further comprises mixing the second flotation unit overflow stream with the first flotation unit overflow to produce the aerated emulsion stream.

[0025] In some implementations, the second flotation unit underflow stream has a temperature ranging from about 50 to about 75 C.

[0026] In some implementations, the second flotation unit underflow stream has a temperature ranging from about 55 to about 70 C.

[0027] In some implementations, the process further comprises mixing at least a portion of the second flotation unit underflow with hot process water to form a heated process water stream, and contacting the oil sands ore with the heated process water stream to obtain the oil sands slurry to be supplied to the primary extraction facility.

[0028] In some implementations, the process further comprises: diverting a portion of the degassed emulsion stream to form a diverted degassed emulsion stream; combining the diverted degassed emulsion stream with at least a portion of the second flotation unit underflow stream to obtain a hot emulsion; mixing the hot emulsion with process water to form a heated process water stream; and contacting the oil sands ore with the heated process water stream to obtain the oil sands slurry to be supplied to the primary extraction facility.

[0029] In some implementations, the process further comprises deaerating the first flotation unit overflow stream to obtain a deaerated stream and treating the deaerated stream in the secondary extraction facility to obtain the bitumen-containing product.

[0030] In some implementations, the flotation system comprises a dedicated flotation system provided at the oil sands mining and extraction facility.
Date Recue/Date Received 2023-12-05

[0031] In some implementations, the flotation system comprises a pre-existing flotation system downstream of a primary separation vessel of the primary extraction facility.

[0032] In some implementations, the process further comprises: recycling at least a portion of the first flotation unit overflow stream back into the primary separation vessel; or recycling a portion of the first flotation unit overflow stream back into the primary separation vessel and supplying another portion of the first flotation unit overflow stream to deaerating and then to the secondary extraction facility;
or supplying the first flotation unit overflow stream to deaerating and then to the secondary extraction facility.

[0033] In some implementations, the secondary extraction facility comprises a naphthenic froth treatment facility.

[0034] In some implementations, the secondary extraction facility comprises a paraffinic froth treatment facility.

[0035] In some implementations, the in situ recovery operation comprises a steam-assisted gravity drainage (SAG D) operation.

[0036] In some implementations, the in situ recovery operation comprises a solvent-assisted recovery operation.

[0037] In some implementations, the in situ recovery operation comprises a solvent-dominated recovery operation.

[0038] In accordance with another aspect, there is provided a process for treating an emulsion comprising bitumen and water produced at an in situ recovery operation site, in an oil sands mining and extraction facility comprising a primary extraction facility and a secondary extraction facility, the process comprising:
providing an oil sands slurry stream obtained by treating oil sands ore recovered from a surface mining operation with process water upstream the primary extraction facility; separating the oil sands slurry stream in a primary separation Date Recue/Date Received 2023-12-05 vessel of the primary extraction facility to recover a first bitumen froth, a middlings stream and a primary extraction tailings stream; degassing the emulsion to form a degassed emulsion stream; cooling the degassed emulsion stream to form a cooled degassed emulsion stream; mixing the cooled degassed emulsion stream with the middlings stream to form a mixed bitumen-containing stream; treating the mixed bitumen-containing stream in a flotation system to produce a second bitumen froth and a flotation tailings stream.

[0039] In some implementations, degassing removes methane and/or H2S from the emulsion. In some implementations, the degassed emulsion stream has a methane concentration less than about 5 ppm. In some implementations, the degassed emulsion stream has a methane concentration less than about 1 ppm.
In some implementations, the degassed emulsion stream has an H2S
concentration less than about 4 ppm. In some implementations, the degassed emulsion stream has an H2S concentration less than about 0.5 ppm.

[0040] In some implementations, degassing comprises flashing at least H2S and methane from the emulsion. In some implementations, flashing is performed at the in situ recovery operation site. In some implementations, the process further comprises scavenging dissolved H2S remaining in the emulsion after flashing.
In some implementations, H2S scavenging is performed by addition of a chemical scavenger comprising at least one amine to the emulsion. In some implementations, the chemical scavenger comprises an amine-aldehyde condensate or a triazine. In some implementations, scavenging is performed at the in situ recovery operation site. In some implementations, scavenging is performed at the oil sands mining and extraction facility. In some implementations, scavenging is performed before cooling. In some implementations, scavenging is performed after cooling.

[0041] In some implementations, the cooled degassed emulsion stream has a temperature ranging from about 50 to about 85 C. In some implementations, the Date Recue/Date Received 2023-12-05 cooled degassed emulsion stream has a temperature ranging from about 55 to about 70 C.

[0042] In some implementations, cooling is performed in at least one heat exchanger by indirectly contacting the degassed emulsion with a cooling fluid thereby recovering a heated fluid. In some implementations, the cooling fluid comprises tailings pond effluent water (PEW) and hot PEW is recovered after the heat exchanger.

[0043] In some implementations, cooling is performed by indirectly contacting the degassed emulsion with a first cooling fluid comprising boiler feed water (BFW) in a first heat exchanger and with a second cooling fluid comprising PEW in a second heat exchanger, wherein hot BFW is recovered after the first heat exchanger and hot PEW is recovered after the second heat exchanger. In some implementations, the hot BFW is further sent to a steam generation unit to generate steam to be used at the in situ recovery operation site.

[0044] In some implementations, the process further comprises contacting the mined oil sands ore with at least a portion of the hot PEW to obtain the oil sands slurry to be supplied to the primary extraction facility.

[0045] In some implementations, the process further comprises mixing at least a portion of the hot PEW with the oil sands slurry to be supplied to the primary extraction facility.

[0046] In some implementations, treating the mixed bitumen-containing stream comprises: feeding the mixed bitumen-containing stream in a first flotation unit to produce the second bitumen froth as a first flotation unit overflow stream, and recover a first flotation unit underflow stream; combining the first flotation unit underflow stream and the primary extraction tailings stream to form a first combined tailings stream.
Date Recue/Date Received 2023-12-05

[0047] In some implementations, the process further comprises sending the second bitumen froth to the secondary extraction facility.

[0048] In some implementations, the second bitumen froth is combined with the first bitumen froth before being sent to the secondary extraction facility.

[0049] In some implementations, treating the mixed bitumen-containing stream comprises: feeding the mixed bitumen-containing stream in a first flotation unit to produce the second bitumen froth and a first flotation unit underflow stream;
recycling at least a portion of the second bitumen froth to the primary separation vessel; combining the first flotation unit underflow stream and the primary extraction tailings stream to form a first combined tailings stream.

[0050] In some implementations, the process further comprises sending the first bitumen froth to the secondary extraction facility.

[0051] In some implementations, the process further comprises: separating the first combined tailings stream in at least one cyclone to recover a cyclone overflow stream and a cyclone underflow stream; separating the cyclone overflow stream in a second flotation unit to recover a second flotation unit overflow stream comprising bitumen and a second flotation unit underflow stream; combining the second flotation unit underflow stream and the cyclone underflow stream to form a second combined tailings stream.

[0052] In some implementations, the process further comprises returning the second flotation unit overflow stream to the primary separation vessel.

[0053] In some implementations, the process further comprises disposing of the second combined tailings stream in a tailings pond.

[0054] In some implementations, the secondary extraction facility comprises a naphthenic froth treatment facility.
Date Recue/Date Received 2023-12-05

[0055] In some implementations, the secondary extraction facility comprises a paraffinic froth treatment facility.

[0056] In some implementations, the in situ recovery operation comprises a steam-assisted gravity drainage (SAG D) operation.

[0057] In some implementations, the in situ recovery operation comprises a solvent-assisted recovery operation.

[0058] In some implementations, the in situ recovery operation comprises a solvent-dominated recovery operation.

[0059] In accordance with another aspect, there is provided a process for heating process water to be used for treating oil sands ore recovered from a surface mining operation so as to form an oil sands slurry stream for hydrotransport to be separated in a primary extraction facility, the process comprising: producing a hot emulsion comprising bitumen and water at an in situ recovery operation site;
degassing the hot emulsion to form a hot degassed emulsion stream; and mixing the hot degassed emulsion stream with the process water to form a heated process water stream.

[0060] In some implementations, degassing removes methane and/or H25 from the emulsion. In some implementations, the degassed emulsion stream has a methane concentration less than about 5 ppm. In some implementations, the degassed emulsion stream has a methane concentration less than about 1 ppm.
In some implementations, degassing comprises removing at least H25 from the emulsion by scavenging. In some implementations, the degassed emulsion stream has an H25 concentration less than about 4 ppm. In some implementations, the degassed emulsion stream has an H25 concentration less than about 0.5 ppm. In some implementations, degassing comprises flashing at least H25 and methane from the emulsion. In some implementations, flashing is performed at the in situ recovery operation site. In some implementations, the process further comprises scavenging dissolved H25 remaining in the emulsion after flashing. In some Date Recue/Date Received 2023-12-05 implementations, H2S scavenging is performed by addition of a chemical scavenger comprising at least one amine to the emulsion. In some implementations, the chemical scavenger comprises an amine-aldehyde condensate or a triazine. In some implementations, scavenging is performed at the in situ recovery operation site. In some implementations, scavenging is performed at the oil sands mining and extraction facility.

[0061] In some implementations, the hot degassed emulsion stream is at a temperature ranging from about 120 C to about 220 C, before mixing with the process water. In some implementations, the process water comprises water recovered from a tailings pond. In some implementations, the water recovered from the tailings pond comprises water originated from the emulsion. In some implementations, the process water comprises water originated from the emulsion.

[0062] In some implementations, the in situ recovery operation comprises a steam-assisted gravity drainage (SAG D) operation.

[0063] In some implementations, the in situ recovery operation comprises a solvent-assisted recovery operation.

[0064] In some implementations, the in situ recovery operation comprises a solvent-dominated recovery operation.

[0065] In accordance with another aspect, there is provided a process for producing an oil sands slurry stream to be separated in a primary extraction facility of an oil sands mining and extraction facility comprising: producing an emulsion comprising bitumen and water at an in situ recovery operation site; degassing the emulsion to form a degassed emulsion stream; cooling the degassed emulsion stream at the oil sands mining and extraction facility to form a cooled degassed emulsion stream; and concurrently supplying the cooled degassed emulsion stream with a mined oil sand ore stream to at least one rotary breaker of the oil sands mining and extraction facility; mixing the cooled degassed emulsion and the Date Recue/Date Received 2023-12-05 mined oil sand ore with hot process water in the rotary breaker to produce the oil sands slurry stream.

[0066] In some implementations, degassing removes methane and/or H2S from the emulsion. In some implementations, the degassed emulsion stream has a methane concentration less than about 5 ppm. In some implementations, the degassed emulsion stream has a methane concentration less than about 1 ppm.
In some implementations, the degassed emulsion stream has an H2S
concentration less than about 4 ppm. In some implementations, the degassed emulsion stream has an H2S concentration less than about 0.5 ppm. In some implementations, degassing comprises flashing at least H2S and methane from the emulsion. In some implementations, flashing is performed at the in situ recovery operation site. In some implementations, the process further comprises scavenging dissolved H2S remaining in the emulsion after flashing. In some implementations, H2S scavenging is performed by addition of a chemical scavenger comprising at least one amine to the emulsion. In some implementations, the chemical scavenger comprises an amine-aldehyde condensate or a triazine. In some implementations, scavenging is performed at the in situ recovery operation site. In some implementations, scavenging is performed at the oil sands mining and extraction facility. In some implementations, scavenging is performed before cooling. In some implementations, scavenging is performed after cooling.

[0067] In some implementations, the degassed emulsion stream is at a temperature ranging from about 120 C to about 220 C before cooling.

[0068] In some implementations, cooling is performed by quenching the degassed emulsion with tailings pond effluent water (PEW).

[0069] In some implementations, cooling is performed at least by indirectly contacting the degassed emulsion with PEW in a heat exchanger and hot PEW is recovered after the heat exchanger.
Date Recue/Date Received 2023-12-05

[0070] In some implementations, cooling is performed at least by indirectly contacting the degassed emulsion with boiler feed water (BFW) in a first heat exchanger and with PEW in a second heat exchanger, wherein hot BFW is recovered after the first heat exchanger and hot PEW is recovered after the second heat exchanger.

[0071] In some implementations, the hot BFW is further sent to a steam generation unit to generate steam to be used at the in situ recovery operation site.

[0072] In some implementations, the process further comprises using at least a portion of the hot PEW as the hot process water.

[0073] In some implementations, the process further comprises mixing at least a portion of the hot PEW with the oil sands slurry produced in the rotary breaker.

[0074] In some implementations, cooling is performed by indirectly contacting the degassed emulsion with boiler feed water (BFW) in a first heat exchanger and then quenching with PEW or with a water stream produced from a flotation system.

[0075] In some implementations, cooling is performed at least by quenching the degassed emulsion with a water stream produced from a flotation system.

[0076] In some implementations, the in situ recovery operation comprises a steam-assisted gravity drainage (SAG D) operation.

[0077] In some implementations, the in situ recovery operation comprises a solvent-assisted recovery operation.

[0078] In some implementations, the in situ recovery operation comprises a solvent-dominated recovery operation.

[0079] In accordance with another aspect, there is provided a process for treating an emulsion comprising bitumen and water produced at an in situ recovery operation site, in an oil sands mining and extraction facility comprising a primary extraction facility and a secondary extraction facility, the process comprising:
Date Recue/Date Received 2023-12-05 degassing the emulsion to form a degassed emulsion stream; cooling the degassed emulsion stream to form a cooled degassed emulsion stream;
dewatering the cooled degassed emulsion stream at the oil sands mining and extraction facility to recover a dewatered emulsion stream; producing a bitumen froth by treating an oil sands slurry stream in the primary extraction facility; treating the dewatered emulsion stream concurrently with the bitumen froth in the secondary extraction facility to recover a bitumen-containing product.

[0080] In some implementations, degassing removes methane and/or H2S from the emulsion. In some implementations, the degassed emulsion stream has a methane concentration less than about 5 ppm. In some implementations, the degassed emulsion stream has a methane concentration less than about 1 ppm.
In some implementations, the degassed emulsion stream has an H2S
concentration less than about 4 ppm. In some implementations, the degassed emulsion stream has an H2S concentration less than about 0.5 ppm. In some implementations, degassing comprises flashing at least H2S and methane from the emulsion. In some implementations, flashing is performed at the in situ recovery operation site. In some implementations, the process further comprises scavenging dissolved H2S remaining in the emulsion after flashing. In some implementations, H2S scavenging is performed by addition of a chemical scavenger comprising at least one amine to the emulsion. In some implementations, the chemical scavenger comprises an amine-aldehyde condensate or a triazine. In some implementations, scavenging is performed at the in situ recovery operation site. In some implementations, scavenging is performed at the oil sands mining and extraction facility. In some implementations, scavenging is performed before cooling. In some implementations, scavenging is performed after cooling.

[0081] In some implementations, dewatering comprises adding a dewatering solvent to the cooled degassed emulsion stream to produce a solvent diluted Date Recue/Date Received 2023-12-05 emulsion stream and separating water from the solvent diluted emulsion stream by gravity.

[0082] In some implementations, the dewatering solvent comprises a blend of light hydrocarbons characterized by a vapour pressure of less than 14.7 psia and/or a density of from about 650 to about 850 kg/m3.

[0083] In some implementations, the dewatering solvent comprises a naphthenic diluent.

[0084] In some implementations, the process comprises combining the dewatered emulsion stream and the bitumen froth upstream the secondary extraction facility to produce a combined bitumen froth and supplying the combined bitumen froth to the secondary extraction facility for treating.

[0085] In some implementations, the process comprises supplying the dewatered emulsion and the bitumen froth separately to the secondary extraction facility and treating the dewatered emulsion and the bitumen froth simultaneously into the secondary extraction facility.

[0086] In some implementations, treating comprises: separating the combined bitumen froth in a gravity separation vessel into a gravity separation vessel overflow comprising the bitumen-containing product and a gravity separation vessel underflow; separating the gravity separation vessel underflow in at least one centrifugal separation vessel into a centrifugal overflow and a centrifugal underflow comprising some solvent and water.

[0087] In some implementations, treating comprises: separating the dewatered emulsion stream and the bitumen froth in a gravity separation vessel into a gravity separation vessel overflow comprising the bitumen-containing product and a gravity separation vessel underflow; separating the gravity separation vessel underflow in at least one centrifugal separation vessel into a centrifugal overflow and a centrifugal underflow comprising some solvent and water.
Date Recue/Date Received 2023-12-05

[0088] In some implementations, the gravity separation vessel comprises an inclined plate separator.

[0089] In some implementations, the centrifugal separation vessel comprises at least one cyclone set.

[0090] In some implementations, the process further comprises sending the centrifugal underflow in a solvent recovery unit to separate the solvent and recover condensate water.

[0091] In some implementations, the condensate water is used to cool a superheated steam stream before injection in the in situ recovery operation.

[0092] In some implementations, treating in the secondary extraction is performed with a naphthenic diluent.

[0093] In some implementations, treating in the secondary extraction is performed with a paraffinic solvent.

[0094] In some implementations, the in situ recovery operation comprises a steam-assisted gravity drainage (SAG D) operation.

[0095] In some implementations, the in situ recovery operation comprises a solvent-assisted recovery operation.

[0096] In some implementations, the in situ recovery operation comprises a solvent-dominated recovery operation.

[0097] In accordance with another aspect, there is provided a process for treating an emulsion comprising bitumen and water produced at an in situ recovery operation site, in an oil sands mining and extraction facility comprising at least one primary extraction facility and a secondary extraction facility, the process comprising: degassing the emulsion to form a degassed emulsion stream; cooling the degassed emulsion stream at the oil sands mining and extraction facility to form a cooled degassed emulsion stream; treating the cooled degassed emulsion Date Recue/Date Received 2023-12-05 stream at the primary extraction facility to produce a bitumen froth stream and a produced water stream.

[0098] In some implementations, degassing removes methane and/or H2S from the emulsion. In some implementations, the degassed emulsion stream has a methane concentration less than about 5 ppm. In some implementations, In some implementations, the degassed emulsion stream has a methane concentration less than about 1 ppm. In some implementations, the degassed emulsion stream has an H2S concentration less than about 4 ppm. In some implementations, the degassed emulsion stream has an H2S concentration less than about 0.5 ppm. In some implementations, degassing comprises flashing at least H2S and methane from the emulsion. In some implementations, flashing is performed at the in situ recovery operation site. In some implementations, the process further comprises scavenging dissolved H2S remaining in the emulsion after flashing. In some implementations, H2S scavenging is performed by addition of a chemical scavenger comprising at least one amine to the emulsion. In some implementations, the chemical scavenger comprises an amine-aldehyde condensate or a triazine. In some implementations, scavenging is performed at the in situ recovery operation site. In some implementations, scavenging is performed at the oil sands mining and extraction facility. In some implementations, scavenging is performed before cooling. In some implementations, scavenging is performed after cooling.

[0099] In some implementations, the cooled degassed emulsion stream has a temperature ranging from about 50 to about 85 C. In some implementations, the cooled degassed emulsion stream has a temperature ranging from about 55 to about 70 C.

[00100] In some implementations, cooling is performed in at least one heat exchanger by indirectly contacting the degassed emulsion with tailings pond effluent water (PEW) and hot PEW is recovered after the heat exchanger.
Date Recue/Date Received 2023-12-05

[00101] In some implementations, cooling is performed by indirectly contacting the degassed emulsion with a first cooling fluid comprising boiler feed water (BFW) in a first heat exchanger and then with a second cooling fluid comprising PEW
in a second heat exchanger, wherein hot BFW is recovered after the first heat exchanger and hot PEW is recovered after the heat second exchanger.

[00102] In some implementations, cooling comprises indirectly contacting the degassed emulsion with: a first cooling fluid comprising boiler feed water (BFW) in a first heat exchanger; a second cooling fluid comprising the produced water stream in a second heat exchanger; and PEW in a third heat exchanger; wherein hot BFW is recovered after the first heat exchanger, hot produced water is recovered after the second heat exchanger, and hot PEW is recovered after the third heat exchanger.

[00103] In some implementations, cooling comprises indirectly contacting the degassed emulsion with: a first cooling fluid comprising boiler feed water (BFW) in a first heat exchanger; a second cooling fluid comprising the bitumen froth stream in a second heat exchanger; and PEW in a third heat exchanger; wherein hot BFW

is recovered after the first heat exchanger, a heated bitumen froth is recovered after the second heat exchanger, and hot PEW is recovered after the third heat exchanger.

[00104] In some implementations, cooling comprises indirectly contacting the degassed emulsion with: a first cooling fluid comprising the produced water stream in a first heat exchanger; a second cooling fluid comprising the bitumen froth stream in a second heat exchanger; and PEW in a third heat exchanger; wherein hot produced water is recovered after the first heat exchanger, a heated bitumen froth is recovered after the second heat exchanger, and hot PEW is recovered after the third heat exchanger.

[00105] In some implementations, cooling comprises indirectly contacting the degassed emulsion with: a first cooling fluid comprising boiler feed water (BFW) in Date Recue/Date Received 2023-12-05 a first heat exchanger; a second cooling fluid comprising the produced water stream in a second heat exchanger; a third cooling fluid comprising the bitumen froth stream in a third heat exchanger; and PEW in a fourth heat exchanger;
wherein hot BFW is recovered after the first heat exchanger, hot produced water is recovered after the second heat exchanger, a heated bitumen froth is recovered after the third heat exchanger, and hot PEW is recovered after the fourth heat exchanger.

[00106] In some implementations, the hot BFW is further sent to a steam generation unit to generate steam to be used at the in situ recovery operation site.

[00107] In some implementations, the hot produced water is further sent to a water treatment unit at the oil sands mining and extraction facility to generate BFW
which can be re-used for cooling the degassed emulsion.

[00108] In some implementations, the process further comprises mixing at least a portion of the hot PEW with the hot produced water upstream the water treatment unit.

[00109] In some implementations, the heated bitumen froth is further sent to the secondary extraction facility.

[00110] In some implementations, treating the cooled degassed emulsion stream comprises: aerating the cooled degassed emulsion stream to form an aerated emulsion stream; separating the aerated emulsion stream in a primary separation vessel (PSV) into a PSV overflow comprising the bitumen froth stream and a PSV

underflow; supplying the PSV underflow to a flotation system to recover the produced water stream.

[00111] In some implementations, aerating comprises adding air into the cooled emulsion stream. In some implementations, aerating comprises adding air into the cooled emulsion stream using an aeration nozzle, a sparger aeration nozzle, an Date Recue/Date Received 2023-12-05 eductor, as dissolved air, via inducing gas into the suction of a pump, or via addition of an aerated secondary fluid into the cooled emulsion stream.

[00112] In some implementations, treating the cooled degassed emulsion stream comprises supplying the cooled degassed emulsion stream to a flotation system.

In some implementations, the flotation system comprises flotation cells, scavenger banks, column flotation vessels, an induced gas flotation system, a DAF
system, or a microbubble flotation systems. In some implementations, the flotation cell system is a single stage flotation cell system. In some implementations, the flotation cell system is a two stage flotation cell system.

[00113] In some implementations, the treating comprises: separating the cooled degassed emulsion stream in a first flotation unit to produce the bitumen froth stream as a first flotation unit overflow stream and a first flotation unit underflow stream; supplying the first flotation unit underflow stream to a second flotation unit and producing a second flotation unit overflow stream comprising bitumen and a second flotation unit underflow stream comprising the produced water.

[00114] In some implementations, the process further comprises returning the second flotation unit overflow stream to the first flotation unit.

[00115] In some implementations, the process further comprises mixing the second flotation unit overflow stream with the first flotation unit overflow to produce the bitumen froth stream.

[00116] In some implementations, the second flotation unit underflow stream has a temperature ranging from about 50 C to about 75 C. In some implementations, the second flotation unit underflow stream has a temperature ranging from about 55 C to about 70 C.

[00117] In some implementations, the flotation system comprises a dedicated flotation system provided at the oil sands mining and extraction facility.
Date Recue/Date Received 2023-12-05

[00118] In some implementations, the flotation system comprises a pre-existing flotation system downstream of a primary separation vessel of the primary extraction facility.

[00119] In some implementations, the process further comprises suppling the bitumen froth stream to the secondary extraction facility.

[00120] In some implementations, the process further comprises mixing the bitumen froth stream with another bitumen froth stream produced from a mined oil sands slurry in another primary facility of the oil sands mining and extraction facility, to form a mixed froth, and supplying the mixed froth to the secondary extraction facility.

[00121] In some implementations, the in situ recovery operation comprises a steam-assisted gravity drainage (SAG D) operation.

[00122] In some implementations, the in situ recovery operation comprises a solvent-assisted recovery operation.

[00123] In some implementations, the in situ recovery operation comprises a solvent-dominated recovery operation.

[00124] In accordance with another aspect, there is provided a process for treating an emulsion comprising bitumen and water produced at an in situ recovery operation site, in an oil sands mining and extraction facility comprising a primary extraction facility and a secondary extraction facility, the process comprising:
degassing the emulsion to form a degassed emulsion stream; cooling the degassed emulsion stream to form a cooled degassed emulsion stream; adding a solvent or diluent to the cooled degassed emulsion stream to produce a diluted emulsion stream; treating the diluted emulsion stream in the secondary extraction facility to recover a diluted bitumen product and a produced water stream.

[00125] In some implementations, degassing removes methane and/or H25 from the emulsion. In some implementations, the degassed emulsion stream has a Date Recue/Date Received 2023-12-05 methane concentration less than about 5 ppm. In some implementations, the degassed emulsion stream has a methane concentration less than about 1 ppm.
In some implementations, the degassed emulsion stream has an H2S
concentration less than about 4 ppm. In some implementations, the degassed emulsion stream has an H2S concentration less than about 0.5 ppm. In some implementations, degassing comprises flashing at least H2S and methane from the emulsion. In some implementations, flashing is performed at the in situ recovery operation site. In some implementations, the process further comprises scavenging dissolved H2S remaining in the emulsion after flashing. In some implementations, H2S scavenging is performed by addition of a chemical scavenger comprising at least one amine to the emulsion. In some implementations, the chemical scavenger comprises an amine-aldehyde condensate or a triazine. In some implementations, scavenging is performed at the in situ recovery operation site. In some implementations, scavenging is performed at the oil sands mining and extraction facility. In some implementations, scavenging is performed before cooling. In some implementations, scavenging is performed after cooling.

[00126] In some implementations, the cooled degassed emulsion stream has a temperature ranging from about 50 to about 85 C. In some implementations, the cooled degassed emulsion stream has a temperature ranging from about 55 to about 70 C.

[00127] In some implementations, cooling is performed in at least one heat exchanger by indirectly contacting the degassed emulsion with tailings pond effluent water (PEW) and hot PEW is recovered after the heat exchanger.

[00128] In some implementations, cooling is performed by indirectly contacting the degassed emulsion with a first cooling fluid comprising the produced water stream in a first heat exchanger and then with a second cooling fluid comprising PEW in a second heat exchanger, wherein hot produced water is recovered after Date Recue/Date Received 2023-12-05 the first heat exchanger and hot PEW is recovered after the heat second exchanger.

[00129] In some implementations, the process further comprises before cooling, a step of flashing the degassed emulsion stream to produce steam and a partially dewatered degassed emulsion stream, wherein cooling the degassed emulsion stream to form the cooled degassed emulsion stream comprises cooling the partially dewatered degassed emulsion stream.

[00130] In some implementations, the produced steam is further used to provide heat for evaporating water in a water treatment unit of the oil sands mining and extraction facility.

[00131] In some implementations, cooling comprises indirectly contacting the degassed emulsion with: a first cooling fluid comprising boiler feed water (BFW) in a first heat exchanger; a second cooling fluid comprising the produced water stream in a second heat exchanger; and PEW in a third heat exchanger; wherein hot BFW is recovered after the first heat exchanger, hot produced water is recovered after the second heat exchanger, and hot PEW is recovered after the third heat exchanger.

[00132] In some implementations, the hot BFW is further sent to a steam generation unit to generate steam to be used at the in situ recovery operation site.

[00133] In some implementations, the hot produced water is further sent to a water treatment unit at the oil sands mining and extraction facility to generate BFW
which can be re-used for cooling the degassed emulsion.

[00134] In some implementations, the process further comprises mixing at least a portion of the hot PEW with the hot produced water upstream the water treatment unit.
Date Recue/Date Received 2023-12-05

[00135] In some implementations, the process further comprises a pre-dewatering step of the diluted emulsion stream before treating in the secondary extraction facility.

[00136] In some implementations, treating comprises: separating the diluted emulsion stream in a gravity separation vessel into a gravity separation vessel overflow comprising the diluted bitumen product and a gravity separation vessel underflow comprising the produced water stream.

[00137] In some implementations, treating comprises: separating the diluted emulsion stream in a gravity separation vessel into a gravity separation vessel overflow comprising the diluted bitumen product and a gravity separation vessel underflow; separating the gravity separation vessel underflow in at least one centrifugal separation vessel into a centrifugal overflow and a centrifugal underflow comprising the produced water stream.

[00138] In some implementations, the gravity separation vessel comprises an inclined plate separator.

[00139] In some implementations, the gravity separation vessel comprises an inclined plate separator and the centrifugal separation vessel comprises at least one cyclone or centrifuge.

[00140] In some implementations, the diluent comprises a naphthenic diluent.

[00141] In some implementations, the solvent comprises a paraffinic solvent.

[00142] In some implementations, the in situ recovery operation comprises a steam-assisted gravity drainage (SAG D) operation.

[00143] In some implementations, the in situ recovery operation comprises a solvent-assisted recovery operation.

[00144] In some implementations, the in situ recovery operation comprises a solvent-dominated recovery operation.
Date Recue/Date Received 2023-12-05

[00145] In accordance with another aspect, there is provided a process for using water produced from an in situ recovery operation, in an oil sands mining and extraction facility comprising a primary extraction facility and a secondary extraction facility, the process comprising: producing an emulsion comprising bitumen and water at an in situ recovery operation site; degassing the emulsion to form a degassed emulsion stream; cooling the degassed emulsion stream to form a cooled degassed emulsion stream; treating the cooled degassed emulsion stream to produce a bitumen-containing product and a produced water stream;
using the produced water stream in the oil sands mining and extraction facility.

[00146] In some implementations, degassing removes methane and/or H2S from the emulsion. In some implementations, the degassed emulsion stream has a methane concentration less than about 5 ppm. In some implementations, the degassed emulsion stream has a methane concentration less than about 1 ppm.
In some implementations, the degassed emulsion stream has an H2S
concentration less than about 4 ppm. In some implementations, the degassed emulsion stream has an H2S concentration less than about 0.5 ppm. In some implementations, degassing comprises flashing at least H2S and methane from the emulsion. In some implementations, flashing is performed at the in situ recovery operation site. In some implementations, the process further comprises scavenging dissolved H2S remaining in the emulsion after flashing. In some implementations, H2S scavenging is performed by addition of a chemical scavenger comprising at least one amine to the emulsion. In some implementations, the chemical scavenger comprises an amine-aldehyde condensate or a triazine. In some implementations, scavenging is performed at the in situ recovery operation site. In some implementations, scavenging is performed at the oil sands mining and extraction facility. In some implementations, scavenging is performed before cooling. In some implementations, scavenging is performed after cooling.
Date Recue/Date Received 2023-12-05

[00147] In some implementations, cooling is performed in one or more heat exchangers by indirectly contacting the degassed emulsion stream with a different cooling fluid in each heat exchanger. In some implementations, the cooling fluid comprises pond effluent water (PEW), boiler feed water (BFW), the bitumen-containing product, or the produced water stream.

[00148] In some implementations, cooling is performed by indirectly contacting the degassed emulsion stream with PEW.

[00149] In some implementations, cooling is performed by indirectly contacting the degassed emulsion stream with BFW and then PEW.

[00150] In some implementations, cooling is performed by indirectly contacting the degassed emulsion stream successively with BFW, the produced water stream, and PEW.

[00151] In some implementations, cooling is performed by indirectly contacting the degassed emulsion stream successively with the produced water stream, the bitumen-containing product, and PEW.

[00152] In some implementations, cooling is performed by indirectly contacting the degassed emulsion stream successively with BFW, the produced water stream, and PEW.

[00153] In some implementations, cooling is performed by indirectly contacting the degassed emulsion stream successively with BFW, the bitumen-containing product, and PEW.

[00154] In some implementations, cooling is performed by indirectly contacting the degassed emulsion stream successively with BFW, the produced water stream, the bitumen-containing product, and PEW.

[00155] In some implementations, treating the cooled degassed emulsion stream comprises aerating the cooled degassed emulsion stream to form an aerated Date Recue/Date Received 2023-12-05 emulsion stream and supplying the aerated emulsion stream to a primary separation vessel of the primary extraction facility to produce the bitumen-containing stream and the produced water stream.

[00156] In some implementations, treating the cooled degassed emulsion is performed in a flotation system. In some implementations, the flotation system comprises a single stage flotation cell system. In some implementations, the flotation system comprises a two stage flotation cell system.

[00157] In some implementations, treating the cooled degassed emulsion stream comprises: separating the cooled degassed emulsion stream in a first flotation unit to produce the bitumen-containing stream and a first flotation unit underflow stream; supplying the first flotation unit underflow stream to a second flotation unit and producing a second flotation unit overflow stream comprising bitumen and a second flotation unit underflow stream comprising the produced water stream.

[00158] In some implementations, the process further comprises returning the second flotation unit overflow stream to the first flotation unit.

[00159] In some implementations, treating the cooled degassed emulsion is performed in the secondary extraction facility.

[00160] In some implementations, treating comprises: adding a solvent or diluent to the cooled degassed emulsion to produce a diluted emulsion stream;
separating the diluted emulsion stream in a gravity separation vessel into a gravity separation vessel overflow comprising the bitumen-containing product in the form of a diluted bitumen product, and a gravity separation vessel underflow comprising the produced water stream.

[00161] In some implementations, treating comprises: adding a solvent or diluent to the cooled degassed emulsion to produce a diluted emulsion stream;
separating the diluted emulsion stream in a gravity separation vessel into a gravity separation vessel overflow comprising the bitumen-containing product in the form of a diluted Date Recue/Date Received 2023-12-05 bitumen product, and a gravity separation vessel underflow; separating the gravity separation vessel underflow in at least one centrifugal separation vessel into a centrifugal overflow and a centrifugal underflow comprising the produced water stream.

[00162] In some implementations, the gravity separation vessel comprises an inclined plate separator.

[00163] In some implementations, using the produced water stream comprises cooling the degassed in situ emulsion.

[00164] In some implementations, using the produced water stream comprises supplying the produced water stream to a water treatment unit to generate BFW.

[00165] In some implementations, the process further comprises using the BFW
to generate superheated steam.

[00166] In some implementations, the process further comprises de-superheating the superheated steam and injecting the de-superheated steam in an injection well of the in situ recovery operation.

[00167] In some implementations, the in situ recovery operation comprises a steam-assisted gravity drainage (SAG D) operation.

[00168] In some implementations, the in situ recovery operation comprises a solvent-assisted recovery operation.

[00169] In some implementations, the in situ recovery operation comprises a solvent-dominated recovery operation.

[00170] In accordance with another aspect, there is provided a process for heating bitumen located in an underground reservoir, comprising: generating superheated steam at an oil sands mining and extraction facility; partially de-superheating a portion of the superheated steam at the oil sands mining and extraction facility to produce a partially de-superheated steam; pipelining the Date Recue/Date Received 2023-12-05 partially de-superheated steam from the oil sands mining and extraction facility to an in situ recovery facility comprising at least one injection well located in the underground reservoir; and introducing at least a portion of the partially de-superheated steam into the at least one injection well to heat the bitumen.

[00171] In some implementations, the superheated steam is generated using feedwater derived from effluent water from an upgrader.

[00172] In some implementations, the superheated steam is generated using feedwater derived from produced water recovered from an in situ bitumen recovery operation.

[00173] In some implementations, the in situ bitumen recovery operation is performed at the in situ recovery facility.

[00174] In some implementations, the superheated steam is generated using feedwater derived from a surface water source.

[00175] In some implementations, the surface water source comprises tailings water.

[00176] In some implementations, the superheated steam is generated using feedwater derived from a ground water source.

[00177] In some implementations, the superheated steam is generated using feedwater comprising any combination of effluent water from an upgrader, produced water recovered from an in situ bitumen extraction operation, a surface water source and a ground water source.

[00178] In some implementations, the feedwater is treated to remove contaminants prior to generating the superheated steam.

[00179] In some implementations, the feedwater is treated at the oil sands mining and extraction facility.
Date Recue/Date Received 2023-12-05

[00180] In some implementations, the pipelining of the partially de-superheated steam to the in situ recovery facility is performed substantially above-ground.

[00181] In some implementations, the pipelining of the partially de-superheated steam to the in situ recovery facility is performed over a distance greater than 5 km.

[00182] In some implementations, the pipelining of the partially de-superheated steam to the in situ recovery facility is performed over a distance greater than 30 km.

[00183] In some implementations, partially de-superheating the portion of the superheated steam comprises adding an aqueous liquid to the superheated steam.

[00184] In some implementations, the amount of de-superheating is controlled by controlling the temperature of the aqueous liquid.

[00185] In some implementations, the amount of de-superheating is controlled by controlling the amount of the aqueous liquid.

[00186] In some implementations, the aqueous liquid comprises effluent water from an upgrader.

[00187] In some implementations, the aqueous liquid comprises overhead condensate from a stripping column.

[00188] In some implementations, the aqueous liquid comprises boiler feedwater.

[00189] In some implementations, the aqueous liquid comprises tailings water.

[00190] In some implementations, the aqueous liquid is at least partly derived from produced water recovered from the in situ recovery facility.

[00191] In some implementations, the aqueous liquid comprises surface water.

[00192] In some implementations, the aqueous liquid comprises ground water.
Date Recue/Date Received 2023-12-05

[00193] In some implementations, the aqueous liquid is treated.

[00194] In some implementations, the aqueous liquid comprises steam condensate.

[00195] In some implementations, the partially de-superheated steam is co-introduced with a solvent into the at least one injection well.

[00196] In some implementations, the partially de-superheated steam is de-superheated to an initial de-superheated temperature at the oil sands mining and extraction facility such that the partially de-superheated steam arrives at the in situ recovery facility in a superheated state.

[00197] In some implementations, the partially de-superheated steam is de-superheated at the oil sands mining and extraction facility to a temperature between 270 C and 370 C at a gauge pressure exceeding 5,000 kPa.

[00198] In some implementations, the partially de-superheated steam is further de-superheated prior to introduction into the at least one injection well.

[00199] In some implementations, the partially de-superheated steam is de-superheated to a saturated state.

[00200] In some implementations, water recovered from the in situ recovery facility is used to further de-superheat the steam at the in situ recovery facility.

[00201] In some implementations, the water recovered from the in situ recovery facility comprises condensate recovered from a degassing unit used to remove gas from production fluid.

[00202] In some implementations, the water recovered from the in situ recover facility comprises condensate recovered from condensing water vapour in a produced gas stream.
Date Recue/Date Received 2023-12-05

[00203] In some implementations, the in situ recovery facility is a steam-assisted gravity drainage (SAGD) facility.

[00204] In some implementations, mobilizing fluid injected into the at least one injection well comprises the partially de-superheated steam and a secondary fluid.

[00205] In some implementations, the secondary fluid and the partially de-superheated steam are mixed prior to injection into the at least one injection well.

[00206] In some implementations, the mobilizing fluid is the de-superheated steam and the secondary fluid is an organic solvent or a non-condensable gas.

[00207] In some implementations, the process further comprises heating the secondary fluid by indirect heat exchange with the partially de-superheated steam to produce a heated secondary fluid, and injecting the heated secondary fluid into the at least one injection well.

[00208] In some implementations, the partially de-superheated steam vaporizes the secondary fluid prior to injection thereof.

[00209] In some implementations, only the partially de-superheated steam is injected into the at least one injection well.

[00210] In some implementations, the heating of the bitumen is performed using steam only.

[00211] In some implementations, the heating of the bitumen is performed using a mixture of steam and solvent.

[00212] In some implementations, a second portion of superheated steam that is not de-superheated for use at the in situ recovery facility is used for one or more of motive force, power generation or heating of a process fluid.

[00213] In some implementations, the second portion of superheated steam is used for heating of the process fluid.
Date Recue/Date Received 2023-12-05

[00214] In some implementations, the process fluid is water that is heated and then mixed with oil sands ore in a rotary breaker for producing an oil sands slurry for hydrotransport to a primary separation vessel at the oil sands mining and extraction facility.

[00215] In some implementations, at least 10% of the total superheated steam is de-superheated and sent to the in situ recovery facility.

[00216] In some implementations, the aqueous liquid is added to the portion of the superheated stream in an amount between 0 to 20% by mass of the partially de-superheated steam.

[00217] In some implementations, the pipelining of the partially de-superheated steam is performed in a pipeline having a diameter between 15 inches and 60 inches.

[00218] In some implementations, the partially de-superheated steam is used for a start-up phase of the in situ recovery facility.

[00219] In some implementations, the partially de-superheated steam is sent to multiple in situ recovery facilities.

[00220] In some implementations, the partially de-superheated steam is sent to multiple injection wells.

[00221] In some implementations, a portion of the partially de-superheated steam is passed through turbines to generate electricity.

[00222] In some implementations, the turbines are located at the oil sands mining and extraction facility.

[00223] In some implementations, the turbines are located at the in situ recovery facility.
Date Recue/Date Received 2023-12-05

[00224] In accordance with another aspect, there is provided a process for heating bitumen located in an underground reservoir, comprising: generating superheated steam at an oil sands mining and extraction facility; partially de-superheating at least a portion of the superheated steam at the oil sands mining and extraction facility to produce a partially de-superheated steam;
pipelining the partially de-superheated steam from the oil sands mining and extraction facility to an in situ recovery facility comprising at least one injection well located in the underground reservoir; and heating the bitumen located in the underground reservoir with heat from at least a portion of the partially de-superheated steam.

[00225] In some implementations, the heating comprises injecting the partially de-superheated steam into the underground reservoir via the at least one injection well.

[00226] In some implementations, the heating comprises indirectly heating an injection fluid with the partially de-superheated steam to produce a heated injection fluid, and injecting the heated injection fluid into the underground reservoir via the at least one injection well.

[00227] In some implementations, the injection fluid comprises solvent.

[00228] In accordance with another aspect, there is provided a process for utilizing steam, comprising: generating superheated steam at an oil sands mining and extraction facility; partially de-superheating a first portion of the superheated steam at the oil sands mining and extraction facility to produce a partially de-superheated steam; generating power and heating water for use at the oil sands mining and extraction facility using a second portion of the superheated steam;
pipelining the partially de-superheated steam from the oil sands mining and extraction facility to a secondary hydrocarbon processing facility; and heating one or more process streams at the secondary hydrocarbon processing facility using the partially de-superheated steam.
Date Recue/Date Received 2023-12-05

[00229] In accordance with another aspect, there is provided a process for utilizing steam, comprising: generating superheated steam at an oil sands mining and extraction facility; partially de-superheating a first portion of the superheated steam at the oil sands mining and extraction facility to produce a partially de-superheated steam; and utilizing at least a portion of the partially de-superheated steam as stripping steam in a stripping column.

[00230] In some implementations, the stripping column is located at the oil sands mining and extraction facility.

[00231] In some implementations, the stripping column is located at the oil in situ recovery facility.

[00232] In some implementations, a first portion of the partially de-superheated steam is used as the stripping steam and a second portion of the partially de-superheated steam is pipelined to an in situ recovery facility for use thereat.

[00233] In accordance with anther aspect, there is provided a process for treating an emulsion comprising bitumen and water produced at an in situ recovery operation site, in an oil sands mining and extraction facility comprising at least one primary extraction facility and a secondary extraction facility, the process comprising: degassing the emulsion to form a degassed emulsion stream; cooling the degassed emulsion stream at the oil sands mining and extraction facility to form a cooled degassed emulsion stream; treating the cooled degassed emulsion stream in a high temperature flotation system to produce a bitumen froth stream and a produced water stream.

[00234] In some implementations, degassing removes methane and/or H2S from the emulsion. In some implementations, the degassed emulsion stream has a methane concentration less than about 5 ppm. In some implementations, the degassed emulsion stream has a methane concentration less than about 1 ppm.
In some implementations, the degassed emulsion stream has an H2S
concentration less than about 4 ppm. In some implementations, the degassed Date Recue/Date Received 2023-12-05 emulsion stream has an H2S concentration less than about 0.5 ppm. In some implementations, degassing comprises flashing at least H2S and methane from the emulsion. In some implementations, flashing is performed at the in situ recovery operation site. In some implementations, the process further comprises scavenging dissolved H2S remaining in the emulsion after flashing. In some implementations, H2S scavenging is performed by addition of a chemical scavenger comprising at least one amine to the emulsion. In some implementations, the chemical scavenger comprises an amine-aldehyde condensate or a triazine. In some implementations, scavenging is performed at the in situ recovery operation site. In some implementations, scavenging is performed at the oil sands mining and extraction facility. In some implementations, scavenging is performed before cooling. In some implementations, scavenging is performed after cooling.

[00235] In some implementations, the cooled degassed emulsion stream has a temperature ranging from about 90 to about 150 C.

[00236] In some implementations, cooling is performed by indirectly contacting the degassed emulsion with a cooling fluid comprising boiler feed water (BFW) in a heat exchanger, wherein hot BFW is recovered after the heat exchanger.

[00237] In some implementations, the hot BFW is further sent to a steam generation unit to generate steam to be used at the in situ recovery operation site.

[00238] In some implementations, treating the cooled degassed emulsion stream in the high temperature flotation system comprises adding air into the cooled emulsion stream. In some implementations, adding air into the cooled emulsion stream is performed using an aeration nozzle, a sparger aeration nozzle, an eductor, as dissolved air, via inducing gas into the suction of a pump, or via addition of an aerated secondary fluid into the cooled emulsion stream.

[00239] In some implementations, the high temperature flotation system comprises a two stage flotation cell system.
Date Recue/Date Received 2023-12-05

[00240] In some implementations, treating the cooled degassed emulsion stream comprises: separating the cooled degassed emulsion stream in a first flotation unit to produce the bitumen froth stream as a first flotation unit overflow stream and a first flotation unit underflow stream; supplying the first flotation unit underflow stream to a second flotation unit and producing a second flotation unit overflow stream comprising bitumen and a second flotation unit underflow stream comprising the produced water stream.

[00241] In some implementations, the process further comprises returning the second flotation unit overflow stream to the first flotation unit.

[00242] In some implementations, the process further comprises mixing the second flotation unit overflow stream with the first flotation unit overflow to produce the bitumen froth stream.

[00243] In some implementations, the second flotation unit underflow stream has a temperature ranging from about 90 C to about 150 C.

[00244] In some implementations, the first flotation unit overflow stream has a temperature ranging from about 80 C to about 150 C.

[00245] In some implementations, the process further comprises treating the bitumen froth stream in a deaerator unit to produce a deaerated froth stream and supplying the deaerated froth stream to the secondary extraction facility.

[00246] In some implementations, the process further comprises treating the bitumen froth stream in a deaerator unit to produce a deaerated froth stream and supplying the deaerated froth stream to an upgrading facility.

[00247] In some implementations, the process further comprises mixing the bitumen froth stream with another bitumen froth stream produced from a mined oil sands slurry in another primary facility of the oil sands mining and extraction facility, to form a mixed froth, and supplying the mixed froth to the secondary extraction facility.
Date Recue/Date Received 2023-12-05

[00248] In some implementations, the in situ recovery operation comprises a steam-assisted gravity drainage (SAG D) operation.

[00249] In some implementations, the in situ recovery operation comprises a solvent-assisted recovery operation.

[00250] In some implementations, the in situ recovery operation comprises a solvent-dominated recovery operation.

[00251] In accordance with another aspect, there is provided a process for heating bitumen located in an underground reservoir, comprising: generating superheated steam at an oil sands mining and extraction facility; partially de-superheating at least a portion of the superheated steam at the oil sands mining and extraction facility to produce a partially de-superheated steam;
pipelining the partially de-superheated steam from the oil sands mining and extraction facility to an in situ recovery facility comprising at least one injection well located in the underground reservoir; and heating the bitumen located in the underground reservoir with heat from at least a portion of the partially de-superheated steam.

[00252] In some implementations, the superheated steam is generated using feedwater derived from one or more of effluent water from an upgrader, produced water recovered from an in situ bitumen recovery operation, a surface water source comprising tailings water, and a ground water source.

[00253] In some implementations, the in situ bitumen recovery operation is performed at the in situ recovery facility.

[00254] In some implementations, the pipelining of the partially de-superheated steam to the in situ recovery facility is performed over a distance greater than 30 km.

[00255] In some implementations, the partially de-superheated steam is de-superheated to an initial de-superheated temperature at the oil sands mining and Date Recue/Date Received 2023-12-05 extraction facility such that the partially de-superheated steam arrives at the in situ recovery facility in a superheated state.

[00256] In some implementations, the partially de-superheated steam is de-superheated at the oil sands mining and extraction facility to a temperature between 270 C and 370 C at a gauge pressure exceeding 5,000 kPa.

[00257] In some implementations, the partially de-superheated steam is further de-superheated prior to introduction into the at least one injection well.

[00258] In some implementations, the partially de-superheated steam is de-superheated to a saturated state.

[00259] In some implementations, water recovered from the in situ recovery facility is used to further de-superheat the steam at the in situ recovery facility.

[00260] In some implementations, the water recovered from the in situ recovery facility comprises condensate recovered from a degassing unit used to remove gas from production fluid or from condensing water vapour in a produced gas stream.

[00261] In some implementations, the heating comprises injecting the partially de-superheated steam into the underground reservoir via the at least one injection well.

[00262] In some implementations, the heating comprises indirectly heating an injection fluid with the partially de-superheated steam to produce a heated injection fluid, and injecting the heated injection fluid into the underground reservoir via the at least one injection well.

[00263] In some implementations, the heating comprises injecting a mobilizing fluid into the at least one injection well, the mobilizing fluid comprising the partially de-superheated steam and a secondary fluid.

[00264] In some implementations, the secondary fluid and the partially de-superheated steam are mixed prior to injection into the at least one injection well.
Date Recue/Date Received 2023-12-05

[00265] In some implementations, the secondary fluid is an organic solvent or a non-condensable gas.

[00266] In some implementations, the process further comprises heating the secondary fluid by indirect heat exchange with the partially de-superheated steam to produce a heated secondary fluid, and further injecting the heated secondary fluid into the at least one injection well.

[00267] In some implementations, the partially de-superheated steam vaporizes the secondary fluid prior to injection thereof.

[00268] In some implementations, a second portion of the superheated steam that is not de-superheated for use at the in situ recovery facility is used for one or more of motive force, power generation or heating of a process fluid.

[00269] In some implementations, at least 10% of the total superheated steam is de-superheated and sent to the in situ recovery facility.

[00270] In some implementations, the pipelining of the partially de-superheated steam is performed in a pipeline having a diameter between 15 inches and 60 inches.
BRIEF DESCRIPTION OF THE DRAWINGS

[00271] Figures 1A-1D represent an overview of possible implementations of a process for treating a bitumen emulsion produced from an in situ site, at a mining and extraction site, where the in situ emulsion is treated concurrently with mined oil sands ore, i.e., when the mining and extraction site is in operation.

[00272] Figure 2 is a flow diagram showing the treatment of an in situ emulsion concurrently with an oil sands slurry in a primary extraction facility.

[00273] Figure 3 is a flow diagram of a process for aerating an in situ emulsion using a two stage flotation system, at a mining and extraction site.
Date Recue/Date Received 2023-12-05

[00274] Figure 4 is a flow diagram showing the mixing of an in situ emulsion concurrently with oil sands ore in a rotary breaker unit at a mining and extraction site to generate a hydrotransport slurry.

[00275] Figure 5 is a flow diagram of an implementation for treating an in situ emulsion concurrently with an oil sands slurry in a primary extraction facility, in which the in situ emulsion is cooled by indirect contact with PEW.

[00276] Figure 6 is a flow diagram of an implementation for treating an in situ emulsion concurrently with an oil sands slurry in a primary extraction facility in which the in situ emulsion is subsequently cooled by indirect contact with BFW
and PEW.

[00277] Figures 7A-7C represent an overview of possible implementations of a process for treating a bitumen emulsion produced from an in situ site, at a mining and extraction site, such as when the processing of mined ore has been terminated.

[00278] Figure 8 is a flow diagram of an implementation for treating an in situ emulsion at a mining and extraction site, such as at the end of the mine life, showing a possible heat integration.

[00279] Figure 9 is a flow diagram of an implementation for treating an in situ emulsion at a mining and extraction site, such as at the end of the mine life, showing another possible heat integration.

[00280] Figure 10 is a flow diagram of an implementation for treating an in situ emulsion in a secondary extraction facility at a mining and extraction site, such as at the end of the mine life, showing a possible heat integration.

[00281] Figure 11 is flow diagram of an implementation for treating an in situ emulsion in a secondary extraction facility at a mining and extraction site, such as at the end of the mine life, showing another possible heat integration.
Date Recue/Date Received 2023-12-05

[00282] Figure 12 is a flow diagram showing the treatment of an in situ emulsion in a high temperature flotation system.

[00283] Figure 13 is a flow diagram showing water treatment stages to generate steam at the mining and extraction site.

[00284] Figure 14 shows a graph of pressure versus temperature for H20 and showing example regions for superheated and de-superheated steam.
DETAILED DESCRIPTION

[00285] The technologies described herein generally concern the integration of in situ bitumen recovery operations with oil sands mining and extraction operations.
Additional aspects of the technology concern other methods for integrating assets used in the context of processing bitumen-containing materials.

[00286] The present description includes processes for treating a bitumen-containing emulsion produced from an in situ recovery operation, such as a steam assisted gravity drainage (SAGD) operation, at a mining and extraction site generally used for treating oil sands ore. As will be detailed below, in some implementations, the bitumen emulsion recovered from the in situ operation can be treated concurrently with oil sands at the mining and extraction site. In other implementations, such as at the end of the mine life when oil sands mining is terminated, the mining and extraction facility can be used and adapted to solely treat the in situ emulsion.

[00287] The present description also includes processes that use de-superheated steam that is generated at an oil sands mining and extraction site for heating applications at an in situ recovery site. For example, boilers at the mining and extraction site can generate superheated steam, a portion of which is de-superheated and then supplied by pipeline to the in situ recovery site for injection into the reservoir to facility in situ recovery of bitumen. De-superheated steam can Date Recue/Date Received 2023-12-05 be used for injection into the reservoir, heating at the surface, or in other applications such as stripping.

[00288] In the present description, the terms "a", "an", and "one" can be defined to mean "at least one", that is, these terms do not exclude a plural number of elements, unless stated otherwise.

[00289] The term "about" that modifies a value, condition, or characteristic of a feature of an exemplary embodiment, should be understood to mean that the value, condition, or characteristic is defined within tolerances that are acceptable for the proper operation of this exemplary embodiment for its intended application or that fall within an acceptable range of experimental error. In particular, the term "about" generally refers to a range of numbers that one skilled in the art would consider equivalent to the stated value (e.g., having the same or equivalent function or result). In some instances, the term "about" means a variation of percent of the stated value.

[00290] In the present description, the terms "in situ emulsion" or "emulsion produced at an in situ recovery operation site" or similar expressions, denote an emulsion containing at least bitumen, water and optionally some solids produced from a recovery operation performed in an underground hydrocarbon reservoir.
In such in situ operations, the underground reservoir is provided with injection wells into which a fluid can be injected to mobilize the bitumen in the reservoir and production wells by which the mobilized bitumen can be produced as an emulsion with water and other components. Various in situ techniques exist to recover bitumen from an underground reservoir. In some implementations, the in situ operation can include a steam assisted gravity drainage (SAGD) operation or any other recovery operation involving the injection of steam into the reservoir to mobilize the bitumen. In some implementations, the in situ operation can involve a steam-solvent co-injection process. In some implementations, the in situ recovery operation can be a solvent-assisted recovery operation, a solvent-dominated Date Recue/Date Received 2023-12-05 recovery operation, or a solvent-only recovery operation. Such techniques can allow the production of a bitumen-containing fluid through a well to the surface and this bitumen-containing fluid can generally correspond to the in situ emulsion discussed in the present description. In addition to containing bitumen, water and some solids, the in situ emulsion can also include dissolved gases, such as methane and H25, as well as solvent when a solvent based process is used. In some implementations, the in situ emulsion can also include other dissolved gases such as ethane, propane, n-butane, isobutane and CO2, or solvents. The water than is present in the emulsion can be from condensed steam injected into the reservoir and/or water that is native to the reservoir itself.

[00291] The terms "in situ recovery site", "in situ recovery facility" or "in situ site"
or similar expressions, denote the site where bitumen can be recovered from an underground reservoir according to the above-described techniques.

[00292] In the present description, the terms "oil sands mining and extraction facility", "mining and extraction facility" or "mining and extraction site" or similar expressions, denote a site or facility where mined oil sands ore, i.e., excavated from an open pit mine, is generally treated to produce a diluted bitumen product that can then be pipelined for further upgrading or sold to market. Mined oil sands ore is treated in a mining and extraction facility located at surface where the ore is typically crushed, sized and mixed with water in rotary breakers to produce a bitumen-containing slurry. The slurry is then subjected to hydrotransport via pipeline to enable conditioning and then supply the slurry to a primary extraction facility where it is separated into two main phases, a bitumen froth and tailings.
The bitumen froth is then treated in a secondary extraction facility by adding a solvent or diluent, such as a paraffinic solvent or a naphthenic diluent, depending on the desired bitumen product quality and process design. The mining and extraction site/facility can thus include mined oil sands ore treatment operations, oil sands slurry transportation equipment, oil sands slurry treatment operations, and bitumen froth treatment operations, including any associated solids, water and Date Recue/Date Received 2023-12-05 solvent/diluent treatment, recovery and/or disposal operations and associated equipment. In some implementations, the mining and extraction site/facility can include more than one primary extraction facility and more than one secondary extraction facility.

[00293] The in situ emulsion and oil sands slurry, which both contain bitumen, water and solids are quite different since the oil sands slurry contains large amounts of solids to be separated, while the in situ emulsion has a relatively low solids content. Another difference between the two materials is that the in situ emulsion is relatively hot compared to the oil sands slurry, particularly when derived from a steam-based in situ process such as SAGD. These differences present some challenges but can also benefit some treatment steps at the mining and extraction site. Some of the present integration technologies leverage certain differences to facilitate efficiencies and performance.
Concurrent treatment of in situ emulsion and oil sands ore at the mining and extraction site

[00294] In some implementations, when the mine is still in operation, for instance close to the end of its life, the in situ emulsion can be treated at the mining and extraction site concurrently with the oil sands ore excavated from the mine.
By "concurrently", it should be understood that the in situ emulsion pipelined from the in situ site (ISS) to the mining and extraction site (MES) is treated in certain MES
assets together with the oil sands ore or various streams derived from the oil sands ore. As will be detailed below, the in situ emulsion can for example be treated with the oil sands ore upstream of the primary extraction in the rotary breakers.
In some implementations, the in situ emulsion can be treated in the primary extraction facility with the slurry derived from the oil sands ore and produced by the rotary breakers. In other implementations, the in situ emulsion can be treated in the secondary extraction facility with a bitumen froth derived from the oil sands ore. In other implementations, the in situ emulsion can be treated separately from mined Date Recue/Date Received 2023-12-05 oil sands slurry in a primary extraction facility, the resulting froth can be blended with a froth recovered from mined oil sands slurry in another primary extraction facility, and the froth blend can be treated in a secondary extraction facility. More details and other examples of concurrent treatments will be provided below in reference to the appended figures. It is worth noting that each of the various possible treatments shown in the figures can be performed independently or more than one treatment can be performed in combination. The various possible concurrent treatments will be commonly referred to as "concurrent treatment scenario" or simply "concurrent scenario" below.

[00295] Figures 1A-1D show examples of treatments to which the in situ emulsion can be subjected when the oil sands ore is concurrently treated at the MES.
With reference to Figure 1C, the in situ emulsion 10 is produced at the ISS, and can be subjected to a degassing step before being sent as a degassed emulsion 18 to the MES. The in situ emulsion 10 can be produced according to various techniques as discussed above.

[00296] In some implementations, the in situ emulsion 10 can be produced using a SAGD process. More specifically, steam is injected as a mobilizing fluid via an injector well, then bitumen in the reservoir is heated in contact with the steam, mobilized, and allowed to flow under gravity to a producer well positioned below the injector well. In a SAGD configuration, the injector well and the producer well each include a horizontal section, and these horizontal sections are parallel to each other, with the horizontal section of the producer well being positioned below the horizontal section of the injector well. Once mobilized, the bitumen combined with water (connate water and/or condensed steam), some solids and dissolved gas can then be recovered at the surface through the producer well, as the in situ emulsion 10. In some implementations, the mobilizing fluid injected into the reservoir can be different from steam and can include a solvent or can be a mixture of steam and solvent. In addition, in some implementations, heating means can be Date Recue/Date Received 2023-12-05 provided downhole to heat the bitumen. Downhole heating can be performed using electric or electromagnetic techniques, for example.

[00297] The in situ emulsion 10 produced from the producer well includes dissolved gas, which can be removed from the emulsion in a degasser unit 12, before the emulsion can be further treated at the MES. In the degasser unit 12, methane and H2S and other potential dissolved gases such as CO2, ethane, propane, n-butane, isobutane and other trace gases are separated as a gaseous phase, and a degassed in situ emulsion 18 is then recovered. In some implementations, degassing can be performed by flashing the gases from the bitumen emulsion 10. In certain implementations, the emulsion 10 can be preheated after exiting the producer well and before flashing the gases in the degasser unit 12. In some implementations, the degassed emulsion stream 18 can have a methane concentration less than about 5 ppm or even less than about 1 ppm. In other implementations, the degassed emulsion stream 18 can have an H2S concentration less than about 4 ppm or even less than about 0.5 ppm.

[00298] The gaseous phase produced in the degasser unit 12, which also includes water vapour, is then sent to a condenser unit 14 where it is cooled to condense the water. The condensed water stream 16 can then be returned to the degasser unit 12. In some implementations, the condenser water stream 16 can be mixed with the in situ emulsion 10 upstream of the degasser unit 12. In other implementations, at least a portion of the condensed water stream 16 can also be mixed with a steam stream 72 to be injected in the injector well, particularly if the steam stream 72 is superheated and some cooling or recycling of the condensed water could be of interest. When the condensed water is added to the steam, the resulting steam can be injected downhole and thus the water is reused in the steam-assisted recovery process rather than being disposed of or processed at surface. The gases, i.e., at least H2S and/or methane, separated from water in the condenser 14 can then be collected and supplied to a fuel system of the ISS, with the H2S being scrubbed out if necessary and the methane being burned as fuel.
Date Recue/Date Received 2023-12-05

[00299] In some implementations, the emulsion that has been degassed to remove as much H2S as possible in the degasser unit 12, can still include remaining H2S which can be dissolved. The remaining dissolved H2S can be sequestered in the liquid phases of the degassed emulsion 18 by addition of at least one chemical scavenger. In Figure 1A, the H2S scavenging step is performed at the MES. However, in some implementations, H2S scavenging can be performed at the ISS. In some implementations, as will be further explained below, the degassed emulsion can be cooled before being supplied to the MES assets, such as by indirect contact with a cooling fluid in at least one heat exchanger such as heat exchangers 22a, 22b and/or 23. Hence, in some implementations, the H2S

scavenging step can be performed upstream of any one of the heat exchangers.
In other implementations, the H2S scavenging step can be performed downstream of any one of the exchangers. In some implementations, H2S scavenging can be performed by addition of a chemical scavenger including at least one amine to the emulsion. For example, the chemical scavenger can include an amine-aldehyde condensate or a triazine. A possible H2S scavenger can be a water-soluble product resulting from the condensation of amines with aldehydes in a hydro-alcoholic solvent. Another example can be an oil-soluble alkyl amine-formaldehyde condensate.

[00300] The degassed emulsion 18, which includes bitumen, water and optionally some solids, is sent to the MES where it can be subjected to several different treatments, as will be described below. Therefore, the present technologies differ from conventional in situ emulsion treatments involving separation of the water phase and the bitumen phase at a central processing facility of the ISS and located proximate to the wells. In the present process, the bitumen emulsion that is sent to the MES still includes the water recovered from the underground reservoir along with the bitumen and the MES assets are used to separate the bitumen from the water.
Date Recue/Date Received 2023-12-05

[00301] The in situ emulsion 10 produced by the producer well can be very hot, such as at temperatures from about 140 C to about 240 C, particularly when a steam-assisted recovery process is used. In some implementations, the degassed emulsion 18, which is still very hot with temperatures ranging from about 120 C
to about 220 C, need to be cooled before being further treated in MES assets, such as primary extraction assets for instance. Further details regarding the cooling step will be provided below.

[00302] In some implementations, the degassed stream 18 or 20 (which has further been subjected to H2S scavenging) can thus be cooled before being subjected to further treatments at the MES. In some implementations, the degassed emulsion stream 18 or 20 can be cooled to obtain a cooled emulsion stream 24 at a temperature ranging from about 50 to about 85 C, or from about 55 to about 70 C. In some implementations, cooling is performed by indirectly contacting the degassed emulsion with a cooling fluid in at least one heat exchanger. As shown in Figures 1A and 2 to 6, the degassed emulsion 18 or 20 can be cooled at least in exchanger 22a, by indirect contact with a pond effluent water (PEW) stream 60 as the cooling fluid. PEW is water recovered from a tailings pond associated with the primary and/or secondary extraction of the MES as shown in Figure 1D for instance, and can also be referred to as cold process water (CPW). In some implementations, the hot PEW stream 88 (HPW) exiting the heat exchanger 22a can be directed to the hot process water system and used in operations occurring upstream of primary separation at the MES. For instance, as shown in Figure 1A, the HPW stream 88 or a portion thereof can be directed to at least one rotary breaker where it can contact the mined oil sands ore to form the oil sands slurry stream 28, which is then supplied to the primary extraction facility.
In some implementations, the HPW stream 88 can be mixed with hot process water, e.g., derived from tailings pond and/or make up water, and the water mixture can be used as hot process water for treating the oil sands ore in the rotary breaker.
In another implementation, the HPW stream 88 or a portion thereof can be diverted Date Recue/Date Received 2023-12-05 for mixing with the oil sands slurry exiting the rotary breaker to form oil sands slurry stream 28 for hydrotransport to the primary extraction facility (see, e.g., Figure 1A
and 4). In some implementations, the mixing of the HPW stream 88 with the oil sands slurry exiting the rotary breaker can be controlled to obtain a hydrotransport slurry stream 28 having a specific gravity of from about 1.5 to about 1.65. In other implementations, the mixing of the HPW stream 88 with the oil sands slurry exiting the rotary breaker can be controlled to obtain a hydrotransport slurry stream having and a temperature of from about 45 C to about 55 C. If required, cold process water can be further added to the hydrotransport slurry stream 28 to achieve the desired gravity and temperature parameters.

[00303] In some implementations, the degassed emulsion 18 or 20 (further subjected to H2S scavenging) can be cooled through a heat exchanger 22b to form the cooled emulsion stream 24, by indirect contact with a boiler feed water (BFW) stream 66 recovered from a water treatment facility 64, as the cooling fluid.
In some implementations, the hot BFW stream exiting heat exchanger 22b can be directed to a steam generation unit 68 to generate a steam stream 70 that can be used in the extraction site and/or at the in situ recovery operation site, e.g., for injection in the hydrocarbon underground reservoir to recover additional bitumen. In some implementations, as more particularly shown in Figure 4, the degassed emulsion 18 or 20 can also be cooled through a heat exchanger 23 to form the cooled emulsion stream 24, by indirect contact with a water stream 86 recovered from the flotation system 74 of a downstream emulsion treatment operation (see Figure 1A), as the cooling fluid. In some implementations, the heated water stream 87 can be sent to a water treatment facility.

[00304] In some implementations, as shown in Figures 1A and 6 for instance, the degassed emulsion 18 or 20 can be cooled through two heat exchangers 22b and 22a in series to form the cooled emulsion stream 24. In this configuration, the degassed emulsion can be cooled in the first heat exchanger 22b by indirect contact with a first cooling fluid 66 and then further cooled in the second heat Date Recue/Date Received 2023-12-05 exchanger 22a by indirect contact with a second cooling fluid 60. In some implementations, the cooling fluid in the first heat exchanger 22b can be a boiler feed water (BFW) stream 66 recovered from a water treatment facility 64. In some implementations, the cooling fluid in the second heat exchanger 22a can be PEW.
As described above, the hot BFW stream exiting heat exchanger 22b can be directed to the steam generation unit 68 to generate the steam stream 70, and the heated PEW stream (HPW) exiting heat exchanger 22a can be used for example in mining operations upstream the primary extraction facility.

[00305] In some implementations, the integration processes described herein can benefit from the hot temperature of the in situ produced emulsion to directly heat the process water that is used to treat the oil sands ore. This step can also be referred to as "direct quench". Hence, in some implementations, the degassed in situ emulsion 18 or 20, which can be previously cooled in one or more of heat exchangers 22a, 22b, and 23, can be quenched with at least a portion of the process water 60, e.g., PEW from tailings ponds and/or make up water. This quenching step results in heating the process water and producing a combined hot process water-emulsion stream that is then mixed with the oil sands ore in the rotary breaker (see e.g., Figures 1A and 4). In another implementation, the degassed emulsion stream 18 or 20 can also be cooled (quenched) by addition thereto of a water stream 86 recovered from a flotation system 74 of a downstream emulsion treatment operation (see Figure 1A). Another possible quench option can include directly mixing the degassed emulsion 18 or 20, at least cooled in exchanger 23, with heated water stream 87 deriving from the water stream 86 (Figure 4). Hence, the degassed emulsion 18 or 20 can flow within heat exchanger 23 and be cooled by indirect contact with the water stream 86 and at least a portion of the heated water stream 87 exiting exchanger 23 can be used to quench the cooled degassed emulsion forming a combined hot process water-emulsion stream that is then mixed with the oil sands ore in the rotary breaker. In some implementations, the combined hot process water-emulsion stream can be added Date Recue/Date Received 2023-12-05 into the rotary breaker via a dedicated connection. In another implementation, the combined hot process water-emulsion stream can be added into the rotary breaker via the spray system or into the feed apron. As more particularly shown in Figure 4 and as mentioned above, the degassed emulsion stream 18 or 20 can be cooled in at least one of the heat exchangers 22a, 22b, and 23 before being mixed with the process water, including PEW and/or heated water stream 87. In some implementations, the degassed emulsion stream 18 or 20 can be cooled by indirect contact with PEW as the cooling fluid in exchanger 22a. At least a portion of the resulting heated fluid, i.e., HPW, can then be directed to the discharge of the breaker pumpbox and be mixed with the oil sands slurry to form the hydrotransport stream 28. In some implementations, at least a portion of HPW exiting exchanger 22a can be directed to the water spray system of the rotary breaker. In other implementations, the degassed emulsion stream 18 or 20 can be cooled by indirect contact with BFW in exchanger 22b followed by indirect contact with PEW in exchanger 22a. In some implementations, the degassed emulsion stream 18 or 20 can thus be subjected to different cooling and/or quenching treatments, which can include: i) cooling in heat exchanger 22a only, ii) cooling in heat exchanger 22b and then heat exchanger 22a, iii) cooling in heat exchanger 22b following by quenching with PEW, iv) quenching with PEW only, v) cooling in heat exchanger 22b followed by quenching with heated water stream 87, or vi) quenching with heated water stream 87 only.

[00306] In some implementations, the cooling and/or quenching treatments described above can be controlled to achieve desired hydrotransport conditions and can be adapted to a certain extent based on the quantity and composition of the mined ore. In some implementations, the cooling and/or quenching of the degassed emulsion stream 18 or 20 can be controlled according to the desired parameters of the hydrotransport slurry stream 28. For instance, the cooling and/or quenching can be controlled to achieve a hydrotransport slurry specific gravity of from about 1.5 to about 1.65, and/or a hydrotransport slurry temperature of from Date Recue/Date Received 2023-12-05 about 45 C to about 55 C. The resulting hydrotransport slurry stream 28 can then be supplied to the primary extraction facility for separating the bitumen phase from the solids phase as will be described below. These treatments can be controlled by varying the flow rates of the streams and/or by varying the cooling of the hot emulsion.

[00307] Referring to Figure 1A, the hydrotransport slurry stream 28 can be supplied to at least one primary separation vessel (PSV) 32 where the slurry can be separated into a bitumen froth overflow stream 34, a middlings stream 36, and a primary extraction tailings underflow stream 38. Conventional primary separation vessels can be used for this separation step. Each of streams 34, 36 and 38 can then be subjected to several treatments that will be described further below.
In some implementations, as shown in Figure 1A and more particularly in Figure 2, the cooled degassed emulsion 24, which can result from cooling the degassed emulsion 18 or 20 according to the various methods described above, can be mixed with the hydrotransport slurry stream 28 to form a mixed slurry 30 that is then supplied to the PSV 32. In this design, the cooled degassed emulsion 24 is preferably aerated before being sent to the PSV 32. In some implementations, the cooled degassed emulsion 24 is aerated to produce the aerated emulsion stream 26 and then this aerated emulsion stream 26 is mixed with the oil sands slurry (optionally including some in situ emulsion as described above) to form the slurry stream 30 that is supplied to the PSV 32. In an alternative implementation (not shown in the figures), the aerated emulsion stream 26 can be supplied to the PSV
32 separately from the oil sands slurry 28 and both streams become mixed inside the PSV. In some implementations, aeration of the cooled degassed emulsion 24 can be performed by air addition. In some implementations, air can be added in-line into the cooled emulsion stream 24 via direct air nozzle injection, via induced gas (i.e., using eductors), using microbubble pumps/systems, or as dissolved air.
In some implementations, aeration of the cooled degassed emulsion 24 can include adding air into the cooled emulsion using an aeration nozzle, a sparger Date Recue/Date Received 2023-12-05 aeration nozzle, an eductor, as dissolved air, via inducing gas into the suction of a pump, or via addition of an aerated secondary fluid into the cooled emulsion stream. In some implementations, the aerated secondary fluid is itself obtained by adding air to a secondary fluid (e.g., water) using an aeration nozzle, a sparger aeration nozzle, an eductor, as dissolved air, or via inducing gas into the suction of a pump.

[00308] In the PSV 32, pre-mixed slurry stream 30, or slurry stream 28 and aerated emulsion stream 26 fed independently, can then be separated into the bitumen froth stream 34, the middlings stream 36 and the tailings stream 38 as mentioned above.

[00309] The bitumen froth stream 34 recovered as the PSV overflow can then be further treated in the secondary extraction facility of the MES to produce a bitumen product stream 48. More particularly, the bitumen froth stream 34 is first supplied to a deaerator unit 40, such as a static deaerator, and the deaerated bitumen froth stream 42 is sent to separators of the secondary extraction facility (see e.g., Figures 1A and 2). In some implementations, the deaerated bitumen froth stream 42 can be stored in a tank before being treated in the secondary extraction facility and/or mixed with another bitumen froth stream derived from the secondary or tertiary separators of the primary extraction facility and/or derived from the in situ emulsion, as will be further explained below. The secondary extraction usually involves addition of an organic solvent or diluent (e.g., often referred to as a paraffinic solvent or a naphthenic diluent) into the bitumen froth and then separating the diluted froth into a diluted bitumen product 48 and an aqueous/solid stream 50 that can be further treated, as shown in Figure 1D. More details will be provided below regarding secondary extraction.

[00310] As shown in Figures 1B and 2, the middlings stream 36 exiting the PSV
32 can be subjected to further separation steps usually involving flotation cells and cyclones, and often referred to as secondary and tertiary separators. More Date Recue/Date Received 2023-12-05 particularly, the middlings stream 36 can be supplied to a first flotation unit 52, which can include several flotation cells, to recover a first flotation unit overflow stream including bitumen and a first flotation unit underflow stream. This first flotation unit 52 can also be referred to as "secondary flotation cells". In some implementations, the overflow from the flotation unit 52 can be recycled back into the PSV 32. In some implementations, the underflow stream from the flotation unit 52 can be supplied to the set of cyclones 56, for further separation. In addition, the tailings underflow stream 38 from the PSV 32 can also be fed to the cyclones 56.
In certain implementations, the underflow from the flotation unit 52 can be combined with the tailings stream 38 from PSV 32 and the resulting combined stream can be supplied to the cyclones 56. In the cyclones 56, the underflow from the flotation unit 52 and/or the tailings stream 38 are separated into a cyclone overflow stream and a cyclone underflow stream. The cyclone overflow stream can then be supplied to a second flotation unit 54, which can include several flotation cells, to recover a second flotation cell overflow stream including bitumen and a second flotation cell underflow stream. The second flotation unit 54 can also be referred to as "tertiary flotation cells". The overflow stream from the second flotation unit 54 can then be returned to the PSV 32. In some implementations, the underflow stream from flotation unit 54 can be combined with the underflow stream from the cyclones 56 to form a combined tailings stream 58. Then, tailings stream 58 can be directed to a tailings pond as shown in Figure 1B.

[00311] Still referring to Figure 1A, according to another implementation, the cooled degassed emulsion 24 can be treated in a flotation system 74 before being sent to the secondary extraction facility. This flotation system 74 can be viewed as dedicated to processing the in situ emulsion and receives little to no streams derived from the oil sands ore. The in situ produced emulsion 10 can be degassed in degasser 12 to form the degassed emulsion 18, and then the degassed emulsion 18 can be cooled as described above to form the cooled emulsion 24, which can be directed to the flotation system 74. In the flotation system 74, the cooled Date Recue/Date Received 2023-12-05 degassed emulsion 24 can be separated into a bitumen froth overflow stream 80 and a water-containing underflow stream 86. This bitumen froth stream 80 can then be treated in downstream assets of the MES to recover the diluted bitumen product 48. The water-containing underflow stream 86 can be recycled into upstream operations as will be discussed further below. In some implementations, the flotation system 74 can include flotation cells, scavenger banks, column flotation vessels, an induced gas flotation system, a Dissolved Air Flotation (DAF) system, a compact flotation unit, and/or a microbubble flotation system. The flotation system 74 can be a dedicated flotation system provided at the MES, or can be a pre-existing flotation system downstream of the PSV of a primary extraction facility which is repurposed for processing the in situ emulsion.

[00312] In the flotation system 74, bitumen in the emulsion can be freed of water and minerals. In some implementations, the treatment can be performed by entrained air that forms bubbles which attach to the bitumen droplets and float them to the surface of the water to form the bitumen froth. In some implementations, the treatment in the flotation system 74 can be performed by introducing an inert gas, such as N2 gas, or a hydrocarbon gas, such as natural gas, into the emulsion. In one implementation, the flotation system 74 can include flotation units where the emulsion is highly aerated. The flotation system 74 can be a single stage flotation system or can be a two stage flotation system. An example of the flotation system 74 is shown in Figure 3. Accordingly, in some implementations, the cooled emulsion stream 24 can be supplied to a first flotation unit 76 of the flotation system 74 to produce an aerated emulsion stream 80 as the first flotation unit overflow and a first flotation unit underflow stream that can be supplied to a second flotation unit 78. Each of the flotation units 76 and 78 can include at least one flotation cell (also referred to as a flotation column).
In some implementations, both flotation units 76 and 78 can include several flotation cells.
In the second flotation unit 78, the underflow from the first flotation unit can be further aerated to produce a second flotation unit overflow stream including Date Recue/Date Received 2023-12-05 bitumen and a second flotation unit underflow 86 including water. In some implementations, the overflow from the second flotation unit 78 can be returned to the first flotation unit 76. For instance, the overflow from the second flotation unit 78 can be mixed with the cooled degassed emulsion 24 and the mixture can be fed to the first flotation unit 76. Alternatively, the streams can be fed separately to the first flotation unit 76. In another implementation (not shown in the figures), the overflow from the second flotation cell 78 can be combined with the first flotation unit overflow 80 and the resulting aerated emulsion stream (i.e., froth) can be sent to further downstream treatments. In some implementations, the second flotation unit underflow 86, can have a temperature ranging from about 50 C to about 75 C, or from about 55 C to about 70 C. In some implementations, at least a portion of the second flotation unit underflow 86, which mainly includes water, can be sent to the hot water process system and be used for treating the oil sands ore in the rotary breaker. In some implementation, as shown in Figures 1A and 4, at least a portion of the water-containing stream 86 can be combined with the hot degassed emulsion stream 18 or 20 (or a portion thereof) and the combined stream can then be used for treating the oil sands ore in the rotary breaker. In some implementations, the combined stream can itself be mixed with cold process water, e.g., from tailings pond, to obtain hot process water at a desired temperature for being supplied to the rotary breaker. In some implementations, the water-containing stream 86 can recover heat from the degassed emulsion stream 18 or 20 in heat exchanger 23, and at least a portion of the heated recovered water stream 87 can be used as feed to a water treatment process.

[00313] In some implementations, although not shown in the Figures, the bitumen froth stream 80 produced by the flotation system 74 can be recycled back into the PSV 32. As such, the bitumen froth stream 80 can be aerated in the PSV 32 before being sent to the secondary extraction of the MES. In other implementations, the bitumen froth stream 80 produced by the flotation system 74 can be deaerated in a deaerator unit and then sent to the secondary extraction facility of the MES. In Date Recue/Date Received 2023-12-05 further implementations, a portion of the bitumen froth stream 80 produced by the flotation system 74 can be recycled back into the PSV and another portion of the bitumen froth stream 80 can be sent to a deaerator unit and then to the second extraction facility. In some implementations, the bitumen froth stream 80, or the stream resulting from the combination thereof with the overflow of flotation unit 78 as described above, is highly aerated and can require a deaeration step before being treated in the secondary extraction facility. Hence, the bitumen froth stream produced by the flotation system 74 can be sent to the deaerator 82 to produce the deaerated stream 84 which can then be supplied to the secondary extraction facility. Although not shown in Figure 1A, in some implementations, the bitumen froth stream 80 produced by the flotation system 74 can be sent to the deaerator 40 upstream the PSV 32. In implementations where N2 or natural gas is used in the flotation system, as described above, the deaeration system would need to be closed and the gas can either be recycled to the flotation system or recovered for an alternative use at the MES. In some implementations, as shown in Figure 1B, deaerated stream 84 can be combined with the bitumen froth stream 42 separated in the PSV 32 before being sent to the secondary extraction step. As described above, the bitumen froth stream 42 produced in PSV 32 can include bitumen derived from the in situ emulsion in addition to bitumen from the mined oil sands, for instance in the scenario where the hot degassed emulsion 18 or 20 is mixed with the process water upstream of the rotary breaker, or where the cooled and aerated emulsion 26 is mixed with the oil sands slurry 28 upstream the PSV.
However, in alternative implementations, the bitumen froth stream 42 produced by the PSV 32 could only contain bitumen derived from the mined oil sands ore. In other words, the deaerated stream 84, which contains in situ produced bitumen, can be combined with the PSV's bitumen froth stream 42, which itself contains in situ produced bitumen or which only contains oil sands ore derived bitumen.

[00314] Another possible integration operation of the present technology, involving the treatment of the in situ produced emulsion at the MES
concurrently Date Recue/Date Received 2023-12-05 with oil sands ore treatment, is illustrated in Figure 1A and includes combining the cooled degassed emulsion stream 24 with the middlings stream 36 produced by the PSV 32. The resulting combined stream can then be treated in the flotation units 52,54 and at least one cyclone 56, as explained above. In this implementation, the middlings stream 36 produced in the PSV 32 can include bitumen derived from the in situ emulsion in addition to bitumen from the mined oil sands, for instance in the scenario where the hot degassed emulsion 18 or 20 is directly mixed with the process water upstream of the rotary breaker, or where the cooled and aerated emulsion 26 is mixed with the oil sands slurry 28 upstream the PSV.

[00315] A further possible integration operation where the in situ produced emulsion is treated at the MES concurrently with oil sands ore, is shown in Figure 1C. More particularly, in this implementation, the degassed emulsion stream 18 or 20 is subjected to a dewatering operation before being mixed with the bitumen froth stream 42 or the combined bitumen froth streams 42 and 84 and sending the resulting mixture to the secondary extraction facility. In some implementations, not shown in Figure 1C, the degassed emulsion stream 18 is cooled before dewatering. For instance, the degassed emulsion stream 18 can be cooled, before dewatering, through indirect contact with various cool streams such as PEW, BFW, and/or stream 86, as discussed above. In some implementations, the dewatering step can be performed by adding a dewatering solvent to the cooled degassed emulsion stream. The dewatering solvent can include a blend of light hydrocarbons. In some implementations, the dewatering solvent can be a blend of light hydrocarbons that is characterized by a vapour pressure of less than 14.7 psia and/or a density of from about 650 to about 850 kg/m3. In some implementations, the dewatering solvent can be a gas condensate or a naphthenic diluent (often simply called "diluent"). In some implementations, where the dewatering solvent includes diluent, the ratio of diluent added to degassed emulsion can be based on the bitumen content in the emulsion, and can typically Date Recue/Date Received 2023-12-05 vary in a range from 0.15 to 0.8 by volume. The resulting solvent diluted emulsion stream can then be sent to a dewatering unit 15, where water is separated from the solvent diluted emulsion stream by gravity. In some implementations, the dewatering unit 15 can include a tank, e.g., a horizontal vessel like a FVVKO.
The recovered dewatered stream 43 can then be stored in a bitumen froth tank, e.g., the tank which receives bitumen froth stream 42 or combined streams 42 and 84, or can be directly mixed with the bitumen froth stream 44 exiting the storage tank before being treated in the secondary extraction facility. In some implementations, the water recovered from the dewatering unit 15 can be sent to the water treatment unit 64 where it can be used to produce BFW. In other implementations, the water recovered from the dewatering unit can be used in the secondary extraction facility, as will be described below.

[00316] Another yet possible integration operation of the present technology, where the in situ produced emulsion is treated concurrently with oil sands ore at the MES, can include producing a bitumen froth stream from the in situ produced emulsion in a first primary extraction facility of the MES, producing another bitumen froth from mined oil sands ore in another primary extraction facility of the MES, mixing the bitumen froths and then treating the mixed froth in the secondary extraction of the MES. For instance, the in situ produced emulsion can be treated in a first primary extraction facility of the MES, as shown in Figure 7A, to produce a bitumen froth stream 134, 190 or 192, and any one of the bitumen froth streams 134, 190 and 192, or any combination thereof, can then be blended with a bitumen froth produced from mined oil sands ore in another primary extraction facility of the MES. Further details regarding the production of bitumen froth streams 134, and 192 from the in situ produced emulsion are provided below. Furthermore, details on bitumen froth streams treatment in the secondary extraction facility are discussed in the next paragraph.

[00317] As explained previously, when the in situ site is operated and integrated concurrently with oil sands mining and extraction, various streams including both Date Recue/Date Received 2023-12-05 bitumen originated from the in situ site and bitumen originated from the mined oil sands, can be treated in the secondary extraction facility of the MES. These streams can include, for instance, the bitumen froth stream 42 derived from the PSV 32 overflow, the bitumen froth stream 84 derived from flotation system 74, a combination of bitumen froth streams 42 and 84, or a combination of the dewatered stream 43 derived from the dewatering unit 15 with either one or both of bitumen froth streams 42 and 84. In this scenario, the froth feed stream to the secondary extraction facility is generally identified as stream 44 in the figures.
However, in some implementations, as mentioned in the previous paragraph, the bitumen froth that is treated in the secondary extraction facility can include a blend of any one of bitumen froth streams 134, 190 and 192, or any combination thereof, with a bitumen froth produced from mined oil sands ore. Various techniques can be used to treat bitumen froth(s) including for example paraffinic or naphthenic froth treatment. Such techniques involve the addition of a solvent or diluent (e.g., paraffinic solvent or naphthenic diluent) to the bitumen froth and then separating the solvent diluted bitumen froth stream in a gravity or centrifugation separation vessel to produce an overflow including a diluted bitumen product and an underflow including water and solids that can be further treated in downstream operations. Although commercial bitumen froth treatment processes use paraffinic solvents or naphthenic diluents, other possible techniques and solvents can be implemented. For instance, the bitumen froth treatment in the secondary extraction facility can involve a first stage using a naphthenic diluent and a second stage using a paraffinic solvent. In some implementations, the paraffinic solvent can be a C4-05 alkane solvent.

[00318] According to some implementations, as shown in Figure 1D, the bitumen froth treatment can be performed using a paraffinic solvent or a naphthenic diluent in a two stage separation system. The solvent or diluent can be added to the bitumen froth stream 44 and, in a first stage, the diluted bitumen froth can be treated in a gravity separation vessel 46 to separate the froth into a separation Date Recue/Date Received 2023-12-05 vessel overflow 48 including diluted bitumen and a separation vessel underflow including water, solids, some bitumen and solvent or diluent. In some implementations, the gravity separation vessel 46 can be an inclined plate separator (IPS). The underflow 50 from the separation vessel 46 can further be treated, in a second stage, in high gravity-force (G-force) separators such as cyclones and/or centrifuges to remove solids and/or water. In some implementations, the separation vessel underflow 50 can be routed through two sets of cyclones in series. The cyclone overflows can either be recycled to the IPS
or directed to centrifuges. In some implementations, the centrifuges can include two sets in series, which combined produce a diluted bitumen product (dilbit) that can then be fed to an upgrader and a stream including water and solids that can be sent to a solvent recovery unit (called naphtha recovery unit, NRU, when using a naphtha diluent) to recover solvent and produce a solids-containing stream.
The underflow of the primary set of cyclones can be fed to the secondary set of cyclones, and then the secondary cyclone underflow can be directed to the solvent recovery unit (e.g., NRU). The solids-containing stream rejected from the solvent recovery unit can be sent as froth treatment tailings to a tailings pond for disposal.
It is worth noting, even if not shown in the Figures, that, in some implementations, the bitumen froth stream 44 can be directly fed to the centrifuges. In some implementations, the flashed recovered solvent or diluent contains some water that is condensed and separated from the solvent/diluent, and the condensate water recovered from the solvent recovery unit can be reused in other operations.
For instance, the condensate water can be used to cool superheated steam to produce de-superheated steam that is supplied to the in situ recovery operation, as will be explained in more detail further below. In other implementations, as shown in Figure 1D, water recovered from the in situ emulsion dewatering operation can be mixed with the underflow stream 50 from the gravity separation vessel 46 before the second stage separation. In an alternative implementation, water recovered from the in situ emulsion dewatering operation can be directed to the solvent recovery unit (e.g., NRU).
Date Recue/Date Received 2023-12-05

[00319] As described above, several integration techniques can be implemented to treat an in situ produced emulsion while concurrently treating a mined oil sands ore at the MES. In addition to the advantage of using some of the MES assets for treating both the in situ emulsion and the mined oil sands ore, these techniques can also benefit from the high temperature of the in situ emulsion for heating various streams at the MES.
In situ emulsion treatment at the mining and extraction site, such as at the end of the mine life

[00320] In this section of the present description, several implementations for treating an in situ produced emulsion at an MES, such as when oil sands mining has been terminated and oil sands ore is no longer processed at the MES, will be described. Although this section is mainly directed to the treatment of an in situ produced emulsion at an MES when oil sands ore is no longer processed at the MES, some implementations, such as those discussed with reference to Figure 7A, can also pertain to a scenario where the in situ emulsion is treated concurrently with oil sands ore at the MES as explained in the previous section.

[00321] Although some processes can be similar for this "in situ only"
scenario as presented in this section comparted to the concurrent treatment scenario presented in the previous section, there are also some differences, for instance with respect to the heat integration, which will be discussed below.

[00322] Figures 7A-7C show examples of treatments to which the in situ emulsion can be subjected at the MES, such as after the end of the mine life. With reference to Figure 7B, the in situ emulsion 10 is produced at the ISS, and subjected to a degassing step before being sent as a degassed emulsion 18 to the MES. The in situ emulsion 10 can be produced according to various techniques as previously described. In some implementations, the in situ emulsion 10 can be produced by a SAGD process as detailed above.
Date Recue/Date Received 2023-12-05

[00323] The degassing of the in situ emulsion 10 in the degasser unit 12 to form the degassed emulsion 18, can be performed as detailed above with respect to the concurrent treatment scenario. The gaseous aqueous phase produced in the degasser unit 12 can be sent to the condenser unit 14 where it is cooled to condense the water and the condensed water stream 16 can be returned to the degasser unit 12 and/or mixed with the in situ emulsion 10 upstream of the degasser unit 12. In some implementations, at least a portion of the condensed water stream 16 can be mixed with a steam stream 172 to be injected in the injector well, particularly if the steam stream 172 is superheated and some cooling thereof could be of interest.

[00324] In some implementations, if some H2S remains dissolved in the degassed emulsion stream 18, the degassed emulsion can further be subjected to H2S
scavenging by addition of at least one chemical scavenger as described above with respect to the concurrent treatment scenario. In Figure 7A, the H2S
scavenging step is performed at the MES. However, in some implementations, H2S

scavenging can be performed at the ISS. In some implementations, as will be further detailed below, the degassed emulsion can be cooled before being supplied to the MES assets, such as by indirect contact with a cooling fluid in at least one heat exchanger such as heat exchangers 122a-d and 222a-c/c'. Hence, in some implementations, the H2S scavenging step can be performed upstream of any one of the heat exchangers. In other implementations, the H2S scavenging step can be performed downstream of any one of the exchangers.

[00325] The degassed emulsion 18 or 20 (further subjected to H2S scavenging), which includes bitumen, water and optionally some solids, is sent to the MES
where it can be subjected to several different treatments, as will be described below. Thus, the present "in situ only" treatments differ from conventional in situ emulsion treatments involving separation of the water phase and the bitumen phase at a central processing facility of the ISS and located proximate to the wells, since, in the present case, the bitumen emulsion that is sent to the MES still Date Recue/Date Received 2023-12-05 includes the water recovered from the underground reservoir along with the bitumen and the MES assets are used to separate the bitumen from the water.

[00326] In some implementations, the degassed emulsion 18, which is still very hot with temperatures ranging from about 120 C to about 200 C, need to be cooled before being further treated in the MES assets, such as primary extraction assets for instance. In some implementations, cooling is performed by indirectly contacting the degassed emulsion with a cooling fluid in at least one heat exchanger.

[00327] As shown in Figures 7A, 7B and 8 to 11, the degassed emulsion 18 or 20 can be cooled at least in exchanger 122a/222a, by indirect contact with a pond effluent water (PEW) stream 160 as the cooling fluid. PEW is water recovered from a tailings pond. In some implementations, the hot PEW stream 188 (HPW) exiting the heat exchanger 122a/222a can be dumped to a pond and/or used as make up water in other operations, for instance the hot PEW stream 188 can be mixed with heated produced water.

[00328] In some implementations, the degassed emulsion 18 or 20 can be cooled through a heat exchanger 122b/222b, by indirect contact with a boiler feed water (BFW) stream 166 recovered from a water treatment facility 164, as the cooling fluid. In some implementations, the hot BFW stream exiting heat exchanger 122b/222b can be directed to a steam generation unit 168 to generate a steam stream 170 that can be used at the in situ recovery operation site, e.g., for injection in the hydrocarbon underground reservoir to recover additional bitumen therefrom.

[00329] In some implementations, the degassed emulsion 18 or 20 can be cooled through at least another type of heat exchanger 122c/222c,c', by indirect contact with a produced water (PW) stream deriving from the primary extraction facility or the secondary extraction facility, as the cooling fluid. For instance, in some implementations, the degassed emulsion 18 or 20 can be cooled by indirect contact with the PW stream 186 recovered from flotation system 174, or by indirect Date Recue/Date Received 2023-12-05 contact with the PW stream 196 recovered from flotation system 194, or by indirect contact with a cooling stream combining streams 186 and 196, in heat exchanger 122c. In another implementation, the degassed emulsion 18 or 20 can be cooled in heat exchanger 222c, by indirect contact with the PW stream obtained as the underflow stream 150 of the gravity separation vessel 146 of the secondary extraction facility. In a further implementation, the degassed emulsion 18 or 20 can be cooled in heat exchanger 222c', by indirect contact with the PW stream 198 recovered from a second stage separation operation of the secondary extraction facility. In this configuration, the heated PW stream exiting exchanger 122c/222c,c' can be sent to the water treatment facility 164 where it can deoiled, the deoiled stream being then sent to an evaporator unit to produce BFW stream 166/218.

[00330] Another possible cooling step can be performed in a further heat exchanger 122d where the cooling fluid used to cool the degassed emulsion 18 or 20 can be a bitumen froth stream 134 produced in the primary separation vessel 132, or a combination of bitumen froth stream 134 and bitumen froth stream 190 recovered as the flotation system 174 overflow. In this configuration, the heated bitumen froth stream 192 exiting heat exchanger 122d can be returned to the bitumen froth mainstream, e.g., stream 134, which is then sent to the secondary extraction facility.

[00331] In some implementations, the degassed emulsion 18 or 20 can be cooled in at least one of the above-described heat exchangers or any combination thereof.
Examples of possible cooling/heat integration techniques will be described in more detail below in reference to Figures 8 to 10.

[00332] Still referring to Figure 7A, in some implementations, the cooled degassed emulsion 124, resulting from cooling the degassed emulsion 18 or 20 through at least one of heat exchangers 122a-d as described above, can be aerated to produce the aerated emulsion stream 126 and then this aerated emulsion stream 126 is supplied to the PSV 132. Aeration of the cooled degassed Date Recue/Date Received 2023-12-05 emulsion 124 can be performed as explained above with respect to the concurrent scenario. In the PSV 132, the aerated emulsion stream 126 can then be separated into bitumen froth stream 134 as the PSV overflow and the underflow stream 138.

[00333] The bitumen froth stream 134 recovered as the PSV overflow can then be further treated in a secondary extraction facility of the MES to produce a bitumen product stream 148. In some implementations, the bitumen froth stream 134 can be stored in a tank before being treated in the secondary extraction facility and/or mixed with another bitumen froth stream derived from other operations, as will be further explained below. In some implementations, the bitumen froth or any combination of bitumen froths can be deaerated before being treated in the secondary extraction facility. The secondary extraction usually involves addition of a solvent or a diluent (e.g., a paraffinic solvent or a naphthenic diluent) into the bitumen froth and then separating the froth into a diluted bitumen product 148 and an aqueous stream 150 that can be further treated, as shown in Figure 7C. More details will be provided below regarding the secondary extraction phase.

[00334] As shown in Figure 7A, the underflow stream 138 from the PSV 132, which mainly contains water but also some residual bitumen, can then be sent to the flotation system 194 to recover a PW stream 196 and a bitumen-containing stream 139 that can be returned to the PSV 132. In some implementations, the bitumen-containing stream 139 recovered from the flotation system 194 can be mixed with the aerated emulsion stream 126 and the mixed stream supplied to the PSV or can be supplied to the PSV separately. As discussed above, the PW
stream 196 can be used to cool the degassed in situ emulsion in heat exchanger 122c. The flotation system 194 can include flotation cells, scavenger banks, column flotation vessels, an induced gas flotation system, a DAF system, or a microbubble flotation system. In some implementations, the treatment in the flotation system 194 can be performed using air as the primary flotation gas.
In some implementations, an inert gas such as N2 gas, or a hydrocarbon gas such as natural gas can also be used in the flotation system 194.
Date Recue/Date Received 2023-12-05

[00335] The flotation system 194 can be a single stage flotation system or can be a two stage flotation system. In some implementations, not shown in the figures, the flotation system 194 is a two stage system where a first stage unit receives the underflow stream 138 from PSV 132 and produces a first stage flotation overflow 139 and a first stage flotation underflow. The first stage flotation overflow 139 can be returned to the PSV 132, as discussed above. The first stage flotation underflow stream can be supplied to a second stage flotation unit. Each of the first stage and second stage flotation units can include at least one flotation cell (also referred to as flotation column). In some implementations, both first and second stage flotation units can include several flotation cells. In the second stage flotation unit, the underflow from the first stage flotation unit can be separated into a second stage flotation overflow stream including bitumen and a second stage flotation underflow including water corresponding to the PW stream 196. In some implementations, the overflow from the second stage flotation unit can be returned to the first stage flotation unit. For instance, the overflow from the second stage flotation unit can be mixed with the PSV underflow stream 138 and the mixture can be fed to the first stage flotation unit of the flotation system 194. In some implementations, the PW stream 196, e.g., the second stage flotation unit underflow where a two stage flotation system 194 is used, can have a temperature ranging from about 50 C
to about 75 C, or from about 55 C to about 70 C. As explained above, the PW
stream 196 can then be used to cool the degassed emulsion 18, 20 and the resulting heated PW stream can be sent to the water treatment facility 164 and be used to generate BFW.

[00336] The flotation system 194 can be a dedicated flotation system provided at the MES or can be a pre-existing flotation system downstream of the PSV 132.
In some implementations, the flotation system 194 can include middlings flotation units such as flotation units 52 and 54 shown in Figure 1B.

[00337] Still referring to Figure 7A, according to another implementation, the cooled degassed emulsion 124 can be directly treated into a flotation system Date Recue/Date Received 2023-12-05 before being sent to the secondary extraction facility. Hence, the in situ produced emulsion 10 can be degassed in degasser 12 to form the degassed emulsion 18, then the degassed emulsion 18 can be cooled as described above to form the cooled emulsion 124, which can be directed to flotation system 174. In flotation system 174, the cooled degassed emulsion 124 can be separated into a bitumen froth overflow stream 190 and a water-containing underflow stream 186. Bitumen froth stream 190 can then be treated in downstream assets of the MES to recover the diluted bitumen product 148. As previously discussed, the water-containing underflow stream 186 (PW stream 186) can be recycled into upstream operations.

More particularly, the PW stream 186 can be used to cool the degassed emulsion 18, 20 and the resulting heated PW can be sent to the water treatment facility to then generate BFW. In some implementations, at least a portion of the PW
stream 186 can be mixed with the PSV underflow stream 138 and the resulting mixture can then be treated in the flotation system 194.

[00338] In some implementations, the flotation system 174 can be a flotation system as described above with respect to flotation system 194. Hence, in some implementations, the flotation system 174 can be a two stage system where a first stage unit receives the cooled degassed emulsion 124 and produces a first stage flotation overflow 190 and a first stage flotation underflow. The first stage flotation underflow stream can then be supplied to a second stage flotation unit. Each of the first stage and second stage flotation units can include at least one flotation cell (also referred to as flotation column). In some implementations, both first and second stage flotation units can include several flotation cells. The first stage flotation overflow 190, optionally combined with the bitumen froth stream 134 recovered as the PSV 132 overflow, can be supplied to the secondary extraction facility. In the second stage flotation unit of flotation system 174, the underflow from the first stage flotation unit can be separated into a second stage flotation overflow stream including bitumen and a second stage flotation underflow including water corresponding to the PW stream 186. In some implementations, Date Recue/Date Received 2023-12-05 the overflow from the second stage flotation unit can be returned to the first stage flotation unit. For instance, the overflow from the second stage flotation unit can be mixed with the cooled degassed emulsion stream 124 and the mixture can be fed to the first stage flotation unit of the flotation system 174. In some implementations, the PW stream 186, e.g., the second stage flotation unit underf low where a two stage flotation system 174 is used, can have a temperature ranging from about 50 C to about 75 C, or from about 55 C to about 70 C.

[00339] Another possible integration operation where the in situ produced emulsion is treated at the MES at the end of the mine life, is shown in Figure 7B.
More particularly, the degassed emulsion stream 18, which has optionally been subjected to H2S scavenging, can be cooled and then subjected to a dewatering operation before being sent to the secondary extraction facility. In some implementations, the degassed emulsion stream 18 can be cooled through indirect contact with various cool streams such as PEW, BFW and/or PW, in heat exchangers 222a-c,c', as discussed above. In some implementations, the dewatering step can be performed by adding a dewatering solvent to the cooled degassed emulsion stream. The dewatering solvent can include a blend of light hydrocarbons. In some implementations, the dewatering solvent can be a blend of light hydrocarbons that is characterized by a vapour pressure of less than 14.7 psia and/or a density of from about 650 to about 850 kg/m3. In some implementations, the dewatering solvent can be a gas condensate or a naphthenic diluent. The resulting diluted emulsion stream can then be sent to a dewatering unit where water is separated from the diluted emulsion stream by gravity. The recovered dewatered stream 204 can then be directed to the secondary extraction facility. In some implementations, the water recovered from the dewatering unit can be sent to the water treatment unit 164 where it can be used to produce BFW.

[00340] As also illustrated in Figure 7B, in another implementation, the degassed emulsion stream 18, which has optionally been subjected to H2S scavenging, can be cooled to produce the cooled emulsion stream 202, which can directly be sent Date Recue/Date Received 2023-12-05 to the secondary extraction facility. As discussed above, cooling of the degassed emulsion stream 18 can be performed by indirect contact with various cooling fluids such as PEW, BFW and/or PW, in heat exchangers 222a-c,c'.

[00341] The treatment of the in situ emulsion at the MES can thus allow producing various bitumen-containing streams, such as streams 134, 190, 192, 202 or 204, which can then be sent to the secondary extraction facility, as shown in Figure 7C.
Each of bitumen-containing streams 134, 190, 192, 202 or 204 can be treated independently or in any combination thereof at the secondary extraction facility.
Secondary extraction techniques that can be used to treat streams 134, 190, 192, 202 or 204, can include paraffinic or naphthenic froth treatments. Such techniques involve the addition of a solvent or diluent (e.g., paraffinic solvent or naphthenic diluent) to the bitumen froth and then separating the diluted bitumen froth stream in a gravity separation vessel into an overflow including a diluted bitumen product and an underflow including water that can be further treated in downstream operations.

[00342] According to some implementations, as shown in Figure 7C, the bitumen froth treatment can be performed using a naphthenic diluent in a two stage separation system. First, naphthenic diluent can be added to the bitumen froth streams 134, 190, 192,202 or 204, or to any combination thereof, and the resulting diluted bitumen froth can be treated in a gravity separation vessel 146 to separate the froth into a separation vessel overflow 148 including diluted bitumen and a separation vessel underflow 150 including mainly water and some residual bitumen. In some implementations, the gravity separation vessel 146 can be an inclined plate separator (IPS). The underflow stream 150 recovered from the separation vessel 146 can be used as cooling fluid in heat exchanger 222c to cool the degassed emulsion 18 or 20 and the resulting heated stream can be sent to the water treatment 164 for deoiling. In other implementations, the underflow stream 150 recovered from the gravity separation vessel 146 can further be treated in an underflow system, which can include high gravity-force (G-force) separators Date Recue/Date Received 2023-12-05 such as cyclones and/or centrifuges. In some implementations, the separation vessel underflow 150 is sent to at least one cyclone unit to recover a cyclone unit overflow, which can be returned to the IPS as stream 200, and a cyclone unit underflow stream 198 including water, which can be sent to deoiling in the water treatment facility 164. In some implementations, the separation vessel underflow 150 is sent to at least one cyclone unit to recover a cyclone unit underflow stream 198 including water, which can be sent to deoiling in the water treatment facility 164, and a cyclone unit overflow, which can be returned as stream 200 to the gravity separation vessel 146 and/or be supplied to at least one centrifuge unit.
The centrifuge unit overflow can then be returned as stream 200 to the gravity separation vessel 146. The cyclone unit can be a one stage or two stage unit.
When the cyclone unit is a two stage unit, the underflow from the first stage cyclone can be sent to the second stage cyclone, and the underflow from the second stage cyclone is sent as water stream 198 to deoiling in the water treatment facility 164.
The overflows from the first and second stage cyclones can be returned as stream 200 to the gravity separation vessel 146, or directed to the centrifuges from which a diluted bitumen product can be recovered and then combined with the IPS
overflow 148. Produced water stream 198 recovered from the underflow system downstream the gravity separation vessel 146, can also be used to cool the degassed emulsion 18 or 20 in heat exchanger 222c'. Still referring to Figure 7C, the PW streams 150 and/or 198 can be treated in the water treatment facility 164, to produce BFW stream 166, which can itself be used for generating superheated steam in unit 168. The generated superheated steam 170 can be used to generate power and/or can be used as injection fluid in the in situ recovery operation.

[00343] Figures 8 to 11, which illustrate in more detail some of the implementations presented above with reference to Figures 7A-7C, will now be described. Figures 8 and 9 more particularly focus on the heat integration techniques in the case where the in situ emulsion is treated in the primary extraction facility prior to the extraction facility, and Figures 10 and 11 focus on the Date Recue/Date Received 2023-12-05 heat integration techniques in the case where the in situ emulsion is sent to the secondary extraction facility without prior treatment in the primary extraction facility.

[00344] As seen in Figure 8, in some implementations, the degassed emulsion stream 18 or 20 can be cooled in a first heat exchanger 122c, a second heat exchanger 122d and then a third heat exchanger 122a, to produce the cooled emulsion steam 124, which can then be supplied to the primary extraction facility for separating the emulsion into at least one bitumen froth stream and at least one produced water stream. In the heat exchanger 122c, the degassed emulsion stream 18 or 20 can be cooled by indirect contact with a produced water stream recovered from the primary extraction operations. The produced water stream (PW
stream) can be any water stream recovered from a water/bitumen separation unit of the primary extraction facility. As discussed above, the PW stream can include, for instance, PW streams 186 and 196 recovered from the flotation systems 174 and 194 or a combination of these PW streams. At the outlet of the heat exchanger 122c, the heated PW stream can have a temperature ranging from about 100 C
to about 200 C. In some implementations, the heated PW stream exiting the heat exchanger 122c can be at a temperature from about 145 C to about 155 C, or from about 145 C to about 150 C, e.g., at about 149 C. The heated PW stream exiting the heat exchanger 122c can then be further treated in a water treatment facility including at least a deoiling unit 208 and an evaporation unit 216.
In some implementations, the heated PW stream exiting the heat exchanger 122c is cooled in the heat exchanger 206 before being supplied to deoiling unit 208. In some implementations, the heated PW stream is cooled in the heat exchanger 206 to a temperature ranging from about 80 C to about 150 C. In some implementations, the temperature of the PW stream exiting the heat exchanger 206 can be from about 120 C to about 130 C. In some implementations, the temperature of the PW stream exiting the heat exchanger 206 can be about 125 C. The fluid that flows in the heat exchanger 206 to cool heated PW stream can be a distillate Date Recue/Date Received 2023-12-05 stream 218 recovered from the evaporation unit 216. In some implementations, the distillate stream 218 exiting the heat exchanger 206 can be used as BFW.
In some implementations, the temperature of the distillate stream 218 exiting the heat exchanger 206 can range from about 80 C to about 190 C. In some implementations, the temperature of the heated distillate stream exiting the heat exchanger 206 can range from about 130 C to about 140 C, and can be e.g., about 135 C. In the heat exchanger 122d, the degassed emulsion stream 18 or 20 can be further cooled by indirect contact with a bitumen froth produced in the primary extraction operations, such as bitumen froth stream 134 produced as the PSV 132 overflow, bitumen froth stream 190 produced in the flotation system or a combination of these bitumen froth streams. The heated bitumen froth stream exiting the heat exchanger 122d can then be supplied to the secondary extraction facility. In some implementations, the bitumen froth stream heated through the heat exchanger 122d can be further heated, if required, by steam injection.
Finally, in the implementation represented in Figure 8, the degassed emulsion stream 18 or 20 can further be cooled in the heat exchanger 122a, by indirect contact with pond effluent water (PEW). The heated PEW exiting the heat exchanger 122a can then be dumped to a pond and/or can be used as make-up water that can be added to the heated produced water before treatment in the deoiling unit 208 of the water treatment facility. Further detail regarding the water treatment will be described later with reference to Figure 13. However, from Figure 8, one can note that the PW water stream, such as stream 186 or 196, can be first treated in deoiling unit 208 to produce a deoiled stream 210 and a bitumen froth stream 212. In some implementations, the bitumen froth stream 212 can be mixed with the bitumen froth heated in the heat exchanger 122d, and the mixed stream can be supplied to the secondary extraction. In further implementations, the deoiling unit 208 can receive PW streams recovered from secondary extraction operations, such as PW stream 150 produced as the underflow of the gravity separation vessel 146 or PW
stream 198 produced in the separation assets downstream of the gravity separation vessel 146 (e.g., cyclones, centrifuges). The deoiled stream 210 exiting the deoiling unit Date Recue/Date Received 2023-12-05 208 can be sent to an evaporation unit 216 to produce a water distillate stream 218 that can be used as BFW. Finally, the evaporator blowdown stream 219 recovered from the evaporation unit 216 can be supplied to the disposal water treatment (DVVT).

[00345] Figure 9 shows another implementation of the in situ emulsion treatment at the MES involving a heat integration design slightly different than the one presented in Figure 8. More particularly, in this implementation, the degassed emulsion stream 18 or 20 can be cooled in a heat exchanger 122b before further cooling in the heat exchangers 122c and/or 122d and 122a. Hence, the degassed emulsion stream 18 or 20 is first cooled in the heat exchanger 122b by indirect contact with the water distillate stream 218 produced in the evaporation unit 216.
The heated distillate exiting the heat exchanger 122b is then used as BFW. In one implementation, the heated degassed emulsion stream 18 or 20 exiting the heat exchanger 122b can be sent to the heat exchanger 122c and then the heat exchanger 122a. In another implementation, the heated degassed emulsion stream 18 or 20 exiting the heat exchanger 122b can be sent to the heat exchanger 122d and then the heat exchanger 122a. In yet another implementation, the heated degassed emulsion stream 18 or 20 exiting the heat exchanger 122b can be sent to the heat exchanger 122c, then the heat exchanger 122d and finally the heat exchanger 122a. Therefore, in the scenario presented in Figure 9, the degassed emulsion stream 18 or 20 can be cooled through three or four different heat exchangers in series. The cooling fluids flowing through the heat exchangers 122a, 122c and 122d are the same fluids as discussed above with reference to Figure 8, namely, PEW for the heat exchanger 122a, a PW stream recovered from the primary extraction for the heat exchanger 122c (e.g., streams 186 and/or 196) and a bitumen froth stream produced in the primary extraction for the heat exchanger 122d (e.g., streams 134 and/or 190). The heated PW stream exiting the heat exchanger 122c can then be sent to the deoiling unit 208 of the water treatment Date Recue/Date Received 2023-12-05 facility. Regarding the other process features and configurations presented in Figure 9, they generally correspond to those described in relation with Figure 8.

[00346] In Figures 10 and 11, particular implementations of the in situ emulsion treatment into the secondary extraction facility are presented. In Figure 10, the degassed emulsion stream 18 or 20 can be cooled in three heat exchangers in series, namely heat exchanger 222b, 222 c' and 222a before addition of the extraction solvent, e.g., naphthenic diluent, to the resulting cooled emulsion stream to produce a diluted emulsion, which can then be separated into the gravity separation vessel 246. Therefore, the degassed emulsion stream 18 or 20 can be cooled by indirect contact with BFW as the cooling fluid of the heat exchanger 222b, then by indirect contact with the PW stream 298 produced in the underflow system associated with the gravity separation vessel 246 as the cooling fluid of the heat exchanger 222c', and finally by indirect contact with PEW as the cooling fluid of the heat exchanger 222a. In some implementations, the diluted emulsion stream can be directly supplied to the gravity separation vessel 246. In other implementations, the diluted emulsion stream can be subjected to a pre-dewatering step before the gravity separation vessel 246. Such pre-dewatering step can correspond to the step discussed above in relation with Figure 7B
producing the dewatered stream 204. Then, the separation step occurring in the gravity separation vessel 246 is as described above with respect to the gravity separation vessel 146. Hence, the diluted emulsion exiting the heat exchanger 222a can be treated in the gravity separation vessel 246 (e.g., an IPS) to separate the emulsion into a separation vessel overflow 248 including diluted bitumen and a separation vessel underflow 250 including mainly water and some residual bitumen. The underflow stream 250 recovered from the gravity separation vessel 246 can further be treated in an underflow system, which can include high gravity-force (G-force) separators such as cyclones and/or centrifuges. In some implementations, the gravity separation vessel underflow 250 is sent to at least one cyclone unit to recover a cyclone unit underflow stream 298 including water, Date Recue/Date Received 2023-12-05 which can be sent to deoiling in the water treatment facility, and a cyclone unit overflow, which can be returned to the gravity separation vessel 246 and/or be supplied to at least one centrifuge unit. The centrifuge unit overflow can then be returned to the gravity separation vessel 246. The cyclone unit can be a one stage or two stage unit. When the cyclone unit is a two stage unit, the underflow from the first stage cyclone can be sent to the second stage cyclone, and the underflow from the second stage cyclone is sent as water stream 298 to deoiling in the water treatment facility. The overflows from the first and second stage cyclones can be returned to the gravity separation vessel 246, or directed to the centrifuges from which a diluted bitumen product can be recovered and then combined with the IPS
overflow 248. Produced water stream 298 can be heated by flowing into the heat exchanger 222c' by contact with the hot degassed emulsion stream, before being supplied to the deoiling unit of the water treatment facility.

[00347] The implementation shown in Figure 11 is fairly similar to the one presented in Figure 10 with regard to the operations carried out downstream the heat exchangers 222c' and 222a but differs in upstream operations with the degassed emulsion stream 18 or 20 being sent to a flash vessel 300 before cooling in the heat exchanger 222c'. In this implementation, the degassed emulsion stream 18 or 20 is thus supplied to the flash vessel 300 to produce steam and a flashed emulsion having a reduced temperature and water content that can then be cooled in the heat exchangers 222c' and 222a before treatment in the gravity separation vessel 246. The step of flashing the degassed emulsion in flash vessel 300 can thus allow cooling and dewatering the emulsion to a certain extent while producing steam, which can be used in other operations at the MES. For instance, the steam produced from the emulsion in flash vessel 300 can be used in the evaporation unit 216,416 when this unit includes a multi-effect evaporator.

[00348] As described above, several integration techniques can be implemented to treat an in situ produced emulsion at a MES at the end of the mine life. In addition to the advantage of being able to use MES assets for treating the in situ emulsion, Date Recue/Date Received 2023-12-05 these techniques can also benefit from the hot temperature of the in situ emulsion for heating various streams at the MES.
Treatment of in situ emulsion by high temperature flotation

[00349] Several techniques have been described above to treat an in situ produced emulsion either with concurrent treatment of mined oil sands ore at the MES or with treatment of only the in situ produced emulsion at the MES, such as after the end of the mine life. As explained above, in some implementations, the in situ emulsion can be treated in flotation systems where the emulsion can be aerated and dewatered. In the above description, the cooled situ emulsion 24,124, which is supplied to the flotation system can have a temperature ranging from about 50 to about 85 C. However, in some implementations, which can apply both to the "concurrent treatment" and "in situ only treatment" scenarios described above, a hot in situ emulsion can be treated by high temperature flotation, as shown in Figure 12.

[00350] Therefore, in this implementation as shown in Figure 12, the degassed in situ emulsion stream 18, which has optionally been subjected to H25 scavenging (stream 20), can be supplied to a high temperature flotation system 310, where the emulsion can be separated into a high temperature bitumen froth stream 312 and high temperature water stream 314. In some implementations, the degassed in situ emulsion stream 18,20 can be cooled to some extent before being supplied to the high temperature flotation system 310, by indirect contact with BFW in the heat exchanger 222b. In some implementations, the emulsion supplied to the high temperature flotation system 310 can have a temperature ranging from about 90 C to about 150 C. In some implementations, the high temperature flotation system 310 can be a single stage flotation system or can be a two stage flotation system. In some implementations, the high temperature flotation system 310 can include two flotation units in series, each including at least one flotation cell (also referred to as flotation column). In some implementations, both the first and second Date Recue/Date Received 2023-12-05 flotation units of the high temperature flotation system 310 can include several flotation cells. The high temperature bitumen froth 312 can be produced as the first flotation unit overflow and the high temperature water steam 314 can be recovered as the second flotation unit underflow. In some implementations, the treatment in the flotation system 310 can be performed by bubbling air and/or an inert gas such as N2 gas, or a hydrocarbon gas such as natural gas into the emulsion. In some implementations, the treatment in the flotation system 310 is run at atmospheric pressure or higher pressure such that the system is operated above the vapour pressure of water at the operating temperature. If an inert or natural gas is used, the gas can be recovered, and either be recycled for re-use in the flotation system or use as fuel in the case where the has is natural gas. In implementations where air is used in the flotation system 310, the air can be vented with or without the use of condensers and/or can be directed to an incinerator. In some implementations, the gas can be recovered from the flotation system by cooling and condensing liquids from the gas, and then separating the gas from the condensed liquids.
The gas used in the flotation system can be added to the flotation system by any means previously discussed (e.g., dissolved gas, microbubble pumps, gas eductor, gas sparger/nozzle). In some implementations, the high temperature bitumen froth can have a temperature ranging from about 80 C to about 150 C. In some implementations, the high temperature water stream 314 can have a temperature ranging from about 90 C to about 150 C. The high temperature bitumen froth stream 312 can then be supplied to a deaerator unit 320 to obtain the deaerated froth stream 342, which can then be supplied to the secondary extraction facility for further treatment. The high temperature bitumen froth 312 is at least deaerated in unit 320. Furthermore, if a gas is bubbled into the emulsion during the flotation treatment, the gas can further be recovered and the recovered gas can be reused.
When the gas includes natural gas, it can be recovered and reused as fuel or recycled to the flotation system 310. When nitrogen is used in the flotation system, it can be recovered and recycled as flotation gas. In the case where air is used in the flotation system, it can be vented to atmosphere or directed to an incinerator.
Date Recue/Date Received 2023-12-05 In some implementations, depending on the temperature of the deaerated bitumen froth stream 342, a cooling step can be performed before the froth is treated in the secondary extraction. For instance, the deaerated bitumen froth stream 342 can be cooled by indirect contact with a water stream of the MES such as BFW, or can be cooled by direct mixing with a bitumen froth stream deriving from the oil sands ore (quenching) in the concurrent treatment scenario.

[00351] In an alternative implementation, the flotation system 310 can be configured to produce a bitumen froth stream 312, which, after deaeration, can form a deaerated bitumen froth stream 342 that can be directly used as a feed stream in upgrading operations. In some implementations, the bitumen froth stream 342 can have a water content of less than 5% by volume before being sent to upgrading operations. In some implementations, the bitumen froth stream 342 can be blended with a diluted bitumen stream from another extraction operation and sent to a diluent stripping unit, can be fed directly to a distillation unit (atmospheric or vacuum), can be fed directly to a coker unit, and/or can be fed to a solvent deasphalting unit.

[00352] In some implementations, the high temperature water stream 314 can be further supplied to a water treatment facility at the MES, which can include an evaporator unit and an optional deoiling unit as discussed above and as will be further described in the next section.

[00353] The present integration techniques involving the treatment of an in situ produced emulsion, such as a SAGD emulsion, either concurrently with oil sands mining operations or at the end of the mine life, can present several advantages.
In addition to the advantage of being able to use MES assets for treating the in situ emulsion, these techniques can also benefit from the hot temperature of the in situ emulsion for heating various streams at the MES. When the in situ emulsion is treated on its own, in the "in situ only" scenario, large equipment required for solids handling can be avoided since the in situ emulsion has low solids content.
This Date Recue/Date Received 2023-12-05 can allow reducing maintenance operations and costs. In the "concurrent treatment" scenario, blending of the in situ emulsion with mined hydrotransport slurry or bitumen froth can allow diluting both the fines and chloride contents in the combined stream, thereby improving treatability (i.e., water and solids removal from the streams) and reducing chloride and mineral load in the feed to downstream upgrading assets. In turn, the chloride and mineral related maintenance on upgrading assets can be reduced. Furthermore, blending the in situ emulsion and mined oil sands slurry can enhance the oil-water separation step, especially when the mine is processing poor quality ore such as close to the end of the mine life. As the mine is near to its life end, the ore can contain high degree of fines, which can impact the oil-water separation. Then, the MES assets should be run at a slower pace and a higher volume of oil sands slurry needs to be processed to get as much dewatering as during regular operations. Since the in situ emulsion contains few solids, the blending thereof with the oil sands slurry can result in a dilution effect, which can overcome the drawback due to the presence of fines. Hence, blending the in situ emulsion with mined oil sands slurry resulting from poor quality ore can produce a mixture that is more treatable, which can allow reducing maintenance operations and costs.
De-superheated steam for use at remote facility

[00354] In this section of the present description, implementations for the generation and use of de-superheated steam will be described in more detail.
More particularly, in some implementations, the process can include generating superheated steam at the oil sands mining and extraction facility, de-superheating a portion of the superheated steam, and transporting the de-superheated steam for use at a remote facility, such as the in situ recovery facility.

[00355] Figures 1A and 1B show example configurations for preparing boiler feedwater (BFVV) and generating steam. In the illustrated configuration, a pond effluent water (PEW) stream 60 is heated (e.g., by indirect heat transfer with the Date Recue/Date Received 2023-12-05 degassed emulsion 18, 20 at heat exchanger 22a) and then the heated PEW 62 is treated in a water treatment unit 64. Other sources of water (W) can also be treated in the water treatment unit 64, including water effluent from an upgrader, produced water recovered from an in situ bitumen recovery operation, a surface water source and/or a ground water source, for example. One or more of the aforementioned water sources (W) can be supplied to the water treatment unit 64 to produce treated water 66 that can be used as BFW and/or other applications. In one implementation, the water treatment unit 64 is located at the oil sands mining and extraction facility. The water treatment unit 64 can include various water treatment vessels and equipment that use chemical and/or evaporative treatments. For example, the water treatment unit 64 can include a multi-effect evaporator which separates condensate from impurities dissolved in the water. In some implementations, the treated water stream 66 can be used to cool other process streams, including the degassed emulsion 18 or 20, which also enables heating of the treated water stream 66. This heat exchange can be performed in the heat exchanger 22b. In some implementations, the treated water stream 66 is preheated and is sent to steam generators 68, which can include drum boilers, which produce a superheated steam stream 70. In some implementations, the steam generators 68 are also located at the oil sands mining and extraction facility.
The steam generators 68 can be configured to generate superheated steam that can be used for various purposes at the mining and extraction facility, and can be designed for certain capacity, requirements or throughput of the mining and extraction facility.

[00356] In some implementations, as shown in Figure 1D, the superheated steam stream 70 is de-superheated to produce a de-superheated steam stream 72. In one implementation, the superheated steam is de-superheated at the oil sands mining and extraction facility and the de-superheated steam is then transported to a remote location for use as a heating medium. In one implementation, the Date Recue/Date Received 2023-12-05 superheated steam is de-superheated by adding an aqueous liquid to the superheated steam stream 70.

[00357] In the present description, the terms "de-superheated" steam and "de-superheating" refer to a reduction in the superheated state of superheated steam.
In this regard, Figure 14 illustrates a pressure versus temperature graph of showing different states including the superheated state. In some implementations, the superheated steam is de-superheated to reduce the temperature and/or the pressure of the steam, such that the de-superheated steam remains in a reduced superheated state. It is also possible to subject the steam to de-superheating to produce steam that is at or near the saturation line, and such de-superheated steam is then transported to the remote location. In a further case, it is possible to reduce the de-superheat of the steam such that it arrives at the remote location in a saturated state, but with minimal or no loss of steam quality. The de-superheating can be conducted depending on the end use of the de-superheated steam and the expected heat loss of the de-superheated during transportation. In the example scenario of Figure 1D, the superheated steam is very hot and at high pressure and the de-superheating is conducted to reduce the temperature of the steam while remaining in a superheated state, and after pipelining to the in situ facility as seen in Figure 7B the de-superheated steam is still in the superheated state but is closer to the saturation state.

[00358] The aqueous liquid can be derived from one or more sources, some of which will be described below. For example, the aqueous liquid can be supplied from any one of effluent water from an upgrader, overhead condensate from a stripping column, BFW, tailings water including the water cap of the pond or release water from dewatering of the tailings, produced water recovered from an in situ recovery facility, surface water, ground water, steam condensate, or any combination thereof. The water can be treated prior to mixing with the superheated steam to reduce the presence of impurities in the process stream. The aqueous liquid can be almost pure water or can be water having a certain concentration of Date Recue/Date Received 2023-12-05 impurities including dissolved salts and organic species. Depending on its origin, the aqueous liquid can be pretreated or not prior to addition to the superheated steam.

[00359] In some implementations, the aqueous liquid is added to the superheated steam in an amount such that it is between 0 and 20 wt% or between 2 and 15 wt% of the resulting de-superheated steam. The quantity of aqueous liquid that is added can also depend on the pressure and temperature conditions of the superheated steam as well as the desired pressure and temperature of the de-superheated steam. The relative amount of the aqueous liquid added to the superheated steam can also be modulated over time depending on the operating conditions and the end-use requirements of the de-superheated steam.

[00360] In some implementations, the aqueous liquid includes steam condensate that is used for de-superheating. The steam condensate can be obtained from a stripping column used for solvent recovery from solvent diluted tailings and which is part of the secondary extraction facility. Stripping columns can be used as solvent recovery units to recover solvent from solvent diluted tailings, where steam is injected at the bottom and condensate is recovered from the vaporized solvent overhead. In some implementations, steam condensate generated in any step during oil sands extraction or processing can be used to de-superheat the superheated steam. The steam condensate could be obtained from a stripping column or another vessel in which steam is injected, or from a flash vessel where water vapour is flashed along with other components and can be recovered, or the steam condensate can be condensed steam from indirect heating applications.

[00361] In another implementation, condensate can be heated by indirect heat exchange with the superheated steam in order to produce heated condensate or re-vaporized condensate (i.e., steam) as well as de-superheated steam. The heated or re-vaporized condensate can the be recycled back into the stripping column as injected steam, to reduce direct energy requirements at the stripping Date Recue/Date Received 2023-12-05 column. The heated or re-vaporized condensate could also be reused in various other unit operations of the mining and extraction facility, for example.

[00362] In some other implementations, at least a portion of the de-superheated steam can be supplied to a stripping column for use as stripping steam. It is possible to send a portion of the de-superheated steam to a stripping column or another unit operation at the oil sands mining and extraction facility, while pipelining another portion of the de-superheated steam to a remote facility such as the in situ recovery facility.

[00363] In some implementations, the aqueous liquid can include water obtained from or used in upgrading facilities as process water and/or cooling water.
For example, in some upgrading operations, water can be used during hydrotreating of bitumen. Water used in this process dissolves impurities from the bitumen and this used upgrading water can be reused to de-superheat the superheated steam.

Upgrader facilities can have various sources of water than can be used in part for de-superheating.

[00364] In some implementations, the aqueous liquid can include water obtained from an in situ recovery facility. For example, some of the water used for de-superheating can be obtained from the dewatering of the degassed in situ emulsion stream 18 using the dewatering unit 15. In such a case, the de-superheated steam would de-superheated at the mining and extraction facility. The aqueous liquid could include some water derived from the in situ emulsion if the emulsion is processed in the mining and extraction facility to remove water therefrom, and some of that water is used for de-superheating. It is also possible to trim cool the de-superheated steam at the in situ facility, for example using condenser water 16 from the condenser 14. The flow rates of the condenser water 16 are typically small and thus could be used for small adjustments to the de-superheated steam and would also facilitate recycling that condenser water back into the reservoir if the de-superheated steam is injected downhole.
Date Recue/Date Received 2023-12-05

[00365] In some implementations, the aqueous liquid can include surface and/or ground water sources. Examples of surface water can be lakes and rivers. These water sources could be pretreated or used directly for addition to the superheated steam.

[00366] While one example implementation of de-superheating uses the addition of the aqueous liquid to the superheated steam, another example implementation is indirect heat exchange with a cooler fluid to remove heat and thus de-superheat the steam. For example, the superheated steam could be supplied to an indirect heat exchanger that also receives a cooler process stream that could be aqueous or hydrocarbon based, to de-superheat the steam and heat the process stream.
Various process streams at the mining and extraction facility require heating and could be used for this purpose.

[00367] The amount of de-superheating can be controlled, for example, by controlling the volume of the aqueous liquid added to the superheated steam and/or the temperature of the aqueous liquid. Other control methods are also possible to manage the de-superheating step, such as controlling the flow rates of the process stream and the steam stream entering the indirect heat exchanger if indirect de-superheating is employed.

[00368] In some implementations, as shown in Figures 1C and 7B, the de-superheated steam 72, 172 is supplied to the in situ recovery facility and can be injected into the reservoir via one or more injector wells. In addition to steam, some in situ methods inject a secondary fluid via the injector well 11. In some implementations, the secondary fluid is an organic solvent, such as naphtha or a C3-C6 paraffinic solvent or a mixture of organic compounds. Other injection additives can also be used. When solvent is used, the solvent can be preheated prior to injection and the de-superheated steam can be used for this preheating. In one implementation, the solvent is heated by mixing it with the de-superheated steam prior to co-injection into the injector well 11. In another implementation, the Date Recue/Date Received 2023-12-05 solvent can be indirectly heated using the de-superheated steam at surface, and then the heated solvent is injected downhole as part of a solvent-dominated or solvent-only process. The solvent can be indirectly heated for injection in vapour phase. In some implementations, the de-superheated steam can instead heat a fluid other than solvent for injection into the injection well, such as a non-condensable gas. In some implementations, the de-superheated steam can be used to indirectly heat a mixture of bitumen and solvent, or a mixture of bitumen, solvent and water for the purpose of recovering the solvent.

[00369] One advantage of generating superheated steam at a central facility and pipelining the steam to a remote facility is that additional steam generation resources do not need to be deployed at the remote facility. This can result in reduced cost for remote deployment, increased usage of existing steam generation resources, as well as reduced logistics and deployment time at the remote facility (e.g., an in situ recovery facility). In one implementation, de-superheated steam is provided at a temperature which permits the de-superheated steam to arrive at the in situ recovery facility in a superheated state (e.g., as in Figure 7B).
Keeping the steam at a superheated state prevents condensation from occurring in pipelines carrying the de-superheated steam. In one implementation, the steam is de-superheated to a temperature of 270 C at a gauge pressure of 5,000 kPa. In another implementation, the steam is de-superheated to a temperature of 370 C
at a gauge pressure exceeding 5,000 kPa. Other temperature and pressure values can be selected based on the requirements of the in situ facility.

[00370] In some implementations, it can be desired for the de-superheated steam arriving at the in situ facility to be further de-superheated prior to injection into the injector well 11. This can allow the de-superheated steam to condense earlier in the well, releasing heat earlier compared to the steam with greater superheat, as well as wetting the reservoir closer to the surface. In some implementations, the de-superheated steam arriving at the in situ recovery facility can be de-superheated to a saturated state. The de-superheated steam arriving at the in situ Date Recue/Date Received 2023-12-05 facility could be further de-superheated in various ways, such as passing the steam through an indirect heat exchanger and/or adding a fluid such as water. In some implementations, the de-superheated steam is handled so that it enters the reservoir via the injector well as close to the saturated state as possible.
Thus, the de-superheated steam can be cooled at the surface and/or introduced into the injector well at a state such that it cools as it flows down the injector well and is injected at a desired saturated state. It is also possible to simply inject the de-superheated steam into the reservoir in a superheated state.

[00371] In one implementation, water recovered from the in situ recovery facility is used to de-superheat the steam at the in situ recovery facility. This water can include condensate recovered from condensing water vapour from a produced gas stream (e.g., from casing gas or from vapours produced by a degasser that receives the emulsion).

[00372] It is noted that the in situ recovery process illustrated in Figure 1C

generally represents a SAGD process, though other in situ recovery processes can be used. In some implementations, the in situ recovery process can include Cyclic Steam Stimulation (CSS) or other steam-based or steam-assisted processes. As previously mentioned, solvent-assisted or solvent-based processes can also be used. Various fluids can be injected over the course of the life of the in situ facility, including organic solvents, surfactants, NCGs, and so on, and these fluids can be injected alone or co-injected with steam or other fluids. Co-injection of steam with another injection fluid can be performed for various reasons.

[00373] The de-superheated steam can be handled prior to injection in accordance with the recovery process that is being used and certain desired effects. For example, the de-superheated steam could be provided at conditions prior to injection to promote heating of the reservoir, to reduce effects such as steam hammer, and other effects that are desired for in situ operations, including stripping H25 from produced water.
Date Recue/Date Received 2023-12-05

[00374] According to some implementations and as previously mentioned, at least a portion of the superheated steam is de-superheated and transported to a remote facility, such as the in situ recovery facility shown in Figure 1C, for use in the injector well 11.

[00375] When a second portion of the superheated steam is not de-superheated and transported to the in situ recovery facility, this second portion of the steam can be used for other purposes at the oil sands mining and extraction facility.
The steam can be used for heating and/or as a process fluid for certain unit operations.
For example, at least some of the second portion of the superheated steam can be directed to the steam driven equipment to generate motive force. In some implementations, at least some of the second portion of the superheated steam can be used to generate power. Power can be generated by steam turbines and generators at the oil sands mining and extraction facility for direct use at the facility or to feed into the grid. In some implementations, at least some of the second portion of the superheated steam can be used to heat process fluids, such as water, by direct steam injection and/or by indirect heat exchange. The steam can be used to heat streams and/or vessels. Process fluids that could be heated using steam include bitumen froth, process water used to form the slurry, among others.
The steam can also be used for preheating process streams that are fed into a phase separation vessel.

[00376] The steam can be distributed between the in situ facility and the extraction facility, and the various uses therein, based on the capacity of the boilers as well as the needs of the facilities and other available steam or heating sources.
The distribution of the steam can also change over time depending on the throughput and steam requirements for each facility. In addition, the deployment and start-up of in situ facilities can be coordinated with steam requirements and availability at the mining and extraction facility. In some implementations, at least 50% of the steam stream 70 is de-superheated and sent to the in situ recovery facility, with the remainder used at the oil sands mining and extraction facility. In Date Recue/Date Received 2023-12-05 some implementations, at least 25% of the steam stream 70 is de-superheated and sent to the in situ recovery facility. In some implementations, at least 10% of the steam stream 70 is de-superheated and sent to the in situ recovery facility.

[00377] In some implementations, the second portion of the superheated steam that is used for generating power at turbines 75 can be subsequently used for other purposes. For example, exhaust stream 71 of the steam turbines 75 is still at a relatively high temperature and its residual heat can be recovered in a multi-effect evaporator 73. In some implementations, the residual heat in the exhaust stream 71 can be used to heat other process streams, such as water from a tailings pond to produce the PEW stream 60.

[00378] In some implementations, the de-superheated steam is transported from the oil sands mining and extraction facility to the in situ recovery facility through a pipeline assembly that includes one or more pipelines configured to transport steam. In some implementations, the pipeline has a diameter between 15 to 60 inches. In some implementations, the de-superheated steam can be transported substantially by above ground pipelines, which can enhance simplicity of construction and monitoring. In some implementations, underground pipelines can be used for transporting the de-superheated steam. In some implementations, the de-superheated steam is transported a distance greater than 5 km from the oil sands mining and extraction facility to one or more of the in situ recovery facilities.
In some implementations, the de-superheated steam is transported a distance greater than 10 km from the oil sands mining and extraction facility to one or more of the in situ recovery facilities. In situ facilities can be located in different directions such that de-superheated steam streams are transported to respective in situ sites.
Although the implementation as illustrated in Figure 7B shows only one in situ recovery facility, there could be multiple in situ recovery facilities that receive de-superheated steam.
Date Recue/Date Received 2023-12-05

[00379] While the in situ facilities can be over 5 km, over 10 km, over 20 km, or over 30 km away from the de-superheating unit located at the oil sands mining and extraction facility, it is also noted that the oil sands mining and extraction facility itself can have a certain footprint that is one or two kilometers in breadth.
The mine face could be located at a greater distance from the stationary assets of the extraction facility.

[00380] It should be noted that in situ facilities that have dedicated on-site steam generators (e.g., once through steam generators, OTSGs) can also receive de-superheated steam that can be used for at-surface heating and/or mixed with the OTSG-generated steam for downhole injection. Alternatively, in situ facilities with dedicated OTSGs could receive no de-superheated steam while only those without dedicated steam generation receive de-superheated steam.

[00381] Bitumen recovery from in situ wells can include multiple stages, such as start-up, ramp-up, production mode and wind-down. Each stage can have different operational and heating requirements. For example, the start-up phase for SAGD

wells can last between two and four months, and serves to establish communication between the injector and producer wells. If steam is used for bullheading and/or circulation, then the de-superheated steam could be supplied for this purpose. During the production mode, the bitumen production is kept relatively constant and the steam requirements can gradually increase as the steam chamber expands. In the wind-down phase, the rate of bitumen recovery is lower and steam injection can be reduced and optionally replaced with co-injection of NCG. The de-superheated steam could be handled and used differently depending on the stage of the in situ operation.

[00382] Referring to Figure 13, there is shown in accordance with one implementation a process diagram outlining the steps for treating water for producing steam. In some implementations, water (e.g., untreated PEW, produced water from the in situ facility, surface water or ground water) can be recovered as Date Recue/Date Received 2023-12-05 a recovered water stream 406. In some implementations, this water can be heated with the superheated steam stream 70 (i.e., it can be used to de-superheat the superheated steam stream 70). The recovered water stream 406 can be treated in a water treatment unit in a water treatment step 408 to separate impurities from the water. For example, the water treatment step 408 can include the use of gravity separation, flotation, adsorption and/or filtration to separate the various components of recovered water stream 406.

[00383] The recovered water stream 406 can be treated in the water treatment step 408 to produce partially treated water stream 410 which can still comprise impurities. The partially treated water stream 410 can be further treated through evaporation in an evaporation step 412, separating the impurities to produce blowdown stream 416 (e.g., for disposal), and water vapor which is then condensed to produce a distillate stream 414. In some implementations, the evaporation step 412 can be carried out in a multi-effect evaporator. The distillate stream 414 can be heated in a heat exchanger, such as heat exchanger 22b, with the degassed emulsion 18, 20 prior to a steam generation unit 420. The steam generation unit 420 can generate superheated steam, for example to be de-superheated and transported for use in a remote in situ recovery facility as described previously. In some implementations, the entirety of the process illustrated in Figure 13 can be performed at the oil sands mining and extraction facility.

[00384] Although reference has mainly been made to an in situ recovery facility, in some implementations the de-superheated steam can be supplied to other units or facilities. For example, it can be desired to provide de-superheated steam to another facility for generation of power, heated water, motive force, stripping, and so on. Other remove facilities can include a remote oil sands mining and extraction facility, a remote bitumen upgrading plant, a remote hydrocarbon processing facility, or another remote site that can utilize de-superheated steam. It is also Date Recue/Date Received 2023-12-05 possible to use the de-superheated steam within the mining and extraction facility itself, as a stripping fluid and/or an indirect heat exchange medium.
Date Recue/Date Received 2023-12-05

Claims

95

1. A process for heating bitumen located in an underground reservoir, comprising:
generating superheated steam at an oil sands mining and extraction facility;
partially de-superheating at least a portion of the superheated steam at the oil sands mining and extraction facility to produce a partially de-superheated steam;
pipelining the partially de-superheated steam from the oil sands mining and extraction facility to an in situ recovery facility comprising at least one injection well located in the underground reservoir; and heating the bitumen located in the underground reservoir with heat from at least a portion of the partially de-superheated steam.

2. The process according to claim 1, wherein the superheated steam is generated using feedwater derived from one or more of effluent water from an upgrader, produced water recovered from an in situ bitumen recovery operation, a surface water source comprising tailings water, and a ground water source.

3. The process according to claim 2, wherein the in situ bitumen recovery operation is performed at the in situ recovery facility.

4. The process of any one of claims 1 to 3, wherein the pipelining of the partially de-superheated steam to the in situ recovery facility is performed over a distance greater than 30 km.

5. The process of any one of claims 1 to 4, wherein the partially de-superheated steam is de-superheated to an initial de-superheated Date Recue/Date Received 2023-12-05 temperature at the oil sands mining and extraction facility such that the partially de-superheated steam arrives at the in situ recovery facility in a superheated state.

6. The process according to claim 5, wherein the partially de-superheated steam is de-superheated at the oil sands mining and extraction facility to a temperature between 270 C and 370 C at a gauge pressure exceeding 5,000 kPa.

7. The process of any one of claims 1 to 6, wherein the partially de-superheated steam is further de-superheated prior to introduction into the at least one injection well.

8. The process of claim 7, wherein the partially de-superheated steam is de-superheated to a saturated state.

9. The process of claim 7, wherein water recovered from the in situ recovery facility is used to further de-superheat the steam at the in situ recovery facility.

10. The process of claim 9, wherein the water recovered from the in situ recovery facility comprises condensate recovered from a degassing unit used to remove gas from production fluid or from condensing water vapour in a produced gas stream.

11. The process of any one of claims 1 to 10, wherein the heating comprises injecting the partially de-superheated steam into the underground reservoir via the at least one injection well.

12. The process of any one of claims 1 to 11, wherein the heating comprises indirectly heating an injection fluid with the partially de-superheated steam to produce a heated injection fluid, and injecting the heated injection fluid into the underground reservoir via the at least one injection well.
Date Recue/Date Received 2023-12-05

13. The process of any one of claims 1 to 11, wherein the heating comprises injecting a mobilizing fluid into the at least one injection well, the mobilizing fluid comprising the partially de-superheated steam and a secondary fluid.

14. The process of claim 13, wherein the secondary fluid and the partially de-superheated steam are mixed prior to injection into the at least one injection well.

15. The process of claim 13 or 14, wherein the secondary fluid is an organic solvent or a non-condensable gas.

16. The process of claim 15, further comprising heating the secondary fluid by indirect heat exchange with the partially de-superheated steam to produce a heated secondary fluid, and injecting the heated secondary fluid into the at least one injection well.

17. The process of claim 16, wherein the partially de-superheated steam vaporizes the secondary fluid prior to injection thereof.

18. The process of any one of claims 1 to 17, wherein a second portion of the superheated steam that is not de-superheated for use at the in situ recovery facility is used for one or more of motive force, power generation or heating of a process fluid.

19. The process of any one of claims 1 to 18, wherein at least 10% of the total superheated steam is de-superheated and sent to the in situ recovery facility.

20. The process of any one of claims 1 to 19, wherein the pipelining of the partially de-superheated steam is performed in a pipeline having a diameter between 15 inches and 60 inches.
Date Recue/Date Received 2023-12-05