CA3138297A1 - Gas and solvent separation in surface facility for solvent based in situ recovery operation - Google Patents

Abstract

A solvent based in situ recovery process can have a surface facility for recovering solvent that includes separate process trains for gas and production fluid. Casing gas and other gas streams high in NCG and containing solvent is processed in a first process train that includes a purification tower to produce fuel gas and recovered solvent for reinjection downhole. The production fluid that includes mainly oil, water and solvent is processed in a second process train using flash separation stages to produce an oil product and recovered solvent for reinjection. The production fluid is subjected to degassing prior to flashing and water removal. Mechanical vapour recompression (MVR) may be used to condense a flashed stream and preheat the feed to a flashing stage. The processes can enhance heat use and inhibit NCG contamination of the solvent, which may be a paraffinic solvent such as butane used for bitumen recovery.

Description

GAS AND SOLVENT SEPARATION IN SURFACE FACILITY FOR SOLVENT BASED
IN SITU RECOVERY OPERATION
TECHNICAL FIELD
[001] The technical field generally relates to solvent based in situ recovery of heavy hydrocarbons, and more particularly to surface facilities and processes for handling production fluid and recovering solvent.
BACKGROUND

[002] Steam based processes have been used to heat and mobilise heavy hydrocarbons present in reservoirs to facilitate recovery to the surface.
Solvent based processes leverage the ability of solvents and heat to reduce the heavy hydrocarbon viscosity to aid recovery. Production fluid that contains solvent is processed at surface to recover the solvent for reinjection into the reservoir and to remove other components to produce an oil product. Efficient solvent recovery at surface facilities can be challenging given the complex multicomponent nature of fluids produced to surface as well as separation requirements. There is indeed a need for a technology that overcomes at least some of the challenges of handling and separating fluids produced in a solvent based in situ recovery process.
SUMMARY

[003] Techniques described herein include surface separation processes for recovering solvent from produced fluids in an efficient manner while inhibiting contamination of the solvent with non-condensable gas.

[004] In some implementations, there is provided a process for recovery of heavy hydrocarbons from a reservoir, comprising: injecting solvent into the reservoir to mobilize the heavy hydrocarbons; recovering production fluid and casing gas from the reservoir;
separately treating the production fluid and the casing gas, comprising: in a first process train, subjecting the casing gas to separation to obtain a first train recovered solvent and solvent-depleted gas; and in a second process train, subjecting the production fluid to separation stages to produce an oil product, a second train recovered solvent, and Date recue / Date received 2021-11-09 produced water. The process also includes reinjecting into the reservoir at least a portion of the first train recovered solvent, the second train recovered solvent, or a combination thereof.

[005] In some implementations, subjecting the casing gas to separation comprises:
supplying the casing gas to a gas separator to produce a solvent enriched stream and a solvent depleted gas stream; and supplying the solvent enriched stream to a distillation tower to produce a top vapour stream and a bottom solvent stream as the first train recovered solvent. In some implementations, the process includes chilling the solvent depleted gas stream to produce a chilled stream; supplying the chilled gas stream to a low temperature separator to produce a gas stream and a second solvent enriched stream;
and supplying the second solvent enriched stream to the distillation tower.
The process can include subjecting the top vapour stream to separation to produce a vapour recycle stream and a liquid stream; and recycling the vapour recycle into the low temperature separator. In some implementations, subjecting the top vapour stream to separation further produces a reflux stream that is fed back into the distillation tower.
The process can include combining the gas stream with a natural gas stream to produce a fuel gas. In some implementations, the chilling is performed so that the chilled stream has a temperature between 10 C and 15 C, and operating the gas separator at a temperature between 35 C and 45 C.

[006] In some implementations, the process includes removing light gases from the production fluid in the second process train; and supplying the light gases to the first process train for processing thereof. In some implementations, the light gases are combined with the casing gas prior to subjecting the casing gas to separation.

[007] In some implementations, subjecting the production fluid to separation stages comprises: a primary flashing stage to produce a first stage flashed stream and a first stage underflow stream; a water removal stage that receives the first stage underflow stream and produces a water enriched stream and a water depleted stream; and a secondary flashing stage that receives the water depleted stream and produces a secondary stage flashed stream and a second stage underflow stream. The process can also include condensing the first stage flashed stream to form a condensed stream and supplying the condensed stream to a primary separator to produce an aqueous stream and a first recovered solvent stream as part of the second train recovered solvent. In some Date recue / Date received 2021-11-09 implementations, the aqueous stream is supplied as washing liquid to a desalting stage to produce the oil product. In some implementations, the secondary stage flashed stream is supplied to a secondary separator to produce a secondary recovered solvent stream as part of the second train recovered solvent. In some implementations, the primary separator also produces a first stage gas stream and/or the secondary separator produces a second stage gas stream, and one or both of the primary and secondary gas streams are combined with the casing gas. In some implementations, the water removal stage also produces a water removal gas stream that is also combined with the casing gas.
In some implementations, the water removal stage is performed using a treater. In some implementations, the first stage gas stream, the second stage gas stream, and/or the water removal gas stream are blanket gases comprising methane. In some implementations, the process includes subjecting the second stage underflow stream to a tertiary flashing stage to produce a third stage flashed stream and a third stage underflow stream. In some implementations, the third stage flashed stream is supplied to a third stage separator to produce a third stage gas stream and a third stage liquid stream. In some implementations, the third stage gas stream is supplied to the secondary separator.
In some implementations, the third stage liquid stream is recycled back into the primary flashing stage. In some implementations, the third stage underflow stream is subjected to the desalting stage to produce the oil product. The process can also include compressing and cooling the third stage gas stream prior to the secondary separator.

[008] In some implementations, the first stage flashed stream is subjected to mechanical vapour recompression to produce a compressed stream. The compressed stream can be used to indirectly preheat the production fluid prior to the primary flashing stage.

[009] In some implementations, the process includes degassing the production fluid prior to the primary flashing stage to produce a degassed production fluid and a recovered gas stream comprising non-condensable gas and solvent. The process can also include combining the recovered gas with the casing gas. In some implementations, the oil product is used to indirectly preheat the production fluid prior to the degassing.

[0010] In some implementations, the second process train does not include a distillation stage. In some implementations, the second process train is configured to supply only light end gases to the first process train for processing. In some implementations, the first Date recue / Date received 2021-11-09 process train is configured to supply only overhead condensate from distillation to the second process train for processing.

[0011] In some implementations, the solvent is a paraffinic solvent having a carbon number from 4 to 6. For example, the solvent can be butane.

[0012] In some implementations, the solvent is injected via an injector well that is vertically spaced from an underlying producer well configured for recovering the production fluid, and the injector and producer wells are operated as a gravity drainage well pair.

[0013] In some implementations, the solvent is injected as a substantially pure solvent injection fluid to provide a solvent-only in situ recovery operation; or the solvent is provided as a main component of injection fluid to provide a solvent-dominated in situ recovery operation.

[0014] In some implementations, the heavy hydrocarbons comprise bitumen and/or the reservoir is an oil sands reservoir.

[0015] In some implementations, the first train recovered solvent and the second train recovered solvent are reinjected into the reservoir. In some implementations, separation units of the second process train are operated without a methane blanket.

[0016] In some implementations, the first train recovered solvent is reinjected into the reservoir. In some implementations, the second train recovered solvent is reinjected into the reservoir. Both can also be injected.

[0017] In some implementations, the casing gas recovered from the reservoir is subjected to compression prior to supply to the first process train. In some implementations, the casing gas recovered from the reservoir is subjected to a pre-separation treatment to remove liquid prior to supply to the first process train. In some implementations, the removed liquid is combined with the production fluid.

[0018] In some implementations, there is provided a process for recovery of heavy hydrocarbons from a reservoir, comprising: injecting solvent into the reservoir to mobilize the heavy hydrocarbons; recovering production fluid and casing gas from the reservoir;
Date recue / Date received 2021-11-09 separately treating the production fluid and the casing gas, comprising: in a first process train, subjecting the casing gas to separation to obtain a first train recovered solvent and solvent-depleted gas; and in a second process train, subjecting the production fluid to separation stages to produce an oil product, a second train recovered solvent, and produced water; and reusing at least a portion of the first train recovered solvent, the second train recovered solvent, or a combination thereof.

[0019] In some implementations, there is provided a system for recovery of heavy hydrocarbons from a reservoir, comprising: an injection well configured for injecting solvent into the reservoir to mobilize the heavy hydrocarbons; a production well configured for recovering production fluid and casing gas from the reservoir; a surface facility for treating the production fluid and the casing gas. The surface facility can include: a first process train configured to receive the casing gas from the production well and subject the casing gas to separation to obtain a first train recovered solvent and solvent-depleted gas; a second process train configured to receive the production fluid from the production well and subject the production fluid to separation stages to produce an oil product, a second train recovered solvent, and produced water; and an injection assembly configured to reinject into the reservoir at least a portion of the first train recovered solvent, the second train recovered solvent, or a combination thereof.

[0020] In some implementations, there is provided a process for recovery of heavy hydrocarbons from a reservoir, comprising: injecting solvent into the reservoir to mobilize the heavy hydrocarbons; recovering production fluid from the reservoir;
processing the production fluid to produce recovered solvent and an oil product, wherein the processing comprises: subjecting the production fluid to degassing to remove substantially all light end gas therefrom and produce: a gas mixture comprising non-condensable gas and solvent; and a degassed production fluid comprising oil, water and solvent.
The processing also includes separating the gas mixture to produce fuel gas and a first portion of the recovered solvent; and subjecting the degassed production fluid to flash separation to produce a second portion of the recovered solvent, produced water and the oil product.
The process also includes reinjecting into the reservoir at least a portion of the first portion of the recovered solvent, the second portion of the recovered solvent, or a combination thereof.
Date recue / Date received 2021-11-09

[0021] processing subjecting the degassed production fluid to flash separation comprises: subjecting the degassed production fluid to a primary flashing stage to produce a first stage flashed stream and a first stage underflow stream; subjecting the first stage underflow stream to a water removal stage to produce a water enriched stream and a water depleted stream; and subjecting the water depleted stream to a secondary flashing stage to produce a second stage flashed stream and a second stage underflow stream.

[0022] In some implementations, the process includes supplying the first stage flashed stream to a primary recovery separator to produce an aqueous stream and a first recovered solvent stream as part of the second portion of the recovered solvent. In some implementations, the aqueous stream is supplied as washing liquid to a desalting stage to produce the oil product. In some implementations, the second stage flashed stream is supplied to a secondary recovery separator to produce a second recovered solvent stream as part of the second portion of the recovered solvent. In some implementations, the water removal stage is performed using a treater.

[0023] In some implementations, the process includes subjecting the second stage underflow stream to a tertiary flashing stage to produce a third stage flashed stream and a third stage underflow stream. In some implementations, the third stage flashed stream is supplied to a third stage recovery separator to produce a third stage gas stream and a third stage liquid stream. In some implementations, the third stage gas stream is supplied to secondary recovery separator. In some implementations, the third stage liquid stream is recycled back into the primary flashing stage. In some implementations, the third stage underflow stream is supplied to the desalting stage to produce a portion of the oil product.
In some implementations, the third stage underflow stream is the oil product and is supplied to a storage vessel.

[0024] In some implementations, the process includes compressing and cooling the third stage gas stream prior to the secondary recovery separator.

[0025] In some implementations, the first stage flashed stream is subjected to mechanical vapour recompression to produce a compressed stream. In some implementations, the compressed stream is used to indirectly preheat the degassed production fluid prior to the primary flashing stage.
Date recue / Date received 2021-11-09

[0026] In some implementations, the oil product is used to indirectly preheat the production fluid prior to the degassing.

[0027] In some implementations, casing gas is recovered from the reservoir separately from the production fluid, and the gas mixture is combined with the casing gas prior to processing thereof.

[0028] In some implementations, separating the gas mixture comprises:
supplying the gas mixture to a gas separator to produce a solvent enriched stream and a solvent depleted gas stream; and supplying the solvent enriched stream to a distillation tower to produce a top vapour stream and a bottom solvent stream as the first portion of the recovered solvent.

[0029] In some implementations, the process includes chilling the solvent depleted gas stream to produce a chilled stream; supplying the chilled gas stream to a low temperature separator to produce a gas stream and a second solvent enriched stream; and supplying the second solvent enriched stream to the distillation tower.

[0030] In some implementations, the process includes subjecting the top vapour stream to separation to produce a vapour recycle stream and a liquid stream; and recycling the vapour recycle into the low temperature separator. In some implementations, subjecting the top vapour stream to separation further produces a reflux stream that is fed back into the distillation tower. In some implementations, the process includes combining the gas stream with a natural gas stream to produce a fuel gas.

[0031] In some implementations, the production fluid is processed in a second process train that does not include a distillation stage. In some implementations, the second process train is configured to supply only light end gases to the first process train for processing.

[0032] In some implementations, the first process train is configured to supply only overhead condensate from distillation to the second process train for processing.

[0033] In some implementations, the solvent is a paraffinic solvent having a carbon number from 4 to 6. In some implementations, the solvent is butane.
Date recue / Date received 2021-11-09 In some implementations, the solvent is injected via an injector well that is vertically spaced from an underlying producer well configured for recovering the production fluid, and the injector and producer wells are operated as a gravity drainage well pair. In some implementations, the solvent is injected as a substantially pure solvent injection fluid to enable a solvent-only in situ recovery operation. In some implementations, the solvent is provided as a main component of injection fluid to provide a solvent-dominated in situ recovery operation.

[0034] In some implementations, separation units for processing the degassed production fluid are operated without a methane blanket.

[0035] In some implementations, the heavy hydrocarbons comprise bitumen. In some implementations, the reservoir is an oil sands reservoir.

[0036] In some implementations, the first portion of the recovered solvent and the second portion of the recovered solvent are reinjected into the reservoir. In some implementations, the first portion of the recovered solvent is reinjected into the reservoir.
In some implementations, the second portion of the recovered solvent is reinjected into the reservoir.

[0037] In some implementations, the casing gas recovered from the reservoir is subjected to compression prior to combining with the gas mixture. In some implementations, the casing gas recovered from the reservoir is subjected to a pre-separation treatment to remove liquid prior to combining with the gas mixture.
In some implementations, the removed liquid is combined with the production fluid.

[0038] In some implementations, the degassing is performed such that the degassed production fluid contains at most 0.05 mol% of non-condensable gas. In some implementations, the degassing is performed such that the degassed production fluid contains at most 0.04 mol% of non-condensable gas. In some implementations, the degassing is performed such that the degassed production fluid contains at most 0.03 mol% of non-condensable gas. In some implementations, the production fluid supplied to the degassing contains at least 0.5 mol% of non-condensable gas. In some implementations, the production fluid supplied to the degassing contains at least 0.3 mol%
Date recue / Date received 2021-11-09 of non-condensable gas. In some implementations, the production fluid supplied to the degassing contains at least 0.2 mol% of non-condensable gas.

[0039] In some implementations, there is provided a process for recovery of heavy hydrocarbons from a reservoir, comprising: injecting solvent into the reservoir to mobilize the heavy hydrocarbons; recovering production fluid from the reservoir;
processing the production fluid to produce recovered solvent and an oil product. The processing comprises: subjecting the production fluid to degassing to remove non-condensable gas therefrom and produce: a gas mixture comprising non-condensable gas and solvent; and a degassed production fluid comprising oil, water and solvent; separating the gas mixture to produce a first portion of the recovered solvent; and subjecting the degassed production fluid to separation to produce a second portion of the recovered solvent, produced water and the oil product. The process also includes reusing at least a portion of the first portion of the recovered solvent, the second portion of the recovered solvent, or a combination thereof.

[0040] In some implementations, there is provided a system for recovery of heavy hydrocarbons from a reservoir, comprising: an injection well configured for solvent into the reservoir to mobilize the heavy hydrocarbons; a production well configured for recovering production fluid from the reservoir; a surface facility for processing the production fluid to produce recovered solvent and an oil product, wherein the surface facility comprises: a degasser configured for subjecting the production fluid to degassing to remove non-condensable gas therefrom and produce: a gas mixture comprising non-condensable gas and solvent; and a degassed production fluid comprising oil, water and solvent; a gas separation assembly configured for separating the gas mixture to produce a first portion of the recovered solvent; a production fluid separation assembly configured for subjecting the degassed production fluid to separation to produce a second portion of the recovered solvent, produced water and the oil product; and an injection assembly configured to reinject into the reservoir at least a portion of the first portion of the recovered solvent, the second portion of the recovered solvent, or a combination thereof.

[0041] In some implementations, there is provided a process for recovery of heavy hydrocarbons from a reservoir, comprising: injecting solvent into the reservoir to mobilize the heavy hydrocarbons; recovering production fluid from the reservoir;
processing the production fluid to produce recovered solvent and an oil product, wherein the processing Date recue / Date received 2021-11-09 comprises: subjecting the production fluid to a primary flashing stage to produce a first flashed stream and a first underflow stream; subjecting the first flashed stream to mechanical vapour recompression to produce a compressed stream; indirectly heating at least one process stream with the compressed stream to produce a heated process stream and a first stage cooled stream; separating the first stage cooled stream to produce a first stage recovered solvent; and processing the first underflow stream to recover additional recovered solvent and the oil product. The process also includes reinjecting into the reservoir at least a portion of the first stage recovered solvent, the additional recovered solvent, or a combination thereof.

[0042] In some implementations, the mechanical vapour recompression comprises a single stage compressor. In some implementations, the mechanical vapour recompression comprises a multistage compressor.

[0043] In some implementations, the compressed stream is used to indirectly heat the production fluid that is fed into the primary flashing stage.

[0044] In some implementations, the compressed stream is condensed during the indirect heating such that the first stage cooled stream is liquid.

[0045] In some implementations, the first stage cooled stream comprises water and solvent, and the separating of the first stage cooled stream further produces an aqueous stream. In some implementations, the aqueous stream is used as a washing liquid to remove salts a hydrocarbon material to produce the oil product.

[0046] In some implementations, subjecting the production fluid to degassing prior to the primary flashing stage.

[0047] In some implementations, casing gas is recovered from the production well and processed separately in a first process train to produce first train recovered solvent and solvent-depleted gas, and the processing of the production fluid is performed in a second process train.

[0048] In some implementations, processing the casing gas comprises: supplying the casing gas to a gas separator to produce a solvent enriched stream and a solvent depleted gas stream; supplying the solvent enriched stream to a distillation tower to produce a top Date recue / Date received 2021-11-09 vapour stream and a bottom solvent stream as the first train recovered solvent; chilling the solvent depleted gas stream to produce a chilled stream; supplying the chilled gas stream to a low temperature separator to produce a gas stream and a second solvent enriched stream; and supplying the second solvent enriched stream to the distillation tower.

[0049] In some implementations, the process includes removing light gases from the production fluid in the second process train; and supplying the light gases to the first process train for processing thereof.

[0050] In some implementations, the light gases are combined with the casing gas prior to subjecting the casing gas to separation.

[0051] In some implementations, the processing of the first underflow stream comprises:
supplying the first underflow stream to a water removal stage to produce a water enriched stream and a water depleted stream; and supplying the water depleted stream to a secondary flashing stage to produce a secondary stage flashed stream and a second stage underflow stream. In some implementations, the secondary stage flashed stream is supplied to a secondary separator to produce a secondary recovered solvent stream as part of the second train recovered solvent. In some implementations, the process also includes subjecting the second stage underflow stream to a tertiary flashing stage to produce a third stage flashed stream and a third stage underflow stream. In some implementations, the third stage flashed stream is supplied to a third stage separator to produce a third stage gas stream and a third stage liquid stream. In some implementations, the third stage gas stream is supplied to the secondary separator. In some implementations, the third stage liquid stream is recycled back into the primary flashing stage. In some implementations, the third stage underflow stream is subjected to the desalting stage to produce the oil product.

[0052] In some implementations, the processing of the production fluid does not include a distillation stage.

[0053] In some implementations, the solvent is a paraffinic solvent having a carbon number from 4 to 6. In some implementations, the solvent is butane.

[0054] In some implementations, the solvent is injected via an injector well that is vertically spaced from an underlying producer well configured for recovering the Date recue / Date received 2021-11-09 production fluid, and the injector and producer wells are operated as a gravity drainage well pair. In some implementations, the solvent is injected as a substantially pure solvent injection fluid to provide a solvent-only in situ recovery operation. In some implementations, the solvent is provided as a main component of injection fluid to provide a solvent-dominated in situ recovery operation.

[0055] In some implementations, separation units for processing the production fluid are operated without a methane blanket.

[0056] In some implementations, the heavy hydrocarbons comprise bitumen. In some implementations, the reservoir is an oil sands reservoir.

[0057] In some implementations, the first stage recovered solvent and the additional recovered solvent are reinjected into the reservoir.

[0058] In some implementations, there is provided a process for recovery of heavy hydrocarbons from a reservoir, comprising: injecting solvent into the reservoir to mobilize the heavy hydrocarbons; recovering production fluid from the reservoir;
processing the production fluid to produce recovered solvent and an oil product, wherein the processing comprises: subjecting the production fluid to flashing stages to produce flashed streams and underflow streams; subjecting at least one of the flashed streams to mechanical vapour recompression to produce a compressed stream; indirectly heating at least one process stream with the compressed stream to produce a heated process stream and a cooled stream; and separating the recovered solvent and the oil product from the flashed streams and the underflow streams. The process also includes reinjecting the recovered solvent into the reservoir.

[0059] In some implementations, the compressed stream is used to indirectly heat a feed stream that is supplied into the flashing stage that produces the flashed stream from which the compressed stream is derived.

[0060] In some implementations, the flashing stages comprise a primary flashing stage, a secondary flashing stage and a tertiary flashing stage. In some implementations, the flashed stream from the primary flashing stage is subjected to the mechanical vapour recompression. In some implementations, the mechanical vapour recompression comprises a single stage compressor. In some implementations, only one of the flashed Date recue / Date received 2021-11-09 streams is subjected to the mechanical vapour recompression. In some implementations, the flashed stream subjected to the mechanical vapour recompression is composed of flashed solvent and water vapour. In some implementations, the cooled stream is completely condensed and is supplied to a separator to produce a first recovered solvent.
In some implementations, the first recovered solvent is reinjected into the reservoir.

[0061] In some implementations, there is provided a system for recovery of heavy hydrocarbons from a reservoir, comprising: an injection well configured for solvent into the reservoir to mobilize the heavy hydrocarbons; a production well configured for recovering production fluid from the reservoir; a surface facility for processing the production fluid to produce recovered solvent and an oil product, wherein the surface facility comprises: a flash vessel that is configured to produce a flashed stream and an underflow stream; a mechanical vapour recompression unit configured to receive the flashed stream and to produce a compressed stream; a heat exchanger configured to indirectly heat at least one process stream with the compressed stream to produce a heated process stream and a cooled stream; and an injection assembly configured to reinject into the reservoir at least a portion of the first portion of the recovered solvent, the second portion of the recovered solvent, or a combination thereof.

[0062] In some implementations, there is provided a process for recovery of heavy hydrocarbons from a reservoir, comprising: injecting solvent into the reservoir to mobilize the heavy hydrocarbons; recovering production fluid from the reservoir;
subjecting the production fluid to a flashing stage to produce a solvent reduced production fluid and a flashed stream that comprises flashed solvent and water vapour; processing the solvent reduced production fluid to produce recovered oil; condensing the flashed stream to produce condensed stream; separating the condensed stream to produce a solvent stream and condensed water; and using at least a portion of the condensed water as a washing liquid for the recovered oil to remove salts therefrom and produce a desalted oil product.

[0063] In some implementations, the production fluid is subjected to degassing to produce a degassed production fluid that is supplied to the flashing stage, and the processing of the solvent reduced production fluid comprises water removal followed by one or more additional flashing stages.
Date recue / Date received 2021-11-09

[0064] In some implementations, the flashed stream is subjected to mechanical vapour recompression to produce a compressed stream; the compressed stream is supplied to a heat exchanger to heat the production fluid prior to the flashing stage and to form a condensed stream; and the condensed stream is supplied to a separator to produce a recovered solvent stream and the condensed water.

[0065] In some implementations, the flashing stage is a primary flashing stage that produces the flashed stream and a first stage underflow stream, and wherein the first stage underflow stream is supplied to a water removal stage to produce a water enriched stream and a water depleted stream; and the water depleted stream is supplied to a secondary flashing stage to produce a secondary stage flashed stream and a second stage underflow stream. In some implementations, the secondary stage flashed stream is supplied to a secondary separator to produce a secondary recovered solvent stream. In some implementations, the process includes subjecting the second stage underflow stream to a tertiary flashing stage to produce a third stage flashed stream and a third stage underflow stream. In some implementations, the third stage flashed stream is supplied to a third stage separator to produce a third stage gas stream and a third stage liquid stream. In some implementations, the third stage gas stream is supplied to the secondary separator.
In some implementations, the third stage liquid stream is recycled back into the primary flashing stage. In some implementations, the third stage underflow stream is the recovered oil that is contacted with the condensed water for desalting to produce the oil product. In some implementations, the reservoir has a chloride content of at least 5,000 ppm. In some implementations, the desalted oil product is supplied to an upgrader for processing. In some implementations, the desalted oil product is diluted with diluent for sale as diluted bitumen.

[0066] In some implementations, the solvent is injected via an injector well that is vertically spaced from an underlying producer well configured for recovering the production fluid, and the injector and producer wells are operated as a gravity drainage well pair. In some implementations, the solvent is injected as a substantially pure solvent injection fluid to enable a solvent-only in situ recovery operation. In some implementations, the solvent is provided as a main component of injection fluid to provide a solvent-dominated in situ recovery operation. In some implementations, the heavy hydrocarbons comprise bitumen. In some implementations, the reservoir is an oil sands reservoir.
Date recue / Date received 2021-11-09

[0067] In some implementations, the solvent is a paraffinic solvent having a carbon number from 4 to 6. In some implementations, the solvent is butane.

[0068] In some implementations, there is provided a process for recovery of heavy hydrocarbons from a reservoir, comprising: injecting solvent into the reservoir to mobilize the heavy hydrocarbons; recovering production fluid from the reservoir;
subjecting the production fluid to separation to produce an oil product and recovered solvent, wherein the processing comprises a flashing stage that produces an underflow stream and a flashed stream that comprises flashed solvent and water vapour; condensing the water vapour to produce condensed water; and reusing the condensed water.

[0069] In some implementations, the condensed water is used for desalting oil.
In some implementations, the condensed water is used for desalting the oil product.

[0070] In some implementations, the process includes compressing the flashed stream to produce a compressed stream; indirectly heating a process stream using the compressed stream to produce a heated process stream and cooled condensed stream that includes the condensed water and condensed solvent; and separating the condensed water from the condensed solvent.

[0071] In some implementations, there is provided a system for recovery of heavy hydrocarbons from a reservoir, comprising: an injection well configured for solvent into the reservoir to mobilize the heavy hydrocarbons; a production well configured for recovering production fluid from the reservoir; a surface facility for processing the production fluid to produce recovered solvent and an oil product, wherein the surface facility comprises: a flash vessel that is configured to produce a flashed stream and an underflow stream, the flashed stream comprising water vapour and solvent; a condenser configured to receive the flashed stream and to produce a condensed stream comprising condensed water and recovered solvent; a separator configured to receive the condensed stream and to separate the condensed water from the recovered solvent; a desalter configured to receive at least a portion of the condensed water and recovered oil and to produce an oil product.

[0072] In some implementations, there is provided a process for recovery of heavy hydrocarbons from a reservoir, comprising: injecting solvent into the reservoir to mobilize the heavy hydrocarbons; recovering production fluid from the reservoir;
subjecting the Date recue / Date received 2021-11-09 production fluid to separation to produce an oil product and recovered solvent, wherein the separation is performed via a plurality of separation vessels comprising at least one gas blanketed vessel that receives a solvent containing fluid and is blanketed with an inert gas; and reinjecting at least a portion of the recovered solvent into the reservoir.

[0073] In some implementations, the inert gas comprises nitrogen. In some implementations, the at least one gas blanketed vessel comprises a solvent storage tank.
In some implementations, the at least one gas blanketed vessel comprises a solvent-water separation vessel that produces a solvent stream and an aqueous stream. In some implementations, the solvent is injected via an injector well that is vertically spaced from an underlying producer well configured for recovering the production fluid, and the injector and producer wells are operated as a gravity drainage well pair. In some implementations, the solvent is injected as a substantially pure solvent injection fluid to enable a solvent-only in situ recovery operation. In some implementations, the solvent is provided as a main component of injection fluid to provide a solvent-dominated in situ recovery operation. In some implementations, the heavy hydrocarbons comprise bitumen. In some implementations, the reservoir is an oil sands reservoir. In some implementations, the solvent is a paraffinic solvent having a carbon number from 4 to 6. In some implementations, the solvent is butane.

[0074] In some implementations, there is provided a method for recovering paraffinic solvent from heavy hydrocarbons for reuse as an injection fluid into a hydrocarbon-containing reservoir, the method comprising separating the paraffinic solvent from heavy hydrocarbons in a surface facility comprising separation and storage vessels, wherein at least one of the separation and storage vessels are blanketed with a blanket gas and all of the blanketed separation and storage vessels use an inert gas as the blanket gas.

[0075] It is also noted that various aspects described above and herein can be combined together in a process or system to treat fluids.
BRIEF DESCRIPTION OF THE DRAWINGS

[0076] Fig 1 is a process flow diagram of a surface facility that processes casing gas and production fluid.
Date recue / Date received 2021-11-09

[0077] Fig 2 is a process flow diagram of a primary flashing stage with an associated mechanical vapour recompression (MVR) unit and preheating units.

[0078] Fig 3 is a process flow diagram of a degasser with associated preheaters.

[0079] Fig 4 is a process flow diagram including units used to separate and handle produced water as well as a solvent recovery unit.

[0080] Fig 5 is a process flow diagram showing the use of condensed water obtained from a flashing stage as a washing liquid in a desalter.

[0081] Fig 6 is a process flow diagram showing casing gas obtained from a production well and subjected to initial treatment.

[0082] Fig 7 is a process flow diagram showing solvent injection.

[0083] Fig 8 is a process flow diagram showing a blanketed vessel that receives solvent containing fluid.
DETAILED DESCRIPTION

[0084] The present description relates to technologies for solvent based in situ recovery of heavy hydrocarbons, such as bitumen, and particularly to processes for handling and separating fluids at surface. The processes can include handling casing gas separately from the liquids in the production fluid to reduce contamination of the solvent with non-condensable gases (NCGs), notably methane. The processes can also include initial degassing of the production fluid to remove light gases and some of the solvent, followed by flashing stages to recover the remainder of the solvent and produce the oil product.
The gas rich streams including casing gas and those obtained from the degasser can be combined and processed together in a distillation tower to produce fuel gas and recovered solvent, while the degassed produced fluid including oil, solvent and water can be processed in flash stages rather than distillation. In addition, mechanical vapour recompression (MVR) can be implemented on the flashed stream from the primary flashing stage for enhanced heat utilization. The processes can include other enhancements to facilitate efficient operations and cost-effective design of surface facilities. The processes can facilitate various functions, including improved heat usage Date recue / Date received 2021-11-09 and efficiency as well as reducing NCG contamination of the solvent which is reinjected downhole. Various aspects and implementations of the processes will be described in more detail further below.

[0085] In some implementations, instead of mixing the casing gas back into the production fluid before passing through various separators, the casing gas is processed separately from the liquids¨including oil, water and the bulk of the solvent¨to inhibit contamination of the solvent with the light gas which is mainly composed of NCGs, such as methane. Inhibiting contamination can be particularly relevant for solvent based in situ recovery operations that are solvent-dominated or solvent-only processes and use paraffinic solvents such as butane, pentane or hexane. Gas streams that are removed from the production fluid can be combined with the casing gas and then the overall gas stream is processed to recover solvent for reuse and to produce fuel gas. In particular, the gas stream recovered from a degassing stage is combined with the casing gas.
If there are multiple degassers, then the respective gas streams could all be sent to be combined with the casing gas. In addition, for downstream vessels having overhead released gas streams, those gas streams could also be combined with the casing gas for processing.
Such overhead released gas include NCGs along with some solvent that have been released from the heavy hydrocarbon phase during the processing. The casing gas includes a notable amount of NCGs (e.g., 40-60 mol%) and a notable amount of solvent (e.g., 40-60 mol%) and thus keeping the casing gas separate from the production fluid while ensuring solvent recovery can facilitate efficient operations. Various process configurations and equipment can be used for the gas processing, and the oil-water-solvent production fluid can be separated in parallel and can leverage flashing stages for the solvent recovery. The production fluid, which can also be referred to as the emulsion, has a lower concentration of NCGs compared to the casing gas and thus keeping the casing gas separate reduces overall solvent contamination. As will be described below, the casing gas and other light gas streams can be treated in a first process train which can include a distillation stage, while the remainder of the production fluid is processed in a second process train.

[0086] In some implementations, the production fluid is subjected to degassing to remove substantially all NCGs and some solvent prior to any further separation steps used to separate the water, oil and solvent. After degassing, the degassed production fluid is Date recue / Date received 2021-11-09 subjected to relatively simple flashing stages instead of distillation. Thus, the entire production fluid including the water, oil and solvent can be heated and subjected to degassing to flash out some solvent and substantially all of the NCGs. While there may be a relatively small quantity of methane in the production fluid (e.g., around 0.5 mol% or 0.2 mol% or less), even small amounts of NCGs could lead to relevant issues if present in the solvent that is reinjected into the reservoir. Thus, the methane is removed so that below 0.05, below 0.04 or below 0.03 mol% remains in the degassed production fluid. The target purity of the solvent for reinjection can be 99.9% C4+ and thus removal of NCGs is performed to facilitate achieving this target. In the degassing stage, the methane is almost completely removed (e.g., leaving only 0.03 mol% in the fluid) and minor amounts of C2-C3 hydrocarbons will also report with the gas stream. The degassing stage is operated to ensure substantial removal of NCGs and therefore the gas stream also includes a notable amount of flashed solvent and some flashed water. For example, the gas stream can include 80-95% water and 5-20% NCG. The degasser is thus operated so that solvent flashes and entrains NCGs to promote substantial removal of the NCGs in this stage of the separation process. The degassed production fluid in liquid phase is then heated and fed to a primary flashing stage to recover the majority of solvent.

[0087] Since substantially all of the NCG, which is predominantly methane, is captured either in the degasser or as casing gas in the produced gas pipeline, only these two streams can be sent to a solvent purification unit while the rest of the solvent can be kept separate from the NCGs and can be separated from the oil by flashing. Thus, the solvent purification unit can be sized and operated for lower flow rates and does not have to handle notable flows of oil or water. This helps reduce the heat and equipment required for vaporization and condensation to achieve separation of the various fluids produced from the reservoir. It is also noted that other minor overhead gas streams containing NCG and solvent can be withdrawn from separation vessels downstream from the primary flashing stage and sent to the first process train.

[0088] Referring to Fig 1, the in situ recovery operation includes a surface facility 10 for processing fluids produced to the surface. The surface facility 10 receives production fluid 12 as well as casing gas 14 from a producer well 16, and enables separation of the produced fluids to provide an oil product 18 as well as recovered solvent 20 for reinjection via the injector well 22. The injector well 22 and the producer well 16 can be arranged in Date recue / Date received 2021-11-09 vertically spaced relation to each other to form a well pair and can be operated for gravity dominated recovery of the heavy hydrocarbons. The in situ recovery operation can be a solvent-dominated process where solvent is co-injected with other fluids, or solvent-only process where the injection fluid is substantially only solvent. The in situ recovery operation can be provided to recover heavy hydrocarbons, such as bitumen, from the reservoir which can be an oil sands reservoir. It is nevertheless noted that various other well patterns and orientations could also be used in conjunction with the surface facilities and processes described herein.

[0089] As shown in Fig 1, the surface facility 10 can include two process trains for processing the casing gas 14 and the production fluid 12 in a substantially separate manner. A first process train 24 receives and processes the casing gas 14 as well as other gas streams separated from the various units of a second process train 26 which processes the bulk of the production fluid 12. The casing gas and degasser gas stream are mainly composed of light hydrocarbons including methane and solvent, and almost all of the NCGs in the system are in these streams. The solvent can be a paraffinic hydrocarbon, such as butane, pentane or hexane, for example, but may include other hydrocarbon compounds depending on the process design. Solvents that can be efficiently liquified to facilitate separation from NCGs and flashed to facilitate recovery from the oil can be effectively used in certain implementations of the processes described herein.

[0090] The first process train 24 receives the casing gas 14 which can be obtained from the producer well and can be compressed before being supplied to the first process train 24. The first process train 24 can include a gas separator 28 that receives the casing gas 14 and produces a top gas 30 including mainly NCGs and a liquid bottom stream containing most of the solvent. The feed to the gas separator 28 is thus cooled sufficiently to liquify a notable portion of the solvent while keeping the lighter hydrocarbons in gas phase. The top gas 30, which can still contain some solvent, can be supplied to a chiller 34 to liquify the remaining solvent and the resulting chilled stream 36 can be supplied to a low temperature separator 38. The low temperature separator 38 facilitates removal of the liquid solvent from the NCGs. The low temperature separator 38 produces a light gas stream 40 and a liquid stream 42 that is fed along with the liquid bottoms 32 to a solvent recovery unit 44, which may be a distillation tower with a reflux system and reboiler. In Date recue / Date received 2021-11-09 some implementations, the solvent recovery unit 42 can be referred to as a solvent purification unit, particularly when pure solvent is relevant for the solvent based in situ recovery operation.

[0091] It is noted that the first process train 24 can be configured in various ways to remove NCGs and obtain purified solvent. One configuration that is shown in Fig 1 uses multiple stages to separate the NCGs from the solvent. In the illustrated configuration, the first stage is operated at conditions to achieve a bulk separation of liquid solvent and NCGs using moderate cooling (e.g., around 40 C for butane as solvent), the second stage is operated at lower temperatures (e.g., 15 C or lower) to liquify and recover the remaining solvent, and the third stage is a distillation tower configured to obtain pure solvent. This configuration facilitates an efficient first stage to remove the bulk of the solvent, thus avoiding the energy use of chilling the entire feed stream to the lower temperature to remove substantially all of the solvent. In addition, the first two stages facilitate removal of a notable quantity of NCGs using relatively simple vapour-liquid separation vessels, which in turn reduces the sizing requirements for the distillation tower. Since adding extra trays or stages to a distillation tower is expensive, the initial separation stages in the first process train reduce the amount of NCGs in the tower feed and thus enable a smaller tower design.

[0092] It is nevertheless noted that the first process train could be designed in other ways. For example, the first process train could include only one vapour-liquid separation stage before the distillation tower, and this vapour-liquid separation stage could be operated at low or at moderate temperature conditions. By chilling to achieve low temperature conditions, a greater amount of solvent could be recovered but the refrigeration energy would be higher. By only cooling to moderate temperature conditions, less solvent could be recovered but the energy demands would be lower. The cooling can be performed using aerial coolers, while the chilling can be performed by a refrigeration unit. It is also possible to separate NCGs from solvent in advance of the distillation tower by increasing the pressure instead of or in addition to cooling and/or chilling. In addition, the first process train could be operated with more than two vapour-liquid separation stages before the distillation tower, where the gas stream of each stage could be cooled to liquify some or all of the solvent prior to the subsequent stage. Multiple vapour-liquid separation stages can decrease the NCG content in the feed of the distillation tower and therefore reduce the tower size. It is also possible to supply the casing gas feed stream Date recue / Date received 2021-11-09 directly to a distillation tower, although the tower would have to be sized accordingly.
Alternatively, the first process train could be designed without a distillation tower and thus rely on vapour-liquid separation vessels arranged in series to progressively purify the solvent and separate NCGs.

[0093] Referring to Fig 1, when pure paraffinic solvent (e.g., butane) is to be injected into the reservoir, the solvent purification unit 44 can be operated to produce pure butane that is 99.9% C4+ and thus can include small amounts of C5 and C6 but very little to no methane. The solvent purification unit 44 produces a recovered solvent bottoms 46 (SA) and an overhead gas 48. The overhead gas 46 can be fed to a reflux system where a portion of condensate is fed back to the tower and another portion of the condensed liquid is supplied to the second process train 26. A gas stream from the reflux system can be recycled back into the feed of the chiller 30. The light gas stream 40 from the low temperature separator 38 can be used as fuel gas, and if required can be subjected to scrubbing to remove any sulfur compounds before being used as fuel gas. The light gas stream 40 can also be combined with a natural gas source, if desired, and the combined gas stream can be optionally scrubbed and used as fuel. In some implementations, the light gas stream 40 produced by the first process train 24 is not scrubbed but is combined with a scrubbed or sweet natural gas source and then the resulting fuel gas is burned as fuel. The scrubbing of the gas may be avoided when the in situ process is operated at lower temperatures (e.g., 40 C to 70 C), which can be facilitated by the use of solvent instead of steam-dominated processes, such that H2S levels are notably reduced in produced fluids.

[0094] The energy generated by combustion of the fuel can be used to generate steam that is used in utilities, including for heating in indirect heat exchanges that are part of the surface facility. Heat exchangers can be provided to heat feed streams prior to vapour-liquid separation vessels. The steam can be used for heating at the surface facility as well as at the well pads for heating the solvent to form heated liquid solvent, vapour phase solvent, or superheated solvent for injection. The steam could also be used for closed- or open-loop circulation heating during startup of certain wells. It is noted that the solvent could be heated to an introduction temperature, such as above 150 C, above 175 C above 200 C, above 225 C or above 250 C, although the solvent chamber formed in the reservoir may be operated at a lower temperature of 40 C to 70 C, for example.
The Date recue / Date received 2021-11-09 production fluid can be at similar temperature as the solvent chamber. It is also possible that the steam could be used for injection into other steam-assisted in situ recovery processes, or used for various other purposes, and the fuel gas could also be supplied by pipeline for use at other facilities.

[0095] The first train recovered solvent 46 (SA) is thus one of the solvent streams recovered and recycled for reinjection into the injector well 22. The first train recovered solvent 46 can be fed along with other solvent streams into a solvent tank and then supplemented with make-up solvent prior to heating and injection. The solvent can be heated at surface, which may include converting the solvent to vapour phase prior to injection, or the solvent can be injected as a liquid or mixed-phase stream and can be vaporized downhole by downhole electric heaters or hot fluid circulation systems located in the injector well, for example. The first train recovered solvent 46 (SA) can have a purity of at least 99.9% or a purity such that when it is combined with the make-up solvent and the other recovered solvent streams, the overall solvent purity is at least 99.9%. When butane is used at the solvent, the solvent purity can be least 99.9% C4+.

[0096] The operating conditions of the equipment in the first process train 24 can be provided depending on the overall process design. For example, the gas separator 28 can be operated at about 35-45 C and about 550-650 kPa, and the chiller 34 and the low temperature separator 38 can be operated at about 10-15 C and about 400-500 kPa. The operating pressures can be provided so as to inhibit methane re-entering the solvent phase while facilitating vapour-liquid separation of the methane from the solvent. Of course, for alternative configurations of the first process train, the operating conditions of the unit operations and the equipment design can be adapted accordingly.

[0097] Thus, the production fluid 12 and the casing gas 14 are processed separately, where the casing gas 14 is subjected to separation to obtain the first train recovered solvent 46 and solvent-depleted gas 40. It is noted that light gas hydrocarbons can be separated from the production fluid in the second process train 26 and fed into the gas feed supplied to the first process train, thus combining those gas streams with the casing gas 14. The main gas stream from the second process train that is combined with the casing gas is the degasser overhead stream 54, which contains a significant portion of the NCGs present in the production fluid 12 and also contains a notable portion of solvent that should be recovered. The degasser overhead stream 54 thus has a composition that is Date recue / Date received 2021-11-09 suitable for separation in the first process train 24, with notable solvent and NCG contents but heavier hydrocarbons are largely absent from this gas stream. Other overhead gas streams can be withdrawn from separation vessels in the second process train and can be fed to the first process train to separation solvent from the NCG. The first process train 24 can therefore be designed and operated for handling a narrower range of light hydrocarbon components, mainly solvent and NCGs.

[0098] Furthermore, Fig 1 shows one optional implementation of the first process train 24 for processing the gas, based on temperature reduction to enable liquification of the solvent to facilitate vapour-liquid separation. An alternative configuration for the first process train includes a compression stage that receives the feed gas, followed by an aerial cooler to reduce the temperature and condense the solvent. The solvent can then be removed in a vapour-liquid separation stage. In one example, the compressor could be located to receive the gas stream 30 to replace the chiller and thus enable the second separation stage to be operated at higher temperatures. In another example, a compression unit such as a multiphase pump could be located to receive the feed to the first process train that includes the casing gas 14 and the degasser overhead 54, as a multiphase stream, such that the compressed stream would be supplied to a first stage vapour-liquid separator 28. Thus, while a temperature reduction strategy is illustrated in Fig 1 for liquifying the solvent for the two initial separation stages, compression strategies are an alternative implementation that could be used instead of or in addition to temperature reduction.

[0099] Still referring to Fig 1, the second process train 26 is configured to treat the production fluid 12 which contains heavy hydrocarbons, water, solvent, gas, and possibly some mineral solids. The production fluid 12 is first fed to a degasser 50 to produce a degassed production fluid 52 and an overhead gas stream 54, which can be combined with the casing gas 14 for treatment in the first process train 24. The degassed production fluid 52 can then be supplied to a primary flashing stage 56 which produces a first stage flashed stream 58 and a first stage underflow stream 60. The primary flashing stage 56 can be operated to remove a substantial portion of the solvent. The first stage flashed stream 58 can then be supplied to a primary recovery separator 62 which produces a first recovered solvent stream 66 (SB), and a water stream 68. The primary recovery separator 62 may also produce a small gas stream 64 composed of NCG and solvent. The water Date recue / Date received 2021-11-09 stream 68 can be supplied to a desalter 70 which produces the oil product 18 and a saline aqueous stream 72.

[00100] Depending on operating conditions, the primary recovery separator 62 may be provided with a gas blanket and can thus release blanket gas that is managed by a vapour recovery unit (VRU). If the feed stream to the primary recovery separator 62 is not fully condensed, then vapours from the feed would be present in the primary recovery separator 62 and a gas blanket would not be required. If a gas blanket is used, the gas could be nitrogen to avoid the use of fuel gas or methane that could re-contaminate the solvent. A nitrogen blanket gas could have a portion withdrawn and discharged to atmosphere or recovered separately by the VRU.

[00101] It is also noted that the desalter 70 is optional and can be implemented depending on the saltiness of the reservoir and/or the downstream requirements of the oil product (e.g., feeding the oil product to an upgrader or to market as dilbit). For reservoirs having low salt content, there may be no desalter in the surface facility. For salty reservoirs, a desalter may be relevant to meet oil product specifications, although even in lower-salt reservoirs a desalter may be required to meet certain downstream specifications. The washing liquid that is used in the desalter may be obtained from various sources, one of which is desalted water from the surface facility itself, as will be described further below.

[00102] As shown in Fig 1, the water stream 68 is derived from the water that flashed in the primary flashing stage 56 and was then condensed and separated in the primary recovery separator 62. Due to flashing, the salt in this water has been removed and the water is therefore suitable for use as a washing liquid. For example, the water stream 68 can be used as a washing liquid in the desalter 70, as shown in Fig 1. It is also possible to use this salt depleted water in other applications at the surface facility.
For salty reservoirs and low-salt product specifications, using at least a portion of salt depleted water that comes from a flashing stage as washing liquid can provide efficient use of water in the overall system and reduce fresh water requirements.

[00103] In some implementations, the primary flashing stage 56 can be operated to remove a substantial portion of the solvent, such as about 90% of the solvent that is in the degassed production fluid and thus leaving 10% for recovery in downstream separators.
It is noted that about 75-80% of the solvent from the reservoir is present in the production Date recue / Date received 2021-11-09 fluid, with about 20-25% being in the casing gas. Once the degasser overhead stream, which contains solvent, has been added to the casing gas, the overall gas feed to the first process train represents about 25% of the solvent in the system. Thus, the system can be designed such that about 25% of the solvent is processed in the first train with the remaining 75% being processed in the second train. It is noted that overhead gas streams containing NCG and solvent from other separation vessels can have very low flow rates compared to the other streams mentioned above.

[00104] Referring back to Fig 1, the first stage underflow stream 60 is supplied to a water removal stage 74 that produces a water enriched stream 76 and a water depleted stream 78 that is mainly solvent and oil. While a fair amount of water flashes out in the primary flashing stage 56, the remaining water is removed in the water removal stage 74.
Removing water prior to downstream flashing stages avoids having to reheat the water component for those flashing stages and thus enables energy efficiencies. The water removal unit 74 can be flooded. Alternatively, the water removal unit can be operated with overhead gas either composed of blanket gas or gas from feed, and an overhead gas stream 80 can be withdrawn. Is the overhead gas 80 is from the feed and is composed of NCG and solvent, then it can be combined with the casing gas 14. The water removal unit 74 can be a treater, for example, or another type of water-hydrocarbon separator. The treater can be configured to remove mineral solids that may be present.

[00105] The water depleted stream 78 can then be supplied to a secondary flashing stage 82 that produces a secondary stage flashed stream 84 and a second stage underflow stream 86. The secondary stage flashed stream 84 can be supplied to a secondary recovery separator 88 that produces a gas stream 90 and a second recovered solvent stream 92 (Sc). The second stage underflow stream 86 can be supplied to a tertiary flashing stage 94 to produce a third stage flashed stream 96 and a third stage underflow stream 98. The third stage flashed stream 96 can be separated in a third stage separator 100 to produce a third stage gas stream 102 that can be combined with the secondary stage flashed stream 84, and a third stage liquid stream 104 that can be recycled back into the primary flashing stage 56 or elsewhere. The third stage underflow stream 98 can be fed to the desalter 70 to produce the oil product 18.

[00106] As shown in Fig 1, the casing gas 14 can be combined with the gas stream 54 from the degasser 50 as well as one or more additional gas streams 106, which can be Date recue / Date received 2021-11-09 made up of several overhead gas streams from the second process train 26, such as gas streams 80, 64, 90, among others depending on the equipment and process configuration that is used. As noted above, if nitrogen blanket gas is used, the withdrawn nitrogen blanket gas would not be supplied to the first process train 24. It is also noted that certain separators can be operated without a gas blanket, either as a flooded vessel or if the inlet fluids are multiphase such that the process fluid forms the gas in the vessel.
Any separation unit in the second process train 26 that generates a methane rich gas stream could be put in fluid communication with the first process train 24 to combine the methane gases with the casing gas 14.

[00107] Turning now to Fig 2, the primary flashing stage 56 can be coupled to a mechanical vapour recompression (MVR) stage 108 which receives the first stage flashed stream 58 and produces a compressed stream 110 which can be used for preheating the feed to the primary flashing stage 56. In particular, the compressed stream 110 can pass through a first stage preheater 112 to produce a preheated degassed fluid 114 and a cooled fluid 116. The cooled fluid is supplied to the primary recovery separator 62 while the preheated degassed fluid 114 can be subjected to additional heating in a primary flash heater 118 prior to feeding into the primary flashing stage 56.

[00108] The MVR stage 108 can include a single-stage or multistage compression system. The inlet pressure can be about 550-650 kPa and the outlet pressure can be 900-1200 kPa, for example, and the temperature can be brought from 80-90 C to 100-110 C.
The compression can be performed so that the compressed fluid is slightly above its vaporization point to avoid liquifying, and then when the compressed fluid is used for heat transfer it liquifies with potentially some subcooling. While the compressed stream 110 can be used to pre-heat the feed to the primary flashing stage 56, it could also be used to heat one or more other streams in the process.

[00109] The primary flashing stage 56 can be operated such that 90%+ of the solvent is flashed and reports to the MVR stage 108, which compresses the vapour stream and the resulting compressed stream provides preheating for the primary flashing stage 56.
Recovering the latent heat from the solvent for preheating has been found to result in 30-40% heat efficiency versus standalone heating and cooling, for butane solvent implementations. This solvent stream bypasses the solvent purification unit of the first process train and is ready for reinjection, which saves an additional step of vaporization Date recue / Date received 2021-11-09 and condensation in the solvent purification tower. The size of the solvent purification tower can also be reduced accordingly. The remaining 10% of solvent can pass through second and third flashing stages for additional recovery in the second process train 26, as described above.

[00110] Turning now to Fig 3, the production fluid 12 can be preheated prior to the degasser 50. The preheating can be performed in one or more heating units. For example, the production fluid 12 can be indirectly preheated in a first heater 119 using some or all of the oil product 18 which is relatively hot, thereby producing a heated production fluid 120 and a cooled oil product 122. The heated production fluid 120 can be further heated in a second heater 124 prior to the degasser 50. It is also noted that various other separation stages can have preheaters arranged to heat the feed using steam or hotter process streams. The production fluid 12 is heated such that substantially all of the NCGs are removed and a portion of the solvent flashes and reports with the overhead stream of the degasser 50, and the degassed fluid contains a very low NCG content (e.g., below 0.03 mol% of NCG).

[00111] Regarding produced water, referring to Fig 4, the treater 74 removes the bulk of the water in the feed and the water reports with the water enriched stream 76 to downstream processing equipment. If there are mineral solids in the production fluid, they can be removed in the treater 74 which can have a desanding unit. The water removal can be performed to reach 0.5 vol% water or lower in the water depleted stream 78, which is thus predominantly composed of oil and solvent. In one example, the water enriched stream 76 can be supplied to a slop tank 126 from which a produced water stream 128 and an oil containing stream 130 can be withdrawn. The produced water stream 128 can be fed to a process water tank 132 along with the saline aqueous stream 72 from the desalter and any other streams that contain a notable amount of water. The produced water tank 132 can be connected to a pipeline to supply the produced water to a disposal site or disposal facility 134. The oil containing stream 130 can be recycled from the slop tank 126 back into an upstream separator, such as the treater 74 for example, to recover additional oil. The produced water can be disposed of in a disposal well, if desired, or can be treated.

[00112] Fig 4 also shows the solvent recovery unit 44 which receives a solvent recovery feed 136 and produces the overhead gas 48. The overhead gas 48 passes through an Date recue / Date received 2021-11-09 overhead condenser 138 and then into reflux separator 140 which produces a reflux liquid 142, a separated gas 144 and a condensate 146. The condensate 146 can be supplied to a unit of the second process train 26, such as the treater 74 as shown in the illustrated example. In some implementations, the condensate 146 and the recycled oil containing stream 130 can be combined together and then fed into a common unit, which can be the treater 74. The condensate 146 from the solvent recovery unit 44 still contains some water and solvent, and thus can be recycled back into the process, e.g., into the treater as illustrated or into the degassing unit. The recycled oil containing stream 130 could also be sent back into an upstream separator, mainly to recover oil. Both of these recycled streams may have relatively low flow rates and can be recycled back to the same or different separation stages.

[00113] Turning now to Fig 5, a flash unit can be operated so that water flashes along with solvent and the water in the flashed stream can be condensed and used as washing liquid for a desalter. While Fig 1 shows the flashing unit as being the primary flashing stage, it is noted that one or more flashing units in the process can be used to obtain the water suitable for use as a washing liquid. The condensed water can be used alone or in combination with another water source for washing in the desalter. The condensing step can be performed by a condenser 147 as shown in Fig 5, or by MVR followed by cooling/condensing in a heat exchanger as shown in Fig 1. This process configuration where flashed water is condensed and reused can be particularly of interest for salty reservoirs so that the oil can be desalted and meet specifications using water obtained from the process itself. This process configuration is also of interest when the oil product should have specifications for certain downstream uses, such as upgrading or refining, where low salt content is desired. All or some of the condensed water can be used as washing liquid. The condensed water can alternatively be used for other purposes where water having low salt content is of interest.

[00114] As noted above, the second process train 26 may be designed to separate solvent using flashing stages instead of distillation or fractionation which can be excluded from that train. Alternatively, it is possible to have distillation or fractionation as part of the second process train, if desired. For example, in some scenarios, a second train distillation tower could replace all of the flashing stages or could be used at a final separation stage after one or more initial flashing stages. In addition, the second process train 26 can be Date recue / Date received 2021-11-09 configured to supply only light end gases (e.g., NCGs, small amounts of solvent, and residual entrained heavier components of the production fluid) to the first process train 24 for processing. As shown in Fig 1, only gas streams obtained from various separators are fed into the feed gas that is supplied to first process train 24, and the gases are predominantly C4 and below with minor amounts of water. In addition, the separation units in the second process train 26 can be operated without blanketing with NCGs (e.g., methane in the form of fuel gas) for pressure maintenance, thus further inhibiting NCG
contamination. Nitrogen or other gases could be used for blanketing. Any off gases and produced gases that contain methane and/or solvent can be captured and supplied to the first process train 24 to be processed. If fuel gas is used for blanketing, the fuel gas withdrawn from the vessels and handled by the VRU could be recycled or could be added to the fuel gas generated by the first process train if those blanket fuel gases have no solvent that should be recovered. Some implementations of the processes described herein are configured to minimize off gas production from the produced emulsion by having the degasser at the front end of the surface facility to remove substantially all NCG
initially. This allows minimum interaction between recovery solvents (e.g., butane) and NCG which can help reduce the flow rate for solvent purification.

[00115] In addition, when the in situ process is conducted at relatively low temperatures (e.g., 40 C to 70 C), there may be little to no H25 in the produced fluids such that de-sulfurization of fuel gas prior to burning would not be required.
Nevertheless, the gases removed form the production fluid (e.g., gas stream 54) could contain H25 and thus could be subjected to scrubbing or another de-sulfurization operation before the gas removed therefrom are used as fuel. However, the casing gas 14 which contains some butane is not expected to have relevant amounts of H25. Thus, the casing gas 14 could be treated separately from the other gas streams to recover solvent, such that the methane in the casing gas 14 is not subjected to de-sulfurization prior to use as fuel. For in situ processes that utilize higher temperatures, H25 may be present in the produced fluids and a scrubbing stage may be provided for de-sulfurization of the fuel gas.

[00116] Regarding the two process trains, they can be kept separate and in parallel in the sense that the first process train 24 is configured to supply only overhead condensate (e.g., condensate 146 from the purification tower 44) to the second process train 26 for processing, and the second process train 26 is configured to supply only light end gases Date recue / Date received 2021-11-09 (e.g., see gas stream 54, and possibly streams 64, 80, 90) to the first process train 24 for processing. It is noted that recovered solvent streams (e.g., SA, SB, Sc) can be combined together prior to heating and reinjection, and in this sense the two process trains converge at the end. However, it is possible to integrate the two process trains in other ways so as to share heating and power sources as well as other fluids, while limiting mixing of NCGs and solvent.

[00117] Implementations of the surface facility and processes described herein can be used in connection with various solvent based in situ recovery operations. For example, solvent-only or solvent-dominated processes using one or more solvents for injection can benefit from such surface separation processes. The solvent can be a paraffinic solvent, such as butane, pentane or hexane. In some implementations, the solvent is separated in order to be relatively pure (e.g., essentially only butane, 99.9% C4+) and thus the solvent recovery unit is operated as a purification unit. Alternatively, the solvent can include a range of hydrocarbon species (e.g., predominantly C4 to C10 hydrocarbons) in various proportions. The solvent mixture can be predominantly in the C4-C6 range or the C5-C6 range, with the remainder being in the range of C7-C10.

[00118] The solvent can also be combined with steam for co-injection or intermittent injection, with the steam content being from 1 wt% to 50 wt%. The steam-solvent injected fluid can be at or near an azeotropic proportion. It is also possible to vary the solvent composition over time, within increased or decreased steam content or varying the hydrocarbon species. In addition, the in situ recovery process can include pulses of different injection fluids (e.g., steam or different solvent). Various aspects of the processes described herein can be implemented for in situ recovery operations where the injected solvent has a desired upper threshold in terms of NCG or light end content, as NCGs or light end hydrocarbons could be kept separate from the heavier solvent when processed at the surface facility. The example surface facility focused on in the present description is for butane as the solvent. If C5+ is used as the solvent, then the first process train would be configured to handle C1-C4 hydrocarbons and the solvent purification tower could be operated as a debutanizer.

[00119] In addition, when steam is used in conjunction with the solvent for injection, the production fluid would contain a higher amount of water due to the condensate.
In such solvent based steam assisted processes, the surface facility could be configured for front Date recue / Date received 2021-11-09 end water removal before the primary flashing stage and it may possibly not include a degassing stage; but the multiple flashing stages and the two separate process trains could be implemented in a similar manner as described herein.

[00120] It is also noted that in situ recovery processes have different phases, such as a startup phase, a production phase, and a winddown phase. In the startup phase, it may be desirable to inject different fluids and thus the surface facility can be designed to handle processing of different types of organic solvents and other fluids. For example, if the startup stage involves the use of an organic startup fluid that is different from the solvent, then the surface facility may be operated to switch from handling the organic startup fluid to handling the solvent once the production phase begins. The organic startup fluid can be an aromatic compound or aromatic mixture, for example, which would be different from a paraffinic solvent such as butane.

[00121] Referring to Fig 7, the various recovered solvent components (e.g., SA, SB and Sc) can be combined together along with any make-up solvent 200 and used for reinjection into one or more injector well 22. An injection assembly 202 can be used for injecting the solvent and can be configured depending on the operating design of the recovery process.
The injection assembly 202 can be connected to one or multiple injection lines for injecting the solvent into one or more injection wells 22.

[00122] When a well pair is used, as shown in Fig 1, it may be located in an oil sands reservoir where the heavy hydrocarbons are predominantly bitumen. The well pair may also be one of several well pairs arranged as an array and extending from a common well pad into the reservoir. The surface facility can receive produced fluids from multiple wells and multiple well pads, and can supply multiple wells and well pads with solvent for reinjection. The surface facility can be located in a central location while the wells and pads are located around the central facility. Alternatively, it is possible to locate some equipment of the surface facility at the well pads.

[00123] Turning now to Fig 6, the casing gas 14 can be subjected to initial treatment before being supplied to the gas separator 28. Raw casing gas 300 can be obtained from the production well 16 along with raw production fluid 302. The raw casing gas 300 can be supplied to a casing gas compression assembly 304, which can include one or more vapour-liquid separators arranged in series to remove liquids from the raw casing gas 300 Date recue / Date received 2021-11-09 and produce the casing gas 14 that is supplied to the first process train. The vapour-liquid separators can be arranged such that the overhead gas stream from one is compressed and supplied to the following vapour-liquid separator, while the separated liquid 306 is combined with the raw production fluid 302. In addition, a slipstream 308 of the raw production fluid 302 can be withdrawn and sent to a test separator 310 that produces a test gas stream 312 that is combined with the raw casing gas 300, and a test liquid stream 314 that is combined with the raw production fluid 302. The arrangement shown in Fig 6 is one example of initial operations that could be performed on the production fluid 12 and the casing gas 14 prior to downstream processing as shown in Fig 1 and described herein.

[00124] Referring to Fig 8, one or more vessels that are part of the surface facility can have a gas blanket 320 above a solvent containing fluid 322, wherein the blanket gas 324 is an inert gas such as nitrogen and contains no methane to avoid contamination of the solvent. The gas blanketed vessel 326 can be a solvent storage vessel, a liquid separator that can be used to separate solvent and water, a slop tank, or another type of separator or vessel. The gas blanketed vessel 326 receives a feed 328 of the solvent containing fluid, and may have one or more outlets depending on the purpose of the vessel.

[00125] As shown in Fig 8, the blanket gas 324 is provided into the vessel 326 and via a two-way line 329 and is also managed by the vapour recovery unit (VRU) 330 and a control unit 332. The control unit 332 is connected to a pressure sensor 334 as well as two valves 336A, 336B which are operated in alternating mode to supply blanket gas to the vessel 326 or allow release of vapour from the vessel 326 and into the VRU 330. Any gas blanketed vessel 326 that receives fluid that contains solvent which will be reinjected into the reservoir can use an inert gas instead of a methane containing gas (e.g., fuel gas) to avoid introducing methane into the solvent. This blanketing technique can be beneficial when the recovered solvent is used in a solvent-only or solvent-dominated recovery process.

[00126] It is noted that various aspects described herein can be implemented in conjunction with each other or not depending on the overall operation and design of the recovery process.
Date recue / Date received 2021-11-09

Claims (170)

34

1. A process for recovery of heavy hydrocarbons from a reservoir, comprising:
injecting solvent into the reservoir to mobilize the heavy hydrocarbons;
recovering production fluid and casing gas from the reservoir;
separately treating the production fluid and the casing gas, comprising:
in a first process train, subjecting the casing gas to separation to obtain a first train recovered solvent and solvent-depleted gas; and in a second process train, subjecting the production fluid to separation stages to produce an oil product, a second train recovered solvent, and produced water; and reinjecting into the reservoir at least a portion of the first train recovered solvent, the second train recovered solvent, or a combination thereof.

2. The process of claim 1, wherein subjecting the casing gas to separation comprises:
supplying the casing gas to a gas separator to produce a solvent enriched stream and a solvent depleted gas stream;
supplying the solvent enriched stream to a distillation tower to produce a top vapour stream and a bottom solvent stream as the first train recovered solvent.

3. The process of claim 2, further comprising:
chilling the solvent depleted gas stream to produce a chilled stream;
supplying the chilled gas stream to a low temperature separator to produce a gas stream and a second solvent enriched stream; and supplying the second solvent enriched stream to the distillation tower.
Date recue / Date received 2021-11-09

4. The process of claim 3, further comprising:
subjecting the top vapour stream to separation to produce a vapour recycle stream and a liquid stream; and recycling the vapour recycle into the low temperature separator.

5. The process of claim 4, wherein subjecting the top vapour stream to separation further produces a reflux stream that is fed back into the distillation tower.

6. The process of any one of claims 3 to 5, further comprising combining the gas stream with a natural gas stream to produce a fuel gas.

7. The process of any one of claims 3 to 6, wherein the chilling is performed so that the chilled stream has a temperature between 10 C and 15 C, and operating the gas separator at a temperature between 35 C and 45 C.

8. The process of any one of claims 1 to 7, further comprising:
removing light gases from the production fluid in the second process train;
and supplying the light gases to the first process train for processing thereof.

9. The process of claim 8, wherein the light gases are combined with the casing gas prior to subjecting the casing gas to separation.

10. The process of any one of claims 1 to 8, wherein subjecting the production fluid to separation stages comprises:
a primary flashing stage to produce a first stage flashed stream and a first stage underflow stream;
a water removal stage that receives the first stage underflow stream and produces a water enriched stream and a water depleted stream; and a secondary flashing stage that receives the water depleted stream and produces a secondary stage flashed stream and a second stage underflow stream.
Date recue / Date received 2021-11-09

11. The process of claim 10, further comprising condensing the first stage flashed stream to form a condensed stream and supplying the condensed stream to a primary separator to produce an aqueous stream and a first recovered solvent stream as part of the second train recovered solvent.

12. The process of claim 11, wherein the aqueous stream is supplied as washing liquid to a desalting stage to produce the oil product.

13. The process of claim 11 or 12, wherein the secondary stage flashed stream is supplied to a secondary separator to produce a secondary recovered solvent stream as part of the second train recovered solvent.

14. The process of claim 13, wherein the primary separator also produces a first stage gas stream and/or the secondary separator produces a second stage gas stream, and one or both of the primary and secondary gas streams are combined with the casing gas.

15. The process of claim 14, wherein the water removal stage also produces a water removal gas stream that is also combined with the casing gas.

16. The process of claim 15, wherein the water removal stage is performed using a treater.

17. The process of any one of claims 14 to 16, wherein the first stage gas stream, the second stage gas stream, and/or the water removal gas stream are blanket gases comprising methane.

18. The process of any one of claims 13 to 17, further comprising subjecting the second stage underflow stream to a tertiary flashing stage to produce a third stage flashed stream and a third stage underflow stream.

19. The process of claim 18, wherein the third stage flashed stream is supplied to a third stage separator to produce a third stage gas stream and a third stage liquid stream.

20. The process of claim 19, wherein the third stage gas stream is supplied to the secondary separator.
Date recue / Date received 2021-11-09

21. The process of claim 19 or 20, wherein the third stage liquid stream is recycled back into the primary flashing stage.

22. The process of any one of claims 18 to 21, wherein the third stage underflow stream is subjected to the desalting stage to produce the oil product.

23. The process of any one of claims 20 to 22, further comprising compressing and cooling the third stage gas stream prior to the secondary separator.

24. The process of any one of claims 10 to 23, wherein the first stage flashed stream is subjected to mechanical vapour recompression to produce a compressed stream.

25. The process of claim 24, wherein the compressed stream is used to indirectly preheat the production fluid prior to the primary flashing stage.

26. The process of any one of claims 10 to 25, further comprising degassing the production fluid prior to the primary flashing stage to produce a degassed production fluid and a recovered gas stream comprising non-condensable gas and solvent.

27. The process of claim 26, further comprising combining the recovered gas with the casing gas.

28. The process of claim 26 or 27, wherein the oil product is used to indirectly preheat the production fluid prior to the degassing.

29. The process of any one of claims 1 to 28, wherein the second process train does not include a distillation stage.

30. The process of any one of claims 1 to 29, wherein the second process train is configured to supply only light end gases to the first process train for processing.

31. The process of any one of claims 1 to 30, wherein the first process train is configured to supply only overhead condensate from distillation to the second process train for processing.
Date recue / Date received 2021-11-09

32. The process of any one of claims 1 to 31, wherein the solvent is a paraffinic solvent having a carbon number from 4 to 6.

33. The process of any one of claims 1 to 32, wherein the solvent is butane.

34. The process of any one of claims 1 to 33, wherein the solvent is injected via an injector well that is vertically spaced from an underlying producer well configured for recovering the production fluid, and the injector and producer wells are operated as a gravity drainage well pair.

35. The process of any one of claims 1 to 34, wherein the solvent is injected as a substantially pure solvent injection fluid to provide a solvent-only in situ recovery operation.

36. The process of any one of claims 1 to 34, wherein the solvent is provided as a main component of injection fluid to provide a solvent-dominated in situ recovery operation.

37. The process of any one of claims 1 to 36, wherein separation units of the second process train are operated without a methane blanket.

38. The process of any one of claims 1 to 37, wherein the heavy hydrocarbons comprise bitumen.

39. The process of any one of claims 1 to 38, wherein the reservoir is an oil sands reservoir.

40. The process of any one of claims 1 to 39, wherein the first train recovered solvent and the second train recovered solvent are reinjected into the reservoir.

41. The process of any one of claims 1 to 39, wherein the first train recovered solvent is reinjected into the reservoir.

42. The process of any one of claims 1 to 39, wherein the second train recovered solvent is reinjected into the reservoir.
Date recue / Date received 2021-11-09

43. The process of any one of claims 1 to 42, wherein the casing gas recovered from the reservoir is subjected to compression prior to supply to the first process train.

44. The process of claim 43, wherein the casing gas recovered from the reservoir is subjected to a pre-separation treatment to remove liquid prior to supply to the first process train.

45. The process of claim 44, wherein the removed liquid is combined with the production fluid.

46. A process for recovery of heavy hydrocarbons from a reservoir, comprising:
injecting solvent into the reservoir to mobilize the heavy hydrocarbons;
recovering production fluid and casing gas from the reservoir;
separately treating the production fluid and the casing gas, comprising:
in a first process train, subjecting the casing gas to separation to obtain a first train recovered solvent and solvent-depleted gas; and in a second process train, subjecting the production fluid to separation stages to produce an oil product, a second train recovered solvent, and produced water; and reusing at least a portion of the first train recovered solvent, the second train recovered solvent, or a combination thereof.

47. A system for recovery of heavy hydrocarbons from a reservoir, comprising:
an injection well configured for injecting solvent into the reservoir to mobilize the heavy hydrocarbons;
a production well configured for recovering production fluid and casing gas from the reservoir;
a surface facility for treating the production fluid and the casing gas, comprising:
Date recue / Date received 2021-11-09 a first process train configured to receive the casing gas from the production well and subject the casing gas to separation to obtain a first train recovered solvent and solvent-depleted gas;
a second process train configured to receive the production fluid from the production well and subject the production fluid to separation stages to produce an oil product, a second train recovered solvent, and produced water; and an injection assembly configured to reinject into the reservoir at least a portion of the first train recovered solvent, the second train recovered solvent, or a combination thereof.

48. A process for recovery of heavy hydrocarbons from a reservoir, comprising:
injecting solvent into the reservoir to mobilize the heavy hydrocarbons;
recovering production fluid from the reservoir;
processing the production fluid to produce recovered solvent and an oil product, wherein the processing comprises:
subjecting the production fluid to degassing to remove substantially all light end gas therefrom and produce:
a gas mixture comprising non-condensable gas and solvent;
and a degassed production fluid comprising oil, water and solvent;
separating the gas mixture to produce fuel gas and a first portion of the recovered solvent; and subjecting the degassed production fluid to flash separation to produce a second portion of the recovered solvent, produced water and the oil product; and Date recue / Date received 2021-11-09 reinjecting into the reservoir at least a portion of the first portion of the recovered solvent, the second portion of the recovered solvent, or a combination thereof.

49. The process of claim 48, wherein subjecting the degassed production fluid to flash separation comprises:
subjecting the degassed production fluid to a primary flashing stage to produce a first stage flashed stream and a first stage underflow stream;
subjecting the first stage underflow stream to a water removal stage to produce a water enriched stream and a water depleted stream; and subjecting the water depleted stream to a secondary flashing stage to produce a second stage flashed stream and a second stage underflow stream.

50. The process of claim 49, further comprising supplying the first stage flashed stream to a primary recovery separator to produce an aqueous stream and a first recovered solvent stream as part of the second portion of the recovered solvent.

51. The process of claim 50, wherein the aqueous stream is supplied as washing liquid to a desalting stage to produce the oil product.

52. The process of claim 51, wherein the second stage flashed stream is supplied to a secondary recovery separator to produce a second recovered solvent stream as part of the second portion of the recovered solvent.

53. The process of claim 52, wherein the water removal stage is performed using a treater.

54. The process of any one of claims 50 to 53, further comprising subjecting the second stage underflow stream to a tertiary flashing stage to produce a third stage flashed stream and a third stage underflow stream.
Date recue / Date received 2021-11-09

55. The process of claim 54, wherein the third stage flashed stream is supplied to a third stage recovery separator to produce a third stage gas stream and a third stage liquid stream.

56. The process of claim 55, wherein the third stage gas stream is supplied to secondary recovery separator.

57. The process of claim 55 or 56, wherein the third stage liquid stream is recycled back into the primary flashing stage.

58. The process of any one of claims 54 to 57, wherein the third stage underflow stream is supplied to the desalting stage to produce a portion of the oil product.

59. The process of any one of claims 54 to 57, wherein the third stage underflow stream is the oil product and is supplied to a storage vessel.

60. The process of any one of claims 56 to 59, further comprising compressing and cooling the third stage gas stream prior to the secondary recovery separator.

61. The process of any one of claims 49 to 60, wherein the first stage flashed stream is subjected to mechanical vapour recompression to produce a compressed stream.

62. The process of claim 61, wherein the compressed stream is used to indirectly preheat the degassed production fluid prior to the primary flashing stage.

63. The process of any one of claims 48 to 62, wherein the oil product is used to indirectly preheat the production fluid prior to the degassing.

64. The process of any one of claims 48 to 63, wherein casing gas is recovered from the reservoir separately from the production fluid, and the gas mixture is combined with the casing gas prior to processing thereof.
Date recue / Date received 2021-11-09

65. The process of any one of claims 48 to 64, wherein separating the gas mixture comprises:
supplying the gas mixture to a gas separator to produce a solvent enriched stream and a solvent depleted gas stream; and supplying the solvent enriched stream to a distillation tower to produce a top vapour stream and a bottom solvent stream as the first portion of the recovered solvent.

66. The process of claim 65, further comprising:
chilling the solvent depleted gas stream to produce a chilled stream;
supplying the chilled gas stream to a low temperature separator to produce a gas stream and a second solvent enriched stream; and supplying the second solvent enriched stream to the distillation tower.

67. The process of claim 66, further comprising:
subjecting the top vapour stream to separation to produce a vapour recycle stream and a liquid stream; and recycling the vapour recycle into the low temperature separator.

68. The process of claim 67, wherein subjecting the top vapour stream to separation further produces a reflux stream that is fed back into the distillation tower.

69. The process of any one of claims 67 to 68, further comprising combining the gas stream with a natural gas stream to produce a fuel gas.

70. The process of any one of claims 48 to 69, wherein the production fluid is processed in a second process train that does not include a distillation stage.

71. The process of claim 69, wherein the second process train is configured to supply only light end gases to the first process train for processing.
Date recue / Date received 2021-11-09

72. The process of any one of claims 48 to 71, wherein the first process train is configured to supply only overhead condensate from distillation to the second process train for processing.

73. The process of any one of claims 48 to 72, wherein the solvent is a paraffinic solvent having a carbon number from 4 to 6.

74. The process of any one of claims 48 to 73, wherein the solvent is butane.

75. The process of any one of claims 48 to 74, wherein the solvent is injected via an injector well that is vertically spaced from an underlying producer well configured for recovering the production fluid, and the injector and producer wells are operated as a gravity drainage well pair.

76. The process of any one of claims 48 to 75, wherein the solvent is injected as a substantially pure solvent injection fluid to enable a solvent-only in situ recovery operation.

77. The process of any one of claims 48 to 76, wherein the solvent is provided as a main component of injection fluid to provide a solvent-dominated in situ recovery operation.

78. The process of any one of claims 48 to 77, wherein separation units for processing the degassed production fluid are operated without a methane blanket.

79. The process of any one of claims 48 to 78, wherein the heavy hydrocarbons comprise bitumen.

80. The process of any one of claims 48 to 79, wherein the reservoir is an oil sands reservoir.

81. The process of any one of claims 48 to 80, wherein the first portion of the recovered solvent and the second portion of the recovered solvent are reinjected into the reservoir.

82. The process of any one of claims 48 to 80, wherein the first portion of the recovered solvent is reinjected into the reservoir.
Date recue / Date received 2021-11-09

83. The process of any one of claims 48 to 80, wherein the second portion of the recovered solvent is reinjected into the reservoir.

84. The process of claim 64, wherein the casing gas recovered from the reservoir is subjected to compression prior to combining with the gas mixture.

85. The process of claim 84, wherein the casing gas recovered from the reservoir is subjected to a pre-separation treatment to remove liquid prior to combining with the gas mixture.

86. The process of claim 85, wherein the removed liquid is combined with the production fluid.

87. The process of any one of claims 48 to 86, wherein the degassing is performed such that the degassed production fluid contains at most 0.05 mol% of non-condensable gas.

88. The process of any one of claims 48 to 86, wherein the degassing is performed such that the degassed production fluid contains at most 0.04 mol% of non-condensable gas.

89. The process of any one of claims 48 to 86, wherein the degassing is performed such that the degassed production fluid contains at most 0.03 mol% of non-condensable gas.

90. The process of any one of claims 48 to 89, wherein the production fluid supplied to the degassing contains at least 0.5 mol% of non-condensable gas.

91. The process of any one of claims 48 to 89, wherein the production fluid supplied to the degassing contains at least 0.3 mol% of non-condensable gas.

92. The process of any one of claims 48 to 89, wherein the production fluid supplied to the degassing contains at least 0.2 mol% of non-condensable gas.

93. A process for recovery of heavy hydrocarbons from a reservoir, comprising:
injecting solvent into the reservoir to mobilize the heavy hydrocarbons;
Date recue / Date received 2021-11-09 recovering production fluid from the reservoir;
processing the production fluid to produce recovered solvent and an oil product, wherein the processing comprises:
subjecting the production fluid to degassing to remove non-condensable gas therefrom and produce:
a gas mixture comprising non-condensable gas and solvent;
and a degassed production fluid comprising oil, water and solvent;
separating the gas mixture to produce a first portion of the recovered solvent; and subjecting the degassed production fluid to separation to produce a second portion of the recovered solvent, produced water and the oil product; and reusing at least a portion of the first portion of the recovered solvent, the second portion of the recovered solvent, or a combination thereof.

94. A system for recovery of heavy hydrocarbons from a reservoir, comprising:
an injection well configured for solvent into the reservoir to mobilize the heavy hydrocarbons;
a production well configured for recovering production fluid from the reservoir;
a surface facility for processing the production fluid to produce recovered solvent and an oil product, wherein the surface facility comprises:
a degasser configured for subjecting the production fluid to degassing to remove non-condensable gas therefrom and produce:
Date recue / Date received 2021-11-09 a gas mixture comprising non-condensable gas and solvent;
and a degassed production fluid comprising oil, water and solvent;
a gas separation assembly configured for separating the gas mixture to produce a first portion of the recovered solvent;
a production fluid separation assembly configured for subjecting the degassed production fluid to separation to produce a second portion of the recovered solvent, produced water and the oil product; and an injection assembly configured to reinject into the reservoir at least a portion of the first portion of the recovered solvent, the second portion of the recovered solvent, or a combination thereof.

95. A process for recovery of heavy hydrocarbons from a reservoir, comprising:
injecting solvent into the reservoir to mobilize the heavy hydrocarbons;
recovering production fluid from the reservoir;
processing the production fluid to produce recovered solvent and an oil product, wherein the processing comprises:
subjecting the production fluid to a primary flashing stage to produce a first flashed stream and a first underflow stream;
subjecting the first flashed stream to mechanical vapour recompression to produce a compressed stream;
indirectly heating at least one process stream with the compressed stream to produce a heated process stream and a first stage cooled stream;
separating the first stage cooled stream to produce a first stage recovered solvent; and Date recue / Date received 2021-11-09 processing the first underflow stream to recover additional recovered solvent and the oil product; and reinjecting into the reservoir at least a portion of the first stage recovered solvent, the additional recovered solvent, or a combination thereof.

96. The process of claim 95, wherein the mechanical vapour recompression comprises a single stage compressor.

97. The process of claim 95, wherein the mechanical vapour recompression comprises a multistage compressor.

98. The process of any one of claims 95 to 97, wherein the compressed stream is used to indirectly heat the production fluid that is fed into the primary flashing stage.

99. The process of any one of claims 95 to 98, wherein the compressed stream is condensed during the indirect heating such that the first stage cooled stream is liquid.

100. The process of any one of claims 95 to 99, wherein the first stage cooled stream comprises water and solvent, and the separating of the first stage cooled stream further produces an aqueous stream.

101. The process of claim 100, wherein the aqueous stream is used as a washing liquid to remove salts a hydrocarbon material to produce the oil product.

102. The process of any one of claims 95 to 101, further comprising subjecting the production fluid to degassing prior to the primary flashing stage.

103. The process of any one of claims 95 to 103, wherein casing gas is recovered from the production well and processed separately in a first process train to produce first train recovered solvent and solvent-depleted gas, and the processing of the production fluid is performed in a second process train.
Date recue / Date received 2021-11-09

104. The process of claim 103, wherein processing the casing gas comprises:
supplying the casing gas to a gas separator to produce a solvent enriched stream and a solvent depleted gas stream;
supplying the solvent enriched stream to a distillation tower to produce a top vapour stream and a bottom solvent stream as the first train recovered solvent;
chilling the solvent depleted gas stream to produce a chilled stream;
supplying the chilled gas stream to a low temperature separator to produce a gas stream and a second solvent enriched stream; and supplying the second solvent enriched stream to the distillation tower.

105. The process of claim 103 or 104, further comprising:
removing light gases from the production fluid in the second process train;
and supplying the light gases to the first process train for processing thereof.

106. The process of claim 105, wherein the light gases are combined with the casing gas prior to subjecting the casing gas to separation.

107. The process of any one of claims 95 to 106, wherein the processing of the first underflow stream comprises:
supplying the first underflow stream to a water removal stage to produce a water enriched stream and a water depleted stream;
supplying the water depleted stream to a secondary flashing stage to produce a secondary stage flashed stream and a second stage underflow stream.
Date recue / Date received 2021-11-09

108. The process of claim 107, wherein the secondary stage flashed stream is supplied to a secondary separator to produce a secondary recovered solvent stream as part of the second train recovered solvent.

109. The process of claim 107 or 108, further comprising subjecting the second stage underflow stream to a tertiary flashing stage to produce a third stage flashed stream and a third stage underflow stream.

110. The process of claim 109, wherein the third stage flashed stream is supplied to a third stage separator to produce a third stage gas stream and a third stage liquid stream.

111. The process of claim 110, wherein the third stage gas stream is supplied to the secondary separator.

112. The process of claim 110 or 111, wherein the third stage liquid stream is recycled back into the primary flashing stage.

113. The process of any one of claims 109 to 112, wherein the third stage underflow stream is subjected to the desalting stage to produce the oil product.

114. The process of any one of claims 95 to 113, wherein the processing of the production fluid does not include a distillation stage.

115. The process of any one of claims 95 to 114, wherein the solvent is a paraffinic solvent having a carbon number from 4 to 6.

116. The process of any one of claims 95 to 114, wherein the solvent is butane.

117. The process of any one of claims 95 to 116, wherein the solvent is injected via an injector well that is vertically spaced from an underlying producer well configured for recovering the production fluid, and the injector and producer wells are operated as a gravity drainage well pair.

118. The process of any one of claims 95 to 117, wherein the solvent is injected as a substantially pure solvent injection fluid to provide a solvent-only in situ recovery operation.
Date recue / Date received 2021-11-09

119. The process of any one of claims 95 to 117, wherein the solvent is provided as a main component of injection fluid to provide a solvent-dominated in situ recovery operation.

120. The process of any one of claims 95 to 119, wherein separation units for processing the production fluid are operated without a methane blanket.

121. The process of any one of claims 95 to 120, wherein the heavy hydrocarbons comprise bitumen.

122. The process of any one of claims 95 to 121, wherein the reservoir is an oil sands reservoir.

123. The process of any one of claims 95 to 122, wherein the first stage recovered solvent and the additional recovered solvent are reinjected into the reservoir.

124. A process for recovery of heavy hydrocarbons from a reservoir, comprising:
injecting solvent into the reservoir to mobilize the heavy hydrocarbons;
recovering production fluid from the reservoir;
processing the production fluid to produce recovered solvent and an oil product, wherein the processing comprises:
subjecting the production fluid to flashing stages to produce flashed streams and underflow streams;
subjecting at least one of the flashed streams to mechanical vapour recompression to produce a compressed stream;
indirectly heating at least one process stream with the compressed stream to produce a heated process stream and a cooled stream;
and Date recue / Date received 2021-11-09 separating the recovered solvent and the oil product from the flashed streams and the underflow streams;
reinjecting the recovered solvent into the reservoir.

125. The process of claim 124, wherein the compressed stream is used to indirectly heat a feed stream that is supplied into the flashing stage that produces the flashed stream from which the compressed stream is derived.

126. The process of claim 124 or 125, wherein the flashing stages comprise a primary flashing stage, a secondary flashing stage and a tertiary flashing stage.

127. The process of claim 126, wherein the flashed stream from the primary flashing stage is subjected to the mechanical vapour recompression.

128. The process of any one of claims 124 to 127, wherein the mechanical vapour recompression comprises a single stage compressor.

129. The process of any one of claims 124 to 128, wherein only one of the flashed streams is subjected to the mechanical vapour recompression.

130. The process of any one of claims 124 to 129, wherein the flashed stream subjected to the mechanical vapour recompression is composed of flashed solvent and water vapour.

131. The process of any one of claims 124 to 130, wherein the cooled stream is completely condensed and is supplied to a separator to produce a first recovered solvent.

132. The process of any one of claims 124 to 131, wherein the first recovered solvent is reinjected into the reservoir.

133. A system for recovery of heavy hydrocarbons from a reservoir, comprising:
an injection well configured for solvent into the reservoir to mobilize the heavy hydrocarbons;
Date recue / Date received 2021-11-09 a production well configured for recovering production fluid from the reservoir;
a surface facility for processing the production fluid to produce recovered solvent and an oil product, wherein the surface facility comprises:
a flash vessel that is configured to produce a flashed stream and an underflow stream;
a mechanical vapour recompression unit configured to receive the flashed stream and to produce a compressed stream;
a heat exchanger configured to indirectly heat at least one process stream with the compressed stream to produce a heated process stream and a cooled stream; and an injection assembly configured to reinject into the reservoir at least a portion of the first portion of the recovered solvent, the second portion of the recovered solvent, or a combination thereof.

134. A process for recovery of heavy hydrocarbons from a reservoir, comprising:
injecting solvent into the reservoir to mobilize the heavy hydrocarbons;
recovering production fluid from the reservoir;
subjecting the production fluid to a flashing stage to produce a solvent reduced production fluid and a flashed stream that comprises flashed solvent and water vapour;
processing the solvent reduced production fluid to produce recovered oil;
condensing the flashed stream to produce condensed stream;
separating the condensed stream to produce a solvent stream and condensed water; and Date recue / Date received 2021-11-09 using at least a portion of the condensed water as a washing liquid for the recovered oil to remove salts therefrom and produce a desalted oil product.

135. The process of claim 134, wherein the production fluid is subjected to degassing to produce a degassed production fluid that is supplied to the flashing stage, and the processing of the solvent reduced production fluid comprises water removal followed by one or more additional flashing stages.

136. The process of claim 134 and 135, wherein the flashed stream is subjected to mechanical vapour recompression to produce a compressed stream; the compressed stream is supplied to a heat exchanger to heat the production fluid prior to the flashing stage and to form a condensed stream; and the condensed stream is supplied to a separator to produce a recovered solvent stream and the condensed water.

137. The process of any one of claims 134 to 136, wherein the flashing stage is a primary flashing stage that produces the flashed stream and a first stage underflow stream, and wherein the first stage underflow stream is supplied to a water removal stage to produce a water enriched stream and a water depleted stream; and the water depleted stream is supplied to a secondary flashing stage to produce a secondary stage flashed stream and a second stage underflow stream.

138. The process of claim 137, wherein the secondary stage flashed stream is supplied to a secondary separator to produce a secondary recovered solvent stream.

139. The process of claim 138, further comprising subjecting the second stage underflow stream to a tertiary flashing stage to produce a third stage flashed stream and a third stage underflow stream.

140. The process of claim 139, wherein the third stage flashed stream is supplied to a third stage separator to produce a third stage gas stream and a third stage liquid stream.

141. The process of claim 140, wherein the third stage gas stream is supplied to the secondary separator.
Date recue / Date received 2021-11-09

142. The process of claim 140 or 141, wherein the third stage liquid stream is recycled back into the primary flashing stage.

143. The process of any one of claims 139 to 142, wherein the third stage underflow stream is the recovered oil that is contacted with the condensed water for desalting to produce the oil product.

144. The process of any one of claims 134 to 143, wherein the reservoir has a chloride content of at least 5,000 ppm.

145. The process of any one of claims 134 to 144, wherein the desalted oil product is supplied to an upgrader for processing.

146. The process of any one of claims 134 to 144, wherein the desalted oil product is diluted with diluent for sale as diluted bitumen.

147. The process of any one of claims 134 to 146, wherein the solvent is injected via an injector well that is vertically spaced from an underlying producer well configured for recovering the production fluid, and the injector and producer wells are operated as a gravity drainage well pair.

148. The process of any one of claims 134 to 147, wherein the solvent is injected as a substantially pure solvent injection fluid to enable a solvent-only in situ recovery operation.

149. The process of any one of claims 134 to 147, wherein the solvent is provided as a main component of injection fluid to provide a solvent-dominated in situ recovery operation.

150. The process of any one of claims 134 to 149, wherein the heavy hydrocarbons comprise bitumen.

151. The process of any one of claims 134 to 150, wherein the reservoir is an oil sands reservoir.

152. The process of any one of claims 134 to 151, wherein the solvent is a paraffinic solvent having a carbon number from 4 to 6.
Date recue / Date received 2021-11-09

153. The process of any one of claims 134 to 151, wherein the solvent is butane.

154. A process for recovery of heavy hydrocarbons from a reservoir, comprising:
injecting solvent into the reservoir to mobilize the heavy hydrocarbons;
recovering production fluid from the reservoir;
subjecting the production fluid to separation to produce an oil product and recovered solvent, wherein the processing comprises a flashing stage that produces an underflow stream and a flashed stream that comprises flashed solvent and water vapour;
condensing the water vapour to produce condensed water; and reusing the condensed water.

155. The process of claim 154, wherein the condensed water is used for desalting oil.

156. The process of claim 155, wherein the condensed water is used for desalting the oil product.

157. The process of any one of claims 154 to 156, further comprising:
compressing the flashed stream to produce a compressed stream;
indirectly heating a process stream using the compressed stream to produce a heated process stream and cooled condensed stream that includes the condensed water and condensed solvent; and separating the condensed water from the condensed solvent.

158. A system for recovery of heavy hydrocarbons from a reservoir, comprising:
an injection well configured for solvent into the reservoir to mobilize the heavy hydrocarbons;
a production well configured for recovering production fluid from the reservoir;
Date recue / Date received 2021-11-09 a surface facility for processing the production fluid to produce recovered solvent and an oil product, wherein the surface facility comprises:
a flash vessel that is configured to produce a flashed stream and an underflow stream, the flashed stream comprising water vapour and solvent;
a condenser configured to receive the flashed stream and to produce a condensed stream comprising condensed water and recovered solvent;
a separator configured to receive the condensed stream and to separate the condensed water from the recovered solvent;
a desalter configured to receive at least a portion of the condensed water and recovered oil and to produce an oil product.

159. A process for recovery of heavy hydrocarbons from a reservoir, comprising:
injecting solvent into the reservoir to mobilize the heavy hydrocarbons;
recovering production fluid from the reservoir;
subjecting the production fluid to separation to produce an oil product and recovered solvent, wherein the separation is performed via a plurality of separation vessels comprising at least one gas blanketed vessel that receives a solvent containing fluid and is blanketed with an inert gas; and reinjecting at least a portion of the recovered solvent into the reservoir.

160. The process of claim 159, wherein the inert gas comprises nitrogen.

161. The process of claim 159 or 160, wherein the at least one gas blanketed vessel comprises a solvent storage tank.

162. The process of any one of claims 159 to 161, wherein the at least one gas blanketed vessel comprises a solvent-water separation vessel that produces a solvent stream and an aqueous stream.
Date recue / Date received 2021-11-09

163. The process of any one of claims 159 to 162, wherein the solvent is injected via an injector well that is vertically spaced from an underlying producer well configured for recovering the production fluid, and the injector and producer wells are operated as a gravity drainage well pair.

164. The process of any one of claims 159 to 163, wherein the solvent is injected as a substantially pure solvent injection fluid to enable a solvent-only in situ recovery operation.

165. The process of any one of claims 159 to 163, wherein the solvent is provided as a main component of injection fluid to provide a solvent-dominated in situ recovery operation.

166. The process of any one of claims 159 to 165, wherein the heavy hydrocarbons comprise bitumen.

167. The process of any one of claims 134 to 166, wherein the reservoir is an oil sands reservoir.

168. The process of any one of claims 159 to 167, wherein the solvent is a paraffinic solvent having a carbon number from 4 to 6.

169. The process of any one of claims 159 to 167, wherein the solvent is butane.

170. A method for recovering paraffinic solvent from heavy hydrocarbons for reuse as an injection fluid into a hydrocarbon-containing reservoir, the method comprising separating the paraffinic solvent from heavy hydrocarbons in a surface facility comprising separation and storage vessels, wherein at least one of the separation and storage vessels are blanketed with a blanket gas and all of the blanketed separation and storage vessels use an inert gas as the blanket gas.
Date recue / Date received 2021-11-09