CA3186453A1 - Systems and methods for processing fluids for recovery of viscous hydrocarbons from a subterranean formation by a cyclic solvent process - Google Patents

Abstract

Methods of processing a production stream to collect solvent compounds and re-inject them back into a subterranean formation are described herein. The production stream is recovered from a subterranean formation after injecting the solvent compounds into the subterranean formation by a cyclic solvent process. The production stream includes a hydrocarbon liquid phase including heavy oil and the solvent compounds, a gas phase mixture, and a water liquid phase. The method includes separating a portion of the solvent compounds present in the production stream in a solvent separator to form a solvent vapor stream comprising the portion of the solvent compounds and a liquid hydrocarbon stream, processing the solvent vapor stream in a cooling subsystem to condense the portion of the solvent compounds into a liquid for re-injection into the subterranean formation and reinjecting the portion of the solvent compounds back into the subterranean formation in a liquid state.

Description

TITLE: SYSTEMS AND METHODS FOR PROCESSING FLUIDS FOR RECOVERY
OF VISCOUS HYDROCARBONS FROM A SUBTERRANEAN FORMATION BY A
CYCLIC SOLVENT PROCESS
Technical Field [0001] The present disclosure relates generally to systems and methods and apparatus for processing fluids from underground reservoirs, and more specifically to methods and apparatus for processing fluids for recovery of viscous hydrocarbons from a subterranean formation by a cyclic solvent process (CSP).
Background

[0002] This section is intended to introduce various aspects of the art that may be associated with the present disclosure. This discussion aims to provide a framework to facilitate a better understanding of particular aspects of the present disclosure.
Accordingly, it should be understood that this section should be read in this light, and not necessarily as an admission of prior art.

[0003] Historically, commercial in-situ oil sands have used processes such as but not limited to cyclic steam stimulation (CSS), steam assisted gravity drainage (SAGD), and steam-flood (SF) to extract oil from underground reservoirs. Each of these processes utilizes steam to heat the oil of the underground reservoir to increase its temperature and reduce its viscosity to cause it to flow and provide for it to be extracted.

[0004] It is anticipated that the next generation of in-situ processes for extracting oil from underground reservoirs will either use a mixture of a solvent and steam or pure solvent to extract oil from similar reservoirs. In solvent-based processes, the solvent mixes with oil, dilutes the oil, and lowers the viscosity of oil allowing it to flow. These processes have the potential to offer lower energy intensity, lower water usage, an ability to access previously uneconomic resources, and higher reservoir recovery rates relative to other steam-based processes.

[0005]
One such solvent-based process is commonly referred to as a cyclic solvent process (CSP), such as but not limited to the process(es) described in U.S.
Patent No.

Date Recue/Date Received 2023-01-16

6,769,486. A CSP is an in-situ bitumen and heavy oil recovery process that consists of alternating cycles of solvent injection and solvent/bitumen mixture production through the same horizontal well of a subterranean formation. The solvent is injected in a liquid state into fingers within a subterranean reservoir to mix with bitumen therein, reducing its viscosity to allow it to flow. In some variations of the process, the injected fluid might be a combination of a main injectant (e.g. solvent) mixed with some co-injectants. In other variations, the injection period of the main injectant may be followed with the injection of filling agents such as water.
[0006] After injection, a mixture of fluids commonly referred to as a production mixture is produced. The production mixture generally comprises at least one hydrocarbon liquid phase (e.g. including a mixture of bitumen/heavy oil with solvent and other co-injectants), a gas phase mixture (e.g. including in-situ native solution gas compounds such as CH4 and a portion of injected compounds such as but not limited to the solvent compounds and co-injectants) and a water liquid phase (e.g.
including a portion of in-situ formation water with dissolved minerals, and a fraction of injected water as filling agent mixed with formation water). The production stream may carry some suspended minerals and solid particles (including sand, silt and clay from the subterranean formation).

[0007] A CSP typically requires a tremendous amount of solvent to be injected into the subterranean formation to reduce the viscosity of the bitumen therein and to produce the production stream. In a CSP, a fraction of the produced solvent may be separated from the production mixture and recycled for re-injection. In addition, some fraction of the produced water may be separated, processed and recycled for re-injection as the filling agent. Current processing techniques for recovering bitumen from the production stream do not adequately account for the amount of solvent present in the production stream and the possibility of recovering it for reinjection with optimized use of thermal and electrical energy to minimize the waste and the associated greenhouse gas emissions with the process.

Date Recue/Date Received 2023-01-16

[0008]
Accordingly, there is a need for improved systems and methods for recovery of viscous hydrocarbons from a subterranean formation by a CSP, particularly with respect to processing of solvent present in a production mixture of a CSP.
Summary

[0009]
According to at least one broad aspect, a method of processing a production stream in a recovery facility to collect solvent compounds of the production stream and re-inject the solvent compounds back into a subterranean formation is described herein.
The production stream is recovered from the subterranean formation after injecting the solvent compounds into the subterranean formation by a cyclic solvent process.
The production stream includes a hydrocarbon liquid phase including heavy oil and the solvent compounds, a gas phase mixture, and a water liquid phase. The method includes separating a portion of the solvent compounds present in the production stream in a solvent separator to form a solvent vapor stream comprising the portion of the solvent compounds and a liquid hydrocarbon stream, the separating being performed in multiple stages;
processing the solvent vapor stream in a cooling subsystem to condense and compress the portion of the solvent compounds into a liquid for re-injection into the subterranean formation, the condensing being performed in multiple stages; and reinjecting the portion of the solvent compounds back into the subterranean formation in a liquid state.

[0010] According to another aspect, separating the portion of the solvent compounds present in the production stream includes separating the portion of the solvent compounds by heating the production stream until the portion of the solvent compounds evaporates.

[0011]
According to another aspect, separating the portion of the solvent compounds present in the production stream includes separating the portion of the solvent compounds in low pressure and low temperature conditions.

[0012]
According to another aspect, separating the portion of the solvent compounds present in the production stream includes separating the portion of the solvent compounds in high pressure and high temperature conditions.

Date Recue/Date Received 2023-01-16

[0013] According to another aspect, separating the portion of the solvent compounds present in the production stream is performed in two stages.

[0014] According to another aspect, separating the portion of the solvent compounds present in the production stream is performed in more than two stages.

[0015] According to another aspect, separating the portion of the solvent compounds is performed in a central recovery facility that is dedicated to a plurality of recovery wells.

[0016] According to another aspect, separating the portion of solvent compounds is performed in a set of satellite recovery facilities that are each dedicated to either a .. recovery well or a group of recovery wells.

[0017] According to another aspect, processing the solvent stream in a cooling subsystem to condense the portion of the solvent compounds into the liquid includes cooling the portion of the solvent compounds, compressing the portion of the solvent compounds and liquefying of the portion of the solvent compounds.

[0018] According to another aspect, processing the solvent stream in a cooling subsystem to condense the portion of the solvent compounds into a liquid is performed in two stages.

[0019] According to another aspect, processing the solvent stream in a cooling subsystem to condense the portion of the solvent compounds for re-injection into the .. subterranean formation is performed in more than two stages.

[0020] According to another aspect, the solvent separator is operated at a temperature and a pressure to minimize energy requirements of the cooling subsystem.

[0021] According to another aspect, the solvent separator is operated at a temperature and a pressure to minimize greenhouse gas emissions associated with the .. cyclic solvent process.

[0022] According to another aspect, a portion of the liquid hydrocarbon stream is re-circulated to a field facility.

Date Recue/Date Received 2023-01-16

[0023] According to another aspect, a portion of the production stream is re-circulated to a field facility.

[0024] According to another aspect, the methods also include, prior to separating the portion of the solvent compounds present in the production stream in a solvent separator, removing water from the production stream in a primary separator.

[0025] According to another aspect, a portion of the liquid hydrocarbon stream is shipped out to the market.

[0026] According to another aspect, the solvent separator is operated at a temperature in a range from 50 C to 100 C.

[0027] According to another aspect, the solvent separator is operated at a pressure in a range from 100 kPa to 700 kPa.

[0028] According to another aspect, the solvent separator is operated at a temperature in a range from 60 C to 90 C and a pressure in a range from 100 kPa to 500 kPa.

[0029] According to another aspect, the solvent separator is operated at a temperature in a range from 65 C to 85 C and a pressure from in a range from 100 kPa to 400 kPa.

[0030] According to another aspect, the solvent separator is operated at a temperature in a range from 70 C to 80 C and a pressure from in a range from 300 kPa to 400 kPa.

[0031] According to another aspect, the solvent separator is operated at a temperature in a range from75 C to 150 C.

[0032] According to another aspect, the solvent separator is operated at a pressure in a range from 700 kPa to 2000 kPa.

[0033] According to anoher aspect, the solvent separator is operated at a temperature in a range from 85 C to 135 C and a pressure in a range from 900 kPa to 2000 kPa.

Date Recue/Date Received 2023-01-16

[0034] According to another aspect, the solvent separator is operated at a temperature in a range from 95 C to 120 C and a pressure in a range from 1200 kPa to 2000 kPa.

[0035] According to another aspect, the solvent separator is operated at a temperature in a range from 100 C to 110 C and a pressure in a range from 1200 kPa to 1600 kPa.

[0036] According to another aspect, the solvent compounds comprise C2 to C5 hydrocarbons.

[0037] According to another aspect, the reinjected portion of the solvent compounds consists of C2 to C5 hydrocarbons.

[0038] According to another aspect, a portion of the liquid hydrocarbon stream is shipped out to another facility for further processing before shipped out to the market.

[0039] According to another aspect, the solvent vapor stream is processed in a second solvent separator operated at low pressure and low temperature conditions prior to processing the solvent vapor stream in the cooling subsystem.

[0040] These and other features and advantages of the present application will become apparent from the following detailed description taken together with the accompanying drawings. However, it should be understood that the detailed description and the specific examples, while indicating preferred embodiments of the application, are given by way of illustration only, since various changes and modifications within the spirit and scope of the application will become apparent to those skilled in the art from this detailed description.
Brief Description of the Drawings

[0041] For a better understanding of the various embodiments described herein, and to show more clearly how these various embodiments may be carried into effect, reference will be made, by way of example, to the accompanying drawings which show at least one example embodiment, and which are now described. The drawings are not intended to limit the scope of the teachings described herein.

Date Recue/Date Received 2023-01-16

[0042] FIG. 1 is a schematic diagram showing the general surface process flow for a CSP, according to at least one embodiment described herein.

[0043] FIG. 2 is a diagram demonstrating viscosity reduction due to mixing of heavy oil and/or bitumen with propane and indicating the phase splitting in the mixture.

[0044] FIG. 3 is a schematic diagram showing a process flow within a recovery facility, according to at least one embodiment described herein.

[0045] The skilled person in the art will understand that the drawings, further described below, are for illustration purposes only. The drawings are not intended to limit the scope of the applicant's teachings in any way. Also, it will be appreciated that for simplicity and clarity of illustration, elements shown in the figures have not necessarily been drawn to scale. For example, the dimensions of some of the elements may be exaggerated relative to other elements for clarity. Further aspects and features of the example embodiments described herein will appear from the following description taken together with the accompanying drawings.
Detailed Description

[0046] To promote an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and no limitation of the scope of the disclosure is hereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. For the sake of clarity, some features not relevant to the present disclosure may not be shown in the drawings.

[0047] At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent.
Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.

Date Recue/Date Received 2023-01-16

[0048] As one of ordinary skill would appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name only. In the following description and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus, should be interpreted to mean "including, but not limited to."

[0049] A "hydrocarbon" is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sands. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.

[0050] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a range from 1 to 9.

[0051] "Bitumen" is a naturally occurring heavy oil material.
Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
- 19 weight (wt.) percent (%) aliphatics (which can range from 5 wt. % to 30 wt. %
or higher);
- 19 wt. % asphaltenes (which can range from 5 wt. % to 30 wt. % or higher);
- 30 wt. % aromatics (which can range from 15 wt. % to 50 wt. % or higher);
- 32 wt. % resins (which can range from 15 wt. % to 50 wt. % or higher);
and - some amount of sulfur (which can range in excess of 7 wt. %), based on the total bitumen weight.

[0052] In addition, bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found in bitumen can vary. The term "heavy oil" includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.

Date Recue/Date Received 2023-01-16

[0053] The term "viscous oil" as used herein means a hydrocarbon, or mixture of hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP
at initial reservoir conditions. Viscous oil includes oils generally defined as "heavy oil" or "bitumen."
Bitumen is classified as an extra heavy oil, with an API gravity of about 100 or less, referring to its gravity as measured in degrees on the API Scale. Heavy oil has an API
gravity in the range of about 22.3 to about 10 . The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes.

[0054] The term "subterranean formation" refers to the material existing below the Earth's surface. The subterranean formation may comprise a range of components, e.g.
minerals such as quartz, siliceous materials such as sand and clays, as well as the oil and/or gas that is extracted. The subterranean formation may be a subterranean body of rock that is distinct and continuous. The terms "reservoir" and "formation"
may be used interchangeably.

[0055] The term "wellbore" as used herein means a hole in the subsurface made by drilling or inserting a conduit into the subsurface. A wellbore may have a substantially circular cross section or any other cross-sectional shape. The term "well,"
when referring to an opening in the formation, may be used interchangeably with the term "wellbore."

[0056] The term "cyclic process" refers to an oil recovery technique in which the injection of a viscosity reducing agent into a wellbore to stimulate displacement of the oil alternates with oil production from the same wellbore and the injection-production process is repeated at least once. Cyclic processes for heavy oil recovery may include a cyclic steam stimulation (CSS) process, a liquid addition to steam for enhancing recovery (LASER) process, a cyclic solvent process (CSP), or any combination thereof.

[0057] The term "continuous process" as used herein refers to an oil recovery technique in which the injection of a viscosity reducing agent occurs in an injector wellbore to stimulate displacement of the oil alternatives with oil production occurring in a separate producer wellbore. The injector wellbore continuously injects the viscosity reducing agent into the reservoir and the producer wellbore continuously produces oil.
Continuous processes for heavy oil recovery may include steam-assisted gravity drainage (SAGD) Date Recue/Date Received 2023-01-16 process, solvent-assisted-steam-assisted gravity drainage (SA-SAGD) process, heated solvent vapor-assisted petroleum extraction (H-VAPEX) process, solvent flooding process, or any combination thereof.

[0058] The articles "the," "a" and "an" are not necessarily limited to mean only one, .. but rather are inclusive and open ended to include, optionally, multiple such elements.

[0059] As used herein, the terms "approximately," "about,"
"substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numerical ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described are considered to be within the scope of the disclosure.

[0060] "At least one," in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase "at least one" refers, whether related or unrelated to those entities specifically identified.
Thus, as a non-limiting example, "at least one of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at least one of A and/or B") may refer, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities).
In other words, the phrases "at least one," "one or more," and "and/or" are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions "at least one of A, B and C," "at least one of A, B, or C,"
"one or more of Date Recue/Date Received 2023-01-16 A, B, and C," "one or more of A, B, or C" and "A, B, and/or C" may mean A
alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C
together, and optionally any of the above in combination with at least one other entity.

[0061] Where two or more ranges are used, such as but not limited to 1 to 5 or 2 to 4, any number between or inclusive of these ranges is implied.

[0062] As used herein, the phrases "for example," "as an example,"
and/or simply the terms "example" or "exemplary," when used with reference to one or more components, features, details, structures, methods and/or figures according to the present disclosure, are intended to convey that the described component, feature, detail, structure, method and/or figure is an illustrative, non-exclusive example of components, features, details, structures, methods and/or figures according to the present disclosure.
Thus, the described component, feature, detail, structure, method and/or figure is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, methods and/or figures, including structurally and/or functionally similar and/or equivalent components, features, details, structures, methods and/or figures, are also within the scope of the present disclosure. Any embodiment or aspect described herein as "exemplary" is not to be construed as preferred or advantageous over other embodiments.

[0063] In spite of the technologies that have been developed, there remains a need in the field for methods of enhancing the recovery of bitumen.
Accordingly, processing methods for a bitumen recovery facility of a CSP
process are herein described. In at least one embodiment, the processing methods separate and recover solvent compounds from extraction fluids (also referred to herein as production fluids, a production stream, or production mixture) to be used, for example, in re-injection.
In at least one embodiment, after production of at least a portion of the solvents from the subterranean formation, the solvent is separated based on its volatility relative to other compounds in the production stream. For example, solvent of the production stream may have a higher volatility in comparison to other compounds in the production stream. In at least one embodiment, the design and operation of the recovery facilities described herein Date Recue/Date Received 2023-01-16 may be optimized to maximize, for example, the economic return of the CSP
while not materially degrading its low greenhouse gas (GHG) intensity performance.

[0064] FIG. 1 schematically depicts a general surface process flow diagram for a CSP recovery facility 100. Recovery facility 100 generally processes a production stream, i.e., a production mixture, to recover and recycle at least a portion of the produced solvent and to prepare it for re-injection. The recovery facility may also recover and recycle some fraction of the produced co-injectants and/or filling agents and prepare them for re-injection.

[0065] Field processing surface facilities 102, or field facilities 102, may be used to collect, test and measure, combine and pre-process production streams from one well or a group of wells 101 and to facilitate their transportation to a main processing facility 104.
The field facilities 102 may include a dual header configuration, such as but not limited to the dual header configuration described in Canadian patent CA3107291.

[0066] In at least one embodiment, the recovery facilities described herein may be a part of a field facility 102. In another embodiment, the recovery facilities described herein may be a part of a central facility to provide a heavy oil product to transport to market. In at least one embodiment, suitable recovery facilities described herein may also include a stand-alone facility which ships out a production stream depleted of the solvent to another facility to process and prepare a heavy oil product to transport to the market. The recovery facility embodiments described herein may produce and separate a gaseous mixture (e.g. including but not limited to CH4 and some vapor light hydrocarbons such as C3) which may be used as a fuel gas in the facilities after required processing. A portion or all of the gaseous mixture may be shipped to another facility for further processing or may be processed and prepared for re-injection as co-injectant by the recovery facility. A portion or all of the produced water may be shipped out to another facility for further processing or disposal. A portion or all of the produced water may alternatively be separated and processed in the recovery facility for re-injection as filling agent. The recovery facilities described herein may re-circulate a fraction of processed streams to the field facilities to co-flow with the production stream and to mitigate potential flow assurance issues.

Date Recue/Date Received 2023-01-16

[0067] To prepare the injection mixture, at least a portion of produced solvent compounds may be separated from the production stream and treated to remove impurities, pressurized/compressed and liquefied. Accordingly, at least a portion of the solvent will be recycled during the operation.

[0068] In the aforementioned CS Ps, one or more solvents may be used to enhance the extraction of petroleum products (e.g. oil and/or bitumen) from subterranean formations. In some embodiments, the solvent(s) used in the CSP may be a light hydrocarbon, a mixture of light hydrocarbons or dimethyl ether. In other embodiments, the solvent may be a C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics.

[0069] In other embodiments, the solvent(s) may be a light, but condensable, hydrocarbon or mixture of hydrocarbons comprising ethane, propane, butane, or pentane.
The solvent(s) may comprise at least one of ethane, propane, butane, pentane, and carbon dioxide. The solvent(s) may comprise greater than 50% C2-05 hydrocarbons on a mass basis. The solvent(s) may be greater than 50 mass% propane, optionally with diluent when it is desirable to adjust the properties of the injectant to improve performance.

[0070] Additional injectants may include CO2, natural gas, C5+
hydrocarbons, ketones, and/or alcohols. Non-solvent injectants that are co-injected with the solvent(s) may optionally include steam, non-condensable gas, and/or hydrate inhibitors.
The solvent composition may comprise at least one of diesel, viscous oil, natural gas, bitumen, diluent, C5+ hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water-soluble solid particles, and solvent soluble solid particles.

[0071] During a CSP, the injection mixture is generally injected in thermal equilibrium with the environment and/or at slightly higher temperatures. Some volumes of make-up solvent and/or co-injectants, and/or a filling agent, may be required to provide enough volume of injection mixture for the recovery of bitumen and/or other viscous hydrocarbons to be successful. Accordingly, the recovery facilities described herein may Date Recue/Date Received 2023-01-16 be built and dedicated to each well, or to a group of wells, or to all of the wells, as a stand-alone facility, or as part of a greater processing facility.

[0072] A unique aspect of a CSP is the liquid solvent injection in thermal equilibrium with the environment and the reservoir. In the production fluid, the solvent is .. typically produced back mainly in its liquid phase in thermal equilibrium with the environment and the reservoir, and mixed with other liquid hydrocarbons produced from the reservoir. In one embodiment of the process, the produced fluid (i.e.
production stream) including solvent, may be heated to temperatures slightly higher than the reservoir temperature by use of downhole heaters. The separation of the solvent from the production stream in the recovery facilities described herein is based on its relatively higher volatility in comparison to bitumen and heavy oil compounds of the production stream. Hence, in the systems described herein, the recovered solvent compounds are recovered in vapor phase with some heat and thermal energy added to facilitate the evaporation and separation of the solvent compounds. In at least one embodiment, the recovered vapor solvent may undergo steps of heating, flashing, compression and cooling processes for liquefaction and preparation for re-injection, as described below.

[0073] Another unique aspect a CSP is the challenge of phase splitting. Propane, for example, is only partially soluble or miscible with bitumen and throughout a CSP
process there can be varying concentrations of propane and bitumen in the liquid phase.
As the fraction of propane increases in the mixture, the liquid (oil) phase will separate into a light liquid and heavy liquid phase with different density and viscosity.
The properties and mass fraction of the resulting light and heavy liquid are dependent on composition, temperature, and pressure. An example of phase splitting is shown in FIG. 2 with splitting at -40% volume propane. Note that this phase diagram is calculated at 13 C
and at a pressure that keeps propane in liquid phase. The curve will change at different temperature and pressures. In view of the aforementioned phase splitting phenomenon, advantageously, the recovery facilities described herein may re-circulate a fraction of processed streams to the field facilities to co-flow with the production stream and to mitigate potential flow assurance issues. More particularly, the recirculated stream may be provided at a higher temperature and lower solvent content (relative to the production stream), thereby mitigating any flow assurance challenges encountered due to the Date Recue/Date Received 2023-01-16 formation of heavy hydrocarbon phase by mixing of solvent and bitumen in the production pipeline.

[0074] The recovery of solvent from the production stream requires various magnitudes of addition of heat, flashing, compression, and cooling to facilitate evaporation of solvent followed by liquefaction for re-injection. Given that CSP is an isothermal process and recovers bitumen without use of thermal energy, the added heat in this solvent recovery process may be appraised as a waste (with associated undesired GHG emissions) unless it is recycled to a great extent. The addition of the heat can be reduced in the expense of more compression. However, the latter generally requires higher operation expenses and GHG associated with purchased electricity from grid power market.

[0075] Referring now to FIG. 3, illustrated therein is a schematic flow diagram of the recovery facility 300.

[0076] Facility 300 receives a production stream via inlet stream 301 from, for example, a field facility. In at least one embodiment, the production stream of the inlet stream 301 is at temperature and pressure conditions that provide for suppressing the separation of the solvent compounds therein from the production stream. In one embodiment, the inlet stream 301 may have a temperature in a range of about 5 C to about 60 C. In one embodiment, the inlet steam 301 may be received at a pressure in a range of about 500 kPa to about 3000 kPa.

[0077] The production stream of a CSP received via inlet stream 301 may be mainly comprised from hydrocarbons and water. Given the cyclic nature of the CSP, the stream composition may change over time as the production continues. The fraction of water to total production stream may change from being <1% to up to about 50%
by weight. The hydrocarbons may include heavy oil components and solvent components with co-injectants. The fraction of heavy oil components to total hydrocarbons may change from <1% to up to about 90% by weight. The hydrocarbons may include solution gas components in liquid dissolved state or vapor state. The fraction of solution gas components to total hydrocarbons can be up to about 5%. In some embodiments, the CSP may be altered such that solvent injection is followed by a filling agent/chaser, e.g., Date Recue/Date Received 2023-01-16 a water chaser or another known fluid/gas filling agent. In these embodiments, the produced fluid may be comprised of up to 100% of the filling agent in some period of the production.

[0078] In at least one embodiment, such as but not limited to the embodiment .. shown in FIG.3, facility 300 includes a primary separator 304 that receives at least a portion of the inlet stream 301. Primary separator 304 is an optional vessel and contents of inlet stream 301, such as but not limited to the production stream, may bypass primary separator 304 or the primary separator 304 may not be included in system 300, particularly in embodiments where a filling agent is not required downstream (as described below).

[0079] In primary separator 304, liquid water is separated from the production stream of inlet stream 301. In at least one embodiment, the liquid water separated out of the production stream in the primary separator 304 can enter water stream 305 and be used for re-injection as a filling agent. In at least one embodiment, primary separator 304 may utilize gravity settling phenomena for separating water out of the production stream.

[0080] In at least one embodiment, at least 50% of the water is separated in primary separator. In other embodiments, the separated water can be 50-99% of the water in the inlet stream 301.

[0081] Water stream 305 may contain some amount of hydrocarbons and solids.
In the embodiment shown in FIG. 3, water stream 305 is directed to a water treatment unit 323. In this embodiment, water stream 305 is treated in the water treatment unit 323 to a selected set of specifications required for water re-injection in a subterranean reservoir in a CSP as a filling agent. This embodiment creates a treated water stream 326 ready for storage and injection as required. This embodiment may also create a disposal stream 325 to carry over impurities such as solids, salts and minerals which may be sent to a water disposal facilities. Water treatment unit 323 may also, optionally, receive a make-up water stream 324. In at least one embodiment, water stream 305 is treated in the water treatment unit 323 to a selected set of environmental specifications required for water disposal such as removal of hydrocarbon contaminants and impurities.

Date Recue/Date Received 2023-01-16

[0082] Returning to primary separator 304, the pressure and temperature of primary separator 304 may be selected to evolve and isolate a vapor phase, mainly composed of solution gas compounds, process gaseous by-products, water vapor and may contain a portion of compounds from the solvent compounds, to produce a primary gas vapor stream 303. The primary gas vapor stream 303 may be directed to the cooling subsystem 316 for further processing, as described below.

[0083] In at least one embodiment, the production stream received from the field facility, or in another embodiment liquid hydrocarbons from an outlet of the primary separator 304, are directed towards a solvent separator 310 to separate at least a portion of the solvent compounds present in the production stream or the liquid hydrocarbons, respectively. In the embodiment shown in FIG. 3, the production stream may be present in bypass stream 308 that is shown bypassing the primary separator 304. The liquid hydrocarbons may be present in outlet stream 306 exiting the primary separator 304.

[0084] In at least one embodiment, outlet stream 306 may have a water content in a range of about 0.1% to 25% by weight. The remaining portion of outlet stream 306 is hydrocarbons. In at least one embodiment, the fraction of heavy oil components to total hydrocarbons may change from <1% to up to 90% by weight.

[0085] In the embodiment shown in FIG. 3, reference number 306 is used to denote both the outlet stream of the primary separator 304 and the inlet stream 306 to the solvent separator. In at least one embodiment, prior to entering the solvent separator 310, the production stream of the bypass stream 308 and/or the outlet stream 306 of liquid hydrocarbons may pass through a heater 307 to increase a temperature of the liquid hydrocarbons therein. The thermal energy to heater 307 may be provided by any direct or indirect heating method, such as but not limited to a fired heater, a hot oil loop, a hot .. glycol loop, by heat exchange with other process streams (e.g. waste heat recovery), by direct steam heating, or the like.

[0086] In at least one embodiment, the solvent separator 310 is a single stage flash unit. In at least one embodiment, the solvent separator 310 is a multiple-stage flash unit.
In at least one embodiment, the solvent separator 310 may be heated. In at least one embodiment, the solvent separator 310 is a combination of a heater and separator such Date Recue/Date Received 2023-01-16 as a reboiler exchanger. For example, the solvent separator 310 may be heated to a desired temperature based on the temperature and pressure of the liquid hydrocarbons in the stream 306 into the solvent separator 310. The thermal energy to heat the solvent separator 310 may be provided by any direct or indirect heating method, such as but not limited to a fired heater, a hot oil loop, a hot glycol loop, by heat exchange with other process streams (e.g. waste heat recovery), by direct steam heating, or the like.

[0087] In at least one embodiment, to reduce the GHG intensity of the recovery facility 300, the heat for heating the solvent separator 310 may be sourced from cooling of the recovered solvent stream by the solvent cooling subsystem 316 (described further below).

[0088] In at least one embodiment, one or more chemicals may be added to the inlet stream 306 prior to entering the solvent separator 310 to inhibit or to reduce, for example, foaming, fouling, scaling, and/or other similar operation phenomena in the solvent separator.

[0089] In at least one embodiment, solvent separator 310 may include mechanical features to inhibit, for example, foaming, fouling, scaling, and/or other similar operation phenomena in the solvent separator.

[0090] In at least one embodiment, the temperature and the pressure of the fluids within the solvent separator 310 may be controlled by controlling heat applied to the solvent separator 310 and/or controlling the temperature and/or the pressure of the liquid hydrocarbons in inlet stream 306 (e.g. via heater 307). In at least one embodiment, the temperature and the pressure of the fluids within the solvent separator 310 may be controlled to optimize the requirement of the compression and/or cooling of the outlet streams 311 and 312 from the solvent separator 310 along with the design of the downstream units (described in greater detail below).

[0091] Solvent separator 310 has a first outlet stream 311 and a second outlet stream 312. First outlet stream 311 carries a vapor comprising solvent compounds along with other gaseous compounds separated out of the liquid hydrocarbons of inlet stream 306. Second outlet stream 312 carries a heavy hydrocarbon stream with reduced content of solvent compounds relative to first outlet stream 311. Each of the heavy hydrocarbons Date Recue/Date Received 2023-01-16 of second outlet stream 312 as well as the vapor of first outlet stream 311 may refer to a single stream or a combination of streams that are grouped together and/or combined into a single stream.

[0092] In at least one embodiment, a single stage flash in solvent separator 310 may be used to recover at least a portion of the produced solvent for re-injection resulting in a single stream of each of 311 and 312. In at least one embodiment, a multi-stage flash in solvent separator 310 may be used to recover at least a portion of the produced solvent for re-injection resulting in multiple streams of 311 and 312. The design and operation of solvent separator 310 is utilized to control the carry-over solvent volumes shipped out to the other processing facility.

[0093] In at least one embodiment, the recovery facility 300 may re-circulate at least a portion of the received production stream, after addition of heat, and/or after recovery of a fraction of the solvent compounds, to the field facility from which the production stream came. In the embodiment shown in FIG. 3, second outlet stream 312 may be split into a heavy liquid product stream 315 and a recirculation stream 313.
Recirculation stream 313 returns at least a portion of the heavy hydrocarbons from the second outlet stream 312 from the solvent separator 310 to the field facility via a dedicated flow path and, optionally, by a booster pump 314. In at least one embodiment, the heavy hydrocarbons of the recirculation stream 313 may have a temperature that is higher than a temperature of the field facility. The higher temperature of recirculation stream 313, and its lower solvent content (i.e. relative to the production stream), may mitigate any flow assurance challenges encountered due to the formation of heavy hydrocarbon phase by mixing of solvent and bitumen in the production pipeline. This may, for example, reduce or eliminate the need for dual header design consideration in the field facilities.

[0094] In at least one embodiment, the recovery facility 300 may re-circulate at least a portion of the of the received production stream, after addition of heat, and/or after recovery of a fraction of the solvent compounds, to the field facility from which the production stream came. In the embodiment shown in FIG. 3, at least a portion of the inlet stream 306 to the solvent separator 310, after the heater 307, may be carried directly into the recirculation stream 313 via stream 316. Recirculation stream 313 returns at least a Date Recue/Date Received 2023-01-16 portion of the heated hydrocarbons downstream of heater 307 to the field facility via a dedicated flow path and, optionally, by a booster pump 314. Recirculation stream 313 may also carry at least a portion of the hydrocarbons present in second outlet stream 312 to the field facilities.

[0095] In at least one embodiment, the hydrocarbons of the recirculation stream 313 may have a temperature that is higher than a temperature of the field facility. The higher temperature of recirculation stream 313 may mitigate any flow assurance challenges encountered due to the formation of heavy hydrocarbon phase by mixing of solvent and bitumen in the production pipeline. This may, for example, reduce or eliminate the need for dual header design consideration in the field facilities.

[0096] First outlet stream 311 from the solvent separator 310 is mainly composed of solvent compounds in a vapor phase. In at least one embodiment, the first outlet stream 311 comprises solution gas compounds and/or water in vapor phase. Solution gas compounds may include methane, carbon dioxide, hydrogen disulfide, helium, nitrogen, ethane and other light hydrocarbons which are not part of the injected solvent com pounds.

[0097] First outlet stream 311 is directed to cooling subsystem 316 where it undergoes a gas separation stage to separate the solvent compounds present in the first outlet stream 311 from other compounds present therein, and to liquefy the solvent compounds, and to prepare the solvent compounds for re-injection.

[0098] Cooling subsystem 316 may be referred to as a gas separator and can be one or more single stage or multiple-stage compression and cooling units, operated in parallel or in series.

[0099] In at least one embodiment, cooling subsystem 316 includes one or more coolers to cool the first outlet stream 311 from the solvent separator 310.
For instance, in at least one embodiment, depending on the temperature and pressure of the first outlet stream 311 from the solvent separator 310, all or some of the vapor streams may be required to be cooled to a desired temperature by one or more coolers.

Date Recue/Date Received 2023-01-16

[0100] In at least one embodiment, cooling subsystem 316 includes one or more compressors to compress the first outlet stream 311 in vapor phase from the solvent separator 310. For instance, in at least one embodiment, all or some of the streams included in the first outlet stream 311 may be required to be compressed to a desired pressure by one or more compressors. Compressing the one or more vapor streams may increase their temperature and require additional cooling.

[0101] The one or more coolers of the cooling subsystem 316 may be designed to provide thermal energy to one or more other streams of system 300. For instance, in at least one embodiment, the cooling subsystem 316 may be configured to provide thermal energy (e.g. heat) to the inlet stream 306 to the solvent separator 310.
Providing thermal energy to inlet stream 306 may provide for reducing waste heat and GHG
intensity.

[0102] Cooling subsystem 316 generally has three outlet streams.
First, solvent outlet stream 317 includes liquefied solvent compounds that are generally free of impurities. Typical impurities include water and solution gas compounds. In at least one embodiment, solvent outlet stream 317 may be ready for re-injection into, for example, a formation for further extraction of bitumen. In the embodiment of FIG. 3, solvent outlet stream 317 is directed to storage vessel 318 for storage and, when desired, is released from the storage vessel 318 as stream 319 and, when optionally combined with one or more other streams (described below), reinjected as reinjection stream 320 via pump 321.

[0103] Second, cooling subsystem 316 includes a water outlet stream 322.
Water outlet stream 322 includes any recovered condensed water from cooling subsystem 316.
In the embodiment shown in FIG. 3, the water outlet stream 322 is directed toward a water storage tank 328 where it can be stored for re-injection as, for example, a filling agent.
Water outlet stream 322 may be directed directly into water storage tank 328 or may be combined, as shown in FIG. 3, with a treated water stream 326 from a water treatment unit 323. Water treatment unit 323 receives water stream 305 from primary separator 304.

[0104] As noted above, treated water stream 326 and water outlet stream 322 from the cooling subsystem 316 may be combined into water storage tank inlet stream that feed the water storage tank 328. Water storage tank outlet 329, also referred to as filling agent stream 329, can be combined with aforementioned solvent storage outlet Date Recue/Date Received 2023-01-16 stream 319 into reinjection stream 320. Alternatively, water in water storage tank 328 may shipped out to the other processing facility.

[0105] In one other embodiment, the water outlet stream 322 may be mixed with the disposal stream 325 and disposed.

[0106] Returning to the outlets from the cooling subsystem 316, gaseous outlet stream 330 includes any outlet gases that may be present in the cooling subsystem 316.
For example, in at least one embodiment, gaseous outlet stream 330 may comprise solution gas compounds with smaller portions of solvent compounds. Gaseous outlet stream 330 may be used as fuel gas in the recovery facility or shipped out to another facility. In at least one embodiment, at least a portion of gaseous outlet stream 330 may be directed as a gaseous reinjection stream 331 to be combined with solvent storage outlet stream 319 and/or water storage tank outlet stream 329 to form reinjection stream 320. In at least one embodiment, a make-up solvent and/or co-injection stream 333 may also be added to the aforementioned streams to form reinjection stream 320.

[0107] As described above, the design (e.g. the number of stages) and operation temperature and operation pressure of the solvent separator 310 may be configured to provide for control of the heating requirement of the liquid hydrocarbons of inlet stream 306. In at least one embodiment, solvent separator 310 may also be configured to provide for control of compression and cooling of the outlet streams 311 and 312 from the solvent separator. In at least one embodiment, solvent separator 310 may also be configured to provide for control of compression and cooling within units of the system 300 downstream of solvent separator 310.

[0108] To this end, solvent separator 310 may be operated in one of two modes, or a combination of thereof. First, in at least one embodiment, solvent separator 310 may be operated in a low pressure and low temperature mode (referred to herein as Mode l).
Example pressures and temperatures are provided below. Mode I requires inlet stream 306 to be heated less than the required heating for Mode II, described below.
Further, Mode I requires more extensive compression utilities (with associated capital and operational expenses and GHG emissions) and less cooling capacity downstream thereof (e.g. within cooling subsystem 316) to prepare the recovered vapor of outlet stream 311 Date Recue/Date Received 2023-01-16 for re-injection. The absorbed heat in the coolers might be low-grade heat with minimal use elsewhere in the recovery facility.

[0109] Second, in at least one embodiment, solvent separator 310 may be operated in a high pressure and high temperature mode (referred to herein as Mode II) Mode II requires more heat addition to the inlet stream with less compression requirement on the recovered higher pressure vapor stream. Again, example pressures and temperatures are provided below. However, the recovered vapor is required to be extensively cooled down and liquefied to prepare for re-injection. In Mode II, the absorbed heat in the coolers of cooling subsystem 316 is high-grade heat with some use elsewhere in the recovery facility.

[0110] Both Mode I and II may utilize multiple flash stages in the design of the solvent separator 310. In these stages, the solvent compounds are separated from the liquid (hydrocarbons) by heating the solvent compounds beyond their boiling point (which may vary based on pressure of the solvent separator 310). In at least one embodiment, at a second stage, the liquid stream from the first stage is heated again before flashing to further separate out solvent compounds present therein. In at least one other embodiment, at a second stage, the liquid stream from the first stage is flashed again without heating to further separate out solvent compounds present therein.
Subsequent stages process the resulting liquid streams in a similar manner. In at least one embodiment, the outlet stream 312 of a solvent separator may be directed to another solvent separator operating in Mode I, to further separate out solvent compounds present therein. In at least one embodiment, multiple flash stages within solvent separator 310 may provide for recovering a greater fraction of produced solvent compounds and may reduce the solvent content in stream 312 (315) , for example shipped out to another facility, to meet any imposed specifications or to reduce the solvent make-up requirements.

[0111] Solvent separator 310 may utilize one, two or more flash and separation stages in both Mode I and II to process the production stream 306. The design and number of heating, flash and separation stages may determine the extent of separation Date Recue/Date Received 2023-01-16 of solvent compounds from heavy oil compounds into the first stream 311 and the second stream 312.

[0112] In both Mode I and mode II, the compression and cooling subsystem 316 increases the pressure of the outlet stream 311 while reducing its temperature to liquefy the solvent components. The outlets of the cooling subsystem 316 may include the recovered water stream 322 from the outlet stream 311, the liquefied solvent stream 317 from the outlet stream 311, and the produced gas stream 330. In one embodiment, the recovered water stream 322 may be mixed with the second outlet stream 312 and shipped out to another facility for re-processing. In one other embodiment, the recovered water stream 322 may be stored for re-injection as the filling agent. In at least one other embodiment, the recovered water stream 322 may be sent to disposal. The produced gas stream 330 may be shipped to another facility, or may be used as fuel gas in facility 300, or re-injected as co-injectant 331 with the solvent to the subterranean reservoir.

[0113] The cooling subsystem 316 may utilize one, two or many compression and cooling stages in both Mode I and II to process the first stream 311. The design and number of compression and cooling stages may determine the extent of separation of solvent compounds from other compounds in the first stream 311. The impurities may include water and solution gas compounds. The liquefied solvent stream 317 may comprise of 95% to 99.9% by weight of solvent compounds. The produced gas stream 330 may compromise up to 10% by weight of solvent compounds as carry-over losses.

[0114] The operation temperature of solvent separator 310 in Mode I
may range from 50 C to 100 C. The operation pressure of solvent separator 310 in Mode I may range from 100 kPa to 700 kPa. The first outlet stream 311 in Mode I is rich in solvent components in vapor phase. The first outlet stream 311 in Mode I may include 80% to 95% by mass of solvent compounds. The remainder is compromised from water and solution gas compounds in vapor phase. The second outlet stream 312 in Mode I
is rich in heavy oil components in liquid phase. In at least one embodiment, the second outlet stream 312 in Model may include a considerable fraction of water. On a water free basis, the second outlet stream 312 in Mode I may include 95% to 99% by mass of heavy oil compounds. The remainder is compromised from solvent compounds in liquid phase.

Date Recue/Date Received 2023-01-16

[0115] The operation temperature of solvent separator 310 in Mode II
may range from 75 C to 150 C. The operation pressure of solvent separator 310 in Mode II may range from 700 kPa to 2000 kPa. The first outlet stream 311 in Mode II is rich in solvent components in vapor phase. The first outlet stream 311 in Mode II may include 85% to 99% by mass of solvent compounds. The remainder is compromised from water and solution gas compounds in vapor phase. The second outlet stream 312 in Mode II
is rich in heavy oil components in liquid phase. In at least one embodiment, the second outlet stream 312 in Mode II may include a considerable fraction of water. On a water free basis, the second outlet stream 312 in Mode II may include 90% to 99% by mass of heavy oil compounds. The remainder is compromised from water and solvent compounds in liquid phase.

[0116] The minimum operating temperature of the solvent separator in Mode I or Mode II is determined based on operating pressure of the solvent separator.
The operating temperature of the solvent separator must be high enough to provide the required relative volatility to the solvent compounds to evaporate from the production stream 306. In general, at any given operating pressure, the higher the operating temperature, the leaner the second outlet stream 312 from the solvent compounds.

[0117] Table 1 summarizes a non-exhaustive list of some of the socio-economic key criteria for the design and operation of the recovery facility for CSP
process. The final design and operation of the facility may be optimized based on an inclusive evaluation of all key criteria included in Table 1 and beyond.
Table 1: Non-exhaustive list of socio-economic key criteria for the design and operation of a recovery facility for a CSP.
Criteria Mode I Mode ll Single stage flash Single stage flash Single stage flash Two stage flash single stage two stage single stage two stage compression compression compression compression Solvent LOW HIGH LOW HIGH
recovery OPEX (excl.
HIGH HIGH HI GH LOW
GHG) CAPEX MODERATE HIGH LOW LOW
Compression MODERATE HIGH LOW LOW
Duty Heating Duty LOW LOW HIGH HIGH

Date Recue/Date Received 2023-01-16 GHGi (incl.
make-up HIGH MODERATE LOW LOW
solvent)

[0118] As indicated in Table 1, in both mode I and mode II of operation of the solvent separator, the solvent recovery is higher in two stage flash configurations. Mode I of operation requires relatively less heating duty as the solvent separator operates at lower temperature conditions. Mode I of operation requires relatively higher compression duty in the cooling subsystem due to lower operating pressure of the solvent separator.
Subsequently, it results in relatively higher capital and operational expenditures to manufacture the cooling subsystem and operate it, respectively. The electricity demand in mode I is also higher to run the cooling subsystem. In general, the greenhouse emission to process a barrel of the produced fluid in mode I is greater than the greenhouse has emission to process a barrel of the produced fluid in mode II.

[0119] While the applicant's teachings described herein are in conjunction with various embodiments for illustrative purposes, it is not intended that the applicant's teachings be limited to such embodiments as the embodiments described herein are .. intended to be examples. On the contrary, the applicant's teachings described and illustrated herein encompass various alternatives, modifications, and equivalents, without departing from the embodiments described herein, the general scope of which is defined in the appended claims.

Date Re cue/Date Received 2023-01-16

Claims (21)

Claims What is claimed is:

1.
A method of processing a production stream in a recovery facility to collect solvent compounds of the production stream and re-inject the solvent compounds back into a subterranean formation, the production stream being recovered from the subterranean formation after injecting the solvent compounds into the subterranean formation by a cyclic solvent process, the production stream comprising a hydrocarbon liquid phase including heavy oil and the solvent compounds, a gas phase mixture, and a water liquid phase, the method comprising:
a) separating a portion of the solvent compounds present in the production stream in a solvent separator to form a solvent vapor stream comprising the portion of the solvent compounds and a liquid hydrocarbon stream, the separating being performed in multiple stages;
b) processing the solvent vapor stream in a cooling subsystem to condense the portion of the solvent compounds into a liquid for re-injection into the subterranean formation, the condensing being performed in multiple stages; and c) reinjecting the portion of the solvent compounds back into the subterranean formation in a liquid state.

2. The method of claim 1, wherein separating the portion of the solvent compounds present in the production stream includes separating the portion of the solvent compounds by heating the portion of the solvent compounds until the portion of the solvent compounds evaporates.

3. The method of claim 1 or claim 2, wherein separating the portion of the solvent compounds present in the production stream includes separating the portion of the solvent compounds in low pressure and low temperature conditions.

4. The method of claim 1 or claim 2, wherein separating the portion of the solvent compounds present in the production stream includes separating the portion of the solvent compounds in high pressure and high temperature conditions.

Date Recue/Date Received 2023-01-16

5. The method of any one of claims 1 to 4, wherein separating the portion of the solvent compounds present in the production stream is performed in two stages.

6. The method of any one of claims 1 to 4, wherein separating the portion of the solvent compounds present in the production stream is performed in more than two stages.

7. The method of any one of claims 1 to 6, wherein separating the portion of the solvent compounds is performed in a central recovery facility that is dedicated to a plurality of recovery wells.

8. The method of any one of claims 1 to 6, wherein separating the portion of solvent compounds is performed in a set of satellite recovery facilities that are each dedicated to either a recovery well or a group of recovery wells.

9. The method of any one of claims 1 to 8, wherein processing the solvent stream in a cooling subsystem to condense the portion of the solvent compounds into the liquid includes cooling the portion of the solvent compounds, compressing the portion of the solvent compounds and liquefying of the portion of the solvent compounds.

10. The method of any one of claims 1 to 9, wherein processing the solvent stream in a cooling subsystem to condense the portion of the solvent compounds into a liquid is performed in two stages.

11. The method of any one of claims 1 to 9, wherein processing the solvent stream in a cooling subsystem to condense the portion of the solvent compounds for re-injection into the subterranean formation is performed in more than two stages.

12. The method of any one of claims 1 to 11, wherein the solvent separator is operated at a temperature and a pressure to minimize energy requirements of the cooling subsystem.

13. The method of any one of claims 1 to 12, wherein the solvent separator is operated at a temperature and a pressure to minimize greenhouse gas emissions associated with the cyclic solvent process.

Date Recue/Date Received 2023-01-16

14. The method of any one of claims 1 to 13, wherein a portion of the liquid hydrocarbon stream is re-circulated to a field facility.

15. The method of any one of claims 1 to 13, wherein a portion of the production stream is re-circulated to a field facility.

16. The method of any one of claims 1 to 15 further comprising, prior to separating the portion of the solvent compounds present in the production stream in a solvent separator, removing water from the production stream in a primary separator.

17. The method of any one of claims 1 to 15, wherein a portion of the liquid hydrocarbon stream is shipped out to the market.

18. The method of any one of claims 1 to 15, wherein a portion of the liquid hydrocarbon stream is shipped out to another facility for further processing before shipped out to the market.

19. The method of any one of claims 1 to 18, wherein the solvent compounds comprise C2 to C5 hydrocarbons.

20. The method of any one of claims 1 to 18, wherein the reinjected portion of the solvent compounds consists of C2 to C5 hydrocarbons.

21. The method of any one of claims 1 to 20, further comprising processing the solvent vapor stream in a second solvent separator operated at low pressure and low temperature conditions prior to processing the solvent vapor stream in the cooling subsystem.

Date Recue/Date Received 2023-01-16