CA3057120A1

CA3057120A1 - System and method for shortened-path processing of produced fluids and steam generation

Info

Publication number: CA3057120A1
Application number: CA3057120A
Authority: CA
Inventors: Susan Wei Sun; Peter Anthony Ferner
Original assignee: Cenovus Energy Inc
Current assignee: Cenovus Energy Inc
Priority date: 2018-09-28
Filing date: 2019-09-27
Publication date: 2020-03-28
Anticipated expiration: 2039-09-27
Also published as: CA3057120C

Abstract

Disclosed herein is a system for processing fluids produced during in situ hydrocarbon recovery. The system comprises an emulsion-separating sub-system that separates an oil-water emulsion into a produced-oil stream and an oily produced-water stream. The system further comprises a water-treating sub-system that de-oils the oily produced- water stream to provide a treated-water stream. The system further comprises a steam- generating sub-system that generates steam having an average quality of at least about 75 % from an input stream which comprises fluid from the treated-water stream. The system is configured to ensure a specific set of fluid parameters is maintained such that system is operable without requiring a lime softener, an evaporator, an ion-exchanger, and/or addition of a diluent. As such, the system has a reduced footprint and is operable at a location that is remote from a central processing facility. Related methods are also disclosed.

Description

SYSTEM AND METHOD FOR SHORTENED-PATH PROCESSING OF
PRODUCED FLUIDS AND STEAM GENERATION
TECHNICAL FIELD
[0001] The present disclosure generally relates to systems and methods for , processing fluids produced during in-situ hydrocarbon recovery and for generating steam therefrom. In particular, the present disclosure relates to efficient systems and abbreviated processes for treating produced emulsions to facilitate steam generation proximate to a well pad.
BACKGROUND

[0002] Viscous hydrocarbons can be extracted from some subterranean reservoirs using in-situ recovery processes. Some in-situ recovery processes are thermal processes wherein heat energy is introduced to a reservoir to lower the viscosity of hydrocarbons in situ such that they can be recovered from a production well. In some thermal processes, heat energy is introduced by injecting a heated fluid ¨ typically steam, solvent, or a combination thereof¨ into the reservoir by way of an injection well that is situated at a well pad. Steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are representative thermal-recovery processes that use steam to mobilize hydrocarbons in situ. Solvent-aided processes (SAP) and solvent-driven processes (SDP) are representative thermal-recovery processes that use both steam and solvent to mobilize hydrocarbons in situ.

[0003] Regardless of whether a recovery process uses steam alone (e.g.
SAGD/CSS) or in combination with solvent (e.g. SAP/SDP), in situ recovery yields a produced-fluid stream that is likely to contain a mixture of produced water, produced oil, and one or more dissolved or entrained materials derived from the reservoir undergoing the hydrocarbon-recovery process. There are advantages associated with using the produced water as a feedstock for steam generation ¨ namely that the produced water can be recycled during the recovery process thereby increasing system efficiencies and reducing environmental impacts. However, these advantages may be at least partially offset by challenges associated with the recycling process in its conventional form.

[0004] In a conventional produced-water recycling process, the produced-fluid stream is transported from the well pad to a central processing facility where oil-water-separation, water-treatment, and steam-generation processes are completed to provide steam. The steam is then transported back to the well pad for re-injection into the reservoir. Transporting the produced fluids from the well pad to the central processing facility requires infrastructure, which increases system complexity.
Likewise, transporting steam from the central processing facility to the well pad requires infrastructure, which increases system complexity. This complexity is compounded by the need to mitigate against heat-loss during steam transportation.
Accordingly, there is a need for systems/methods that allow for produced-fluid processing and steam generation at or near the well pad. However, central processing facilities remain the de-facto choice among producer companies and industry professionals as well-pad-scale installations based on current technologies are not economically viable.
SUMMARY

[0005] It is generally accepted that large-scale steam generation for hydrocarbon recovery operations necessitates the use of feed water that has been heavily treated to ensure specific water-chemistry parameters are maintained.
In particular, it is widely held that the silica content and the hardness content of a feed-water stream must be lower than about 50 ppm and about 0.5 ppm, respectively, in order to mitigate against unwanted occurrences such as scale accumulation.
However, in view of recent advances in steam-generation technology, the proposition that such restrictive water-chemistry parameters are necessary for large-scale steam generation should be reconsidered. The systems and methods of the present disclosure utilize steam-generation technologies that are capable of large-scale steam generation from feeds that include higher-than-conventionally-acceptable impurity levels. In particular, the systems and methods of the present disclosure utilize such steam-generation technologies in combination with emulsion-treating technologies and de-oiling technologies that are suitable for high-temperature and high-pressure applications. As such, the systems and methods of the present disclosure are based on unique combinations of process components that, taken together and operated in accordance with the teachings of the present disclosure, allow for high-temperature and high-pressure processing of produced fluids and steam generation. By obviating the requirement for fluid-treatment processes that operate under low-temperature/low-pressure conditions, the systems and methods of the present disclosure substantially reduce the complexity and equipment-footprint associated with fluid processing and steam generation. In view of this reduced complexity and footprint, the present disclosure provides systems and methods that are suitable for use at or near a well pad. This provides for further process efficiencies .. by obviating the need for produced-fluid and/or steam-piping infrastructure to/from a central processing facility. Briefly stated, the present disclosure provides for shortened-path fluid processing and steam generation.

[0006] In select embodiments, the present disclosure relates to a system for processing fluids at a location that is proximate to a well pad. The system is for use in the context of a thermal process for recovering hydrocarbons from a subterranean reservoir.

[0007] The system comprises an emulsion-treating sub-system that is operable to separate an oil-water emulsion produced from the subterranean reservoir into a produced-oil stream and an oily produced-water stream. The system is configured to maintain the temperature of the oily produced-water stream above the normal boiling point thereof and to maintain the pressure of the oily produced-water stream above ambient atmospheric pressure. The emulsion-treating sub-system is configured to separate the oil-water emulsion such that the oily produced-water stream has an average residual-oil concentration of less than about 10,000 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm.

[0008] The system further comprises a de-oiling sub-system that is operable to treat the oily produced-water stream to provide a de-oiled-water stream.
The system is configured to maintain the temperature of the de-oiled-water stream above the normal boiling point thereof and to maintain the pressure of the de-oiled-water stream above ambient atmospheric pressure. The de-oiling sub-system is configured to treat the oily produced-water stream such that the de-oiled-water stream has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 PPrn=

[0009] The system further comprises a steam-generating sub-system.
The steam-generating sub-system is operable to generate steam having an average quality of at least about 75 % from an input stream that comprises fluids from the de-oiled-water stream. The input stream has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm. The system is configured to maintain the temperature of the input stream above the normal boiling point thereof and to maintain the pressure of the input stream above ambient atmospheric pressure.

[0010] In select embodiments, the present disclosure relates to a method for processing produced fluids. Likewise, in select embodiments, the present disclosure relates to a method for generating steam from a produced-fluid stream that comprises impurities. Method-related embodiments of the present disclosure are suitable for implementation at a location that is proximate to a well pad.
Method-related embodiments of the present disclosure are for use in the context of a thermal process for recovering hydrocarbons from a subterranean reservoir.

[0011] Method-related embodiments of the present disclosure comprise separating an oil-water emulsion produced from the subterranean reservoir into a produced-oil stream and an oily produced-water stream. The temperature of the oily produced-water stream is maintained above the normal boiling point thereof and the pressure of the oily produced-water stream is maintained above ambient atmospheric pressure. The oily produced-water stream has an average residual-oil concentration of less than about 10,000 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm.

[0012] Method-related embodiments of the present disclosure further comprise de-oiling the oily produced-water stream to provide a de-oiled-water stream. The temperature of the de-oiled-water stream is maintained above the normal boiling point thereof and the pressure of the de-oiled-water stream is maintained above ambient atmospheric pressure. The de-oiled-water stream has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 PPm=

[0013] Method-related embodiments of the present disclosure further comprise generating steam having an average quality of at least about 75 % from an input stream that comprises fluids from the de-oiled-water stream and that has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm.
The temperature of the input stream is maintained above the normal boiling point thereof.
The pressure of the input stream is maintained above ambient atmospheric pressure BRIEF DESCRIPTION OF THE DRAWINGS

[0014] These and other features of the present disclosure will become more apparent in the following description in which reference is made to the appended drawings. The appended drawings illustrate one or more embodiments of the present disclosure by way of example only and are not to be construed as limiting the scope of the present disclosure.

[0015] FIG. 1 is a schematic illustration of a prior art process for separating, treating, and generating steam from a produced-fluid stream.

[0016] FIG. 2 is a schematic illustration of a first shortened-path produced,fluid processing and steam-generation process in accordance with the present disclosure.

[0017] FIG. 3 is a schematic illustration of a second shortened-path produced-fluid processing and steam-generation process in accordance with the present disclosure.

[0018] FIG. 4 is a plot of fluid density as a function of temperature for a water sample and a bitumen sample.
DETAILED DESCRIPTION

[0019] Steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are representative thermal-recovery processes that use steam to mobilize hydrocarbons (e.g. bitumen and/or heavy oil) in situ. Solvent-aided processes (SAP) and solvent-driven processes (SDP) are representative thermal-recovery processes that use both steam and solvent to mobilize hydrocarbons in situ. Regardless of whether a recovery process uses steam alone (e.g. SAGD/CSS) or in combination with solvent (e.g. SAP/SDP), in-situ recovery yields a produced-fluid stream that is likely to contain a mixture of produced water, produced oil, and one or more dissolved or entrained materials derived from the reservoir undergoing the hydrocarbon-recovery process. There are advantages associated with using produced water as a feedstock for steam generation. However, these advantages may be offset by challenges associated with the necessity to treat produced water to obtain treated water that is suitable as a feedstock for steam generation. In particular, recycling produced water typically requires substantial reductions in residual-oil content, silica content, hardness content, total-suspended-solids content, soluble-organics content, and/or turbidity. In thermal hydrocarbon-recovery processes, water treatment is often complex and/or expensive, and water treatment can be challenging to manage, as the composition of a produced-water stream is likely to vary over time.
Furthermore, conventional water-treatment processes are often sub-optimal in that they are designed to function at temperatures and pressures that are substantially lower than those typical of produced water. It is inefficient to cool and de-pressurize produced water for treatment given that high temperatures and high pressures are required for steam generation. In addition, the footprint of conventional water-treatment processes and systems may be substantial.

[0020] FIG. 1 is a schematic illustration of a conventional system 100 for separating, treating, and generating steam from a produced-fluid stream. In the conventional process 100 a produced-fluid steam is received at a well pad and directed to a central processing facility by way of produced-fluid-transport infrastructure 101. At the central processing facility, the produced fluid is subjected to an emulsion-treatment sub-process 102 to provide coarse oil-water separation.
The coarse oil-water separation provides an oily produced-water stream that typically contains residual oil, silica, hardness, suspended solids, and/or solubilized organic compounds, and it is common practice to treat the oily produced-water stream to provide a treated-water stream that is suitable for use as a feedstock for steam generation. Accordingly, the conventional process 100 includes a heat-exchange sub-process 104 to reduce the temperature of the oily produced-water stream to a temperature that it is suitable for a de-oiling sub-process 106 and a water-treatment sub-process 108. Subjecting the produced-water stream to the de-oiling sub-process 106 and the water-treatment sub-process 108 provides a treated-water stream that is then re-heated in a heat-recovery sub-process 110 and input into a steam-generation sub-process 112 to generate steam. The steam is then directed back to the well pad by way of steam-transport infrastructure 114.

[0021] The emulsion treatment sub-process 102 typically involves a number of distinct steps and parameters as follows. Oil-water emulsion from the reservoir may vary in temperature and pressure. For example, the produced-fluid stream may have a temperature between about 80 C and about 250 C (typically between about C and about 220 C) and a pressure of between about 1,200 kPag and about 2,000 kPag. After emulsion is recovered from the reservoir, it may be degassed and then cooled to between about 130 C and about 140 C to allow for diluent-aided separation. The cooled emulsion may then be treated for coarse oil-water separation, for example in a free-water knock out unit, and/or another emulsion treater.
For traditional gravity separation, this typically occurs at a pressure of between about 800 kPag and about 1,500 kPag and at a temperature of between about 130 C and about 140 C. Alternatively, for flash treating (for example), coarse oil-water separation typically occurs at a pressure of between about 100 kPag and about 800 kPag and a temperature of between about 130 C and about 140 C. These conventional emulsion-treating systems typically use a diluent to aid in separation of oil and water.
The diluent is traditionally a pentane rich natural gas liquid or a synthetic crude oil.
The diluent typically remains in the de-watered oil, which is typically cooled and sent to sales oil tanks.

[0022] The heat-exchange sub-process 104 typically involves one or more heat exchangers to decrease the temperature of the oily produced-water stream from between about 130 C and 140 C to a low temperature such as between about 80 C and about 95 C. At the same time, the oily produced-water stream is typically de-pressurized to a low pressure such as atmospheric pressure to accommodate the inlet specifications for the de-oiling sub-process 106 and/or the water-treatment sub-process 108.

[0023] The de-oiling sub-process 106 typically involves passing the oily produced-water stream through a series of units including a skim tank for gravity separation, a flotation unit (such as an induced gas flotation unit or an induced static flotation unit) for further removal of suspended solids, and a filtration unit (such as' an oil-removal filter unit) to provide a de-oiled water stream. The de-oiling sub-process 106 may also include a chemical treatment.

[0024] The water-treatment sub-process 108 typically involves passing the de-oiled-water stream through a lime-softening sub-process and an ion-exchange sub-process to provide the treated-water stream. The lime-softening sub-process increases the pH of the de-oiled water stream by introducing lime thereto.
This serves to remove hardness in the form of calcium and magnesium as carbonate precipitates.
The lime-softening sub-process may also be configured to remove silica to ensure the treated-water stream meets the specifications of the steam-generation sub-process 112. The ion-exchange sub-process may be configured to remove inorganic cations (such as Li, Ca2+, Mg2+, and Fe3+) for similar reasons. For example, typical steam-generation feed streams may be required to contain less than 50 ppm silica, less than 1 ppm hardness, and less than 1 ppm oil so that boiler-manufacturer-recommended parameters (i.e. less than 100 ppm silica oxides and less than 1 ppm hardness as expressed as CaCO3) are adhered to even when accounting for upset conditions.

[0025] The decrease in temperature and pressure of the oily produced-water stream is necessary in conventional systems and processes for several reasons.
For example, operation of the various units (e.g. the skim tank, the induced gas flotation unit and/or the lime softener) at high pressure would be economically unfavorable when compared to operation at atmospheric pressure. As well, a number of the units require lower temperature for effective operation. A significant decrease in temperature of the produced-water stream entering de-oiling is generally understood to be necessary for operational reasons, particularly so that surge capacity may be carried out at atmospheric pressure in tanks.

[0026] In the heat-recovery sub-process 110, the treated-water stream passes through a series of heat exchangers to recover at least some of the enthalpy forfeited during the heat-exchange sub-process 104. The pressure of the treated-water stream is also typically increased through pumping. As such, the treated-water stream is typically pre-conditioned before it is used as a feed stream (i.e. boiler-feed water) for the steam-generation sub-system 112. It will be evident to those skilled in the art that the heat-exchange sub-process 104 and the heat-recovery sub-process 110 typically require substantial investments in equipment and energy input as boiler-feed water is typically input into a steam generator at a temperature of between about and about 200 C.

[0027] The steam-generation sub-system 112 typically involves a number of distinct steps as follows. The pre-heated boiler-feed water typically enters an economizer section, which further heats the boiler-feed water using convection from flue gas, and then the boiler-feed water enters the fired section of the boiler.
Conventional once-through steam generators typically produce steam having a .. quality of between about 75 % and about 90 % at pressures between about 7 MPa and 15 MPa, which is considered as standard in the industry. Optionally, produced steam may be separated into dry steam and a liquid fraction that contains impurities.
The dry steam is typically sent to one or more well pads for use in the reservoir during the hydrocarbon-recovery process. The liquid fraction separated from the generated steam (referred to as boiler blowdown) is typically sent for recycling or disposal.
Steam separation is typical for SAGD but not for all thermal in-situ processes.

[0028] In view of conventional processes such as the one shown in FIG. 1, in the context of the present disclosure it has been determined that there is an unmet need for systems/methods that allow for a shortened path for produced-fluid .. processing and steam generation at or near a well pad (i.e. proximate to a well pad and remote from any central processing facility as discussed, for example, with respect to FIG. 2 and FIG. 3 below). The systems/methods of the present disclosure enable such processing by utilizing a select combination of complementary technologies for emulsion treating, de-oiling, and steam generation. The steam-.. generation technologies are selected based on their capacity to process feeds that include higher-than-conventionally-acceptable impurity levels. Selecting such technologies removes constraints associated with the low-temperature and low-pressure conditions typical of conventional water-treatment processes. The emulsion-treating technologies and the de-oiling technologies are selected to complement the steam-generation technologies in order to leverage the absence of such temperature/pressure constraints. In particular, the emulsion-treating technologies and the de-oiling technologies are selected based on their capacity to process feeds at high temperature and high pressure. As such, the present disclosure provides unique combinations of processing technologies that, when integrated and operated in accordance with particular processing parameters set out herein, provide for efficient systems and abbreviated methods for produced-fluid processing and steam generation. In other words, the present disclosure provides for shortened-path produced-fluid processing and steam generation (herein referred to as shortened-path SAGD (SP-SAGD)). However, those skilled in the art will understand that hydrocarbon recovery technologies other than SAGD, such as those described below, are intended to be incorporated herein. Shortened-path processing and steam generation serves to: (i) reduce the energy input required for steam generation by retaining a substantial amount of the latent heat energy and pressure of the produced fluids throughout the process; (ii) reduce or eliminate the requirement for system additives (such as diluent for oil-water-emulsion separation); (iii) reduce or eliminate the requirement for specific treatment components/steps (such as lime softeners, evaporators, and/or ion exchange units); and/or (iv) reduce the amount of fluid-transport infrastructure required to execute in-situ hydrocarbon recovery.

[0029] In the following section, the efficient systems and abbreviated methods for processing fluids and generating steam proximate to a well pad are described in detail. The following description is for illustrative purposes and is not meant to be limiting in any way. All reference to dimensions, capacities, embodiments, substitutions, modifications, optional features and/or examples throughout this disclosure (including the drawings) should be considered non-limiting and a reference to an illustrative and non-limiting embodiment or an illustrative and non-limiting example. Numerous details are set forth to provide an understanding of the embodiments and examples described herein. The embodiments and examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not described in detail to avoid obfuscating the focus of the present disclosure. All ranges referred to herein are intended to be interpreted as being a reference to all values of the range and should be considered a disclosure of all values within each referred-to range. The description and claims are not to be considered as limited to the scope of the examples described herein.

[0030] As noted above, the systems and methods of the present disclosure are for use in the context of a thermal process for recovering hydrocarbons from a subterranean reservoir. The thermal process may be for example a steam-assisted gravity-drainage (SAGD) process, a cyclic-steam-simulation (CSS) process, a steam-flooding (SF) process, a solvent-assisted-cyclic steam stimulation process, a toe-to-heel-air-injection (THAI) process, a solvent-aided process (SAP), a solvent-driven process (SDP), or a combination thereof (for example occurring at different well pads that feed into fluid handling processes and systems described herein). In embodiments of the present disclosure wherein the hydrocarbon-recovery process involves solvent injection, the produced-fluid stream may comprise solvent.
For example, the produced-fluid stream may have a solvent:water ratio of up to about 1:9 % on a weight basis. Solvent content in the produced-fluid stream may influence the processing parameters used during emulsion treating. In particular, the emulsion-treating sub-system may be configured to capitalize on density differences between oil-based and water-based phases to facilitate separation. As significant solvent content in the produced-fluid stream may impact the density of the oil-based phase, the occurrence of substantial solvent content in the produced-fluid streams may hinder oil-water separation (increasing solvent content may decrease the difference in densities between oil-based and water-based phases). Accordingly, in some embodiments of the present disclosure, solvent may be removed prior to emulsion treating. Those skilled in the art, having benefited from the teachings of the present disclosure, will recognize the modulations required of the emulsion-treating sub-system to account for produced-fluid streams that comprise substantial volumes of solvent and/or the technologies available to separate solvent prior to emulsion treatment.

[0031] In the context of the present disclosure, the produced-fluid stream may be produced at a production temperature that is above 80 C, above 100 C, or in some cases significantly above 100 C, for example being at least 125 C, 150 C, 175 C, 200 C, or 225 C, or being within the range of from about 100 C to 250 C.
.. Typical temperatures for fluids produced during SAGD may for example be between about 150 C and 250 C, while other thermal-recovery processes, such as CSS, may produce fluids at temperatures from about 50 C to 250 C.

[0032] In the context of the present disclosure, the produced-fluid stream may have an oil:water ratio of between about 20:80 and about 90:10, or any ratio between .. these values. Those skilled in the art will recognize that such ratios typically fluctuate during production. In SAGD, this ratio may for example be from about 20:80 to about 35:65. In SAP, this ratio may for example be from about 60:40 to about 90:10, or for example alternatively about 75:25 to about 90:10, depending on the amount of solvent injected. These produced fluids are typically characterized by relatively high levels of dissolved and entrained materials, with the water portion for example being characterized by one or more parameters that may include between about 50 ppm and about 4000 ppm total suspended solids, between about 50 ppm and about 400 ppm silica, between about 5 ppm and about 75 ppm hardness (or alternatively between about 5 ppm and about 225 ppm hardness), and between about 30 ppm and about 1000 ppm soluble organics (measured as total organic carbon), or a combination thereof.

[0033] The systems/methods of the present disclosure comprise an emulsion-treating sub-system that is configured to separate the produced-fluid stream into a produced-oil stream and an oily produced-water stream.

[0034] In select embodiments of the present disclosure, the emulsion-treating sub-system may comprise an upside-down separator. In the upside-down separator, the processing temperature may be maintained at (or heated to) a relatively high level, for example in a range of between about 150 C and about 250 C to provide a lower viscosity and a sufficient density difference between the oil and the water to effect gravity separation. Under such conditions, the hot emulsion may separate with the oil portion being more dense than the water portion, hence the term "upside down". The upside-down separator may be configured as an upside-down treater (UDT). Those skilled in the art will recognize that an upside-down treater is a separator that is configured to provide a produced-oil stream that meets water-content transportation specifications without additional processing.

[0035] In select embodiments of the present disclosure, the emulsion-treating sub-system may comprise a hot-cyclone separator. In the hot-cyclone separator, the produced-fluid stream emulsion may be maintained at (or heated to) a relatively high degree such as a temperature in a range of between about 180 C and about 230 C
to provide a lower viscosity and wider density difference between the oil and the water. This may allow for hot-emulsion separation with the oil portion being heavier than the water portion. The hot-cyclone separator may comprise a hot-hydrocyclone separator, a hot-oleocyclone separator, or a combination thereof (in that the emulsion treating sub-system may involve single or multiple stage separation). Cyclone separators leverage differences in angular velocities of spinning fluids to separate oil and water (cyclones are for example described in the following patent documents:
US 5,017,288; US 5,071,557; and US 5,667,686). The oil-water emulsion may be degassed, prior to or in the absence of heating, and then may be pumped up to a higher pressure such as between about 1,500 kPag and about 2,500 kPag to prevent flashing in the cyclone. The emulsion may then enter the cyclone unit where the difference in density between the oil and the water may cause the heavier product, in this case oil, to coalesce on the outside of the cyclone, with the lighter fluid, in this case water, floating to the inside of the cyclone (in contrast to conventional hydrocyclone separation). The oil may exit the cyclone via the tapered end with the water exiting via the overflow stream outlet. Each phase of the emulsion may require additional cyclonic steps to reach the desired product qualities for further processing, transportation, or disposal. Additionally, pumps may be required to overcome the pressure drop require for each cyclone stage.

[0036] Regardless of whether the emulsion-treating sub-system comprises an upside-down separator or a hot cyclone separator, the emulsion-treating sub-system may reduce or eliminate the need for diluent and may reduce or eliminate the need for treatment chemicals as compared to conventional processes. Such as the one shown in FIG. 1, wherein diluent addition is exemplified by an inlet to the conventional emulsion-treatment process 102.

[0037] Accordingly, the emulsion-treating sub-system may be suitable for use as component in a system for processing remote from a central processing facility.
Moreover, the emulsion-treating sub-system may provide the produced-oil stream with relatively little water inclusion and the oily produced-water stream with relatively little oil inclusion. The produced-oil stream may then be flashed in a flash treater to remove the remaining water to below 0.5 % basic sediment and water while remaining in, for example, the 130 C to 230 C temperature range. At the same time the oily produced-water stream may be maintained by the system at a baseline temperature of, for example, at least about 130 C, 150 C, 160 C, 170 C, 175 C, 180 C, 185 C, 190 C, 195 C, or 200 C in the absence of heating. Heating above this baseline temperature is optional. For example, the oily produced-water stream may be maintained by the system at a temperature of between about 190 C and about C and/or a pressure of between about 1 MPa and about 3.1 MPa. A heater used for heating may be, for example, an electric heater, an induction heater, an infrared heater, a radio-frequency heater, a microwave heater, a natural gas heater, a circulating fluid heater, or a combination thereof. In the absence of this optional heating, the system is to maintain the oily produced-water stream close to or above this baseline temperature. Enthalpy maintenance sub-systems of the system may for example be adapted so that the temperatures and/or pressures maintained in the emulsion-treating sub-system are kept within a particular degree of departure from the temperatures and/or pressures of the produced emulsion, for example within a variation of 20 %, 15 %, 10 % or 5 %. As such, an enthalpy maintenance sub-system may for example include insulation and other fluid handling adaptations that maintain the temperature and/or pressure of fluids within the system.

[0038] The emulsion-treating sub-system may be configured to separate a high proportion of the oil, leaving the oily produced-water stream with a relatively low residual oil concentration, for example of less than about 10,000 ppm (such as less than about 2,000 ppm, in particular between about 10 ppm and about 200 ppm).
The produced-oil stream may correspondingly have a relatively low basic sediment and water (BS&W) content, for example of less than 0.5 % to meet transportation specifications. The oily produced-water stream may be maintained at elevated temperatures and pressures within the system. Dissolved and entrained materials in the oily produced-water stream may be characterized as including: a total-suspended-solids content of at least about 100 ppm; a turbidity of at least about 250 NTU; a turbidity of less than about 1,000 ppm; a silica content of at least about 20 ppm (such as at least about 250 ppm, or between about 50 ppm and about 400 ppm);
a hardness content of at least about 5 ppm (such as at least about 10 ppm, or between about 5 ppm and about 225 ppm); a soluble organics content of between about 30 ppm and about 400 ppm; or a combination thereof. In effect, the dissolved and entrained material that is quantified by these characteristics is segregated predominantly into the oily produced-water stream, as opposed to into the produced-oil stream. The degree of this segregation may be quantified, so that a select proportion of the relevant chemical species segregates into the oily produced-water stream for each of the foregoing parameters. For example, at least 70 %, 75 %, %, 85 %, 90 %, 95 % or 98 % of the total suspended solids, silica, hardness, total organic carbon, or a combination thereof, present in the produced-fluid stream may be segregated into the oily produced-water stream.

[0039] In the context of the present disclosure, the produced-oil stream may be discharged from the system, for example for transportation, upgrading, and/or sales storage. With respect to transportation, the produced-oil stream may be blended and/or processed to meet transportation specifications such as pipeline specifications, railway specifications, truck specifications, or a combination thereof.
Blending and/or processing of the produced-oil steam may occur proximate to the well pad or at a central processing facility. With respect to upgrading, residual heat present in the produced-oil stream may be capitalized on to reduce the energy input required to achieve the elevated temperatures and pressures used to upgrade the produced-oil stream. Upgrading the produced-oil stream may for example involve one or more viscosity and/or density reduction processes, for example involving chemical (e.g., hydrocracking/hydrotreating), thermal (coking/visbreaking) or physical (separation) treatments, such as those involving cavitation (optionally involving reactive co-feeds or conventional or enhanced thermal techniques such as coking or visbreaking; see for example the following patent documents: CA 2,611,251; CA
2,617,985; CA 2,858,705; and CA 2,858,877). At the central processing facility, the produced-oil stream may be fed directly into a partial-upgrading system where it may be heated and fractionated to enhance the process or recover lighter ends or diluent.
Partial upgrading may improve oil properties, for example, density, viscosity, asphaltenes content, total acid number, sulfur content, or a combination thereof, and partial upgrading may be used to help meet oil transportation (e.g., pipeline, truck, and/or railway) specifications. The produced-oil stream may be further heated at the central processing facility to above about 350 C and the oil may be partially upgraded, for instance, by converting longer heavy oil chains into smaller chains.
Those skilled in the art will recognize that such processes may lower the viscosity of the resulting partially-upgraded oil compared to the oil that entered the partial-upgrading system. The oil may then be fractionated and the lighter fractions hydro-polished to reduce olefins below typical pipeline specifications of 1 %.
Partial-upgrading processes may involve cavitation, shearing, thermal cracking and/or catalyst enhanced upgrading (in general terms, including for example mild thermal cracking such as visbreaking or mild coking, which may include enhancements such as the use of shearing, cavitation, or co-reactants).

[0040] In the context of the present disclosure, the oily produced-water may be further de-oiled and/or treated in a de-oiling process to reduce residual-oil content, silica content, hardness content, total-suspended-solids content, soluble-organics content, and/or turbidity. As noted above, conventional processes de-oil and treat water below 100 C, because they rely on equipment that is not amenable to high temperature and/or high pressure processing. As a first example, conventional water-treatment tanks must operate at temperatures below the boiling point of their contents in order to ensure containment. As a second example, conventional hardness-removal technologies (e.g. ion-exchange units) typically rely on hardness removal resins that degrade at higher temperatures. In contrast, the systems/methods of the present disclosure utilize a de-oiling sub-system that is operable at high-temperature and high pressure and that does not require at least some of the additional equipment associated with conventional water treatment (such as the acid tanks and caustic tanks associated with ion-exchange units). As such the de-oiling sub-system of the present disclosure may occupy a modest footprint as compared to a traditional water-treating system at a central processing facility, and the de-oiling sub-system may be modular, portable, and/or upgradable

[0041] In select embodiments of the present disclosure, the de-oiling sub-system comprises a flotation-type unit. Flotation-type units are advantageous in the context of the present disclosure, because flotation is typically performed in vessels that may be designed to operate within a wide range of conditions (including high-temperature and high-pressure conditions). In select embodiments of the present disclosure, the flotation-type unit may be a compact flotation unit (CFU), a traditional multi-stage horizontal flotation unit, a single-stage flotation unit, or a combination thereof. Those skilled in the art will recognize that a compact flotation unit typically comprises a multi-stage (typically vertical) vessel with swirling/cyclonic separation enhancement (see Advances in Compact Flotation Units (CFUs) for Produced Water Treatment by Bhatnagar, M. & Sverdrup, C. J. Offshore Technology Conference Asia held in Kuala Lumpur, Malaysia, 25-28 March 2014 (OTC-24679-MS)). De-oiling via a flotation-type unit may be aided by the addition of a density-reducing agent (i.e. a light hydrocarbon or other chemical agent capable of reducing the density of an oil phase in the oily produce-water stream). The density-reducing agent may be oleophilic and/or hydrophobic such that it forms a single phase with residual oil in the oily produced-water stream. The density-reducing agent may have a density, which is lower than that of the residual oil in the oily-produced water stream such that addition of the density-reducing agent may aid in oil-water separation by increasing the floatability of the oil phase. For example, the density-reducing agent may be a pentane-rich natural gas liquid.

[0042] In select embodiments of the present disclosure, the de-oiling sub-system comprises a filtration-type unit. Filtration-type units are advantageous in the context of the present disclosure, because filtration-type units may be configured to accommodate a wide variety of operating conditions (including high-temperature and high-pressure conditions). In select embodiments of the present disclosure, the filtration-type unit comprises a filter press, a traditional filter, a membrane filter, or a combination thereof. Filtration units are further described in the following patent documents: US 6,180,010; US 5,437,793; US 5,698,139; US 5,837,146; US
5,961,823; and US 7,264,722.

[0043] Regardless of whether the de-oiling sub-system comprises a flotation-type unit or filtration-type unit, the de-oiling sub-system may be configured to de-oil the oily produced-water stream such that the de-oiled water stream has: a residual oil content of less than about 25 ppm (such as less than about 20 ppm, 15 ppm, ppm, or 5 ppm); a total-suspended-solids content of less than about 900 ppm (such as less than 5 ppm, or between about 50 ppm and about 900 ppm); a turbidity of less than about 10 NTU; a silica content of at least 50 ppm (such as between about , ppm and about 400 ppm); a hardness content of at least 5 ppm (such as between about 5 ppm and 225 ppm, in particular between about 5 ppm and about 15 ppm);
a soluble organics content of less than about 700 ppm (such as between about 30 ppm and about 700 ppm, in particular between about 30 ppm and about 400 ppm); or a combination thereof. In select embodiments, the de-oiled water stream may for example have residual total suspended solids, silica, hardness, and total organic carbon values within a preferred degree of variance from the values of the produced water stream, for example within 5 %, 10 %, 15 %, 20 %, 25 % or 30 % of the total suspended solids, silica, hardness, and/or total organic carbon values of the oily produced-water stream.

[0044] In select embodiments of the present disclosure, make-up water may be added to the de-oiled-water stream to produce an input stream for a steam-generating-sub-system. As will be appreciated by those skilled in the art, make-up water may comprise one or more dissolved or entrained materials. For example, brackish make-up water may have a silica content of between about 0.1 ppm and about 200 ppm, a hardness content of between about 10 ppm and about 1000 ppm, and a total-dissolved-solids content of between about 100 ppm and about 15000 ppm.
The make-up water may be combined with the de-oiled-water stream in equipment such as piping, a tank, a vessel, or a combination thereof. Prior to combining the make-up water with the de-oiled-water stream, the make-up water may be processed and/or handled to ensure that the steam-generating-sub-system input stream has average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm. For example, the make-up water may be filtered, exposed to ion exchange, stored in a holding tank or a surge tank, pumped through a heat exchanger to either increase or decrease the make-up water temperature, or a combination thereof.
Heat exchange between the make-up water and at least one of blowdown, sales oil, or other process facility fluid streams may contribute to the energy efficiency of the method of processing fluids as described herein. Alternatively, heat exchange with the make-up water may be facilitated via a glycol system, a cooler, or any other suitable heat exchange process as will be understood by those skilled in the art.

[0045] In the context of the present disclosure, the steam-generating-inlet stream may comprise fluids from the de-oiled-water stream (A) and fluids from the make-up-water stream (B). The volume ratio of these components (A:B) may vary.
For example, the volume ratio (A:B) may be between about 40:60 and about 100:0.
The volume ratio (A:B) may be modulated to accommodate parameters associated with production from the reservoir. In particular, the volume ratio (A:B) may be modulated to account for changes in the steam-to-oil ratio (SOR), the produced-water-to-steam ratio (PWSR), steam quality, or a combination thereof. The volume ratio (A:B) may also be modulated to account for water entrained in the produced-oil stream (intended to maintain water as the continuous phase for transportation to sales oils tanks). For example, for a process providing a SOR of about 1.8, a PWSR
of about 0.95, a steam quality of about 75 %, and a 20 % water diversion to the produced-oil stream, make-up water may account for about 40 % of the steam-generating input stream. As a further example, for a process providing an SOR
of about 3.0, a PWSR of about 1.15, a steam quality of about 75 %, and a 20 %
water diversion to the produced-oil stream, make-up water may account for about 20 %
of the steam-generating input stream. Those skilled in the art will recognize that PWSR
of greater than one may occur when hydrocarbon production is executed on a reservoir that contains substantial amounts of connate water. Those skilled in the art, having benefited from the teachings of the present disclosure will recognize how to achieve a suitable volume ratio (A:B) for the inlet stream in view of the relevant process parameters and having regard to the particular water-chemistry specifications set out herein for the inlet stream to the steam-generating sub-system.
In the context of the present disclosure, the de-oiled-water stream and the steam-generating-sub-system input fluid stream may for example be maintained by the system at a baseline temperature and/or pressure. For example, the base-line temperature may be, for example, at least 100 C, 125 C, 150 C, 160 C, 170 C or 175 C in the absence of heating and the baseline pressure may be, for example, between about 1 MPa and about 3.1 MPa. Optionally, the input stream for the steam-generation sub-system may be heated above the baseline input temperature; in the absence of this optional heating, the system may be constructed and operated so that it maintains the fluids undergoing processing in the fluid handling system above the baseline steam generator input temperature. The enthalpy maintenance sub-systems of the system, for example temperature maintenance systems, such as insulation, and/or pressure containment systems, such as pressure vessels, may for example be adapted so that in the process of producing the input fluid stream, temperatures and/or pressures are maintained within a particular degree of departure from the temperatures and/or pressures of the de-oiling sub-system, for example within a variation of 20 %, 15%, 10% or 5 %.

[0046] In select embodiments of the present disclosure, produced-fluid-recycling efficiencies are provided by the system, so that the volume ratio of oily produced-water stream to the input stream of the steam-generating sub-system is relatively high, representing for example at least 75 %, 80 %, 85 %, 90 % or 95 %
produced water reuse for steam generation. In essence, as much of the oily produced-water stream as practical moves forward for use as the steam generator input fluid stream. Similarly, the system may be adapted to maintain a relatively high ratio of treated water volume to make-up water volume, for example of at least 6:4, 7:3, 8:2 or 9:1, representing for example at least 60 % of the treated water volume being used for steam generation along with 30 % make-up water. The enthalpy maintenance sub-systems of the fluid handling system may be adapted to maintain the steam generator input temperature within a desired range of the produced emulsion temperature, in the absence of optional heating by the system, for example within 50 C, 40 C, 30 C or 20 C.

[0047] In the context of the present disclosure the steam-generating sub-system may comprise any of a variety of steam generating technologies provided the steam-generating sub-system is operable to generate steam having an average quality of at least about 75 % from an input stream that comprises fluid from the de-oiled-water stream, wherein the input stream has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 50 ppm, and an average hardness content of at least about 5 ppm, and wherein:
(i) the system is configured to maintain the temperature of the input stream above the normal boiling point thereof, and (ii) the system is configured to maintain the pressure of the input stream above ambient atmospheric pressure.

[0048] As a first non-limiting example, the steam-generating sub-system may comprise a flash steam generator. The Flash steam generator may be made up of a fired heater and a flash vessel. The steam generator input fluid, which may include de-oiled water and make-up water, may be pumped to high pressures, for example from 10 MPa to 20 MPa, heated to above the desired flash point without creating a steam substantial fraction, for example at about 300 C to 400 C, and flashed in a flash vessel to create a steam fraction, for example of 20 to 40 % steam quality. From this, dry steam may be injected into the reservoir for thermal hydrocarbon-recovery processes, while the remaining liquid fraction (blowdown) may be re-pressurized, filtered, and recombined with the steam generator input fluid stream. In this way, the overall steam-generating process may produce a dry steam fraction for use in hydrocarbon recovery and a liquid blowdown that may be disposed of, or recycled back into the steam generator input fluid stream.

[0049] As a second non-limiting example, the steam-generation sub-system may comprise an ultra-low-quality (ULQ) steam-generation sub-system as describe in Canadian patent application number 2,978,237. ULQ steam-generation sub-systems are capable of operating with feed streams having impurity levels that are orders of magnitude greater than what is traditionally considered feasible by industry and boiler manufacturers due at least in part to their inlet-stream velocities. For example, the inlet stream for a ULQ steam generation sub-system may for example have a silica content of greater than about 150 mg/L and a total hardness of greater than about 10 mg/L. In some embodiments of the present disclosure, the steam portion of the ULQ steam generator outlet stream may be between about 10 % and about 50 % of the outlet stream by mass (i.e. a steam quality of between about 10 %
and about 50 %). In other embodiments the steam portion of the outlet stream may be between about 20 % and about 40 % of the outlet stream by mass. The stream produced at the outlet of the ULQ steam generator may thus be a wet steam stream having a relatively low steam quality. A steam separator may accordingly be provided as part of the ULQ steam-generation sub-system. The steam separator may have an inlet, a steam outlet, and a recirculation-stream outlet. The steam separator may be operable to separate at least a portion of a remaining liquid phase portion from the outlet stream to produce a recirculation stream at the recirculation stream outlet.
Separation of liquid phase portions of the outlet stream increases a mass proportion of the steam portion in the outlet stream at the steam outlet to have an increased steam proportion by mass. A recirculation line may be provided to recirculate a recirculation stream from the recirculation stream outlet back to the steam generator input fluid. The recirculation stream would typically have a temperature above C, and optionally a temperature in a range of about 220 C to about 270 C. A
relatively, high fluid flow rate within the ULQ steam-generation sub-system may be used to provide increased velocity-head values (wherein velocity-head = 1/2pv2 wherein p is fluid density, and v is fluid-flow speed at a point within flow line as used in Bernoulli's equation) within the fluid flow, which may reduce the propensity for impurities in the feedwater to cause scaling within the ULQ steam-generation sub-system. Examples of empirically determined bounds for 1/2pv2 would be a minimum of about 10,000 Ibft-1s-2 and a maximum of about 60,000 1bft-1s-2 (in particular between about 10,000 lbft-15-2 and about 30,000 1bft-1s-2). The operating parameters of flow rate, firing rate, and steam quality are thus selected to operate the ULQ steam-generation sub-system within a desired 1/2pv2range and for a targeted steam production at the steam outlet. When the flow rate at which the feedwater stream is delivered is selected as described, a substantial portion of impurities remain in solution in the liquid phase portion thus reducing scaling within the ULQ
steam-generation sub-system. In some embodiments, the proportion of impurities remaining in solution in the liquid phase may for example be between about 50 % and about 100 % (in particular between about 50 % and about 90 %).

[0050] The steam-generating sub-system may further comprise a recirculation loop to recirculate liquids, vapours, or a combination thereof from an outlet of the steam separator to the input to the steam-generating sub-system.

[0051] Regardless of the particulars of the steam-generation sub-system, the steam may have a quality on the order of at least 75 %, 80 %, 85 %, 90 % or 95 %
steam quality. This steam may then be delivered by the system to a well head for injection into the reservoir, with the fluid handling system constructed and operated so as to preserve steam quality so that the injected steam has a quality within 5 % of the steam quality of the outlet stream of the steam generator or the steam separator, being for example at least 70 %, 75 %, 80 %, 85 % or 90 %. In this context, steam quality refers to an average steam quality over a period of time, for example a day, a week, a month or a year. It will typically be the case that there are intervals within such periods during which steam quality deviates significantly from the average value, for example falling significantly below the average steam quality achieved in processes described herein.

[0052] FIG. 2 is a schematic illustration of a first shortened-path produced-fluid processing and steam-generation process in accordance with the present disclosure.
The shortened-path produced-fluid processing and steam-generation process includes an upside down separator as the emulsion-treating sub-system, a flotation-type unit (e.g. a compact flotation unit (CFU)) as the de-oiling sub-system, and a flash steam generator as the steam generating sub-system. Of course, the steam-generating sub-system may alternatively be a ULQ steam-generation sub-system or any other steam-generation sub-system that is operable to generate steam having an average quality of at least about 75% from an input stream that comprises fluid from .. the de-oiled-water stream, wherein the input stream has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 50 ppm, and an average hardness content of at least about 5 ppm, and wherein:
(i) the system is configured to maintain the temperature of the input stream above the normal boiling point thereof, and (ii) the system is configured to maintain the pressure of the input stream above ambient atmospheric pressure.

[0053] FIG. 3 is a schematic illustration of a second shortened-path produced-fluid processing and steam-generation process in accordance with the present disclosure. The fluid-processing system includes a hot-cyclone separator as the emulsion-treating sub-system, a filtration-type unit as the de-oiling sub-system, and a ULQ steam-generation sub-system as the steam-generating sub-system. Of course, the steam-generating sub-system may alternatively be a flash steam generator or any other steam-generation sub-system that is operable to generate steam having an average quality of at least about 75% from an input stream that comprises fluid from the de-oiled-water stream, wherein the input stream has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 50 ppm, and an average hardness content of at least about ppm, and wherein: (i) the system is configured to maintain the temperature of the input stream above the normal boiling point thereof, and (ii) the system is configured 5 to maintain the pressure of the input stream above ambient atmospheric pressure.

[0054] In select implementations of embodiments of the present disclosure, such as those shown in FIG. 2 and FIG. 3, a demulsifier and/or a reverse emulsion breaker may for example be added upstream of the emulsion-treating sub-system.
In addition, a clarifier may be added to the inlet or oily-produced-water outlet of the emulsion-treating sub-system. A pH adjustment may take place, for example at the inlet of a boiler-feed water surge vessel in the steam-generating sub-system.
For corrosion control, an amine inlet may for example be included in the steam line out of the steam-generating sub-system. For example, amine in liquid or solution form may be stored in a tank and introduced (added) into the steam line by pumping through an injection quill.

[0055] In select implementations of the illustrated processes of FIG.
2 and/or FIG. 3, operating temperatures in the system may be in the range of about 130 C-220 C, throughout the train of treatment steps, with that temperature maintained through the emulsion-treating, de-oiling, and steam-generating sub-processes to ' capitalize on greater fluid density differences at higher processing temperatures. This phenomena is exemplified by the plot illustrated in FIG. 4, which provides empirically determined fluid density values as a function of temperature for 9.40 API raw bitumen and water at 1800 kPa. In the context of FIG. 4, it is apparent that the difference between the fluid density of the water sample and the fluid density of the bitumen increases with increasing temperature beyond an equivalence point at about 130 C.
This may allow the relatively hot emulsion to separate with the oil portion being heavier than the water portion. The emulsion separation may require reduced or no diluent and reduced or no treatment chemicals to produce semi-dry oil and de-oiled produced water streams (for example the process may be carried out without a demulsifier).

[0056] In select embodiments of the present disclosure, the steam generating input fluid stream may be characterized as having an oil and grease content of .. between about 1 ppm and about 5 ppm, a silica content of between about 100 ppm and about 250 ppm, and a hardness content of between about 15 ppm and about ppm.

[0057] In select embodiments of the present disclosure, a surge vessel may be used to dampen changing flow rates of steam generator input fluid into the steam-generating sub-system. The boiler-feed water (which may include both treated water and make-up water) may be pumped to high pressures, for example from 10 MPag to 20 MPag, heated to above the desired flash point without creating a steam fraction at about 300 C to 400 C, and flashed in a flash vessel to create a steam fraction of between about 20 % and about 40 % steam quality. This dry steam may be injected .. into the reservoir for thermal hydrocarbon-recovery processes, while a portion of the remaining liquid fraction (i.e. blowdown) may be re-pressurized, filtered, and recombined with the boiler-feed-water stream. The overall steam-generation process will produce a dry steam fraction for use in hydrocarbon recovery and a liquid blowdown that may be disposed of.

[0058] In alternative embodiments of the present disclosure, solvents (for example, propane or butane) may be injected into the steam-generating and handling systems associated with the facilities described herein, to aid in the thermal hydrocarbon-recovery process via, for example, co-injection of a solvent with steam in a solvent-aided process (SAP). Solvent may for example be co-injected with steam into an injection well, and this solvent may be added to injection fluids within the systems disclosed herein. In this way, a thermal recovery fluid is provided that comprises a solvent. Propane, butane, or alternative solvents may be supplied directly for a SAP (e.g. from a solvent bullet). In alternative embodiments, the solvent may for example be a light hydrocarbon solvent, selected on the basis that it is miscible with, and capable of enhancing the mobility of, the reservoir hydrocarbons.
As such, the solvent may be deployed as a mobilizing fluid, comprising for example one or more C3 through Cio linear, branched, or cyclic alkanes, alkenes, or alkynes, in substituted or unsubstituted form, or other aliphatic or aromatic compounds. Select embodiments may for example use an n-alkane as the dominant component, for example propane or n-butane.

[0059] In the present disclosure, all terms referred to in singular form are meant to encompass plural forms of the same. Likewise, all terms referred to in plural form are meant to encompass singular forms of the same. Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure pertains.

[0060] In the context of the present application, various terms are used in accordance with what is understood to be the ordinary meaning of those terms.
For example, "petroleum" is a naturally occurring mixture consisting predominantly of hydrocarbons in the gaseous, liquid or solid phase. In the context of the present application, the words "petroleum" and "hydrocarbon" are used to refer to mixtures of widely varying composition. The production of petroleum from a reservoir necessarily involves the production of hydrocarbons, but is not limited to hydrocarbon production and may include, for example, trace quantities of metals (e.g. Fe, Ni, Cu, and/or V).
Similarly, processes that produce hydrocarbons from a well will generally also produce petroleum fluids that are not hydrocarbons. In accordance with this usage, a process for producing petroleum or hydrocarbons is not necessarily a process that produces exclusively petroleum or hydrocarbons, respectively. "Fluids", such as petroleum fluids, include both liquids and gases. Natural gas is the portion of petroleum that exists either in the gaseous phase or in solution in crude oil in natural underground reservoirs, and which is gaseous at atmospheric conditions of pressure and temperature. Natural gas may include amounts of non-hydrocarbons.

[0061] It is common practice to categorize petroleum substances of high viscosity and density into two categories, "heavy oil" and "bitumen". For example, some sources define "heavy oil" as a petroleum that has a mass density of greater than about 900 kg/m3. Bitumen is sometimes described as that portion of petroleum that exists in the semi-solid or solid phase in natural deposits, with a mass density greater than about 1,000 kg/m3 and a viscosity greater than 10,000 centipoise (cP;
or 10 Pa's) measured at original temperature in the deposit and atmospheric pressure on a gas-free basis. Although these terms are in common use, references to heavy oil and bitumen represent categories of convenience, and there is a continuum of properties between heavy oil and bitumen. Accordingly, references to heavy oil and/or bitumen herein include the continuum of such substances, and do not imply the existence of some fixed and universally recognized boundary between the two substances. In particular, the term "heavy oil" includes within its scope all "bitumen"
including hydrocarbons that are present in semi-solid or solid form.

[0062] A "reservoir" is a subsurface formation containing one or more natural accumulations of moveable petroleum, which are generally confined by relatively impermeable rock or other geological feature. An "oil sand" or "oil sands"
reservoir is generally comprised of strata of sand or sandstone containing petroleum.
"Thermal recovery" or "thermal stimulation" refers to enhanced oil recovery techniques that involve delivering thermal energy to a petroleum resource, for example to a heavy oil reservoir. There are a significant number of thermal recovery techniques other than SAGD, such as cyclic steam stimulation (CSS), Solvent-aided processes (SAP), solvent-driven processes (SDP), in-situ combustion, hot water flooding, steam flooding and electrical heating. In general, thermal energy and/or a viscosity-reducing agent is provided to reduce the viscosity of the petroleum to facilitate production. This thermal energy may be provided by a "thermal recovery fluid", which is accordingly a fluid that carries thermal energy, for example in the form of steam or solvents or mixtures thereof, with or without additives such as surfactants.

=

[0063] As used herein, the term "about" refers to an approximately +/-10 %
variation from a given value. It is to be understood that such a variation is always included in any given value provided herein, whether or not it is specifically referred to.

[0064] It should be understood that the compositions and methods are described in terms of "comprising," "containing," or "including" various components or steps, the compositions and methods can also "consist essentially of or "consist of the various components and steps. Moreover, the indefinite articles "a" or "an," as used in the claims, are defined herein to mean one or more than one of the element that it introduces.

[0065] For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, "from about a to about b," or, equivalently, "from approximately a to b," or, equivalently, "from approximately a-b") disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.

[0066] Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual embodiments are discussed, the disclosure covers all combinations of all those embodiments.
Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

[0067] Many obvious variations of the embodiments set out herein will suggest themselves to those skilled in the art in light of the present disclosure.
Such obvious variations are within the full intended scope of the appended claims.

Claims

Claims:

1. A system for processing fluids, the system being integrated with a thermal process for recovering hydrocarbons from a subterranean reservoir, the system comprising:
an emulsion-treating sub-system that is proximate to a well pad and that is operable to separate an oil-water emulsion produced at the well pad from the subterranean reservoir into a produced-oil stream and an oily produced-water stream that has an average residual-oil concentration of less than about 10,000 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about ppm, wherein: (i) the system is configured to maintain the temperature of the oily produced-water stream above the normal boiling point thereof, and (ii) the system is configured to maintain the pressure of the oily produced-water stream above ambient atmospheric pressure;
a de-oiling sub-system that is proximate to the well pad and that is operable to de-oil the oily produced-water stream to provide a de-oiled-water stream that has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm, wherein: (i) the system is configured to maintain the temperature of the de-oiled-water stream above the normal boiling point thereof, and (ii) the system is configured to maintain the pressure of the de-oiled-water stream above ambient atmospheric pressure; and a steam-generating sub-system that is proximate to the well pad and that is operable to generate steam having an average quality of at least about 75%
from an input stream that comprises fluid from the de-oiled-water stream, wherein the input stream has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 50 ppm, and an average hardness content of at least about 5 ppm, and wherein: (i) the system is configured to maintain the temperature of the input stream above the normal boiling point thereof, and (ii) the system is configured to maintain the pressure of the input stream above ambient atmospheric pressure.

2. The system of claim 1, wherein the average silica content of the oil-water emulsion is at least about 20 ppm and the average hardness content of the oil-water emulsion is at least about 5 ppm.

3. The system of claim 1 or 2, wherein the average silica content of the oil-water emulsion is between about 50 ppm and about 400 ppm.

4. The system of any one of claims 1 to 3, wherein the average silica content of the oil-water emulsion is between about 100 ppm and about 300 ppm.

5. The system of any one of claims 1 to 4, wherein the average hardness content of the oil-water emulsion is between about 5 ppm and about 225 ppm.

6. The system of any one of claims 1 to 5, wherein the average hardness content of the oil-water emulsion is between about 5 ppm and about 75 ppm.

7. The system of any one of claims 1 to 6, wherein the oil-to-water ratio of the oil-water emulsion is between about 20:80 and about 90:10.

8. The system of any one of claims 1 to 7, wherein the oil-to-water ratio of the oil-water emulsion is between about 20:80 and about 35:65.

9. The system of any one of claims 1 to 8, wherein the oil-to-water ratio of the oil-water emulsion is between about 60:40 and about 90:10.

10. The system of any one of claims 1 to 9, wherein the average temperature of the oil-water emulsion is between about 100 °C and about 250 °C.

11. The system of any one of claims 1 to 10, wherein the average temperature of the oil-water emulsion is between about 130 °C and about 230 °C.

12. The system of any one of claims 1 to 11, wherein the average temperature of the oil-water emulsion is between about 170 °C and about 230 °C.

13. The system of any one of claims 1 to 12, wherein the oil-water emulsion has an average pressure of between about 1 MPa and about 3.1 MPa.

14. The system of any one of claims 1 to 13, wherein the oil-water emulsion comprises a solvent.

15. The system of claim 14, wherein at least a portion of the solvent is removed before the oil-water emulsion enters the emulsion-treating sub-system.

16. The system of any one of claims 1 to 15, wherein the average silica content of the oily produced-water stream is between about 50 ppm and about 400 ppm.

17. The system of any one of claims 1 to 16, wherein the average silica content of the oily produced-water stream is between about 100 ppm and about 300 ppm.

18. The system of any one of claims 1 to 17, wherein the average hardness content of the oily produced-water stream is between about 5 ppm and about 225 ppm.

19. The system of any one of claims 1 to 18, wherein the average hardness content of the oily produced-water stream is between about 5 ppm and about 75 ppm.

20. The system of any one of claims 1 to 19, wherein the average residual-oil content of the oily produced-water stream is less than about 2,000 ppm.

21. The system of any one of claims 1 to 20, wherein the average residual-oil content of the oily produced-water stream is between about 10 ppm and about 2,000 ppm.

22. The system of any one of claims 1 to 21, wherein the average temperature of the oily produced-water stream is between about 100 °C and about 250 °C.

23. The system of any one of claims 1 to 22, wherein the average temperature of the oily produced-water stream is between about 130 °C and about 230 °C.

24. The system of any one of claims 1 to 23, wherein the average temperature of the oily produced-water stream is between about 170 °C and about 230 °C.

25. The system of any one of claims 1 to 24, wherein the average pressure of the oily produced-water stream is between about 1 MPa and about 3.1 MPa.

26. The system of any one of claims 1 to 25, wherein the average silica content of the de-oiled-water stream is between about 50 ppm and about 400 ppm.

27. The system of any one of claims 1 to 26, wherein the average silica content of the de-oiled-water stream is between about 100 ppm and about 300 ppm.

28. The system of any one of claims 1 to 27, wherein the average hardness content of the de-oiled-water stream is between about 5 ppm and about 225 ppm.

29. The system of any one of claims 1 to 28, wherein the average hardness content of the de-oiled-water stream is between about 5 ppm and about 75 ppm.

30. The system of any one of claims 1 to 29, wherein the average residual-oil content of the de-oiled-water stream is less than about 20 ppm.

31. The system of any one of claims 1 to 30, wherein the average residual-oil content of the de-oiled-water stream is less than about 10 ppm.

32. The system of any one of claims 1 to 31, wherein the average temperature of the de-oiled-water stream is between about 100 °C and about 250 °C.

33. The system of any one of claims 1 to 32, wherein the average temperature of the de-oiled-water stream is between about 130 °C and about 230 °C.

34. The system of any one of claims 1 to 33, wherein the average temperature of the de-oiled-water stream is between about 170 °C and about 230 °C.

35. The system of any one of claims 1 to 34, wherein the average pressure of the de-oiled-water stream is between about 1 MPa and about 3.1 MPa.

36. The system of any one of claims 1 to 35, wherein the average silica content of the input stream is between about 50 ppm and about 400 ppm.

37. The system of any one of claims 1 to 36, wherein the average silica content of the input stream is between about 100 ppm and about 300 ppm.

38. The system of any one of claims 1 to 37, wherein the average hardness content of the input stream is between about 5 ppm and about 225 ppm.

39. The system of any one of claims 1 to 38, wherein the average hardness content of the input stream is between about 5 ppm and about 75 ppm.

40. The system of any one of claims 1 to 39, wherein the average residual-oil content of the input stream is less than about 20 ppm.

41. The system of any one of claims 1 to 40, wherein the average residual-oil content of the input stream is less than about 10 ppm.

42. The system of any one of claims 1 to 41, wherein the average temperature of the input stream is between about 100 °C and about 250 °C.

43. The system of any one of claims 1 to 42, wherein the average temperature of the input stream is between about 130 °C and about 230 °C.

44. The system of any one of claims 1 to 43, wherein the average temperature of the input stream is between about 170 °C and about 230 °C.

45. The system of any one of claims 1 to 44, wherein the average pressure of the input stream is between about 1 MPa and about 3.1 MPa.

46. The system of any one of claims 1 to 45, wherein the average residual-oil content of the input stream is less than about 20 ppm.

47. The system of any one of claims 1 to 46, wherein the average residual-oil content of the input stream is less than about 10 ppm.

48. The system of any one of claims 1 to 47, wherein the average temperature of the input stream is between about 100 °C and about 250 °C.

49. The system of any one of claims 1 to 48, wherein the average temperature of the input stream is between about 130 °C and about 230 °C.

50. The system of any one of claims 1 to 49, wherein the average temperature of the input stream is between about 170 °C and about 230 °C.

51. The system of any one of claims 1 to 50, wherein the average pressure of the input stream is between about 1 MPa and about 3.1 MPa.

52. The system of any one of claims 1 to 51, wherein the input stream further comprises fluids from a make-up-water stream.

53. The system of claim 52, wherein the average silica content of the make-up-water stream is between about 50 ppm and about 400 ppm.

54. The system of claim 52 or 53, wherein the average silica content of the make-up-water stream is between about 100 ppm and about 300 ppm.

55. The system of any one of claims 52 to 54, wherein the average hardness content the make-up-water stream is between about 5 ppm and about 225 ppm.

56. The system of any one of claims 52 to 55, wherein the average hardness content the make-up-water stream is between about 5 ppm and about 75 ppm.

57. The system of any one of claims 52 to 56, wherein the average temperature of the make-up-water stream is between about 100 °C and about 250 °C.

58. The system of any one of claims 52 to 57, wherein the average temperature of the make-up-water stream is between about 130 °C and about 230 °C.

59. The system of any one of claims 52 to 58, wherein the average temperature of the make-up-water stream is between about 170 °C and about 230 °C.

60. The system of any one of claims 52 to 59, wherein the average pressure of the make-up-water stream is between about 1 MPa and about 3.1 MPa.

61. The system of any one of claims 52 to 60, wherein the ratio of the fluids from the de-oiled-water stream to the fluids from the make-up-water stream in the input stream is between about 40:60 and about 100:0 on a volume basis.

62. The system of any one of claims 52 to 61, wherein the ratio of the fluids from the de-oiled-water stream to the fluids from the make-up-water stream in the input stream is between about 50:50 and about 80:20 on a volume basis.

63. The system of any one of claims 52 to 62,wherein the ratio of the fluids from the de-oiled-water stream to the fluids from the make-up-water stream in the input stream is modulated in response to variations in steam-to-oil ratio, produced-water-to-steam ratio, steam quality, or a combination thereof.

64. The system of any one of claims 52 to 63, wherein the ratio of the fluids from the de-oiled-water stream to the fluids from the make-up-water stream in the input stream is modulated in response to variations in the amount of water entrained in the produced-oil stream.

65. The system of any one of claims 1 to 64, wherein the emulsion-treating sub-system comprises an upside-down separator.

66. The system of claim 65, wherein the upside-down separator comprises an upside-down treater.

67. The system of any one of claims 1 to 64, wherein the emulsion-treating sub-system comprises a hot-cyclone separator.

68. The system claim 67, wherein the hot-cyclone separator comprises a hot-hydrocyclone separator, a hot-oleocyclone separator, or a combination thereof.

69. The system of any one of claims 1 to 68, wherein the emulsion-treating sub-system is configured to provide the produced-oil stream and the oily produced-water stream in the absence of a diluent, a chemical additive, or a combination thereof.

70. The system of any one of claims 1 to 69, wherein the de-oiling sub-system comprises a flotation-type unit.

71. The system of claim 70, wherein the flotation-type unit comprises a compact flotation unit, a traditional multi-stage horizontal flotation unit, a single-stage floatation unit, or a combination thereof.

72. The system of any one of claims 1 to 69, wherein the de-oiling sub-system comprises a filtration-type unit.

73. The system of claim 72, wherein the filtration-type unit comprises a filter press, a traditional filter, a membrane filter, or a combination thereof.

74. The system of any one of claims 1 to 73, wherein the de-oiling sub-system is configured to receive a density-reducing agent and to use the density-reducing agent to facilitate the separation of the residual oil content from the oily produced-water stream.

75. The system of any one of claims 1 to 74, wherein the steam-generating sub-system comprises a flash steam generator.

76. The system of any one of claims 1 to 74, wherein the steam-generating sub-system comprises an ultra-low-quality steam generator

77. The system of claim 76, wherein the input stream to the ultra-low-quality steam generator has a .rho.v2-valueof between about 10,000 Ibft-1s-2 and about 60,000 lbft-1s-2, wherein.rho. is fluid density and v is fluid flow speed at a point within flow line

78 The system of any one of claims 1 to 74, wherein the steam-generating sub-system further comprises a steam separator.

79. The system of claim 78, wherein the steam-generating sub-system further comprises a recirculation loop to recirculate liquids, vapours, or a combination thereof from an outlet of the steam separator to the input to the steam-generating sub-system

80. The system of any one of claims 1 to 79, wherein the quality of the steam is at least about 85 %

81 The system of any one of claims 1 to 80, wherein the quality of the steam is at least about 95 %.

82. The system of any one of claims 1 to 81, wherein the system further comprises a heater to heat the oil-water emulsion, the oily produced-water stream, the produced-oil stream, the de-oiled-water stream, the input stream, or a combination thereof

83. The system of claim 82, wherein the heater comprises an electric heater, an induction heater, an infrared heater, a radio-frequency heater, a microwave heater, a natural gas heater, a circulating fluid heater, or a combination thereof

84 The system of any one of claims 1 to 83, wherein the system further comprises an enthalpy-maintenance sub-system to maintain the enthalpy of the oil-water emulsion, the oily produced-water stream, the produced-oil stream, the de-oiled-water stream, the input stream, or a combination thereof

85. The system of claim 84, wherein the enthalpy-maintenance sub-system further comprises, an insulator, a heat exchanger, or a combination thereof.

86 The system of any one of claims 1 to 85, wherein the average temperature of the input stream is within about 50 °C of the average temperature of the oil-water emulsion.

87. The system of any one of claims 1 to 86, wherein the average temperature of the input stream is within about 40 °C of the average temperature of the oil-water emulsion

88. The system of any one of claims 1 to 87, wherein the average temperature of the input stream is within about 30 °C of the average temperature of the oil-water emulsion

89 The system of any one of claims 1 to 88, which operates in the absence of a lime softener, an evaporator, an ion exchanger, or a combination thereof

90. The system of any one of claims 1 to 89, Wherein the recovery process comprises a steam-assisted gravity-drainage process, a cyclic-steam-simulation process, a steam-flooding process, a solvent-assisted-cyclic steam stimulation process, a toe-to-heel-air-injection process, a solvent-aided process, a solvent-driven process, or a combination thereof.

91 A method for processing fluids at a location that is proximate to a well pad, as part of a thermal process for recovering hydrocarbons from a subterranean reservoir, the method comprising:
separating an oil-water emulsion produced from the subterranean reservoir into a produced-oil stream and an oily produced-water stream that has an average residual-oil concentration of less than about 10,000 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm, wherein: (i) the temperature of the oily produced-water stream is maintained above the normal boiling point thereof, and (ii) the pressure of the oily produced-water stream is maintained above ambient atmospheric pressure;
de-oiling the oily produced-water stream to provide a de-oiled-water stream that has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about ppm, wherein: (i) the temperature of the de-oiled-water stream is maintained above the normal boiling point thereof, and (ii) the pressure of the de-oiled-water stream is maintained above ambient atmospheric pressure; and operating a steam-generating sub-system to generate steam having an average quality of at least about 75 % from an input stream that comprises fluids from the de-oiled-water stream and that has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm, wherein: (i) the temperature of the input stream is maintained above the normal boiling point thereof, and (ii) the pressure of the input stream is maintained above ambient atmospheric pressure.

92. A
method for generating steam from a fluid source that comprises impurities, at a location that is proximate to a well pad, as part of a thermal process for recovering hydrocarbons from a subterranean reservoir, the method comprising:
separating an oil-water emulsion produced from the subterranean reservoir into a produced-oil stream and an oily produced-water stream that has an average residual-oil concentration of less than about 10,000 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm, wherein: (i) the temperature of the oily produced-water stream is maintained above the normal boiling point thereof, and (ii) the pressure of the oily produced-water stream is maintained above ambient atmospheric pressure;
de-oiling the oily produced-water stream to provide a de-oiled-water stream that has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm, wherein: (i) the temperature of the de-oiled-water stream is maintained above the normal boiling point thereof, and (ii) the pressure of the de-oiled-water stream is maintained above ambient atmospheric pressure; and operating a steam-generating sub-system to generate steam having an average quality of at least about 75 % from an input stream that comprises fluids from the de-oiled-water stream and that has an average residual-oil concentration of less than about 25 ppm, an average silica content of at least about 20 ppm, and an average hardness content of at least about 5 ppm, wherein: (i) the temperature of the input stream is maintained above the normal boiling point thereof, and (ii) the pressure of the steam-generating-sub-system input stream is maintained above ambient atmospheric pressure.

93. The method of claim 91 or 92, wherein the average silica content of the oil-water emulsion is at least about 20 ppm and the average hardness content of the oil-water emulsion is at least about 5 ppm.

94. The method of any one of claims 91 to 93, wherein the average silica content of the oil-water emulsion is between about 50 ppm and about 400 ppm.

95. The method of any one of claims 91 to 94, wherein the average silica content of the oil-water emulsion is between about 100 ppm and about 300 ppm.

96. The method of any one of claims 91 to 95, wherein the average hardness content of the oil-water emulsion is between about 5 ppm and about 225 ppm.

97. The method of any one of claims 91 to 96, wherein the average hardness content of the oil-water emulsion is between about 5 ppm and about 75 ppm.

98. The method of any one of claims 91 to 97, wherein the oil-to-water ratio of the oil-water emulsion is between about 20:80 and about 90:10.

99. The method of any one of claims 91 to 98, wherein the oil-to-water ratio of the oil-water emulsion is between about 20:80 and about 35:65.

100. The method of any one of claims 91 to 99, wherein the oil-to-water ratio of the oil-water emulsion is between about 60:40 and about 90:10.

101. The method of any one of claims 91 to 100, wherein the average temperature of the oil-water emulsion is between about 100 °C and about 250 °C.

102. The method of any one of claims 91 to 101, wherein the average temperature of the oil-water emulsion is between about 130 °C and about 230 °C.

103. The method of any one of claims 91 to 102, wherein the average temperature of the oil-water emulsion is between about 170 °C and about 230 °C.

104. The method of any one of claims 91 to 103, wherein the average pressure of the oil-water emulsion is between about 1 MPa and about 3.1 MPa.

105. The method of any one of claims 91 to 104, wherein the oil-water emulsion comprises a solvent.

106. The method of claim 105, wherein at least a portion of the solvent is removed prior to the separating of the oil-water emulsion into the produced-oil stream and the oily produced-water stream.

107. The method of any one of claims 91 to 106, wherein the average silica content of the oily produced-water stream is between about 50 ppm and about ppm.

108. The method of any one of claims 91 to 107, wherein the average silica content of the oily produced-water stream is between about 100 ppm and about ppm.

109. The method of any one of claims 91 to 108, wherein the average hardness content of the oily produced-water stream is between about 5 ppm and about 225 ppm.

110. The method of any one of claims 91 to 109, wherein the average hardness content of the oily produced-water stream is between about 5 ppm and about 75 ppm.

111. The method of any one of claims 91 to 110, wherein the average residual-oil content of the oily produced-water stream is less than about 2,000 ppm.

112. The method of any one of claims 91 to 111, wherein the average residual-oil content of the oily produced-water stream is between about 10 ppm and about 2,000 ppm.

113. The method of any one of claims 91 to 112, wherein the average temperature of the oily produced-water stream is between about 100 °C
and about 250 °C.

114. The method of any one of claims 91 to 113, wherein the average temperature of the oily produced-water stream is between about 130 °C
and about 230 °C.

115. The method of any one of claims 91 to 114, wherein the average temperature of the oily produced-water stream is between about 170 °C
and about 230 °C.

116. The method of any one of claims 91 to 115, wherein the average pressure of the oily produced-water stream is between about 1 MPa and about 3.1 MPa.

117. The method of any one of claims 91 to 116, wherein the average silica content of the de-oiled-water stream is between about 50 ppm and about 400 ppm.

118. The method of any one of claims 91 to 117, wherein the average silica content of the de-oiled-water stream is between about 100 ppm and about 300 ppm.

119. The method of any one of claims 91 to 118, wherein the average hardness content of the de-oiled-water stream is between about 5 ppm and about 225 ppm.

120. The method of any one of claims 91 to 119, wherein the average hardness content of the de-oiled-water stream is between about 5 ppm and about 75 ppm.

121. The method of any one of claims 91 to 120, wherein the average residual-oil content of the de-oiled-water stream is less than about 20 ppm.

122. The method of any one of claims 91 to 121, wherein the average residual-oil content of the de-oiled-water stream is less than about 10 ppm.

123. The method of any one of claims 91 to 122, wherein the average temperature of the de-oiled-water stream is between about 100 °C and about 250 °C.

124 The method of any one of claims 91 to 123, wherein the average temperature of the de-oiled-water stream is between about 130 °C and about 230 °C.

125. The method of any one of claims 91 to 124, wherein the average temperature of the de-oiled-water stream is between about 170 °C and about 230 °C.

126. The method of any one of claims 91 to 125, wherein the average pressure of the de-oiled-water stream is between about 1 MPa and about 3.1 MPa.

127. The method of any one of claims 91 to 126, wherein the average silica content of the input stream is between about 50 ppm and about 400 ppm.

128. The method of any one of claims 91 to 127, wherein the average silica content of the input stream is between about 100 ppm and about 300 ppm.

129. The method of any one of claims 91 to 128, wherein the average hardness content of the input stream is between about 5 ppm and about 225 ppm.

130. The method of any one of claims 91 to 129, wherein the average hardness content of the input stream is between about 5 ppm and about 75 ppm.

131. The method of any one of claims 91 to 130, wherein the average residual-oil content of the input stream is less than about 20 ppm.

132. The method of any one of claims 91 to 131, wherein the average residual-oil content of the input stream is less than about 10 ppm.

133. The method of any one of claims 91 to 132, wherein the average temperature of the input stream is between about 100 °C and about 250 °C.

134. The method of any one of claims 91 to 133, wherein the average temperature of the input stream is between about 130 °C and about 230 °C.

135. The method of any one of claims 91 to 134, wherein the average temperature of the input stream is between about 170 °C and about 230 °C.

136. The method of any one of claims 91 to 135, wherein the average pressure of the input stream is between about 1 MPa and about 3.1 MPa.

137. The method of any one of claims 91 to 136, wherein the average residual-oil content of the input stream is less than about 20 ppm.

138. The method of any one of claims 91 to 137, wherein the average residual-oil content of the input stream is less than about 10 ppm.

139. The method of any one of claims 91 to 138, herein the average temperature of the input stream is between about 100 °C and about 250 °C.

140 The method of any one of claims 91 to 139, wherein the average temperature of the input stream is between about 130 °C and about 230 °C.

141. The method of any one of claims 91 to 140, wherein the average temperature of the input stream is between about 170 °C and about 230 °C.

142 The method of any one of claims 91 to 141, wherein the average pressure of the input stream is between about 1 MPa and about 3.1 MPa.

143 The method of any one of claims 91 to 142, wherein the input stream further comprises fluids from a make-up-water stream

144 The method of claim 143, wherein the make-up-water stream has average silica content of between about 50 ppm and about 400 ppm.

145 The method of claim 143 or 144, wherein the average silica content of the make-up-water stream is between about 100 ppm and about 300 ppm.

146. The method of any one of claims 143 to 145, wherein the average hardness content of the make-up-water stream is between about 5 ppm and about 225 ppm.

147 The method of any one of claims 143 to 146, wherein the average hardness content the make-up-water stream is between about 5 ppm and about 75 ppm

148 The method of any one of claims 143 to 147, wherein the average temperature of the make-up-water stream is between about 100 °C and about 250 °C.

149. The method of any one of claims 143 to 148, wherein the average temperature of the make-up-water stream is between about 130 °C and about 230 °C.

150. The method of any one of claims 143 to 149, wherein the average temperature of the make-up-water stream is between about 170 °C and about 230 °C.

151. The method of any one of claims 143 to 150, wherein the average pressure of the make-up-water stream is between about 1 MPa and about 3 1 MPa

152. The method of any one of claims 143 to 151, wherein the ratio of the fluids from the de-oiled-water stream to the fluids from the make-up-water stream in the input stream is between about 40.60 and about 100.0 on a volume basis

153 The method of any one of claims 143 to 152, wherein the ratio of the fluids from the de-oiled-water stream to the fluids from the make-up-water stream in the input stream is between about 50:50 and about 80 20 on a volume basis.

154. The method of any one of claims 143 to 153, wherein the ratio of the fluids from the de-oiled-water stream to the fluids from the make-up-water stream in the input stream is modulated in response to variations in steam-to-oil ratio, produced-water-to-steam ratio, steam quality, or a combination thereof.

155 The method of any one of claims 143 to 154, wherein the ratio of the fluids from the de-oiled-water stream to the fluids from the make-up-water stream in the input stream is modulated in response to variations in amount of water entrained in the produced-oil stream.

156 The method of any one of claims 91 to 155, wherein the separating of the oil-water emulsion to the produced-oil stream and the oily produced-water stream occurs in an emulsion-treating sub-system

157 The method of claim 156, wherein the emulsion-treating sub-system comprises an upside-down separator

158. The method of claim 157, wherein the upside-down separator comprises an upside-down treater.

159 The method of claim 156, wherein the emulsion-treating sub-system comprises a hot-cyclone separator

160. The method of claim 159, wherein the hot-cyclone separator comprises a hot-hydrocyclone separator, a hot-oleocyclone separator, or a combination thereof.

161. The method of any one of claims 156 to 160, wherein the emulsion-treating sub-system is configured to provide the produced-oil stream and the oily produced-water stream in the absence of a diluent, a chemical additive, or a combination thereof.

162. The method of any one of claims 91 to 161, wherein the de-oiling of the oily produced water stream occurs in a de-oiling sub-system that comprises a flotation-type unit.

163. The method of claim 162, wherein the flotation-type unit comprises a compact flotation unit, a traditional multi-stage horizontal flotation unit, a single-stage floatation unit, or a combination thereof.

164. The method of any one of claims 91 to 161, wherein the de-oiling of the oily produced-water stream occurs in a de-oiling sub-system that comprises a filtration-type unit.

165. The method of claim 164, wherein the filtration-type unit comprises a filter press, a traditional filter, a membrane filter, or a combination thereof.

166. The method of any one of claims 162 to 165, wherein the de-oiling sub-system is configured to receive a density-reducing agent and to use the density-reducing agent to facilitate the separation of the residual oil content from the oily produced-water stream.

167. The method of any one of claims 91 to 166, wherein the steam-generating sub-system comprises a flash steam generator.

168. The method of any one of claims 91 to 166, wherein the steam-generating sub-system comprises an ultra-low-quality steam generator.

169. The method of claim 168, wherein the input stream to the ultra-low-quality steam generator has a .rho.v2-value of between about 10,000 lbft-1s-2 and about 60,000 lbft-1s-2.

170 The method of any one of claims 91 to 166, wherein the steam-generating sub-system further comprises a steam separator.

171. The method of claim 170, wherein the steam-generating sub-system further comprises a recirculation loop to recirculate liquids, vapours, or a combination thereof from an outlet of the steam separator to the input to the steam-generating sub-system.

172. The method of any one of claims 91 to 171, wherein the quality of the steam is at least about 85 %.

173. The method of any one of claims 91 to 172, wherein the quality of the steam is at least about 95 %.

174. The method of any one of claims 91 to 173, further comprising heating the oil-water emulsion, the oily produced-water stream, the produced-oil stream, the de-oiled-water stream, the input stream, or a combination thereof.

175. The method of claim 174, wherein the heating is executed by an electric heater, an induction heater, an infrared heater, a radio-frequency heater, a microwave heater, a natural gas heater, a circulating fluid heater, or a combination thereof.

176 The method of any one of any one of claims 91 to 175, further comprising maintaining at least a portion of the enthalpy of the oil-water emulsion, the oily produced-water stream, the produced-oil stream, the de-oiled-water stream, the input stream, or a combination thereof with an enthalpy-maintenance sub-system.

177 The method of claim 176, wherein the enthalpy-maintenance sub-system further comprises, an insulator, a heat exchanger, or a combination thereof

178. The method of any one of claims 91 to 177, wherein the average temperature of the input stream is within about 50°C of the average temperature of the oil-water emulsion

179. The method of any one of claims 91 to 178, wherein the average temperature of the input stream is within about 40°C of the average temperature of the oil-water emulsion.

180. The method of any one of claims 91 to 179, wherein the average temperature of the input stream is within about 30°C of the average temperature of the oil-water emulsion.

181. The method of any one of claims 91 to 180, which is absent of a lime softening step, an evaporating step, an ion exchanging step, or a combination thereof.

182. The method of any one of claims 91 to 181, wherein the recovery process comprises a steam-assisted gravity-drainage process, a cyclic-steam-simulation process, a steam-flooding process, a solvent-assisted-cyclic steam stimulation process, a toe-to-heel-air-injection process, a solvent-aided process, a solvent-driven process, or a combination thereof.