CA3016971A1

CA3016971A1 - Processes for treating hydrocarbon recovery produced fluids

Info

Publication number: CA3016971A1
Application number: CA3016971A
Authority: CA
Inventors: Stewart A. H. Adams; Glenn Robert Price; Susan Wei Sun; Kenneth Switala
Original assignee: Cenovus Energy Inc
Current assignee: Cenovus Energy Inc
Priority date: 2017-09-08
Filing date: 2018-09-07
Publication date: 2019-03-08

Abstract

Processes and systems are provided for integrated processing of produced fluids for use in thermal hydrocarbon recovery processes. The integrated processes include initial emulsion treating, and subsequently maintaining the produced water from emulsion treating at elevated pressures and temperatures, so as to reduce the equipment and energy required for steam generation. To achieve energetic efficiencies, these integrated processes are carried out in an interconnected and contained fluid handling system. The containment of the system facilitates the operation of the whole process at an elevated temperature, and at correspondingly high pressures.

Description

PROCESSES FOR TREATING HYDROCARBON RECOVERY PRODUCED FLUIDS
FIELD OF THE INVENTION
[0001] The present disclosure is in the field of thermal hydrocarbon recovery processes, such as steam-assisted gravity drainage (SAGD) processes in heavy oil reservoirs. In particular, facilities for high temperature processing of emulsions for water reuse.
BACKGROUND

[0002] Some subterranean deposits of viscous hydrocarbons can be extracted in-situ by lowering the viscosity of the petroleum to mobilize it so that it can be moved to, and recovered from, a production well. Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbons, heavy oil, bitumen, oil sands, or (previously) tar sands. The in-situ processes for recovering oil from oil sands typically involve the use of multiple wells drilled into the reservoir, and are assisted or aided by thermal recovery techniques, such as injecting a heated fluid, typically steam, into the reservoir from an injection well. One process of this kind is steam-assisted gravity drainage (SAGD).

[0003] The SAGD process is in widespread use to recover heavy hydrocarbons from the Lower Cretaceous McMurray Formation, within the Athabasca Oil Sands of northeastern Alberta, Canada. The geology of this region is emblematic of the geological complexities associated with many heavy oil bearing formations. In general terms, a thick sequence of marine shales and siltstones of the Clearwater Formation unconformably overlies the McMurray Formation in most areas of northeastern Alberta.
In some areas, glauconitic sandstones of the Wabiskaw member are present at the base of the Clearwater. The Grand Rapids Formation overlies the Clearwater Formation, and quaternary deposits unconformably overlie the Cretaceous section. The pattern of hydrocarbon deposits within this geological context is accordingly complex and varied. This geologic complexity gives rise to challenges in handling fluids produced in SAGD processes, because these produced fluids may contain a very wide range of dissolved solids and other materials derived from the reservoir undergoing the hydrocarbon recovery process.

[0004] In a typical SAGD process, as for example disclosed in Canadian Patent No.
1,130,201 issued on 24 August 1982, hydrocarbons are recovered along with significant volumes of produced water (or production water). There are advantages associated with recycling produced water for steam generation. However, these advantages may be offset by challenges associated with the necessity to treat produced water so as to obtain a treated water that is suitable for use in steam generation. In particular, recycling of produced water has typically required overall removal of suspended solids, dissolved solids and of scale-forming chemicals, among other ions and chemical compounds, that affect the operation of steam generating systems. Conventional processes used to achieve appropriate degrees of water treatment may be complex and expensive. It may also be challenging to manage these processes as the composition of a produced water stream changes over time. It is also inefficient to cool the process water to fit in with conventional processing.

[0005] Produced water is typically received at a relatively high temperature and pressure, both of which must currently conventionally be reduced before the produced water is treated. For this reason, produced water treatment typically involves the use of heat exchangers to reduce the temperature of the produced water before treatment to remove oil and emulsions, suspended solids, dissolved solids and scale-forming chemicals such as calcium, magnesium and silica. For recycling, treated water is then conventionally re-heated and re-pressurized in advance of steam generation, with water entering a steam generator characterized as boiler feed water (BFVV) having relatively stringent limits on entrained and dissolved materials so as to minimize scale formation.
The cooling and re-heating and the re-pressurization of the treated water represents a significant proportion of the overall energy consumption of a SAGD process.

[0006] A conventional process for separating produced emulsion for oil sales and further water treatment involves a number of distinct steps, as follows. Oil-water emulsion from the reservoir may vary in temperature, for example from 80 C-250 C, more typically 180 C-220 C, and with a pressure of about 1,200-2,000 kPag.
After emulsion is recovered from the reservoir it may be degassed and then cooled to 140 C to allow for diluent aided separation. The cooled emulsion is then treated for coarse oil-water separation, for example in free-water knock out (FWKO) unit(s), and/or other emulsion treaters, typically operating at about 800-1,500 kPag and 130 C-for traditional gravity separation, or alternatively operating at much lower pressures of between 100-800 kPag and 130 C-140 C for flash treating. These conventional emulsion treating systems typically use diluent to aid in separation of oil and water, where the diluent is traditionally a pentane rich natural gas liquid (NGL) or a synthetic crude oil, and where the diluent remains in the dewatered oil that is then cooled and sent to sales oil tanks.

[0007] A conventional process for treating produced water for re-use in steam generation involves a number of distinct steps, as follows. Conventionally, produced water from emulsion treatment is cooled, using for example one or more heat exchangers, before it is subjected to de-oiling and further water treatment.
This heat exchange process may for example decrease the produced water temperature from 130 C-140 C to 80 C-95 C. De-oiling typically comprises several units, such as a skim tank for bulk oil separation, a floatation type unit such as an induced gas or induced static floatation unit (IGF/ISF) for further removal of oil and suspended solids, and a filtration type unit such as an oil removal filter (ORF). Subsequent water treatment typically includes, for example, a warm lime softener (WLS), which increases the pH of the water and adds MagOx (Magnesium Oxide) to remove silica. The WLS is typically followed by an ion exchange unit where removal of scaling ions occurs. Scaling ions typically include dissolved calcium, magnesium, lithium and iron. 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. Typical water quality from de-oiling and water treatment may be less than 50 ppm silica, less than 0.1 ppm hardness, and less than 1 ppm oil.

[0008] A conventional system for steam generation using treated produced water involves a number of distinct steps including pre-heating through heat exchangers, or an alternative process of heat exchange, which typically increases the boiler feed water (BFW) temperature to between about 160 C and 220 C as a water inlet temperature prior to the steam generator. The pre-heated BFW typically enters an economizer section which further heats the BFW using convection from flue gas and then the BFW
enters the fired section of the boiler. Conventional OTSGs (Once Through Steam Generators) typically produce from 75-90% steam quality at pressures between 7 and 15 MPa depending on the thermal reservoir requirements. The steam may then be separated into dry steam and a liquid fraction containing impurities, which is typical for SAGD but not for all thermal in-situ processes, with the dry steam sent to one or more well heads or well pads for use in the reservoir during the hydrocarbon recovery process. Dry refers to steam at a very high steam quality of about 95% or higher. The liquid fraction separated from the generated steam (referred to as boiler blowdown) is sent for recycling or disposal.

[0009] A conventional system for treating recovered heavy oil (once dewatered as described above) involves blending with a hydrocarbon diluent, which may be for example a natural gas condensate, a synthetic hydrocarbon blend, naphtha, butane, or any combination thereof, to meet shipping specifications, primarily viscosity and density of the sales oil product.

[0010] 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, 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. The abbreviation POIP stands for "producible oil in place" and in the context of the methods disclosed herein is generally defined as the exploitable or producible oil structurally located above the production well elevation.

[0011] 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.$) 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.

[0012] A "reservoir" is a subsurface formation containing one or more natural accumulations of moveable petroleum, which are generally confined by relatively impermeable rock. 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), in-situ combustion, hot water flooding, steam flooding and electrical heating. In general, thermal energy 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.
SUMMARY

[0013] Processes and systems are provided for integrating the main areas of a hydrocarbon recovery produced fluid processing facility to reduce equipment and increase efficiencies. In select processes and systems, conventional or alternative emulsion treating techniques, such as upside down treating or condensate/propane as diluent treating, may allow for a hot dewatered oil that can flow directly to a partial upgrading solution, such as viscosity reduction by thermal cracking, shearing or catalytic conversion processes. Concurrently the produced water from emulsion treating may be kept at emulsion treating pressure and temperature to reduce the required equipment and associated facility space. This pressurized treated produced water may then flow into various alternative steam generation configurations that are advantaged by the higher temperature feed, and may be adapted so as not to require the inlet water quality of conventional systems.

[0014] Methods and systems are accordingly provided for processing fluids for use in a subterranean thermal hydrocarbon recovery process, wherein the method is carried out in an interconnected and contained fluid handling system operating above atmospheric pressure. These methods and systems may include steps, or means for, a succession of treatments, including: producing an oil-water emulsion;
separating the produced emulsion into a produced oil stream and an oily produced water stream; de-oiling and treating the oily produced water stream; adding make up water to the treated water; generating steam; and, injecting a thermal recovery fluid.

[0015] Steps involved in producing an oil-water emulsion from a hydrocarbon reservoir undergoing the thermal recovery process, may for example include producing the emulsion at a production temperature above about 100 C. The oil:water ratio of the emulsion may for example be between about 20:80 and about 90:10.

[0016] Steps involved in separating the produced emulsion into a produced oil stream and an oily produced water stream may be carried out in an emulsion treating module. In this module, the produced oil stream may for example have a basic sediment and water content of less than about 0.5%, wherein the fluid making up the oily produced water stream is maintained by the fluid handling system at a temperature of at least about 100 C in the absence of heating. The oily produced water may for example have: a residual oil content of less than about 10,000 ppm (such as between about 10 ppm and about 5,000 ppm); a silica content of at least about 50 ppm (such as at least about 250 ppm, or between about 50 ppm and about 400 ppm); a hardness content of at least about about 5 ppm (such as at least about 10 ppm, or between about 5 ppm and about 225 ppm); or a combination thereof.

[0017] Steps of de-oiling and treating the oily produced water stream may be carried out in a water treatment module, to produce a treated water stream that is maintained by the fluid handling system at a temperature of at least about 100 C in the absence of heating. The treated water stream may for example have: a residual oil content of less than about 25 ppm (such as less than about 5 ppm; a silica content of at least about 50 ppm (such as between about 50 ppm and about 400 ppm); a hardness content of at least about 5 ppm (such as between about 5 ppm and 225 ppm); or a combination thereof.

[0018] Make up water may be added to the treated water to produce a steam generator input fluid stream, and the treated water and the steam generator input fluid may be maintained by the fluid handling system at a baseline steam generator input temperature of at least about 100 C in the absence of heating. In select embodiments, at least about 75% of the steam generator input fluid volume is made up of fluid from the oily produced water.

[0019] Steam may be generated from the steam generator input fluid stream in a steam generator. In select embodiments, the steam generator may for example produce an outlet stream comprising steam of at least about 75% quality. A thermal recovery fluid comprising the steam may then be injected into the hydrocarbon reservoir, and the injected steam quality may for example be at least about 70%.
BRIEF DESCRIPTION OF THE DRAWINGS

[0020] Figure 1 is a schematic illustration of a fluid processing system, showing modules or subsystems within the dash-dotted line that together make up an interconnected and contained fluid handling system operating above ambient atmospheric pressure.

[0021] Figure 2 is a schematic illustration of a fluid processing system that includes an upside down treater (UDT), compact floatation unit (CFU), flash steam generator (FSG) and a produced oil upgrading process that involves viscosity reduction by a mild thermal cracking process which may involve enhancements or modifications such as shearing.

[0022] Figure 3 is a schematic illustration of a modification to the process of Figure 2 for a thermal hydrocarbon recovery well pad.

[0023] Figure 4 is a schematic illustration of a further modification to the process of Figure 2, including a propane diluent emulsion treating system in place of the upside down treater.

[0024] Figure 5 is a schematic illustration of a modification to the process of Figure 4 for a thermal hydrocarbon recovery well pad.

[0025] Figure 6 is a schematic illustration of a modification to the process of Figure 2 above including a once through steam generator (OTSG) instead of a FSG.

[0026] Figure 7 is a schematic illustration of a modification to the process of Figure 6 for a thermal hydrocarbon recovery well pad.

[0027] Figure 8 is a schematic illustration of alternative upgrading processes.

[0028] Figure 9 is a schematic illustration of a further modification to the process of Figure 4, including conventional diluent emulsion treating system in place of the propane diluent treating.

[0029] Figure 10 is a schematic illustration of a modification to the process of Figure 9 for a thermal hydrocarbon recovery well pad.
DETAILED DESCRIPTION

[0030] Various aspects of the present disclosure involve integrated and energetically efficient methods and systems for processing fluids for use in thermal hydrocarbon recovery processes. To achieve energetic efficiencies, these processes are "integrated"
in the sense that a series of subsystems, assemblies or modules are implemented in an interconnected and contained fluid handling system. The containment of the system facilitates the operation of the whole process at elevated temperatures, and at correspondingly high pressures, above ambient atmospheric pressure. Because the subsystems, assemblies, and/or modules are implemented in an interconnected and contained fluid handling system, they may be implemented as part of a well-pad scale facility which may be modular, portable, and/or upgradable. Additionally or alternatively, the subsystems, assemblies, and/or modules may be implemented in a central processing facility.

[0031] In an initial stage of the process, an oil-water emulsion may be produced from a hydrocarbon reservoir undergoing the thermal recovery process, such as a SAGD
process, cyclic steam simulation (CSS), steam flooding (SF), solvent assisted-cyclic steam simulation, toe-to-heel-air-injection (THAI), a solvent-aided process (SAP), or a combination thereof (for example occurring at different well pads that feed into fluid handling processes and systems described herein). The production fluids may include a significant proportion of connate water produced from the reservoir. The emulsion 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 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] The produced oil:water ratio of the emulsion may for example be from about 20:80 to about 90:10, or any ratio between these values, and will of course typically fluctuate over time during production. In a SAGD process, this ratio may for example be from about 20:80 to about 35:65. In a 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 emulsions for example being characterized by one or more parameters that may include 50-900 mg/L total suspended solids (TSS), 50-400 mg/L silica, 5-75 mg/L or alternatively 5-225 mg/L hardness, 30-700 mg/L soluble organics measured as total organic carbon (TOC), or a combination thereof.

[0033] The produced emulsion may be separated into a produced oil stream and an oily produced water stream in an emulsion treating module. This emulsion treating module may be operated so that the oily produced water stream is maintained by the fluid handling system at a baseline temperature, for example of at least 100 C, 125 C, 150 C, 160 C, 170 C, 175 C, 180 C, 185 C, 190 C, 195 C, 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 fluid handling system at a temperature of at least about 190 C to about 200 C and/or a pressure of between about 1 MPa and about 3.1 MPa. A heater utilized for heating may be 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, or any other suitable heater as would be understood by a person of skill in the art. In the absence of this optional heating, the fluid handling system is constructed as an interconnected and contained fluid handling network, and operated so that it maintains the processed fluids close to or above this baseline temperature. Enthalpy maintenance subsystems of the fluid handling system may for example be adapted so that the temperatures and/or pressures maintained in the emulsion treating module 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 subsystem may for example include insulation and other fluid handling adaptations that maintain the temperature and/or pressure of fluids within the fluid handling system.

[0034] Exemplary emulsion treating modules may for example involve one or more of a membrane separation process, an upside down treater (UDT) process, a hot hydrocyclone process or a propane or other diluent or solvent treating system, for example using a natural gas condensate, propane, butane, pentane or other alkanes or alkane mixtures.

[0035] Oil-water separation is advancing with membranes that, for example, allow oil to pass through but not water. An alternative membrane separation system may consist of a pressurized filter system with membrane cartridges/units in place of traditional filters. A suitable membrane may be utilized to aid in oil-water separation, thus reducing the need for traditional produced emulsion treating chemicals and/or diluents.

[0036] In an aspect of an upside down treater process, the produced emulsion may be heated to a relatively high temperature range, for example of at least about 150 C or 180 C, from about 150 C to 250 C, or from about 180 C to 230 C, to provide a lower viscosity and wider density difference between oil and water; the hot emulsion may separate with the oil portion being more dense than the water portion, hence the term 'upside down'. The emulsion separation may reduce or eliminate the need for diluent and may reduce or eliminate the need for treatment chemicals compared to a conventional SAGD operation, and may produce semi-dry oil and relatively clean produced water streams. The semi-dry oil may then be flashed in a flash treater to remove the remaining water to below 0.5% basic sediment and water (BS&W) while remaining in, for example, the 180 C to 230 C temperature range. Concurrently the produced water may optionally also remain at the same high temperature range with oil in water contents below about 2,000 ppm.

[0037] Similarly, in an aspect of a hot hydrocyclone process, the emulsion may be heated to a relatively high temperature range of about 180 C to 230 C to provide a lower viscosity and wider density difference between oil and water, and this may allow for hot emulsion separation with the oil portion being heavier than the water portion.
Cyclones, hydrocyclones or oleocyclones may replace conventional SAGD process facility vessels and may involve single or multiple stage separation. The cyclones make use of the angular velocity of the fluids to impart higher acceleration forces and may separate oil and water more efficiently than traditional gravity separation equipment.
Emulsion may be degassed, prior to or in the absence of heating, and then may be pumped up to a higher pressure such as 1,500 kPag to 2,500 kPag to prevent flashing in the cyclone. The emulsion may then enter the cyclone unit where the difference in density between oil and 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 required product qualities for further processing, transportation, or disposal.
Additionally, pumps may be required to overcome the pressure drop require for each cyclone stage. The emulsion separation may require less or fully eliminate the need for traditional diluent treating and may require less or fully eliminate the need for treatment chemicals to produce semi-dry oil and relatively clean produced water streams.
The semi-dry oil may then be flashed in a flash treater to remove the remaining water to below 0.5% BS&W and may remain at an elevated temperature, for example of at least about 180 C, or about 180 C to 230 C. Concurrently the produced water may also optionally remain at about 180 C to 230 C with oil in water contents below about 2,000 ppm.

[0038] The emulsion treating process may be carried out so as to separate a high proportion of the oil, leaving the oily produced water 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 separated 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 may be maintained at elevated temperatures and pressures within the contained fluid handling system. Dissolved and entrained materials in the oily produced water 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 50 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 for each foregoing parameter a select proportion of the relevant chemical species segregates into the oily produced water. For example, at least 70%, 75%, 80%, 85%, 90%, 95% or 98% of the TSS, silica, hardness, TOC, or a combination thereof, present in the produced emulsion may be segregated into the oily produced water. The treated water may comprise at least 70%, 75%, 80%, 85%, 90%, 95% or 98% of the TSS, silica, hardness, TOC, or a combination thereof, segregated into the oily produced water.

[0039] The produced oil stream may be discharged from the fluid handling system, for example for upgrading. Processes of upgrading may take advantage of residual heat present in the discharged produced oil stream by virtue of the elevated temperatures and pressures used to treat the produced emulsion. Upgrading the produced oil 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 patent documents CA2611251, CA2617985, CA2858705, CA2858877). 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 (TAN), sulfur content, or a combination thereof, and partial upgrading may be utilized to help meet oil transportation (e.g., pipeline, railway) specifications. The produced oil stream may be further heated to above about 350 C and the oil may be partially upgraded, for instance, by converting longer heavy oil chains into smaller chains, which lowers 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 solutions 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] The oily produced water may be further de-oiled and/or treated in a water treatment process to reduce oil and components with the potential to foul (scale) a downstream steam generator. Conventional systems de-oil and treat water below 100 C because of the use of equipment such as tanks, which must occur below the normal boiling point of the contents therein to ensure containment.
Conventional systems also have temperature limitations of processes, for example, hardness removal resins degrade at higher temperatures. Some conventional systems use evaporators, which necessarily involve energetically expensive phase changes.

[0041] Treatment of the oily produced water may for example be carried out so as to produce a treated water stream having: a residual oil content of less than about 25 ppm (such as less than about 20 ppm, 15 ppm, 10 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 50 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.. õ In select embodiments, the treated water stream may for example have residual TSS, silica, hardness, and TOC 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 TSS, silica, hardness, and/or TOC
values of the oily produced water stream.

[0042] Oily produced water treatment according to an alternative embodiment may for example be carried out so as to produce a treated water stream having an oil concentration of less than 1 ppm (alternatively up to 100 ppm), a hardness of less than 0.1 ppm (where hardness refers to free calcium, magnesium, lithium and/or strontium ions; and where the oily produced water may be characterized by a hardness of up to 25 ppm), and a silica concentration of less than 50 ppm (where oily produced water may be characterized by a silica concentration of up to 350 ppm). In alternative embodiments, hardness may for example be maintained at <0.5 ppm.

[0043] The process of de-oiling and treating the oily produced water stream may be performed to recover valuable oil and reduce scale formation (fouling) during subsequent steam generation. Produced water may contain between 200 and 10,000 ppm oil, between 5 and 225 ppm hardness, between 100 and 350 ppm silica, between 25 and 75 ppm dissolved organics, or a combination thereof. While some steam generation processes may not require produced water de-oiling or treatment, such as Direct Steam Generation (DSG), Flash Steam Generation (FSG) and/or a Fluidized Bed Boiler (FBB) (see CA2947355), other steam generation processes may require at least some produced water de-oiling and treatment such as a Once Through Steam Generator (OTSG).

[0044] De-oiling the produced water as much as possible, for example, to below 50 ppm oil, may be desirable because the oil is a valuable product to recover.
The use of floatation processes, units, and/or systems for oil separation is advantageous for high temperature, pressurized produced water treatment applications because floatation is typically performed in vessels that may be designed for most, if not any, operating conditions. Examples of floatation technologies include a Compact Floatation Unit (CFU, 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)), which is a multistage, typically vertical, vessel with swirling/cyclonic separation enhancement;
traditional multistage horizontal floatation units; or single stage floatation units.
Additional oil separation processes may include hydrocyclones, filter presses, traditional filters or membrane filters (see for example oil removal filtration processes as described in US
Patent Nos: US6180010, U55437793, U55698139, U55837146, U55961823 and US7264722; and, hydrocyclones as for example described in US Patent Nos.
US5017288, US5071557 and US5667686).

[0045] Oily produced water treatment processes may involve the reduction of steam generator scaling components within the oily produced water stream and may occur before, during or after the de-oiling process. The oily produced water may be processed to generate a treated water in a water treating module. The desired treated water quality depends on the steam generation process to be utilized and oily produced water treatment processes prior to steam generation may include ion exchange to reduce hardness, chemical addition to reduce reactive silica (for example, by adding magnesium oxide or a silica inhibitor), chemical or electrical reduction of organics, hardness and/or silica, or a combination thereof. Oily produced water treatment processes may involve an electro-flocculation (EF) or electro-coagulation (EC) process of imparting voltage and current through submerged metal plates, commonly formed of iron, to generate a metal ion rich solution. Hydroxide or other flocs may be formed from the solution, at an appropriate pH. These flocs serve to remove the contaminants in the water by various mechanisms, such as absorption and coagulation. Oily produced water treatment processes may involve a cationic resin to attract free hardness ions. The resin may then be regenerated, for example when exhausted, with either brine or acid and caustic solutions. Oily produced water treatment processes may involve selective membranes in reverse osmosis or other flow arrangements. These or other oily produced water treatment processes may be utilized to generate a treated water.

[0046] In select embodiments, make up water may be added to the treated water to produce a steam generator input fluid stream. The make up water may be combined with the treated water in equipment such as piping, a tank, a vessel, or a combination thereof. Make up water may be processed and/or handled, for example, 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, prior to combining the make up water with the treated water. 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, cooler, or any other suitable heat exchange process as would be understood by a person of skill in the art.

[0047] The treated water and the steam generator input fluid stream may for example be maintained by the fluid handling system at a baseline steam generator input temperature and/or pressure. For example, the treated water stream and the steam generator input fluid stream may be maintained at a temperature of at least 100 C, 125 C, 150 C, 160 C, 170 C or 175 C in the absence of heating and/or at a pressure of between about 1 MPa and about 3.1 MPa. Optionally, the steam generator input fluid stream may be heated above the baseline steam generator input temperature; in the absence of this optional heating, the fluid handling 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. By reducing the usage of tanks, reducing the number of equipment steps needed, and ensuring appropriate insulation, the produced fluids may be maintained at a relatively high temperature, which may improve system efficiency compared to a conventional SAGD facility.
The enthalpy maintenance subsystems of the fluid handling 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 steam generator input fluid stream, temperatures and/or pressures are maintained within a particular degree of departure from the temperatures and/or pressures of the water treatment module, for example within a variation of 20%, 15%, 10% or 5%.

[0048] In select embodiments, produced fluid recycling efficiencies are provided by the contained fluid handling system, so that the ratio of oily produced water volume to steam generator input fluid volume 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 volume as possible moves forward for use as the steam generator input fluid stream. Similarly, the contained fluid handling system may be adapted to maintain a relatively high ratio of treated water volume to make up water volume, for example of at least 7:3, 8:2 or 9:1, representing for example at least 70% of the treated water volume being utilized for steam generation along with 30%
make up water.

[0049] The enthalpy maintenance subsystems 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 fluid handling system, for example within 50 C, 40 C, 30 C or 20 C.

[0050] The steam generator input fluid stream may be converted into steam in a steam generator, such as a flash steam generator, fluidized bed steam generator, direct steam generator, OTSG, or a steam generator that further comprises a steam separator. In embodiments wherein the steam generator further comprises a steam separator, the fluid handling system may further comprise a recirculation line that is operable to recirculate non-vapourized outlet fluids from the steam separator back into the steam generator input fluid stream as describe in Canadian patent application number 2,987,237. The steam generator (optionally comprising the steam separator) may be adapted to produce an outlet stream comprising steam of a select quality (the proportion of gaseous water in the total fluids produced by the steam generator), for example greater than 20%, on the order of at least 70%, 75%, 80%, 85%, 90% or 95%
steam quality. This steam may then be delivered by the fluid handling 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 65%, 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.

[0051] Figure 1 is a schematic illustration of a fluid processing system, showing modules or subsystems within the dash-dotted line that together make up an interconnected and contained fluid handling system operating above ambient atmospheric pressure. An exemplary embodiment is illustrated in Figure 2, which includes an upside down treater (UDT), compact floatation unit (CFU), flash steam generator (FSG, illustrated as the Fired Heater and Flash Vessel) and a produced oil upgrading process (from Charge Pump to Hydro-polisher) that involves viscosity reduction by thermal cracking and cavitation induced by shearing. In select implementations of such an embodiment, demulsifier and/or reverse emulsion breaker may for example be added upstream of the inlet degasser and UDT (and optionally added to slop tanks). In addition, a clarifier may be added to the inlet or oily produced water outlet of the UDT. A pH adjustment may take place, for example at the inlet of the BF\N surge vessel. For corrosion control, an amine inlet may for example be included in the steam line out of the FSG. 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. In select implementations of the illustrated processes of Figure 2, operating temperatures in the interconnected and contained fluid handling system may be in the range of about 180 C-220 C, throughout the train of treatment steps, with that temperature maintained through the deoiling, water treatment and boiler feed water processes. In select embodiments, the steam generator input fluid stream may be characterized as having about 1-5 ppm oil and grease, about 200-250 ppm silica, and about 15-20 ppm hardness.

[0052] In alternative embodiments of the illustrated process, the emulsion may for example be heated to a temperature range of about 180 C to 230 C which provides a lower viscosity and wider density difference between oil and water than at lower temperatures, and which may allow this relatively hot emulsion to separate with the oil portion being heavier than the water portion, hence explaining the term 'upside down,' as discussed above. The emulsion separation may require reduced or no diluent (for example, a natural gas condensate as is utilized in some conventional SAGD
operations) and reduced or no treatment chemicals to produce semi-dry oil and clean produced water streams (for example the process may be carried out without a demulsifier). The semi-dry oil may then be flashed in, for example, a flash treater to remove the remaining water to below 0.5% BS&W. Alternatively, other oil polishing equipment may be utilized, for example a cyclone or secondary treater.

[0053] The oil may remain at about 180 C to 230 C, and may be fed directly into the partial upgrading process where it may be further heated to above 350 C and sheared to convert long heavy oil chains into smaller chains, which may lower the viscosity to yield a partially upgraded oil. The oil may then be fractionated and hydro-polished to reduce olefin content to typical pipeline specifications of <1%. Concurrently, the hot, pressurized oily produced water that was separated from the emulsion may be de-oiled through a CFU and then may be dosed with chemicals, such as caustic (NaOH) to increase the pH, chelants to reduce free scaling ions, sulfite to reduce free oxygen, or a combination thereof, to produce treated water for steam generation. A surge vessel may be required to even out steam generator input fluid (i.e. BFW) stream flow into the steam generation system. The BFW (which may include both treated 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 fraction at about 300 C
to 400 C, and flashed in a flash vessel to create a steam fraction of 20 to 40% steam quality. This dry steam may be injected into the reservoir for thermal hydrocarbon recovery processes, while the remaining liquid fraction (known as blowdown) may be re-pressurized, filtered, and recombined with the BFW 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, or recycled back into the BWF.

[0054] In an alternative embodiment, a solvent (for example, propane or butane) may be injected into the steam generation 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 interconnected and contained fluid handling 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). Alternatively, for example, one or more natural gas liquids (NGLs)-rich vapour streams from the treating vessels may be cooled to condense the gaseous NGLs into a liquid phase (for example from the Inlet Degasser, FWKO, Treater, Upside Down Treater, and/or Flash Treater), so that a three phase separator (3 Phase Sep) is where the solvent is ultimately recovered from the water/NGL/vapour mixture. The NGL phase may be, for example, propane rich and may be re-used as a solvent. Cooling prior to separation may occur either through aerial coolers or a chilling system. 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 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, for example n-propane or n-butane, or a mixture such as n-butane +
iso-butane.

[0055] Shown in Figures 1 and 2 are the integration of several different major facility component areas, representing modules, subsystems or assemblies within the overall fluid handling process. The modules, subsystems, and/or assemblies may be implemented as part of a well-pad scale facility which may be modular, portable, and/or upgradable. Additionally or alternatively, the subsystems, assemblies, and/or modules may be implemented in a central processing facility. Figure 1 outlines in a dash-dotted line an exemplary collection of subsystems or modules that together make up an interconnected and contained fluid handling system operating above ambient atmospheric pressure, taking produced fluids from the production wellhead, treating and recirculating those fluids, to provide the injection fluids at the injector wellhead. As shown in Figure 2, the high temperature produced oil stream produced in the emulsion treating module (including an emulsion heater, upside down treater, and flash treater) with reduced or no diluent treating may be coupled to a partial upgrading module, subsystem or assembly (including a crude heater, shear module, post-reaction fractionation module, and hydro-polishing module), where less heat input is required compared to conventional SAGD processing facilities and upfront fractionation may not be required. Additionally, the elevated temperature, pressurized water treatment module (including a compact floatation unit (CFU)) allows for a reduced aerial footprint compared to traditional systems; by maintaining the treated water at an elevated temperature, the treated water may be delivered to the steam generation subsystem or module (including a flash steam generator (FSG)) with less heat exchange required than in conventional SAGD facilities and a higher temperature BFW may increase the efficiency of the steam generation system.

[0056] Figure 3 is a schematic illustration of a modification to the process of Figure 2, for conventional thermal recovery well pad use. While the process is generally the same, allowances may be provided for operational upset conditions (e.g., during a scenario in which one or more pieces of equipment must be shut down for troubleshooting or maintenance) to send slop to a central processing plant instead of a separate slop system. There may also be allowances for external steam injection from another source such as a central plant steam header.

[0057] The exemplary embodiment of Figure 4 includes a propane (C3) diluent, which dissolves in the oil phase in the produced emulsion to promote floatation of the oil in a process that typically operates at temperatures of about 120 C to 150 C.
The propane diluent emulsion treating system may alternatively operate at lower temperatures, for example of 100 C to 150 C, and may make use of chemical injection to aid in oil-water separation, such as a dennulsifier and/or reverse breaker.
In some embodiments, as illustrated, the propane diluent treating system may include a free water knockout ("FWKO") and Treaters for water removal. The FWKO units and treaters may for example be operated at about 125 C to 145 C and about 900-1,500 kPag.
Optionally a flash vessel may be provided to reduce pressure to 100 to 800 kPag to flash off the propane which may then be sent to a vapour cooling system for capture and reuse. The process as illustrated also includes a CFU, FSG and a produced oil upgrading process that involves viscosity reduction by thermal cracking and cavitation induced by shearing. In such an embodiment, demulsifier and/or reverse emulsion breaker may for example be added upstream of the inlet degasser and treaters.
In addition, a clarifier may be added to an oily water outlet from the FWKO, treaters, or both. A pH adjustment may take place, for example at the inlet of the BFW
surge vessel, and an amine inlet may for example be included in the steam line out of the FSG. In select implementations of the illustrated processes of Figure 4, operating temperatures in the interconnected and contained fluid handling system may be in the range of about 100 C-150 C, throughout the train of treatment steps, with that temperature maintained through the deoiling, water treatment and boiler feed water processes. In select embodiments, the steam generator input fluid stream may be characterized as having about 1-5 ppm oil and grease, about 200-250 ppm silica, and about 15-20 ppm hardness.

[0058] Figure 5 is a schematic illustration of a modification to the process of Figure 4, for conventional thermal hydrocarbon recovery well pad use. While the process is generally the same, there may be allowances for upset conditions to send slop to the central processing plant instead of a slop system. There may also be allowances for external steam injection from another source such as the central plant steam header.

[0059] Figure 6 is a schematic illustration of a modification to the process of Figure 2, showing an alternative oily produced water treatment process and an alternative steam generation process (OTSG instead of FSG). An electro-flocculation or electro-coagulation unit may be added to the water treatment module, with pH
adjustment to create iron flocks to reduce organics, silica, hardness and oil in the oily produced water stream; the flocks may then be removed in the CFU along with additional oil present in the oily produced water stream. The steam generator may be a traditional once through steam generator with BFW quality specifications such as up to about 350 ppm silica, up to about 15 ppm hardness, up to about 2 ppm oil, or a combination thereof. The exemplary embodiment of Figure 6 includes an UDT, CFU, OTSG and a produced oil upgrading process that involves viscosity reduction by thermal cracking and cavitation induced by shearing. In select implementations of such an embodiment, demulsifier and/or reverse emulsion breaker may for example be added upstream of the inlet degasser and UDT (and optionally to slop tanks). A clarifier may be added to the inlet of the UDT or oily produced water downstream of the UDT, or a combination thereof. A pH
adjustment may take place, for example at the inlet of the BFW surge vessel, and an amine inlet may for example be included in the steam line out of the OTSG. In select implementations of the illustrated processes of Figure 6, operating temperatures in the interconnected and contained fluid handling system may be in the range of about 180 C-220 C, throughout the train of treatment steps, with that temperature maintained through the deoiling, water treatment and boiler feed water processes. In select embodiments, the steam generator input fluid stream may be characterized as having about 0-2 ppm oil and grease, about 15-50 ppm silica, and about 1-2 ppm hardness.

[0060] Figure 7 is a schematic illustration of a modification to the process of Figure 6, for conventional thermal recovery well pad use. While the process is generally the same, there may be allowances for upset conditions to send slop to the central processing plant instead of a slop system. There may also be allowances for external steam injection from another source such as the central plant steam header.

[0061] In select implementations of the illustrated embodiments, emulsion produced from the reservoir may for example range in temperature from about 160 C to 230 C, with a pressure as high as 2,700 kPag (approximately steam saturation pressure at 230 C). In some cases, the UDT may for example operate at temperatures of about 170 C to 220 C, with a pressure as high at 2,300 kPag (approximately steam saturation pressure at 220 C).

[0062] A wide variety of alternative oil upgrading processes may be implemented in alternative embodiments. Figure 8 illustrates exemplary embodiments of an oil upgrading process, that may for example include a partial upgrading reaction module "P" and a post-reaction fractionation module ("F"), to separate hydrocarbon fractions. As illustrated, the produced oil stream 1 enters the crude heater. The output stream 2 from the crude heater enters the partial upgrading reaction module. The output stream 3 from the partial upgrading reaction module enters the fractionation module. The fractionation module segregates a heavy fraction 5 from a light fraction 4, with light fraction 4 proceeding to hydro-polishing to produce output stream 7. Both fractions 5 and 7 are returned for re-blending as combined output stream 6 back into the product sales oil. In select embodiments, the partial upgrading reaction module may for example include technologies such as: conventional thermal cracking/visbreaking, Fractal's JetShear technology, FluidOil's HTLNHTL technology, hydrogen-donor assisted thermal cracking, thermal decarboxylation, catalyst-assisted thermal processes, hydroprocessing (for example, hydrocracking, slurry hydrocracking, molten-sodium assisted hydrocracking, hydrotreating, or a combination thereof). In select embodiments, particularly the shearing example set out above, process conditions for fluid flow in the upgrading module may for example be as set out in the following Table.
Stream Temperature (deg. C) Pressure (psig)

[0063]
Figure 9 is a schematic illustration of a modification to the process of Figure 4, showing conventional diluent based emulsion treating in place of the solvent (e.g., propane) emulsion treating described above. An additional diluent recovery or fractionation step may be added prior to the partial upgrading solution, with that recovered diluent being optionally reused in the emulsion treating process.
Additional diluent may also be required for treating. In select implementations of the illustrated processes of Figure 9, operating temperatures in the interconnected and contained fluid handling system may be in the range of about 120 C-150 C, throughout the train of treatment steps, with that temperature maintained through the deoiling, water treatment and boiler feed water processes. In select embodiments, the steam generator input fluid stream may be characterized as having about 1-5 ppm oil and grease, about 150-250 ppm silica, and about 10-20 ppm hardness.

[0064]
Figure 10 is a schematic illustration of a modification to the process of Figure 9, for conventional thermal recovery well pad use. While the process is generally the same, there may be allowances for upset conditions to send slop to the central processing plant instead of a slop system. There may also be allowances for external steam injection from another source such as the central plant steam header.

[0065]
Although various embodiments of particular innovations are disclosed herein, many adaptations and modifications may be made within the scope of the invention in accordance with the common general knowledge of those skilled in this art.
Such modifications include the substitution of known equivalents for any aspect of the invention in order to achieve the same result in substantially the same way.
Numeric ranges are inclusive of the numbers defining the range. The word "comprising"
is used herein as an open-ended term, substantially equivalent to the phrase "including, but not limited to", and the word "comprises" has a corresponding meaning. As used herein, the singular forms "a", "an" and "the" include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to "a thing" includes more than one such thing. References herein to "modules" or "subsystems" or an "assembly"
generally connote an interoperating component of a larger system, with a meaning informed by the broader context of the description, where that component is itself made up of interoperating parts or processes (and as such these words may be used interchangeably). Citation of references herein is not an admission that such references are prior art to the present invention. Any priority document(s) and all publications, including but not limited to patents and patent applications, cited in this specification are incorporated herein by reference as if each individual publication were specifically and individually indicated to be incorporated by reference herein and as though fully set forth herein. The invention includes all embodiments and variations substantially as hereinbefore described and with reference to the examples and drawings.

Claims

1. A method of processing fluids for use in a subterranean thermal hydrocarbon recovery process, wherein the method is carried out in an interconnected and contained fluid handling system operating above ambient atmospheric pressure, and wherein the method comprises:
producing an oil-water emulsion from a hydrocarbon reservoir undergoing the thermal hydrocarbon recovery process, the emulsion being produced at a production temperature above about 100°C, wherein the oil:water ratio of the emulsion is between about 20:80 and about 90:10;
separating the produced emulsion into a produced oil stream and an oily produced water stream in an emulsion treating module, wherein the produced oil stream has a basic sediment and water content of less than about 0.5%, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of at least about 100°C in the absence of heating, wherein the oily produced water has a residual oil content of less than about 10,000 ppm, a silica content of at least about 50 ppm, and a hardness content of at least about 5 ppm;
de-oiling and treating the oily produced water stream in a water treatment module to produce a treated water stream that is maintained by the fluid handling system at a temperature of at least about 100°C in the absence of heating, the treated water stream having an oil content of less than about 25 ppm, a silica content of at least about 50 ppm, and a hardness content of at least about 5 ppm;
adding make up water to the treated water to produce a steam generator input fluid stream, wherein the treated water and the steam generator input fluid are maintained by the fluid handling system at a baseline steam generator input temperature of at least about 100°C in the absence of heating, and wherein at least about 75% of the steam generator input fluid volume is made up of fluid from the oily produced water;
generating steam from the steam generator input fluid stream in a steam generator, wherein the steam generator produces the steam of at least about 75%
quality; and injecting a thermal recovery fluid comprising the steam into the hydrocarbon reservoir, wherein the injected steam quality is at least about 70%.

2. The method of claim 1, wherein the emulsion production temperature is at least about 150°C.

3. The method of claim 1 or 2, wherein the emulsion production temperature is below about 250°C.

4. The method of any one of claims 1 to 3, wherein the emulsion production temperature is within about 50°C of the steam generator input temperature, in the absence of heating by the fluid handling system.

5. The method of any one of claims 1 to 3, wherein the emulsion production temperature is within about 40°C of the steam generator input temperature, in the absence of heating by the fluid handling system.

6. The method of any one of claims 1 to 3, wherein the emulsion production temperature is within about 30°C of the steam generator input temperature, in the absence of heating by the fluid handling system.

7. The method of any one of claims 1 to 6, wherein separating the produced emulsion into the produced oil stream and the oily produced water stream in the emulsion treating module comprises a membrane separation process.

8. The method of any one of claims 1 to 7, wherein separating the produced emulsion into the produced oil stream and the oily produced water stream in the emulsion treating module comprises an upside down treater process.

9. The method of any one of claims 1 to 8, wherein separating the produced emulsion into the produced oil stream and the oily produced water stream in the emulsion treating module comprises a hot hydrocyclone process.

10. The method of any one of claims 1 to 9, wherein separating the produced emulsion into the produced oil stream and the oily produced water stream in the emulsion treating module comprises treating the produced emulsion with a diluent.

11. The method of claim 10, wherein the diluent is propane, butane, pentane, a natural gas liquid, naphtha, a synthetic hydrocarbon blend, or a combination thereof.

12. The method of any one of claims 1 to 11, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of at least about 130°C.

13. The method of any one of claims 1 to 11, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of at least about 150°C.

14. The method of any one of claims 1 to 11, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of at least about 160°C.

15. The method of any one of claims 1 to 14, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of less than about 220°C.

16. The method of any one of claims 1 to 15, wherein the oily produced water stream is maintained by the fluid handling system at a pressure of between about 1 MPa and about 3.1 MPa.

17. The method of any one of claims 1 to 16, wherein the residual oil content of the oily produced water is between about 10 ppm and about 5,000 ppm.

18. The method of any one of claims 1 to 17, wherein the oily produced water stream has a turbidity of at least about 250 NTU.

19. The method of any one of claims 1 to 18, wherein the silica content of the oily produced water stream is at least about 250 ppm.

20. The method of any one of claims 1 to 18, wherein the silica content of the oily produced water stream is between about 50 ppm and about 400 ppm.

21. The method of any one of claims 1 to 20, wherein the oily produced water stream has a soluble organics content of between about 30 ppm and about 400 ppm.

22. The method of any one of claims 1 to 21, wherein the hardness content of the oily produced water stream is between about 5 ppm and about 225 ppm.

23. The method of any one of claims 1 to 21, wherein the hardness content of the oily produced water stream is at least about 10 ppm.

24. The method of any one of claims 1 to 21, wherein the hardness content of the oily produced water stream is between about 5 ppm and about 75 ppm.

25. The method of any one of claims 1 to 24, wherein the hardness content is measured as free calcium, magnesium, lithium and/or strontium ions.

26. The method of any one of claims 1 to 25, wherein the oily produced water stream has a total suspended solids content of at least about 100 ppm.

27. The method of any one of claims 1 to 26, wherein the treated water stream is maintained by the fluid handling system at a temperature of at least about 130°C.

28. The method of any one of claims 1 to 26, wherein the treated water stream is maintained by the fluid handling system at a temperature of at least about 150°C.

29. The method of any one of claims 1 to 26, wherein the treated water stream is maintained by the fluid handling system at a temperature of at least about 160°C.

30. The method of any one of claims 1 to 29, wherein the treated water stream is maintained by the fluid handling system at a temperature of less than about 220°C.

31. The method of any one of claims 1 to 30, wherein the treated water stream is maintained by the fluid handling system at a pressure of between about 1 MPa and about 3.1 MPa.

32. The method of any one of claims 1 to 31, wherein the residual oil content of the treated water stream is less than about 5 ppm.

33. The method of any one of claims 1 to 32, wherein the treated water stream has a total suspended solids content of less than about 5 ppm.

34. The method of any one of claims 1 to 32, wherein the treated water stream has a total suspended solids content of between about 50 ppm and about 400 ppm.

35. The method of any one of claims 1 to 34, wherein the treated water stream has a turbidity of less than about 10 NTU.

36. The method of any one of claims 1 to 35, wherein the silica content of the treated water stream is between about 50 ppm and about 400 ppm.

37. The method of any one of claims 1 to 35, wherein the silica content of the treated water is between about 50 ppm and about 300 ppm.

38. The method of any one of claims 1 to 37, wherein the hardness content of the treated water stream is between about 5 ppm and about 225 ppm.

39. The method of any one of claims 1 to 38, wherein the oily produced water stream has a soluble organics content of between about 30 ppm and about 400 ppm.

40. The method of any one of claims 1 to 39, wherein the silica content and the hardness content of the treated water stream are within about 20% of the silica content and the hardness content of the oily produced water stream.

41. The method of any one of claims 1 to 39, wherein the silica content and the hardness content of the treated water stream are within about 10% of the silica content and the hardness content of the oily produced water stream.

42. The method of any one of claims 1 to 39, wherein the silica content and the hardness content of the treated water stream comprises at least about 80% of the silica content and the hardness content of the oily produced water stream.

43. The method of any one of claims 1 to 39, wherein the silica content and the hardness content of the treated water stream comprises at least about 90% of the silica content and the hardness content of the oily produced water stream.

44. The method of any one of claims 1 to 43, wherein the oil:water ratio of the emulsion is between about20:80 and about 35:65, and wherein the thermal recovery process is a steam-assisted gravity drainage (SAGD) process.

45. The method of any one of claims 1 to 43, wherein the oil:water ratio of the emulsion is between about 60:40 and about 90:10, and wherein the thermal recovery process is a solvent-aided process (SAP).

46. The method of any one of claims 1 to 45, wherein de-oiling and treating the oily produced water stream in the water treatment module comprises an electro-flocculation process.

47. The method of any one of claims 1 to 46, wherein de-oiling and treating the oily produced water stream in the water treatment module comprises a floatation process.

48. The method of claim 47, wherein the floatation process comprises a compact floatation process.

49. The method of any one of claims 1 to 48, wherein de-oiling and treating the oily produced water stream in the water treatment module comprises an oil removal filtration process.

50. The method of any one of claims 1 to 49, wherein de-oiling and treating the oily produced water stream in the water treatment module comprises a hydrocyclone process.

51. The method of any one of claims 1 to 50, wherein at least about 85% of the steam generator input fluid volume is made up of fluid from the oily produced water stream.

52. The method of any one of claims 1 to 50, wherein at least about 95% of the steam generator input fluid volume is made up of fluid from the oily produced water stream.

53. The method of any one of claims 1 to 52, wherein the ratio of treated water volume to make up water volume is at least about 7:3.

54. The method of any one of claims 1 to 52, wherein the ratio of treated water volume to make up water volume is at least about 8:2.

55. The method of any one of claims 1 to 52, wherein the ratio of treated water volume to make up water volume is at least about 9:1.

56. The method of any one of claims 1 to 55, wherein the steam generator is a once through steam generator.

57. The method of any one of claims 1 to 55, wherein the steam generator is a flash steam generator.

58. The method of any one of claims 1 to 55, wherein the steam generator is a fluidized bed steam generator.

59. The method of any one of claims 1 to 55, wherein the steam generator is a direct steam generator.

60. The method of any one of claims 1 to 55, wherein the steam generator further comprises a steam separator.

61. The method of any one of claims 1 to 60, wherein the steam generator produces the steam of at least about 80% quality.

62. The method of any one of claims 1 to 60, wherein the steam generator produces the steam of at least about 85% quality.

63. The method of any one of claims 1 to 62, wherein the injected steam quality is at least about 75%.

64. The method of any one of claims 1 to 62, wherein the injected steam quality is at least about 80%.

65. The method of any one of claims 1 to 64, wherein the fluid handling system comprises a heater for heating fluids contained therein.

66. The method of claim 65, wherein the heater is an electric heater, an induction heater, an infrared heater, a radio-frequency heater, a microwave heater, a natural gas heater, or a circulating fluid heater.

67. The method of any one of claims 1 to 66, further comprising discharging the produced oil stream from the fluid handling system.

68. The method of claim 67, further comprising upgrading the produced oil discharged from the fluid handling system.

69. The method of claim 68, wherein upgrading the produced oil comprises at least one of a chemical, thermal or physical process.

70. The method of claim 68 or 69, wherein upgrading the produced oil comprises a cavitation process, a shearing process, a thermal cracking process, a catalysis process, or a combination thereof.

71. The method of any one of claims 1 to 70, wherein the fluid handling system is implemented as part of a central processing facility.

72. The method of any one of claims 1 to 70, wherein the fluid handling system is implemented as part of a well-pad scale facility.

73. The method of claim 72, wherein the well-pad scale facility is modular, portable, upgradable, or a combination thereof.

74. A system for processing fluids for use in a subterranean thermal hydrocarbon recovery process, the system comprising:
an interconnected and contained fluid handling system operable above ambient atmospheric pressure, the fluid handling system comprising:
an emulsion treating module operable to separate an oil-water emulsion produced from the hydrocarbon reservoir undergoing the thermal hydrocarbon recovery process into a produced oil stream and an oily produced water stream, wherein the emulsion is produced at a production temperature above about 100°C, wherein the oil:water ratio of the emulsion is between 20:80 and about 90:10, wherein the produced oil stream has a basic sediment and water content of less than about 0.5%, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of at least about 100°C in the absence of heating, wherein the oily produced water has a residual oil content of less than about 10,000 ppm, and wherein the oily produced water has a silica content of at least about 50ppm and a hardness content of at least about 5 ppm;
a water treatment module operable to de-oil and treat the oily produced water stream to produce a treated water stream, wherein the treated water stream is maintained by the fluid handling system at a temperature of at least about 100°C in the absence of heating, and wherein the treated water stream has a residual oil content of less than about 25 ppm, a silica content of at least about 50 ppm, a hardness content of at least about 5 ppm; and a steam generator operable to receive a steam generator input fluid stream comprised of the treated water and a make up water, wherein the treated water and the steam generator input fluid are maintained by the fluid handling system at a baseline steam generator input temperature of at least about 100°C in the absence of heating, wherein at least about 75% of the steam generator input fluid volume is made up of fluid from the oily produced water, wherein the steam generator produces a steam of at least about 75% quality, wherein a thermal recovery fluid comprising the steam is injected into the hydrocarbon reservoir and the injected steam quality is at least about 70%.

75. A system for processing fluids for use in a subterranean thermal hydrocarbon recovery process, wherein the system comprises an interconnected and contained fluid handling system operable above ambient atmospheric pressure, and wherein the system comprises interconnected subsystems comprising means for:
producing an oil-water emulsion from a hydrocarbon reservoir undergoing the thermal recovery process, the emulsion being produced at a production temperature above about 100°C, wherein the oil:water ratio of the emulsion is between 20:80 and about 90:10;
separating the produced emulsion into a produced oil stream and an oily produced water stream in an emulsion treating module, wherein the produced oil stream has a basic sediment and water content of less than about 0.5%, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of at least about 100°C in the absence of heating, wherein the oily produced water has a residual oil content of less than about 10,000 ppm, and wherein the oily produced water has a silica content of at least about 50 ppm and a hardness content of at least about 5 ppm;
de-oiling and treating the oily produced water stream in a water treatment module to produce a treated water stream that is maintained by the fluid handling system at a temperature of at least about 100°C in the absence of heating, the treated water stream having a residual oil content of less than about 25 ppm, a silica content of at least about 50 ppm, and a hardness content of at least about 5 ppm;
adding make up water to the treated water to produce a steam generator input fluid stream, wherein the treated water and the steam generator input fluid are maintained by the fluid handling system at a baseline steam generator input temperature of at least about 100°C in the absence of heating, and wherein at least about 75% of the steam generator input fluid volume is made up of water from the oily produced water;
generating steam from the steam generator input fluid stream in a steam generator, wherein the steam generator produces the steam of at least about 75%
quality; and, injecting a thermal recovery fluid comprising the steam into the hydrocarbon reservoir, wherein the injected steam quality is at least about 70%.

76. The system of claim 74 or 75, wherein the emulsion production temperature is at least about 150°C.

77. The system of any one of claims 74 to 76, wherein the emulsion production temperature is below about 250°C.

78. The system of any one of claims 74 to 77, wherein the emulsion production temperature is within about 50°C of the steam generator input temperature, in the absence of heating by the fluid handling system.

79. The system of any one of claims 74 to 77, wherein the emulsion production temperature is within about 40°C of the steam generator input temperature, in the absence of heating by the fluid handling system.

80. The system of any one of claims 74 to 77, wherein the emulsion production temperature is within about 30°C of the steam generator input temperature, in the absence of heating by the fluid handling system.

81. The system of any one of claims 74 to 80, wherein separating the produced emulsion into the produced oil stream and the oily produced water stream in the emulsion treating module comprises a membrane separation process.

82. The system of any one of claims 74 to 81, wherein separating the produced emulsion into the produced oil stream and the oily produced water stream in the emulsion treating module comprises an upside down treater process.

83. The system of any one of claims 74 to 82, wherein separating the produced emulsion into the produced oil stream and the oily produced water stream in the emulsion treating module comprises a hot hydrocyclone process.

84. The system of any one of claims 74 to 83, wherein separating the produced emulsion into the produced oil stream and the oily produced water stream in the emulsion treating module comprises treating the produced emulsion with a diluent.

85. The system of claim 84, wherein the diluent is propane, butane, pentane, a natural gas liquid, naphtha, a synthetic hydrocarbon blend, or a combination thereof.

86. The system of any one of claims 74 to 86, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of at least about 130°C.

87. The system of any one of claims 74 to 86, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of at least about 150°C.

88. The system of any one of claims 74 to 86, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of at least about 160°C.

89. The system of any one of claims 74 to 88, wherein the oily produced water stream is maintained by the fluid handling system at a temperature of less than about 220°C.

90. The system of any one of claims 74 to 89, wherein the residual oil content of the oily produced water stream is between about 10 ppm and about 5,000 ppm.

91. The system of any one of claims 74 to 90, wherein the oily produced water has a turbidity of at least about 250 NTU.

92. The system of any one of claims 74 to 91, wherein the silica content of the oily produced water stream is at least about 250 ppm.

93. The system of any one of claims 74 to 91, wherein the silica content of the oily produced water stream is between about 50 ppm and about 400 ppm.

94. The system of any one of claims 74 to 93, wherein the oily produced water stream has a soluble organics content of between about 30 ppm about 400 ppm.

95. The system of any one of claims 74 to 94, wherein the hardness content of the oily produced water stream is between about 5 ppm and about 225 ppm.

96. The system of any one of claims 74 to 94, wherein the hardness content of the oily produced water stream is between about 5 ppm and about 75 ppm.

97. The system of any one of claims 74 to 96, wherein the hardness content is measured as free calcium, magnesium, lithium and/or strontium ions.

98. The system of any one of claims 74 to 97, wherein the oily produced water stream has a total suspended solids content of at least about 50 ppm.

99. The system of any one of claims 74 to 98, wherein the treated water stream is maintained by the fluid handling system at a temperature of at least about 130°C.

100. The system of any one of claims 74 to 98, wherein the treated water stream is maintained by the fluid handling system at a temperature of at least about 150°C.

101. The system of any one of claims 74 to 98, wherein the treated water stream is maintained by the fluid handling system at a temperature of at least about 160°C.

102. The system of any one of claims 74 to 101, wherein the treated water stream is maintained by the fluid handling system at a temperature of less than about 220°C.

103. The system of any one of claims 74 to 102, wherein the residual oil content of the treated water stream is less than about 5 ppm.

104. The system of any one of claims 74 to 103, wherein the treated water stream has a total suspended solids content of less than about 5 ppm.

105. The system of any one of claims 74 to 103, wherein the treated water stream has a total suspended solids content of between about 50 ppm and about 400 ppm.

106. The method of any one of claims 74 to 105, wherein the treated water stream has a turbidity of less than about 10 NTU.

107. The method of any one of claims 74 to 106, wherein the silica content of the treated water stream is between about 50 ppm and about 400 ppm.

108. The method of any one of claims 74 to 106, wherein the silica content of the treated water is between about 50 ppm and about 300 ppm.

109. The method of any one of claims 74 to 108, wherein the hardness content of the treated water stream is between about 5 ppm and about 225 ppm.

110. The method of any one of claims 74 to 109, wherein the treated water stream has a soluble organics content of between about 30 ppm and about 400 ppm.

111. The system of any one of claims 74 to 110, wherein the oil:water ratio of the emulsion is between about 20:80 and about 35:65, and wherein the thermal recovery process is a steam-assisted gravity drainage (SAGD) process.

112. The system of any one of claims 74 to 110, wherein the oil:water ratio of the emulsion is between about 60:40 and about 90:10, and wherein the thermal recovery process is a solvent-aided process (SAP).

113. The system of any one of claims 74 to 112, wherein de-oiling and treating the oily produced water stream in the water treatment module comprises an electro-flocculation process.

114. The system of any one of claims 74 to 113, wherein de-oiling and treating the oily produced water stream in the water treatment module comprises a floatation process.

115. The system of claim 114, wherein the floatation process comprises a compact floatation process.

116. The system of any one of claims 74 to 115, wherein de-oiling and treating the oily produced water stream in the water treatment module comprises an oil removal filtration process.

117. The system of any one of claims 74 to 116, wherein de-oiling and treating the oily produced water stream in the water treatment module comprises a hydrocyclone process.

118. The system of any one of claims 74 to 117, wherein at least about 85% of the steam generator input fluid volume is made up of fluid from the oily produced water stream.

119. The system of any one of claims 74 to 117, wherein at least about 95% of the steam generator input fluid volume is made up of fluid from the oily produced water stream.

120. The system of any one of claims 74 to 119, wherein the ratio of treated water volume to make up water volume is at least about 7:3.

121. The system of any one of claims 74 to 119, wherein the ratio of treated water volume to make up water volume is at least about 8:2.

122. The system of any one of claims 74 to 119, wherein the ratio of treated water volume to make up water volume is at least about 9:1.

123. The system of any one of claims 74 to 122, wherein the steam generator is a once through steam generator.

124. The system of any one of claims 74 to 122, wherein the steam generator is a flash steam generator.

125. The system of any one of claims 74 to 122, wherein the steam generator is a fluidized bed steam generator.

126. The system of any one of claims 74 to 122, wherein the steam generator is a direct steam generator.

127. The system of any one of claims 74 to 123, wherein the steam generator further comprises a steam separator.

128. The system of any one of claims 74 to 127, wherein the steam generator produces the steam of at least about 80% quality.

129. The system of any one of claims 74 to 127, wherein the steam generator produces the steam of at least about 85% quality.

130. The system of any one of claims 74 to 129, wherein the injected steam quality is at least about 75%.

131. The system of any one of claims 74 to 129, wherein the injected steam quality is at least about 80%.

132. The system of any one of claims 74 to 131, wherein the fluid handling system comprises a heater for heating fluids contained therein.

133. The system of claim 132, wherein the heater is an electric heater, an induction heater, an infrared heater, a radio-frequency heater, a microwave heater, a natural gas heater, or a circulating fluid heater.

134. The system of any one of claims 74 to 133, further comprising discharging the produced oil stream from the fluid handling system.

135. The system of claim 134, further comprising upgrading the produced oil discharged from the fluid handling system.

136. The system of claim 135, wherein upgrading the produced oil comprises operating at least one of a chemical, thermal or physical upgrading module.

137. The system of claim 134 or 135, wherein the upgrading module comprises a cavitation process, a shearing process, a thermal cracking process, a catalysis process, or a combination thereof.

138. The system of any one of claims 74 to 137, wherein the fluid handling system is implemented as part of a central processing facility.

139. The system of any one of claims 74 to 137, wherein the fluid handling system is implemented as part of a well-pad scale facility.

140. The system of claim 139, wherein the well-pad scale facility is modular, portable, upgradable, or a combination thereof.