CA2962834C

CA2962834C - Front to back central processing facility

Info

Publication number: CA2962834C
Application number: CA2962834A
Authority: CA
Inventors: Steve PORTELANCE
Original assignee: WorleyParsons Canada Services Ltd
Current assignee: WorleyParsons Canada Services Ltd
Priority date: 2016-02-11
Filing date: 2017-02-11
Publication date: 2019-08-20
Anticipated expiration: 2037-02-11
Also published as: WO2017137829A1; CA2962834A1

Abstract

Embodiments disclosed herein relate generally to systems and processes for water treatment, stream generation and waste treatment associated with enhanced oil recovery processes. The front to back central processing facilities may include high temperature electrocoagulation, regen waste recycle, and other process steps that may improve or enhance the enhanced oil recovery process, some embodiments including advantages of reduced waste, carbon capture, and other benefits.

Description

FRONT TO BACK CENTRAL PROCESSING FACILITY
FIELD OF THE DISCLOSURE
[0001] Embodiments disclosed herein relate generally to systems and processes for water treatment, stream generation and waste treatment associated with enhanced oil recovery processes.
BRIEF DESCRIPTION OF DRAWINGS

[0002] Figures 1-6 are simplified block flow diagrams of a cyclic steam stimulation central processing facility (CSS-CPF) according to embodiments herein.

[0003] Figures 7-14 are simplified block flow diagrams of a steam assisted gravity drainage central processing facility (SAGD-CPF) according to embodiments herein.

[0004] Figure 15 is a simplified block flow diagram of a comparative process for generating steam.

[0005] Figures 16-19 illustrate simplified block flow diagrams of facilities retrofitted or debottlenecked to incorporate the front to back central processing facilities according to embodiments herein.
SUMMARY OF CLAIMED EMBODIMENTS

[0006] In one aspect, the present application is directed toward a front-to-back central processing facility. The front-to-back central processing facility may include an inlet for receiving an oil-water emulsion from an enhanced oil recovery system, the emulsion comprising one or more of dissolved solids, entrained gases and/or light hydrocarbons, distillate and/or heavier hydrocarbons, and water. A gas-oil-water separation system may be used for separating the entrained gases and/or light hydrocarbons from the oil-water emulsion, producing a vapor stream and an oil-water stream. A deoiling system is provided for separating the oil-water stream into a recovered oil fraction and a water fraction containing dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants.
A
high temperature electrocoagulation system may be provided for ionizing, complexing, and/or absorbing the dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants in the water fraction, producing a vapor fraction and a solids/froth/water mixture. The system may also i include a water separation and solids/froth/sludge dewatering system for separating the solids/froth/water mixture into a sludge fraction and a clarified water fraction; a polishing system for reducing a total hardness of the clarified water fraction to less than 0.2 ppm and producing a regeneration waste water stream and a boiler feed water stream. A steam generation system may convert the boiler feed water stream to steam; an outlet for providing steam from the steam generation process to the enhanced oil recovery system.

[0007] In some embodiments, the deoiling system may include a free water knockout drum to separate the oil-water emulsion into a free water fraction and an oil-emulsion fraction; an oil treater for contacting the oil-emulsion fraction with a hydrocarbon solvent to reduce a density and viscosity of the hydrocarbons in the oil-emulsion fraction and forming an oil fraction and a water-oil suspension containing residual oil; a skim/surge tank for coalescing the residual oil in the water-oil suspension and producing a coalesced oil fraction and a water effluent; a dissolved gas flotation unit for further de-oiling the water effluent, producing an oil fraction and a water fraction containing less than 10 ppm oil; and an optional deoiled /
makeup water storage tank for storing the water fraction prior to feed to the high temperature electrocoagulation system.

[0008] The deoiling system may also include a diluent feed system for providing the hydrocarbon solvent to the deoiling system. In some embodiments, natural gas feed system for providing natural gas to one or more tanks of the deoiling system, and/or a heat exchanger for reducing a temperature of the water-oil suspension to less than 95 C via indirect heat exchange with one or more of air, glycol, or boiler feed water, and/or an oil recovery / slop tank for further dewatering of the coalesced oil fraction.
One or more feed lines may also be provided in the deoiling system for admixing the water fraction with one or more of groundwater, brackish water, filtered makeup water, or recycled neutralized ion exchange regenerant waste water or for providing one or more of groundwater, brackish water, filtered makeup water, or recycled neutralized ion exchange regenerant waste water to the skim/surge tank.

[0009] The water-oil suspension may have less than 3000 ppm residual oil.
The system may also include a chemical treatment feed system for admixing chemicals with the water-oil suspension to enhance coalescence of oil droplets.

[0010] The high temperature electrocoagulation system may include electrocoagulation cells for ionizing, complexing, and/or absorbing the dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants in the water fraction. The high temperature electrocoagulation system may further comprise of a vapor inlet for injecting a gas into the electrocoagulation cells for promoting flotation and removal of solids/froth generated.

[0011] The system may also include a chemical feed system for mixing pre-treatment chemicals with the water fraction prior to processing the water fraction in the deoiling system and high temperature electrocoagulation system. In various embodiments, the water separation and solids/froth/sludge dewatering system comprises one or more of a vacuum clarifier, a filter press, a sequential baffle solids/froth separating / breaking cell or tank, a hydrocyclone, a dissolved gas floatation system, a micro-media filter, a settling pond, or a sludge dewatering filter press.

[0012] A sludge conditioning chemical addition system may be used in some embodiments for admixing sludge conditioning chemicals to the solids/froth or sludge fraction upstream or downstream of one or more of the hydrocyclone, dissolved gas floatation system, the settling pond, or the sludge dewatering filter press. The polishing system may include one or more of a strong acid cation exchanger or a weak acid cation exchanger, wherein the exchangers are used alone or together, and in series or in parallel. The system may also include a neutralization regen waste storage tank for receiving the regeneration waste water stream and an additive feed system for adjusting the pH of the regeneration waste water stream. A
flow line may be provided for feeding pH adjusted regeneration waste water from the neutralization regen waste storage tank to the deoiling system or for admixture with the water fraction upstream of the high temperature electrocoagulation system.

[0013] The system may also include a steam deaerator for removing entrained gases from the boiler feed water stream. Additionally, the steam generation system further comprising one or more of: an ammonia or volatile amine feed system for admixing ammonia or a volatile amine with the steam upstream of the enhanced oil recovery system; a medium/low pressure steam separator; a disposal well treatment process;
disposal tanks; an excess utility steam condenser; an oxygen scavenger and boiler feed water conditioner additive system; a desuperheater; a flash evaporator; a crystallizer; or a carbon dioxide scrubber.

[0014] In another aspect, embodiments disclosed herein relate to a process for providing steam to an enhanced oil recovery system. The process may include a step of receiving an oil-water emulsion from an enhanced oil recovery system, the emulsion comprising one or more of dissolved solids, entrained gases and/or light hydrocarbons, distillate and/or heavier hydrocarbons, and water. The entrained gases and/or light hydrocarbons may be separated from the oil-water emulsion, producing a vapor stream and an oil-water stream. The oil-water stream may be separated into a recovered oil fraction and a water fraction containing dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants. The water fraction may then be processed in a high temperature electrocoagulation system for ionizing, complexing, and/or absorbing the dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants in the water fraction, producing a vapor fraction and a solids/froth/water mixture. The solids/froth/water mixture may be separated into a sludge fraction and a clarified water fraction. A total hardness of the clarified water fraction may be reduced to less than 0.2 ppm, producing a regeneration waste water stream and a boiler feed water stream. A steam generation system may then convert the boiler feed water stream to steam, providing steam from the steam generation process to the enhanced oil recovery system.
DETAILED DESCRIPTION

[0015] Embodiments disclosed herein relate generally to systems and processes for water treatment, steam generation and waste treatment. In some embodiments, central processing facilities disclosed herein may be used in association with enhanced oil recovery systems, such as cyclic steam stimulation (CSS), steam assisted gravity drainage (SAGD) or other heavy oil recovery systems, to deoil the water, treat the water, generate steam, and treat generated wastes. In other embodiments, central processing facilities disclosed herein, or variants thereof, may be used in association with other processes that may benefit from such water treatment or enhancement processes, such as mining operations.

[0016] The "Front To Back" (FTB) Central Processing Facility (CPF) systems disclosed herein may incorporate six major water treatment, steam generation and blowdown waste treatment steps for Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), or Steam Flood enhanced oil recovery operations.

[0017] The major steps that may be included in embodiments herein are:
High Quality De-oiling; high temperature Electrocoagulation (EC); EC Sludge/ Solids Separation, Dewatering, and Filtration; Low Hardness (Polishing) and Deaeration;
Once-Through Steam Generators (OTSGs) or Force Circulation Steam Generators (FCSGs) or Heat Recovery Steam Generators (HRSGs) for High and/or Low Pressure Steam Production; and Blowdown Waste Treatment.

[0018] The heart of the water treatment process incorporates the use of a high temperature (HT) EC process for efficient and cost effective removal of hardness, silica, total organic carbon and suspended solids. The HT EC process has yet to be utilized commercially for primary treatment of produced or mixed produced plus fresh and/or brackish makeup water in steam enhanced operations in the heavy oil industry. Integrating EC as a primary treatment process results in a reduction in the composition complexity of boiler feed water (BFW) and blowdown wastewater produced by the steam generating processes.

[0019] The reduced BFVV composition complexity enables steam generators, such as OTSGs, installed at thermal heavy oil facilities to produce a steam quality in excess of 90% while significantly reducing the risk of organic or mineral salt fouling, overheating and failure of tubes in the steam generator convection or radiant sections. Similarly, due to the reduced blowdown wastewater composition complexity, the risk of fouling or plugging of disposal systems is significantly reduced whether the FTB CPF design includes the application of evaporator processes installed downstream of the steam generating processes or not. The reduced wastewater composition complexity enables the efficiency and service factor of optional evaporation processes and subsequent waste disposal systems described herein to be maximized.

[0020] Key changes to current CPF designs used for the heavy oil industry through application of one of the FTB CPF designs according to embodiments herein may include one or more of: Exclusion of Oil Removal Filters; Exclusion of Hot or Warm Lime Softeners; Exclusion of Front End Mechanical Vapor Compression;
Exclusion of Primary Ion Exchangers; Exclusion of Disposal Wells for handling Ion Exchange Regeneration Wastes; and Reduction of Waste Solids quantity, toxicity and/or handling complexity generated for landfill compared to lime softening processes or Zero Liquid Discharge (ZLD) processes.

[0021] The improved BFW quality generated by the FTB process enables once-through steam generators ("OTSG") to generate a steam quality of >90%, thereby reducing high pressure and subsequent low pressure separator blowdown streams by >50%, relative to traditional targets currently used. The much lower blowdown production allows the producer to meet or exceed the current environmental regulatory guidelines, such as those set forth in the Alberta Energy Resources guidelines, without further blowdown waste treatment. Depending on the total dissolved solids (TDS) concentration of the produced water from the field and availability of disposal wells, salt cavern or other disposal services, the FTB CPF
design can eliminate the need to utilize evaporation to further reduce blowdown waste to disposal.

[0022] Where the TDS of the produced water or combined produced-makeup waters result in generating BFW that is above the allowable OTSG operating specifications or where waste water disposal options are limited or too costly, the FTB CPF
design options available can reduce BFW TDS or reduce waste to disposal to achieve near ZLD or actual ZLD capability. These reductions may be achieved through the use of either a slip stream evaporator or the use of steam generation blowdown evaporation and crystallization without the challenges of handling high hardness or high silica and high molecular weight organics in the evaporation or crystallization processes.

[0023] In addition to adopting the entire FTB-CPF design for new plants, embodiments herein may incorporate EC with other water treatment processes in the overall FTB-CPF design to provide add-on debottlenecking solutions to increase steam quality or increase the quantity of steam to field for thermal heavy oil facilities. The facilities where the add-on debottlenecking FTB designs can be used include but are not limited to: Smaller Ion Exchange only - OTSG operations, Larger Lime Softening-OTSG operations, and Evaporator - Drum Boiler operations.

[0024] The FTB-CPF designs according to embodiments herein, and useful for full scale commercial CSS, Steam Flood, and SAGD thermal heavy oil operations are shown in Figures 1-14, where Figures 1-6 focus on FTB-CPF cyclic steam stimulation configurations, and Figures 7-14 focus on FTB-CPF steam assisted gravity drainage configurations, each of which are described further below.

[0025] HIGH QUALITY DEOILING

[0026] Oil/Water/Gas emulsion streams entering the Central Processing Facility undergo field gas separation followed by primary oil-from-water separation that occurs through the use equipment such as a Free Water Knockout (FWKO) and an Oil Treater (OT) that may, in some embodiments, utilize the addition of a hydrocarbon solvent or "diluent" to lower the density and viscosity of the oil and enhance oil separation from the water. The produced water recovered from the FWKO and OT may be cooled to less than 95 C through heat exchange with OTSG
BFW and (if needed) an aerial or glycol cooler. The produced water from the FWKO and OT is transferred to a skim/surge tank (ST), and may contain an average of 2000 ppm of residual oil, in some embodiments, less than 3000 ppm or less than 3500 ppm in other embodiments, with excursions that may exceed 5000 ppm for short periods.

[0027] The produced water-oil suspension in the feed to the ST is chemically treated to enhance coalescence of the oil droplets to effect more rapid gravity separation of the oil that rises to the surface in the tank. The ST may be designed to reduce the oil in water concentration in the effluent to 10% of the inlet concentration. The oil separated in the ST is skimmed off and returned to either the FWKO or an oil recovery/slop tank for additional treatment and dewatering. Embodiments of the current processes allow the elimination of other steps that would normally be found in existing processes, including Hot/Warm lime softening and/or front end MVC
vapor recovery.

[0028] The ST effluent is further de-oiled with a dissolved gas floatation unit (DGF).
The dissolved gas floatation unit may be designed to reduce the oil in water to less than 10 ppm, for example. Oil that is separated from the water and skimmed off from the DGF unit is returned to the skim tank or transferred to the recovery/slop oil tank.

[0029] The deoiled produced water from the DGF unit may be transferred to an optional deoiled / makeup water storage tank, where the deoiled product may be thoroughly mixed with filtered makeup water from groundwater or surface water sources (with or without pH adjustment) and recycled neutralized weak acid cation exchange regenerant waste water prior to being transferred to the high temperature electrocoagulation process.

[0030] ELECTROCOAGULATION

[0031] The benefits of high temperature electrocoagulation (HT EC) are the elimination of the Hot/Warm lime softening and/or eliminating the need for using front end evaporators to produce a higher quality BFW to enable the OTSGs to produce a >90% steam quality that will lower the volume and improve the quality of the blowdown (i.e. less silica and organics), enabling the blowdown to be more easily treated and disposed of. Similarly the FTB processes herein allow the elimination of a Front End MVC Vapor Recovery process to produce BFW for steam generation in drum boilers or forced circulation steam generators, both of which are not the most cost effective water treatment to steam generation processes.
As used herein, high temperature electrocoagulation refers to electrocoagulation processes operated at, for example, temperatures greater than 60 C.

[0032] The blended water from the deoiled/makeup water storage tank is pumped and evenly distributed to the required correctly sized number of operating electrocoagulation ("EC") cells. EC cells are described, for example, in W099/43617. The high temperature EC system may be designed to include one spare cell to enable servicing of an operating cell intermittently as required while maintaining treatment throughput capacity. The EC cells, depending on required capacity, may be sized to hold up to 217 plates, such as iron or aluminum electrode plates, for example. DC power is supplied to the cells to deliver up to 7 kw/m3 of throughput with iron consumption by the process typically between 0.02 to 0.03 kg/m3 of treated water. The power supply polarity across the plates may be reversed periodically to help prevent deposits from building up on the plates.
Additionally, in some embodiments, the pH of the feed to the HT EC system may be modified to improve or optimize EC contaminant removal efficiency.

[0033] The iron that dissolves during the EC process is simultaneously converted to a charged oxidized particle while ionizing/complexing/absorbing dissolved silica, hardness, total organic carbon and many other dissolved organic and inorganic contaminants, including multivalent contaminants. This sequence promotes coagulation of the free suspended oil and solids that all combine and make up the composition of the entrained suspended solids/froth. The solids/froth/water mixture flows out of the EC cell into a collection trough that feeds the downstream solids/froth/solids water breaking and separation unit. The EC cell and the trough are fitted with a vapor containment cover to direct any gases or vapors generated to a dedicated knockout drum and discharge vent or recovered for fuel gas or disposal using a Vapor Recovery Unit (VRU). The EC unit design includes the option to inject air or inert gas into the bottom of the cell to promote floatation and removal of the solids/froth generated. Fugitive toxic gas emissions are not expected to exceed regulatory limits but may be recovered through the use of a VRU.

[0034] The electrode plates and EC cells are cleaned, "pickled,"
sequentially and routinely to maintain electrocoagulation energy efficiency using a dilute HC1 or H2SO4 acid clean-in-place (CIP) solution stored in a separate single tank dedicated to service all EC cells. The CIP solution is used over and over until the acid strength is depleted at which time the exhausted solution is pH neutralized and directed back, at a steady controlled rate, into the feed distribution line to the EC cells for treatment where the contaminants in the solution are removed as solids/froth.

[0035] SOLIDS SEPARATION, DEWATERING and FILTRATION

[0036] The solids/froth/water mixture generated by the EC process flows into a solids-froth-water separation process. Three process options may be used to remove the froth entrained gas and consolidate the entrained solids for dewatering.

[0037] Option 1 ¨Solids/Froth Breaking Cell and HydroCyclone

[0038] The first option is to allow the EC froth-water mixture into to a three stage enclosed sequential cascading solids/froth breaking (defoaming) cell. The solids/froth breaker uses strategically designed spreaders and water sprays to break the foam and entrain the solids. The solids entrained water passes through hydrocyclones designed to maximize the removal of fine entrained solids, such as particles, and reduce the clarified solids concentration in the effluent to less than 30 mg/L. The hydrocyclone system may include provisions to include coagulation or flocculation upstream or downstream to further maximize solids removal and subsequent filtration or dewatering efficiency. The separated solids collected in the bowl of the hydrocyclone unit are discharged, as required, to be sent to a surge tank and filter press for final dewatering and subsequent landfill, or may be alternatively sent to a settling pond or centrifuge for disposal. Off spec water from the hydrocyclones will be treated with chemical and may be recycled back through the EC system or defoaming unit via the filter dirty backwash storage tank for re-processing or sent through a secondary off-spec polishing hydrocyclone unit.

[0039] Option 2 ¨ Vacuum Clarifier & Filter Press

[0040] The second option passes the solids/froth/treated water mixture down through a vacuum clarifier to collapse the solids/froth and allow solids to gravity settle and concentrate in a clarifier tank below. The settled solids are removed via a bottom rotating rake in the tank to be removed and pumped to a filter press or alternatively to a pond or centrifuge for dewatering.

[0041] Option 3 ¨Froth Transfer and Gas Floatation

[0042] The third option is to transfer the froth laden treated EC mixture to a DGF
unit. The use of air, nitrogen or sweet natural gas may be selected as the floatation gas for the DGF. The solids/froth in the feed to the DGF are separated from the produced water by gas floatation and skimmed off the top. The skimmed solids are transferred to a solids slurry-mix tank, which may or may not undergo chemical treatment, to coagulate the solids prior to dewatering by either a filter press or centrifuge or alternatively sent to a settling pond.

[0043] The clarified separated water from any of the above water solids separation processes is filtered using micro-media filters or alternatively ultrafiltration membranes to remove trace solids from the clarified water. The filters are designed to produce an effluent having a turbidity value of less than 2 and a solids content of less than 1 ppm. When solids loading on the micro media filters create a pressure drop that reduces the throughput capacity of the filters, the filter media is air or gas scoured and then backwashed. Should an ultrafiltration system be utilized the membranes are constantly discharging a concentrated slurry to the dirty backwash tank and undergo a high pressure back pulse intermittently to dislodge entrapped solids within the membrane lattice. Filtrate from the media filters supplies clean backwashing (BW) water to the clean BW water storage tank. The dirty backwash or slurry stream from the filtration system backwashing sequence is sent to a dirty backwash tank then recycled back to the inlet of the solids/froth defoaming cell or hydrocyclone unit. Intermittent chemical cleaning combined with air scour cleaning of the micro-media filter media is optional and used as required to maintain media quality and filter performance.

[0044] RESIDUAL HARDNESS REMOVAL AND DEAERATING

[0045] The effluent from the EC process and filtration system may contain hardness that requires removal using Weak Acid Cation (WAC) polishers to an acceptable BFW concentration of less than 0.2 ppm. The WAC units are operated in the Sodium (Nat) form and are regenerated in-situ with dilute HC1 (acid) to remove the exchanged hardness then converted to the Na + form with dilute NaOH (caustic).

Boiler Feed Water is used to dilute the concentrated chemicals delivered to the plant to prepare the chemical regenerants. When process conditions and produced and/or makeup water total hardness (TH) levels are excessive thereby significantly increasing the EC effluent TH, thereby risking hardness leakage into the BFW
stream, embodiments herein contemplate the use of a dual primary ¨ polishing WAC
ion exchange configuration to be included in the FTB-CPF design.

[0046] A unique feature of the FTB-CPF design is the recycling and treatment of the regeneration waste water. The regeneration waste water generated may be pH
adjusted to neutrality in a neutralization tank with additional acid or caustic then recycled in a slow controlled manner to the inlet of the EC cells while in operation or mixed with the incoming produced water in the skim or optional deoiled /
make-up water storage tank. When the regeneration waste water hardness is processed by the EC unit the majority of the hardness contaminants are removed as solids to a level required for ion exchange. This recycle treatment feature eliminates the need for a dedicated waste disposal well for the regeneration waste water or the use of costly chemicals to precipitate the waste dissolved hardness by lime softening. The sodium and chloride ions present in the regeneration waste water stream are monovalent ions and are not removed by the EC process and significantly impact the TDS of the regenerant waste water. High TDS of the regenerant waste water will impact the total TDS and chloride concentration of the BFW somewhat depending upon regenerant waste water volume and rate of recycle. For thermal heavy oil produced waters the TDS and chloride concentrations are typically low enough to enable recycle of the regeneration waste water while maintaining a BFW
chloride concentration below the maximum target concentration of 3500 mg/L for OTSGs fitted with conventional tubing material and producing at least 90% steam quality.

[0047] The softened BFW may be deaerated using a steam deaerator before being stored in a BFW storage tank prior to steam generation. Steam to the deaerator may be supplied from the medium and/or low pressure steam separators located in the steam plant or via a low pressure letdown station should insufficient low pressure steam be available for the deaerator. The deaerated BFW out of the BFW storage tank may be treated with an oxygen scavenger to remove trace oxygen to less than 0.007 ppm and if necessary caustic to adjust the pH to 9.0 to meet boiler feedwater guidelines, such as those specified by the American Boiler Manufacturers Association (ABMA) or the American Society of Mechanical Engineers (ASME).

[0048] STEAM GENERATION

[0049] The OTSG steam generators, which may or may not be fitted with rifle tubes in up to 50% of the latter part of the radiant section, may be used to produce 90% or greater steam quality.

[0050] For CSS or Steam Flood facilities, all of the 90% quality steam that the OTSG
produces may be sent to the field for injection. At CSS or Steam Flood facilities the utility steam needed to operate the FTB deaerator is supplied via a high pressure steam letdown station on the outlet of the OTSGs or alternatively a utility boiler package is provided.

[0051] For SAGD facilities, the steam phase is separated from the liquid phase by a high pressure separator (HPS) to deliver 100% quality steam to the field. At SAGD
facilities, a volatile-filming amine may be injected into the 100% steam to field distribution line as the traditional method to control the potential for carbonic acid corrosion in the line. An alternative option may be used for the FTB CPF
designs according to embodiments herein, where liquefied ammonia may be used to provide similar corrosion protection.

[0052] For SAGD facilities where the HPS produces blowdown (BD) the HP BD
pressure is let down in a medium pressure (MP) and/or a low pressure (LP) steam separator with an optional de-super heater installed off the HPS unit to ensure sufficient utility steam is available for subsequent blowdown treatment to maximize water reuse and minimize waste disposal quantities. The MP plus LP steam separators together typically can convert up to 40% of the water to MP and LP
steam that is used to operate the BFW steam deaerator and provide some or all of the steam needed to operate an optional "back-end" multiple effect evaporator or optional crystallizer for maximizing water reuse and minimizing blowdown waste for disposal. Where insufficient MP or LP steam is available for operating back-end blowdown waste reduction evaporators and optional crystallizers, additional steam may be supplied via a de-super heater.

[0053] BOILER PRIMARY AND SECONDARY BLOWDOWN TREATMENT

[0054] The blowdown remaining from the MP or LP steam separator can be cooled via cross exchange with BFW, and / or an aerial or glycol cooler, and sent to a disposal well. The volume of blowdown may meet the regulatory guidelines for waste disposal and water reuse. The FTB-CPF options available to maximize water reuse and minimize disposal include additional treatment utilizing a multiple effect evaporator system with optional stack gas scrubber and/or optional crystallizer system to: meet regulatory guidelines; achieve near ZLD capability;
Participate in a Green House Gas emission reduction initiatives to receive carbon credits or reduce carbon taxes; and/or achieve ZLD capability.

[0055] Figures 2-4 and 6-10 are various FTB-CPF Block Flow Diagrams that illustrate the TDS reduction evaporator and blowdown evaporator treatment options for CSS and SAGD facilities, and are described further below. The FTB-CPF for steam flood facilities is essentially the same as the CSS case except for minor differences in the oil treating unit, but the water treatment and steam generation units are identical.

[0056] The FTB-CPF design provides for recycle of a portion of the blowdown stream back to the HT EC unit inlet, should the TDS of the BFW be less than ppm for a 90% steam quality OTSG operations having radiant tubes rated for handling up to 35,000 mg/L of chlorides in the blowdown water phase. For higher TDS BFW, the OTSG radiant section tube material of construction for some or all of the tubes may be changed to handle higher chloride concentrations, which may not be economically feasible, thereby preventing further recovery of blowdown fluids.

[0057] The above-described processes according to embodiments herein are illustrated in Figures 1-10, described below.

[0058] The block flow diagram of Figure 1 provides an overview of a front-to-back central processing facility for a CSS enhanced oil recovery system according to embodiments herein. Figure 1, similar to other figures herein, is a block flow diagram, illustrating primary steps in the CSS FTB-CPF designs according to embodiments herein.

[0059] The front-to-back central processing facility for a CSS enhanced oil recovery system as illustrated in Figure 1 may include six primary stages, including primary gas-oil-water separation stage 10, a high quality de-oiling stage 20, high temperature electrocoagulation stage 30, waste separation and froth/sludge dewatering stage 40, low hardness removal and boiler feed water storage stage 50, and steam generation stage 60.

[0060] A produced emulsion 12, such as an oil-water emulsion from an enhanced oil recovery system, is fed to an inlet of the gas-oil-water separation stage 10.
The produced oil-water emulsion may be provided directly or indirectly from an enhanced oil recovery system, and may include one or more of dissolved solids, entrained gases and/or light hydrocarbons, distillate and/or heavier hydrocarbons, and/or water. In primary gas-oil-water separation stage 10, the emulsion is treated so as to separate the entrained gases and light hydrocarbons from the oil and water in the emulsion. The gases evolved may be fed via flow line 14 to a vapor recovery unit (not shown) for further processing. The remaining oil-water emulsion may then be fed via flow line 16 to de-oiling stage 20.

[0061] Deoiling system 20 may separate the oil-water emulsion in stream 16 into a recovered oil fraction 22 and a water fraction 24. Water fraction 24 may contain, among other components, dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants. To facilitate the separations, a hydrocarbon solvent 25 may be used to reduce a density and viscosity of the hydrocarbons in the oil-emulsion fraction and forming an oil fraction and a water-oil suspension containing residual oil.

[0062] To maintain an inert atmosphere in various tanks and other unit operations in the de-oiling system, a blanket gas that is typically natural gas and could be an inert gas, such as nitrogen, may be provided via flow line 26. The vapors recovered from the tank and unit operation vents may be recovered via one or more flow lines and fed to a vapor recovery unit, such as a common vapor recovery unit with the primary gas-oil-water separations, for recovery or further processing of the vapor streams, including any water, vaporized solvent, and light hydrocarbons therein.

[0063] Other feed streams to the de-oiling system may include a water feed 27, which may be used to provide fresh ground, brackish, or make-up water to the system.

Lastly, a neutralized regen waste recycle stream 28 may be provided from low hardness removal and boiler feed water storage stage 50 for further processing through the FTB-CPF.

[0064] The water fraction 24 may then be fed to high temperature electrocoagulation system 30. The high temperature electrocoagulation system is configured for ionizing, complexing, and/or absorbing the dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants in the water fraction, producing a vapor fraction 32 and a solids/froth/water mixture 34.
Chemicals may be used to pre-treat the feed to the high temperature electrocoagulation unit, and may be supplied via flow line 36. A recycle stream 38, such as a filtrate recycle from waste separation and solids/froth/sludge dewatering stage 40 may also be provided to the high temperature electrocoagulation system.

[0065] Water separation and solids/froth/sludge dewatering system 40 may separate the solids/froth/water mixture 34 into a sludge fraction 42, which may include filtered solids, and a clarified water fraction 44. A vapor stream 46 may also be recovered from water separation and solids/froth/sludge dewatering stage 40, and processed in the above-noted vapor recovery unit. Sludge conditional chemicals, if used, may be fed to water separation and solids/froth/sludge dewatering system via flow line 48.

[0066] The clarified water fraction 44 may then be fed to low hardness removal and boiler feed water storage stage 50. The "polishing" system may reduce a total hardness of the clarified water fraction to less than 0.2 ppm, for example, producing a regeneration waste water stream 28 and a boiler feed water stream 52. Ion exchange regen chemicals may be fed to system 50 via flow line 54, and vent gases recovered via flow line 56 may be processed in the vapor recovery unit, as noted above. Steam used in the polished water deaerator for producing and pre-heating boiler feed water for storage stage 50 may be supplied from the steam generation stage 60 via flow line 58.

[0067] Steam generation stage 60 may be used to convert the water in boiler feed water stream 52 to steam, such as by using once through steam generators, as noted above. Steam generated in steam generation system 60 may be provided to the enhanced oil recovery system (not shown) via flow line 62, to the polished water deaerator for producing and pre-heating boiler feed water for storage stage 50 via flow line 58, and to other uses via one or more steam lines 64. Other outputs from steam generation stage 60 may include OTSG stack gas 66, solids / landfill waste stream 67, and blowdown water 68 to a disposal well or treatment process (not shown). As needed, boiler feed water conditioner 70 and oxygen scavenger 72 may be introduced to the steam generation system 60 as well.

[0068] Various steps within each of the noted system blocks illustrated in Figure 1 are described above, and below in Figures 2-6, and as such are not described in detail with respect to Figure 1. Figure 1 simply provides a general overview of the various systems used in the FTB-CPF according to embodiments herein that may be used with a CSS enhanced oil recovery system.

[0069] Referring now to Figure 2, a block process flow diagram of a front-to-back central processing facility for a CSS enhanced oil recovery system according to embodiments herein is illustrated, illustrating embodiments of steps 10 and 20 of Figure 1 in greater detail, where like numerals represent like parts.

[0070] A produced emulsion 12, such as an oil-water emulsion from a CSS
enhanced oil recovery system, is fed to an inlet of the gas-oil-water separation stage 10. The produced oil-water emulsion may be provided directly or indirectly from a CSS
enhanced oil recovery system, and may include one or more of dissolved solids, entrained gases and/or light hydrocarbons, distillate and/or heavier hydrocarbons, and/or water. In primary gas-oil-water separation stage 10, the emulsion may be treated initially in a Free Water Knockout (FWKO) drum 210 to separate the entrained gases and light hydrocarbons from the oil and water in the emulsion.
The gases evolved may be fed via flow line 14 to a vapor recovery unit (not shown) for further processing. The remaining oil-water emulsion may then be fed via flow line 16 to de-oiling stage 20.

[0071] Deoiling system 20 may separate the oil-water emulsion in stream 16 into a recovered oil fraction 22 and a water fraction 24. Water fraction 24 may contain, among other components, dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants. Oil-water emulsion 16 may be fed to an Oil Treater (OT) 215 for recovery of oil from water. To facilitate the separations in OT 215, a hydrocarbon solvent 25 may be used to reduce a density and viscosity of the hydrocarbons in the oil-emulsion fraction and forming an oil fraction 22 and a water-oil suspension (produced water) 217 containing residual oil.

[0072] The produced water 217 recovered from the FWKO 210 and OT 215 may be cooled to less than 95 C through heat exchange with OTSG BFW and (if needed) an aerial or glycol cooler (one or more exchangers 219). The produced water 217 from OT 215 is transferred to a skim/surge tank (ST) 220, and may contain an average of 2000 ppm of residual oil, in some embodiments, less than 3000 ppm or less than 3500 ppm in other embodiments, with excursions that may exceed 5000 ppm for short periods.

[0073] The produced water-oil suspension 217 in the feed to ST 220 may be chemically treated to enhance coalescence of the oil droplets to effect more rapid gravity separation of the oil that rises to the surface in the tank. The ST
220 may be designed to reduce the oil in water concentration in the effluent to 10% of the inlet concentration. The oil separated in ST 220 is skimmed off and returned via flow line 222 to one of OT 215, FWKO 210, or an oil recovery/slop tank (not illustrated) for additional treatment and dewatering.

[0074] ST 220 effluent 224 may be further de-oiled with a dissolved gas floatation unit (DGF) 225. The DGF unit 225 may be designed to reduce the oil in water to less than 10 ppm, for example. Oil that is separated from the water and skimmed off from the DGF unit may be returned via flow line 227 to the skim tank 220 or transferred to a recovery/slop oil tank (not shown).

[0075] The deoiled produced water 229 from the DGF unit 225 may be transferred to an optional deoiled / makeup water storage tank 230, where the deoiled product may be thoroughly mixed with filtered makeup water 27 from groundwater or surface water sources (with or without pH adjustment) and recycled neutralized weak acid cation exchange regenerant waste water 28 prior to being transferred to the high temperature electrocoagulation process (Figure 3) via flow line 24.

[0076] To maintain a non oxidizing atmosphere in various tanks and other unit operations in the de-oiling system, a blanket gas that is typically natural gas but could be an inert gas, such as nitrogen, may be provided via flow line 26. The vapors recovered from the tank and unit operation vents may be recovered via one or more flow lines 23 and fed to a vapor recovery unit, such as a common vapor recovery unit with the primary gas-oil-water separations vent 14, for recovery or further processing of the vapor streams 14, 26, including any water, vaporized solvent, and light hydrocarbons therein.

[0077] Referring now to Figure 3, a block process flow diagram of a front-to-back central processing facility for a CSS enhanced oil recovery system according to embodiments herein is illustrated, illustrating embodiments of steps 30 and 40 of Figure 1 in greater detail, where like numerals represent like parts.

[0078] The water fraction 24 may then be fed to high temperature electrocoagulation system 30. The high temperature electrocoagulation system is configured for ionizing, complexing, and/or absorbing the dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants in the water fraction, producing a vapor fraction 32 and a solids/froth/water mixture 34.
The blended water 24 from the deoiled/makeup water storage tank is pumped and evenly distributed to the required correctly sized number of operating electrocoagulation ("EC") cells in high temperature EC system 30. As noted above, the EC cells may hold iron or aluminum plates, for example. DC power is supplied to the cells to deliver up to 7 kw/m3 of throughput with electrode plate consumption by the process typically between 0.02 to 0.03 kg/m3 of treated water.

[0079] Chemicals used to pre-treat the feed to the high temperature electrocoagulation unit may be supplied via flow line 36. A recycle stream 38, such as a filtrate recycle from clean boiler water storage tank 320 in waste separation and froth/sludge dewatering stage 40 may also be provided to the high temperature electrocoagulation system.

[0080] The power supply polarity across the plates may be reversed periodically to help prevent deposits from building up on the plates. Additionally, in some embodiments, the pH of the feed to the HT EC system may be modified to improve or optimize EC contaminant removal efficiency. The iron or aluminum electrodes that dissolve during the EC process is simultaneously converted to a charged oxidized particle while ionizing/complexing/absorbing dissolved silica, hardness, total organic carbon and many other dissolved organic and inorganic contaminants, including multivalent contaminants. This sequence promotes coagulation of the free suspended oil and solids that all combine and make up the composition of the entrained suspended froth 34. The solids/froth/water mixture 34 flows out of the EC
cell into a collection trough (not shown) that feeds the downstream solids/froth water separation unit 325. The HT EC cell and the trough may be fitted with a vapor containment cover to direct any gases or vapors generated via flow line 32 to a dedicated knockout drum and discharge vent or recovered for fuel gas or disposal using a Vapor Recovery Unit (VRU) (not shown), which may be the same or different VRU than that used with respect to stages 10 and 20. The HT EC unit design may include the option to inject air or inert gas 323 into the bottom of the cell to promote floatation and removal of the froth solids generated. Fugitive toxic gas emissions are not expected to exceed regulatory limits but may be recovered through the use of the VRU.

[0081] The electrode plates and EC cells are cleaned, "pickled,"
sequentially and routinely to maintain electrocoagulation energy efficiency using a dilute HC1 or H2SO4 acid clean-in-place (CIP) solution stored in a separate single tank 329 dedicated to service all EC cells. The C1P solution is used over and over until the acid strength is depleted at which time the exhausted solution is pH
neutralized and directed back, at a steady controlled rate, into the feed distribution line to the EC
cells for treatment, where the contaminants in the solution are removed as solids in the froth 34.

[0082] Water separation and froth/sludge dewatering system 40 may separate the solids/froth/water mixture 34 into a sludge fraction 42, which may include filtered solids, and a clarified water fraction 44. A vapor stream 46 may also be recovered from water separation and froth/sludge dewatering stage 40, and processed in the above-noted vapor recovery unit. Sludge conditional chemicals, if used, may be fed to water separation and froth/sludge dewatering system 40 via flow line 48.

[0083] As illustrated in Figure 3, the HT EC effluent, froth-water mixture 34, nay be fed into to a three stage enclosed sequential cascading froth breaking (defoaming) cell 325. The froth breaker 325 uses strategically designed spreaders and water sprays to break the foam and entrain the solids, producing a solids entrained water effluent 331.

[0084] The solids entrained water 331 passes through hydrocyclones 330, which may be designed to maximize the removal of fine entrained solids as small as 10 micron in size, and reduce the clarified solids concentration in the resulting effluent 337 to less than 30 mg/L. The hydrocyclone system 330 may include provisions to include coagulation of flocculation upstream or downstream to further maximize solids removal and subsequent filtration efficiency. The separated solids collected in the bowl of the hydrocyclone unit are discharged via flow line 339, as required, and sent to a surge tank and filter press 340 for final dewatering and subsequent landfill of solids 42. Off spec water 336 from the hydrocyclones may be treated with chemical and may be recycled back through the EC system (as shown) or defoaming unit via the filter dirty backwash storage tank for re-processing or sent through a secondary off-spec polishing hydrocyclone unit (not shown).

[0085] The clarified separated water 337 from hydrocyclone 330 is then filtered using micro-media filters 345 or alternatively ultrafiltration membranes to remove trace solids from the clarified water. The filters 345 may be designed to produce an effluent having a turbidity value of less than 2 and a solids content of less than 1 ppm. When solids loading on the micro media filters 345 create a pressure drop that reduces the throughput capacity of the filters, the filter media is air or gas scoured and then backwashed. Should an ultrafiltration system be utilized the membranes are constantly discharging a concentrated slurry to the dirty backwash tank and undergo a high pressure back pulse intermittently to dislodge entrapped solids within the membrane lattice. Filtrate from the media filters supplies clean backwashing (BW) water to the clean BW water storage tank. The dirty backwash or slurry stream from the filtration system backwashing sequence is sent to a dirty backwash tank then recycled back to the inlet of the solids/froth defoaming cell. Intermittent chemical cleaning via clean-in-place system 346 combined with air scour cleaning of the micro-media filter media is optional and may be used as required to maintain media quality and filter performance.

[0086] The clarified water fraction 44 may then be fed to the clean backwash water storage tank, the low hardness removal and steam deaerator stage 50 (Figure 4) and boiler feed water storage tank 320. One or more water storage tanks 320 may be used to provide a water stream 38 to the HT EC unit 30, as well as feed 44B to stage 50, as a supply of water 348 for backwash of the filtration system 345, and as a supply 354 of water to filter press 340, as needed. For example, a first tank 920 may be used to supply dilution water for the chemicals required for regeneration of the ion exchangers, and clean service water may be provided from a clean backwash water storage tank 920 to provide service water to the HC EC unit (rinse after CIP
treatment), Defoaming Cell, Filter Press and backwashing of the media filters.

Water recovered from the dewatering filter press 340 may be returned via flow line 352 to either HT EC unit 30 or filtration unit 345 for further processing.

[0087] Referring now to Figure 4, a block process flow diagram of a front-to-back central processing facility for a CSS enhanced oil recovery system according to embodiments herein is illustrated, illustrating embodiments of steps 50 and 60 of Figure 1 in greater detail, where like numerals represent like parts.

[0088] The clarified water fractions 44, 44B may then be fed to the clean backwash water storage tank and low hardness removal stage 50, which may include an ion exchange system 410 and a de-aerator 415 in some embodiments. The "polishing"

system 50 may reduce a total hardness of the clarified water fraction to less than 0.2 ppm, for example, producing a regeneration waste water stream 28 and a boiler feed water stream 52.

[0089] The effluent 44, 44B from the EC process and filtration system may contain hardness that requires removal using Weak Acid Cation (WAC) polishers to an acceptable BFVV concentration of less than 0.2 ppm. The WAC units 410 are operated in the Sodium (Nat) form and are regenerated in-situ with dilute HC1 (acid) to remove the exchanged hardness then converted to the Nat form with dilute NaOH
(caustic). Ion exchange regen chemicals may be fed to system 50 via flow line 54, and Boiler Feed Water 44B may be used to dilute the concentrated chemicals delivered to the plant to prepare the chemical regenerants.

[0090] A unique feature of the FTB-CPF design is the recycling and treatment of the regeneration waste water. The regeneration waste water 417 generated in the ion exchange system 410 may be pH adjusted to neutrality in a neutralization tank with additional acid or caustic then recycled in a slow controlled manner via flow line 28 to the inlet of the HT EC cells 30 while in operation or mixed with the incoming produced water 217 in the skim tank 220 or optional deoiled / make-up water storage tank 230 (each in Figure 2). When the regeneration waste water hardness is processed by the EC unit 30, the majority of the hardness contaminants are removed as solids to a level required for ion exchange. This recycle treatment feature eliminates the need for a dedicated waste disposal well for the regeneration waste water or the use of costly chemicals to precipitate the waste dissolved hardness by lime softening. The sodium and chloride ions present in the regeneration waste water stream are monovalent ions and are not removed by the EC process and significantly impact the TDS of the regenerant waste water. High TDS of the regenerant waste water will impact the total TDS and chloride concentration of the BFVV somewhat depending upon regenerant waste water volume and rate of recycle.
For thermal heavy oil produced waters the TDS and chloride concentrations are typically low enough to enable recycle of the regeneration waste water while maintaining a BFW chloride concentration below the maximum target concentration of 5770 mg/L for OTSGs producing at least 90% steam quality.

[0091] The softened BFW 419 may be deaerated using a steam deaerator 415 before being stored in a BFW storage tank 425 prior to steam generation. Steam to the deaerator may be supplied from the medium and/or low pressure steam separators 430 located in the steam plant 60. The deaerated BFW 427 out of the BFW
storage tank 425 may be treated with an oxygen scavenger 72 to remove trace oxygen to less than 0.007 ppm and if necessary caustic 70 to adjust the pH to 9.0 to meet boiler feedwater guidelines, producing a water feed 429 to the steam generators.

[0092] Steam generation stage 60 may be used to convert the water in boiler feed water stream 52 to steam, such as by using once through steam generators 435, as noted above. The OTSG steam generators 435, which may or may not be fitted with rifle tubes in up to 50% of the latter part of the radiant section, may be used to produce 90% or greater steam quality. Combusted fuel, stack gas 66, resulting from the steam generation process may be output via stack 440.

[0093] Steam generated in steam generation system 60 may be provided to the enhanced oil recovery system 445 via flow line 62. During startup, steam and water from steam generator 435 may be routed to a startup blowdown pond 450 via flow line 68. A portion 461 of the boiler feed water 427/429 may also be combined with steam stream 364 in a de-superheater 430 to produce low and/or medium pressure steam for feed to the deaerator 415 via flow line 58, and to other uses via one or more steam lines 64. For CSS or Steam Flood facilities, all of the 90% quality steam that the OTSG produces may be sent to the field 445 for injection.

[0094] Referring now to Figure 5, a block process flow diagram of a front-to-back central processing facility for a CSS enhanced oil recovery system according to embodiments herein is illustrated, illustrating other embodiments of steps 50 and 60 of Figure 1 in greater detail, where like numerals represent like parts.

[0095] The clarified water fractions 44, 44B may be fed to the clean backwash water storage tank and low hardness removal stage 50, which may include an ion exchange system 410 and a de-aerator 415 in some embodiments. The "polishing" system 50 may reduce a total hardness of the clarified water fraction to less than 0.2 ppm, for example, producing a regeneration waste water stream 28 and a boiler feed water stream 52.

[0096] The effluent 44, 44B from the EC process and filtration system may contain hardness that requires removal using Weak Acid Cation (WAC) polishers to an acceptable BFW concentration of less than 0.2 ppm. The WAC units 410 are operated in the Sodium (Nat) form and are regenerated in-situ with dilute HC1 (acid) to remove the exchanged hardness then converted to the Na + form with dilute NaOH
(caustic). Ion exchange regen chemicals may be fed to system 50 via flow line 54, and Boiler Feed Water 44B may be used to dilute the concentrated chemicals 54 delivered to the plant to prepare the chemical regenerants.

[0097] The regeneration waste water 417 generated in the ion exchange system 410 may be pH adjusted to neutrality in a neutralization tank 420 with additional acid or caustic then recycled in a slow controlled manner via flow line 28 to the inlet of the HT EC cells 30 while in operation or mixed with the incoming produced water in the skim tank 220 or optional deoiled / make-up water storage tank 230 (each in Figure 2). When the regeneration waste water hardness is processed by the EC
unit 30, the majority of the hardness contaminants are removed as solids to a level required for ion exchange. This recycle treatment feature eliminates the need for a dedicated waste disposal well for the regeneration waste water or the use of costly chemicals to precipitate the waste dissolved hardness by lime softening. The sodium and chloride ions present in the regeneration waste water stream are monovalent ions and are not removed by the EC process and significantly impact the TDS of the regenerant waste water. High TDS of the regenerant waste water will impact the total TDS and chloride concentration of the BFW somewhat depending upon regenerant waste water volume and rate of recycle. For thermal heavy oil produced waters the TDS and chloride concentrations are typically low enough to enable recycle of the regeneration waste water while maintaining a BFW chloride concentration below the maximum target concentration of 5770 mg/L for OTSGs producing at least 90% steam quality.

[0098] The softened BFW 419 may be deaerated using a steam deaerator 415 before being stored in a BFW storage tank 425 prior to steam generation. Steam 58 to the deaerator may be supplied from the medium and/or low pressure steam separators 430 located in the steam plant 60. The deaerated BFW 427 out of the BFW
storage tank 425 may be treated with an oxygen scavenger 72 to remove trace oxygen to less than 0.007 ppm and if necessary caustic 70 to adjust the pH to 9.0 to meet boiler feedwater guidelines, producing a water feed 429 to the steam generators.

[0099] Steam generation stage 60 may be used to convert the water in boiler feed water stream 429 to steam, such as by using once through steam generators 435, as noted above. The OTSG steam generators 435, which may or may not be fitted with rifle tubes in up to 50% of the latter part of the radiant section, may be used to produce 90% or greater steam quality. Combusted fuel, stack gas 66, resulting from the steam generation process may be output via stack 440.

[00100] Steam generated in steam generation system 60 may be provided to the enhanced oil recovery system 445 via flow line 62. For CSS or Steam Flood facilities, all of the 90% quality steam that the OTSG produces may be sent to the field 445 for injection.

[00101] During startup, steam and water from steam generator 435 may be routed to a startup blowdown pond 450 via flow line 68. A portion 461 of the boiler feed water 427/429 may also be combined with steam stream 364 in a de-superheater 430 to produce low and/or medium pressure steam for feed to the deaerator 415 via flow line 58, and to other uses via one or more steam lines.

[00102] As illustrated in Figure 5, the CSS FTB-CPF embodiment illustrated may be used to maximize water reuse and minimize disposal. Steam from desuperheater 430 may be fed via flow line 462 to a multiple effect evaporator system 470 for TDS
reduction. A slip stream 472 of softened water may be combined with the steam 462, producing a vapor stream 474 and a water stream 476. The rate of the slip stream 472 may be based on the target TDS in the boiler feed water. Water stream 476 may be routed to a disposal well or treatment process 480. Optionally, a crystallizer system 490 may be used to process water stream 476 along with steam 489 for zero liquid discharge capability, producing a solids stream 67 to landfill and a steam stream 478, which may be processed with flash evaporator effluent 482 via cooler 495, such as an aerial heat exchanger, the condensate 497 from which may be fed to deaerator 415 along with softened water 419 for further processing.

[00103] Referring now to Figure 6, a block process flow diagram of a front-to-back central processing facility for a CSS enhanced oil recovery system according to embodiments herein is illustrated, illustrating other embodiments of steps 50 and 60 of Figure 1 in greater detail, where like numerals represent like parts.

[00104] In this embodiment, the clarified water fractions 44, 44B may be processed and turned into steam in a manner similar to that described with respect to Figures 4 and 5. Steam generation stage 60 may be used to convert the water in boiler feed water stream 52 to steam, such as by using once through steam generators 435, as noted above. The OTSG steam generators 435, which may or may not be fitted with rifle tubes in up to 50% of the latter part of the radiant section, may be used to produce 90% or greater steam quality. Combusted fuel, stack gas 66, resulting from the steam generation process may be output via stack 440.

[00105] Steam generated in steam generation system 60 may be provided to the enhanced oil recovery system 445 via flow line 62. During startup, steam and water from steam generator 435 may be routed to a startup blowdown pond 450 via flow line 68. A portion 461 of the boiler feed water 427/429 may also be combined with steam stream 364 in a de-superheater 430 to produce low and/or medium pressure steam for feed to the deaerator 415 via flow line 58, and to other uses.

[00106] As illustrated in Figure 6, the CSS FTB-CPF embodiment illustrated may be used to maximize water reuse and minimize disposal. The CSS FTB-CPF
embodiment of Figure 6 may maximize water reuse and minimize disposal, and includes additional treatment utilizing a multiple effect evaporator system 470 with an optional stack gas scrubber 500 and/or an optional crystallizer system 490 to:
meet regulatory guidelines; achieve near ZLD capability; Participate in a Green House Gas emission reduction initiative to receive carbon credits or reduce carbon taxes; and/or achieve ZLD capability.

[00107] As illustrated, steam from desuperheater 430 may be fed via flow line 462 to a multiple effect evaporator system 470 for TDS reduction. A slip stream 472 of softened water may be combined with the steam 462, producing a vapor stream and a water stream 476. The rate of the slip stream 472 may be based on the target TDS in the boiler feed water.

[00108] Water stream 476 may be routed to a scrubber 500, contacting a slip stream 66B of the stack gas from stack 440. Scrubber 500 may be used to contact the water stream 476 with the stack gas to reduce greenhouse gas emissions and reduce the pH

of the water 476 from the multi-effect evaporator 470. The pH adjusted water may then be fed to a disposal well or treatment process 480. Optionally, a crystallizer system 490 may be used to process water stream 502 along with steam 489 for zero liquid discharge capability, producing a solids stream 67 to landfill and a steam stream 478, which may be processed with flash evaporator effluent 482 via cooler 495, such as an aerial heat exchanger, the condensate 497 from which may be fed to deaerator 415 along with softened water 419 for further processing.

[00109] The block flow diagram of Figure 7 provides an overview of a front-to-back central processing facility for a SAGD enhanced oil recovery system according to embodiments herein. Figure 7, similar to other figures herein, is a block flow diagram, illustrating primary steps in the SAGD FTB-CPF designs according to embodiments herein.

[00110] The front-to-back central processing facility for a SAGD
enhanced oil recovery system as illustrated in Figure 7 may also include six primary stages, including primary gas-oil-water separation stage 710, a high quality de-oiling stage 720, high temperature electrocoagulation stage 730, waste separation and solids/froth/sludge dewatering stage 740, low hardness removal and boiler feed water storage stage 750, and steam generation stage 760.

[00111] A produced emulsion 712, such as an oil-water emulsion from a SAGD
enhanced oil recovery system, is fed to an inlet of the gas-oil-water separation stage 710. The produced oil-water emulsion may be provided directly or indirectly from a SAGD enhanced oil recovery system, and may include one or more of dissolved solids, entrained gases and/or light hydrocarbons, distillate and/or heavier hydrocarbons, and/or water. In primary gas-oil-water separation stage 710, the emulsion is treated so as to separate the entrained gases and light hydrocarbons from the oil and water in the emulsion. The gases evolved may be fed via flow line 714 to a vapor recovery unit (not shown) for further processing. The remaining oil-water emulsion may then be fed via flow line 716 to de-oiling stage 720.

[00112] De-oiling system 720 may separate the oil-water emulsion in stream 716 into a recovered oil fraction 722 and a water fraction 724. Water fraction 724 may contain, among other components, dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants. To facilitate the separations, a hydrocarbon solvent 725 may be used to reduce a density and viscosity of the hydrocarbons in the oil-emulsion fraction and forming an oil fraction and a water-oil suspension containing residual oil.

[00113] To maintain an inert atmosphere in various tanks and other unit operations in the de-oiling system, a blanket gas, such as nitrogen, may be provided via flow line 726. The vapors recovered from the tank and unit operation vents may be recovered via one or more flow lines 723 and fed to a vapor recovery unit, such as a common vapor recovery unit with the primary gas-oil-water separations, for recovery or further processing of the vapor streams, including any water, vaporized solvent, and light hydrocarbons therein.

[00114] Other feed streams to the de-oiling system may include a water feed 727, which may be used to provide fresh ground, brackish, or make-up water to the system. Lastly, a neutralized regen waste recycle stream 728 may be provided from low hardness removal and boiler feed water storage stage 750 for further processing through the SAGD FTB-CPF.

[00115] The water fraction 724 may then be fed to high temperature electrocoagulation system 730. The high temperature electrocoagulation system for ionizing, complexing, and/or absorbing the dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants in the water fraction, producing a vapor fraction 732 and a solids/froth/water mixture 734. Chemicals used to pre-treat the feed to the high temperature electrocoagulation unit may be supplied via flow line 736. A recycle stream 738, such as a filtrate recycle from waste separation and froth/sludge dewatering stage 740 may also be provided to the high temperature electrocoagulation system.

[00116] Water separation and froth/sludge dewatering system 740 may separate the solids/froth/water mixture 734 into a sludge fraction 742, which may include filtered solids, and a clarified water fraction 744. A vapor stream 746 may also be recovered from water separation and froth/sludge dewatering stage 740, and processed in the above-noted vapor recovery unit. Sludge conditional chemicals, if used, may be fed to water separation and froth/sludge dewatering system 740 via flow line 748.

[00117] The clarified water fraction 744 may then be fed to low hardness removal and boiler feed water storage stage 750. The "polishing" system may reduce a total hardness of the clarified water fraction to less than 0.2 ppm, for example, producing a regeneration waste water stream 728 and a boiler feed water stream 752. Ion exchange regen chemicals may be fed to system 750 via flow line 754, and vent gases recovered via flow line 756 may be processed in the vapor recovery unit, as noted above. Steam used in the low hardness removal and boiler feed water storage stage 750 may be supplied from the steam generation stage 760 via flow line 758.

[00118] Steam generation stage 760 may be used to convert the water in boiler feed water stream 752 to steam, such as by using once through steam generators, as noted above. Steam generated in steam generation system 760 may be provided to the enhanced oil recovery system (not shown) via flow line 762, to the low hardness removal and boiler feed water storage stage 750 via flow line 758, and to other uses via one or more steam lines 764. Other outputs from steam generation stage 760 may include OTSG stack gas 766, solids / landfill waste stream 767, and blowdown water 768 to a disposal well or treatment process (not shown). As needed, boiler feed water conditioner 770 and oxygen scavenger 772 may be introduced to the steam generation system 760 as well. The SAGD FTB-CPF may also include a volatile amine or ammonia feed 780, as well as a water recycle stream 782 fed to the high temperature electrocoagulation system 30 along with the filtrate recycle stream 738.

[00119] Various steps within each of the noted system blocks illustrated in Figure 7 are described above, and below in Figures 8-14, and as such are not described in detail with respect to Figure 7. Figure 7 simply provides a general overview of the various systems used in the FTB-CPF according to embodiments herein that may be used with a SAGD enhanced oil recovery system.

[00120] Referring now to Figure 8, a block process flow diagram of a front-to-back central processing facility for a SAGD enhanced oil recovery system according to embodiments herein is illustrated, illustrating embodiments of steps 710 and 720 of Figure 7 in greater detail, where like numerals represent like parts.

[00121] A produced emulsion 712, such as an oil-water emulsion from a SAGD
enhanced oil recovery system, is fed to an inlet of the gas-oil-water separation stage 710. The produced oil-water emulsion may be provided directly or indirectly from a SAGD enhanced oil recovery system, and may include one or more of dissolved solids, entrained gases and/or light hydrocarbons, distillate and/or heavier hydrocarbons, and/or water. In primary gas-oil-water separation stage 710, the emulsion may be treated initially in a Free Water Knockout (FWKO) drum 810 to separate the entrained gases and light hydrocarbons from the oil and water in the emulsion. The gases evolved may be fed via flow line 714 to a vapor recovery unit (not shown) for further processing. The remaining oil-water emulsion may then be fed via flow line 716 to de-oiling stage 720.

[00122] Deoiling system 720 may separate the oil-water emulsion in stream 716 into a recovered oil fraction 722 and a water fraction 724. Water fraction 724 may contain, among other components, dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants. In de-oiling system 720, oil-water emulsion 716 may be fed to an Oil Treater (OT) 815 for recovery of oil from water. To facilitate the separations in OT 815, a hydrocarbon solvent 725 may be used to reduce a density and viscosity of the hydrocarbons in the oil-emulsion fraction and forming an oil fraction 722 and a water-oil suspension (produced water) 817 containing residual oil.

[00123] The produced water 817 recovered from the FWKO 810 and OT 815 may be cooled to less than 95 C through heat exchange with OTSG BFW and (if needed) an aerial or glycol cooler (one or more exchangers 819). The produced water 817 from OT 815 is transferred to a skim/surge tank (ST) 820, and may contain an average of 2000 ppm of residual oil, in some embodiments, less than 3000 ppm or less than 3500 ppm in other embodiments, with excursions that may exceed 5000 ppm for short periods.

[00124] The produced water-oil suspension 817 in the feed to ST 820 may be chemically treated to enhance coalescence of the oil droplets to effect more rapid gravity separation of the oil that rises to the surface in the tank. The ST
820 may be designed to reduce the oil in water concentration in the effluent to 10% of the inlet concentration. The oil separated in ST 820 is skimmed off and returned via flow line 822 to one of OT 815, FWKO 810, or an oil recovery/slop tank (not illustrated) for additional treatment and dewatering.

[00125] ST 820 effluent 824 may be further de-oiled with a dissolved gas floatation unit (DGF) 825. The dissolved gas floatation unit 825 may be designed to reduce the oil in water to less than 10 ppm, for example. Oil that is separated from the water and skimmed off from the DGF unit may be returned via flow line 827 to the skim tank 820 or transferred to a recovery/slop oil tank (not shown).

[00126] The deoiled produced water 829 from the DGF unit 825 may be transferred to an optional deoiled / makeup water storage tank 830, where the deoiled product may be thoroughly mixed with filtered makeup water 727 from groundwater or surface water sources (with or without pH adjustment) and recycled neutralized weak acid cation exchange regenerant waste water 728 prior to being transferred to the high temperature electrocoagulation process (Figure 9) via flow line 24.

[00127] To maintain an inert atmosphere in various tanks and other unit operations in the de-oiling system, a blanket gas, such as nitrogen, may be provided via flow line 726. The vapors recovered from the tank and unit operation vents may be recovered via one or more flow lines 723 and fed to a vapor recovery unit, such as a common vapor recovery unit with the primary gas-oil-water separations vent 714, for recovery or further processing of the vapor streams 714, 726, including any water, vaporized solvent, and light hydrocarbons therein.

[00128] Referring now to Figure 9, a block process flow diagram of a front-to-back central processing facility for a SAGD enhanced oil recovery system according to embodiments herein is illustrated, illustrating embodiments of steps 730 and 740 of Figure 7 in greater detail, where like numerals represent like parts.

[00129] The water fraction 724 may be fed to high temperature electrocoagulation system 730. The high temperature electrocoagulation system 730 may be configured for ionizing, complexing, and/or absorbing the dissolved silica, hardness, total organic carbon, and other dissolved or inorganic contaminants in the water fraction, producing a vapor fraction 732 and a solids/froth/water mixture 734.
The blended water 724 from the deoiled/makeup water storage tank is pumped and evenly distributed to the required correctly sized number of operating electrocoagulation ("EC") cells in high temperature EC system 730. As noted above, the EC cells may hold iron or aluminum electrode plates, for example. DC power is supplied to the cells to deliver up to 7 kw/m3 of throughput with iron or aluminum electrode consumption by the process typically between 0.02 to 0.03 kg/m3 of treated water.

[00130] Chemicals used to pre-treat the feed to the high temperature electrocoagulation unit may be supplied via flow line 736. A recycle stream 738, such as a filtrate recycle from clean boiler water storage tank 920 in waste separation and froth/sludge dewatering stage 740 may also be provided to the high temperature electrocoagulation system.

[00131] The power supply polarity across the plates may be reversed periodically to help prevent deposits from building up on the plates. Additionally, in some embodiments, the pH of the feed to the HT EC system may be modified to improve or optimize EC contaminant removal efficiency. The electrode plates that dissolve during the EC process is simultaneously converted to a charged oxidized particle while ionizing, complexing, and/or absorbing dissolved silica, hardness, total organic carbon and many other dissolved organic and inorganic contaminants, including multivalent contaminants. This sequence promotes coagulation of the free suspended oil and solids that all combine and make up the composition of the entrained suspended solids/froth 734. The solids/froth/water mixture 734 flows out of the EC cell into a collection trough (not shown) that feeds the downstream solids/froth water separation unit 925. The HT EC cell 730 and the trough may be fitted with a vapor containment cover to direct any gases or vapors generated via flow line 732 to a dedicated knockout drum and discharge vent or recovered for fuel gas or disposal using a Vapor Recovery Unit (VRU) (not shown), which may be the same or different VRU than that used with respect to stages 710 and 720. The HT
EC unit 730 design may include the option to inject air or inert gas 923 into the bottom of the cell to promote floatation and removal of the solids\froth generated.
Fugitive toxic gas emissions are not expected to exceed regulatory limits but may be recovered through the use of the VRU.

[00132] The electrode plates and EC cells are cleaned, "pickled,"
sequentially and routinely to maintain electrocoagulation energy efficiency using a dilute HC1 or H2SO4 acid clean-in-place (OP) solution stored in a separate single tank 929 dedicated to service all EC cells. The ClP solution is used over and over until the acid strength is depleted at which time the exhausted solution is pH
neutralized and directed back, at a steady controlled rate, into the feed distribution line to the EC

cells for treatment, where the contaminants in the solution are removed as solids/froth 734.

[00133] Water separation and solids/froth/sludge dewatering system 740 may separate the solids/froth/water mixture 734 into a sludge fraction 742, which may include filtered solids, and a clarified water fraction 744. A vapor stream 746 may also be recovered from water separation and froth/sludge dewatering stage 740, and processed in the above-noted vapor recovery unit. Sludge conditional chemicals, if used, may be fed to water separation and froth/sludge dewatering system 740 via flow line 748.

[00134] As illustrated in Figure 9, the HT EC effluent, solids-froth-water mixture 734, nay be fed into to a three stage enclosed sequential cascading solids/froth breaking (defoaming) cell 925. The solids/froth breaker 925 uses strategically designed spreaders and water sprays to break the froth and release the trapped solids, producing a solids entrained water effluent 931 with no froth or foam.

[00135] The solids entrained water 931 passes through hydrocyclones 930, which may be designed to maximize the removal of fine entrained solids, such as particles as small as 10 micron in size, and reduce the clarified solids concentration in the resulting effluent 937 to less than 30 mg/L. The hydrocyclone system 930 may include provisions to include coagulation of flocculation upstream or downstream to further maximize solids particle size, removal and subsequent filtration efficiency.
The separated solids collected in the bowl of the hydrocyclone unit are discharged via flow line 939, as required, and sent to a surge tank and filter press 940 for final dewatering and subsequent landfill of solids 742. Off spec water 936 from the hydrocyclones may be treated with chemical and may be recycled back through the EC system (as shown) or defoaming unit via the filter dirty backwash storage tank for re-processing or sent through a secondary off-spec polishing hydrocyclone unit (not shown).

[00136] The clarified separated water 937 from hydrocyclone 930 is then filtered using micro-media filters 945 or alternatively ultrafiltration membranes to remove trace solids from the clarified water. The filters 945 may be designed to produce an effluent having a turbidity value of less than 2 and a solids content of less than 1 ppm. When solids loading on the micro media filters 945 create a pressure drop that reduces the throughput capacity of the filters, the filter media is air or gas scoured and then backwashed. Should an ultrafiltration system be utilized the membranes are constantly discharging a concentrated slurry to the dirty backwash tank and undergo a high pressure back pulse intermittently to dislodge entrapped solids within the membrane lattice. Filtrate from the media filters supplies clean backwashing (BW) water to the clean BW water storage tank. The dirty backwash or slurry stream from the filtration system backwashing sequence is sent to a dirty backwash tank then recycled back to the inlet of the solids/froth defoaming cell. Intermittent chemical cleaning via clean-in-place system 946 combined with air scour cleaning of the micro-media filter media is optional and may be used as required to maintain media quality and filter performance.

[00137] The clarified water fraction 744 may then be fed to a clean backwash water storage tank and low hardness removal stage 750 (Figure 10) and boiler feed water storage tank 920. One or more water storage tanks 920 may be used to provide a water stream 738 to the HT EC unit 730, as well as feed 744B to stage 750, as a supply of water 948 for backwash of the filtration system 945, and as a supply of water to filter press 940, as needed. For example, a first tank 920 may be used to supply dilution water for the chemicals required for regeneration of the ion exchangers, and clean service water may be provided from a clean backwash water storage tank 920 to provide service water to the HC EC unit (rinse after CIP
treatment), Defoaming Cell, Filter Press and backwashing of the media filters.
Water recovered from the dewatering filter press 940 may be returned via flow line 952 to either HT EC unit 730 or filtration unit 945 for further processing.

[00138] Referring now to Figure 10, a block process flow diagram of a front-to-back central processing facility for a SAGD enhanced oil recovery system according to embodiments herein is illustrated, illustrating embodiments of steps 50 and 60 of Figure 7 in greater detail, where like numerals represent like parts.

[00139] The clarified water fractions 744, 744B may be fed to low hardness removal stage 750, which may include a clean backwash water storage tank, an ion exchange system 1010 and a de-aerator 1015 in some embodiments. The "polishing" system 750 may reduce a total hardness of the clarified water fraction to less than 0.2 ppm, for example, producing a regeneration waste water stream 728 and a boiler feed water stream 752.

[00140] The effluent 744, 744B from the EC process and filtration system (Figure 9) may contain hardness that requires removal using Weak Acid Cation (WAC) polishers to an acceptable BFW concentration of less than 0.2 ppm. The WAC
units 1010 are operated in the Sodium (Nat) form and are regenerated in-situ with typically dilute HC1 acid to remove the exchanged hardness then converted to the Nat form with dilute NaOH (caustic). Ion exchange regen chemicals may be fed to system 750 via flow line 754, and Boiler Feed Water 744B may be used to dilute the concentrated chemicals delivered to the plant to prepare the chemical regenerants.

[00141] A unique feature of the SAGD FTB-CPF design is the recycling and treatment of the regeneration waste water. The regeneration waste water 1017 generated in the ion exchange system 1010 may be pH adjusted to neutrality in a neutralization tank 1020 with additional acid or caustic then recycled in a slow controlled manner via flow line 728 to the inlet of the HT EC cells 730 while in operation or mixed with the incoming produced water 817 in the skim tank 820 or optional deoiled /
make-up water storage tank 830 (each in Figure 2). When the regeneration waste water hardness is processed by the EC unit 730, the majority of the hardness contaminants are removed as solids to a level required for ion exchange. This recycle treatment feature eliminates the need for a dedicated waste disposal well for the regeneration waste water or the use of costly chemicals to precipitate the waste dissolved hardness by lime softening. The sodium and chloride ions present in the regeneration waste water stream are monovalent ions and are not removed by the EC process and significantly impact the TDS of the regenerant waste water. High TDS of the regenerant waste water will impact the total TDS and chloride concentration of the BFW somewhat depending upon regenerant waste water volume and rate of recycle.

For thermal heavy oil produced waters the TDS and chloride concentrations are typically low enough to enable recycle of the regeneration waste water while maintaining a BFW chloride concentration below the maximum target concentration of 5770 mg/L for OTSGs producing at least 90% steam quality.

[00142] The softened BFW 1019 may be deaerated using a steam deaerator 1015 before being stored in a BFW storage tank 1025 prior to steam generation.
Steam to the deaerator may be supplied from the medium and/or low pressure steam separators 1030 located in the steam plant 760. The deaerated BFW 1027 out of the BFW storage tank 1025 may be treated with an oxygen scavenger 772 to remove trace oxygen to less than 0.007 ppm and if necessary caustic 770 to adjust the pH to 9.0 to meet boiler feedwater guidelines, producing a water feed 1029 to the steam generators.

[00143] Steam generation stage 760 may be used to convert the water in boiler feed water stream 752 to steam, such as by using once through steam generators 1035, as noted above. The OTSG steam generators 1035, which may or may not be fitted with rifle tubes in up to 50% of the latter part of the radiant section, may be used to produce 90% or greater steam quality. Combusted fuel, stack gas 766, resulting from the steam generation process may be output via stack 1040.

[00144] Steam generated in steam generation system 760, as noted above, is of 90% or greater steam quality. The resulting 90% steam phase 1036 is separated from the liquid phase by a high pressure separator (HPS) 1042 to deliver 100% quality steam to the SAGD enhanced oil recovery system 1045 via flow line 762. At SAGD
facilities, a volatile-filming amine 1050 may be injected via feed system 1052 into the 100% steam to field distribution line as to control the potential for carbonic acid corrosion in the line. An alternative option may be used for the FTB CPF
designs according to embodiments herein, where liquefied ammonia may be used to provide similar corrosion protection.

[00145] For SAGD facilities where the HPS produces blowdown (BD) 1044, the HP
BD pressure is let down in a medium pressure (MP) and/or a low pressure (LP) steam separator 1060. The MP plus LP steam separators 1060 together can convert up to 40% of the water to MP and LP steam 758 that is used to operate the BFW
steam deaerator 1015. Excess utility steam, if any, may be cooled in one or more exchangers 1090 and the condensate routed to the boiler feed water storage tank 1025.

[00146] Condensate blowdown 1065 from steam separators 1060 may be forwarded to disposal tanks 1070, and thence via line 1072 to a disposal well or treatment process 1080. If the boiler feed water TDS is below 5500, it may be possible to route the blowdown 1065 back to the HT EC cell 730 for further processing.

[00147] Referring now to Figure 11, a block process flow diagram of a front-to-back central processing facility for a SAGD enhanced oil recovery system according to embodiments herein is illustrated, illustrating other embodiments of steps 750 and 760 of Figure 7 in greater detail, where like numerals represent like parts.

[00148] In this embodiment, the clarified water fractions 744, 744B may be processed and turned into steam in a manner similar to that described with respect to Figure 10.
Steam generation stage 760 may be used to convert the water in boiler feed water stream 752 to steam, such as by using once through steam generators 1035, as noted above. The OTSG steam generators 1035, which may or may not be fitted with rifle tubes in up to 50% of the latter part of the radiant section, may be used to produce 90% or greater steam quality. Combusted fuel, stack gas 766, resulting from the steam generation process may be output via stack 1040.

[00149] Steam generated in steam generation system 760, as noted above, is of 90% or greater steam quality. The resulting 90% steam phase 1036 is separated from the liquid phase by a high pressure separator (HPS) 1042 to deliver 100% quality steam to the SAGD enhanced oil recovery system 1045 via flow line 762. At SAGD
facilities, a volatile-filming amine 1050 may be injected via feed system 1052 into the 100% steam to field distribution line as to control the potential for carbonic acid corrosion in the line. An alternative option may be used for the FTB CPF
designs according to embodiments herein, where liquefied ammonia may be used to provide similar corrosion protection.

[00150] For SAGD facilities where the HPS produces blowdown (BD) 1044, the HP
BD pressure is let down in a medium pressure (MP) and/or a low pressure (LP) steam separator 1060. The MP plus LP steam separators 1060 together can convert up to 40% of the water to MP and LP steam 758 that is used to operate the BFW
steam deaerator 1015. Condensate blowdown 1065 from steam separators 1060 may be forwarded to disposal tanks 1070, and thence via line 1072 to a disposal well or treatment process 1080.

[00151] As illustrated in Figure 11, the CSS FTB-CPF embodiment illustrated may be used to maximize water reuse and minimize disposal. A portion of steam stream 758, utility steam stream 1110, may be fed to a multiple effect evaporator system 1120 for TDS reduction. A slip stream 1073 of softened water, and optionally a portion of blowdown stream 1072 may be combined with the steam 1110, producing a vapor stream 1074 and a water stream 1076. The rate of the slip stream 1072 may be based on the target TDS in the boiler feed water. Water stream 1076 may be routed to a disposal well or treatment process 1080. Vapor stream 1074 may be condensed via one or more exchangers 1090 and returned via line 1092 to the steam deaerator 1015 for further processing. As a further option, steam 1148 from phase separator 1042 may be provided to a de-superheater 1150, contacting boiler feed water slip stream 1157 to produce additional low or medium pressure steam 1159 for use in evaporator 1120 or deaerator 1015.

[00152] Referring now to Figure 12, a block process flow diagram of a front-to-back central processing facility for a SAGD enhanced oil recovery system according to embodiments herein is illustrated, illustrating other embodiments of steps 750 and 760 of Figure 7 in greater detail, where like numerals represent like parts.

[00153] In this embodiment, the clarified water fractions 744, 744B may be processed and turned into steam in a manner similar to that described with respect to Figures and 11. Steam generation stage 760 may be used to convert the water in boiler feed water stream 752 to steam, such as by using once through steam generators 1035, as noted above. The OTSG steam generators 1035 may be used to produce 90% or greater steam quality. Combusted fuel, stack gas 766, resulting from the steam generation process may be output via stack 1040.

[00154] Steam generated in steam generation system 760, as noted above, is of 90% or greater steam quality. The resulting 90% steam phase 1036 is separated from the liquid phase by a high pressure separator (HPS) 1042 to deliver 100% quality steam to the SAGD enhanced oil recovery system 1045 via flow line 762. At SAGD
facilities, a volatile-filming amine 1050 may be injected via feed system 1052 into the 100% steam to field distribution line as to control the potential for carbonic acid corrosion in the line. An alternative option may be used for the FTB CPF
designs according to embodiments herein, where liquefied ammonia may be used to provide similar corrosion protection.

[00155] For SAGD facilities where the HPS produces blowdown (BD) 1044, the HP
BD pressure is let down in a medium pressure (MP) and/or a low pressure (LP) steam separator 1060. The MP plus LP steam separators 1060 together can convert up to 40% of the water to MP and LP steam 758 that is used to operate the BFW
steam deaerator 1015.

[00156] As illustrated in Figure 12, the SAGD FTB-CPF embodiment illustrated may be used to maximize water reuse and minimize disposal. A portion of steam stream 758, utility steam stream 1110, and blowdown stream 1072 may be fed to a multiple effect evaporator system 1120 for TDS reduction, producing a vapor stream 1074 and a water stream 1076.

[00157] Vapor stream 1074 may be condensed via one or more exchangers 1090 and returned via line 1092 to the steam deaerator 1015 for further processing.
Water stream 1076 may be routed to a disposal well or treatment process 1080. If the boiler feed water TDS is below 5500, it may be possible to route the water stream 1076 via line 1077 back to the HT EC cell 730 for further processing.

[00158] Optionally, a crystallizer system 1290 may be used to process water stream 1076 along with steam 1112 for zero liquid discharge capability, producing a solids stream 67 to landfill and a steam stream 1078, which may be processed with flash evaporator effluent 1074 via cooler 1090, such as an aerial heat exchanger, the condensate 1092 from which may be fed to deaerator 1015 along with softened water 1019 for further processing.

[00159] As a further option, steam 1148 from phase separator 1042 may be provided to a de-superheater 1150, contacting boiler feed water slip stream 1157 to produce additional low or medium pressure steam 1159 for use in evaporator 1120, deaerator 1015, or crystallizer 1290.

[00160] Referring now to Figure 13, a block process flow diagram of a front-to-back central processing facility for a SAGD enhanced oil recovery system according to embodiments herein is illustrated, illustrating other embodiments of steps 750 and 760 of Figure 7 in greater detail, where like numerals represent like parts.

[00161] In this embodiment, the clarified water fractions 744, 744B may be processed and turned into steam in a manner similar to that described with respect to Figure 10.
Steam generation stage 760 may be used to convert the water in boiler feed water stream 752 to steam, such as by using once through steam generators 1035, as noted above. The OTSG steam generators 1035, which may or may not be fitted with rifle tubes in up to 50% of the latter part of the radiant section, may be used to produce 90% or greater steam quality. Combusted fuel, stack gas 766, resulting from the steam generation process may be output via stack 1040.

[00162] Steam generated in steam generation system 760, as noted above, is of 90% or greater steam quality. The resulting 90% steam phase 1036 is separated from the liquid phase by a high pressure separator (HPS) 1042 to deliver 100% quality steam to the SAGD enhanced oil recovery system 1045 via flow line 762. At SAGD
facilities, a volatile-filming amine 1050 may be injected via feed system 1052 into the 100% steam to field distribution line as to control the potential for carbonic acid corrosion in the line. An alternative option may be used for the FTB CPF
designs according to embodiments herein, where liquefied ammonia may be used to provide similar corrosion protection.

[00163] For SAGD facilities where the HPS produces blowdown (BD) 1044, the HP
BD pressure is let down in a medium pressure (MP) and/or a low pressure (LP) steam separator 1060. The MP plus LP steam separators 1060 together can convert up to 40% of the water to MP and LP steam 758 that is used to operate the BFW
steam deaerator 1015.

[00164] Condensate blowdown 1065 from steam separators 1060 may be routed to a scrubber 1300, contacting a slip stream 766B of the stack gas from stack 1040.

Scrubber 1300 may be used to contact the water stream 1065 with the stack gas to reduce greenhouse gas emissions and reduce the pH of the water 1065. The pH
adjusted water 1302 may then be fed to a disposal well or treatment process 1080. If the boiler feed water TDS is below 5500, it may be possible to route the pH
adjusted water stream 1302 via line 1077 back to the HT EC cell 730 for further processing.

[00165] Referring now to Figure 14, a block process flow diagram of a front-to-back central processing facility for a SAGD enhanced oil recovery system according to embodiments herein is illustrated, illustrating other embodiments of steps 750 and 760 of Figure 7 in greater detail, where like numerals represent like parts.
In this embodiment, the clarified water fractions 744, 744B may be processed and turned into steam, and the steam processed in a manner similar to that described with respect to Figures 12, including the multi-effect evaporator 1120 and the crystallizer 1290. Additionally in this embodiment, scrubber 1300 may be used to contact the water stream 1076 with the stack gas to reduce greenhouse gas emissions and reduce the pH of the water in stream 1076. The pH adjusted water 1302 may then be fed to a disposal well or treatment process 1080 or alternatively may be fed to crystallizer 1090 for a zero liquid discharge option.

[00166] FTB ADD-ON DEBOTTLENECKING DESIGNS

[00167] The FTB-CPF designs disclosed herein has additionally fostered the development of five FTB Add-On process debottlenecking and production enhancement designs for the thermal heavy oil industry, described below. A
base case as reference is provided. Add-On cases 1-3 integrate design features of the FTB-CPF water treatment processes according to embodiments herein within a 30,000 bopd lime softening ¨ OTSG CPF facility. Cases 4 and 5 were developed to resolve known production bottlenecks that may be encountered at thermal in-situ facilities. Variations of these Add-On debottlenecking designs or a combination of these can be utilized according to embodiments herein to retrofit most existing thermal heavy oil facilities

[00168] 30,000 bopd BASE CASE SAGD FACILITY

[00169] A 30,000 bopd Base Case SAGD facility with a steam to oil ratio of 3.0 was used for reference to foster the development of debottlenecking FTB Add-On designs.
The Base Case facility incorporates conventional Free Water Knockout and Treater oil separation units followed by a skim tank, induced gas floatation unit and oil filters for deoiling of hot produced water. The hot deoiled water with blended fresh or brackish makeup ground water is treated to BFW specs using a warm lime softener to remove primarily silica and hardness that is followed by filtration and then ion exchange for final hardness removal. The lime softener throughput is limited to the settling rate of the precipitated solids in the unit which for warm lime softening as shown is traditionally between 0.7 ¨ 1.2 usgpm/ft2 and for hot lime softening (not shown) is traditionally between 2 and 2.2 usgpm/ft2. All equipment downstream of the lime softener is sized to accommodate the maximum throughput of the lime softening unit that often is unable to achieve the maximum throughput rates thereby creating a bottleneck in the water treatment process should additional steam-to-field capacity and increased oil production be the objective of the heavy oil producer.

[00170] A block flow diagram illustrating the base case flow scheme is provided in Figure 15. The reference numerals and unit operations used in the base case flow diagram are provided in Table 1 below.
Table 1. Figure 15 unit operations and reference numbers.
Reservoir 1500 Produced Water 1502 Produced Water to 1503 Landfill / Disposal 1505 Sales Stream from Water Treatment Water Losses To 1504 Oil Treating 1506 reservoir Preflash Vessel 1508 FWKO 1510 Treaters 1512 Vapor Recovery 1514 Diluent 1516 Diluted Bitumen 1518 Oil Recycle 1520 Deoiled Water 1522 Deoiling 1524 Skim Tank 1526 IGF/ISF/ORG units 1528 Water Treatment 1530 PW Tank 1532 WLS 1534 AF/WAC 1536 BFW Tank 1538 Steam Generation 1540 OTSGs 1542 HPS 1544 LP Flash 1546 Boiler Feed Water 1548 Wet Steam 1550 HP Steam 1552 Blowdown 1554 LPF Condensate 1556 Blowdown to 1558 Disposal Blowdown Recycle 1559 Make-up Water 1561 Produced Water from 1560 Produced Water from 1562 FWKO Treaters

[00171] The base case conditions and results are shown in Table 2 below.
Table 2.
Reservoir SOR 3.00 GOR 5.00 Water Losses to Reservoir 9000 (bpd) Bitumen bpd 30000 API gravity 7.1 Produced Water from Reservoir bpd 81000 TDS (ppm) 1492 TH (ppm) 14 Silica (mg 5i02 /1) 188 Produced Water Sales (bpd) 200 Produced Gas MMSCFD 0.88 Water from Oil Treating bpd 80800 Make-up Water bpd 18100 Si02 (ppm) 7 Deoiled Water bpd 80800 Water Treatment Blowdown Recycle (bpd) 9900 Landfill / disposal (bpd) 1000 Boiler Feed Water bpd 115400 TDS (ppm) <8000 Si02 (ppm) <50 TH (ppm) <0.5 Steam Generation Wet Steam Quality (%) 78 Wet Steam bpd 115400 HP Steam Quality (%) 100 HP Steam bpd 90000 Blowdown (bpd) 25400 Condensate Recycle (bpd) 7600 Blowdown to Disposal (bpd) 7900 Blowdown TDS (ppm) <50900 Blowdown Si02 (ppm) <320 Blowdown TH (ppm) <3.0

[00172] The FTB Add-On debottlenecking designs were developed for all the cases included herein assuming that as a result of an increase in steam quality or steam to field, the oil separation and deoiling equipment are capable of processing an increase in the amount of oil water emulsion from the field or the equipment would be modified and/or increased in quantity as required.

[00173] Case 1 ¨ Increase OTSG Steam Quality

[00174] The FTB-CPF Add-On CASE 1 design was developed to increase the steam quality generated by the OTSGs by 4% from the traditional operating level of 78%
and provide solutions to existing operating bottlenecks or to meet operating cost reduction objectives that included: (A) The lime softener throughput is not able to achieve maximum design treatment rates and BFW quantity to meet steam production targets; (B) The amount of blowdown from the OTSGs and subsequent recycle, recovery and disposal of the blowdown fraction was insufficient for meeting the Alberta Energy Regulator targets; (C) The amount of fresh or brackish makeup water that is available and needed at the facility is insufficient to meet the BFW
supply target; and (D) An objective to reduce the cost of fuel and future carbon emission taxes.

[00175] The Case 1 design specifies the use of a dual train EC system each designed to treat up to 36,400 bpd (136 m3/hr) of hot produced water followed by defoaming, dewatering, filtration and ion exchange processes. The BFW produces in a higher quality than what is being produced by the base case process. The higher quality BFW

is attributed to the FTB-EC cells to deliver a reduction in the concentration of silica (Sia,) of up to 80% and a reduction in soluble total organic carbon (TOC) of up to 50%. A reduction in these dissolved components together with hardness removal results in a reduction in the rate of silicate and organic compound scale deposition on the internal surfaces of the OTSG tubing and potential tube failures while improving the OTSG heat transfer efficiency between generator inspection periods.

[00176] The high quality BFW produced by the FTB-CPF Add-On package is blended with the existing BFW produced by the Base Case water treatment processes to achieve a silica reduction of up to 33% and a TOC reduction of up to 25%
thereby enabling the OTSGs to increase the high pressure steam quality to 82% while generating the same mass of steam to field using 4.9% less BFW.

[00177] Additional impacts of integrating this FTB-CPF Add-On design with Base Case plant operations include: (A) The lime softener throughput rate decreases by up to 38% based on a reduction of up to 45% in produced water feed and 12%
decrease in the OTSG blowdown recycle rate to the lime softener; (B) Less BFW required results in a 12% reduction in makeup water; and (C) The OTSG blowdown to disposal is reduced by 34%.

[00178] A block flow diagram illustrating the Case 1 Add On flow scheme is provided in Figure 16. The reference numerals and unit operations used in the Case 1 Add On flow diagram are provided in Table 3 below.
Table 3. Figure 16 unit operations and reference numbers.
Reservoir 1600 Produced Water to 1602 Sales Water Losses To 1604 Produced Water 1606 reservoir (after degassing) Deoiling 1608 Deoiled Water 1610 IGF/ISF/ORG units 1612 Skim Tank 1614 FTB Add On 1616 HT EC 1618 Solids Dewatering 1620 Solds-Water 1622 Separations MicroFiltration 1624 WAC 1626 Boiler Feed Water 1628 Deaerator 1629 PW Tank 1632 Water Treatment 1630 Steam Generation 1640 BFW Tank 1638 HPS 1644 OTSGs 1642 LP Flash 1648 Blowdown 1646 LP Blowdown to 1652 LPF Condensate 1650 Disposal Recycle Wet Steam 1656 Blowdown Recycle 1654 Make-up Water 1660 HP Steam 1658 Solids to Landfill 1664 Landfill / Disposal 1662 Stream from Water Treatment Deaerator Steam 1666 Boiler Feed Water 1670

[00179] The Case 1 conditions and results are shown in Table 4 below.
Table 4.
Reservoir SOR 3.00 GOR 5.00 Water Losses to Reservoir 9000 (bpd) Bitumen bpd 30000 API gravity 7.1 Produced Water from Reservoir bpd 81000 TDS (ppm) 1492 TH (ppm) 14 Silica (mg Si02 / I) 188 Produced Water Sales (bpd) 200 Produced Gas MMSCFD 0.88 Water from Oil Treating bpd 80800 to FTB add-on 36400 To existing water treatment 44400 Make-up Water bpd 15000 Si02 (ppm) 7 Water Treatment Blowdown Recycle (bpd) 8700 Landfill / disposal (bpd) 600 Boiler Feed Water bpd 109800 Steam Generation Wet Steam Quality (%) 82 Wet Steam bpd 109800 HP Steam Quality (%) 100 HP Steam bpd 90000 Blowdown (bpd) 19800 Condensate Recycle (bpd) 4800 Blowdown to Disposal (bpd) 5200

[00180] Compared to the base case, Case 1 provides a 4% increase in wet steam quality, requires 12% less make-up water, may decrease disposal by 34%, and may reduce landfill by about 40%.

[00181] FTB-CPF Add-On CASE 2 - Increase Steam Quantity to Field

[00182] The FTB-CPF Add-On CASE 2 design was developed to increase the steam to field generated by the OTSGs by 33% and correspondingly increase oil production for a heavy oil producer compared to the Base Case design. The Add-On includes the addition of HT EC modules, solids dewatering, solids-water separation, microfiltration, WAC, and a deaerator, similar to embodiments of one or more of Figures 1-14. The flow scheme for this Case 2 is the same as illustrated in Figure 16 /
Table 3. For this case, the deoiled water was again divided between the HT EC
plus filtration and an existing water treatment unit without HT EC, solids dewatering, solids-water separation, microfiltration, WAC, and a deaerator, debottlenecking an existing facility.

[00183] Additional impacts of integrating this FTB-CPF Add-On design on Base Case plant operations include: (A) The lime softener throughput rate decreases by up to 1.4% based on a reduction of up to 11.8% in produced water feed and 40.4%
increase in the OTSG blowdown recycle rate to the lime softener; (B) The amount of makeup water supply to the lime softener increases by 27.6%; (C) The OTSG blowdown to disposal rate increases by up to 24.1%; (D) The disposal of the blowdown fraction is 7.5% of total inflows which depending upon the fresh to brackish makeup water fractions used is between 0.5 and 6.0% below the disposal limit calculated by the Alberta Energy Regulator; (E) Additional steam generation capacity will be required;
(F)Increase in sweet fuel gas supply will be required; and (G) Modifications or equipment additions to the oil separation and deoiling trains will be required.

[00184] The Case 2 conditions and results are shown in Table 5 below.
Table 5.
Reservoir SOR 3.00 GOR 5.00 Water Losses to Reservoir 12000 (bpd) Bitumen bpd 40000 API gravity 7.1 Produced Water from Reservoir bpd 108000 TDS (ppm) 1492 TH (ppm) 14 Silica (mg Si02 / 1) 188 Produced Water Sales (bpd) 300 Produced Gas MMSCFD 0.88 Water from Oil Treating bpd 107700 to FTB add-on 36400 To existing water treatment 71300 Solids from oil treating kg/d 139 Make-up Water bpd 23100 Si02 (ppm) 7 Water Treatment Blowdown Recycle (bpd) 13900 Landfill / disposal (bpd) 1000 Boiler Feed Water bpd 153900 Steam Generation Wet Steam Quality (%) 78 Wet Steam bpd 153900 HP Steam Quality (%) 100 HP Steam bpd 120000 Blowdown (bpd) 33900 Condensate Recycle (bpd) 9100 Blowdown to Disposal (bpd) 9800 Deaerator steam (bpd) 1100

[00185] FTB-CPF Add-On CASE 2+ - Increase Steam Quantity and Quality

[00186] The FTB-CPF Add-On CASE 2+ design is an extension of FTB-CPF Add-On CASE 2 utilizing the design theory applied for FTB-CPF Add-On CASE 1 to increased steam quality generated by the OTSGs. Similar to FTB-CPF Add-On CASE 2, a 33% increases in the quantities of BFW, steam to field and oil production over the Base Case design is achieved. The flow scheme for this Case 2+ is the same as illustrated in Figure 16 / Table 3.

[00187] Additional impacts of integrating this FTB-CPF Add-On design on Base Case plant operations include: (a) The lime softener throughput rate decreases by up to 6.2% based on a reduction of up to 11.7% in produced water feed a 14.1%
increase in the OTSG blowdown recycle rate to the lime softener and up to 12.7% increase in the required makeup water supply; (b) The OTSG blowdown to disposal rate decreases by up to 10%; (c) The disposal of the blowdown fraction is 7.5% of total inflows which, depending upon the fresh to brackish makeup water fractions used, is between 3.4 to 8.5% below the disposal limit calculated by the Alberta Energy Regulator; (d) Additional steam generation capacity will be required; (e) Increase in sweet fuel gas supply will be required; (f) Modifications or equipment additions to the oil separation and deoiling trains will be required; and (g) The BFW produced by the FTB-CPF
Add-On package is blended with the existing BFW produced by the Base Case water treatment processes to achieve a silica reduction of up to 24% and a TOC
reduction of up to 30% thereby enabling the OTSGs to increase the high pressure steam quality to 82% while generating the same mass of steam to field using 4.9% less BFW.

[00188] The Case 2+ conditions and results are shown in Table 6 below.
Table 6.
Reservoir S OR 3.00 GOR 5.00 Water Losses to Reservoir 12000 (bpd) Bitumen bpd 40000 API gravity 7.1 Produced Water from Reservoir bpd 108000 TDS (ppm) 1492 TH (ppm) 14 Silica (mg Si02 /1) 188 Produced Water Sales (bpd) 300 Produced Gas MMSCFD 0.88 Water from Oil Treating bpd 107700 to FTB add-on 36400 To existing water treatment 71300 Solids from oil treating kg/d 139 Make-up Water bpd 20350 5i02 (ppm) 7 Water Treatment Blowdown Recycle (bpd) 11300 Landfill / disposal (bpd) 950 Boiler Feed Water bpd 146300 Steam Generation Wet Steam Quality (%) 82 Wet Steam bpd 146300 HP Steam Quality (%) 100 HP Steam bpd 120000 Blowdown (bpd) 26300 Condensate Recycle (bpd) 6800 Blowdown to Disposal (bpd) 7100 Deaerator steam (bpd) 1100

[00189] FTB-CPF Add-On CASE 3 - Debottlenecking Steam Generation Capacity

[00190] The FTB-CPF Add-On CASE 3 design incorporates additional OTSG
steam generation to increase steam to field and oil production by 33% while lowering the BFW production and steam to field requirements for Base Case operations by 4.2%
The additional steam generator design used for this case is based on the complete FTB-CPF design that uses Rife Tubes installed in the last 50% of the radiant tube section of the OTSG to enable the generator to produce 90% steam quality.

[00191] The Add-On for Case 3 includes the addition of HT EC modules, solids dewatering, solids-water separation, microfiltration, WAC, and a deaerator, as shown in embodiments of one or more of Figures 1-14. For this case, the deoiled water was again divided between the HT EC plus filtration and an existing water treatment unit without HT EC, solids dewatering, solids-water separation, microfiltration, WAC, and a deaerator, debottlenecking an existing facility. This case also included a dedicated boiler feed water tank, with flow divided between an add on with a 90% steam quality OTSG with HP separator and an existing steam generation system.

[00192] Additional impacts of integrating the FTB-CPF Add-On CASE 3 design with Base Case plant operations include: (a) The lime softener throughput rate decreases by up to 5.1% based on a reduction of up to 11.7% in produced water feed, up to 19.2%
increase in the OTSG blowdown recycle rate to the lime softener and up to 16.3%
increase in the required makeup water supply; (b) The OTSG blowdown to disposal rate decreases by up to 1.3%; (c) A dedicated BFW storage tank is required for the 90% OTSG to segregate the higher quality BFW from the traditional Base Case BFW
that contains a much higher concentration of silica and dissolved TOC; (d) Increase in sweet fuel gas supply will be required; and (e) Modifications or equipment additions to the oil separation and deoiling trains will be required

[00193] A block flow diagram illustrating the Case 3 flow scheme is provided in Figure 17. The reference numerals and unit operations used in the Case 3 flow diagram are provided in Table 7 below.
Table 7. Figure 17 unit operations and reference numbers.
Reservoir 1700 Produced Water 1702 Produced Water to 1704 Water Losses to 1706 Sales Reservoir FTB Add-on 1708 HT EC 1710 Solids Dewatering 1712 Solids to Landfill 1714 Solids-Water 1716 Microfiltration 1718 Separations WAC 1720 Deaerator 1722 Water Treatment 1724 Make-up water 1726 PW Tank 1728 WLS 1730 AF/WAC 1732 Water Treatment 1734 wastes to Landfill Boiler Feed Water 1736 Boiler Feed Water to 1738 Tank Existing Steam Gen.
Boiler Feed Water to 1739 Deaerated BFW 1741 Add-On Steam Gen.
Additional Steam 1740 HP Steam 1742 Generation Dedicated BFW Tank 1744 90% OTSG 1746 HP Separations 1748 Blowdown 1750 Existing Steam 1752 OTSG 1754 Generation HPSeparations 1756 LP Flash 1758 Wet Steam 1760 HP Steam 1762 Blowdown 1764 Blowdown to 1766 Disposal Deaerator Steam 1768 Blowdown Recycle 1770

[00194] The Case 3 conditions and results are shown in Table 8 below.
Table 8.
Reservoir SOR 3.00 GOR 5.00 Water Losses to Reservoir 12000 (bpd) Bitumen bpd 40000 API gravity 7.1 Produced Water from Reservoir bpd 108000 TDS (ppm) 1492 TH (ppm) 14 Silica (mg Si02 /1) 188 Produced Water Sales (bpd) 300 Produced Gas MMSCFD 0.88 Water from Oil Treating bpd 107700 to FTB add-on 36400 To existing water treatment 71300 Solids from oil treating kg/d 139 Make-up Water bpd 21050 Si02 (ppm) 7 Water Treatment Blowdown Recycle (bpd) 11800 Landfill / disposal (bpd) 950 Boiler Feed Water bpd 148000 To existing steam generation 110500 To add-on steam generation 37500 Steam Generation Wet Steam Quality (%) 78 Wet Steam bpd 110500 HP Steam Quality (%) 100 HP Steam bpd 86200 Blowdown (bpd) 24300 Condensate Recycle (bpd) 7300 Blowdown to Disposal (bpd) 7800 Deaerator steam (bpd) 1100 Add-on Steam Generation Steam Quality (%) 90 HP Steam Quality (%) 100 HP Steam (bpd) 33800 Blowdown (bpd) 3700

[00195] FTB-CPF Add-On CASE 4¨ Fixed Capacity Evaporator / Drum Boiler

[00196] The FTB-CPF Add-On CASE 4 design was developed for a thermal heavy oil producer that may encounter a drop in production using their design steam to oil ratio of 3Ø The facility included a fixed capacity front end mechanical vapor (MVC) evaporator to produce very high quality BFW from produced water which allowed for drum boilers to be used to generate high pressure steam. Due to the fixed capacity of the MVC evaporator the plant would not be able to increase BFW production and produce the additional steam necessary with a new drum boiler to satisfy a new higher steam to oil ratio target of 4.5 to maintain the 30,000 bopd production capacity.

[00197] The FTB-CPF Add-On Case 4 design developed incorporated a dual EC
module FTB water treatment package to produce a BFW for operating a Rifle Tube OTSG to produce 90% quality steam which, after high pressure separation, added 37.6% more 100% quality steam to field. The main advantage provided by this design is up to a 7,500 bopd increase in oil production to 27,500 bopd which is 8.3%
below the design production capacity for the facility. Achieving the design oil production target or increasing oil production is possible by reducing the size of the water treatment module and operating more than one train and if necessary installing a larger OTSG or two smaller ones.

[00198] Additional impacts of integrating the FTB-CPF Add-On CASE 4 design within a facility equipped with MVC evaporators and drum boilers included: (a) Sustained operation of the MVC evaporator at design capacity with no changes in Drum Boiler steam to field generated; (b) Generation of 2650 bopd of blowdown from the 90% OTSG for blending with the 4800 bopd of blowdown from the evaporator prior to disposal thereby not changing the disposal well license specifications; (c) Increase in sweet fuel gas supply will be required; (d) Increasing production and lower disposal volumes are possible using a larger sized FTB-Add-On design and multiple OTSGs. This enhanced design will process additional produced water for BFW supplied to the OTSGs and back off the amount of produce water processed by the existing Evaporator and replace that produced water with an equivalent volume of blowdown from the OTSGs. This maintains evaporator BFW production capacity and will reduce blowdown waste water disposal volume by up to 50%.

[00199] A block flow diagram illustrating the Case 4 flow scheme is provided in Figure 18. The reference numerals and unit operations used in the Case 4 flow diagram are provided in Table 9 below.
Table 9. Figure 18 unit operations and reference numbers.
Reservoir 1800 Produced Water 1802 Produced Water to 1804 Water Losses to 1806 Sales Reservoir Deoiling 1808 Skim Tank 1810 IGS/ISF/ORG units 1812 Deoiled Water 1814 Existing Boiler 1816 Make-Up Water 1818 System Deaerator 1820 Evaporator 1822 BFW Tank 1824 Drum Boiler 1826 HP Steam 1828 Blowdown Recycle 1830 to Evaporator Evaporator 1832 FTB Add-on 1834 Blowdown HT EC 1836 Solids Dewatering 1838 Solids-Water 1840 Micro Filtration 1842 Separations WAC / SAC 1844 Deaerator 1846 Add-On Steam Gen 1848 Dedicated BFW tank 1850 90% SQ OTSG 1852 HP Separations 1854 LP Flash 1856 Boiler Feed Water 1858 HP Steam 1860 Deaerator Steam 1862 Blowdown to 1864 Solids to Landfill 1866 Disposal

[00200] The Case 4 conditions and results are shown in Table 10 below.
Table 10.
Reservoir S OR 3.00 GOR 5.00 Water Losses to Reservoir 12000 (bpd) Bitumen bpd 40000 API gravity 7.1 Produced Water from Reservoir bpd 111400 TDS (ppm) 1492 TH (ppm) 14 Silica (mg 5i02 /1) 188 Produced Water Sales (bpd) 300 Produced Gas MMSCFD 0.88 Water from Oil Treating bpd 111100 to FTB add-on 36400 To existing water treatment 74700 Solids from oil treating kg/d 130 Make-up Water bpd 21900 SiO2 (ppm) 7 Water Treatment Blowdown Recycle to 1800 evaporator (bpd) Landfill / disposal (bpd) 4800 Boiler Feed Water bpd 148000 To existing drum boiler 74700 To add-on EC / Filtration and 36400 steam generation Drum Boiler Steam Generation HP Steam Quality (%) 100 HP Steam bpd 90000 Boiler Blowdown Recycle 1800 (bpd) Evaporator Blowdown to 4800 Disposal (bpd) Add-on Steam Generation Steam Quality (%) 90 HP Steam Quality (%) 100 HP Steam (bpd) 33800 Blowdown (bpd) 2650 Deaerator steam (bpd) 1100 Total Disposal bpd 7450

[00201] FTB-CPF Add-On CASE 5 ¨ Small Facility Ion Exchange ¨ OTSG

[00202] The FTB-CPF Add-On CASE 5 design was developed for a small 6,000 bopd thermal heavy oil producer that may be treating a blend of fresh and brackish water with ion exchangers to make BFW to operate OTSGs at 90% SQ. All of the produced water recovered from the field was deoiled and being disposed of as allowed by the Alberta Energy Regulator (AER). Due to, for example, limitations in the groundwater AER license the company is required to treat the deoiled produced water for OTSG
operation to increase steam to field and oil production.

[00203] The FTB-CPF Add-On Case 5 design developed for such a producer incorporated a single EC module FTB water treatment package to produce a BFW
for operating a Rifle Tube OTSG to produce 90% quality steam which, after high pressure separation, added 83.3% more 100% quality steam to field. The main advantage provided by this design is a 5,000 bopd increase in oil production using their steam to oil ratio of 2.5. Additional impacts of integrating the FTB-CPF
Add-On CASE 5 design within a facility equipped with ion exchangers only and OTSGs include: a 1000 bopd (59%) increase in OTSG blowdown sent to disposal; a 17%
reduction in the bopd of produced water sent to disposal; no change in the amount of groundwater withdrawn or the withdrawal license is required; increase in sweet fuel gas supply will be required; and modifications or equipment additions to the oil separation and deoiling trains will be required.

[00204] A block flow diagram illustrating the Case 5 flow scheme is provided in Figure 19. The reference numerals and unit operations used in the Case 5 flow diagram are provided in Table 11 below.
Table 11. Figure 19 unit operations and reference numbers.
Reservoir 1900 Produced Water 1902 Produced Water to 1904 Water Losses To 1906 Sales Reservoir Deoiling 1908 Skim Tank 1910 Secondary Deoiling 1912 HP Steam 1914 Deoiled Water to 1916 Deoiled water to FTB 1918 disposal Add-on Make-up water 1920 Ion exchangers 1922 Regen waste to 1924 BFW tank 1926 disposal OTSG 1928 Blowdown 1930 FTB add-on 1932 HTEC 1934 Solids Dewatering 1936 Landfill Solids 1938 Solids-Water 1940 MicroFiltration 1942 Separations WAC / SAC 1944 Deaerator 1946 Steam Gen Add-on 1948 Dedicated BFW Tank 1950 90% SQ OTSG 1952 HP Separations 1954 LP Flash 1956 Boiler Feed Water 1958 Wet Steam 1960 HP Steam 1962 Deaerator Steam 1964 Blowdown 1966

[00205] The Case 5 conditions and results are shown in Table 12 below.
Table 12.
Reservoir SOR 2.50 GOR 5.00 Water Losses to Reservoir 2750 (bpd) Bitumen bpd 11000 API gravity 8 Produced Water from Reservoir bpd 24750 TDS (ppm) 5500 TH (ppm) 300 Silica (mg Si02 /1) 150 Produced Water Sales (bpd) 50 Produced Gas MMSCFD 0.88 Water from Oil Treating bpd 13500 to FTB add-on 13500 To existing water treatment 0 Solids from treating kg/d 53 Make-up Water bpd 18700 To existing ion exchange and OTSG
Make-up Water Treatment Landfill / disposal (bpd) 2000 Existing OTSG
Steam bpd 16700 Steam Quality 90%
Steam to Field (bpd) 15000 Blowdown to disposal (bpd) 1700 Add-on Steam Generation Steam Quality (%) 90 HP Steam Quality (%) 100 HP Steam (bpd) 12500 Blowdown (bpd) 1000 Deaerator steam (bpd) 400 Total Blowdown to Disposal bpd 2700

[00206] While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure.

Claims

The embodiments of the present invention for which an exclusive property or privilege is claimed are defined as follows:

1. A front-to-back central processing facility, comprising:
an inlet for receiving an oil-water emulsion from an enhanced oil recovery system, the emulsion comprising one or more of dissolved solids, entrained gases and/or light hydrocarbons, distillate and/or heavier hydrocarbons, or water;
a gas-oil-water separation system for separating the entrained gases and/or light hydrocarbons from the oil-water emulsion, producing a vapor stream and an oil-water stream;
a deoiling system for separating the oil-water stream into a recovered oil fraction and a water fraction containing dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants, wherein the deoiling system comprises:
a free water knockout drum to separate the oil-water emulsion into a free water fraction and an oil-emulsion fraction;
an oil treater for contacting the oil-emulsion fraction with a hydrocarbon solvent to reduce a density and viscosity of the hydrocarbons in the oil-emulsion fraction and forming an oil fraction and a water-oil suspension containing residual oil;
a skim/surge tank for coalescing the residual oil in the water-oil suspension and producing a coalesced oil fraction and a water effluent;
a gas flotation unit for further de-oiling the water effluent, producing an oil fraction and a water fraction containing less than 10 ppm oil; and a deoiled / makeup water storage tank for storing the water fraction prior to feed to a high temperature electrocoagulation system;
the high temperature electrocoagulation system for ionizing, complexing, and/or absorbing the dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants in the water fraction, producing a vapor fraction and a solids/froth/water mixture;

a water separation and solids/sludge dewatering system for separating the solids/ water mixture into a sludge fraction and a clarified water fraction;
a polishing system for reducing a total hardness of the clarified water fraction to less than 0.2 ppm and producing a regeneration waste water stream and a boiler feed water stream;
a feed line for feeding the regeneration waste water stream to the skim/surge tank and/or for mixing the regeneration waste water stream with the water fraction upstream of the high temperature electrocoagulation system;
a steam generation system for converting the boiler feed water stream to steam;
an outlet for providing steam from the steam generation process to the enhanced oil recovery system.

2. The system of claim 1, further comprising a diluent feed system for providing the hydrocarbon solvent to the deoiling system.

3. The system of claim 1 or claim 2, further comprising a natural gas or inert feed gas system for providing a natural gas or inert gas to one or more tanks of the deoiling system.

4. The system of any one of claims 1 to 3, further comprising a heat exchanger for reducing a temperature of the water-oil suspension to less than 95°C
via indirect heat exchange with one or more of air, glycol, or boiler feed water.

5. The system of any one of claims 1 to 4, further comprising an oil recovery / slop tank for further dewatering of the coalesced oil fraction.

6. The system of any one of claims 1 to 5, further comprising one or more feed lines for admixing the water fraction with one or more of groundwater, brackish water, or filtered makeup water, or for providing one or more of groundwater, brackish water, or filtered makeup water to the skim/surge tank.

7. The system of any one of claims 1 to 6, wherein the water-oil suspension comprises less than 3000 ppm residual oil.

8. The system of any one of claims 1 to 7, further comprising a chemical treatment feed system for admixing chemicals with the water-oil suspension to enhance coalescence of oil droplets.

9. The system of any one of claims 1 to 8, wherein the high temperature electrocoagulation system comprises electrocoagulation cells for ionizing, complexing, and/or absorbing the dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants in the water fraction, the high temperature electrocoagulation system further comprising a vapor inlet for injecting a gas into the electrocoagulation cells for promoting flotation and removal of solids/froth generated.

10. The system of any one of claims 1 to 9, further comprising a pre-treatment chemical feed system intermediate the deoiling system and the high temperature electrocoagulation system for mixing pre-treatment chemicals with the water fraction prior to processing the water fraction in the high temperature electrocoagulation system.

11. The system of any one of claims 1 to 10, wherein the solids/froth/water separation and solids/sludge dewatering system comprises one or more of a vacuum clarifier, a sequential baffle solids/froth separating / breaking tank, a hydrocyclone, a dissolved gas floatation system, a micro-media filter, a settling pond, a centrifuge, or a solids/sludge dewatering filter press.

12. The system of claim 11, further comprising a sludge conditioning chemical addition system for admixing sludge conditioning chemicals to the solids/water mixture or sludge fraction upstream of one or more of the hydrocyclone, the settling pond, or the sludge dewatering filter press.

13. The system of any one of claims 1 to 12, wherein the polishing system comprises one or more of a strong acid cation exchanger or a weak acid cation exchanger, wherein the exchangers are used alone or together, and in series or in parallel.

14. The system of any one of claims 1 to 13, further comprising a neutralization regen waste storage tank for receiving the regeneration waste water stream and an additive feed system for adjusting the pH of the regeneration waste water stream.

15. The system of claim 14, further comprising a flow line for feeding pH
adjusted regeneration waste water from the neutralization regen waste storage tank to the deoiling system or for admixture with the water fraction upstream of the high temperature electrocoagulation system.

16. The system of any one of claims 1 to 15, further comprising a steam deaerator for removing entrained gases from the boiler feed water stream.

17. The system of any one of claims 1 to 16, the steam generation system further comprising one or more of:
an ammonia or volatile amine feed system for admixing ammonia or a volatile amine with the steam upstream of the enhanced oil recovery system;
a medium/low pressure steam separator;
a disposal well treatment process;
disposal tanks;
an excess utility steam condenser;
an oxygen scavenger and boiler feed water conditioner additive system;
a desuperheater;
a flash evaporator;
a crystallizer; or a carbon dioxide scrubber.

18. A process for providing steam to an enhanced oil recovery system, the process comprising:
receiving an oil-water emulsion from an enhanced oil recovery system, the emulsion comprising one or more of dissolved solids, entrained gases and/or light hydrocarbons, distillate and/or heavier hydrocarbons, and water;
separating the entrained gases and/or light hydrocarbons from the oil-water emulsion, producing a vapor stream and an oil-water stream;
in a deoiling system, separating the oil-water stream into a recovered oil fraction and a water fraction containing dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants, wherein the deoiling system comprises:
a free water knockout drum to separate the oil-water emulsion into a free water fraction and an oil-emulsion fraction;
an oil treater for contacting the oil-emulsion fraction with a hydrocarbon solvent to reduce a density and viscosity of the hydrocarbons in the oil-emulsion fraction and forming an oil fraction and a water-oil suspension containing residual oil;
a skim/surge tank for coalescing the residual oil in the water-oil suspension and producing a coalesced oil fraction and a water effluent;
a gas flotation unit for further de-oiling the water effluent, producing an oil fraction and a water fraction containing less than 10 ppm oil; and a deoiled / makeup water storage tank for storing the water fraction prior to feed to a high temperature electrocoagulation system;
processing the water fraction in a high temperature electrocoagulation system for ionizing, complexing, and/or absorbing the dissolved silica, hardness, total organic carbon, and other dissolved organic and inorganic contaminants in the water fraction, producing a vapor fraction and a solids/froth/water mixture;
separating the solids/froth/water mixture into a sludge fraction and a clarified water fraction;

reducing a total hardness of the clarified water fraction to less than 0.2 ppm and producing a regeneration waste water stream and a boiler feed water stream;
feeding the regeneration waste water stream to the skim/surge tank or mixing the regeneration waste water stream with the water fraction upstream of the high temperature electrocoagulation system;
a steam generation system for converting the boiler feed water stream to steam;
providing steam from the steam generation process to the enhanced oil recovery system.

19. The process of claim 18:
wherein the water fraction contains less than 10 ppm of residual oil;
wherein the clarified water fraction has a turbidity value of less than 2 and a solids content of less than 1 ppm;
wherein the boiler feed water stream has a total hardness of less than 0.2 ppm; and wherein the boiler feed water stream has an oxygen content of less than 0.007 ppm and a pH of 9Ø