WO2016115497A1

WO2016115497A1 - Switchable polar solvent-based forward osmosis water purification system incorporating waste exhaust and heat streams from co-located facilities with co2 sequestration

Info

Publication number: WO2016115497A1
Application number: PCT/US2016/013664
Authority: WO
Inventors: Karen Fleckner; Michael K. Neylon
Original assignee: Artesion, Inc.
Priority date: 2015-01-16
Filing date: 2016-01-15
Publication date: 2016-07-21

Abstract

The present invention provides a water purification system and method using a switchable polar solvent as a draw solvent in a forward osmosis (FO) process, incorporating waste exhaust and heat streams from co-located facilities that produce heat and C0₂. The invention provides both clean water and C0₂ separation for further processes and product applications or sequestration.

Description

SWITCHABLE POLAR SOLVENT-BASED FORWARD OSMOSIS WATER PURIFICATION SYSTEM INCORPORATING WASTE EXHAUST AND HEAT STREAMS FROM CO-LOCATED FACILITIES WITH CO₂ SEQUESTRATION

RELATED APPLICATION DATA

[0001] This application claims the benefit of priority under 35 U.S.C. §119(e) of U.S. Provisional Patent Application Serial No. 62/104,277, filed January 16, 2015, the entire contents of which is incorporated herein by reference in its entirety.

BACKGROUND OF THE INVENTION FIELD OF THE INVENTION

[0002] The present invention relates generally to water purification systems, and more specifically, to a water purification system using a switchable polar solvent as a draw solvent in a forward osmosis (FO) process, incorporating waste exhaust and heat streams from co- located facilities that produce heat and CO₂.

BACKGROUND INFORMATION

[0003] Carbon Capture Sequestration (CCS) can be categorized in two basic types: Terrestrial and Geologic. In Geologic sequestration, the captured CO₂ is typically pressurized and stored in natural underground formations. In Terrestrial (or biologic) sequestration applications plants are used to capture CO₂ from the atmosphere and then stored as carbon in the stems and roots of the plants as well as in the soil. There are also other processes where the CO₂ can be used in an environmentally-benign beneficial manner such as using the CO₂ to enhance agricultural soil. Within the CO₂ sequestration process is a separation step to remove CO₂ from other gases in exhaust streams, typically contain nitrogen, oxygen, and moisture which would reduce the efficacy of the CO₂ storage.

[0004] CCS consists of two steps: capturing CO₂ out of a post-combustion exhaust stream using adsorption or absorption processes, and then sequestering the CO₂. The most common means of sequestration of CO₂ is to pressurize and store it in natural underground formations. The pressure used will be a function of the storage depth, with more pressure required for deeper storage, and will range from 100 to 400 atm. Any impurities in CO₂ including non- condensable gases such as N₂, 0₂, and Ar, will reduce the storage effectiveness at high pressures. A CO₂ stream with 15 vol% impurity of other non-condensable gases has a 40% lower sequestration storage capacity compared to a pure CO₂ stream. The impurities also more difficult to deliver the CO₂ to the storage point. The CO₂ capture process that removes CO₂ from post-combustion streams must be able to achieve a high purity of CO₂ and minimize the amount of non-condensable gases, particularly N₂ which is nearly always within combustion processes.

[0005] CO₂ capture can be performed through adsorption (where the CO₂ adheres to a substance) or absorption (where the CO₂ is dissolved into a substance), and can be done through a physical or chemical process. Of the available options, chemical absorption is considered the most applicable technology in the near-term for CCS, as it can operate on low- pressure flue streams generated from post-combustion processes. Of these, amine-based absorption, often called an amine scrubber system, is the most established option.

[0006] The most common approach to remove CO₂ is through an amine scrubber system. An example of an amine scrubber is shown in Figure 1.

[0007] An anime scrubber is based on a carrier solvent containing one or more primary and secondary amines, such as methylethylamine (MEA) in an aqueous solution. In an absorber column, the exhaust gas stream is bubbled through the solvent at ambient conditions, during which the amine reacts with the CO₂ to form either a carbamate salt or a bicarbonate salt as follows.

[0008] Carbamate route: 2R₂ H + CO₂ R₂ HH⁺ + R₂NCOO^" (Reaction 1)

[0009] Bicarbonate route: R₃N + CO₂ + H₂0 R₃ H⁺ + HCOO^" (Reaction 2)

[0010] The amines are selected so that these salts have very high solubility in water, as to maximize the amount of CO₂ that can be absorbed per pass. The other gases in the exhaust stream (primarily nitrogen and oxygen) do not interact with the solvent, and are released to the environment after passing through the column.

[0011] Once CO₂ is absorbed, the solvent is then moved to a desorption column. This is nominally a heated unit operating no greater than 90° C. The temperature is sufficient to reverse the above salt formation reactions, regenerating the amine and releasing CO₂, without causing the water solvent to vaporize. The CO₂ is then treated to remove traces of condensable components such as moisture and amine prior to sequestration or other downstream uses.

[0012] The amine scrubbing process is effective for CO₂ removal, and can often be tied and driven by a co-located power generation plant, which will have excess energy for the utility loads on the scrubber systems, and low-quality heat that can drive the CO₂ release reactions. Additional equipment and power will be required to then pressurize and store the CO₂ for sequestration applications. However, this process does little else with the CO₂ despite the ability to convert it into an active chemical species (the bicarbonate or carbamate forms) at ambient temperature and pressure. The ability to activate the otherwise inert CO₂ at these conditions presents an opportunity to use this behavior for other processes. An embodiment of the invention describes how water purification can be tied to the process of CO₂ sequestration using a novel solvent approach.

[0013] The combination of a switchable polar solvents used for water purification and utilizing CO₂ to enable the process is not obvious to combine with carbon separation or CCS. This is because one of the properties of switchable polar solvents is their "switchable" nature, which is normally an undesirable property for amine scrubbing. The addition of CO₂ (an ionizing agent) to switchable polar solvents transforms non-ionic, hydrophobic amines into a highly ionic, hydrophilic solution. For switchable amines, this transformation is reversible, which causes the amine to separate from the water solution. In traditional amine scrubbing, this separation is undesirable as it makes it costly and difficult to recycle the amine solution, but this is an ideal property that can be exploited for water purification as water can be recovered from the switchable solvent. Previous work has shown the switchable nature of these amines using CO₂ can be used for phase separation of organic materials and to assist phase-catalyzed reactions. Of interest to this invention is the identification of such switchable polar solvents for water treatment using forward osmosis in combination with their ability to capture and separate CO₂. The switchable nature of these specific switchable polar solvents would enable simultaneous carbon separation and water treatment within the same system to support a co-located facility using waste streams (CO_2; residual water and heat) from that facility, which can be beneficial for many types of industries where carbon separation and water treatment processes are desired and available.

[0014] Within the water purification field, one identified approach is to use the activated CO₂ to enhance a draw solvent for forward osmosis (FO). In forward osmosis systems, a draw solvent is prepared with a much larger osmotic pressure than the feed solvent containing water to be purified. The osmotic pressure differential is the driving force that pulls water across the water permeable membrane from the feed into the draw solvent. Downstream processes are used to separate the water and regenerate the draw solvent. FO systems are favorable as they do not require high hydraulic pressures typical of reverse osmosis (RO). One significant drawback of FO processes is the energy requirements to regenerate the draw solvent after it is diluted with water from the membrane. In most proposed FO designs, the draw solute is a highly concentrated salt solution, with two options to regenerate the diluted draw solvent: the use of a secondary reverse osmosis (RO) membrane, or the evaporation of the solution. Both methods are energy intensive, with net energy costs anticipated to be greater than typical FO systems.

[0015] FO for water treatment has many potential advantages compared to reverse osmosis (RO), where hydraulic pressure is used to force the water across the membrane. FO water treatment systems use concentrated draw solutions with high osmotic pressures (200 atm and greater) to create large osmotic pressure differentials. FO systems can surpass physical limitations of RO systems. RO systems are limited to feed water that is no more saline than seawater (35,000 ppm TDS). The RO process at this concentration requires hydraulic pressures around 60 to 80 atm. It becomes very energy intensive to pressurize water above 80 atm, and requires more exotic materials of construction that can withstand these pressures, significantly increasing the system cost. Further, RO systems can only recover about 50% of the water within seawater due to the pressure limitation. FO systems can treat much higher salinity feed solutions like brine (-200,000 ppm TDS), and can achieve higher water recovery rates from equivalent feeds than RO; it is estimated that FO systems can achieve at least 75% water recovery from seawater and potentially as high as 85%. A drawback of FO is the energy requirements for water recovery. FO research to date has primarily focused on using salt-based draw solutes such as NaCl or MgCl₂. The recovery of water from salt-based FO draw solution requires either vaporization of the water or pressurized membrane processes such as RO. The energy requirements for FO using salt draw solutes are estimated to be higher than direct RO processes.

[0016] Switchable amines have been identified as draw solutes for FO that overcome some of the issues with salts while retaining the benefits of high osmotic pressure, the robust range of feed water that can be treated, and water recovery efficiencies. Concentrated amine solutions, once ionized by CO₂, can have high osmotic pressures greater than 200 atm, generating high osmotic pressure differences required for effective water draw across the membrane. To produce water from the dilute draw solution, the amine solute is dissociated from CO₂, leaving it in a non-ionic and generally insoluble form, simplifying its separation from the produced water. This process follows the same chemistry as the desorption process in amine scrubbing, and can be done at temperatures less than 90° C and without vaporization of the water. It is estimated that the energy requirements for amine-based FO are much lower than with salt-based FO, and can be lower than an equivalent optimized RO system. Further, the low temperature requirements allow low quality waste heat streams (those with a temperature less than 150° C) to be utilized directly to provide the required energy to extract clean water, further lowering additional energy requirements. Tertiary amines have been found to be best suited for FO draw solutes. The lack of hydrogen bonded to the central nitrogen prevents carbamate formation, which is a more energy-intensive pairing to dissociate compared to bicarbonate. Additionally, the non-ionic form of tertiary amines cannot readily undergo hydrogen bonding, making them less soluble in water and easing the energy requirements for water extraction.

[0017] Efforts have been made to find alternate draw solvents that can be regenerated with lower energy requirements. One option that has been identified is the use of switchable polar solvents (SPS), tertiary amines that can absorb CO₂ to form the bicarbonate ionic pair. A key feature of the SPS solvents is that they are non-polar (hydrophobic) prior to CO₂ absorption, and become polar (hydrophilic) following CO₂ absorption. Further, the ionic polar form possess very high osmotic pressure (exceeding 250 atm and can be high as 10,000 atm when highly concentrated), making it an excellent draw solvent for even concentrated dirty water streams. The water, once drawn across the membrane, is separated by reversing the polarity shift of the SPS from its polar to non-polar form similar to releasing CO₂ in an anime scrubber. The water and SPS form two immiscible phases that can be separated through simple mechanical needs, reducing the need for any high pressure or high temperature requirements. The permeate of the water purification process contains both water and switchable draw solution. These immiscible phases of water and switchable polar solvents can be liquid-solid, liquid-gas, or liquid-liquid. This classification of the immiscible phases of the water and switchable polar solvents have overlapping definitions due to prior art nomenclature.

[0018] CO₂ is a driving factor for the SPS-based FO system. In a standalone system, the system would need to be charged with CO₂, and makeup CO₂ would ultimately need to be added to account for losses from incomplete recovery of CO₂ or potential gas leaks in the process. This would require a source of CO₂ to recover those losses. For small scale systems this may be accomplished by stored CO₂ tanks, but larger water purification systems may require makeup CO₂ at a rate exceeding what one can reasonable expect for CO₂ storage. Alternatively, as described by this invention, CO₂ can be obtained from the off-gases of a combustion-type or other biological, industrial or commercial plant, or from prior sequestered CO₂ sources. The CO₂ exhaust can either be used directly or from CO₂ sequestration storage. As demonstrated in the examples described in this invention, an FO system that produces 1 million gallons of water per day would utilize around 430 tons of CO₂ per day in the draw solute recycle loop. While most of this CO₂ is recycled within the system, even small losses will require significant CO₂ storage or direct supply. Additionally, such plants will have low- quality (<100° C, other sources have reported up to 300° C) heat waste streams normally vented to atmosphere. These streams can be used to drive the SPS regeneration/CO₂ release from the draw solvent in the SPS system.

[0019] One documented example of where water purification has been coupled with CO₂ sequestration is described in U.S. Patent No. 8,551,221, "Method for Combining Desalination and Osmotic Power with Carbon Dioxide Capture". U.S. Patent No. 8,551,221 describes an FO process using an ammonia-water draw solvent, similar to the solvent used in CO₂ absorption. Aqueous ammonia solutions can be converted to a highly concentrated ionic solution via CO₂ absorption from exhaust streams through the above carbamate/bicarbonate reactions. The high concentration generates osmotic pressures up to 250 atm, which can drive water across a semi-permeable membrane from typical feeds such as salt water (3.5 wt% NaCl, approximately 27 atm osmotic pressure). The ammonia solution is regenerated by heating the diluted solvent. Heating creates two effects: it reverses the salt formation reactions above to release gaseous CO₂ and aqueous ammonia, and it vaporizes the ammonia from solution to leave behind nearly-pure water. The gaseous ammonia is separated from the CO₂ to be reintroduced into the draw solvent. The CO₂ is subsequently removed from the system and sent to be sequestered.

[0020] While this ammonia-water patent demonstrates the ability to combine CO₂ separation and sequestration with water removal, it is an energy intensive process. The following described invention uses the more energy-efficient SPS water purification system as a basis due for further energy-efficiency when coupled with the exhaust CO₂ and heat from other biological, industrial, and commercial systems.

[0021] Other art teaches the potential of using waste heat energy from co-located source to drive distillation or RO systems for water purification. Such patents include U.S. Patent No. 7,037430, U.S. Patent No. 8,221,628, and U.S. Patent No. 8,545,681. For distillation, these processes require higher-grade heat sources (> 350° C) to vaporize the water to distill it, a high energy process, while this invention describes the use of low-grade heat sources for the FO recovery process. The heat use in RO systems is applied towards heating the feed water, which can improve the efficiency of the permeation process, but will still require high hydraulic pressures driven by electricity to drive water across the membrane. This invention is uniquely situated to take low-quality waste heat alongside waste CO₂ to produce clean water while separating CO₂ from the waste stream.

SUMMARY OF THE INVENTION

[0022] In various aspects, the present invention relates to a process in which a water purification system is co-located and operated in a co-generation mode that utilizes the exhaust CO₂ and heat produced from a biological, industrial, or commercial facility. The water purification system is based on the use of the more energy-efficient switchable polar solvents (SPS), tertiary amines that have the ability to switch from a non-polar to a polar form in the presence of CO₂. The CO₂ is obtained from the exhaust from the co-located facility. The waste heat stream(s) from the facility can be used to drive the CO₂ removal step, reducing the utility load of the water purification process. The combined process provides a means of separating CO₂ from exhaust gases while providing clean water that can be used either by the facility or for local uses such as drinking water or irrigation.

[0023] Accordingly, in one embodiments, the invention provides a method for water purification. The method includes a) providing a water purification system; b) providing the system with an impure water source; and c) generating a purified water effluent from the impure water source via the purification system. In embodiments, the system is adapted to utilize exhaust heat and a CO₂ containing waste stream generated via an auxiliary facility or process to generate the purified water effluent. In embodiments, the auxiliary facility or process is a co-located facility or biological, industrial or commercial process that generates exhaust heat and a CO₂ containing waste stream. In one embodiment, the co-located facility is operated in co-generation mode.

[0024] In various embodiments, the method of the invention utilizes a water purification system capable of performing a forward osmosis (FO) separation process. The FO process includes: a) a draw solvent regeneration cycle; b) a membrane process utilizing a water- permeable membrane unit; c) a recovery process utilizing a unit to recover water from draw solvent; and d) a process to remove trace components of draw solvent to generated a purified water stream prior to delivery utilizing one or more low-pressure units. In various embodiments, the draw solvent regeneration cycle utilizes a switchable draw solute or polar solvent. In one embodiment, the draw solvent regeneration cycle includes an aqueous draw solution using a draw solute that becomes highly soluble and ionic upon the addition of an ionizing agent, and becomes insoluble and non-ionic on the dissociation of the ionizing agent. [0025] In another aspect, the invention provides a water purification system configured to utilize exhaust heat and one or more CO₂ containing waste streams generated via an auxiliary facility, such as a co-located facility, or process to generate purified water effluent.

[0026] In yet another aspect, the invention provides a water purification system that treats one or more water feed streams and generates one or more purified water effluent streams. The system is configured to utilize exhaust heat and one or more CO₂ containing waste streams generated via a co-located facility to generate the purified water effluent streams. The system includes a control system and one or more water treatment sub-systems, wherein at least one of the sub-systems is a forward osmosis (FO) water treatment system comprising: a) a draw solution using a switchable draw solute which, at standard ambient conditions, is hydrophobic and is immiscible or insoluble in water, and which can be ionized by the addition of CO₂ to become hydrophilic and highly soluble in water, and which subsequently can be dissociated from CO₂ to return to its hydrophobic form; b) a membrane system comprising one or more semi-permeable membranes that allows for passage of water while rejecting suspended solids, ions, and organic and biological materials in the water, where one side of each membrane is contacted with a impure feed water stream, and an opposite side contacting concentrated draw solution comprising ionized draw solute and CO₂, whereby an osmotic pressure difference between draw solution and feed solution causes water to permeate across the membrane into the draw solution thereby diluting it; c) a recovery process which dissociates CO₂ from the draw solute in the diluted draw solution, which some or all of the CO₂ being released as exhaust, and which separates the non-ionized draw solute from the water; d) a regeneration process which combines water, draw solution, the recovery draw solute, and additional CO₂ from one or more CO₂-laden streams from one or more co- located facilities to ionize the draw solute and create a concentrated draw solution; and e) a control system to monitor and control the switchable forward osmosis water treatment subsystem.

BRIEF DESCRIPTION OF THE DRAWINGS

[0027] Figure 1 is a process flow diagram illustrating a typical prior art amine-based CO₂ scrubber system used for CO₂ sequestration.

[0028] Figure 2 is a process flow diagram for a SPS-based FO water purification system in one embodiment of the present invention. [0029] Figure 3 is a process flow diagram for a SPS-based FO water purification system in one embodiment of the present invention, wherein the water purification system od driven by waste exhaust from a co-located plant operated in co-generation mode.

[0030] Figure 4 is a process flow diagram for a SPS-based FO water purification system in one embodiment of the present invention, wherein the water purification system is driven by multiple CO₂ streams.

[0031] Figures 5a-5b demonstrate the use of the invention in the enhanced oil recovery (EOR) process. Figure 5a is a diagram outlining the basic features of EOR, and Figure 5b is a diagram illustrating the inclusion of the switchable FO water treatment sub-system within the EOR process.

[0032] Figures 6a-6b demonstrate the use of the invention for landfill gas (LFG). Figure 6a is a diagram illustrating the invention using the waste heat and products from a LFG- burning power plant, while Figure 6b is a diagram illustrating use of the invention to separate CH₄ from LFG while burning some of the LFG for heat and power while producing water.

DETAILED DESCRIPTION OF THE INVENTION

[0033] The present invention provides a water purification system and process utilizing an energy-efficient SPS water purification system as a basis for energy-efficiency when coupled with exhaust CO₂ and heat from other biological, industrial, and commercial systems. This process when combined with CO₂ sequestration provides an innovative energy efficient water purification process.

[0034] Before the present method and system are described, it is to be understood that the invention is not limited to the particular methods, systems and experimental conditions described, as such methods, systems and conditions may vary. It is also to be understood that the terminology used herein is for purposes of describing particular embodiments only, and is not intended to be limiting, since the scope of the present invention will be limited only in the appended claims.

[0035] As used in this specification and the appended claims, the singular forms "a", "an", and "the" include plural references unless the context clearly dictates otherwise. Thus, for example, references to "the method" includes one or more methods, and/or steps of the type described herein which will become apparent to those persons skilled in the art upon reading this disclosure and so forth.

[0036] Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which the invention belongs. Although any methods and materials similar or equivalent to those described herein can be used in the practice or testing of the invention, the preferred methods and materials are now described.

[0037] Definitions

[0038] A "water treatment system" is considered to be a system process composed of multiple treatment sub-systems that processes water from a source to produce a desired quality of water.

[0039] A "water treatment sub-system" is considered to be either a singular sub-system, or a set of water treatment sub-systems arranged in series or parallel configurations, along with supporting balance-of-plant equipment (valves, pumps, sensors, etc.) that handle one aspect of water treatment. For example, a RO water treatment sub-system may be composed of a pump, one or more RO membranes within their housing units, and pressure, flow rate, and temperature sensors located throughout the system to monitor performance.

[0040] "Produced water" refers to the water generated by the water treatment system.

[0041] "Clean water" refers to the effluent water generated by the water treatment system. This effluent can be pure water, but not always.

[0042] "Recycled water" refers to water that is produced from secondary or tertiary treatment of wastewater. Such water often referred to as "reclaimed water" and "purple pipe water".

[0043] "Impaired water" refers to surface water or groundwater sources which do not meet water quality standards that governments or authorities have set, even after point sources of pollution have installed the minimum required levels of pollution control technology, such as those defined under the U.S. Clean Water Act, section 303(d).

[0044] "Upstream" and "downstream" refer to the placement of sub-systems with respect to the flow of the feed water as it is purified, unless otherwise noted. The water sources are upstream of the water treatment system, while the produced water is collected downstream of the system.

[0045] A "switchable" material is a chemical component or mixture that, when in the presence of water, can change the ionic nature of the water through the addition or dissociation of an ionizing agent. A switchable draw solute becomes more ionic when contacted by the ionizing agent, and becomes less ionic when the ionizing agent is removed.

[0046] A "switchable polar solvent", unless otherwise clarified, is considered in this invention to be a draw solution that uses a switchable material. [0047] An "ionizing agent" is a material that can provide a proton to ionize the switchable draw solute, while forming an anion itself. In an embodiment of the invention, the ionizing agent of interest is CO₂.

[0048] "Standard ambient conditions" refers to a temperature of 25° C and a pressure of 1 atm.

[0049] "Standard temperature and pressure" (STP) or "standard conditions" refers to a temperature of 0° C and a pressure of 1 atm. Certain gas volumes described in this invention are reported in "standard cubic feet" (scf), from which mass and density calculations use the density of the gas at STP.

[0050] "Organic compounds" defined here are molecules that primarily contain a carbon backbone chain and the presence of hydrogen, with, on average, at least one hydrogen molecule bonded to each carbon in the molecule. "Inorganic compounds" are molecules that otherwise do not meet this definition of "organic compound", and can include carbon-based structures that lack hydrogen or have, on average, far less than one hydrogen bonded to each carbon in the molecule, such as graphite.

[0051] A "regeneration system" as used herein is a set of processes that bring together water, draw solute, ionizing agent, and diluted draw solution to form the concentrated draw solution. This process is also referred to in prior art as a "gassing" system, as the ionizing agent, and in some cases the draw solute, are normally introduced as gases.

[0052] A "recovery system" as used herein is a set of processes that separate the draw solute and the ionizing agent from the diluted draw solution to produce clean water. This process is also referred to in the prior art as a "degassing" system, as the ionizing agent, and in some cases the draw solute, are normally removed from the draw solute as gases.

[0053] Unless otherwise stated, a "draw solvent" refers to a draw solution in the membrane process which can readily accept the addition and remove of draw solute and other salts that may transfer from the feed solution into the draw solution. A "switchable draw solvent" is such a solution that uses a switchable material, as defined above.

[0054] The quality of a heat stream relates to the ease which with one can extract thermal energy from, though there are no exact definitions of how to classify a given process stream. For purposes of the invention, "low quality heat" is defined here as a process stream that is at atmospheric pressure and a temperature less than 150° C. "Medium quality heat" is defined as a process stream at atmosphere pressure and a temperature between 150° C and 250° C. "High quality heat" is defined as a process stream at atmosphere pressure and a temperature greater than 250° C. These values follow from reports that assess the potential for waste heat use for power.

[0055] Rates of electrical energy and thermal energy in watts are distinguished using W_e and W_t, respectively. Energy rates or quantities given in British thermal units (BTUs) represent thermal energy quantities.

[0056] "Balance of plant" represents process units and components, not explicitly defined by the invention, that are used to support the operation of the water treatment system or its sub-systems. Balance of plant may include, but are not limited to, pumps, compressors, fans, blowers, vacuum pumps, heaters, coolers, chillers, sensors, control units, alarms, storage tanks and vessels, piping, electrical connections and wiring, support structures, health and safety equipment, and external connections and interfaces to utilities.

[0057] A "co-located facility" is defines as one or more processes that are located in close proximity to the water treatment system, as to allow effective transfer of thermal energy to the system. This implies that the water treatment system would be located at the same land site at the co-located facility. For purposes of the invention, it is assumed that the co-located facility is within one mile of the water treatment system, though preferably will be much closer to prevent the loss of thermal energy over transfer distance.

[0058] In embodiments, the invention described herein provides a method of water purification utilizing a water purification system capable of performing a forward osmosis (FO) separation process. The FO process includes: a) a draw solvent regeneration cycle; b) a membrane process utilizing a water-permeable membrane unit; c) a recovery process utilizing a unit to recover water from draw solvent; and d) a process to remove trace components of draw solvent to generated a purified water stream prior to delivery utilizing one or more low-pressure units.

[0059] In embodiments the method utilizes an FO water purification system using an SPS draw solvent that is driven by waste flue gas, containing CO₂, and heat from exhaust.

[0060] In another aspect, the invention provides a water purification system configured to utilize exhaust heat and one or more CO₂ containing waste streams generated via an auxiliary facility, such as a co-located facility, or process to generate purified water effluent.

[0061] FO systems using an SPS draw solvent have been previously described, for example, in International Application No. PCT/US2015/065322, filed December 11, 2015, which is herein incorporated by reference in its entirety. The process of this system is shown in Figure 2. [0062] The switchable polar solvent in the draw solvent loop is generally a tertiary amine; they can be switched through the bicarbonate route as previously described for CO₂ scrubber amines.

[0063] R₃N + CO₂ + H₂0 R₃N⁺ + HCOO^"

[0064] In the process, the SPS in its non-polar form is gassed with CO₂ and water to convert it into its polar form, highly concentrated in aqueous solution (50-99% by weight). This highly concentrated solution has a high osmotic pressure (275 atm or greater), and can readily drive water across a FO membrane from feed solvents such as brackish or sea water. After the membrane, the diluted SPS solvent is heated to no greater than 90° C to reverse the salt formation reaction: CO₂ is released and the SPS reverts to its non-polar form which is immiscible with water. This phenomena can be applied to SPS's solid, liquid, and gas phases. Physical, gravity-driven and mechanical processes can be used to separate the clean water from the SPS. Low-pressure filtration can be used to remove the trace polar SPS form in the water, and a final amine polishing step is used to bring the water to desired quality. High purity CO₂ (greater than 99%) can be introduced from a variety of sources including; compressed or cryogenic storage tanks, CO₂ from co-located facilities that can be further purified in a separation process, or from previously stored CO₂ that has been sequestered. The high purity CO₂ can come from one or more of these sources.

[0065] The SPS FO process of the invention is designed to be more energy efficient than other typical FO processes. The draw solvent in most FO processes is a salt with high solubility in water. While concentrated salt solutions can achieve similar osmotic pressures to draw water through a membrane, the separation of water from the draw solvent must be done using either evaporative methods (heating to above 100° C) or using a reverse osmosis membrane. Evaporative methods require a large amount of energy to vaporize water. Similarly, reverse osmosis will be energy intensive as they require very high hydraulic pressures upwards of 50-60 atm to work against the osmosis pressure. When a SPS draw solvent is used, some energy in the form of heat is required to reverse the bicarbonate formation reaction at temperatures below 90° C, but this is far less energy required to vaporize water, and can be completed at low to atmospheric pressures (1-3 atm), reducing the required utility loads. The remaining separation process is through the natural gravity-driven phase separation between the non-polar SPS and water and does not require significant energy input. [0066] Draw Solution and Properties

[0067] A goal of the present invention is to achieve nearly complete separation of the draw solute, CO₂, and water using either or both low and high quality heat within the recovery process. In a preferred embodiment, at least 50%, but preferably 99% of the draw solute can be dissociated from the CO₂ at atmospheric pressure and a temperature no greater than 90° C, and in a more preferred embodiment, no greater than 75° C, and most preferable no greater than 60° C. In a further embodiment, at least 50%, but preferably 99% of the draw solute can be removed from the water at atmospheric pressure and a temperature no greater than 90° C, and in a more preferred embodiment, no greater than 75° C, and most preferable no greater than 60° C. While 100% separation of these species is desirable, it may be impractical to achieve at these temperatures without significant energy and cost. The switchable FO water treatment sub-system, as described by this invention, is capable of handling trace CO₂ and draw solute in the recovered water through the additional polishing steps.

[0068] In an embodiment of the invention, the solubility of the draw solute in its non-ionic form is less than 0.1 g/mL in water, and more preferably, less than 0.0001 g/mL, and the solubility of the draw solute in its ionic form upon association with the ionizing agent is greater than 1000 g/mL in water.

[0069] The separation of the CO₂, draw solute, and water all occur within the recovery process, which is the largest energy consumer of the switchable FO water treatment subsystem. It is desirable to keep the operating temperatures for the recovery process as low as possible, yet sufficient to complete the separations as described above, so as to have the optimal energy efficiency. In an embodiment of the invention, the recovery process operates at a temperature of no greater than 90° C at 1 atm, and more preferably at a temperature no greater than 75° C, and most preferably at a temperature no greater than 60° C.

[0070] In a preferred embodiment of the invention, the recovery process is operated under a vacuum, at an absolute pressure greater than 0.4 atm and less than 1 atm, and more preferably greater than 0.5 atm and less than 1 atm. The dissociation and removal of CO₂ is facilitated by the vacuum, allowing the recovery system to be run at lower temperatures and reducing the thermal heating requirements. The vacuum can be pulled using a vacuum pump, blower, or ejector. This process is discussed in International Application No. PCT/US2015/065322. In a preferred embodiment, the vacuum can be pulled from an existing vacuum system or other available mechanical (shaft) work on the co-located facility or equipment. This can be done in association with compression, using the shaft work from a compressor to create the vacuum.

[0071] The switchable solvent separation feature described above has been demonstrated with several amine compounds. In an embodiment of the invention, the switchable solute in the draw solution process loop is an amine that normally has non-ionic nature and is insoluble in water, and becomes ionic and highly soluble with the reversible addition of CO₂. In a more preferred embodiment, this solvent or solute is a tertiary amine. Tertiary amines are desired as they can only be switched through the bicarbonate route as previously described for CO₂ scrubber amines (Reaction 2), avoiding the formation of carbamates (Reaction 1) that require more energy for dissociation.

[0072] In an embodiment of the invention, the draw solute is an amine of the general form RWN, or an amidine of the general form R¹-C(= R²)- R³R⁴), or a guanidine of the general form R¹R²-C(= R³)- R⁴R⁵). In these, R¹, R², R³, R⁴, and R⁵ are each independently selected from the following substitution groups: hydrogen, a substituted or unsubstituted alkyl group, including linear, branched, and cyclic components, with between one and 10 carbon atoms; a substituted or unsubstituted C_nSi_m group (wherein n and m are integers independently selected from 0 to 10, and wherein (n + m) is an integer from 1 to 10); and a substituted or unsubstituted aryl group or heteroaryl group that may contain at least one {- Si(R⁶)2-0-} group, wherein R⁶ is a substituted or unsubstituted alkyl, aryl, heteroaryl, or alkoxy group. If the group is substituted, the substituent may be an alkyl, alkenyl, alkynl, alkyl halide, aryl, aryl halide, heteroaryl, non-aromatic ring, Si(alkyl)₃, Si(alkoxy)₃, alkoxy, amino, ester, amide, thioether, alkylcarbonate, or thioester group. The amine can also be a cyclic compound, with the nitrogen of the amine as a heteroatom within the cyclic structure. In an embodiment of the invention, the draw solute can be a combination of two or more amines as described above.

[0073] In one embodiment of the invention, the draw solute is a chemical that is normally a liquid at standard ambient conditions (25° C and 1 atm). For this embodiment, the liquid will be immiscible with water in the non-ionic state, allowing for physical separation through processes such as decanting or centrifuging. When CO₂ is added, the liquid draw solute dissolves in the water and creates a draw solution with high osmotic pressure. Such amines include Ν,Ν-dimethylcyclohexylamine and 1-cyclohexylpiperdiene.

[0074] In another embodiment of the invention, the draw solute is a polymer, the polymer is constructed from amine-based monomers, with the monomer having the base formula - where and are functional groups as described above. The polymer in

its non-ionic state may remain suspended in solution or precipitate out. CO₂ will interact with the nitrogen atoms on the amine monomer to make the polymer molecule ionic, increasing its solubility in water and increasing the osmotic pressure. When CO₂ is dissociated from the polymer, the polymer will return to its non-ionic form. The larger size of the polymer allows less energy-intensive separation processes such as filtration to recover the draw solute from solution. The larger polymer size also will reduce the amount of reverse salt flux at the FO membrane, limiting the amount of draw solute that crosses into the feed solution. The larger size may further reduce the effects of the internal concentration polarization (ICP) within the forward osmosis membrane which can negatively influence the FO membrane performance. Such polymers have been demonstrated as potential draw solutes. In a preferred embodiment, the polymer has an average molecular weight greater than 1,000, and in a more preferred embodiment, 10,000. In a preferred embodiment, the polymer is homomeric from the same amine monomer. In another preferred embodiment, the polymer is heteromeric, with at least one monomer being an amine. In a more preferred embodiment, the monomer is a tertiary amine. In yet another preferred embodiment, the draw solute is a combination of two or more polymers that have amine monomer bases as described above.

[0075] In yet another embodiment of the invention, the draw solute is a gas at standard ambient conditions. The types of chemical compounds for the gaseous draw solute are the same as defined for those previously described earlier for the liquid-based draw solute and can be used in the gas phase for this embodiment. Effective separation of the draw solute as a gas from CO₂ will be through a cooling process as to collect the condensed form of the draw solute while releasing the CO₂ as a gas. This requires that the vaporization temperature for the draw solute to exceed the vaporization temperature of CO₂, -79.5° C. In a preferred embodiment, the vaporization temperature for the draw solute is at least -40° C, and more preferably at least -20° C, and most preferable at least 0° C.

[0076] The concentration of the draw solution, including the relative ratio of CO₂ to amine, will affect its solubility and osmotic pressure. For simplicity, the term "CO₂ to amine centers" molar ratio is defined as the moles of CO₂ to the number of moles of nitrogen atoms in the draw solute compound that act as amines. This ratio follows from Reaction 2, the bicarbonate reaction, previously described, to assure that each amine-based atomic center reacts with one CO₂ molecule. For the liquid-based draw solutes, these is generally only one such nitrogen atom per amine molecule. For the polymer-based draw solutes, there will usually be one nitrogen atom for every amine-based monomer in the polymer.

[0077] In a preferred embodiment of the invention, the molar ratio of the CO₂ to amine centers is at least 1 and preferably less than 10, and more preferably less than 2 and most preferably less than 1.5. In a preferred embodiment, the concentration of concentrated draw solution, possessing both draw solute and CO₂, is between 5% to 90% by mass, and more preferably between 25% and 80% by mass.

[0078] In a preferred embodiment of the invention, the osmotic pressure of the concentrated draw solution prior to the membrane process is at least 100 atm, and more preferably at least 200 atm, and most preferably more than 400 atm. Some switchable draw solutes have shown osmotic pressure as high as 750 atm and would be applicable under this invention.

[0079] Ionizing Agent

[0080] In embodiments of the invention, the ionizing agent is a material when in solution with water, can generate a proton which is then subsequently used to create the cation of the draw solute. In a preferred embodiment of the invention, the ionizing agent is a chemical in the gas phase at standard ambient conditions (25° C, 1 atm) that has a low solubility in pure water, less than 0.1 g/ml, or a Henry's constant of 1 x 104 (Pa/mol-fraction) or greater. More preferably, this material is C02, CS2, COS, N02, or S02, or a mixture of 2 or more of these gases. Most preferably, the ionizing agent is C02. In another embodiment, the ionizing agent is a Bronsted acid. In a preferred embodied, the Bronsted acid is hydrochloric acid, carbonic acid, formic acid, nitric acid, or a combination of two or more of these.

[0081] CO₂ Use and Separation

[0082] In an embodiment of the invention, the SPS FO system described above is modified to introduce CO₂ into the SPS fluid by an exhaust gas stream from a co-located facility. This is demonstrated in Figure 3. The exhaust gas stream should be the resulting stream from combustion, incineration, biological, or other thermo-chemical process that involves generating heat in which CO₂ is a significant component (from 1% to 50%) of the exhaust. The stream preferably is treated prior to the SPS FO to remove acid gas components like H₂S, S0₂, and HC1, such that the exhaust stream is composed primarily of nitrogen, oxygen, carbon dioxide and water vapor. More preferably, the water vapor from the exhaust stream is dried to remove the bulk of the water, leaving only nitrogen, oxygen, and carbon dioxide. [0083] In a separate embodiment, the modified SPS FO system can takes in multiple sources of CO₂ with varying grades of purity. In this embodiment, the CO₂ sources can come from one or more high purity CO₂ sources (greater than 99%) such as compressed or cryogenic storage tanks, CO₂ from co-located facilities that can be further purified in a separation process, or from previously stored CO₂ that has been sequestered. Further, the CO₂ sources can come directly from one or more exhaust streams of a co-located facility post removal of all acid gas components. A combination of these sources of CO₂ can be used in desired ratios to achieve a consistent supply of CO₂ capable of switching the polarity of the SPS draw solvent.

[0084] In this embodiment, the exhaust stream is contacted with the non-polar form of the SPS and water in a gas-liquid contacting vessel, such as a packed or tray column. The ratio of water to SPS is held at a slight excess on a molar ratio, from about 1.05: 1 to 1.1 : 1, to assure complete switching of the SPS to its polar form once CO₂ is introduced. The column is designed to agitate these immiscible liquids to assure good mixing while the exhaust gas is bubbled through. The SPS, water, and CO₂ will react to make the polar form of the SPS. The remaining portion of the exhaust gas - nitrogen, oxygen, and CO₂ that is not absorbed by the SPS - leaves the process and released as emissions.

[0085] In an embodiment of the invention, the amount of CO₂ recycled from the CO₂ degasser to the gasser can be adjusted as to adapt the water purification system to meet the exhaust size of the co-generation plant. For example, the system can operate in full sequestration mode, where none of the degassed CO₂ is recycled; this would require the largest co-generating plant size to supply that much CO_2. If the co-generation plant is smaller, more of the CO₂ can be regenerated through the system to make up for the lower amounts of CO₂ exhaust available. CO₂ exhaust streams from larger plants can always be used, but some portion of the CO₂ will not be caught as sequestered material. This embodiment is illustrated in Figure 3 and demonstrated in Examples 1 and 2.

[0086] The amount of CO₂ in the CO₂-laden streams will determine the size of the water treatment sub-system in combination with the amount of CO₂ that is recycled within the subsystem. These parameters determine how much CO₂ can be present in the draw solution recycle loop, and subsequently set the flow rate for the draw solution loop and how much water can be produced by the sub-system, in proportion with the amount of CO₂. For example, a CO₂-laden stream can provide 100 lb/hr of CO₂ to the switchable FO water treatment sub-system. If the sub-system fully exhausts the CO₂ and recycles none of it, then the draw solution will have 100 lb/hr of CO₂ that is introduced at the regeneration stage and will be present at the membrane. If the sub-system exhausts only 50% of the CO₂ and recycles the rest, then the draw solution will have 200 lb/hr of CO₂ (exhausting 100 lb/hr and making that up from the 100 lb/hr of the CO₂-laden stream), which should be able to produce twice the amount of clean water as the first system with the same draw solution concentration. Larger water treatment systems will require more thermal and electrical power, creating a tradeoff between the recycle ratio and power requirements.

[0087] It is not required to use all of the CO₂ in the CO₂-laden stream for the switchable FO water treatment sub-system; a fraction of the CO₂ can be used along with a smaller water treatment sub-system but this will not allow for full separation or sequestration of the CO₂ from the CO₂-laden stream. It also may not be possible to capture 100% of the CO₂ in the CO₂-laden streams due to kinetic or chemical equilibrium limitations. CO₂ recovery efficiencies in CSS processes range from 70% to 85% for example. In a preferred embodiment of the invention, some or all of the CO₂ in the CO₂-laden streams is captured and used for the switchable FO water treatment sub-system.

[0088] Co-located Facility

[0089] The sources of the CO₂ in this embodiment are CO₂-laden streams from a co- located facility to the overall water treatment system. In a preferred embodiment, at least one CO₂-laden stream is the resulting stream from combustion, incineration, gasification, pyrolysis or other thermo-chemical process that involves generating heat by combining a hydrocarbon fuel and air. The exhaust gas from these processes will have a significant fraction of CO₂, from between 1 to 75 vol%, depending on the type of fuel, oxygen-to-fuel ratio, and other factors. In another embodiment, at least one CO₂-laden stream is an effluent stream from a chemical process with CO₂ content greater than 1%. For example, the cement and pulp and paper industries use readily-available calcium carbonate (limestone) in heated processes to produce CaO for further processing. The heating of CaC0₃ releases CO₂ in the process and contributes significantly to their emissions. In yet another embodiment, at least one CO₂-laden stream is from an existing, natural or man-made CO₂ source such as stored CO₂ in storage vessel, underground formation, or geothermal release, or a CO₂ pipeline, where the CO₂ would be used by the co-located facility as part of its normal operations. For example, enhanced oil recovery (EOR) uses high purity CO₂ to mobilize oil in rock beds to improve oil recovery, while within the food industry, high purity CO₂ is used as an inert atmosphere and as a supercritical inert fluid for extraction and rapid cooling. [0090] Another aspect of the invention is the CO₂ degassing system. As described, this unit is a heated column or vessel to temperatures of no greater than 90° C to switch the polar SPS form back to the non-polar form. CO₂ is released by this process which is normally collected and recycled in the SPS FO process. In this invention, the CO₂ instead is released as an effluent stream; it will be nearly pure CO₂ with trace amounts of water and non-polar SPS that vaporize with the CO₂. Prior to storage or other end use, the water and non-polar SPS vapor components are removed using a chiller or similar system, taking advantage of CO₂ possessing a lower vaporization temperature than either water or the SPS. The final CO₂ effluent stream will possess high purity for storage or other potential sequestration applications.

[0091] In a preferred embodiment of the invention, the CO₂ degassing vessel is heated using waste heat from the co-generation facility. The temperature required to switch the SPS from polar to non-polar is under about 90° C, and preferably in the range of about 40-70° C. These temperatures are well-suited for application of "low quality" waste heat sources from co-located plants operated in co-generation mode. Low quality waste heat sources are typically off-gas streams at temperatures from about 100-300° C that are unsuitable to drive thermal processes, but can be used for energy scavenging such as water heating or as part of an Organic Rankine Cycle (ORC) turbine system. Low quality waste heat is particularly suited for the SPS switching cycle due to the low temperature and energy requirements. This invention can also use "high quality" heat sources from co-located facilities or equipment.

[0092] Through this preferred embodiment, the additional energy required to drive the water purification process will be significantly reduced. In any FO osmosis system, the larger energy driver is the process to separate the drawn water from the draw solvent. The SPS FO system is designed to use low temperature heat and gravity-driven processes to perform this separation, significantly reducing energy requirements over more typical FO systems. However, the largest energy consumer in this process is the heat needed for CO₂ degassing. This energy requirement is removed by using the waste heat from a process operated in co- generation mode. In this manner, the water purification system is primarily driven by waste streams from a co-located process, requiring only nominal utility power loads. This effectively represents a very low-energy water purification process by adding a co-located facility and utilizing its waste heat with CO₂ sequestration.

[0093] In a preferred embodiment of the invention, the recovery process within the switchable FO water treatment sub-system uses waste heat from the co-located facility. As described in an embodiment of the invention, the recovery process in the FO sub-system operates at a temperature no greater than about 90° C, and more preferably no greater than about 60 to 75° C. These temperatures are ideal to take advantage of low-quality waste heat streams possessing a temperature under about 350° C. In most industrial facilities, it is difficult to capture heat from these streams due to the low temperature, and they are generally rejected to the environment, or used as part of combined heat-and-power (CHP) systems for producing hot air and water for building supplies and other proposes. The switchable FO subsystem can use these streams effectively to trigger the dissociation of the CO₂ from the draw solute, and the removal of the draw solute from water, thus enabling the efficient production of clean water without additional energy input. It is also possible to use higher-quality heat streams if these are available.

[0094] A further preferred embodiment of the above process is where both the utility power requirements and the heat requirements of the SPS FO water purification system are provided by the co-located facility as typical co-generation. Balance-of-plant components of the SPS FO system such as pumps and vacuums as previously described in International Patent Application No. PCT/US2015/065322 can be driven from either electrical or mechanical work generated by the co-located facility.

[0095] In a further preferred embodiment, the switchable FO water treatment system is powered through electricity that is generated by the co-located facility. This is well suited when the co-located facility is an electric power plant, or where an auxiliary power plant is used to support the overall co-located facility. The thermal energy supplied by the waste heat streams can drive the recovery process, but additional electrical power will be needed to operate balance-of-plant components such as pumps, compressors, sensors, and the control system. As demonstrated in Example 2 and the other examples, the amount of electrical power needed for the switchable FO water treatment system is estimated to be about a tenth of the thermal energy requirements for the recovery process. It is possible to use thermal energy through devices such as organic Rankine cycle (ORC) engines to produce electricity but this can be very inefficient, with thermal -to-electrical energy conversion of around 10%. The conversion efficiency will also strongly depend on the geography of the site, as ORC become less efficient in warmer climates. It is more desirable to use a co-located electricity source directly if it is available with little additional cost.

[0096] In a preferred embodiment, the co-located facility that provides the CO₂-laden source requires either the purification of the CO₂-laden source before use, or the near- removal of CO₂ from the CO₂-laden source. For example, enhanced oil recovery will recycle CO₂ through the process, and the CO₂ will become mixed with small amounts of natural gas and moisture from the cycle. The removal of these components will improve the efficiency of the CO₂ compression and re-injection process, which can be offered alongside water purification with this switchable FO water treatment sub-system. In the case of landfill gas (LGF), which contains around 50% methane and 50% CO₂, it can be beneficial to purify the methane to make it nearly CO₂-free, creating a high-BTU gas comparable to natural gas which can be inserted into the natural gas pipeline. LGF applications are a good candidate for use with the invention as often there is a need clean the leachate water from the landfill while utilizing the LGF to produce power, heat, CO₂ and some water for a combined benefit. The switchable FO water treatment sub-system can be used to purify the methane while also producing clean water. In another example, CO₂ generated by metal processing facilities like steel mills can be used as a feedstock gas to produce biofuels through a biochemical gas-to- liquid process; the purification of the CO₂ to remove nitrogen and other inert components would improve the performance of the gas-to-liquid process. This invention can be used in conjunction with syngas process that integrate the use of biological agents that convert CO into biofuels. The feed streams containing the CO come from the effluent process from industry and often contain CO₂, methane, H₂, N₂, 0₂, H₂0 and other hydrocarbons. The biofuel process could separate the various components to give a higher yield of pure CO and the H₂ for biofuel product while using the CO₂ for water purification for the process or other uses.

[0097] Membrane

[0098] In embodiments of the invention, the membrane process of the FO water treatment sub-system uses at least one membrane unit that houses a semi-permeable membrane which is designed to allow water to pass through the membrane while restricting the flow of other contaminants in the water, including anions and cations, suspended solids, organic molecules, and biological materials. As previously described, multiple membrane units with their own semi-permeable membrane may be used.

[0099] Typical membranes identified for osmotic processes (both RO and FO) are supported membranes containing one or more thin active layers where the primary reject of water contaminants occurs, and a more porous support layer that provides structural stability against hydrodynamic stresses. Additional active layers can increase salt rejection and reduce reverse salt flux. In a preferred embodiment of the invention, the membrane used in the membrane unit is a single-active layer supported membrane. In another preferred embodiment, the membrane is a double- or triple-active layer supported membrane.

[00100] The orientation of the active layer relative to the draw solution can affect the membrane performance, as this will create internal concentration polarization (ICP) within the membrane itself. In most cases, membranes with active layers used for FO applications are used in "FO mode", with the active layer against the feed solution and the support layer towards the draw solution. In some cases, the membrane may be used in "PRO mode" (Pressure retarded osmosis), with the active layer against the draw solution. FO performance in PRO mode is typically less than that in FO mode as PRO mode will develop large ICP effects that reduce the effective driving force for osmotic draw. In a preferred embodiment of the invention when supported membranes are used, the membrane is oriented in FO mode relative to the feed and draw solutions. In another embodiment, the supported membrane is oriented in PRO mode.

[00101] In another embodiment of the invention, the membrane is a symmetric or asymmetric self-supporting membrane, consisting of one single layer. The mechanical strength of the semi-porous material is sufficient to withstand hydrodynamic stresses. A symmetric self-supporting membrane will have approximately the same porosity, tortuosity, and other structural factors throughout its thickness, so that that the osmotic performance will not be affected by which direction it is placed between the feed and draw solutions. An asymmetric self-supporting membrane will have an engineered variation in the membrane structural factors through its thickness, such as smaller pore openings towards one side of the membrane, and its orientation will affect its performance as in the case of a supported membrane. Single layer membranes can reduce the impact of the ICP on the water flux.

[00102] In yet another embodiment of the invention, the membrane has active layers on both sides of the support layer, also known as double-skin membranes. The addition of the second active layer can reduce the effect of the ICP, and can also eliminate some of the reverse salt flux that can occur in FO membranes. In a preferred embodiment of the invention, the two active layers are composed of different materials. This allows the active layer to be tuned to both the feed solution and the draw solution separately.

[00103] In a preferred embodiment of the invention, the FO membrane is constructed of inorganic materials. Draw solutions using switchable draw solutes will generally be highly caustic, with pH ranging from 7 to 13 and higher. Many organic materials used for membranes can tolerate a pH up to 9 or 10 but not higher. Cellulose triacetate (CTA), a common inexpensive membrane based on naturally-derived cellulosic material, can only sustain a pH range from 4 to 8, and would quickly degrade in most draw solutions using switchable draw solutes. Inorganic membranes will typically have a much wider pH tolerance range, and would not degrade in caustic conditions. Further, the presence of the ICP within the membrane will serve to concentrate the caustic solute within the membrane and will exacerbate degradation of the membrane materials. It is thus necessary to use membrane materials that can withstand the higher localized pH created by the ICP.

[00104] Some examples of preferred membranes that are embodied by the invention include but not limited to the following. Ceramic materials based on alumina, silica, zirconia, and other materials and mixtures thereof. Ceramics are very durable materials. These materials can be prepared through sol-gels to obtain a nano-porous structure to meet water flux and salt rejection requirements. Borosilicate glass membranes, which possess higher structural stability and lower thermal expansion than typical glasses, and can be constructed to provide porosity necessary for water permeability and salt rejection. Zeolite-based membranes typically based on frameworks of alumina and silica but may include other metal- oxide components, as well as zeolites that are loaded and functionalized by metal and metal oxide. The narrow pore structures of some zeolite structures can reject salt while allowing for water flow. Carbon-only based structures such as carbon nanotubes and graphene. These materials are generally stable in a wide range of pH values due to the stability of the carbon- carbon bond structures. These materials also have a natural hydrophobicity that enhances the flow of water through the narrow structures.

[00105] Another embodiment of the invention is the use of mixed-phased inorganic-organic membranes as supported single or double-skin membranes. These materials would have an inorganic layer (such as the materials identified above) atop a water-permeable organic membrane. In the membrane units, the caustic-tolerant inorganic layer would be exposed to the draw solution, while the less-tolerant organic side exposed to the feed solution. The combination of materials would provide good permeability characteristics of organic membranes, and the required durability towards the caustic draw solution from the inorganic material. In this embodiment, the inorganic component of the membrane would be of those classes identified above. The organic substrate of the membrane would be a material known for good water permeability, and can include but is not limited to polymers such as polyamides, polysulfates, Teflon, and cellulose triacetate. [00106] The geometry and form factor of the membrane unit will be a function of the underlying material and design of the membrane modules. In embodiments of the invention, the membrane may be constructed as a tubular membrane, hollow fiber membrane, a flat sheet membrane, spiral wound membrane, or a plate-and-frame membrane.

[00107] Membrane Cascade

[00108] There is presently little data that demonstrates the performance and durability of membranes in use with switchable FO draw solutions. As described above, current RO membranes have drawbacks that impact FO systems, and commercially available RO membranes have compatibility issues with the caustic switchable FO solutions. There are current efforts to engineer better FO membranes but it is unclear what will be the best solution for switchable FO systems at the present time. To address this unknown, an embodiment of the invention features a membrane cascade that is composed of a combination of series or parallel membrane configurations. This cascade can be used to select membranes with various durability and performance and utilize these in the most optimal manner, maximizing water draw and minimizing salt flux and membrane degradation within the switchable FO water treatment sub-system.

[00109] In embodiments of the invention, the membrane process of the FO water treatment sub-system includes at least one membrane unit. A single membrane unit has a maximum effective capacity for water draw resulting from membrane and geometry limitations, so multiple membranes are required to scale the water treatment process to larger volumes.

[00110] In a preferred embodiment of the invention, the membrane process contains two or more membranes units arranged in a series configuration, where the concentrated feed water outlet from one membrane serves as the diluted feed water inlet on a different membrane. Many membranes can be arranged in series on this flow configuration. In one preferred embodiment, the draw solution may also be similarly arranged in flow series, with the diluted draw solution outlet from one membrane serving as the concentrated draw solution for a second membrane, and continuing for all other membranes before returning to the recovery process. In this embodiment, the flow of draw solution may be counter-current or co-current with respect to the feed water flow. In another preferred embodiment, the draw solution may be split individually between each of the modules, passing through some of the membrane units before being returned to the recovery process. In yet another preferred embodiment, the draw solution is split among some of the membranes in series to achieve a combination of the prior two embodiments. For example, if there are four membranes in series, the draw solution may be split to feed the first and third membranes; the diluted draw solution from the first membrane serves the second membrane, and the diluted draw solution from the first membrane serves the fourth membrane. In a preferred embodiment for membranes in series, upstream and downstream valves and plumbing are included to allow feed and draw flow to bypass a given module in the series.

[00111] In another preferred embodiment of the invention, the membrane process contains two or more membranes arranged in a parallel configuration. In a preferred embodiment, the membrane units are of equivalent design and performance specifications. In this configuration, both the feed and draw solutions are equivalently split between each membrane in the parallel configuration. In a preferred embodiment, valves are included in both upstream and downstream paths of the feed and draw solution on each membrane to isolate that membrane from the others in the parallel configuration.

[00112] In yet another preferred embodiment of the invention, the membrane process contains three or more membranes arranged in a combination of the series and parallel configurations described above. For example, the membrane process could consist of 4 parallel banks, each with 2 membrane units in series, for a total of eight membrane units. Many such configurations could exist, and the invention documents only some of these possible configurations.

[00113] In these embodiments where multiple membranes are used in the membrane process, the membranes do not have to be of the same material type, configuration or operating conditions. This enables the use of different membrane materials to optimize the forward osmosis process while recognizing that there may be material incompatibility between the concentrated draw solution and membrane materials. This optimizes the membrane system for maximum water recovery by discretizing the membrane process over multiple membranes, using each membrane type for its best use and within its durability and other performance characteristic levels. For example, in the series configuration, the first membrane that the concentrated draw solution contacts may be of an inorganic material with high durability towards the caustic fluid, but with poor permeability, while subsequent membranes in the series configuration are of high permeability but are only durable with diluted draw solution. The first membrane is thus configured to draw enough water from the feed into the draw to dilute the draw solution, reduce its pH, and making the effluent draw solution compatible with the remaining membranes. This concepts works in conjunction with monitoring the performance across each membrane within the control system of the FO water treatment sub-system, as described below

[00114] The exact configuration and types of membranes would be a function of the draw solution, feed solution, and water quality requirements. The exact configuration would need to be optimized based on membrane performance, capital and operational costs, and other process efficiencies and economics.

[00115] Recovery Process

[00116] Following the membrane, the diluted draw solution must be processed to separate the switchable draw solute and the ionizing agent from the water. In embodiments of the invention, this requires the dissociation of the ionizing agent from the switchable draw solute, leaving the solute in its non-ionic, insoluble form, and either the simultaneous or subsequent removal of the insoluble switchable draw solute from water. This may be performed in a single processing step or over multiple processing steps depending on the nature of the switchable draw solute.

[00117] Complete (100%) removal of the draw solute and ionizing agent from the draw solution within the recovery process possible but generally not practical. The recovery processes are based on phase and chemical equilibrium processes. Complete removal may not be possible due to azeotropes or it may require a great deal of energy and residence time. The more complete of draw solute separation from the water, the easier it is for the FO water treatment subsystem to produce clean water. In a preferred embodiment of the invention, at least 75% of the ionizing agent and draw solute are removed from the processed dilute draw solution in the recovery process. In a more preferred embodiment, at least 95% of the ionizing agent and draw solute are removed from the processed draw solution in the recovery process. In the most preferred embodiment, at least 99% of the ionizing agent and draw solute are removed from the processed draw solution in the recovery process.

[00118] One means of improving the extraction of draw solute and ionizing agent from the diluted draw solution is to operate the recovery process on a portion of draw solution. It is not required to fully separate the draw solute from the water since the regeneration process will ultimately recombine these in the concentrated draw solution. This serves to lower the energy requirements for the recovery process. In a preferred embodiment of the invention, the diluted draw solution is split; some fraction of the diluted draw solution is processed to separate the ionizing agent and the switchable draw solute material, while the remaining draw solution material bypasses the recovery process and goes directly to the regeneration process as a bypass stream. In a more preferred embodiment, this split fraction will be determined based on the design of water draw within the membrane process so that the amount of water in the diluted draw solution to be processed in the removal stage will be within 10% of the amount of water drawn across the membrane. In this situation, the re-addition of the recovered switchable draw solute and ionizing agent to the remaining diluted draw stream will bring the stream back up to the target concentration for the draw solution, eliminating the need for additional water. For example, if the draw solution flowing at 100 gal/hr is designed to draw 50 gal/hr of water across the membrane process to generate 150 gal/hr of diluted draw solution, then only 33% +/- 10% of the diluted draw solution (representing 50 +/- 5 gal/hr) will be split into the recovery process, the remaining solution sent to the regeneration system.

[00119] In embodiments of the invention, the dissociation of the ionizing agent is an endothermic reaction, requiring the input of energy into the process. In embodiments of the patent, the energy comes from a thermal source, which can include but not limited to generated heat from electrical or chemical sources, heat integration with other processes within the forward osmosis sub-system, heat integration with other sub-systems of the water treatment system, heat integration from external sources from the water treatment system such as flue gases from a combustion source, or any combination of two or more of these sources. In this embodiment of the invention, the process unit where heat is used to remove the ionizing agent includes but is not limited to: a closed tank, a mixing tank, a packed column, a tray column, a distillation tower, or two or more of these units used in series or parallel configurations.

[00120] Operating a vacuum can lower the temperature in which the ionizing agent can be easily separated from the water. In a preferred embodiment of the invention, the process to remove the ionizing agent with heat is performed under a vacuum from 0.1 to 1 atm. In the more preferred embodiment, the process is performed under a vacuum from 0.5 to 1 atm. In a preferred embodiment where a vacuum is employed, the vacuum can be generated using a vacuum pump downstream of the recovery unit with respect to the recovered gas stream. In a more preferred embodiment the vacuum is created from a venturi-type pump or an ejector located on the flow of draw solution or water prior to the regeneration system. The Venturi effect on the liquid flow draws the gas phase from the recovery process into the liquid flow where it will be regenerated. [00121] In a further preferred embodiment, when a vacuum is applied to the recovery process for either the liquid phase or polymer solute, a chiller or condenser is incorporated on the vacuum line. This chiller or condenser can capture the water that is inevitably vaporized by the recovery process due to its vapor pressure at elevated temperatures, and travels with the ionizing agent to the regeneration process. The condensed water from this process unit will be of very high quality though of low volume, but represents another effluent from the forward osmosis sub-system.

[00122] Another means to improve the separation of the ionizing agent from the water is by sparging or bubbling an inert gas through the diluted draw solution. The gas can alter the vapor-liquid equilibrium of the separation process, driving more of the ionizing agent out of the diluted draw solution. As this is a mass-transfer limited process, the bubbles should be well-agitated and as small as possible to provide a large amount of interfacial surface area. Gas sparging with microbubbles (<100 um) or nanobubbles (<lum) are known to enhance mass-transfer limited reaction rates in other processes. In another preferred embodiment of the invention, the process to remove the ionizing agent is through the use of gas bubbling with a gas that has less than 1% of the ionizing agent and draw solute. In a more preferred embodiment, this gas is an inert gas which includes but is not limited to nitrogen, oxygen, air, or steam. In a different preferred version, the process to remove the ionizing agent is through the use of gas bubbling with CO₂ or a gas mixture with more than 1% CO₂.

[00123] In a preferred embodiment where gas sparging or bubbling is used in the recovery process, the gas is introduced through a device within the separation unit that produces bubbles within the diluted draw solution, which can include but not limited to frits, screens, semi-permeable membranes, and gas spargers. In a more preferred embodiment, the bubbles generated by this device are less than 100 um in size. In an even more preferred embodiment, the bubbles generated by this device are less than 1 um in size.

[00124] Regeneration System

[00125] The diluted draw solution is regenerated to its concentrated form, following the extraction of produced water in the recovery system. In the invention, the recovered stream(s) containing the switchable draw solute and the ionizing agent are mixed with water to produce the concentrated draw solution stream. In a preferred embodiment where only a portion of the diluted draw stream is processed for switchable draw solute recovery, this regeneration also mixes in the fraction of the diluted draw solution stream that was not processed for switchable draw solute recovery (the bypass stream). [00126] This regeneration process is exothermic. In embodiments of the invention, the heat generated by the exothermic regeneration is recovered to be used elsewhere within other parts of the overall systems, including but not limited to: within the forward osmosis sub-system, other sub-systems of the water treatment system, within other processes outside the water treatment system, or a combination of these locations. In a preferred embodiment of the invention, the heat generated by the draw solution regeneration is utilized within the draw solution recovery process. In an embodiment of the invention, heat is transferred through the use of a heat transfer material (like water or a coolant) from one process to another. In another embodiment of the invention, there is physical integration of the regeneration process and the recovery process for the direct utilization of the regeneration reaction heat.

[00127] In embodiments of the invention, the regeneration process can occur in a process vessel that includes but is not limited to: a closed tank, a mixing tank, a packed column, a tray column, a distillation tower, or a combination of two or more of these units.

[00128] In some embodiments of the invention, the ionizing agent and possibly the switchable draw solute will be reintroduced into the draw solution as a gas. The regeneration process will be limited by mass-transfer between the gas and liquid phases, but can be enhanced by physical mixing and introducing the gas in small bubbles into the regenerated draw solution to increase the surface area for mass transfer. In a preferred embodiment of the invention, the gases are introduced through a device within the separation unit that produces bubbles within the regenerated draw solution, which can include but not limited to frits, screens, semi-permeable membranes, and gas spargers. In a more preferred embodiment, the bubbles generated by this device are less than 100 um in size. In an even more preferred embodiment, the bubbles generated by this device are less than 1 um in size.

[00129] Control System

[00130] In an embodiment of the invention, the forward osmosis water treatment subsystem is monitored through the use of sensors on the feed water, the draw solution loop, and the produced water by a control system which records all collected data. In an embodiment of the invention, the sensed data can include but are not limited to: temperature, pressure, density, flow rate, pH, conductivity, viscosity, chemical/compositional analysis, turbidity, discoloration, total dissolved and suspended solids, and biological and chemical oxygen demand. Several of these types of measurements can be directly related to the quality of the water or draw solution, which will influence the performance of the membrane, the recovery process, and the regeneration processes. In a preferred embodiment of the invention, the forward osmosis water treatment sub-system control system obtains and records sensor data from other locations outside of the forward osmosis sub-system, such as but not limited to: upstream feed water quality, sensors on upstream water treatment sub-systems, ambient temperature and pressure, weather conditions, downstream water quality, the concentration, temperature, and pressure of the CO₂-laden source from the co-located facility, the electrical power available from the co-located facility, and the quality and flow rate of thermal heat from the co-located facility.

[00131] In a preferred embodiment of the invention, the control system on the FO water treatment sub-system is used to automatically manage control hardware within the forward osmosis processes based on the input from the sub-system's sensors and external information, and records all actions taken. In this preferred embodiment, the control system manages a variety of hardware including but not limited to: hydraulic and vacuum pumps, valves, pressure regulators, heaters, chillers, temperature regulators, and to interface and support operator and process safety. In a more preferred embodiment of the invention, the control system is used to adjust the flow rate and concentration of the regenerated draw solution to track against internal changes of the draw solution composition, to changes in the quality of the feed water, or to changes in the rate and composition of the CO₂-laden source. For example, the control system can react to a temporary increase in the concentration of contaminants in the upstream feed water by increasing the concentration of the switchable draw solution. The concentration of the draw solution in this embodiment can be managed through a combination of controllers, including the fraction of diluted draw solution used in the recovery process; the specific method will depend on the internal design of the FO subsystem. In a preferred embodiment, the FO water treatment control system also includes means for manual interaction from human operators, including initiating safety and failsafe processes (HAZOPS).

[00132] In an embodiment of the invention, the control system for the forward osmosis sub-system sends sensor data and control operations to the control system on the overall water treatment system. In a preferred embodiment, the control system on the overall water treatment system also communicates information and control logic to the control system of the forward osmosis sub-system.

[00133] Overall System

[00134] In an embodiment of the invention, the water treatment system includes one or more water treatment sub-systems, with at least one of these sub-systems being a switchable FO sub-system as described above. Other sub-systems that may be present in the water stream system include but are not limited to: additional switchable FO sub-systems; non- switchable FO sub-systems; RO sub-systems; filtration sub-systems (including particulate filtration, microfiltration, ultrafiltration, and nanofiltration); evaporative and distillation subsystems, membrane distillation and hybrid membrane sub-systems; chemical treatment, capture, and destruction sub-systems; ion exchange sub-systems; biological treatment and destruction sub-systems; ultra-violet (UV) treatment sub-systems; advanced oxidation treatment systems; settling tank sub-systems; and anti-scaling sub-systems. The additional switchable FO sub-systems describe here may or may not also use the same or other CO₂- laden streams from the co-located facility as described.

[00135] In an embodiment of the invention, the overall water treatment system includes an automated monitoring and control system, which consists of a plurality of sensors and control units located between and within individual water treatment sub-systems on the system, all in communication with a central processing unit. The control system can also include self- contained control systems that are part of the individual water treatment sub-systems which also communicate with the central processing unit. The sensors will measure and record the quality and state of the water, which include but are not limited to: temperature, pressure, density, flow rate, pH, conductivity, viscosity, chemical/compositional analysis, turbidity, discoloration, total dissolved and suspended solids, and biological and chemical oxygen demand. Additional sensors for detection of external conditions can also be used; these sensors include but are not limited to measuring: ambient temperature and pressure, storage tank levels, the concentration, temperature, and pressure of the CO₂-laden source from the co- located facility, the electrical power available from the co-located facility, and the quality and flow rate of thermal heat from the co-located facility. In a more preferred embodiment, the overall control system monitors for potential security threats to the systems and interfaces to supervisory control and data acquisition (SCADA). In this embodiment, the overall water treatment control system operates and records control unit hardware around the individual sub-systems. Control unit hardware can include, but are not limited to valves, pumps, pressure regulators, electric power generators, heaters, coolers, chillers, and to interface and support operator and process safety. In a preferred embodiment, the control system also includes means for manual interaction from human operators, including initiating safety and failsafe processes (HAZOPS). In a preferred embodiment, the overall control system, including the individual control systems on each sub-system, can be monitored and controlled remotely. In a more preferred embodiment, the overall control system remotely interfaces with sustainable platforms that aggregate data from relevant power grid operational systems, power producing facilities, water utility systems, water treatment facilities, and other power and water sources that support analytic and business intelligence capabilities for emissions (carbon, SO_x, NO_x, and particulate matter, and hydrocarbons) and water trading found Cap and Trade markets. This interfacing is particularly critical when the co-located facility is of a power or water-related system, as to integrate both power and water-grid related data for security and hardening.

[00136] In an embodiment of the invention, the control system incorporates data from several locations relative to the water treatment system, and operates the control units on the system to produce water of required quantity and quality. In this embodiment, locations for sensor data include but are not limited to: upstream feed water quality sensors, intra-process sensors between the sub-systems of the water treatment system, process sensors within each of the water treatment system's sub-systems in the water treatment system, and downstream water quality sensors. In a more preferred embodiment, the data may come from sources external to the water treatment system, including but not limited to: upstream water treatment plant data, produced water quality, ambient temperature and pressure, current weather conditions, time of day, current and projected produced water use, temperature, pressure, flow rate, and composition of the CO₂-laden streams and waste heat streams from the co- located facility, electrical power availability from the co-located facility, and peak utility hours for power, water and emissions.

[00137] Water Purity

[00138] In embodiments of the invention, the source water to be treated is a contaminated water stream that may include but is not limited to: grey water, brackish water, seawater, surface and groundwater including impaired and polluted sources, brine, high-salinity bodies of water, secondary and tertiary treated wastewater (also commonly referred to as recycled water, reclaimed water or "purple pipe" water), biomass, municipal solid waste and associated leachate, pharmaceutical, food/beverage, and industrial process streams (for the processing and removal of water), industrial and commercial wastewater, agriculture, and produced water from oil and gas (hydro-fracturing), geothermal, and from mining operations. In an embodiment, two or more sources of water are processed by the water treatment system. In an embodiment, these sources include, at minimum, industrial and commercial wastewater and secondary and tertiary treated wastewater. [00139] The method of the invention will produce clean water to the purity requirements of the application. In an embodiment of the invention, the method will produce water that meets or exceeds the quality requirements for tertiary treated wastewater for the local area (approximately no greater than 1000 ppm TDS). In another embodiment, the method will produce water that meets or exceeds quality requirements for potable/tap water for the local area. The requirements of potable water vary by nation and state. The U.S. Environmental Protection Agency (EPA) has set a secondary standard for potable water as having less than 500 ppm TDS along with additional requirements on specific biological, organic, and inorganic content. In a preferred embodiment, the water treatment system can produce two or more clean water streams of differing standards, such as potable and terti ary -treated streams.

[00140] In embodiments of the invention, one of the sub-systems in the water treatment system is a switchable FO sub-system. The switchable FO sub-system contains, at minimum, the following major unit operations: a) draw solution that uses a switchable material as its draw solute in aqueous solution, along with an ionizing agent that is used to enable the switching of the draw solute (this is also considered as a "switchable polar solvent"); b) a semi-permeable membrane or plurality of membranes that allow water to pass through but restrict passage of other chemical species, including ions, dissolved and suspended solids, and biological materials (feed water, from which clean water will be produced from, contacts one side of the membrane(s) as the feed solution, while the draw solution contacts the opposite side of the membrane; c) a recovery process to dissociate the ionizing agent from the switchable draw solute, returning it to its non-ionic form, and to subsequently remove both from the water as to produce a clean water effluent stream; d) a regeneration process to contact the non-ionized switchable draw solute in solution with an ionizing agent to create a highly ionic draw solution; and e) a control system that monitors and controls the switchable FO sub-system.

[00141] Figure 1 shows a general amine-based scrubber system used for CCS. An aqueous amine solution 2 is put into contact with a CO₂-laden exhaust stream 4 in a gas contacting column 6, such as a packed bed. CO₂ will be absorbed into the amine solution, while the remaining species such as nitrogen or oxygen, are not absorbed and are released as CO₂-lean exhaust 10. The amine solution carrying the CO₂ 8 enters the desorption column 12, where heat or other energy sources are used to extract the CO₂ from solution. The removed CO₂ is sent out as effluent 16 for sequestration or other uses, while the amine solution 14 is pumped back through the system through a circulation pump 18. [00142] Figure 2 shows a representative forward osmosis water treatment sub-subsystem 100 that uses a switchable draw solution, representative of one that may be used in an embodiment of the invention. Feed water 102 is introduced to one side of a semi-permeable membrane within the membrane process 108. The concentrated switchable draw solution 106 is in contact with the other side of the membrane. The osmotic pressure differential between the draw solution and feed solution draws water across the membrane into the draw solution. The remaining feed water effluent 104 is more concentrated on leaving the system. The diluted draw solution 110 is then sent to the recovery process 112.

[00143] Within the recovery process 112, there are two main processing steps. The first process 114 is the dissociation of CO₂ from the draw solution and its subsequent removal as a gas 116. This is done at temperatures less than 90° C to avoid vaporization of the water or the draw solute. The second process 118 uses other means to separate the draw solute 120 from the water 118. This should be a low-energy process such as decanting for liquid-based solutes, or filtering for polymer-based solutes. The water effluent 118 from this process may still have trace amounts of CO₂ and solute, so additional polishing stages are used to improve the purity of the clean water and recover more CO₂ and solute 122. The effluent from polishing is the produced clean water from water treatment 124. Optionally, some of the diluted draw solution may bypass the recovery process through a flow splitter 132, with the bypass stream 134 sent directly to the regeneration process 128.

[00144] Within the regeneration process 128, CO₂ 116, draw solute 120, effluent from the polishing stages 126, and the bypass stream 134 are mixed to reform the concentrated draw solution. A pump 130 then sends draw solution towards the membrane, completing the recycle loop. The overall sub-system includes a control system 140 to monitor and control the various processes based on sensors internal and external to the sub-system.

[00145] The FO sub-system 100 is a component of the overall water treatment system 150, which can consist of a number of upstream and downstream water treatment sub-systems (154 and 156, respectively). This may also include parallel subsystems to the FO water treatment sub-system 100. These additional components may be used to pre-treat the feed water directly from its source 152, or to perform post-cleanup on the produced water 158 before delivered to its point-of-use. An overall control system 160 is in communication with the individual sub-systems, including the control system of the FO sub-system 140, and to sensors both internal to the overall water treatment system and external data sources. [00146] Figure 3 shows the modification of Figure 2 in an embodiment of the invention. The removed CO₂ 116 is split into two streams 162, some leaving the system as high purity CO₂ 164, while the remaining fraction 166 returns to the regeneration process 128. Some or all of the removed CO₂ can be split as high-purity product. A CO₂-laden source 170 from a co-located facility 172, such as the flue gas from a combustion source, is used make up the CO₂ requirements for the FO sub-system within the regeneration process 128. The draw solution will selectively absorb CO₂ without any of the inerts or non-reactive species within the source stream. The unabsorbed components will exit the process as exhaust 174.

[00147] Two additional unit operations may be necessary to include within this process, as depicted in Figure 3. If the CO₂-laden source contains materials that are negatively reactive with the draw solution, a pre-treatment step 180 may be necessary to remove these materials. For example, if the CO₂ source is from the combustion of fossil fuels, it is expected that the exhaust will contain quantities of SO_x or H₂S, which may negatively react the solution. This pre-treatment process would use unit operations like adsorption beds or columns to strip out these components while leaving most of the CO₂ in the stream. The second unit operation that may be needed is a stage to remove condensable materials (particularly water) and other post- treatment operations 182, particularly if the CO₂ will be compressed in subsequent processes as for sequestration. Heat is required to dissociate the CO₂ from the draw solute, and this will likely cause some water to evaporate and leave with the CO₂. Condensable water reduces the effectiveness of pressurizing the CO₂ for sequestration or storage. Their removal prior to compression makes compression more efficient. There may also be components of the draw solution (including the draw solute) and contaminants that have gotten into the draw solution from the feed water after crossing through the membrane. These post-treatment operations can either recover these contaminants to be used for regeneration 184 or destroy them to keep the CO₂ of high-purity.

[00148] In addition to the reuse of CO₂, three additional points of integration are described as represented in Figure 3. Heat generated by the co-located facility 190 may be used within the FO sub-system 100, specifically within the recovery process 112, to drive the dissociation of CO₂ and removal of draw solute. Electricity that may be generated by the co-located facility 192 can be used to power the overall water treatment system 150. Further, data that is generated by the co-located facility relating to the quantity and quality of the CO₂-laden stream, heat availability, electrical availability, and other factors 194 is communicated to the control system 160 for the overall water treatment system to use as part of its control scheme. [00149] Figure 4 demonstrates a modification of the embodiment of Figure 3 where there are multiple potential sources for CO₂. In addition to direct use of a CO₂-laden source 170 without any additional treatment, one can also use a CO₂-laden source 200 that may require additional pretreatment 202, such as the removal of combustible gases like methane, particulates or siloxanes. Further, pure CO₂ or a CO₂-laden source may be stored on site 204 through compressed or cryogenic sources to supplement CO₂ for the CO process. A control system may be used to manage the consistency of the CO₂ flow from these multiple sources for the FO process.

[00150] Figure 5 demonstrates the use of a preferred embodiment of the invention with enhanced oil recovery (EOR), enhanced gas recovery (EGR), or enhanced coalbed methane recovery (ECMR), described in more detail in Example 4.

[00151] Figure 5a shows the current approach of EOR using CO₂ flooding. An oil field 500 which has been exhausted of oil drilled by conventional means is flooded with compressed CO₂ 506. An external source of CO₂ 502 is initially required, and either may be from natural CO₂ formations, or from anthropogenic, man-made sources transferred to the oilfield via pipeline. The external source is used to make up for any deficiencies lost during the recycling of CO₂ from production well collection. The CO₂ is compressed to pressures in excess of 1200 psi by a compressor 504 and then injected into the oil well. The injections are generally alternated with water 510 as to spread the CO₂ throughout the well and prevent rapid CO₂ breakthrough. The compressed CO₂ is miscible with oil and helps to push it out of the well to the production well 508. The mixture of oil, water, and gases (CO₂ and natural gas) are separated 510. The oil is sent as crude for refining 512. The recovered water 514, having gained salts, minerals, and organic components from its passage through the ground, is treated 516 before re-injecting it into the well 510. The gas mixture 518 is separated 520 to recover high purity CO₂ 522 and natural gas 524. The natural gas may be sent for further refining, but can be used to produce power for the site via a power plant 526.

[00152] Figure 5b demonstrates the inclusion of the switchable FO water treatment system within the EOR process. The switchable FO system 550 replaces the water treatment system 516 and the gas separator 520 from Figure 5a. The recovered gas stream is used to provide CO₂ to the switchable FO process, with the natural gas components rejected by the draw solute and thus easily separated from the CO₂. Following the membrane process, the CO₂ is then dissociated from the draw solute, and can be recovered at high purity (> 90%) required for good compression. Power and heat 552 from the power plant can be used to drive the water treatment process.

[00153] Figure 6 demonstrates two methods described by this invention of integrating the switchable FO water purification process with landfill gas (LFG), commonly a 50-50 mix by volume of methane and CO₂. As methane has a 25-times greater influence on global warming, it is desirable to eliminate the methane emissions in any possible form, even if this produces CO₂.

[00154] Figure 6a, LFG 600 is treated to remove trace amounts condensation, particulates, siloxanes, and sulfur compounds 602. The cleaned LFG is then used as fuel for a power plant 604 to produce power. The exhaust from this plant 606 will have more than 50% CO₂ which is used to drive the switchable FO water treatment system 608 to produce clean water 612 from a dirty source 610. The switchable FO water treatment system will separate the non- CO₂ components of the exhaust (primarily nitrogen) 616 from the CO₂ 614, which could be sequestered if necessary. The power plant 602 produces electricity 618 and thermal energy 622. A portion of the electricity 618 can be used to drive the electrical requirements for the switchable FO water treatment system 608 alongside the thermal energy.

[00155] Figure 6b shows an alternate approach where the goal is to upgrade the medium BTU LGF into high BTU methane for use with natural gas. In this configuration, a fraction of the treated LFG 650 is used as fuel in a smaller power plant 652 that is sized to support the electrical and thermal needs of the switchable FO water treatment system 608. This plant produces some exhaust 654. The remaining LFG is used within the switchable FO water treatment system 608 to drive the production of clean watch, and will further produce a high purity CH₄ stream 656 mostly free of CO₂, and a CO₂ rich stream 658. The high-purity CH₄ stream can be of appropriate quality to be injected into a natural gas pipeline.

[00156] The following examples are provided to further illustrate the advantages and features of the present invention, but are not intended to limit the scope of the invention. While they are typical of those that might be used, other procedures, methodologies, or techniques known to those skilled in the art may alternatively be used. EXAMPLE I

CO₂ FOR WATER TREATMENT USING SWITCHABLE FORWARD OSMOSIS

[00157] Computer-aided modeling was used to estimate the CO₂ requirements to drive the SPS forward osmosis water generation process. The source of CO₂ was assumed to be the exhaust product of a natural gas co-located combustion plant operating in a co-generation mode that is running at 10% excess oxygen. Water in the exhaust gas was removed prior to introduction into the SPS gassing system. The power generated by this natural gas plant was assumed to on a 34% thermal efficiency, a nominal value for gas turbines.

[00158] The water purification system was designed to provide 100 gallons per minute of clean water from a salt water source as a base case. The SPS used for this scenario was N,N- dimethylcyclohexylamine.

[00159] Several scenarios were evaluated based on the ratio of fresh CO₂ provided from the natural gas co-located plant relative to the amount of total CO₂ needed to switch the draw solvent including the excess. The rest of the CO₂ required is generated from the degassing of the draw solvent as part of the regeneration process. Because some fraction of CO₂ is provided from the co-located plant, not all the CO₂ recovered from the regeneration process is needed, and the excess CO₂ from this process becomes pure CO₂ product gas to be sequestered.

[00160] Table 1 summarizes the results of this analysis based on generating 100 gallons per minute of clean water from a salt water source through SPS FO. Each column represents one of the cases described above, based on the amount of CO₂ required for gassing the draw solvent provided by the co-located plant exhaust, ranging from 5% to 99%. The second row represents the smallest size of a co-located plant that would provide the necessary CO₂. The third row lists the maximum amount of CO₂ that would be separated and available for sequestration through this process. [00161] Table 1: Estimates of CO₂ Sequestration Capacity and Co-Located Support for a 100 gallon-per-minute SPS-based FO water purification plant coupled with a Co- Located Unit.

[00162] Table 1 shows that an appreciable water purification system capable of providing 100 gallons per minute can be integrated with a co-generation plant of reasonable sizes (from around 1 to 10 MW). Larger water production systems can be driven from the CO₂ generated by larger power plants, following linear trends of this data. For example, a 1000 gallon per minute water purification plant can be driven with CO₂ exhaust from co-located plants ranging from 10 to 100 MW.

[00163] The co-located plant size represents a minimum value for each case. A larger co- located plant would be able to provide more exhaust and CO₂, exceeding the requirements for the water purification system. However, additional CO₂ introduced this way will not be taken up by the SPS fluid; only the amount of CO₂ listed in the third row will be separated and ready to be sequestered. The excess CO₂ in the co-generation plant exhaust will be left as emissions from this process if no additional sequestration is used. In this situation, the water purification plant would be sized appropriate for the co-located plant as to separate as much of the CO₂ from the co-located plant as possible.

[00164] Alternatively, if CO₂ sequestration is already a function of the plant, so that pure CO₂ can be provided to the water purification system, then the water purification system can undersized related to the power plant size. For example, the 100 gallon-per-day water purification system can be driven easily with the CO₂ that has already been separated from the exhaust of a power plant larger than 10 MW; the excess CO₂ during gassing will still remain pure and can be sequestered easily. EXAMPLE 2

CO₂ AND ENERGY REQUIREMENTS FOR WATER TREATMENT USING

SWITCHABLE FORWARD OSMOSIS

[00165] In an embodiment of the invention, a modified switchable FO water treatment system is used to capture CO₂ from an external process stream as part of the process for regenerating the switchable FO draw solution. Normally, the CO₂ will already be present in the FO system and will be recycled through the process, with some makeup provided to account for losses in the produced water, leaks to the environment, or side reactions within the draw solution. The invention described considers that not all of this CO₂ needs to be recycled if makeup CO₂ is available from a process stream.

[00166] This example demonstrates an estimate of the potential range of CO₂ that can be provided from an external source that can drive the switchable FO process. The exact range will be a function of the draw solute selection, the concentration of the draw solute, and other design factors within the FO water treatment system. Some analysis in this example is based on prior art to analyze the energy and cost requirements for an FO system for treating seawater.

[00167] In this example, it is assumed that the draw solute is N,N-dimethylcyclohexyl amine (DMCHA). The concentrated form of the draw solution is taken as 77 wt% of DMCHA and CO₂ at a 1 : 1 molar ratio, following from the noted example. There would be 1.65 lb CO₂ for every gallon of concentrated draw solution. It is estimated using ASPEN calculations, that the osmotic pressure of the ionic draw solution is around 500 atm.

[00168] A design target of 100 gal/hr of produced water is taken as the calculation basis. Further, it is taken that the draw solution should be diluted by half from the water that permeates across the membrane which then is subsequently removed as produced water. The concentration of the diluted draw solution is thus 38.5 wt% of DMCHA and CO₂. This would require 100 gal/hr of water to be drawn across the membrane to achieve this dilution. The osmotic pressure of this dilute solution remains greater than 200 atm, making it a suitable draw solution for high salinity feed streams.

[00169] Turning to the amount of CO₂ required for the process, there is net flow of 165 lb/hr of CO₂ within the draw solvent loop from the above basis. The maximum CO₂ requirement would thus be 1.65 lb CO₂ for every gallon of produced water. While there is a total flow of 165 lb/hr of CO₂ within the draw solution recycle loop, it is not required to make up this much CO₂ on every pass. First, as described previously, some of the diluted draw solution can bypass the recovery process, so the CO₂ in this bypass will remain in the solution. Second, as embodied in this invention, some of the CO₂ removed in the recovery process can be recycled to the regeneration process. This recycle ratio is a design feature that allows the FO water treatment to be scaled to match the CO₂ output flow rate of the co- located process.

[00170] For this example, it is assumed that 50% of the diluted draw solution bypasses the recovery process, leaving 100 gal/hr of 38.5 wt% DMCHA-CO₂ solution. There is 82.5 lb/hr CO₂ that can be removed from the remaining solution, which equates to the maximum of CO₂ required from the co-location exhaust stream to make-up for this removal. If all of this CO₂ was simply exhausted out after removal (0% CO₂ recycle or 100% CO₂ exhaust), one would need to make up 0.825 lb CO₂ for every gallon of water produced. The makeup amount can be lessened by reducing the percentage that is exhausted, increasing the amount of CO₂ recycle. With only 5% of the CO₂ exhausted, 95% of the CO₂ is recycled, and the CO₂ makeup requirement is reduced to 0.0413 lb per gallon of produced water.

[00171] There is a tradeoff between the size of the water treatment system as determined by how much CO₂ is recycled or exhausted and energy consumption that will be evaluated in the following examples. For all of the following examples, it is assumed the water treatment system is operating on a feed water stream with a salinity near that of seawater (3.5 wt%). An energy evaluation of the DMCHA FO process for seawater treatment has been performed in the previously described prior art. In this analysis, the thermal energy required to drive the recovery process is between 23.0 and 33.0 kW_t-hr/m³ (0.0871 - 0.125 kW_t-hr/gal). The electrical requirements are between 1.8 and 2.6 kW_e-hr/m³ (0.00681 - 0.00984 kW_e-hr/gal). There are means of using additional electrical energy to supply some of the thermal energy, but this will be less efficient than using thermal energy directly. The examples described below are based on using these estimates of thermal and electrical energy for the switchable FO water treatment system. Both electrical and thermal energy requirements will change with the concentration of the feed water, with more energy being required to produce water from higher salinity feed streams.

EXAMPLE 3

SWITCHABLE FO WATER TREATMENT USING POWER PLANT EXHAUST

[00172] Power plants are a major source of CO₂; as of 2013, 37% of the CO₂ emitted in the United States comes from power plants for electrical energy production. Power plants also produce a great deal of waste heat in the inefficiencies in converting thermal energy into electrical. The wasted thermal heat is generally released to the environment, though more recent efforts are made to utilize the waste heat in co-generation or combined heat-and-power (CHP) add-ons to use the thermal energy, including those from low-quality heat sources, to heat water and air for heating and cooling, or to use systems like organic Rankine cycles to capture the heat into electricity. A preferred embodiment of the invention is to use both the CO₂ and waste heat to drive the switchable FO process to also provide water treatment.

[00173] Representative numbers for coal and natural gas-based power plants (including combined-cycle plants) are shown in Table 2. Electrical efficiency is based on how much electricity is generated based on the total heat energy is available in the fuel source (using higher heating values). Values for coal and for natural gas, with and without the use of a combined cycle process, are shown. The CO₂ emissions from coal plants will be based on the type of coal; for all further examples here, an assumed average of 2.12 lb/kW_e-hr is used.

[00174] Table 2: Average Emissions and Electrical Efficiency for Power Plants

[00175] This example demonstrates a preferred embodiment of the invention of using the exhaust CO₂ and waste thermal heat from a power plant to drive the switchable FO process. The example considers the addition of a switchable FO water treatment system on the back- end of an existing plant size to estimate the treatment capacity for the system.

[00176] The design basis in this case is a power plant (coal, natural gas, and natural gas with combined cycle) that generates a net electrical output of 40 MW_e. The total thermal power available and CO₂ produced, based on the average heat duty for these plants and a 50% heat recovery assumption, are given in the table below:

00177 Table 3: Estimated Thermal Out ut and CO₂ Production for Power Plants

[00178] This example assumes the addition of a switchable FO water treatment system that can operate on water of similar salinity as seawater (approximately 3.5 wt% TDS), as described in Example 1. The maximum switchable FO water treatment systems that can be added onto the backend of the power plant is estimated by assuming that all of the CO₂ available from the plant is used as makeup, and on the percentage of CO₂ that is recycled within the draw solvent recycle loop, with the assumption that 50% of the dilute draw solution bypasses the recovery process. Tables 3-6 list the estimated maximum water treatment system sizes for the three types of power plants, based on the percent of CO₂ that recycles within the draw solution loop. Electrical and thermal energy requirements are given as a range based on the energy estimates shown in Example 2.

[00179] Table 4: Estimation of Maximum Switchable FO Water Treatment Unit based on a Coal Power Plant

[00180] Table 5: Estimation of Maximum Switchable FO Water Treatment Unit based on a Natural Gas Power Plant

[00182] From these tables, it can be seen that water treatment systems of about 1-2 million gallons per day can be supported from the waste CO₂ and heat from 40 MW_e power plants, when none of the CO₂ removed in the recovery process is recycled back into the regeneration process within the FO sub-system (that is, 100% exhaust). A small fraction of the electricity generated by the plant (1 to 2.5%) is needed for auxiliary power for the water treatment system. At this scale, this will also produce a nearly pure CO₂ stream that can be sequestered. Smaller water treatment systems can be used (for example, 0.5 million gallons of produced water per day) that will have lower electrical and thermal requirements, but a smaller water treatment system will also not utilize or separate all of the CO₂ exhaust from the power plant output, leaving some CO₂ within the other exhaust gases. It is ideal to match the water treatment system to the capabilities of the power plant as to achieve the best-use case.

[00183] When some CO₂ is kept in the recycle loop (recycle ratio > 0% or exhaust ratio < 100%)), the power plant' s CO₂ makes up the remainder and larger water treatments can be used. Larger water treatment systems will require more energy, and potentially outsize what the power plant can provide. As seen on the above tables, the CO₂ and electrical needs for the larger water treatment system can be met, but there will not be enough thermal energy to support a water treatment system of that size for any of the three plant types. For all three power plant types, this is generally at the point where the water treatment system recycles more than 75% of the CO₂ (exhausting out less than 25%), or a water treatment system producing more than 9 million gal/day of clean water. It may be possible to use additional electrical energy to provide the required thermal energy through electrical heating, but this will reduce the overall effectiveness of energy generated by the power plant.

[00184] To provide a reference for scale, the outputs from the power plant and water treatment system can be compared on a per capita basis. In the United States, the average consumption of power per capita for residential users in 2013 was 66.9 MMBTU/yr, or 2.238 kW, and the average consumption of water per capita for residential users in 2010 was 88 gal/day. From the above numbers, a 40 MW_e electrical power plant can service approximately 178,000 people, and can also support a water treatment system with 100% CO₂ exhaust that can support between 11,400 and 28,000 people. While this is not a perfect match in terms of population served, the ability to supply sufficient water to 6% to 16% of the power plant's customers without any additional thermal or electrical energy costs can help offset water shortages in some areas.

[00185] Another metric to consider is the energy requirements for the CO₂ separation from the exhaust gas. An amine scrubber system using 30 wt% monoethanolamine (MEA) as part of a CO₂ sequestration system for a coal -based power plant will use about 27% of the plant's gross power output to separate the CO₂ and compress it; of this energy, 34% is used towards compression. An example 500 MW coal plant will generate 2.58 million metric tons of CO₂ per year, and will require a total of 136 MW of energy for CO₂ separation and sequestration, with 89.8 MW specifically for the separation process (no compression). This equates to a net 0.139 kW-hr/lb CO₂ energy requirement for CO₂ separation alone. For the switchable FO water treatment system, the combined electrical and thermal energy requirements using the high-end estimates are 9.96 MW for 84,800 lb/yr of CO₂ generation, or 0.1 17 kW-hr/lb. This figure is very comparable to the amine scrubber systems, which is expected since the same effective chemical processes involving the association and dissociation of amine and CO₂ occur. The estimate presented for the water treatment system, while using conservative assumptions for energy use, may not account for additional processes needed to either pre- treat the power plant's exhaust stream before the switchable FO water treatment system, such as fixed adsorption beds to strip acid gas components, or to post-treat the CO₂ to improve its compressibility, such as the removal of water and other condensable fluids. In either case, it is not expected that these processes will require the same magnitude of energy, particularly thermal energy, to operate. The net energy requirements for the switchable FO water treatment are expected to remain comparable to the requirements for amine scrubbing. The ability to add water recovery to this CO₂ scrubbing process can be seen as a benefit that adds no significant additional energy costs to established processes.

EXAMPLE 4

SWITCHABLE FO WATER TREATMENT CO-LOCATED WITH ENHANCED OIL

RECOVERY

[00186] Enhanced oil recovery (EOR) is a technique used to obtain more oil from existing wells once primary and secondary recovery methods have been exhausted; similar concepts are used for enhanced gas recovery (EGR) and enhanced coalbed methane recovery (ECMR). Within EOR, a fluid is used to push oil out of the existing cracks and fractures in the rock bed which are otherwise immobile in the normal drilling process. The desired working fluid is compressed CO₂ for several benefits. When compressed to high pressures greater than 1200 psi, CO₂ becomes miscible with oil. The mixture is less viscous that oil itself, and helps to mobilize the remaining oil for collection. EOR differs from hydraulic fracking as the process is not intended to break apart rock beds but instead to get into the existing cracks and fractures as to extract the traces of oil that remain.

[00187] One preferred method of EOR is CO₂ flooding. In CO₂ flooding as illustrated in Figure 5a, compressed CO₂ is added to an injection well, and the product crude oil is collected from a production well. Plugs of other working fluid, most commonly water, are alternated with CO₂ during the process. The water plug helps to prevent CO₂ from breaking through from the injection well to production well, bypassing the oil, and helps to spread the CO₂ across the entire oil bed to maximize the oil recovery process.

[00188] The production well will collect oil, CO₂, water (now containing salts and other substances from its passage in the rock bed), and light gases such as natural gas. The oil, water, and gases are separated. The oil is sent off as crude for refining. The water is treated and re-used for injection. The CO₂ and natural gas are further separated, with the purified CO₂ reused for the EOR process, while natural gas may either be sent for refining or used as fuel for on-site power systems. This power may include electricity generation to drive CO₂ compression, or the generation of heat that is used to elevate the temperature of the oil to further improve its mobility. EOR has the added benefit that as the well runs dry of oil, its volume has been displaced by CO₂, providing an effective means of sequestration of CO₂.

[00189] The switchable FO water treatment system co-located with EOR has many advantages for this system as it replaces both the water treatment system and the gas separator, as shown in Figure 5b. First, it can provide a source of high purity CO₂ (greater than 90%) from either an outside source, or by separating the CO₂ from the natural gas from the production well. High purity CO₂ is desired to reduce efficiency loses in compressing the CO₂ prior to injection. Second, it can help treat the water that is collected by the production well. The water will gain salt and mineral content in its passage through the bed, and organic content from the separation process, and prior to re-injection, will need to be treated again. This can be a function served by the FO water treatment system.

[00190] The required amount of CO₂ for EOR between new CO₂ purchases and recycle will vary based on the field. A representative case for current EOR uses 17.4 millions of standard cubic feet (MMscf) of CO₂ per barrel of oil recovered, with a daily production from one field being about 611,000 barrels per day. This is equivalent to 2.0 lb CO₂ per barrel of oil recovered with a use of 1.22 million lb CO₂/day or 50,920 lb CO₂/hr. Water use for CO₂ flooding also varies based on the field and mobility requirements, with the ratio of water to CO₂ ranging between 0.5 and 5 on a volume basis. Assuming a nominal water-to- compressed CO₂ volume ratio of 1.4, then about 0.28 gal of water is needed for every pound of CO₂ used in EOR. EOR on this example oil field would need approximately 341,600 gal/day or 14,200 gal/hr of water.

[00191] As described in Example 2, a switchable FO water treatment system with 50% bypass and without any CO₂ recycle (exhausting all remaining CO₂) would be need a CO₂ makeup of 0.825 lb for every gallon of produced water from the FO system. With the FO system used in EOR to perform full separation/purification of the EOR CO₂ recycle at 1.22 million lb/day, the FO system could produce up to 1.01 million gallons of water per day (42,080 gal/hr), nearly three times the required 341,600 gallons/day (14,200 gal/hr). Thus, within an EOR plant, the switchable FO water treatment system would be able to treat both the water extracted from the process and additional local source water to product high purity water needed for injection and water that can be used for other local needs, such as residential, commercial, industrial, or irrigation.

[00192] The power requirements for EOR will vary by field, technology type, and other factors but is dominated by the power needed for compression of CO₂ for injection. It is estimated that 120 kW_e-hr are needed per metric ton of CO₂ to be compressed, or 0.536 kW_e- hr/lb CO₂. The above site would need a power plant able to produce 654,000 kW_e-hr/day for this requirement, equivalent to a 27.3 MW_e plant. If this is a natural gas power plant, either using the natural gas recovered from the EOR process or pipelined onto the site, then similar estimates of power and available waste heat can be made as outlined in Example 3. The 27.3 MW_e natural gas plant, without combined cycle, would produce 27.7 MW_t waste heat that can be captured for use in the switchable FO water treatment system.

[00193] As described in Example 2, a 1.01 million gallon/day switchable FO water treatment system would need between 87,970 and 126,250 kW_t-hr/day (3.6 to 5.3 MW_t) of thermal energy and between 6,880 and 9,940 kW_e-hr/day (0.29 to 0.40 MW_e). Both of these energy requirements are readily within the capacity of this plant. Thus, the additional of the switchable FO water treatment system to both purify CO₂ for recycle and to treat the plant's water can run of the existing exhaust or waste streams from the combined plant with a minimal amount of additional electricity required. This makes the switchable FO technology well suited for use within EOR systems.

EXAMPLE 5

SWITCHABLE FO WATER TREATMENT WITH LANDFILL GAS

[00194] Landfill gas (LFG) is the product of the decomposition of organic and biological wastes over time once these wastes are deposited in landfills. Initially these gases will be from aerobic decomposition, primarily nitrogen and oxygen. As the decomposition becomes more anaerobic over time, LFG will have a composition around 45-60% methane, 40-60% CO₂, and trace levels of nitrogen. Waste will produce LFG at a consistent rate over 20 to 30 years or more once anaerobic decomposition begins, so the production will accumulate in landfills over time. It is estimated that a landfill with accumulated waste of about 10 million metric tons (representative of a landfill servicing an urban population center) will produce 850,000 MMBTU/yr of LFG.

[00195] Methane is considered a potent greenhouse gas, and can impact global warming 25 times more than CO₂. This has led to the collection and use of LFG for beneficial manners. Most commonly, it can be burnt and converted into energy, either used to provide electricity to the grid, or to drive turbines and boilers for electricity and heat or steam generation. LFG is a medium BTU gas with a higher heating value around 500 BTU/scf, compared to natural gas which is a high BTU gas and a higher heating value of 1,020 BTU/scf. This leads to lower efficiency engines, as measured by the heat rate, the amount of energy that must be generated in an engine to produce 1 kWh of electricity. The heat rate for LFG-fired engines is approximately 1 1,700 BTU/kWh, while for natural gas engines (without combined cycle), the heat rate is 10,354 BTU/kWh. This equates to an approximate 29.1% electrical efficiency. Combustion of LFG containing 50% CH₄ will produce about 2.88 lb CO₂/kW-hr, a combination from the CO₂ already in the LFG and CO₂ generated by combustion. Though burning LFG will release additional CO₂ to the environment, the conversion of LFG to power is considered to reduce greenhouse gas emissions since this is transforming the undesirable release of methane to the atmosphere to a less environmentally benign form. LFG will need to be treated to remove some contaminants prior to its use as a fuel source to maintain energy conversion efficiency and avoid emissions of harmful pollutants; these trace contaminants include condensation, particulates, siloxanes, and sulfur compounds.

[00196] Using the 10 million ton landfill example above, 850,000 MMscf/yr of LFG at 50% CH₄ content will be able to run an 8.3 MW_e power plant. The amount of thermal output that can be captured, following the assumptions from Example 3, would be 10.0 MW_t. This plant would produce a combined total of 23,900 lb/hr of CO₂ (accounting for CO₂ already in the LFG and the CO₂ generated by combustion).

[00197] Following the approach in Example 3 and as illustrated in Figure 6a, the switchable FO water treatment system would be able to produce 29,000 gal/hr (695,000 gal/day) of water using the 23,900 lb/hr of CO₂ produced from LFG combustion. This size system would require electrical power between 0.20 and 0.28 MW_e, and thermal energy between 2.6 and 3.6 MW_t, both values well within the potential electrical (8.3 MW_e) and thermal (10.0 MW_t) output of the power plant. As with Example 4 for EOR, the use of the switchable FO water treatment system is well suited to fit within the LFG frame work.

EXAMPLE 6

UPGRADING OF MEDIUM BTU LANDFILL GAS TO HIGH BTU METHANE WITH SWITCHABLE FO WATER PURIFICATION

[00198] A second means of using LFG is to prepare the gas for injection into the natural gas pipeline. This step requires the removal of CO₂ to leave nearly pure methane, the primary component of natural gas. This is a means of upgrading the medium BTU fuel to a high BTU fuel. The process to remove CO₂ from the LFG is similar to options used for CO₂ sequestration, such as amine or physical scrubbers, water scrubbers, or membrane-based separation. The switchable FO water treatment system offers another mean of removing CO₂ from the LFG while providing the treatment of impure water.

[00199] Following from the previous example, a 10 million metric ton waste-in-place landfill produces about 850,000 MMscf/yr. Assuming 50% CH₄, this would have a total CO₂ content of about 12,000 lb/hr. A switchable FO water treatment system using this CO₂ could produce 14,500 gal/hr (348,000 gal/day) of water. The water treatment system would require between 0.10 and 0.14 MW_e of electricity, and 1.26 and 1.81 MW, of thermal energy. [00200] These energy sources can come from burning a small amount of the LFG prior to separation or from burning the separated methane, as shown in Figure 6b. This example demonstrates the use of burning the LFG prior to separation, as this reduces the net CO₂ separation requirement. As thermal energy is the limiting factor, such a power plant would be sized to provide this much thermal energy. It is estimated that diverting 15% of the 850,000 MMBTU/yr LFG as fuel for a small power plant is sufficient to drive the switchable FO water treatment system scaled to remove the CO₂ in the remaining 85% of the LFG. In this configuration, with the switchable FO water treatment system used to produce water and separate CO₂ from LFG, the combined system can produce 12,300 gal/hr (233,000 gal/day) of produced clean water, 722,500 MMBTU/yr of high purity CH₄ for pipeline use, and about 0.8 - 1.0 MW of electrical power that can be used elsewhere.

[00201] Although the invention has been described with reference to the examples herein, it will be understood that modifications and variations are encompassed within the spirit and scope of the invention. Accordingly, the invention is limited only by the following claims.

Claims

What is claimed is

1. A method for water purification comprising:

a) providing a water purification system;

b) providing the system with an impure water source; and

c) generating a purified water effluent from the impure water source via the purification system, wherein the system is adapted to utilize exhaust heat and a CO₂ containing waste stream generated via an auxiliary facility or process to generate the purified water effluent.

2. The method of claim 1, wherein the auxiliary facility or process is a co-located facility or biological, industrial or commercial process that generates exhaust heat and a C02 containing waste stream.

3. The method of claim 2, wherein the co-located facility is operated in co-generation mode.

4. The method of claim 1, wherein the water purification system utilizes a forward osmosis (FO) separation process.

5. The method of claim 4, wherein the FO process comprises:

a) a draw solvent regeneration cycle;

b) a membrane process utilizing a water-permeable membrane unit;

c) a recovery process utilizing a unit to recover water from draw solvent; and d) a process to remove trace components of draw solvent to generated a purified water stream prior to delivery utilizing one or more low-pressure units.

6. The method of claim 5, wherein the draw solvent regeneration cycle utilizes a switchable draw solute or polar solvent.

7. The method of claim 6, wherein the draw solvent regeneration cycle comprises an aqueous draw solution using a draw solute that becomes highly soluble and ionic upon the addition of an ionizing agent, and becomes insoluble and non-ionic on the dissociation of the ionizing agent.

8. The method of claim 5, wherein the membrane process comprises contacting one side of at least one semi-permeable membrane with the impure feed source, and contacting another side of the at least one semi-permeable membrane with concentrated draw solution, wherein water is drawn through the membrane from the feed source into the draw solution through the difference in osmotic pressure between the draw solution and feed solution.

9. The method of claim 8, wherein the recovery process comprises treating diluted draw solution following the membrane process to dissociate the ionizing agent from draw solute, and subsequently remove the draw solute and the ionizing agent from the water.

10. The method of claim 9, further comprises reintroducing into aqueous solution, recovered draw solute and ionizing agent thereby generating a concentrated draw solution prior to the membrane process.

11. The method of claim 1, wherein the purified water effluent has a total dissolved solids (TDS) content of no greater than 0.1 wt%, 0.01 wt%, or 0.001 wt%.

12. The method of claim 1, wherein the impure feed source has a total dissolved solids (TDS) concentration of at least 0.1 wt%, 1.0 wt%, or 3.0 wt%.

13. The method of claim 6, wherein the draw solvent is a switchable polar solvent that is activated by CO₂ and water.

14. The method of claim 13, wherein the switchable polar solvent is a tertiary amine.

15. The method of claim 13, wherein the draw solvent regeneration cycle includes the introduction of CO₂ into a non-polar form of the switchable polar solvent and water through a CO₂ gassing system.

16. The method of claim 15, wherein the CO₂ containing waste stream is an exhaust stream from a co-located facility.

17. The method of claim 16, wherein the exhaust stream comprises nitrogen, oxygen, CO₂ and water vapor.

18. The method of claim 17, wherein the exhaust stream is treated to remove acid gas components selected from the group consisting of H₂S, S0₂, and HC1.

19. The method of claim 15, wherein the source of CO₂ is high purity CO₂ having a purity of greater than 99%.

20. The method of claim 19, wherein the high purity CO₂ is from one or more sources selected from the group consisting of compressed or cryogenic storage tanks, CO₂ from co- located facilities which can be further purified in a separation process, and previously stored CO₂ that has been sequestered.

21. The method of claim 15, wherein the source of CO₂ is a combination of an exhaust stream from a co-located facility and a high purity CO₂ source having a purity of greater than 99%.

22. The method of claim 13, wherein the solvent regeneration cycle includes heating of the draw solvent to release CO₂ and switch the polar solvent to its non-polar state.

23. The method of claim 22, wherein the heating is held to a temperature no greater than 90° C.

24. The method of claim 22, wherein the heating is held to a temperature in the range of 40 to 70° C.

25. The method of claim 22, wherein the released CO₂ is chilled or processed to remove trace water and solvent from the gas phase.

26. The method of claim 25, wherein the released CO₂ is used as a product gas, is sequestered through terrestrial or geologic means, or used for other process applications.

27. The method of claim 22, wherein heating is accomplished via heat energy provided by waste heat streams from a co-generation process.

28. The method of claim 4, wherein both utility power requirements and heat requirements of the water purification system are provided by a co-located facility as typical co-generation.

29. The method of claim 28, wherein the water purification utilizes 100% or a fraction of the total CO₂ produced by the co-located facility.

30. The method of claim 29, wherein unused CO₂ from the co-located facility is used as a product gas, is sequestered through terrestrial or geologic means, or used for other process applications.

31. The method of claim 7, wherein the draw solute has a molecular weight greater than 31.

32. The method of claim 31, wherein the draw solute is an amine of the general form RWN, or an amidine of the general form R¹-C(=NR²)-NR³R⁴), or a guanidine of the general form R¹R²-C(=NR³)-NR⁴R⁵).

33. The method of claim 32, wherein R¹, R², R³, R⁴, and R⁵ are each independently selected from the following substitution groups: hydrogen; a substituted or unsubstituted alkyl group, including linear, branched, and cyclic components, with between one and 10 carbon atoms; a substituted or unsubstituted C_nSi_m group (wherein n and m are integers independently selected from 0 to 10, and wherein (n + m) is an integer from 1 to 10); and a substituted or unsubstituted aryl group or heteroaryl group that may contain at least one {- Si(R⁶)2-0-} group, wherein R⁶ is a substituted or unsubstituted alkyl, aryl, heteroaryl, or alkoxy group.

34. The method of claim 32, wherein the nitrogen is a heteroatom in a cyclic group incorporating two of the R¹, R², or R³ substitution groups.

35. The method of claim 32, wherein the draw solute is a tertiary amine, wherein none of R¹, R², or R³ is a hydrogen atom.

36. The method of claim 32, wherein the draw solute consists of two more amines of the general form R^XR²R³N.

37. The method of claim 31, wherein the draw solute is a polymer.

38. The method of claim 37, wherein the polymer has an amine monomer base in the general form -[R¹R²R³N]-, and wherein at least one carbon atom separates each nitrogen atom from each other in the polymer chain.

39. The method of claim 38, wherein R¹, R², and R³ are each independently selected from the following substitution groups: hydrogen, a substituted or unsubstituted alkyl group, including linear, branched, and cyclic components, with between one and 10 carbon atoms; a substituted or unsubstituted C_nSi_m group (wherein n and m are integers independently selected from 0 to 10, and wherein (n + m) is an integer from 1 to 10); and a substituted or unsubstituted aryl group or heteroaryl group that may contain at least one {-Si(R⁶)₂-0-} group, wherein R⁶ is a substituted or unsubstituted alkyl, aryl, heteroaryl, or alkoxy group. If the group is substituted, the substituent may be an alkyl, alkenyl, alkynl, alkyl halide, aryl, aryl halide, heteroaryl, non-aromatic ring, Si(alkyl)₃, Si(alkoxy)₃, alkoxy, amino, ester, amide, thioether, alkylcarbonate, or thioester group.

40. The method of claim 1, wherein the membrane unit comprises at least one semipermeable membrane.

41. The method of claim 40, wherein the membrane comprises a single self-supporting layer with either symmetric or asymmetric properties.

42. The method of claim 40, wherein the membrane is an asymmetric membrane comprising a support layer and one or more active layers atop the support layer.

43. The method of claim 42, wherein the membrane is positioned within the membrane unit to expose the active layer to the feed source and the support layer to the draw solution.

44. The method of claim 42, wherein the membrane is positioned within the membrane unit to expose the active layer to the draw solution and the support layer to the feed source.

45. The method of claim 40, wherein the membrane is a symmetric or asymmetric membrane comprising a support layer, and at least one or more active layers on one side of the support layer, and at least one or more active layers on the other side of the support layer.

46. The method of claim 40, wherein the membrane layer in contact with the draw solution is compatible with caustic fluids up to a pH of about 12, 13, 14 or greater.

47. The method of claim 40, wherein the membrane is constructed from inorganic layers selected from ceramics, boro-silicates, zeolites, carbon nanotubes, and graphene.

48. The method of claim 40, wherein the membrane is constructed from both inorganic and organic layers, with the inorganic layer in contact with the draw solution.

49. The method of claim 48, wherein the organic layer is constructed of polymer material, selected from polyamides, polysulfates, Teflon, and cellulose triacetate.

50. The method of claim 48, wherein the inorganic layer is selected from ceramics, boro- silicates, zeolites, carbon nanotubes, and graphene.

51. The method of claim 40, wherein the semi-permeable membrane is selected from a tubular membrane, a hollow fiber membrane, a spiral wound membrane, a plate-and-frame membrane, or a flat-sheet membrane.

52. The method of claim 40, wherein the membrane unit comprises two or more membranes.

53. The method of claim 52, wherein the membranes are arranged in parallel configuration relative to the flow of either the feed source or the draw solution.

54. The method of claim 52, wherein the membranes are arranged in a combination of serial and parallel configurations.

55. The method of claim 52, wherein the feed and draw solution inlets and outlets of at least one or more membranes in the membrane unit are individually monitored through sensing devices.

56. The method of claim 55, wherein the sensing data includes but is not limited to: temperature, pressure, density, flow rate, pH, conductivity, viscosity, chemical/compositional analysis, turbidity, discoloration, total dissolved and suspended solids, and biological and chemical oxygen demand.

57. A water purification system configured to utilize exhaust heat and one or more CO₂ containing waste streams generated via an auxiliary facility or process to generate purified water effluent.

58. The system of claim 57, wherein the auxiliary facility or process is a co-located facility or biological, industrial or commercial process that generates exhaust heat and a CO₂ containing waste stream.

59. The system of claim 58, wherein the co-located facility is operated in co-generation mode.

60. The system of claim 57, wherein the water purification system utilizes a forward osmosis (FO) separation process.

61. The system of claim 60, wherein the FO process comprises:

a) a draw solvent regeneration cycle;

b) a membrane process utilizing a water-permeable membrane unit;

62. The system of claim 61, wherein the draw solvent is a switchable polar solvent that is activated by CO₂.

63. The system of claim 62, wherein the draw solute in its non-ionic form has a solubility in water less than 0.1 g/mL, and more preferably, less than 0.0001 g/mL, and in its ionic form upon association with the ionizing agent, a solubility greater than 1000 g/mL.

64. The system of claim 63, wherein upon dissociation with CO₂, at least 50 wt%, or 99% of the draw solute can be separated from CO₂ at a temperature no greater than 90 °C at 1 atm, 75 °C at 1 atm, or 60 °C at 1 atm.

65. The system of claim 64, wherein upon dissociation and separation from CO₂, at least 50 wt% or 99 wt% of the draw solute can be separated from water at a temperature no greater than 90 °C at 1 atm, 75 °C at 1 atm, or 60 °C at 1 atm.

66. The system of claim 61, wherein the draw solute is an amine of the general form RiR₂R₃N, or an amidine of the general form

or a guanidine of the general form

or a combination of two or more of these materials.

67. The system of claim 66, wherein R¹, R², R³, R⁴, and R⁵ are each independently selected from the following substitution groups: hydrogen; a substituted or unsubstituted alkyl group, including linear, branched, and cyclic components, with between one and 10 carbon atoms; a substituted or unsubstituted C_nSi_m group (wherein n and m are integers independently selected from 0 to 10, and wherein (n + m) is an integer from 1 to 10); and a substituted or unsubstituted aryl group or heteroaryl group that may contain at least one {- Si(R⁶)2-0-} group, wherein R⁶ is a substituted or unsubstituted alkyl, aryl, heteroaryl, or alkoxy group.

68. The system of claim 66, wherein the nitrogen is a heteroatom in a cyclic group incorporating two of Ri, R₂, or R₃.

69. The system of claim 66, wherein the draw solute is a tertiary amine, where none of Ri, R₂, or R₃ is a hydrogen atoms.

70. The system of claim 61, wherein the draw solute is a polymer.

71. The system of claim 70, wherein the polymer has an anime monomer base in the general form -[RiR₂R₃N]-, and where at least one carbon atom separates each nitrogen atom from each other in the polymer chain.

72. The system of claim 71, wherein the nitrogen is a heteroatom in a cyclic group having two of Ri, R₂, or R₃.

73. The system of claim 71, wherein the nitrogen monomer is a tertiary amine where none of Ri, R₂, or R₃ are hydrogen.

74. The system of claim 71, wherein the polymer is composed only of the amine monomer base.

75. The system of claim 71, wherein the polymer is a co-polymer, with one of the monomers being the amine base.

76. The system of claim 71, wherein the polymer has an average molecular weight of at least 1,000, and more preferably at least 10,000.

77. The system of claim 64, wherein the draw solute at standard ambient conditions in its non-ionic form is an immiscible liquid with water.

78. The system of claim 64, wherein the draw solute at standard ambient conditions in its non-ionic form is a particulate or solid.

79. The system of claim 64, wherein the draw solute at standard ambient conditions in its non-ionic form is a gas.

80. The system of claim 79, wherein the vaporization temperature of the gaseous draw solute is at least -40 °C, -20 °C, or 0 °C.

81. The system of claim 62, wherein the switchable polar solvent is a tertiary amine.

82. The system of claim 61, wherein the solvent regeneration cycle includes the introduction of CO₂ to the non-polar form of the switchable polar solvent and water through a CO₂ gassing system.

83. The system of claim 82, wherein the molar ratio of CO₂ added to the draw solution during the regeneration process relative to the number of amine centers in the draw solute is at least 1 and less than 10.

84. The system of claim 83, wherein the concentration of the concentrated draw solution after the addition of C02 is between 5% to 90% by mass.

85. The system of claim 84, wherein the draw solution in its concentrated state has an osmotic pressure greater than about 100 atm, 200 atm, or 400 atm.

86. The system of claim 58, wherein the source of CO₂ is from one or more exhaust streams from the co-located facility.

87. The system of claim 86, wherein the CO₂-laden stream contains at least 1 mole% CO₂, at least 5 mole% CO₂, or at least 10 mole% CO₂.

88. The system of claim 87, wherein the CO₂-laden stream is at least 90 mole% CO₂ or at least 95 mole% CO₂.

89. The system of claim 87, wherein the CO₂-laden stream is pre-treated to remove contaminants in the stream that are not compatible with the draw solute, draw solution, or membrane components of the switchable FO water treatment sub-system.

90. The system of claim 87, wherein the source for the CO₂-laden stream is flue gas from one or more processes that combust, incinerate, gasify, pyrolyze or use thermo-chemical conversion of a hydrocarbon fuel in air, oxygen, or another oxidizing source for a power, heat or combined heat-and-power generation system.

91. The system of claim 90, wherein the hydrocarbon fuel is synthetic gas, methane, natural gas, coal, gasoline, diesel, methanol, dimethyl ether, propane, landfill gas, biogas, biomass, municipal solid waste, agricultural waste, or combination thereof.

92. The system of claim 87, wherein the source for the CO₂-laden stream is from one or more industrial processes in which CO₂ is generated.

93. The system of claim 87, wherein the source for the CO₂-laden stream is from a natural or man-made CO₂-rich storage or process stream that is used at the co-located facility.

94. The system of claim 93, wherein the co-located facility is used for enhanced oil recovery, enhanced gas recovery, or enhanced coalbed methane recovery.

95. The system of claim 87, wherein the source for the CO₂-laden stream is from a naturally occurring source that generates CO₂ in its output.

96. The system of claim 95, wherein the source is geothermal energy, landfill gas, or gas generated from biomass conversion.

97. The system of claim 86, wherein the exhaust stream comprises nitrogen, oxygen, C02 and water vapor.

98. The system of claim 97, wherein the exhaust stream has been treated to remove acid gas components comprising H₂S, S0₂, and HC1.

99. The system of claim 87, wherein the source of CO₂ is high purity CO₂ having a purity greater than 99% from a one or more sources comprising compressed or cryogenic storage tanks, CO₂ from co-located facilities that can be further purified in a separation process, or from previously stored CO₂ that has been sequestered.

100. The system of claim 61, wherein the solvent regeneration cycle includes the heating of the draw solvent to release CO₂ and switch the polar solvent to its non-polar state.

101. The system of claim 100, wherein the heating is held to a temperature no greater than 90 °C.

102. The system of claim 100, wherein the heating is held to a temperature in the range of 40 to 70 °C.

103. The system of claim 100, wherein the released CO₂ is chilled or processed to remove trace water and solvent from the gas phase.

104. The system of claim 103, wherein the released CO₂ is used as a product gas, and/or is sequestered through terrestrial or geologic means, and/or used for other process applications.

105. The system of claim 100, wherein the heat energy is provided by waste heat streams from the co-generation process.

106. The system of claim 59, wherein both the utility power requirements and the heat requirements of the water purification system are provided by the co-located facility as typical co-generation.

107. The system of claim 60, wherein the water purification uses 100% or a fraction of the total CO₂ produced by the co-located facility.

108. The system of claim 107, wherein the unused CO₂ from the co-located facility is used as a product gas, is sequestered through terrestrial or geologic means, or is used for other process applications.

109. A water purification system that treats one or more water feed streams and generates one or more purified water effluent streams, the system being configured to utilize exhaust heat and one or more CO₂ containing waste streams generated via a co-located facility to generate the purified water effluent streams, the system comprising a control system and one or more water treatment sub-systems, wherein at least one of the sub-systems is a forward osmosis (FO) water treatment system comprising: a) a draw solution using a switchable draw solute which, at standard ambient conditions, is hydrophobic and is immiscible or insoluble in water, and which can be ionized by the addition of CO₂ to become hydrophilic and highly soluble in water, and which subsequently can be dissociated from CO₂ to return to its hydrophobic form;

b) a membrane system comprising one or more semi-permeable membranes that allows for passage of water while rejecting suspended solids, ions, and organic and biological materials in the water, where one side of each membrane is contacted with a impure feed water stream, and an opposite side contacting concentrated draw solution comprising ionized draw solute and CO₂, whereby an osmotic pressure difference between draw solution and feed solution causes water to permeate across the membrane into the draw solution thereby diluting it;

c) a recovery process which dissociates CO₂ from the draw solute in the diluted draw solution, which some or all of the CO₂ being released as exhaust, and which separates the non-ionized draw solute from the water;

d) a regeneration process which combines water, draw solution, the recovery draw solute, and additional CO₂ from one or more CO₂-laden streams from one or more co- located facilities to ionize the draw solute and create a concentrated draw solution; and

e) a control system to monitor and control the switchable forward osmosis water treatment sub-system.

110. The system of claim 109, wherein the water feed has a total dissolved solids (TDS) concentration of at least 0.1 wt%, 1.0 wt%, or 3.0 wt%.

111. The system of claim 110, wherein the water feed is selected from greywater, brackish water, seawater, surface and groundwater including impaired and polluted sources, brine, high-salinity bodies of water, secondary and tertiary treated wastewater, recycled water, reclaimed water, purple pipe water, biomass, municipal solid waste and associated leachate, pharmaceutical, food/beverage, and industrial process streams, industrial and commercial wastewater, agriculture, and produced water from oil & gas (hydro-fracturing), geothermal, and mining operations.

112. The system of claim 110, wherein the water feed comes from two or more different sources.

113. The system of claim 109, wherein the one or more water effluent streams has a TDS content of no greater than 0.1 wt%, 0.01 wt%, or 0.001 wt%.

114. The system of claim 113, wherein the one or more water effluent streams is of potable water quality.

115. The system of claim 113, wherein the one or more water effluent streams is of tertiary treated water quality.

116. The system of claim 109, wherein the co-located facility possesses one or more available sources of thermal energy in the form of low-quality heat (< 150 °C), medium- quality heat (150-250 °C), or high-quality heat (>250 °C).

117. The system of claim 116, wherein some or all of the available thermal energy from the co-located facility is used within the recovery process of the sub-system to dissociate CO₂ from the draw solute, remove CO₂ from the water and draw solute, and separate the draw solute from the water.

118. The system of claim 117, wherein some of the available thermal energy is also used within the overall water treatment system to providing additional heating within additional sub-systems other than the FO sub-system.

119. The system of claim 109, wherein the co-located facility generates electricity either as its primary function or to support electricity requirements of other systems within the facility.

120. The system of claim 119, wherein some or all of the available electricity generated by the co-located facility is used to power the control system, sensors, controlling unit operations, and other electrical equipment on the FO sub-system.

121. The system of claim 120, wherein some of the available electrical energy is also used within the overall water treatment system to providing additional power within its control system, or within additional sub-systems other than the FO sub-system.

122. The system of claim 109, wherein the FO sub-system produces a CO₂-rich stream at purity greater than 90 mole%, or 95 mole%.

123. The system of claim 122, wherein the produced CO₂ is stripped of condensable gases through post-treatment unit operations selected from condensers, chillers, and coolers.

124. The system of claim 122, wherein the produced CO₂ is stripped of contaminants from the feed waters or the draw solute through post-treatment unit operations.

125. The system of claim 122, wherein the produced CO₂ stream is compressed for CO₂ storage or CO₂ sequestration.

126. The system of claim 122, wherein the produced CO₂ stream is used by the co-located facility as a chemical feedstock stream for further use or processing.

127. The system of claim 109, wherein the FO sub-system produces a CO₂-lean stream from the CO₂-laden stream, with a CO₂ removal of at least 50%, 75%, or 90%.

128. The system of claim 109, wherein some or all of the CO₂ in the diluted draw solution is dissociated and removed from the water and draw solution, leaving the water treatment system as an effluent.

129. The system of claim 127, wherein the amount of CO₂ available in the CO₂-laden stream from the co-located facility is equal to or greater than the amount of CO₂ removed as effluent in the recovery process.

130. The system of claim 109, wherein the control system monitors and records sensors located on feed water inlets, draw solution loop, and produced water outlets.

131. The system of claim 130, wherein the sensors are selected from temperature, pressure, density, flow rate, pH, conductivity, viscosity, chemical/compositional analysis, turbidity, discoloration, total dissolved and suspended solids, and biological and chemical oxygen demand.

132. The system of claim 130, wherein the control system monitors and records sensor information external to the FO sub-system.

133. The system of claim 132, wherein external sensor data comprises one or more of upstream feed water quality, sensors on upstream water treatment sub-systems, ambient temperature and pressure, weather conditions, downstream water quality, the concentration, temperature, and pressure of the C02-laden source from the co-located facility, the electrical power available from the co-located facility, and the quality and flow rate of thermal heat from the co-located facility.

134. The system of claim 130, wherein the control system operates and records control hardware on the FO sub-system in response to sensed data.

135. The system of claim 134, wherein the control hardware includes hydraulic and vacuum pumps, valves, pressure regulators, heaters, chillers, temperature regulators, and devices to interface and support for operator and process safety.

136. The system of claim 134, wherein the control system includes means for manual interaction from human operators, including initiating safety and failsafe processes (HAZOPS).

137. The system of claim 130, wherein a control system on the FO sub-system sends sensor data and control operations to the overall control system.

138. The system of claim 137, wherein a control system on the FO sub-system receives information and control logic from the overall control system.

139. The system of claim 109, wherein the system further comprises an automated control system to monitor and manage the overall system, including through interaction of the forward osmosis water treatment sub-system autonomous control system, and control systems on other water treatment sub-systems.

140. The system of claim 139, wherein the control system monitors and records sensors around individual sub-systems.

141. The system of claim 140, wherein sensor data comprises temperature, pressure, density, flow rate, pH, conductivity, viscosity, chemical/compositional analysis, turbidity, discoloration, total dissolved and suspended solids, biological and chemical oxygen demand, ambient temperature and pressure, storage tank levels, the concentration, temperature, and pressure of the C02-laden source from the co-located facility, the electrical power available from the co-located facility, and the quality and flow rate of thermal heat from the co-located facility.

142. The system of claim 140, wherein the control system monitors for potential security threats to the systems and interfaces to a supervisory control and data acquisition (SCADA) system as well as for trading of emissions and water in a Cap and Trade market.

143. The system of claim 140, wherein the control system operates control hardware around the individual sub-systems.

144. The system of claim 143, wherein the control hardware comprises valves, pumps, pressure regulators, electric power generators, heaters, coolers, chillers, and devices to interface and support operator and process safety.

145. The system of claim 143, wherein the control system further comprises means for manual interaction from human operators, including initiating safety and failsafe processes (HAZOPS).

146. The system of claim 143, wherein the control system, including the individual control systems on each sub-system, can be monitored and controlled remotely.

147. The system of claim 146, wherein the control system remotely interfaces with sustainable platforms that aggregate data from relevant power grid operational systems, power producing facilities, water utility systems, water treatment facilities, and other power and water sources that support analytic and business intelligence capabilities for emissions and water trading for a Cap and Trade market.

148. The system of claim 140, wherein the control system monitors and responds to data from external sources comprising incoming feed stream water quality, upstream water treatment plant data, produced water quality, ambient temperature and pressure, current weather conditions, time of day, current and projected produced water use, and peak utility hours.