WO2016115497A1 - Système d'épuration d'eau par osmose directe sur la base de solvant polaire commutable, intégrant les flux de rejets thermiques provenant d'installations colocalisées avec séquestration de co2 - Google Patents

Système d'épuration d'eau par osmose directe sur la base de solvant polaire commutable, intégrant les flux de rejets thermiques provenant d'installations colocalisées avec séquestration de co2 Download PDF

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WO2016115497A1
WO2016115497A1 PCT/US2016/013664 US2016013664W WO2016115497A1 WO 2016115497 A1 WO2016115497 A1 WO 2016115497A1 US 2016013664 W US2016013664 W US 2016013664W WO 2016115497 A1 WO2016115497 A1 WO 2016115497A1
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water
draw
membrane
stream
sub
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Karen Fleckner
Michael K. Neylon
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Artesion, Inc.
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    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F1/00—Treatment of water, waste water, or sewage
    • C02F1/44—Treatment of water, waste water, or sewage by dialysis, osmosis or reverse osmosis
    • C02F1/445—Treatment of water, waste water, or sewage by dialysis, osmosis or reverse osmosis by forward osmosis
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D61/00—Processes of separation using semi-permeable membranes, e.g. dialysis, osmosis or ultrafiltration; Apparatus, accessories or auxiliary operations specially adapted therefor
    • B01D61/002—Forward osmosis or direct osmosis
    • B01D61/0021—Forward osmosis or direct osmosis comprising multiple forward osmosis steps
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D61/00—Processes of separation using semi-permeable membranes, e.g. dialysis, osmosis or ultrafiltration; Apparatus, accessories or auxiliary operations specially adapted therefor
    • B01D61/002—Forward osmosis or direct osmosis
    • B01D61/0022—Apparatus therefor
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D61/00—Processes of separation using semi-permeable membranes, e.g. dialysis, osmosis or ultrafiltration; Apparatus, accessories or auxiliary operations specially adapted therefor
    • B01D61/002—Forward osmosis or direct osmosis
    • B01D61/0023—Accessories; Auxiliary operations
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D61/00—Processes of separation using semi-permeable membranes, e.g. dialysis, osmosis or ultrafiltration; Apparatus, accessories or auxiliary operations specially adapted therefor
    • B01D61/002—Forward osmosis or direct osmosis
    • B01D61/0024—Controlling or regulating
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/204—Amines
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/50—Carbon oxides
    • B01D2257/504—Carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2258/00—Sources of waste gases
    • B01D2258/02—Other waste gases
    • B01D2258/0283—Flue gases
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2311/00—Details relating to membrane separation process operations and control
    • B01D2311/06—Specific process operations in the permeate stream
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1456—Removing acid components
    • B01D53/1475—Removing carbon dioxide
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2209/00—Controlling or monitoring parameters in water treatment
    • C02F2209/01—Density
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2209/00—Controlling or monitoring parameters in water treatment
    • C02F2209/02—Temperature
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2209/00—Controlling or monitoring parameters in water treatment
    • C02F2209/03—Pressure
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2209/00—Controlling or monitoring parameters in water treatment
    • C02F2209/05—Conductivity or salinity
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2209/00—Controlling or monitoring parameters in water treatment
    • C02F2209/06—Controlling or monitoring parameters in water treatment pH
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2209/00—Controlling or monitoring parameters in water treatment
    • C02F2209/10—Solids, e.g. total solids [TS], total suspended solids [TSS] or volatile solids [VS]
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2209/00—Controlling or monitoring parameters in water treatment
    • C02F2209/11—Turbidity
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2209/00—Controlling or monitoring parameters in water treatment
    • C02F2209/40—Liquid flow rate
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00—Capture or disposal of greenhouse gases
    • Y02C20/40—Capture or disposal of greenhouse gases of CO2
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E50/00—Technologies for the production of fuel of non-fossil origin
    • Y02E50/30—Fuel from waste, e.g. synthetic alcohol or diesel

Definitions

  • 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 CO 2 .
  • FO forward osmosis
  • Carbon Capture Sequestration can be categorized in two basic types: Terrestrial and Geologic.
  • Terrestrial (or biologic) sequestration applications plants are used to capture CO 2 from the atmosphere and then stored as carbon in the stems and roots of the plants as well as in the soil.
  • Terrestrial (or biologic) sequestration applications plants are used to capture CO 2 from the atmosphere and then stored as carbon in the stems and roots of the plants as well as in the soil.
  • CO 2 can be used in an environmentally-benign beneficial manner such as using the CO 2 to enhance agricultural soil.
  • Within the CO 2 sequestration process is a separation step to remove CO 2 from other gases in exhaust streams, typically contain nitrogen, oxygen, and moisture which would reduce the efficacy of the CO 2 storage.
  • CCS consists of two steps: capturing CO 2 out of a post-combustion exhaust stream using adsorption or absorption processes, and then sequestering the CO 2 .
  • the most common means of sequestration of CO 2 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 CO 2 including non- condensable gases such as N 2 , 0 2 , and Ar, will reduce the storage effectiveness at high pressures.
  • a CO 2 stream with 15 vol% impurity of other non-condensable gases has a 40% lower sequestration storage capacity compared to a pure CO 2 stream.
  • the impurities also more difficult to deliver the CO 2 to the storage point.
  • the CO 2 capture process that removes CO 2 from post-combustion streams must be able to achieve a high purity of CO 2 and minimize the amount of non-condensable gases, particularly N 2 which is nearly always within combustion processes.
  • CO 2 capture can be performed through adsorption (where the CO 2 adheres to a substance) or absorption (where the CO 2 is dissolved into a substance), and can be done through a physical or chemical process.
  • 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.
  • amine-based absorption often called an amine scrubber system, is the most established option.
  • 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.
  • MEA methylethylamine
  • the exhaust gas stream is bubbled through the solvent at ambient conditions, during which the amine reacts with the CO 2 to form either a carbamate salt or a bicarbonate salt as follows.
  • the amines are selected so that these salts have very high solubility in water, as to maximize the amount of CO 2 that can be absorbed per pass.
  • the other gases in the exhaust stream primarily nitrogen and oxygen
  • 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 CO 2 , without causing the water solvent to vaporize. The CO 2 is then treated to remove traces of condensable components such as moisture and amine prior to sequestration or other downstream uses.
  • the amine scrubbing process is effective for CO 2 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 CO 2 release reactions. Additional equipment and power will be required to then pressurize and store the CO 2 for sequestration applications.
  • this process does little else with the CO 2 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 CO 2 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 CO 2 sequestration using a novel solvent approach.
  • switchable polar solvents used for water purification and utilizing CO 2 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.
  • CO 2 an ionizing agent
  • 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.
  • 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.
  • FO forward osmosis
  • 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).
  • RO reverse osmosis
  • 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.
  • RO reverse osmosis
  • 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 MgCl 2 .
  • 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.
  • 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 CO 2 , can have high osmotic pressures greater than 200 atm, generating high osmotic pressure differences required for effective water draw across the membrane.
  • the amine solute is dissociated from CO 2 , 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.
  • SPS switchable polar solvents
  • tertiary amines that can absorb CO 2 to form the bicarbonate ionic pair.
  • a key feature of the SPS solvents is that they are non-polar (hydrophobic) prior to CO 2 absorption, and become polar (hydrophilic) following CO 2 absorption.
  • 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 CO 2 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.
  • CO 2 is a driving factor for the SPS-based FO system.
  • the system would need to be charged with CO 2 , and makeup CO 2 would ultimately need to be added to account for losses from incomplete recovery of CO 2 or potential gas leaks in the process. This would require a source of CO 2 to recover those losses. For small scale systems this may be accomplished by stored CO 2 tanks, but larger water purification systems may require makeup CO 2 at a rate exceeding what one can reasonable expect for CO 2 storage.
  • CO 2 can be obtained from the off-gases of a combustion-type or other biological, industrial or commercial plant, or from prior sequestered CO 2 sources.
  • the CO 2 exhaust can either be used directly or from CO 2 sequestration storage.
  • an FO system that produces 1 million gallons of water per day would utilize around 430 tons of CO 2 per day in the draw solute recycle loop. While most of this CO 2 is recycled within the system, even small losses will require significant CO 2 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/CO 2 release from the draw solvent in the SPS system.
  • 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 CO 2 absorption. Aqueous ammonia solutions can be converted to a highly concentrated ionic solution via CO 2 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 CO 2 and aqueous ammonia, and it vaporizes the ammonia from solution to leave behind nearly-pure water.
  • the gaseous ammonia is separated from the CO 2 to be reintroduced into the draw solvent.
  • the CO 2 is subsequently removed from the system and sent to be sequestered.
  • ammonia-water patent demonstrates the ability to combine CO 2 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 CO 2 and heat from other biological, industrial, and commercial systems.
  • 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 CO 2 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 CO 2 .
  • SPS switchable polar solvents
  • tertiary amines that have the ability to switch from a non-polar to a polar form in the presence of CO 2 .
  • the CO 2 is obtained from the exhaust from the co-located facility.
  • the waste heat stream(s) from the facility can be used to drive the CO 2 removal step, reducing the utility load of the water purification process.
  • the combined process provides a means of separating CO 2 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.
  • 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.
  • the system is adapted to utilize exhaust heat and a CO 2 containing waste stream generated via an auxiliary facility or process to generate the purified water effluent.
  • the auxiliary facility or process is a co-located facility or biological, industrial or commercial process that generates exhaust heat and a CO 2 containing waste stream.
  • the co-located facility is operated in co-generation mode.
  • 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.
  • the draw solvent regeneration cycle utilizes a switchable draw solute or polar solvent.
  • 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.
  • the invention provides a water purification system configured to utilize exhaust heat and one or more CO 2 containing waste streams generated via an auxiliary facility, such as a co-located facility, or process to generate purified water effluent.
  • 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 CO 2 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 CO 2 to become hydrophilic and highly soluble in water, and which subsequently can be dissociated from CO 2 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 CO 2 , 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;
  • Figure 1 is a process flow diagram illustrating a typical prior art amine-based CO 2 scrubber system used for CO 2 sequestration.
  • Figure 2 is a process flow diagram for a SPS-based FO water purification system in one embodiment of the present invention.
  • 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.
  • FIG. 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 CO 2 streams.
  • 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
  • Figure 5b is a diagram illustrating the inclusion of the switchable FO water treatment sub-system within the EOR process.
  • 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
  • Figure 6b is a diagram illustrating use of the invention to separate CH 4 from LFG while burning some of the LFG for heat and power while producing water.
  • 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 CO 2 and heat from other biological, industrial, and commercial systems. This process when combined with CO 2 sequestration provides an innovative energy efficient water purification process.
  • 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.
  • 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.
  • 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.
  • Processed water refers to the water generated by the water treatment system.
  • Croan water refers to the effluent water generated by the water treatment system. This effluent can be pure water, but not always.
  • 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”.
  • Pair 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).
  • 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.
  • 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.
  • a "switchable polar solvent”, unless otherwise clarified, is considered in this invention to be a draw solution that uses a switchable material.
  • An "ionizing agent” is a material that can provide a proton to ionize the switchable draw solute, while forming an anion itself.
  • the ionizing agent of interest is CO 2 .
  • Standard ambient conditions refers to a temperature of 25° C and a pressure of 1 atm.
  • STP Standard temperature and pressure
  • scf standard cubic feet
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the method utilizes an FO water purification system using an SPS draw solvent that is driven by waste flue gas, containing CO 2 , and heat from exhaust.
  • the invention provides a water purification system configured to utilize exhaust heat and one or more CO 2 containing waste streams generated via an auxiliary facility, such as a co-located facility, or process to generate purified water effluent.
  • the SPS in its non-polar form is gassed with CO 2 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.
  • the diluted SPS solvent is heated to no greater than 90° C to reverse the salt formation reaction: CO 2 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.
  • High purity CO 2 (greater than 99%) can be introduced from a variety of sources including; compressed or cryogenic storage tanks, CO 2 from co-located facilities that can be further purified in a separation process, or from previously stored CO 2 that has been sequestered.
  • the high purity CO 2 can come from one or more of these sources.
  • 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.
  • a goal of the present invention is to achieve nearly complete separation of the draw solute, CO 2 , and water using either or both low and high quality heat within the recovery process.
  • at least 50%, but preferably 99% of the draw solute can be dissociated from the CO 2 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.
  • 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.
  • the switchable FO water treatment sub-system is capable of handling trace CO 2 and draw solute in the recovered water through the additional polishing steps.
  • 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.
  • the separation of the CO 2 , 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.
  • 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.
  • 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 CO 2 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.
  • 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.
  • the switchable solvent separation feature described above has been demonstrated with several amine compounds.
  • 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 CO 2 .
  • 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 CO 2 scrubber amines (Reaction 2), avoiding the formation of carbamates (Reaction 1) that require more energy for dissociation.
  • R 1 , R 2 , R 3 , R 4 , and R 5 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 n Si 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(R 6 )2-0- ⁇ group, wherein R 6 is a substituted or unsubstituted alkyl, aryl, heteroaryl, or alkoxy group.
  • 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
  • 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.
  • the draw solute can be a combination of two or more amines as described above.
  • the draw solute is a chemical that is normally a liquid at standard ambient conditions (25° C and 1 atm).
  • the liquid will be immiscible with water in the non-ionic state, allowing for physical separation through processes such as decanting or centrifuging.
  • CO 2 When CO 2 is added, the liquid draw solute dissolves in the water and creates a draw solution with high osmotic pressure.
  • amines include ⁇ , ⁇ -dimethylcyclohexylamine and 1-cyclohexylpiperdiene.
  • 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 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.
  • ICP internal concentration polarization
  • the polymer has an average molecular weight greater than 1,000, and in a more preferred embodiment, 10,000.
  • the polymer is homomeric from the same amine monomer.
  • the polymer is heteromeric, with at least one monomer being an amine.
  • the monomer is a tertiary amine.
  • the draw solute is a combination of two or more polymers that have amine monomer bases as described above.
  • 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 CO 2 will be through a cooling process as to collect the condensed form of the draw solute while releasing the CO 2 as a gas.
  • 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.
  • the concentration of the draw solution including the relative ratio of CO 2 to amine, will affect its solubility and osmotic pressure.
  • the term "CO 2 to amine centers" molar ratio is defined as the moles of CO 2 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 CO 2 molecule.
  • Reaction 2 the bicarbonate reaction, previously described, to assure that each amine-based atomic center reacts with one CO 2 molecule.
  • the liquid-based draw solutes these is generally only one such nitrogen atom per amine molecule.
  • the polymer-based draw solutes there will usually be one nitrogen atom for every amine-based monomer in the polymer.
  • the molar ratio of the CO 2 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.
  • the concentration of concentrated draw solution, possessing both draw solute and CO 2 is between 5% to 90% by mass, and more preferably between 25% and 80% by mass.
  • 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.
  • 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.
  • 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.
  • the ionizing agent is C02.
  • 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.
  • the SPS FO system described above is modified to introduce CO 2 into the SPS fluid by an exhaust gas stream from a co-located facility.
  • the exhaust gas stream should be the resulting stream from combustion, incineration, biological, or other thermo-chemical process that involves generating heat in which CO 2 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 H 2 S, S0 2 , 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.
  • the modified SPS FO system can takes in multiple sources of CO 2 with varying grades of purity.
  • the CO 2 sources can come from one or more high purity CO 2 sources (greater than 99%) such as compressed or cryogenic storage tanks, CO 2 from co-located facilities that can be further purified in a separation process, or from previously stored CO 2 that has been sequestered.
  • the CO 2 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 CO 2 can be used in desired ratios to achieve a consistent supply of CO 2 capable of switching the polarity of the SPS draw solvent.
  • 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.
  • 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 CO 2 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 CO 2 will react to make the polar form of the SPS.
  • the remaining portion of the exhaust gas - nitrogen, oxygen, and CO 2 that is not absorbed by the SPS - leaves the process and released as emissions.
  • the amount of CO 2 recycled from the CO 2 degasser to the gasser can be adjusted as to adapt the water purification system to meet the exhaust size of the co-generation plant.
  • the system can operate in full sequestration mode, where none of the degassed CO 2 is recycled; this would require the largest co-generating plant size to supply that much CO 2.
  • the co-generation plant is smaller, more of the CO 2 can be regenerated through the system to make up for the lower amounts of CO 2 exhaust available. CO 2 exhaust streams from larger plants can always be used, but some portion of the CO 2 will not be caught as sequestered material. This embodiment is illustrated in Figure 3 and demonstrated in Examples 1 and 2.
  • the amount of CO 2 in the CO 2 -laden streams will determine the size of the water treatment sub-system in combination with the amount of CO 2 that is recycled within the subsystem. These parameters determine how much CO 2 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 CO 2 .
  • a CO 2 -laden stream can provide 100 lb/hr of CO 2 to the switchable FO water treatment sub-system. If the sub-system fully exhausts the CO 2 and recycles none of it, then the draw solution will have 100 lb/hr of CO 2 that is introduced at the regeneration stage and will be present at the membrane.
  • the draw solution will have 200 lb/hr of CO 2 (exhausting 100 lb/hr and making that up from the 100 lb/hr of the CO 2 -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.
  • the sources of the CO 2 in this embodiment are CO 2 -laden streams from a co- located facility to the overall water treatment system.
  • at least one CO 2 -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 CO 2 , from between 1 to 75 vol%, depending on the type of fuel, oxygen-to-fuel ratio, and other factors.
  • at least one CO 2 -laden stream is an effluent stream from a chemical process with CO 2 content greater than 1%.
  • At least one CO 2 -laden stream is from an existing, natural or man-made CO 2 source such as stored CO 2 in storage vessel, underground formation, or geothermal release, or a CO 2 pipeline, where the CO 2 would be used by the co-located facility as part of its normal operations.
  • enhanced oil recovery uses high purity CO 2 to mobilize oil in rock beds to improve oil recovery, while within the food industry, high purity CO 2 is used as an inert atmosphere and as a supercritical inert fluid for extraction and rapid cooling.
  • CO 2 degassing system 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.
  • CO 2 is released by this process which is normally collected and recycled in the SPS FO process.
  • the CO 2 instead is released as an effluent stream; it will be nearly pure CO 2 with trace amounts of water and non-polar SPS that vaporize with the CO 2 .
  • the water and non-polar SPS vapor components 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 CO 2 possessing a lower vaporization temperature than either water or the SPS.
  • the final CO 2 effluent stream will possess high purity for storage or other potential sequestration applications.
  • the CO 2 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.
  • ORC Organic Rankine Cycle
  • 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.
  • the additional energy required to drive the water purification process will be significantly reduced.
  • 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.
  • the largest energy consumer in this process is the heat needed for CO 2 degassing. This energy requirement is removed by using the waste heat from a process operated in co- generation mode.
  • 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 CO 2 sequestration.
  • the recovery process within the switchable FO water treatment sub-system uses waste heat from the co-located facility.
  • 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.
  • CHP combined heat-and-power
  • the switchable FO subsystem can use these streams effectively to trigger the dissociation of the CO 2 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.
  • 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.
  • 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.
  • 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.
  • the co-located facility that provides the CO 2 -laden source requires either the purification of the CO 2 -laden source before use, or the near- removal of CO 2 from the CO 2 -laden source.
  • enhanced oil recovery will recycle CO 2 through the process, and the CO 2 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 CO 2 compression and re-injection process, which can be offered alongside water purification with this switchable FO water treatment sub-system.
  • LGF landfill gas
  • the switchable FO water treatment sub-system can be used to purify the methane while also producing clean water.
  • CO 2 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 CO 2 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 CO 2 , methane, H 2 , N 2 , 0 2 , H 2 0 and other hydrocarbons.
  • the biofuel process could separate the various components to give a higher yield of pure CO and the H 2 for biofuel product while using the CO 2 for water purification for the process or other uses.
  • 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.
  • 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.
  • multiple membrane units with their own semi-permeable membrane may be used.
  • Typical membranes identified for osmotic processes 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.
  • the membrane used in the membrane unit is a single-active layer supported membrane.
  • the membrane is a double- or triple-active layer supported membrane.
  • 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.
  • ICP internal concentration polarization
  • 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.
  • 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.
  • the membrane is oriented in FO mode relative to the feed and draw solutions.
  • the supported membrane is oriented in PRO mode.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the geometry and form factor of the membrane unit will be a function of the underlying material and design of the membrane modules.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the flow of draw solution may be counter-current or co-current with respect to the feed water flow.
  • 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.
  • 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.
  • upstream and downstream valves and plumbing are included to allow feed and draw flow to bypass a given module in the series.
  • the membrane process contains two or more membranes arranged in a parallel configuration.
  • the membrane units are of equivalent design and performance specifications.
  • both the feed and draw solutions are equivalently split between each membrane in the parallel configuration.
  • 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.
  • the membrane process contains three or more membranes arranged in a combination of the series and parallel configurations described above.
  • 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.
  • 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.
  • 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.
  • the diluted draw solution must be processed to separate the switchable draw solute and the ionizing agent from the water.
  • 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.
  • 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.
  • 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.
  • 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.
  • the dissociation of the ionizing agent is an endothermic reaction, requiring the input of energy into the process.
  • 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.
  • 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.
  • 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.
  • 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.
  • a chiller or condenser 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.
  • 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.
  • 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.
  • 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.
  • this gas is an inert gas which includes but is not limited to nitrogen, oxygen, air, or steam.
  • the process to remove the ionizing agent is through the use of gas bubbling with CO 2 or a gas mixture with more than 1% CO 2 .
  • 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.
  • 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.
  • 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.
  • the diluted draw solution is regenerated to its concentrated form, following the extraction of produced water in the recovery system.
  • the recovered stream(s) containing the switchable draw solute and the ionizing agent are mixed with water to produce the concentrated draw solution stream.
  • 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).
  • 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.
  • the heat generated by the draw solution regeneration is utilized within the draw solution recovery process.
  • heat is transferred through the use of a heat transfer material (like water or a coolant) from one process to another.
  • a heat transfer material like water or a coolant
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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 CO 2 -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.
  • 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.
  • 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.
  • 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 CO 2 -laden source.
  • 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.
  • 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.
  • FO water treatment control system also includes means for manual interaction from human operators, including initiating safety and failsafe processes (HAZOPS).
  • control system for the forward osmosis sub-system sends sensor data and control operations to the control system on the overall water treatment system.
  • control system on the overall water treatment system also communicates information and control logic to the control system of the forward osmosis sub-system.
  • 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 CO 2 - laden streams from the co-located facility as described.
  • 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 CO 2 -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.
  • the overall control system monitors for potential security threats to the systems and interfaces to supervisory control and data acquisition (SCADA).
  • SCADA supervisory control and data acquisition
  • 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.
  • control system also includes means for manual interaction from human operators, including initiating safety and failsafe processes (HAZOPS).
  • HZOPS safety and failsafe processes
  • the overall control system including the individual control systems on each sub-system, can be monitored and controlled remotely.
  • 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.
  • 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.
  • 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.
  • 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 CO 2 -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.
  • 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 CO 2 -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.
  • 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.
  • two or more sources of water are processed by the water treatment system.
  • these sources include, at minimum, industrial and commercial wastewater and secondary and tertiary treated wastewater.
  • the method of the invention will produce clean water to the purity requirements of the application.
  • 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).
  • 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.
  • the water treatment system can produce two or more clean water streams of differing standards, such as potable and terti ary -treated streams.
  • 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;
  • Figure 1 shows a general amine-based scrubber system used for CCS.
  • An aqueous amine solution 2 is put into contact with a CO 2 -laden exhaust stream 4 in a gas contacting column 6, such as a packed bed.
  • CO 2 will be absorbed into the amine solution, while the remaining species such as nitrogen or oxygen, are not absorbed and are released as CO 2 -lean exhaust 10.
  • the amine solution carrying the CO 2 8 enters the desorption column 12, where heat or other energy sources are used to extract the CO 2 from solution.
  • the removed CO 2 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.
  • FIG. 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.
  • the first process 114 is the dissociation of CO 2 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 CO 2 and solute, so additional polishing stages are used to improve the purity of the clean water and recover more CO 2 and solute 122.
  • the effluent from polishing is the produced clean water from water treatment 124.
  • 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.
  • 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.
  • 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.
  • Figure 3 shows the modification of Figure 2 in an embodiment of the invention.
  • the removed CO 2 116 is split into two streams 162, some leaving the system as high purity CO 2 164, while the remaining fraction 166 returns to the regeneration process 128. Some or all of the removed CO 2 can be split as high-purity product.
  • the draw solution will selectively absorb CO 2 without any of the inerts or non-reactive species within the source stream.
  • the unabsorbed components will exit the process as exhaust 174.
  • Two additional unit operations may be necessary to include within this process, as depicted in Figure 3.
  • a pre-treatment step 180 may be necessary to remove these materials.
  • This pre-treatment process would use unit operations like adsorption beds or columns to strip out these components while leaving most of the CO 2 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 CO 2 will be compressed in subsequent processes as for sequestration.
  • 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 CO 2 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 CO 2 -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 CO 2 .
  • CO 2 -laden source 200 In addition to direct use of a CO 2 -laden source 170 without any additional treatment, one can also use a CO 2 -laden source 200 that may require additional pretreatment 202, such as the removal of combustible gases like methane, particulates or siloxanes. Further, pure CO 2 or a CO 2 -laden source may be stored on site 204 through compressed or cryogenic sources to supplement CO 2 for the CO process. A control system may be used to manage the consistency of the CO 2 flow from these multiple sources for the FO process.
  • 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.
  • EOR enhanced oil recovery
  • EGR enhanced gas recovery
  • ECMR enhanced coalbed methane recovery
  • FIG. 5a shows the current approach of EOR using CO 2 flooding.
  • An oil field 500 which has been exhausted of oil drilled by conventional means is flooded with compressed CO 2 506.
  • An external source of CO 2 502 is initially required, and either may be from natural CO 2 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 CO 2 from production well collection.
  • the CO 2 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 CO 2 throughout the well and prevent rapid CO 2 breakthrough.
  • the compressed CO 2 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 (CO 2 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 CO 2 522 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.
  • 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 CO 2 to the switchable FO process, with the natural gas components rejected by the draw solute and thus easily separated from the CO 2 .
  • the CO 2 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.
  • 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 CO 2 .
  • LFG landfill gas
  • 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 CO 2 .
  • 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% CO 2 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- CO 2 components of the exhaust (primarily nitrogen) 616 from the CO 2 614, 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.
  • 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.
  • 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 CH 4 stream 656 mostly free of CO 2 , and a CO 2 rich stream 658.
  • the high-purity CH 4 stream can be of appropriate quality to be injected into a natural gas pipeline.
  • 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.
  • 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 CO 2 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 CO 2 . The third row lists the maximum amount of CO 2 that would be separated and available for sequestration through this process. [00161] Table 1: Estimates of CO 2 Sequestration Capacity and Co-Located Support for a 100 gallon-per-minute SPS-based FO water purification plant coupled with a Co- Located Unit.
  • 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 CO 2 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 CO 2 exhaust from co-located plants ranging from 10 to 100 MW.
  • 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 CO 2 , exceeding the requirements for the water purification system.
  • additional CO 2 introduced this way will not be taken up by the SPS fluid; only the amount of CO 2 listed in the third row will be separated and ready to be sequestered.
  • the excess CO 2 in the co-generation plant exhaust will be left as emissions from this process if no additional sequestration is used.
  • the water purification plant would be sized appropriate for the co-located plant as to separate as much of the CO 2 from the co-located plant as possible.
  • 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 CO 2 that has already been separated from the exhaust of a power plant larger than 10 MW; the excess CO 2 during gassing will still remain pure and can be sequestered easily.
  • a modified switchable FO water treatment system is used to capture CO 2 from an external process stream as part of the process for regenerating the switchable FO draw solution.
  • the CO 2 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 CO 2 needs to be recycled if makeup CO 2 is available from a process stream.
  • This example demonstrates an estimate of the potential range of CO 2 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.
  • the draw solute is N,N-dimethylcyclohexyl amine (DMCHA).
  • DMCHA N,N-dimethylcyclohexyl amine
  • the concentrated form of the draw solution is taken as 77 wt% of DMCHA and CO 2 at a 1 : 1 molar ratio, following from the noted example. There would be 1.65 lb CO 2 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.
  • 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 CO 2 . 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.
  • the electrical requirements are between 1.8 and 2.6 kW e -hr/m 3 (0.00681 - 0.00984 kW e -hr/gal).
  • 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.
  • Power plants are a major source of CO 2 ; as of 2013, 37% of the CO 2 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.
  • CHP heat-and-power
  • a preferred embodiment of the invention is to use both the CO 2 and waste heat to drive the switchable FO process to also provide water treatment.
  • This example demonstrates a preferred embodiment of the invention of using the exhaust CO 2 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.
  • 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 CO 2 produced, based on the average heat duty for these plants and a 50% heat recovery assumption, are given in the table below:
  • 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 CO 2 available from the plant is used as makeup, and on the percentage of CO 2 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 CO 2 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.
  • Table 4 Estimation of Maximum Switchable FO Water Treatment Unit based on a Coal Power Plant
  • Table 5 Estimation of Maximum Switchable FO Water Treatment Unit based on a Natural Gas Power Plant
  • the outputs from the power plant and water treatment system can be compared on a per capita basis.
  • the average consumption of power per capita for residential users in 2013 was 66.9 MMBTU/yr, or 2.238 kW
  • the average consumption of water per capita for residential users in 2010 was 88 gal/day.
  • a 40 MW e electrical power plant can service approximately 178,000 people, and can also support a water treatment system with 100% CO 2 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.
  • Another metric to consider is the energy requirements for the CO 2 separation from the exhaust gas.
  • An amine scrubber system using 30 wt% monoethanolamine (MEA) as part of a CO 2 sequestration system for a coal -based power plant will use about 27% of the plant's gross power output to separate the CO 2 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 CO 2 per year, and will require a total of 136 MW of energy for CO 2 separation and sequestration, with 89.8 MW specifically for the separation process (no compression). This equates to a net 0.139 kW-hr/lb CO 2 energy requirement for CO 2 separation alone.
  • the combined electrical and thermal energy requirements using the high-end estimates are 9.96 MW for 84,800 lb/yr of CO 2 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 CO 2 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 CO 2 to improve its compressibility, such as the removal of water and other condensable fluids.
  • EOR Enhanced oil recovery
  • EGR enhanced gas recovery
  • ECMR enhanced coalbed methane recovery
  • 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 CO 2 for several benefits. When compressed to high pressures greater than 1200 psi, CO 2 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.
  • CO 2 flooding One preferred method of EOR is CO 2 flooding.
  • CO 2 flooding as illustrated in Figure 5a, compressed CO 2 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 CO 2 during the process. The water plug helps to prevent CO 2 from breaking through from the injection well to production well, bypassing the oil, and helps to spread the CO 2 across the entire oil bed to maximize the oil recovery process.
  • the production well will collect oil, CO 2 , 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 CO 2 and natural gas are further separated, with the purified CO 2 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 CO 2 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 CO 2 , providing an effective means of sequestration of CO 2 .
  • 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.
  • the required amount of CO 2 for EOR between new CO 2 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 CO 2 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 CO 2 per barrel of oil recovered with a use of 1.22 million lb CO 2 /day or 50,920 lb CO 2 /hr.
  • Water use for CO 2 flooding also varies based on the field and mobility requirements, with the ratio of water to CO 2 ranging between 0.5 and 5 on a volume basis.
  • the power requirements for EOR will vary by field, technology type, and other factors but is dominated by the power needed for compression of CO 2 for injection. It is estimated that 120 kW e -hr are needed per metric ton of CO 2 to be compressed, or 0.536 kW e - hr/lb CO 2 . 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.
  • Landfill gas 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% CO 2 , 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.
  • Methane is considered a potent greenhouse gas, and can impact global warming 25 times more than CO 2 . 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% CH 4 will produce about 2.88 lb CO 2 /kW-hr, a combination from the CO 2 already in the LFG and CO 2 generated by combustion.
  • burning LFG will release additional CO 2 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.
  • 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 CO 2 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.
  • the use of the switchable FO water treatment system is well suited to fit within the LFG frame work.
  • a second means of using LFG is to prepare the gas for injection into the natural gas pipeline. This step requires the removal of CO 2 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 CO 2 from the LFG is similar to options used for CO 2 sequestration, such as amine or physical scrubbers, water scrubbers, or membrane-based separation.
  • the switchable FO water treatment system offers another mean of removing CO 2 from the LFG while providing the treatment of impure water.

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  • Engineering & Computer Science (AREA)
  • Water Supply & Treatment (AREA)
  • Chemical & Material Sciences (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Hydrology & Water Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Organic Chemistry (AREA)
  • Separation Using Semi-Permeable Membranes (AREA)

Abstract

La présente invention concerne un système de purification d'eau et un procédé utilisant un solvant polaire commutable comme solvant d'extraction dans un procédé d'osmose directe (FO), intégrant l'échappement de déchets et des flux de chaleur issus d'installations colocalisées qui produisent de la chaleur et du CO2. La présente invention concerne la séparation à la fois de l'eau propre et du C02 pour des traitements ultérieurs et des applications du produit ou la séquestration.
PCT/US2016/013664 2015-01-16 2016-01-15 Système d'épuration d'eau par osmose directe sur la base de solvant polaire commutable, intégrant les flux de rejets thermiques provenant d'installations colocalisées avec séquestration de co2 WO2016115497A1 (fr)

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CN111573949A (zh) * 2020-05-27 2020-08-25 山东建筑大学 一种基于正渗透技术的页岩气压裂返排液处理系统和工作方法
WO2021029866A1 (fr) * 2019-08-09 2021-02-18 Saline Water Conversion Corporation Séquestration de dioxyde de carbone
US11306008B2 (en) 2020-03-19 2022-04-19 Kabushiki Kaisha Toshiba Working medium and water treatment system
EP3978101A4 (fr) * 2019-05-31 2023-07-19 Asahi Kasei Kabushiki Kaisha Système de concentration de solution de matière première
US11955782B1 (en) 2022-11-01 2024-04-09 Typhon Technology Solutions (U.S.), Llc System and method for fracturing of underground formations using electric grid power

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EP3978101A4 (fr) * 2019-05-31 2023-07-19 Asahi Kasei Kabushiki Kaisha Système de concentration de solution de matière première
WO2021029866A1 (fr) * 2019-08-09 2021-02-18 Saline Water Conversion Corporation Séquestration de dioxyde de carbone
US11306008B2 (en) 2020-03-19 2022-04-19 Kabushiki Kaisha Toshiba Working medium and water treatment system
CN111573949A (zh) * 2020-05-27 2020-08-25 山东建筑大学 一种基于正渗透技术的页岩气压裂返排液处理系统和工作方法
US11955782B1 (en) 2022-11-01 2024-04-09 Typhon Technology Solutions (U.S.), Llc System and method for fracturing of underground formations using electric grid power

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