WO2023097118A1 - Sustainable desalination systems and methods using carbon dioxide captured from a flue gas - Google Patents

Abstract

The present disclosure generally relates to a system. The system includes a flue gas production unit that receives an air flow and one or more hydrocarbons. The flue gas production unit generates a flue gas stream based on the air flow and the one or more hydrocarbons. The system also includes a caustic scrub system configured to receive the flue gas stream and a caustic stream, wherein the caustic scrub system is configured to generate a soda ash stream based on the flue gas stream and the caustic stream.

Description

SUSTAINABLE DESALINATION SYSTEMS AND METHODS USING CARBON DIOXIDE CAPTURED FROM A FLUE GAS

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application benefits from the priority of U.S. Provisional Patent Application No. 63/283,844, entitled “Sustainable Desalination Systems and Methods Using Carbon Dioxide Captured from a Cement Kiln,” filed November 29, 2021. This application also benefits from the priority of U.S. Provisional Patent Application No. 63/283,847, entitled “Sustainable Desalination Systems and Methods Using Glass Produced From Soda Ash,” filed November 29, 2021. Each of the foregoing applications is hereby incorporated by reference in its entirety.

BACKGROUND

[0002] The subject matter disclosed herein generally relates to a system for sustainable water desalination, and more specifically, to techniques for generating cement and soda ash.

[0003] There are several regions in the United States (e.g., the southwestern United States including New Mexico, Southern California, and parts of Texas) and throughout the world that experience shortages in potable water supplies due, in part, to the arid climate of these geographic locales. As water supplies are limited, innovative technologies and alternative water supplies for both drinking water and agriculture may be utilized. One method for obtaining an alternative source of potable water uses desalination systems to produce the potable water.

[0004] The desalination process may involve the removal of salts from seawater, agricultural run-off water, and/or brackish ground water brines to produce potable water. Membrane-based desalination may use an assortment of filtration methods, such as nanofiltration and reverse osmosis, to separate the raw brine stream into a desalinated water stream and tailing streams. The tailing streams may contain various salts and other materials left over after the desalination process. Included in these tailing streams may be valuable salts and minerals which may be extracted using membrane-based and/or evaporative techniques.

BRIEF DESCRIPTION

[0005] The present disclosure generally relates to a system. The system includes a flue gas production unit that receives an air flow and one or more hydrocarbons. The flue gas production unit generates a flue gas stream based on the air flow and the one or more hydrocarbons. The system also includes a caustic scrub system configured to receive the flue gas stream and a caustic stream, wherein the caustic scrub system is configured to generate a soda ash stream based on the flue gas stream and the caustic stream.

[0006] The present disclosure also generally relates to an additional system. The additional system includes a glass production unit that receives a soda ash stream and one or more minerals. The one or more minerals comprise limestone, gypsum, shale, sand, or a combination thereof. The glass production unit generates a flue gas stream based on the soda ash stream and the one or more minerals. The system also includes a caustic scrub unit configured to receive the flue gas stream and to generate a scrubbed nitrogen stream based on the flue gas stream. Further, the system includes a catalytic oxidizer unit disposed downstream from the caustic scrub unit, wherein the catalytic oxidizer unit is configured to receive the scrubbed nitrogen stream and to generate a crude nitrogen stream, wherein the crude nitrogen stream comprises relatively more nitrogen gas as compared to the scrubbed nitrogen stream.

[0007] The present disclosure also generally relates to an additional system. The system includes a glass production unit that receives a soda ash stream and one or more minerals, wherein the one or more minerals comprise limestone, gypsum, shale, sand, or a combination thereof. The glass production unit generates a flue gas stream based on the soda ash stream and the one or more minerals. The system also includes a caustic scrub unit configured to receive the flue gas stream and to generate a soda ash solution and a scrubbed nitrogen stream based on the flue gas stream. Further, the system includes a soda ash recovery system configured to receive the soda ash solution.

BRIEF DESCRIPTION OF THE DRAWINGS

[0008] These and other features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

[0009] FIG. 1A is a block diagram of an embodiment of a CO2 production system, in accordance with the present techniques;

[0010] FIG. IB is a block diagram of an embodiment of the CO2 production system of FIG. 1 A, in accordance with the present techniques;

[0011] FIG. 2 is a block diagram of an embodiment of a flue gas production system that may be used in the CO2 production system of FIGS. 1A and IB, in accordance with the present techniques;

[0012] FIG. 3 is a schematic diagram of an embodiment of a cement production system that may be used in the CO2 production system of FIGS. 1A and IB or the flue gas production system of FIG. 2, in accordance with the present techniques;

[0013] FIG. 4 is a schematic diagram of an embodiment of a catalytic oxidizer unit that may be used in the CO2 production system of FIGS. 1A and IB, the flue gas production system of FIG. 2, or the cement production system of FIG. 3, in accordance with the present techniques;

[0014] FIG. 5 is a schematic diagram of an embodiment of a selective catalytic reformer (SCR) unit that may be used in the CO2 production system of FIGS. 1A and IB, the flue gas production system of FIG. 2, or the cement production system of FIG. 3, in accordance with the present techniques;

[0015] FIG. 6 is a schematic diagram of an embodiment of a flue gas compression unit that may be used in the CO2 production system of FIGS. 1 A and IB, the flue gas production system of FIG. 2, or the cement production system of FIG. 3, in accordance with the present techniques;

[0016] FIG. 7 is a schematic diagram of an embodiment of a liquid nitrogen wash unit that may be used in the CO2 production system of FIGS. 1 A and IB, the flue gas production system of FIG. 2, or the cement production system of FIG. 3, in accordance with the present techniques;

[0017] FIG. 8 is a block diagram of an embodiment of a purge gas recovery unit that may be used in the CO2 production system of FIGS. 1A and IB, the flue gas production system of FIG. 2, or the cement production system of FIG. 3, in accordance with the present techniques;

[0018] FIG. 9 is a schematic diagram of an embodiment of a liquid nitrogen unit that may be used in the CO2 production system of FIGS. 1A and IB, the flue gas production system of FIG. 2, or the cement production system of FIG. 3, in accordance with the present techniques;

[0019] FIG. 10 is a schematic diagram of an embodiment of an ammonia production unit that may be used in the CO2 production system of FIGS. 1 A and IB, the flue gas production system of FIG. 2, or the cement production system of FIG. 3, in accordance with the present techniques;

[0020] FIG. 11 is a schematic diagram of an embodiment of a soda ash recovery unit that may be used in the CO2 production system of FIGS. 1 A and IB, the flue gas production system of FIG. 2, or the cement production system of FIG. 3, in accordance with the present techniques; [0021] FIG. 12 is a schematic diagram of an embodiment of a methanol production system that may be used in the CO2 capture system of FIGS. 1A and IB, in accordance with the present techniques;

[0022] FIG. 13 is a schematic diagram of an embodiment of a liquid oxygen production system that may be used in the CO2 capture system of FIGS. 1A and IB, in accordance with the present techniques;

[0023] FIG. 14 is a schematic diagram of a glass production unit that may be used in the CO2 capture system of FIGS. 1 A and IB, in accordance with the present techniques;

[0024] FIG. 15 is a schematic diagram of an embodiment of a carbon dioxide liquefaction unit that may be used in the CO2 capture system of FIGS. 1 A and IB, in accordance with the present techniques; and

[0025] FIG. 16 is a schematic diagram of an embodiment of a water cooling system that may be used in the CO2 capture system of FIGS. 1 A and IB, in accordance with the present techniques.

DETAILED DESCRIPTION

[0026] One or more specific embodiments of the present disclosure will be described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions may be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. [0027] When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.

[0028] At least in some instances, such as in arid locations, photovoltaic (PV) solar panels can generate power at a lower cost than fossil fuel based power plants. For example, a PV solar panel may use a bifacial design that enables sunlight to generate power from both sides of the silicon wafer. Such a PV solar panel may include glass on the front and back of the PV solar panel, which may protect the PV solar panel and substantially reduce a change in the opacity to the surface of the panel due to certain environmental conditions, such as sandstorms.

[0029] Sand having silica, soda ash, dolomite, limestone, and sodium sulfate may be used for generating glass. It is noted that soda ash, dolomite, and limestone are carbonates that emit CO2 when converted to their oxide glass components. Soda ash emits a relatively large amount (e.g., 1 ton) of CO2 per ton of soda ash during production. Additionally, soda ash may emit another 0.5 tons CO2 per ton of soda ash during glass production. The limestone and dolomite may add another 0.6 tons CO2 per ton of dolomite and limestone. The kiln fuel adds additional CO2, giving a total of approximately 1 ton CCb/ton glass for the kiln operation. Adding soda ash mining and processing, dolomite and limestone mining, and feed and product transportation may increase the total CO2 footprint to 2 tons CCb/ton glass. This CO2 emission may increase the cost of glass production significantly.

[0030] Processes for producing concrete also emit relatively large amounts of CO2 since the processes convert limestone to calcium oxide in a high temperature fossil fueled kiln. Glass reinforced polymer based composites may be used to replace cement and limit its growth. The polymer component may be produced from carbon captured from the glass component and cement production so that a net zero CO2 solution is theoretically possible for both cement and glass production. [0031] To achieve a net zero CO2 solution with a large glass production, green glass may be produced. This involves substituting caustic soda (NaOH) produced using renewable energy for remotely mined high CO2 emitting soda ash. Soda ash is typically cheaper than caustic soda; however, when a CO2 penalty is added for the soda ash production, the caustic soda option has better economics. Recent coal price increases due to limits on mine expansions have caused soda ash prices to increase versus caustic soda. This further increases the economic drivers to switch from soda ash to caustic soda.

[0032] Oxyfuel (i.e., oxygen replaces air) fired glass kilns may reduce fuel requirements as compared to air fired glass kilns by limiting flue gas heat losses. Oxyfuel fired glass kilns may also allow low cost flue gas CO2 capture when certain fuels, such as zero sulfur fuels, are used to fire the kiln. There may be limited particulate contamination since the solid feeds are melted in the kiln to produce glass. Most new glass kilns are designed for oxyfuel firing since the increased thermal efficiency pays for the oxygen. Oxyfuel essentially eliminates NOx emissions since there is no nitrogen present in the kiln. Oxyfuel kilns are considered best available technology due to the higher efficiency and lower emissions. Many new oxyfuel kilns are planned to meet the growing need for glass for PV panels and for glass reinforced polymer composites.

[0033] Electrically heated glass kilns are commercially available, but the cost of electricity may be higher than the cost of natural gas. Thus, it may be advantageous to fuel glass kilns with natural gas. While low cost daytime renewable energy may be available, glass kilns may have relatively long startup and shutdown times, and thus, it may be more efficient to have glass kilns running continuously.

[0034] Cement kilns may be fired with relatively low cost high sulfur fuels (e.g., coal or residual fuel oil). The cement components may not be melted, and the high lime content enables capture of much of the sulfur. Cement kilns can also serve as efficient thermal oxidizers (e.g., carbon recyclers) due to the high temperature, long residence time, and solids present. Scrap tires, plastic and hazardous organic materials can be used as supplemental fuel. However, the carbon in the feed may end up as a low purity CO2 stream with significant levels of SOx, NOx, particulates, CO, and unburned hydrocarbons. Air is typically used in the cement kiln since the low cost fuel does not justify the cost of oxygen for oxyfuel operation.

[0035] Accordingly, the present disclosure is directed to techniques for capturing CO2 from flue gas producing systems, such as cement kilns, ethylene crackers, and the like, using caustics produced from seawater desalination to produce soda ash. FIG. l is a block diagram of a CO2 capture system 10 including a first embodiment of a flue gas production system 12 and a glass production system 14.

[0036] In the illustrated embodiment of FIGS. 1A and IB, the CO2 capture system 10 includes a flue gas production unit 12 (e.g., cement kiln unit, an ethylene cracker unit, and the like), a caustic scrubber unit 18 (e.g., NaOH scrub), a catalytic oxidation and selective catalytic reformer (SCR) deoxidation unit 20 (e.g., Cat Ox and SCR Deox unit), a liquid N2 wash unit 22, a liquid nitrogen production unit 24, and an ammonia production unit 26 (e.g., electrolytically produced ammonia).

[0037] In general, and in embodiments in which the flue gas production unit 12 is a cement kiln unit, the flue gas production unit 12 receives a purge gas 53 (e.g., from the methanol production unit 84) mineral feedstocks 28 such as limestone, shale, slag, sand, and gypsum. The cement kiln also receives air 30 (e.g., an oxygen source) and a fossil fuel (e.g., relatively low value fossil fuels 32 such as petroleum coke, coal, and high sulfur fuel oil), waste materials (e.g., used tires, used plastic, certain organic chemical wastes), certain byproduct hydrocarbons such as fusel oil (i.e., mixed alcohols), and offgas purge from wet methanol distillation (e.g., during certain times of the day such as at night or during daylight hours). In some embodiments, the byproduct hydrocarbons may be produced by an e- methanol unit (e.g., methanol produced by electrolysis using hydrogen and captured CO2). In some embodiments, air 30 provided to the flue gas production unit 12 may be supplemented with oxygen. In any case, the flue gas production unit 12 generates a flue gas stream 34 and chemical products 36. The chemical products 36 may include cement, such as cement in embodiments in which the flue gas production unit 12 is a cement kiln. As another non-limiting example, the chemical products 36 may include glass, ethylene, or other products of flue gas producing systems.

[0038] The caustic scrubber unit 18 receives the flue gas stream 34 and an NaOH 38 stream). In general, the caustic scrubber unit 18 quenches and contacts the stack gas with a caustic solution (e.g., NaOH 38) to produce a soda ash solution 40 (e.g., 29 wt% Na2CO3, 1 wt% Na2SO3 solution). In some embodiments, the soda ash solution 40 may include limestone, sand, alumina fine particulates (e.g., electrostatic precipitator solids slip). In some embodiments, the soda ash solution 40 may be heated to produce a warm (e.g., approximately 70°C) solution, which may be contacted with oxygen to convert the Na2SO3 to Na2SO4. In any case, the solution may then be routed to a soda ash recovery unit 42 to evaporate the soda ash solution to produce and store crystalline (solid phase) soda ash. As illustrated, the glass production system 14 receives the crystalline soda ash 40a.

[0039] The flue gas stream 34 may include nitrogen (N2), carbon dioxide (CO2), water (H2O), sulfur dioxide (SO2), oxygen (O2), carbon monoxide (CO), nitrogen oxide species (NOx), other fluids (e.g., Argon), parti culate(s), or combination thereof. As such, the caustic scrubber unit 18 may remove the carbon and sulfur species (e.g., the SO2, CO, CO2) using the NaOH 38 to produce a scrubbed nitrogen stream 44. In general, the scrubbed nitrogen stream 44 may include the N2, O2, and Argon from the flue gas stream 34. For example, the scrubbed nitrogen stream 44 may include 97% N2, 1.5% Ar, and 1% O2.

[0040] In the illustrated embodiment, the catalytic oxidizer (CO), selective catalytic reduction (SCR) and catalytic deoxidation (CD) unit 20 receives the scrubbed nitrogen stream 44 (e.g., a first nitrogen stream). Additionally, the CO, SCR, CD unit 20 receives an ammonia stream 46 for the SCR and a hydrogen stream 48 for the CD. In general, the CO, SCR, CD unit 20 generates a crude nitrogen stream 50 (e.g., a second nitrogen stream) using the scrubbed nitrogen stream 44, the ammonia stream 46, and the hydrogen stream 48. The crude nitrogen stream 50 may include hydrogen (H2), N2, and Ar. The CO, SCR, CD unit 20 may remove the O2 from the scrubbed nitrogen stream 44 as a collected water condensate described in more detail with respect to FIG. 2. [0041] The liquid N2 wash unit 22 may further remove any residual oxygen containing fluids from the crude nitrogen stream 50, thereby producing a recycle Argon, N2, and O2 stream 52, a recycle CO and N2 stream 54, a high purity N2 stream 56, and a liquid argon stream 58. As a non-limiting example, trace CO2 and water vapor from the crude nitrogen stream 50 is removed in a temperature swing absorber (TSA) and together with TSA regeneration nitrogen is routed to the recycle Argon, N2, CO2, and O2 stream 52. As another non-limiting example, a portion of the high purity N2 stream 56 is compressed and recycle to the cold box to liquify all the non-nitrogen components except for the residual hydrogen, facilitating their removal from the high purity N2 stream 56.. As another nonlimiting example, trace oxygen and argon are purged from the argon recovery column as a bottoms component from the cold box and blended into the recycle Argon, N2, CO2, and O2 stream 52. Additional details regarding the liquid nitrogen wash unit are shown in FIG. 7. As illustrated, the flue gas production unit 12 may receive the recycle Argon, N2, CO2, and O2 stream 52and/or the CO and N2 stream 54 to produce additional flue gas. In some embodiments, the high purity N2 stream 56 may be stored in the liquid nitrogen production unit 24. In general, the liquid nitrogen production unit 24 may provide liquid N2 60 to other components described herein and/or receive gaseous N262 to produce liquid N2. The ammonia production unit 26 receives the high purity N2 stream 56 and/or a H2 and N2 stream 64 from the liquid nitrogen production unit 24. In turn, the ammonia production unit 26 generates the ammonia stream 46 (e.g., e-ammonia).

[0042] The glass production system 14 includes a glass kiln 66 that receives the crystalline soda ash solution 40a, photovoltaic (PV) power 68, a second mineral feedstock 70, an e-methanol stream 72, and an oxygen stream 74 (e.g., vaporized liquid oxygen stream). In turn, the glass kiln 66 generates a second flue gas stream 76. Additionally, the glass production system 14 includes a second NaOH scrub unit 78, a catalytic oxidation unit 80, a CO2 liquefaction and storage unit 82, a green H2 and methanol production unit 84, a liquid H2 unit 86, and a liquid O2 production unit 88. [0043] In a generally similar manner as described with respect to the caustic scrubber unit 18, the second NaOH scrub unit 78 generates a soda ash solution stream 90 and a scrubbed fluid stream 92. The catalytic oxidation unit 80 receives the scrubbed fluid stream 92. In general, scrubbed fluid stream 92 from the second NaOH scrub unit 78 may include CO, O2, and CO2. The catalytic oxidation unit 80 may include suitable catalysts for converting the CO and O2 into CO2, thereby producing a CO2 stream 94. The CO2 liquefaction and storage unit 82 receives the CO2 stream 94, where the CO2 may compressed to form a liquid CO2 stream 96. In some embodiments, the liquid CO2 may be stored and purge a gaseous CO2 stream containing impurities (e.g., trace O2, CO) stream 96a provided to other components of the flue gas production system 12 and/or the glass production system 14. For example, the purge gaseous CO2 stream 96a may be directed to the recycle CO and N2 stream 54.

[0044] As illustrated, the green H2 and methanol production unit 84 (e.g., e-methanol production unit) receives the liquid CO2 stream 96. Additionally, the green H2 and methanol production unit 84 receives PV power 68 (e.g., during the day) and water condensate 98. In turn, the green H2 and methanol production unit 84 generates a methanol stream 72, an O2 stream 100, and an H2 stream 102. The liquid O2 production unit 88 may receive and compress the O2 stream 100 to generate the O2 stream 74 (i.e., liquid O2 stream). Similarly, the liquid H2 unit 86 may receive and compress the H2 stream 102 to generate the H2 stream 48.

[0045] FIG. 2 is a block diagram of an embodiment of the flue gas production unit 12 of the CO2 capture system 10. In general, FIG. 2 shows more details regarding the catalytic oxidation (CO), SCR, and catalytic deoxidation (CD) unit 20 and the caustic scrubber unit 18. As illustrated, the flue gas production system 16 is a cement kiln unit 110, the caustic scrubber unit 18 (e.g., NaOH scrub), the catalytic oxidation and selective catalytic reformer (SCR) deoxidation unit 20 (e.g., Cat Ox, SCR Cat Deoxo unit), the liquid N2 wash unit 22, the liquid nitrogen production unit 24, and the ammonia production unit 26 (e.g., electrolytically produced ammonia). [0046] In general, the cement kiln unit 110 produces the flue gas stream 34, and the caustic scrubber unit 18 receives the flue gas stream 34. As illustrated, the caustic scrubber unit 18 generates multiple recycle condensation streams 112 that are directed upstream of the caustic scrubber unit 18. The caustic scrubber unit 18 produces the soda ash solution 40 and the scrubbed nitrogen stream 44 in a generally similar manner as described with respect to FIG. 1.

[0047] As illustrated, the catalytic oxidation and selective catalytic reformer (SCR) deoxidation unit 20 includes a catalytic oxidizer and SCR unit 114, a condenser 116, a compressor 118, a condenser unit 120, and a deoxidation unit 122. In general operation, the catalytic oxidizer and SCR unit 114 receives the scrubbed nitrogen stream 44 and ammonia stream 46. The catalytic oxidizer and SCR unit 114 converts hydrocarbons and CO to CO2, and converts NO and NO2 to N2 and H2O, thereby forming the crude nitrogen stream 50, which is a catalytically treated.

[0048] With regard to the caustic scrubber unit 18, warm flue gas stream 34 from the cement or lime kiln or other type of furnace may be routed to the first stage of the caustic scrubber unit 18 (e.g., water scrubbing section) where the flue gas is contacted with recirculating caustic and soda ash stream. The effluent gas is routed to the second sate where trace caustic mist and residual solids are scrubbed from the flue gas using recirculating which is fed by overflow water from the third stage and which overflows (purges) into the first stage. The warm water scrubbed flue gas from the water scrubbing section (second stage) is routed to a pump around condensing section (third stage). The hot condensate from the bottom of the condensing section may be routed through a chilled or cooling water cooler, cooled to 15-25°C and recirculated to the top of the condensing section. A cold condensate blowdown may be taken downstream of the chilled water cooler stream 134. In addition a small portion of the hot condensate overflows from the third stage to the second stage as makeup scrubbing water.

[0049] The recycle condensate stream 112 from the condensing section (e.g., approximately 97% nitrogen, 1.5% Ar, 1% oxygen, 0.5% water vapor) may be routed to an optional blower and then to a combined catalytic oxidizer (e.g., catalytic oxidizer unit) and selective catalytic reformer (SCR) unit 114 (e.g., catalytic reformer unit described in more detail with respect to FIG. 5). The recycle condensate stream 112 is reheated in a feed/product exchanger, further heated in a hot oil 135 exchanger and routed to a clean gas, high conversion, honeycomb type oxidation catalyst for conversion of unburned hydrocarbons and CO to CO2 using the residual oxygen in the flue gas. Within the catalytic oxidizer and SCR unit 114, the oxidation catalyst effluent is mixed with ammonia from an E-Ammonia plant and routed to a clean gas, high conversion, honeycomb type SCR catalyst for conversion of residual NO and NO2 to N2 and H2O. Additional details are described with respect to FIG. 5.

[0050] A higher than typical ammonia slip is used in the SCR (additional ammonia injected) to enhance (e.g., maximize) conversion of NO and NO2 to N2 and H2O. The excess ammonia stream 46 is recovered downstream and routed to agriculture as a fertilizer (see below). The treated flue gas (i.e., the crude nitrogen stream 50) from the SCR of the catalytic oxidizer and SCR unit 114 is routed through the condenser 116, which includes a feed product exchanger, and then to a second condensing section 120 using the same pump around condenser system described above. The stream 126 output from the condenser 116 is routed to the compressor 118, producing a compressed stream 128. The compressed stream is routed to the second condenser 120. The blowdown condensate 121 from the second condenser 120 contains ammonia and is routed to agriculture as an ammonia water fertilizer solution or as fertigation water. Additional details regarding the catalytic oxidizer unit are shown in FIG. 4, and additional details regarding the catalytic reformer unit are shown in FIG. 5.

[0051] The cooled flue gas from the second condensing column 120 may be routed to a compressor 118 which compresses the flue gas to 10 bar. Chilled water intercoolers and aftercoolers are used in the compressor to remove the residual water vapor as condensate 123 to agriculture (trace amounts of ammonia). [0052] The compressor discharge nitrogen stream 130 is routed to a catalytic deoxogenation system 122. In one example, a 1 mol% residual oxygen in the compressed and cooled flue gas stream 130 may be converted to water vapor, and any residual NO from the SCR (e.g., SCR unit 148 as described with respect to FIG. 5) may be converted to N2 and water vapor. Approximately 100% excess hydrogen may be used to ensure that essentially all the trace NO and O2 is removed from the flue gas. The resulting hydrogen concentration may be approximately 1 mol% in the effluent flue gas. This hydrogen may be recovered as product ammonia in a downstream ammonia plant. The deoxygenated flue gas may be cooled in a feed product exchanger and an aftercooler and routed to a liquid N2 wash unit, described in more detail with respect to FIG. 7.

[0053] FIG. 3 shows an example of cement kiln unit 110. In general, the illustration shows initial raw material is extracted from a quarry (top). Then, the raw material is provided to a mill, where the raw material is then crushed (top middle). Subsequently, fossil fuel (e.g., fossil fuel 32 as described in FIG. 1), such as coal, and/or other material sources, such as rubber, are added to a heated flow of the crushed raw material (top middle). Additionally, minerals (e.g., mineral feedstock 28 as described in FIG. 1), such as gypsum, are added (bottom middle). It is presently recognized that it may be advantageous to capture the CO2 during a pre-heat treatment before the crushed raw material is combined with the fossil fuel and/or minerals (bottom).

[0054] FIG. 4 is a schematic diagram of an embodiment of a catalytic oxidizer unit 114 (e.g., catalytic oxidizer and SCR unit 114 that may be used in the CO2 production system of FIG. 1, the flue gas production system of FIG. 2, or the cement production system of FIG. 3. In general, the catalytic oxidizer and SCR unit 114 may be used to convert certain carbon species, such as CO, in scrubbed nitrogen stream 44 to CO2. As shown, the catalytic oxidizer and SCR unit 114 receives the scrubbed nitrogen stream 44 and ammonia stream 46 into a heat exchanger 140. The combined gas flow 142 is provided to an oxidation catalyst region 144, thereby forming an oxidized scrubbed nitrogen stream 146, which includes CO2. It should be noted that it may be advantageous to use a catalytic oxidizer when the concentration of organic materials (e.g., hydrocarbons present in the scrubbed nitrogen stream 44) are within a particular range (e.g., 2500 ppm or less). As shown, the scrubbed nitrogen stream 44 and ammonia stream 46 are directed to a heater 143 disposed upstream of the oxidation catalyst region 144.

[0055] FIG. 5 is a schematic diagram of an embodiment of a catalytic oxidizer and selective catalytic reformer (SCR) deoxidation unit 20 that may be used in the CO2 production system of FIG. 1, the flue gas production system of FIG. 2, or the cement production system of FIG. 3. As illustrated, the catalytic oxidation and SCR deoxidation unit 20 includes an SCR unit 148 that is disposed downstream of the oxidation catalyst region 144. In general operation, the oxidation catalyst region 144 receives the scrubbed nitrogen stream 44, which may include NOx and CO. The oxidation catalyst region 144 oxidizes the CO, thereby forming the oxidized nitrogen oxide stream 146, which includes a relatively higher amount of CO2 as compared to the scrubbed nitrogen stream 44. The SCR unit 148 receives the oxidized scrubbed nitrogen stream 146 and reduces the nitrogen oxide species to nitrogen. Accordingly, the crude nitrogen stream 50 may contain N2 and H2O.

[0056] To further illustrate certain components that may be used in the disclosed techniques, FIG. 6 shows an example of a flue gas compression unit (e.g., flue gas production unit 12) that may be used in the that may be used in the CO2 production system of FIG. 1, the flue gas production system of FIG. 2, or the cement production system of FIG. 3. As shown, the flue gas compression unit 16 includes an air compressor 136, an air dryer/filtration unit 137, an air buffer 138, a nitrogen generator 139, and a nitrogen buffer 141. In general, the flue gas production unit 12 receives the air 30 as well as certain minerals (e.g., the mineral feedstock 28 and fossil fuel 32 as described with respect to FIG. 1) and generates the scrubbed nitrogen stream 34.

[0057] FIG. 7 is a schematic diagram of an embodiment of a liquid nitrogen wash unit that may be used in the CO2 production system of FIG. 1, the flue gas production system of FIG. 2, or the cement production system of FIG. 3. The liquid N2 wash unit 22 may have a temperature swing absorber unit which uses molecular sieves to absorb trace amounts of CO2 and water vapor to substantially reduce or eliminate freezing in the downstream cold box. The molecular sieves are periodically regenerated with heated high purity product nitrogen, and the low pressure residual stream is recycled to the flue gas production unit 12. In general, the liquid N2 wash unit 22 may remove residual impurities such as CO, Ar, and methane (CH4) from a crude nitrogen stream to produce a nitrogen stream suitable for ammonia production. It should be noted that CO should be removed since it may poison the ammonia synthesis catalyst.

[0058] In general, the crude nitrogen stream 50 (i.e., now compressed and cooled flue gas) may be routed to the absorber unit 150, which generally removes traces of water, CO2, and solvents (e.g., methanol). The absorber unit 150 may include a feed product exchanger and a hot oil trim heater to heat the high purity product nitrogen stream used for absorber regeneration. The absorber unit 150 generates a treated gas flow 152, which is received by the cold box 154.

[0059] In one example, a 1 mol% residual oxygen in the compressed and cooled flue gas 130 may be converted to water vapor, and any residual NO from the SCR (e.g., SCR unit 148 as described with respect to FIG. 5) may be converted to N2 and water vapor. Approximately 100% excess hydrogen may be used to ensure that essentially all the trace NO and O2 is removed from the flue gas. The resulting hydrogen concentration may be approximately 1 mol% in the effluent flue gas. This hydrogen may be recovered as product ammonia in a downstream ammonia plant. The deoxygenated flue gas may be cooled in a feed product exchanger and an aftercooler and routed to a liquid N2 wash unit, described in more detail with respect to FIG. 9.

[0060] The treated gas flow 152 from the temperature swing absorber of the absorber unit 150 is routed to the cold box 154 along with a portion of the product nitrogen that is compressed to a higher pressure (e.g., between approximately 20-40 barg). In the cold box 154, the feed streams are cooled against the product streams which liquefies the high pressure nitrogen stream. The liquified high pressure nitrogen stream is letdown across an expansion valve which further cools the liquid nitrogen. The liquid nitrogen is used to condense the trace amount of higher boiling components (e.g., argon and CO) in the main adsorbed flue gas feed.

[0061] An overhead vapor product 147 (e.g., > 99.99% N2+H2) is routed to the feed product exchangers and out of the cold box as product nitrogen 149. The liquid bottoms from the liquid N2 wash column 151 is routed to a CO and N2 column 153 which produces a fuel gas stream 157 of N2, CO and a portion of the argon. The overhead stream from the downstream argon column 155 provides the heat to vaporize the N2, CO and a portion of the argon from the liquid N2. The fuel gas stream is routed to the feed product exchangers and out of the cold box as recycle fuel gas to the flue gas production unit 12.

[0062] The bottoms from the CO and N2 column (argon and trace amounts of oxygen) is routed to an argon column which produces high purity liquid argon 58 (> 99.99% purity) for sale. The liquid nitrogen from the wash column provides the cooling sufficient to liquify the argon. In some embodiments, the argon column 155 bottoms are heated with a portion of the feed nitrogen to produce heat for the argon column 155 and a small purge oxygen and argon stream that is recycled to the flue gas production unit 12.

[0063] A small vapor purge may be taken from the e- Ammonia unit 26 to the CO and N2 recycle stream 54 as shown in FIG. 8. FIG. 8 is a block diagram of an embodiment of a purge gas recovery unit 160. In general, the purge gas recovery unit 160 may be used in conjunction with the ammonia production unit 26. As illustrated, the purge gas recovery unit 160 includes an ammonia recovery unit 162 and a gas recovery unit 164. In general, the ammonia recovery unit 162 may recover ammonia stream 46 from the purge gas. The residual, non-recovered gas is received by the gas recovery unit 164 that may recover H2 102, Ar stream 58, and/or N2 62.

[0064] The product high purity N2+H2 stream 166 (e.g., H2 102 and N2 62) may be routed to the ammonia production unit 26 and/or to a liquid nitrogen production unit 24. FIG. 9 is a schematic diagram of an embodiment of a liquid nitrogen production unit 24 that may be used in the CO2 production system of FIG. 1, the flue gas production system of FIG. 2, or the cement production system of FIG. 3. In general, the liquid nitrogen production unit 24 receives the high purity N2 stream 56 and generates liquid nitrogen 60. A cold box 168 and an expansion valve 170 or cryogenic expander may be used to produce liquid nitrogen 60 from the feed N2+H2 to the liquid nitrogen production unit 24. A N2+H2 purge stream may be taken from the liquid nitrogen vessel back through the cold box to purge hydrogen from the system. The N2+H2 purge stream is routed to an ammonia plant along with the main portion of the product high purity N2+H2 stream. The liquid nitrogen may be vaporized while producing chilled methanol 72 to provide backup and supplemental nitrogen to the ammonia plant in instances the flue gas production unit 12 cannot provide sufficient nitrogen. A portion of the liquid nitrogen may be used to help liquify green hydrogen (Fig 1, Unit 86). The liquid nitrogen provides precooling to the compressed gaseous hydrogen stream. The remaining cooling for hydrogen liquefaction is provided by the recompression, cooling and expansion of the recycle gaseous hydrogen. The gaseous nitrogen produced from precooling the compressed gaseous hydrogen stream is recompressed cooled with the methanol based thermal energy storage system and recycled to the cold box to produce liquid nitrogen.

[0065] FIG. 10 is a schematic diagram of an embodiment of an ammonia production unit that may be used in the CO2 production system of FIG. 1, the flue gas production system of FIG. 2, or the cement production system of FIG. 3. As shown in the illustrated embodiment, the ammonia production unit mixes the N2 + H2 mixture from the liquid nitrogen system, the N2 stream 62 from the liquid nitrogen wash system, and the hydrogen stream 48 from the electrolysis section of the methanol production unit 84 and routes them to a compression system. The N2 + H2 gas mixture 58 and 62 is compressed to high pressure (> 150 barg) and routed to a primary reactor system 171 which includes a feed preheater and heat recovery systems. The reactor effluent is cooled and product ammonia liquid 172 is condensed from the effluent. The residual N2 + H2 is recompressed and routed to an ammonia synthesis loop 173 (reactors and heat recovery) which produces additional product ammonia and recycles the residual N2 + H2 to substantial extinction. No or very small (< 0.1% of the feed gas) purge from the ammonia synthesis loop is taken and recycled back to the SCR (replaces a portion of the feed ammonia) or to the CD unit feed stream 130.

[0066] In any case, soda ash solutions stream 40 and 90 are produced by the caustic (e.g., NaOH) scrubber units 18 and 78 as illustrated in FIG. 1, which may be recovered by a soda ash recovery unit 42. FIG. 11 is a schematic diagram of an embodiment of a soda ash recovery unit that may be used in the CO2 production system of FIG. 1, the flue gas production system of FIG. 2, or the cement production system of FIG. 3. As illustrated, the soda ash recovery unit 42 includes mix tanks 180. The soda ash solution 40 from the caustic scrubber unit 18 may be routed to a soda ash recovery system feed mix tank 180 where the fresh and recycle feeds are mixed and the pH is adjusted to 12 by the addition of 30-35 wt% NaOH 184. Sodium hypochlorite 182 may be added to the feed mix tank 180 to convert any nitrites in the brine to nitrates and sulfites to sulfates. The mixture is then routed to an evaporative crystallizer 181. In the evaporative crystallizer the soda ash solution is evaporated in a multi-effect steam driven crystallizer or a mechanical vapor recompression (MVR) crystallizer to produce Na2CO3-H2O (sodium carbonate monohydrate). The insoluble material (e.g., mainly calcium carbonate) in the soda ash feed solution may also precipitate out with the sodium carbonate monohydrate. Sodium sulfate 183 may be contained in the sodium carbonate monohydrate.

[0067] The sodium carbonate monohydrate solids from the crystallizer centrifuge or filter are routed to a steam heated dryer to convert the sodium carbonate monohydrate to anhydrous sodium carbonate. The dried solids are fed to the glass kiln 66, replacing mined or synthetic sodium carbonate, and sodium sulfate and a small portion of the calcium carbonate typically fed to the glass kiln 66 described with respect to FIG. 1.

[0068] A purge may be taken from the first crystallizer 181 to substantially reduce the possibility that sodium chloride (e.g., trace component in the feed caustic to the cement kiln flue gas scrubber) crystallizes out with the sodium carbonate monohydrate. The purge stream is routed to a vacuum or surface cooled crystallizer operating at between approximately 10-30 °C using chilled water. The low temperature crystallizer produces sodium carbonate decahydrate and sodium sulfate decahydrate. The solids are mixed with a portion of the hot condensate from the first crystallizer to produce a warm (e.g., between approximately 35-50 °C) saturated brine that is recycled to the first crystallizer.

[0069] A purge is taken from the second crystallizer 185 to substantially reduce the possibility that sodium chloride crystallizes out with the sodium carbonate and sodium sulfate solids. The purge stream is routed to a third crystallizer 187 which is a multi-effect steam driven crystallizer or an MVR crystallizer to produce sodium chloride, which may be routed to a FULL RECOVERY DESALINATION® unit for purification to chemical grade salt for sale. A purge is taken from the third crystallizer to a second vacuum or surface cooled crystallizer operating at approximately 10-30°C using TES chilled water. The second low temperature crystallizer produces a mixture of sodium sulfate decahydrate and sodium nitrate. A purge from the fourth crystallizer is taken back to the third crystallizer to substantially reduce the possibility thatNaCl crystallizes out with the sodium sulfate decahydrate and sodium nitrate.

[0070] The sodium sulfate decahydrate and sodium nitrate solids are mixed with a small portion of the condensate produced in the sodium carbonate monohydrate and sodium chloride crystallizers and heated in a mix tank to 30-40 C to melt and redissolve the sodium sulfate and sodium nitrate. The brine is fed to a nanofiltration (NF) unit. The NF produces a purge sodium nitrate permeate stream and a sodium sulfate rich concentrate stream which is recycled back to the first reactor to produce sodium sulfate solids. The sodium nitrate permeate may be routed to an electrodialysis metathesis (EDM) unit along with a potassium chloride brine solution.

[0071] The ion pairs switch may switch within the EDM unit. For example, the potassium chloride is switched to a potassium nitrate brine and the sodium nitrate is switched to a sodium chloride brine. The potassium nitrate may be sold as a fertilizer solution, and the sodium chloride brine may be routed to a FULL RECOVERY DESALINATION® plant for purification and production of chemical grade NaCl for sale. [0072] The present techniques may provide a relatively low cost CO2 capture from a flue gas production unit 12 using caustic (e.g., NaOH) to produce low purity, low cost soda ash suitable for glass production. At least in some instances, it may be advantageous to use particulate contaminants from the flue gas production unit 12 and the captured SOx (e.g., as Na2SO4) as feedstocks to a glass kiln. The byproduct scrubbed nitrogen from the cement plant is purified to high purity nitrogen suitable for high efficiency purge free ammonia production without utilizing high cost oxygen co-production for which there is no market (excess oxygen is produced from electrolysis in an e-Methanol plant). High purity argon is a further byproduct of the nitrogen purification process. The flue gas production unit 12 may convert low value high sulfur fuel, waste tires, and plastics to CO2, which may be recycled to e-methanol while reducing (e.g., minimizing, substantially eliminating) emissions such as unbumed hydrocarbons, CO, SOx, NOx, particulate, and CO2. It is presently recognized that the embodiments of the present disclosure may provide profits from both gas sales (N2, Ar) and avoided CO2 offsets, which may be more than 5 times the profit from cement production alone.

[0073] FIG. 12 is a schematic diagram of an embodiment of a methanol production system 84 that may be used in the CO2 capture system of FIG. 1. In the illustrated embodiment, water 191 (e.g., high purity condensate or reverse osmosis permeate) from a desalination system is purified using Electrodeionization (EDI), which uses a combination of electrodialysis and ion exchange to purify the water (e.g., in the treatment unit). The purified water is routed to an electrolysis unit (e.g., water electrolysis), which uses photovoltaic (PV) power during daytime operation to produce hydrogen and oxygen. A portion of the hydrogen 48 is routed to the ammonia production unit 26 and the remainder routed to a feed gas compressor along 193 with CO2 96 from liquid storage (see below). The compressed mixture is routed to a methanol synthesis catalytic reactor which converts most (>80%) of the CO2 and hydrogen to methanol.

[0074] A high pressure (HP) separator separates the reactor effluent after heat recovery into recycle CO2 and hydrogen, and crude methanol plus water. The recycle CO2 and hydrogen is recompressed and recycled to the methanol reactor 84 . The crude methanol and water are flashed in an LP separator, and the flash gas and liquid streams are routed to a distillation section, which separates the feed into a low pressure recycle gas, a product high purity, low water content methanol, fusel oil 195 (e.g., mixed multi-carbon alcohols), and process water condensate. The fusel oil is routed to the flue gas production unit 12 as a liquid fuel and the process water condensate 196 is routed to agricultural irrigation.

[0075] At least a portion of the e-methanol plant (e.g., all units but the distillation unit which is operated night and day) may be operated during daytime when PV power based electrolyzers can produce hydrogen. During nighttime, the distillation unit may be used to separate the water from the wet methanol produced in the glass kiln flue gas drying column. During operation with this external feed, the low pressure recycle gas stream 53 is routed to the flue gas production unit 12 as fuel gas, since the methanol synthesis reactor is not operating and contaminants in the recycle gas stream from the wet methanol may poison the methanol reactor catalyst.

[0076] The e-methanol may be stored in a large tank to provide low cost seasonal (e.g., winter to summer) storage. This allows any excess electrical PV power generated during spring and fall to be stored in the form of e-methanol for winter use when less PV solar resource is available. A small (e.g., < approximately 5% of e-Methanol design) flow of hot (e.g., approximately 375 C) syngas from methanol decomposition (see below) may optionally be fed to the methanol synthesis reactor at night when Hz feed from PV powered electrolysis is not available. This keeps the reactor and heat recovery system warm, facilitating a more rapid restart when Hz feed from PV powered electrolysis is available.

[0077] FIG. 13 is a schematic diagram of an embodiment of a liquid oxygen production system 88 that may be used in the COz capture system of FIG. 1. As illustrated, the liquid oxygen production unit 88 includes compressors 118, a surge drum 200, a cold box 202, a liquid oxygen revaporizer 204, and a liquid Oz storage 206. Further, the liquid Oz production unit 88 includes an absorber unit 208, a pump 210 (e.g., a cryo pump), a blower 212, and heat exchangers 214. As shown, one or more of the heat exchangers 214 may be cooled with circulated water 132.

[0078] In general, oxygen 74 from the methanol production unit 84 is provided to a cold box 202 via the blower 212. Liquid nitrogen 60 is provided to the cold box 202, and the nitrogen 62, after being heated, may be directed to the liquid nitrogen production unit 24. The oxygen 74, when suitably cooled and pressurized, generates liquid oxygen 216. In some embodiments, a portion (e.g., between approximately 30-70%) of the byproduct oxygen produced in the e-methanol electrolysis section may be vented via 203 in certain instances, such as when significant hydrogen is produced for byproduct ammonia. A portion is pressurized in a blower and routed to the absorber unit 208, such as a Temperature Swing Absorber (TSA) unit similar to the one in the Liquid N2 Wash System, as described with respect to the liquid nitrogen system of FIG. 10, to remove water vapor to substantially reduce or eliminate ice formation in the downstream cold box. A portion of the product oxygen is heated using low pressure steam and used to regenerate the aluminosilicate based molecular sieves. The wet oxygen from regeneration is vented via 205.

[0079] Liquid nitrogen 60 from the liquid nitrogen production unit 24 is used to cool and liquify the low pressure oxygen from the absorber unit 208. The liquid oxygen is stored in a near ambient pressure liquid oxygen tank 206. A small portion of the oxygen is vented from the tank 206 through the cold box 202 to the feed blower 212 to maintain a relatively low temperature. During daytime operation when large amounts of oxygen are being liquified, the vaporized liquid nitrogen 62 from the cold box 202 (i.e., upstream of the liquid O2 storage 206) is recycled to the liquid nitrogen production unit 24. During nighttime operation, a small amount of oxygen is recirculated through the liquid oxygen storage vent 207, through the cold box 202, and back to the feed blower 212, and the small amount of vaporized liquid nitrogen sufficient to maintain liquid oxygen temperatures is vented. [0080] A liquid oxygen pump 210 may be used to pressurize the liquid oxygen to pipeline pressure (e.g., approximately 40 bar), and recirculated medium pressure (MP) (e.g., approximately 10 barg) nitrogen 62 from the surge drum 200 is used to heat the oxygen and recover the refrigeration duty. Revaporization may occur at night when supplemental fuel is utilized for the glass kiln. The cold MP nitrogen (e.g., approximately -100°C) is used to chill methanol from 0°C to -85°C which is stored in a thermal energy storage (TES) unit chilled methanol tank. The MP N2 from methanol chilling may be used to chill TES water, and the heated MP nitrogen is routed to a surge drum 200. From the surge drum 200, the MP nitrogen may be routed to a recirculation compressor 118 which circulates the nitrogen through the recirculation loop (e.g., through 204 and 202). Nitrogen may function as an intermediate between methanol and oxygen to substantially reduce or eliminate leakage of oxygen into the methanol system, which is pressurized above the nitrogen pressure. Backup nitrogen from the liquid nitrogen system (see above) is used to make up any nitrogen leaks in the nitrogen recirculation system.

[0081] As described above, the glass production system may include a glass kiln. A schematic diagram of an embodiment of the glass kiln is shown in FIG 14. Methanol from the e-Methanol system 84 (Fig 1) may be pumped to a medium pressure steam exchanger, and the methanol may be vaporized and heated to approximately 250°C. The heated vaporized methanol is then routed to a hot oil heated methanol decomposition catalytic reactor where the methanol is heated to 375°C and decomposed into CO + 2H2 (syngas). The medium pressure steam and hot oil are generated using flue gas heat from the glass kiln (see below).

[0082] In general, the glass kiln includes boilers 220a, 220b, and 220c, the glass kiln may use a combination of preheated syngas, heated and vaporized oxygen, and PV based daytime power in a hybrid electric + oxyfuel type glass kiln. The high temperature (e.g., 1500°C) effluent gas is used to heat the hot oil used for methanol reforming into syngas and to generate medium pressure steam, a portion of which is consumed in heating and vaporizing the methanol feed to the methanol decomposition reactor. Low pressure (e.g., atmospheric pressure) steam is produced in the final stage of flue gas heat recovery. The low pressure steam may be used to heat the TES return water 132 from 65°C to 75°C.

[0083] Due to the lack of nitrogen in the oxygen from electrolysis and lack of nitrogen in the methanol fuel, there may be very low NOx in the effluent flue gas from the glass kiln. The syngas fuel and oxyfuel operation reduces (e.g., minimizes) CO and unburned hydrocarbons. There is no or minimal SOx since the methanol is a sulfur free fuel.

[0084] The hybrid fuel (syngas/oxyfuel) and electric (daytime PV power) allows the glass kiln fuel flexibility. Whenever low cost PV power is available, its use is increased (e.g., maximized) and the syngas/oxyfuel is reduced to maintain the total heat flow sufficient for operation of the glass kiln.

[0085] The stack gas from the glass kiln at 120°C is routed to a caustic scrubber system, which quenches and contacts the stack gas with caustic to produce a 20 wt% NaHCOs solution containing trace amounts of NaHSCh, limestone, sand, and alumina fine particulates (e.g., fines from the glass kiln). The warm (e.g., 70°C) solution is routed to a soda ash recovery system (e.g. ‘soda ash’ as described with respect to FIG. 1 and 11).

[0086] The warm caustic scrubbed flue gas from the caustic contact section is routed to a water scrubbing section where trace caustic mist and residual solids are scrubbed from the flue gas. The warm water scrubbed flue gas from the water scrubbing section is routed to a pump around a condensing section where condensate is circulated through a packed section. The hot condensate from the bottom of the condensing section is routed through a chilled water cooler, cooled to 15°C, and recirculated to the top of the condensing section. A cold condensate blowdown is taken downstream of the chilled water cooler.

[0087] FIG. 15 is a schematic diagram of an embodiment of a carbon dioxide liquefaction unit 82 that may be used in the CO2 capture system of FIG. 1. In general, a the CO2 liquefaction and storage unit 82 generates high purity CO2 96 based on the CO2 stream 94. As illustrated, the CO2 liquefaction and storage unit 82 includes heat exchangers 214 (i.e., in thermal contact with water 132, the CO2 stream 94, or methanol 72), a CO2 stripper 230, and a CO2 liquid storage tank 232.

[0088] The compressed (e.g., 10 barg) crude CO2 (e.g., 99% CO2, 1% O2) may be cooled and condensed using -50 C methanol from a TES system 233 and CO2 stripper purge gas to -40 C. The crude CO2 may be flashed across an expansion valve and routed to a CO2 stripper operating at 6 barg and -52 C. Compressed CO2 vent gas may be used to strip the residual oxygen and any trace NO and CO from the CO2. The stripper overhead purge gas 231 may be used to cool the feed CO2, heated with TES water, and routed to the cement kiln.

[0089] The stripped CO2 liquid may be flashed across an expansion valve 235 into the CO2 liquid storage vessel 232 operating at 5 barg and -55°C. Trace amounts of liquid methanol and water (e.g., < 100 ppm) will be mixed with the CO2 (non-miscible). The flashed CO2 may be compressed via the compressor 118 and routed to the CO2 stripper 230 as stripping CO2.

[0090] During daytime when the e-Methanol plant is operated, liquid CO2232 from the storage vessel is heated and vaporized using the warm (e.g., 10°C) methanol from the TES system to produce chilled methanol (e.g., -50°C). The warm (e.g., 5°C) vaporized CO2 is compressed to 10 barg and routed to the e-methanol system 84.

[0091] FIG. 16 is a schematic diagram of an embodiment of a water cooling system that may be used in the CO2 capture system of FIG. 1. The water cooling system 249 includes a seawater cooling tower 250, a evaporator 251, a NF unit 254, a brine pretreatment system 255, and a crystallizer 257.

[0092] A zero discharge seawater cooling tower 250 may be used to provide cooling duty to the overall system. Pretreated seawater 252 from a FULL RECOVERY DESALINATION® system is mixed with sulfuric acid, sodium sulfate, and recycle sodium sulfate rich brine. A nanofiltration unit 254 may be used to separate the seawater 252 into NF concentrate 256, which is routed to a FULL RECOVERY DESALINATION® plant, as described in U.S. PCT Application 2022/025985, which is herein incorporated by reference in its entirety. The NF permeate 258 may be routed to the cooling tower 250 as makeup water.

[0093] Circulating cooling water 260 is routed to a chiller, which chills closed loop cooling water during daytime when low cost PV power is available in a TES tank from 35°C to 10°C. Another portion of circulating cooling water is routed to a feed water cooler on the return closed loop cooling water. TES closed loop chilled water (e.g., 10°C) is routed to the scrubbers, compressors, and other equipment of the flue gas production unit 12 and/or glass production unit 14.

[0094] Warm (e.g., 75°C) return closed loop cooling water 132 from the scrubbers, compressors, glass kiln, and other equipment is routed to a heat pump that extracts heat to produce 45 C return closed loop cooling water, which is routed to the seawater cooling water exchanger 259, and 100 C closed loop water/ethylene glycol mixture.

[0095] The cooling tower blowdown is chilled with 10°C TES closed loop cooling water from 30°C to 15°C and is routed to a multieffect distillation (MED) brine evaporator 251. The lower feed temperature enables the MED evaporator 251 to use more effects increasing water production per MWH of heat added. Hot water/ethylene glycol (e.g., 100°C) from the water/ethylene glycol TES tank with a supplemental LP steam trim heater is used to provide the heat to the MED evaporator 251. Cooling is provided by the cooling water blowdown feed.

[0096] The concentrated monovalent brine 261 from the MED evaporator (e.g., approximately 20 wt% total dissolved solids) may be routed to a monovalent brine pretreatment system, which produces Mg(OH)2, CaCCh, boron brine, sodium sulfate brine, and a purified monovalent brine. The purified monovalent brine is routed to a crystallizer 257 to produce high purity commercial grade NaCl. The blowdown brine is routed to a KC1 crystallizer in a FULL RECOVERY DESALINATION® plant. [0097] The condensate 262 from the MED evaporator and the NaCl crystallizer is recycled back to the cooling tower makeup. Optionally, the condensate can be exported as desalination water and additional NF permeate fed to the cooling tower to compensate for sections where it is desirable to have more water.

[0098] Technical effects of techniques described herein may provide relatively low cost daytime PV power to produce e-methanol and liquid hydrogen, and provide supplemental glass furnace heat. In some embodiments, e-methanol may be used in thermal energy storage (TES) systems to recover refrigeration duty during nighttime vaporization of hydrogen and CO2 for use in daytime liquefaction and storage. In some embodiments, e- methanol may be used as a drying agent for CO2 and nitrogen. This may substantially reduce or eliminate e-methanol contamination from other liquid drying agents (e.g., ethylene glycols), as well as substantially reduce or eliminate e-methanol catalyst contamination. In some embodiments, e-methanol and concentrated solar power (CSP) heat may be used to produce hot (e.g., > 400 C) syngas as the primary nighttime fuel for the glass kiln. The vaporization, heating, and decomposition process may increase the effective fuel heating value of the methanol, thereby increasing the glass kiln efficiency.

[0099] The techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical. Further, if any claims appended to the end of this specification contain one or more elements designated as “means for [perform]ing [a function], . .” or “step for [perform]ing [a function]...”, it is intended that such elements are to be interpreted under 35 U.S.C. 112(f). However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).

Claims

CLAIMS:

1. A system, comprising: a flue gas production unit configured to receive an air flow and one or more hydrocarbons, wherein the flue gas production unit is configured to generate a flue gas stream based on the air flow and the one or more hydrocarbons; and a caustic scrub system configured to receive the flue gas stream and a caustic stream, wherein the caustic scrub system is configured to generate a soda ash stream based on the flue gas stream and the caustic stream.

2. The system of claim 1 , comprising a catalytic oxidizer unit disposed downstream of the caustic scrub system, wherein the catalytic oxidizer unit is configured to receive the flue gas stream and to generate a nitrogen gas stream based on the flue gas stream.

3. The system of claim 2, comprising a nitrogen wash unit disposed downstream of the catalytic oxidizer unit, wherein the nitrogen wash unit is configured to generate a plurality of purge gas streams and a high purity nitrogen gas stream based on the flue gas stream.

4. The system of claim 3, comprising an ammonia production unit configured to receive the high purity nitrogen gas stream and to generate an ammonia stream based on the high purity nitrogen gas stream.

5. The system of claim 1, wherein the flue gas production unit comprises a cement production unit configured to receive one or more minerals, the one or more minerals comprise limestone, gypsum, shale, sand, or a combination thereof, and the cement production unit is configured to generate the flue gas stream and a particulate stream based on the one or more minerals.

29

6. The system of claim 1, comprising a glass production unit configured to receive the soda ash stream and one or more minerals, wherein the one or more minerals comprise limestone, gypsum, shale, sand, or a combination thereof, and the glass production unit is configured to generate glass and an additional flue gas stream based on the soda ash stream and the one or more minerals.

7. The system of claim 6, comprising a carbon dioxide liquefaction unit disposed downstream of the glass production unit, wherein the carbon dioxide liquefaction unit is configured to generate a liquid carbon dioxide stream based on the additional flue gas stream.

8. The system of claim 1, wherein the soda ash stream comprises sodium sulfate.

9. A system, comprising: a glass production unit configured to receive a soda ash stream and one or more minerals, wherein the one or more minerals comprise limestone, gypsum, shale, sand, or a combination thereof, and the glass production unit is configured to generate a flue gas stream based on the soda ash stream and the one or more minerals; a caustic scrub unit configured to receive the flue gas stream and to generate a scrubbed nitrogen stream based on the flue gas stream; and a catalytic oxidizer unit disposed downstream from the caustic scrub unit, wherein the catalytic oxidizer unit is configured to receive the scrubbed nitrogen stream and to generate a crude nitrogen stream, wherein the crude nitrogen stream comprises relatively more nitrogen gas as compared to the scrubbed nitrogen stream.

10. The system of claim 9, comprising a carbon dioxide liquefaction unit configured to generate a liquid carbon dioxide stream based on the crude nitrogen stream.

30

11. The system of claim 10, comprising an e-methanol production system configured to receive the crude nitrogen stream and to generate a methanol stream based on the crude nitrogen stream.

12. The system of claim 11, wherein the glass production unit is configured to receive the methanol stream.

13. The system of claim 9, comprising a soda ash production system disposed upstream of the glass production unit, wherein the soda ash production system comprises: a flue gas production unit configured to receive an air flow and one or more hydrocarbons, wherein the flue gas production unit is configured to generate an additional flue gas stream based on the air flow and the one or more hydrocarbons; and a caustic scrub system configured to receive the additional flue gas stream and a caustic stream, wherein the caustic scrub system is configured to generate the soda ash stream based on the flue gas stream and the caustic stream.

14. The system of claim 9, comprising an ammonia production unit configured to generate ammonia based on the crude nitrogen stream.

15. A system, comprising: a glass production unit configured to receive a soda ash stream and one or more minerals, wherein the one or more minerals comprise limestone, gypsum, shale, sand, or a combination thereof, and the glass production unit is configured to generate a flue gas stream based on the soda ash stream and the one or more minerals; a caustic scrub unit configured to receive the flue gas stream and to generate a soda ash solution and a scrubbed nitrogen stream based on the flue gas stream; and a soda ash recovery system configured to receive the soda ash solution.

16. The system of claim 15, comprising a catalytic oxidizer unit disposed downstream of the caustic scrub unit, wherein the catalytic oxidizer unit is configured to receive the scrubbed nitrogen stream and to generate a crude nitrogen stream, wherein the crude nitrogen stream comprises relatively more nitrogen gas as compared to the scrubbed nitrogen stream.

17. The system of claim 16, comprising a carbon dioxide liquefaction unit configured to receive the crude nitrogen stream and to generate a liquid carbon dioxide stream

18. The system of claim 17, comprising a methanol production unit configured to receive the liquid carbon dioxide stream and to generate methanol based on the liquid carbon dioxide stream.

19. The system of claim 18, wherein the methanol production unit is configured to generate a hydrogen gas stream, and the system comprises an ammonia production unit configured to receive the hydrogen gas stream and to generate ammonia based on the hydrogen gas stream.

20. The system of claim 15, comprising a soda ash production system disposed upstream of the glass production unit, wherein the soda ash production system comprises: a flue gas production unit configured to receive an air flow and one or more hydrocarbons, wherein the flue gas production unit is configured to generate an additional flue gas stream based on the air flow and the one or more hydrocarbons; and an additional caustic scrub unit configured to receive the additional flue gas stream and a caustic stream, wherein the additional caustic scrub system is configured to generate the soda ash stream based on the additional flue gas stream and the caustic stream.