Removal of greenhouse gases and heavy metals from an emission stream

Abstract

The present disclosure relates to a flue gas treatment system (e.g. a multi-pollutant flue gas treatment system) for removal of greenhouse gases such as SO.sub.2, NO, NO.sub.2, H.sub.2S, HCl, water and CO.sub.2 as well as heavy metals (e.g. mercury, arsenic, bismuth, cadmium, lead and/or selenium) from the flue gases of fossil-fueled utility and industrial plants by reacting the raw flue gas, firstly, with chlorine in a gas-phase oxidation reaction and recovering the resulting products as marketable products, and then, secondly, treating the cleaned gas, which includes CO.sub.2, with a Sabatier reaction to produce a hydrocarbon fuel (e.g. methane). The system also includes an electrolytic unit for electrolyzing HCl to produce hydrogen gas for the Sabatier reaction as well as chlorine gas, which may then be recycled into the reactor.

Claims

1. A system comprising: (a) a gas phase oxidation (GPO) reactor configured to receive a flue gas stream comprising NO.sub.x species and carbon dioxide gas, the GPO reactor further configured to receive chlorine gas, liquid or solution, and to oxidize the NO.sub.x species in the flue gas stream to produce a gas stream comprising nitric acid and hydrochloric acid, wherein the GPO reactor is configured to receive a chlorine gas stream; (b) an electrolytic unit configured to receive the hydrochloric acid and configured to electrolyse the hydrochloric acid to produce hydrogen gas and chlorine gas, optionally wherein at least a portion of the chlorine gas produced in the electrolytic unit is recycled into the GPO reactor; and (c) a Sabatier reactor configured to receive both a gas stream, downstream from the GPO reactor, and at least a portion of the hydrogen gas from the electrolytic unit, the Sabatier reactor further configured to hydrogenate the carbon dioxide gas in the gas stream into a hydrocarbon fuel comprising methane.

2. The system according to claim 1, further comprising a NO.sub.x absorber configured to receive a gas stream from (a) or downstream from (a), the NO.sub.x absorber further configured to oxidize and collect the NO.sub.x species remaining in the gas stream, wherein the system is further configured to direct at least a portion of hydrochloric acid from the NO.sub.x absorber to the electrolytic unit, optionally wherein the NO.sub.x absorber is configured in series between the GPO reactor and the Sabatier reactor.

3. The system according to claim 1, wherein the flue gas further comprises SO.sub.x species, and wherein the system further comprises a SO.sub.x absorber configured to receive a gas stream from (a) or downstream from (a), and further configured to oxidize and collect the SO.sub.x species in the gas stream as sulfuric acid.

4. The system according to claim 2, wherein the flue gas further comprises SO.sub.x species, and wherein the system further comprises a SO.sub.x absorber configured in series between the GPO reactor and the NO.sub.x absorber, the SO.sub.x absorber configured to receive a gas stream from (a) or downstream from (a), and further configured to oxidize and collect the SO.sub.x species in the gas stream as sulfuric acid, optionally: wherein the flue gas further comprises mercury and/or at least one heavy metal trace element and the SO.sub.x absorber is further configured to remove the mercury and/or the at least one heavy metal trace element.

5. The system according to claim 3, wherein the flue gas further comprises mercury and/or at least one heavy metal trace element, and wherein the SO.sub.x absorber is further configured to remove the mercury and/or the at least one heavy metal trace element.

6. The system according to claim 1, wherein the flue gas further comprises water vapour, and wherein the system further comprises a water vapour remover configured to remove the water vapour from the gas stream before (c), optionally wherein the water vapour remover is configured in parallel to the electrolytic unit.

7. The system according to claim 2, wherein the flue gas further comprises water vapour, and wherein the system further comprises a water vapour remover configured in series between the NO.sub.x absorber and the Sabatier reactor, optionally wherein the water vapour remover is configured in parallel to the electrolytic unit.

8. The system according to claim 1, wherein the Sabatier reactor uses a catalyst selected from the group consisting of a nickel catalyst, a ruthenium catalyst, an alumina catalyst, and a copper catalyst, optionally wherein the catalyst is the copper catalyst.

9. The system according to claim 1, further configured to direct the methane to a boiler or combustion chamber for combustion of the methane to generate heat or power.

10. The system according to claim 1, further comprising a compressor configured to condense liquefied natural gas from the methane.

11. A method of producing a hydrocarbon fuel, comprising methane, from a flue gas stream comprising NO.sub.x species, water vapour, and carbon dioxide gas, the method comprising: (a) generating hydroxyl radicals and chlorine radicals; (b) oxidizing the NO.sub.x species in the gas stream with the hydroxyl radicals and chlorine radicals to produce a gas stream comprising nitric acid and hydrochloric acid, water vapour and carbon dioxide gas; (c) removing the water vapour from the gas stream to produce a dehydrated gas stream; (d) producing hydrogen gas from electrolyzing the hydrochloric acid produced in (b), and optionally from electrolyzing the water vapour removed from the gas stream in (c); and (e) using a Sabatier reaction to hydrogenate the carbon dioxide gas in the dehydrated gas stream from (c) with the hydrogen gas produced in (d) to produce the hydrocarbon fuel.

12. The method according to claim 11, wherein the flue gas stream further comprises SO.sub.x species, and wherein the method further comprises oxidizing the SO.sub.x species to produce sulfuric acid, and removing the sulfuric acid from the gas stream to produce a gas stream that is substantially free of SO.sub.x species.

13. The method according to claim 12, wherein the flue gas stream further comprises trace elements selected from a group consisting of antimony, arsenic, cadmium, chromium, nickel, selenium, zirconium, and any combination thereof, and wherein the method further comprises removing the trace elements from the gas stream by capturing the trace elements in the sulfuric acid, and wherein the method optionally further comprises removing the trace elements from the sulfuric acid by ion exchange.

14. The method according to claim 12, the flue gas stream further comprising mercury, and wherein the method further comprises removing the mercury from the gas stream, wherein removing the mercury optionally comprises converting the mercury to HgCl.sub.2 and capturing the HgCl.sub.2 in the sulfuric acid, and wherein the method optionally further comprises recovering the mercury from the sulfuric acid.

15. The method according to claim 11, further comprising further oxidizing the NO.sub.x species with steam to produce hydrochloric acid and a gas stream that is substantially free of NO.sub.x species.

16. The method according to claim 15, further comprising using chlorine gas produced from (d) to generate at least some of the chlorine radicals in (a).

17. The method according to claim 11, wherein (d) comprises electrolyzing the water vapour removed from the gas stream in (c), the electrolyzing of the water vapour also producing oxygen gas, and wherein the method optionally further comprises directing the oxygen gas from (d) to aid in combustion of a fuel to generate heat or power.

18. The method according to claim 11, wherein the Sabatier reaction is catalysed by a catalyst selected from the group consisting of a nickel catalyst, a ruthenium catalyst, an alumina catalyst, and a copper catalyst.

19. The method according to claim 11, further comprising compressing the methane to reduce the volume of the methane or condensing the methane to produce liquefied natural gas.

20. The method according to claim 11, further comprising combusting the methane to generate heat or power, optionally wherein the methane is blended and co-fired with another hydrocarbon fuel that is optionally selected from coal or gas.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) In the accompanying drawings, which illustrate one or more exemplary embodiments:

(2) FIG. 1 is a flue gas treatment system for use in a coal-firing facility according to an embodiment, the treatment system comprising a gas phase reactor, a SO.sub.x absorber, a NO.sub.x absorber, a water vapour remover, and a carbon dioxide absorber.

(3) FIG. 2 is a schematic of a flue gas treatment system for use in a gas-burning facility according to another embodiment, the treatment system comprising a gas phase reactor, a NO.sub.x absorber, a water vapour remover, and a carbon dioxide absorber.

DETAILED DESCRIPTION

(4) Directional terms such as “top”, “bottom”, “upwards”, “downwards”, “vertically”, and “laterally” are used in the following description for the purpose of providing relative reference only, and are not intended to suggest any limitations on how any article is to be positioned during use, or to be mounted in an assembly or relative to an environment.

(5) Any element expressed in the singular form also encompasses its plural form. Any element expressed in the plural form also encompasses its singular form. The use of the word “a” or “an” when used herein in conjunction with the term “comprising” may mean “one”, but it is also consistent with the meaning of “one or more”, “at least one”, and “one or more than one”.

(6) As used herein, the terms “comprising”, “having”, “including”, and “containing”, and grammatical variations thereof, are inclusive or open-ended and do not exclude additional, un-recited elements and/or method steps. The term “consisting essentially of” when used herein in connection with a composition, use or method, denotes that additional elements, method steps or both additional elements and method steps may be present, but that these additions do not materially affect the manner in which the recited composition, method or use functions. The term “consisting of” when used herein in connection with a composition, use or method, excludes the presence of additional elements and/or method steps.

(7) As used herein, the term “about” when followed by a recited value means plus or minus 10% of the recited value.

(8) The present disclosure relates to a system and a method for removing greenhouse gases and other pollutants from an emission stream (e.g. flue gas). Greenhouse gases and other pollutants may include, without limitation, one or more of: SO.sub.x (e.g. SO.sub.2), NO.sub.x (e.g. NO, NO.sub.2), H.sub.2S, water vapour, carbon dioxide, heavy metals (e.g. mercury), soot, smoke, dust, and trace elements.

(9) The present disclosure also relates to systems and methods for removing water vapour and carbon dioxide gas from the emission stream (e.g. flue gas), and for converting the carbon dioxide gas into a hydrocarbon fuel via the Sabatier process. It is contemplated that the system may be able to internally produce a large enough volume of hydrogen gas to drive the Sabatier process and remove carbon dioxide gas from the emission stream. It is also contemplated that the Sabatier process may be incorporated into an industrial scale setting and be economically competitive against conventional emission stream treatment methods.

(10) Emission streams may be pre-cleaned through an electrostatic precipitator (an “ESP”), as known in the art, to remove fine particles such as, but not limited to, dust, soot, smoke, and trace elements. Trace elements include, but are not limited to, antimony, arsenic, cadmium, chromium, nickel, selenium, and zirconium, all of which have been identified as elements that have detrimental impacts on the environment and human health. However, even if the ESP operates at about 99% efficiency, a portion of these trace elements pass through the ESP. The remaining trace elements are captured in sulfuric acid produced by the oxidation of SO.sub.x species (described below) where they may be removed by ion exchange.

(11) NO.sub.x species in the emission stream may be oxidized to produce hydrochloric acid and nitric acid. The produced nitric acid may be sold as is, and the produced hydrochloric acid may be electrolyzed to produce hydrogen gas and chlorine gas. The hydrogen gas may be used to hydrogenate the carbon dioxide gas present in the flue gas to a hydrocarbon fuel. The chlorine gas may be used to generate chlorine radicals required in the oxidation of SO.sub.x species, NO.sub.x species, and heavy metals (e.g. mercury) present in the emissions stream.

(12) Water vapour in the emission stream may be removed from the emission stream and electrolyzed to form hydrogen gas and oxygen gas. The hydrogen gas may be used to hydrogenate the carbon dioxide gas present in the emission stream to a hydrocarbon fuel. The oxygen gas may be directed to a furnace of the system to aid in combustion or sold.

(13) The hydrocarbon fuel produced from the hydrogenation of carbon dioxide via, for example, the Sabatier process may be condensed further to reduce gas volumes and to aid in storage and transport. In some instances, produced hydrocarbon fuel may be condensed up to about 600%.

(14) Thus, various embodiments of the present disclosure relate to a system, e.g. a flue gas treatment system configured for use with a coal-firing facility or a gas-burning facility. The system includes, at a minimum: (a) a gas phase oxidation (GPO) reactor (referred elsewhere herein as a “gas phase reactor”), (b) an electrolytic unit, and (c) a Sabatier reactor (also referred to herein as a “carbon dioxide absorber”). The flue gas may be from a coal-firing plant or a gas-burning plant, or from any other flue gas source. In some embodiments, the flue gas will have been pre-cleaned as described above (e.g. through an ESP). The flue gas comprises NO.sub.x species (e.g. NO, NO.sub.2), and carbon dioxide gas and may further comprise one or more of: water vapour, SO.sub.x species (e.g. SO.sub.2), mercury and/or heavy metal trace elements. In some embodiments, the flue gas comprises SOx species, NO.sub.x species, water vapour, mercury, carbon dioxide gas and may further comprise heavy metal trace elements.

(15) In some embodiments, the system further includes water vapour remover. In some embodiments, the system further includes a NO.sub.x absorber. In some embodiments, the system further includes a SOx absorber. In some embodiments, the system includes: a GPO reactor, a SOx absorber, a NO.sub.x absorber, an electrolytic unit, a water vapour remover and a Sabatier reactor. Primary products of these systems are nitric acid and methane, the latter of which may be used on site, stored compressed or converted to liquefied natural gas (LNG). For any of the above embodiments, the system may thus further comprise a compressor for compressing the methane or a condenser for condensing the methane into LNG. Depending on the components of the flue gas, other products of these systems may include sulfuric acid and/or mercury. HCl and H.sub.2(g) are also produced, and in certain embodiments may be recycled into the system. O.sub.2 (g) may also be produced, and in certain embodiments may be recycled into the system.

(16) The GPO reactor is configured to receive a flue gas stream, and is further configured for oxidation of the NO.sub.x species in the flue gas. In some embodiments, for example, the GPO reactor is configured to further receive chlorine (as gas, a liquid or in solution), which oxidizes the NO.sub.x species in the flue gas to produce a gas stream (i.e. a product gas stream) which comprises, among other things, nitric acid and hydrochloric acid.

(17) In some embodiments, the chlorine is a chlorine gas and the GPO reactor is configured to receive a chlorine gas stream. In such embodiments, chlorine gas and flue gas may be: (i) delivered into the GPO reactor operating at pre-set reaction conditions; and (ii) mixed in the GPO reactor. The GPO reactor may be a reactor that is known in the art, such as a commercially available gas phase reactor that can adequately mix the gases. Appropriate reaction conditions are also known in the art (see for example U.S. Pat. No. 4,619,608). For example, the GPO reactor may be set at a temperature between about 100° C. and about 650° C. For example, the temperature of the GPO reactor may be set at about 100° C., 125° C., 150° C., 175° C., 200° C., 225° C., 250° C., 275° C., 300° C., 325° C., 350° C., 375° C., 400° C., 425° C., 450° C., 475° C., 500° C., 525° C., 550° C., 575° C., 600° C., 625° C., 650° C., or any temperature therebetween.

(18) At elevated temperatures in the GPO reactor, it is believed that chlorine gas reacts with water vapour in the flue gas to generate chlorine radicals and hydroxyl radicals. The NO.sub.x species or a portion thereof present in the flue gas is oxidized in the GPO reactor in the presence of the generated chlorine radicals and the generated hydroxyl radicals. Using nitric oxide (NO) as an non-limiting example of a NO.sub.x species, and without wishing to be bound by theory, it is believed that nitric oxide (NO) in flue gas is oxidized to nitric acid (HNO.sub.3) and hydrochloric acid in the GPO reactor according to the following chemical reactions:
NO+.Math.OH.fwdarw.HNO.sub.2;  6.
NO+.Math.Cl.fwdarw.NOCl;  7.
NOCl+H.sub.2O.fwdarw.HNO.sub.2+HCl;  8.
HNO.sub.2+.Math.Cl.fwdarw.NO.sub.2+HCl;  9.
NO.sub.2+.Math.OH.fwdarw.HNO.sub.3;  10.
NO.sub.2+.Math.Cl.fwdarw.NO.sub.2Cl;  11.
NO.sub.2Cl+H.sub.2O.fwdarw.HNO.sub.3+HCl.  12.

(19) Without being bound by theory, it is also believed that the oxidized forms of polluting species are more readily removable from flue gas than the non-oxidized forms thereof. In addition, it is believed that the predominant final products of NO.sub.x removal are nitric acid and hydrochloric acid. The gas stream exiting the GPO reactor (i.e. the product gas stream) thus comprises dissolved nitric acid and hydrochloric acid and other pollutants (e.g. CO.sub.2 (g), and in some cases one or more of water vapour, sulfuric acid, HgCl.sub.2, trace heavy metals, and may further include remaining non-oxidized NO.sub.x species, SO.sub.x species, and/or non-chlorinated mercury.

(20) The product gas stream may be substantially free of NO.sub.x species or may benefit from further oxidation to yield a product gas stream that is substantially free of NO.sub.x species. When present in the flue gas, SOx species will also be oxidized in the GPO reactor, forming sulfuric acid. In such case, the product gas stream may be substantially free of SO.sub.x species or may benefit from further oxidation to yield a product gas stream that is substantially free of SO.sub.x species.

(21) For example, in some embodiments (e.g. when the flue gas comprises SO.sub.x species), the system may further comprise a SO.sub.x absorber configured to receive the product gas stream from the GPO reactor or a further processed gas stream, downstream from the GPO reactor. Such systems may further include a NO.sub.x absorber. For example, the SO.sub.x absorber may be positioned in series between the NO.sub.x absorber and the GPO reactor. In some embodiments, the system further includes a SO.sub.x absorber and does not include a NO.sub.x absorber. For example, the SO.sub.x absorber may be positioned in series between the GPO reactor and the Sabatier reactor, or between the GPO reactor and a water vapour remover.

(22) In embodiments that further comprise a SO.sub.x absorber, SO.sub.x absorber may be configured to receive the product gas stream from the GPO reactor or a further processed gas stream, downstream from GPO reactor, and may be further configured to collect from the gas stream the oxidized SO.sub.x species converted in the GPO reactor.

(23) The SO.sub.x absorber may be any suitable absorber that is known in the art. For example, the SO.sub.x absorber may be one that is substantially similar to the one described in U.S. Pat. No. 4,619,608 both in design and reaction conditions. The SO.sub.x absorber may achieve SO.sub.2 capture rates of above 99% without producing CO.sub.2 as a by-product. Where CO.sub.2 capture and storage by sequestration is desired, SO.sub.x limits of 10 ppm or below may be required. Conventional limestone scrubbers may not remove SO.sub.2 from flue gas with the same efficiency.

(24) The SO.sub.x absorber may be arranged horizontally or vertically, depending on spatial restrictions or requirements of the system. The SO.sub.x absorber may also comprise packed towers or cross-flow vessels that condense and collect one or more resulting acid streams, e.g. one or more of sulfuric acid, nitric acid, hydrochloric acid, and/or other acid streams, and may further collect as mercury products and/or trace heavy metal products. The SO.sub.x absorber may be a single integrated absorber or consist of a plurality of non-integrated components. The SO.sub.x absorber may be a single SO.sub.x absorber unit, or may comprise a plurality of SO.sub.x absorber units.

(25) In addition to oxidizing NO.sub.x species, the conditions in the GPO reactor also oxidize SOx species. In the SO.sub.x absorber, additional solution chemistry may occur to aid in oxidation and/or collection and to build up the strengths of the acids. For example, but without limitation, water may circulated in the SO.sub.x absorber or steam may be sprayed into the SO.sub.x absorber. This oxidation process converts SO.sub.x species to sulfuric acid so as to convert the remaining SO.sub.x species to sulfuric acid. In the presence of steam, SO.sub.x generally reacts in preferential order over NO.sub.x. Using sulfur dioxide (SO.sub.2) as a non-limiting example of a SO.sub.x species, and without wishing to be bound by theory, it is believed that the sulfur dioxide is oxidized to sulfuric acid (H.sub.2SO.sub.4) in the SO.sub.x absorber according to the following chemical reaction:
SO.sub.2+Cl.sub.2+2H.sub.2O.fwdarw.H.sub.2SO.sub.4+2HCl  13.
SO.sub.2 removal rates of about 99% may be achieved at Cl.sub.2 levels as low as 1.0 Cl.sub.2/SO.sub.2 molar ratio. An equilibrium concentration of about 70% or higher H.sub.2SO.sub.4 to H.sub.2O may also be achieved. The collected mixture of H.sub.2SO.sub.4/H.sub.2O may be further treated by a process to remove H.sub.2O, thereby concentrating the remaining sulfuric acid to a purity of up to about 93-96% (commercial grade). The purified H.sub.2SO.sub.4 may then be collected and shipped to industry for sale. Accordingly, in certain embodiments, the system may further comprise means for removing water from the mixture of H.sub.2SO.sub.4/H.sub.2O.

(26) In some embodiments (e.g. when the flue gas further comprises mercury), the SO.sub.x absorber may be further configured to remove the mercury. For example, but without limitation, the HgCl.sub.2 produced by halogenation reaction in the GPO reactor, and/or produced in the SO.sub.x absorber itself, may be captured in the condensed sulfuric acid that is collected by the SO.sub.x absorber. The SO.sub.x absorber may be further configured to convert metallic mercury remaining in the gas stream to HgCl.sub.2 and to collect the produced HgCl.sub.2. Mercuric halides (e.g. mercuric chloride) in the sulfuric acid (wherever produced) may be separated out using various methods, e.g. but not limited to, any described in PCT/CA1999/000403. In one non-limiting example, an alkali metal halogen (e.g. potassium iodide) salt is added to precipitate mercuric iodide (see PCT/CA1999/000403). In other embodiments, the system may not be configured for heavy metal removal. Yet in other embodiments, mercury recovery from the collected sulfuric acid may occur at an off-site location.

(27) In some embodiments (e.g. when the flue gas further comprises at least one heavy metal trace element), the SO.sub.x absorber or the system may be further configured to remove the at least one heavy metal trace element (e.g. one or more of antimony, arsenic, cadmium, chromium, nickel, selenium, and zirconium). For example, but without limitation, the trace elements may be captured in the sulfuric acid produced from oxidizing the SO.sub.x species and condensed in the SO.sub.x absorber. In some embodiments, the system further comprises means for removing the trace elements from the sulfuric acid by ion exchange. In other embodiments, trace element removal may not occur. Yet in other embodiments, trace element removal may occur at an off-site location.

(28) As discussed, in some embodiments the system may further comprise a NO.sub.x absorber configured to receive the product gas stream from the GPO reactor or a further processed gas stream, downstream from the GPO reactor (e.g. a gas stream exiting a SO.sub.x absorber). As discussed, such systems may further include a SO.sub.x absorber. For example, the NO.sub.x absorber may be positioned in series between the SO.sub.x absorber and the Sabatier reactor, or between the SO.sub.x absorber and a water vapour remover. In some embodiments, the system further includes a NO.sub.x absorber and does not include a SO.sub.x absorber. For example, the NO.sub.x absorber may be positioned in series between the GPO reactor and the Sabatier reactor, or between the GPO reactor and a water vapour remover.

(29) The NO.sub.x absorber is further configured to collect oxidized NO.sub.x species converted in the GPO reactor. The NO.sub.x absorber may be any absorber that is known in the art to be suitable for this purpose. For example, the NO.sub.x absorber may be one that is substantially similar to the one described in U.S. Pat. No. 4,619,608 both in design and reaction conditions. NO.sub.x removal efficiency of about 98% may be achieved by the combination of a GPO reactor and a NO.sub.x absorber. When no ammonia is used in a NO.sub.x absorber, there is no ammonia slip. The NO.sub.x absorber may be arranged horizontally or vertically, depending on spatial restrictions or requirements of the system. The NO.sub.x absorber may also comprise packed towers or cross-flow vessels that condense and collect nitric acid, hydrochloric acid, as well as heavy metal products (e.g. HgCl.sub.2). In some embodiments, the NO.sub.x absorber is a plurality of NO.sub.x absorber units. In some embodiments, the NO.sub.x absorber may be a single NO.sub.x absorber unit.

(30) In some embodiments, the NOx absorber may be further configured to further oxidize NO.sub.x species that may remain in the product gas stream (e.g. from the GPO reactor) or in the further treated gas stream (e.g. from the SO.sub.x reactor), so as to convert the remaining NO.sub.x species to nitric acid and hydrochloric acid. For example, the gas stream entering the NO.sub.x absorber may be sprayed with steam to further oxidize the NO.sub.x species. The gas stream may be sprayed with steam at a non-zero angle (e.g. orthogonally). The gas stream may be sprayed with steam at a suitable spraying pressure. Without being bound by theory, it is believed that the following reactions are involved in the removal of NO.sub.x species from gas stream in the NO.sub.x absorber:
Cl.sub.2+H.sub.2O.fwdarw.HOCl+HCl  14.
NOCl+H.sub.2O.fwdarw.HNO.sub.2+HCl  15.
NOCl+HOCl+H.sub.2O.fwdarw.HNO.sub.3+2HCl  16.
NO.sub.2Cl+H.sub.2O.fwdarw.HNO.sub.2+HOCl  17.
2NO.sub.2+H.sub.2O.fwdarw.HNO.sub.2+HNO.sub.3  18.
HNO.sub.2+HOCl.fwdarw.HNO.sub.3+HCl  19.
2NO+H.sub.2O+HNO.sub.3.fwdarw.3HNO.sub.2  20.
It is thus believed that the predominant final products of NO.sub.x removal are nitric acid and hydrochloric acid.

(31) The NO.sub.x absorber may collect nitric acid having a purity of up to about 99% that may be directed to further processing and/or storage in preparation for commercial shipment and/or sale.

(32) In certain embodiments, the NO.sub.x absorber is configured to remove mercury and/or heavy metal trace elements, using equipment and process(es) known in the art, e.g. but not limited to those described in PCT/CA1999/000403 or described elsewhere herein.

(33) In some embodiments, the NO.sub.x absorber may be configured to collect the hydrochloric acid and to direct at least a portion of the hydrochloric acid from the NO.sub.x absorber to the electrolytic unit. At the electrolytic unit, the HCl undergoes electrolysis to produce hydrogen gas and chlorine gas. Methods of electrolysing hydrochloric acid are known in the art, and any suitable commercially available electrolytic unit may be used. In a non-limiting example, the electrolytic unit comprises high temperature electrolysis cells. The electrolytic unit is thus configured to receive the hydrochloric acid (e.g. from the NO.sub.x absorber, or a portion of which is from the NO.sub.x absorber) and is further configured to electrolyse the hydrochloric acid to produce both hydrogen gas and chlorine gas. In alternative embodiments, the system may be configured to direct HCl separated from the condensed products of the SO.sub.x absorber to the electrolytic unit.

(34) The hydrogen gas produced from the electrolysis of HCl at the electrolytic unit may be re-used in the system or elsewhere in the plant, or potentially stored, e.g. for sale/transport. In a non-limiting example, the produced hydrogen gas or a portion thereof is re-directed to the Sabatier reactor for use in converting carbon dioxide gas into a hydrocarbon fuel. The chlorine gas produced from the electrolysis of HCl at electrolytic unit (or a portion thereof) may be re-used in the system or elsewhere in the plant, or potentially stored, e.g. for sale/transport. In a non-limiting example, the system is further configured to direct the chlorine gas produced in the electrolytic unit to supply all or a portion of the chlorine gas stream for GPO reactor.

(35) In some embodiments, the system may be configured such that the product gas stream leaving the GPO reactor is fed directly to the Sabatier reactor. In other embodiments, additional components (e.g. SO.sub.x absorber(s), NO.sub.x absorber(s) and/or water vapour remover(s)) to treat the product gas stream are included in series between the GPO reactor and the Sabatier reactor to treat (further process or clean) the gas stream for a more efficient Sabatier reaction.

(36) For example, in some embodiments (e.g. when the flue gas further comprises water vapour), the system further comprises a water vapour remover configured to remove the water vapour from the gas stream before reaching the Sabatier reactor. The water vapour remover may be positioned in series in the system between the NO.sub.x absorber and the Sabatier reactor. The water vapour remover may be positioned in series between the SO.sub.x absorber and the Sabatier reactor. The water vapour remover may be positioned in series between the GPO reactor and the Sabatier reaction, e.g. immediately prior to receiving the treated gas stream at Sabatier reactor. The water vapour remover may be configured in parallel to the electrolytic unit.

(37) Any suitable water vapour remover may be used, as is well known in the art. In a non-limiting example, thermal energy generated from the system itself (e.g. heat from excess steam, or heat added specifically for the step of water vapour removal is used to heat the gas stream to evaporate any H.sub.2O content remaining therein, the evaporated H.sub.2O content being collectable downstream. In another non-limiting example, water vapour is removed from the gas stream by heat exchangers and the removed water vapour may be collected as steam. Without such treatment or removal step, the water vapour generally would otherwise be vented into the atmosphere. The system may be configured to use the collected steam or to condense the steam to liquid water (e.g. by cooling). Accordingly, in certain embodiments, the system may be further configured to recycle the collected water content (steam or liquid water) back into the system. For example, but without limitation, the system may be configured to: (i) return the H.sub.2O content to a steam cycle of the system; (ii) re-use the H.sub.2O content recovered from the gas stream as process water in the SO.sub.x absorber (if present), the NO.sub.x absorber (if present), or both the SO.sub.x absorber and the NO.sub.x absorber; (iii) use the H.sub.2O content recovered from the gas stream to aid in the electrolysis of HCl in the electrolytic unit; and/or (iv) use the H.sub.2O content recovered from the gas stream as a heat source to increase the temperature of the electrolytic reaction of HCl in the electrolytic unit, thereby improving the efficiency of electrolysis. Such recycling of evaporated H.sub.2O content from flue gas may be desired, particularly for flue gas treatment systems that are situated in locations that experience or are prone to drought or drought-like conditions. It is estimated that, for a 500 MW plant, up to about 750,000 lbs/hr of H.sub.2O content that would otherwise be vented into the atmosphere as steam may be recovered and re-used within the system herein.

(38) In some embodiments, the system is configured to direct the H.sub.2O content collected in the water vapour remover (or a portion thereof) to a separate water electrolytic unit configure to convert the water to hydrogen gas and oxygen gas. In these embodiments, the system may be configured to direct the hydrogen gas generated from the electrolysis of the collected H.sub.2O content (or a portion thereof) to the Sabatier reactor. The system may be further configured to use the oxygen gas generated from the electrolysis as a fuel source within the system or elsewhere in the plant. In other embodiments, the collected water content removed from the gas stream in the water vapour remover does not undergo further hydrolysis.

(39) The water vapour remover is configured to direct the resulting dehydrated gas stream (comprising CO.sub.2 gas or consisting essentially of CO.sub.2 gas) to the Sabatier reactor.

(40) The Sabatier reactor is configured to receive a gas stream (i.e. the product gas stream of the GPO reactor or a further treated gas stream downstream from the GPO reactor) and is further configured to receive a hydrogen gas stream (e.g. from one or more electrolytic units electrolyzing HCl and/or water). For example, the Sabatier reactor may be configured to receive a gas stream from the SO.sub.x absorber, the NO.sub.x absorber or the water vapour remover. In certain embodiments, the Sabatier reactor is configured to receive a gas stream from the water vapour remover.

(41) The Sabatier process is catalyzed in the Sabatier reactor by an appropriate catalyst such as, but not limited to, a nickel catalyst, ruthenium, alumina, or a copper catalyst. In certain embodiments, the catalyst is a copper catalyst. In certain embodiments, the Sabatier reactor is configured for the Sabatier reaction to occur at atmospheric pressure. In some embodiments, the molar feed ratio of H.sub.2:CO.sub.2 is greater than or equal to about 3.5:1, and the Sabatier process may be carried out at a temperature between about 400° F. and about 700° F. In other embodiments, other suitable reaction parameters may be used. Any suitable Sabatier reactor and conditions may be used.

(42) In the Sabatier reactor, the Sabatier reaction hydrogenates the carbon dioxide gas in the product gas stream into a hydrocarbon fuel. In some embodiments, the hydrocarbon fuel comprises methane. In some embodiments, the hydrocarbon fuel consists essentially of methane.

(43) In some embodiments, the system may be further configured to direct the methane (or a portion thereof) to a boiler or combustion chamber configured to combust the methane to generate heat or power. For example, the methane (or a portion thereof) may be blended and co-fired with coal at the plant, or may be used as a fuel to power a separate turbine. In some embodiments, the system may further comprise a compressor or condenser configured to condense liquefied natural gas from the methane (or a portion thereof). In some embodiments, the system may further comprise a compressor configured to condense the volume of the hydrocarbon fuel, e.g. for transport from the plant.

(44) In other non-limiting examples, the system may be further configured to convert the methane (or a portion thereof) to other products such as, but not limited to, a methyl halide. In a non-limiting example, methane (or a portion thereof) may be converted to chloromethane through the following reaction, as known in the art:
CH.sub.4+Cl.sub.2.fwdarw.CH.sub.3Cl+HCl  21.

(45) The resulting methyl chloride may be further processed into other organic polyhalides, such as dichloro-methane. The resulting methyl chloride may also be converted to other products like methyl alcohols, ethyl alcohols, ethers, aldehydes, ketones, organic acids, esters, amines, and fats and soaps.

(46) In various embodiments, the system may comprise: (a) a GPO reactor configured to receive a gas stream comprising SO.sub.x species, NO.sub.x species, water vapour, heavy metals, and carbon dioxide gas, the GPO reactor further configured to oxidize the SO.sub.x species and NO.sub.x species; (b) a SO.sub.x absorber configured to receive the gas stream from the GPO reactor, the SO.sub.x absorber further configured to further oxidize and collect the SO.sub.x species as H.sub.2SO.sub.4; (c) a NO.sub.x absorber configured to receive the gas stream from the SO.sub.x absorber, the NO.sub.x absorber further configured to further oxidize the NO.sub.x species in the gas stream, the NO.sub.x absorber further configured to collect hydrochloric acid produced from oxidizing the NO.sub.x species; (d) an electrolytic unit configured to receive the hydrochloric acid collected at the NO.sub.x absorber, and further configured to electrolyse the hydrochloric acid to produce hydrogen gas; (e) a water vapour remover configured to receive the gas stream from the NO.sub.x absorber, and further configured to remove water vapour from the gas stream; and (f) a Sabatier reactor configured to receive the gas stream from the water vapour remover and the hydrogen gas from the electrolytic unit, the hydrogen gas for hydrogenating the carbon dioxide gas in the gas stream into a hydrocarbon fuel comprising methane.

(47) The present disclosure also relates to a method of producing a hydrocarbon fuel from a flue gas stream comprising NO.sub.x species, water vapour, and carbon dioxide gas. Without limitation, the flue gas may be from a coal-firing facility or a gas-burning facility. As such, the flue gas may further comprise SO.sub.x species, mercury, and/or heavy metal trace elements. In some embodiments, the flue gas will have been pre-cleaned as described above (e.g. through an ESP). In some embodiments, the hydrocarbon fuel comprises methane. In some embodiments, the hydrocarbon fuel consists essentially of methane.

(48) The method comprises: (a) generating hydroxyl radicals and chlorine radicals; (b) oxidizing the NO.sub.x species in the gas stream with the hydroxyl radicals and chlorine radicals to produce a gas stream comprising nitric acid and hydrochloric acid, water vapour and carbon dioxide gas; (c) removing the water vapour from the gas stream to produce a dehydrated gas stream; (d) producing hydrogen gas from one or both of: (di) electrolyzing the water vapour removed from the gas stream in step (c) to produce hydrogen gas and oxygen gas; and (dii) electrolyzing the hydrochloric acid produced in step (b) to produce hydrogen gas and chlorine gas; (e) using a Sabatier reaction to hydrogenate the carbon dioxide gas in the dehydrated gas stream from (c) with the hydrogen gas produced in step (d) to produce the hydrocarbon fuel.

(49) In embodiments where the flue gas stream further comprises SO.sub.x species, the method may further comprise step (bi) oxidizing the SO.sub.x species (e.g. using the hydroxyl radicals and and/or chlorine radicals from step (a), and/or by using steam or water) to produce sulfuric acid, and removing the sulfuric acid from the gas stream (e.g. using a SO.sub.x absorber as described for the system above) to produce a gas stream that is substantially free of SO.sub.x species. In embodiments where the flue gas stream further comprises heavy metal trace elements (e.g. but not limited to, one or more selected from a group consisting of antimony, arsenic, cadmium, chromium, nickel, selenium, zirconium, and/or any combination thereof), the method further may further comprise removing the trace elements from the gas stream by capturing the trace elements in the sulfuric acid (as described for the system above). In certain embodiments, but without limitation, the trace elements may be removed from the sulfuric acid by ion exchange. In embodiments where the flue gas stream further comprises mercury, the method may further comprise removing the mercury from the gas stream (as described for the system above). In certain embodiments, removing the mercury comprises converting the mercury to HgCl.sub.2 and capturing the HgCl.sub.2 in sulfuric acid (e.g. collected in a SO.sub.x absorber). The method may further comprise recovering the mercury from the sulfuric acid (as described for the system above). For example, but without limitation, the mercury may be removed from the sulfuric acid by precipitating out mercury by adding an alkali metal halogen (e.g. potassium iodide to precipitate out mercuric iodide (see PCT/CA1999/000403).

(50) In certain embodiments, the method may further comprise step (bii) further oxidizing the NO.sub.x species with steam or water to produce hydrochloric acid and a gas stream that is substantially free of NO.sub.x species (e.g. by passing the gas stream through a NO.sub.x absorber as described above). In certain embodiments of the method that comprise step (dii), i.e. electrolyzing the hydrochloric acid produced from step (a) and/or step (bii) to produce hydrogen gas and chlorine gas, the method may further comprise using the chlorine gas from step (dii) to generate at least some of the chlorine radicals in step (a). In certain embodiments of the method that comprise step (di), i.e. electrolyzing the water vapour, the method further comprises directing the oxygen gas from step (di) to aid in combustion of a fuel to generate heat or power.

(51) In certain embodiments of the method, the Sabatier reaction is catalysed by a catalyst selected from the group consisting of a nickel catalyst, a ruthenium catalyst, an alumina catalyst, and a copper catalyst. In certain embodiments, the catalyst is a copper catalyst.

(52) In certain embodiments, the method further comprises compressing the methane (or the hydrocarbon fuel) to reduce the volume of the methane (or the hydrocarbon fuel). In certain embodiments, the method further comprises condensing the methane to produce liquefied natural gas. In certain embodiments, the method further comprises combusting the methane (or the hydrocarbon fuel) to generate heat or power. In certain embodiments, the method further comprises blending and co-firing the methane with a fuel (e.g. a fossil or hydrocarbon fuel, such as coal, gas, or any other fuel).

(53) The present disclosure also relates to use of a Sabatier reaction for converting carbon dioxide gas into a hydrocarbon fuel in an industrial-size flue gas treatment system. In certain embodiments, but without limitation, the hydrocarbon fuel is methane. In certain embodiments, the hydrocarbon fuel is compressed to reduce its volume (e.g. to facilitate storage or transport). In certain embodiments, the hydrocarbon fuel is condensed to produce liquefied natural gas. In certain embodiments, the hydrocarbon fuel is blended and co-fired with coal.

(54) The present disclosure also relates, without limitation, to the following enumerated embodiments:

Embodiment(s) 1

(55) A system comprising: (a) a reactor configured to receive a gas stream comprising NOx species and carbon dioxide gas, the reactor further configured to oxidize the NOx species in the gas stream to produce hydrochloric acid; (b) an electrolytic unit configured to receive the hydrochloric acid and configured to electrolyse the hydrochloric acid to produce hydrogen gas; and (c) a carbon dioxide absorber configured to receive the gas stream from the reactor and the hydrogen gas from the electrolytic unit, the hydrogen gas for hydrogenating the carbon dioxide gas in the gas stream into a hydrocarbon fuel.

Embodiment(s) 2

(56) The system according to embodiment(s) 1, wherein the reactor is a gas phase reactor.

Embodiment(s) 3

(57) The system according to embodiment(s) 1 or 2, wherein the reactor is further configured to receive a chlorine gas stream.

Embodiment(s) 4

(58) The system according to any one of embodiment(s) 1 to 3, further comprising a NOx absorber.

Embodiment(s) 5

(59) The system according to embodiment(s) 4, wherein the NOx absorber is configured in series between the reactor and the carbon dioxide collector.

Embodiment(s) 6

(60) The system according to any one of embodiment(s) 1 to 5, further comprising a SOx absorber.

Embodiment(s) 7

(61) The system according to any one of embodiment(s) 1 to 6, the gas stream further comprising water vapour, and the system further comprising a water vapour remover.

Embodiment(s) 8

(62) The system according to embodiment(s) 7, wherein the water vapour remover is configured in series between the NOx absorber and the carbon dioxide collector.

Embodiment(s) 9

(63) The system according to embodiment(s) 8, wherein the water vapour remover is configured in parallel to the electrolytic unit.

Embodiment(s) 10

(64) The system according to any one of embodiment(s) 1 to 9, wherein the carbon dioxide gas is converted to the hydrocarbon fuel by a Sabatier reaction.

Embodiment(s) 11

(65) The system according to embodiment(s) 10, wherein the Sabatier reaction uses a catalyst selected from the group consisting of a nickel catalyst, a ruthenium catalyst, an alumina catalyst, and a copper catalyst.

Embodiment(s) 12

(66) The system according to embodiment(s) 11, wherein the catalyst is the copper catalyst.

Embodiment(s) 13

(67) A system comprising: (a) a gas phase reactor configured to receive a gas stream comprising NOx species, water vapour, and carbon dioxide gas, the gas phase reactor further configured to oxidize the NOx species in the gas stream to produce hydrochloric acid; (b) a NOx absorber configured to receive the gas stream from the gas phase reactor, the NOx absorber further configured to oxidize the NOx species in the gas stream, the NOx absorber further configured to collect the hydrochloric acid produced from oxidizing the NOx species in the gas stream in the NOx absorber and oxidizing the NOx species in the gas phase reactor; (c) an electrolytic unit configure to receive the hydrochloric acid collected at the NOx absorber, and further configured to electrolyse the hydrochloric acid to produce hydrogen gas; (d) a water vapour remover configured to receive the gas stream from the NOx absorber, and further configured to remove the water vapour from the gas stream; and (e) a carbon dioxide absorber configured to receive the gas stream from the water vapour remover and the hydrogen gas from the electrolytic unit, the hydrogen gas for hydrogenating the carbon dioxide gas in the gas stream into a hydrocarbon fuel.

Embodiment(s) 14

(68) The system according to embodiment(s) 13, wherein the reactor is further configured to receive a chlorine gas stream.

Embodiment(s) 15

(69) The system according to embodiment(s) 13 or 14, wherein the electrolytic unit is configured to electrolyse the hydrochloric acid to produce the hydrogen gas and chlorine gas.

Embodiment(s) 16

(70) The system according to embodiment(s) 15, wherein the chlorine gas is recycled into the chlorine gas stream.

Embodiment(s) 17

(71) The system according to any one of embodiment(s) 13 to 16, wherein the carbon dioxide gas is converted to the hydrocarbon fuel by a Sabatier reaction.

Embodiment(s) 18

(72) The system according to embodiment(s) 17, wherein the Sabatier reaction uses a catalyst selected from the group consisting of a nickel catalyst, a ruthenium catalyst, an alumina catalyst, and a copper catalyst.

Embodiment(s) 19

(73) A method of treating a gas stream comprising NOx species, water vapour, and carbon dioxide gas, the method comprising: (a) generating hydroxyl radicals and chlorine radicals; (b) oxidizing the NOx species in the gas stream with the hydroxyl radicals and chlorine radicals to produce nitric acid and hydrochloric acid; (c) removing the water vapour from the gas stream; (d) reacting the carbon dioxide gas with hydrogen gas produced from electrolyzing the water vapour removed from the gas stream, the hydrochloric acid, or both, to produce a hydrocarbon fuel.

Embodiment(s) 20

(74) The method according to embodiment(s) 19, the gas stream further comprising SOx species, the method further comprising oxidizing the SOx species.

Embodiment(s) 21

(75) The method according to embodiment(s) 19 or 20, the gas stream further comprising a heavy metal, the method further comprising removing the heavy metal from the gas stream.

Embodiment(s) 22

(76) The method according to embodiment(s) 21, wherein the heavy metal is mercury.

Embodiment(s) 23

(77) The method according to any one of embodiment(s) 20 to 22, the gas stream further comprising trace elements selected from a group consisting of antimony, arsenic, cadmium, chromium, nickel, selenium, zirconium, and any combination thereof, the method further comprising removing the trace elements from the gas stream.

Embodiment(s) 24

(78) The method according to embodiment(s) 23, further comprising capturing the trace elements in sulfuric acid produced from oxidizing the SOx species, and removing the trace elements from the sulfuric acid by ion exchange.

Embodiment(s) 25

(79) The method according to any one of embodiment(s) 19 to 24, further comprising electrolyzing the hydrochloric acid to produce chlorine gas.

Embodiment(s) 26

(80) The method according to embodiment(s) 25, further comprising using the chlorine gas to generate at least some of the chlorine radicals.

Embodiment(s) 27

(81) The method according to any one of embodiment(s) 19 to 26, further comprising electrolyzing the water vapour removed from the gas stream to produce oxygen gas.

Embodiment(s) 28

(82) The method according to embodiment(s) 27, further comprising using the oxygen gas to aid in combustion.

Embodiment(s) 29

(83) The method according to any one of embodiment(s) 19 to 28, wherein the carbon dioxide gas is converted into the hydrocarbon fuel by a Sabatier reaction.

Embodiment(s) 30

(84) The method according to embodiment(s) 29, wherein the Sabatier reaction is catalysed by a catalyst selected from the group consisting of a nickel catalyst, a ruthenium catalyst, an alumina catalyst, and a copper catalyst.

Embodiment(s) 31

(85) Use of a Sabatier reaction for converting carbon dioxide gas into a hydrocarbon fuel in an industrial-size flue gas treatment system.

Embodiment(s) 32

(86) The use according to embodiment(s) 31, wherein the hydrocarbon fuel is methane.

(87) The present invention will be further illustrated in the following non-limiting examples.

EXAMPLE 1

(88) Referring to FIG. 1, and according to an embodiment of the present disclosure, there is a flue gas treatment system 100 configured for use within a coal-firing facility, the system 100 comprising a gas phase reactor 140, a SO.sub.x absorber 150, a NO.sub.x absorber 160, a water vapour remover 170, and a carbon dioxide absorber 180.

(89) Flue gas 110 comprises SO.sub.x species, NO.sub.x species, water vapour, heavy metals (e.g. mercury), and carbon dioxide gas.

(90) Chlorine gas 130 and flue gas 110 are: (i) delivered into the gas phase reactor 140 operating at pre-set reaction conditions; and (ii) mixed in the gas phase reactor 140. The gas phase reactor may be a reactor that is known in the art, such as a commercially available gas phase reactor. Appropriate reaction conditions are also known in the art (see for example U.S. Pat. No. 4,619,608). For example, the gas phase reactor 140 can be set at a temperature between about 100° C. and about 650° C. For example, the temperature of the gas phase reactor 140 can be set at about 100° C., 125° C., 150° C., 175° C., 200° C., 225° C., 250° C., 275° C., 300° C., 325° C., 350° C., 375° C., 400° C., 425° C., 450° C., 475° C., 500° C., 525° C., 550° C., 575° C., 600° C., 625° C., 650° C., or any temperature therebetween.

(91) At elevated temperatures in the gas phase reactor 140, it is believed that chlorine gas 130 reacts with the water vapour in the flue gas 110 to generate chlorine radicals and hydroxyl radicals. The NO.sub.x species or a portion thereof present in the flue gas 110 is oxidized in the gas phase reactor 140 in the presence of the generated chlorine radicals and the generated hydroxyl radicals. Using nitric oxide (NO) as an example of a NO.sub.x species, and without wishing to be bound by theory, it is believed that nitric oxide (NO) in flue gas 110 is oxidized to nitric acid (HNO.sub.3) and hydrochloric acid in the gas phase reactor 140 according to the following chemical reactions:
NO+.Math.OH.fwdarw.HNO.sub.2;  6.
NO+.Math.Cl.fwdarw.NOCl;  7.
NOCl+H.sub.2O.fwdarw.HNO.sub.2+HCl;  8.
HNO.sub.2+.Math.Cl.fwdarw.NO.sub.2+HCl;  9.
NO.sub.2+.Math.OH.fwdarw.HNO.sub.3;  10.
NO.sub.2+.Math.Cl.fwdarw.NO.sub.2Cl;  11.
NO.sub.2Cl+H.sub.2O.fwdarw.HNO.sub.3+HCl.  12.
Without being bound by theory, it is also believed that the oxidized forms of polluting species are more readily removable from flue gas than the non-oxidized forms thereof. In addition, it is believed that the predominant final products of NO.sub.x removal are nitric acid and hydrochloric acid. Gas stream 110a comprising dissolved nitric acid and hydrochloric acid and other pollutants exits the reactor 140 and is directed towards the SO.sub.x absorber 150.

(92) The SO.sub.x absorber 150 may be any suitable absorber that is known in the art. For example, and as contemplated in this embodiment, the SO.sub.x absorber 150 is one that is substantially similar to the one described in U.S. Pat. No. 4,619,608 both in design and reaction conditions. The SO.sub.x absorber 150 may achieve SO.sub.2 capture rates of above 99% without producing CO.sub.2 as a by-product. Where CO.sub.2 capture and storage by sequestration is desired, SO.sub.x limits of 10 ppm or lower may be required. Conventional limestone scrubbers may not remove SO.sub.2 from flue gas with the same efficiency.

(93) The SO.sub.x absorber 150 may be arranged horizontally or vertically, depending on spatial restrictions or requirements of the system 100. The SO.sub.x absorber 150 may also comprise packed towers or cross-flow vessels that condense and collect resulting sulfuric acid, nitric acid, hydrochloric acid, or other acid streams, as well as heavy metal (e.g. mercury) products.

(94) In the SO.sub.x absorber 150, the gas stream 110a is sprayed with steam to facilitate SO.sub.x oxidation; in the presence of the steam, SO.sub.x generally reacts in preferential order over NO.sub.x. Using sulfur dioxide (SO.sub.2) as a non-limiting example of a SO.sub.x species, and without wishing to be bound by theory, it is believed that the sulfur dioxide is oxidized to sulfuric acid (H.sub.2SO.sub.4) in the SO.sub.x absorber 150 according to the following chemical reaction:
SO.sub.2+Cl.sub.2+2H.sub.2O.fwdarw.H.sub.2SO.sub.4+2HCl  13.
SO.sub.2 removal rates of about 99% may be achieved at Cl.sub.2 levels as low as 1.0 Cl.sub.2/SO.sub.2 molar ratio. An equilibrium concentration of about 70% or higher H.sub.2SO.sub.4 to H.sub.2O may also be achieved. The collected mixture of H.sub.2SO.sub.4/H.sub.2O may be further treated by a process 150′ to remove H.sub.2O thereform, thereby concentrating the remaining sulfuric acid to a purity of up to about 93-96% (commercial grade). The purified H.sub.2SO.sub.4 may then be collected and shipped to industry for sale.

(95) Although not shown in FIG. 1, in certain embodiments the method may further comprise removing the heavy metals (or a portion thereof), e.g. mercury, in the SO.sub.x absorber or in the gas stream exiting the SO.sub.x absorber, e.g. by a process known in the art such as, but not limited to, the one described in PCT/CA1999/000403. For example, mercury may be converted into a mercury halide (e.g. mercury chloride) and collected from the sulfuric acid. In certain embodiments, heavy metal removal may or may further comprise capturing the trace elements (e.g. one or more of antimony, arsenic, cadmium, chromium, nickel, selenium, and zirconium) in the sulfuric acid produced from oxidizing the SO.sub.x species, and removing the trace elements from the sulfuric acid by ion exchange. In other embodiments, heavy metal removal may not occur. Yet in other embodiments, heavy metal removal may occur at an off-site location.

(96) After oxidation of the SO.sub.x species in the SO.sub.x absorber 150, gas stream 110b is produced and directed towards the NO.sub.x absorber 160.

(97) The NO.sub.x absorber 160 may be any suitable NO.sub.x absorber that is known in the art. For example, the NO.sub.x absorber 160 may be one that is substantially similar to the one described in U.S. Pat. No. 4,619,608 both in design and reaction conditions. NO.sub.x removal efficiency of about 98% may be achieved by the combination of a gas phase reactor and a NO.sub.x absorber. Since no ammonia is used in the NO.sub.x absorber 160, no ammonia slip occurs. The NO.sub.x absorber 160 may be arranged horizontally or vertically, depending on spatial restrictions or requirements of the system 100. The NO.sub.x absorber 160 may also comprise packed towers or cross-flow vessels that condense and collect nitric acid, hydrochloric acid, as well as heavy metal (e.g. mercury) products.

(98) In the NO.sub.x absorber 160, the gas stream 110b is sprayed with steam to further oxidize the NO.sub.x species. The gas stream 110b may be sprayed with steam at a non-zero angle (e.g. orthogonally). The gas stream 110b may be sprayed with steam at a suitable spraying pressure. Without being bound by theory, it is believed that the following reactions are involved in the removal of NO.sub.x species from gas stream 110b in the NO.sub.x absorber 160:
Cl.sub.2+H.sub.2O.fwdarw.HOCl+HCl  14.
NOCl+H.sub.2O.fwdarw.HNO.sub.2+HCl  15.
NOCl+HOCl+H.sub.2O.fwdarw.HNO.sub.3+2HCl  16.
NO.sub.2Cl+H.sub.2O.fwdarw.HNO.sub.2+HOCl  17.
2NO.sub.2+H.sub.2O.fwdarw.HNO.sub.2+HNO.sub.3  18.
HNO.sub.2+HOCl.fwdarw.HNO.sub.3+HCl  19.
2NO+H.sub.2O+HNO.sub.3.fwdarw.3HNO.sub.2  20.
It is believed that the predominant final products of NO.sub.x removal are nitric acid and hydrochloric acid.

(99) The NO.sub.x absorber 160 collects nitric acid having a purity of up to about 99% that may be directed to further processing and/or storage 160″ in preparation for commercial shipment and/or sale.

(100) The HCl produced from the oxidation of NO.sub.x species in the gas reactor 140 and the NO.sub.x absorber 160 is collected and directed to an electrolytic unit 160′. At the electrolytic unit 160′, the HCl undergoes electrolysis to produce hydrogen gas and chlorine gas. Methods of electrolysing hydrochloric acid are known in the art, and any commercially available electrolytic unit may be used. In a non-limiting example, the electrolytic unit comprises high temperature electrolysis cells.

(101) The hydrogen gas produced from the electrolysis of HCl at electrolytic unit 160′ may be re-used in the flue gas treatment system 100. In a non-limiting example, the produced hydrogen gas or a portion thereof is re-directed to the carbon dioxide absorber 180 for use in converting carbon dioxide gas into a hydrocarbon fuel.

(102) The chlorine gas produced from the electrolysis of HCl at electrolytic unit 160′ may be re-used in the flue gas treatment system 100. In a non-limiting example, the produced chlorine gas is re-directed towards the reactor 140 and forms the chlorine gas 130 or a part thereof.

(103) Although not shown in FIG. 1, in certain embodiments that gas stream 110b undergoes further heavy metal removal in the NO.sub.x absorber 160 (i.e. removal of any heavy metals that were not removed in the SO.sub.x absorber 150) by a process known in the art such as, but not limited to, the one described in PCT/CA1999/000403. For example, mercury may be converted into a mercury halide (e.g. mercury chloride) which may be collected, sold, or reused, for other downstream applications. In other embodiments, this further heavy metal removal process may not occur.

(104) Gas stream 110c leaving the NO.sub.x absorber 160 is generally removed of NO.sub.x species and consists essentially of water vapour and carbon dioxide gas. Water vapour present in gas stream 110c is removed therefrom by the water vapour remover 170. Such removal may be done by methods known in the art. In a non-limiting example, thermal energy generated from the treatment system 100 (e.g. heat from excess steam, or heat generated specifically for the step of water vapour removal from gas stream 110c) is used to heat the gas stream 110c to evaporate the H.sub.2O content remaining therein, the evaporated H.sub.2O content being collectable downstream. In another non-limiting example, water vapour is removed from gas stream 110c by heat exchangers and the removed water vapour may be collected as steam. Without such treatment or removal step, the water vapour generally would otherwise be vented into the atmosphere.

(105) The collected evaporated H.sub.2O content from gas stream 110c may be condensed into water, and the collected condensed water may be used for other purposes in the flue gas treatment system 100. Such other purposes include, but are not limited to: (i) returning the H.sub.2O content recovered from gas stream 110c to a steam cycle of the flue gas treatment system 100; (ii) re-using the H.sub.2O content recovered from gas stream 110c as process water in the SO.sub.x absorber 150, the NO.sub.x absorber 160, or both the SO.sub.x absorber 150 and the NO.sub.x absorber 160; (iii) using the H.sub.2O content recovered from gas stream 110c to aid in the electrolysis 160′ of HCl; and (iv) using the H.sub.2O content recovered from gas stream 110c as a heat source to increase the temperature of the electrolytic reaction of HCl thereby improving the efficiency of said reaction at the electrolytic unit 160′. Such recycling of evaporated H.sub.2O content from flue gas may be desired, particularly for flue gas treatment systems that are situated in locations that experience or are prone to drought or drought-like conditions. It is estimated that, for a 500 MW plant, up to about 750,000 lbs/hr of H.sub.2O content that would otherwise be vented into the atmosphere as steam may be recovered and re-used within the treatment system 100.

(106) Gas stream 110d, which is removed of water vapour, is directed to the carbon dioxide absorber 180 for further processing.

(107) Gas stream 110d consists essentially of carbon dioxide gas. Hydrogen gas produced from the electrolysis of HCl at the electrolytic unit 160′ is fed into the carbon dioxide absorber 180, and serves as a reactant required to hydrogenate the carbon dioxide gas in gas stream 110d into methane 112, at the carbon dioxide absorber 180, via the Sabatier process, at industrial scale and economically reasonable costs.

(108) The Sabatier process is catalyzed in the carbon dioxide absorber 180 by an appropriate catalyst such as, but not limited to, a nickel catalyst, ruthenium, alumina, or a copper catalyst. As contemplated in this embodiment, the Sabatier process in the carbon dioxide collector 180 is catalyzed by a copper catalyst, and occurs under atmospheric pressure. As contemplated in this embodiment, the molar feed ratio of H.sub.2:CO.sub.2 is greater than or equal to about 3.5:1, and the Sabatier process is carried out at a temperature between about 400° F. and about 700° F. In other embodiments, other suitable reaction parameters may be used.

(109) It is also contemplated in this embodiment (though not shown in FIG. 1) that at least a portion of the water vapour removed from gas stream 110c and the H.sub.2O content collected therefrom undergoes its own electrolytic reaction to generate hydrogen gas and oxygen gas. The hydrogen gas generated from the electrolysis of the collected H.sub.2O content may be directed to the carbon dioxide absorber 180 for use in converting carbon dioxide gas into a hydrocarbon fuel and to further provide the volume of hydrogen gas that is required to hydrogenate the carbon dioxide gas in gas stream 110d into methane 112, at the carbon dioxide absorber 180, via the Sabatier process, at industrial scale and economically reasonable costs. The oxygen gas generated from said electrolysis may be used as a fuel source within the system 100. In other embodiments, the water vapour removed from gas stream 110c and the H.sub.2O content collected therefrom does not undergo further hydrolysis.

(110) Methane 112 produced in the carbon dioxide absorber 180 may be directed downstream for further processing 190. In certain embodiments, methane 112 (or a portion thereof) is compressed (condensed) by methods known in the art to form downstream fuel sources such as, but not limited to, liquefied natural gas (LNG), which may be used (or a portion thereof may be used) as a source of fuel in downstream applications, recycled for use as a fuel source within the system 100, or sold as a product (e.g. as a fuel or chemical feedstock). For example, but without limitation, LNG may be removed from the plant via cryogenic road tanker.

(111) Since methane is combustible without requiring compression or other treatment, in certain embodiments (not shown in FIG. 1) methane 112 (or a portion thereof) may be fed directly into the boiler of the plant, blended and co-fired with the coal, gas or another fossil or hydrocarbon fuel, or may be used as fuel to power a separate turbine, thereby eliminating or reducing the need to store, sequester, or sell the product of condensation (i.e. LNG), while increasing the power output of the plant.

(112) In other non-limiting examples, the methane 112 (or a portion thereof) may be converted to other products such as, but not limited to, a methyl halide. In a non-limiting example, methane 212 (or a portion thereof) is converted to chloromethane through the following reaction, as known in the art:
CH.sub.4+Cl.sub.2.fwdarw.CH.sub.3Cl+HCl  21.
The resulting methyl chloride from Reaction 21 may be further processed into other organic polyhalides, such as dichloro-methane. The resulting methyl chloride may also be converted to other products like methyl alcohols, ethyl alcohols, ethers, aldehydes, ketones, organic acids, esters, amines, and fats and soaps.

EXAMPLE 2

(113) Referring to FIG. 2, and according to another embodiment of the present disclosure, there is a flue gas treatment system 200 configured to serve a gas burning facility, the treatment system 200 comprising a gas phase reactor 140, a NO.sub.x absorber 160, a water vapour remover 170, and a carbon dioxide absorber 180. As SO.sub.x species are not generally produced in a gas burning facility, the presence of a SO.sub.x absorber would be optional for a gas burning facility flue gas treatment system.

(114) Flue gas 210 comprises NO.sub.x species, water vapour, and carbon dioxide gas.

(115) Chlorine gas 130 and flue gas 210 are: (i) delivered into the gas phase reactor 140 operating at pre-set reaction conditions such as the reaction conditions described in Example 1; and (ii) mixed in the gas phase reactor 140. For example, the gas phase reactor 140 can be set at a temperature between about 100° C. and about 650° C. Flue gas 210 and chlorine gas 130 mix in the gas phase reactor 140, and the NO.sub.x gas in the flue gas 210 is oxidized generally to nitric acid and hydrochloric acid (see for example Reactions 6 to 12). Gas stream 210a comprising dissolved nitric acid and hydrochloric acid and other pollutants exits the reactor 140 and is directed towards the NO.sub.x absorber 160.

(116) NO.sub.x species that were not removed (e.g. converted) in the reactor 140 are removed from the gas stream 210a in the NO.sub.x absorber 160. Without being bound by theory, it is believed that NO.sub.x species that were not removed in the reactor 140 are removed from the gas stream 210a in the NO.sub.x absorber 160 per reactions 14 to 20 described above in Example 1. It is believed that the predominant final products of NO.sub.x removal are nitric acid and hydrochloric acid.

(117) The NO.sub.x absorber 160 collects nitric acid of a purity up to about 99% that may be directed to further processing and/or storage 160″ in preparation for commercial shipment and/or sale.

(118) Although not shown in FIG. 2, in certain optional embodiments, gas stream 210a may undergo heavy metal removal in the NO.sub.x absorber 160 by a process known in the art such as, but not limited to, the one described in PCT/CA1999/000403. In other embodiments, this heavy metal removal process may not occur. Heavy metals are generally not present in a gas plant.

(119) The HCl produced from the oxidation of NO.sub.x species in the gas reactor 140 and the NO.sub.x absorber 160 is collected and directed to an electrolytic unit 160′. At the electrolytic unit 160′, the HCl undergoes electrolysis to produce hydrogen gas and chlorine gas. Methods of electrolysing hydrochloric acid are known in the art, and any commercially available electrolytic unit may be used. The hydrogen gas produced from the electrolysis of HCl at electrolytic unit 160′ may be re-used in the flue gas treatment system 200. In a non-limiting example, the produced hydrogen gas or a portion thereof is re-directed to the carbon dioxide absorber 180 for use in converting carbon dioxide gas into a hydrocarbon fuel. The chlorine gas produced from the electrolysis of HCl at electrolytic unit 160′ may be re-used in the flue gas treatment system 200. In a non-limiting example, the produced chlorine gas is re-directed towards the reactor 140 and forms the chlorine gas 130 or a part thereof.

(120) Gas stream 210b leaving the NO.sub.x absorber 160 is generally removed of NO.sub.x species and consists essentially of water vapour and carbon dioxide gas. Water vapour present in gas stream 210b is removed therefrom by the water vapour remover 170. Such removal may be done by the non-limiting examples described in Example 1.

(121) The collected evaporated H.sub.2O content from gas stream 210b may be condensed into water, and the collected condensed water may be used for other purposes in the flue gas treatment system 200 such as, but not limited to, those described in Example 1. In addition, it is contemplated in this embodiment (though not shown in FIG. 2) that at least a portion of the water vapour removed from gas stream 210b and the H.sub.2O content collected therefrom undergoes its own electrolytic reaction to generate hydrogen gas and oxygen gas. The hydrogen gas generated from the electrolysis of the collected H.sub.2O content may be directed to the carbon dioxide absorber 180 for use in converting carbon dioxide gas into a hydrocarbon fuel. The oxygen gas generated from said electrolysis may be used as a fuel source within the system 200. In other embodiments, the water vapour removed from gas stream 210b and the H.sub.2O content collected therefrom does not undergo further hydrolysis.

(122) Gas stream 210c, which is removed of water vapour, is directed to the carbon dioxide absorber 180 for further processing. Gas stream 210c consists essentially of carbon dioxide gas. Hydrogen gas produced from the electrolysis of HCl at the electrolytic unit 160′ is fed into the carbon dioxide absorber 180, and serves as a reactant that is required to hydrogenate the carbon dioxide gas in gas stream 210c into methane 212, at the carbon dioxide absorber 180, via the Sabatier process.

(123) Methane 212 produced in the carbon dioxide absorber 180 may be directed downstream for further processing 290.

(124) In certain embodiments, methane 112 (or a portion thereof) is condensed by methods known in the art to form downstream fuel sources such as, but not limited to, liquefied natural gas (LNG), which may be used (or a portion thereof may be used) as a source of fuel in downstream applications, recycled for use as a fuel source within the system 200, or sold as a product (e.g. as a fuel or chemical feedstock). For example, but without limitation, LNG may be removed from the plant via cryogenic road tanker.

(125) Since methane is combustible without requiring further treatment, in certain embodiments (not shown in FIG. 1) methane 112 or a portion thereof may be used as fuel to generate heat or power a turbine, thereby eliminating or reducing the need to store, sequester, or sell the product of condensation (i.e. LNG), while increasing the power output of the plant.

(126) In addition to conversion to liquefied natural gas as described in Example 1, methane 212 (or a portion thereof) may be rendered into other products. In a non-limiting example, methane 212 (or a portion thereof) is converted to chloromethane using Reaction 21 (as described in Example 1). The resulting methyl chloride from Reaction 21 may be further processed into other organic polyhalides, such as dichloro-methane. The resulting methyl chloride may also be converted to other products like methyl alcohols, ethyl alcohols, ethers, aldehydes, ketones, organic acids, esters, amines, and fats and soaps.

(127) While Examples 1 and 2 above describe the water vapour remover 170 and the carbon dioxide absorber 180 as separate units, in other embodiments and examples, the water vapour remover and the carbon dioxide absorber may be combined as one unit. In a non-limiting example, heat exchangers are placed around the carbon dioxide absorber to evaporate the water vapour from the gas stream prior to reacting the carbon dioxide gas remaining in the gas stream with hydrogen gas. In another non-limiting example, steam from the system is passed over the carbon dioxide absorber to evaporate the water vapour from the gas stream prior to reacting the carbon dioxide gas remaining in the gas stream with hydrogen gas.

(128) It is understood that the embodiments presented in the disclosure are non-limiting examples of flue gas treatment systems contemplated in this disclosure. While in the embodiments only one clean-up unit (e.g. a SO.sub.x absorber, a NO.sub.x absorber, a carbon dioxide absorber, a Sabatier reactor, etc.) is described for each targeted flue gas pollutant, other embodiments may contemplate one or more clean-up units per targeted flue gas pollutant. For example, a treatment system may comprise one or more gas phase reactors connected in series, one or more SO.sub.x absorbers connected in series, one or more NO.sub.x absorbers connected in series, one or more water vapour removers connected in series, one or more H.sub.2O electrolytic units connected in series, one or more HCl electrolytic units connected in series, and/or one or more carbon dioxide absorbers connected in series. Having one or more of the same clean-up units arranged in series may improve the collection and removal of certain flue gas pollutants. For example, since the volumes of carbon dioxide in the flue gas are much greater than the volumes of SO.sub.x and NO.sub.x species in the flue gas, additional carbon dioxide absorbers connected in series may be beneficial in order to adequately remove the carbon dioxide from the flue gas by converting it, for example by the Sabatier process, into, for example, a hydrocarbon fuel for use in downstream applications.

(129) All citations herein, and all documents cited in the cited documents, are hereby incorporated by reference.

(130) It is contemplated that any part of any aspect or embodiment discussed in this specification can be implemented or combined with any part of any other aspect or embodiment discussed in this specification. While particular embodiments have been described in the foregoing, it is to be understood that other embodiments are possible and are intended to be included herein. It will be clear to any person skilled in the art that modification of and adjustment to the foregoing embodiments, not shown, is possible. Accordingly, the scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole.

REFERENCES

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