Process to reduce emissions of nitrogen oxides and mercury from coal-fired boilers

Abstract

A flue gas additive is provided that includes both a nitrogenous component to reduce gas phase nitrogen oxides and a halogen-containing component to oxidize gas phase elemental mercury.

Claims

1. A method, comprising: contacting a combustion feed material with an additive to form a combined combustion feed material, the additive comprising a nitrogenous material; and combusting the combined combustion feed material to form an off-gas comprising a nitrogen oxide and a derivative of the nitrogenous material, the derivative of the nitrogenous material causing removal of at least a portion of the nitrogen oxide, wherein the nitrogenous material comprises at least one of an amine and amide, wherein the derivative of the nitrogenous material comprises ammonia, and wherein the additive is a free flowing particulate composition having a P80 size ranging from about 6 to about 20 mesh (Tyler).

2. The method of claim 1, wherein the nitrogenous material is supported by a particulate substrate, the particulate substrate being one or more of the combustion feed material, a zeolite, other porous metal silicate material, clay, activated carbon, char, graphite, (fly) ash, metal, and metal oxide.

3. The method of claim 1, wherein an amount of nitrogen added in the nitrogenous material added to the off-gas is at least about 0.5% of a theoretical stoichiometric ratio based on an amount of nitrogen oxide present, wherein the combined combustion feed material comprises from about 0.05 to about 0.75 wt. % of the additive, wherein the additive comprises a halogen-containing material, and wherein a mass ratio of the nitrogen content of the nitrogenous material to the halogen content in the additive ranges from about 1:1 to about 2400:1.

4. The method of claim 1, wherein a P80 particle size distribution of the additive is reduced from about 6 to 20 mesh (Tyler) to no more than about 200 mesh (Tyler) via in-line milling followed by introduction, without intermediate storage, to the combustor.

5. The method of claim 1, further comprising: at a location remote from a combustor, contacting the additive with the combustion feed material to form the combined combustion feed material; and transporting the combined combustion feed material to the combustor.

6. The method of claim 1, wherein the combusting is in a combustion zone of a combustor and wherein the combustion zone has a temperature ranging from about 1,400° F. to about 3,500° F.

7. The method of claim 6, wherein the temperature ranges from about 1,400° F. to about 2,000° F.

8. The method of claim 1, wherein the combustion feed material is a coal, and wherein the coal is at least one of a high alkali, high iron, and high sulfur coal.

9. The method of claim 1, wherein the combined combustion feed material comprises a halogen-containing additive that forms a gas phase halogen when combusted.

10. The method of claim 9, wherein the combined combustion feed material comprises a mass ratio of nitrogen:halogen from the halogen-containing additive ranging from about 1:1 to about 2400:1.

11. A flue gas additive, comprising: a nitrogenous material that forms ammonia when combusted; and a halogen-containing material that forms a gas phase halogen when combusted, wherein the flue gas additive comprises a coating to impede thermal degradation and/or decomposition of the nitrogenous material.

12. The flue gas additive of claim 11, wherein the nitrogenous material comprises one or more of an amine and amide.

13. The flue gas additive of claim 11, wherein the halogen in the halogen-containing material is one or more of iodine and bromine.

14. The flue gas additive of claim 11, wherein a mass ratio of the nitrogen content of the nitrogenous material to the halogen content in the additive ranges from about 1:1 to about 2400:1.

15. The flue gas additive of claim 11, wherein the additive is supported.

16. The flue gas additive of claim 11, wherein the additive is unsupported and in the form of a free-flowing particulate.

17. The flue gas additive of claim 11, wherein the flue gas additive is mixed with coal.

18. A combined combustion feed material comprising coal and a nitrogenous material for reducing nitrogen oxides, wherein the combined combustion feed material comprises from about 0.05 to about 1 wt. % of the additive, with the remainder being coal.

19. The combined combustion feed material of claim 18, wherein the nitrogenous material is at least one of an amine and amide and wherein the coal is at least one of a high alkali, high iron, and high sulfur coal.

20. The combined combustion feed material of claim 19, wherein the additive comprises a halogen-containing material and wherein the combined combustion feed material comprises a mass ratio of the nitrogen content of the nitrogenous material to the halogen content of the additive ranging from about 1:1 to about 2400:1.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) The accompanying drawings are incorporated into and form a part of the specification to illustrate several examples of the present disclosure. These drawings, together with the description, explain the principles of the disclosure. The drawings simply illustrate preferred and alternative examples of how the disclosure can be made and used and are not to be construed as limiting the disclosure to only the illustrated and described examples. Further features and advantages will become apparent from the following, more detailed, description of the various aspects, embodiments, and configurations of the disclosure, as illustrated by the drawings referenced below.

(2) FIG. 1 is a block diagram according to an embodiment showing a common power plant configuration;

(3) FIG. 2 is a block diagram of a CFB boiler-type combustor according to an embodiment;

(4) FIG. 3 is a block diagram of a PC boiler-type combustor according to an embodiment;

(5) FIG. 4 is a process flow chart according to an embodiment of the disclosure;

(6) FIG. 5 is a record of the emissions of mercury (Hg) and nitrogen oxides (NO.sub.x) measured at the baghouse exit of a small-scale CFB combustor.

(7) FIG. 6 is a record of the emissions of mercury (Hg) and nitrogen oxides (NO.sub.x) measured at the stack of a CFB boiler; and

(8) FIG. 7 is a block diagram showing transportation of the combined combustion feed material to the combustor from a remote location according to an embodiment.

DETAILED DESCRIPTION

The Additive

(9) The additive comprises at least two components, one to cause removal of nitrogen oxides and the other to cause removal of elemental mercury. The former component uses a nitrogenous material, commonly an ammonia precursor such as an amine and/or amide, while the latter uses a halogen or halogen-containing material.

(10) The additive can contain a single substance for reducing pollutants, or it can contain a mixture of such substances. For example, the additive can contain a single substance including both an amine or amide and a halogen, such as a haloamine formed by at least one halogen and at least one amine, a halamide formed by at least one halogen and at least one amide, or other organohalide including both an ammonia precursor and dissociable halogen. In an embodiment, the additive comprises an amine or amide. In an embodiment, the precursor composition comprises a halogen. In a preferred embodiment, the precursor composition contains a mixture of an amine and/or an amide, and a halogen.

The Nitrogenous Component

(11) Without being bound by theory, the ammonia precursor is, under the conditions in the furnace or boiler, thermally decomposed to form ammonia gas, or possibly free radicals of ammonia (NH.sub.3) and amines (NH.sub.2) (herein referred to collectively as “ammonia”). The resulting ammonia reacts with nitrogen oxides formed during the combustion of fuel to yield gaseous nitrogen and water vapor according to the following global reaction:
2NO+2NH.sub.3+½O.sub.2.fwdarw.2N.sub.2+3H.sub.2O  (1)

(12) The optimal temperature range for Reaction (1) is from about 1550° F. to 2000° F. Above 2000° F., the nitrogenous compounds from the ammonia precursor may be oxidized to form NO.sub.x. Below 1550° F., the production of free radicals of ammonia and amines may be too slow for the global reaction to go to completion.

(13) Commonly, the ammonia precursor is an amine or amide. Sources of amines or amides include any substance that, when heated, produces ammonia gas and/or free radicals of ammonia. Examples of such substances include, for example, urea, carbamide, polymeric methylene urea, animal waste, ammonia, methamine urea, cyanuric acid, and combinations and mixtures thereof. In an embodiment, the substance is urea. In an embodiment, the substance is animal waste.

(14) Commonly at least about 25%, more commonly at least most, more commonly at least about 75%, more commonly at least about 85% and even more commonly at least about 95% of the nitrogenous component is added in liquid or solid form to the combustion feed material. Surprisingly and unexpectedly, it has been discovered that co-combustion of the nitrogenous component with the combustion feed material does not thermally decompose the nitrogenous component to a form that is unable to react with nitrogen oxides or to nitrogen oxides themselves. Compared to post-combustion addition of the nitrogenous component, co-combustion has the advantage of not requiring an injection grid or specific post-combustion injection location in an attempt to provide adequate mixing of the additive with the combustion off-gas, or flue gas. Distribution of the nitrogenous component is not as critical as for post-combustion addition of the component because the additive is added with the combustion feed material and is pre-mixed, and substantially homogeneously distributed, during combustion. Additionally, the nitrogenous component can advantageously be added to the combustion feed material at a remote location, such as prior to shipping to the utility plant or facility.

(15) The nitrogenous component can be formulated to withstand more effectively, compared to other forms of the nitrogenous component, the thermal effects of combustion. In one formulation, at least most of the nitrogenous component is added to the combustion feed material as a liquid, which is able to absorb into the matrix of the combustion feed material. The nitrogenous component will volatilize while the bulk of the combustion feed material consumes a large fraction thermal energy that could otherwise thermally degrade the nitrogenous component. The nitrogenous component can be slurried or dissolved in the liquid formulation. The liquid formulation can include other components, such as a solvent (e.g., water, surfactants, buffering agents and the like), and a binder to adhere or bind the nitrogenous component to the combustion feed material, such as a wax or wax derivative, gum or gum derivative, and other inorganic and organic binders designed to disintegrate thermally during combustion (before substantial degradation of the nitrogenous component occurs), thereby releasing the nitrogenous component into the boiler or furnace freeboard, or into the off-gas. A typical nitrogenous component concentration in the liquid formulation ranges from about 20% to about 60%, more typically from about 35% to about 55%, and even more typically from about 45% to about 50%. In another formulation, at least most of the nitrogenous component is added to the combustion feed material as a particulate. In this formulation, the particle size distribution (P.sub.80 size) of the nitrogenous component particles as added to the fuel commonly ranges from about 20 to about 6 mesh (Tyler), more commonly from about 14 to about 8 mesh (Tyler), and even more commonly from about 10 to about 8 mesh (Tyler).

(16) With reference to FIG. 7, the combined combustion feed material 108 containing solid nitrogenous particulates are added at a remote location 600, such as a mine site, transported or shipped 604, such as by rail or truck, to the plant site 616, where it is stockpiled in intermediate storage. The combined combustion feed material 108 is removed from storage, comminuted in 608 in-line comminution device to de-agglomerate the particulates in the combined combustion feed material 108, and then introduced 612 to the combustor 112 in the absence of further storage or stockpiling. Such comminution may be accomplished by any of a number of commercial size reduction technologies including but not limited to a crusher or grinder.

(17) In another configuration, the additive particulates are stockpiled at the plant site 616 and further reduced in size from a first size distribution to a more finely sized second size distribution by an in-line intermediate milling stage 608 between storage and addition to the coal feed, which combined combustion feed material 108 is then introduced 612 to the combustor 112 without further storage. In one application, a P.sub.80 particle size distribution of the additive is reduced from about 6 to 20 mesh (Tyler) to no more than about 200 mesh (Tyler) via in-line milling followed by introduction, without intermediate storage, to the combustor. Typically, a time following in-line milling to introduction to the combustor 112 is no more than about 5 days, more typically no more than about 24 hours, more typically no more than about 1 hour, more typically no more than about 0.5 hours, and even more typically no more than about 0.1 hours. This stage may reduce the particle residence time in the combustion zone. Such milling may be accomplished by any of a number of commercial size reduction technologies including but not limited to jet mill, roller mill and pin mill. Milling of nitrogenous materials is a continuous in-line process since the materials are prone to re-agglomeration. At least a portion of the nitrogenous component will sublime or otherwise vaporize to the gas phase without thermally decomposing. In this formulation, the particle size distribution (P.sub.80 size) of the nitrogenous component particles as added to the combustion feed material 104 commonly ranges from about 400 to about 20 mesh (Tyler), more commonly from about 325 to about 50 mesh (Tyler), and even more commonly from about 270 to about 200 Mesh (Tyler).

(18) In another formulation, the nitrogenous component is combined with other chemicals to improve handing characteristics and/or support the desired reactions and/or inhibit thermal decomposition of the nitrogenous component. For example, the nitrogenous component, particularly solid amines or amides, whether supported or unsupported, may be encapsulated with a coating to alter flow properties or provide some protection to the materials against thermal decomposition in the combustion zone. Examples of such coatings include silanes, siloxanes, organosilanes, amorphous silica or clays. In yet another formulation, granular long chain polymerized methylene ureas are preferred reagents, as the kinetics of thermal decomposition are expected to be relatively slower and therefore a larger fraction of unreacted material may still be available past the flame zone. Other granular urea products with binder may also be employed. In yet another formulation, the nitrogenous component is supported by a substrate other than a combustion feed material. Exemplary substrates to support the nitrogenous component include zeolites (or other porous metal silicate materials), clays, activated carbon (e.g., powdered, granular, extruded, bead, impregnated, and/or polymer coated activated carbon), char, graphite, (fly) ash, (bottom) ash, metals, metal oxides, and the like. In any of the above formulations, other thermally adsorbing materials may be applied to substantially inhibit or decrease the amount of nitrogenous component that degrades thermally during combustion. Such thermally adsorbing materials include, for example, amines and/or amides other than urea (e.g., monomethylamine and alternative reagent liquids).

The Halogen Component

(19) Compositions comprising a halogen compound contain one or more organic or inorganic compounds containing a halogen or a combination of halogens, including but not limited to chlorine, bromine, and iodine. Preferred halogens are bromine and iodine. The halogen compounds noted above are sources of the halogens, especially of bromine and iodine. For bromine, sources of the halogen include various inorganic salts of bromine including bromides, bromates, and hypobromites. In various embodiments, organic bromine compounds are less preferred because of their cost or availability. However, organic sources of bromine containing a suitably high level of bromine are considered within the scope of the invention. Non-limiting examples of organic bromine compounds include methylene bromide, ethyl bromide, bromoform, and carbonate tetrabromide. Non-limiting sources of iodine include hypoiodites, iodates, and iodides, with iodides being preferred. Furthermore, because various compositions of combustion feed materials may be combined and used, combustion feed materials rich in native halogens may be used as the halogen source.

(20) When the halogen compound is an inorganic substituent, it can be a bromine- or iodine-containing salt of an alkali metal or an alkaline earth element. Preferred alkali metals include lithium, sodium, and potassium, while preferred alkaline earth elements include magnesium and calcium. Halide compounds, particularly preferred are bromides and iodides of alkaline earth metals such as calcium.

(21) There are a number of possible mechanisms for mercury capture in the presence of a halogen.

(22) Without being bound by theory, the halogen reduces mercury emissions by promoting mercury oxidation, thereby causing it to better adsorb onto the fly ash or absorb in scrubber systems. Any halogen capable of reducing the amount of mercury emitted can be used. Examples of halogens useful for practicing the present invention include fluorine, chlorine, bromine, iodine, or any combination of halogens.

(23) While not wishing to be bound by any theory, oxidation reactions may be homogeneous, heterogeneous, or a combination thereof. A path for homogeneous oxidation of mercury appears to be initiated by one or more reactions of elemental mercury. and free radicals such as atomic Br and atomic I. For heterogeneous reactions, a diatomic halogen molecule, such as Br.sub.2 or I.sub.2, or a halide, such as HBr or HI, reacts with elemental mercury on a surface. The reaction or collection surface can, for example, be an air preheater surface, duct internal surface, an electrostatic precipitator plate, an alkaline spray droplet, dry alkali sorbent particles, a baghouse filter, an entrained particle, fly ash, carbon particle, or other available surface. It is believed that the halogen can oxidize typically at least most, even more typically at least about 75%, and even more typically at least about 90% of the elemental mercury in the flue gas stream.

(24) Under most flue gas conditions, the mercury reaction kinetics for iodine appear to be faster at higher temperatures than mercury reaction kinetics for chlorine or bromine at the same temperature. With chlorine, almost all the chlorine in the flame is found as HCl, with very little Cl. With bromine, there are, at high temperatures, approximately equal amounts of HBr on the one hand and Br.sub.2 on the other. This is believed to be why oxidation of Hg by bromine is more efficient than oxidation by chlorine. Chemical modeling of equilibrium iodine speciation in a subbituminous flue gas indicates that, at high temperatures, there can be one thousand times less HI than I (in the form of atomic iodine) in the gas. At lower temperatures, typically below 800° F., diatomic halogen species, such as I.sub.2, are predicted to be the major iodine-containing species in the gas. In many applications, the molecular ratio, in the gas phase of a mercury-containing gas stream, of diatomic iodine to hydrogen-iodine species (such as HI) is typically at least about 10:1, even more typically at least about 25:1, even more typically at least about 100:1, and even more typically at least about 250:1.

(25) While not wishing to be bound by any theory, the end product of reaction can be mercuric iodide (HgI.sub.2 or Hg.sub.2I.sub.2), which has a higher condensation temperature (and boiling point) than both mercuric bromide (HgBr.sub.2 or Hg.sub.2Br.sub.2) and mercuric chloride (HgCl.sub.2 or Hg.sub.2Cl.sub.2). The condensation temperature (or boiling point) of mercuric iodide (depending on the form) is in the range from about 353 to about 357° C. compared to about 322° C. for mercuric bromide and about 304° C. for mercuric chloride. The condensation temperature (or boiling point) for iodine (I.sub.2) is about 184° C. while that for bromine (Br.sub.2) is about 58° C.

(26) While not wishing to be bound by any theory, another possible reaction path is that other mercury compounds are formed by multi-step reactions with the halogen as an intermediate.

(27) As will be appreciated, any of the above theories may not prove to be correct. As further experimental work is performed, the theories may be refined and/or other theories developed. Accordingly, these theories are not to be read as limiting the scope or breadth of this disclosure.

Flue Gas Treatment Process Using the Additive

(28) Referring to FIG. 1, an implementation of the additive 100 is depicted.

(29) The combustion feed material 104 can be any carbonaceous and combustion feed material, with coal being common. The coal can be a high iron, alkali and/or sulfur coal. Coal useful for the process can be any type of coal including, for example, anthracite coal, bituminous coal, subbituminous coal, low rank coal or lignite coal. Furthermore, the composition of components in coal may vary depending upon the location where the coal was mined. The process may use coal from any location around the world, and different coals from around the world may be combined without deviating from the present invention.

(30) The additive 100 is added to the combustion feed material 104 to form a combined combustion feed material 108. The amount of additive 100 added to the combustion feed material 104 and the relative amounts of the nitrogenous and halogen-containing components depend on the amount of nitrogen oxides and elemental mercury, respectively, generated by the combustion feed material 104 when combusted. In the former case, commonly at least about 50%, more commonly at least about 100%, and even more commonly at least about 300% of the theoretical stoichiometric ratio of the nitrogenous component required to remove the nitrogen oxides in the off-gas is added to the combustion feed material 104. In many applications, the amount of NO.sub.x produced by combustion of a selected combustion feed material 104 in the absence of addition of the nitrogenous component is reduced commonly by an amount ranging from about 10 to about 50% and more commonly from about 20 to about 40% with nitrogenous component addition.

(31) In absolute terms, the combined combustion feed material 108 comprises commonly from about 0.05 to about 0.5, more commonly from about 0.1 to about 0.4, and even more commonly from about 0.2 to about 0.4 wt. % additive, with the remainder being coal. The mass ratio of the nitrogen:halogen in the additive 100 commonly ranges from about 1:1 to about 2400:1, more commonly from about 7:1 to about 900:1, and even more commonly from about 100:1 to about 500:1.

(32) The additive 100 is commonly added to the combustion feed material 104 prior to its combustion. Given that the combustion feed material 104 can be in any form, the additive 100 can also be in any form convenient for adding to a given combustion feed material 104. For example, the additive 100 can be a liquid, a solid, a slurry, an emulsion, a foam, or combination of any of these forms. The contact of the additive 100 and combustion feed material 104 can be effected by any suitable technique so long as the distribution of the additive 100 throughout the combustion feed material 104 is substantially uniform or homogenous. Methods of combining the additive 100 with the combustion feed material 104 will largely be determined by the combustion feed material 104 and the form of the additive 100. For example, if the combustion feed material 104 is coal and the additive 100 is in a solid form, they may be mixed together using any means for mixing solids (e.g., stirring, tumbling, crushing, etc.). If the combustion feed material 104 is coal and the additive 100 is a liquid or slurry, they may be mixed together using suitable means such as, for example, mixing, stirring or spraying.

(33) The additive 100 may be added to the combustion feed material 104 at a time prior to the fuel being delivered to the combustor 112. Moreover, contact of the additive 100 and combustion feed material 104 can occur on- or off-site. In other words, the contact can occur at the mine where the combustion feed material 104 is extracted or at some point in between the mine and utility, such as an off-loading or load transfer point.

(34) In one application and as discussed above in connection with FIG. 7, the additive 100 is added to the combustion feed material 104 at a physical location different than the location of, or off-site relative to, the combustor 112. By way of example, the additive 100 can be added to the combustion feed material 104 at the site of production of the combustion feed material 104 (e.g., the coal mine). Likewise, the additive 100 can be added to the combustion feed material 104 at a site secondary to the site of production, but that is not the site of combustion (e.g., a refinery, a storage facility). Such a secondary site can be a storage facility located on the property of a combustor 112, for example, a coal pile or hopper located near a combustor 112. In one particular application, the combustion feed material 104 is treated with the additive 100 at a site that is commonly at least about 1,000 miles, more commonly at least about 500 miles, more commonly at least about 10 miles, more commonly at least about 5 miles, and even more commonly at least about 0.25 mile away from the combustor 112.

(35) In some embodiments, the additive 100 is added to the combustion feed material 104 and then shipped to another location or stored for a period of time. The amount of the additive 100 required to reduce the nitrogen oxide is dependent upon the form of the additive 100, whether it be liquid, solid or a slurry, the type of coal and its composition, as well as other factors including the kinetic rate and the type of combustion chamber. Typically the nitrogenous material is applied to the coal feed in a range of 0.05% to 0.75% by weight of the coal. The additive 100 can also comprise other substances that aid in delivery of the nitrogenous material to the combustion feed material 104. For example, the precursor composition may comprise a dispersant that more evenly distributes the additive 100.

(36) The combined combustion feed material 108 is introduced into a combustor 112 where the combined combustion feed material 108 is combusted to produce an off-gas or flue gas 116. The combustor 112 can be any suitable thermal combustion device, such as a furnace, a boiler, a heater, a fluidized bed reactor, an incinerator, and the like. In general, such devices have some kind of feeding mechanism to deliver the fuel into a furnace where the fuel is burned or combusted. The feeding mechanism can be any device or apparatus suitable for use. Non-limiting examples include conveyer systems, hoppers, screw extrusion systems, and the like. In operation, the combustion feed material 104 is fed into the furnace at a rate suitable to achieve the output desired from the furnace.

(37) The target contaminants, namely nitrogen oxides and mercury, volatilize or are formed in the combustor 112. While not wishing to be bound by any theory, nitrogen oxides form in response to release of nitrogen in the coal as ammonia, HCN, and tars. Oxidation of these compounds is believed to produce NO.sub.x. Competition is believed to exist between oxidation of nitrogen and conversion to molecular nitrogen. Nitrogen is believed to be oxidized either heterogeneously (which is the dominant oxidation mechanism at off-gas temperatures less than about 1,470° F.) or homogeneously (which is the dominant oxidation mechanism at off-gas temperatures of more than about 1,470° F.). Heterogeneous solid surface catalytic oxidation of nitrogen on limestone is believed to yield NO. In homogeneous gas phase oxidation, ammonia is believed to be oxidized to molecular nitrogen, and HCN to nitrous oxide Gas phase species, such as SO.sub.2* and halogen free radicals such as Br* and I*, are believed to increase the concentration of carbon monoxide while decreasing the concentration of NO. Under reducing conditions in the combustion zone, SO.sub.2* is believed to be released, and some CaSO.sub.4 is converted back to CaO. Reducing conditions normally exist in the bed even at overall fuel lean stoichiometric ratios. NO oxidation to NO.sub.2 is believed to occur with gas phase hydrocarbons present and is not reduced back to NO under approximately 1,550° F.

(38) Commonly, at least most of the nitrogen oxides or NO.sub.x are in the form of nitric oxide and, more commonly, from about 90-95% of the NO.sub.x is nitric oxide. The remainder is commonly in the form of nitrogen dioxide. At least a portion of the mercury is in elemental form, with the remainder being speciated. Commonly, target contaminant concentrations in the flue gas 116, in the absence of additive treatment ranges from about 50 to about 500 ppmv for nitrogen oxides and from about 1 to about 40 μg/m.sup.3 for elemental mercury.

(39) The combustor 112 can have a number of different designs.

(40) FIG. 2 depicts a combustor 112 having a circulating fluidized bed (“CFB”) boiler design. The combustor 112 includes a CFB boiler 202 having fluidized bed zone 200 (where larger particulates of coal and additive 100 collect after introduction into the combustor 112), mixing zone 204 (where the introduced combined combustion feed material 108 mixes with upwardly rising combustion off-gases), and freeboard zone 208 (where finely sized particulates of combined combustion feed material 108 and solid partial or complete combustion byproducts are entrained with the flow of the off-gases) combustor sections and a cyclone 210 in fluid communication with the boiler. Primary air 212 enters through the bottom of the boiler to fluidize the bed and form the fluidized bed zone 200. The bed contains not only the combined combustion feed material 108 but also limestone particulates 216, both introduced in the fluidized bed zone 200. The particle P.sub.80 size distribution for the combustion feed material 104 and 108 particulates commonly ranges from about 325 to about 140_mesh (Tyler) and for the limestone particulates commonly ranges from about 140 to about 6 mesh (Tyler). Secondary air 220 is introduced above the fluidized bed zone 200 and into the freeboard zone 208. Overfire air 224 is introduced into the freeboard 208. The combined combustion feed material 108 further includes (partially combusted or uncombusted) finely sized solid particulates 228 recovered by the cyclone 210 from the off-gas received from the freeboard zone 208. The finely sized solid particulates are typically one or more of uncombusted or partially combusted feed material particulates and/or limestone particulates. Recycled particulates can have an adsorbed amine and/or amide and/or ammonia, which can be beneficial to NO.sub.x reduction. Limestone is used to control emissions of sulfur oxides or SO.sub.x. In one configuration, the additive 100 is contacted with the finely sized solid particulates 228 before they are contacted with the combustion feed material 104. Prior to the contact, the combustion feed material 104 may or may not contain the additive. In one configuration, the additive 100 is contacted with the combustion feed material 104 before the combustion feed material 104 is contacted with the finely sized solid particulates 228.

(41) The temperatures in the fluidized bed zone 200 (or combustion zone), and freeboard zone 208 sections varies depending on the CFB design and the combustion feed material. Temperatures are controlled in a range that is safely below that which the bed material could fuse to a solid. Typically, the fluidized bed zone 200 temperature is at least about 1,400° F., more typically at least about 1,500° F., and even more typically at least about 1,550° F. but typically no more than about 1,800° F., more typically no more than about 1,700° F., more typically no more than about 1,650° F., and even more typically no more than about 1,600° F. Typically, the freeboard zone 208 temperature is at least about 1,500° F., more typically at least about 1,550° F., and even more typically at least about 1,600° F. but typically no more than about 1,800° F., more typically no more than about 1,750° F., more typically no more than about 1,600° F., and even more typically no more than about 1,550° F.

(42) The primary air 212 typically constitutes from about 30 to about 35% of the air introduced into the system; the secondary air 220 from about 50 to about 60% of the air introduced into the system; and the remainder of the air introduced into the combustor 112 is the overfire air 224.

(43) In one configuration, additional additive is introduced in the freeboard zone 208, such as near the entrance to the cyclone 210 (where high gas velocities for turbulent mixing and significant residence time in the cyclone are provided). In other configurations, additional additive is introduced into the mixing zone 204 and/or fluidized bed zone 200.

(44) FIG. 3 depicts a combustor 112 having a pulverized coal boiler (“PC”) design. The combustor 112 includes a PC boiler 300 in communication with a pulverizer 304. The combustion feed material 104 or 108 is comminuted in a pulverizer 304 and the comminuted combined combustion feed material 108 introduced, typically by injection, into the PC boiler 300 as shown. The particle P.sub.80 size distribution for the comminuted combustion feed material 108 particulates commonly ranges from about 325 to about 60 mesh (Tyler). Primary combustion air 304 is introduced into the combustion zone of the PC boiler 300 in spatial proximity to the point of introduction of the pulverized combustion feed material 108. Combustion off-gas or flue gas 116 is removed from the upper portion of the PC boiler 300, and ash or slag 308, the byproduct of coal combustion, from the lower portion of the PC boiler 300. In one configuration, the additive 100 is contacted with the combustion feed material 104 before comminution by the pulverizer 304. In one configuration, the additive 100 is contacted with the combustion feed material 104 during comminution. In one configuration, the additive 100 is contacted with the combustion feed material 104 after comminution.

(45) The temperature in the combustion zone varies depending on the PC boiler design and combustion feed material. Typically, the temperature is at least about 2,000° F., more typically at least about 2,250° F., and even more typically at least about 2,400° F. but no more than about 3,500° F., more commonly no more than about 3,250° F., and even more commonly no more than about 3,000° F.

(46) In one configuration, additional additive is introduced in the upper portion of the PC boiler 300 near the outlet for the flue gas 116 (where high gas velocities for turbulent mixing and significant residence time are provided). In other configurations, additional additive is introduced into the combustion zone in the lower portion of the PC boiler 300.

(47) Returning to FIG. 1, after the combustor 112 the facility provides convective pathways for the combustion off-gases, or flue gases, 116. Hot flue gases 116 and air move by convection away from the flame through the convective pathway in a downstream direction. The convection pathway of the facility contains a number of zones characterized by the temperature of the gases and combustion products in each zone. The combustion off-gases 116 upstream of the air pre-heater 120 (which preheats air before introduction into the combustor 112) is known as the “hot-side” and the combustion off-gases 124 downstream of the air pre-heater 120 as the “cold-side”.

(48) Generally, the temperature of the combustion off-gases 116 falls as they move in a direction downstream from the combustion zone in the combustor 112. The combustion off-gases 116 contain carbon dioxide as well as various undesirable gases containing sulfur, nitrogen, and mercury and entrained combusted or partially combusted particulates, such as fly ash. To remove the entrained particulates before emission into the atmosphere, particulate removal systems 128 are used. A variety of such removal systems can be disposed in the convective pathway, such as electrostatic precipitators and/or a bag house. In addition, dry or wet chemical scrubbers can be positioned in the convective pathway. At the particulate removal system 128, the off-gas 124 has a temperature of about 300° F. or less before the treated off-gases 132 are emitted up the stack.

(49) A method according to an embodiment of the present disclosure will now be discussed with reference to FIG. 4.

(50) In step 400, the additive 100 is contacted with the combustion feed material 104 to form the combined combustion feed material 108.

(51) In step 404, the combined combustion feed material 108 is introduced into the combustor 112.

(52) In step 408, the combined combustion feed material 108 is combusted in the presence of molecular oxygen, commonly from air introduced into the combustion zone.

(53) In step 412, the combustion and off-gas conditions in or downstream of the combustor 112 are monitored for target contaminant concentration and/or other target off-gas constituent or other parameter(s).

(54) In step 416, one or more selected parameters are changed based on the monitored parameter(s). A number of parameters influence nitrogen oxide and mercury generation and removal. By way of example, one parameter is the rate of introduction of the additive 100. If the rate of addition of additive 100 drops too low, gas phase NO.sub.x levels can increase due to competition between oxidation of additional ammonia and the reaction of ammonia with NO. Another parameter is the gas phase concentration(s) of nitrogen dioxide and/or nitric oxide. Another parameter is the concentration of gas phase molecular oxygen in the mixing zone 204. This parameter controls carbon and additive burnout, NO.sub.x formation, and SO.sub.x capture and decomposition. Another parameter is the temperature in the combustor 112. Higher temperatures in the combustor 112 and lower molecular oxygen concentrations can chemically reduce NO.sub.x. Higher combustor temperatures can also decrease gas phase carbon monoxide concentration. Another parameter is gas phase carbon monoxide concentration. Gas phase carbon monoxide concentration in the freeboard zone 208, of the combustor 112 can scavenge radicals and thereby inhibit reactions between the nitrogenous component and NO.sub.x. Generally, a negative correlation exists between gas phase CO and NO concentrations; that is, a higher CO concentration indicates a lower NO concentration and vice versa. There further appears to be a negative relationship between gas phase CO concentration and gas phase mercury (total) concentration; that is as CO concentration increases, total mercury concentration decreases. Limestone concentration in the combustor 112 is yet another parameter. Removing catalytic surfaces, such as limestone, can chemically reduce NO.sub.x. Gas phase SO.sub.2 concentration in the combustor 112 is yet another parameter as it can influence nitrogen oxides. Higher gas phase SO.sub.2 concentrations yields a higher gas phase CO concentration, a lower gas phase NO concentration, and higher gas phase nitrous oxide concentration. In CFB combustors, the presence of the nitrogenous component (e.g., urea) makes the fluidized bed zone 200 more reducing so gas phase SO.sub.2 concentration increases from decomposition of gypsum, a byproduct of limestone reaction with SO.sub.x, and gas phase carbon monoxide concentration increases due to less efficient combustion. Gas phase SO.sub.2 concentration increases when limestone flow decreases as well as decreasing NO due to less catalytic surface area. Generally, a negative correlation exists between limestone feed rate and gas phase SO.sub.2, CO, and NO concentrations; that is, a higher limestone feed rate indicates lower SO.sub.2, CO, and NO concentrations and vice versa. Bed depth and/or bed pressure drop are yet further parameters. These parameters may be controlled by bed drains and control bed temperature; that is a higher pressure drop makes the bed more dense, thereby affecting bed temperature.

(55) Any of these parameters can be changed, or varied (e.g., increased or decreased) to change nitrogen oxide, carbon dioxide, sulfur oxide, and/or mercury emissions in accordance with the relationships set forth above.

(56) Steps 412 and 416 can be implemented manually or by a computerized or automated control feedback circuit using sensors to sense one or more selected parameters, a computer to receive the sensed parameter values and issue appropriate commands, and devices to execute the commands. Microprocessor readable and executable instructions stored on a computer readable medium, such as memory or other data storage, can implement the appropriate control algorithms.

(57) The treated off-gas 132 commonly has substantially reduced levels of nitrogen oxides and mercury compared to the off-gas 116. The additive 100 commonly causes the removal of at least 20% of the gas phase nitrogen oxides and 40% of the elemental mercury generated by combustion of the combustion feed material 104.

(58) Reductions in the amount of a gas phase pollutant are determined in comparison to untreated fuel. Such reductions can be measured in percent, absolute weight or in “fold” reduction. In an embodiment, treatment of fuel with the additive 100 reduces the emission of at least one pollutant by at least about 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 95% or 100%. In another embodiment, treatment of fuel with the additive 100 reduces the emission of at least one pollutant by two-fold, three-fold, four-fold, five-fold, or ten-fold. In another embodiment, treatment of fuel with the additive reduces the emission of one or more of NO.sub.x and total mercury to less than about 500 ppmv, 250 ppmv, 100 ppmv, 50 ppmv, 25 ppmv, 10 ppmv, 5 ppmv, 4 ppmv, 3 ppmv, 2 ppmv, 1 ppmv, 0.1 ppmv, or 0.01 ppmv. As noted, the pollutant is one or both of nitrogen oxides and total or elemental mercury.

(59) It should be appreciated that the terms amount, level, concentration, and the like, can be used interchangeably. Amounts can be measured in, for example, parts per million (ppm), or in absolute weight (e.g., grams, pounds, etc.) Methods of determining amounts of pollutants present in a flue gas are known to those skilled in the art.

EXPERIMENTAL

(60) The following examples are provided to illustrate certain aspects, embodiments, and configurations of the disclosure and are not to be construed as limitations on the disclosure, as set forth in the appended claims. All parts and percentages are by weight unless otherwise specified.

(61) In preliminary testing, coal additives were tested at a small-scale circulating fluidized bed (CFB) combustor. Coal was treated by mixing solid urea with crushed coal and by spraying an aqueous solution containing potassium iodide onto crushed coal. Coal was fed into the combustion chamber by means of a screw feeder at a rate of approximately 99 lb/hr. Limestone was not fed continuously but added batchwise to the bed. The only air pollution control device on the combustor was a fabric filter baghouse. The concentrations of nitrogen oxides (NO.sub.x) and total gaseous mercury were measured in gas at the baghouse exit using continuous emission monitors (CEMs). The treatment rate of the coal corresponded to 0.0069 lb urea/lb coal and 0.000007 lb iodine/lb coal. The ratio of nitrogen to iodine added on a mass basis was 460 lb nitrogen per lb iodine. FIG. 5 is a record of the emissions of mercury (Hg) and nitrogen oxides (NO.sub.x) measured at the baghouse exit during two periods: before the treated coal was added to the boiler and during combustion of the treated coal. The vertical dotted line indicates the time at which the coal started to be treated with the additives. During the baseline (no treatment period), the average emissions of NO.sub.x and Hg were 175 ppmv and 12.9 μg/m.sup.3, respectively. During a steady-state period of coal treatment, average emissions of NO.sub.x and Hg were 149 ppmv and 0.8 μg/m.sup.3, respectively. Comparing these two periods, the reductions in NO.sub.x and Hg due to the coal treatment were 14.5% and 93.5%, respectively.

(62) Coal additives were tested at a circulating fluidized bed (CFB) boiler. Coal was treated by adding solid urea prill and by spraying an aqueous solution containing potassium iodide onto the coal belt between the coal crusher and the silos. Coal was fed from the silos directly into the boiler. The boiler burned approximately 190 tons per hour of coal. Limestone was fed into the bed at a rate of approximately 12 tons per hour. The only air pollution control device on the boiler was a fabric filter baghouse. The concentrations of nitrogen oxides (NO.sub.x) and total gaseous mercury were measured in the stack using continuous emission monitors (CEMs). The treatment rate of the coal corresponded to 0.0025 lb urea/lb coal and 0.000005 lb iodine/lb coal. The ratio of nitrogen to iodine added on a mass basis was 233 lb nitrogen per lb iodine. FIG. 6 is a record of the emissions of mercury (Hg) and nitrogen oxides (NO.sub.x) measured at the stack during two periods: before the treated coal was added to the boiler and during combustion of the treated coal. The vertical dotted line indicates the time at which the coal started to be treated with the additives. The shaded region on the left-hand side of the graph in FIG. 5 represents the baseline (no treatment period), with average emissions of NO.sub.x and Hg of 82.2 ppmv and 12.1 μg/m.sup.3, respectively. The shaded region on the right-hand-side of the graph represents the steady-state emissions from treated coal, with average emissions of NO.sub.x and Hg of 62.2 ppmv and 4.9 μg/m.sup.3, respectively. Comparing these two periods, the reductions in NO.sub.x and Hg due to the coal treatment were 24.3% and 60%, respectively.

(63) In another embodiment of the technology, coal additives were tested at a circulating CFB boiler. Coal was treated by spraying a solution consisting of 50% urea in water and by spraying an aqueous solution containing potassium iodide onto the coal belt between the coal crusher and the silos. Coal was fed from the silos directly into the boiler. The boiler burned approximately 210 tons per hour of coal. Limestone was fed into the bed at a rate of approximately 16 tons per hour. The only air pollution control device on the boiler was a fabric filter baghouse. The concentrations of nitrogen oxides (NO.sub.x) and total gaseous mercury were measured in the stack using continuous emission monitors (CEMs). The treatment rate of the coal corresponded to 0.0040 lb urea/lb coal and 0.000007 lb iodine/lb coal. The ratio of nitrogen to iodine added on a mass basis was 266 lb nitrogen per lb iodine. During the baseline (no treatment period), the average emissions of NO.sub.x and Hg were 85.2 ppmv and 14.8 μg/m.sup.3, respectively. During a steady-state period of coal treatment, average emissions of NO.sub.x and Hg were 58.9 ppmv and 7.1 μg/m.sup.3, respectively. Comparing these two periods, the reductions in NO.sub.x and Hg due to the coal treatment were 30.9% and 51.9%, respectively.

(64) A number of variations and modifications of the disclosure can be used. It would be possible to provide for some features of the disclosure without providing others. The present disclosure, in various aspects, embodiments, and configurations, includes components, methods, processes, systems and/or apparatus substantially as depicted and described herein, including various aspects, embodiments, configurations, subcombinations, and subsets thereof. Those of skill in the art will understand how to make and use the various aspects, aspects, embodiments, and configurations, after understanding the present disclosure. The present disclosure, in various aspects, embodiments, and configurations, includes providing devices and processes in the absence of items not depicted and/or described herein or in various aspects, embodiments, and configurations hereof, including in the absence of such items as may have been used in previous devices or processes, e.g., for improving performance, achieving ease and\or reducing cost of implementation.

(65) The foregoing discussion of the disclosure has been presented for purposes of illustration and description. The foregoing is not intended to limit the disclosure to the form or forms disclosed herein. In the foregoing Detailed Description for example, various features of the disclosure are grouped together in one or more, aspects, embodiments, and configurations for the purpose of streamlining the disclosure. The features of the aspects, embodiments, and configurations of the disclosure may be combined in alternate aspects, embodiments, and configurations other than those discussed above. This method of disclosure is not to be interpreted as reflecting an intention that the claimed disclosure requires more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive aspects lie in less than all features of a single foregoing disclosed aspects, embodiments, and configurations. Thus, the following claims are hereby incorporated into this Detailed Description, with each claim standing on its own as a separate preferred embodiment of the disclosure.

(66) Moreover, though the description of the disclosure has included description of one or more aspects, embodiments, or configurations and certain variations and modifications, other variations, combinations, and modifications are within the scope of the disclosure, e.g., as may be within the skill and knowledge of those in the art, after understanding the present disclosure. It is intended to obtain rights which include alternative aspects, embodiments, and configurations to the extent permitted, including alternate, interchangeable and/or equivalent structures, functions, ranges or steps to those claimed, whether or not such alternate, interchangeable and/or equivalent structures, functions, ranges or steps are disclosed herein, and without intending to publicly dedicate any patentable subject matter.