Patent Publication Number: US-2010116183-A1

Title: Use of hydrocarbon emulsions as a reburn fuel to reduce nox emissions

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of International Application No. PCT/US2008/066537 filed Jun. 11, 2008, which claimed priority to U.S. Application No. 60/943,133 filed Jun. 11, 2007, each of which are incorporated herein by reference in their entirety. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The invention relates to a method of reducing NO x  emissions from various types of furnaces ranging from utility boilers to industrial package boilers to Once Through Steam Generators to refinery furnaces. 
     2. Description of Related Art 
     The art has long recognized the presence of NO x  in effluent gases from various types of hydrocarbon burning devices and the desirability of reducing such NO x . 
     Masaki et al., U.S. Pat. No. 4,060,983, discloses that it is well known to reduce the amount of NO x  in an engine by employing a non-stoichiometric air-fuel ratio [in automobile engine] 
     Zamanshy et al., U.S. Pat. No. 6,471,506, utilizes metal containing compounds in a furnace reburn zone to reduce NO x . 
     Zauderer, U.S. Pat. No. 6,453,830, reduces NO x  by introducing sufficient fuel into the furnace downstream of the primary combustion zone into a fuel rich zone at a temperature that favors the conversion of NO x  to N2. Then further downstream air is added to complete combustion of any unburned fuel. 
     Additional fuel, where the fuel is pyrolysis gas from the partial gasification of a solid fuel, is introduced into a downstream combustion zone as solid particles dispersed in aqueous droplets of varying size. In other embodiments the fuel is a liquid fuel or is pulverized coal or shredded biomass particles. 
     In Zamansky et al., U.S. Pat. No. 7,168,947, a fuel rich zone is established containing a plurality of reduced n-containing species, introducing over fire air downstream of the fuel rich zone so that the n-containing species react with the NOX in the overfire zone. 
     Arand et al., U.S. Pat. No. 4,325,924, introduces urea in the presence of excess fuel as a solid or liquid at a temperature in excess of 1900° F. 
     Hura et al., U.S. Pat. No. 5,908,003, burns a solid fuel in a primary zone and injects a gaseous fuel into a downstream fuel lean zone at a temperature of 1800 to 2400° F. 
     Breen et al., U.S. Pat. No. 6,213,032, injects a water-oil emulsion into flue gas where the emulsion is 35-80% water. Urea or water may be added to emulsion which is preferably atomized before injection. 
     Payne et al., U.S. Pat. No. 6,481,998, discloses an apparatus for high velocity injection of liquid fuel into an NOX containing stream downstream of the primary combustion chamber without using recirculated flue gas or other carrier gas. 
     Reburn is a combustion hardware modification in which the NO x  produced in the main combustion zone is reduced downstream by providing a second combustion zone (the reburn zone). Up to 20% of the total fuel heat input to the furnace may be diverted from the main combustion zone and introduced above the top row of burners to create reducing (sub-stoichiometric in O 2  terms) conditions in the reburn zone. The reburn fuel is typically natural gas or micronized coal, a coal that is pulverized to 90% through a 300-mesh screen. The reburn fuel is injected into the furnace to create a fuel-rich zone where the NO formed in the main combustion zone is reduced to N 2 , NH 3 , HCN, other reduced nitrogen compounds and water vapor. 
     The reburn fuel may be injected alone or may be injected with a carrying medium such as re-circulated flue gas to improve fuel distribution in the furnace. 
     Combustion of the fuel-rich combustion gases leaving the reburn zone is completed by injecting overfire air (also called “completion air” when referring to reburn) in the burnout zone. At this point the NH 3 , HCN, and other reduced forms are oxidized to N 2 , and NO. At this step and throughout the mixing process there is also a direct reaction between NO and NH 3  to form N 2 . In each step, part of the fixed nitrogen (originally NO) is converted to N 2  thus fulfilling the purpose of the reburn process. 
     The gas reburn principal can be implemented in several ways. The traditional approach involves overall fuel-rich gas reburn. NO containing furnace gases from the primary combustion zone enter a downstream gas mixing and reburn zone in which a sufficient flow rate of natural gas is injected to form an overall fuel-rich mixture, Essentially, a region in the secondary combustion zone is driven sub-stoichiometric. 
     The total fuel flow to the reburn zone of the furnace is typically in the range of 10% to 20% of the total energy input utilized in the furnace. Reburn reactions in the overall fuel-rich NO x  reduction reburn zone reduce NO to N 2 , but produce relatively high levels of CO. Nitrogen in the reburn zone enters from the combustion gases from the primary combustion zone and from nitrogen contained in the reburn fuel, if any. 
     This CO produced in the reburn zone is then reduced in a final burnout zone by injecting completion overfire air to produce overall lean conditions in which oxidation of the reburn gas is completed. Such conventional gas reburn technology has demonstrated NO x  reductions above 50% in many installations. 
     A related technology, the modified reburn process, can achieve comparatively moderate NO x  reductions, but at a much lower heat input than in conventional reburn furnaces, and without the need for a completion overfire air system to achieve CO burnout. In the modified reburn process technology, natural gas or an emulsion of water and oil is injected into the upper furnace at sufficiently low rates to maintain overall fuel-lean conditions in the upper furnace region. The NO x  reburning reactions then occur within local fuel-rich regions formed by the gas injection and the mixing process. 
     Mixing between the injected reburn fuel and furnace gas is key to effective NO x  control. CO burnout is achieved by the excess O 2  available in the overall furnace flue gas, without the need for a completion overfire air system. This technology has achieved 35% to 40% NO x  reductions at 7% burnout fuel heat inputs without significant impact on the primary furnace combustion process. 
     Successful application of this modified reburn technology to any given installation hinges on achieving proper mixing of the injected gas with furnace gases to achieve optimum NO x  removal and low CO emissions. Uniform mixing of the injected gas will in most cases not produce the highest NO x  removal efficiencies. The NO x  and CO performance of this technology thus depends on the location, size, shape and placement of the gas injectors, which determine details of the resulting gas mixing process. To date, the results indicate that maximum NO x  reductions of 35% at 7% maximum gas heat input levels are limited by increased levels of CO emissions. 
     Attempts to maximize gas mixing are exemplified by the high velocity fuel injectors specified in Payne et al. U.S. Pat. No. 6,481,998 issued Nov. 19, 2002. 
     In those processes where a carrier gas is used to input the reburn fuel, the carrier gas maybe steam, air, or combustion products. Steam is expensive. The use of air or recycled combustion products such as flue gas recirculation requires expensive ductwork, or the need for an expensive flue gas recirculation fan. These fans are expensive to operate and high maintenance items. 
     Micronized coal requires a long burnout time when utilized as a reburn fuel. Utilizing micronized coal as a fuel source requires that both the fuel and the completion air be added at an earlier point in the furnace. As a result, much of the reaction occurs at higher temperatures, which results in more NO x  emissions. 
     Where boilers use neat bitumen or heavy fuel oil as the primary fuel, with high concentrations of vanadium in the ash of the fuel, a SCR (Selected Catalytic Reduction) process will not be practical due to the negative impact of the vanadium (in the form of Va 2 0 5 ) on the catalyst in the SCR. 
     In addition, the need for completion air in traditional reburn processes requires that boiler pressure parts be modified (tube wall bending) which are expensive and can impact boiler water flow circulation patterns and heat transfer characteristics. 
     The first installation and combustion optimization of natural gas as a reburn fuel in the first full-scale utility boiler in the USA was accomplished in the Niles Station of Ohio Edison in the late 1980&#39;s on a cyclone boiler. 
     The Electric Power Research Institute (EPRI) issued a report entitled “Gas Cofiring Assessment for Coal-Fired Utility boilers, EPRI, Palo Alto, Calif.: 2000, (10000513) considering the following: 
     Gas Reburning (RP) 
     Fuel Lean Gas Reburning (FLGR™) 
     Amine Enhanced Fuel Lean Gas Reburning (ALFLGR™) 
     Advanced Gas Reburning (AGR) 
     Supplemental gas cofiring 
     Coal/Gas cofiring burners 
     Although all of these reburn methods reduce NO x  emissions the industry has been slow to adopt them. 
     Commercial technologies available for NOX reduction have disadvantages that create boiler operational problems or cannot achieve NO x  levels below 0.15 lbs./MM Btu without using two or more of these technologies. 
     Selected Catalytic Reduction can achieve lowest NOx emissions levels but create operational and maintenance problems that impact costs and boiler availability. 
     Low NO X  Burners alone can not achieve the low NOx levels alone without adding Over Fire Air as an example. In addition, Low NO X  Burners&#39; firing refinery gas can experience stability problems. 
     Over Fire Air creates the sub-stoichiometric conditions that lead to the high temperature vanadium corrosion attack. 
     Selected Non-Catalytic Reduction can not achieve low NOx levels (primary objective) and has high ammonia slip. 
     Traditional Reburn creates the sub-stoichiometric conditions that lead to the high temperature vanadium corrosion attack. 
     Advanced oil recovery methods, such as the Cyclic Steam Stimulation process (CSS) and the Steam Assisted Gravity Drainage (SAGD) process, use steam to extract oil in situ through the use of injected steam. Boilers used in these processes do not presently use reburn technology. 
     For many applications, the associated costs and installation problems discussed above when considered against the projected level of NO x  emissions reduction has not been perceived to be worth the investment. 
     Thus, there continues to be a need for a reburn method/application which provides significant NO x  emissions reduction without requiring extensive duct work, FGR fans, and modifications to the boiler pressure parts. 
     SUMMARY OF THE INVENTION 
     Provided are a method and apparatus for reducing NO x  emissions in which a bitumen containing aqueous emulsion is injected into the flue gas of a furnace downstream of the primary combustion chamber and combusted in an oxygen poor reducing environment to remove a significant portion of the NOx components in the combustion gases. 
     The disclosed method of introducing NO x  reduction into boilers used for the Steam Assisted Gravity Drainage oil sands Steam Assisted Gravity Drainage application (OTSG &amp; package drum boilers), refinery furnaces, or utility boilers will maintain overall stoichiometric conditions above 1.0 throughout the boiler and specifically in the primary furnace. 
     All four of the current NOX reduction technologies—Selected Catalytic Reduction, Low NO x  Burners, Over Fire Air, Selected Non-Catalytic Reduction and traditional reburn—have serious problems when applied to the boilers used for the Steam Assisted Gravity Drainage process when using alternative fuels in oil sands applications, refinery boilers and utility boilers. 
     The emulsion is a hydrocarbon in water emulsion where the hydrocarbon component may itself be an emulsion of varying composition in the aqueous component of the emulsion. 
     The aqueous component of the emulsion may be composed simply of water or may contain nitrogenous compounds such as urea or ammonia. 
     The hydrocarbon component is preferably composed of bitumen, vacuum residue, or asphalt or a mixture thereof where the individual components of the hydrocarbon emulsion may vary greatly in proportion. 
     The oil in water emulsion is injected into the secondary combustion region of the furnace above the primary combustion zone in a manner that creates oil in water bilayered droplets with an external aqueous layer of water alone or in combination with urea, or ammonia and an inner hydrocarbon layer of bitumen, vacuum residue or asphalt or mixture thereof. 
     It is preferable that the droplets are evenly distributed throughout the input stream and not broken when the emulsion passes through the atomizer or injector into the furnace. The emulsion droplets are sized (Sauter Mean Diameter (SMD) by the atomizer/injector, so that the jet penetration and evaporation rate allow for the formation of localized fuel rich contrary currents. 
     In the localized fuel rich contrary currents created in the furnace by the carefully adjusted injection of the reburn fuel into the secondary combustion region, the droplets provide secondary atomization (micro-explosions) as the liquid aqueous outer droplet layer vaporizes to steam and releases the smaller hydrocarbon droplets which create localized fuel rich contrary currents. 
     It is preferable to provide injectors that are in several planes of the furnace to cover a range of regions in the furnace. 
     As the NO x  emissions from the primary combustion zone passes through the currents rich in reburn fuel in the reburn zone the NO x  are reduced to N 2 , HCN, and other reduced nitrogen entities. 
     The use of the reburn fuel disclosed herein and the process of minimizing NO x  emissions solves many of the existing problems associated with present systems and lowers the installation and maintenance costs of NO x  emission control systems. 
     Other objects and advantages of this application, method and apparatus invention will become apparent from a description of certain preferred embodiments shown in the attached figures. 
    
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
         FIG. 1  is a conceptual diagram of the contrary current local cloud NO x  reduction process in accordance with the present invention. 
         FIG. 2  is a process flow diagram, which shows the fuel handling and emulsion making process of the reburn fuel for delivery to the atomizers/injectors. 
         FIG. 3  is an example of a dual fluid atomizer/injector using either steam or sour solution gas as an atomizing fluid and the resultant primary and secondary atomization process used to both set up the localized fuel rich contrary currents and introduce the fixed reduced nitrogen agent in accordance with the present invention. 
         FIG. 4  is a diagram showing one embodiment of the fuel injector delivery system of the present invention. 
         FIGS. 5 &amp; 6  are diagrams of a utility boiler and Once Through Steam Generator furnace to which injectors have been added in accordance with the present invention. 
     
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     NO x  components in the combustion gases from a furnace are reduced by injecting a bitumen containing aqueous emulsion into the flue gas of a furnace downstream of the primary combustion chamber and combusted in an oxygen poor reducing environment to remove a significant portion of the NO x  components in the combustion gases. 
     As used herein “sour gas solution” means natural gas that is not refined and often contains species such as hydrogen sulfide (H 2 S) in the 2000 PPM range. 
     As used herein, “atmospheric tower bottoms” (ATB) or straight run residue, is the byproduct that remains and reflects the fraction or cut of the refining distillation curve representing products with a boiling temperature &gt;800° F. (&gt;426.7° C.). 
     As used herein, “vacuum residue” means the fraction that remains after distillation of bitumen or crude oil under either atmospheric (ATB or Atmospheric Tower Bottom) or vacuum (VTB or Vacuum Tower Bottom) conditions that contains fewer volatiles. Straight run residue or ATB is a byproduct that remains and reflects the fraction or cut of the refining curve representing products with a boiling temperature greater than or equal to 800° F. (426.7° C.). The typical application of this bottom product (VTB) is feed to an asphalt plant, a thermal cracker, a coker, or as a blending component for residual fuel (#6 HFO). 
     These bottom fractions or high boiling residues are also used as asphalt or residual fuel oil (#6 HFO). Asphalt is one of two available alternatives the refiner or upgrading process may consider for these bottom residues, depending upon the quality of the bitumen and the available market. 
     The asphaltene concentration determines the quality of the asphalt. Asphaltenes are very complex molecular substances found naturally in neat bitumen, which impart a high viscosity to the residue appearing solid at room temperature. Asphaltenes consist of polyaromatic compounds with high carbon-to-hydrogen ratios (˜1:1.2 depending on source) defined operationally as the n-heptane insoluble, toluene soluble component of carbonaceous material, such as crude oil or bitumen. 
     As bitumen is processed, the asphaltene concentration increases. A more comprehensive technical definition for asphaltenes is contained in ASTM test method D 6560. 
     As used herein, “Solvent De-Asphalter” (SDA) is the next step along the refining process, which operates at an even higher temperature to handle an even more viscous product. The SDA process uses a hydrocarbon solvent tailored to ensure the most economical de-asphalting design. Propane solvent is typical for the low-de-asphalted oil or a heavier residue or bitumen. Designs have been developed to produce a maximum yield of de-asphalted oil and minimum yield of asphalt, the latter having a viscosity range of 60,000 cp at 530° F. (276.7° C.) with a very high concentration of asphaltene. 
     As used herein, “bitumen” means a mixture of highly viscous primarily highly condensed polycyclic aromatic hydrocarbons. Naturally occurring or crude bitumen is a sticky, tar-like form of petroleum. Refined bitumen is obtained by fractional distillation of crude oil. It is the heaviest fraction and the one with the highest boiling point, boiling at 525° C. (977° F.). Most bitumens contain sulfur and several heavy metals such as nickel, vanadium, lead, chromium, mercury and also arsenic, selenium, and other toxic elements. 
     Naturally occurring crude bitumen is the prime feed stock for petroleum production from oil sands currently under development in Alberta, Canada. Canada has most of the world&#39;s supply of natural bitumen. The Athabasca oil sands is the largest bitumen deposit in Canada and the only one accessible to surface mining, although recent technological breakthroughs have resulted in deeper deposits becoming producible by in-situ methods. 
     As used herein “neat bitumen” is a product extracted from oil sands (typically using the SAGD or CSS process), is very viscous and is also referred to as non-conventional oil or crude bitumen to distinguish it from the freer-flowing hydrocarbon mixtures. 
     As used herein “burnout air” or “overfire air” means the air introduced to the furnace downstream of the reburn zone to complete combustion in a burnout zone downstream of the reburn zone 
     Emulsion 
     The fuel utilized in all embodiments of the invention comprises an emulsion of a hydrocarbon and water. Depending of the relative quantities of each present, the emulsion may be an oil in water emulsion or a water in oil emulsion. The two types of emulsions function differently in the instant process. 
     Where the emulsion is a hydrocarbon in water emulsion the hydrocarbon component may itself be an emulsion of varying composition in the aqueous component of the emulsion. 
     The droplet size is an important characteristic and may range in diameter from 60 to 300 micrometer or larger encasing 5 to 30 micrometers of inner droplet, preferably from 60 to 300 micrometer encasing 5 to 20 micrometers of inner droplet. 
     Aqueous Component 
     The aqueous component of the emulsion may be composed simply of water or may contain nitrogenous compounds such as urea or ammonia. 
     Where the emulsion is enhanced with a fixed nitrogen reagent, the instant process will allow the water to volatilize first and result in the process chemistry to take place in the fuel rich clouds (local sub-stoichiometric air to fuel ratios) created by the small droplets of hydrocarbons from the inner bilayer of the fuel droplets released by the secondary atomization process. 
     The emulsion comprises an aqueous phase comprising from 1% to 32% of the total volume (1 to 43% by weight) of the droplet, preferably 20% to 32% by volume (30 to 43% by weight), most preferably 15% to 25% by volume (20 to 34% by weight). 
     The oil in water emulsions usable comprise 5 to 25, preferably 5 to 20 micron size hydrocarbon droplets (SMD) in larger (80 to 300 micron) water droplets. The size of the hydrocarbon droplets which form the center portion of the water droplets is determined by the process by which the emulsion is formed and by the micro explosions of the vaporized aqueous surface of the droplets that serves to disperse the hydrocarbons. The injector and/or atomizer is the delivery system that distributes the 80 to 300 micron droplets of the oil in water emulsion to the furnace (primary atomization). 
     The water in oil emulsions usable comprise 80 to 300 micron size hydrocarbon droplets (SMD) established by the injector and/or atomizer (primary atomization) with the size of the smaller water droplets encompassed within the droplet determined by the emulsion process and are typically in the range of 5 to 30 microns or larger dispersed in the oil emulsion droplets. 
     In this process the micro explosions of the individual droplets determine the hydrocarbon droplets size (secondary atomization). 
     The percentage of water in oil in water emulsions is in the range of about 10 to 32% with optimum percentage water in the 20 to 30% range. The percentage of water in water in oil emulsions is in the range of about 1 to 10% with the optimum percentage water in the 5 to 8% range. 
     The emulsion can also be made from a urea solution or aqueous ammonia solution where the normal stoichiometric ratio (NSR) which defines the concentration of the solution (amount of urea, etc.) based on the amount of NO x  emissions exiting the primary flame zone is between 1 and 3. An example of the calculation using NH 3  (17 molecular weight) to NO x  as NO 2  (46 molecular weight) is for NSR=1: 
       NH 3  (tons)=[NO x  (tons)][17/46] 
     and for NSR=1.5: 
       NH 3  (tons)=[NO x  (tons)][25.5/46] 
     The aqueous phase of the droplets provides a means of control of the reaction temperature in the fuel rich zones, which will improve the NO removal. 
     Hydrocarbon Component 
     The hydrocarbon component is preferably composed of bitumen, atmospheric residue, heavy fuel oil, vacuum residue, asphalt, or solvent de-asphalter or a mixture thereof where the individual components of the hydrocarbon emulsion may vary greatly in proportion. 
     The amount of the hydrocarbon component in the hydrocarbon emulsion is as follows: 
     Bitumen: 57 to 99%, preferably 60 to 85%, most preferably 65 to 80% by weight. 
     Atmospheric residue: 57 to 99%, preferably 60 to 85%, most preferably 65 to 80% by weight. 
     Heavy fuel oil: 57 to 99%, preferably 60 to 85%, most preferably 65 to 80% by weight. 
     Vacuum Residue: 57 to 99%, preferably 60 to 85%, most preferably 65 to 80% by weight. 
     Asphalt: 57 to 99%, preferably 60 to 85%, most preferably 65 to 80% by weight. 
     Solvent de-asphalter: 57 to 99%, preferably 60 to 85%, most preferably 65 to 80% by weight. 
     The hydrocarbon emulsion of bitumen, atmospheric residue, heavy fuel oil, vacuum residue, asphalt, or solvent de-asphalter is produced by providing high shear to the materials as shown in  FIG. 2 . The mixture of hydrocarbons forms an emulsion in which the bitumen, vacuum residue (VTB and SDA), or asphalt droplets are small enough so that a majority of them do not break or coalesce when the emulsion is stored in a day tank or passes through the atomizer/injector into the furnace. 
     Furnace Temperature 
     To reduce the NO x , the emulsion of water (only or fixed nitrogen enhanced water) and hydrocarbon is introduced into the boiler after the primary combustion zone in a region where the temperature is in the range of about 2000° F. to 2600° F. or about 1100° C. to 1427° C., as shown in  FIG. 1 . 
     Preferably, the emulsion is injected into regions of the furnace in which the flue gas temperature is between 1900° F. (1038° C.) and 2600° F. (1427° C.), preferably between 1900° F. (1038° C.) and 2350° F. (1288° C.), most preferably between 1900° F. (1038° C.) and 2200° F. (1205° C.). 
     The process is designed to allow the disclosed reburn fuel to react with the oxygen in the reburn combustion process and to burn out almost completely. The emulsion is designed and produced so the aqueous phase is the continuous phase and the hydrocarbon phase is dispersed in the aqueous phase as very small droplets (SMD=5 to 15 micrometers). 
     In this manner the volatization of the hydrocarbons present in the hydrocarbon phase is delayed while the water volatilizes. The delay may be finely tuned to the type of furnace and combustion conditions so as to achieve and maintain a desired temperature in the secondary combustion, region to maximize NO x  removal consistent with the maintenance of other suitable operating conditions. This procedure results in the lowest possible emissions of NO x  at the lowest cost. 
     In general, it is preferred to operate reburn fuel at temperatures that are as low as possible, while still being able to complete the burnout of the reburn fuel. This increases the NO x  reduction potential directly proportional to the decrease in equilibrium NO x  as the temperature decreases. 
     However, where the fuel is very economical it is possible to overcome this temperature limitation by using more reburn fuel. Where the reburn fuel emulsion contributes and amount in the range of 8% to 20% of the total heat input to the furnace, it is necessary to use a large amount of completion air. 
     If no completion air is used and an amount of reburn emulsion, in the range of 1% to 7.9% of the total heat input is used it is only necessary to assure that the primary furnace is sufficiently air rich to supply the oxygen for burnout. 
     Where the emulsion is made from materials that are less expensive than the base fuel, higher quantities of heat inputs of reburn fuel may be used to achieve higher NOx reductions. 
     The temperature window of the presently described process is much wider than other reburn and Selected Non-Catalytic Reduction (SNCR) processes. 
     The temperature window is 19000 F (1038° C.) to 2600° F. (1427° C.). The emulsion is from 5% to 32%, preferably 20 to 30% aqueous phase and adjustments can be made to accommodate different furnaces or furnace conditions. 
     The emulsion is injected into fuel rich areas (sub-stoichiometric conditions) of the furnace and the secondary atomization and water volatization takes place in the localized fuel rich regions. 
     The ratio of aqueous phase to hydrocarbon phase in the droplets may be modified to provide an aqueous phase within the range of 5% to 34% to further modify the very local reburn temperature. 
     Amount of Reburn Fuel 
     In one embodiment, the heat input from these emulsified fuels is between 1% and 20% of the total boiler heat input. In a preferred embodiment, the heat input from these emulsified fuels is between 2% and 7.9%. Most preferably the heat input from these emulsified fuels is between 5% and 7%. 
     The droplet has an outside diameter in the range of 60 to 300 microns or larger, preferably 80 to 300 micron, most preferably 120 to 300 micron. The oleophilic inner droplet layer has a diameter of from 5 to 25 micron, preferably 6 to 20 micron, most preferably 6 to 15 micron droplets. 
     The reburn reaction takes place in the fuel rich contrary currents of the furnace zone down stream of (see attached figures for injection locations) the primary flame zone. 
     Where the aqueous phase of the emulsion contains urea or aqueous ammonia, an additional NO x  reduction is obtained from the secondary atomization characteristics of the emulsion releasing the fixed reduced nitrogen agents in the fuel rich contrary currents or the deep staged regions of the primary flame zone prior to the introduction of overfire air. 
     Although overfire air can be used in the instant process the preferred method is not to use overfire air. 
     These agents improve the NO x  reduction by reacting with the NO x  to form N 2 . The fact that this reagent reaction takes place in a localized or deep staged (localized fuel rich contrary currents) fuel rich environments allows for the process to perform effectively at a wider and higher temperature range (1900° F. to 2600° F.) for peak reduction efficiency of the reagents in a localized reducing environment. 
     This is the reason for not using overfire air in the most preferred embodiment because driving the entire furnace sub-stoichiometric (total reducing environment in the furnace) causes rapid corrosion of the boiler tubes and tube hanger metals in the boiler due to high temperature accelerated vanadium corrosion attack. 
     This is when compared to traditional SNCR which take place in an oxidizing environment with a narrow temperature window (1750° F.+/−50° F.). These are bell curves and the wider temperature range for the localized reducing environments gives the NOx reduction process more flexibility and improved NOx reduction efficiency without causing accelerated corrosion. 
     The instantly disclosed method allows for lower NSR and the least amount of ammonia slip. The most preferred temperature range for this invention is 1900° F. to 2200° F. where peak NO x  reduction efficiency for localized reducing environment is obtained with an NSR=1 to 1.5. 
     CO burnout is achieved by the excess oxygen available in the fuel gas from the primary flame zone, without the need for a completion overfire air system (OFA) or in the deep staged condition with the introduction of OFA. 
     Injection 
     The emulsion is introduced both as streams (jets) and spray droplets, usually in combination to assure better coverage. 
       FIG. 3  shows an example of a single “Y” jet dual fluid atomizer providing primary atomization using the energy from the atomizer and secondary atomization from the emulsion to both release the fixed nitrogen reagent and create the fuel rich local cloud (contrary currents). In addition, a low-pressure mechanical atomizer can be used to inject the emulsion into the furnace. Preferred methods of introducing the burnout fuel utilize either dual fluids using sour solution gas or low pressure (100 to 250 PSI range) mechanical injectors. The most preferred injection method utilizes low pressure (125 to 200 PSI range) mechanical injectors. 
     Different sized jets and atomized drops can be used depending upon the requirements of the specific furnace. The droplet size utilized is boiler and site specific and the determination of optimal sizing is well within the competence of those skilled in the art to determine. 
     Atomizing Fluid 
     Sour solution gas is a preferred atomizing fluid in the atomizers/injectors. Other atomizing fluids such as steam may be used. 
     The ratio of sour solution gas or steam to emulsion product in the atomizers/injectors is in the range of 0.05:1 to 0.5:1 atomizing fluid to emulsion product, preferably in the range of 0.05:1 to 0.20:1, most preferably in the range of 0.05:1 to 0.10:1 of sour solution gas or steam to the emulsion (on a pound per pound basis of atomizing fluid to fuel). In a highly preferred embodiment low pressure mechanical injectors requiring no atomizing fluid are utilized. 
     Chemistry 
     The chemistry of the process is complex and involves over thirty (30) chemical reactions. For illustrative purposes, the process can be represented by one (1) basic equation which occurs in a localized reducing atmosphere at a temperature in the range of about 1100° C. and 1425° C.: 
       NO x +NH 3 +H 2 O+H 2 →N 2 +H 2    
     The kinetics involved in the reburn zone to reduce NO x  are complex. The chemical reactions involved in the reburning process were first proposed by J. O. L. Wendt in the late 1960&#39;s (Wendt et al, 1973). The following discussion, derived from a report published by the U.S. Department of Energy (Farzan and Wessel, 1991), is based on the concepts introduced in this work. The major chemical reactions follow. In the presence of heat &amp; 0 2  deficiency in local clouds the reaction process shown in Equation 3.1.1-1 shows hydrocarbon radical formation in the reburn zone. 
       CH 4 →CH 3   + +H +  (hydrocarbon radicals)  (3.1.1-1) 
     These hydrocarbon radicals are produced due to the pyrolysis of the fuel in an oxygen-deficient, high temperature environment. The hydrocarbon radicals then mix with the combustion gases from the main combustion zone and react with NO to form CN radicals, NH 2  radicals, and other stable products (Equations 3.1.1-2 to 3.1.1-4). 
       CH 3   + +NO→HCN+H 2 O  (3.1.1.2) 
       N 2 +CH 3   + →NH 2   + +HCN  (3.1.1.3) 
       H+HCN→CN + +H 2   (3.1.1.4) 
     The CN and NH 2  radicals and other products can then react with NO to form N 2 , thus completing the major NO x  reduction step (Equations 3.1.1-5 to 3.1.1-7) 
       NO+NH 2   + →N 2 +H 2 O  (3.1.1.5) 
       NO+CN + →N 2 +CO  (3.1.1.6) 
       2NO+2CO→N 2 +2CO  (3.1.1.7) 
     An oxygen-deficient (reducing atmosphere) environment is critical to these reactions. If 0 2  levels are high, the NO, reduction mechanism will not occur and other reactions will predominate (Equations 3.1.1-8 and 3.1.1-9). 
       CN+0 2 →CO+NO  (3.1.1-8) 
       NH2+O 2 →H 2 O+NO  (3.1.1.9) 
     To complete the combustion process, the excess air (0 2 ) from the primary flame zone is used to complete the fuel burnout after the local reburn zones have reduced the NOx emissions. Conversion of HCN and ammonia compounds in the burnout zone may regenerate some of the decomposed NO ″  by the reactions. 
     Although some additional NO x  may be formed in the burnout zone through these reactions, the net effect of the reburn process is to reduce significantly the total quantity of NO x  emitted by the boiler. 
     The bilayer emulsion is preferably introduced through atomizing nozzles or injectors, which can handle the bilayer emulsion without breaking it down, and through jets for maximum penetration and optimum droplet size distribution. 
     The atomizers can include internal mixing, “Y” jet, and “F” jet dual fluid atomizers with a range of spray angles, including cone shaped spray angles, flat sprays, individual finger sprays and single jet sprays. These dual fluid atomizers (see  FIG. 3  as example) can use various atomizing fluids with either steam or sour solution gas as the preferred atomizing fluid and sour solution gas as the most preferred atomizing fluid. 
     The ratio of atomizing fluid to emulsion product can range from 0.05:1 to 0.5:1 preferably from 0.05:1 to 0.20:1, most preferably from 0.05:1 to 0.10:1. 
     Operating pressures may range from 20 PSIG to 150 PSIG, preferably from 75 to 125, most preferably from 100 to 125 for dual fluid injectors. The preferred injection method utilizes either dual fluids using sour solution gas or low pressure (100 to 250 PSI range) mechanical injectors. The most preferred injection method utilizes low pressure (125 to 200 PSI range) mechanical injectors. 
     Burnout or Completion Air is Used 
     In an embodiment of the invention where burnout or completion air is used, reburn fuel droplets are delivered to the total furnace reburn region. 
     Burnout or Completion Air is Not Used 
     In an embodiment of the invention where no burnout air is used, the reburn area, the area of the furnace where the furnace atmosphere is a reducing atmosphere, is injected with the reburn fuel without mixing any of the reburn fuel into other areas of the furnace where the oxidizing atmosphere is left unchanged. 
       FIG. 4  shows an example of a multi-nozzle fuel handling and delivery system to be used to inject the emulsion products into the furnace at several furnace planes, levels, and areas. 
     In an embodiment where no burnout air is used and a face fired or opposed fired utility boiler is used it is preferred to establish where the lanes of reducing mixtures are located and inject the reburn emulsion into these lanes while maintaining oxidizing lanes between the injection lanes. 
     The relative width of the lanes depends upon the amount of oxygen in the initial combustion products, the final amount of oxygen, and how much additional fuel will be injected into the reducing lanes. The absolute widths will be sufficient to allow almost complete volatilization and combustion of the hydrocarbon reburn fuel in the reducing zone. The evaporation of the urea and/or aqueous ammonia, if present in the emulsion, takes place in these reducing lanes, thus allowing for the fixed nitrogen reagent to be activated in these reducing lanes. 
     Furnace Type 
     In an embodiment of the invention where a tangentially fired utility boiler is used, it is preferred to introduce streams of emulsion one above the other in each corner of the furnace. Atomized streams maybe introduced with the jets to assure complete coverage in the proper SMD range so the secondary atomization process takes place in the reducing atmosphere locations of the furnace. It is not necessary to introduce the emulsion into every corner. The same general arrangement of the bitumen, vacuum residue, or asphalt water emulsion injection would be used with and without completion air. 
     In an embodiment of the invention where a Cyclone furnace is utilized, the NO x &#39;s present are treated in the furnace after the combustion gases have exited the cyclones. A lane arrangement is best unless completion air is used. 
     In an embodiment of the invention utilizing the SAGD or CSS process or refinery furnace, where no burnout air is used in a Once Through Steam Generator (OTSG), a package drum boiler, a field erected industrial boiler/furnace or a horizontal pass type “D” package boiler, it is preferred to introduce streams of reburn fuel emulsion into lanes of reducing mixtures established by the primary burner/atomizer (fingers of fuel rich fuel), by injecting the emulsion into these lanes and maintaining oxidizing lanes between these lanes. The relative width of the lanes depends upon the amount of oxygen in the initial combustion products, the final amount of oxygen, and how much surplus fuel is to be in the reducing lanes. The same general arrangement of reburn fuel emulsion injection is used with or without completion air. 
     In an embodiment of the invention utilizing a Circulating Fluidized Bed (CFB) boiler where no burnout air is used, it is preferable to establish alternate lanes of reducing mixtures exiting the Circulating Fluidized Bed, by injecting the reburn fuel emulsion into these lanes and maintaining oxidizing lanes between the injection lanes. The relative width of the lanes depends upon the amount of oxygen in the initial combustion products, the final amount of oxygen, and how much surplus fuel is to be in the reducing lanes. The same general arrangement of reburn fuel emulsion injection is used with and without completion air. 
       FIGS. 5 &amp; 6  show examples of the reburn injection without completion air in both a Once Through Steam Generator and a face fired utility boiler. 
     The inventive process does not require carrier air, steam, or re-circulated flue gas. The atomizing fluid is preferably sour solution gas used at heat inputs ranging from 0.35% to 2% of the total heat input of the boiler. 
     With this invention expected NOx reductions can range from 25% to 65% of the total NO x  exiting the primary flame zone. 
     The foregoing specification describes certain presently preferred embodiments of the inventive method but it should be understood that the invention is not limited thereto but may be variously embodied within the scope of the following claims.