Abstract:
A method for removing pollutants from flue gas generated by a plant having one or more burners located at an inlet end of a vertically extending stack, the flue gas being discharged through an outlet end of the stack. The pollutants are removed by an emission treatment system which includes a major component module and inlet and outlet ductwork providing fluid communications between the stack and the major component module. The major component module includes an SCR segment, a heat exchanger segment, and an ID fan, the SCR segment having at least one catalyst unit composed of materials for selectively catalyzing at least one pollutant. The method comprises the steps of drawing the flue gas from the stack and through the major component module with the ID fan, removing the pollutant from the flue gas with the SCR segment to produce a clean flue gas, and discharging the clean flue gas to the stack with the ID fan.

Description:
BACKGROUND OF THE INVENTION 
     This invention relates generally to processes and apparatus for the removal of nitrogen oxides or “NO x ” (principally nitric oxide (NO) and nitrogen dioxide (NO 2 )) from exhaust gases and the like. More particularly, the present invention relates to processes and apparatus for reducing NO x  selectively from exhaust gases produced during petroleum refining, petrochemical production and also to industrial processes producing exhaust gases containing NO x . 
     Carbonaceous fuels are burned in internal combustion engines and in a wide variety of industrial process (i.e. boilers, furnaces, heaters and incinerators, petroleum refining, petrochemical production, and the like). Excess air frequently is used to complete the oxidation of combustion byproducts such as carbon monoxide (CO), hydrocarbons and soot. Free radicals of nitrogen (N 2 ) and oxygen (O 2 ) combine chemically to form NO x , primarily NO, at high combustion temperatures. This thermal NO x  tends to form even when nitrogen is not present in the fuel. Combustion modifications which decrease the formation of thermal NO x  generally are limited by the generation of objectionable byproducts or deteriorating flame properties. 
     When discharged to the air, NO emissions oxidize to form NO 2 , which in the presence of sunlight reacts with volatile organic compounds to form ground level ozone, eye irritants and photochemical smog. Despite advancements in fuel and combustion technology, ground level ozone concentrations still exceed federal guidelines in many urban regions. Under the Clean Air Act and its amendments, these ozone non-attainment areas must implement stringent NO x  emissions regulations. Such regulations require low NO x  emissions levels that are attained only by exhaust after-treatment. When an exhaust after-treatment system is applied to a refinery or petrochemical plant, it is particularly important to minimize any impact on the operation of the underlying refining or petrochemical process. 
     Exhaust after-treatment techniques tend to reduce NO x  using various chemical or catalytic methods. Such methods are known in the art and involve non-selective catalytic reduction (NSCR), selective catalytic reduction (SCR) or selective noncatalytic reduction (SNCR). Alternatively, NO may be oxidized to NO 2  for removal by wet scrubbers. Such after-treatment methods typically require some type of reactant for removal of NO x  emissions. 
     Wet scrubbing of NO 2  produces waste solutions that represent potential sources of water pollution. Wet scrubbers primarily are used for NO x  emissions from nitric acid plants or for concurrent removal of NO 2  with sulfur dioxide (SO 2 ). High costs and complexity generally limit scrubber technology to such special applications. 
     The NSCR method typically uses unburned hydrocarbons and CO to reduce NO x  emissions in the absence of O 2 . Fuel/air ratios must be controlled carefully to ensure low excess O 2 . Both reduction and oxidation catalysts are needed to remove emissions of CO and hydrocarbons while also reducing NO x . The cost of removing excess O 2  precludes practical applications of NSCR methods to many O 2 -containing exhaust gases. 
     Chemical reactions on a solid catalyst surface of commercial SCR systems convert NO x  to N 2 . These solid catalysts are selective for NO x  removal and do not reduce emissions of CO and unburned hydrocarbons. Large catalyst volumes are normally needed to produce low levels of NO x . The catalyst activity depends on temperature and declines with use. Normal variations in catalyst activity are accommodated only by enlarging the volume of catalyst or limiting the range of combustion operation. Catalysts may require replacement prematurely due to sintering or poisoning when exposed to high levels of temperature or exhaust contaminants. 
     Commercial SCR systems primarily use ammonia (NH 3 ) as the reductant. Excess NH 3  needed to achieve low NO x  levels tends to result in NH 3  breakthrough as a byproduct emission. Even under normal operating conditions, SCR systems require a uniform distribution of NH 3  relative to NO x  in the exhaust gas. NO x  emissions, however, are frequently distributed nonuniformly, so low levels of both NO x  and NH 3  breakthrough may be achieved only by controlling the distribution of injected NH 3  or mixing the exhaust to a uniform NO x  level. 
     SUMMARY OF THE INVENTION 
     Briefly stated, the invention in a preferred form is a method for removing pollutants from flue gas generated by a plant having one or more burners located at an inlet end of a vertically extending stack, the flue gas being discharged through an outlet end of the stack. The pollutants are removed by an emission treatment system which includes a major component module and inlet and outlet ductwork providing fluid communications between the stack and the major component module. The major component module includes an SCR segment, a heat exchanger segment, and an ID fan, the SCR segment having at least one catalyst unit composed of materials for selectively catalyzing at least one pollutant. The method comprises the steps of drawing the flue gas from the stack and through the major component module with the ID fan, removing the pollutant from the flue gas with the SCR segment to produce a clean flue gas, and discharging the clean flue gas to the stack with the ID fan. 
     When the pollutant to be removed is NO x , the emission treatment system also includes an ammonia addition subsystem which is in fluid communication with the inlet ductwork, and at least one catalyst unit is composed of materials for selectively catalyzing NO x . In addition, the method also comprises the step of mixing ammonia vapor with the flue gas upstream of the SCR segment. The ammonia vapor is mixed with the flue gas by injecting the ammonia vapor into the inlet ductwork and mixing the ammonia vapor with the flue gas over the length of the inlet ductwork. The mixing is facilitated by creating turbulence in the flue gas by changing the direction of flue gas flow from a vertical direction in the stack to a horizontal direction in the inlet ductwork. 
     The ammonia addition subsystem includes a source of ammonia vapor, an ammonia injection grid disposed in the inlet ductwork, an ammonia vapor pipe providing fluid communication between the source of ammonia vapor and the ammonia injection grid, and a throttle valve disposed in the ammonia vapor pipe. The rate of ammonia addition is controlled by regulating the throttle valve with an ammonia addition controller. In a first control scheme, the throttle valve is regulated on the basis of the flue gas flow rate and the level of NO x  entering and exiting the emission treatment system. In a second control scheme, the throttle valve is regulated on the basis of ammonia carry-over. In a third control scheme, the throttle valve is regulated on the basis of the fuel flow rate and the composition of the fuel. 
     The flow rate of the flue gas through the major component module is controlled by regulating the pressure decrease across the ID fan with a controller. A damper controlling the pressure decrease across the ID fan is regulated on the basis of the ID fan supply and discharge pressures and the differential pressures across the SCR and heat exchange segments. 
     The plant also has a boiler and a feed pump circulating feedwater to the boiler, the flow of the feedwater through the heat exchange segment is controlled by regulating the speed of the feed pump with a pump speed controller. The feed pump is regulated on the basis of the feedwater temperature and pressure in the feed and return lines. 
     It is an object of the invention to provide a method of removing pollutants from flue gas which is easily adapted to the removal of many pollutants. 
     It is also an object of the invention to provide a method of removing pollutants from flue gas which is relatively simple to perform. 
     Other objects and advantages of the invention will become apparent from the drawings and specification. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present invention may be better understood and its numerous objects and advantages will become apparent to those skilled in the art by reference to the accompanying drawings in which: 
         FIG. 1  is a perspective view of an emission treatment system in accordance with the invention; 
         FIG. 2  is a simplified, schematic view, partly in cross section, of the system of  FIG. 1  installed on an ethylene heater; 
         FIG. 3  is an enlarged, schematic, cross section view of the selective catalytic reduction segment of  FIG. 2 ; 
         FIG. 4  is an enlarged, schematic, cross section view of Area IV of  FIG. 2 ; 
         FIG. 5  is a flow diagram of the method of installing the emission treatment system of  FIG. 1 ; 
         FIG. 6  is a flow diagram of the preparation sub-steps of the method of  FIG. 5 ; 
         FIGS. 7   a  and  7   b  are a flow diagram of the initial installation sub-steps of the method of  FIG. 5 ; 
         FIG. 8  is a flow diagram of the tie-in outage sub-steps of the method of  FIG. 5 ; 
         FIG. 9  is a simplified, schematic view of the ammonia addition subsystem; 
         FIG. 10  is a simplified, schematic view of the fan control system; and 
         FIG. 11  is a simplified, schematic view of the heat exchanger coolant control system. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     As concern for the environment grows, greater efforts are being undertaken to reduce emissions of known pollutants, such as particulate matter, NO x , SO x , mercury, etc, by the promulgation of more stringent control requirements. For the refinery and petrochemical industries, the first of these more stringent requirements focuses on NO x  reduction. 
     With reference to the drawings wherein like numerals represent like parts throughout the several figures, an emission treatment system  10  in accordance with the present invention reduces NO x  by SCR technology, provides for future emissions control of other pollutants, and is a stand-alone system that may be installed on the ground along side the existing equipment, or on legs along side the existing equipment, or on top of the existing equipment, thereby reducing the downtime of the refinery or petrochemical production equipment. 
     The emission treatment system  10  may be utilized with most refinery and petrochemical production systems. However, for descriptive purposes, the system  10  is described herein installed with an ethylene-cracking furnace  12  ( FIG. 2 ). Fuel is fired by burners  14  located at the bottom or side of the furnace  12  generating high temperature gas and NO x . The “cracking” of hydrocarbon molecules into simpler molecules occurs in a coil  16  in this highest temperature zone. As the furnace gases pass upward through the furnace, heat is recovered from the flue gas by a series of additional coils  18  which contain either cracking feedstock for preheating or water/steam for use in this process or other processes. Typically, ethylene-cracking furnaces  12  have one or more induced draft (ID) fans  20  located on top of the heater connected by a vertical stack  22 . Ethylene-cracking furnaces  12  typically run for several years between significant outages and are a key provider of feedstock for other processes within the refinery or petrochemical plant. Therefore, the downtime to install an SCR is severely limited and costly to the owner. 
     SCR NO x  removal processes are typically most efficient at temperatures of 500–750° F. Gases at this temperature are typically found just upstream of the ethylene-cracking furnace boiler feedwater heating coil  24  and the ID fan  20 . One conventional approach for an SCR retrofit is to shut down the furnace  12 , cut into the stack  22  at the appropriate location, lift up the downstream sections and install the SCR. This is much too time consuming to be an economically attractive solution. 
     The subject emission treatment system  10  includes a stand-alone, modular major component module  26 , typically at ground level, that includes an SCR segment  28 , a boiler feedwater heat exchange segment  30 , and an ID fan  32 . By “abandoning” the stack ID fan  20  and the ethylene-cracking furnace boiler feedwater heating coil  24  installed in the stack  22 , the emission treatment system  10  is installed without requiring any major modifications to the ethylene-cracking furnace  12 . This allows installation of the emission treatment system  10  without significantly interrupting use of the ethylene-cracking furnace  12 . The major component module  26  may also be placed on legs above the ground, or even on top of the existing furnace  12 , as individual application circumstances may require. The new, system ID fan  32  is sized to provide for the increased draft requirements of the emission treatment system  10 , principally for the SCR segment  28 . The boiler feedwater heat exchange segment  30  may have higher heat recovery efficiency than the stack boiler feedwater heating coil  24 , depending on the design and materials of the stack boiler feedwater heating coil  24 , providing an improvement in overall cycle efficiency and/or reduced fuel costs. The stand-alone nature of the system  10  allows for future modification of the SCR segment  28  or the addition of additional segments for emissions control of other pollutants. 
     With further reference to  FIG. 2 , the emission treatment system  10  also includes a blanking member  34  or bypass flapper  34 ′ mounted within the vertical stack  22 , just upstream of the ethylene-cracking furnace boiler feedwater heating coil  24 . The blanking member  34  is installed across the stack  22  to permanently cutoff all flow through the ethylene-cracking furnace boiler feedwater heating coil  24  and the stack ID fan  20 . The bypass flapper  34 ′ is installed across the stack  22  to selectively cutoff all flow through the ethylene-cracking furnace boiler feedwater heating coil  24  and the stack ID fan  20 . Flue gas take-off and return openings  36 ,  38  are formed in the stack  22  just upstream of the blanking member/bypass flapper  34 ,  34 ′ and just downstream of the stack ID fan  20 , respectively. Inlet ductwork  40  connected to flue gas take-off opening  36  and an inlet transition piece  42  in the upper end portion of the major component module  26  and outlet ductwork  44  connected to flue gas return opening  38  and the outlet of system ID fan  32  provide fluid communication between the stack  22  and the major component module  26 . The inlet ductwork  40  includes a horizontal run  46  and a vertical run  48 , each having a nominal length of thirty (30) feet. Dynamic vanes  50  may be positioned in the elbow  52  between horizontal run  46  and vertical run  48  to reduce the pressure drop through the elbow ( FIG. 4 ). 
     Conventional utility boiler applications having SCR systems generally use ammonia (NH 3 ) as a reductant and include an ammonia addition system which provides a mixture of ammonia diluted with air or flue gas to uniformly distribute the ammonia across the face of the SCR catalyst, which is located a relatively short distance downstream of the injector. Accordingly, a conventional ammonia addition system consists of a control system, a source of ammonia (NH 3 ) vapor, a static mixer, at least one blower, and an injector which includes multiple spray lines, each having multiple spray nozzles. The ammonia vapor source injects ammonia vapor into the static mixer. Dilution air is blown by the blower(s) into the static mixer to dilute the ammonia vapor and propel the diluted ammonia vapor out of the ammonia addition subsystem via the injector nozzles. 
     The subject emission treatment system  10  includes an ammonia addition subsystem  54  which takes advantage of the relatively long lengths of the horizontal and vertical runs  46 ,  48  to provide for proper mixing of the ammonia vapor in the flue gas stream. The ammonia addition subsystem  54  does not include dilution air blowers, blower controls, and the larger diameter diluted ammonia ducting. The ammonia addition subsystem  54  consists of only three major components, a controller  56 , a source of ammonia vapor  58 , and an ammonia injection grid (AIG)  60 . Only a small diameter ammonia vapor pipe  62  is needed. As discussed in greater detail below, the AIG  60  is preferably installed within ten (10) feet of the stack  22 . A static mixer/diffuser  64  may be positioned in the horizontal run  46  in the event that the AIG  60  must be located at a significant distance from the stack  22  or to simply provide additional assurance of complete mixing of the ammonia vapor and the flue gas. The inlet transition piece  42  at the entrance to the major components module  26  distributes the ammonia vapor/flue gas mixture evenly across the inlet to the downstream SCR segment  28 . 
     In addition, the AIG  60  is much simpler than the injectors of conventional systems, having a much reduced number of spray lines and no nozzles, the ammonia vapor being sprayed through openings in the sidewall of the spray line. The exact number of spray lines and openings is dependent on the installation specific parameters, such as the flue gas flow rate and the required rate of ammonia addition. The AIG  60  is preferably located within ten feet of the stack  22  to take advantage of the turbulence within the flue gas steam created by the “bend” formed by the blanking member/bypass flapper  34 ,  34 ′ and opening  36 . The turbulence further ensures that the ammonia vapor is thoroughly mixed with the flue gas. Analysis has shown that sufficient ammonia/flue gas mixing occurs even if the AIG  60  is located in horizontal run  46  within ten (10) feet of the stack  22 . It is possible that additional analysis would show that sufficient mixing will also occur at greater distances from the stack  22 . The motive force for injecting the ammonia vapor into the flue gas stream may provided by the vapor pressure of the ammonia in the ammonia source  58 . As shown in Table 1, the pressure of the ammonia vapor is sufficient over a full range of expected ambient temperatures to provide the required motive force. 
     
       
         
               
               
               
             
               
               
               
             
           
               
                   
                 TABLE 1 
               
               
                   
                   
               
               
                   
                 Ambient Temperature 
                 NH 3  Vapor Pressure 
               
               
                   
                 (° F.) 
                 (psia) 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                   
                 30 
                 60 
               
               
                   
                 70 
                 129 
               
               
                   
                 100 
                 242 
               
               
                   
                   
               
             
          
         
       
     
     With reference to  FIG. 3 , the SCR segment  28  contains catalyst units  66  which remove NO x . The catalyst units  66  are conventional units, each having nominal dimensions of three feet—three inches by six feet—six inches (3.25′×6.5′). As shown in  FIG. 3 , upper and lower groups  68 ,  70  of catalyst units  66 , each including one to eight units  66 , may be positioned within the SCR segment housing  72 . Intermediate support rails  74  carry the weight of the upper group  68  of catalyst units  66 , while allowing the flue gas/ammonia vapor mixture to access all of the catalyst units  66  contained within the SCR segment housing  72 . If only three catalyst units  66  are required to remove the NO x , a blanking mechanism  76  may be included in the SCR segment  28  to selectively block half of the catalyst units  66 . Such a blanking mechanism  76  may comprise one or more flappers  77 ,  77 ′ which each have a single side edge pivotally mounted to opposite inside surfaces of the housing  72 . Initially, flapper  77  is in the vertical, open position (allowing flow through the catalyst units  66  disposed under flapper  77 ) and flapper  77 ′ is in the horizontal, closed position (preventing flow through the catalyst units disposed under flapper  77 ′). As the catalyst units  66  disposed under flapper  77  become depleted, flapper  77 ′ is repositioned to the vertical, open position (allowing flow through the catalyst units  66  disposed under flapper  77 ′). Flapper  77  may be repositioned to the closed position. Alternatively, flapper  77  may remain in the open position, to allow use of any residual NO x  removal capability of the catalyst units  66  disposed thereunder. If it is expected that flapper  77  will never be positioned in the close position, only flapper  77 ′ need be installed. 
     Alternatively, the SCR segment  28  may contain upper and lower groups  68 ,  70  of two catalyst units  66  or a single layer of one to eight catalyst units  66 , depending on the amount of NO x  which must be removed and other application specific considerations. If space permits, and if other pollutants (e.g. CO, hydrocarbons, etc.) must be removed from the flue gas, catalyst units  78  targeting such other pollutants or catalyst units  80  removing NO x  plus such other pollutants may be included in the SCR segment  28 . Alternatively, the housing  82  located above the SCR segment  28  may be converted into a second SCR segment to provide for removing additional NO x  and/or other pollutants. 
     As noted above, the emission treatment system  10  may be installed without significantly interrupting use of the ethylene-cracking furnace  12  by eliminating the need to make major modifications to the stack  22 . The impact on the plant is further reduced by the modular construction of the major component module  26 . The major component module  26  includes upper, middle and lower sub-modules  84 ,  85 ,  86 . The lower sub-module  86  includes the ID fan  32 , an outlet transition piece  88 , and power and controls boxes (not shown), all of which are mounted on a base plate  90 . The middle sub-module  85  includes the heat exchange segment  30 . The upper sub-module  84  includes the SCR segment  28  and the inlet transition piece  42 . Each of the sub-modules  84 ,  85 ,  86  is sized to fit on a conventional flat-bed tractor trailer. 
     With reference to  FIGS. 5–8 , installation of the emission treatment system  10  is a relatively simple process, providing for a low on-site construction time and minimal disruption of normal refinery activities. A number of activities are required take place in preparation  92  for the arrival of the major component module  26 . The installation site of the major component module  26  must be selected  94  and an appropriate foundation installed  96  at such installation site. The location of the flue gas take-off and return openings  36 ,  38  must be determined  98 . The heat exchanger take-off and return must be identified  100 . Sources for the ammonia vapor, electric power, and control air (if needed) must be identified  102 ,  104 ,  106 . Finally, all control system interfaces must be identified  108 . It should be appreciated that the majority of these tasks may be conducted in parallel. 
     Initial installation  110  begins by setting  112  the lower sub-module  86  on the foundation with a crane and securing  114  the base plate  90  to the foundation with anchor bolts (not shown). The crane is then used to set  115  the middle sub-module  85  on top of lower sub-module  86 , set  116  the upper sub-module  84  on top of middle sub-module  85  and the three sub-modules  84 ,  86  are welded  118  together. The crane is then used to set  120  the inlet and outlet ductwork  40 ,  44  in place, along with its appropriate support structure, and the ductwork  40 ,  44  is connected to inlet transition piece  42  and outlet transition piece, respectively. The ammonia injection grid (AIG)  60  is installed  121 , including connection to the ammonia vapor source  58 . Connecting flanges  122  are welded  124  to the stack  22  at the location where the flue gas take-off and return openings  36 ,  38  will be cut, but openings  36  and  38  are not cut at this time. Interconnecting piping  126  is run  128  between the new heat exchanger segment  30  and the heat exchanger take-off and return and connected to heat exchanger segment  30 . Using the crane again, platforms and ladders  130  are mounted  132  to the major components module  26 . The instrumentation is installed and the ammonia vapor feed, electric power, control, and instrumentation connections are installed  134  with the corresponding system devices. The catalyst units  66  are loaded  136  in the SCR segment  28 . Commissioning and pre-start procedures are conducted  138 . During a scheduled tie-in outage  140 , the flue gas take-off and return openings  36 ,  38  are cut  142 , the blank/damper  34 ,  34 ′ is installed  144  within the stack  22 , and the heat exchanger feed and return lines  126  are connected  146  to the heat exchanger segment  30  and the take-off and the return. Finally, the ethylene-cracking furnace  12  and emission treatment system  10  are started-up  150 . 
     As discussed above, the motive force for injecting the ammonia vapor into the flue gas stream is provided by the vapor pressure of the ammonia in the ammonia source  58 . With reference to  FIG. 9 , a throttle valve  152  in ammonia vapor pipe  62  controls the flow of the ammonia vapor into the AIG  60 . Preferably, valve  152  is controlled by the controller  56  on the basis of the flue gas flow rate, the amount of NO x  entering the emission treatment system  10 , and the amount of NO x  exiting the emission treatment system  10 . A flow sensor  154  positioned upstream of AIG  60  and NO x  detectors  156 ,  158  located upstream of AIG  60  and at the outlet of fan  32 , respectively, provide the necessary inputs to controller  56  to control ammonia addition in this manner. Alternatively, ammonia addition may be controlled on the basis of ammonia carry-over or slip. For control in this manner, an ammonia sensor  160  may be positioned at the outlet of fan  32 . In still another alternative, ammonia addition may be controlled on the basis of the fuel flow to the burners  14  and the composition of such fuel. Interconnections  162  may be provided between controller  56  and the fuel control  164  of the furnace  12  to control in this manner. Ammonia vapor flow may be monitored by pressure, temperature and flow detectors  166 ,  168 ,  170  disposed in ammonia vapor pipe  62 . 
     With reference to  FIG. 10 , proper flow of the flue gas through the emission treatment system  10  is maintained by a controller  172  which controls the position of a damper  173  in the inlet of fan  32  on the basis of the fan supply pressure, the fan discharge pressure, the differential pressure across SCR  28 , and the differential pressure across heat exchanger  30 . Pressure detectors  174 ,  176  at the inlet and outlet of fan  32 , respectively, and differential pressure detectors  178 ,  180  on SCR  28  and heat exchanger  30 , respectively, provide necessary inputs to controller  172 . The temperature of the flue gas stream may be monitored by a temperature detector  182  positioned upstream of AIG  60  ( FIG. 9 ). 
     With reference to  FIG. 11 , a feed pump  184  in the heat exchanger feed and return lines  126  controls the flow of the boiler feedwater through heat exchanger  30 . The speed of pump  184  is controlled by a controller  186  on the basis of the boiler feedwater pressure and temperature. Pressure sensors  188  and temperature sensors  190  positioned in the boiler feedwater inlet and outlet of the heat exchanger  30  provide the necessary inputs to controller  56  to feedwater flow in this manner. Temperature detectors  192 ,  194  in the flue gas stream upstream and downstream of heat exchanger  30 , respectively, allow the efficiency of the heat exchanger  30  to be monitored. 
     The emission treatment system  10  described above is intended for use in treating flue gas having little or no sulfur. If sulfur is present or expected to be present in the flue gas, such sulfur must be removed before the flue gas enters the SCR segment  28 . The major components module  26  is also described above as a vertical system. The benefit of such a vertical system is that it reduces the size of the foot print required for installing the module  26 . However, if the foot print size is not a concern, the major components module  26  may be installed as a horizontal system, thereby providing easier access to the SCR and heat exchange segments  28 ,  30 . 
     Many ethylene-cracking furnaces  12  have relied on “first generation” low NO x  burners to reduce NO x  emissions to levels which were acceptable under the old emissions standards. However, newer “second generation” low NO x  burners must be used to attain levels which are acceptable under the new emissions standards. The second generation low NO x  burners adversely affect the efficiency of the furnace  12  due to the different flame shape and heat distribution produced by such burners, compared to first generation low NO x  burners. It should be appreciated that the use of the emission treatment system  10  allows the continued use of the first generation low NO x  burners, thereby maintaining the ethylene-cracking furnace  12  at peak efficiency. In addition, burner control systems may be used which optimize burner efficiency. 
     While preferred embodiments have been shown and described, various modifications and substitutions may be made thereto without departing from the spirit and scope of the invention. Accordingly, it is to be understood that the present invention has been described by way of illustration and not limitation.