The present invention relates to apparatus and processes for combustion, such as to provide for lower emissions of undesirable combustion products.

Combustion units such as those large industrial boilers which may be used in the generation of electricity or steam for supply to homes and industry, even when operating efficiently, typically produce a number of combustion products which are undesirable. These undesirable combustion products include NO _x and SO _x compounds which are known to be damaging to health and the natural environment.

Governments and industry have for a number of years sought to reduce the emission of NOx and SO _x through regulation and technological advance. While there has been some success in the development of so-called "clean" power supplies to help achieve these aims, the need to maintain a stable and ready supply of electricity to populations means that many older power stations utilising, for example, coal fired furnaces which can produce relatively high concentrations of NO _x and SO _x remain in use and are likely to be utilised for many years to come. Some existing coal fired power stations have been retro-fitted with systems for reducing NOx and SO _x emissions. In relation to the reduction of NO _x , such systems may include means for inducing a "staged" combustion by reducing the quantity of air in the initial combustion zones such that there is a sub-stoichiometric air-to-fuel ratio. Some such systems involve the introduction of a portion (often around 10% to 15%) of the air provided to the furnace above the region of the burners and are known as "over fire air" (OFA) systems. Boosted over fire air (BOFA) systems typically provide a larger proportion of the air to the supplied to the boiler (around 10% to 15% of the total) and where deployed in conjunction with OFA systems, the combined air flow through the BOFA and OFA systems is typically less that 20% of the total air flow to the furnace.

Other systems which include the injection of air to the boiler above the burner region include a rotating opposed fire air system, details of which are set out in US5809910. Such systems are typically configured to supply a very large proportion of the total combustion air flow to the boiler through high pressure injectors, typically in a proportion between 30% and 35%. Further alternative methods of reducing NO _x and SO _x in flue gas include the use of selective catalytic reduction (SCR) technologies which although effective can be extremely expensive to install and run. There is a desire to provide a combustion unit and a method for operating a combustion unit which minimises the production of NO _x in normal use. In particular, there is a regulatory need for a combustion unit which when burning fossil fuels, for example for the generation of electricity, produces NO _x at a level no higher than 200mg/Nm ³ in flue gas at 6% O2 concentration on dry base (the same base being used to describe NO _x concentration in flue gas hereafter). There is a further need for apparatus that can be retrofitted to existing combustion units to achieve similarly low NO _x emissions, and these combustion units may have already have low NO _x combustion technologies installed.

Existing rotating opposed fire air systems have proved very successful in reducing NO _x emissions from combustion units such as those in coal-fired power stations. However, one drawback of those systems is that they typically require the use of powerful fans which consume large quantities of power. There is therefore a desire for a system which can provide the same efficient power generation and low NO _x emissions as existing rotating opposed fire air systems, while consuming less power in operation.

In a first aspect, the present invention provides a combustion unit comprising

a furnace;

one or more combustion injectors configured to inject fuel and/or combustion air into the furnace at at least one combustion plane;

one or more secondary injectors configured to inject air into the furnace at a ratio of between 2% and 20% of the total combustion air flow to the furnace at at least one secondary injection plane, the secondary injection plane being above the combustion plane;

a plurality of tertiary injectors configured to inject air into the furnace at a ratio of greater than 15% of the total air flow to the furnace at at least one tertiary injection plane, the tertiary injection plane being above the secondary injection plane.

Preferably, the tertiary and secondary injectors are configured such that the combined air flow through the secondary and tertiary injectors is in a ratio greater than 30% of the total air flow to the furnace Surprisingly, the inventors have found that the inclusion of secondary injectors (such as OFA injectors) in the furnace between the combustion injectors and the tertiary injectors, similar NO _x reduction performance and boiler efficiency can be achieved while consuming less power in fans driving the air flow to the tertiary injectors than in the absence of those secondary injectors.

Preferably, the tertiary injectors are configured to inject air to the furnace at a ratio of greater than 20% (e.g. greater than 25%) of the total airflow to the furnace, and/or the secondary injectors are configured to inject air to the furnace at a ratio of less than 15% (e.g. less than 10%) of the total air flow to the furnace. Preferably, the tertiary injectors are configured to inject air into the furnace at a ratio of less than 35% of the total air flow to the boiler. Preferably, the tertiary injectors are configured to inject air to the furnace at a nozzle pressure of at least two times the nozzle pressure of the secondary injectors. Preferably, the tertiary injectors are configured to inject air to the furnace at a nozzle pressure greater than 3 kPa (e.g. at least 4 kPa or at least 5 kPa, for example 5 kPa to 10 kPa). Preferably, the secondary injectors are configured to deliver air to the furnace at a nozzle pressure of between 0.25 kPa and 1.5 kPa.

Preferably, the tertiary injectors are configured to inject air to the furnace at a temperature from 100°C to 300°C, e.g. from 200°C to 250°C and/or the secondary injectors are configured to inject air to the furnace at a temperature from 100°C to 300°C, e.g. from 200°C to 250°C.

Preferably, the furnace comprises an inwardly protruding nose portion extending from an inner wall, the nose portion positioned above the tertiary injectors. In some embodiments, the or each tertiary injection plane is positioned closer to the nose portion than to the combustion plane or planes. Additionally or alternatively, the furnace comprises a steam exchanger located above the tertiary injection plane. In some embodiments, the or each tertiary injection plane is positioned closer to the steam exchanger than to the combustion plane or planes.

Preferably, the tertiary injectors are configured to provide a maximum turbulent kinetic energy in use at or about the tertiary injection plane is greater than around 60 m ² /s ² , for example greater than 80 m ² /s ² or 100 m ² /s ² . Additionally or alternatively, the secondary injectors are configured to provide a maximum turbulent kinetic energy in use at, around or below the secondary injection plane is 60 m ² /s ² or less, for example less than 50 m ² /s ² . Preferably, the tertiary injectors are configured to induce fluid rotation in the furnace in use.

Preferably, the combustion unit comprises a utility boiler configured to operate at a load of up to 700MW {e.g. up to 550MW or up to 500MW) while producing less than 200 mg/Nm ³

Preferably, the furnace comprises a selective non catalytic reduction system configured to supply reduction compounds (e.g. urea) to the boiler above the tertiary injection plane and preferably above the or a nose portion.

In another aspect of the invention, there is provided a method of operating a combustion unit, the combustion unit comprising:

a furnace;

one or more combustion injectors configured to inject fuel and/or combustion air into the furnace at at least one combustion plane;

one or more secondary injectors configured to inject air into the furnace at at least one secondary injection plane, the secondary injection plane being above the combustion plane; a plurality of tertiary injectors configured to inject air into the furnace at at least one tertiary injection plane, the tertiary injection plane being above the secondary injection plane; the method comprising

operating the secondary injectors to provide air to the furnace at a ratio of between 2% and 20% of the total air flow to the furnace; and

operating the tertiary injectors to provide air to the furnace at a ratio of greater than 15% of the total air flow to the furnace.

Preferably, the method comprises operating the tertiary injectors to inject air to the furnace at a ratio of greater than 20% (e.g. greater than 25%) of the total airflow to the furnace, and/or operating the secondary injectors to inject air to the furnace at a ratio of less than 15% (e.g. less than 10%) of the total air flow to the furnace. Preferably, the method comprises operating the tertiary and secondary injectors such that the combined air flow through the secondary and tertiary injectors is in a ratio greater than 30% of the total air flow to the furnace Preferably, the method comprises operating the tertiary injectors to inject air into the furnace at a ratio of less than 35% of the total air flow to the boiler. Preferably, the method comprises operating the tertiary injectors to inject air into the furnace at a nozzle pressure of at least twice the nozzle pressure of the secondary injectors. The method may also comprise operating the tertiary injectors to inject air to the furnace at a nozzle pressure greater than 3 kPa (e.g. at least 4 kPa or at least 5 kPa, for example 5 kPa to 10 kPa). Additionally or alternatively, the method comprises operating the secondary injectors to deliver air to the furnace at a nozzle pressure of between 0.25 kPa and 1.5 kPa.

Preferably the method comprises operating the tertiary injectors to inject air to the furnace at a temperature from 100°C to 300°C, e.g. from 200°C to 250°C and/or operating the secondary injectors to inject air to the furnace at a temperature from 100°C to 300°C, e.g. from 200°C to 250°C.

Preferably, the furnace comprises an inwardly protruding nose portion extending from an inner wall, the nose portion positioned above the tertiary injectors. In some embodiments, the or each tertiary injection plane is positioned closer to the nose portion than to the combustion plane or planes. . Additionally or alternatively, the furnace comprises a steam exchanger located above the tertiary injection plane. In some embodiments, the or each tertiary injection plane is positioned closer to the steam exchanger than to the combustion plane or planes.

Preferably, the method comprises operating the tertiary injectors to provide a maximum turbulent kinetic energy at or about the tertiary injection plane greater than around 60 m ² /s ² , for example greater than 80 m ² /s ² or 100 m ² /s ² . In some embodiments, the method comprises operating the secondary injectors to provide a maximum turbulent kinetic energy at, around or below the secondary injection plane of 60 m ² /s ² or less, for example less than 50 m ² /s ² .

Preferably, the method comprises operating the tertiary injectors to induce fluid rotation in the furnace.

Preferably, the combustion unit comprises a utility boiler and the method comprises operating the utility boiler at a load of up to 700MW {e.g. up to 550MW or up to 500MW) while producing less than 200 mg/Nm ³ NO _x .

Preferably, the furnace comprises a selective non catalytic reduction system and the method comprises using the SNCR system to supply reduction compounds (e.g. urea) to the boiler above the tertiary injection plane and preferably above the or a nose portion. In another aspect, the invention provides a method of retrofitting a NO _x reduction system to a combustion unit, the combustion unit comprising

a furnace;

one or more combustion injectors configured to inject fuel and/or combustion air into the furnace at at least one combustion plane;

one or more secondary injectors configured to inject air into the furnace at at least one secondary injection plane, the secondary injection plane being above the combustion plane; the method comprising

installing a plurality of tertiary injectors and configuring the tertiary injectors to inject air into the furnace at at least one tertiary injection plane, the tertiary injection plane being above the secondary injection plane;

configuring the secondary injectors to inject air to the furnace at a ratio of between 2% and 20% of the total air flow to the furnace;

configuring the tertiary injectors to inject air to the furnace at a ratio of greater than 15% of the total air flow to the furnace.

In another aspect, the invention provides a method of retrofitting a NO _x reduction system to a combustion unit, the combustion unit comprising

a furnace;

one or more combustion injectors configured to inject fuel and/or combustion air into the furnace at at least one combustion plane;

the method comprising

installing one or more secondary injectors configured to inject air into the furnace at at least one secondary injection plane, the secondary injection plane being above the combustion plane;

installing a plurality of tertiary injectors and configuring the tertiary injectors to inject air into the furnace at at least one tertiary injection plane, the tertiary injection plane being above the secondary injection plane;

configuring the secondary injectors to inject air to the furnace at a ratio of between 2% and 20% of the total air flow to the furnace;

configuring the tertiary injectors to inject air to the furnace at a ratio of greater than 15% of the total air flow to the furnace.

Preferably, the method comprises configuring the tertiary injectors to inject air to the furnace at a ratio of greater than 20% (e.g. greater than 25%) of the total airflow to the furnace, and/or configuring the secondary injectors to inject air to the furnace at a ratio of less than 15% (e.g. less than 10%) of the total air flow to the furnace. Preferably, the method comprises configuring the tertiary and secondary injectors such that the combined air flow through the secondary and tertiary injectors is in a ratio greater than 30% of the total air flow to the furnace. Preferably, the method comprises configuring the tertiary injectors to inject air into the furnace at a ratio of less than 35% of the total air flow to the boiler. Preferably, the method comprises configuring the tertiary injectors to inject air into the furnace at a nozzle pressure of at least twice the nozzle pressure of the secondary injectors. In some embodiments, the method comprises configuring the tertiary injectors to inject air to the furnace at a nozzle pressure greater than 3 kPa (e.g. at least 4 kPa or at least 5 kPa, for example 5 kPa to 10 kPa). Additionally or alternatively, the method comprises configuring the secondary injectors to deliver air to the furnace at a nozzle pressure of between 0.25 kPa and 1.5 kPa.

Preferably, the method comprises configuring the tertiary injectors to inject air to the furnace at a temperature from 100°C to 300°C, e.g. from 200°C to 250°C. In some embodiments, the method comprises configuring the secondary injectors d to inject air to the furnace at a temperature from 100°C to 300°C, e.g. from 200°C to 250°C.

Preferably, the furnace comprises an inwardly protruding nose portion extending from an inner wall, the method comprising positioning the tertiary injectors such that the or each tertiary injection plane is below the nose portion. Preferably, the method comprises positioning the tertiary injectors such that the or each tertiary injection plane is positioned closer to the nose portion than to the combustion plane or planes. . Additionally or alternatively, the furnace comprises a steam exchanger located above the tertiary injection plane. Preferably, the method comprises positioning the tertiary injectors such that the or each tertiary injection plane is positioned closer to the steam exchanger than to the combustion plane or planes.

Preferably, the method comprises configuring the tertiary injectors to provide a maximum turbulent kinetic energy at or about the tertiary injection plane of greater than around 60 m ² /s ² , for example greater than 80 m ² /s ² or 100 m ² /s ² . In some embodiments, the method comprises configuring the secondary injectors to provide a maximum turbulent kinetic energy at, around or below the secondary injection plane of 60 m ² /s ² or less, for example less than 50 m ² /s ² . Preferably, the method comprises configuring the tertiary injectors to induce fluid rotation in the furnace in use.

Preferably, the combustion unit comprises a utility boiler and the method comprising configuring the utility boiler to operate at a load of up to 700MW (e.g. up to 550MW or up to 500MW) while producing less than 200 mg/Nm ³ NO _x .

Preferably, the method comprises installing a selective non catalytic reduction system and configuring the selective non catalytic reduction system to supply reduction compounds (e.g. urea) to the boiler above the tertiary injection plane and preferably above the or a nose portion.

Embodiments of the invention will now be discussed with reference to the following drawings:

Figure 1 shows a cross section of a furnace before retrofitting of an apparatus according to the invention;

Figure 2 shows a cross section of a furnace according to the present invention;

Figure 3 shows a diagram of a rotating opposed fire air system for installation in a combustion unit of the present invention;

Figure 4 shows a comparison of temperatures at different positions in the furnace of the invention and an unmodified furnace;

Figure 5 shows a comparison of oxygen concentration at different positions in the furnace of the invention and an unmodified furnace;

Figure 6 shows a comparison of carbon monoxide concentration at different positions in the furnace of the invention and an unmodified furnace;

Figure 7 shows a comparison of NO _x concentration at different positions in the furnace of the invention and an unmodified furnace;

Figure 8 shows a comparison of turbulent kinetic energy at different positions in the furnace of the invention and an unmodified furnace;

Figure 9 shows a plot of turbulent kinetic energy against height in furnace for a furnace of the invention and an unmodified furnace;

Figure 10 shows a trace of the SNCR injection in a furnace according to the invention. A combustion unit according to the present invention was produced by retrofitting an apparatus into a 500MW utility boiler of typical construction. The boiler has a furnace 10 shown in cross section in Figure 1. This twin-tangential fired furnace 10 is 42.52 m high, 24.43 m wide and 11.06 m deep. In total, there are six burners 12 located at each corner. Each burner group includes two closed coupled over fire air (CCOFA) nozzles (not shown), six pulverized fuel (coal) burners (not shown), three oil burners (not shown), and one biomass burner (not shown). Each coal nozzle secondary air group is made of a fuel-air nozzle and top and bottom auxiliary air nozzles. In addition there are two small auxiliary air nozzles located at the top and bottom of burner group. Secondary air nozzles between two coal nozzles have an offset angle from coal nozzle. The nozzles of the burners 12 are positioned to encourage rotation of the primary and secondary air about the furnace in a first direction. Air is supplied to the respective nozzles by a main windbox (not shown).

Located above the burner group are the separated over fire air (SOFA) ports 14. A total of eight SOFA ports 14 are located on the front 22 and rear 23 walls while being offset slightly from each corner of the furnace 10. The SOFA ports 14 are positioned to encourage rotation of fluid in the furnace 10 in the same direction as the primary and secondary air from the burners 12.

An upper portion 16 of the furnace 10 is partially divided from the remainder of the furnace 10 by a horizontally and inwardly extending nose portion 24 which extends from the rear wall 23 of the furnace 10. In the upper portion 16 of the furnace 10, twelve radiant 3 ^rd stage superheater platens 18 vertically extend from the furnace ceiling 20 downward near the front wall 22 of the furnace 10 to the horizontal nose 24. Additional superheater platens 26 and pendants 28 are located downstream from the 3 ^rd stage elements 18 extending from the upper furnace 16 to a convection pass 30.

The retrofitting of apparatus to reduce NO _x emissions from the furnace 10 produced a furnace 10 as shown in Figure 2 and included the addition of a rotating opposed fire air system including injection boxes 56, selective non-catalytic reduction (SNCR) units 70 and modifications to the burners 12, as will be described below.

Rotating Opposed Fire Air System

The rotating opposed fire air system 50, an overview of which is shown in Figure 3, includes two identical boosted-pressure fans 52 connected to air ducting 54 which in turn connects the fans 52 to a series of air injection boxes 56 comprising nozzles 58, and modulated dampers (not shown) for installation in the interior of the furnace 10.

As is described above, the rotating opposed fire air system was installed such that the injection boxes 56 were positioned on two adjacent and horizontally arranged levels above the existing SOFA ports 14 and just below the horizontal nose 24. The air supply for the rotating opposed fire air system 50 is taken from ducts (not shown) at the outlet of air preheaters (not shown), boosted in pressure by the fans 52 and then delivered through the air ducting 54 to the injection boxes 56 and out of the nozzles 58 into the furnace 10.

The air pressure at the nozzles is optimized as required to achieve significant mixing as was determined by computational fluid dynamics (CFD) modeling. Preferred air pressure at the nozzles is greater than 3 kPa, such that the velocity of the air entering the boiler is sufficient to induce significant levels of turbulent flow. All air flow and air pressure to the rotating opposed fire air nozzles 58 is automatically controlled via pre-set controlling curves based on a relationship to boiler steam flow generated through furnace tuning. Additionally, feed-forward and feed-back control strategies were implemented to reduce system upsets during load fluctuations. As is described briefly above, a total of twelve injection boxes 56 are installed on the front 22 and rear 23 walls at two separate elevations located in between the SOFA ports 14 and horizontal nose 24. Each of the injection boxes 56 is positioned in a horizontal plane closer to the horizontal plane of the lower extent of the nose portion 24 than to the horizontal plane of the uppermost burner 12. The lower elevation 56a of the injection boxes 56 consists of eight, three-nozzle boxes and the upper elevation 56b consists of four, two-nozzle boxes. The arrangement of the injection boxes 56 is configured to create counter-rotating mixing with flue gas in the furnace 12.

Selective Non-Catalytic Reduction System

The SNCR system is intended to supply a reactant such as urea to the furnace to chemically reduce undesired combustion products such as NO _x . It consists of an air delivery system and a liquid delivery system. The liquid system includes a urea storage tank ultimately connected to injection lances for delivering water and urea to the furnace 10. The air delivery system of the SNCR system contains a small ambient-air fan and ductwork similar to the rotating over fire air system, but smaller in size. The SNCR system utilizes ambient temperature air and as such the size of the ductwork is significantly reduced compared to the rotating opposed fire air system and thermal insulation is not required. Three levels of SNCR injection ports 70 are installed on the front wall 22 of the furnace 10, all being above the horizontal nose 24 and generally adjacent to the radiant 3 ^rd stage superheater platens 18. Multiple injection elevations 70a, 70b, 70c are necessary to account for the changes in flue gas temperatures associated with load changes in use. This ensures that the urea SNCR reactant is able to contact its target co-reactant NO _x at a temperature appropriate for successful reduction.

Burner Modifications Air nozzle resizing

The presently described modifications to the furnace 10 require that significant air flow is taken from the main windbox for use in the rotating opposed fire air system. It is therefore necessary to review the burner and firing systems to assure near-burner fuel/air mixing, ignition and flame stability are not adversely impacted, as would be understood by one skilled in the art. In some circumstances, it is necessary to resize the main windbox nozzle tips. Moreover, it is often necessary to introduce dampers to the furnace with any major change in air flow distribution. In the present furnace, all of the main windbox air nozzles and CCOFA nozzles were reduced in size so as to ensure that the air provided by them in use had the same exit velocity as before the inventive modifications. These changes ensure that desired mixing between burner primary air and secondary air is achieved.

Venturi damper

Venturi type air dampers were applied between the main windbox and the burner nozzles to increase the air flow biasing control of the boiler. The air flow to the windbox is controlled by two sets of dampers in series. The first damper controls the total air to all burner pairs and the second damper controls secondary air flow to each port individually. The downstream of dampers were modified and optimized by adding a venturi shaped entry to prevent any loss in pressure. In addition to the venturi dampers, turning vanes were also added to even the air flow distribution from the secondary air duct to the windbox.

Burner tilt

The existing burners and secondary air nozzles had compartmental tilt control and an operating tilt range of +20 to -10 degrees. For long term steam temperature, NO _x and combustion efficiency control, reliable tilts are extremely important. During the installation of the present system, the tilt was upgraded to extend the tilt range to -27 / +27 degrees. This automated secondary air nozzle tilt control allows for the controlling of superheat (SH) and reheat (RH) temperatures along with controlling the impact of an existing steam attemperation system.

Additionally to the system installation and burner modifications, electrical controls were modified to allow for the central control of the rotating opposed fire air and SNCR systems.

CFD MODELING Prior to commissioning of the upgrades to the furnace, the system was tested via CFD modelling. This was performed to (1) understand the baseline (unmodified) unit operation and performance; (2) design and optimize the rotating opposed fire air and SNCR system design and operation for this unit; and (3) predict the furnace combustion performance and NOx emissions.

Combustion Model Overview

The inventors used FLUENT software (produced by ANSYS, Inc.) to model coal combustion in this study. FLUENT solves for the velocity, temperature, and species concentrations fields for gas and particles in the furnace, as well as the combustion of char particles and volatiles in the gas phase. A k-ε turbulence model was used in the simulation and incompressible flow was assumed. Eddy Dissipation combustion model was also used in this study. The model solves the particle phase (coal) in the Lagrangian reference frame. The gas phase and particle phase conversation equations are solved separately due to non-linear characteristics of the governing differential equations; however, these two phases are strongly coupled through iterative transformation of the source terms. Turbulent dispersion of particles is modeled with the stochastic discrete- particle approach. Coal is injected through the burners by specifying a Rosin-Rammler particle size distribution and a particle velocity slightly less than the gas phase velocity within the primary injectors. Parameters for this distribution are derived from sieve data collected onsite. Gas phase air flow rates were specified for all air nozzles and rotating opposed fire air ports using appropriate inlet mass flow, temperatures, turbulence intensities, and swirl levels.

The model used different expressions for particle heating and reaction at each stage of the process. An inert heating law applied when particle temperature was less than the onset temperature for devolatilization. The particle was heated by convective heat transfer from the gas phase and the radiant flux from the furnace. During devolatilization and char oxidation, the particle energy balance also included heat of devolatilization and heat of combustion, in addition to the convective and radiant heat transfer rates. The following two step mechanism were used.

Coal + a 0 ₂ → b CO + c C0 ₂ + d H ₂ 0

CO + 0.5 0 ₂ → C0 ₂

Where the stoichiometric coefficients (a, b, c, and d) were determined from the fuel proximate and ultimate analyses.

The FLUENT software provided the capability to model thermal, prompt, and fuel NO _x formation from combustion. After coal devolatilization, coal-N is partitioned into volatile-N and char-N. HCN is the dominant nitrogen species in volatile-N released from coal. Char-N is released into the gas phase at a rate that is proportional to the carbon burnout rate. As char-N conversion chemistry is complex, a fixed fraction of char-N was used which directly converted char-N to NO with the rest of N converted to N ₂ , an assumption often used in literature (for example, see Niksa, S., and Liu, G.-S., "Incorporating detailed reaction mechanisms into simulations of coal-nitrogen conversion in p.f. flames", Fuel 81 (18), pp. 2371-2385 (2002)). The gas phase NO can be reduced under reducing atmosphere, on the char surface, or through ammonia/urea injection (SNCR).

In SNCR chemistry modeling, after urea solution droplets are injected into the upper furnace, water in droplets vaporizes completely before solid urea decomposition occurs. Urea (CO(NH ₂ ) ₂ ) decomposes into NH3 and HNCO, both of which are SNCR reducing agents. The reduction of NO by the SNCR process is characterized by a "temperature window" in which the reduction of NO is possible. Outside this window lower temperatures result in no reaction among NH3/HNCO and NO, and appreciable amounts of NH3/HNCO can be released as slip. Higher temperatures result in possibility that N H3/HNCO can be oxidized to NO and even higher amounts of NO compared to baseline can be emitted. The FLUENT software has incorporated this SNCR urea chemistry and we have validated results against several full scale cases.

Geometry and Model Inputs

The furnace enclosure in CFD model domain for baseline and rotating opposed fire air cases is defined as beginning at the burners 12 and rotating opposed fire air ports (inlet boundary conditions) and ending at a vertical plane right before the 2 ^nd stage reheater (outlet boundary condition). The furnace volume extends into the bottom ash hopper. Overall geometry for baseline with SOFA and rotating opposed fire air/SNCR was the same. The pendants of the 3 ^rd , 4 ^th , 5 ^th , and 6 ^th stage superheater, and the 3 ^rd stage reheater are accurately depicted in the model with actual numbers and dimensions to account for accurate heat absorption and flow stratification. Due to symmetric configuration of the furnace, only half of the furnace is modeled. Detailed burner configuration (including primary air, secondary air, CCOFA and SOFA nozzles) as well as jet injection angle were well represented in the model with the opening area matching to the actual area. The furnace geometry for the baseline was represented in the computer model with approximately 1.6 million computational cells in an unstructured, hybrid (all hexahedral) grid. This large number of computational cells is adequate to solve the most relevant features of the three- dimensional combustion process.

Key inputs for the furnace CFD baseline simulations are listed in Table 1. The input for fuel composition is given in Table 2, which were the averaged value from measurements of previous use of the furnace. The firing rate was calculated based on the boiler operational data. Fuel flow was calculated based on the firing rate and heating value. Total air flow (TAF) was obtained through stoichiometric calculation with given fuel compositions and exit O2 levels that were recorded in operating data received during the testing. Primary air flows were estimated based on the ratio (2.0) of total primary air to total fuel flow. SOFA air flow was calculated based on the extent of damper openings recorded in the PI data. The split of secondary air among small secondary air, bottom secondary air, large secondary air, and over fire air from windbox air was based on the damper opening in the PI data. In contrast to the baseline case, a large portion of combustion air was redirected to the rotating opposed fire air/SNCR ports in rotating opposed fire air/SNCR models.

Table 1 : System Operating Conditions at Baseli

Table 2: Fuel Composition of Testing Coal Blend.

CFD Modeling Results

The baseline modeling results were first validated against HVT testing results, which are not presented here. This validation ensures the combustion in furnace and the main gas species concentration at the furnace exit match to the testing data. When rotating opposed fire air/SNCR cases are modeled, the model parameters remain constant as in the baseline case. Rotating Opposed Fire Air vs. Baseline: Main Parameters

Table 3 provides the main CFD results including gas temperatures, major species and emissions for the rotating opposed fire air case in comparison with the baseline case at 31.06 m and the modeled outlet. Note that five rotating opposed fire air designs were meshed and modeled. Only the optimal rotating opposed fire air design is included in the table for discussion. With rotating opposed fire air installed and supplying 25% of the total air flow to the furnace at a nozzle pressure of 7.5 kPa, the CFD model predicts that NO _x emission is reduced by 46.7% from baseline, at the same time loss on ignition (LOI) is kept almost the same. This is due to the strong mixing of combustion air from the high velocity rotating opposed fire air jets enhancing the mixing of the combustible char particles in the gas. The rotating opposed fire air case shows some improvement in combustion, dramatic NOx reduction, and similar levels of LOI. CO concentration is slightly higher than the baseline case, which can be controlled during tuning.

Table 3: Comparison of Baseline Model Results with Rotating Opposed Fire Air Results.

Temperature Distribution

The temperature distribution on six horizontal planes in the baseline case appears in the left panel of Figure 4. The temperature distribution indicates that coal ignites soon after being injected into the furnace. This rapid ignition is due to the release of volatiles of coal during rapid heating. The ignition occurs at the boundary between primary air and secondary air jets, which can be seen from the bottom two planes. The rotation formed by air and fuel jets can also be seen.

The flame then propagates and expands while most of the combustibles burn in the annulus between primary air and secondary air. This is typical for tangential fired furnaces. It shows that the majority of coal combustion occurs in the region below the nose. Above the nose, due to heat transfer to the super heated pendants the gas temperature decreases quickly. The maximum flame temperature in the baseline furnace is about 1658°C and that in rotating opposed fire air case is about 1620°C.

The temperature distribution in the rotating opposed fire air case appears in the right panel of Figure 4. Air injected through the rotating opposed fire air ports can be seen from the middle horizontal planes. Temperatures in the region between the planes at the upper rotating opposed fire air ports and the nose elevation in the rotating opposed fire air case are relatively higher than those in the baseline case because of continuous burnout of CO and unburned char. The rotating opposed fire air case shows considerably better combustion distribution and consequently better flue gas mixing throughout the upper furnace than does the baseline case.

O2 Distribution

The left panel of Figure 5 shows the O2 distribution of the baseline case. Higher O2 concentrations are found near the furnace walls. Lower O2 concentrations are found in each furnace chamber center. This is because part of the secondary air deflected toward the walls and part of it was consumed when it met the fuel. This non-uniform O2 distribution suggests that combustion is less complete than with the rotating opposed fire air case. Below the rotating opposed fire air ports, as seen in the right panel of Figure 5, are areas of corresponding low O2 concentrations which are increased in comparison with baseline results due to deep staging. This indicates a strong reducing environment for NO _x reduction. In the region between the lower rotating opposed fire air ports and the nose, air injected through rotating opposed fire air ports mixes very well with the flue gas. Therefore, the O2 distribution in the upper furnace becomes relatively uniform due to dramatically enhanced mixing. This can be clearly seen from the plane at the nose elevation. The small areas with high O2 concentration on the top plane are because of air injection from SNCR ports.

CO Distribution

Figure 6 shows CO distribution between baseline and rotating opposed fire air cases. As shown in the left panel, the formation of CO initiates near the boundary between secondary air and primary air jets. High CO concentration is in the annulus between primary air and secondary air. CO is relatively lower in concentration in the chamber center because a smaller amount of fuel was transported into the furnace center. CO quickly diminished from the top of burner to the nose. In the rotating opposed fire air case in the right panel of Figure 6, a larger amount of CO is formed in the lower furnace due to deep staging and reduced O2 concentration. The high CO concentration persists up to the rotating opposed fire air ports in the upper furnace, but is then burnt rapidly after rotating opposed fire air penetrates the combustion chamber. The CO distribution is uniform at the top plane. The furnace exit CO concentration is slightly higher than baseline case level due to the relatively short residence time in the rotating opposed fire air case.

NOx Distribution

Figure 7 shows NO _x distribution between the baseline and rotating opposed fire air cases. NOx formation in the rotating opposed fire air case is significantly reduced in contrast to the baseline case. The outlet NO _x was reduced from 467 mg/Nm ³ in the baseline with SOFA to 249 mg/Nm ³ in the rotating opposed fire air case, a 46.7% reduction. The baseline NO _x concentration in the left panel of Figure 7 indicates that NO _x is most likely formed in the area between primary air and secondary air jets. It is postulated that this comes from volatiles combusting as well as the release of partial oxidization from char nitrogen. Below the SOFA ports, NOx is lower in the chamber center. High NO _x concentration can be clearly seen in the upper furnace which is due to the high nitrogen content in the fuel and O2 availability. As a result of strong air staging by the rotating opposed fire air system, the lower furnace has, an overall, reducing atmosphere. The amount of NO _x formed in the region between the primary air and secondary air jets is subsequently reduced because of this reducing environment. Thus, the NO _x concentration is dramatically reduced in the entire furnace shown in the right panel of Figure 7.

Turbulent Kinetic Energy Figure 8 shows turbulent kinetic energy (TKE) distribution in baseline and rotating opposed fire air cases. In the baseline case, the maximum turbulent kinetic energy appears in the burner zone from the secondary air and CCOFA jets. In the rotating opposed fire air case, high turbulent kinetic energy zones appear at the rotating opposed fire air injection and downstream region below the upper nose elevation. This high turbulence rapidly diminishes as these jets penetrate into and mix the furnace flue gas. Turbulent kinetic energy is dissipated into the bulk flow through eddy dissipation. That is, large amount of kinetic energy results in strong mixing of combustion air from high velocity rotating opposed fire air jets with the upstream gas flow carrying combustible CO and char particles. High turbulent mixing promotes the chemical reaction, which is the reason for rapid burnout of CO in the ROFA case and is the key for ROFA design.

Figure 9 presents mass-weighted averaged TKE along the entire furnace height. TKE in entire furnace in baseline case is smaller than 60 m ² /s ² . TKE in the burner region for the rotating opposed fire air case is relatively weaker than that in the baseline case because of less amount of secondary air present. The TKE greater than 60 m ² /s ² are found near the rotating opposed fire air ports. The highest TKE peak is adjacent to the lower rotating opposed fire air ports.

SNCR Modeling

Figure 10 shows the streamline of SNCR urea injections, colored by temperature. It can be seen from the streamlines that the urea solution is carried into the furnace by SNCR air to a distinctive distance. Then the evaporated and dissociated reducing agent species are deflected upward by the bulk flow. During SNCR modeling, the urea flow through each SNCR port was adjusted and tested. Table 4 shows the best case condition for SNCR results. The NO _x concentration in the rotating opposed fire air -only case (i.e. without addition of urea) is used for comparison with urea injection. The NO _x concentration is well above 200 ppm at the exit plane in baseline case. The rotating opposed fire air system alone leads to significant NO _x reduction. With additional urea injection, very low NO _x concentrations appear in some areas of the exit. The model shows that about 24.9% NO _x reduction was achieved by urea injection at a normalized stoichiometric ratio (NSR) of 1.3 and with about 5 ppm ammonia slip at the furnace exit. The ammonia slip concentration will be lower due to slow depletion and conversion as it travels to downstream and exits the furnace.

Table 4: SNCR-Urea Injection Modeling Results.

The CFD modelling led to a preferred operation where the rotating opposed fire air injectors provide 25% of the total air flow to the boiler at a nozzle pressure 7.5 kPa and a temperature of around 250°C. SOFA injectors provide around 8% of the total air flow to the boiler at a nozzle pressure of around 1 kPa and a temperature of around 250°C. Such pressures and air flows can be modified by, for example, the utilizing varying fan powers and deploying venturi dampers in or around the injectors as required.

FIELD PERFORMANCE Performance Test A two-hour performance test was conducted by a certified third-party company, for both the baseline and the rotating opposed fire air/SNCR installed and tuned condition. During the performance test, NO _x was measured through the CEMS installed in the stack. The LOI was measured through isokinetic sampling in the airheater outlet duct while the CO was measured at the inlet to the flue gas deulfurization system. Ammonia slip was measured by six ammonia slip analyzers installed at the airheater inlet. Table 5 is a comparison of the performance test results before and after rotating opposed fire air/SNCR installation at full load operation. It is seen that CO concentration was reduced slightly following the rotating opposed fire air/SNCR installation. LOI was increased slightly from 8.4% to 8.9%. Note: the slight increase in LOI this does not however prevent the owners of the utility boiler from selling their flyash.

As expected, boiler efficiency decreased slightly from 92.4% to 92.1 %, predominantly due to the injection of water from the SNCR system. The urea flow of 0.22 kg/s was under predicted urea usage as shown in Table 4. Ammonia slip of 1.2 ppm average was well controlled at minimum level possible. This low level NH3 slip resulted in relatively low NH3 in flyash, according to NH3 mass balance analysis discussed later.

The biggest change in unit operation was NO _x emission which was reduced from 483 mg/Nm ³ in baseline to 192 mg/Nm ³ , a 60% reduction by the rotating opposed fire air/SNCR system. As shown in Table 4, the CFD modeling predicted a NO _x emission of 187 mg/Nm ³ , which is in agreement with the performance test results.

Table 5: Comparison of Performance Test Results Before and After Installation.

It was also found that to produce this performance, it was necessary to run the rotating opposed fire air fans at a lower power consumption of 1880 kw compared to the power consumption that would have been required to run rotating opposed fire air fans when no SOFA system remains in the furnace on a similar capacity system (typically above 2500 kw). Trial Tests Prior to the performance guarantee test, a continuous 17-day trial test was completed. During this trial test, the unit followed the typical day/night load swings.

Over a period of a month, baseline NO _x was varying consistently between 400 and 600 mg/Nm ³ for the load between 250 MWe and 500 MWe. The variation was predominantly due to frequent fuel switching and variation of unit operation. After rotating opposed fire air/SNCR had been installed, less than 200 mg/Nm ³ NO _x emissions was achieved consistently over the entire load range from 250 MWe to 500 MWe, and the average NO _x over the 17-day test was 186 mg/Nm ³ . The other significant observation was that the variation of NO _x due to operational changes was much smaller compared to baseline variation.

The present invention therefore provides a means for achieving elevated NO _x reduction while maintaining efficient combustion by enhancing furnace mixing and allowing for decreased power consumption of the additional systems. Through detailed analysis including CFD modeling, the technology has been designed and installed on a 500 MWe coal-fired boiler. Together with burner modifications, the system achieved the following performance goals:

NO _x emission levels of 192 mg/Nm ³ at full load, and averaging 186 mg/Nm ³ over long-term test. This is 60% reduction from baseline with SOFA in service. The NO _x level is in reasonable agreement with CFD prediction.

Efficient combustion (via LOI, CO and boiler efficiency) while achieving significant NOx reduction due to mixing introduced by rotating opposed fire air system.

Industrially acceptable ammonia slip of 1.2 ppm with average ammonia in ash of 39 mg/kg and ammonia in gypsum of 1-8 mg/kg.

Preferences and options for a given aspect, feature or parameter of the invention should, unless the context indicates otherwise, be regarded as having been disclosed in combination with any and all preferences and options for all other aspects, features and parameters of the invention. The listing or discussion of an apparently prior-published document in this specification should not necessarily be taken as an acknowledgement that the document is part of the state of the art or is common general knowledge.