TW202434833A - System and method for optimizing combustion in a boiler - Google Patents

Abstract

A system (62) and method for optimizing combustion in boiler (12) is described. The optimization of the combustion in the boiler (12) involves obtaining various data relating to the flow of fuel and air to burners of the boiler and the flame in the burner zone (21) of the boiler (12) that is generated from the introduction of the fuel and air into the burner zone. The data is used to determine air flows to the burners. The data and air flows are used to balance air and fuel at individual burners by manipulating air to match the fuel flow. The balancing of air and fuel at individual burners by manipulating air to match the fuel flow uses a guided search optimization algorithm that mixes stoichiometry determinations with a custom search algorithm that accounts for measurement inaccuracies and unexpected interactions between burners.

Description

System and method for optimizing combustion in a boiler

Embodiments of the present disclosure relate generally to combustion systems and, more particularly, to a system and method for optimizing combustion in a boiler, such as, for example, a tangentially-fired (T-fired) boiler and a wall-fired boiler.

In general, a boiler comprises a furnace in which a fuel is burned to produce thermal energy or heat. The fuel, which may be a pulverized solid fuel such as coal, or a liquid or gaseous fuel, is generally provided to the furnace as a mixture of fuel and air. Burners located on one or more walls of the boiler (such as at the corners in the case of a tangentially fired boiler, or on a single or opposing walls in the case of a wall-fired boiler) introduce a mixture of fuel and air into the furnace for combustion and flame production. The flame produced by the combustion of the fuel and air produces thermal energy. The thermal energy is used to heat a liquid or vapor (such as water or steam) in water-walled tubes lining the furnace walls. Heating the liquid or vapor in the water wall tubes causes the production of steam, which can flow to a steam turbine to generate electricity or provide heat for other purposes.

Operators of power plants that use boilers (such as coal-fired boilers) to generate steam face multiple challenges. With the increase of renewable energy on the grid, power plants used for baseload operation now more often have output ranges that cycle from minimum load to full capacity, and in some cases, are shut down and started more frequently. In addition, in some markets, changes in coal and gas prices, along with changing regulatory requirements, are placing new demands on power plant operators. Moreover, these power plants must maintain stable combustion to generate electricity at output levels that are lower than what was historically necessary.

As coal-based power generation is expected to continue to contribute a large amount of electricity worldwide, power plant operators seek solutions to improve power plant efficiency while controlling emissions. Combustion optimization is a method used to improve the efficiency and reduce emissions of boilers, such as those deployed in typical coal-fired steam generators. Given the number of variables at play in a coal-fired steam power plant, combustion optimization typically involves the use of software and analysis to understand the many variables and their dependencies, process states, performance impacts, and costs.

A general combustion optimization solution available to power plant operators implements this understanding in a model and is used in conjunction with an optimization search engine. The boiler model is often a neural network-like model, but other model types are used. The optimization search engine often relies on well-known search techniques, which may include linear programming, particle swarm optimization, or genetic algorithm search, etc. In operation, the optimization search engine uses the model to try combinations of different boiler settings to produce a list of settings that provide good results with respect to the model. The boiler settings that provide good results with respect to the model are then applied to the boiler control.

There are several problems with these combustion optimization methods that rely on boiler models and optimization search engines. For example, there may be accuracy issues with the boiler model due to changes in boiler equipment conditions, fuels, or other environmental conditions. Therefore, the boiler model needs to undergo re-tuning to account for these changes that may cause inaccuracies in the model. In addition, these known combustion optimization methods generally manipulate primary and secondary air flows, air flow by elevation and/or corners, and burner tilt, but do not manipulate individual air dampers for consistent stoichiometry at individual burners because the boiler model does not include this level of detail. Reducing the amount of excess air available for combustion generally reduces nitrous oxide (NOx) emissions while increasing carbon monoxide (CO) emissions, while increasing the amount of excess air available for combustion generally increases NOx emissions while reducing CO emissions. This occurs because of localized combustion zones of low oxygen gas that partially burn carbon from the air to carbon monoxide (CO) rather than carbon dioxide (CO ₂ ). At high temperatures, the combustion zones with high air content convert most of the nitrogen and oxygen in the air to nitrogen oxides (NOx) at high temperatures. In addition, these combustion optimization methods generally focus on nitrogen oxides (NOx) emissions or boiler efficiency rather than low boiler load and flame stability. In addition, these combustion optimization methods require a wide range of historical operating data to build and tune the boiler model.

Other combustion optimization methods have been tried, but are less widely used than those that rely on boiler models and optimization search engines. One such method involves coal flow balancing systems, but these systems suffer from corrosion problems and require extensive maintenance.

The following presents a simplified summary of the disclosed subject matter to provide a basic understanding of some aspects of the various embodiments described herein. This summary is not an extensive overview of the various embodiments. It is not intended to arbitrarily identify key features or essential features of the claimed subject matter as set forth in the claims, nor is it intended to aid in determining the scope of the claimed subject matter. Its sole purpose is to present some concepts of the present disclosure in a concise form as an introduction to the more detailed description presented later.

The aforementioned problems associated with combustion optimization methods that rely on boiler models and optimization search engines have led to the need for different methods for optimizing the combustion of boilers used in power plants or even in industrial equipment that uses boilers for steam generation. The embodiments described herein provide a solution to the problems of combustion optimization that relies on learned boiler models and optimization search engines. The solution provided by the embodiments includes a system and method for combustion optimization in a boiler (such as a tangentially fired boiler and a wall-fired boiler that burns fuel (e.g., coal, or liquid or gaseous fuel)) in a power plant and an industrial equipment.

In various embodiments, measured fuel flow, air flow, air flow control device data, flame scan data, and flue gas property data may be used to identify local stoichiometry (air-to-fuel ratio) near each of the burners. Air flow is adjusted per determined bias for achieving more uniform local stoichiometry near each burner since all of the air flow contributes to a single merged fireball in the case of a tangentially fired boiler, or to multiple flames in a wall-fired boiler. In one embodiment, combustion optimization may be performed using a guided search optimization algorithm. The guided search optimization algorithm combines a physics-based approach involving measured and/or calculated chemical measurements of the burners mixed in the boiler with a search algorithm that is customized to find operating biases that can be applied to one or more of the burners to produce better combustion operating results for the boiler while taking into account measurement inaccuracies, equipment condition variations, and unexpected interactions between burners when determining and evaluating the operating biases. Various higher-level combustion measurements, including one or more of combustion gas species, temperature distribution, and flame stability measurements, are used to evaluate combustion before and after adjustments. More uniform local stoichiometry results in reduced carbon monoxide (CO) and NOx emissions by reducing local combustion zones where the air content is significantly higher or lower than the available fuel. More uniform local stoichiometry also results in better flame stability, especially at low boiler loadings.

In addition to simultaneously reducing CO and NOx emissions and providing better flame stability, the systems and methods of various embodiments provide other advantages. For example, such embodiments may help reduce minimum boiler load in response to intermittent renewable energy with better low-load flame stability. Furthermore, embodiments may help increase efficiency at higher boiler loads to reduce operating costs and emissions by reducing excess air. In addition, fuel flow sensors, air flow sensors, flue gas sensors, and flame scanners that may be used in embodiments may provide more accurate measurements of fuel flow and air flow, thereby supporting uniform burner stoichiometry. By using a guided search optimization algorithm, embodiments may provide improved response to unexpected boiler behavior, fuel changes, and operating modes. Additionally, because a physics-based approach is used with the embodiments and not with a boiler model-based approach, periodic re-tuning of the boiler model to account for model inaccuracies over time can be avoided.

According to another embodiment, a system is provided. The system of this embodiment includes: a boiler having a furnace including a burner zone for burning fuel and air to produce flue gas therefrom, the boiler including one of a tangentially fired (T-fired) boiler and a wall-fired boiler; a plurality of burners positioned around the boiler to define an arrangement of fuel and air introduction locations, the burners The fuel and air introduction position is used to introduce a mixture of main fuel and air into the burner zone to produce a flame therein, each of the burners includes a fuel nozzle, the fuel nozzle operates to provide a flow of the main fuel and air into the burner zone; a plurality of auxiliary air nozzles, which are positioned around the plurality of burners, the plurality of an auxiliary air nozzle operative to supply a flow of auxiliary air into the burner zone for contributing to combustion with the primary fuel and air; a plurality of air flow control devices for controlling the supply of selected flows of auxiliary air into the burner zone through the plurality of auxiliary air nozzles; a plurality of fuel flow sensors for obtaining the flow of the primary fuel; The fuel flow sensors are configured to measure the flow of a primary fuel to the plurality of burners, each of the fuel flow sensors being operative to obtain a real-time measurement of the flow of the primary fuel supplied to one of the plurality of burners via a corresponding fuel nozzle; and one or more auxiliary air flow sensors being operative to obtain a real-time measurement of the flow of the primary fuel supplied to the burner region via one or more of the auxiliary air nozzles. A plurality of auxiliary air flow sensors are provided for measuring the flow of the auxiliary air in the burner zone, each of the auxiliary air flow sensors is operated to obtain a real-time measurement of the flow of the auxiliary air supplied to the burner zone by one or more of the plurality of auxiliary air nozzles; a plurality of flame scanners are used to obtain flame scanning data of the flame in the burner zone; a plurality of smoke sensors , which operate to obtain measurements of a plurality of properties associated with the flue gases, the measurements of the plurality of properties being indicative of combustion occurring in the burner zone, each of the flue gas sensors being operative to obtain a measurement of at least one of the properties; and a controller operative to generate a plurality of fuel flow sensors, the one or more auxiliary air ... The controller optimizes the combustion of the fuel and air in the burner zone based on information provided by the flue gas detector, the plurality of flame scanners, the plurality of flue gas sensors and the plurality of air flow control devices, wherein the controller includes a guided search optimization algorithm, the guided search optimization algorithm is configured to mix the measured and/or calculated chemical measurements of the burners in the boiler with a search algorithm, the search algorithm is customized to find operating biases applied to one or more of the burners to simultaneously consider measurement inaccuracies, equipment condition variations, and unexpected interactions between burners when determining and evaluating the operating biases, thereby producing better combustion operating results for the boiler.

According to a second embodiment, a method for optimizing combustion in a boiler is provided. The boiler includes: a furnace including a burner zone for burning fuel and air to produce flue gases therefrom; a plurality of burners, wherein each burner includes a fuel nozzle, the fuel nozzle being operative to provide a flow of primary fuel and air into the burner zone to produce a flame therein; a plurality of auxiliary air nozzles, the plurality of burners being disposed around the plurality of burners; a burner, the plurality of auxiliary air nozzles being operated to supply a flow of auxiliary air into the burner zone for contributing to combustion with the primary fuel and air; a plurality of air flow control devices for controlling the supply of selected flows of auxiliary air into the burner zone through the plurality of auxiliary air nozzles; a plurality of fuel flow sensors for obtaining measurements of the flow of the fuel to the plurality of burners; one or more auxiliary air flow sensors for obtaining measurements of the flow of the auxiliary air supplied to the burner zone by one or more of the plurality of auxiliary air nozzles; a plurality of flame scanners for obtaining flame scanning data of the flame in the burner zone; a plurality of flue gas sensors for operating to obtain measurements of a plurality of properties associated with the flue gases; and a controller for operating to execute a method for optimizing the combustion of the boiler based on fuel flow, air flow, flame data, flue gas data, and information associated with a plurality of air flow control devices. In this embodiment, the method includes: determining the amount of air near each of the burners; determining the air-fuel ratio near each of the burners; determining operating biases that redistribute air through one or more burners or near the one or more burners to be more consistent with the air-fuel ratio of other burners while maintaining approximately the same amount of air at each elevation level of a vertical furnace in the tangentially-fired boiler, or at each longitudinal distance of the burners from a horizontal furnace in a wall-fired boiler; and applying the operating biases to one or more of the burners or near one or more of the burners.

Example embodiments of the present invention will be described more fully below with reference to the accompanying drawings, which show some but not all embodiments. In fact, the present invention may be embodied in many different forms and should not be construed as limited to the embodiments set forth herein; rather, these embodiments are provided so that this disclosure will satisfy applicable legal requirements. Like numbers may refer to like elements throughout.

Turning now to the drawings, Fig. 1 shows a schematic diagram of a fuel boiler system 10 having a boiler 12 including a furnace 14 and a combustion chamber in which a mixture of fuel and air is burned to produce a flame that is used to produce steam that can be utilized in power generation applications that drive a generator with steam. The boiler 12 may include a tangentially fired boiler and a wall-fired boiler. Although the various embodiments of the present invention are described with respect to tangentially fired boilers and wall-fired boilers, it is not intended to be limiting as aspects of the embodiments may have applicability to other types of boilers, including but not limited to suspension burners for biomass boilers, Dutch oven boilers, hybrid suspension grate boilers, and fire tube boilers.

Referring back to FIG. 1 , the fuel boiler system 10 may include a fuel source, such as a pulverizer 16 configured to grind a fuel, such as coal, to a desired fineness. The pulverized coal may be transferred from the pulverizer 16 to the boiler 12 using primary air. An air source 18, such as a fan, supplies auxiliary air or combustion air to the boiler 12, where it is mixed with the fuel and air provided by the pulverizer 16 and combusted in the furnace 14, as discussed in more detail below.

Although the fuel boiler system 10 is described as a coal-based boiler system, it should be understood that other boiler systems may use other types of pulverized fuels and liquid or gaseous fuels. Examples of other types of pulverized solid fuels that can be used with the fuel boiler system 10 may include, but are not limited to, biomass, wood, peat, grain, and coke, while liquid or gaseous fuels may include, but are not limited to, oil, natural gas, generator gas, and chemical byproducts from industrial processes. Like pulverized coal-fired boiler systems, these other types of pulverized solid fuel boilers and liquid or gaseous fuel boilers may require combustion optimization, and therefore the combustion optimization systems and methods provided by various embodiments may have the utility of such non-coal-based boiler systems.

As shown in FIG1 , the boiler 12 may have a burner zone 21 including a main burner zone 22 and a burner zone 24 above the main burner zone to form a combustion chamber of the furnace 14. The main burner zone 22 receives a mixture of fuel and air from the pulverizer 16 and auxiliary air from the air source 18. The mixture of fuel and air is ignited by a burner (not shown) as it is introduced into the main burner zone 22. The ignition of the mixture of fuel and air results in combustion and flame generation.

The hopper zone 20 can be located below the main burner zone 22 to remove ash produced by the combustion of fuel and air. At the same time, with the assistance of the overfire air introduced above the main burner zone 22 and the fuel and air added to the main burner zone through the pulverizer 16 and the air source 18, the combustion zone 24 above the main burner zone 22 can burn any air or fuel that has not been burned in the main burner zone 22.

Thermal energy is generated by the flames from the combustion of fuel and air in the main burner zone 22 and the combustion zone 24. The thermal energy is used to heat liquid or vapor (such as water or steam) in water wall tubes (not shown) lining the walls of the furnace 14. Heating the water in the water wall tubes produces saturated water, which can be separated into water and steam in a boiler drum (not shown), or the water can be converted to steam in the water wall tubes. The superheater zone 26 with a superheater circuit can superheat the steam to supply to a steam turbine (not shown) to generate electricity or provide heat for other purposes.

The combustion of fuel and air within the boiler 12 generates a flue gas flow which is subjected to final treatment and discharged through a chimney downstream of the economizer zone 28 which contains an economizer which may be used to preheat feed water supplied to the boiler drum of the boiler with the flue gases. As used herein, the term "downstream" means in the general direction relative to the flow of the flue gases, and the term "upstream" refers to the direction of the flue gases opposite to the "downstream" direction relative to the flow of the flue gases.

The fuel boiler system 10 of Figure 1 may include an array of sensors, actuators, and monitoring devices to monitor and control the combustion process. For example, the pulverized solid fuel boiler system 10 may include a plurality of air flow control devices 30 associated with a duct that supplies auxiliary air from an air source 18 to the boiler 12 for introduction into the main burner zone 22 through an auxiliary air nozzle (not shown) for combustion by a burner (not shown) with the fuel and air introduced and ignited into the main burner zone 22. In one embodiment, the air flow control device 30 may be an electrically or pneumatically actuated air damper that can be adjusted to vary the amount of air provided to each auxiliary air nozzle associated with a respective burner. Other examples of air flow control devices may include, but are not limited to, variable orifices, deflectors, baffles, sliding gates, or multiple designs of turning vanes and blades and dampers. Each of the air flow control devices 30 may be individually controlled by a control unit 100 to ensure that the desired air/fuel ratio and flame temperature is achieved for each burner or fuel nozzle location.

The fuel boiler system 10 of FIG. 1 may further include a plurality of flame scanners 46 associated with each burner and corresponding fuel nozzles that provide a flow of fuel and air to the main burner zone 22. The flame scanners may perform several operations. Generally speaking, the flame scanner 46 may be used to determine whether a flame is present in the main burner zone 22 and the overall quality of the flame. In addition, the flame scanner 46 may calculate several characteristics of the flame, including but not limited to the average intensity of the flame, the change in flame brightness, the frequency of change in flame brightness, and the temperature of the flame. The flame scanner 46 may provide characteristics of one or more different ranges of optical wavelengths. The flame scanner 46 may be electrically connected or otherwise communicatively coupled to the control unit 100 for conveying this information. Although the flame scanner 46 is described as being around the main burner zone 22, other configurations are possible. For example, as shown in FIG. 1 , the flame scanner 46 may be positioned in the upper portion of the furnace for monitoring and evaluating further flame characteristics (e.g., temperature). In one embodiment, the flame scanner 46 may include a two-dimensional optical flame scanner, such as an in-furnace camera or optical flame system. In general, the flame scanner 46 may include any commercially available flame scanner, such as the Perfecta or Exacta flame scanner systems provided by General Electric Company, or functionally equivalent flame scanner systems from other suppliers.

In addition to the flame scanner 46, the fuel boiler system 10 may also include a flame stability monitor 34 positioned, for example, just above the combustion zone 24, which may be configured to measure or otherwise assess fireball stability within the boiler 12. The flame stability monitor 34 may also be electrically connected or otherwise communicatively coupled to the control unit 100 for communicating this information for further analysis and assessment of flame stability.

In one embodiment, as shown in FIG1 , in the back stack 38 of the boiler 12, a monitoring device 40 may be located upstream of the economizer zone 28 to monitor the flue gas. In one embodiment, the monitoring device 40, which may include a plurality of flue gas sensors, may be configured to measure and evaluate the gas species in the back stack 38, including but not limited to carbon monoxide (CO), carbon dioxide (CO ₂ ), mercury (Hg), sulfur dioxide (SO ₂ ), sulfur trioxide (SO ₃ ), nitrogen dioxide (NO ₂ ), nitrogen monoxide (NO), and oxygen (O ₂ ). SO ₂ and SO ₃ may be collectively referred to as SOx, and NO ₂ and NO may be collectively referred to as NOx.

In one embodiment, the monitoring device 40 may include a laser-type monitoring device, such as a tunable diode laser flue gas monitoring device. The monitoring device 40 may include one or more light sources, which may, for example, pass through a portion of the flue pipe defined by the tail flue 38. The light sources may provide light beams that pass through the flue gas within the tail flue 38 and are detected by a corresponding plurality of optical detectors (not shown). As the light beams pass through the flue gas, there is absorption of various wavelength characteristics of components within the flue gas. The light sources may be coupled to a processor to provide characteristics of the received optical signals and identification of the components, their concentrations, and other physical characteristics or parameters of the substances in the flue gas. In other embodiments, such analysis may be performed internally by the control unit 100.

The fuel boiler system 10 of FIG. 1 may further include a plurality of flue gas sensors 42 downstream of the economizer zone 28, the plurality of flue gas sensors operating to obtain measurements of a plurality of properties associated with the flue gases. The measurements of the plurality of properties may provide information indicative of combustion occurring in the combustor zone. In one embodiment, the plurality of flue gas sensors 42 may be configured to detect combustion gas species within the flue gases downstream of the economizer zone 28, including but not limited to CO, CO ₂ , Hg, SOx, NOx, and O ₂ . The plurality of flue gas sensors 42 may include laser-type detectors, but other types of detectors capable of detecting the amount of gas species in the flue gas may also be used without departing from the broader aspects of the present invention. Such flue gas sensors may, for example, alternatively extract a sample of the flue gas by inserting a probe into the economizer outlet duct. The extracted flue gas sample is then transported to one or more chemical analyzers located outside the flue gas duct. Similarly, the plurality of flue gas sensors 42 may be electrically or communicatively coupled to the control unit 100 for transmitting data related to the measurements obtained by the sensors 42.

In one embodiment, one or more temperature sensors 43 may be disposed around the flue gas to detect the temperature of the flue gas in this section of the boiler 12. The temperature sensors 43 may also be electrically or communicatively coupled to the control unit 100 for transmitting data related to the temperature measurements obtained by the sensors 43.

It should be understood that a plurality of flue gas sensors 42 and temperature sensors 43 may be disposed in other locations of the boiler 12 in addition to or in lieu of the flue gas sensors and temperature sensors located downstream of the economizer zone 28. For example, if a reheater is deployed within the boiler, it may be desirable to have flue gas sensors 42 and temperature sensors 43 located in the superheater zone 26 or the reheater zone. To this end, in one embodiment, the information provided by the flue gas sensors 42 and temperature sensors 43 in this section may be used to gain an understanding of the combustion in the boiler based on the heat exchange occurring at the superheater zone 26 and the reheater zone.

FIG. 1 further shows that the fuel boiler system 10 may include an oxygen sensor 44 disposed in the outlet to the chimney, the oxygen sensor being configured to monitor the oxygen concentration in the flue gas. In one embodiment, the sensor 44 may be a paramagnetic sensor. The sensor 44 may also be communicatively coupled to the control unit 100 for relaying the detected oxygen concentration to the control unit 100.

While the array of sensors and monitoring devices discussed above may be used to detect, for example, CO, NOx and other emissions, _O2 distribution, flame information, temperature, and the like, various other sensors and monitoring devices may also be utilized within the fuel boiler system 10. Other examples of sensors that may be deployed include, but are not limited to: pressure sensors that measure pressure drops between various locations within the boiler 12 or high frequency pressure pulsations caused by uneven combustion; and temperature sensors located at other locations within the boiler. In one embodiment, the chimney may be configured with an opacity monitor to assess the extent to which the visibility of the background (i.e., blue sky) is reduced by particulates for determining the amount or concentration of particulates in the flue gas exiting the chimney. In one embodiment, wall condition sensors may be deployed around the water wall of the boiler to assess heat flux and furnace wall conditions, such as corrosion and/or deposit accumulation.

It should be understood that the components of the boiler 12 depicted in FIG. 1 do not represent all elements that may be part of the boiler. One of ordinary skill in the art will understand that a boiler may have other components depending on the type and use, such as, for example, subcritical steam generation or supercritical steam generation. For the sake of clarity and for a general understanding of the various embodiments, the components depicted in FIG. 1 are for the purpose of providing a basic understanding of a steam boiler. The components and operation are not intended to limit the various embodiments, as it is understood that the components and operation of the boiler may vary.

As mentioned above, the fuel and air provided by the pulverizer 16 are mixed with auxiliary air provided by the air source 18 and the overfire air added above the fuel and air and burned in the burner area of the furnace 14, resulting in the generation of flames. FIG2 shows a schematic diagram of this portion of the boiler 12 depicted in FIG1 together with further details of the combustion of fuel and air in the furnace according to an embodiment of the present invention.

In the schematic diagram of FIG2 , one or more wind boxes 48 may be positioned on one or more walls of the furnace 14, such as at a corner in the case of a tangentially fired boiler, or on a single or opposing walls in the case of a wall-fired boiler. In the embodiment depicted in FIG2 , the wind boxes 48 are positioned in a corner of the boiler 12 and thus may correspond to a tangentially fired boiler. Each wind box 48 may have a plurality of air compartments 50 through which auxiliary air supplied from the air source 18 is injected into the burner zone 21 (i.e., the main burner zone). Also disposed in each wind box 48 are a plurality of fuel compartments 52 through which fuel and air provided from one or more pulverizers 16 are injected into the main burner zone via a plurality of fuel conduits 54. One or more pulverizers 16 are operably connected to an air source (e.g., a fan) so that the air flow generated by the air source transports the fuel from the pulverizers 16 through the fuel conduits 54, through the fuel compartments 52, and to the main burner zone of the burner zone 21 in a manner well known to those of ordinary skill in the art.

In this configuration, a plurality of fuel compartments 52 and a plurality of air compartments 50 define an elevated configuration of fuel and air introduction locations along the wall of the furnace 14 for introducing a mixture of fuel and air into the main burner zone to generate a flame therein. In this configuration, each of the plurality of fuel compartments 52 may include a burner having a fuel nozzle that operates to provide a flow of fuel and air into the main burner zone, and the plurality of air compartments 50 may each include one or more auxiliary air nozzles that operate to supply an auxiliary air flow into the burner zone for contributing to combustion with the primary fuel and air provided by the fuel nozzles.

The burner and corresponding fuel nozzles and auxiliary air nozzles may comprise any common assembly of such components known to those skilled in the art. In addition, it will be appreciated that in the case where air is used to convey pulverized fuel, a burner for liquid or gaseous fuels such as natural gas is more likely to have separate nozzles for air and fuel than a burner designed for pulverized solid fuels. As used herein, in the case where air is used to transport powdered fuel, a fuel nozzle that provides a flow of fuel and air to a burner zone covers fuel nozzles operating as providing a flow of fuel and air to a burner zone in conjunction with powdered solid fuel, and compact fuel and air nozzles performing similar functions as associated with a burner configured for liquid or gas fuels.

In the case of an elevated configuration with fuel and air introduction locations at corners as depicted in FIG2 , each elevation will correspond to an angular firing step with one or more burners, with each step separated by an air compartment 50. In this manner, the burners and air compartments can produce a swirl and rotating fireball that meets the furnace combustion chamber 14 just off-center, filling a majority of its cross-section. It should be understood that the schematic depicted in FIG2 represents a configuration for a tangentially fired boiler and is not intended to be limiting. For example, there may be more angular firing steps than depicted in FIG2 , or the boiler furnace may be wider, with eight burners per elevation, configured to produce two swirling fireballs in each group of four burner groups. Furthermore, it will be appreciated by those of ordinary skill in the art that a tangentially fired boiler may include, for example, 4, 5, 6, 7, or 8 levels. To this end, a tangentially fired boiler may have a number of burners, for example ranging from 16 to 64, located at four or eight corners of the furnace. Furthermore, it will be appreciated that in this configuration for a tangentially fired boiler, there may be one or more pulverizers 16 for supplying fuel and air to the burners. For example, it may be feasible to have a separate pulverizer for each of the four or eight corners of the furnace to feed the burners at each angular level.

Referring to Figure 2, in order to assist in the combustion of any air or fuel that is not burned in the main burner zone, one or more discrete levels of separated fire air (SOFA) can be incorporated into each corner of the boiler 12 so that it is located between the top of each wind box 48 and the boiler outlet plane 56 of the boiler, thereby providing, for example, low-level separated fire air 58 and high-level separated fire air 60.

FIG. 3 is a schematic diagram of a system 62 for optimizing combustion in a boiler such as that depicted in FIG. 1 and FIG. 2 . As shown in FIG. 3 , the system 62 includes a plurality of fuel flow sensors 64 to obtain measurements of the flow of fuel and air provided to the plurality of burners in a plurality of fuel compartments (described above with respect to FIG. 2 ). In one embodiment, each of the fuel flow sensors 64 operates to obtain real-time measurements of the flow of fuel and air supplied to the burners. The fuel flow sensor 64 may take the form of any of the commercially available fuel flow sensors known in the art. Non-limiting examples of fuel flow sensors include those provided by Doppler radar, triboelectric charging, or ultrasonic measurement techniques. In addition, it is well known to those skilled in the art that some fuel flow manufacturers may recommend installing more than one sensor in each conduit to achieve the most accurate measurement results. Further references herein to a fuel flow sensor 64 in each conduit may refer to multiple sensors in each conduit being interchangeable with a single fuel flow sensor per conduit.

One or more auxiliary air flow sensors 66 can obtain a measurement of the flow of auxiliary air (combustion air) supplied to the burner zone by a plurality of auxiliary air nozzles (FIG. 2) positioned in a plurality of air compartments around (i.e., above, below, or around) a plurality of burners. In one embodiment, each of the auxiliary air flow sensors 66 operates to obtain a real-time measurement of the flow of auxiliary air supplied to the burner zone by one or more of the plurality of auxiliary air nozzles. The auxiliary air flow sensors 66 can take the form of any of the commercially available air flow sensors known in the art. Non-limiting examples of auxiliary air flow sensors include technologies using such as hot wires, moving vanes, vortices, coriolis, or a pressure differential across an orifice plate.

When it is impractical to use a separate air flow sensor for each air nozzle, the air flow can be calculated from the air flow in a larger duct or bellows 48 (FIG. 2) and the position of the separate baffles or air flow control devices 30 leading to each air compartment 50 and nozzle (FIG. 2). The effective free flow area through each baffle has a nonlinear relationship with the baffle position. The nonlinear relationship varies with the mechanical design of the air compartment 50 and its nozzle, and the mechanical design of the air baffle blades if the air flow control device 30 is an air baffle. Public scientific literature provides many examples of such nonlinear relationships that can be used to determine the effective free stream cross-sectional area of each air compartment 50 and nozzle with the air flow control device 30 at a known location. Alternatively, a scaled solid flow model or computational fluid mechanics model can be used to determine the nonlinear relationship for a particular air compartment 50 and nozzle and air control baffle design. The air flow through each air compartment 50 and nozzle is roughly proportional to the total air flow through the bellows 48 multiplied by the effective free stream area of the particular air compartment 50 and nozzle divided by the effective free stream area of all air compartments 50 fed by the bellows 48 and the total effective free stream area of the nozzles.

3 also shows that the system 62 may further include a plurality of flame scanners 46 to obtain flame scanning data of the flame in the burner region 21 ( FIG. 2 ) of the boiler 12. The flame scanning data obtained by the flame scanner 46 may include any of the aforementioned information discussed above with respect to the flame scanner.

A plurality of flue gas sensors 42 may obtain measurements of a plurality of properties associated with the flue gas. The measurements of the plurality of properties obtained by the flue gas sensors 42 may provide information indicative of combustion occurring in the combustor zone. In one embodiment, the flue gas sensors 42 may be configured to detect combustion gas species in the flue gas downstream of the economizer zone 28 (FIG. 2), including but not limited to CO, _CO2 , Hg, SOx, NOx, and _O2 . The flue gas sensors may take the form of any of the aforementioned gas sensors.

In addition to the measurements obtained by the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, and the flue gas sensor 42, the system 62 can collect other information about the boiler. For example, because the actual air flow near each burner can be affected by the air flow control device 30, information related to such devices can be collected and utilized as part of the combustion optimization described herein. As shown in Figure 3, a plurality of air flow control devices 30 can control the supply of auxiliary air flow to the burner zone through a plurality of auxiliary air nozzles. In one embodiment, the plurality of air flow control devices 30 may include electrically or pneumatically actuated air dampers, however, in alternative embodiments, any of the aforementioned air flow control devices may be deployed.

In operation, each of the air flow control devices 30 may be coupled to one of a plurality of auxiliary air nozzles such that each air flow control device operates to control the flow of auxiliary air into the burner zone through the correspondingly coupled auxiliary air nozzle. Information may be collected regarding the location of each of the air flow control devices 30 and their operating status, as such items may have relevance to the actual air flow near the burner. In one embodiment, this information associated with the air flow control devices 30 may be collected by a power plant control unit 100 that may provide overall control of the boiler 12.

In one embodiment, as shown in FIG3, one or more pressure sensors 70 can obtain pressure measurements about the furnace of the boiler 12. For example, the pressure sensor 70 can measure combustion variations or high frequency pulses caused by pressure drops between various locations within the boiler 12.

3, the controller 72 may receive information provided by the fuel flow sensor 64, the auxiliary air flow sensor 66 (if present), the flame scanner 46, the smoke sensor 42, the air flow control device 30, and the pressure sensor 70. In one embodiment, the controller 72 operates to optimize the combustion of fuel and air in the burner zone based on the information provided by the fuel flow sensor 64, the auxiliary air flow sensor 66 or the calculated air flow (as described above), the flame scanner 46, the smoke sensor 42, and the air flow control device 30. The details of the optimization performed by the controller 72 are described with reference to Figures 4 to 6, however, in general, the controller determines the air-fuel ratio near each of the burners based on data collected from the fuel flow sensor 64, the auxiliary air flow sensor 66 or the calculated or calculated air flow, the flame scanner 46, the smoke sensor 42 and the air flow control device 30. The controller 72 then determines an operating bias that redistributes the air near one or more burners to more consistently match the air-fuel ratio of the other burners while maintaining approximately the same amount of air at each elevation of the vertical furnace in the case of a tangentially fired boiler or a vertical wall-fired boiler, or at each longitudinal distance of the burner from the furnace in the case of a horizontal wall-fired boiler. The operating bias determined by the controller 72 may be communicated to the power plant control unit 100 via the communication network 74. The control unit 100 may apply the operating bias to one or more of the burners at a controlled rate via the air flow control device 30. The controller 72 evaluates the combustion operation of the boiler after applying the operating bias to one or more of the burners to determine whether the applied operating bias results in a better combustion operating result than the combustion operating result obtained before the application of the operating bias.

If the operating bias applied to one or more of the burners does not produce a better combustion operating result, the controller 72 may revert to the operating bias applied to one or more of the burners, collect more data, and repeat the same operation (e.g., determine the amount of air near each of the burners, the air-fuel ratio of each of the burners, determine another set of operating biases, apply those biases to another one or more of the burners, and evaluate the combustion operating results). These operations may continue until there is an air-fuel ratio balance between each of the burners, or until no further combustion improvement is observed, and then continue again when the operation changes (e.g., such as a change in the energy generated) or when a burner under maintenance is selected.

It should be understood that communications between the controller 72, the power plant control unit 100 and the remote control unit 76 (which may perform any number of activities, including but not limited to performing remote monitoring and diagnostics of the controller and the power plant control unit, reviewing boiler operation and the effects of applied optimization biases, or updating limits and tuning parameters in the application logic via the communication network 74) may include any of the well-known communication networks and data communication protocols used to convey information between such networks. For example, a wide area network (WAN) and a local area network (LAN) may be used in conjunction with the communication network 74 to enable communications between the controller 72, the power plant control unit 100, and the remote control unit 76, while using data communication protocols (such as Modbus TCP/IP) or other communication protocols (such as Remote Desktop Protocol (RDP)) to facilitate information communications between each of these components.

Furthermore, the embodiment depicted in FIG. 3 represents only one method for deploying the system 62 and is not intended to be limiting, as one of ordinary skill in the art will appreciate that the system 62 may take the form of other configurations. For example, the controller 72 may be located on one computer and/or distributed between two or more computers. Furthermore, the controller 72 and the power plant control unit 100 may be distributed to one or more control units in different configurations and still operate according to the various embodiments of the present invention. For example, instead of having the controller 72 and the power plant control unit 100 configured as separate components, it should be understood that these components may be combined into a single unit, or divided into 3 or more units. In one embodiment, the controller 72 may be integrated into the power plant control unit 100 such that data from the various sensors and devices are provided to the power plant control unit and the optimization aspects of the various embodiments may be performed by the combustion optimization components within the power plant control unit. Furthermore, it should be understood that the system 62 depicted in FIG. 3 is applicable to operation with the boiler depicted in FIG. 1 and FIG. 2. Furthermore, as mentioned above, the boiler depicted in FIG. 1 and FIG. 2 represents only one boiler configuration and is not intended to be limiting to the various embodiments, as one of ordinary skill in the art will understand that the system 62 and its operation have applicability to other boiler configurations.

FIG. 4 is a block diagram showing more details of the controller 72 depicted in FIG. 3 according to an embodiment of the present invention, the controller including a combustion optimization component for performing combustion optimization of a boiler. The aspects of the controller 72 (including the methods, procedures, and operations performed by it) may constitute machine executable components embodied in (multiple) machines, such as embodied in one or more computer readable media (or media) associated with one or more machines. Such components, when executed by one or more machines (e.g., (multiple) computers, (multiple) computing devices, (multiple) automation devices, (multiple) virtual machines, etc.), may cause the (multiple) machines to perform the described operations.

Further, in the following description of the controller 72 in FIG. 4 and in the description associated with other figures, the terms "object", "module", "interface", "component", "system", "platform", "engine", "selector", "manager", "unit", "store", "network", "generator", and the like may be used to indicate a computer-related entity, or an entity associated with or being a part of an operating machine or device having a specific functionality. These entities may be hardware, a combination of hardware and firmware, a combination of firmware, hardware and software, software, or software in execution. In addition, entities identified by the above terms are generally referred to herein as "functional elements." As an example, a component may be, but is not limited to, a program running on a processor, a processor, an object, an executable file, a thread, a program, and/or a computer. For example, an application running on a server and the server may both be components. One or more components may reside within a program and/or thread, and components may be localized on one computer and/or distributed between two or more computers. Furthermore, these components may be executed from a variety of computer-readable storage media having a variety of data structures stored thereon. The components may communicate via local and/or remote processes, such as based on signals having one or more data packets (e.g., data from a component interacting with another component in a local system, a distributed system, and/or data from a component interacting with other systems via the signal across a network (such as the Internet). As an example, a component may be a device having specific functionality provided by mechanical parts operated by an electrical or electronic circuit system, which is operated by software, or firmware applications executed by a processor, where the processor may be internal or external to the device and execute at least a portion of the software or firmware application. As another example, a component may be a device that provides specific functionality through electronic components rather than mechanical parts. The electronic component may include a processor therein to execute software or firmware that at least partially grants the functionality of the electronic component. The interface(s) may include input/output (I/O) components and associated processor(s), application(s), or API(s) components. Although the examples presented above are related to components, the exemplary features or aspects also apply to objects, modules, interfaces, systems, platforms, engines, selectors, managers, units, storage, networks, and the like.

Referring again to FIG. 4 , the controller 72 may include a data acquisition and preprocessing component 78, a combustion optimization component 80 (which may also be referred to as an “optimizer”), an interface component 82, one or more processors 84, and memory 86, which may include static or dynamic random access memory (RAM), flash memory, rotational disk memory, solid state disk (SSD), or optical storage such as a compact disk (CD) or digital versatile disk (DVD). The memory 86 stores data 88, which may include but is not limited to the time history of sensor data, the time history of processed sensor data, the time history of calculated burner stoichiometry, the time history of calculated bias, the time history of data communicated between the controller 72 and the control unit 100, the program executable code used for the controller 72, the warnings or messages generated by the executable code, and the configuration data used by the executable code to perform the above-mentioned actions and the actions of reference Figures 5 and 6.

In various embodiments, one or more of the data acquisition and pre-processing component 78, the combustion optimization component 80, the interface component 82, the one or more processors 84, and the memory 86 may be electrically and/or communicatively coupled to each other to perform one or more of the functions of the controller 72. In some embodiments, one or more of the data acquisition and pre-processing component 78, the combustion optimization component 80, and the interface component 82 may include software instructions stored on the memory 86 and executed by the processor 84. In addition, the controller 72 may interact with other hardware and/or software components not depicted in FIG. For example, processor(s) 84 may interact with one or more external user interface devices such as a keyboard, mouse, display monitor, touch screen, printer, network communications controller, removable memory device (such as a flash memory drive), or other such interface devices.

The data acquisition and pre-processing assembly 78 may be configured to acquire measurements obtained by the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, and the smoke sensor 42, the pressure sensor 70, and position and status information from the air flow control device 30. In one embodiment, the data acquisition and pre-processing assembly 78 may include a plurality of analog-to-digital converters (A/D), wherein each A/D converter is operably coupled to one of the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, the smoke sensor 42, and the air flow control device 30.

In another embodiment, some or all of the sensors listed in the preceding sentence may communicate with the data acquisition and pre-processing component 78 via one or more digital communication interfaces (including but not limited to communication networks and protocols such as Modbus/TCP or Modbus RTU), wireless communication systems (including but not limited to WiFi, Bluetooth or Zigbee), or analog electrical signals (such as 4-20ma current loops or 0V-to-10V electrical signals). In another embodiment, some or all of the sensors listed in this paragraph may transmit electrical signals to one or more separate input/output devices, which then communicate with the data acquisition and pre-processing component 78 via digital communication interfaces (including but not limited to Modbus/TCP or Modbus RTU). In another embodiment, some or all of the sensors may communicate with the power plant control unit 100, which may then communicate the measurements via a digital communication interface, including but not limited to Modbus/TCP, Modbus RTU, or OLE for process control (OPC). In this manner, the A/D converter may convert the physical condition signals provided to the controller 72 by the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, the flue gas sensor 42, and the air flow control device 30 into digital form for further storage and analysis.

The data acquisition and pre-processing component 78 may further include a data pre-processor configured to eliminate noise embedded in the signals obtained from the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, the smoke sensor 42, and the air flow control device 30, and extract key feature related information from these components. In general, data pre-processing may include segmenting the data received from the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, the smoke sensor 42, and the air flow control device 30, cleaning the data, and extracting key feature related information. In one embodiment, data pre-processing may include time averaging of data obtained from the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, the flue gas sensor 42, and the air flow control device 30. In this manner, the time-averaged pre-processed data may provide representative data values indicative of combustion conditions in the boiler while accounting for unstable operation and noise measurements in the boiler.

In one embodiment, data preprocessing may include performing other mathematical processing or statistical operations on the data to obtain an indication of combustion conditions. Such mathematical processing and statistical operations may include, but are not limited to, one or more of averaging, sensor value range checks to exclude unrealistic values based on boiler process conditions, using sensor status or measurement quality information to exclude known poor or inaccurate sensor measurements, excluding sensor values that differ too much from previous measurements in time and are therefore known to be erroneous, excluding a group of similar measurements that differ too much from the median or mean of the sensor value, or other forms of data preprocessing.

To this end, a representation of the combustion condition may be obtained by performing any of these mathematical processing operations. For example, a Doppler radar based fuel flow sensor may be affected by an increase in turbulent air flow and report a fuel flow value that is higher than the expected fraction of the pulverizer fuel flow, such as significantly higher than one-quarter or one-eighth of the total pulverizer fuel flow in a tangentially fired boiler. In another example, the measurement quality reported by the fuel flow sensor may be poor if the sensor is unable to successfully complete a measurement. When the corresponding measurement quality is poor, any measurement value from the sensor should be excluded from the data set used for combustion optimization. In another example, if the controller loses communication with the sensor or I/O device, the measurement data may be discarded.

Utilizing the data acquired and pre-processed by the data acquisition and pre-processing component 78, the combustion optimization component 80 may use this information to optimize the combustion of fuel and air in the burner zone based on information provided by the fuel flow sensor 64, the auxiliary air flow sensor 66 or equivalent calculated air flow, the flame scanner 46, the smoke sensor 42 and the air flow control device 30 and the pressure sensor 70. In one embodiment, the combustion optimization component 80 may include a guided search optimization algorithm that blends measured and/or calculated chemical measurements of the burners in the boiler with a search algorithm that is customized to find operating biases that can be applied to one or more of the burners to simultaneously consider measurement inaccuracies and unexpected interactions between burners when determining and evaluating the operating biases, producing better combustion operating results for the boiler.

In general, the guided search optimization algorithm of the combustion optimization component 80 optimizes the combustion of fuel and air in the burner area of the boiler by performing and facilitating certain operations. These operations may include determining the air-fuel ratio near each of the burners based on the acquired and pre-processed data provided by the data acquisition and pre-processing component 78. Next, operating biases are determined that redistribute air in the vicinity of one or more burners to more consistently match the air-fuel ratio of the other burners while maintaining approximately the same amount of air at each elevation of the vertical furnace in the case where the boiler is a vertical tangentially-fired boiler or a vertical wall-fired boiler, or at each longitudinal distance of the burner from the furnace in the case where the boiler is a horizontal wall-fired boiler.

The determined operating bias may then be communicated to the power plant control unit 100 via the interface component 82. The power plant control unit 100 may then apply the operating bias to one or more of the burners using air control logic known in the art. The data acquisition and pre-processing component 78 may then collect data from the boiler after a predetermined amount of time has elapsed with the applied bias. The guided search optimization algorithm of the combustion optimization component 80 may then evaluate the data to determine whether the applied operating bias results in a better combustion operating result than the combustion operating result obtained before the application of the operating bias.

If the operating bias applied to one or more of the burners produces a better combustion operation result, the guided search optimization algorithm can determine additional operating biases for one or more additional burners. Alternatively, if the operating bias applied to one or more of the burners does not produce a better combustion operation result, the guided search optimization algorithm can return to the operating bias applied to one or more of the burners, collect more data, and repeat the same operation (e.g., determine the amount of air near each of the burners, the air-fuel ratio near each of the burners, determine another set of operating biases, apply those biases to another one or more of the burners, and evaluate the combustion operation results). These operations performed by the guided search optimization algorithm may continue until there is an air-fuel ratio balance between each of the burners, or until no further combustion improvement is observed, and then again when boiler operation changes (e.g., changes in boiler fuel or air flow) or burner changes are selected for maintenance. Further details of the optimization performed by the guided search optimization algorithm of the combustion optimization component 80 are described with reference to Figures 5 and 6 for tangentially fired boilers and wall-fired boilers, respectively.

As mentioned above, the interface component 82 can communicate the determined operating preference to the power plant control unit 100 via the communication network component 74 (Figure 3), however, the interface component can be used to perform other functions. These functions include but are not limited to storing data (such as time series sensors and calculation data or application messages) and alerting to the memory 86 as part of the stored data 88. The interface component 82 can also communicate, such as power plant historical data records to other power plant control, data communication and display or data storage systems.

The one or more processors 84 may perform one or more of the functions described herein with reference to operations associated with the data acquisition and preprocessing component 78, the combustion optimization component 80, and the interface component 82. The memory 86 may be a computer-readable storage medium that may store computer-executable instructions and/or information for performing the functions described herein for performing the functions described herein with reference to the disclosed systems and/or methods associated with the data acquisition and preprocessing component 78, the combustion optimization component 80, and the interface component 82.

FIG. 5 is a flow chart 102 describing a method for optimizing combustion in a tangentially fired boiler according to an embodiment of the present invention. Generally speaking, a tangentially fired boiler utilizes burners located on one or more walls of the boiler, such as, in particular, at the corners of the wall. The burners at the corners of the boiler may define an elevated configuration of fuel and air introduction locations for introducing a mixture of fuel and air into the furnace of the boiler (and, in particular, the burners of the furnace) to produce a flame. The elevated configuration of fuel and air introduction locations at the corners generally includes a plurality of firing angle levels, wherein each firing angle level has one or more burners, with 4 or 8 burners being most common. Each of the burners includes a fuel nozzle that operates to provide a flow of fuel and air into the burner zone at a specified angle of incidence within the elevated configuration. In this way, the burner can produce a vortex and a rotating fireball that meets the eccentricity of the furnace just in time, filling a large portion of its cross-section. The number of angles of incidence that can be arranged vertically on the corners of the wall can include, for example, 4, 5, 6, 7 or 8 levels. For this purpose, assuming 4 or 8 corners and 4 to 8 levels, a tangentially fired boiler can have a number of burners disposed in the corners of the furnace, for example ranging from 16 to 64. Other combinations of elevations and corners are also possible and do not include optimization using various embodiments of the present invention.

The method of optimizing combustion in a tangentially fired boiler as described in the flow chart 102 of FIG5 may begin at 104 by collecting sensor data. In one embodiment, the data acquisition and pre-processing component 78 of the controller 72 may collect measurements obtained by the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, and the flue gas sensor 42, as well as position and status information from the air flow control device 30. This data collected may include: individual fuel flow to each burner; any of the aforementioned flame data produced by the flame scanner 46; the amount of _O2 , CO, and NOx in the flue gas (e.g., downstream of the economizer outlet); the position of the air flow control device 30; and the flow of auxiliary air to the auxiliary nozzles. It should be understood that the data acquisition and pre-processing assembly 78 may collect other types of data, and therefore embodiments of the present invention are not intended to be limited to any particular data, and only data obtained by the above-mentioned sensors. For example, the data acquisition and pre-processing assembly 78 may collect the temperature of the primary air flow associated with the fuel supplied to the fuel injectors, and the temperature of the auxiliary air flow in the wind box provided to the burner zone. Other data may include, but are not limited to, pressure measurements, fuel pulverizer motor amps or power consumption, steam temperature from superheater or reheater heat exchanger tubes or headers or air, and fuel velocity measurements.

This data collection may occur for a predetermined amount of time sufficient to obtain an average amount of data, taking into account fluctuations in the boiler process due to factors that may include, but are not limited to, variations in the delivery of fuel to the burner, variations in the ability of the sensors to measure data, sensor signals or measurement noise from a variety of reasons. In one embodiment, the data acquisition and pre-processing component 78 may collect data from the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, the flue gas sensor 42, and the air flow control device 30 for up to ten minutes. One of ordinary skill in the art will appreciate that other time periods may be utilized to obtain a good average of representative data, and thus the ten minute time period is not intended to be limiting.

The flow chart 102 continues at 106 by pre-processing the collected data to remove noise embedded in the signals obtained from the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, the smoke sensor 42, and the air flow control device 30, and extract key feature related information from these signals. In one embodiment, the data pre-processing may include time averaging of the data obtained from the fuel flow sensor 64, the auxiliary air flow sensor 66, the flame scanner 46, the smoke sensor 42, and the air flow control device 30. To this end, the time-averaged data may provide data values representative of the combustion conditions in the boiler while taking into account unstable operation and noise measurements in the boiler.

In one embodiment, data preprocessing may include performing other mathematical processing or statistical operations on the data to obtain an indication of the combustion condition. As mentioned above, such mathematical processing and statistical operations may include, but are not limited to, using sensor measurement quality or status values to identify and reject known or suspected poor measurement data, and some or all of the other techniques mentioned above may also be employed when preprocessing the measurement data to provide the most accurate assessment of the current boiler combustion. To this end, an indication of the combustion condition may be obtained by performing any of these mathematical processing operations.

As mentioned at 108, if there are any major operational changes of the boiler, the operations of flow diagram 102 may collect more sensor data at 104 and pre-process the data at 106. As used herein, a major operational change of the boiler may include, but is not limited to, a significant change in boiler fuel flow rate or energy output, starting or stopping operation, a change in fuel properties, or communication errors with key sensors.

If no major operational changes have occurred as determined at 108, then operation of the flow chart continues with determining air from primary and secondary air streams near each of the burners at 110. Generally, air near each of the burners from the primary air stream that carries fuel to the boiler can be determined based on primary air flow through a fuel pulverizer, mill air flow testing, effective nozzle free stream area based on nozzle/baffle geometry, and nonlinear baffle opening/air flow relationships. As used herein, "near each of the burners" means air that is injected into the furnace along with fuel or from a nearby air inlet nozzle where the air is expected to react with the fuel from the burner nozzle.

In one embodiment, the air from the primary air flow near each of the burners is determined by dividing the primary air flowing through the fuel pulverizer by the number of burners fed by that pulverizer. For example, in a tangentially fired furnace, each elevation typically has 4 or 8 burners. If pulverizer air flow test data is available, it is used to determine that the air flowing through the pulverizer flows through each burner nozzle at a different percentage, rather than simply dividing the total flow by the number of burners. If the individual air nozzle flows are not measured separately, they can be calculated as described above. The measured or calculated air flow from the auxiliary air nozzles directly above the burners in the tangentially fired furnace and the fuel air nozzles supplying air directly around the main fuel/air flow are added to the main stage air flow that conveys the fuel through the burners to determine the air flow near each burner. If there are additional air inlets near the burners (e.g., fuel air, compact over-fire air (CCOFA), concentric combustion system (CFS) air nozzles, or crotch air nozzles), the calculated or measured air flow from these nozzles may be included in the total air near the burners. At operation 112, the addition of air at all various levels is reflected in FIG. 5.

With this estimate of the total air near each of the nozzles, the operation of the flowchart 102 continues at 114, where the air-fuel ratio near each of the burners (i.e., stoichiometry) can be determined. Specifically, as described above, the pre-processed average of the air flowing through or near each burner is divided by the pre-processed average fuel flowing through the burner to determine the current air-fuel ratio for the time period. In one embodiment, the time period for sampling data can be 10 minutes.

At 116, operating biases are determined that redistribute air through or near one or more of the burners at the elevation step to be more consistent with the air-fuel ratio of the other burners around the elevation step while maintaining approximately the same amount of air at each elevation step while complying with various limitations, such as minimum and maximum allowable biases for the damper operating range (e.g., -10% to +10%), or a minimum opening value for each fuel-air damper to ensure that adequate cooling air is provided to the burner nozzle tip. As used herein, "more consistent" means that the optimizer can deflect the required amount of air flow to achieve a perfectly balanced air-fuel ratio for the burner being optimized, and "maintaining approximately the same amount of air at each elevation level" means that the deflection restriction applied to some but not all air injectors at an elevation may result in a slight increase or decrease in the total amount of air flowing through the burner or injectors at that elevation because an equal mass flow of air is not added or removed near the burner at that elevation.

In one embodiment, the operating bias is determined by: calculating the mass air flow required to achieve a perfectly balanced air-fuel ratio at the burner at the elevation while maintaining the same total air flow at the elevation; calculating a new desired air flow, which may include a certain fraction of the change in mass air flow required to achieve the perfectly balanced air-fuel ratio; calculating the damper position change required to achieve the desired air flow; and then limiting the damper bias if the allowed bias limit is less than the damper adjustment required to achieve the desired air flow. Then, for example, if the requested damper position change exceeds the damper bias limit, or if the resulting position of the fuel air damper will not supply sufficient cooling air to the burner nozzle tip, then the bias limit is applied. If a bias limit is applied to some but not all burners at an elevation, the total amount of air flowing through the burners or nozzles at that elevation may be slightly increased or decreased because an equal amount of air flow is not added or removed from the burners. Optionally, the optimizer may be configured to intentionally increase the total air flow at an elevation if some dampers are relatively closed and cannot be further closed sufficiently to achieve a desired mass air flow, or conversely, to decrease the total air flow at an elevation if some dampers are relatively open and cannot be further opened sufficiently to achieve a desired mass air flow.

Depending on whether the previous optimization bias at a level succeeded or failed, the desired air flow may be varied in a subsequent optimization step by the fraction of air flow that achieves perfect air-fuel ratio balance in the burner at that level. That is, the level may be skipped after repeated optimization failures, or the desired air flow fraction may be calculated such that the desired air-fuel ratio after the bias is applied is significantly different. In the case of significant measurement errors, or unexpected interactions between air and fuel injected near different burners, such as caused by faulty burners and air nozzle tilting mechanisms in tangentially fired boilers, a bias in a wrong direction may be deliberately made to improve combustion. As used herein, "biasing in the wrong direction" means biasing the air flow to increase (rather than decrease) the range of air-fuel ratios of the burner being optimized based on measured or calculated values for the various air and fuel flows. This can help the optimizer achieve better overall combustion even in the face of inaccurate measurements or unexpected interactions between the air and fuel inlets in the furnace that most boiler models will not correctly predict.

Next, at 118, the determined operating bias may be applied to one or more of the burners at the elevation level or near one or more of the burners at a controlled rate to avoid significant boiler transients. As used herein, "significant boiler transients" means air or fuel flow disturbances, steam temperature changes that may exceed operating temperature or rate of change limits, or control system oscillations caused by poorly tuned control loops. In one embodiment, the determined operating bias is communicated to the power plant control unit 100 via the interface component 82. The power plant control unit 100 may then use air control logic to apply an operating bias to one or more of the burners at the elevated level at a controlled rate via the air flow control device 30 ( FIG. 3 ).

Then at 119, the data acquisition and preprocessing component 78 may collect data from the boiler and preprocess the data after a predetermined amount of time has elapsed with the applied bias. Then at 120, the combustion operation of the boiler is evaluated to determine whether the applied operating bias results in better combustion operating results than the combustion operating results obtained before the application of the operating bias. As used herein, "better combustion operating results" means an overall improvement taking into account factors including, but not limited to, pollutant emissions, uniformity of resulting _O2 across furnace or economizer outlets due to high or low local stoichiometry near different burners, uniformity of flue gas temperature across furnace or economizer outlets or resulting steam temperature variations in heat exchanger tubes, and flame stability as determined from flame scanners, furnace pressure pulses, or other flame stability indicators. Depending on the operation of the boiler and the emission limits, these factors may be considered with higher or lower weighting factors when determining whether combustion has been improved overall.

In one embodiment, the evaluation of the combustion operation of the boiler includes estimating one or more combustion operation parameters. Such combustion operation parameters may include, but are not limited to, CO, NOx, _O2 , flame stability, and temperature distribution of flue gas or steam temperature leaving the heat exchanger tubes as determined from a flame scanner or other sensor, which temperature distribution may change due to changes in flue gas temperature. This estimating one or more combustion operation parameters may include applying a weighting factor to each of the combustion operation parameters. To this end, each weighting factor may be assigned a lesser or greater degree of importance with respect to evaluating the combustion operation of the boiler. For example, if a boiler generally operates at near or sometimes above its allowable NOx emission levels, the weighting factor applied to the increased NOx emissions may be increased, or the ammonia charges required to reduce NOx emissions through a selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR) emission control system may impose a financial burden on the boiler operator. In another example, a boiler that more frequently experiences burner trips due to unstable combustion may have a higher weighting factor applied to minimum and/or average flame stability and a lower weighting factor applied to the other evaluation criteria.

If, as determined at 122, the operating bias applied to one or more of the burners produces a better combustion operating result, then operation of flow chart 102 continues at 124 where additional operating biases for the next level of burners are determined and, after data is collected at 119, applied at 118 and evaluated at 120. The processes for calculating the biases at steps 116 and 124 may be identical, and it is understood that step 124 includes the calculations performed in steps 110, 112, 114, and 116. Alternatively, if the operating bias applied to one or more of the burners does not produce a better combustion operating result as determined at 122, then the operations of flowchart 102 continue at 126, where the operating bias applied to one or more of the burners is reversed and the optimization of the next level begins at 128. In one embodiment, this optimization at the next level may be initiated after more data is collected for a predetermined period of time to establish a baseline. Operations 106 to 128 may then be repeated. Generally speaking, these operations mentioned in flowchart 102 may continue until there is an air-fuel ratio balance between each of the burners, until no further combustion improvement is observed, and may be restored to help when the boiler operation is changed and optimized.

Although for the purpose of easy explanation, the operation shown in Figure 5 is described as a series of actions. It is necessary to understand and appreciate that the innovation of this subject associated with Figure 5 is not limited by the order of actions, because some actions can occur in different orders and/or occur simultaneously with other actions from those shown and described herein. For example, a person with ordinary knowledge in the art will understand and appreciate that the methodology or operation described in Figure 5 can be alternatively represented as a series of related states or events in a state diagram. In addition, it is not necessary for all actions to be drawn to implement the methodology according to this innovation. Furthermore, when different entities formulate different parts of the methodology, (multiple) interaction diagrams can represent the methodology or method according to this disclosure. Further, two or more of the disclosed example methods can be combined with each other to complete one or more features or advantages described herein.

To this end, it should be understood that the guided search optimization algorithm can be used to optimize the elevation levels of a tangentially fired boiler in accordance with different sequences described with respect to FIG. 5. For example, the guided search optimization algorithm can determine and apply an operational bias to burners at one or more elevation levels at a time. Further, because sometimes burners at certain elevation levels are not operating with respect to boiler loading, the guided search optimization algorithm can be configured to skip those levels in the combustion optimization. In one embodiment, instead of directing the operational flow to step 124 after determining improved combustion at step 122, the flow can be directed to step 110 for determining air passing through each of the burners and subsequent subsequent steps.

FIG. 6 is a flow chart 130 describing a method for optimizing combustion in a wall-fired boiler according to an embodiment of the present invention. Generally, a wall-fired boiler includes a burner positioned vertically on one wall or opposing walls of the boiler. Due to this configuration of the burners, swirls and rotating fireballs are generally not produced in a wall-fired boiler as in a tangentially-fired boiler. Instead, a wall-fired boiler produces multiple flames from the burner to the burner zone, wherein the flames move around each other. In addition, because there may be fewer burners than in a tangentially-fired boiler, one pulverizer may feed fewer burners.

The method of optimizing combustion in a wall-fired boiler as described in the flowchart 130 of Figure 6 has similarities to the flowchart 102 described with respect to a tangentially fired boiler. For example, the flowchart 130 of Figure 6 collects sensor data at 132, pre-processes the data at 134, checks for major operating changes at 136, determines air from the primary air stream near each of the burners at 138, adds primary air, secondary air, and tertiary air (if any) through the burner at the burner design. If auxiliary air or compact overfire air is present above or near each of the burners, it may be added to the air flow near the burners to determine the local combustion air near each burner at 140 and to determine the air-fuel ratio (i.e., stoichiometry) near each of the burners at 142. The operations in FIG. 6 are performed in substantially the same manner as described with reference to the flow chart in FIG. 5 and are not repeated for brevity. In general, the differences between the flow chart 130 of FIG. 6 and the flow chart of FIG. 5 result from the mechanical differences between wall-fired boilers and tangentially-fired boilers. These differences result in changes in how the operating bias is determined, applied, and evaluated.

In one embodiment, the group of burners selected for optimization may include the burners with the highest and lowest air-fuel ratios, while the subsequent optimized group includes the burners with the next highest and next lowest air-fuel ratios. This embodiment addresses the burners that are farthest from the average air-fuel ratio first, with the understanding that those burners are likely to make the greatest improvement in overall combustion. In another embodiment, all burners fed by a single pulverizer are selected for optimization together, while subsequent burner groups are fed by different pulverizers. This embodiment is more similar to the embodiment for a tangentially fired boiler, where all burners fed by a single pulverizer can be optimized together. Many wall-fired boiler designs feed a group of burners across the width of the boiler from each pulverizer, so this embodiment can produce more even combustion across the left and right sides of the furnace. Those skilled in the art will recognize that additional methods of grouping the burners for optimization are possible and embodiments of the present invention do not exclude such methods.

FIG6 depicts such aspects of optimization of the burners of a wall-fired boiler, as follows. At 144, an operating bias is determined that redistributes the air through or near one or more of the burners at the wall of the boiler to be more consistent with the air-fuel ratio of the other burners around the wall while maintaining approximately the same amount of air at each longitudinal distance from the burner. As used herein, "at each longitudinal distance" means the distance in the direction of flue gas flow from the burner at which the secondary air from the burner, the tertiary air from the burner (if present), and any air from any additional nozzles near the burner (if present) are expected to join the primary air and fuel addition from the burner to add combustion fuel. For horizontal wall-fired boilers (such as many industrial-scale boilers), the longitudinal distance will be measured along a straight line emanating from the centerline of the burner. Because the burners in a typical vertical wall-fired boiler point horizontally toward the opposite side of the furnace and the flue gases flow upward, these longitudinal distances can be measured along a curve rather than a straight line.

The determined operating bias may then be applied to one or more burners at a controlled rate to avoid significant boiler transients at 146. In one embodiment, the determined operating bias is communicated to the power plant control unit 100 via the interface component 82. The power plant control unit 100 may then use air control logic to apply the operating bias to one burner at a controlled rate via the air flow control device 30 (FIG. 3).

Then at 147, the data acquisition and preprocessing component 78 may collect data from the boiler and preprocess the data after a predetermined amount of time has elapsed with the applied bias. Then at 148, the combustion operation of the boiler is evaluated to determine whether the applied operating bias results in better combustion operating results than the combustion operating results obtained before the application of the operating bias.

If, as determined at 150, the operating bias applied to one or more burners produces a better combustion operating result, then the operation of the flowchart 130 continues at 152, where an additional operating bias for the burner with the next highest air-fuel ratio imbalance or the burner fed from a different pulverizer is determined, applied at 146, and evaluated at 148 after collecting sensor data at 147. Alternatively, if, as determined at 150, the operating bias applied to one burner does not produce a better combustion operating result, then the operation of the flowchart 130 continues at 154, where the operating bias applied to one or more burners is reversed, and then optimization of the next one or more burners is initiated at 156. In one embodiment, this optimization of the next one or more burners may be initiated after more data has been collected for a predetermined period of time to establish a baseline. Operations 134 to 156 may then be repeated. Generally speaking, these operations mentioned in flow chart 130 may continue until there is an air-fuel ratio balance between each of the burners, or until no further combustion improvement is observed, and then continue again when the boiler is operating (e.g., producing energy) or a burner under maintenance is selected.

Although for the purpose of easy explanation, the operation shown in Figure 6 is described as a series of actions. It is necessary to understand and appreciate that the innovation of this subject associated with Figure 6 is not limited by the order of actions, because some actions can occur in different orders and/or occur simultaneously with other actions from those shown and described herein. For example, a person with ordinary knowledge in the art will understand and appreciate that the methodology or operation described in Figure 6 can be alternatively represented as a series of related states or events in a state diagram. In addition, it is not necessary for all actions to be drawn to implement the methodology according to this innovation. Furthermore, when different entities formulate different parts of the methodology, (multiple) interaction diagrams can represent the methodology or method according to this disclosure. Further, two or more of the disclosed example methods can be combined with each other to implement one or more features or advantages described herein. To this end, instead of sequencing by starting with the burners with the highest and lowest air-fuel ratios, or grouping together all burners fed from the same pulverizer (as discussed in FIG. 6 ), it is possible to sequence multiple groups of burners at a time. One skilled in the art will recognize that other methods of grouping and sequencing pulverizers (including larger or smaller groups) for optimization are possible in addition to the two embodiments described above. The various embodiments of the present invention do not exclude such additional grouping and sequencing methods.

Although the flow charts depicted in FIGS. 5 and 6 generally describe an iterative process of determining additional operating biases after improving combustion, or reversing unimproved combustion and determining new biases to apply, in situations where multiple iterations fail to improve combustion after air-fuel balancing of one or more burners, other approaches may be considered, or additional combustion improvements may be provided after evaluating all burners for optimization. For example, in one embodiment, the optimizer sequence may attempt different air flow adjustments designed to achieve air-fuel ratio imbalances between the current calculated air-fuel ratio imbalance and the calculated air flow required for perfect air-fuel ratio balance between all burners being optimized, i.e., gradually achieving the goal of perfect air-fuel ratio balance. In another embodiment, the optimization sequence may temporarily skip optimizing a level where the previous optimization was biased toward failing to improve combustion after one or more optimization attempts.

In another embodiment, the calculated air flow bias may be calculated to further increase the calculated air-fuel ratio imbalance after one or more previous optimization steps have not resulted in improved combustion. This embodiment is intended to accommodate inaccurate sensor measurements of air and/or fuel flow, and to account for unintended interactions between burners in different corners or elevations of a tangentially fired furnace, or between different burners on the front and/or rear walls of a wall-fired furnace. For example, excess air supplied near one burner may reduce CO emissions from another nearby burner, or may contribute to NOx emissions from another nearby burner, or slag formed by the combustion of solid fuel may partially block air or fuel from flowing into the combustion chamber through one or more nozzles.

Another enhancement to the flow charts depicted in Figures 5 and 6 may include adding steps at the end of the process that include adjusting the secondary air and flue gas recirculation rates after adjusting the individual burners. For example, in one embodiment, the set point for controlling the total amount of air provided for combustion may be increased to reduce CO emissions and potentially reduce the amount of unburned carbon from solid fuel remaining in the ash, or the total combustion air may be reduced to reduce NOx emissions and improve boiler efficiency. In another embodiment of a boiler equipped with a flue gas recirculation (FGR) system, the volume of flue gas recirculated may be increased to reduce NOx emissions, or may be reduced to improve flame stability. In another embodiment, the fraction of combustion air injected into the burner zone of a tangentially fired boiler or a wall-fired boiler may be reduced while increasing the fraction of secondary overfire air (SOFA) to further stage combustion and reduce NOx emissions, or the fraction of combustion air injected into the burner zone may be increased and the fraction of combustion air injected into the SOFA zone may be reduced to further stage combustion and reduce NOx emissions. Improved flame stability. In another embodiment, the amount of compact overfire air (CCOFA) in a tangentially fired furnace can be adjusted to reduce NOx or CO emissions. In another embodiment, the burner plates in a tangentially fired furnace can be adjusted to better balance the amount of energy absorbed in the furnace wall with the amount of energy absorbed in the superheater, reheater and economizer heat exchangers.

The embodiments listed above are not shown in the flow charts in FIG. 5 or FIG. 6 , however, one of ordinary skill in the art will recognize that similar adjustments not listed here may be applied after individual burner groups have been optimized, may be applied after all burner groups have been selected for optimization, or may be applied based on the results of specific criteria for evaluating boiler combustion. All of these alternatives, although not shown in FIG. 5 or FIG. 6 , are not excluded from various embodiments of the present invention.

In order to provide a context for various aspects of the disclosed subject matter, FIGS. 7 and 8 and the following discussion are intended to provide a brief, general description of suitable environments in which various aspects of the disclosed subject matter may be implemented.

7, an example environment 1000 for implementing various aspects of the aforementioned subject matter includes a computer 1012. The computer 1012 includes a processing unit 1014, a system memory 1016, and a system bus 1018. The system bus 1018 couples system components (including but not limited to the system memory 1016) to the processing unit 1014. The processing unit 1014 can be any of a variety of available processors. Multi-core microprocessors and other multi-processor architectures can also be used as the processing unit 1014.

The system bus 1018 may be any of several types of bus structures, including a memory bus or memory controller, a peripheral bus or external bus, and/or any type of available bus architecture, including but not limited to 8-bit bus, Industrial Standard Architecture (ISA), Micro-Channel Architecture (SMA), Serial Advanced Technology Attachment (SATA), IEEE 1394 FireWire, Extended ISA (EISA), Intelligent Drive Electronics (IDE), VESA Local Bus (VLB), Peripheral Component Interconnect (PCI), and/or any type of available bus architecture. PCI), Universal Serial Bus (USB), Advanced Graphics Port (AGP), Personal Computer Memory Card International Association bus (PCMCIA), and Small Computer Systems Interface (SCSI).

System memory 1016 includes volatile memory 1020 and non-volatile memory 1022. A basic input/output system (BIOS), which contains basic routines to transfer information between components within computer 1012 (such as during startup), is stored in non-volatile memory 1022. By way of example and not limitation, non-volatile memory 1022 may include read-only memory (ROM), programmable ROM (PROM), electrically programmable ROM (EPROM), electrically erasable PROM (EEPROM), or flash memory. Volatile memory 1020 includes random access memory (RAM), which acts as external cache memory. By way of example and not limitation, RAM is available in many forms, such as synchronous RAM (SRAM), dynamic RAM (DRAM), synchronous DRAM (SDRAM), double data rate SDRAM (DDR SDRAM), enhanced SDRAM (ESDRAM), synchronous link DRAM (SLDRAM), and direct Rambus RAM (DRAM).

The computer 1012 also includes removable/non-removable, volatile/non-volatile computer storage media. FIG7 shows an example of a disk storage 1024. The disk storage 1024 includes, but is not limited to, devices such as a disk drive, a floppy drive, a tape drive, a Jaz drive, a Zip drive, an LS-100 drive, a flash memory card, or a USB memory stick. In addition, disk storage 1024 may include storage media alone or in combination with other storage media, including but not limited to an optical disk drive, such as a compact disk ROM device (CD-ROM), a CD recordable drive (CD-R Drive), a CD rewritable drive (CD-RW Drive), or a digital versatile disk ROM drive (DVD-ROM). To facilitate the connection of disk storage 1024 to system bus 1018, a removable or non-removable interface, such as interface 1026, is generally used.

It should be understood that FIG. 7 depicts software that acts as an intermediary between a user and basic computer resources described in a suitable operating environment 1000. This software includes an operating system 1028. The operating system 1028, which may be stored on disk storage 1024, functions to control and allocate resources of the computer 1012. System applications 1030 manage resources through the operating system 1028, through program modules 1032 and program data 1034 stored in system memory 1016 or on disk storage 1024. It should be understood that one or more embodiments of the present disclosure may be implemented using a variety of operating systems or combinations of operating systems.

The user inputs commands or information into the computer 1012 through the input device(s) 1036. The input device 1036 includes, but is not limited to, a pointing device such as a mouse, a trackball, a stylus, a touch panel, a keyboard, a microphone, a joystick, a game controller, a satellite dish, a scanner, a TV tuner card, a digital camera, a digital camcorder, a webcam, and the like. These and other input devices are connected to the processing unit 1014 through the system bus 1018 via the interface port(s) 1038. The interface port(s) 1038 include, for example, a serial port, a parallel port, a game port, and a universal serial bus (USB). Output device(s) 1040 use some of the same types of ports as input device(s) 1036. Thus, for example, a USB port may be used to provide input to computer 1012 and output information from computer 1012 to output device 1040. Output adapter 1042 is provided to illustrate that there are some output devices 1040 such as monitors, speakers, and printers in addition to other output devices 1040 that require special adapters. By way of example and not limitation, output adapter 1042 includes video and sound cards that provide a means of connection between output device 1040 and system bus 1018. It should be noted that other devices and/or systems of devices provide both input and output capabilities, such as remote computer(s) 1044.

Computer 1012 may operate in a networked environment using logical connections to one or more remote computers, such as remote computer(s) 1044. Remote computer(s) 1044 may be personal computers, servers, routers, network firewalls, network PCs, workstations, microprocessor-based appliances, peer devices or other public network nodes, and the like, and generally include many or all of the elements described with respect to computer 1012. For purposes of brevity, only memory storage device 1046 is illustrated with remote computer 1044. Remote computer(s) 1044 are logically connected to computer 1012 via network interface 1048, and in turn physically connected to the computer via communication connection 1050. Network interface 1048 includes communication networks such as local area networks (LANs) and wide area networks (WANs). LAN technologies include Fiber Distributed Data Interface (FDDI), Copper Distributed Data Interface (CDDI), Ethernet/IEEE 802.3, Token Ring/IEEE 802.5, and the like. WAN technologies include but are not limited to point-to-point links, circuit-switched networks such as Integrated Services Digital Networks (ISDN) and its variations, packet-switched networks, and Digital Subscriber Lines (DSL).

Communication connection(s) 1050 refer to the hardware/software employed to connect the network interface 1048 to the system bus 1018. Although the communication connection 1050 is shown as being internal to the computer 1012 for clarity of illustration, it may also be external to the computer 1012. The hardware/software necessary for connection to the network interface 1048 includes, for exemplary purposes only, internal and external technologies such as modems including conventional telephone grade modems, cable modems and DSL modems, ISDN adapters, wireless networks (such as WiFi or Bluetooth), and Ethernet cards.

FIG8 is a schematic block diagram of a sample computing environment 1100 with which the subject matter of the present disclosure may interact. The sample computing environment 1100 includes one or more clients 1102. The client(s) 1102 may be hardware and/or software (e.g., threads, programs, computing devices). The sample computing environment 1100 also includes one or more servers 1104. The server(s) 1104 may also be hardware and/or software (e.g., threads, programs, computing devices). As described herein, the server 1104 may host a thread to perform migration by, for example, employing one or more embodiments as described herein. One possible communication between the client 1102 and the server 1104 may be in the form of data packets adapted to be transmitted between two or more computer programs. The sample computing environment 1100 includes a communication framework 1106 that may be employed to facilitate communication between the client(s) 1102 and the server(s) 1104. The client(s) 1102 may be operatively connected to one or more client data stores 1108 that may be employed to store local information of the client(s) 1102. Similarly, the server(s) 1104 may be operatively connected to one or more server data stores 1110 that may be employed to store local information of the server(s) 1104.

From the foregoing description, it should be clear that the systems and methods for optimizing combustion in a boiler according to each embodiment have many technical effects and improvements that are equivalent to technical differences to the known methods for optimizing boilers. For example, in an embodiment in which pulverized solid fuel (such as coal) is provided to the boiler, the fuel flow sensor 64, which may include a coal flow sensor, provides a new real-time measurement of fuel flow to each individual burner. Generally speaking, these fuel flow sensors are temporarily only used for manual pulverizer or boiler tuning. Another technical distinction from various embodiments is that the air flowing through and near each individual burner can be calculated using a number of data including but not limited to auxiliary air flow sensors, power plant control data, air flow control device information (e.g., status, geometry, positioning), and mill test data (if available). To this end, this provides a matching air flow near each burner, which is combined with the fuel flow measurement to calculate the local chemical measurement near each burner.

Various embodiments also differ in that a guided search optimization algorithm may be utilized to perform combustion optimization. The guided search optimization algorithm blends a physics-based approach involving measured and/or calculated chemical measurements of burners in a boiler (which may include tangentially-fired boilers and wall-fired boilers) with a search algorithm that is customized to find operating biases that may be applied to one or more of the burners to simultaneously account for measurement inaccuracies and unexpected interactions between burners when determining and evaluating the operating biases, producing better combustion operating results for the boiler.

By more effectively balancing the local stoichiometry near each burner, pockets of high or low oxygen in the fireball or furnace volume can be reduced. Low oxygen pockets produce CO and can contribute to unburned carbon in the ash, while high oxygen pockets increase NOx. More uniform local burner stoichiometry has been seen to reduce both CO and NOx. In contrast, model-based low NOx combustion optimization methods generally reduce NOx while increasing CO until it is just below the maximum allowable value. After balancing the individual burners, the overall air flow can be reduced to improve efficiency and further reduce NOx if necessary.

Another technical difference of various embodiments compared to known methods for optimizing boilers is that a boiler model is not included in the embodiments. This eliminates the problem of boiler model accuracy under changing equipment and process conditions. There is also no need for a wide range of historical operating data to build and tune the boiler model.

Because of these technical distinctions, various embodiments have several advantages over known methods for optimizing boilers. For example, these embodiments can help reduce the minimum boiler load in response to intermittent renewable energy with better low-load flame stability. Furthermore, embodiments can help increase efficiency at higher boiler loads to reduce operating costs and emissions by reducing excess air while maintaining CO and NOx emissions within environmentally permitted limits. Specifically, NOx and CO emissions can be reduced simultaneously. In addition, fuel flow sensors, air flow sensors, flue gas sensors, and flame scanners that can be used in embodiments can provide more accurate measurements of fuel flow and air flow, thereby supporting uniform burner stoichiometry. By using a guided search optimization algorithm, embodiments can provide improved response to unexpected boiler behavior, fuel changes, and operating modes. In addition, because a physics-based approach is used with embodiments instead of a model-based approach, periodic re-tuning of the model to account for model inaccuracies over time can be avoided.

The above description of illustrative embodiments of the present disclosure (including what is described in the Abstract) is not intended to be exhaustive or to limit the disclosed embodiments to the precise form disclosed. Although specific embodiments and examples are described herein for illustrative purposes, various modifications considered to be within the scope of such embodiments and examples are possible as would be appreciated by one of ordinary skill in the art. For example, components, assemblies, steps, and aspects from different embodiments may be combined in other embodiments or adapted for use in other embodiments even if not described in the present disclosure or depicted in the drawings. Therefore, since certain changes may be made to the above invention without departing from the spirit and scope of the invention involved herein, it is intended that all of the subject matter described above shown in the accompanying drawings should be interpreted merely as illustrating examples of the concepts of the invention herein and should not be taken as limitations on the invention.

In this regard, although the disclosed subject matter has been described with respect to various embodiments and corresponding drawings, it is understood that other similar embodiments may be used, or modifications and additions may be made to the described embodiments, to perform the same, similar, alternative, or replacement functions of the disclosed subject matter without departing therefrom, where applicable. Accordingly, the disclosed subject matter should not be limited by any single embodiment described herein, but rather should be interpreted in accordance with the breadth and scope of the claims appended hereto. For example, reference to "one embodiment" of the invention is not intended to be interpreted to exclude the existence of additional embodiments that also incorporate the recited features.

In the accompanying claims, the terms "including" and "in which" are used as the plain-English equivalents of the terms "comprising" and "comprise." In addition, in the following claims, terms such as "first," "second," "third," "upper," "lower," "bottom," "top," etc. are used merely as labels and are not intended to impose numerical or positional requirements on such objects. The terms "substantially," "generally," and "about" indicate conditions that are within reasonably achievable manufacturing and assembly tolerances relative to ideally desired conditions applicable to achieve the functional purpose of a component or assembly. Furthermore, the following claim limitations are not written in means-plus-function form and are not intended to be so construed unless and until such claim limitations expressly use the phrase "means for" followed by a description of function without further structure.

What has been described above is included to illustrate examples of systems and methods of the disclosed subject matter. Of course, it is not possible to describe every combination of components or methodologies here. One of ordinary skill in the art will recognize that many further combinations and permutations of the claimed subject matter are possible. Furthermore, where the terms "include," "has," "possess," and the like are used in the embodiments, claims, appendices, and drawings, such terms are intended to be inclusive in a manner similar to how the term "comprising" is interpreted when "comprising" is used as a transitional word in the claims. That is, unless explicitly stated to the contrary, embodiments “comprising,” “including,” or “having” an element or a plurality of elements having a particular property may include additional such elements not having that property.

This written description uses examples to disclose several embodiments of the invention, including the best mode, and also to enable a person of ordinary skill in the art to practice the embodiments of the invention, including making and using any device or system and performing any incorporated methods. The patentable scope of the invention is defined by the claims and may include other examples that occur to a person of ordinary skill in the art. If such other examples do not have structural elements that differ from the literal language of the claims, or if such other examples include equivalent structural elements that are not substantially different from the literal language of the claims, then they are intended to be within the scope of the claims.

Further aspects of the invention are provided by the subject matter of the following clauses: A system comprising: a boiler having a furnace containing a burner zone for burning fuel and air to produce flue gases therefrom, the boiler including one of a tangentially fired (T-fired) boiler and a wall-fired boiler; a plurality of burners positioned about the boiler to define an arrangement of fuel and air introduction locations, the burners The burners are each provided with a fuel nozzle and an air introduction position for introducing a mixture of a main fuel and air into the burner zone to generate a flame therein, each of the burners including a fuel nozzle that operates to provide a flow of the main fuel and air into the burner zone; a plurality of auxiliary air nozzles that are positioned around the plurality of burners, the plurality of auxiliary air nozzles being provided to the burner zone. Auxiliary air nozzles are operated to supply a flow of auxiliary air into the burner zone for contributing to the combustion of the main fuel with air; a plurality of air flow control devices, which are used to control the supply of selected flows of auxiliary air into the burner zone through the plurality of auxiliary air nozzles; a plurality of fuel flow sensors, which are used to obtain the main fuel The fuel flow sensors are configured to measure the flow of the primary fuel supplied to the plurality of burners through a corresponding fuel nozzle; and one or more auxiliary air flow sensors are configured to measure the flow of the primary fuel supplied to the burner region through one or more of the auxiliary air nozzles. A plurality of auxiliary air flow sensors are provided for measuring the flow of the auxiliary air supplied to the burner zone by one or more of the plurality of auxiliary air nozzles; a plurality of flame scanners are provided for obtaining flame scanning data of the flame in the burner zone; a plurality of smoke sensors, the plurality of flue gases being operable to obtain measurements of a plurality of properties associated with the flue gases, the measurements of the plurality of properties being indicative of combustion occurring in the burner zone, each of the flue gas sensors being operable to obtain measurements of at least one of the properties; and a controller being operable to generate a plurality of fuel flow sensors, the one or more auxiliary air ... The controller includes a controller for optimizing the combustion of the fuel and air in the burner zone based on information provided by the burner, the plurality of flame scanners, the plurality of flue gas sensors, and the plurality of air flow control devices, wherein the controller includes a guided search optimization algorithm configured to mix the measured and/or calculated chemical measurements of the burners in the boiler with a search algorithm, the search algorithm being customized to find operating biases applied to one or more of the burners to simultaneously consider measurement inaccuracies, equipment condition variations, and unexpected interactions between burners when determining and evaluating the operating biases, producing better combustion operating results for the boiler.

A system as in the foregoing clause, wherein the guided search optimization algorithm is configured to perform operations including: determining the amount of air near each of the burners; determining the air-fuel ratio near each of the burners; determining operating biases, the operating biases redistributing the air passing through one or more burners or near the one or more burners to be more consistent with the air-fuel ratio of other burners, while maintaining approximately the same amount of air at each elevation level of a vertical furnace in the tangentially-fired boiler, or at each longitudinal distance of the burners from a horizontal furnace in a wall-fired boiler; and applying the operating biases to one or more of the burners or near one or more of the burners.

A system as in any of the foregoing clauses, wherein the guided search optimization algorithm is configured to further perform the following operations: after applying the operating biases to one or more of the burners or near one or more of the burners, evaluating the combustion operation of the boiler to determine whether the applied operating biases result in a better combustion operation result than the combustion operation result obtained before the application of the operating biases, the evaluation comprising: A method for evaluating the combustion operation parameters by evaluating the combustion operation parameters based on a weighting factor for each of the one or more combustion operation parameters, wherein each weighting factor is assigned a lesser or greater degree of importance with respect to evaluating the combustion operation of the boiler; and determining an additional operation bias and applying it to one or more additional burners or the one or more additional burners if the operation bias applied to one or more of the burners or near one or more of the burners produces a better combustion operation result. and if the operating biases applied to one or more of the burners or near one or more of the burners do not produce better combustion operation results, then: reverting the operating biases applied to one of the burners or near one of the burners; collecting better combustion information from the plurality of fuel flow sensors, the one or more auxiliary air flow sensors, the plurality of air flow control devices, the plurality of smoke sensors, and the plurality of flame scanners; and repeatedly determining the amount of air near each of the burners, determining the air-fuel ratios near each of the burners, determining another set of operating biases, applying the another set of operating biases to another one or more of the burners or near another one or more of the burners, and evaluating the combustion operation results produced by the another set of operating biases applied to another one or more of the burners or near another one or more of the burners.

A system as in any of the preceding clauses, wherein the determined amount of air near each of the burners includes the air in the flow of the main fuel and air provided to the burner, the auxiliary air provided near the burner or as part of the burner but separated from the main fuel and air flow, and, if present, compact overfire air introduced into the burner zone above the plurality of burners to contribute to the combustion of the main fuel and air and the auxiliary air.

A system as in any of the preceding clauses, wherein the determined amount of air near each of the burners takes into account the effective free flow area of each of the plurality of auxiliary air nozzles, each of the effective free flow areas being determined based on the nozzle and air flow control device design and geometry.

A system as in any of the preceding clauses, wherein the air-fuel ratios determined near each of the burners are based on the fuel flow measurements of the fuel to the plurality of burners and the determined air amounts near each of the burners.

A system as in any of the preceding clauses, wherein evaluating the combustion operation of the boiler comprises estimating one or more combustion operation parameters to determine whether the combustion operation with the operating biases applied to one or more of the burners is better than the combustion operation results obtained before applying the operating biases.

A system as in any of the preceding clauses, wherein the guided search optimization algorithm is further configured to skip additional optimizations after repeated optimization fails, or to intentionally bias in an erroneous direction to improve combustion in the event of significant measurement errors or unexpected interactions between air and fuel injected near or through different burners.

A system as in any of the preceding clauses, wherein the controller is configured to facilitate a change in the amount of air in the burner zone, the change comprising one or more of: increasing or decreasing excess air; increasing or decreasing an air percentage in the secondary overfire air (SOFA) or compact overfire air (CCOFA) in the tangentially fired boiler; changing the burner tilt angle; and deflecting air left to right in the furnace, up and down in the furnace, or between corners in the furnace.

A method for optimizing combustion in a boiler having: a furnace including a burner zone for combusting fuel and air to produce flue gases therefrom; a plurality of burners, wherein each burner includes a fuel nozzle operative to provide a flow of primary fuel and air into the burner zone to produce a flame therein; a plurality of auxiliary air nozzles positioned about the plurality of burners, the plurality of auxiliary air nozzles operative to supply a flow of auxiliary air into the burner zone, for contributing to combustion with the primary fuel and air; a plurality of air flow control devices for controlling the supply of selected flows of auxiliary air to the burner zone through the plurality of auxiliary air nozzles; a plurality of fuel flow sensors for obtaining measurements of the flow of the fuel to the plurality of burners; one or more auxiliary air flow sensors for obtaining measurements of the flow of the auxiliary air supplied to the burner zone through one or more of the plurality of auxiliary air nozzles; a plurality of fire a flame scanner for obtaining flame scan data of the flame in the burner zone; a plurality of smoke sensors, which operate to obtain measurements of a plurality of properties associated with the smoke; and a controller, which operates to execute a method for optimizing the combustion of the boiler based on fuel flow, air flow, flame data, smoke data and information associated with a plurality of air flow control devices, the method comprising: determining an amount of air near each of the burners; ... determining operating biases that redistribute air through or in the vicinity of one or more burners to be more consistent with the air-fuel ratio of the other burners while maintaining approximately the same amount of air at each elevation level of a vertical furnace in the tangentially-fired boiler or at each longitudinal distance of the burners from a horizontal furnace in a wall-fired boiler; and applying the operating biases to or in the vicinity of one or more of the burners.

The method of the preceding clause further comprises: after applying the operating biases to one or more of the burners or in the vicinity of one or more of the burners, evaluating the combustion operation of the boiler to determine whether the applied operating biases result in a better combustion operation result than the combustion operation result obtained before the application of the operating biases, the evaluation comprising evaluating the combustion operation result according to a weighting factor applied to each of the one or more combustion operation parameters. The combustion operation parameters are calculated, wherein each weighting factor is assigned a lighter or heavier degree of importance with respect to evaluating the combustion operation of the boiler; if the operation biases applied to one or more of the burners or near one or more of the burners produce better combustion operation results, then additional operation biases are determined and applied to one or more additional burners or near the one or more additional burners; and if the operation biases applied to one or more of the burners or near the one or more additional burners produce better combustion operation results, then additional operation biases are determined and applied to one or more additional burners or near the one or more additional burners. If the operating biases of one or more or near one or more of the burners do not produce better combustion operation results, then: reverting the operating biases applied to one of the burners or near one of the burners; collecting more data from the plurality of fuel flow sensors, the one or more auxiliary air flow sensors, the plurality of air flow control devices, the plurality of smoke sensors, and the plurality of flame scanners; and repeating Determining the amount of air near each of the burners, determining the air-fuel ratios near each of the burners, determining another set of operating biases, applying the another set of operating biases to another one or more of the burners or near another one or more of the burners, and evaluating the combustion operating results produced by the another set of operating biases applied to another one or more of the burners or near another one or more of the burners.

A method as in any of the preceding clauses, wherein the determined amount of air near each of the burners includes the air in the flow of the fuel and air provided to the burner, the auxiliary air provided near the burner or as part of the burner but separated from the main fuel and air flow, and, if present, compact overfire air introduced into the burner zone above the plurality of burners to contribute to the combustion of the main fuel and air and the auxiliary air.

A method as in any of the preceding clauses, wherein the determined amount of air near each of the burners takes into account the effective free flow area of each of the fuel nozzles and the plurality of auxiliary air nozzles, each of the effective free flow areas being determined based on nozzle and air flow control device design and geometry.

A method as in any of the preceding clauses, further comprising skipping additional optimizations after repeated optimizations fail, or intentionally biasing in an error direction to improve combustion in the event of significant measurement errors or unexpected interactions between air and fuel injected near or through different burners.

A method as in any of the preceding clauses, further comprising promoting a change in the amount of air in the burner zone, the change comprising one or more of: increasing or decreasing excess air; increasing or decreasing an air percentage in the secondary overfire air (SOFA) or compact overfire air (CCOFA) in the tangentially fired boiler; changing the burner tilt angle; and deflecting the air left to right in the furnace, up and down in the furnace, or between corners in the furnace.

10: Fuel boiler system 12: Boiler 14: Furnace 16: Pulverizer 18: Air source 20: Hopper area 21: Burner area 22: Main burner area 24: Combustion area 26: Superheater area 28: Economizer area 30: Air flow control device 34: Flame stability monitor 38: Tail flue 40: Monitoring device 42: Flue gas sensor 43: Temperature sensor 44: Oxygen sensor 46: Flame scanner 48: Bellows 50: Air compartment 52: Fuel compartment 54: Fuel duct 56: Boiler outlet plane 58: Separation of air above the fire at the lower level 60: Separation of air above the fire at the upper level 62: System 64: Fuel flow sensor 66: Auxiliary air flow sensor 70: Pressure sensor 72: Controller 74: Communication network 76: Remote control unit 78: Data acquisition and pre-processing component 80: Combustion optimization component 82: Interface component 84: Processor 86: Memory 88: Data 100: Control unit 102: Flow chart 104: Step; Operation 106: Step; Operation 108: Step; Operation 110: Step; Operation 112: Step; Operation 114: Step; Operation 116: Step; Operation 118: Step; Operation 119: Step; Operation 120: Step; Operation 122: Step; Operation 124: Step; Operation 126: Step; Operation 128: Step; Operation 130: Flowchart 132: Step; Operation 134: Step; Operation 136: Step; Operation 138: Step; Operation 140: Step; Operation 142: Step; Operation 144: Step; Operation 146: Step; Operation 147: Step; Operation 148: Step; Operation 150: Step; Operation 152: Step; Operation 154: Step; Operation 156: Step; Operation 1000: Environment 1012: Computer 1014: Processing Unit 1016: System Memory 1018: System Bus 1020: Volatile Memory 1022: Non-Volatile Memory 1024: Disk Storage 1026: Interface 1028: Operating System 1030: System Application 1032: Program Module 1034: Program Data 1036: Input Device 1038: Interface Port 1040: output device 1042: output adapter 1044: remote computer 1046: memory storage device 1048: network interface 1050: communication connection 1100: sample computing environment 1102: client 1104: server 1106: communication framework 1108: client data storage 1110: server data storage

The present invention will be better understood by reading the following description of non-limiting embodiments and referring to the following accompanying drawings herein: [FIG. 1] is a simplified schematic diagram of a fuel boiler system that produces steam that can be used in power generation applications, in which systems and methods for optimizing combustion in the boiler according to various embodiments of the present invention can be deployed; [FIG. 2] is a schematic diagram of further details of an example of a furnace of a boiler such as that depicted in FIG. 1 together with a configuration of windboxes on the walls having air and fuel compartments, which inject a mixture of air and fuel into the furnace for combustion, wherein the combustion can be optimized according to various embodiments of the present invention; [FIG. 3] is a schematic diagram of a system for optimizing combustion in a boiler such as that depicted in FIG. 1 and FIG. 2 according to an embodiment of the present invention; [FIG. 4] is a block diagram showing more details of the controller depicted in FIG. 3 according to an embodiment of the present invention; [FIG. 5] is a flow chart describing a method for optimizing combustion in a tangentially fired boiler according to an embodiment of the present invention; [FIG. 6] is a flow chart describing a method for optimizing combustion in a wall-fired boiler according to an embodiment of the present invention; [FIG. 7] is an example computing environment in which various embodiments of the present invention may be implemented; and [FIG. 8] is an example network environment in which various embodiments may be implemented.

10: Fuel boiler system

12: Boiler

14: Stove

16: Crusher

18: Air source

20: Hopper area

21: Burner area

22: Main burner area

24: Burning area

26: Superheater area

28: Economizer area

30: Air flow control device

34: Flame stability monitor

38: Tail flue

40: Monitoring device

42: Smoke sensor

43: Temperature sensor

44: Oxygen sensor

46: Flame Scanner

100: Control unit

Claims (15)

A system (62) comprising: a boiler (12) having a furnace (14) including a burner zone (21) for burning fuel and air to produce flue gas therefrom, the boiler (12) including one of a tangentially-fired (T-fired) boiler and a wall-fired boiler; a plurality of burners positioned about the boiler (12) to define an arrangement of fuel and air introduction locations for introducing a mixture of primary fuel and air into the burner zone (21) to generate a flame therein, each of the burners comprising a fuel nozzle operative to provide a stream of the primary fuel and air into the burner zone (21); a plurality of auxiliary air nozzles positioned about the plurality of burners, the plurality of auxiliary air nozzles operative to supply a stream of auxiliary air into the burner zone (21) for contributing to the combustion of the primary fuel and air; a plurality of air flow control devices (30) for controlling the supply of selected flows of auxiliary air to the burner zone (21) through the plurality of auxiliary air nozzles; a plurality of fuel flow sensors (64) for obtaining a measurement of the flow of the primary fuel to the plurality of burners, each of the fuel flow sensors (64) being operated to obtain a real-time measurement of the flow of the primary fuel supplied to one of the plurality of burners through a corresponding fuel nozzle; One or more auxiliary air flow sensors (66) for obtaining a measurement of the flow of the auxiliary air supplied to the burner zone (21) through one or more of the plurality of auxiliary air nozzles, each of the auxiliary air flow sensors (66) operating to obtain a real-time measurement of the flow of the auxiliary air supplied to the burner zone (21) through one or more of the plurality of auxiliary air nozzles; A plurality of flame scanners (46) for obtaining flame scanning data of the flame in the burner zone (21); a plurality of flue gas sensors (42) operative to obtain measurements of a plurality of properties associated with the flue gases, the measurements of the plurality of properties being indicative of combustion occurring in the burner zone (21), each of the flue gas sensors (42) operative to obtain a measurement of at least one of the properties; and a controller (72) operative to optimize the combustion of the fuel and air in the burner zone (21) based on information provided by the plurality of fuel flow sensors (64), the one or more auxiliary air flow sensors (66), the plurality of flame scanners (46), the plurality of smoke sensors (42) and the plurality of air flow control devices (30), wherein the controller (72) includes a guided search optimization algorithm, The guided search optimization algorithm is configured to blend measured and/or calculated chemical measurements of the burners in the boiler (12) with a search algorithm that is customized to find operating biases to apply to one or more of the burners to produce better combustion operating results for the boiler (12) while taking into account measurement inaccuracies and unexpected interactions between burners when determining and evaluating the operating biases. The system (62) of claim 1, wherein the guided search optimization algorithm is configured to perform operations including: determining the amount of air near each of the burners; determining the air-to-fuel ratio near each of the burners; determining an operating bias that redistributes air through or near one or more burners to be more consistent with the air-to-fuel ratio of other burners while maintaining approximately the same amount of air at each elevation of a vertical burner in the T-fired boiler or at each longitudinal distance from the burners in a horizontal burner in a wall-fired boiler; and Applying such operating bias to one or more of such burners or in the vicinity of one or more of such burners. A system (62) as claimed in claim 2, wherein the guided search optimization algorithm is configured to further perform the following operations: After applying the operating biases to one or more of the burners or near one or more of the burners, evaluating the combustion operation of the boiler (12) to determine whether the applied operating biases result in a better combustion operation result than the combustion operation result obtained before the application of the operating biases, the evaluation comprising estimating the combustion operation parameters based on a weighting factor applied to each of the one or more combustion operation parameters, wherein each weighting factor is assigned a lighter or heavier degree of importance with respect to evaluating the combustion operation of the boiler (12); If the operating biases applied to one or more of the burners or near one or more of the burners produce better combustion operation results, then determine additional operating biases and apply them to one or more of the additional burners or near the one or more additional burners; and If the operating biases applied to one or more of the burners or near one or more of the burners do not produce better combustion operation results, then: return the operating biases applied to one of the burners or near one of the burners; from the plurality of fuel flow sensors (64), the one or more auxiliary air flow sensors (66), the plurality of air flow control devices (30), the plurality of smoke sensors (42), and the plurality of flame scanning The device (42) collects more data; and repeatedly determines the air volume near each of the burners, determines the air-fuel ratios near each of the burners, determines another set of operating biases, applies the another set of operating biases to another one or more of the burners or near another one or more of the burners, and evaluates the combustion operation results produced by the another set of operating biases applied to another one or more of the burners or near another one or more of the burners. A system (62) as in claim 2, wherein the determined amount of air near each of the burners includes the air in the flow of the main fuel and air provided to the burner, the auxiliary air provided near the burner or as a part of the burner but separated from the main fuel and air flow, and, if present, compact overfire air introduced into the burner zone (21) above the plurality of burners to contribute to the combustion of the main fuel and air and the auxiliary air. A system (62) as in claim 2, wherein the determined amount of air near each of the burners takes into account the effective free flow area of each of the plurality of auxiliary air nozzles, each of the effective free flow areas being determined based on the nozzle and air flow control device design and geometry. A system (62) as claimed in claim 2, wherein the air-fuel ratios determined near each of the burners are based on the fuel flow measurements of the fuel to the plurality of burners and the determined air quantities near each of the burners. A system (62) as claimed in claim 3, wherein evaluating the combustion operation of the boiler (12) includes estimating one or more combustion operation parameters to determine whether the combustion operation when the operating biases are applied to one or more of the burners is better than the combustion operation results obtained before applying the operating biases. A system (62) as claimed in claim 3, wherein the guided search optimization algorithm is further configured to skip additional optimizations after repeated optimization fails, or to intentionally bias in an error direction to improve combustion in the event of significant measurement errors or unexpected interactions between air and fuel injected near or through different burners. The system (62) of claim 1, wherein the controller (72) is configured to facilitate a change in the amount of air in the burner zone (21), the change comprising one or more of: increasing or decreasing excess air; increasing or decreasing an air percentage in the secondary over-fired air (SOFA) or close-coupled overfire air (CCOFA) in the T-fired boiler; changing the burner tilt angle; and and deflecting air left to right in the furnace, up and down in the furnace (14), or between corners in the furnace (14). A method for optimizing combustion in a boiler (12) having: a furnace (14) including a burner zone (21) for burning fuel and air to produce flue gases therefrom; a plurality of burners, each of which includes a fuel nozzle operative to provide a flow of primary fuel and air into the burner zone (21) to produce a flame therein; a plurality of auxiliary air nozzles positioned about the plurality of burners, the plurality of auxiliary air nozzles operating to supply a flow of auxiliary air into the burner zone (21) for contributing to the combustion of the primary fuel and air; a plurality of air flow control devices (30) for controlling the supply of selected flows of auxiliary air into the burner zone (21) through the plurality of auxiliary air nozzles; a plurality of a fuel flow sensor (64) for obtaining a measurement of the flow of the fuel to the plurality of burners; one or more auxiliary air flow sensors (66) for obtaining a measurement of the flow of the auxiliary air supplied to the burner zone (21) by one or more of the plurality of auxiliary air nozzles; a plurality of flame scanners (46) for obtaining a measurement of the flow of the burner zone (21); flame scan data of the flame in the boiler; a plurality of smoke sensors (42) operating to obtain measurements of a plurality of properties associated with the smoke; and a controller (72) operating to execute a method for optimizing the combustion of the boiler (12) based on fuel flow, air flow, flame data, smoke data and information associated with a plurality of air flow control devices, the method comprising: Determining the amount of air near each of the burners; Determining the air-fuel ratio near each of the burners; Determining operating biases that redistribute air through or near one or more burners to be more consistent with the air-fuel ratio of the other burners while maintaining approximately the same amount of air at each elevation of a vertical burner in the T-fired boiler or at each longitudinal distance of the burners from a horizontal burner in a wall-fired boiler; and Applying the operating biases to or near one or more of the burners. The method of claim 10, further comprising: After applying the operating biases to one or more of the burners or near one or more of the burners, evaluating the combustion operation of the boiler (12) to determine whether the applied operating biases result in a better combustion operation result than the combustion operation result obtained before the application of the operating biases, the evaluation comprising estimating the combustion operation parameters according to a weighting factor applied to each of the one or more combustion operation parameters, wherein each weighting factor is assigned a lighter or heavier degree of importance with respect to evaluating the combustion operation of the boiler (12); If the operating biases applied to one or more of the burners or near one or more of the burners produce better combustion operation results, then determine additional operating biases and apply them to one or more of the additional burners or near the one or more additional burners; and If the operating biases applied to one or more of the burners or near one or more of the burners do not produce better combustion operation results, then: return the operating biases applied to one of the burners or near one of the burners; from the plurality of fuel flow sensors (64), the one or more auxiliary air flow sensors (66), the plurality of air flow control devices (30), the plurality of smoke sensors (42), and the plurality of flame scanning The device (46) collects more data; and repeatedly determines the air volume near each of the burners, determines the air-fuel ratios near each of the burners, determines another set of operating biases, applies the another set of operating biases to another one or more of the burners or near another one or more of the burners, and evaluates the combustion operation results produced by the another set of operating biases applied to another one or more of the burners or near another one or more of the burners. A method as in claim 10, wherein the determined amount of air near each of the burners includes the air in the flow of fuel and air provided to the burner, the auxiliary air provided near the burner or as a part of the burner but separated from the main fuel and air flow, and, if present, compact overfire air introduced into the burner zone above the plurality of burners to contribute to the combustion of the main fuel and air and the auxiliary air. A method as claimed in claim 10, wherein the determined amount of air near each of the burners takes into account the effective free flow area of each of the fuel nozzles and the plurality of auxiliary air nozzles, each of the effective free flow areas being determined based on the nozzle and air flow control device design and geometry. The method of claim 11, further comprising skipping additional optimization after repeated optimization fails, or intentionally biasing in an error direction to improve combustion in the event of significant measurement errors or unexpected interactions between air and fuel injected near or through different burners. The method of claim 11, further comprising promoting a change in the amount of air in the burner zone (21), the change comprising one or more of the following: increasing or decreasing excess air; increasing or decreasing an air percentage in the secondary overfire air (SOFA) or compact overfire air (CCOFA) in the T-fired boiler; changing the burner tilt angle; and deflecting the air left to right in the furnace, up and down in the furnace, or between corners in the furnace.