LOWERING EMISSIONS THAT RESULT FROM FUEL COMBUSTION IN BOILERS

Abstract

A method for lowering emissions that result from fuel combustion in a boiler may include obtaining, from a first sensor device, a plurality of fuel values of fuel parameters associated with a fuel injected into the boiler; obtain, from a second sensor device, a plurality of air values of air parameters associated with air injected into the boiler; identifying a fuel target flow rate and an air target flow rate based on the plurality of fuel values and the plurality of air values, wherein the fuel target flow rate and the air target flow rate result in a lower temperature in the boiler and in lowering the emissions from combustion in the boiler; controlling a fuel injection system to inject the fuel into the boiler at the fuel target flow rate; and controlling an air injection system to inject the air into the boiler at the air target flow rate.

Description

TECHNICAL FIELD

The present application is related to fuel combustion and, more particularly, to lowering emissions that result from fuel combustion in boilers.

BACKGROUND

The combustion of fossil fuels results in emissions that are released into the environment. Nitrogen oxides (NOx) are among these emissions. NOx refers to a binary combination of nitrogen and oxygen, which results in a large number of different compounds (e.g., nitric oxide, nitrogen dioxide, dinitrogen trioxide, nitrate, nitroxylate, nitrosonium). Regulations and incentives currently exist to reduce NOx emissions, particularly nitric oxide and nitrogen dioxide. Some ways that a reduction of NOx emissions from a combustion process can be achieved is through emission control technologies that treat emissions from the combustion process before those emissions are released into the atmosphere. Other methods focus on the combustion process, which can involve inserting and/or adjusting additives and/or other components of the combustion process.

SUMMARY

In general, in one aspect, the disclosure relates to a method for lowering emissions that result from fuel combustion in a boiler. The method can include obtaining a plurality of fuel values of fuel parameters associated with a fuel injected into the boiler. The method can also include obtaining a plurality of air values of air parameters associated with air injected into the boiler. The method can further include identifying a fuel target flow rate and an air target flow rate based on the plurality of fuel values and the plurality of air values, wherein the fuel target flow rate and the air target flow rate result in a lower temperature in the boiler and in lowering the emissions from combustion in the boiler. The method can also include controlling a fuel injection system to inject the fuel into the boiler at the fuel target flow rate. The method can further include controlling an air injection system to inject the air into the boiler at the air target flow rate.

In another aspect, the disclosure relates to a combustion control system for lowering emissions that result from fuel combustion in a boiler, where the system includes a controller that is configured to: obtain, from a first sensor device, a plurality of fuel values of fuel parameters associated with a fuel injected into the boiler; obtain, from a second sensor device, a plurality of air values of air parameters associated with air injected into the boiler; identify a fuel target flow rate and an air target flow rate based on the plurality of fuel values and the plurality of air values, where the fuel target flow rate and the air target flow rate result in a lower temperature in the boiler and in lowering the emissions from combustion in the boiler; control a fuel injection system to inject the fuel into the boiler at the fuel target flow rate; and control an air injection system to inject the air into the boiler at the air target flow rate.

In yet another aspect, the disclosure relates to a non-transitory computer readable medium comprising computer readable program code, which when executed by a computer processor, enables the computer processor to: facilitate obtaining a plurality of fuel values of fuel parameters associated with a fuel injected into a boiler; facilitate obtaining a plurality of air values of air parameters associated with air injected into the boiler; facilitate identifying a fuel target flow rate and an air target flow rate based on the plurality of fuel values and the plurality of air values, wherein the fuel target flow rate and the air target flow rate result in a lower temperature in the boiler and lower emissions from combustion in the boiler; facilitate controlling a fuel injection system to inject the fuel into the boiler at the fuel target flow rate; and facilitate controlling an air injection system to inject the air into the boiler at the air target flow rate.

These and other aspects, objects, features, and embodiments will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings illustrate only example embodiments and are therefore not to be considered limiting in scope, as the example embodiments may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positions may be exaggerated to help visually convey such principles. In the drawings, the same reference numerals used in different figures may designate like or corresponding but not necessarily identical elements.

FIG. 1 shows a diagram of another system that includes a combustion control system according to certain example embodiments.

FIGS. 2A and 2B show a diagram of another system that includes a combustion control system according to certain example embodiments.

FIG. 3 shows a diagram of the combustion control system of the system FIGS. 2A and 2B according to certain example embodiments.

FIG. 4 shows a computing device in accordance with certain example embodiments.

FIG. 5 shows a graph illustrating NOx emissions of a boiler used to create steam according to certain example embodiments.

FIG. 6 shows a graph illustrating NOx emissions of a boiler used to create heated water according to certain example embodiments.

FIG. 7 shows a graph illustrating relationships between adiabatic flame temperature and excess air according to certain example embodiments.

FIG. 8 shows a flowchart of a method for lowering emissions that result from fuel combustion in a boiler according to certain example embodiments.

FIGS. 9A through 9C show images of combustion in a burner of a boiler without the aid of example embodiments.

FIGS. 10A and 10B show images of combustion in a burner of a boiler according to certain example embodiments.

DESCRIPTION OF THE INVENTION

The example embodiments discussed herein are directed to systems, apparatus, methods, and devices for lowering emissions that result from fuel combustion in boilers. The use of the terms “about”, “approximately”, and similar terms applies to all numeric values, whether or not explicitly indicated. These terms generally refer to a range of numbers that one of ordinary skill in the art would consider as a reasonable amount of deviation to the recited numeric values (i.e., having the equivalent function or result). For example, this term may be construed as including a deviation of ±10 percent of the given numeric value provided such a deviation does not alter the end function or result of the value. Therefore, a value of about 1% may be construed to be a range from 0.9% to 1.1%. Furthermore, a range may be construed to include the start and the end of the range. For example, a range of 10% to 20% (i.e., range of 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein. Similarly, a range of between 10% and 20% (i.e., range between 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein.

It is understood that when combinations, subsets, groups, etc. of elements are disclosed (e.g., combinations of components in a composition, or combinations of steps in a method), that while specific reference of each of the various individual and collective combinations and permutations of these elements may not be explicitly disclosed, each is specifically contemplated and described herein. By way of example, if an item is described herein as including a component of type A, a component of type B, a component of type C, or any combination thereof, it is understood that this phrase describes all of the various individual and collective combinations and permutations of these components. For example, in some embodiments, the item described by this phrase could include only a component of type A. In some embodiments, the item described by this phrase could include only a component of type B. In some embodiments, the item described by this phrase could include only a component of type C. In some embodiments, the item described by this phrase could include a component of type A and a component of type B. In some embodiments, the item described by this phrase could include a component of type A and a component of type C. In some embodiments, the item described by this phrase could include a component of type B and a component of type C. In some embodiments, the item described by this phrase could include a component of type A, a component of type B, and a component of type C. In some embodiments, the item described by this phrase could include two or more components of type A (e.g., A1 and A2). In some embodiments, the item described by this phrase could include two or more components of type B (e.g., B1 and B2). In some embodiments, the item described by this phrase could include two or more components of type C (e.g., C1 and C2). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type A (A1 and A2)), optionally one or more of a second component (e.g., optionally one or more components of type B), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type B (B1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type C (C1 and C2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type B).

If a component of a figure is described but not expressly shown or labeled in that figure, the label used for a corresponding component in another figure may be inferred to that component. Conversely, if a component in a figure is labeled but not described, the description for such component may be substantially the same as the description for the corresponding component in another figure. The numbering scheme for the various components in the figures herein is such that each component is a three-digit number or a four-digit number, and corresponding components in other figures have the identical last two digits. For any figure shown and described herein, one or more of the components may be omitted, added, repeated, and/or substituted. Accordingly, embodiments shown in a particular figure should not be considered limited to the specific arrangements of components shown in such figure.

Further, a statement that a particular embodiment (e.g., as shown in a figure herein) does not have a particular feature or component does not mean, unless expressly stated, that such embodiment is not capable of having such feature or component. For example, for purposes of present or future claims herein, a feature or component that is described as not being included in an example embodiment shown in one or more particular drawings is capable of being included in one or more claims that correspond to such one or more particular drawings herein.

Example embodiments of lowering emissions that result from fuel combustion in boilers will be described more fully hereinafter with reference to the accompanying drawings, in which example embodiments of lowering emissions that result from fuel combustion in boilers are shown. Lowering emissions that result from fuel combustion in boilers may, however, be embodied in many different forms and should not be construed as limited to the example embodiments set forth herein. Rather, these example embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of lowering emissions that result from fuel combustion in boilers to those of ordinary skill in the art. Like, but not necessarily the same, elements (also sometimes called components) in the various figures are denoted by like reference numerals for consistency.

Terms such as “first”, “second”, “primary,” “secondary,” “above”, “below”, “inner”, “outer”, “distal”, “proximal”, “end”, “top”, “bottom”, “upper”, “lower”, “side”, “left”, “right”, “front”, “rear”, and “within”, when present, are used merely to distinguish one component (or part of a component or state of a component) from another. This list of terms is not exclusive. Such terms are not meant to denote a preference or a particular orientation, and they are not meant to limit embodiments of lowering emissions that result from fuel combustion in boilers. In the following detailed description of the example embodiments, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

FIG. 1 shows a diagram of a system 100 that includes a combustion control system 125 according to certain example embodiments. The system 100 of FIG. 1 includes an example combustion control system 125, a boiler 170, one or more water sources 166, one or more water injection systems 164, an optional preheater 119, one or more steam consumer 169, and one or more optional hot water consumer. The boiler 170 in this case includes one or more economizers 120, a furnace 179, and one or more burners 175.

The boiler 170 has two different flow paths for fluids in this example. In alternative embodiments, the boiler 170 can have a single flow path for fluids or more than two (e.g., 4, 8) flow paths for fluids. One flow path in this case starts with water 167 (also sometimes called feed water), propelled by the one or more water injection systems 164, flowing from the water sources 166 through piping to the optional preheater 119, which can raise the temperature of the water 167 by some amount (e.g., 10°, 20°). The water 167 then enters the economizer 120-1 of the boiler 170, where the economizer 120-1 further raises the temperature of the water 167. The water 167 then enters boiler tubes (e.g., embedded in the walls of the furnace 179, disposed on tube hangers in close proximity to the furnace refractory within the furnace 179). The heat generated within the furnace 179 is transferred to the water 167 in the boiler tubes of the furnace 179. If the furnace 179 is configured to generate steam 168, the steam 168 exits the boiler and is delivered to one or more of the steam consumer 169. Alternatively, if the furnace 179 is configured to generate hot water, the hot water exits the boiler and is delivered to one or more of the hot water consumer. As defined herein, steam 168 can be different types of steam. For example, steam 168 can be “wet steam”, which has both liquid water and steam vapor components. In some cases, the steam 168 can have a “steam quality” of 80% or less, where the “steam quality” defines the ratio of steam vapor mass to the combined vapor/liquid mass. In some cases, the boiler 170 of the example system 100 can include a steam drum that is capable of providing steam 168 in the form of saturated dry steam vapor and/or superheated steam.

The other fluid path to the boiler 170 is a mixture of fuel and air that is delivered to one or more of the burners 175 of the boiler 170. The mixture of fuel and air can be arranged such that the proportions of fuel and air are super-stoichiometric, having an excess of air relative to fuel (i.e., fuel lean). In certain example embodiments, there is no sub-stoichiometric mixture of fuel and air (i.e., fuel-rich). In some cases, the mixture of fuel and air is pre-mixed in a burner 175 prior to combustion, which is commonly referred to as a lean premix. The combined mixture of fuel and air is also commonly referred to as the reactants. This mixture is combusted in the burners 175, and the combustion is directed into the furnace 179. The resulting flue gas 137 exits the furnace 179 and is sent through the economizer 120-2, where some of the heat of the flue gas 137 is captured and sent to the economizer 120-1 to pre-heat the water 167.

The flue gas 137 than exits the boiler 170 and is vented to atmosphere. In some cases, some of the flue gas 137 is recirculated to enter the burners 175 as part of the air and fuel mixture. For example, the flue gas 137 may be recirculated and mixed with inlet air to result in vitiated air. The vitiated air can then be delivered to the windbox of the burner 175, where the fuel is added. The inlet air may be subject to changing local process conditions (e.g., barometric pressure, temperature, relative humidity) that effectively alter the composition of the inlet air and its corresponding property values. The vitiated air mixture represents products of combustion (e.g., fuel) mixed with the inlet air in a desired proportion and results in a modified composition and corresponding property values for the vitiated mixture.

The excess air in the reactant mixture will result in the flue gas 137 having oxygen (O₂) in it, and so the air (e.g., inlet air supplied from the ambient environment) that mixes with the recirculated flue gas 137 is scaled back (reduced) to maintain the desired concentration of oxygen (O₂) in the vitiated air. (The term oxygen as used herein refers to the oxygen molecule, O₂, unless specifically designated as elemental oxygen (O).) Recirculating flue gas 137 cools the combustion process in the boiler 170. Specifically, recirculating flue gas 137 reduces the peak magnitudes of the local combustion temperatures so that the net effect is a reduction in the overall NOx emissions formation rate, which also reduces the concentration of NOx emissions in the flue gas 137 (also sometimes called stack gases or the final products of combustion). This cooling action is attributable to the thermal ballast effects of the additional flue gas 137 in addition to the reduced reaction rate resulting from the fuel and vitiated air mixture relative to a mixture of fuel and air only (without recirculated flue gas 137).

In some cases, the flue gas 137 that is vented can be treated (e.g., flows through an electrostatic precipitator, selective catalytic reduction, selective non-catalytic reduction, scrubbing, sequestration) to remove or reduce one or more chemical compounds and/or elements from the flue gas 137 before the flue gas 137 is released into the ambient environment. Many of the components of the system 100 of FIG. 1 are discussed in more detail below with respect to FIGS. 2A and 2B.

FIGS. 2A and 2B show a diagram of another system 200 that includes a combustion control system 225 according to certain example embodiments. Specifically, FIG. 2A shows the system 200, and FIG. 2B shows a detailed view of the boiler 270 of the system 200 and inputs to the boiler 270. Referring to FIGS. 1 through 2B, the system 200 of FIGS. 2A and 2B includes an example combustion control system 225, a boiler 270, one or more water sources 266, one or more water injection systems 264, one or more ignition fuel sources 241, one or more ignition fuel injection systems 243, one or more pilot maintenance fuel sources 244, one or more pilot maintenance fuel injection systems 246, one or more primary fuel sources 247, one or more primary fuel injection systems 249, one or more secondary fuel sources 251, one or more secondary fuel injection systems 253, one or more tertiary fuel sources 254, one or more tertiary fuel injection systems 257, one or more air sources 263, one or more air injection systems 261, one or more steam consumer 269, one or more controllers 204, one or more sensor devices 260, one or more users 250 (including one or more optional user systems 255), a network manager 280, piping 288, and one or more valves 285. The boiler 270 includes one or more burners 275, a furnace 279, and multiple boiler tubes 295.

The components shown in FIGS. 2A and 2B are not exhaustive, and in some embodiments, one or more of the components shown in FIGS. 2A and 2B may not be included in the example system 200. Any component of the system 200 may be discrete or combined with one or more other components of the system 200. Also, one or more components of the system 200 may have different configurations. For example, one or more sensor devices 260 may be disposed within or disposed on other components (e.g., the piping 288, a valve 285, the primary fuel injection system 249, the water injection system 264, the furnace 279 of the boiler 270). As another example, a controller 204, rather than being a stand-alone device, may be part of one or more other components (e.g., the combustion control system 225, the secondary fuel injection system 253, the air injection system 261, the pilot maintenance fuel injection system 246) of the system 200. As yet another example, one or more valves 285 can be located at one or more different and/or additional locations among the piping 288 throughout the system 200.

Referring to FIGS. 1 through 2B, there is piping 288 throughout the system 200. The piping 288 may include multiple pipes, ducts, headers, elbows, joints, sleeves, collars, and similar components that are coupled to each other (e.g., using coupling features such as mating threads or flanged connections) to establish a network for transporting the one or more fluids (e.g., air 262, primary fuel 248, secondary fuel 252, water 267, flue gas 237) within the system 200. Each component of the piping 288 may have an appropriate size (e.g., inner diameter, outer diameter) and be made of an appropriate material (e.g., steel, PVC) to safely and efficiently handle the pressure, temperature, flow rate, and other characteristics of the particular fluid that passes therethrough.

There may be a number of valves 285 placed in-line with the piping 288 at various locations in the system 200 to control the flow of any of the various fluids (in this case, the fluids in the system 200 include air 262, primary fuel 248, ignition fuel 242, pilot maintenance fuel 245, secondary fuel 252, tertiary fuel 256, water 267, steam and flue gas 237) that flow through the piping 288. A valve 285 may have one or more of any of a number of configurations, including but not limited to a guillotine valve, a ball valve, a gate valve, a butterfly valve, a pinch valve, a needle valve, a plug valve, a diaphragm valve, and a globe valve. A valve 285 can be used for control action and have a trim characteristic that describes the nature of the control action in the overall process. Typical examples can include, but are not limited to, equal-percentage, linear, and quick-opening. Each of control action valves 285 can determine the nature of the flow response relative to the %-open position of the valve and is intended to achieve desired control system response characteristics. One valve 285 may be configured the same as or differently compared to another valve 285 in the system 200. Also, one valve 285 may be controlled (e.g., manually, automatically by the controller 204) the same as or differently compared to another valve 285 in the system 200. In some cases, a valve 285 can be a general term for one or more other forms of control elements, including but not limited to adjustable speed drive motor controllers, blowers, fans, and pumps.

Generally speaking, the process to generate steam 268 using a boiler 270 involves pumping or otherwise causing water 267 to flow into boiler tubes 295 of the boiler 270. The boiler tubes 295 are located within the furnace 279 of the boiler 270, and heat within the furnace 279 is transferred to the water 267 flowing through the boiler tubes 295, converting the water 267 to steam 268. For example, the boiler tubes 295 can be contained within the furnace 279 adjacent to refractory lined walls within the furnace 279, which basically has the shape of a cylindrical shell. In certain example embodiments, the boiler 270 is defined as a forced-flow once through boiler. In other cases, the boiler 270 can be defined as a drum-style power boiler.

The furnace 279 is able to reach the elevated temperatures required to convert the water 267 to steam 268 by initiating an ignition process within the one or more burners 275 of the boiler 270 and directing the ignition out of the burners 275 and into the furnace 279, where some secondary ignitions can also take place.

The boiler 270 can be any type (e.g., a once-through forced-flow boiler, a fired heater) of boiler. The boiler 270 can be used to produce heated water (e.g., have only a single combustion stage) or to produce steam (e.g., have multiple combustion stages). The boiler 270 can include one or more burners 275 and a furnace 279. When the boiler 270 has multiple burners 275, one burner can be configured the same as, or differently than, one or more of the other burners 275. The distribution of multiple burners 275 of a boiler 270 can be equal, symmetrical, random, and/or fall into some other pattern. Each burner 275 generally has a cylindrical shape with a an orientation (e.g., horizontal, vertical, diagonal, linear, curved) and an open distal end that leads into the furnace 279. In this way, the combustion that occurs in a burner 275 is directed through the open distal end of the burner 275 into the furnace 279.

Each burner 275 can have ports that allow for the injection of air 262 (including flue gas 237 that is recirculated) and one or more fuels at some point along the length of the burner 275. Different ports can be grouped or categorized as belonging to certain stages (discussed below) in the combustion process. The shape of the burner 275, the location of the various ports, and other elements of the configuration of the burner 275 facilitate the combustion of the fuel in the burner 275 and delivering the combustion into the furnace 279. The boiler tubes 295 of the boiler 270 can be embedded in at least some of the walls of the part of the boiler 270 that define the furnace 279. The boiler tubes 295 can be made of a thermally conductive material that absorbs the heat generated in and delivered to the furnace 279. The heat is then transferred to the water 267 that flows through (e.g., is pumped) the boiler tubes 295 to generate steam 268 or heated water.

The water 267 is directed into the boiler tubes 295 of the boiler 270 through piping 288 using the one or more water injection systems 264. The water 267 comes from one or more of a number of water sources 266. The water 267 can be naturally-occurring fresh water, oilfield produced water, treated water (e.g., distilled water, purified water, softened water, otherwise chemically treated water), or any other type of water. The water 267 in this process originates from a water source 266, which can be naturally-occurring or manmade. Examples of a water source 266 can include, but are not limited to, a lake, a river, a tank, a pond, a subterranean reservoir or aquifer, and a collection vessel. In some cases, as when a water source 266 derives from oilfield operations, the water 267 may be treated (e.g., de-oiled, remove suspended solids, softened) prior to being delivered by a water injection system 264 to the boiler 270 as feed water.

Each water injection system 264 is configured to deliver water 267 from one or more of the water sources 266 through some of the piping 288 to one or more of the burners 275 of the boiler 270. An ignition fuel injection system 243 can include one or more of a number of components, including but not limited to a motor, a pump, a compressor, a fan, a blower, piping 288, a valve 285, a controller (e.g., one of the controllers 204), a sensor device 260, a protective relay, and an electrical cable.

The steam 268 that exits the boiler tubes 295 of the boiler 270 can flow through piping 288 to one or more steam consumer 269. Examples of a steam consumer 269 can include, but are not limited to, a turbine (e.g., as from a turbine/generator set), a manufacturing process, a heating system, and a geothermal process. In some cases, there can be an optional steam conveyance system (not shown in FIG. 2A) that can be used to convey the steam 268 through the piping 288 to a steam consumer 269. A steam conveyance system can include equipment that includes, but is not limited to, a motor, a pump, a compressor, additional piping 288, a valve 285, a fan, a controller (e.g., one of the controllers 204), a sensor device 260, a protective relay, and an electrical cable. In some cases, as when the boiler has only one stage of combustion, heated water rather than steam 268 exits the boiler tubes 295 of the boiler 270. In such cases, the steam consumer 269 is a heated water source.

Each burner 275 of the boiler 270 can have multiple stages for combustion before the combustion reaches the furnace 279. For example, as shown in FIG. 2B, each burner 275 can include a stage 1A portion 276 and a stage 1B portion 277. Each stage portion within a burner 275 can include one or more ports (e.g., 8 ports for stage 1A portion 276, 7 ports for stage 1B portion 277) that are used to deliver one or more fuels and/or air 262 to the burner 275. The number of ports for stage 1A portion 276 can be the same as, or different than, the number of ports for stage 1B portion 277. The ports for stage 1A portion 276 and stage 1B portion 277 can have any of a number of distribution patterns, including but not limited to even, biased, staggered, and random. Examples of ports in a burner 275 are shown below in FIGS. 9A through 10B.

The stage 1A portion 276 in this case can include pre-heated products of combustion plus a fuel (e.g., an ignition fuel 242, a pilot maintenance fuel 245). In some cases, the ports used for stage 1A portion 276 may be located at a different location (e.g., further away from the furnace 279 within a burner 275) relative to the location of the ports used for stage 1B portion 277 within the burner 275. The stage 1B portion 277 of a burner 275 may include an air-to-fuel (A/F) ratio (e.g., a lean A/F ratio (fuel lean, with excess air), a rich A/F ratio (fuel rich, with no excess air)). Each of these stages within a burner 275 can be configured to strike a balance between the amount of heat that is delivered into the furnace 279 and the amount of NOx and other emissions that are generated by combusting the various fuels in the boiler 270.

Similarly, the furnace 279 of the boiler 270 can have multiple stages for further combustion to increase the total amount of heat release within the furnace 279. For example, as shown in FIG. 2B, the furnace 279 can include a stage 2 portion 286 and a stage 3 portion 289. Similar to stage 1A portion 276 and stage 1B portion 277, each of these stage portions within a burner 275 and/or the furnace 279 can include one or more ports (e.g., 4 ports for stage 2 portion 286, 3 ports for stage 3 portion 289) that are used to deliver one or more fuels and/or air 262 to the burner 275. The number of ports for stage 2 portion 286 can be the same as, or different than, the number of ports for stage 3 portion 289. The ports for stage 2 portion 286 and stage 3 portion 289 can have any of a number of distribution patterns, including but not limited to even, biased, staggered, and random.

The stage 2 portion 286 in this case can include pre-heated products of combustion plus a fuel (e.g., a secondary fuel 252). In some cases, the ports used for stage 2 portion 286 may be located closer to the distal end of the burners 275 within the furnace 279 relative to the location of the ports used for stage 3 portion 289 within the furnace 279. The stage 3 portion 289 of the furnace 279 may include pre-heated products of combustion plus a fuel (e.g., a tertiary fuel 256) that can be the same as, or different than, the fuel used in the stage 2 portion 286. Each of these stage portions within the furnace 279 can be configured to strike a balance between the amount of heat that is generated in the furnace 279 and the amount of NOx and other emissions that are generated by combusting the various fuels in the boiler 270.

When an operation of the boiler 270 begins, one or more ignition fuels 242 is used to initiate a combustion reaction within one or more burners 275 (e.g., at the stage 1A portion 276) of the boiler 270. Specifically, the one or more ignition fuels 242 is ignited in a burner 275, and this ignition is maintained when one or more other fuels (e.g., pilot maintenance fuels 245, primary fuels 248) are injected into the burner 275. During the initial ignition of a burner 275, an ignition fuel 242 can be mixed with air 262 before (e.g., at a header in the piping 288) and/or within the burner 275. Each ignition fuel 242 is transported from one or more ignition fuel sources 241 through piping 288 using one or more of the ignition fuel injection systems 243. Examples of an injection fuel 242 can include, but are not limited to, natural gas, hydrogen, ammonia, and propane.

An injection fuel 242 may be in a gaseous state. In alternative embodiments, an ignition fuel 242 may be in a liquid state or a solid state. In some cases, an ignition fuel 242 can be a composition of multiple fuels (e.g., natural gas, hydrogen, and ammonia) from multiple injection fuel sources 241. These ignition fuels 242 and/or ignition fuel sources 241 can vary and/or originate from different fuel supply systems, and/or have different process properties, conditions, and/or compositions. In some cases, the composition and/or properties of an injection fuel 242 can be subject to time-varying changes.

Each ignition fuel source 241 may hold one or more injection fuels 242. Examples of an ignition fuel source 241 may include, but are not limited to, a tank, a pipeline, and a processing plant. Each ignition fuel injection system 243 is configured to deliver one or more of the ignition fuels 242 from one or more injection fuel sources 241 through some of the piping 288 to one or more of the burners 275 of the boiler 270. An ignition fuel injection system 243 can include one or more of a number of components, including but not limited to a motor, a pump, a compressor, piping 288, a valve 285, a controller (e.g., one of the controllers 204), a sensor device 260, an ignitor (e.g., a sparkplug), an ignition transformer, a protective relay, and an electrical cable.

Once an operation of the boiler 270 has started, one or more pilot maintenance fuels 245 are used to maintain a combustion reaction within one or more burners 275 (e.g., at the stage 1A portion 276) of the boiler 270. Specifically, the one or more pilot maintenance fuels 245 (also sometimes called a center fuel or a startup stabilization fuel) is delivered to and ignited in a burner 275 after initial ignition has occurred in the burner 275. The pilot maintenance fuels 245 serve as a supplement to one or more of the other fuels (e.g., the primary fuels 248) in the system 200. A pilot maintenance fuel 245 may be combined with one or more other fuels (e.g., secondary fuels 252, primary fuels 248) just upstream of (e.g., at a header in the piping 288) and/or within a burner 275. Each pilot maintenance fuel 245 is transported from one or more pilot maintenance fuel sources 244 through piping 288 using one or more of the pilot maintenance fuel injection systems 246. Examples of a pilot maintenance fuel 245 can include, but are not limited to, natural gas and propane. A pilot maintenance fuel 245 may be in a gaseous state. In alternative embodiments, a pilot maintenance fuel 245 may be in a liquid state or a solid state.

Each pilot maintenance fuel source 244 may hold one or more pilot maintenance fuels 245. Examples of a pilot maintenance fuel source 244 may include, but are not limited to, a tank, a pipeline, and a processing plant. Each pilot maintenance fuel injection system 246 is configured to deliver one or more of the pilot maintenance fuels 245 from one or more pilot maintenance fuel sources 244 through some of the piping 288 to one or more of the burners 275 of the boiler 270. In some cases, a pilot maintenance fuel 245 can be a composition of multiple fuels (e.g., natural gas, hydrogen) from multiple pilot maintenance fuel sources 244. These pilot maintenance fuels 245 and/or pilot maintenance fuel sources 244 can vary and/or originate from different fuel supply systems, and/or have different process properties, conditions, and/or compositions. In some cases, the composition and/or properties of a pilot maintenance fuel 245 can be subject to time-varying changes. A pilot maintenance fuel injection system 246 can include one or more of a number of components, including but not limited to a motor, a pump, a compressor, piping 288, a controller (e.g., one of the controllers 204), a sensor device 260, a protective relay, and an electrical cable.

In the current art, one or more pilot maintenance fuels 245 are used during most if not all of the operations of a boiler 270. In certain example embodiments, such valves 285 and/or other equipment can be installed in the piping 288 from the pilot maintenance fuel sources 244 to the burners 275. Such valves 285 and/or other equipment can be controlled by the controller 204 of the system 200 to reduce the amount of pilot maintenance fuel 245 that is combusted in the burners 275 in an effort to reduce the amount of NOx and other emissions in the flue gas 237 while at least maintaining the function of the boiler 270 in converting the water 267 to steam 268.

During operation of the boiler 270, one or more primary fuels 248 are used to sustain a combustion reaction within one or more burners 275 of the boiler 270. Specifically, the one or more primary fuels 248 is delivered to and ignited in a burner 275 (e.g., at the stage 1B portion 277) after initial ignition has occurred in the burner 275. A primary fuel 248 may be combined with air 262 and/or one or more other fuels (e.g., secondary fuels 252, pilot maintenance fuels 245) just upstream of (e.g., at a header in the piping 288) and/or within a burner 275. Each primary fuel 248 is transported from one or more primary fuel sources 247 through piping 288 using one or more of the primary fuel injection systems 249. Examples of a primary fuel 248 can include, but are not limited to gaseous fuels such as, natural gas, sour gas, field-produced gas, and propane. A primary fuel 248 may be in a gaseous state. In alternative embodiments, a primary fuel 248 may be in a liquid state or a solid state.

Each primary fuel source 247 may hold one or more primary fuels 248. Examples of a primary fuel source 247 may include, but are not limited to, a tank, a pipeline, and a processing plant. Each primary fuel injection system 249 is configured to deliver one or more of the primary fuels 248 from one or more of the primary fuel sources 247 through some of the piping 288 to one or more of the burners 275 of the boiler 270. In some cases, a primary fuel 248 can be a composition of multiple fuels (e.g., natural gas, hydrogen) from multiple primary fuel sources 247. These primary fuels 248 and/or primary fuel sources 247 can vary and/or originate from different fuel supply systems, and/or have different process properties, conditions, and/or compositions. In some cases, the composition and/or properties of a primary fuel 248 can be subject to time-varying changes. A primary fuel injection system 249 can include one or more of a number of components, including but not limited to a motor, a pump, a compressor, piping 288, a valve 285, a controller (e.g., one of the controllers 204), a sensor device 260, a protective relay, and an electrical cable.

At the start of and during operation of the boiler 270, air 262 may be used to start and sustain a combustion reaction within one or more burners 275 (e.g., at the stage 1A portion 276, at the stage 1B portion 277) of the boiler 270. Specifically, the air 262 is delivered to and ignited in a burner 275 during and after initial ignition has occurred in the burner 275. Air 262 may be combined with one or more other fuels (e.g., primary fuels 248, pilot maintenance fuels 245) just upstream of (e.g., at a header in the piping 288) and/or within a burner 275. The air 262 is transported from one or more air sources 263 through piping 288 using one or more of the air injection systems 261. Examples of air 262 can include, but are not limited to, ambient air, oxygenated air, vitiated air (a mixture of flue gas 237 and ambient air), and flue gas 237 that is recirculated rather than released for emission. In some cases, the air 262 delivered to the burners 275 is a combination of different types of air.

Air 262 may be in a gaseous state. The air 262 can include one or more of a number of chemical components, including but not limited to oxygen (O₂), hydrogen (H₂), nitrogen (N₂), helium (He), argon (Ar), carbon dioxide (CO₂), and water vapor (H₂O). Some or all of these chemical components of the air 262 may not contribute to combustion within the burners 275 and/or the furnace 279, but such chemical components can take away heat from the combustion process within the burners 275 and/or the furnace 279, resulting in the heat loss in thermal ballast 759 in the graph 799 of FIG. 7, discussed below.

In some cases, if there is too much excess air 262 in the boiler during combustion, the heat losses become so great that a flame (combustion) cannot be sustained, resulting in a flameout in the burners 275. As a result, reducing the amount of excess air 262 in the boiler 270 during combustion is a desired result. However, this must be balanced against the undesired and unsafe result of not having enough air 262 in the combustion process within the boiler 270, which results in the production of excess carbon monoxide (CO).

Each air source 263 may hold some amount of air 262. Examples of an air source 263 may include, but are not limited to, a tank, a pipeline, a container, a vessel, an ambient environment, some of the piping 288, and a processing plant. Each air injection system 261 is configured to deliver air 262 from one or more of the air sources 263 through some of the piping 288 to one or more of the burners 275 (e.g., at the stage 1A portion 276, at the stage 1B portion 277) of the boiler 270. An air injection system 261 can include one or more of a number of components, including but not limited to a motor, a pump, a compressor, a fan, a dehumidifier, a preheater, an evaporative cooler, piping 288, a valve 285, a controller (e.g., one of the controllers 204), a sensor device 260, a protective relay, and an electrical cable.

During operation of the boiler 270, one or more secondary fuels 252 are used to sustain a combustion reaction within the furnace 279 of the boiler 270 and/or to deliver a greater quantity of heat into the process to satisfy the total thermal demand of the overall process. Delivering this heat via a “staged fuel” process allows for a lowering of the peak/local flame temperatures, and thus the reduction in NOx emissions. In some cases, the one or more secondary fuels 252 is delivered to and ignited in the furnace 279 (e.g., at the stage 2 portion 286) using the ignition generated within the burners 275 and delivered to the furnace 279. A secondary fuel 252 may be combined with air 262 and/or one or more other fuels (e.g., tertiary fuels 256) just upstream of (e.g., at a header in the piping 288) and/or within the furnace 279. Each secondary fuel 252 is transported from one or more secondary fuel sources 251 through piping 288 using one or more of the secondary fuel injection systems 253. Examples of a secondary fuel 252 can include, but are not limited to, natural gas, sour gas, field-produced gas, and propane. A secondary fuel 252 may be in a gaseous state. In alternative embodiments, a secondary fuel 252 may be in a liquid state or a solid state.

Each secondary fuel source 251 may hold one or more secondary fuels 252. Examples of a secondary fuel source 251 may include, but are not limited to, a tank, a pipeline, and a processing plant. Each secondary fuel injection system 253 is configured to deliver one or more of the secondary fuels 252 from one or more of the secondary fuel sources 251 through some of the piping 288 to the furnace 279 of the boiler 270. In some cases, a secondary fuel 252 can be a composition of multiple fuels (e.g., natural gas, hydrogen) from multiple secondary fuel sources 251. These secondary fuels 252 and/or secondary fuel sources 251 can vary and/or originate from different fuel supply systems, and/or have different process properties, conditions, and/or compositions. In some cases, the composition and/or properties of a secondary fuel 252 can be subject to time-varying changes. A secondary fuel injection system 253 can include one or more of a number of components, including but not limited to a motor, a pump, a compressor, piping 288, a valve 285, a controller (e.g., one of the controllers 204), a sensor device 260, a protective relay, and an electrical cable.

During operation of the boiler 270, one or more tertiary fuels 256 are used to sustain a combustion reaction within the furnace 279 of the boiler 270. Specifically, the one or more tertiary fuels 256 is delivered to and ignited in the furnace 279 (e.g., at the stage 3 portion 289) using the ignition generated within the burners 275 and delivered to the furnace 279. A tertiary fuel 256 may be combined with air 262 and/or one or more other fuels (e.g., secondary fuels 252) just upstream of (e.g., at a header in the piping 288) and/or within the furnace 279. Each tertiary fuel 256 is transported from one or more tertiary fuel sources 254 through piping 288 using one or more of the tertiary fuel injection systems 257. Examples of a tertiary fuel 256 can include, but are not limited to, natural gas, sour gas, field-produced gas, and propane. A tertiary fuel 256 may be in a gaseous state. In alternative embodiments, a tertiary fuel 256 may be in a liquid state or a solid state.

Each tertiary fuel source 254 may hold one or more tertiary fuels 256. Examples of a tertiary fuel source 254 may include, but are not limited to, a tank, a pipeline, and a processing plant. Each tertiary fuel injection system 257 is configured to deliver one or more of the tertiary fuels 256 from one or more of the tertiary fuel sources 254 through some of the piping 288 to the furnace 279 of the boiler 270. In some cases, a tertiary fuel 256 can be a composition of multiple fuels (e.g., natural gas, hydrogen, and ammonia) from multiple tertiary fuel sources 254. These tertiary fuels 256 and/or tertiary fuel sources 254 can vary and/or originate from different fuel supply systems, and/or have different process properties, conditions, and/or compositions. In some cases, the composition and/or properties of a tertiary fuel 256 can be subject to time-varying changes. A tertiary fuel injection system 257 can include one or more of a number of components, including but not limited to a motor, a pump, a compressor, piping 288, a valve 285, a controller (e.g., one of the controllers 204), a sensor device 260, a protective relay, and an electrical cable.

The combustion control system 225 of the system 200 may be configured to control one or more of the injection systems (e.g., a water injection system 264, an air injection system 261, a primary fuel injection system 249), including components (e.g., valves 285) thereof, to control one or more emission characteristics (e.g., NOx, opacity, SOx, CO, CO₂) of the flue gas 237 that is released from the boiler 270. In some cases, the combustion control system 225 monitors one or more emission characteristics of the flue gas 237. When this occurs, and when the actual values differ from the forecast or expected values, the information from monitoring the emission characteristics of the flue gas 237 can be used to update one or more components (e.g., protocols 332, algorithms 333) of the combustion control system 225 that are used to control one or more of the various injection systems.

The example combustion control system 225 can be designed to manage air 262-fuel (e.g., primary fuel 248) combustion control in addition to normal process control functions for boiler 270/fired heater operations. The example combustion control system 225 can also be designed to manage the overall combustion reaction, as well as for each individual stage of combustion, such that the air-fuel and the fuel-staging relationships are maintained in a fashion where combustion occurs such that temperatures are maintained below the adiabatic flame temperature (AFT) and that they are a suitably small margin above the temperature stability limit for sustainable combustion. The intent of this temperature control action is to address the “extent of reaction” in which each combustion stage requires time for all the combustion to take place. This occurs while the air-fuel mixture is moving with some velocity from the burner 275 into the furnace 279. As a result, the combustion between sequential stages may overlap in “space-time”, serving to blur the boundary between the stages.

The AFT is the theoretical maximum possible temperature and is never actually achieved in practice due to the combination of radiant and convective heating actions within the combustion process and to/from the surroundings. The example combustion control system 225 accounts for this and manages the combination of excess air 262 and fuel staging to achieve the desired combustion “temperature control” action at a defined point for which stable and reliable combustion can be sustained. This temperature control accounts for the effect of heat losses from the combustion products to both the thermal ballast products as well as surrounding surfaces within the furnace 279.

These combustion heat losses serve to elevate the temperature of the thermal ballast and internal surfaces of the furnace 279. The example combustion control system 225 balances the heat losses against the need to maintain sufficient heat such that the combination of the extent of reaction and heat losses do not result in gas temperatures below that at which sustainable combustion is maintained (i.e., the auto-ignition temperature). In some cases, since the autoignition temperature (AIT) of a fuel mixture is composition dependent, the example combustion control system 225 introduces an additional feature that establishes the AIT control reference as that of methane, which is the predominant species in many applicable fuel mixtures, and also happens to have the highest AIT requirement of a number of applicable fuel mixtures. Some of these features are shown graphically below in FIG. 7.

The combustion control system 225 can also model a combustion reaction, which represents the overall combined combustion of total fuel and total air, from which the control action for total heat demand and stack O₂ control are performed. This combustion reaction is not an actual physical combustion process, but is applied to achieve some overall control objectives (e.g., total heat demand, flue gas O2 concentration control, etc.). The example combustion control system 225 can be designed to control existing ultra-low NOx burner (ULNB) and/or flue gas 237 recirculation (FGR) equipped boilers 270 with a focus on, for example, further reducing NOx emissions and improving reliability.

Example combustion control systems 225 can be used with any of a number of types (e.g., heavy oil boiler units, once-through forced-flow boilers/heaters, oilfield upstream or downstream fired equipment) of boilers 270. Example combustion control systems 225 can achieve a number of benefits, including but not limited to achieving regulatory compliance with a step-change reduction (e.g., 40%) in allowable NOx emission permit limits, achieving regulatory compliance without major capital investment, improving combustion reliability, and reducing/eliminating the need for technicians to tune parts of the boiler control system. Example combustion control systems 225 can be used with new boilers 270 or retrofit with existing boilers 270 and their related equipment.

Example combustion control systems 225 can be, at least in part, a software program applied in controller hardware that interfaces with control equipment (e.g., injection systems, one or more controllers 204, the network manager 280, a user system 255) used to manage combustion within the boiler 270. Example combustion control systems 225 can be used to significantly reduce emissions rates (e.g., in CO, in NOx) in the flue gas 237 by controlling the temperatures at which combustion occurs within parts (e.g., in a burner 275, in the furnace 279) of the boiler 270. For example, the formation rate of NOx has a residence time component, and by using the example combustion control system 225 to reduce peak temperatures in the furnace 279, disassociation of the nitrogen modules is prevented, which reduces the formation of NOx.

In other words, the combustion control system 255 can achieve a stable, reliable, and distributed flameless combustion reaction having temperatures for which the NOx formation rate is very low. The resulting NOx emissions are single-digit (in ppm) and may be further reduced to well below 5 ppm vd at 3% O₂ with the additional application of flue gas recirculation. (The values of NOx are reported on a volumetric dry (vd) gas basis and corrected to 3% oxygen (O₂) concentration.) The example combustion control system 225 does not change the efficiency of the boiler 270. Rather, the temperature distribution within the boiler 270 implemented by the combustion control system 225 is changed to control where combustion occurs in the boiler 270. The process of mixing the air 262 and the various fuels, as well as the relationship between the air 262 and the fuels, effectively reduces the temperature of the materials in localized regions within the furnace 279, which reduces NOx while continuing to deliver the total heat demand by the boiler 270.

The combustion stability that results from employing example combustion control systems 225 enables sustainable combustion to proceed without the need for maintaining the pilot maintenance fuel 245 (sometimes called a “flame anchor”) or any fuel rich flame core that is commonly applied with industrial low-NOx burner systems. The pilot maintenance fuel 245 associated with the flame anchor/fuel rich core is generally less than 2% of the total fuel consumption, but disproportionately accounts for a significant proportion of the NOx emissions in the flue gas 237. The ability to eliminate the fuel rich combustion reaction brought on by the pilot maintenance fuel 245 while maintaining stable and sustainable combustion at a specific combustion temperature during operations using the example combustion control system 225 enables the step-change in NOx emissions reduction. It should be noted that the use of the pilot maintenance fuel 245 as a flame anchor is still employed during the start-up operations to ensure flame stability until the burner 275 and/or the furnace 279 heats up to normal operating conditions, at which time the pilot maintenance fuel 245 is removed from the fuel mix used for combustion.

The example combustion control system 225 can achieve a proportioning mixture of air 262 and the one or more fuels used at a point in time that allows the lean pre-mixed reactants exiting the stage 1A portion 276 and/or the stage 1B portion 277 of the mix tubes of a burner 275 to effectively “self-anchor” at the exit of the mix tubes, thereby eliminating the need for any other form of flame anchor and the use of pilot maintenance fuel 245. The quantity of fuel (e.g., primary fuel 248) associated with the combustion process in the self-anchored stage 1A portion 276 and/or the stage 1B portion 277 of a burner 275 is more than an order of magnitude less (e.g., in the range of 0.1% or less of total fuel consumption) than typical flame anchor/fuel rich core requirements, which leads to the step change reduction in NOx emissions. For example, with some furnaces 279, acoustic effects combined with a small amount of pilot maintenance fuel 245 may help stabilize the combustion environment within the furnace 279.

Having the flame anchored (e.g., fixing the combustion process “in space”) is an essential requirement to combustion stability, avoiding undesirable acoustic effects within the furnace 279. If the flame separates from the anchor point and combustion occurs in downstream space within the furnace 279 (away from the burner 275), this leads to potential moving flame front (i.e., deflagration) like combustion and can cause pressure transient effects that disrupt air flow and further contribute to stability issues. Combustion instability leads to pressure variations in the furnace 279 that can result in undesirable air supply flow variations, which further compounds the combustion instability and can result in a nuisance trip of the combustion process.

A nuisance trip is initiated by the Burner Management System (BMS) in existing boilers, where the BMS utilizes flame scanning sensors to detect the presence or absence of flame within a burner 275. A flame that moves away from the flame anchor passes outside the scanning sensor viewport, which triggers the trip event. The example combustion control system 225 may also manipulate the reaction rate and flame volume relationships to flame scanning. Changing the TWR concentrations by altering the amount of XSA and/or inert fuel/FGR content can change the rate of reaction, specifically the “burn time” and the thickness of the flame front. These changes also impact the intensity of the UV radiation and the point in space at which the radiation occurs (thereby changing the image as seen in the view port of a UV flame scanner). More detail about how the example combustion control system 225 can work is provided below with respect to FIG. 7.

As discussed below with respect to FIG. 3, the combustion control system 225 can include multiple components. For example, in certain example embodiments, the combustion control system 225 can include one or more valves 285, one or more sensor devices 260, and/or other equipment that can be used, for example, to control the flow of the pilot maintenance fuel 245 to one or more of the burners 275 at any point during operation of the boiler 270. As discussed above, in the current art, such regulation of the flow of the pilot maintenance fuel 245 does not exist. Instead, in the current art, the flow of pilot maintenance fuel 245 to the burners 275 generally remains substantially constant during the operation of the boiler 270, with some exceptions that may occur when there is a slight load-dependent pressure droop effect that occurs with heat demand changes (e.g., changing the fuel flow control valve position alters the gas supply pressure of the pilot maintenance fuel source 244, which leads to a variation in flow rate of the pilot maintenance fuel flow rate). This pressure droop effect can vary depending upon the type of center gas port (e.g., open pipe vs. nozzle) and has a reduced effect for the nozzle style.

In some cases, the fuel (e.g., the primary fuel 248) may be a gas mixture predominantly composed of paraffinic hydrocarbons (alkanes) having the general formula C_xH_y where C is an elemental carbon atom, H is an elemental hydrogen atom, x and y are integers, and y=2x+2. In other cases, other gaseous fuel species (e.g., carbon monoxide (CO), hydrogen (H₂), hydrogen sulfide (H₂S), ammonia (NH₃)) may also be included in the gas mixture. Additionally, quantities of oxygen (O₂) and/or other inert non-reactive species (N₂, Ar, CO₂, He, H₂O, SO₂) may be found in the fuel gas mixture. Since the composition of typical fuel gas supplies are subject to variations over time, the example combustion control system 225 may compensate for changing fuel compositions. Also, the one or more fuels used may vary based on the industrial application (e.g., refinery, power generation). The example combustion control system 225 can be used with any fuels, whether or not those fuels are expressly listed herein.

The combustion control system 225 can be communicably coupled to one or more of the sensor devices 260, one or more of the controllers 204, the network manager 280, one or more of the users 250 (including associated user systems 255), one or more of the steam consumer 269, one or more of the water injection systems 264, one or more of the ignition fuel injection systems 243, one or more of the pilot maintenance fuel injection systems 246, one or more of the primary fuel injection systems 249, one or more of the air injection systems 261, one or more of the secondary fuel injection systems 253, one or more of the tertiary fuel injection systems 257, and/or any components (e.g., a controller for a damper) of the boiler 270.

Interaction between the combustion control system 225 and any of these other components of the system 200 may be facilitated by communication links 205 and/or power transfer links 287. Each communication link 205 may include wired (e.g., Class 1 electrical cables, Class 2 electrical cables, electrical connectors, Power Line Carrier, RS485) and/or wireless (e.g., Wi-Fi, Zigbee, visible light communication, cellular networking, Bluetooth, Bluetooth Low Energy (BLE), ultrawide band (UWB), WirelessHART, ISA100) technology. A communication link 205 may transmit signals (e.g., communication signals, control signals, data) between each controller 204, the sensor devices 260, the users 250 (including any associated user systems 255), the network manager 280, and the other components of the system 200. When a communication link 205 includes wired technology, the communication link 205 may be sized (e.g., 28 gauge, 32 gauge) in a manner suitable for the amount (e.g., 10 mV, 1.0 V) and type (e.g., alternating current, direct current) of signal (e.g., communication, control, data) transferred therethrough.

Each power transfer link 287 may include one or more electrical conductors, which may be individual or part of one or more electrical cables. In some cases, as with inductive power, power may be transferred wirelessly using power transfer links 287. A power transfer link 287 may transmit power between each controller 204, the sensor devices 260, the users 250 (including any associated user systems 255), the network manager 280, and the other components of the system 200. Each power transfer link 287 may be sized (e.g., 12 gauge, 18 gauge, 4 gauge) in a manner suitable for the amount (e.g., 480V, 24V, 120V) and type (e.g., alternating current, direct current) of power transferred therethrough.

The amount of the individual fluids (in this example, the water 267, the air 262 (which can include flue gas 237), the one or more ignition fuels 242, the one or more pilot maintenance fuels 245, the one or more primary fuels 248, the air 262, the one or more secondary fuels 252, and the one or more tertiary fuels 256) that serve as inputs to the burners 275 and/or the furnace 279 of the boiler 270 may be regulated in real time. This regulation may be performed automatically by the example combustion control system 225 and/or manually by a user 250 (which may include an associated user system 255). This regulation may be performed using equipment such as, but not limited to, the various injection systems (e.g., the primary fuel injection system 249, the air injection system 261), including valves 285, regulators, and sensor devices 260. This regulation can be implemented by and/or based on information provided by the example combustion control system 225, including portions thereof (e.g., the control engine 306, one or more algorithms 333, one or more protocols 332 (discussed below)).

In certain example embodiments, the flue gas 237 emitted from the boiler 270 is evaluated. Part of the evaluation of the flue gas 237 can include measuring (e.g., using one or more of the sensor devices 260) and/or calculating (e.g., using one or more algorithms 333 (discussed below)) one or more parameters associated with the flue gas 237. Examples of such parameters can include, but are not limited to, a level of NOx in the flue gas 237, a level of any other emission component (e.g., SOx, CO, CO₂, O₂) in the flue gas 237, a level of opacity of the flue gas 237, and a temperature of the flue gas 237). For example, the combustion control system 225 can be or include a feedback controller that measures the windbox O₂ concentration and then adjusts the flow rate of the flue gas 237 accordingly. Used by itself, the flue gas flow measurement or calculation enables a form of open loop control, including the windbox O₂ measurement allowing for closed loop control action and, in some cases, using an algorithmic method.

Evaluation of the flue gas 237 can be performed over time according to some schedule (e.g., instantaneously, continuously, periodically, randomly). This evaluation may be performed by the example combustion control system 225, by a controller 204, and/or by a user 250 (including an associated user system 255). In some cases, based on the evaluation of the flue gas 237, adjustments of one or more of the algorithms 333 and/or one or more of the protocols 332 of the combustion control system 225 can be made (e.g., by the controller 304 of the combustion control system 225, by a user 250 (including an associated user system 255).

The evaluation of the flue gas 237 can be driven by one or more of a number of goals. Such goals can include, but are not limited to, lowering the level of NOx in the flue gas 237, lowering the level of other emission parameters in the flue gas 237, altering the temperature of the flue gas 237, and lowering or eliminating the amount of any of the fuels that were not combusted in the boiler 270 and remain in the flue gas 237 after leaving the boiler 270. Using the example combustion control system 225, operations may result in zero ppm of CO or single digit levels (in ppm) of CO.

As mentioned above, the system 200 may include one or more controllers 204. Each controller 204 can be communicably coupled to the combustion control system 225. A controller can also be communicably coupled to one or more other components of the system 200, including but not limited to the network manager 280, a user 250 (including an associated user system 255), a sensor device 260, and one or more of the injection systems (or portions thereof). A controller 204 performs a number of functions that include obtaining and sending data, evaluating data, following protocols, running algorithms, and sending commands. A controller 204 may include one or more of a number of components. A controller 204 of FIG. 2A can include one or more of the components of the controller 304 (discussed below with respect to FIG. 3) of the combustion control system 225 and/or perform one or more of the functions of the controller 304 of the combustion control system 225. For example, components of a controller 304 may include, but are not limited to, a control engine, a communication module, a timer, a counter, a power module, a storage repository, a hardware processor, memory, a transceiver, an application interface, and a security module.

When there are multiple controllers 204 (e.g., one controller 204 for one or more primary fluid injection systems 249, another controller 204 for an air injection system 261, yet another controller 204 for a water injection system 264, still another controller 204 for one or more secondary fuel injection systems 253), each controller 204 may operate independently of each other. Alternatively, one or more of the controllers 204 may work cooperatively with each other. As yet another alternative, one of the controllers 204 may control some or all of one or more other controllers 204 in the system 200. As still another alternative, each controller 204 may be in communication with and controlled by the controller 304 of the combustion control system 225. Each controller 204 may be considered a type of computer device, as discussed below with respect to FIG. 4.

Each sensor device 260 includes one or more sensors that measure one or more parameters (e.g., pressure, flow rate, temperature, humidity, fluid content, voltage, current, opacity, concentration(s) of fuel, air, and flue gas species such as NOx, SOx, CO, CO₂, O₂). Examples of a sensor of a sensor device 260 may include, but are not limited to, a temperature sensor, a flow sensor, a pressure sensor, a pressure differential sensor, a gas spectrometer, a voltmeter, an ammeter, an opacity meter, an infrared sensor, a Venturi meter, an orifice meter, and a camera. A sensor device 260 may be integrated with or measure a parameter associated with one or more components of the system 200. For example, a sensor device 260 may be configured to measure a parameter (e.g., flow rate, pressure, temperature, volume) of an input (e.g., a secondary fuel 252, air 262, water 267, ignition fuel 242) to the boiler 270 and/or an output (e.g., steam 268, flue gas 237) to the boiler 270 flowing through the piping 288 at a particular location (e.g., between a primary fuel source 247 and the phase 1B portion 277 of a burner 275 of the boiler 270, between a secondary fuel source 251 and the furnace 279 of the boiler 270, between the boiler tubes 295 of the boiler 270 and a steam consumer 269).

As another example, a sensor device 260 may be configured to measure a parameter (e.g., flow rate, pressure, temperature, volume, level of NOx, level of SOx, level of opacity, level of CO, level of CO₂, level of O₂) of the flue gas 237 flowing out of the furnace 279 of the boiler 270 before reaching the atmosphere. As yet another example, a sensor device 260 may be configured to indicate how open or closed a valve 285 within the system 200 is. As still another example, one or more sensor devices 260 may be used to indicate whether certain equipment (e.g., a motor, a pump, a fan) of an injection system is working properly and/or the level to which such equipment is operating. In some cases, a number of sensor devices 260, each measuring a different parameter, may be used in combination to determine and confirm whether the combustion control system 225 (or some other component of the system 200, such as a controller 204) should take a particular action (e.g., operate a valve 285, operate or adjust the operation of an injection system). When a sensor device 260 includes its own controller (e.g., a controller 204 or portions thereof), then the sensor device 260 may be considered a type of computer device, as discussed below with respect to FIG. 4.

A user 250 may be any person that interacts, directly or indirectly, with the combustion control system 255 and/or any other component of the system 200. Examples of a user 250 may include, but are not limited to, a business owner, an engineer, an operator, a data analyst, a company representative, a geologist, a consultant, a drilling engineer, a contractor, and a manufacturer's representative. A user 250 may use one or more user systems 255, which may include a display (e.g., a GUI). A user system 255 of a user 250 may interact with (e.g., send data to, obtain data from) the combustion control system 225 and/or some other component of the system 200 via an application interface and using the communication links 205. The user 250 may also interact directly with the combustion control system 225 (or portion thereof) through a user interface (e.g., keyboard, mouse, touchscreen).

The network manager 280 is a device or component that controls all or a portion (e.g., the combustion control system 225, a communication network, a controller 204) of the system 200. The network manager 280 may be substantially similar to a controller 204, as described above. For example, the network manager 280 may include a controller that has one or more components and/or similar functionality to some or all of a controller 204. Alternatively, the network manager 280 may include one or more of a number of features in addition to, or altered from, the features of a controller 204. As described herein, control and/or communication with the network manager 280 may include communicating with one or more other components of the same system 200 or another system. In such a case, the network manager 280 may facilitate such control and/or communication. The network manager 280 may be called by other names, including but not limited to a master controller, a network controller, and an enterprise manager. The network manager 280 may be considered a type of computer device, as discussed below with respect to FIG. 4.

FIG. 3 shows a diagram of the combustion control system 225 of the system of FIGS. 2A and 2B according to certain example embodiments. The combustion control system 225 of FIG. 3 includes a controller 304, one or more optional sensor devices 360, and one or more optional valves 385. In some cases, the combustion control system 225 can include one or more other components (e.g., a report module) that are not shown in FIG. 3.

The components shown in FIG. 3 are not exhaustive, and in some embodiments, one or more of the components shown in FIG. 3 may not be included in the example combustion control system 225. Any component of the combustion control system 225 may be discrete or combined with one or more other components of the combustion control system 225. Also, one or more components of the combustion control system 225 may have different configurations. For example, one or more sensor devices 360 may be disposed within or disposed on other components (e.g., piping 288, a valve 285). As another example, the controller 304, rather than being a stand-alone device, may be part of one or more other components of the combustion control system 225 or the system 200. For instance, the combustion control system 225 can be part of the network manager 280.

Referring to FIGS. 1 through 3, the combustion control system 255 is configured to control temperatures in the furnace through analysis and control of the various inputs to the boiler 270. This analytic implementation may result in significantly lower levels of certain emissions (e.g., NOx), improved reliability, simplified startup operations (e.g., equivalent to a “single pushbutton” of starting the boiler 270), and/or improved operation of the boiler 270. The controller 304 of the combustion control system 225 can include one or more of a number of components. For example, in this case, the controller 304 can include a control engine 306, an optimization module 336, an emissions level module 338, a communication module 307, a timer 335, a power module 330, a storage repository 331, a hardware processor 321, a memory 322, a transceiver 324, an application interface 326, and, optionally, a security module 323. The various components of the controller 304 may be centrally located. In addition, or in the alternative, some of the components of the controller 304 may be located remotely from (e.g., in the cloud, at an office building) one or more of the other components of the controller 304.

The storage repository 331 may be a persistent storage device (or set of devices) that stores software and data used to assist the controller 304 in communicating with one or more other components of a system, such as the users 250 (including associated user systems 255), the network manager 280, the sensor devices 260, and any other component of the system 200 of FIG. 2 above. In one or more example embodiments, the storage repository 331 stores one or more protocols 332, one or more algorithms 333, and stored data 334.

The protocols 332 of the storage repository 331 may be any procedures (e.g., a series of method steps) and/or other similar operational processes that the control engine 306 of the controller 304 follows based on certain conditions at a point in time. The protocols 332 may include any of a number of communication protocols that are used to send and/or obtain data between the controller 304 and other components of a system (e.g., the system 200). Such protocols 332 used for communication may be a time-synchronized protocol. Examples of such time-synchronized protocols may include, but are not limited to, a highway addressable remote transducer (HART) protocol, a wireless HART protocol, and an International Society of Automation (ISA) 100 protocol. In this way, one or more of the protocols 332 may provide a layer of security to the data transferred within a system (e.g., testing system 200). Other protocols 332 used for communication may be associated with the use of Wi-Fi, Zigbee, visible light communication (VLC), cellular networking, BLE, UWB, and Bluetooth.

The algorithms 333 may be any formulas, mathematical models, forecasts, simulations, and/or other similar tools that the control engine 306 of the controller 304 uses to reach a computational conclusion. For example, one or more algorithms 333 may be used, in conjunction with one or more protocols 332, to assist the controller 304 to determine the various chemical components of one or more of the inputs (e.g., a secondary fuel 252, air 262, water 267, ignition fuel 242) to the boiler 270. As another example, one or more algorithms 333 may be used, in conjunction with one or more protocols 332, to assist the controller 304 to determine the various chemical components of one or more of the outputs (e.g., flue gas 237, stream 268) from the boiler 270.

As yet another example, one or more algorithms 333 may be used, in conjunction with one or more protocols 332, to assist the controller 304 to determine a flow rate of air 262 to be mixed with flue gas 237 before mixing the air 262 and the flue gas 237 and injecting the mixture into one or more of the burners 275. As still another example, one or more algorithms 333 may be used, in conjunction with one or more protocols 332, to assist the controller 304 to determine an optimal temperature within the furnace 279 during combustion. As yet another example, one or more algorithms 333 may be used, in conjunction with one or more protocols 332, to assist the controller 304 to make adjustments in the combustion process based on ambient conditions surrounding the boiler 270.

One or more of the algorithms 333 used herein can represent a first principles-based model/representation of the entire process, coupling flow mechanics, thermodynamics, chemistry, combustion, heat and material balances, and appropriate equations of state to establish the “flowing” properties of the various fluids (e.g., air, fuel, flue gas, water, steam) used in the combustion process. The flowing properties can then be applied to derive the flow and heat rates, from which mixing relationships and concentrations can be evaluated. Mixture properties and combustion reactions can be evaluated for the various control objectives (e.g., total, by stage, differing stoichiometric and/or excess air arrangements, etc.). Fundamental control is a heat demand, with following fuel controller, which then establishes air controls in accordance with ‘desired’ air-fuel proportioning and associated fuel-stage proportioning to achieve desired excess air controls (e.g., staged, total) for the purpose of combustion temperature control at values that achieve reliable and self-sustaining combustion performance with minimal criteria pollutant emissions (e.g., NOx, CO).

In addition to actual performance, expected performance can also be evaluated based on the results of one or more algorithms 333, and these results can then be used to inform compensation control methods (e.g., for when fuel composition varies). The combustion control system 225 can use the results of the algorithms 333 in a feedforward cascade control fashion to establish the operating setpoints for each process controller for any range of possible process conditions within the sensor configuration ranges.

Stored data 334 may be any data associated with the various equipment (e.g., a secondary fuel injection system 253, a water injection system 264, a steam consumer 269, the boiler 270), including associated components, of the system 200, the various inputs (e.g., a secondary fuel 252, air 262, water 267, ignition fuel 242) to the boiler 270, the outputs (e.g., flue gas 237, stream 268) from the boiler 270, the example combustion control system 225, the user systems 255, the network manager 280, the sensor devices (e.g., sensor devices 260, sensor devices 360), measurements made by the sensor devices (e.g., sensor devices 260, sensor devices 360), threshold values, tables, results of previously run or calculated algorithms 333, updates to protocols 332 and/or algorithms 333, user preferences, and/or any other suitable data. Such data may be any type of data, including but not limited to historical data, present data, and future data (e.g., forecasts). The stored data 334 may be associated with some measurement of time derived, for example, from the timer 335.

Examples of a storage repository 331 may include, but are not limited to, a database (or a number of databases), a file system, cloud-based storage, a hard drive, flash memory, some other form of solid-state data storage, or any suitable combination thereof. The storage repository 331 may be located on multiple physical machines, each storing all or a portion of the protocols 332, the algorithms 333, and/or the stored data 334 according to some example embodiments. Each storage unit or device may be physically located in the same or in a different geographic location.

The storage repository 331 may be operatively connected to the control engine 306. In one or more example embodiments, the control engine 306 includes functionality to communicate with the users 250 (including associated user systems 255), the sensor devices 260, the sensor devices 360, the network manager 280, and any other components in the system 200. More specifically, the control engine 306 sends information to and/or obtains information from the storage repository 331 in order to communicate with the users 250 (including associated user systems 255), the sensor devices 260, the sensor devices 360, the network manager 280, and any other components of the system 200. As discussed below, the storage repository 331 may also be operatively connected to the communication module 307 in certain example embodiments.

In certain example embodiments, the control engine 306 of the controller 304 controls the operation of one or more components (e.g., the communication module 307, the timer 335, the transceiver 324) of the controller 304. For example, the control engine 306 may activate the communication module 307 when the communication module 307 is in “sleep” mode and when the communication module 307 is needed to send data obtained from another component (e.g., a sensor device 360, a controller 204) in the system 200. In addition, the control engine 306 of the controller 304 may control the operation of one or more other components (e.g., a sensor device 360, a controller 204), or portions thereof, of the system 200.

The control engine 306 of the controller 304 may communicate with one or more other components of the system 200. For example, the control engine 306 may use one or more protocols 332 to facilitate communication with the sensor devices 360 to obtain data (e.g., measurements of various parameters, such as temperature, pressure, and flow rate), whether in real time or on a periodic basis and/or to instruct a sensor device 360 to take a measurement. The control engine 306 may use measurements of parameters taken by sensor devices 360 to perform one or more steps in reducing (e.g., minimizing) emissions (e.g., NOx) that result from fuel combustion in a boiler 270 using one or more protocols 332 and/or one or more algorithms 333. As yet another example, the control engine 306 may use one or more algorithms 333 and/or protocols 332 to determine the various chemical components of one or more of the inputs (e.g., a secondary fuel 252, air 262, water 267, ignition fuel 242) to the boiler 270.

As still another example, the control engine 306 may use one or more algorithms 333 and/or protocols 332 to determine the various chemical components of one or more of the outputs (e.g., flue gas 237, stream 268) from the boiler 270. As yet another example, the control engine 306 may use one or more algorithms 333 and/or protocols 332 to determine a flow rate of air 262 to be mixed with flue gas 237 before mixing the air 262 and the flue gas 237 and injecting the mixture into one or more of the burners 275. As still another example, the control engine 306 may use one or more algorithms 333 and/or protocols 332 to determine an optimal temperature within the furnace 279 during combustion. As yet another example, the control engine 306 may use one or more algorithms 333 and/or protocols 332 to make adjustments in the combustion process based on ambient conditions surrounding the boiler 270.

The control engine 306 may generate and process data associated with control, communication, and/or other signals sent to and obtained from the users 250 (including associated user systems 255), the sensor devices 260, the sensor devices 360, the network manager 280, and any other components of the system 200. In certain embodiments, the control engine 306 of the controller 304 may communicate with one or more components of a system external to the system 200. For example, the control engine 306 may interact with an inventory management system by ordering replacements for components or pieces of equipment (e.g., a sensor device 360, a valve 285, a motor) within the system 200 that has failed or is failing. As another example, the control engine 306 may interact with a contractor or workforce scheduling system by arranging for the labor needed to replace a component or piece of equipment in the system 200. In this way and in other ways, the controller 304 is capable of performing a number of functions beyond what could reasonably be considered a routine task.

In certain example embodiments, the control engine 306 may include an interface that enables the control engine 306 to communicate with the sensor devices 260, the sensor devices 360, the user systems 255, the network manager 280, and any other components of the system 200. For example, if a user system 255 operates under IEC Standard 62386, then the user system 255 may have a serial communication interface that will transfer data to the controller 304. Such an interface may operate in conjunction with, or independently of, the protocols 332 used to communicate between the controller 304 and the users 250 (including corresponding user systems 255), the sensor devices 260, the sensor devices 360, the network manager 280, and any other components of the system 200.

The control engine 306 (or other components of the controller 304) may also include one or more hardware components and/or software elements to perform its functions. Such components may include, but are not limited to, a universal asynchronous receiver/transmitter (UART), a serial peripheral interface (SPI), a direct-attached capacity (DAC) storage device, an analog-to-digital converter, an inter-integrated circuit (I2C), and a pulse width modulator (PWM).

The optimization module 336 of the controller 304 of the combustion control system 225 may be configured to optimize one or more of the emission components (e.g., NOx, opacity, CO, CO₂) of the flue gas 237. The optimization module 336 can optimize the one or more emission components of the flue gas 237 by making recommendations to adjust one or more of the inputs (e.g., a secondary fuel 252, air 262, water 267, ignition fuel 242) to the boiler 270. The optimization module 336 can use measurements of one or more parameters made by one or more sensor devices (e.g., sensor devices 260, sensor devices 360) to optimize the emission components of the flue gas 237. Examples of such parameters can include, but are not limited to, ambient conditions (e.g., temperature, humidity, atmospheric pressure), flow rates, composition of a fluid, composition of the water 267, and composition of the air 262. The optimization module 336 can use one or more protocols 332 and/or one or more algorithms 333 to optimize the one or more emission components of the flue gas 237.

The emissions level module 338 of the controller 304 of the combustion control system 225 may be configured to forecast an emission level of one or more emission components (e.g., NOx, SOx, opacity, CO, CO₂, O₂) of the flue gas 237 at a certain point in time. The emissions level module 338 can use one or more protocols 332 and/or one or more algorithms 333 to forecast an emission level of one or more emission components of the flue gas 237. In certain example embodiments, the forecast generated by the emissions level module 338 can be based on some or all of the output of the optimization module 336.

The communication module 307 of the controller 304 determines and implements the communication protocol (e.g., from the protocols 332 of the storage repository 331) that is used when the control engine 306 communicates with (e.g., sends signals to, obtains signals from) the user systems 255, the sensor devices 260, the sensor devices 360, the network manager 280, and any other components of the system 200. In some cases, the communication module 307 accesses the stored data 334 to determine which communication protocol is used to communicate with another component of the system 200. In addition, the communication module 307 may identify and/or interpret the communication protocol of a communication obtained by the controller 304 so that the control engine 306 may interpret the communication. The communication module 307 may also provide one or more of a number of other services with respect to data sent from and obtained by the controller 304. Such services may include, but are not limited to, data packet routing information and procedures to follow in the event of data interruption.

The timer 335 of the controller 304 may track clock time, intervals of time, an amount of time, and/or any other measure of time. The timer 335 may also count the number of occurrences of an event, whether with or without respect to time. Alternatively, the control engine 306 may perform a counting function. The timer 335 is able to track multiple time measurements and/or count multiple occurrences concurrently. The timer 335 may track time periods based on an instruction obtained from the control engine 306, based on an instruction obtained from a user 250, based on an instruction programmed in the software for the controller 304, based on some other condition (e.g., the occurrence of an event) or from some other component, or from any combination thereof. In certain example embodiments, the timer 335 may provide a time stamp for each packet of data obtained from another component (e.g., a sensor device 360) of the system 200.

The power module 330 of the controller 304 obtains power from a power supply (e.g., AC mains) and manipulates (e.g., transforms, rectifies, inverts) that power to provide the manipulated power to one or more other components (e.g., the timer 335, the control engine 306) of the controller 304, where the manipulated power is of a type (e.g., alternating current, direct current) and level (e.g., 12V, 24V, 120V) that may be used by the other components of the controller 304. In some cases, the power module 330 may also provide power to one or more of the sensor devices 360.

The power module 330 may include one or more of a number of single or multiple discrete components (e.g., transistor, diode, resistor, transformer) and/or a microprocessor. The power module 330 may include a printed circuit board, upon which the microprocessor and/or one or more discrete components are positioned. In addition, or in the alternative, the power module 330 may be a source of power in itself to provide signals to the other components of the controller 304. For example, the power module 330 may be or include an energy storage device (e.g., a battery). As another example, the power module 330 may be or include a localized photovoltaic power system.

The hardware processor 321 of the controller 304 executes software, algorithms (e.g., algorithms 333), and firmware in accordance with one or more example embodiments. Specifically, the hardware processor 321 may execute software on the control engine 306 or any other portion of the controller 304, as well as software used by the users 250 (including associated user systems 255), the network manager 280, and/or other components of the system 200. The hardware processor 321 may be an integrated circuit, a central processing unit, a multi-core processing chip, SoC, a multi-chip module including multiple multi-core processing chips, or other hardware processor in one or more example embodiments. The hardware processor 321 may be known by other names, including but not limited to a computer processor, a microprocessor, and a multi-core processor.

In one or more example embodiments, the hardware processor 321 executes software instructions stored in memory 322. The memory 322 includes one or more cache memories, main memory, and/or any other suitable type of memory. The memory 322 may include volatile and/or non-volatile memory. The memory 322 may be discretely located within the controller 304 relative to the hardware processor 321. In certain configurations, the memory 322 may be integrated with the hardware processor 321.

In certain example embodiments, the controller 304 does not include a hardware processor 321. In such a case, the controller 304 may include, as an example, one or more field programmable gate arrays (FPGA), one or more insulated-gate bipolar transistors (IGBTs), and/or one or more integrated circuits (ICs). Using FPGAs, IGBTs, ICs, and/or other similar devices known in the art allows the controller 304 (or portions thereof) to be programmable and function according to certain logic rules and thresholds without the use of a hardware processor. Alternatively, FPGAs, IGBTs, ICs, and/or similar devices may be used in conjunction with one or more hardware processors 321.

The transceiver 324 of the controller 304 may send and/or obtain control and/or communication signals. Specifically, the transceiver 324 may be used to transfer data between the controller 304 and the users 250 (including associated user systems 255), the sensor devices 260, the sensor devices 360, the network manager 280, and any other components of the system 200. The transceiver 324 may use wired and/or wireless technology. The transceiver 324 may be configured in such a way that the control and/or communication signals sent and/or obtained by the transceiver 324 may be obtained and/or sent by another transceiver that is part of a user system 255, a sensor device 260, a sensor device 360, the network manager 280, and/or another component of the system 200. The transceiver 324 may send and/or obtain any of a number of signal types, including but not limited to radio frequency signals.

When the transceiver 324 uses wireless technology, any type of wireless technology may be used by the transceiver 324 in sending and obtaining signals. Such wireless technology may include, but is not limited to, Wi-Fi, Zigbee, VLC, cellular networking, BLE, UWB, and Bluetooth. The transceiver 324 may use one or more of any number of suitable communication protocols (e.g., ISA100, HART) when sending and/or obtaining signals.

Optionally, in one or more example embodiments, the security module 323 secures interactions between the controller 304, the users 250 (including associated user systems 255), the sensor devices 260, the sensor devices 360, the network manager 280, and any other components of the system 200. More specifically, the security module 323 authenticates communication from software based on security keys verifying the identity of the source of the communication. For example, user software may be associated with a security key enabling the software of a user system 255 to interact with the controller 304. Further, the security module 323 may restrict receipt of information, requests for information, and/or access to information.

The optional valves 385 and the optional sensor devices 360 can be substantially the same as the valves 285 and the sensor devices 260 discussed above with respect to FIGS. 2A and 2B. In some cases, one or more of the valves 385 and/or one or more of the valves 285 can include other components and equipment, including but not limited to motors, drive systems, controllers, sensors, and electrical wiring.

A user 250 (including an associated user system 255), the sensor devices 260, the sensor devices 360, the network manager 280, and the other components of the system 200 may interact with the controller 304 using the application interface 326. Specifically, the application interface 326 of the controller 304 obtains data (e.g., information, communications, instructions, updates to firmware) from and sends data (e.g., information, communications, instructions) to the user systems 255 of the users 250, the sensor devices 260, the sensor devices 360, the network manager 280, and/or the other components of the system 200. Examples of an application interface 326 may be or include, but are not limited to, an application programming interface, a web service, a data protocol adapter, some other hardware and/or software, or any suitable combination thereof. Similarly, the user systems 255 of the users 250, the sensor devices 260, the sensor devices 360, the network manager 280, and/or the other components of the system 200 may include an interface (similar to the application interface 326 of the controller 304) to obtain data from and send data to the controller 304 in certain example embodiments.

In addition, as discussed above with respect to a user system 255 of a user 250, one or more of the sensor devices 260, one or more of the sensor devices 360, the network manager 280, and/or one or more of the other components of the system 200 may include a user interface. Examples of such a user interface may include, but are not limited to, a graphical user interface, a touchscreen, a keyboard, a monitor, a mouse, some other hardware, or any suitable combination thereof.

The controller 304, the users 250 (including associated user systems 255), the sensor devices 260, the sensor devices 360, the network manager 280, and the other components of the system 200 may use their own system or share a system in certain example embodiments. Such a system may be, or contain a form of, an Internet-based or an intranet-based computer system that is capable of communicating with various software. A computer system includes any type of computing device and/or communication device, including but not limited to the controller 304. Examples of such a system may include, but are not limited to, a desktop computer with a Local Area Network (LAN), a Wide Area Network (WAN), Internet or intranet access, a laptop computer with LAN, WAN, Internet or intranet access, a smart phone, a server, a server farm, an android device (or equivalent), a tablet, smartphones, and a personal digital assistant (PDA). Such a system may correspond to a computer system as described below with regard to FIG. 4.

Further, as discussed above, such a system may have corresponding software (e.g., user system software, sensor device software, controller software). The software may execute on the same or a separate device (e.g., a server, mainframe, desktop personal computer (PC), laptop, PDA, television, cable box, satellite box, kiosk, telephone, mobile phone, or other computing devices) and may be coupled by the communication network (e.g., Internet, Intranet, Extranet, LAN, WAN, or other network communication methods) and/or communication channels, with wire and/or wireless segments according to some example embodiments. The software of one system may be a part of, or operate separately but in conjunction with, the software of another system within the system 200.

FIG. 4 illustrates one embodiment of a computing device 418 that implements one or more of the various techniques described herein, and which is representative, in whole or in part, of the elements described herein pursuant to certain example embodiments. For example, a controller 304 (including components thereof, such as a control engine 306, a hardware processor 321, a storage repository 331, a power module 330, and a transceiver 324) may be considered a computing device 418. Computing device 418 is one example of a computing device and is not intended to suggest any limitation as to scope of use or functionality of the computing device and/or its possible architectures. Neither should the computing device 418 be interpreted as having any dependency or requirement relating to any one or combination of components illustrated in the example computing device 418.

The computing device 418 includes one or more processors or processing units 414, one or more memory/storage components 415, one or more input/output (I/O) devices 416, and a bus 417 that allows the various components and devices to communicate with one another. The bus 417 represents one or more of any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. The bus 417 includes wired and/or wireless buses.

The memory/storage component 415 represents one or more computer storage media. The memory/storage component 415 includes volatile media (such as random access memory (RAM)) and/or nonvolatile media (such as read only memory (ROM), flash memory, optical disks, magnetic disks, and so forth). The memory/storage component 415 includes fixed media (e.g., RAM, ROM, a fixed hard drive, etc.) as well as removable media (e.g., a Flash memory drive, a removable hard drive, an optical disk, and so forth).

One or more I/O devices 416 allow a user 250 to enter commands and information to the computing device 418, and also allow information to be presented to the user 250 and/or other components or devices. Examples of input devices 416 include, but are not limited to, a keyboard, a cursor control device (e.g., a mouse), a microphone, a touchscreen, and a scanner. Examples of output devices include, but are not limited to, a display device (e.g., a monitor or projector), speakers, outputs to a lighting network (e.g., DMX card), a printer, and a network card.

Various techniques are described herein in the general context of software or program modules. Generally, software includes routines, programs, objects, components, data structures, and so forth that perform particular tasks or implement particular abstract data types. An implementation of these modules and techniques are stored on or transmitted across some form of computer readable media. Computer readable media is any available non-transitory medium or non-transitory media that is accessible by a computing device. By way of example, and not limitation, computer readable media includes “computer storage media”.

“Computer storage media” and “computer readable medium” include volatile and non-volatile, removable and non-removable media implemented in any method or technology for storage of information such as computer readable instructions, data structures, program modules, or other data. Computer storage media include, but are not limited to, computer recordable media such as RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which is used to store the desired information and which is accessible by a computer.

The computer device 418 (also sometimes called a computer system 418) is connected to a network (not shown) (e.g., a LAN, a WAN such as the Internet, cloud, or any other similar type of network) via a network interface connection (not shown) according to some example embodiments. Those skilled in the art will appreciate that many different types of computer systems exist (e.g., desktop computer, a laptop computer, a personal media device, a mobile device, such as a cell phone or personal digital assistant, or any other computing system capable of executing computer readable instructions), and the aforementioned input and output means take other forms, now known or later developed, in other example embodiments. Generally speaking, the computer system 418 includes at least the minimal processing, input, and/or output means necessary to practice one or more embodiments.

Further, those skilled in the art will appreciate that one or more elements of the aforementioned computer device 418 is located at a remote location and connected to the other elements over a network in certain example embodiments. Further, one or more embodiments is implemented on a distributed system having one or more nodes, where each portion of the implementation (e.g., the combustion control system 225) is located on a different node within the distributed system. In one or more embodiments, the node corresponds to a computer system. Alternatively, the node corresponds to a processor with associated physical memory in some example embodiments. The node alternatively corresponds to a processor with shared memory and/or resources in some example embodiments.

FIG. 5 shows a graph 599 illustrating NOx emissions of a boiler 270 used to create steam according to certain example embodiments. In other words, the boiler 270 in this case has multiple combustion zones to generate steam. Referring to FIGS. 1 through 5, the graph 599 of FIG. 5 shows a plot 527 of NOx levels (in ppm) along the vertical axis versus Kelvin temperature along the horizontal axis, representing the adiabatic flame temperature for an example air-fuel mixture that may be used in a boiler 270. The graph 599 shows that there is a minimum threshold 572 (corresponding to approximately 1515 K and 0.9 ppm of NOx) below which self-sustaining combustion cannot occur in the boiler 270 (e.g., because not all of the fuel will combust in the boiler 270). The minimum threshold 572 represents the example operating point for which heat losses (predominantly radiation losses) exiting the combustion “thermodynamic control volume” are basically balancing the actual flame temperature (AFT) less losses against the autoignition temperature (AIT), which is defined as the threshold for achieving self-sustaining combustion. The graph 599 also shows that there is a maximum threshold 571 (corresponding to approximately 1665 K and 9.0 ppm of NOx) above which combustion should not occur in the boiler 270 (e.g., because the level of NOx emitted exceeds a regulatory value).

In between the minimum threshold 572 and the maximum threshold 571 is a target area. For example, point 573 on the plot 527, corresponding to approximately 1615 K and 4.5 ppm of NOx, falls within the target zone. Using the example combustion control system 225 described herein can locate the optimal place along the plot 527 within the target zone, based on actual values of parameters associated with the fuels, the air 262 (including the flue gas 237 when the flue gas 237 is recirculated), and/or the ambient environment.

FIG. 6 shows a graph 699 illustrating NOx emissions of a boiler 270 used to create heated water according to certain example embodiments. In other words, the boiler 270 in this case has a single combustion zone to generate heated water. Referring to FIGS. 1 through 6, the graph 699 of FIG. 6 shows a plot 627 of NOx levels (in ppm) along the vertical axis versus Kelvin temperature along the horizontal axis. The graph 699 shows that there is a minimum threshold 672 (corresponding to approximately 1515 K and 0.9 ppm of NOx) below which combustion cannot occur in the boiler 270 (e.g., because not all of the fuel will combust in the boiler 270). The graph 699 also shows that there is a maximum threshold 671 (corresponding to approximately 1645 K and 6.8 ppm of NOx) above which combustion should not occur in the boiler 270 (e.g., because the level of NOx emitted exceeds a regulatory value).

In between the minimum threshold 672 and the maximum threshold 671 is a target area. For example, point 673 on the plot 627, corresponding to approximately 1605 K and 3.8 ppm of NOx, falls within the target zone. Using the example combustion control system 225 described herein can locate the optimal place along the plot 627 within the target zone, based on actual values of parameters associated with the fuels, the air 262 (including the flue gas 237 when the flue gas 237 is recirculated), and/or the ambient environment. The results shown in FIGS. 5 and 6 can vary based on changes to any of a number of factors, and so these graphs are meant only to be examples.

FIG. 7 shows a graph 799 illustrating relationships between adiabatic flame temperature and excess air according to certain example embodiments. Referring to FIGS. 1 through 7, the graph 799 of FIG. 7 shows multiple plots (e.g., a range) of the Kelvin temperature of an adiabatic flame along the vertical axis versus excess air expressed as a percentage of the stoichiometric air along the horizontal axis. The example method employed herein using the combustion control system 225 to achieve ultra-low NOx emissions is based upon including a combustion temperature control solution that establishes and maintains combustion conditions at a threshold slightly greater than the limit of sustainable combustion, which is established at the fuel concentration corresponding to the lower flammability limit 794 (LFL 794) of the individual fuel species. The threshold conditions can be adjustable depending on factors that can include, but are not limited to, the type of fuel (e.g., gas, coal, oil), the characteristics of the fuel, the ambient temperature, and the configuration of the boiler. The threshold is based upon establishing the lower flammability limit 794 (LFL 794) for the fuel mixture (e.g., shown as 1515.6 K for certain example embodiments). The LFL 794 can be defined for specified reference conditions and can serve to establish the adiabatic combustion temperature for which sustainable combustion is possible. By definition, the LFL 794 is the mole fraction of the combustible fuel in the total reactant mixture.

As defined herein, combustion describes a chemical reaction in which fuel (e.g., primary fuel 248, ignition fuel 242) and oxidizer reactants (e.g., air 262, flue gas 237) combine in an exothermic reaction to create products of combustion and heat. The oxidizer is generally oxygen molecules (O2) and are supplied with atmospheric air. The heat serves to increase the temperature of both the products and any unused reactants (e.g., for the period during which the combustion process is proceeding and the extent of reaction (i.e., the fraction of the combustion process which has been completed) is less than 100%, where 100% represents complete combustion of all supplied fuel). The maximum possible temperature of the products can be produced when the mixture of fuel and air is both stoichiometric and completely combusted, such that the reaction is balanced so that all of the fuel and oxygen molecules are consumed in the reaction, and so that no unburned fuel or oxygen is present in the products. This maximum temperature is the stoichiometric adiabatic flame temperature 758 (AFT 758) and represents the maximum possible temperature for a given fuel before any heat losses occur. The stoichiometric AFT 758 is an idealized temperature and is not generally observed in practice since the combustion process is subject to heat losses. The predominant form of heat loss that is significant with respect to the action of the combustion reaction is the transfer of radiant heat 713. For paraffinic hydrocarbon fuel gas mixtures (e.g., methane through hexane), the magnitude of the loss from radiant heat 713 is on the order of 40% of the total heat release.

The action of the transfer of radiant heat 713 results in a reduction of the available heat to sustain the combustion reaction. The limiting condition for sustainable combustion can generally be defined as having a temperature value defined as the autoignition temperature 701 (AIT 701). This AIT 701 is the minimum temperature at which self-sustaining ignition of fuel and air occurs without the need for an external source of ignition. At temperatures below the AIT 701, the combustion reaction will be extinguished. The range of temperatures between the stoichiometric AFT 758 and the AIT 701 represents the operational envelope within which sustainable combustion is possible. For example, the difference between the AIT 701 and the AFT curve 790, represented by the fuel mixture (e.g., in this example, methane) and as a function of excess air, may define the operational envelope.

In practice, normal combustion occurs with an excess quantity of air (shown along the horizontal axis of the graph 799 of FIG. 7) in the reactant mixture. This excess quantity of air is added to ensure that the fuel is always completely combusted, which ensures safety by avoiding conditions in which unburned fuel may be present in downstream process equipment. An additional reason for the supply of excess air relates to reducing the combustion temperature for the purpose of emissions control. Having excess air in the reactants is commonly referred to as lean combustion with respect to the fuel. While not shown in the graph 799 of FIG. 7, if the reaction has excess fuel (i.e., if the reaction has no excess air), the reaction is referred to as fuel-rich combustion (e.g., sub-stoichiometric, having insufficient oxygen to completely combust all of the fuel).

As the quantity of excess air is increased, the computed value of the maximum adiabatic flame temperature 790 (AFT 790) decreases. From a reaction heat and mass balance perspective, the quantity of heat released in the combustion reaction remains the same, but the temperature of the products is less. This is due to the heating of the additional molecules supplied as excess air. The heat contained by the excess air represents a thermal ballast 759 or heat sink. As the amount of excess air is increased, the amount of thermal ballast 759 also increases until the limit condition for sustainable combustion is reached at the LFL 794. The combustion process at the LFL 794 has the minimum value of AFT for which sustainable combustion can be maintained. This value of the AFT 790 is still much greater than the AIT 701 value.

The difference between these combustion temperatures is primarily due to the radiant heat losses 713 associated with the combustion reaction at the LFL 794. The radiant heat losses 713 may serve to not only heat the thermal ballast 759 to above the AIT 701, but may also serve to deliver heat to surrounding surfaces (e.g., refractory, boiler tubes) within the furnace 279. The LFL temperature 794 may be the temperature at which combustion occurs such that the amount of heat loss required to heat the thermal ballast 759 and surrounding surfaces remains above the AIT temperature 701. This ensures sustainable combustion.

When FGR is employed, there is more mass flow that mixes with the fuel, which adds to the thermal ballast 759, which in turn results in an adjustment to one or more of the combustion control system 225 setpoints (e.g., excess air setpoint 702 (also called XSA_SP 702), FGR setpoint, fuel-proportioning setpoint(s), flue gas O₂ setpoint, AFT set point 790). The graph 799 of FIG. 7 shows that ambient conditions may have a significant impact on the AFT 758 result, which then impacts the XSA_SP 702. The AFT 758 vs XSA_SP 702 curve is relatively flat at the tail end approaching the LFL stability limit 794. As a result, changes in AFT 758 (e.g., computed by the example combustion control system 225) can materially alter the requirement of the XSA_SP 702.

The extent of reaction describes the degree of completion for the combustion reaction, with zero (0.0) representing no reaction and with unity (1.0) representing a complete reaction. The extent of reaction can also be useful to account for the time required to complete the combustion reaction. In other words, since time is required to complete the combustion reaction, until sufficient time has passed, the reaction is in varying stages of completion. This is important since it means that the amount of heat formed by the reaction has a time dependency with the total heat release only being available at the conclusion of the complete reaction. This implies that the AFT 790 also exhibits a time dependency and can increase over time as the reaction proceeds to completion because heat losses are also occurring, and so low values of AIT 701 may not be realized.

As a result, the time required to complete the combustion process may result in a temperature gradient within the air and fuel reactant mixture as products are produced. The minimum temperature must by necessity be greater than the AIT 701 or else the combustion reaction will not be sustained. With normal industrial premix burners, the air and fuel are supplied as flow streams that mix together in the burner to produce a reactant mixture, which is conveyed with a bulk fluid (e.g., a gas) velocity and combusts upon igniting. The combination of the flowing velocity and the varying extent of reaction means that the temperature gradient occurs spatially within the burner/furnace volume, and so the air and fuel reactant mixture travels some distance within the burner or out into the furnace before the reaction completes.

The actual “burn time” (also called flame speed) occurs in a relatively small flame front for which significant temperature gradient occurs. This burn time exhibits a concentration dependency that depends not only on the specific fuel species but also the concentration of the oxygen. The act of increasing XSA_SP 702 results in an increase in oxygen concentration. This serves to reduce the burn time (i.e., faster combustion, smaller “combustion volume”). Even though the additional XSA_SP 702 dilutes the fuel concentration, the net effect is faster combustion. The act of diluting the fuel with inert content (e.g., adding N₂ or CO₂/FGR) serves to dilute the effective fuel concentration and increases the burn time (e.g., slower combustion, larger combustion volume, reduced UV intensity in flame scanner view port).

Combustion of fuel gas mixtures (e.g., paraffinic hydrocarbons, CO, H₂, H₂S, and NH₃) generally results in products of combustion (e.g., CO₂, H₂O, SO₂, N₂) and/or inert air species or non-reactive species (e.g., O₂). In addition, common byproducts of the combustion process may be carbon monoxide (CO) and/or NOx. The CO is normally formed during the combustion reaction and represents incompletely combusted fuel gas due to factors that can include, but are not limited to insufficient oxygen concentration, temperatures too low to sustain combustion, and poor air-fuel mixing. The NOx results from the disassociation of nitrogen (N₂) at elevated localized combustion temperatures, from which NOx forms. This highlights the importance of ensuring proper air-fuel mixing prior to combustion to minimize the likelihood of elevated temperatures, which results in elevated levels of NOx.

The example combustion control system 225 can establish a minimum control temperature at which the combustion reactants (fuel (e.g., primary fuel 248, ignition fuel 242) and air (e.g., air 262, flue gas 237)) are maintained above to ensure reliable and sustainable combustion. This minimum temperature is dependent on the composition of the fuel and air, and their corresponding lower flammability limit 794 (LFL 794). When the fuel is a mixture of gaseous fuels (e.g., natural gas, field-produced gas), the species having the maximum AFT 790 should serve as the basis for defining the minimum temperature, lower range limit (LRL), upon which the control temperature is then based. The minimum control temperature AFT_SP 790 must be greater than the adiabatic flame temperature low range limit (AFT_LRL) by a suitable margin. This temperature margin (T_margin) must be defined within a narrow control range 703 and serves to satisfy at least two control objectives: Low NOx/CO emissions and reliable combustion performance. The choice of T_margin is largely governed by the need to ensure that the maximum adiabatic combustion temperature, upper range limit (URL), remains below 1800 K. The T_margin may be influenced by many different performance considerations, including but not limited to the extent of reaction, the fire rate, the composition of each fuel, fuel staging, composition of the air 262, local ambient conditions (atmospheric pressure, temperature and humidity), and whether FGR is employed. A minimum value for T_margin, which achieves reliable and sustainable combustion, represents certain example embodiments.

The extent of reaction represents the proportion of the fuel within the reactants that is consumed. The combustion reaction of a flowing air-fuel reactant mixture takes place over a period of time, leading to a varying extent of reaction relative to time and space within the burner 275 and furnace 279. A consequence of this is that the flame temperature is dependent on the extent of reaction (ξ). This also highlights that the adiabatic flame temperature (i.e., lossless) is an idealized theoretical maximum that is not actually realized in practice. The primary heat losses within a combustion process are those associated with thermal radiation (the radiant heat loss 713), which can vary over time, depending on the state of the operation. For example, during a “cold start”, the radiation losses can be greater compared to steady state operation because of the cold furnace 279. In such cases, pilot maintenance fuel 245 may be used during startup operations. Also, an effect of the increased radiant heat loss 713 with a cold furnace 279 is a larger flame volume, where the extra cooling effect effectively slows down the reaction rate within the burner 275, which takes longer to burn, resulting in the increased flame volume. When an excess of air is included within the reactants, typical of industrial processes, the non-reactive reactant species (e.g., NO₂, excess O₂, CO₂ with FGR or inert fuel content) serve as a thermal ballast 759 and further reduce the magnitude of the AFT.

The example combustion control system 225 may achieve precise combustion temperature control without the need for actual temperature measurements within the burner 275 or furnace 279. No physical changes to piping 288, instrumentation (e.g., sensor devices 260), final control elements (e.g., controllers 204) or other hardware are required to implement example embodiments on existing combustion systems. The example combustion control system 225 may be implemented as a software upgrade with new control functionality to achieve a step change capability in further reducing NOx emissions for systems already designated as Low-NOx. The example combustion control system 225 has been successfully demonstrated in combustion systems equipped with lean-premix staged-fuel combustion burners 275 and performs over the full turndown rating of the burners 275, whether with fuel-staged operation or with non-fuel-staged operation.

The example combustion control system 225 controls the combustion temperature to a specific value within a narrow control span to achieve low-NOx emissions in the flue gas 237. The control span is constrained to a narrow range (the combustion zone 703) governed by the combustion stability limits at the low range limit (LRL) and governed by temperature at which the NOx formation rate becomes significant for the desired limit condition for NOx emissions at the upper range limit (URL). To ensure reliable and stable combustion suitable for long-term around the clock (e.g., 24/7/365) operation of the combustion system, an appropriate temperature margin is applied above the LFL 794 stability limit. The specific values applied for the LRL, the URL, and temperature margin are dependent upon the gaseous fuel composition as well as fuel staging considerations. The temperatures described above may all be considered to be adiabatic. The actual combustion temperatures may be reduced relative to the adiabatic values to account for the effects of heat losses (primarily radiant heat 713), effects of thermal ballast 759 for non-reactive species (e.g., excess air 262, inert fuel content), fuel staging/preheating effects, and varying extent of reaction in time and space within the combustion process. The example combustion control system 225 accounts for these considerations in the development of the adiabatic control temperature values.

While not shown in the graph 799 of FIG. 7, there may be one or more alternative plots that each illustrate a range of adiabatic flame temperatures associated with each individual fuel species and for the annualized min/max ambient conditions (e.g., temperature, humidity, barometric pressure) over the range of excess air values from 0% (stoichiometric) to the LFL 794 for each respective fuel species. In any case, the actual AFT vs. excess air curve will be determined by the composition of fuel species in the air-fuel mixture. Additionally, each stage will have a different curve in accordance with pre-heating effects, and total reactant composition (e.g., the stage 2 portion 286 receives fuel in addition to unreacted stage 1A portion 276 and stage 1B portion 277 reactants in addition to combusted stage 1A portion 276 and stage 1B portion 277 reactants, the stage 3 portion 289 receives fuel in addition to unreacted stage 1A portion 276 through stage 2 portion 286 reactants in addition to combusted stage 1A portion 276 through stage 2 portion 286 reactants).

The AIT 701 shown in the graph 799 of FIG. 7 is substantially approximated for methane, which has the highest AIT of the alkane fuel species, and corresponds to a computed extent of reaction of ˜60%. In other words, 60% of the fuel must burn to have enough residual temperature at the LFL 794 (air-fuel concentration limit) to achieve a self-sustaining combustion process.

FIG. 8 shows a flowchart 810 of a method for lowering emissions that result from fuel combustion in a boiler according to certain example embodiments. While the various steps in this flowchart 810 are presented sequentially, one of ordinary skill will appreciate that some or all of the steps may be executed in different orders, may be combined or omitted, and some or all of the steps may be executed in parallel. Further, in one or more of the example embodiments, one or more of the steps shown in this example method may be omitted, repeated, and/or performed in a different order.

In addition, a person of ordinary skill in the art will appreciate that additional steps not shown in FIG. 8 may be included in performing this method. Accordingly, the specific arrangement of steps should not be construed as limiting the scope. Further, a particular computing device, such as the computing device 418 discussed above with respect to FIG. 4, may be used to perform or facilitate performance of one or more of the steps (or portions thereof) for the method shown in FIG. 8 in certain example embodiments. Any of the functions (or portions thereof) performed below by a controller 304 may involve the use of one or more protocols 332, one or more algorithms 333, and/or stored data 334 stored in a storage repository 331. In addition, or in the alternative, any of the functions (or portions thereof) in the method may be performed by a user (e.g., user 250). In some cases, one or more of the various steps in the method of FIG. 8 can be performed automatically, as by a controller 304 of the combustion control system 225.

The method shown in FIG. 8 is merely an example that may be performed by using an example system described herein. In other words, systems for lowering emissions that result from fuel combustion in a boiler may perform other functions using other methods in addition to and/or aside from those shown in FIG. 8. Referring to FIGS. 1 through 8, the method shown in the flowchart 810 of FIG. 8 begins at the START step and proceeds to step 881, where values of parameters associated with one or more fuels are obtained. As used herein, the term “obtaining” may include receiving, retrieving, accessing, generating, etc. or any other manner of obtaining the information.

The parameters associated with a fuel and/or a mixture of fuels (collectively sometimes called fuel parameters herein) can include, but are not limited to, pressure, temperature, chemical composition (mol fractions, mass fractions), molar volume, compressibility, heating value, specific heat capacities, specific enthalpy, enthalpy, thermal power, density, viscosity, molar mass, mass flow rate (mass fractions), molar flow rate, a change in the number of moles for the reaction balance, volumetric flow rate, lower flammability limit, upper flammability limit, stoichiometric oxygen coefficients, heat of reaction, heat of formation, mean heat capacity, and adiabatic flame temperature. A fuel with which the parameters can be associated can include, but are not limited, to, an ignition fuel 242, a pilot maintenance fuel 245, a primary fuel 248, a secondary fuel 252, and a tertiary fuel 256. Each fuel may be injected into a portion (e.g., a burner 275, the furnace 279) of the boiler 270. Some or all of the values may be measured by one or more sensor devices (e.g., a sensor device 260, a sensor device 360). In addition, or in the alternative, some or all of the values may be calculated by a controller 304 of the combustion control system 225. The values can be continuous or discrete over a period of time (e.g., a second, a minute, an hour, a day, a week, a month).

The values (also sometimes called fuel values herein) may be obtained by a controller 304 (or an obtaining component thereof), which may include the controller 304 of the combustion control system 225 of FIG. 3 above, using one or more algorithms 333, one or more protocols 332, the communication module 307, the transceiver 324, and/or the application interface 326. The values may be obtained from a user 250, including an associated user system 255. In addition, or in the alternative, the values may be obtained from one or more sensor devices (e.g., sensor device 360) that measure one or more of the various parameters.

In step 882, values of parameters associated with the air 262 are obtained. The parameters associated with the air 262 (also sometimes called air parameters herein) can include, but are not limited to, pressure, temperature, chemical composition (e.g., mol fractions, mass fractions), molar volume, compressibility, heating value, specific heat capacities, specific enthalpy, enthalpy, density, viscosity, molar mass, mass flow rate (mass fractions), molar flow rate, mean heat capacity, a change in the number of moles for the reaction balance, volumetric flow rate, lower flammability limit, upper flammability limit, stoichiometric oxygen coefficients, heat of reaction, heat of formation, mean heat capacity, and adiabatic flame temperature. The air 262 with which the parameters can be associated can also include some of the flue gas 237. The air 262 (including in some cases flue gas 237 when the flue gas 237 is recirculated) may be injected into a portion (e.g., a burner 275) of the boiler 270. Some or all of the values may be measured by one or more sensor devices (e.g., a sensor device 260, a sensor device 360). In addition, or in the alternative, some or all of the values may be calculated by a controller 304 of the combustion control system 225. The values can be continuous or discrete over a period of time (e.g., a second, a minute, an hour, a day, a week, a month).

The values (also sometimes called air values herein) may be obtained by a controller 304 (or an obtaining component thereof), which may include the controller 304 of the combustion control system 225 of FIG. 3 above, using one or more algorithms 333, one or more protocols 332, the communication module 307, the transceiver 324, and/or the application interface 326. The values may be obtained from a user 250, including an associated user system 255. In addition, or in the alternative, the values may be obtained from one or more sensor devices (e.g., sensor device 360) that measure one or more of the various parameters.

In certain example embodiments, values of parameters associated with the ambient air (in other words, the air in the ambient environment surrounding the boiler 270 as opposed to air 262 to be injected into the boiler 270) are also obtained. In such cases, these values (also sometimes called ambient environment values herein) can be used in identifying the target flow rate of one or more of the fuels and/or the target flow rate of the air 262 (including the flue gas 237 if some of the flue gas 237 is recirculated).

In some cases, values of parameters associated with a mixture of air 262 and one or more fuels can additionally or alternatively be obtained. The parameters associated with the air/fuel mixture can include, but are not limited to, pressure, temperature, chemical composition (e.g., mol fractions, mass fractions), molar volume, compressibility, heating value, specific heat capacities, specific enthalpy, enthalpy, density, viscosity, molar mass, mass flow rate (mass fractions), molar flow rate, mean heat capacity, the heat of formation, a change in the number of moles for the reaction balance, volumetric flow rate, lower flammability limit, upper flammability limit, stoichiometric oxygen coefficients, heat of reaction, heat of formation, mean heat capacity, and adiabatic flame temperature. The values of parameters associated with an air/fuel mixture may be used for the full range of A/F ratios from stoichiometric 758 to LFL 794, such that the target XSA_SP 702 and fuel staging requirements can be established.

In such cases, the values of parameters associated with an air/fuel mixture may be obtained by a controller 304 (or an obtaining component thereof), which may include the controller 304 of the combustion control system 225 of FIG. 3 above, using one or more algorithms 333, one or more protocols 332, the communication module 307, the transceiver 324, and/or the application interface 326. The values may be obtained from a user 250, including an associated user system 255. In addition, or in the alternative, the values may be obtained from one or more sensor devices (e.g., sensor device 360) that measure one or more of the various parameters.

In step 883, target flow rates for the fuel(s) and the air 262 are identified. The target flow rate for each fuel (also sometimes called a fuel target flow rate herein) can be identified based on the values of the parameters obtained for that particular fuel in step 881. Similarly, the target flow rate for the air 262 (also sometimes called an air target flow rate or an air flow setpoint herein) can be identified based on the values of the parameters obtained for the air 262 (also sometimes including the flue gas 237 when the flue gas 237 is recirculated) in step 882.

The target flow rate of each fuel and the target flow rate of the air 262 can be identified by the controller 304 (or an identifying portion thereof) of the combustion control system 225 using one or more algorithms 333, one or more protocols 332, the communication module 307, the transceiver 324, and/or the application interface 326. For example, the emissions level module 338 of the controller 304 of the combustion control system 225 may be configured to forecast an emission level of one or more emission components (e.g., NOx, SOx, opacity, CO, CO₂, O₂) of the flue gas 237 based on multiple potential target flow rates of the fuels and the air, and the optimization module 336 of the controller 304 can identify the target flow rates of the fuels and the air 262 from among the various potential target flow rates while considering one or more of a number of other factors, including but not limited to ensuring that all of the fuels are combusted in the boiler 270 and the level of NOx in the flue gas 237.

A goal in identifying the target flow rates for each fuel and for the air 262 is to have a lower temperature (relative to temperatures used without the benefit of the example combustion control system 225) in the boiler 270 during combustion. Another goal in identifying the target flow rates for each fuel and for the air 262 is to have lower emissions (relative to the emissions that result without the benefit of the example combustion control system 225) in the flue gas 237 after combustion in the boiler 270. The optimization module 336 of the controller 304 can consider these and/or other goals in identifying the target flow rates for each fuel and for the air 262.

In step 884, one or more fuel injection systems are controlled to inject the target flow rate for each fuel into the boiler 270 (or portion thereof). When a target flow rate has been identified for an ignition fuel 242, then one or more of the ignition fuel injection systems 243 can be controlled. When a target flow rate has been identified for a pilot maintenance fuel 245, then one or more of the pilot maintenance fuel injection systems 246 can be controlled. When a target flow rate has been identified for a primary fuel 248, then one or more of the primary fuel injection systems 249 can be controlled. When a target flow rate has been identified for a secondary fuel 252, then one or more of the secondary fuel injection systems 253 can be controlled. When a target flow rate has been identified for a tertiary fuel 256, then one or more of the tertiary fuel injection systems 257 can be controlled.

A fuel injection system (or one or more portions thereof) can be controlled directly by the controller 304 of the combustion control system 225. In addition, or in the alternative, a fuel injection system (or one or more portions thereof) can be controlled indirectly by the controller 304 of the combustion control system 225. In such a case, the controller 304 of the combustion control system 225 can direct one or more local controllers 204 of the fuel injection system to control the fuel injection system (or portions thereof) to produce the target flow rate for the fuel associated with that fuel injection system. In some cases, a user 250 (including an associated user system 255) can additionally or alternatively control a fuel injection system to produce the target flow rate for the fuel associated with that fuel injection system.

In some cases, one or more sensor devices 260 and/or one or more sensor devices 360 can be used to measure values of one or more parameters associated with each fuel after the fuel injection system for that fuel has been controlled. In such cases, the controller 304 of the combustion control system 225 can obtain and use these values to verify that the actual flow rate of a fuel is substantially the same as the target flow rate for that fuel. In addition, or in the alternative, the controller 304 of the combustion control system 225 can calculate the actual flow rate of a fuel using, for example, one or more algorithms 333, one or more protocols 332, and/or stored data 334.

In step 811, an air injection system 261 is controlled to inject the target flow rate for air 262 (including in some cases flue gas 237 when the flue gas 237 is recirculated) into the boiler 270 (or portion thereof). An air injection system 261 (or one or more portions thereof) can be controlled directly by the controller 304 of the combustion control system 225. In addition, or in the alternative, an air injection system 261 (or one or more portions thereof) can be controlled indirectly by the controller 304 of the combustion control system 225. In such a case, the controller 304 of the combustion control system 225 can direct one or more local controllers 204 of the air injection system 261 to control the air injection system 261 (or portions thereof) to produce the target flow rate for the air 262. In some cases, a user 250 (including an associated user system 255) can additionally or alternatively control an air injection system 261 to produce the target flow rate for the air 262.

In step 812, values of parameters associated with the one or more fuels and the air 262 continue to be obtained. For example, in some cases, one or more sensor devices 260 and/or one or more sensor devices 360 can be used to measure values of one or more parameters associated with each fuel after the fuel injection system for that fuel has been controlled. In such cases, the controller 304 of the combustion control system 225 can obtain and use these values to verify that the actual flow rate of a fuel is substantially the same as the target flow rate for that fuel. In addition, or in the alternative, the controller 304 of the combustion control system 225 can calculate and/or otherwise obtain values for one or more of the parameters associated with a fuel. In such cases, the controller 304 of the combustion control system 225 can obtain the actual flow rate of a fuel using these obtained values in conjunction with, for example, one or more algorithms 333, one or more protocols 332, and/or stored data 334.

As another example, in some cases, one or more sensor devices 260 and/or one or more sensor devices 360 can be used to measure values of one or more parameters associated with the air and/or the flue gas 237 after the air injection system 261 has been controlled. In such cases, the controller 304 of the combustion control system 225 can obtain and use these values to verify that the actual flow rate of the air is substantially the same as the target flow rate for the air. In addition, or in the alternative, the controller 304 of the combustion control system 225 can calculate and/or otherwise obtain values of one or more parameters associated with the air 262. In such cases, the controller 304 of the combustion control system 225 can obtain the actual flow rate of the air using these obtained values in conjunction with, for example, one or more algorithms 333, one or more protocols 332, and/or stored data 334.

In step 891, a determination is made as to whether the values of one or more parameters associated with one or more of the fuels and/or the air 262 (potentially including the flue gas 237 when the flue gas 237 is recirculated) have changed. In some cases, a change in a value can be based on one or more threshold values and/or tolerances (e.g., part of stored data 334 and established by the controller 304 of the combustion control system 225) relative to the initial value of a parameter. In addition, or in the alternative, a change in value can be based on the passage of some amount of time (e.g., a measured by the timer 335 of the controller 304) from when the initial value of the parameter was obtained.

The determination as to whether a value of a parameter associated with a fuel or the air 262 has changed can be made by the controller 304 (or comparing portion thereof) of the combustion control system 225. In addition, or in the alternative, a user 250 (including an associated user system 255) can make the determination as to whether a value of a parameter associated with a fuel or the air 262 has changed. If the value of a parameter associated with a fuel or the air 262 has changed, then the process proceeds to step 892. If the value of a parameter associated with a fuel or the air 262 has not changed, then the process proceeds to step 896.

In step 892, revised target flow rates for one or more of the fuels and/or the air 262 (including at times flue gas 237 when the flue gas 237 is recirculated) are identified. The revised target flow rate for each fuel can be identified based on the latest values of the parameters obtained for that particular fuel in step 812. Similarly, the revised target flow rate for the air 262 can be identified based on the latest values of the parameters obtained for the air 262 (also sometimes including the flue gas 237 when the flue gas 237 is recirculated) in step 812.

The revised target flow rate of each fuel and the revised target flow rate of the air 262 can be identified by the controller 304 (or an identifying portion thereof) of the combustion control system 225 using one or more algorithms 333, one or more protocols 332, the communication module 307, the transceiver 324, and/or the application interface 326. For example, the emissions level module 338 of the controller 304 of the combustion control system 225 may be configured to generate a revised forecast of an emission level of one or more emission components (e.g., NOx, SOx, opacity, CO, CO₂) of the flue gas 237 based on multiple potential target flow rates of the fuels and the air, and the optimization module 336 of the controller 304 can identify the revised target flow rates of the fuels and the air 262 from among the various potential target flow rates while considering one or more of a number of other factors, including but not limited to ensuring that all of the fuels are combusted in the boiler 270 and the level of NOx in the flue gas 237.

In step 893, one or more fuel injection systems and/or the air injection system 261 are controlled to inject the revised target flow rate for each fuel and the air 262 into the boiler 270 (or portion thereof). A fuel injection system (or one or more portions thereof) and/or the air injection system 261 (or one or more portions thereof) can be controlled directly by the controller 304 of the combustion control system 225. In addition, or in the alternative, a fuel injection system (or one or more portions thereof) and/or the air injection system 261 (or one or more portions thereof) can be controlled indirectly by the controller 304 of the combustion control system 225. In such a case, the controller 304 of the combustion control system 225 can direct one or more local controllers 204 of a fuel injection system and/or the air injection system 261 to control the respective injection system (or portions thereof) to produce the revised target flow rate for each fuel and/or the air 262. In some cases, a user 250 (including an associated user system 255) can additionally or alternatively control a fuel injection system and/or the air injection system 261 to produce the revised target flow rate for a fuel and/or the air 262.

In some cases, one or more sensor devices 260 and/or one or more sensor devices 360 can be used to measure values of one or more parameters associated with each fuel and/or the air 262 after the various injection systems have been controlled. In such cases, the controller 304 of the combustion control system 225 can obtain and use these values to verify that the actual flow rate of a fuel and/or the air 262 is substantially the same as the revised target flow rate for that fuel and/or the air 262. In addition, or in the alternative, the controller 304 of the combustion control system 225 can calculate the actual flow rate of a fuel and/or the air 262 using, for example, one or more algorithms 333, one or more protocols 332, and/or stored data 334. When step 893 is complete, the process reverts to step 812.

In step 896, a determination is made as to whether actual emission values match forecast emission values. For example, a value of one or more of the parameters of a fuel or the air 262 (including the flue gas 237 when the flue gas 237 is recirculated) can be compared to an expected or forecast emission value (e.g., as determined by the emissions level module 338 of the controller 304 of the combustion control system 225). As a specific example, a value for the current level of NOx in the flue gas 237 can be compared to a forecast level of NOx in the flue gas 237 based on executing one or more of the algorithms 333. The actual emission values can be among the values obtained in step 812 above.

In some cases, a difference between an actual emission value and a corresponding forecast emission value can be based on one or more threshold values and/or tolerances (e.g., part of stored data 334 and established by the controller 304 of the combustion control system 225). In addition, or in the alternative, a difference between an actual emission value and a corresponding forecast emission value can be based on the passage of some amount of time (e.g., a measured by the timer 335 of the controller 304) between when the forecast emission value was obtained and when the actual emission value was obtained for a particular emission parameter.

The controller 304 (or a determining portion thereof, such as the optimization module 336 thereof) of the combustion control system 225 can make the determination as to whether one or more of the actual emission values match one or more of the forecast emission values for corresponding emission parameters. If the actual emission values match the forecast emission values, then the process proceeds to step 898. If the actual emission values do not match the forecast emission values, then the process proceeds to step 897.

In step 897, one or more of the algorithms 333 used to identify the target flow rates for one or more of the fuels and/or the air 262 is modified. An algorithm 333 can be modified by the controller 304 of the combustion control system 225 using one or more protocols 332, one or more other algorithms 333 directed to adjusting for the actual emission values, and/or stored data 334. In addition, or in the alternative, an algorithm 333 can be modified by a user 250, including an associated user system 255. In some cases, one or more of the algorithms 333 can be modified based on a comparison of actual values versus forecast values for some non-emission parameter associated with a fuel and/or the air in a similar fashion. When step 897 is completed, the process reverts to step 892.

In step 898, a determination is made as to whether the operations of the boiler 270 are continuing. The determination as to whether the boiler 270 is continuing to operate can be made by the controller 304 of the combustion control system 255 using one or more protocols 332, one or more other algorithms 333, stored data 334, input from a user 250 (including an associated user system 255), measurements made by one or more of the sensor devices (e.g., sensor devices 260, sensor devices 360), and/or any other information. In addition, or in the alternative, the determination as to whether the boiler 270 is continuing to operate can be made by a user 250 (including an associated user system 255). If the operations of the boiler 270 are continuing, then the process reverts to step 812. If the operations of the boiler 270 have stopped, then the process proceeds to the END step.

FIGS. 9A through 9C show images of combustion in a burner 975 of a boiler without the aid of example embodiments. Referring to FIGS. 1 through 9C, the images of FIGS. 9A through 9C show a bright yellow flame 929, which indicates a hotter than needed temperature. In addition, because excess fuel (e.g., pilot maintenance fuel 245) is often used, the level of NOx is elevated. The primary injection ports 928, used to introduce one or more fuels (e.g., primary fuel 248, ignition fuel 242) into the burner 975, are mostly not visible because of the luminous state of the combustion within the burner 975. There is no combustion at the cylindrical tube wall 940 of the burner 975. Rather, most of the combustion reaction takes place at relatively reduced temperatures for which there is limited visible radiation. This phenomenon is sometimes called distributed flameless combustion. Since the flame is largely invisible, there is limited lighting within the furnace (e.g., furnace 279), and so the tubes appear dark. The visible lighting may be derived from the visible blue flames and/or reflected light from the refractory behind the cylindrical tube wall 940 of the burner 975.

FIGS. 10A and 10B show images of combustion in a burner 1075 of a boiler according to certain example embodiments. Referring to FIGS. 1 through 10B, the images of FIGS. 10A and 10B show a muted orange color background 1029 which represents radiant heat transfer from the refractory tile on the fire wall of the burner reaction chamber with very little visible flame 1029 (bright blue/purple), which indicates a substantially lower overall temperature for the combustion process relative to the burner 975 of FIGS. 9A through 9C. In addition, because no excess fuel (e.g., pilot maintenance fuel 245) is used, the overall level of NOx is greatly reduced relative to the level of NOx generated by the burner 975 of FIGS. 9A through 9C. Further, all of the fuel injected into the burner 1075 is burned. The primary injection ports 1028, used to introduce one or more fuels (e.g., primary fuel 248, ignition fuel 242) into the burner 1075, are completely visible because of the non-luminous state of the combustion within the burner 1075. As with FIGS. 9A through 9C, visible lighting in FIGS. 10A and 10B may be derived from the visible blue flames and/or reflected light from the refractory behind the cylindrical tube wall 1040 of the burner 1075.

Example embodiments may provide feedforward cascade controls to derive operating setpoints in accordance with actual process conditions (e.g., per measured process parameter values). Example embodiments may provide the capability to operate a boiler/heater within mechanical design limits and at any required process conditions (e.g., delivery pressure, steam quality, water-steam mass flow rate, etc.). Example embodiments may provide the capability to operate with net heat added having any value over the full turndown range of the burner rating.

Example embodiments may allow for derived properties (e.g., thermodynamic, fluid, physical, transport) for some or all fluid flow streams (e.g., air, vitiated air, fuels, reactant mixtures, product mixtures, recirculated flue gas, water, steam) to enable accurate measurement with effectively no sensor turndown limitations due to inaccurate measurement. In other words, example embodiments provide the ability to accurately determine the actual flowing conditions for each of the fluid flow streams over the full calibrated range of the sensor instruments, enabling a “universal” operating capability with no artificial or arbitrary turndown constraints. In the current art, physical constraints to operations can include the calibrated sensor range limits and/or any mechanical limits (e.g., MAWP, nameplate ratings (e.g., rated motor speed, rated pump/blower speed, full load amps, etc.)). This combination of measurement and property evaluation using example embodiments may enable the transition to a hybrid boiler/heater, which can operate with any level of hot water or wet saturated steam (e.g., up to 80% quality) within the rated equipment constraints (e.g., water rate, burner turndown rating).

Example embodiments may provide a stable and reliable combustion process, achieving a distributed flameless combustion process (e.g., low temperature, with no visible radiation) such that the peak temperatures are predominantly below a target temperature threshold at which high NOx formation rate occurs. Example embodiments may provide for improved stability/reliability associated with performance of the control system to enable the elimination of the pilot maintenance fuel, which is normally a fuel rich combustion process (not premixed) and which results in a high NOx formation rate. Example embodiments may provide for virtual measurement methods for FGR flow control, including flow control valve characterization methods and positions to achieve FGR flow control in accordance with FGR flow setpoint.

Example embodiments may provide for stoichiometric air trim control per FGR flow rate to maintain excess air at setpoint when FGR flow control is introduced. This compensation control ensures that the total air flow is adjusted for the oxygen content included in the flue gas and that the excess air flow requirement is not adversely impacted by the addition of FGR. When FGR is used, there is an expectation that a revised (e.g., lowered) AFT temperature control is derived from the new operating point. Otherwise, the AFT controller adjusts the XSA_SP 702 downward, defeating the purpose for using FGR. In other words, the total air-fuel ratio is maintained at setpoint via closed loop control action, and thus the AFT temperature control does not experience a deviation from setpoint due to FGR control actions (on/off/modulating).

Example embodiments may provide for virtual measurement for the pilot maintenance fuel using a combination of mass balance from other fuel mass flow measurements. Example embodiments may provide for methods of performing mixing relationships and subsequent evaluations of mixture properties. Example embodiments may provide for methods of computing the AFT values, Including all correction methods for tabulated reference properties. Example embodiments may provide for methods of performing fuel composition correction (e.g., based upon backward formulary for orifice metering) to establish expected flow element differential head given expected composition. Example embodiments may provide for comparing actual head and actual heat demand (and accounting for combustion efficiency).

Example embodiments may provide for the use of physical parameters (e.g., parameters that are directly measured by a sensor device) and/or derived parameters (e.g., parameters that are calculated from a model, parameters that are derived from tabulated reference properties, parameters that are derived from equations of state) to produce the complete set of parameters, which are then employed to compute the relevant process performance parameters for which control actions may be performed.

Example embodiments may be used to identify characteristics of each fuel (e.g., primary fuel, ignition fuel, secondary fuel), air (e.g., ambient air, flue gas) used as inputs to a boiler that uses heat to convert water into steam or heated water. The boiler used with example embodiments can have one or more burners and a furnace. Example embodiments may also identify characteristics of the ambient environment surrounding the boiler. Example embodiments can use this information to control the temperature in the boiler by controlling the flow rates of the various fuels and air for combustion in the boiler. Example embodiments can continually monitor conditions to make adjustments in real time. Example embodiments result in lowering emissions (e.g., NOx) in the flue gas that is emitted from the boiler. Example embodiments can also result in more efficient operations (e.g., less use of fuel, higher efficiency rating) of the boiler. Example embodiments can be used with new boilers or retrofit to work with existing boilers and related equipment. In some cases, no new equipment (e.g., sensor devices, valves, motors) are needed with existing boiler systems when example embodiments are used. Alternatively, some minimal amount of new equipment can be added to an existing boiler system to improve the effectiveness of example embodiments. Example embodiments may provide a number of benefits. Such benefits may include, but are not limited to, ease of use, short commissioning time (e.g., 2-4 hours), extending the life of a boiler system, flexibility, configurability, and improved compliance with applicable industry standards and regulations.

Although embodiments described herein are made with reference to example embodiments, it should be appreciated by those skilled in the art that various modifications are well within the scope of this disclosure. Those skilled in the art will appreciate that the example embodiments described herein are not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the example embodiments, equivalents of the elements shown therein will suggest themselves to those skilled in the art, and ways of constructing other embodiments using the present disclosure will suggest themselves to practitioners of the art. Therefore, the scope of the example embodiments is not limited herein.

Claims

1. A method for lowering emissions that result from fuel combustion in a boiler, the method comprising: obtaining a plurality of fuel values of fuel parameters associated with a fuel in gaseous form injected into the boiler;obtaining a plurality of air values of air parameters associated with air injected into the boiler;identifying a target temperature in the boiler at which to operate, wherein the target temperature is lower than a current temperature;identifying a fuel target flow rate and an air target flow rate based on the target temperature, the plurality of fuel values, and the plurality of air values, wherein the fuel target flow rate and the air target flow rate result in the target temperature in the boiler and in lowering the emissions from combustion in the boiler;controlling a fuel injection system to inject the fuel into the boiler at the fuel target flow rate, based on the target temperature in the boiler, without measuring an actual temperature within a burner or a furnace of the boiler; andcontrolling an air injection system to inject the air into the boiler at the air target flow rate, based on the target temperature in the boiler, without measuring the actual temperature within the burner or the furnace of the boiler.

2. The method of claim 1, wherein the lower emissions comprises NOx.

3. A combustion control system for lowering emissions that result from fuel combustion in a boiler, the system comprising a controller that is configured to: obtain, from a first sensor device, a plurality of fuel values of fuel parameters associated with a fuel in gaseous form injected into the boiler;obtain, from a second sensor device, a plurality of air values of air parameters associated with air injected into the boiler;identify a target temperature in the boiler at which to operate, wherein the target temperature is lower than a current temperature;identify a fuel target flow rate and an air target flow rate based on the target temperature, the plurality of fuel values, and the plurality of air values, wherein the fuel target flow rate and the air target flow rate result in the target temperature in the boiler and in lowering the emissions from combustion in the boiler;control a fuel injection system to inject the fuel into the boiler at the fuel target flow rate, based on the target temperature in the boiler, without measuring an actual temperature within a burner or a furnace of the boiler; andcontrol an air injection system to inject the air into the boiler at the air target flow rate, based on the target temperature in the boiler, without measuring the actual temperature within the burner or the furnace of the boiler.

4. The combustion control system of claim 3, wherein the fuel comprises a pilot fuel used to start the combustion in the boiler.

5. The combustion control system of claim 3, wherein the fuel comprises a primary fuel, wherein the primary fuel comprises natural gas.

6. The combustion control system of claim 5, wherein the fuel further comprises a pilot maintenance fuel that is mixed with the primary fuel.

7. The combustion control system of claim 6, further comprising: a third sensor device communicably coupled to the controller, wherein the third sensor device is configured to measure a second plurality of fuel values of fuel parameters associated with a second fuel injected into the boiler, wherein the second fuel comprises the pilot maintenance fuel.

8. The combustion control system of claim 7, further comprising: a valve configured to be controlled by the controller, wherein the valve regulates a second fuel target flow rate, identified by the controller, for the second fuel.

9. The combustion control system of claim 6, wherein the primary fuel, the pilot maintenance fuel, and the air are mixed and combusted in the burner of the boiler.

10. The combustion control system of claim 5, wherein the fuel further comprises a secondary fuel that is injected into the furnace of the boiler, wherein the secondary fuel comprises a sour gas.

11. The combustion control system of claim 10, wherein the fuel further comprises a tertiary fuel that is injected into the furnace of the boiler, wherein the tertiary fuel comprises a waste gas.

12. The combustion control system of claim 11, wherein the secondary fuel is injected into a first portion of the furnace, wherein the tertiary fuel is injected into a second portion of the furnace, and wherein the first portion of the furnace is closer to the burner than the second portion of the furnace.

13. The combustion control system of claim 12, wherein the air comprises ambient air and flue gas resulting from the fuel combustion in the boiler.

14. A non-transitory computer readable medium comprising computer readable program code, which when executed by a computer processor, enables the computer processor to: facilitate obtaining a plurality of fuel values of fuel parameters associated with a fuel in gaseous form injected into a boiler;facilitate obtaining a plurality of air values of air parameters associated with air injected into the boiler;facilitate identifying a target temperature in the boiler at which to operate, wherein the target temperature is lower than a current temperature;facilitate identifying a fuel target flow rate and an air target flow rate based on the target temperature, the plurality of fuel values, and the plurality of air values, wherein the fuel target flow rate and the air target flow rate result in the target temperature in the boiler and lower emissions from combustion in the boiler;facilitate controlling a fuel injection system to inject the fuel into the boiler at the fuel target flow rate, based on the target temperature in the boiler, without measuring an actual temperature within a burner or a furnace of the boiler; andfacilitate controlling an air injection system to inject the air into the boiler at the air target flow rate, based on the target temperature in the boiler, without measuring the actual temperature within the burner or the furnace of the boiler.

15. The non-transitory computer readable medium of claim 14, wherein the computer readable program code, which when executed by a computer processor, further enables the computer processor to: facilitate obtaining a plurality of ambient environment values of ambient environment parameters associated with an ambient environment surrounding the boiler, wherein the plurality of ambient environment values are used in identifying the fuel target flow rate and the air target flow rate.

16. The non-transitory computer readable medium of claim 14, wherein the fuel target flow rate and the air target flow rate are identified using an algorithm.

17. The non-transitory computer readable medium of claim 14, wherein all of the fuel is combusted in the boiler.

18. The non-transitory computer readable medium of claim 14, wherein the computer readable program code, which when executed by a computer processor, further enables the computer processor to: facilitate obtaining a second plurality of fuel values of the fuel parameters associated with the fuel injected into the boiler;facilitate identifying a difference between the second plurality of fuel values and the plurality of fuel values;facilitate identifying a revised fuel target flow rate and a revised air target flow rate based on the target temperature, the second plurality of fuel values, and the plurality of air values, wherein the fuel target flow rate and the air target flow rate result in the target temperature in the boiler and lower emissions from combustion in the boiler;facilitate controlling the fuel injection system to inject the fuel into the boiler at the revised fuel target flow rate, based on the target temperature in the boiler, without measuring the actual temperature within the burner or the furnace of the boiler; andfacilitate controlling the air injection system to inject the air into the boiler at the revised air target flow rate, based on the target temperature in the boiler, without measuring the actual temperature within the burner or the furnace of the boiler.

19. The non-transitory computer readable medium of claim 14, wherein the computer readable program code, which when executed by a computer processor, further enables the computer processor to: facilitate obtaining actual emissions data for flue gas resulting from the combustion in the boiler;facilitate identifying a difference between the actual emissions data and forecast emissions based on the fuel target flow rate and the air target flow rate;facilitate modifying an algorithm used to identify the fuel target flow rate and the air target flow rate.

20. The non-transitory computer readable medium of claim 14, wherein identifying the fuel target flow rate and the air target flow rate is further based on a configuration of the boiler.