Patent Publication Number: US-2016238244-A1

Title: Methods and apparatus to increase industrial combustion efficiency

Description:
RELATED APPLICATION 
     This patent arises as a continuation-in-part of U.S. patent application No. 14/622,247, which was filed on Feb. 13, 2015, and is hereby incorporated by reference in its entirety. 
    
    
     FIELD OF THE DISCLOSURE 
     This disclosure relates generally to combustion systems such as industrial and utility boiler plants and, more particularly, to methods, materials, and apparatus to reduce fireside slagging and fouling, fuel consumption, emissions, (including SO x , NO x , HCl, Hg, Se, As, toxic metals and acid-forming compounds) and capital cost for new plants, while recovering useful amounts of water, and increasing the overall efficiency of existing and new boiler plants. 
     BACKGROUND 
     Boiler plants are typically used to generate steam and/or electricity from combusting solid fuels such as coal. Typically, such combustion processes necessitate combustion byproducts (particulate and gaseous) are removed from the resulting flue gas to meet certain environmental and/or regulatory standards. In many combustion processes, acid-forming compounds may be present in the resultant flue gas. Such acid-forming compounds may require special materials in the boiler plant and/or precautions for acid resulting from acid-forming compounds in the flue gas. In many boiler plants, a wet flue gas desulphurization (“FGD”) process is used to remove acid-forming compounds. Though sometimes effective for SO 2  removal, they are not as effective in capturing the much lesser quantities of the acid precursor SO 3 , which can present an environmental problem. These processes are also very capital intensive, consume large quantities of water, and generate significant quantities of CaSO 3  and gypsum for sale or land fill disposal. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIGS. 1A-1C  are schematic illustrations of known boiler plants. 
         FIG. 2  is a schematic overview of an example process in accordance with the teachings of this disclosure. 
         FIG. 3A  is a schematic illustration of an example boiler plant to implement the example process of  FIG. 2 . 
         FIG. 3B  is a schematic illustration of an alternative example boiler plant to implement the process of  FIG. 2 . 
         FIG. 4  illustrates an example catalytic filter of the example boiler plants of  FIGS. 3A and 3B . 
         FIG. 5  is a detailed view of a filter element of the example catalytic filter of  FIG. 4 . 
         FIG. 6  is a flowchart representative of an example method that may be used to implement and/or control the example boiler plant of  FIG. 3A , for example. 
         FIG. 7  is a flowchart representative of another example method that may be used to implement and/or control the example boiler plant of  FIG. 3A , for example. 
         FIG. 8  is a block diagram of an example processor platform capable of executing machine readable instructions to implement the example methods of  FIGS. 6 and 7 . 
     
    
    
     The figures are not to scale. Instead, to clarify multiple layers and regions, the thickness of the layers may be enlarged in the drawings. Wherever possible, the same reference numbers will be used throughout the drawing(s) and accompanying written description to refer to the same or like parts. As used in this patent, stating that any part (e.g., a layer, film, area, or plate) is in any way positioned on (e.g., positioned on, located on, disposed on, or formed on, etc.) another part, means that the referenced part is either in contact with the other part, or that the referenced part is above the other part with one or more intermediate part(s) located therebetween. Stating that any part is in contact with another part means that there is no intermediate part between the two parts. 
     DETAILED DESCRIPTION 
     Methods, materials, and apparatus to reduce emission of particulates, toxic metals, gaseous pollutants, and condensable acid-forming compounds in flue gas from industrial combustion process equipment, such as coke calciners, iron or steel processing furnaces, incinerators, gasifiers, limestone production furnaces, refinery systems industrial ovens or furnaces and/or power plant equipment, and more specifically in boiler plant flue gas are disclosed herein. Typically, flue gas resulting from the combustion of most fuels (e.g., gas exiting a combustion chamber or furnace in a boiler plant) may contain fine ash particles, gaseous pollutants, and acid-forming compounds such as sulfur oxides and/or halogen containing compounds, etc. Such acid-forming compounds may cause damage and/or require special construction materials that may be relatively expensive, for example, to guide and/or contain the flue gas containing acid-forming compounds. In known examples, flue gases are kept above the highest dew point of the acid-forming compound(s) and/or vaporized components. In particular, the flue gas may be maintained at temperatures above approximately 320° F. (160° C.) to prevent acid-forming compounds from condensing. 
     In known examples, a flue gas desulphurization (FGD) process is used to remove a significant fraction of the acidic compounds from the flue gas. In particular, an FGD scrubber, which may utilize a spray (e.g. a spray of −325 mesh limestone slurry or Ca(OH) 2 , etc.) to remove compounds containing both sulfur and oxygen (e.g., SO x  compounds), is applied to flue gas kept at a temperature above the dew point of the acid compounds in the flue gas. Usually, the application of the spray causes the flue gas to be cooled rapidly in the FGD scrubber, thereby resulting in a significant loss of heat from the flue gas and vaporization of significant amounts of water. 
     A number of other emission control technologies (Dry Sorbent Injection and Dry Scrubbers, etc.) have been deployed that are somewhat less capital intensive and somewhat less efficient. Each of those technologies have their pros and cons and have been deployed commercially. The least costly and least capital intensive emission control technology, Furnace Sorbent Injection (FSI), has not been widely deployed, but will likely increase in use with the examples disclosed herein. In an early unsuccessful version of the technology employed, what was viewed by industry as fine powder (−325 mesh) powder was inefficient and consumed large quantities of the powdered calcium compounds and produced significant quantities of solid waste for disposal. The examples disclosed herein bypass these shortcomings by employing micronized sorbents, some of which are waste or byproducts and others are commercially available and widely used in other industries. 
     Because power plant flue gases normally contain low concentrations of condensable acids which may quickly corrode heat exchangers and ducting and force the plant off line, industry practice has been to discharge the flue gas up the stack without capturing roughly 20% of the fuel energy. Both the latent heat of the gases and the heat of vaporization for the significant amounts of water in the flue gas are normally lost. The industry has for years applied small quantities additives (primarily calcium, magnesium, and fly ash) to mitigate some of the fouling and corrosion caused by the condensable acids 
     Generally, little effort has been made in known examples to capture the bulk of acid as solids so that the temperatures can be safely lowered to make it feasible to reap the benefits of capturing a significant fraction of the wasted energy and the vaporized water. The examples disclosed herein circumvent problems encountered with the early efforts to control SO 2  emissions by furnace injection. The examples disclosed herein also provide a relatively large stoichiometric excess of micronized bases (as much as 50 to 1) to capture a significant amount or essentially all of the condensable acids as filterable solids and employs one or both of two methods, for example, to concurrently enhance capture of the SO 2 . In particular, the two methods are staged Condensing Heat Exchangers (CHX) and hot catalytic filters. The hot catalytic filters function to increase efficiency of the micronized reagent (e.g., sorbent) by increasing the residence time of the sorbent particles in the flue gas path, preferably at or near optimum operation conditions, and then once essentially all the acid gases have been removed, the supplemental condensing heat exchange surface brings the flue gas below the acid dewpoints, thereby enhancing the capture of SO x  by the sorbent. 
     The examples disclosed herein further enhance the power plant economics by supplementing commercially produced micronized CaCO 3  with waste or byproduct micronized materials such as water softening sludges, beet lime, micronized fly ash, etc. These materials may be used separately or in combination with wet processed micronized reagents converted into discrete particles for furnace injection by employing commercially available equipment such as the Hosokawa Drymeister, for example. 
     The examples disclosed herein enable reduction of acid-forming compounds in flue gas while reducing (e.g., eliminating) the need for rapid cooling of the flue gas, and reducing (e.g., eliminating) the dissipation of significant amounts of useful/usable energy during the vaporization of water, as seen in known FGD systems. The examples disclosed herein allow for less expensive materials to be used with flue gas due to effective upstream reduction (e.g., removal) of acid-forming compounds from the flue gas. Even further, the examples disclosed herein allow significant improvements in energy efficiency and, thus, boiler plant operating costs by enabling efficient recovery of heat from the flue gas by recovering heat from both the cooling of the gas and avoiding the unnecessary expenditure of energy in evaporating water, for example. The examples disclosed herein also allow recovery of heated water condensed from the flue gas to be provided after a polishing purification for various plant uses, as a boiler feed and/or a boiler feed processing system, for example, thereby allowing reduced overall water consumption, and possibly for reduced necessary heating of the water for later use. Additionally, the examples disclosed herein require a smaller footprint (e.g., are significantly more compact) than known FGD systems. Thus, the examples disclosed herein enable lower cost boiler plants and/or lower capital expenditures to build boiler plants (e.g., less expensive materials required because of effective reduction of acid-forming compounds, simpler and less bulky hardware, etc.) along with significantly reduced operating costs via energy savings and/or water recovery and thereby reduce the amount of CO 2  released per unit of energy produced by the boiler. 
     As used herein, in regards to adding a sorbent to a combustion chamber for example, “provided to” may include injecting and/or ad-mixing to fuel, combustion air and/or a mixture thereof before providing the resulting mixture to the combustion chamber and also includes direct injection into the combustion chamber. 
       FIGS. 1A-1C  are schematic illustrations of known boiler plants that have wet flue gas desulphurization (“FGD”) and separate DeNOx systems to remove acid-forming compounds and/or nitrogen-oxides from flue gas. These known boiler plants are used to remove compounds from the flue gas so that the flue gas may exit the boiler plant system to the external environment. 
     Turning to  FIG. 1A , a known selective catalytic reduction (SCR) high dust system  100  is shown. The SCR system  100  includes a steam generator (e.g., a two draft boiler)  102 , a DeNOx reactor  104 , an air preheater  106 , a dust remover  108 , an FGD scrubber  112 , and a stack (e.g., an exhaust stack, etc.)  114 . The steam generator  102  is where carbon fuels, are combusted in order to produce steam, which, in turn, is used to generate electricity by turning a steam turbine. The FGD scrubber  112  is used to reduce SO 2  and part of acid-forming compound(s) from the flue gas. It is common on most scrubbers for the SO 3  to pass through the FGD system exiting as an acid mist of fine droplets that is visible once the steam plume evaporates. The DeNOx reactor  104  is used to reduce and/or remove nitrogen oxides (NO x , mono-nitrogen oxides, etc.) from the flue gas. 
     In operation, as a result of the combustion process and fuels used in the combustion process, the resultant flue gas may contain acid-forming compounds such as sulfur oxides, hydrochloric acid (HCl) and/or halogen containing compounds, nitrogen oxides, and/or dust, etc. As the flue gas exits the steam generator  102 , ammonia (NH 3 ) is added to the flue gas prior to the flue gas entering the DeNOx reactor  104 . The ammonia typically is added to the flue gas to reduce NO 2  in the flue gas, which may result from nitrogen in the air used in combustion. Problems with airheater fouling by ammonium bisulfate are common and due in part to reaction of the excess ammonia required for NO x  control with the combustion derived SO 3 . The furnace sorbent injection of micronized carbonate disclosed herein tends to scavenge the SO 3  and mitigate the air heater fouling. The flue gas leaving the DeNOx reactor  104  is used to heat furnace combustion air, for example, by the air preheater  106 . In some known examples, the temperature of the flue gas is maintained at a higher temperature than the dew point of acid-forming compounds in the flue gas. The flue gas is then provided to the dust remover  108 , whereby dust is removed from the flue gas. Prior to entering the FGD scrubber  112 , the flue gas is kept above the highest dew point of acid-forming compounds contained within the flue gas. 
     The flue gas is then provided to the FGD scrubber  112  to remove fly ash and/or acid-forming compounds such as sulfur-dioxide (SO 2 ), for example. The flue gas is rapidly cooled in the FGD scrubber  112  to a temperature such as 175° F. (80° C.) by a spray (e.g., a spray column of an aqueous solution such as hydrated lime (Ca(OH) 2 ), etc.) that is used to remove sulfur-dioxide in the flue gas, for example. Thus, the heat energy of the flue gas is lost to the spray and, thus, lost and/or generally unrecoverable for the purposes of energy conservation. 
     The flue gas then leaves the FGD scrubber  112  and exits the SCR system  100  via the stack  114 . Because the FGD scrubber is used later in the process of the SCR system  100 , the flue gas is kept at a relatively high temperature that is above the dew point of any of the acid-forming compounds present in the flue gas. The known systems of  FIGS. 1A-1C  have numerous stages that may require significant amounts of space (e.g., have a large footprint). In known examples where the flue gas is not constantly heated, significant capital expenditures may be required (e.g., stronger and more expensive materials and/or components, etc.) to withstand the formation of acid resulting from condensation of fluid containing acid-forming compounds in these systems. 
     Turning to  FIG. 1B , a known SCR system  124 , which is an SCR low dust system and similar to the SCR high dust system  100  described above in connection with  FIG. 1A , is shown. In this known example and in contrast to the SCR high dust system  100 , the dust remover  108  is upstream relative to the DeNOx reactor  104 . In this example, a reheat of the flue gas is necessary prior to the flue gas entering the FGD scrubber  112  and, thus, requires additional energy and/or running expense. 
     Turning to  FIG. 1C , a known SCR tail-end system  140 , which is similar to the SCR high dust systems  100  and SCR low dust system  124  described above in connection with  FIGS. 1A and 1B , respectively, is shown. In this known example, the flue gas used to preheat air for the steam generator  102  by the air preheater  106  prior to flowing into the dust remover  108 . A low temperature economizer  142  is used prior to the flue gas flowing into the FGD scrubber  112 . The flue gas is then reheated at a hot steam fuel-gas preheater  144 , which may require hot steam. The numerous stages and/or cycles of cooling and reheating the flue gas may lead to significant energy losses throughout known FGD systems. 
     As set forth herein,  FIG. 2  is a schematic overview of an example process  200  in accordance with the teachings of this disclosure. In this example, fuel (e.g., solid fuel, coal, etc.)  202  is provided to a combustor (e.g., a combustion chamber, a furnace, etc.)  204  of an example boiler plant where the fuel  202  is combusted. The combustion of the fuel  202  releases energy that is used to generate steam and move a turbine, thereby generating electricity. 
     In this example, a sorbent  206 , such as calcium carbonate (CaCO 3 ), for example, is provided to (e.g., injected to, ad-mixed to or mixed with) the fuel  202  prior to the fuel  202  being combusted in the combustion chamber (e.g., a furnace sorbent injection (FSI) process). For example, the sorbent  206  may be injected or admixed to the fuel, the combustion air and/or to a mixture of fuel and combustion air provided to the combustor. As shown by the line  208 , in some examples, additionally or alternatively, the sorbent  206  is injected directly into the combustion chamber as the fuel is combusted in the combustion chamber via a direct furnace injection process, for example. Likewise, additionally or alternatively, a line  210  illustrates another example process step where sorbent may be injected into flue gas after exiting the combustion chamber via a dry sorbent injection (DSI) process, for example. In some examples, the sorbent used in a DSI process is hydrated lime. It should be noted that the examples described are not exhaustive and any appropriate process or combination of FSI and DSI processes to provide sorbent to the example process  200  may be utilized. The hot gas filter of the illustrated example is deployed not only to address NOx, but to also provide increased contact time in the optimum temperature range (e.g., above 480° F. (250° C.) 1,110° F. (600° C.), and more preferably 570° F. (300° C.)-750° F. (400° C.)) of the pollutant scavenging particles and thereby enhanced capture efficiency and utilization of the injected sorbent. A less capital-intensive bag house dust collector may also be used to increase sorbent flue gas contact, but at lower temperatures below 500° F. (300° C.) where capture reactions are slower. Substituting the bag house for the hot catalytic filter results in separating the NO x  control function from the dust collector. Though feasible, this option may be less economically attractive because two distinct stems are used instead of one and a greater space requirement. 
     Whichever option is chosen, a sorbent  206  is provided to the example process  200 , prior to a hot gas filter  212 , in which the flue gas enters, of the example boiler plant. The hot gas filter of the illustrated example may be a catalytic gas filter a ceramic catalytic gas filter, or any appropriate type of filter. In other examples, the type of filtration used after sorbent is provided may vary and, additionally or alternatively, include a dust/particle separator (e.g., a particulate removal device or stripper, a cyclone, and/or a filter stage, scrubber etc.). Additionally or alternatively, any selected combination to apply or deliver sorbent (e.g., an FSI process, a DSI process and/or a direct furnace injection process, etc.) prior to filtering hot flue gas may be applied (e.g., DSI with catalytic filtration, FSI with ceramic catalytic filtration, DSI with dust/particle separator filtration, etc.). 
     As a result of the flue gas being filtered at the hot gas filter  212 , the flue gas, in some examples, is used to provide a condensate from condensable liquids and/or vapors and/or recoverable heat energy  214 . In some examples, the condensed water from the flue gas is provided to a steam cycle after a “purity polishing step” for use as a boiler feed or for other plant use, thereby resulting in conservation of water and/or reduced water consumption of the boiler plant. In some examples, the condensate is provided to an alternate consuming process. Additionally or alternatively, the water provided to the boiler feed still retains heat and, thus, requires less heating when the water is reused (e.g., heat is recovered). 
     Alternatively, in some examples, it is advantageous to stage the condensing heat exchangers to enhance pollution control and/or avoid moisture issues in the dust collector or air heater depending on the configuration. In particular the condensing heat exchangers may have multiple stages including a first stage and a second stage. The first stage, which has materials to withstand acids, may cool the flue gas to just below the acid dew point, thereby allowing the acids and/or acid-forming compounds to condense on the sorbent particles and be removed from the system. The second stage, which has ordinary materials is upstream from the stack, is used to condense relatively clean water (e.g., water with minimal or eliminated acids and/or acid-forming compounds). 
     Both the hot gas filter and the CHXs enhance the pollutant capture performance of the sorbent. They may be used together or separate from one another. 
     In some examples, heat recovered from the condensation process is substituted for the steam used to heat boiler feed water allowing more steam to be delivered to the turbine to generate additional electricity, thereby resulting in energy recovery and/or less energy (e.g., heat energy) required to be provided to the combustion process and/or reduced operating costs. It has been determined that in some of the examples in accordance with the teachings of this disclosure that an average reduction in energy required to operate the boiler plant of significantly greater than 3% over known boiler plant systems may be seen. Additionally or alternatively, the heat recovered might be provided to the combustion chamber and/or furnace via an additional heat exchanger to pre-heat the fuel and/or combustion air. Additionally or alternatively, the heat recovered may be provided to any appropriate portion(s) of the example process  200  or, more generally, the example boiler plant or external to the boiler plant, etc. In some examples it may be beneficial to provide the recovered heat or at least a fraction of the recovered heat to a heat supply network (e.g., a long-distance or district heating), an organic rankine cycle (ORC) system, and/or an industrial heat consuming process (e.g. dryer, roaster, other ovens). 
       FIG. 3A  is a schematic diagram of an example boiler plant  300  to implement the example process  200  of  FIG. 2 . In order to more clearly illustrate the process, the figure shows components of a typical boiler as if they are external to rather than enclosed within the boiler structure. The example boiler plant  300  of the illustrated example includes a coal feed  302 , a fuel sorbent injection (FSI) device  304 , a combustion chamber (e.g., a furnace)  306  (e.g., the water walls of the furnace are for steam generation and are part of the furnace), the steam superheater and reheater heat exchangers  308 , an air preheater (e.g., an economizer)  310 , a dry sorbent injection (DSI) device  312 , an ammonia injection device  314 , a dust separation device (e.g., a catalytic hot gas filter)  320 , an ash removal mechanism  322 , a heat recovery steam generator  324 , a boiler water feed  326 , a condenser (e.g., a heat exchanger)  328 , resulting condensate  330  and a stack feed  332 . Since the ash removed from the filter will be at roughly the temperature of the entering flue gas, the heat can be returned to the system via any of the mechanisms typically used with hot ESP&#39;s to capture that energy. 
     In this example, the coal feed  302  is provided with sorbent via the FSI device  304 . In particular, solid fuel such as coal of the coal feed  302 , for example, is provided with calcium carbonate (CaCO 3 ) from precipitated or ground forms, which, for maximum pollutant capture, may be finely ground, preferably micronized under 3 microns median, or nominally minus 325 mesh for DSI. Additionally or alternatively, materials from waste processes such as fly ash, water softening sludges, sugar beet processing wastes, etc. may be used as sorbent. While coal is shown in this example, any appropriate fuel, especially liquid fuel and/or solid fuel may be used. In some examples, solid fuel is pre-mixed and/or pre-processed with the sorbent material. In this example, the coal mixed with the sorbent is combusted in the combustion chamber  306 . During the combustion process, sulfur dioxide (SO 2. ), an acid forming compound, and calcium oxide (CaO), amongst others, are formed. In this example, the combustion process occurs at greater than 570° F. (300° C.). Providing the sorbent into the combustion chamber  306  allows the sulfur dioxide to be reduced by 80% of flue gas exiting the combustion chamber  306  (e.g., a removal efficiency of approximately 80%). Additionally, providing the sorbent to the fuel allows greater effectiveness of the sorbent and/or reduced amounts of unutilized sorbent, thereby reducing the required amount of provided sorbent relative to known examples (e.g., known FGD systems, etc.). 
     The flue gas is then provided to the steam generator  308 , thereby reducing the temperature of the flue gas. More specifically, while the flue gas passes through, the boiler heat is recovered by the superheater and reheater heat exchangers of the steam generator  308 , thereby reducing the temperature of the flue gas. Next, the air preheater  310  uses the flue gas to heat air for the combustion chamber  306  and/or the steam generator  308  (e.g., a heat recovery process) after the flue gas exits the steam generator  308 . Additionally or alternatively, the flue gas is provided with sorbent via the dry sorbent injection (DSI) device  312 , which may provide hydrated lime or calcium hydroxide (Ca(OH) 2 ) to the flue gas, for example. In some examples, a reducing agent such as ammonia is provided by the ammonia injector  314  to the flue gas to reduce NO x  compounds in the flue gas by selectively converting the NO x  compounds to nitrogen and water vapor, for example. In some examples, reducing agent, and/or a liquid, liquidized, dissolved or disperged agent is provided to the flue gas. 
     Next, in this example, the flue gas is provided to the dust separation device  320 , which is a catalytic hot gas filter in this example, where SO x  is allowed to react with the sorbent (e.g., quick lime or hydrated lime) and ash (e.g., CaO, CaSO 2  and/or unreacted DSI Ca(OH) 2 ) is reduced and/or removed from the flue gas, thereby greatly reducing the amount of acid-forming SO x  compounds (e.g., SO 2 , SO 3 , etc.) in the flue gas. In particular, in this example, the amount of SO 2  is reduced to less than 1%, and the amount of SO 3  is reduced to less than 1 part per million (ppm). The ash collected from the hot gas filter may be discharged to the ash removal mechanism  322  of one of the types of recovery systems that have been developed for and deployed in conjunction with hot electrostatic precipitators (ESPs). The dust separation device  320  of the illustrated example is described in greater detail below in connection with  FIGS. 4 and 5 . This effective removal of the condensible acid compounds in the flue gas enables relatively inexpensive materials (e.g., steel, stainless steel, etc.) to be used with the flue gas, thereby reducing or eliminating the need for more expensive materials (e.g., high strength and/or acid-resistant materials or alloys are no longer required due to the effective and substantial removal of acid gas compounds). 
     In some preferred examples, the ash removal mechanism  322  comprises a back-pulsing device, whereby pulses of compressed air are injected into at least a subset of filter elements of a hot gas filter in a direction that is substantially opposite to a nominal flow direction of fluid to be filtered. For example, the pulses of compressed air will blow at least portion of the settled ash or dust off the filter elements. Alternatively or in addition, the ash removal mechanism  322  may include a mechanic and/or sonic vibration device causing at least a subset of the filter elements of the hot gas filter to vibrate at a frequency causing the ash or dust to drop-of the surface of the filter elements. In a preferred example, the sonic vibration device may include or be driven by a supersonic source. Additionally or alternatively, the ash removal mechanism  322  may include a striking or hammer device capable of acting on at least a subset of the filter elements by short tips or kicks to cause the ash or dust to fall off the surface of the filter elements. Additionally or alternatively, the ash removal mechanism  322  may comprise a suction device causing a reverse flow of a flushing medium through at least a subset of the filter elements, whereby reverse flow means a flow in the opposite direction of a nominal fluid flow through the filter elements. 
     In this example, the flue gas is then provided to the heat recovery steam generator  324 , whereby the flue gas is further cooled down. Typically the flue gas leaving the heat recovery steam generator  324  may have temperatures below 446° F. (230° C.), preferably below 392° F. (200° C.) and down to approximately 320° F. (160° C.). After leaving the heat recovery steam generator  324 , the flue gas is provided to a condenser  328  in this example. Within the condenser  328 , the flue gas is further cooled to at least a temperature below the dew point of one condensable fluid or vapor component (e.g., below at least the highest dew point of a vaporized component, especially to a temperature below the dew points of the most prominent or frequent condensable fluid or vapor components of the flue gas carrying at least 50%, especially at least 75%, preferably at least 90% of the latent thermal energy releasable by condensation, preferably to a temperature below the lowest dew point of one of its condensable fluid or vapor components). In some examples, the flue gas exiting the condenser  328  may have a temperature of approximately 140° F. (60° C.). The heat recovered from the flue gas at the steam generator  324  and/or the condenser  328  may be used and/or provided to other portions of the example boiler plant  300  such as the combustion chamber  306  and/or the steam generator  308 , thereby reusing energy that would have been otherwise lost and, thus, reducing overall energy needs of the boiler plant  300  and, thus, also reducing operating costs of the boiler plant  300 . As a result, this reduction in energy needs also allows the boiler plant  300  to have a reduced carbon dioxide footprint per unit of electrical energy produced. Further, because acid-forming compounds in the flue gas have been significantly reduced, the flue gas may be cooled significantly during a heat recovery process and relatively inexpensive materials may be used and/or implemented in the condenser  328  or any heat exchangers, for example. 
     In a boiler plant  300  according to the example of  FIG. 3A , where the flue gas temperature after the recovery steam generator  324  is below 446° F. (230° C.), the condenser  328  and/or a section of the condenser  328  may be produced with synthetic materials or plastics. The condenser  328  may be construed in close relation and/or similar to a plastic evaporator known from WO 2010/079148 A1, which is hereby incorporated by reference, and/or a heat exchanger, especially a tube bundle heat exchanger known from WO 2009/007065 A1, which is also hereby incorporated by reference. A condenser  328  in accordance with this approach further decreases costs of the system due to the use of cheaper and/or lighter materials than steel or other metals. Furthermore, in some examples, a synthetic or plastic material may also be robust enough against residual acid-forming components remaining in the flue gas. 
     Additionally or alternatively, heated water condensate  330  condensed from the condenser  328  is provided after polishing purification, for example, to other portions of the boiler plant  300  such as the boiler water feed  326  to reduce a need for water to be provided to the boiler plant  300 , thereby reducing overall water consumption and/or recovering heat energy to reduce overall operating costs, for example. In particular, the effective removal of acid-forming compounds in the flue gas and, thus, the resultant condensed liquid facilitates the reuse of the water. Additionally, the heat of the condensed water may be recovered for the boiler feed (e.g., utilized in the boiling process of the steam generator  308 ), for example. 
     While the illustrated example of  FIG. 3A  describes a boiler plant, any of the examples disclosed may instead be applied to a kiln, a coke calciner, a steel furnace, a refinery and/or ore processing, etc. In other words, .any of the examples disclosed herein including the examples disclosed with respect to the example boiler plant  300 , may be applied to other appropriate types of applications. Further, any other appropriate gas filtration systems may be used instead. 
       FIG. 3B  is a schematic illustration of an alternative example boiler plant  333  to implement the process of  FIG. 2 . The example boiler plant  333  is similar to the boiler plant  300 , but includes a side stream. In this example, at least the dust separation device  320  and/or the heat recovery steam generator  324  and/or the condenser  328  is bypassed by the side stream, whereby the side stream is directed by a bypass or shunt pipe, or more generally a branch line. Preferably, the side stream is split off the flow of the exhaust gas after the exhaust gas has left the furnace  306  or after a passage of the exhaust gas through the steam superheater and reheater heat exchangers  308  or the air preheater  310 . In this example, the flow of the side stream is controlled by a valve  334  in the branch line to allow treatment of a partial flow of the flue gas for complete acid compound removal and condensation of its moisture. After treatment, the partial flow is provide back to (e.g., mixed with) the main flue gas flow before entering the stack. In some examples, especially retrofitting such branch lines to combustion chambers, combustion systems and/or boiler plants with existing air pollution control equipment, the branch lines may utilize or include already existing exhaust pipe or exhaust line. 
     Such examples are especially advantageous for retrofit in or to combustion chambers, combustion systems and/or boiler plants with existing air pollution control equipment, such as an instance electrostatic precipitator (ESP)  336  used for de-dusting and/or dust reduction, for example. Additionally or alternatively, the existing air pollution control equipment may comprise a flue gas scrubber, exhaust scrubber, exhaust gas conditioner, electro-magnetic separator, a stripper and/or a cyclone, for example, or any other appropriate air pollution control equipment. While the electrostatic precipitator  336  is used in this example, any of the above-mentioned air pollution control equipment may be used. These examples allow effective removal of SO 2  at reduced sorbent consumption as well as partial NO x  reduction, while simultaneously increasing the performance of the existing air pollution control equipment, which can be continuously operated in partial load. Additionally or alternatively, such examples are especially advantageous for retrofit with existing NO reduction equipment, such as a selective non-catalytic reduction (SNCR) appliance or a SNCR system, for example. Such examples may allow effective reduction of ammonia feed rate as well as ammonia slip to the stack. 
     Additionally, energy consumption of the main flue gas fan  338  is reduced at partial load, while a fan (e.g., a relatively smaller fan, etc.)  340  with lower energy consumption can be used for the side stream at lower temperature. 
     In some examples, an additional gas valve may be provided after the gas fan  338  to prevent a backflow into the branch line or to allow for improved control of the flow of the side stream. While the DSI device  312  is shown in the illustrated example, in some examples, the DSI  312  device may not be provided because the dust separation device  320  provides the additional contact time needed for the CaO generated in the furnace will be provided by the dust separation device  320  while allowing reduced overall use of reagents and/or lower cost reagents. 
       FIG. 4  illustrates the example dust separation device  320 , which is a catalytic filter in this example, of the example boiler plant  300  of  FIG. 3A  and the example boiler plant  333  of  FIG. 3B . The example dust separation device  320  has an inlet  402 , a filtration area  404 , a valve  405 , filter elements  406 , a clamping plate  408 , a manifold  409 , a jet tube  410 , a plenum  412  and an outlet  416 . In this example, the filter elements  406  are positioned and/or held in place by the clamping plate  408 , which has openings to allow the flue gas exiting the filter elements  406  (e.g., the filtered flue gas) to flow into the plenum  412 . 
     In operation, flue gas of the illustrated example enters the inlet  402  of the dust separation device  320  and moves into the filtration area  404 . In some examples, the dust separation device  320  operates at a temperature between 570-700° F. (300-400° C.). The flue gas then enters the filter elements  406 , whereby compounds such as ash and CaO, CaSO 4 , CaSO 3 , and/or Ca(OH) 2  are filtered out of the flue gas to greatly reduce and/or effectively eliminate SO x  compounds in the flue gas. In this example, the manifold  409  and the jet tube  410  are used to control the flow of pulse air to frequently clean the filter elements from compounds such as ash (e.g., CaO, CaSO 3  and/or Ca(OH) 2 ). After the filtered flue gas flows into the plenum  412 , the flue gas exits the dust separation device  320  via the exit  416 . 
     In some examples, the ash built up on the filter elements  406  falls to the bottom of the filtration area  404  to the valve  405 , where the ash may exit the dust separation device  320 . As mentioned above, in some examples, the filter elements  406  and/or a subset (e.g., a portion) of the filter elements  406  are back-pulsed (e.g., periodically back-pulsed and/or back-pulsed based on condition(s) of the filter elements  406 , etc.) to cause the ash to fall into the valve  405  for removal from the boiler plant  300 , for example, and/or to control the residence time of the sorbent. In some examples, a subset or portion of the filter elements  406  are back-pulsed and/or alternating portions of the filter elements  406  are back-pulsed to remove filter cake from the filter elements  406 . Alternatively or in addition, the filter elements  406  are provided with an ash removal device (e.g. mechanic and/or sonic such as a supersonic ash remover, etc.), such as the ash removal devices described in conjunction with the ash removal mechanism  322  described above in connection with  FIG. 3A , to cause the ash to fall away from the filter elements  406  when activating the ash removal device on the filter elements  406  and/or a subset of the filter elements  406 . 
       FIG. 5  is a detailed view of the example filter element  406  of the example catalytic filter of  FIG. 4 . The filter element  406  includes a surface barrier  502 , fibers  504  and catalyst particles  506  within the fibers  504 . In other examples, the filter element  406  contains additional layers, fibers and/or catalyst materials, etc. Additionally or alternatively, the filter element  406  may be fabric. 
     In operation, alkali aerosols  508  of the illustrated example that are contained in flue gas move in a direction generally indicated by an arrow  510 , thereby forming a filter cake  512  as the flue gas flows through the surface barrier  502 . The filter cake  512  of the illustrated example increases the residence time of the sorbent to increase removal efficiency of compounds such as SO x , halogens, and toxic metals (e.g., Hg, As, and Se) by the sorbent. In preferred examples, the controlling of the ash layer on the filter elements  406  or the filter cake  512  via a dedicated activation of the back-pulsing and/or ash removal device can allow for a control of the removal efficiency of the injected sorbent. In particular, the removal efficiency will be influenced by the surface area of the injected sorbents and may range from 90 to 99%, for example. As the flue gas of the illustrated example flows through the fibers  504 , additional SO x  molecules are removed. Next, in this example, the flue gas flows exits the filter element  406  and, more generally, the dust separation device  320  and flows through the remaining portions of the example boiler plant  300 . In some examples, the filter cake also facilitates removal of NO x  compounds by increasing removal efficiency of these compounds when ammonia is provided to the flue gas. 
     Flowcharts representative of example machine readable instructions for implementing or controlling the example boiler plant  300  of  FIG. 3A  or the example boiler plant  333  of  FIG. 3B  are shown in  FIGS. 6 and 7 . Controlling the example boiler plant  300  or the example boiler plant  333  may be accomplished by manually adjustable equipment, such as a rotary valve to provide sorbent at a relatively constant rate to comply with desired SO x  reduction at the outlet of a furnace (e.g., the furnace  306 ), which has to be occasionally verified at the exit flow of the furnace and continuously verified in the exit flow of the filter by, for instance, EPA Test Methods  6 C,  8  and  8 A. Such controls may additionally exist by a valve controlling the flow of a reducing agent, such as ammonia or urea, at a rate adjusted to the mass flow of the flue gas to be continuously verified by for instance EPA Test Method 2 and  2 F and to the concentration of NO x  to be verified by for instance EPA Test Method 7 upstream of the injection point in order to comply with the desired concentration of NO x  to be verified by, for instance, EPA Test Method 7 in the exit flow of the filter. Such controls may additionally use membrane valves controlling the time of flow of pressurized reverse pulse air to a relatively clean side of the filter, which is verified by a maximum allowable difference of the pressure between the inlet flow and the outlet flow of the filter. Such controls may additionally result from a valve controlling the flow of water to the tube inlet of a condensing heat exchanger to be verified by the measurement of a minimum allowable temperature of the exit flow of the shell side of the heat exchanger. Such controls may additionally exist with a valve controlling the height of a liquid filling in the liquid collector of the shell side of the heat exchanger. 
     In the examples of  FIGS. 6 and 7 , the machine readable instructions comprise a program for execution by a processor such as the processor  812  shown in the example processor platform  800  discussed below in connection with  FIG. 8 . The program may be embodied in software stored on a tangible computer readable storage medium such as a CD-ROM, a floppy disk, a hard drive, a digital versatile disk (DVD), a Blu-ray disk, or a memory associated with the processor  812 , but the entire program and/or parts thereof could alternatively be executed by a device other than the processor  812  and/or embodied in firmware or dedicated hardware. Further, although the example program is described with reference to the flowcharts illustrated in  FIGS. 6 and 7 , many other methods of implementing the example boiler plant  300  may alternatively be used. For example, the order of execution of the blocks may be changed, and/or some of the blocks described may be changed, eliminated, or combined. 
     As mentioned above, the example processes of  FIGS. 6 and 7  may be implemented using coded instructions (e.g., computer and/or machine readable instructions) stored on a tangible computer readable storage medium such as a hard disk drive, a flash memory, a read-only memory (ROM), a compact disk (CD), a digital versatile disk (DVD), a cache, a random-access memory (RAM) and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and/or for caching of the information). As used herein, the term tangible computer readable storage medium is expressly defined to include any type of computer readable storage device and/or storage disk and to exclude propagating signals and to exclude transmission media. As used herein, “tangible computer readable storage medium” and “tangible machine readable storage medium” are used interchangeably. Additionally or alternatively, the example processes of  FIGS. 6 and 7  may be implemented using coded instructions (e.g., computer and/or machine readable instructions) stored on a non-transitory computer and/or machine readable medium such as a hard disk drive, a flash memory, a read-only memory, a compact disk, a digital versatile disk, a cache, a random-access memory and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and/or for caching of the information). As used herein, the term non-transitory computer readable medium is expressly defined to include any type of computer readable storage device and/or storage disk and to exclude propagating signals and to exclude transmission media. As used herein, when the phrase “at least” is used as the transition term in a preamble of a claim, it is open-ended in the same manner as the term “comprising” is open ended. 
       FIG. 6  is a flowchart representative of an example method that may be used to implement and/or control the example boiler plant  300  of  FIG. 3A , for example. The example method begins at block  602  where fuel is being provided to a combustion chamber (e.g., a furnace) such as the combustion chamber  306  of an example boiler plant (e.g., the boiler plant  300 , the boiler plant  333 ) (block  602 ). In some examples, sorbent such as calcium carbonate is provided to the fuel and/or mixed in with the fuel prior to the fuel and/or the sorbent being combusted in the combustion chamber. In some examples, the fuel is pre-processed with sorbent (e.g., manufactured with sorbent) prior to the sorbent being provided to the combustion chamber. In some examples, the amount of sorbent provided is adjusted by the amount of SO x  in the flue gas. Additionally or alternatively, the amount of sorbent added may be based on concentration differences of SO x  at different stages of the boiler plant  300  and/or a pressure drop of a hot gas filter of the boiler plant  300 . 
     Sorbent and/or sorbent mixed with fuel (e.g., solid fuel, etc.) is then provided to the combustion chamber (block  604 ). Additionally or alternatively, sorbent is injected directly into the combustion chamber when the fuel is being combusted (e.g., a direct furnace injection process). Next, the fuel is combusted (block  606 ) to produce steam to drive a generator, for example. In some examples, additionally or alternatively, a dry sorbent is provided and/or injected into flue gas exiting the combustion chamber (e.g., a DSI process, etc.) (block  608 ). In particular, the dry sorbent provided to the flue gas may be calcium hydroxide (Ca(OH) 2 ). In some examples, ammonia (NH 3 ) is added to the flue gas to facilitate removal of NO x  from the flue gas (e.g., a de-NO x  process) (block  610 ). 
     Next, the flue gas is provided to and/or flows into a hot gas filter. In this example, the flue gas is provided to a catalytic filtration system such as the dust separation device  320  described above in connection with  FIGS. 3A and 4  for removal SO x  compounds, NO x  compounds and/or ash (block  612 ). In this example ash caked on filter elements of the catalytic filtration system is removed by back-pulsing the filter elements (block  614 ). In some examples, the flue gas exiting the hot gas filter is provided to a heat recovery steam generator (e.g., the heat recovery steam generator  324 ) (block  616 ) 
     In this example, liquid (e.g., water, etc.) is condensed from the flue gas (block  618 ). This condensation process may occur by rapidly cooling the flue gas, for example. In some examples, heat from the flue gas is recovered during the condensation process and provided and/or directed towards the combustion chamber (e.g., an energy recovery system, etc.) to reduce the amount of provided energy necessary for the combustion chamber, thereby reducing the overall energy expenditure of the boiler plant. 
     If it is determined that the process is not to end (block  620 ), the liquid and/or water condensed from the flue gas may be provided to a boiler feed (block  624 ) and the process is restarted (block  602 ). In some examples, the condensed liquid and/or water is further processed (e.g., the condensed liquid undergoes a neutralization process) prior to being reintroduced into the boiler plant process. Alternatively, if it is determined that the process is to end (block  620 ), the process ends (block  622 ). 
       FIG. 7  is a flowchart representative of another example method that may be used to implement and/or control the example boiler plant  300  of  FIG. 3A , for example. The example method begins at block  702  where fuel (e.g., solid fuel, coal, etc.) provided to a boiler plant (e.g., the boiler plant  300 , the boiler plant  333 ) is about to be combusted to power a steam generator. In this example, sorbent (e.g., calcium carbonate) is provided to a combustion chamber (e.g., a furnace) via an FSI process, for example (block  704 ). Additionally or alternatively, sorbent (e.g., dry sorbent) is provided to flue gas exiting the combustion chamber (block  706 ) and/or ammonia is provided to the flue gas (block  708 ). In some examples, the amount of sorbent provided is adjusted by the amount of SO x  in the flue gas. Additionally or alternatively, the amount of sorbent added may be based on concentration differences of SO x  at different stages of the boiler plant  300  and/or a pressure drop of a hot gas filter of the boiler plant  300 , for example. 
     In this example, the flue gas from the combustion chamber is then provided to a catalytic filter such as the dust separation device  320  described above in connection with  FIGS. 3A and 4  (block  710 ). 
     Next, in this example, it is determined whether the catalytic filter and/or filter elements of the catalytic filter require cleaning and/or removal of filter cake (e.g., ash filter cake) from one or more filter elements (block  712 ). Such a determination may occur via a hot gas filter controller  836  described below in connection with  FIG. 8 . The catalytic filter cleaning may occur at time intervals that may be regular or irregular, and/or determinations based on sensor measurements (e.g., from optical sensors, weight sensors and/or flow rate sensors, etc.). 
     If it is determined that the catalytic filter of the illustrated example requires cleaning and/or automated cake removal (block  712 ), in this example, the filter elements and/or a portion of the filter elements are back-pulsed and/or displaced to allow the filter cake to fall within the catalytic filter and, thus, removed from the catalytic filter via an opening or valve, for example ( 714 ). In some examples, back-pulsing of the hot gas filter (e.g., frequency, peak pressure, etc.) may be varied in relation to SO x -concentration-difference and/or pressure drop(s) within or between an inlet and an outlet of the hot gas filter. In some examples, the flue gas is then provided to a heat recovery steam generator (block  716 ) and liquid and/or water is condensed from the flue gas (block  718 ) and may be provided to a boiler feed of the boiler plant. 
     In this example, it is then determined whether an amount and/or frequency of sorbent provided to the combustion chamber needs to be adjusted (block  720 ). This determination may be based on steam generator needs, flue gas flow rate, fuel delivery rate, fuel flow rate, and/or type of fuel being combusted, etc. In particular, a sorbent rate controller  834  described below in connection with  FIG. 8  may be used to make the determination. If it is determined that the amount and/or frequency of sorbent to provided is to be adjusted (block  720 ), the amount and/or frequency of sorbent provided is adjusted (block  722 ) and the process repeats (block  702 ). The amount and/or frequency of sorbent provided may be adjusted through changing the amount of sorbent provided to the fuel, the amount of sorbent provided to the combustion chamber and/or an amount of sorbent provided to the flue gas via a dry sorbent injection (DSI) process, for example. In examples where sorbent is provided at multiple stages and/or locations, the control of sorbent delivery (e.g., frequency and/or amount of sorbent) at each of the stages and/or locations may be independently controlled by a controller (e.g., the sorbent rate controller  834 ). Independent control of sorbent may also allow greater use or utilization of the sorbents and/or reduce the amount of sorbent wasted, thereby reducing overall operating costs of the boiler plant. If the amount and/or frequency of sorbent is not to be adjusted (block  720 ), the process repeats (block  702 ). 
       FIG. 8  is a block diagram of an example processor platform  800  capable of executing the instructions of  FIGS. 6 and 7  to implement the example boiler plant  300  of  FIG. 3A  or the example boiler plant  333  of  FIG. 3B , for example. The processor platform  800  can be, for example, a server, a personal computer, a mobile device (e.g., a cell phone, a smart phone, a tablet such as an iPad™), a personal digital assistant (PDA), an Internet appliance, a DVD player, a CD player, a digital video recorder, a Blu-ray player, a gaming console, a personal video recorder, a set top box, or any other type of computing device. 
     The processor platform  800  of the illustrated example includes a processor  812 . The processor  812  of the illustrated example is hardware. For example, the processor  812  can be implemented by one or more integrated circuits, logic circuits, microprocessors or controllers from any desired family or manufacturer. 
     The processor  812  of the illustrated example includes a local memory  813  (e.g., a cache). The processor  812  includes the sorbent rate controller  834  and the hot gas filter controller  836 . The processor  812  of the illustrated example is in communication with a main memory including a volatile memory  814  and a non-volatile memory  816  via a bus  818 . The volatile memory  814  may be implemented by Synchronous Dynamic Random Access Memory (SDRAM), Dynamic Random Access Memory (DRAM), RAMBUS Dynamic Random Access Memory (RDRAM) and/or any other type of random access memory device. The non-volatile memory  816  may be implemented by flash memory and/or any other desired type of memory device. Access to the main memory  814 ,  816  is controlled by a memory controller. 
     The processor platform  800  of the illustrated example also includes an interface circuit  820 . The interface circuit  820  may be implemented by any type of interface standard, such as an Ethernet interface, a universal serial bus (USB), and/or a PCI express interface. 
     In the illustrated example, one or more input devices (e.g., sensors)  822  are connected to the interface circuit  820 . The input device(s)  822  permit(s) a user to enter data and commands into the processor  812 . The input device(s) can be implemented by, for example, an audio sensor, a microphone, a camera (still or video), a keyboard, a button, a mouse, a touchscreen, a track-pad, a trackball, isopoint and/or a voice recognition system. 
     One or more output devices  824  are also connected to the interface circuit  820  of the illustrated example. The output devices  824  can be implemented, for example, by display devices (e.g., a light emitting diode (LED), an organic light emitting diode (OLED), a liquid crystal display, a cathode ray tube display (CRT), a touchscreen, a tactile output device, a printer and/or speakers). The interface circuit  820  of the illustrated example, thus, typically includes a graphics driver card, a graphics driver chip or a graphics driver processor. 
     The interface circuit  820  of the illustrated example also includes a communication device such as a transmitter, a receiver, a transceiver, a modem and/or network interface card to facilitate exchange of data with external machines (e.g., computing devices of any kind) via a network  826  (e.g., an Ethernet connection, a digital subscriber line (DSL), a telephone line, coaxial cable, a cellular telephone system, etc.). 
     The processor platform  800  of the illustrated example also includes one or more mass storage devices  828  for storing software and/or data. Examples of such mass storage devices  828  include floppy disk drives, hard drive disks, compact disk drives, Blu-ray disk drives, RAID systems, and digital versatile disk (DVD) drives. 
     The coded instructions  832  of  FIGS. 6 and 7  may be stored in the mass storage device  828 , in the volatile memory  814 , in the non-volatile memory  816 , and/or on a removable tangible computer readable storage medium such as a CD or DVD. 
     From the foregoing, it will be appreciated that the above disclosed method and apparatus allow boiler plants to have reduced building and/or construction costs (e.g., capital costs, material costs, etc.) and also allow reduced operating costs and/or greater efficiency (e.g., energy per unit of fuel consumed, etc.) of the boiler plants. The examples disclosed herein also allow boiler plants to have smaller footprints (e.g., have reduced necessary space) and may also reduce the carbon dioxide output per unit of energy produced (e.g., a relatively low carbon footprint, etc.). 
     The examples disclosed herein present implementation of the technology of this patent with respect to new power plants, however, the examples disclosed herein are suitable for retrofits including those with existing wet FGD systems, in which efficiency enhancement(s) may be desired. In an example retrofit, the filtration and cooling of sorbent provided flue gas upstream from the scrubber may both recover more energy, reduce water evaporation, and/or reduce the load on the wet FGD. 
     Although the examples described herein demonstrate and disclose examples of boiler plant applications, the scope of coverage of this patent is not limited to boiler plants. The teachings of the examples disclosed herein can be applied in analogous way to other industrial combustion processes or industrial systems based on or working with combustion processes for burning fuels, especially carbon-based fuels, which cause emission of particulates, toxic metals, gaseous pollutants, and/or condensable acid-forming compounds in their resulting flue gas. In numerous types of industrial combustion of fuel, especially carbon-based fuels, the overall efficiency in energy consumption and emissions control can be enhanced by applying the teaching disclosed herein. Although certain example methods, apparatus and articles of manufacture have been disclosed herein, the scope of coverage of this patent is not limited thereto. On the contrary, this patent covers all methods, apparatus and articles of manufacture fairly falling within the scope of the claims of this patent.