REDUCTION OF MERCURY FROM A COAL FIRED BOILER

Abstract

A method and system are disclosed for achieving reduced mercury emissions from a power plant at a minimum cost. The parameters of the combustion chamber and a sorbent injector are manipulated to control the residual carbon in ash and the injected sorbent. These two elements combine to reduce mercury in the exhaust gas to an acceptable level.

Description

FIELD OF THE INVENTION

The present invention relates to coal fired boiler systems and more particularly to the reduction of mercury emissions from such a system.

DESCRIPTION OF THE PRIOR ART

Mercury (Hg) is identified as a hazardous air pollutant and is one of the most toxic volatile metals in the atmosphere. Elemental mercury vapor can be widely dispersed from emission sources. Other forms of mercury pollutants include organic and inorganic compounds that accumulate in plants and animals. Mercury is a constituent part of coal mineral matter. Its emission from coal-fired power plants is suspected to be a major source of environmental mercury.

Various “post combustion” techniques can be employed to reduce mercury from the emissions of a coal-fired power plant. Activated Carbon Injection (ACI) is one of many “post combustion” techniques available for controlling mercury emissions from coal-fired power plants. The ACI technique is accomplished by injecting activated carbon into the flue gas stream. The vaporized mercury is absorbed by the activated carbon which, because it is a particulate, is then removed by downstream particulate control equipment. A few small scale or full-scale tests of the ACI technique have been conducted at various coal fired power plants such as the WEPCO Pleasant Prairie Power Plant. These tests have shown that mercury can be successfully captured using the ACI technique. The use of injected carbon as a sorbent, however, is quite costly as the cost of sorbent material represents about 60% to 70% of the total cost of the mercury removal process. While ACI is currently favored as a method to capture mercury, other “post combustion” techniques are likely to be developed in the future.

Other studies have been conducted to determine the effectiveness of mercury reduction from the Residual Carbon in Ash (RCA) that normally results from the combustion process. RCA is defined as that portion of carbon from the fuel source (coal) that has not fully reacted with oxygen in the combustion chamber. RCA is sometimes referred to as Carbon In Ash (CIA) or Unburned Carbon (UBC) and is typically measured as a percent (%) (carbon mass/total ash mass=% CIA). Depending on a range of factors including coal type, temperature in the reaction zone and local turbulence, the RCA can effectively sequester between 1% and 60% of the mercury.

Thus, the total sequestrating material available for mercury removal comes from two sources. The RCA occurs in the combustion chamber, and various post combustion sorbents (PCS), of which ACI has the highest current market acceptance, is added after combustion. The optimal contribution from the post combustion sorbent depends on the carbon content within the fly ash (RCA), since this provides initial capture, which varies as a function of other process conditions. The other process conditions include those factors that affect the optimal absorption of mercury by PCS methods including local gas temperature and turbulence levels in the reaction zone among others. Therefore, the optimum PCS contribution to total mercury removal is necessarily dependent on the absorption of mercury from the combustion RCA.

Therefore, it is desirable to automate the optimized or balanced contribution of PCS and RCA to overall mercury reduction to thereby minimize sorbent use and achieve reduced cost for removal of the mercury.

SUMMARY OF THE INVENTION

In accordance with one aspect of the present invention, a system for controlling a power generating facility is provided that includes a combustion chamber and a post combustion sorbent adding device, the combustion chamber emitting exhaust gas. The system includes a processor, one or more storing units for storing signals, and software program instructions which are stored in one or more of the storing units and when executed by the processor cause the system to perform a method. A measurement is received indicative of the amount of residual carbon in ash within the exhaust gas. A measurement is received indicative of the amount of mercury within the exhaust gas. A measurement is received indicative of combustion chamber efficiency. An economic value is assigned to the boiler efficiency. An economic value is assigned to a sorbent. An economic value is assigned to the residual carbon in ash. A predetermined target mercury level is set for the exhaust gas. A target amount is determined of the sorbent to be added to the exhaust gas and a target amount of the residual carbon in ash to be formed in the combustion chamber based upon a balancing of the economic value assigned to the boiler efficiency, the economic value of the sorbent and the economic value of the residual carbon in ash. The target amounts of the sorbent and the residual carbon in ash correlate to the most cost effective ratio of sorbent to residual carbon in ash. The controls of the combustion chamber and the post combustion sorbent adding device are then manipulated in accordance with the target sorbent and residual carbon in ash.

In accordance with another aspect of the present invention, a method of controlling a power generating facility is provided. The power generating facility includes a combustion chamber and a post combustion sorbent adding device, wherein the combustion chamber emits exhaust gas. A measurement is received indicative of the amount of residual carbon in ash within the exhaust gas. A measurement is received indicative of the amount of mercury within the exhaust gas. A measurement is received indicative of combustion chamber efficiency. An economic value is assigned to the boiler efficiency. An economic value is assigned to a sorbent. An economic value is assigned to the residual carbon in ash. A predetermined target mercury level is set for the exhaust gas. A target amount is determined of the sorbent to be added to the exhaust gas and a target amount of the residual carbon in ash to be formed in the combustion chamber based upon a balancing of the economic value assigned to the boiler efficiency, the economic value of the sorbent and the economic value of the residual carbon in ash. The target amounts of the sorbent and the residual carbon in ash correlate to the most cost effective ratio of sorbent to residual carbon in ash. The controls of the combustion chamber and the post combustion sorbent adding device are then manipulated in accordance with the target sorbent and residual carbon in ash.

In accordance with yet another aspect of the present invention, a system for controlling a power generating facility is provided. The system includes a combustion chamber, the combustion chamber emitting exhaust gas. The system includes a first reaction zone located in the combustion chamber. A sorbent injector is located downstream of the first reaction zone. A second reaction zone is located downstream of the sorbent injector. A mercury analyzer is located downstream of the second reaction zone. A processor is provided along with one or more storing units for storing signals. Software program instructions are stored in one or more of the storing units and when executed by the processor cause the system to perform a method. Residual carbon in ash is produced in the first reaction zone. A sorbent is injected at the second reaction zone. The amount of mercury in the exhaust gas is measured at the mercury analyzer. The cost of the sorbent is determined. The cost of the residual carbon in ash is determined. A predetermined target mercury level is set for the exhaust gas at the mercury analyzer. A rate to inject the sorbent and a target amount of the residual carbon in ash to be formed in the first reaction zone is determined based upon a balancing of the cost of the residual carbon in ash and the cost of the sorbent. The controls of the combustion chamber and the sorbent injector are manipulated in accordance with the determined sorbent injection rate and the target residual carbon in ash.

DESCRIPTION OF THE DRAWING

FIG. 1 shows a typical configuration of a coal-fired steam generator that has a mercury control system.

FIG. 2 shows a model for the rate of mercury removal from the emissions of the coal-fired power plant.

FIG. 3 shows a block diagram of a closed loop model based controller based on the model of FIG. 2 that optimizes the mercury removal process and the boiler efficiency.

FIG. 4 shows a typical on-line system in which the mercury emissions reduction procedure of the present invention can be used.

DETAILED DESCRIPTION

FIG. 1 depicts a generating system 10 including a coal fired steam generator 12 with a mercury control system 14. This system includes some components, described below, to facilitate mercury removal and optimization. The letters BE shown in the steam generator 12 reference a real time methodology utilized to calculate Boiler Efficiency (BE). The most common and accepted method of calculating BE is by the use of ASME standards. Significant in that calculation for the present invention are the efficiency considerations as defined by the Dry Gas Losses and Unburned Carbon (UBC). For the purposes of describing the present invention, UBC and RCA are the same.

The letters TE shown at the combustion gas outlet 12b of steam generator 12 reference a measurement of the temperature of the combustion gas in the proximity of the PCS. In the zone 14a where the PCS reacts with the mercury in the exhaust gas of the coal-fired steam generator 12, certain process measurements are monitored for each of the PCS methods and optimized to improve the absorption effect of each of the various PCS methodologies. These process measurements include but are not limited to gas temperature, flow rates and turbulence factors and are measured by appropriate and well known instruments in addition to the TE measurement.

The mercury control system 14 is positioned at the combustion gas outlet 12b of steam generator 12. The generation system 10 includes a first and a second mercury sequestration reaction zone 12a and 14a. The first mercury sequestration reaction zone 12a is inside the steam generator 12, wherein the RCA is formed to sequester mercury. The second mercury sequestration reaction zone 14a is downstream of the steam generator 12, in the mercury control system 14.

Mercury control system 14 includes in the embodiment shown in FIG. 1, the two Mercury Analyzers 16 indicated by the letter M in FIG. 1. Analyzer 16 may be an actual device, or a Virtual Online Analyzer (VOA) which measures before and after the mercury sequestration reaction zones either the actual or predicted level of mercury to judge the relative effectiveness of the various mercury absorption stages. Thus the first analyzer 16, just after first reaction zone 12a, measures the actual or predicted level of mercury after the first reaction zone 12a and the second analyzer 16 just after second reaction zone 14a measures the actual or predicted level of mercury after second reaction zone 14a.

Mercury control system 14 also includes a sorbent injector 18 and particle size detector 19. Sorbent injector 18 introduces a mercury sorbent material into the gas flow. Sorbent material may include, for example ACI.

The other components shown in FIG. 1 are those that make up a typical coal fired steam generator. These components include: the boiler or combustion chamber 12e where the first mercury sequestration reaction zone 12a is located and fuel and air are mixed and combusted; various heat absorption devices 12c and 12d that transfer the heat derived from the combustion of the fuel and the air into a secondary medium like water or steam, so that this fluid can be used to provide mechanical work, such as heating a building, or turning a turbine to generate electricity; a device to remove fly ash from the flue gas stream such as an Electrostatic Precipitator (ESP) 10a; and a stack or chimney 10b which provides a convenient location to exit the flue gas from generation system 10 and disperse into the atmosphere away from humans.

Referring now to FIG. 2, there is shown a model 20 for the rate of mercury removal from the emissions of the coal-fired power plant. Model 20 includes a boiler model 22 and a mercury removal model 24. The inputs to the boiler model 22 are the boiler combustion control variables with the greatest effects on UBC and BE values. These variables include, but are not limited to, temperature, feed rate and air distribution information.

The selected variables vary as a function of fuel type and firing system configuration. Final selection of the boiler combustion control variables to be the inputs to model 22 is based on field testing and the use of empirical data. The output of the boiler model 22, which is input to the mercury removal model 24, includes the carbon content (RCA) and BE as well as other outputs that may vary as a function of fuel type and the firing system configuration of the boiler 12. RCA is primarily derived from the use of an On Line UBC instrument. One example of such an instrument is the CIA instrument sold by ABB whose function is described in commonly owned U.S. Pat. No. 6,490,909, the disclosure of which is incorporated herein by reference. This on line measure of carbon density and ash density at the boiler outlet 12b of FIG. 1 is used in a calculation in the model 22 that includes compensation for changes in the gas mass flow that occur as part of normal boiler operations.

The other input to model 24 is PCS 26 of which ACI is believed to be one of the most common mercury capture methods. Thus how much mercury has been removed at the first stage, boiler outlet 12b of FIG. 1, affects the use of sorbent from PCS. The mercury removal rate at the boiler outlet 12b depends on a number of variables, including the content of the carbon in fly ash and combustion conditions.

With the inputs described above, model 24 provides both a current prediction of the mercury removal rate and a future prediction as to what that rate will be, given the current conditions fed from model 22 and PCS 26. For example, if certain boiler related conditions were to vary, model 22 would provide input into model 24 that the mercury removal rate from the boiler 12 will change. For example, if the input from model 22 is that the mercury removal rate from the boiler will change toward less removal, then given this information, and the current status of the mercury removal based on PCS 26, the mercury removal rate output from model 24 is revised downward. Models 22 and 24 may be derived, in a manner well known to those of ordinary skill in the art, from a combination of first principles and empirical modeling techniques.

Referring now to FIG. 3, there is shown a block diagram of a closed loop model based controller 30 that optimizes the mercury removal process 32 and the efficiency of boiler 12. Controller 30 is constructed (in part) using the model 20 of FIG. 2. The inputs to optimizer 30 are, among other boiler process variables, the Hg measurement 30a, RCA measurement 30b and boiler efficiency BE 30c which may be calculated as described above in connection with the description of FIG. 1.

The outputs 30d from the optimizer 30 to boiler 12 include those combustion related manipulated variables, such as for example, air and fuel distribution and excess air levels, as are found to have an impact on boiler operation and in particular a high correlation to Boiler Efficiency and Unburned Carbon (UBC) rate. The available combustion related manipulated variables differ with the firing system and fuel type found in each boiler. Regardless of the firing system and fuel type, the determination of which variables have a high correlation to BE and UBC rate is obtained empirically by test methods in which variables are manipulated and the results of this manipulation are recorded and evaluated. Evaluation methods include, but are not limited to sensitivity analysis among other statistical methodologies.

Using the above described inputs of Hg measurement 30a, RCA measurement 30b and boiler efficiency 30c, the optimizer 30 evaluates the optimized PCS and boiler operating requirements to achieve the maximal economical overall operation of the coal-fired power plant.

The optimization boiler operating calculation is based on achieving the best economic solution between high boiler efficiency and high RCA rate, given the operator set goals of boiler efficiency versus PCS use, and the current operating conditions of the coal fired steam generator 12. The method for deriving this calculated optimal is based on a real time determination of the economic value for RCA as a replacement for PCS vs. the value of the lost BE for the same RCA. The current economic value for PCS is determined from the real time cost for materials. The optimizer 30 then evaluates the total cost of PCS versus boiler efficiency and determines the best economic solution.

The optimization strategy described above in optimizer 30 can be used to actively control RCA. The optimizer 30 actively controls the combustion related manipulated variables such as air and fuel distribution and excess air levels. Additionally, RCA information is used to provide anticipatory action for supplemental mercury reduction by the PCS system which is also actively controlled by the optimizer 30. As can be appreciated from model 20, an improved reduction in mercury that is obtained from increased RCA results in reduced need for PCS 26.

From the above description, it should be appreciated that the combustion condition inside the boiler 12 affects carbon content in fly ash as well as sequestration of mercury. The combustion condition is affected by steam generator loading among other controlled and uncontrolled phenomena. Given consideration of the total cost to generate power and income from the by-product (the fly ash), which is effected by RCA levels, there is a global optimization point that can be determined by optimizer 30 in conjunction with state-of-the-art boiler controls and instruments such as distributed control systems and CIA.

At a given RCA rate, the optimizer 30 can anticipate the PCS flow required to achieve the set mercury removal goal, that is, how much mercury should be removed and the acceptable mercury level leaving the stack 10b, as well as the cost of that required PCS flow rate, for example, the maximum cost acceptable for this level of mercury sequestration. With both the cost of combustion related absorption and PCS absorption understood by optimizer 30, the optimizer 30 can now optimize PCS versus UBC costs and thus find the best or optimal solution that provides the best economics to satisfy the mercury removal goal. Referring now to FIG. 4, there is shown a typical on-line system 40 which may be used to implement the mercury emissions reduction procedure of the present invention that is described above. The system 40 includes a computing device 42, such as a desktop or laptop computer, in which a software program that implements the mercury emissions reduction procedure is stored. The software program includes all of the steps described above.

The computing device 42 may include the software program or the program may be resident on media, including but not limited to a CD-ROM or a flash drive, that interfaces with the device 42 such that the program can be loaded into the computing device 42. Alternatively, the software program may be downloaded into the device 42 through the PC network 44 to which computing device 42 is connected. PC network 44 may be an intranet which may be connected to or connectable to the Internet. In any case, network 44 allow the software program that performs the mercury emissions reduction procedure to be downloaded from the same site where device 42 is located or at another site that is remote from the site where device 42 is located.

System 40 also includes a boiler control system 46 which may be in the form of a distributed control system (DCS) to which computing device 42 is connected by DCS link 48. Also shown in FIG. 4, are the plant network 50, the operator room 52 with the one or more operator consoles 52a typically located therein, and the interfaces 54 between the boiler control system 46 and the plant network 50.

It is to be understood that the description of the foregoing exemplary embodiment(s) is (are) intended to be only illustrative, rather than exhaustive, of the present invention. Those of ordinary skill will be able to make certain additions, deletions, and/or modifications to the embodiment(s) of the disclosed subject matter without departing from the spirit of the invention or its scope, as defined by the appended claims.

Claims

1. A system for controlling a power generating facility including a combustion chamber and a post combustion sorbent adding device, the combustion chamber emitting exhaust gas, the system comprising: a processor;one or more storing units for storing signals; andsoftware program instructions which are stored in one or more of saidstoring units and when executed by the processor cause the system to perform a method comprising: receiving a measurement indicative of the amount of residual carbon in ash within the exhaust gas;receiving a measurement indicative of the amount of mercury within the exhaust gas;receiving a measurement indicative of combustion chamber efficiency;assigning an economic value to the boiler efficiency;assigning an economic value to a sorbent;assigning an economic value to the residual carbon in ash;setting a predetermined target mercury level in the exhaust gas;determining a target amount of the sorbent to be added to the exhaust gas and a target amount of the residual carbon in ash to be formed in the combustion chamber based upon a balancing of the economic value assigned to the boiler efficiency, the economic value of the sorbent and the economic value of the residual carbon in ash, wherein the target amounts of the sorbent and the residual carbon in ash correlate to the most cost effective ratio of sorbent to residual carbon in ash; andmanipulating the controls of the combustion chamber and the post combustion sorbent adding device in accordance with the target sorbent and residual carbon in ash.

2. The system of claim 1, wherein the method further comprises assigning an economic value to the fly ash generated as a by-product in the combustion chamber.

3. The system of claim 2, wherein the method further comprises determining a global optimization point wherein the controls of the combustion chamber and the post combustion sorbent adding device are manipulated to reduce the total cost to generate power and maximize the income from the fly ash.

4. The system of claim 1, wherein the method step of assigning an economic value to the residual carbon in ash, further comprises determining the correlation between reduced boiler efficiency and increased residual carbon in ash.

5. A method of controlling a power generating facility including a combustion chamber and a post combustion sorbent adding device, the combustion chamber emitting exhaust gas, the method comprising: receiving a measurement indicative of the amount of residual carbon in ash within the exhaust gas;receiving a measurement indicative of the amount of mercury within the exhaust gas;receiving a measurement indicative of the boiler efficiency;assigning an economic value to the boiler efficiency;assigning an economic value to a sorbent;assigning an economic value to the residual carbon in ash;setting a predetermined target mercury level in the exhaust gas;determining a target amount of the sorbent to be added to the exhaust gas and a target amount of the residual carbon in ash to be formed in the combustion chamber based upon a balancing of the economic value assigned to the boiler efficiency, the economic value of the sorbent and the economic value of the residual carbon in ash, wherein the target amounts of the sorbent and the residual carbon in ash correlate to the most cost effective ratio of sorbent to residual carbon in ash; andmanipulating the controls of the combustion chamber and the post combustion sorbent adding device in accordance with the target sorbent and residual carbon in ash.

6. The method of claim 5, further comprising assigning an economic value to the fly ash generated as a by-product in the combustion chamber.

7. The method of claim 6, further comprising determining a global optimization point wherein the controls of the combustion chamber and the post combustion sorbent adding device are manipulated to reduce the total cost to generate power and maximize the income from the fly ash.

8. The method of claim 5, wherein the method step of assigning an economic value to the residual carbon in ash, further comprises determining the correlation between reduced boiler efficiency and increased residual carbon in ash.

9. A system for controlling a power generating facility including a combustion chamber, the combustion chamber emitting exhaust gas, the system comprising: a first reaction zone located in the combustion chamber;a sorbent injector located downstream of the first reaction zone;a second reaction zone located downstream of said sorbent injector;a mercury analyzer located downstream of said second reaction zone;a processor;one or more storing units for storing signals; andsoftware program instructions which are stored in one or more of said storing units and when executed by the processor cause the system to perform a method comprising: producing residual carbon in ash in said first reaction zone;injecting a sorbent at the second reaction zone;measuring the amount of mercury in the exhaust gas at the mercury analyzer;determining the cost of the sorbent;determining the cost of the residual carbon in ash;setting a predetermined target mercury level for the exhaust gas at the mercury analyzer;determining a rate to inject the sorbent and a target amount of the residual carbon in ash to be formed in the first reaction zone based upon a balancing of the cost of the residual carbon in ash and the cost of the sorbent; andmanipulating the controls of the combustion chamber and the sorbent injector in accordance with the determined sorbent injection rate and the target residual carbon in ash.

10. The system of claim 9, wherein the method further comprises assigning an economic value to the fly ash generated as a by-product in the combustion chamber.

11. The system of claim 10, wherein the method further comprises determining a global optimization point wherein the controls of the combustion chamber and the sorbent injector are manipulated to reduce the total cost to generate power and maximize the income from the fly ash.

12. The system of claim 9, wherein the method step of determining a cost of the residual carbon in ash, further comprises determining the correlation between reduced boiler efficiency and increased residual carbon in ash.