Patent Publication Number: US-9841185-B2

Title: Steam temperature control using model-based temperature balancing

Description:
TECHNICAL FIELD 
     This patent relates generally to the control of boiler systems and in one particular instance to the control and optimization of steam generating boiler systems using model-based temperature balancing. 
     BACKGROUND 
     A variety of industrial as well as non-industrial applications use fuel burning boilers which typically operate to convert chemical energy into thermal energy by burning one of various types of fuels, such as coal, gas, oil, waste material, etc. An exemplary use of fuel burning boilers is in thermal power generators, wherein fuel burning boilers generate steam from water traveling through a number of pipes and tubes within the boiler, and the generated steam is then used to operate one or more steam turbines to generate electricity. The output of a thermal power generator is a function of the amount of heat generated in a boiler, wherein the amount of heat is directly determined by the amount of fuel consumed (e.g., burned) per hour, for example. 
     In many cases, power generating systems include a boiler which has a furnace that burns or otherwise uses fuel to generate heat which, in turn, is transferred to water flowing through pipes or tubes within various sections of the boiler. A typical steam generating system includes a boiler having a superheater section (having one or more sub-sections) in which steam is produced and is then provided to and used within a first, typically high pressure, steam turbine. While the efficiency of a thermal-based power generator is heavily dependent upon the heat transfer efficiency of the particular furnace/boiler combination used to burn the fuel and transfer the heat to the water flowing within the superheater section or any additional section(s) of the boiler, this efficiency is also dependent on the control technique used to control the temperature of the steam in the superheater section or any additional section (s) of the boiler. 
     However, as will be understood, the steam turbines of a power plant are typically run at different operating levels at different times to produce different amounts of electricity based on energy or load demands. For most power plants using steam boilers, the desired steam temperature setpoints at final superheater outlets of the boilers are kept constant, and it is necessary to maintain steam temperature close to the setpoints (e.g., within a narrow range) at all load levels. In particular, in the operation of utility (e.g., power generation) boilers, control of steam temperature is critical as it is important that the temperature of steam exiting from a boiler and entering a steam turbine is at an optimally desired temperature. If the steam temperature is too high, the steam may cause damage to the blades of the steam turbine for various metallurgical reasons. On the other hand, if the steam temperature is too low, the steam may contain water particles, which in turn may cause damage to components of the steam turbine over prolonged operation of the steam turbine as well as decrease efficiency of the operation of the turbine. Moreover, variations in steam temperature also cause metal material fatigue, which is a leading cause of tube leaks. 
     Typically, each section (i.e., the superheater section and any additional sections such as a reheater section) of the boiler contains cascaded heat exchanger sections wherein the steam exiting from one heat exchanger section enters the following heat exchanger section with the temperature of the steam increasing at each heat exchanger section until, ideally, the steam is output to the turbine at the desired steam temperature. For example, some heat exchanger sections include individual primary superheaters that are connected in parallel, and which may in turn be connected in series to a final superheater. In such cascaded arrangements, steam temperature is controlled primarily by controlling the temperature of the water at the output of the first stage of the boiler which is primarily achieved by changing the fuel/air mixture provided to the furnace or by changing the ratio of firing rate to input feedwater provided to the furnace/boiler combination. In once-through boiler systems, in which no drum is used, the firing rate to feedwater ratio input to the system may be used primarily to regulate the steam temperature at the input of the turbines. 
     While changing the fuel/air ratio and the firing rate to feedwater ratio provided to the furnace/boiler combination operates well to achieve desired control of the steam temperature over time, it is difficult to control short term fluctuations in steam temperature at the various sections of the boiler using only fuel/air mixture control and firing rate to feedwater ratio control. Instead, to perform short term (and secondary) control of steam temperature, saturated water is sprayed into the steam at a point before the final heat exchanger section located immediately upstream of the turbine. This secondary steam temperature control operation typically occurs at the output of each primary superheater and before the final superheater section of the boiler. To effect this operation, temperature sensors are provided along the steam flow path and between the heat exchanger sections to measure the steam temperature at critical points along the flow path, and the measured temperatures are used to regulate the amount of saturated water sprayed into the steam for steam temperature control purposes. 
     In many circumstances, it is necessary to rely heavily on the spray technique to control the steam temperature as precisely as needed to satisfy the turbine temperature constraints described above. In one example, once-through boiler systems, which provide a continuous flow of water (steam) through a set of pipes within the boiler and do not use a drum to, in effect, average out the temperature of the steam or water exiting the first boiler section, may experience greater fluctuations in steam temperature and thus typically require heavier use of the spray sections to control the steam temperature at the inputs to the turbines. In these systems, the firing rate to feedwater ratio control is typically used, along with superheater spray flow, to regulate the furnace/boiler system. In these and other boiler systems, a distributed control system (DCS) uses cascaded PID (Proportional Integral Derivative) controllers to control both the fuel/air mixture provided to the furnace as well as the amount of spraying performed upstream of the turbines. 
     However, cascaded PID controllers typically respond in a reactionary manner to a difference or error between a setpoint and an actual value or level of a dependent process variable to be controlled, such as a temperature of steam to be delivered to the turbine. That is, the control response occurs after the dependent process variable has already drifted from its set point. For example, spray valves that are upstream of a turbine are controlled to readjust their spray flow only after the temperature of the steam delivered to the turbine has drifted from its desired target. Needless to say, this reactionary control response coupled with changing boiler operating conditions can result in large temperature swings that cause stress on the boiler system and shorten the lives of tubes, spray control valves, and other components of the system. 
     SUMMARY 
     Embodiments of systems, methods, and controllers as described herein include a technique of controlling a steam generating system include using dynamic matrix control to control at least a portion of the steam generating system, such as a temperature of steam input into a final superheater component of the steam generating system. The final superheater component heats the input steam to produce output steam that is input to a turbine. As used herein, the term “output steam” refers to the steam delivered from the steam generating system immediately into a turbine. An “output steam temperature,” as used herein, is a temperature of the output steam that is exiting the steam generating system and entering into the turbine. 
     The technique of controlling a steam generating system may include a first control block that receives, as inputs, two signals each corresponding to an actual value, level, or measurement of an intermediate portion of the steam generating system. The technique further includes a dynamic matrix control block that receives, as its inputs, a signal corresponding to an actual value, level, or measurement of the portion of the steam generating system that is to be controlled (e.g., the actual output steam temperature); and a setpoint of the portion of the steam generating system that is to be controlled (e.g., the output steam temperature setpoint). The first control block generates, based on its inputs, an offset value that represents a difference between the actual value, level, or measurement of the two input signals. The dynamic matrix control block generates, based on its inputs, a control signal associated with multiple field devices to control the values, levels, or measurements of the intermediate portion. The technique further includes a module to generate, from the control signal of the dynamic matrix control, a first control signal and a second control signal. An additional module modifies the first control signal based on the offset value. The technique is configured to provide the modified first control signal to a first field device to control a section of the intermediate portion and provide the second control signal to a second field device to control an additional section of the intermediate portion. The first field device and the second field device influence the at least a portion of the steam generating system towards its desired output steam temperature setpoint. Accordingly, life spans of tubes, valves, and other internal components of the steam generating system are prolonged as the technique minimizes stress due to swings of temperature and other variables in the system. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  illustrates a block diagram of a typical boiler steam cycle having a superheater section for a typical set of steam powered turbines, the superheater section having two primary superheaters connected in parallel to a final superheater; 
         FIG. 2  illustrates a schematic diagram of a prior art manner of controlling a superheater section of a boiler steam cycle for a steam powered turbine, such as that of  FIG. 1 ; 
         FIG. 3  illustrates a schematic diagram of a manner of controlling the boiler steam cycle of the superheater section of  FIG. 1  in a manner which helps to optimize efficiency of the system; 
         FIG. 4  illustrates an exemplary method of controlling a steam generating boiler system. 
     
    
    
     DETAILED DESCRIPTION 
     Although the following text sets forth a detailed description of numerous different embodiments of the invention, it should be understood that the legal scope of the invention is defined by the words of the claims set forth at the end of this patent. The detailed description is to be construed as exemplary only and does not describe every possible embodiment of the invention as describing every possible embodiment would be impractical, if not impossible. Numerous alternative embodiments could be implemented, using either current technology or technology developed after the filing date of this patent, which would still fall within the scope of the claims defining the invention. 
       FIG. 1  illustrates a block diagram of a once-through boiler steam cycle for a typical boiler  100  that may be used, for example, in a thermal power plant. The boiler  100  may include various sections through which steam or water flows in various forms. The boiler  100  of  FIG. 1  depicts multiple superheater sections through which superheated steam flows, although it should be appreciated that other sections such as a reheater section are envisioned. While the boiler  100  illustrated in  FIG. 1  has various boiler sections situated horizontally, in an actual implementation, one or more of these sections may be positioned vertically with respect to one another, especially because flue gases heating the steam in various different boiler sections, such as a water wall absorption section, rise vertically (or, spiral vertically). 
     In any event, as illustrated in  FIG. 1 , the boiler  100  includes a furnace and a primary water wall absorption section  102 , a first primary superheater absorption section  104 , a second primary superheater absorption section  105 , and a final superheater absorption section  106 . Additionally, the boiler  100  may include a first desuperheater or sprayer section  110 , a second desuperheater section or sprayer section  111 , and an economizer section  114 . During operation, the main steam generated by the boiler  100  and output by the final superheater absorption section  106  is used to drive a high pressure (HP) turbine  116 . In some cases, the boiler  100  may also be used to drive a low or intermediate pressure turbine, such as one included in a reheater absorption section, which is not illustrated in  FIG. 1 . 
     The water wall absorption section  102 , which is primarily responsible for generating steam, includes a number of pipes through which water or steam from the economizer section  114  is heated in the furnace. Of course, feedwater coming into the water wall absorption section  102  may be pumped through the economizer section  114  and this water absorbs a large amount of heat when in the water wall absorption section  102 . The steam or water provided at output of the water wall absorption section  102  is fed to both the first primary superheater absorption section  104  and the second primary superheater absorption section  105 . 
     As illustrated in  FIG. 1 , the first primary superheater absorption section  104  is connected in parallel with the second primary superheater absorption section  105  (i.e., water flows concurrently through the first primary superheater absorption section  104  and the second primary superheater absorption section  105 ). Each of the first primary superheater absorption section  104  and the second primary superheater absorption section  105  is configured to heat water entering therein and to output the heated water. Water exiting from both the first primary superheater absorption section  104  and the second primary superheater absorption section  105  is fed to the final superheater absorption section  106 . In particular, water from the first primary superheater absorption section  104  is combined with water from the second primary superheater absorption section  105  before being fed to the final superheater absorption section  106 . The use of the first primary superheater absorption section  104 , the second primary superheater absorption section  105 , and the final superheater absorption section  106  together raise the steam temperature to very high levels. The main steam output from the final superheater absorption section  106  drives the high pressure turbine  116  to generate electricity. 
     The first sprayer section  110  and the second sprayer section  111  may be used to control the respective temperatures of the steam output from the first primary superheater absorption section  104  and the second primary superheater absorption section  105 , and therefore to control the temperature of the steam input into the final superheater absorption section  106  as well as, to a lesser degree, the final steam temperature at the input of the turbine  116 . Accordingly, the first sprayer section  110  and the second sprayer section  111  may be controlled to adjust the final steam temperature at the input of the turbine  116  to be at a desired setpoint. For each of the first sprayer section  110  and the second sprayer section  111 , a spray feed may be used as a source of water (or other liquid) that is supplied to a valve (as illustrated: valves  122  and  124 ) used to control an amount of spray that is applied to the output steam from the respective sprayer section  110  or  111  and therefore used to adjust the temperature of the output steam. Generally, the more spray that is used (i.e., the more that the valve  122  or  124  is opened), the more the output steam from the respective sprayer section  110  or  111  is cooled or reduced in temperature. In some cases, the spray feed provided to the sprayer sections  110  and  111  can be tapped from the feed line into the economizer section  114 . 
     It should be appreciated that the steam from the turbine  116  may be routed to a reheater absorption section (not illustrated in  FIG. 1 ), and the hot reheated steam that is output from the reheater absorption section can be fed through one or more additional turbine systems (not illustrated in  FIG. 1 ), and/or to a steam condenser (not illustrated in  FIG. 1 ) where the steam is condensed to a liquid form, and the cycle begins again with various boiler feed pumps pumping the feedwater through a cascade of feedwater heater trains and then to the economizer section  114  for the next cycle. The economizer section  114  is located in the flow of hot exhaust gases exiting from the boiler  100  and uses the hot gases to transfer additional heat to the feedwater before the feedwater enters the water wall absorption section  102 . 
     As illustrated in  FIG. 1 , a controller or controller unit  120  is communicatively coupled to the furnace within the water wall section  102  and to the valves  122  and  124  which respectively control the amount of water provided to sprayers in the first sprayer section  110  and the second sprayer section  111 . The controller  120  can also be communicatively coupled to flow sensors (not shown in  FIG. 1 ) at the outputs of the valves  122 ,  124 . The controller  120  is also coupled to various sensors, including an intermediate temperature sensor  125  located at the output of the water wall absorption section  102 , multiple primary temperature sensors  126 ,  127  respectively located at the outputs of the first sprayer section  110  and the second sprayer section  111 ; and an output temperature sensor  128  located at the output of the final superheater absorption section  106 . The controller  120  also receives other inputs including the firing rate, a load signal (typically referred to as a feed forward signal) which is indicative of and/or a derivative of an actual or desired load of the power plant, as well as signals indicative of settings or features of the boiler including, for example, damper settings, burner tilt positions, etc. The controller  120  may generate and send other control signals to the various boiler and furnace sections of the system and may receive other measurements, such as valve positions, measured spray flows, other temperature measurements, etc. While not specifically illustrated as such in  FIG. 1 , the controller or controller unit  120  could include separate sections, routines and/or control devices for controlling the superheater section and the optional reheater section of the boiler system. 
       FIG. 2  is a schematic diagram  200  showing the various sections of the boiler system  100  of  FIG. 1  and illustrating a typical manner in which control is currently performed in various boilers of this type in the prior art. In particular, the diagram  200  illustrates an economizer  214 , a primary furnace or water wall section  202 , a superheater section A  204 , a superheater section B  205 , a first sprayer section  210  coupled to the superheater section A  204 , and a second sprayer section  211  coupled to the superheater section B  205 . The superheater section A  204  is connected in parallel with the superheater section B  205 , with each having outputs connecting to a final superheater section  206 .  FIG. 2  also illustrates a cascaded proportional-integral-derivative (PID) based control loop  230  which may be implemented by the controller  120  of  FIG. 1  or by one or more other DCS controllers to control the fuel and feedwater operation of the furnace  202  to affect (i.e., control) a temperature  228  of steam output from the final superheater section  206  and delivered by the boiler system to a turbine  216  to be at a setpoint. 
     In particular, the control loop  230  includes a first control block  232 , illustrated in the form of a PID control block, which uses, as primary inputs, a setpoint  233  in the form of a factor or signal corresponding to a desired or optimal value of a control variable and an actual or measured temperature value  234  of the boiler system. As illustrated in  FIG. 2 , the actual parameter value  234  may correspond to the output steam temperature  228  (i.e., the temperature of the steam output from the final superheater section  206 ) whereby the actual parameter value  234  may be the actual or measured output steam temperature  228  or a value based thereon. Further, the setpoint  233  may correspond to, for example, a desired temperature for the steam output from the final superheater section  206  or a value based thereon. In other cases, the setpoint  233  may correspond to other conditions that may influence the output steam temperature  228 , such as a damper position of a damper within the boiler system, a position of a spray valve, an amount of spray, some other control, manipulated or disturbance variable or combination thereof that is used to control or is associated with one or more sections of the boiler system. Generally, the setpoint  233  may correspond to a control variable or a manipulated variable of the boiler system, and may be typically set by a user or an operator. 
     The first control block  232  can compare the setpoint  233  to a measure of the actual parameter value  234  to produce a desired output value. For clarity of discussion,  FIG. 2  illustrates a situation in which the setpoint  233  at the first control block  232  corresponds to a desired output steam temperature. The control block  232  compares the output steam temperature setpoint  233  to the actual parameter value  234  (i.e., a measure of the actual temperature  228  of the steam currently being output from the final superheater section  206 ), to produce an output temperature signal  235 . The output temperature signal  235  is indicative of a setting or position for one or more field devices to influence the steam output from the final superheater section  206  to achieve the desired temperature setpoint  233 . 
     Typically, the output temperature signal  235  is used to determine respective settings or positions for the first sprayer section  210  and the second sprayer section  220  (i.e., valve positions associated with controlling sprayers at the first sprayer section  210  and the second sprayer section  220 ). In particular, the output temperature signal  235  is provided to a balancer module  236  of the control loop  230  which can process the output temperature signal  235  to generate, determine, or calculate a temperature A value  237  and a temperature B value  238 . The balancer module  236  generally operates to generate the values  237 ,  238  such that the values  237 ,  238  are equivalent (i.e., balanced). The temperature A value  237  can be indicative of a desired value for a temperature A  243  of steam output from the superheater section A  204  and the temperature B value  238  can be indicative of a desired value for a temperature B  244  of steam output from the superheater section B  205 . 
     The control loop  230  as illustrated in  FIG. 2  further includes a second control block  240  and a third control block  241 , both illustrated in the form of PID control blocks. The second control block  240  uses, as primary inputs, the temperature A value  237  that is output by the balancer module  236  and the actual temperature A  243  of steam output from the superheater section A  204 . The third control block  241  uses, as primary inputs, the temperature B value  238  that is output by the balancer module  236  and the actual temperature B  244  of steam output from the superheater section B  205 . The second control block  240  compares the temperature A value  237  to the actual temperature A  243  to produce a desired valve A control signal  245 , and the third control block  241  compares the temperature B value  238  to the actual temperature B  244  to produce a desired valve B control signal  246 . The valve A control signal  245  drives a valve  222  that controls the first sprayer section  210  to a desired valve position, and therefore to adjust the amount of water sprayed on the steam output from the superheater section A  204 , and to adjust the temperature A  243  from the current temperature A  243  closer to the temperature A value  237 . Similarly, the valve B control signal  246  drives a valve  224  that controls the second sprayer section  211  to a desired valve position, and therefore to adjust the amount of water sprayed on the steam output from the superheater section B  205 , and to adjust the temperature B  244  from the current temperature B  244  closer to the temperature B value  238 . 
     However, the control loop  230  as it exists in current process control systems has some drawbacks. In particular, the valve control signals  245 ,  246  are determined based on current conditions within the boiler system  100 , versus predicted or modeled conditions that are determined to result from various modifications. As a result, the valve control signals  245 ,  246  output using the three PID control blocks  232 ,  240 ,  241  may result in a situation in which the output steam temperature  228  may never reach its setpoint  233 . In other situations, an oscillating effect may result whereby valves A and B ( 222 ,  224 ) are adjusted too frequently as a result of the respective temperatures A and B  243 ,  244  oscillating above and below the respective temperature A and B values  237 ,  238 . Accordingly, the control system as depicted in  FIG. 2  may experience a large amount of fluctuation and general overuse. 
       FIG. 3  illustrates a control system or control scheme  300  for controlling the steam generating boiler system  100 . The control system  300  may control at least a portion of the boiler system  100  such as one or more control variables or other dependent process variable(s) of the boiler system  100 . In the example illustrated in  FIG. 3 , the control system  300  controls the output steam temperature  228 , but it should be appreciated that the control system  300  may control another portion of the boiler system  100  (e.g., a system output, an output parameter, or an output control variable such as a pressure of the output steam at the turbine  118 ). In particular, the control system  300  controls a valve A control signal  259  and a valve B control signal  257  that control respective valve-sprayer component pairs ( 210 ,  222  and  211 ,  224 ) that supply water to steam respectively output from superheater section A  204  and superheater section B  205 . Further, as illustrated in  FIG. 3 , the superheater section A  204  is connected in parallel with the superheater section B  205 , which are both connected to the final superheater section  206  which outputs steam having the output steam temperature  228 . 
     The control system  300  may be performed in or may be communicatively coupled with the controller or controller unit  120  of the boiler system  100 . For example, at least a portion of the control system  300  may be included in the controller  120 . In other implementations, the entire control system  300  may be included in the controller  120 . 
     The components of the control system  300  can reduce the plateauing and/or oscillating effect experienced in PID-based control loop  230  as discussed with respect to  FIG. 2 . Indeed, the control system  300  of  FIG. 3  may be a replacement for the PID-based control loop  230  of  FIG. 2 . Instead of being reactionary like the control loop  230  (e.g., where a control adjustment is not initiated until after a difference or error is detected between the portion of the boiler system  100  that is desired to be controlled and a corresponding setpoint), the control system  300  is at least partially feed forward in nature, so that the control adjustment can be initiated before a difference or error at the portion of the boiler system  100  is detected. 
     As illustrated in  FIG. 3 , the furnace  202  generates steam and provides, in parallel, the steam to superheater section A  204  for heating and to superheater section B  205  for heating. It should be appreciated that multiple furnaces can respectively provide steam to superheater section A  204  and superheater section B  205 . Valve A  222  can control the first sprayer section  210  to control the amount of water supplied to the steam output from superheater section A  204 , and therefore control the temperature ( 243 ) of the steam output from superheater section A  204 . Valve B  224  can control the second sprayer section  211  to control the amount of water supplied to the steam output from superheater section B  205 , and therefore control the temperature ( 244 ) of the steam output from superheater section B  205 . The output steam (after any cooling by the respective sprayer sections  210 ,  211 ) from superheater section A  204  and superheater section B  205  is combined and provided as input steam to the final superheater section  206 , whereby the final superheater section  206  is configured to heat the combined output steam. The output steam from the final superheater section  206  can be provided to the turbine  216  to generate electricity. 
     As illustrated in  FIG. 3 , a control loop  330  of the control system  300  includes an input controller  250  and an output controller  251 . The input controller  250  can be a PID-based controller or a dynamic matrix controller (DMC), and the output controller  251  can be a DMC. The input controller  250  can receive, as inputs, temperature A  243  (or a control value associated with temperature A  243 ) of the steam output from superheater section A  204  and temperature B  244  (or a control value associated with temperature B  244 ) of the steam output from superheater section B  205 , after any cooling by the respective sprayer sections  210 ,  211 . 
     Generally, as the number of inputs for a DMC-based output controller (such as the output controller  251 ) increases, the model used to program that output controller increases exponentially due to the number of potential input combinations for which to account. To reduce the complexity of the model of the output controller  251 , the output controller  251  and its model thereof account for a single temperature value that corresponds to both temperature A  243  and temperature B  244 . In particular, the single temperature value represents an equal temperature value for both temperature A  243  and temperature B  244  (i.e., the output controller  251  “assumes” that temperature A  243  is equal to temperature B  244 ). Therefore, the model is significantly less complex that what would be required if the model was to account for the input combinations of both temperature A  243  and temperature B  244 . 
     In order to ensure that temperature A  243  is equal to temperature B  244 , the control loop  330  includes the input controller  250  to calculate a temperature difference or offset used to facilitate the equal values of temperature A  243  and temperature B  244 . Because the input controller  250  simply operates based on the difference or offset between temperature A  243  and temperature B  244 , the programming of the input controller  250  need not be complex, and certainly not as complex as programming the model-based output controller  251  to account for both temperature A  243  and temperature B  244 . The combination of the input controller  250  and the output controller  251  therefore enables the control loop  330  to effectively and efficiently control both temperature A  243  and temperature B  244  without the complex programming required by model-based controllers that account for multiple parameters. 
     Referring to  FIG. 3 , the input controller  250  can determine an offset value output  252  based on temperature A  243  and temperature B  244 . In some cases, the offset value output  252  can reflect a difference between temperature A  243  and temperature B  244 . For example, if temperature A  243  is 200° F. and temperature B  244  is 215° F., the offset value output  252  can be a value or amount that reflects, according to one of various conventions, the temperature difference of 15° F. In the implementations as discussed with respect to  FIG. 3 , the offset value output  252  can be a value or amount that corresponds to a valve position (e.g., a valve position of valve A  222  and/or valve B  224 ), and can be positive or negative. For example, a negative amount for the offset value output  252  can correspond to a closing of a valve and a positive amount for the offset value output  252  can correspond to an opening of a valve (or vice-versa). It should be appreciated that the output value output  252  can have a linear, exponential, or other mathematical relationship with the difference between temperature A  243  and temperature B  244 , and that the input controller  250  can calculate the offset value output  252  according to various techniques or calculations. 
     Generally speaking, the model predictive control performed by the DMC-based output controller  251  is a multiple-input-single-output (MISO) control strategy in which the effects of changing each of a number of process inputs on each of a number of process outputs is measured and these measured responses are then used to create a model of the process. In some cases, though, a multiple-input-multiple-output (MIMO) control strategy may be employed. Whether MISO or MIMO, the model of the process is inverted mathematically and is then used to control the process output or outputs based on changes made to the process inputs. In some cases, the process model includes or is developed from a process output response curve for each of the process inputs and these curves may be created based on a series of, for example, pseudo-random step changes delivered to each of the process inputs. These response curves can be used to model the process in known manners. Model predictive control is known in the art and, as a result, the specifics thereof will not be described herein. However, model predictive control is described generally in Qin, S. Joe and Thomas A. Badgwell, “An Overview of Industrial Model Predictive Control Technology,”  AIChE Conference,  1996. 
     Moreover, the generation and use of advanced control routines such as model predictive control (MPC) control routines may be integrated into the configuration process for a controller for the steam generating boiler system. For example, Wojsznis et al., U.S. Pat. No. 6,445,963 entitled “Integrated Advanced Control Blocks in Process Control Systems,” the disclosure of which is hereby expressly incorporated by reference herein, discloses a method of generating an advanced control block such as an advanced controller (e.g., an MPC controller or a neural network controller) using data collected from the process plant when configuring the process plant. More particularly, U.S. Pat. No. 6,445,963 discloses a configuration system that creates an advanced multiple-input-multiple-output control block within a process control system in a manner that is integrated with the creation of and downloading of other control blocks using a particular control paradigm, such as the Fieldbus paradigm. In this case, the advanced control block is initiated by creating a control block (such as the output controller  251 ) having desired inputs and outputs to be connected to process outputs and inputs, respectively, for controlling a process such as a process used in a steam generating boiler system. The control block includes a data collection routine and a waveform generator associated therewith and may have control logic that is untuned or otherwise undeveloped because this logic is missing tuning parameters, matrix coefficients or other control parameters necessary to be implemented. The control block is placed within the process control system with the defined inputs and outputs communicatively coupled within the control system in the manner that these inputs and outputs would be connected if the advanced control block was being used to control the process. Next, during a test procedure, the control block systematically upsets each of the process inputs via the control block outputs using waveforms generated by the waveform generator specifically designed for use in developing a process model. Then, via the control block inputs, the control block coordinates the collection of data pertaining to the response of each of the process outputs to each of the generated waveforms delivered to each of the process inputs. This data may, for example, be sent to a data historian to be stored. After sufficient data has been collected for each of the process input/output pairs, a process modeling procedure is run in which one or more process models are generated from the collected data using, for example, any known or desired model generation or determination routine. As part of this model generation or determination routine, a model parameter determination routine may develop the model parameters, e.g., matrix coefficients, dead time, gain, time constants, etc. needed by the control logic to be used to control the process. The model generation routine or the process model creation software may generate different types of models, including non-parametric models, such as finite impulse response (FIR) models, and parametric models, such as auto-regressive with external inputs (ARX) models. The control logic parameters and, if needed, the process model, are then downloaded to the control block to complete formation of the advanced control block so that the advanced control block, with the model parameters and/or the process model therein, can be used to control the process during run-time. When desired, the model stored in the control block may be re-determined, changed, or updated. 
     The output controller  251  can receive, as inputs, the output steam temperature  228  (or a control value associated with the output steam temperature  228 ) of the steam output from the final superheater section  206  as well as a setpoint  233  that may correspond to, for example, a desired temperature for the steam output from the final superheater section  206 . In other cases, the setpoint  233  may correspond to other conditions that may influence the output steam temperature  228 , such as a damper position of a damper within the boiler system, a position of a spray valve, an amount of spray, some other control, manipulated, or disturbance variable or combination thereof that is used to control or is associated with one or more sections of the boiler system. Generally, the setpoint  233  may correspond to a control variable or a manipulated variable of the boiler system, and may be typically set by a user or an operator. 
     The output controller  251  can compare the setpoint  233  to a measure of the actual temperature  228  of the steam currently being output from the final superheater section  206 , to generate, determine, or calculate an input steam control signal  253 . The input steam control signal  253  can be indicative of positions for valve A  222  and valve B  224  that, when combined with operation of the superheater section A  204 , the superheater section B  205 , and the final superheater section  206 , aims to achieve the desired temperature (i.e., the setpoint  233 ) of the steam output from the final superheater section  206 . Particularly, the input steam control signal  253  can correspond to valve settings (i.e., physical valve positions) for valve A  222  to control the first sprayer section  210  and for valve B  224  to control the second sprayer section  211 . It should be appreciated that the output controller  251  can calculate the input steam control signal  253  according to various model-based techniques or calculations, as discussed herein. 
     The input steam control signal  253  can be provided to a balancer module  254  which can process the input steam control signal  253  to generate, determine, or calculate a temporary valve A control signal  255  and a desired valve B control signal  257 . The balancer module  254  can include hardware and/or software components and can optionally be integrated as part of the output controller  251 . In some implementations, the balancer module  254  can generate the temporary valve A control signal  255  and the desired valve B control signal  257  such that the control signals  255 ,  257  are equivalent (i.e., balanced), although it should be appreciated that the balancer module  254  can generate different values for the control signals  255 ,  257  based on physical configurations or settings of the valves  222 ,  224  or other components of the control system  300 . The temporary valve A control signal  255  can correspond to a setting or position of valve A  222  to achieve a desired value for temperature A  243  of steam output from the superheater section A  204  and the valve B control signal  257  can drive valve B  224  to achieve a desired value for temperature B  244  of steam output from the superheater section B  205 . The desired values for temperature A  243  and temperature B  244  are, of course, based on the setpoint  233  and the measure of the actual temperature  228 . The balancer module  254  (or another module or component such as the output controller  251 ) can provide at least the valve B control signal  257  to valve B  224  to control the second sprayer component  211  and accordingly the temperature  244  of the steam output from superheater section B  205 . 
     The control loop  330  further includes a summer module  256  configured to interface with the balancer module  254 , the input controller  250 , and optionally the output controller  251 . The summer module  256  can include hardware and/or software components and can optionally be integrated as part of either the input controller  250  or the output controller  251 . As illustrated in  FIG. 3 , the summer module  256  can receive, as inputs, the offset value output  252  output by the input controller  250  and the temporary valve A control signal  255  output by the balancer component  254 . The summer module  256  can generate the desired valve A control signal  259  that is used to control valve A  222 . 
     In particular, the summer module  256  can modify the temporary valve A control signal  255  by applying (e.g., adding, subtracting, or the like) the offset value output  252  to the temporary valve A control signal  255 . For example, if the temporary valve A control signal  255  specifies an amount of 100 and the offset value output  252  is 5, the summer module  256  can add the offset value (5) to the temporary control signal ( 100 ) to determine the desired valve A control signal  259  of 105. It should be appreciated that other calculations, applications, determinations, or the like can be utilized to determine the desired valve A control signal  259 . The summer module  256  (or another component such as the output controller  251 ) can provide at the desired valve A control signal  259  to valve A  222  to control the first sprayer section  210  and accordingly the temperature  243  of the steam output from superheater section A  204 . 
     As discussed herein, the balancer module  254  can determine the valve B control signal  257  and provide the valve B control signal  257  to valve B  224  to control the second sprayer component  211 , and the summer module  256  can determine the valve A control signal  259  and provide the valve A control signal  259  to valve A  222  to control the first sprayer component  210 . The boiler system can experience improved temperature controls as measured by resulting temperature A  243 , temperature B  244 , and the output steam temperature  228 . In operation, the adjustments of the first sprayer component  210  and the second sprayer component  210  results in the output steam temperature  228  that approaches and/or meets the setpoint  233 . The use of the input controller  250 , the output controller  251 , the balancer module  254 , and the summer module  256  in the control loop  330  reduces the frequency with which valve A and valve B are adjusted, thereby reducing overall temperature discrepancies and overall system use. Further, use of the control loop  330  helps increase the response time of the boiler system. Additionally, if there is a change in the setpoint  233 , the control loop  330  determines a new valve B control signal  257  and a new valve A control signal  259  so that the boiler system efficiently and effectively achieves the desired output steam temperature  228  in a reduced amount of time. 
     Generally, as discussed herein, the control loop  330  of  FIG. 3  is able to minimize complexity while still achieving efficient boiler system control. The output controller  251  can include a matrix or other model that includes values for the output controller  251  to use to determine, based on the output steam temperature  288  and the setpoint  233 , a single input steam control signal. For example, if the output steam temperature  228  is 200° F. and the setpoint  233  is 220° F., the output controller  251  can determine (e.g., from using matrix values) that the temperature of the steam being input into the final superheater  206  needs to be 180° F. and accordingly that an input valve needs to be set at 50% to achieve the input steam temperature of 180° F. However, there are two valves, namely valve A  222  and valve B  224 , that are needed to control the sprayer sections  210 ,  211 . Adding data for an additional valve to the matrix or model of the output controller  251  would exponentially increase a number of entries and/or data needed in the matrix or model. By leveraging the input controller  250  that determines the offset value  252  and the summer module  256  that modifies the temporary valve A control signal  255  according to the offset value  252 , the control loop  330  can account for both of the valve B control signal  257  and the valve A control signal  259  without having to over-complicate the programming of the output controller  251 . Stated differently, the inclusion of the input controller  250  and the summer module  256  enables the output controller  251  to only have to determine a single valve control signal even though there are two valves to control. 
       FIG. 4  illustrates an exemplary method  400  of controlling a steam generating boiler system, such as the steam generating boiler system  100  of  FIG. 1 . The method  400  may also operate in conjunction with the control system or control scheme  300  of  FIG. 3 . For example, the method  400  may be performed by one or more components of the control loop  330  or the controller  120 . For clarity, the method  400  is described below with simultaneous referral to the boiler  100  of  FIG. 1  and to the control system or scheme  300  of  FIG. 3 . 
     At block  480 , a first temperature  243  (or a control value associated therewith) of first input steam may be obtained or received. The first input steam can correspond to steam output from the first superheater component  204  and used as an input to the final superheater component  206 . At block  482 , a second temperature  244  (or a control value associated therewith) of second input steam may be obtained or received. The second input steam can correspond to steam output from the second superheater component  205  and also used as an input to the final superheater component  206 . At block  484 , an output temperature  228  (or a control value associated therewith) may be obtained or received. The output temperature  228  can correspond to the temperature of steam output from the final superheater component  206 . 
     At block  486 , an offset value  252  based on the first temperature  243  and the second temperature  244  can be determined or calculated. In particular, the control loop  330  or the controller  120  can calculate the offset value  252  based on a difference between the first temperature  243  and the second temperature  244 , wherein the offset value  252  can, in some cases, represent a difference in control signals that respectively control sprayers that respectively operate on steam having the first temperature  243  and the second temperature  244 . It should be appreciated that other calculations for the offset value  252  may be utilized. At block  488 , an input steam control signal  253  for controlling the first temperature  243  and the second temperature  244  can be generated, determined, or calculated based on the output temperature  228  and an output temperature setpoint  233 . The input steam control signal  253  can be a value representing a first valve control signal  245  and a second valve control signal  246  that respectively control the first sprayer section  210  and the second sprayer section  211 , and therefore the first temperature  243  and the second temperature  244 . 
     At block  490 , a first control signal  255  based on the input steam control signal  253  can be generated, determined, or calculated. At block  492 , a second control signal  257  based on the input steam control signal  253  can be generated, determined, or calculated. In particular, a balancer module  254  can determine the first control signal  255  and the second control signal  257  based on the input steam control signal  253 , whereby the first control signal  255  and the second control signal  257  can be similar or equal, or can otherwise specify the same or equal positions for the corresponding valve A  222  and valve B  224  that control respective sprayers  210 ,  211  for steam respectively output from the first superheater component  204  and the second superheater component  205 . 
     At block  494 , the first control signal  255  can be modified based on the offset value  252 . In particular, the offset value  252  can be applied (e.g., added to, subtracted from, or the like) to the first control signal  255 . At block  496 , the first control signal that was modified  259  can be provided to a first field device  210  to control the first temperature  243 . At block  498 , the second control signal  257  can be provided to a second field device  211  to control the second temperature  244 . Each of the first field device  210  and the second field device  211  is a valve for a sprayer component (e.g., valve A  222  and valve B  224 ), although it should be appreciated that other field devices for controlling the temperatures  243 ,  244  are envisioned. 
     The control schemes, systems and methods described herein are each applicable to steam generating systems that use other types of configurations for superheater sections than illustrated or described herein. Thus, while  FIGS. 1-3  illustrate three superheater sections, the control scheme described herein may be used with boiler systems having more or less superheater sections, and which use any other type of configuration within each of the superheater sections. 
     Moreover, the control schemes, systems and methods described herein are not limited to controlling only an output steam temperature of a steam generating boiler system. Other dependent process variables of the steam generating boiler system may additionally or alternatively be controlled by any of the control schemes, systems and methods described herein. For example, the control schemes, systems and methods described herein are each applicable to controlling an amount of ammonia for nitrogen oxide reduction, drum levels, furnace pressure, throttle pressure, and other dependent process variables of the steam generating boiler system. 
     Although the forgoing text sets forth a detailed description of numerous different embodiments of the invention, it should be understood that the scope of the invention is defined by the words of the claims set forth at the end of this patent. The detailed description is to be construed as exemplary only and does not describe every possible embodiment of the invention because describing every possible embodiment would be impractical, if not impossible. Numerous alternative embodiments could be implemented, using either current technology or technology developed after the filing date of this patent, which would still fall within the scope of the claims defining the invention. 
     Thus, many modifications and variations may be made in the techniques and structures described and illustrated herein without departing from the spirit and scope of the present invention. Accordingly, it should be understood that the methods and apparatus described herein are illustrative only and are not limiting upon the scope of the invention.