Dynamic adjustment of a dynamic matrix control of steam temperatures

Abstract

Method for dynamically adjusting the control of a steam-generating boiler system (100), comprising the following: Determining the presence of a fault corresponding to a temperature (202) of the outlet steam, wherein the outlet steam is generated by the steam-generating boiler system (100) and is supplied from there to a turbine (116); Providing a signal indicating the magnitude of the error to an input of a function block (250E); Modifying the signal indicating the magnitude of the error using a function (250F) contained in the function block (250E); Generating an output of the function block (250E) based on the modified signal, which indicates the extent of the error; Adjusting a signal indicating a rate of change of a disturbance variable used in the steam-generating boiler system (100) based on the error, comprising adjusting the signal indicating the rate of change of the disturbance variable based on the output of the function block (250E); Generating a control signal based on the adapted signal indicating the rate of change of the disturbance variable by a dynamic matrix control (222); and Controlling the temperature of the outlet steam based on the control signal.

Description

Cross-reference to related applications

[0001] This application is a continuation-in-part of pending US patent application US 2012 / 0040298 A1, filed on August 16, 2010, entitled "Steam Temperature Control Using Dynamic Matrix Control," the contents of which are expressly incorporated herein by reference. General state of the art

[0002] Fuel-burning boilers are used in a variety of industrial and non-industrial applications. They typically convert chemical energy into heat energy through the combustion of various fuels, such as coal, gas, oil, waste materials, etc. An example application of fuel-burning boilers is in heat flow generators, where fuel-burning boilers convert water flowing through a number of pipes and tubes in the boiler into steam. The generated steam is then used to drive one or more steam turbines to generate electricity. The output of a heat flow generator is a function of the amount of heat generated in a boiler, with the amount of heat being directly determined by the amount of fuel consumed (e.g., burned) per hour.

[0003] In many cases, power generation systems include a boiler having a furnace that burns or otherwise consumes fuels to generate heat, which in turn is transferred to water flowing through pipes or tubes in various sections of the boiler. A conventional steam generation system includes a boiler having a superheater section (with one or more subsections) in which steam is generated, which is then typically fed to and used in a first steam turbine, usually a high-pressure steam turbine. To increase the efficiency of the system, the steam exiting this first steam turbine may be reheated in a reheater section, which may have one or more subsections, of the boiler and then fed to a second steam turbine, usually at a lower pressure.While the performance of a heat-based power generator depends largely on the heat transfer efficiency of the specific furnace / boiler combination used to burn the fuel and transfer the heat to the water flowing in the various sections of the boiler, this efficiency also depends on the control technology used to regulate the temperature of the steam in the various sections of the boiler, such as the superheater section of the boiler and the reheater section of the boiler.

[0004] However, it should be understood that steam turbines in a power plant are typically operated at different operating levels at different times to generate different amounts of electricity depending on energy or load demand. In most power plants that use steam boilers, the desired steam temperature setpoints at the end outlets of the superheaters and reheaters are maintained constant, and it is necessary to maintain the steam temperature close to (e.g., within a narrow range) these setpoints under all load levels. Steam temperature control is particularly essential in the operation of utility steam generators (e.g., for power generation), as it is important that the temperature of the steam exiting a boiler and entering a steam turbine be at the optimal, desired temperature.If the steam temperature is too high, it can damage the steam turbine blades for various metallurgical reasons. If the steam temperature is too low, the steam can contain water particles, which can damage steam turbine components over extended periods of operation and impair turbine performance. Fluctuations in steam temperature can also lead to material fatigue, which is the main cause of line leaks.

[0005] Typically, each section (i.e., the superheater section and the reheater section) of the boiler contains cascaded heat exchanger sections, with steam exiting one heat exchanger section being passed to the next heat exchanger section, and the temperature of the steam increasing in each heat exchanger section until, ideally, the steam reaches the desired steam temperature and is fed to the turbine. In such an arrangement, the steam temperature is controlled primarily by controlling the water temperature at the boiler's first stage exit, which is achieved primarily by varying the fuel / air mixture fed to the furnace or by varying the ratio of the combustion rate to the feedwater supplied to the furnace / boiler combination.In once-through boiler systems where no drum is used, the ratio of the combustion rate to the feedwater supply to the system can be used primarily to control the steam temperature at the inlet to the turbines.

[0006] While adjusting the fuel / air ratio and the ratio of combustion rate to feedwater supply to the furnace / boiler combination is well-suited to achieving the desired steam temperature control over time, it is difficult to control short-term fluctuations in steam temperature in different sections of the boiler solely by controlling the fuel / air ratio and the ratio of combustion rate to feedwater supply. To achieve short-term (and secondary) steam temperature control, saturated water is injected into the steam at a point before the last heat exchanger section, immediately upstream of the turbine. This secondary steam temperature control is typically performed before the last superheater section of the boiler and / or before the last reheater section of the boiler.To trigger this workflow, temperature sensors are arranged along the steam flow path and between the heat exchanger sections, which measure the steam temperature at critical points along the flow path, and the measured temperatures are used to control the amount of saturated water that is injected into the steam for steam temperature control purposes.

[0007] In many cases, such systems rely heavily on spray technology to control the steam temperature as precisely as necessary to meet the turbine temperature limitations described above. Once-through boiler systems, which provide a continuous flow of water (steam) through a series of pipes within the boiler and do not use a drum to average the temperature of the steam or water exiting the first boiler section, can experience larger fluctuations in steam temperature and typically make greater use of spray sections to control the steam temperature at the turbine inlets. In such systems, in addition to controlling the ratio of combustion rate to feedwater supply, superheater spray flow is typically used to control the furnace / boiler system.In these or other boiler systems, a distributed control system (DCS) uses cascaded PID (proportional-integral-differentiator) controllers to control both the supply of fuel / air mixture to the furnace and the amount of injection performed upstream of the turbines.

[0008] However, cascaded PID controllers typically react in a reactionary manner to an error or difference between a setpoint and the actual value or level of a dependent process variable being controlled, such as the temperature of the steam being fed to the turbine. The controller therefore only reacts after the dependent process variable has already deviated from its setpoint. Spray valves upstream of a turbine, for example, are controlled to adjust their spray flow only after the temperature of the steam being fed to the turbine has already deviated from the desired target value. This reactionary control behavior, combined with changing boiler operating conditions, can lead to large temperature swings that place severe stress on the boiler system and shorten the life of the piping, spray control valves, and other system components.

[0009] From US 2010 / 0 077 970 A1, a method for controlling the outlet temperatures of steam from a final superheater of a steam generation system with heat recovery is known, comprising the following steps: predicting an outlet temperature of steam from the final superheater using a model-based predictive temperature control; and performing a temperature control upstream of an inlet to the final superheater if the predicted outlet temperature of the steam is greater than a setpoint temperature for the outlet temperature.

[0010] WO 2009 / 106563 A2 discloses a method for controlling a single-tube steam generator integrated into a combined-cycle power plant with a steam turbine and a gas turbine, wherein the steam generator has an HP economizer, an HP evaporator, and at least one superheater. The method is characterized in that the opening of a valve for regulating the flow volume in a feedwater supply line into the high-pressure evaporator is controlled in series by means of several control stages as a function of a setpoint temperature for the steam for the steam turbine and a measured steam temperature at the outlet of the at least one superheater. The control stages take into account the measured steam temperature at the outlet of the superheater, a degree of superheating at the outlet of the high-pressure evaporator, and a degree of subcooling of the feedwater at the inlet to the high-pressure evaporator.

[0011] WO 2010 / 108904 A2 discloses a method for controlling the temperature of steam in a steam power plant. In this method, a state controller feeds back several steam states in a superheater for superheating the steam with the aid of an observer that calculates these states, outputting a steam setpoint temperature as a manipulated variable. The steam setpoint temperature is then passed on to another controller for temperature control.

[0012] DE 10 2007 035 976 A1 discloses a saturated water spray system configured to respond rapidly to rapid load changes by implementing a single integrated DCS control block. The integrated DCS control block may include a variety of process control routines necessary to control the operation of the spray system. For example, upstream and downstream PID control routines may determine and output control variables, and other control routines may be provided as needed to handle disturbances in a boiler that affect the steam outlet and spray temperatures and to ensure that steam temperatures do not fall into the saturation range during boiler operation. Brief description

[0013] It is an object of the present invention to provide an improved method for dynamically adjusting the control of a steam-generating boiler system as well as a corresponding control unit and a steam boiler system.

[0014] The object is achieved by a method having the features of patent claim 1, a control unit having the features of patent claim 3 and a steam boiler system having the features of patent claim 5. Advantageous further developments are specified in the subclaims.

[0015] An embodiment of a method for dynamically adjusting the control of a steam boiler system may include determining the presence of a fault corresponding to a temperature of the exit steam, wherein the exit steam is generated by the steam boiler system to be then supplied to a turbine. The method may further include adjusting a signal indicative of a rate of change of a disturbance variable used in the steam-generating boiler system based on the fault and generating a control signal based on the adjusted signal indicative of the rate of change of the disturbance variable through a dynamic matrix controller. The method may further include controlling the temperature of the exit steam based on the control signal.

[0016] An embodiment of a dynamically adjusted controller for use in a steam boiler system may include a dynamically adjusted controller communicatively coupled to a field device and a boiler of the steam boiler system. The dynamically adjusted controller may include a dynamic matrix controller (DMS) having a first DMS input at which a signal indicative of a rate of change of a disturbance variable of the steam boiler system is received, a second DMS input at which a signal indicative of an error corresponding to a temperature of the outlet steam generated by the steam boiler system is received, and a dynamic matrix control routine.The dynamic matrix control routine may be configured such that, when executed, it adjusts the signal indicative of the rate of change of the disturbance variable based on the signal corresponding to the error and determines a control signal based on the adjusted signal indicative of the rate of change of the disturbance variable. The strain gauge may further include a strain gauge output to provide the control signal to the field device to thereby control the outlet steam temperature.

[0017] An embodiment of a steam boiler system may include a boiler, a field device, a controller communicatively coupled to the boiler and the field device, and a dynamically tuned control system. The dynamically tuned control system may be communicatively coupled to the controller to receive a signal indicative of a rate of change of a disturbance variable. The dynamically tuned control system may include a routine that, when executed, modifies the signal indicative of the rate of change of the disturbance variable based on a difference between a setpoint and a level of an output parameter of the boiler, generates a control signal based on the modified signal indicative of the rate of change of the disturbance variable, and provides the control signal to the field device to control the level of the output parameter of the boiler. Brief description of the drawings

[0018] They show: Fig. 1 is a block diagram of a typical boiler steam cycle for a conventional set of steam-driven turbines, the boiler steam cycle comprising a superheater section and a reheater section; Fig. 2 is a schematic diagram of a control of a superheater section of a boiler steam cycle for a steam-driven turbine, as in Fig. 1, according to the current state of the art; Fig. 3 is a schematic diagram of a control of a reheater section of a boiler steam cycle for a steam-driven turbine system, as shown in Fig. 1, according to the current state of the art; Fig. 4 a schematic diagram of a method for controlling the boiler steam cycle of the steam-driven turbines from Fig. 1, in a way that helps to optimize the efficiency of the system; Fig. 5A an embodiment of the rate of change detector of Fig. 4; Fig. 5B an embodiment of the error detection unit from Fig. 4; Fig. 5C an example of a function f(x) that is used in the function block Fig. 5B is included; Fig. 5D is a schematic representation of a control method for the boiler steam cycle of the steam-driven turbines from Fig. 1 in a manner which prevents saturated steam from entering a superheater section of a steam boiler system; Fig. 5E an embodiment of the prevention block from Fig. 5D; Fig. 5F an example of a function g(x) that is used in the fuzzifier from Fig. 5E is included; Fig. 6 an exemplary method of controlling a steam boiler system; Fig. 7 an exemplary method of dynamic control adjustment of a steam boiler system; and Fig. 8 shows an exemplary method for preventing saturated steam from entering a superheater section of a steam boiler system. Detailed description

[0019] Although the following text discloses a detailed description of several different embodiments of the invention, it is to be understood that the legal scope of the invention is defined by the language of the claims recited at the end of this patent. This detailed description is to be interpreted as exemplary only and does not describe every possible embodiment of the invention, since describing every possible embodiment would be impractical, if not impossible. Using current technology or technology developed after the filing date of this patent, numerous alternative embodiments can be implemented that would still fall within the scope of the claims defining this invention.

[0020] Fig. Figure 1 shows a block diagram of a once-through boiler steam cycle for a conventional boiler 100, which may be used, for example, in a thermal power plant. The boiler 100 may include several sections through which steam or water flows in various forms, for example, as superheated steam, reheated steam, etc. During the Fig. 1 comprises a plurality of horizontally arranged boiler sections, in an actual implementation one or more of these sections may be arranged vertically (relative to each other), particularly since exhaust gases which heat the steam in a plurality of different boiler sections, such as the water wall absorption section, rise vertically (or spiral vertically).

[0021] As in Fig. 1, the boiler 100 in any case includes a furnace and a primary water wall absorption section 102, a primary superheater absorption section 104, a superheater absorption section 106, and a reheater section 108. In addition, the boiler may include one or more desuperheater or spray sections 110 and 112 and a preheater section 114. During operation, the main steam generated by the boiler 100 and exhausted from the superheater section 106 is used to drive a high pressure (HP) steam turbine 116, and the hot, heated steam coming from the reheater section 108 is used to drive an intermediate pressure (IP) turbine 118. Typically, the boiler 100 may also be used to drive a low pressure (LP) turbine, which in Fig. 1 is not shown.

[0022] The water wall absorption section 102, which is primarily responsible for steam generation, includes a number of conduits through which water or steam from the economizer section 114 is heated in the furnace. Feedwater flowing into the water wall absorption section 102 can, of course, be pumped through the economizer section 114, and this water absorbs a large amount of heat in the water wall absorption section 102. The steam or water provided at the outlet of the water wall absorption section 102 is passed to the primary superheater absorption section 104 and from there to the superheater absorption section 106, which together raise the steam temperature to very high temperature levels. The main steam outlet from the superheater absorption section 106 drives the high-pressure turbine 116 to generate electricity.

[0023] Once the main steam drives the high-pressure turbine 116, the steam is passed through the reheater absorption section 108, and the hot, reheated steam exhaust from the reheater absorption section 108 is used to drive the intermediate-pressure turbine 118. The spray sections 110 and 112 can be used to control the final steam temperature at the inlets of the turbines 116 and 118 to desired setpoints. The steam from the intermediate-pressure turbine 118 can finally be passed through a low-pressure turbine system (not shown here) to a steam condenser (not shown here) where the steam is condensed to a liquid, and then the cycle begins again with multiple boiler feed pumps passing feedwater for the next cycle, first through a cascade of feedwater heater banks and then through an economizer.The preheater section 114 is located in the flow of hot exhaust gases exiting the boiler and uses the hot gases to transfer additional heat to the feedwater before the feedwater enters the water wall absorption section 102.

[0024] As in Fig. 1, a controller or control unit 120 within the water wall section 102 is communicatively connected to the furnace and valves 122 and 124, which regulate the amount of water supplied to the sprayers in the spray sections 110 and 112. The controller 120 is also connected to various sensors, including intermediate temperature sensors 126A located at the outlets of the water wall section 102, the desuperheater 110, and the desuperheater 112; exit temperature sensors 126B located at the second superheater section 106 and the reheater section 108; and flow sensors 127 at the outlets of the valves 122 and 124.The controller 120 also receives other inputs, including the combustion rate, a load signal (commonly referred to as a feedforward signal) corresponding to an actual or desired load of the power plant and / or indicative of a difference in that load, and signals indicative of boiler settings or functions, such as 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 flow, other temperature measurements, etc. Although not specifically identified as such in . Fig. 1, the controller or control unit 120 could also include separate sections, routines and / or control devices for controlling the superheater and reheater sections of the boiler system.

[0025] Fig. 2 is a schematic diagram 128 showing the various sections of the boiler system 100 of Fig. 1 and shows a conventional manner in which control is currently carried out in boilers according to the current state of the art. In particular, in diagram 128, the preheater 114, the primary furnace or water wall section 102, the superheater section 104, the secondary superheater section 106, and the spray section 110 are shown. Fig. 1. In this case, the spray water supplied to the superheater spray section 110 is taken from the supply line to the preheater 114. Fig. 2 also shows two PID-based control loops 130 and 132, which are formed in the controller 120 from Fig. 1 or by other DCS controls to control the fuel and feedwater operation of the furnace 102 to in turn affect the temperature 151 of the outlet steam supplied from the boiler system to the turbine.

[0026] The control loop 130 specifically includes a first control block 140, illustrated as a proportional-integral-derivative (PID) control block, which has as its primary input a setpoint 131A in the form of a factor or signal corresponding to a desired or optimal value of a variable or manipulated variable 131A used to control or related to a portion of the boiler system 100. The desired value 131A may, for example, correspond to a desired superheater spray setpoint or an optimal burner tilt position. In other cases, the desired or optimal value 131A may correspond to a damper position of a damper in the boiler system 100, a spray valve position, a spray volume, another control, a manipulated variable, or disturbance variable, or a combination thereof, used to control or related to a portion of the boiler system 100.Generally, the setpoint 131A may correspond to a control variable or manipulated variable of the boiler system 100 and may typically be set by a user or operator.

[0027] The control block 140 compares the setpoint 131A with a measurement of the actual control variable or manipulated variable 131B currently being used to produce a desired output value. To clarify the description, Fig. 2 illustrates an embodiment in which the setpoint 131A at control block 140 corresponds to a desired superheater spray rate. Control block 140 compares the superheater spray setpoint to a measurement of the actual superheater spray rate (e.g., superheater spray flow) currently being used to generate a desired waterwall exit temperature setpoint. The waterwall exit temperature setpoint indicates the desired waterwall exit temperature required to control the temperature at the exit of the second superheater 106 (reference numeral 151) to match the desired turbine inlet temperature based on the spray flow rate determined by the desired superheater spray setpoint.This waterwall exit temperature setpoint is passed to a second control block 142 (also shown as a PID control block), which compares the waterwall exit temperature setpoint with a signal indicative of the measured waterwall vapor temperature and generates a flow control signal. The flow control signal is then scaled in a multiplier block 144, for example, based on the combustion rate (which indicates or is based on a power demand). The output of the multiplier block 144 is passed as a control input to a fuel / feedwater circuit 146, which controls the ratio between the combustion rate and the feedwater of the furnace / boiler combination, or the ratio of the fuel / air mixture provided to the primary furnace section 102.

[0028] The operation of the superheater spray section 110 is controlled by control loop 132. The control loop 132 includes a control block 150 (shown as a PID control block) which compares a temperature setpoint for the temperature of the steam at the inlet of the turbine 116 (usually set or established based on operating characteristics of the turbine 116) with a measurement of the actual temperature of the steam at the inlet of the turbine 116 (reference numeral 151) to generate an output control signal based on the difference between the two values. The output of the control block 150 is passed to an adder block 152, which adds the control signal from the control block 150 to a feedforward signal generated by a block 154, for example, a derivative of a load signal corresponding to an actual or desired load generated by the turbine 116.The output of adder block 152 is then passed as a setpoint to another control block 156 (again shown as a PID control block), where the setpoint indicates the desired temperature at the inlet of the second superheater section 106 (reference numeral 158). The control block 156 compares the setpoint from block 152 to an intermediate measurement of the steam temperature 158 at the outlet of the superheater spray section 110 and, based on the difference between the two values, generates a control signal that regulates the valve 122, which controls the amount of spray provided in the superheater spray section 110. According to this description, an "intermediate" measurement or value of a controlled or manipulated variable is determined at a location upstream of a location at which a dependent process variable to be controlled is measured. As shown in . Fig. 2, the "intermediate" steam temperature 158 is determined at a location upstream of the location at which the exit steam temperature 151 is measured (e.g., the "intermediate steam temperature" or "intermediate steam temperature" 158 is determined at a location farther from the turbine 116 than the exit steam temperature 151).

[0029] As can be seen from the PID-based control loops 130 and 132 Fig. 2, the operation of the furnace 102 is thus directly controlled as a function of the desired superheater spray rate 131A, the intermediate temperature measurement 158, and the exit steam temperature 151. In particular, the control circuit 132 maintains the temperature of the steam at the inlet of the turbine 116 (reference numeral 151) at a setpoint by controlling the operation of the superheater spray section 110, and the control circuit 130 controls the operation of the fuel supplied to and combusted in the furnace 102 to maintain the superheater spray rate at a predetermined setpoint (thus maintaining the superheater spray operation or spray rate at an "optimal" level).

[0030] While the described embodiment utilizes the superheater spray flow rate as input to control loop 130, it should be understood that one or more other control-related signals or factors may be utilized, or in other cases, used as input to control loop 130 to generate one or more output control signals to control boiler / furnace operation and thus provide steam temperature control. For example, control block 140 may compare the actual burner tilt positions to an optimal burner tilt position, which may be derived from a characterization of a computer-independent unit (particularly for boiler systems manufactured by Combustion Engineering), a separate, connected optimization program, or other source.In another example with a different boiler design configuration, in cases where flue gas bypass dampers are used for primary reheater steam temperature control, the signals indicating the desired (or optimal) and actual burner tilt positions in control loop 130 may be replaced or supplemented by signals indicating the desired (or optimal) and actual damper positions.

[0031] While the control circuit 130 in Fig. 2 as a control loop that generates a control signal to regulate the fuel / air mixture of the fuel supplied to the furnace 102, the control loop 130 could additionally generate other types or kinds of control signals to control the operation of the furnace, such as the fuel-feedwater ratio used to supply fuel and feedwater to the furnace / boiler combination, the amount or quantity or type of fuel used in or supplied to the furnace, etc. Furthermore, the control block 140 may use disturbance variable(s) as an input, even if that variable itself is not used to directly control the dependent variable (in the embodiment described above, the desired exit steam temperature 151).

[0032] Furthermore, the control of the operation of the furnace, as can be seen from the control circuits 130 and 132 in Fig. 2, in both control loops 130 and 132, the control circuits are reactionary. This means that the control loops 130 and 132 (or parts thereof) react in such a way that they only initiate a change after a difference between a setpoint and an actual value has been detected. For example, only after the control block 150 has detected a difference between the outlet steam temperature 151 and a desired setpoint does the control block 150 generate a control signal that is sent to the adder 152, and only after the control block 140 has detected a difference between a desired and an actual value of a disturbance variable or manipulated variable does the control block 140 generate a control signal corresponding to a setpoint for the water wall outlet temperature and forward it to the control block 142.This reactionary control behavior can result in large output fluctuations that stress the boiler system, shortening the life of piping, spray control valves, and other system components, especially when the reactionary control occurs in conjunction with changing operating conditions.

[0033] Fig. Figure 3 shows a conventional (state of the art) control circuit 160 used in a reheater section 108 of a steam turbine power generation system, for example, controlled by the controller or control unit 120 in Fig. 1. Here, a control block 161 can operate with a signal corresponding to an actual value of a control variable or a manipulated variable 162 used to control or related to the boiler system 100. To clarify the description, Fig. 3 shows an embodiment of control loop 160 in which input 162 corresponds to steam flow (usually determined by load demand). Control block 161 generates a temperature setpoint for the temperature of the steam introduced into turbine 118 as a function of steam flow. A control block 164 (shown as a PID control block) compares this temperature setpoint with a measurement of the actual steam temperature 163 at the outlet of reheater section 108 to generate a control signal resulting from the difference between these two temperatures. A block 166 then adds this control signal to a measurement of steam flow, and the output of block 166 is passed to a spray setpoint unit or block 168 and a compensation unit 170.

[0034] The balancing unit 170 includes a balancer 172, which sends a control signal to a superheater damper control unit 174 and a reheater damper control unit 176, which control the exhaust dampers in the various superheater and reheater sections of the boiler. It should be understood that the exhaust damper control units 174 and 176 adjust or modify the damper settings to control the amount of exhaust gases from the furnace diverted to the superheater and reheater sections of the boiler. Accordingly, the control units 174 and 176 thus control or balance the amount of energy provided by each of the superheater and reheater sections of the boiler.As a result, the balancing unit 170 is the primary control at the reheater section 108 for regulating the amount of energy or heat generated in the furnace 102 used in the operation of the reheater section 108 of the boiler system in . Fig. 1 is used. The operation of the dampers provided by the balancing unit 170, of course, controls the ratio or relative amount of energy or heat supplied to the reheater section 108 and the superheater sections 104 and 106, since diverting more exhaust gases to one section usually reduces the amount of exhaust gases supplied to the other section. Although the balancing unit 170 in Fig. 3 as the unit performing the damper control, the equalizer 170 may further also provide control by the furnace burner tilt position, or in some cases both.

[0035] Due to temporary or short-term fluctuations in steam temperature and the fact that the operation of the balancing unit 170 is related to the operation of the superheater sections 104 and 106 and the reheater section 108, the balancing unit 170 may not be able to provide complete control of the steam temperature 163 at the outlet of the reheater section 108 to ensure that the desired steam temperature is achieved at this point 161. For this reason, a second control of the steam temperature 163 is provided by the use of the reheater spray section 112 at the inlet of the turbine 118.

[0036] In particular, control of the reheater spray section 112 is provided by the operation of the spray setpoint unit 168 and a control block 180. In this case, the spray setpoint unit 168 determines a reheater spray setpoint in a known manner based on a plurality of factors, taking into account the operation of the balancing unit 170. Typically, the spray setpoint unit 168 is only configured to operate the reheater spray section 112 when the operation of the balancing unit 170 cannot provide sufficient or adequate control of the steam temperature 161 at the inlet of the turbine 118.In any case, the reheater spray setpoint is provided as a setpoint to control block 180 (again depicted as a PID control block), which compares this setpoint to a measurement of the actual steam temperature 161 at the outlet of the reheater section 108. Based on the difference between these two signals, a control signal is generated, and the control signal is used to control the reheater spray valve 124. As is already known, the reheater spray valve 124 provides a controlled reheater spray rate to provide further or additional control of the steam temperature at the outlet of the reheater 108.

[0037] In some embodiments, the control of the reheater spray section 112 may be performed using a similar control scheme as for Fig. 2. The use of a reheater section variable 162 as input to the control loop 160 from Fig. 3, for example, is not limited to a manipulated variable that is used to actually control the reheater section in certain situations. Accordingly, it may also be possible to use a manipulated variable 162 of the reheater that is not actually used to control the reheater section 108, or another control or disturbance variable of the boiler system 100, as input to the control loop 160.

[0038] Similar to the PID-based control loops 130 and 132 from Fig. 2, the PID-based control loop 160 is also reactionary. This means that the PID-based control loop 160 (or portions thereof) reacts by initiating a change only after a difference or error between a setpoint and an actual value has been detected. For example, control block 164 generates a control signal to be passed to summer 166 only after control block 164 has detected a difference between the exit steam temperature 163 and a desired setpoint generated by control block 161, and only after control block 180 has detected a difference between the reheater exit temperature 163 and the setpoint determined by block 168 does control block 180 pass a control signal to spray valve 124.This reactionary control behavior, combined with changing boiler operating conditions, can lead to large discharge fluctuations that shorten the life of piping, spray control valves, and other system components.

[0039] Fig. 4 shows an embodiment of a control system or control scheme 200 for controlling the steam generating boiler system 100. The control system 200 may control at least a portion of the boiler system 100, such as a control variable or other dependent process variables of the boiler system 100. In the Fig. In the example illustrated in Figure 4, the control system 200 regulates a temperature of the exit steam 202 supplied from the boiler system 100 to a turbine 116. However, in other embodiments, the control scheme 200 may additionally or alternatively control other portions of the boiler system 100 (e.g., a central portion, such as the temperature of the steam entering the second superheater section 106, or a system output, an output parameter, or an output control variable, such as a pressure of the exit steam at the turbine 118). In some embodiments, multiple control schemes 200 may control different output parameters.

[0040] The control system or control scheme 200 may be implemented in or communicatively coupled to the controller or control unit 120 of the boiler system 100. For example, in some embodiments, at least a portion of the control system or control scheme 200 may be included in the controller 120. In some embodiments, the entire control system or control scheme 200 may be included in the controller 120.

[0041] In fact, the tax system can be 200 Fig. 4 the PID-based control loops 130 and 132 Fig. 2. Instead of being implemented in a reactionary manner like control loops 130 and 132 (e.g., where a control adjustment is only performed after a difference or error between the portion of the boiler system 100 being controlled and an associated setpoint is detected), the control scheme 200 is implemented at least in part as feedforward so that the control adjustment is initiated before a difference or error is detected at the portion of the boiler system 100. In particular, the control system or scheme 200 may be based on a rate of change of one or more disturbance variables that affect the portion of the boiler system 100 to be controlled. A dynamic matrix control (DMS) block may receive the rate of change of the one or more disturbance variables at an input and cause the process to execute at an optimal point based on the rate of change.Furthermore, the strain gauge block can continuously optimize the process as the rate of change itself changes. Because the strain gauge block continuously estimates the best control response and predictively optimizes and adjusts the process based on current inputs, the dynamic matrix control block is implemented as feedforward, or predictive, and is thus capable of controlling the process closer to its setpoint. Accordingly, with the strain gauge-based control system 200, the process components are not subject to large temperature fluctuations or other such factors. On the contrary, PID-based control systems or schemes are not capable of predicting or estimating optimization at all, since PID-based control systems or schemes rely on a measurement result or error in the controlled variable actually occurring to perform any process adjustments.As a result, PID-based control systems or schemes deviate further from desired setpoints than control system or scheme 200, and the process components of PID-based control systems typically fail sooner due to these extremes.

[0042] Another difference to the PID-based control loops 130 and 132 from Fig. 2 is that the DMS-based control system or scheme 200 does not require as input an intermediate or upstream measured value corresponding to the portion of the boiler system 100 to be controlled, such as the intermediate steam temperature 158 determined after the spray valve 122 and before the second superheater section 106. Because the DMS-based control system or scheme 200 operates at least partially predictively, the DMS-based control system or scheme 200 does not require intermediate "checkpoints" to optimize the process, as is the case with PID-based schemes. These differences and details of the control system 200 are described in more detail below.

[0043] In particular, the control system or scheme 200 includes a rate of change detector 205 that receives a signal corresponding to a measurement of an actual disturbance variable of the control scheme 200 that is currently affecting a desired operation of the boiler system 100, or a desired output value of a control variable or dependent process variable 202 of the control scheme 200, similar to the measurement of the control variable or manipulated variable 131B provided at the control block 140 from Fig. 2 is received. In the Fig. 4, the desired operation of the boiler system 100 or the controlled variable of the control scheme 200 is the outlet steam temperature 202, and the disturbance variable input to the control scheme 200 at the rate-of-change detector 205 is a fuel / air ratio 208 supplied to the furnace 102. However, the input to the rate-of-change detector 205 may be any disturbance variable. For example, the disturbance variable of the control scheme 200 may be a manipulated variable used in a different control loop of the boiler system 100 than the control scheme 200, such as a damper position. The disturbance variable of the control scheme 200 may be a control variable used in a different control loop of the boiler system 100 than the control scheme 200, such as the intermediate temperature 126B of Fig. 1. The disturbance variable input to the rate-of-change detector 205 can be viewed simultaneously as a control variable of another specific control loop and as a manipulated variable of another control loop in the boiler system 100, such as the fuel-air ratio. The disturbance variable can be another disturbance variable of another control loop, e.g., ambient air pressure or another process input variable.Examples of possible disturbance variables that may be used in conjunction with the DMS-based control system or scheme include, but are not limited to, a furnace burner tilt position; a steam flow; a sootblower amount; a damper position; a power setting; a furnace fuel-to-air mixture ratio; a furnace combustion rate; a spray flow; a waterwall steam temperature; a load signal for either the target load or the actual turbine load; a flow temperature; a fuel-to-feedwater mixture ratio; the exit steam temperature; a fuel amount; a fuel type; or another manipulated, control, or disturbance variable. In some embodiments, the disturbance variable may be a combination of one or more control variables, manipulated variables, and / or disturbance variables.

[0044] Although only one signal corresponding to a measurement of a disturbance variable of the control system or scheme 200 is shown as being received at the rate of change determiner 205, in some embodiments, one or more signals corresponding to one or more disturbance variables of the control system or scheme 200 may also be received by the rate of change determiner 205. In contrast to reference numeral 131A of Fig. 2, it is not necessary for the rate of change detector 205 to receive a setpoint or desired / optimal value corresponding to the measured disturbance variable, e.g., in Fig. 4 not required to receive a setpoint for the fuel-air ratio 208.

[0045] The rate of change determiner 205 is configured to determine a rate of change of the disturbance variable input 208 and generate a signal 210 corresponding to the rate of change of the input 208. Fig. 5A shows an example of the rate of change determiner 205. In this example, the rate of change determiner 205 includes at least two time difference blocks 214 and 216, each adding a lead or delay to the received input 208. Using the two time difference blocks 214 and 216, the rate of change determiner 205 determines a difference between two measurements of the signal 208 at two different times and accordingly determines a decay or rate of change of the signal 208.

[0046] In particular, the signal 208 corresponding to the measurement of the disturbance variable may be received at an input of the first time difference block 214, which adds a time delay. An output generated by the first time difference block 214 may be received at a first input of a difference block 218. The output of the first time difference block 214 may also be received at an input of a second time difference block 216, which may add an additional time delay that may be the same as or different from the time delay added by the first time difference block 214. The output of the second time difference block 216 may be received at a second input of the difference block 218.The difference block 218 determines a difference between the outputs of the time difference blocks 214 and 216 and can determine a decay or rate of change of the disturbance variable 208 based on the time delays of the time difference blocks 214, 216. The difference block 218 can generate a signal 210 corresponding to a rate of change of the disturbance variable 208. In some embodiments, one or both of the time difference blocks 214, 216 can be adjustable to vary their respective time delays. For example, for a disturbance input 208 that changes very slowly over time, a time delay at one or both of the time difference blocks 214, 216 can be increased. In some embodiments, the rate of change determiner 205 can collect more than two measurements of the signal 208 to more accurately calculate the decay or rate of change. Fig. 5A is of course only an example of the change rate detector 205 from Fig. 4 and other examples may be possible.

[0047] With further reference to Fig. 4, the signal 210 corresponding to the rate of change of the disturbance variable may be received by a gain block or gain adjuster 220, which amplifies the signal 210. The amplification may be broadening or fractional. The amount of amplification added by the gain block 220 may be manually or automatically selected. In some embodiments, the gain block 220 may be omitted.

[0048] The signal 210, which corresponds to the rate of change of the disturbance variable of the control system or scheme 200 (including a desired gain added by the optional gain block 220), may be received at a dynamic matrix control (DMS) block 222. The DMS block 222 may also receive as inputs a measurement of a current or actual value of a portion of the boiler system 100 to be controlled (e.g., the control variable or controlled variable of the control system or scheme 200; in the example of Fig. 4 the temperature 202 of the steam outlet), and an associated setpoint 203. The dynamic matrix control block 222 can perform a model predictive control based on the received inputs to generate a control output signal. It should be noted that the DMS block 222, in contrast to the PID-based control loops 130 and 132 of Fig. 2, no signals corresponding to intermediate measurements of the part of the boiler system 100 to be controlled, such as the intermediate steam temperature 158, need be received. However, such signals may, if desired, be used as inputs to the DMS block 222, for example, when a signal corresponding to an average measurement is input to the rate of change detector 205 and the rate of change detector 205 generates a signal corresponding to the rate of change of the average measurement. Although this is Fig. 4, the strain gauge block 222 may also receive other inputs in addition to the rate-of-change signal 210, the signal corresponding to an actual value of the controlled variable (e.g., reference numeral 202), and its setpoint 203. For example, the strain gauge block 222 may receive signals other than the rate-of-change signal 210 that correspond to zero or more disturbance variables.

[0049] Generally speaking, the model predictive control performed by DMS block 222 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 are measured, and these measured responses are then used to create a model of the process. However, in some cases, a multiple-input, multiple-output (MIMO) control strategy may also be employed. Whether MISO or MIMO, the model of the process is mathematically inverted and then used to control the process output(s) based on changes in the process inputs.In some cases, the process model includes, or is derived from, a process output response curve for each of the process inputs, and each of these curves can be constructed, for example, based on a series of pseudorandom step changes applied to each of the process inputs. These response curves can be used to shape the process in a known manner. Because model predictive control is well known in the art, the specific details will not be discussed here. Model predictive control is generally described in Qin, S. Joe, and Thomas A. Badgwell, "An Overview of Industrial Model Predictive Control Technology," AIChE Conference, 1996.

[0050] Furthermore, the generation and use of advanced control routines, such as MPC control routines, can be integrated into the configuration process for a controller for the steam-generating boiler system. Wojsznis et al., US Pat. No. 6,445,963 B1, entitled "Integrated Advanced Control Blocks in Process Control Systems," the disclosure of which is expressly incorporated by reference herein, discloses a method for generating an advanced control block, such as an advanced controller (e.g., an MPC controller or a neutral network controller), using data collected during process plant configuration.More specifically, US 6,445,963 B1 discloses a configuration system that creates an advanced multi-input / multi-output control block in a process control system in a manner integrated with the creation and downloading of other control blocks that use a particular control pattern, such as the Fieldbus pattern. In this case, the advanced control block is initiated by creating a control block (such as DMS block 222) having desired inputs and outputs associated with process outputs and inputs, respectively, to control a process, such as a process used in a steam-generating boiler system.The control block includes a data collection routine and an associated function generator and may have control logic that is frequency-independent or otherwise undeveloped because this logic lacks tuning parameters, matrix coefficients, or other control parameters required for implementation. The control block is placed within the process control system, with the defined inputs and outputs communicatively linked within the control system so that these inputs and outputs would be linked when the advanced control block were deployed to control the process. During a test run, the control block systematically overrides each of the process inputs using functions generated by a function generator specifically designed for use in generating a process model.Via the control block inputs, the control block coordinates the collection of data related to the response of each of the process outputs to each of the generated functions passed to each of the process inputs. This data can, for example, be sent to a data historian for storage. After sufficient data has been collected for each of the process input / output pairs, a process modeling operation is performed in which one or more process models are generated from the collected data, for example, using any known or desired model generation or model discovery routine. As part of this model generation or model discovery routine, a model parameter discovery routine can develop the model parameters, e.g., matrix coefficients, failure time, gain, time constants, etc., required by the control logic to control the process.The model generation routine or process model generation software can generate various types of models, including non-parametric models, such as finite impulse response (FIR) models, and parametric models, such as autoregressive models with external inputs (ARX). The control logic parameters and, if necessary, the process model are then downloaded to the control block to complete the advanced control block. This allows the advanced control block, with the model parameters and / or process model contained therein, to be used to control the process during operation. If desired, the model stored in the control block can be redefined, modified, or updated.

[0051] In the Fig. 4, the inputs to the dynamic matrix control block 222 include the signal 210 corresponding to the rate of change of one or more disturbance variables of the control scheme 200 (such as one or more of the disturbance variables described above), a signal corresponding to a measurement of an actual value or level of the controlled output 202, and a setpoint 203 corresponding to a desired or optimal value of the controlled output. Typically (but not necessarily), the setpoint 203 is determined by a user or operator of the steam generating boiler system 100.The strain gauge block 222 may utilize a dynamic matrix control routine to predict an optimal response based on the inputs and a stored model (usually parametric, but in some cases non-parametric), and the strain gauge block 222 may generate a control signal 225 to control a field device based on the optimal response. Upon receiving the signal 225 generated by the strain gauge block 222, the field device may adjust its operation based on the control signal 225 received from the strain gauge block 222 and bias the output toward the desired or optimal value. In this way, the control scheme 200 may feedforward the rate of change 210 of one or more disturbance variables and provide advanced correction for any difference or error that may occur in the output value or level.As the rate of change of the one or more disturbance variables 210 changes, the DMS block 222 further predicts a subsequent optimal response based on the changed inputs 210 and generates a corresponding updated control signal 225.

[0052] In the specific Fig. 4, the input to the rate of change determiner 205 is a fuel-to-air ratio 208 supplied to the furnace 102, the portion of the steam-generating boiler system 100 controlled by the control scheme 200 is the exit steam temperature 202, and the control scheme 200 controls the exit steam temperature 202 by adjusting the spray valve 122. Accordingly, a dynamic matrix control routine of the DMS block 222 uses the signal 210 corresponding to the rate of change of the fuel-to-air ratio 208 generated by the rate of change determiner 205, a signal corresponding to a measurement of an actual exit steam temperature 202, a desired exit steam temperature or setpoint 203, and a parametric model to determine a control signal 225 for the spray valve 122.The parametric model used by DMS block 222 can identify precise relationships between input values ​​and the control of spray valve 122 (rather than only one-way, as in the case of PID control). DMS block 222 generates control signal 225, and upon receipt, spray valve 122 adjusts a spray flow rate based on control signal 225, thereby influencing exit steam temperature 202 toward the desired temperature. Through this feedforward control, control system 200 regulates spray valve 122, and consequently exit steam temperature 202, based on a rate of change of fuel-to-air ratio 208. If fuel-to-air ratio 208 subsequently changes, DMS block 222 can utilize the updated fuel-to-air ratio 208, the parametric model, and, in some cases, previous input values, to determine a subsequent optimal response.A subsequent control signal 225 can then be generated and sent to the spray valve 122.

[0053] The control signal 225 generated by the strain gauge block 222 may be received by an amplifier block or gain adjuster 228 (e.g., a summing gain adjuster), which amplifies the control signal 225 before transmitting it to the field device 122. In some cases, the amplification may be expansion. In some embodiments, the amplification may be fractional. The amount of amplification added by the amplification block 228 may be selected manually or automatically. In some embodiments, the amplification block 228 may be omitted.

[0054] Steam-generating boiler systems, by their nature, generally respond somewhat slower to controls, due at least in part to the large volumes of water and steam moving through the system. To reduce response time, the control scheme 200 may include a secondary dynamic matrix control (DMS) block 230 in addition to the primary dynamic matrix control block 222. The secondary DMS block 230 may use a stored model (either parametric or non-parametric) and a secondary dynamic matrix control routine to determine an amount of gain by which the control signal 225 is varied based on the rate of change or derivative of the disturbance variable received at an input of the secondary DMS block 230. In some cases, the control signal 225 may also be based on a desired weighting of the disturbance variable and / or its rate of change.For example, a particular disturbance variable may be given a greater weight so that it has a greater influence on the controlled output (e.g., on reference numeral 202). Typically, the model stored in secondary DMS block 230 (e.g., the secondary model) may differ from the model stored in primary DMS block 222 (e.g., the primary model) because DMS blocks 222 and 230 each receive a different set of inputs to produce different outputs. Secondary DMS block 230 may produce a gain signal or secondary signal 232 at its output that corresponds to the gain measure.

[0055] An adder block 238 may receive the gain signal 232 generated by the secondary strain gauge block 230 (including any desired gain performed by the optional amplifier block 235) and the control signal 225 generated by the primary strain gauge block 222. The adder block 238 may combine the control signal 225 and the gain signal 232 to generate an adder output control signal 240 used to control a field device, such as the spray valve 122. For example, the adder block 238 may add the two input signals 225 and 232 or otherwise amplify the control signal 225 by the gain signal 232. The adder output control signal 240 may be sent to the field device to control the field device. In some embodiments, the adder output control signal 240 may optionally be amplified by the gain block 228 in the manner described above for the gain block 228.

[0056] Upon receipt of the adder output control signal 240, a field device, such as the spray valve 122, can be controlled so that the response time of the boiler system 100 is shorter than a response time if the field device were controlled solely by the control signal 225, in order to bring the portion of the boiler system being controlled to the desired operating value or level more quickly. For example, if the rate of change of the disturbance variable is slower, the boiler system 100 has more time to respond to the change, and the secondary strain gauge block 230 would generate a gain signal corresponding to a lower gain, which is combined with the control input of the primary strain gauge block 230.If the rate of change is faster, the boiler system 100 would have more time to react more quickly and the secondary strain gauge block 230 would generate a gain signal corresponding to a larger gain that is combined with the control output of the primary strain gauge block 230.

[0057] In the Fig. 4, the secondary DMS block 230 may receive the signal 210 from the rate of change determiner 205, which corresponds to the rate of change of the fuel-air ratio 208, including any desired gain added by the optional gain block 220. Based on the signal 210 and a parametric model stored in the secondary DMS block 230, the secondary DMS block 230 may determine (for example, via a secondary dynamic matrix control routine) a gain amount that is combined with the control signal 225 generated by the primary DMS block 222 and generate a corresponding gain signal 232. The gain signal 232 generated by the secondary DMS block 230 may be received by a gain block or gain (e.g., a derivative or gain adjuster) 235, which amplifies the gain signal 232.The gain may be either expansive or fractional, and the amount of gain introduced by gain block 235 may be selected manually or automatically. In some embodiments, gain block 235 may be omitted.

[0058] Although not illustrated here, various embodiments of the control system or scheme 200 are possible. For example, the secondary strain gauge block 230, the associated gain block 235, and the adder block 238 may be optional. Particularly in some systems with a faster response time, the secondary strain gauge block 230, the gain block 235, and the adder block 238 may be omitted. In some embodiments, one or all of the gain blocks 220, 228, and 235 may be omitted. In some embodiments, a single rate of change determiner 205 may receive one or more signals corresponding to multiple disturbance variables and provide a signal 210 corresponding to a rate of change to the primary strain gauge block 222.In some embodiments, multiple rate-of-change determiners 205 may receive one or more signals corresponding to different disturbance variables, and the primary strain gauge block 222 may receive multiple signals 210 from the multiple rate-of-change determiners 205. In embodiments including multiple rate-of-change determiners 205, each of the multiple rate-of-change determiners 205 may be connected to a different associated secondary strain gauge block 230, and the multiple secondary strain gauge blocks 230 may each provide their respective gain signals 232 to the adder block 238. In some embodiments, the multiple rate-of-change determiners 205 may each provide their respective gain outputs 210 to a single secondary strain gauge block 230. Of course, other embodiments of the control system 200 are possible.

[0059] Since the steam-generating boiler system 100 generally includes multiple field devices, embodiments of the control system or scheme 200 may further support the multiple field devices. For example, a different control system 200 may correspond to each of the multiple field devices, such that each of the different field devices is controlled by a different rate-of-change detector 205, a different primary DMS block 222, and a different (optional) secondary DMS block 230. This means that different operations of the control system 200 may be included in the boiler system 100, with each of the multiple operations corresponding to a different field device. In some embodiments of the boiler system 100, at least a portion of the control scheme 200 may serve multiple field devices. For example, a single rate-of-change detector 205 may serve multiple field devices, such as multiple spray valves.In an illustrative scenario where more than one spray valve is to be controlled based on a rate of change in the fuel-to-air ratio, a single rate of change determiner 205 may generate a signal 210 corresponding to the rate of change in the fuel-to-air ratio and route the signal 210 to different primary DMS blocks 222 corresponding to the different spray valves. In another example, a single primary DMS block 222 may control all spray valves in part or all of the boiler system(s) 100. In other examples, a single secondary DMS block 230 may route a gain signal 232 to multiple primary DMS blocks 222, with each of the multiple primary DMS blocks 222 routing its respective generated control signal 225 to a different field device. Of course, other embodiments of the control system or scheme 200 may be possible to control multiple field devices.

[0060] In some embodiments, the control system or scheme 200 and / or the control unit 120 may be dynamically adjusted. For example, the control system or scheme 200 and / or the control unit 120 may be dynamically adjusted using an error detection unit or block 250. In particular, the error detection unit may detect the presence of an error or difference between the desired value 203 of an output parameter and an actual value 202 of the output parameter. The error detection unit 250 may receive a signal corresponding to the output parameter 202 (in this example, the temperature of the outlet steam 202) at a first input. At a second input, the error detection unit 250 may receive a signal corresponding to the setpoint 203 of the output parameter 202.The error detection unit 250 may detect a magnitude of a difference between the signals received at the first and second inputs and may provide an output signal 252 indicating the magnitude of the difference to the primary dynamic matrix control block 222.

[0061] The DMS block 222 may receive a signal corresponding to the rate of change of the disturbance variable 210 at a third input. As described above, the signal indicative of the rate of change of the disturbance variable 210 may or may not be modified by the gain block 220. The DMS block 222 may adjust the signal corresponding to the rate of change of the SV 210 based on the output signal 252 generated by the error detection unit 250 (e.g., based on the magnitude of the difference between the target value 203 and the actual level of the output parameter 202). In some embodiments, if the output signal 252 of the error detection unit 250 indicates a larger difference, this may mean that a larger error or difference exists between an actual level of the output parameter 202 and a desired level 203 of the output parameter 202.Accordingly, the strain gauge block 222 may more aggressively adjust or adjust the signal corresponding to the rate of change of the SV 210 to more quickly compensate for the error or difference. e.g., the signal corresponding to the rate of change of the SV 210 may be adjusted to a greater extent. Similarly, if the output signal 252 of the error detection unit 250 indicates a smaller difference or error, the strain gauge block 222 may less aggressively adjust or adjust the signal corresponding to the rate of change of the SV 210. e.g., the signal corresponding to the rate of change of the SV 210 may be adjusted to a lesser extent.If the output signal 252 indicates that the magnitude of the difference between the actual level of the output parameter 202 and the desired level 203 of the output parameter 202 is substantially zero or otherwise within the tolerance range (as determined by an operator or system parameter), the control system or scheme 200 may be operated to maintain the output parameter 202 within an acceptable range and the signal corresponding to the rate of change of the SV 210 need not be adjusted.

[0062] In this way, the dynamic matrix control block 222 is capable of providing dynamic adjustment of the control system or scheme 200. For example, the DMS block 222 may provide dynamic adjustment of the rate of change of the disturbance variable 210 based on the magnitude of a difference or error between a desired level 203 and an actual level of the output parameter 202. As the magnitude of the difference or error changes, the magnitude of the rate of change adjustment of the SV 210 may be adjusted accordingly.

[0063] It should be noted that although the error detection block or unit 250 in Fig. 4 as a separate device from the DMS block 222, in some embodiments at least some portions of the error detection block or unit 250 and the DMS block 222 may be combined into a single device.

[0064] Fig. 5B shows an embodiment of the error detection unit or block 250 of Fig. 4. In this embodiment, the error detection unit 250 may include a difference block or unit 250A that determines the difference between the actual level of the output parameter 202 and its associated setpoint 203. With reference to Fig. 4, for example, the difference block 250A may determine the difference between the actual exit steam temperature 202 and a desired exit steam temperature setpoint 203. In one embodiment, the difference block / unit 250A may receive at a first input a signal indicative of an actual level of the output parameter 202 and at a second input a signal indicative of a setpoint 203 corresponding to the output parameter 202. The difference block or unit 250A may generate an output signal 250B indicative of the difference between the two inputs 202 and 203.

[0065] The error detection unit 250 may include an absolute value or magnitude block 250C that receives the output signal 250B from the difference block 250A and determines an absolute value or magnitude of a difference between the received input signals 202 and 203. In the Fig. In the embodiment illustrated in Figure 5B, the absolute value block 250C may generate an output signal 250D indicating a magnitude of the difference between the actual 202 and desired 203 values ​​of the output parameter. In some embodiments, the difference block 250A and the absolute value block 250C may be included in a single block (not shown) that receives the input signals 202, 203 and generates the output signal 250D indicating the magnitude of the difference between the actual 202 and desired 203 values ​​of the output parameter.

[0066] The output signal 250D may be provided to a functional block or functional unit 250E. The functional block or functional unit 250E may include a routine, algorithm, or computer-executable instructions for a function f(x) (reference 250F) that operates on the signal 250D (indicating the magnitude of the difference between the actual 202 and desired 203 output parameter levels). The output signal 252 of the error detection block 250 may be based on the output of the function f(x) (reference 250F) and may be provided to the dynamic matrix control block 222.Accordingly, the signal 250D, which indicates the magnitude of the difference between the actual 202 and desired 203 value of the output parameter, may be modified based on f(x) (reference 250F), and the modified or adjusted signal 252 may be provided to the dynamic matrix control block 222 to dynamically adjust the control system or control scheme 200.

[0067] In some embodiments, the output signal 252 of the fault detection 250 may be stored in a register R, which the DMS block 222 accesses to generate the control signal 225. In particular, the DMS block may compare the value in register R to a value in a register Q to determine an aggressiveness, reflected in the control signal 225, of the setting for controlling the control system 200. The value in register Q may, for example, be provided by another device within the control scheme 200 or boiler system 100, manually provided, or configured. In one example, when the value of R moves away from the value of Q, the DMS may adjust the control signal 225 more aggressively to control the process. When the value of R approaches the value of Q, the DMS block 222 may adjust the control signal 225 accordingly for less aggressive control.In other embodiments, the opposite may be true: as the value of R approaches the value of Q, the DMS may generate a more aggressive signal 225, and as the value of R moves farther away from the value of Q, the DMS may generate a less aggressive signal 225. In some embodiments, registers R and Q may be internal registers of the DMS block 222.

[0068] Fig. Figure 5C shows an example of a function f(x) (reference number 250F) that is generated in function block 250E from Fig. 5B. The function f(x) (reference numeral 250F) may use as an input the difference between the current or actual value of the output parameter 202 and its associated setpoint 203, as represented by the x-axis 260. In some embodiments, the value of the input 260 of f(x) may be determined by the signal 250D in Fig. 5B. The function f(x) may include a curve 262 that indicates an output value (e.g., the y-axis 265) for each input value 260. In some embodiments, a value of the output 265 of f(x) (reference number 250F) may be stored in the R register of the DMS block 222 and may influence the control signal 225. In the Fig. In the example shown in Figure 5C, an error or temperature difference between a current process value and its setpoint of 10 may result in an f(x) output of 2, and a zero point difference may result in an f(x) output of 20.

[0069] Although Fig. 5C shows one embodiment of the function f(x), other embodiments of f(x) may be used in conjunction with the error detection block 250. For example, the curve 262 may be different than in Fig. 5C. In another example, the value ranges of the x-axis 260 and / or the y-axis 265 can be Fig. 5C. In some embodiments, the output or y-axis of the function f(x) may not be provided to a register R. In some embodiments, the function f(x) may correspond to the output 252 of the error detector 250. Other embodiments of f(x) may also be possible.

[0070] In some embodiments, at least a portion of the function f(x) (reference numeral 250F) may be modifiable. This means that an operator may manually modify one or more portions of the function f(x) and / or one or more portions of the function f(x) may be automatically modified based on one or more parameters of the control scheme 200 or the boiler 100. For example, one or more boundary conditions of f(x) may be changed or modified, a constant contained in f(x) may be modified, a slope or curve of f(x) between a certain range of input values ​​may be modified, etc.

[0071] Again with reference to Fig. 5B, in some embodiments of the error detection block 250, the functional block 250E may be omitted. In these embodiments, the signal indicating the magnitude of the difference between the actual 202 and desired 203 value of the output parameter (reference numeral 250D) may correspond to the output signal 252 generated by the error detection block 250.

[0072] Some embodiments of the dynamic matrix control scheme or control system 200 may include preventing saturated steam from entering the superheater 106. As is well known, if steam at a saturated temperature is introduced into the final superheater 106, the saturated steam may be introduced into the turbine 202 and may therefore cause undesirable consequences, such as turbine damage. Accordingly, Fig. 5D illustrates an embodiment of the dynamic matrix control scheme or system 200 that includes a prevention block 282 that helps prevent saturated steam from entering the superheater 106. To keep the description as concise and clear as possible, Fig. 5D not the entire Fig. 4 is shown repeatedly. Instead, in Fig. 5D a section 280 of the control scheme 200 from Fig. 4, which includes the prevention block 282. It should be noted that although the prevention block 282 in Fig. 5D as a separate device from the DMS block 222, in some embodiments at least some portions of the prevention block 282 and the DMS block 222 may be combined into a single device.

[0073] The prevention block 282 may receive at a first input a control signal 225B from the primary DMS block 222. The DMS block 222 may receive a routine that generates a control signal 225A and is provided to the routine of the DMS block 222, which Fig. 4 generates the control signal 225. The embodiment 280 of Fig. 5D is also similar Fig. 4 in that the control signal 225A is shown as being added to the gain signal 232 at block 238, and the added signal is modified by gain in block 228, thus generating the control signal 225B. As also described above, in some embodiments, block 238 and / or block 228 may be optional (as indicated by dashed lines 285), and one or both of blocks 238 and 228 may be omitted. In embodiments where the blocks included in dashed lines 285 are omitted, the control signal 225B corresponds to the control signal 225A.

[0074] The prevention block 282 may receive a signal indicative of the atmospheric pressure (AD) 288 at a second input and may receive a signal indicative of the current intermediate steam temperature 158 at a third input. Based on the atmospheric pressure, the prevention block 282 may determine a saturated steam temperature. Based on the saturated steam temperature and the current intermediate steam temperature 158, the prevention block 282 may determine a magnitude of a temperature difference between temperatures 158 and 288 and determine an adjustment or modification of the control signal 225B corresponding to the magnitude of the temperature difference to prevent the intermediate steam temperature 158 from reaching the saturated steam temperature.When the control signal 225B is adjusted or modified, the prevention block 282 may provide an adjusted or modified control signal 225C at an output to control the intermediate steam temperature 158. In the embodiment shown in . Fig. 5D, the adjusted or modified control signal 225C may be provided to the spray valve 122, and the spray valve 122 may adjust its opening and closing based on the modified control signal 225C to help prevent the intermediate steam temperature 158 from reaching the saturated steam temperature.

[0075] Fig. Figure 5E shows an embodiment of the prevention unit or the prevention block of Fig. 5D. The prevention unit or block 282 may receive a signal indicative of a current atmospheric pressure (AD) 288 at a first input of a steam table or calculator 282A and a unit steam pressure at a second input of the steam table 282A. Steam tables or calculators, such as the steam table 282A, may determine a saturated steam temperature 282B based on a specified atmospheric pressure and the unit steam pressure. A signal indicative of the saturated steam temperature 282B may be provided from the steam table 282A to a first input of a comparator block or comparator unit 282C.The comparator block 282C may receive a signal indicative of the current intermediate steam temperature 158 at a second input and may determine a temperature difference between the saturated steam temperature 282B and the current intermediate steam temperature 158 based on the two received signals. In an exemplary embodiment, the comparator block 282C may determine a magnitude of the temperature difference. In other embodiments, the comparator block or comparator unit 282C may determine a direction of the temperature difference, e.g., whether the temperature difference is increasing or decreasing. The comparator 282C may provide a signal 282D indicative of the magnitude of the temperature difference or the direction of the temperature difference to a fuzzifier block or fuzzifier unit 282E.

[0076] The fuzzifier block 282E may receive the signal 282D at a first input and the control signal 225B at a second input. Based on the signal 282D from the comparator 282C (e.g., based on a temperature difference between the saturated steam temperature 282B and the current value of the intermediate steam temperature 158), the fuzzifier block 282E may determine an adjustment or modification of the control signal 225B and generate the adjusted or modified signal 225C at an output.

[0077] In some embodiments, the adjustment or modification of the control signal 225B may be determined based on a comparison of the magnitude of the temperature difference with a threshold T, such that the fuzzifier 282E does not adjust or modify the signal 225B until the threshold T is exceeded. In one example, the threshold T may be 15 degrees Fahrenheit (F) [or approximately 8.3 degrees Kelvin], and the examples and embodiments described herein refer to the threshold T being 15 degrees F [or approximately 8.3 degrees Kelvin] for convenience of description. However, it should be understood that other values ​​or units of the threshold T may also be possible. Furthermore, in some embodiments, the threshold T may be adjustable either automatically or manually.

[0078] In embodiments that include a threshold T, the fuzzifier block 282E may adjust the control signal 225B to generate a modified control signal 225C when the magnitude of the difference between the saturated steam temperature 282B and the actual intermediate steam temperature is less than T (e.g., less than 15 degrees F [or approximately 8.3 degrees Kelvin]). The adjustment applied may be based, for example, on the signal 282D. The modified control signal 225C may be provided to the spray valve 122 to control the spray valve 122 to move toward a closed position. Moving the spray valve 122 toward a closed position may cause the intermediate steam temperature 158 to increase and may thus reduce the likelihood of steam at a saturated temperature entering the superheater 106.If the magnitude of the difference between the saturated steam temperature 282B and the actual intermediate steam temperature 158 is greater than T, the intermediate steam temperature 158 may have a permissible value difference from the saturated steam temperature 282B and the fuzzifier may simply forward the control signal 225B to the field device 122 without making any adjustments (e.g., the adjusted control signal 225C in this case corresponds to the control signal 225B).

[0079] The value of 15 degrees F [or approximately 8.3 degrees Kelvin] is, of course, only one example of a possible threshold. The threshold can also be set to other values. Furthermore, the threshold can be modifiable either by an operator, automatically based on one or more values ​​or parameters in the steam boiler system, or both manually and automatically.

[0080] In some embodiments, the determination of the adjustment of the control signal 225B by the fuzzifier block 282E may be based on an algorithm, routine, or computer-executable instructions for a function g(x) (reference 282F) included in the fuzzifier block 282E. The function g(x) may or may not include the threshold T. For example, the adjustment routine g(x) (reference 282F) may generate an adjusted control signal 225C to control the rate of closing and opening of the spray valve 122 based on the direction (e.g., increasing or decreasing) of the temperature difference, regardless of the threshold T.In another example, the adjustment routine g(x) need not adjust the control signal 225B when the magnitude of the temperature difference is greater than the threshold T, but may determine an adjustment of the control signal 225B corresponding to a rate of increase or decrease in the magnitude of the temperature difference when the temperature difference is less than the threshold T. Other examples of embodiments of g(x) (reference numeral 282F) are also possible and may be used in the fuzzifier 282E.

[0081] In some embodiments, at least a portion of the algorithm or function g(x) (reference number 282F) may be implemented in a similar manner to possible modifications or adaptations of f(x) from Fig. 5C can be modified or adapted either manually or automatically.

[0082] Fig. 5F shows an exemplary embodiment of a function g(x) (reference numeral 282F). In this embodiment, at least a portion of g(x) (reference numeral 282F) may be represented by a curve 285. The x-axis 288 may include a range of values ​​corresponding to a range of magnitudes of temperature differences between the saturated steam temperature 282C and a current intermediate steam temperature 158. The range of values ​​of the x-axis 288 may correspond to a range of values ​​determined by the fuzzifier 282E from Fig. 5E received signal 282D. The y-axis 290 may include a range of values ​​of a multiplier applied to the magnitude of the temperature difference between the saturated steam temperature and the current intermediate steam temperature, e.g., applied to the signal 282D. In Fig. 5F, the units of the y-axis 290 are depicted as fractional; for example, the multiplier may range from a value of zero through a plurality of fractional values ​​to a maximum value. In other embodiments, the multiplier may be specified in a different unit, such as percent, e.g., 0% to 100%.

[0083] Using curve 285, a corresponding multiplier value 290 can be determined for a given magnitude of a temperature difference 288, and the determined multiplier value 290 can be applied to the input signal 282D received by fuzzifier 282E. The modified input signal can then be used by fuzzifier 282E to adjust or modify control signal 225B to generate an adjusted or modified control signal 225C, and the adjusted control signal 225C can then be output by fuzzifier 282E.

[0084] In the Fig. 5F, when the temperature difference is greater than the threshold T (e.g., x > T), the intermediate steam temperature 158 may be sufficiently above the saturated steam temperature 282B, indicating that the current control level is sufficient to maintain the intermediate steam temperature 158 within a desired range. Accordingly, the control signal 225B may not need to be adjusted, and the curve 285 may indicate that the associated multiplier to be applied to the input signal 282D is substantially zero or negligible. In this scenario, the signal 282D may have minimal or no effect on the control signal 225B, and the output control signal 225C of the fuzzifier 282E may be substantially equal to the input control signal 225B.

[0085] If the magnitude of the temperature difference is lower than the threshold T (e.g., x < T), the intermediate steam temperature 285 may move undesirably close to the saturated steam temperature. In these scenarios, the control signal 225B may need to be adjusted more aggressively. As the temperature difference approaches zero, the multiplier 290 may increase according to curve 285. For example, if the intermediate steam temperature is substantially identical to the saturated steam temperature (e.g., x = 0), a multiplier of one may be applied to the signal 282D so that the signal 282D can fully influence the control signal 225B to generate the output control signal 225C. In another example, with a temperature difference of 7.5 degrees (e.g.,In the scenario where the temperature difference is substantially zero (e.g., x = 7.5), the curve 285 may indicate that the multiplier to be applied to the input signal 282D is 0.5 or 50%, and the modified signal 282D therefore has half the effect on the control signal 225B as in the scenario where the temperature difference is substantially zero. Thus, since more aggressive control is requested by the control scheme 200, the function g(x) may more aggressively apply a multiplier of the signal 282D to adjust the input control signal 225B.

[0086] Fig. Figure 5F includes an additional curve 292 superimposed over curve 285 to illustrate the effect of g(x) (reference numeral 282F) on the positioning of a field device. Curve 292 may illustrate the movement of the field device in response to the output control signal 225C generated by fuzzifier 282E. In this embodiment, the field device may be a spray valve that affects the intermediate steam temperature, such as valve 122, although the principles described herein are applicable to other field devices.

[0087] Curve 292 may define a position multiplier 290 for a current device position for each value of the magnitudes of temperature differences between the saturated steam temperature and the current intermediate steam temperature 288. In this embodiment of curve 292, when the difference between the saturation and intermediate steam temperatures is at or above the threshold T (e.g., x > T), the system 200 may operate at or above a desired range of temperature differences and thus may not require the spray valve 122 to increase or decrease the current spray volume to maintain current operating conditions. Accordingly, curve 292 shows that for temperature differences above the threshold T, the valve position may not deviate from its current value (e.g., the device position multiplier is one).

[0088] However, as the intermediate steam temperature moves toward the saturated steam temperature (e.g., x < T), it may be desirable for the intermediate steam temperature 158 to increase. To trigger this desired increase in the intermediate steam temperature 158, it is desirable to decrease the volume of cooling spray currently provided by the valve 122. As x approaches zero, the curve 292 may indicate that the position multiplier 290 decreases to move the valve toward a closed position. For example, the curve 292 indicates that the position multiplier 290 to be applied at the current valve position may be 0.5 or 50% when the temperature difference is 7.5 degrees, and thus the valve may be controlled by the output control signal 225C of the fuzzifier 282E to move to half of its current position.When the intermediate steam temperature is substantially at the saturated steam temperature value (e.g., x = 0), the position multiplier 290 to be applied to the current valve position is substantially zero, so that the valve can be controlled by the output control signal 225C to move to zero percent of its current position (e.g., fully closed), thereby raising the intermediate steam temperature as quickly as possible.

[0089] As described above, curve 292 superimposed on curve 285 corresponding to g(x) (reference numeral 282F) illustrates one of numerous possible examples of how the input signal 282D at the fuzzifier 282E may be modified based on the intermediate steam temperature value 158 and how the resulting adjusted or modified control signal 225C output by the fuzzifier 282E may influence the positioning of the field device 122. Curves 285 and 292 are, of course, purely exemplary in nature. Other embodiments of curves 285 and 292 are also possible and may be used in connection with the present disclosure.

[0090] Fig. 6 shows an exemplary method 300 of controlling a steam boiler system, such as the steam boiler system 100 of Fig. 1. The method 300 may also be used in conjunction with embodiments of the control system or control scheme 200 of Fig. 4. For example, the method 300 may be performed by the control system 200 or the controller 120. For clarity, the method 300 is described below with simultaneous reference to the boiler 100 of Fig. 1 and the tax system or scheme 200 from Fig. 4 described.

[0091] At a block 302, a signal 208 indicative of a disturbance variable used in a steam-generating boiler system 100 may be obtained or received. The disturbance variable may be any controlled variable, manipulated variable, or disturbance variable used in the boiler system 100, such as a furnace burner tilt position; a steam flow; a sootblower amount; a damper position; a power setting; a furnace fuel-air mixture ratio; a furnace burn rate; a spray flow; a waterwall steam temperature; a load signal for either the target load or the actual turbine load; a flow temperature; a fuel-feedwater mixture ratio; the exit steam temperature; a fuel amount; or a fuel type. In some embodiments, one or more signals 208 may correspond to one or more disturbance variables. At a block 305, a rate of change of the disturbance variable may be determined.At block 308, a signal 210 indicative of the rate of change of the disturbance variable may be generated and passed to an input of a dynamic matrix controller, such as the primary DMS block 222. In some embodiments, blocks 302, 305, and 308 may be performed by the rate of change determiner 205.

[0092] At block 310, a control signal 225 corresponding to an optimal response may be generated based on the signal 210 generated at block 308 and corresponding to the rate of change of the disturbance variable. For example, the control signal 225 may be generated by the primary DMS block 222 based on the signal 210 corresponding to the rate of change of the disturbance variable and the parametric model corresponding to the primary DMS block 222. At a block 312, based on the control signal 225 generated by block 310, the temperature 202 of the exit steam generated by the steam-generating boiler system 100 may be controlled immediately prior to being passed to a turbine 116 or 118.

[0093] In some embodiments, the method 300 may include additional blocks 315-328. In such embodiments, the signal 210 corresponding to the rate of change of the disturbance variables generated by block 305 may also be provided at block 315 to a secondary dynamic matrix controller, such as the secondary DMS block 230 of Fig. 4. At block 318, a gain measure may be determined based on the rate of change of the disturbance variable, and at block 320, a gain signal or secondary signal 232 corresponding to the gain measure determined at block 318 may be generated.

[0094] At block 322, the gain signal generated at block 320 or the secondary signal 232 and the control signal 225 generated at block 310 may be applied to an adder, such as the adder block 238 of Fig. 4, may be provided. At block 325, the gain signal or secondary signal 232 and the control signal 225 may be combined. For example, the gain signal 232 and the control signal 225 may be added or otherwise combined. At block 328, a adder output control signal may be generated based on the combination, and at block 312, the temperature of the exit steam may be controlled based on the adder output control signal. In some embodiments, block 312 may include providing the control signal 225 to a field device in the boiler system 100 and controlling the field device based on the control signal 225 so that the exit steam temperature 202 is, in turn, controlled.It should be noted that in some embodiments of the method 300 including blocks 315-328, the flow from block 310 to block 312 is omitted and the method 300 instead continues from block 310 to block 322 as shown by the dashed arrows.

[0095] Fig. 7 shows a method 350 of dynamically adjusting the control of a steam boiler system, such as the steam boiler system of Fig. 1. The method 350 may be used in conjunction with embodiments of the control system or control scheme 200 of Fig. 4, embodiments of the error detection unit or the error detection block 250 of Fig. 5B, embodiments of the function f(x) from Fig. 5C and / or embodiments of the method 300 of Fig. 6. For clarity, the method 350 is described below with simultaneous reference to the boiler system 100 of Fig. 1, the tax system or scheme 200 from Fig. 4 and the error detection unit or the error detection block 250 from Fig. 5B.

[0096] At a block 352, a signal indicative of an output parameter of a steam boiler system (such as system 100) or a level of the output parameter of the steam boiler system may be retrieved or received. The output parameter may correspond, for example, to an amount of ammonia produced by the steam boiler system, a level of a drum of the steam boiler system, a pressure of a furnace in the steam boiler system, a pressure at a throttle of the steam boiler system, or another quantified or measured output parameter of the boiler system. In one example, the output parameter may correspond to a temperature of the exit steam produced by the boiler system 100 and provided to a turbine, such as the temperature 202 from Fig. 4. In some embodiments, the signal indicating the output parameter of the steam boiler system may be detected by a fault detection block or unit, such as the fault detection block or unit 250 of Fig. 4, can be retrieved or obtained. In some embodiments, the signal indicative of the output parameter of the steam boiler system 100 can be directly processed by a dynamic matrix control block, such as the DMS block 222 of Fig. 4, accessed or received.

[0097] At a block 355, a signal may be retrieved or received that indicates a setpoint corresponding to the output parameter. For example, the setpoint may be a setpoint corresponding to the temperature of the outlet steam generated by the boiler system and provided to a turbine, such as setpoint 203 of Fig. 4. In some embodiments, the signal indicating the setpoint may be detected by an error detection block or unit, such as the error detection block or unit 250 of Fig. 4, retrieved or received. In some embodiments, the signal indicating the setpoint may be directly controlled by a dynamic matrix control block, such as the DMS block 222 of Fig. 4, retrieved or received.

[0098] At a block 358, a difference or error between the actual value of the output parameter (e.g., reference number 202) retrieved at block 352 and the desired value of the output parameter (e.g., reference number 203) retrieved at block 355 may be determined. For example, the difference between the actual 202 and desired 203 values ​​of the output parameter may be determined by a difference block or unit 250A in the error detection block or unit 250. In another example, the DMS block 222 may determine the difference between the actual 202 and desired 203 values ​​of the output parameter.

[0099] At a block 360, the extent or magnitude of the difference / error determined at block 358 may be determined. For example, the extent of the difference may be determined at block 360, taking into account the absolute value of the difference determined at block 358. In some embodiments, the absolute value block 250C may be composed of Fig. 5B at block 360 determine the extent of the difference between the actual 202 and desired 203 value of the output parameter.

[0100] At an optional block 362, the magnitude of the difference between the actual 202 and desired 203 value of the output parameter may be modified or adjusted. A signal indicating the magnitude of the difference between the actual 202 and desired 203 value of the output parameter (e.g., the output generated by block 360) may be provided as indicated by reference numeral 250F in Fig. 5C, be modified or adjusted by a function f(x). The function f(x) may receive as input the signal indicating the magnitude of the difference between the actual 202 and desired 203 values ​​of the output parameter. After the function f(x) has processed the signal indicating the magnitude of the difference, the function f(x) may produce an output corresponding to a signal indicating the modified or adjusted magnitude of the difference between the actual 202 and desired 203 values ​​of the output parameter.

[0101] In some embodiments, block 362 may be executed by the error detection block 250, such as functional block 250E of the error detection block 250. In some embodiments, block 362 may be executed by the dynamic matrix control block 222. In some embodiments, block 362 may be omitted entirely, for example, if f(x) is not desired or required. In these embodiments, block 365 may directly follow block 360 in the method 350.

[0102] At block 365, the signal indicating the modified or adjusted extent of the difference or error between the actual 202 and desired 203 value of the output parameter may be used to generate the signal corresponding to the rate of change of the disturbance variable, such as the signal 210 of Fig. 4, to modify or adjust. In a preferred embodiment, f(x) utilized in block 362 may be defined such that as the magnitude of the difference or error between the actual 202 and desired 203 values ​​of the output parameter increases, the rate or extent of adjustment or modification of the signal corresponding to the rate of change of the SV is increased at a block 365, and as the magnitude of the difference or error between the actual 202 and desired 203 values ​​of the output parameter decreases, the rate or extent of adjustment or modification of the signal corresponding to the rate of change of the SV is decreased at block 365. For negligible differences / errors or differences / errors that are within the error margin of the steam boiler system 100, the signal corresponding to the rate of change of the SV may not need to be adjusted or modified at all.In this manner, the signal corresponding to the rate of change of the SV can be changed accordingly, as defined by f(x), at block 365 as the magnitude of the error or difference between the actual 202 and desired 203 value of the output parameter changes in magnitude.

[0103] At a block 367, the modified or adjusted signal generated in block 365 may be provided to the DMS block 222. If the signal corresponding to the rate of change of the SV 210 is not modified or changed in block 365, a control signal corresponding to the original signal 210 (including any desired gain 220) may be provided to the DMS block 222.

[0104] In some embodiments, block 365 may be performed by DMS block 222. In these embodiments, the signal corresponding to the output of f(x) may be applied by DMS block 322 to a first input (e.g., reference numeral 252 of Fig. 4) and stored in a first register or memory location R. The signal corresponding to the rate of change of the disturbance variable can be applied to a second input (e.g. reference numeral 210 or 220 of Fig. 4) are received. The strain gauge block 222 can compare the values ​​stored in Q and R and determine a magnitude or absolute value of the difference. Based on the magnitude or absolute value of the difference between Q and R, the strain gauge block 222 can determine an amount of adjustment or modification of the rate of change of the SV and generate a modified or adjusted signal corresponding to the SV. The strain gauge block 222 can then generate a control signal 225 based on the modified or adjusted signal corresponding to the SV.

[0105] In some embodiments, block 365 may be executed by another block (not shown) associated with DMS block 222, rather than by dynamic matrix control block 222. In these embodiments, the rate of change of the disturbance variable (e.g., reference numeral 210 or 220 of Fig. 4) be modified or adjusted based on the magnitude of the difference between the actual 202 or desired 203 value of the output parameter. The modified or adjusted signal corresponding to the disturbance variable can be provided as an input to the DMS block, which uses it in conjunction with other inputs to generate the control signal 225.

[0106] In some embodiments, the method 350 may be Fig. 7 in connection with the procedure 300 from Fig. 6. For example, the modified or adjusted signal corresponding to the rate of change of the SV (e.g. by block 365 of Fig. 7) may be provided as an input 252 to the DMS block 222 to be used in generating the control signal 225. In this example, the method 350 of Fig. 7, as shown by the compound A in Fig. 6 and Fig. 7, block 308 from Fig. Replace 6.

[0107] Fig. Figure 8 shows a method 400 for preventing saturated steam from entering a superheater section of the steam boiler system, such as the boiler system of Fig. 1, occurs. The method 400 may be used in conjunction with embodiments of the control system or control scheme 200 of Fig. 4 and Fig. 5D, embodiments of the prevention unit or the prevention block 282 from Fig. 5E, embodiments of g(x) described with reference to Fig. 5F, and / or embodiments of the method 300 of Fig. 6 and / or the procedure 350 from Fig. 7. For clarity, the method 400 is described below with simultaneous reference to the boiler system 100 of Fig. 1 and the control system or control scheme 200 from Fig. 4 and Fig. 5D and the prevention unit or prevention block 282 from Fig. 5B and Fig. 5E described.

[0108] At block 310, a control signal may be generated based on a signal indicative of a rate of change of a disturbance variable used in the steam-generating boiler system. The control signal may be generated by a dynamic matrix controller. For example, as shown in Fig. 4, the dynamic matrix control block 222 may generate a control signal 225 based on the signal 210 indicating the rate of change of the disturbance variable 208. It should be noted here that the block 310 is also used in the method 300 of Fig. 6 may be included.

[0109] At block 405, a saturated steam temperature may be retrieved. In one example, the saturated steam temperature may be retrieved by retrieving a current atmospheric pressure and determining the saturated steam temperature based on the atmospheric pressure from a steam table or steam calculator. As shown in Fig. 5E, a steam table 282A may receive a signal indicative of a current atmospheric pressure 288, determine a corresponding saturated steam temperature 282B, and generate a signal indicative of the corresponding saturated steam temperature 282B.

[0110] At a block 408, an intermediate steam temperature may be retrieved. The temperature of the intermediate steam may, for example, be retrieved at a point in the boiler 100 where the intermediate steam is supplied to a superheater or a final superheater. In one example, a signal representing the current intermediate steam temperature 158 in Fig. 5D, by a comparator block or comparator unit 282C.

[0111] At a block 410, the saturated steam temperature and the current intermediate steam temperature may be compared to determine a temperature difference. In some embodiments, a magnitude of the temperature difference may be determined. In some embodiments, a direction (e.g., increase or decrease) of the temperature difference may be determined. As shown in Fig. For example, as shown in Figure 5D, the comparator 282C may receive a signal indicative of the associated saturated steam temperature 282B and a signal indicative of a current intermediate steam temperature 158, and the comparator 282C may determine the magnitude and / or direction of the temperature difference based on the two received signals.

[0112] At a block 412, an adjustment or modification of the control signal generated at block 310 can be determined based on the temperature differences determined at block 410. For example, a fuzzifier block or fuzzifier unit 282E can be Fig. 5E, based on the signal indicative of the temperature difference 282D, determine an adjustment or modification of the control signal 225B. In some embodiments, the adjustment or modification of the control signal may be based on a comparison of the magnitude of the temperature difference with a threshold. In some embodiments, the adjustment or modification of the control signal may be based on a routine, algorithm, or function, such as g(x) (reference numeral 282F), included in the fuzzifier unit 282E.

[0113] At block 415, an adjusted or modified signal corresponding to the rate of change of the SV may be generated. For example, the fuzzifier 282E may generate an adjusted or modified control signal 225C based on the adjustment or modification determined at block 412.

[0114] At a block 418, the intermediate steam temperature may be controlled based on the adjusted or modified control signal. In the embodiment of Fig. 4, the field device 122 may receive the adjusted control signal 225C and respond accordingly to regulate the intermediate steam temperature 158. In embodiments where the field device 122 is a spray valve, the spray valve may move toward an open position or toward a closed position based on the adjusted control signal 225C.

[0115] In some embodiments, the method 400 may be Fig. 8 in connection with the procedure 300 from Fig. 6. For example, blocks 405 to 418 of process 400 may be performed before the temperature of the exit steam 312 of process 300 is controlled, as indicated by connection B in Fig. 6 and Fig. 8 shown.

[0116] Furthermore, the control schemes, systems, and methods described herein are each applicable to steam generating systems that utilize other types of configurations for superheater and reheater sections than those illustrated or described herein. Although Fig. 1-4 are shown with two superheater sections and one reheater section, the control scheme described herein can therefore also be used with boiler systems that have more or fewer superheater sections and reheater sections, and that use any type of configuration within each of the superheater and reheater sections.

[0117] Furthermore, the control schemes, systems, and methods described herein are not limited to controlling solely the exit steam temperature of a steam generating boiler system. Other dependent process variables of the steam generating boiler system may also be additionally or alternatively controlled by any of the control schemes, systems, or methods described herein. For example, the control schemes, systems, and methods described herein are each applicable to controlling an ammonia rate for nitrogen oxide reduction, a drum level, furnace pressure, throttle pressure, and other dependent process variables of the steam generating boiler system.

[0118] Although the above text discloses a detailed description of several different embodiments of the invention, it is to be understood that the legal scope of the invention is defined by the language of the claims recited at the end of this patent. This detailed description is to be interpreted as exemplary only and does not describe every possible embodiment of the invention, since describing every possible embodiment would be impractical, if not impossible. Using today's technology or technology developed after the filing date of this patent, numerous alternative embodiments can be implemented that would still fall within the scope of the claims defining this invention.

[0119] Accordingly, many modifications and variations may be made to the techniques and structures described and illustrated herein without departing from the spirit and scope of the present invention. Accordingly, it is to be understood that the methods and apparatus described herein are merely exemplary in nature and do not limit the scope of the invention.

Claims

[1] A method for dynamically adjusting the control of a steam generating boiler system (100), comprising: Determining the presence of a fault corresponding to a temperature (202) of the outlet steam, the outlet steam being generated by the steam generating boiler system (100) and delivered therefrom to a turbine (116); Providing a signal indicative of a magnitude of the error to an input of a function block (250E); Modifying the signal indicating the extent of the error using a function (250F) contained in the function block (250E); generating an output of the function block (250E) based on the modified signal indicating the extent of the error; Adjusting a signal indicative of a rate of change of a disturbance variable used in the steam generating boiler system (100) based on the error, comprising adjusting the signal indicative of the rate of change of the disturbance variable based on the output of the functional block (250E); generating a control signal based on the adjusted signal indicative of the rate of change of the disturbance variable by a dynamic matrix controller (222); and Control the temperature of the outlet steam based on the control signal. [2] The method of claim 1, further comprising: Providing the signal (210) indicative of the rate of change of the disturbance variable to a first input of the dynamic matrix controller (222), Providing a signal indicative of the output of the functional block (250E) to a second input of the dynamic matrix controller (222); and wherein adjusting the signal (210) indicative of the rate of change of the disturbance variable based on the output of the functional block (250E) comprises adjusting the signal (210) indicative of the rate of change of the disturbance variable by the dynamic matrix controller (222) based on the signals received at the first input and the second input of the dynamic matrix controller (222). [3] A dynamically adjusted control unit for use in a steam boiler system (100), the dynamically adjusted control unit being communicatively connected to a field device and a boiler of the steam boiler system (100), the dynamically adjusted control unit comprising: a dynamic matrix control, DMS, (222), including: a first DMS input at which a signal is received indicative of a rate of change of a disturbance variable of the steam generating boiler system (100); a second DMS input at which a signal is received indicating an error corresponding to a temperature (202) of the outlet steam generated by the steam generating boiler system (100); a dynamic matrix control routine that: adjusting the signal (210) indicating the rate of change of the disturbance variable based on the signal corresponding to the error, and determining a control signal (225) based on the adjusted signal indicating the rate of change of the disturbance variable; and a strain gauge output to provide the control signal (225) to the field device and thus control the outlet steam temperature (202), wherein the dynamically adjusted control unit further comprises an error detection unit (250) which generates the signal corresponding to the error corresponding to the outlet steam temperature, wherein the error detection unit (250): receives a signal at a first input which corresponds to a setpoint (203), receives a signal at a second input corresponding to the outlet steam temperature (202), and at an output based on the signals received at the first input and the second input, generates the signal (250B) corresponding to the error corresponding to the outlet steam temperature (202), wherein the error detection unit (250) includes a functional unit (250E) which: receives a signal (250D) indicating an extent of a difference between the setpoint (203) and the outlet steam temperature (202), the signal (250D), which indicates the extent of the difference between the setpoint (203) and the outlet steam temperature (202), is adjusted using a function (250F) and providing the adjusted signal indicating the magnitude of the difference between the setpoint (203) and the outlet steam temperature (202) to an output of the fault detection unit (250). [4] A dynamically adjusted control unit according to claim 3, wherein the function (250F) used by the functional unit (250E) to adjust the signal indicating the magnitude of the difference between a setpoint (203) and the outlet steam temperature (202) is modifiable. [5] Steam boiler system (100) comprising: a boiler; a field device; a controller that is communicatively connected to the boiler and the field device; and a dynamically adjusted control system communicatively coupled to the controller to receive a signal indicative of a rate of change of a disturbance variable, the dynamically adjusted control system including a first routine that: modifying the signal (210) indicative of the rate of change of the disturbance variable based on the magnitude of a difference between a setpoint (203) and a level of an output parameter of the boiler; generates a control signal (225) based on the modified signal indicating the rate of change of the disturbance variable; and provides the control signal (225) to the field device to regulate the level of the boiler output parameter, wherein the steam boiler system (100) further includes a second routine that: receives a first signal corresponding to the setpoint (203); receives a second signal corresponding to the level of the boiler output parameter; based on the first signal and the second signal, generates a signal (250B) indicating the extent of the difference between the setpoint value (203) and the level of the output parameter, and provides the signal (250B) indicating the extent of the difference between the setpoint value (203) and the level of the output parameter to the first routine, wherein the second routine uses a modifiable function to adjust the signal (250B) indicating the extent of the difference between the setpoint value (203) and the level of the output parameter and provides the adjusted signal indicating the extent of the difference between the setpoint value (203) and the level of the output parameter (202) to the first routine.

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