Classifications

• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23C—METHODS OR APPARATUS FOR COMBUSTION USING FLUID FUEL OR SOLID FUEL SUSPENDED IN  A CARRIER GAS OR AIR 
  • F23C10/00—Fluidised bed combustion apparatus
  • F23C10/18—Details; Accessories
  • F23C10/28—Control devices specially adapted for fluidised bed, combustion apparatus
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F22—STEAM GENERATION
  • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
  • F22B35/00—Control systems for steam boilers
  • F22B35/008—Control systems for two or more steam generators
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F22—STEAM GENERATION
  • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
  • F22B35/00—Control systems for steam boilers
  • F22B35/18—Applications of computers to steam boiler control
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N5/00—Systems for controlling combustion
  • F23N5/02—Systems for controlling combustion using devices responsive to thermal changes or to thermal expansion of a medium
  • F23N5/022—Systems for controlling combustion using devices responsive to thermal changes or to thermal expansion of a medium using electronic means
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N5/00—Systems for controlling combustion
  • F23N5/24—Preventing development of abnormal or undesired conditions, i.e. safety arrangements
  • F23N5/242—Preventing development of abnormal or undesired conditions, i.e. safety arrangements using electronic means
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N2223/00—Signal processing; Details thereof
  • F23N2223/06—Sampling
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N2223/00—Signal processing; Details thereof
  • F23N2223/10—Correlation
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N2223/00—Signal processing; Details thereof
  • F23N2223/40—Simulation
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N2223/00—Signal processing; Details thereof
  • F23N2223/48—Learning / Adaptive control
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N2223/00—Signal processing; Details thereof
  • F23N2223/50—Human control
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N2225/00—Measuring
  • F23N2225/08—Measuring temperature
  • F23N2225/10—Measuring temperature stack temperature
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N2225/00—Measuring
  • F23N2225/08—Measuring temperature
  • F23N2225/19—Measuring temperature outlet temperature water heat-exchanger
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N2225/00—Measuring
  • F23N2225/08—Measuring temperature
  • F23N2225/21—Measuring temperature outlet temperature
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23N—REGULATING OR CONTROLLING COMBUSTION
  • F23N2237/00—Controlling
  • F23N2237/10—High or low fire

Definitions

• the invention relates to control of combustion boilers, in particular fluidized bed boilers, such as circulating fluidized bed (CFB) boilers or bubbling fluidized bed (BFB) boilers.
• fluidized bed boilers such as circulating fluidized bed (CFB) boilers or bubbling fluidized bed (BFB) boilers.
• Technical background Combustion boilers such as grate boilers and fluidized bed boilers are commonly utilized to generate steam which can be used for variety of purposes, such as for producing electricity and heat.
• CFB fluidized bed
• BFB bubbling fluidized bed
• the fluidized bed can in a BFB be rather conveniently controlled by controlling the fluidization gas feed and fuel feed.
• certain additives such as aluminum silicates (such as, non-hydrated clay) and alkali alkaline earth metal carbonates and mixtures thereof (such as, limestone or calcium carbonate) may be added to the combustion to improve sorption of possible heavy metals, sulfur, and also to improve alkali sorption.
• CFB combustion fluidization gas is passed through the bed material. Most bed particles will be entrained in the fluidization gas and they will be carried with flue gas. The particles are separated from the flue gas in at least one particle separator and circulated returning them back into the furnace.
• Improbed AB discloses a thermal load control method for a combustion boiler.
• the thermal load of a combustion boiler is reduced if monitored flue gas velocity in at least one location of the boiler exceeds a pre-determined maximum flue gas velocity limit.
• the flue gas velocity is computed from volume flow of flue gas divided by the cross-sectional area of the flue gas duct in the location just downstream the cyclone using an equation group.
• a combustion boiler traditionally is designed for a given load that is the respective boiler maximum continuous rating (BMCR) of the boiler. This is sometimes called the design load level. It is an objective of the invention to improve performance, profitability, and flexibility of the boiler, and also to improve control of the boiler load. This objective can be achieved with the combustion boiler control method according to claim 1 and with the combustion boiler according to claim 19. A further objective of the invention is to reduce complexity of control system of a combustion boiler. This objective can be met with a combustion boiler computation system according to claim 24.
• the dependent claims describe advantageous aspects of the combustion boiler control method, of the combustion boiler, and of the combustion boiler computation system.
• the combustion boiler control method comprises the steps of a) monitoring the current load Q h of a combustion boiler; b) finding such a numerical value for a current computational maximum boiler momentary load for which at least one flue gas factor computed using currently monitored process data with a numerical model of the boiler fulfills an acceptance condition, and selecting the numerical value as the current computational maximum boiler momentary load Q h, max ; c) indicating the current computational maximum boiler momentary load Q h,max to the operator and/or, if the current load Q h is c1) smaller than the current computational maximum boiler momentary load: c1i) indicating the boiler operator that the boiler load may be increased, and/or c1ii) automatically increasing the boiler load, and/or c2) larger than the current computational maximum boiler momentary load: c2i) indicating the boiler operator that the boiler load Q h exceeds the current computational maximum boiler momentary load, and/or c2ii) automatically reducing the boiler load Q h .
• the method instead of having a fixed boiler maximum load, with the method of computing a flue gas factor and selecting its acceptance conditions suitable, it is possible to safely operate the combustion boiler at or closer to its current computational maximum boiler momentary load that at times may be higher than the fixed boiler maximum load would be.
• the current computational maximum boiler momentary load can be higher than the design load level. Therefore, the overall performance of the boiler may be improved and enabling increased power/heat production. Further, since the current computational maximum boiler momentary load may occasionally be smaller than the design load level, boiler wear resulting from exceeding the current computational maximum boiler momentary load may be better reduced. In other terms, the current computational maximum boiler momentary load can be considered as maximum allowable boiler load and/or preferable boiler load.
• the present applicant has been able to obtain in the tests performed, in average, power output from a combustion boiler that exceeds the fixed boiler maximum load.
• the present applicant could in the tests demonstrate that for a combustion boiler the improvement potential may lie between 2,5 – 5% which corresponds, for example, 3 to 6 MW th for a 120 MW th combustion boiler.
• the currently monitored process data of the boiler includes ia) current flue gas exit temperature in a flue gas flow channel and ib) heat duty for each heat transfer surface in the flue gas flow channel and further: ii) monitored process data from both ia) and ib) is used in computation of the flue gas factor and when finding the numerical value for the current computational maximum boiler momentary loadQ h,max .
• the finding may be performed such that, if the at least one flue gas factor computed using currently monitored process data with a numerical model of the boiler fails to fulfill an acceptance condition, a next numerical value is automatically selected.
• the next numerical value is selected iteratively.
• This may enable the use of computational library functions, and, in particular of an iterative solver (such as, Python FSOLVE function which solves roots of function).
• the finding may be carried out with performing the computational steps of: - I: computing an estimate for boiler flue gas exit temperature that results in a computational boiler model when the thermal load of the boiler corresponds to the numerical value; - II: computing flue gas mass flow - III: computing a heat duty for each heat transfer surface in the flue gas flow channel with its current heat duty that is corrected by using a numerical boiler model; - IV: using the computed heat duties for each heat transfer surface in the flue gas flow channel to compute flue gas temperatures at each heat transfer surface in the flue gas flow channel in the upstream direction of flue gas flow, starting from the heat transfer surface that is closest to the flue gas exit using the estimate for the boiler flue gas exit temperature; - V: computing a flue gas factor for each heat transfer surface in the flue gas flow channel.
• heat transfer surface means a heat exchanger, a heat exchanger tube, heat exchanger tube bundle, heat exchanger packages and/or a constructive group of heat exchangers, such as economizer) in the flue gas flow channel
• heat transfer surface means a constructive group of heat exchangers, such as economizer.
• the fitting of the parameters (par j,i ⁇ can be done manually by human or automatically by computer utilizing historical data. Automatic update of the parameters may be done e.g. once per month. AI and neural network based algorithms can be utilized in automatic update.
• this enables predicting the maximum computational allowable current boiler momentary load without going to the limit with the current boiler load, in contrast to the method disclosed in WO 2016/202640 A1, and on the other hand, and even more importantly, enables going to the limit without exceeding the maximum computational allowable current boiler momentary load.
• k i is a non-zero parameter that may be chosen combustion-boiler specifically, preferably positive (non-zero) number
• q m,fluegas is a flue gas mass flow
• n is a model parameter that may be chosen combustion-boiler specifically, preferably positive (non-zero) number
• ⁇ fluegas i is the density of the flue gas at the i th heat transfer surface
• a cross,i is the cross-sectional area of the flue gas flow path at the i th heat transfer surface.
• the model parameter n may be selected to include at least one of the following: i) in the range of 0,9 to 1,1, preferably equivalent or about 1.0, for using computed flue gas velocity; ii) in the range of 2,9 to 3,5, preferably between 3,2 and 3,35, for using computed flue gas caused erosion; or iii) in the range of 1,8 to 2,2, preferably equivalent or about 2.0, for using pressure loss.
• the value for n may be changed over time.
• the flue gas factor may be shifted over time, to better reflect the actual boiler situation.
• the comparison between the flue gas factor df i and a predetermined maximum value for the flue gas factor df max,i can be carried out for each heat transfer surface.
• the predetermined flue gas factor represents maximum ash loading value. It can also be adjustable based on the ash properties (softness, etc.).
• df max,i – ⁇ ⁇ df i ⁇ df max,i it means that at least one flue gas factor computed using currently monitored process data with a numerical model of the boiler fulfills the acceptance condition and in such a case maximum allowable boiler load has been found and so the numerical value Q h, candidate is selected as the current computational maximum boiler momentary load Q h, max .
• the summation index i goes over all of the heat transfer surfaces.
• the summation index i goes over only a part of the heat transfer surfaces, preferably in a flue gas channel.
• the coefficients ⁇ may be obtained by fitting after measuring flue gas exit values for a number of discrete steam load values. This data may be collected over time and refreshed from time to time, such as, periodically. Alternatively, or in addition, it may be collected in one or more calibration runs of the combustion boiler.
• the fitting of the coefficients ( ⁇ can be done manually by human or automatically by computer utilizing historical data. Automatic update of the coefficients may be done e.g. once per month. AI and neural network based algorithms can be utilized in automatic update.
• the flue gas exit temperature may be substantially estimated by utilizing artificial intelligence tools.
• the flue gas exit temperature may be substantially estimated by utilizing neural network.
• the fitting of the coefficients ( ⁇ ) can be done manually by human or automatically by computer utilizing historical data. Automatic update of the coefficients may be done e.g. once per month. AI and neural network based algorithms can be utilized in automatic update.
• the flue gas mass flow is computed using boiler mass and energy balance equations.
• the computation of flue gas mass flow may include taking into account mass flow of components CO 2 , H 2 O, N 2 , SO 2 , O 2 . The concentration of these components can be measured reliably with rather simple equipment.
• the component values may include fuel parameters.
• the step b) may be performed remotely to the combustion boiler, preferably in a cloud-based computation service. This helps to simplify the maintenance of the combustion boiler, since the remote computation equipment, such as configured to run the cloud-based computation service, can be maintained separately from the combustion boiler.
• the computational software updates for example, can thus be performed centrally at one or a few locations, instead of updating software at each combustion boiler.
• the step b) may be performed locally at the combustion boiler, preferably at an edge server.
• Any of the currently monitored process data and/or current load may be obtained from real-time measurements. Instead of this, or in addition to it, the currently monitored process data and/or current load may be treated by filtering, treated by averaging, computing trends or any combination of these. This helps to avoid noise or outlier measurements to impact the outcome of the computation, and thus facilitates to increase stability of the current computational maximum boiler momentary load.
• the acceptance condition may include a hysteresis condition, requiring a predefined minimum change before changing the current computational maximum boiler momentary load. This may increase the stability of the current computational maximum boiler momentary load, preferably helping to avoid changing the current computational maximum boiler momentary load up and down within a short period of time.
• combustion boiler is a circulating fluidized bed (CFB) or a bubbling fluidized bed (BFB) boiler
• the step b) is carried out for the combustion boiler heat transfer surfaces.
• the method is particularly convenient for CFB or BFB boilers.
• the step b) is carried out for the combustion boiler heat transfer surfaces between a furnace and stack.
• a combustion boiler comprises: - a furnace and associated passes defining a flue gas flow path a flue gas flow path and having a number of heat transfer surfaces; - measurement instrumentation to monitor current load of the combustion boiler; - further measurement instrumentation to currently monitor process data; and - a control system configured to carry out the boiler control method.
• combustion boiler comprises a furnace and associated passes defining a flue gas flow path a flue gas flow path and having a number of heat transfer surfaces in the flue gas flow path.
• the control system may comprise an edge server which may be configured to process the real-time measurement results for currently monitored process data and/or current load, namely by filtering, averaging, and/or computing trends.
• the edge server will facilitate cutting down the amount of currently monitored process data. In certain installations this may be particularly useful especially in view of the fact that there may be 60 to 90 gigabytes of monitored process data each day.
• the control system may be configured to carry out the method step b) to determine the current computational maximum boiler momentary load locally.
• control system may be configured to send data to a remote, preferably cloud-based, computing system which may be configured to carry out the method step b) and return the current computational maximum boiler momentary load to the control system.
• a remote, preferably cloud-based, computing system which may be configured to carry out the method step b) and return the current computational maximum boiler momentary load to the control system.
• the edge server may be configured to reduce amount of measurement data that is passed to the remote computing system. In this manner, a smaller bandwidth for transferring data may suffice. In certain installations this may be particularly useful especially in view of the fact that there may be 60 to 90 gigabytes of monitored process data each day.
• a combustion boiler computation system comprises - a group of combustion boilers, each boiler comprising a boiler control system comprising an edge server system which is configured to process the real-time measurement results for currently monitored process data and/or current load, namely by filtering, averaging, and/or computing trends, and send the processed real-time measurement results to a remote computing system; - a remote computing system which preferably is a cloud-based computing system, configured to receive data processed from real time measurement results and to compute data using a numerical boiler model for each of the boilers, and return computation results for each of the boilers. Further, in the combustion boiler computation system, the boiler control system is configured to adapt its function based on the computation results.
• the advantage for this arrangement is that the need of computation devices at the combustion boiler can be reduced, still obtaining effective and fast computation results from the remote computing system.
• the computing system may be configured to find such a numerical value or a current computational maximum boiler momentary load for which at least one flue gas factor computed using currently monitored process data with a numerical model of the boiler that fulfills an acceptance condition and selecting the numerical value as the current computational maximum boiler momentary load. This basically enables using the method of the invention also in a distributed environment.
• the boiler computation system may be configured to adapt or calibrate a numerical model, such as, the flue gas factor numerical model, for a boiler using processed measurement data for the boiler. This makes it easier to remotely adapt or calibrate the numerical model for boiler control.
• the boiler computation system may be configured to adapt or calibrate a numerical model for a boiler using processed measurement data collected also from other boilers. This enables using a larger collection of data to adjust the numerical model for boiler control.
• FIG 1 illustrates a CFB boiler
• FIG 2 illustrates a BFB boiler
• FIG 3 illustrates the flow of measurement data from sensors
• FIG 4 is a flow diagram illustrating a first method for finding the current computational maximum boiler momentary load Q h, max
• FIG 5 is a flow diagram illustrating a second method for finding the current computational maximum boiler momentary load Q h, max
• FIG 6 illustrates how the current computational maximum boiler momentary load Q h, max can be presented to the boiler operator
• FIG 7 shows boiler momentary load Q h and computed current computational maximum boiler momentary load Q h, max , as well as the effect of using the method according to the invention during a test period
• FIG 1 shows a combustion boiler 10 that is a CFB boiler and comprises a furnace 12 that has tube walls 13 connected to water-steam circuit of the combustion boiler 10.
• Water is fed from water tank (not shown) to economizer and from the economizer via a steam drum to evaporative heat transfer surfaces such as the tube walls 13 and then guided via the steam drum to superheaters and then to a turbine.
• Flue gas channel may be provided with economizer and/or superheater/s.
• Fluidization gas (such as, air and/or oxygen-containing gas) is fed from fluidization gas supply 153 to below the grate (the grate not shown in FIG 1) via a windbox (not shown), wherefrom the primary fluidization air enters into the furnace through nozzles (not shown) (to fluidize the bed), and secondary fluidization gas feed 152 (to feed oxygen containing gas to control combustion).
• the effect is that the bed materials will be fluidized and also oxygen required for the combustion is provided into the furnace 12.
• fuel is fed into the furnace 12 via the fuel feed 22.
• the combustion can be adjusted by controlling the fuel feed 22 (such as, by reducing or increasing fuel feed), and by controlling the fluidization gas feed (such as, by reducing or increasing amount of oxygen supply into the furnace 12).
• Fuel can be fed together with additives, in particular with such additives that act as alkali sorbents, such as CaCO 3 and/or clay for example.
• NOx reduction agents such as ammonium or urea can be fed into the combustion zone of the furnace 12, or above the combustion zone of the furnace 12.
• Bed material is also fed into the furnace, which bed material may comprise sand, limestone, and/or clay, that in particular may comprise kaolin.
• One effect of the bed and, generally, of the combustion is that in the water-steam circuit, water and steam is heated in the tube walls 13 and water is converted to steam.
• Ash may fall to the bottom of the furnace 12 and be removed via an ash chute (omitted from FIG 1 for the sake of clarity) and part of the ash, so-called fly ash, will be carried along flue gas.
• Combustion products such as flue gas, unburnt fuel and bed material proceed from the furnace 12 to a particle separator 17 that may comprise a vortex finder 103.
• the particle separator 17 separates flue gases from solids. Especially in larger combustion boilers 10, there may be more than one (two, three, ...) separators 17 preferably arranged in parallel to each other. Solids separated by the separator 17 pass through a loop seal 160 that preferably is located at the bottom of the separator 17.
• fluidized bed heat exchanger (FBHE) 100 that is also a heat transfer surface so that the FBHE 100 collects heat from the solids to further heat the steam in the water-steam circuit.
• the chamber in which the FBHE 100 is located may be fluidized and the FBHE 100 itself comprises heat transfer tubes or other kinds of heat transfer surfaces.
• FBHE 100 may be arranged as a reheater or as a superheater. From the FBHE outlet 101, steam is passed into a high- pressure turbine (if the FBHE 100 is superheater) or medium-pressure turbine (if the FBHE 100 is a reheater). For the sake of clarity, the turbines are not illustrated in FIG 1.
• the solids may be returned from the FBHE 100 via a return channel 102 into the furnace 12.
• a return channel 102 into the furnace 12.
• some of the FBHE 100 may be arranged as superheaters while some others may be arranged as reheaters.
• the flue gases are passed from the separator 17 to horizontal pass 15 and from there further to backpass 16 (that preferably may be a vertical pass) and from there via flue gas conduit 18 to stack 19.
• heat transfer surfaces 21 1 , 21 2 , 21 3 , ..., 21 k-1 , 21 k are illustrated.
• Heat transfer surface 21 k depicts air preheater.
• Heat transfer surfaces 21 k-1 , 21 2 depict superheaters and heat transfer surfaces 21 1 , 21 3 depict reheaters.
• the actual number of different heat transfer surfaces in each of these components may be selected for each combustion boiler differently according to actual needs. And there may be further components as well, comprising a heat transfer surface 21.
• Flue gas exiting the last heat transfer surface 21 k will be in flue gas exit temperature T FG, exit .
• This temperature is measured with temperature sensor 20 k .
• the temperatures before and after each preceding heat transfer surface 21 i (T FG,in,i , T FG,in,i+1 ) can be obtained numerically.
• a combustion boiler 10 is equipped with a plurality of sensors and computer units. Actually, one middle-size (100 – 150 MW th ) combustion boiler 10 may produce 100 million measurement results / day, which needs 25 GB of storage space.
• Process data may be collected from the sensors by distributed control system (DCS) 201.
• DCS distributed control system
• the data collection may most conveniently be arranged over a field bus 290, for example.
• DCS 201 may have a display/monitor 202 for displaying operational status information to the operator.
• An EDGE server 203 may process measurement data from the obtained from sensors, such as, filter and smooth it.
• There may be a local storage 204 for storing data.
• the DCS 201, display/monitor 202, EDGE server 203, local storage 204 may be in combustion boiler network 280 (local storage 204 preferably directly connected to the EDGE server).
• the combustion boiler network 280 is preferably separate from the field bus 290 that is used to communicate measurement results from the sensors to the DCS 201 and/or the EDGE server 203.
• Combustion boiler network 280 may be in connection with the internet 200, preferably via a gateway 290.
• measurement results may be transferred from the combustion boiler network 280 to a cloud service, such as process intelligence system 205 located in a computation cloud 206.
• the applicant currently operates a cloud service running an analysis platform.
• the cloud service may be operated on a virtualized server environment, such as on Microsoft® Azure® which is a virtualized, easily scalable environment for distributed computing and cloud storage for data. Other cloud computing services may be suitable for running the analysis platform too.
• FIG 2 illustrates a combustion boiler 10 that is a BFB boiler.
• BFB boiler differs from CFB boiler in that the fluidized bed is not a circulating bed but a bubbling bed.
• the separator 17, loop seal 160, FBHE 100 and return channel 102 There is normally at least one superheater 14 located in the furnace 12, preferably on top of the furnace 12.
• Superheater 14 inlet 141 is preferably the steam drum or from another superheater and the outlet 142 is to high pressure turbine.
• FIG 4 illustrates the combustion boiler control method: a) the current load Q h of combustion boiler 10 is monitored in step K1 (in the method illustrated in FIG 4, also flue gas exit temperature T FG, exit is monitored and heat duty Q fluid,i for each heat transfer surface 21i in the flue gas flow channel (vertical pass 16). b) a numerical value Q h, candidate is selected (step K3), after which heat duties at heat transfer surfaces 21 i are computed and flue gas temperatures in relation to Q h, candidate .
• the numerical value Q h, candidate is then used to compute (step K7) at least one flue gas factor df i using currently monitored process data with a numerical model of the boiler fulfills an acceptance condition (which is tested in step K9), and selecting the numerical value Q h, candidate as the current computational maximum boiler momentary load Q h, max (step K11); c) the current computational maximum boiler momentary load Q h, max is indicated to the operator (such as, by displaying on the monitor/screen 202) and/or, if the current load Q h is c1) smaller than the computational boiler maximum momentary load Q h,max : c1i) indicating the boiler operator that the boiler load Q h may be increased, and/or c1ii) automatically increasing the boiler load Q h , and/or c2) larger than the computational boiler maximum momentary load Q h,max : c2i) indicating the boiler operator that the boiler load Q h exceeds the boiler maximum momentary load, and/or c2ii) automatically reducing the boiler
• the step b) is preferably carried out for the combustion boiler 10 heat transfer surfaces 21 i between furnace 12 and stack 19.
• the currently monitored process data of the boiler may include a) current flue gas exit temperature T FG,exit in a flue gas flow channel and b) heat duty Q fluid,i for each heat transfer surface 21 i in the flue gas flow channel (back pass 16).
• monitored process data from both a) and b) may be used in computation of the flue gas factor df i and when finding the numerical value Q h, candidate for the current computational maximum boiler momentary load Q h,max .
• the finding is performed such that, if the at least one flue gas factor df i computed using currently monitored process data with a numerical model of the boiler that fails to fulfill an acceptance condition, a next numerical value Q h, candidate is automatically selected.
• the automatic selection is preferably done iteratively.
• Step II) may include computing flue gas mass flow q m,fluegas,m for selected flue gas components.
• the flue gas temperatures at each heat transfer surface can be computed, for instance, wherein T fluegas,in,i is the flue gas temperature at the inlet of ith heat transfer surface, C p is specific heat capacity, and T fluegas,out,i is the flue gas temperature at the outlet of ith heat transfer surface.
• the flue gas temperatures could be determined with artificial intelligence tools.
• the flue gas temperatures could be determined with neural network.
• ki is a predetermined non-zero parameter that may be chosen combustion-boiler specifically, preferably positive (non-zero) number
• qm,fluegas is a flue gas mass flow
• n is a positive number (which may be selected as a natural number, rational number, real number, or even as complex number)
• ⁇ fluegas,i is flue gas density obtainable from flue gas temperature TFG, in, i at i th heat transfer surface 21i and A is a cross section of flue gas channel at i th heat transfer surface 21 i .
• n may be selected to include at least one of the following: i) in the range of 0,9 to 1,1, preferably equivalent or about 1.0, for using computed flue gas velocity; ii) in the range of 2,9 to 3,5, preferably between 3,2 and 3,35, for using computed flue gas caused erosion; or iii) in the range of 1,8 to 2,2, preferably equivalent or about 2.0, for using pressure loss.
• the value for n may be changed over time.
• the value for n may be determined from a group of combustion boilers, the group comprising at least two separate combustion boilers 10, such that using operational data monitored for each of the combustion boilers 10 is used in the determination.
• the coefficients ⁇ 0 , ⁇ 1 , ⁇ 2 , ... have been obtained beforehand by fitting after measuring flue gas exit temperature T FG, exit values for a number of discrete boiler load Q steam values.
• step IV) of the computation as q m,fluegas,m values some or all of q m,fluegas,CO2 , q m,fluegas,H20 , q m,fluegas,N2 ,q m,fluegas,SO2 ,q m,fluegas,O2 may be used. They are preferably measured in flue gas conduit 18 or in flute 19, for which reason suitable sensors are installed in the flue gas passage.
• the component values may further include fuel parameters.
• Flue gas mass flow may be based on computation of sums of flue gas component mass flows q m,fluegas,m which are calculated based on fuel analysis (proximate and ultimate analysis of fuel), combustion air flow and/or recirculation gas flow according to boiler mass and energy balance calculation.
• first subscript denotes component and second subscript is either fuel or combustion air referred, q m,fuel is a fuel flow, q m,air is combustion air flow and M x denotes molar mass.
• fuel properties as utilized in flue gas mass flow components and combustion air properties. Fuel moisture may be measured or calculated.
• the step b) may be performed remotely to the combustion boiler, such as, in the process intelligence system 205. Alternatively, the step b) may be performed locally at the combustion boiler, preferably at the EDGE server 203. Any of the currently monitored process data and/or current load may be obtained from real-time measurements, treated by filtering, treated by averaging, computing trends or any combination of these.
• the acceptance condition may include a hysteresis condition, requiring a predefined minimum change before changing the current computational maximum boiler momentary load Q h,max .
• the acceptance condition preferably includes comparing the computed at least one flue gas factor df i against a respective maximum value df max,i .
• the maximum value df max,i is a preset value and preferably boiler specific.
• the numerical value Q h, candidate is rejected if the maximum value df max,i is exceeded.
• the furnace 12 and associated passes define a flue gas flow path.
• the furnace 12 and the passes 15, 16 have a number of heat transfer surfaces 21 i in the flue gas flow path.
• the combustion boiler 10 also has measurement instrumentation to monitor current load Q h of the combustion boiler, and further measurement instrumentation to currently monitor process data.
• the control system (DCS 201, and EDGE server 203, or DCS 201 remote process intelligence system 205, possibly under the participation of the EDGE server 203) is configured to carry out the boiler control method.
• the EDGE server 203 may be configured to process the real-time measurement results for currently monitored process data and/or current load, namely by filtering, averaging, and/or computing trends.
• the control system may be configured to carry out the method step b) to determine the current computational maximum boiler momentary load Q h,max locally at the combustion boiler 10, and/or to send data to a remote, preferably cloud-based (such as, computation cloud 206), computing system (such as, process intelligence system 205) which is configured to carry out the method step b) and return the current computational maximum boiler momentary load Q h,max to the control system.
• the control system may then use the display/monitor to indicate the information, such as in method step c), to the boiler operator, such as, by displaying the information.
• the EDGE server 203 may be configured to reduce amount of measurement data that is passed to the remote computing system.
• a combustion boiler computation system comprises a group of combustion boilers 10, each combustion boiler 10 comprising a boiler control system (CS) comprising an EDGE server (203) system which is configured to process the real-time measurement results for currently monitored process data and/or current load, namely by filtering, averaging, and/or computing trends, and send the processed real-time measurement results to a remote computing system.
• the remote computing system is preferably a cloud-based computing system, configured to receive data processed from real time measurement results and to compute data using a numerical boiler model for each of the combustion boilers 10, and to return computation results for each of the combustion boilers 10.
• the boiler control system may be configured to adapt its function based on the computation results.
• the computing system is preferably configured to find such a numerical value Q h, candidate for a current computational maximum boiler momentary load Q h,max for which at least one flue gas factor df i computed using currently monitored process data with a numerical model of the boiler that fulfills an acceptance condition, and selecting the numerical value Q h, candidate as the current computational maximum boiler momentary load Q h,max .
• the boiler computation system may be configured to adapt or calibrate a numerical model for a boiler using processed measurement data for the combustion boiler 10.
• the boiler computation system may be configured to adapt or calibrate a numerical model for a combustion boiler 10 using processed measurement data collected also from other combustion boilers 10.
• FIG 5 shows a modification of the method shown in FIG 4.
• Steps L1, L3, L7, L9 are the same as steps K1, K3, K9, K11, respectively, but in step L5, the flue gas factors df i can be directly computed for all heat transfer surfaces 20 i : if the temperatures T FG,in,i are measured using the respective temperature sensors 21 i , the back-calculation will not be necessary and thus the step K7 can be omitted in the method illustrated in FIG 5.
• FIG 6 shows in step N1 the use of possible inputs to the numerical boiler model.
• the Q h,max is computed numerically using the boiler model, and in step N5, the estimated maximum load Qh,max is presented to boiler operator via a specific user interface (UI), preferably via display/monitor 202.
• UI user interface
• FIG 7 shows boiler momentary load Q h and computed current computational maximum boiler momentary load Q h, max , as well as the effect of using the method according to the invention during a test period.
• the 120 MW th boiler power obtained in average a 3 to 6 MW th higher load as outside the test period.
• FIG 8 illustrates the 10 day test period in more detail.
• the current computational maximum boiler momentary load Q h,max of the combustion boiler is estimated using a numerical model using determined fluidized bed combustion boiler operating parameters.
• the current boiler load Q h is computed using steam circuit measurement data.
• the boiler load Q h is smaller than the current computational maximum boiler momentary load Q h,max , it is i) indicated to the boiler operator that the boiler load may be increased, and/or ii) the boiler load is automatically increased.
• the boiler load Q h is larger than the boiler maximum momentary load Q h,max , it is i) indicated to the boiler operator that the boiler load exceeds the boiler maximum momentary load, and/or ii) the boiler load is automatically reduced.
• T FG exit flue gas temperature at outlet of heat exchanger 21 k
• k) 22 fuel feed 100 fluidized bed heat exchanger (FBHE) 101 FBHE outlet 102 return channel 103 vortex finder 141 superheater inlet 142 superheater outlet 151 primary fludization gas feed 152 secondary fludization gas feed 153 fludization gas supply 161 reheater output 200 internet 201 distributed control system 202 display / monitor 203 EDGE server 204 local storage 205 process intelligence system 206 computation cloud 210 open platform communications server 280 combustion boiler network 290 field bus

Landscapes

• Engineering & Computer Science (AREA)
• Chemical & Material Sciences (AREA)
• Combustion & Propulsion (AREA)
• Mechanical Engineering (AREA)
• General Engineering & Computer Science (AREA)
• Physics & Mathematics (AREA)
• Thermal Sciences (AREA)
• Control Of Steam Boilers And Waste-Gas Boilers (AREA)
• Fluidized-Bed Combustion And Resonant Combustion (AREA)

Applications Claiming Priority (1)

Publications (1)

Family

ID=77913081

Family Applications (2)

Family Applications After (1)

Country Status (5)

Family Cites Families (5)

• 2021
  • 2021-09-09 KR KR1020247011282A patent/KR20240065111A/ko active Search and Examination
  • 2021-09-09 AU AU2021463486A patent/AU2021463486A1/en active Pending
  • 2021-09-09 WO PCT/EP2021/074838 patent/WO2023036426A1/en active Application Filing
  • 2021-09-09 EP EP21777437.1A patent/EP4222417A1/en active Pending
  • 2021-09-09 CN CN202180102240.0A patent/CN117957402A/zh active Pending
• 2022
  • 2022-09-09 WO PCT/EP2022/075087 patent/WO2023036921A1/en active Application Filing
  • 2022-09-09 EP EP22782478.6A patent/EP4222418A1/en active Pending
  • 2022-09-09 KR KR1020247011275A patent/KR20240065109A/ko unknown
  • 2022-09-09 AU AU2022344519A patent/AU2022344519A1/en active Pending

Also Published As

Similar Documents

Legal Events