JP7778227B2 - Combustion boiler control method, combustion boiler, and boiler calculation system - Google Patents

Description

The present invention relates to the control of combustion boilers, and in particular to the control of fluidized bed boilers, such as circulating fluidized bed (CFB) boilers or bubbling fluidized bed (BFB) boilers.

Fired boilers, such as grate boilers and fluidized bed boilers, are commonly used to generate steam, which can be used for a variety of purposes, including generating electricity and heat.

In a fluidized bed boiler, fuel and a solid granular bed material are introduced into the furnace. The bed material and fuel are fluidized by introducing a fluidizing gas from the bottom of the furnace. Combustion of the fuel takes place within the furnace. In BFB combustion, the fluidizing gas passes through the bed, creating bubbles within the bed. The fluidized bed can be controlled fairly easily in BFBs by controlling the fluidizing gas supply and the fuel supply. In addition to the fuel, certain additives may be added to the combustion, such as aluminum silicates (e.g., non-hydrated clays), alkali alkaline earth metal carbonates, and mixtures thereof (e.g., limestone or calcium carbonate), to enhance sorption of possible heavy metals and sulfur, as well as alkali sorption.

In CFB combustion, a fluidizing gas is passed through the bed material. Most of the bed particles become entrained in the fluidizing gas and are carried along with the exhaust gas. The particles are separated from the exhaust gas in at least one particle separator and circulated back into the furnace. A fluidized bed heat exchanger is typically located downstream of the particle separator to recover heat from the particles before they are returned to the furnace.

In all boilers, regardless of combustion technology, combustion conditions such as air and fuel mixing may not be ideal.

Published international application WO 2016/202640 A1 to Improved AB discloses a method for controlling the heat load of a fired boiler, in which the heat load of the fired boiler is reduced if the flue gas velocity monitored at at least one location in the boiler exceeds a predetermined maximum flue gas velocity limit. The flue gas velocity is calculated using a set of equations by dividing the volumetric flue gas flow rate by the cross-sectional area of the flue gas duct at a location immediately downstream of the cyclone.

Fired boilers are traditionally designed for a given load, which is the boiler's respective boiler maximum continuous rating (BMCR). This is sometimes called the design load level.

The first object of the present invention is to improve boiler performance, profitability, and flexibility, and to improve boiler load control. The second object of the present invention is to reduce the complexity of combustion boiler control systems.

The first object can be achieved by the combustion boiler control method described in claim 1 and the combustion boiler described in claim 19. The second object can be achieved by the combustion boiler calculation system described in claim 24.

The dependent claims describe advantageous aspects of the combustion boiler control method, the combustion boiler, and the combustion boiler calculation system.

Advantages of the Invention The combustion boiler control method includes the following steps.
a) monitoring the current load _Qh of the combustion boiler;
b) finding a value for the current calculated maximum boiler instantaneous load for which at least one flue gas coefficient calculated using currently monitored process data including a numerical model of the boiler satisfies an acceptance condition, and selecting this value as the current calculated maximum boiler instantaneous load Q _h,max ;
c) indicating to the operator the current calculated maximum boiler instantaneous load Q _h,max , and/or determining whether the current load Q _h is:
c1) If it is smaller than the current calculated maximum boiler instantaneous load,
c1i) indicating to the boiler operator that the boiler load may increase, and/or c1ii) automatically increasing the boiler load;
and/or c2) if it is greater than the current calculated maximum boiler instantaneous load;
c2i) indicating to the boiler operator that the boiler load _Qh exceeds the current calculated maximum instantaneous boiler load, and/or c2ii) automatically reducing the boiler load _Qh .

In this manner, rather than fixing the boiler's maximum load, by calculating the exhaust gas coefficient and appropriately selecting the allowable exhaust gas coefficient, the fired boiler can be safely operated at or near the fired boiler's current calculated maximum boiler load, which may sometimes be higher than the boiler's fixed maximum load. The current calculated maximum boiler load may be higher than the design load level. Therefore, the boiler's overall performance can be improved, and power/heat generation can be increased. Furthermore, because the current calculated maximum boiler load may be lower than the design load level, boiler wear due to exceeding the current calculated maximum boiler load can be more appropriately reduced. The current calculated maximum boiler load, in other words, can be considered the maximum allowable boiler load and/or the preferred boiler load.

In the tests carried out, the applicant was able to obtain, on average, a power output from the fired boiler that exceeds the fixed boiler maximum load. The applicant was able to demonstrate that for fired boilers, the tests showed that the improvement potential could be between 2.5 and 5%, which corresponds, for example, to 3 to 6 MW _th for a 120 MW _th fired boiler.

In this method, it is preferable that:
i) The currently monitored process data of the boiler is
ia) the current exhaust gas outlet temperature in the exhaust gas flow path;
ib) the heat duty of each heat transfer surface in the exhaust gas flow path, and
ii) The monitored process data from both ia) and ib) is used in calculating the flue gas coefficients and is used in finding a value for the current calculated maximum boiler instantaneous load Q _h,max .

Calculating the heat load of a heat exchanger is known to those skilled in the art, and the heat load can be obtained, for example, by using the following formula:
Q _fluid,i =q _m,fluid,i ×(h _fluid,out -h _fluid,in )
where q _m,fluid,i is the fluid flow rate at the i-th heat transfer surface, h _fluid,in is the enthalpy of the fluid entering the i-th heat transfer surface, and h _fluid,out is the enthalpy of the fluid exiting the i-th heat transfer surface.

This discovery can be performed such that if at least one exhaust gas coefficient calculated using currently monitored process data, including a numerical model of the boiler, fails to meet the tolerance criteria, a next value is automatically selected. Preferably, the next value is selected iteratively. This can enable the use of computational library functions, in particular iterative solvers (such as Python's FSOLVE function, which solves the roots of a function).

This finding can be done by performing the following computational steps:
I: a step of calculating an estimate of the boiler exhaust gas outlet temperature, which results in a calculated boiler model when the boiler thermal load corresponds to the numerical value;
- II: calculating the exhaust gas mass flow rate;
III: Calculating the heat load of each heat transfer surface in the exhaust gas flow path using the current heat load corrected by using a numerical boiler model;
- IV: Using the calculated heat load for each heat transfer surface in the flue gas flow path, calculate the flue gas temperature at each heat transfer surface, starting from the heat transfer surface in the flue gas flow path closest to the flue gas outlet in the upstream direction of the flue gas flow, using an estimate of the boiler flue gas outlet temperature;
- V: A step of calculating the exhaust gas coefficient for each heat transfer surface in the exhaust gas flow path.

Using this technique, the condition of each heat transfer surface (hereinafter, "heat transfer surface" means a heat exchanger, heat exchanger tube, heat exchanger tube bundle, heat exchanger package, and/or heat exchanger component group such as economizer) in the exhaust gas flow path can be numerically estimated using the exhaust gas coefficients when the boiler's thermal load matches the numerical value. The term "heat transfer surface" preferably means a heat exchanger component group such as an economizer. Therefore, it is now possible to test whether a specific numerical value that is a candidate for the current calculated maximum boiler instantaneous load creates an acceptable condition for the heat transfer surface.

According to one embodiment of the present invention, in step III), the numerical boiler model is a model of the form Q _{fluid,i,candidate} = Q _{fluid,i,current} +Σα _j,i (Q _h,candidate ) ^j −Σpar _j,i (Q _h,current ) ^j .

The fitting of the parameters (par _j,i ) can be done manually by a human or automatically by a computer using historical data. Automatic updating of the parameters may be performed, for example, once a month. AI and neural network-based algorithms can be used in the automatic updating.

This makes it possible, on the one hand, to predict the current maximum boiler load that is mathematically allowable without reaching a limit at the current boiler load, unlike the method disclosed in WO 2016/202640 A1, and, even more importantly, to reach a limit without exceeding the current maximum boiler load that is mathematically allowable.

Preferably, the exhaust gas coefficients include or are less than or equal to the following:
df _i =k _i (q _m,fluegas /(ρ _fluegas,i ×A _cross,i )) ⁿ
where:
k _i is a non-zero parameter, preferably a positive (non-zero) number, that can be specifically selected for the combustion boiler;
q _m,fluegas is the mass flow rate of the exhaust gas;
n is a model parameter, preferably a positive (non-zero) number, that may be specifically selected for a combustion boiler;
ρ _fluegas,i is the density of the exhaust gas at the i-th heat transfer surface;
A _cross,i is the cross-sectional area of the exhaust gas flow passage on the i-th heat transfer surface.

This is particularly advantageous because choosing this functional form for the flue gas coefficient gives the flue gas coefficient a great deal of flexibility and allows it to be easily adapted to suit the needs of various combustion boilers, including based on current fuel conditions.

The model parameter n is particularly advantageous because it can be chosen to be at least one of the following:
i) if a calculated exhaust gas velocity is used, in the range of 0.9 to 1.1, preferably equal to or about 1.0;
ii) when using calculated corrosion-causing exhaust gases, in the range of 2.9 to 3.5, preferably between 3.2 and 3.35; or iii) when using pressure drop, in the range of 1.8 to 2.2, preferably equal to or about 2.0.

The value of n can be changed over time. This is advantageous because flue gas flow conditions at the heat transfer surface can change over time due to slagging, ash agglomeration, or fuel or bed conditions. The flue gas coefficient can therefore be shifted over time to better reflect actual boiler conditions.

According to one embodiment of the present invention, if n=2 and the exhaust gas coefficients represent pressure losses, a comparison of the exhaust gas coefficients df _i with a predefined maximum value df _max,i for the exhaust gas coefficients can be carried out for each heat transfer surface. According to one embodiment, the permissible condition is substantially df _i =df _max,i .

According to one embodiment of the present invention, when n=2 and the exhaust gas coefficients represent pressure losses, the sum of the exhaust gas coefficients df _i ,
dp _tot =Σdf _i
A comparison can be made between dp _{max,i and the sum of the predetermined exhaust gas coefficients df max,i} , or the predetermined exhaust gas coefficients simply represent the total pressure drop, and therefore the comparison represents a comparison of the total pressure drop between the furnace and the chimney. According to one embodiment, the permissible condition is substantially dp _tot =dp _max,i .

The exhaust gas factor, according to one embodiment of the present invention, represents the ash deposition factor and can be written in the following form:
df _i =k _ph C(d)q _{m_fa} v _p ⁿ
where k _ph is the particle hardness coefficient, C(d) is the particle diameter function, q _{m_fa} is the mass flow rate of the fly ash, v _p is the particle velocity, and n is a power exponent (0, 3-4). The predetermined flue gas coefficient represents the maximum ash deposition value in such cases. The ash deposition coefficient can also be adjusted based on the properties of the ash (such as softness).

The tolerance condition is substantially df _i =df _max,i according to one embodiment of the present invention, but in a practical situation the tolerance condition can be defined as follows:
df _max,i −δ<df _i ≦df _max,i
where δ>0 and depends on the numerical precision and/or method. If _{df max,i} - δ< df _i ≦ df _max,i , it means that at least one flue gas coefficient calculated using the currently monitored process data including the numerical model of the boiler satisfies the tolerance condition, and in such a case the maximum allowable boiler load is found, and therefore the value Q _h,candidate is selected as the currently calculated maximum boiler instantaneous load Q _h,max .

The tolerance condition is, according to one embodiment of the present invention, substantially Σ(df _i )=Σ(df _max,i ), but in practical situations the tolerance condition can be defined using the sum:
Σ(df _max,i )−δ<Σ(df _i )≦Σ(df _max,i )
where δ>0 and varies depending on the numerical precision and/or method. If Σ(df _max,i )-δ<Σ(df _i )≦Σ(df _max,i ), it means that at least one flue gas coefficient calculated using currently monitored process data including a numerical model of the boiler satisfies the tolerance condition, and in such a case, the maximum allowable boiler load is found, and therefore the value Q _h,candidate is selected as the current calculated maximum boiler instantaneous load Q _h,max . According to one embodiment, the summation index i is over all of the heat transfer surface. According to another aspect of the invention, the summation index i is over only a portion of the heat transfer surface, preferably within the flue gas channel.

It is particularly useful if the value of n is determined using monitored operational data for each of the boilers from a boiler fleet that includes at least two separate boilers. Using a larger number of boilers (two, three, four, etc.) will result in a larger data set, and therefore more operational data being monitored. This can produce better results, and may be particularly advantageous in situations where interpolation and/or extrapolation of experimental data is used in the determination.

The exhaust gas outlet temperature can be substantially estimated in the calculation of step I) by the following formula:
T _boiler,exit =α ₀ +Σα _i Q ⁱ _h,candidate
Alternatively, it is preferable that the coefficient α be estimated by a first-, second-, third-, or higher-order approximation of the above equation. The coefficient α can be obtained by measuring the value of the exhaust gas outlet for several individual steam load values and then fitting the measured value. This data can be collected over time and updated as needed, such as periodically. Alternatively or additionally, this data can be collected when performing one or more calibrations of the combustion boiler.

The coefficients (α) can be applied manually by a human or automatically by a computer using historical data. Automatic updates of the coefficients may be performed, for example, once a month. AI and neural network-based algorithms can be used for the automatic updates.

According to one embodiment of the present invention, the exhaust gas outlet temperature can be substantially estimated in step I) by utilizing an artificial intelligence tool. According to another embodiment of the present invention, the exhaust gas outlet temperature can be substantially estimated in step I) by utilizing a neural network.

The exhaust gas outlet temperature can be estimated in step I) according to one embodiment of the present invention by the following formula:
T _{boiler, exit} = α ₀ + α ₁ × Q _{h, candidate} + α ₂ × Q _{h, candidate} ²
where α ₀ , α ₁ , and α ₂ can be predefined constants. Alternatively or additionally, the coefficients (α) can be fitted manually by a human or automatically by a computer using historical data. Automatic updating of the coefficients may be performed, for example, once a month. AI and neural network-based algorithms can be used for the automatic update.

According to one embodiment of the present invention, the α ₀ term can be solved based on the current state values.
α ₀ = T _{boiler, exit, current} - α ₁ ×Q _{h, current} - _{α 2} ×Q _{h, current} ²
where T _{boiler,exit,current} represents the measured exhaust gas outlet temperature.

In one embodiment of the present invention, the exhaust gas mass flow rate is calculated in step II) using the boiler mass and energy balance equation.

In step II), the calculation of the exhaust gas mass flow rate may include taking into account the mass flow rates of the components _CO2 , _H2O , _N2 , _SO2 , and _O2 . The concentrations of these components can be reliably measured using fairly simple equipment.

In step II), the component values may include fuel parameters, which may reflect changes in fuel properties and/or the type of fuel used in the combustion boiler. For example, stricter tolerances may be used for fuels that tend to cause more corrosion, while less stringent tolerances may be used for fuels that tend to cause less corrosion.

Step b) may be performed remotely from the combustion boiler, preferably in a cloud-based computing service. This helps to simplify maintenance of the combustion boiler, as remote computing devices, such as those configured to run the cloud-based computing service, can be maintained separately from the combustion boiler. Updates to computing software, for example, can thereby be performed centrally at one or a few locations, rather than updating the software at each combustion boiler.

Step b) may alternatively be performed locally at the combustion boiler, preferably at an edge server. This may speed up the calculations as data does not need to be transferred to a remote calculation location.

Either the currently monitored process data and/or the current load may be obtained by real-time measurement. Alternatively, or in addition, the currently monitored process data and/or the current load may be processed by filtering, averaging, calculating trends, or any combination thereof. This helps to avoid noisy or outlier measurements that affect the calculation results, thereby facilitating increased stability of the currently calculated maximum boiler instantaneous load.

The tolerance condition may include a hysteresis condition that requires a predetermined minimum change before changing the current calculated maximum boiler instantaneous load. This is preferable because it can increase the stability of the current calculated maximum boiler instantaneous load and help prevent the current calculated maximum boiler instantaneous load from fluctuating up and down in a short period of time.

While this method can be used with any type of combustion boiler, the applicant has discovered that it is particularly useful when the combustion boiler is a circulating fluidized bed (CFB) or bubbling fluidized bed (BFB) boiler and step b) is performed on the combustion boiler heat transfer surface. This method is particularly advantageous for CFB or BFB boilers.

In one embodiment, step b) is performed on the combustion boiler heat transfer surface between the furnace and the chimney.

The combustion boiler comprises:
- a furnace and associated passages defining an exhaust gas flow path and comprising several heat transfer surfaces;
- measuring equipment for monitoring the current load of the combustion boiler,
- another measuring device for monitoring current process data; and - a control system configured to implement the boiler control method.

The fired boiler, according to one embodiment, includes a furnace and associated passages defining an exhaust gas flow path and including several heat transfer surfaces within the exhaust gas flow path.

In such a combustion boiler, boiler control can be improved. The advantages are the same as those of the method.

The control system may include an edge server that may be configured to process real-time measurements of currently monitored process data and/or current loads, i.e., by filtering, averaging, and/or calculating trends. The edge server may facilitate reducing the amount of currently monitored process data. This may be particularly useful in light of the fact that in certain installations, there may be 60-90 gigabytes of monitored process data each day.

The control system may be configured to perform step b) of the method to locally determine the current calculated maximum boiler instantaneous load. This facilitates rapid decision-making at the combustion boiler, as less or no data may need to be transferred from the combustion boiler system.

Alternatively, or additionally, the control system may be configured to transmit the data to a remote, preferably cloud-based, computing system that may be configured to perform step b) of the method and return the current calculated maximum boiler instantaneous load to the control system. This makes it easier to simplify the combustion boilers and to update the computing system. Updates can, in this situation, be performed centrally rather than at each and every combustion boiler.

The edge server can be configured to reduce the amount of measurement data passed to the remote computing system. In this way, a smaller bandwidth may be sufficient for data transfer. This can be particularly useful considering the fact that in a particular installation, there may be 60-90 gigabytes of monitored process data each day.

The combustion boiler calculation system includes:
a group of fired boilers comprising a boiler control system, each boiler comprising an edge server system configured to process, i.e., by filtering, averaging, and/or calculating trends, real-time measurements of currently monitored process data and/or current loads, and to transmit the processed real-time measurements to a remote computing system;
- A remote computing system, preferably a cloud-based computing system, configured to receive processed data from the real-time measurements, calculate the data for each of the boilers using a numerical boiler model, and return the calculated results to the respective boilers.

In the combustion boiler calculation system, the boiler control system is further configured to adapt the function of the boiler control system based on the calculation results.

The advantage of this configuration is that it reduces the need for computing devices at the combustion boiler, while still providing efficient and fast computational results from a remote computing system.

The computing system may be configured to find a numerical value or current calculated maximum boiler instantaneous load for which at least one exhaust gas coefficient calculated using currently monitored process data, including a numerical model of the boiler, satisfies an acceptable condition, and select this numerical value as the current calculated maximum boiler instantaneous load. This essentially makes it possible to use the method of the present invention in a distributed environment.

The boiler calculation system may be configured to use the processed boiler measurement data to calibrate or adapt a numerical model of the boiler, such as an exhaust gas coefficient numerical model. This makes it easier to remotely calibrate or adapt the numerical model for boiler control.

The boiler calculation system can be configured to adapt or calibrate the boiler's numerical model using collected and processed measurement data from other boilers, allowing for the use of more collected data to adjust the boiler control numerical model.

The combustion boiler and combustion boiler control method are described in more detail below in connection with the embodiments shown in the accompanying drawings, Figures 1 to 9.

FIG. 1 is a diagram showing a CFB boiler. FIG. 1 is a diagram showing a BFB boiler. FIG. 2 is a diagram showing the flow of measurement data from a sensor. 1 is a flow chart illustrating a first method for finding the current calculated maximum boiler instantaneous load Q _h,max . 10 is a flow chart illustrating a second method for finding the current calculated maximum boiler instantaneous load Q _h,max . FIG. 10 illustrates how the current calculated maximum boiler instantaneous load Q _h,max can be presented to the boiler operator. 1 is a graph showing the boiler instantaneous load Q _h and the calculated current maximum calculated boiler instantaneous load Q _h,max and the effect of using the method according to the invention during a test period. Looking more closely at the data of Figure 7, the effect of using the method of the present invention becomes more apparent during the 10-day test period. Figure 7 is a graph showing the boiler instantaneous load Q _h and the calculated current maximum calculated boiler instantaneous load Q _h,max .

In all figures, the same reference numbers refer to the same technical features.

Figure 1 shows a combustion boiler 10, which is a CFB boiler, and includes a furnace 12 with tube walls 13 connected to the steam circuit of the combustion boiler 10. Water is supplied from a water tank (not shown) to an economizer, from which it is supplied to an evaporative heat transfer surface such as the tube walls 13 via a steam drum, and then directed via the steam drum to a superheater and then to a turbine. The exhaust gas channel may be provided with an economizer and/or a superheater.

Fluidizing gas (e.g., air and/or oxygen-containing gas) is supplied from a fluidizing gas supply 153 through a wind box (not shown) below the grate (the grate is not shown in FIG. 1). Primary fluidizing air enters the furnace from below the grate through a nozzle (not shown) (for fluidizing the bed) and a secondary fluidizing gas supply 152 (which supplies oxygen-containing gas to control combustion). This fluidizes the bed medium and also supplies oxygen necessary for combustion to the furnace 12. Furthermore, fuel is supplied to the furnace 12 via a fuel supply 22. Combustion can be adjusted by controlling the fuel supply 22 (e.g., by decreasing or increasing the fuel supply) and the fluidizing gas supply (e.g., by decreasing or increasing the amount of oxygen supplied to the furnace 12). The fuel can be supplied together with additives, specifically additives that act as alkaline adsorbents, such as CaCO3 and/or clay. Additionally or alternatively, a NOx reducing agent, such as ammonium or urea, may be provided in or above the combustion zone of the furnace 12.

A bed medium is also fed into the furnace and may include sand, limestone, and/or clay, with the clay specifically including kaolin. As a result of the bed, and generally of combustion, water and steam are heated within the tube walls 13 in the steam circuit, converting the water to steam.

The ash falls to the bottom of the furnace 12 and is removed via an ash chute (omitted from Figure 1 for clarity), with some of the ash, so-called fly ash, being carried away with the exhaust gases.

Combustion products such as exhaust gas, unburned fuel, and bed media pass from the furnace 12 to a particle separator 17, which may include a vortex finder 103. The particle separator 17 separates the exhaust gas from the solids. There may be multiple separators 17 (two, three, ...), preferably arranged parallel to one another, particularly in larger combustion boilers 10.

The solids separated by the separator 17 pass through a loop seal 160, preferably located at the bottom of the separator 17. The solids then proceed to a fluidized bed heat exchanger (FBHE) 100, which also serves as a heat transfer surface, to collect heat from the solids and further heat the steam in the steam circuit. The chamber within which the FBHE 100 is located may be fluidized, and the FBHE 100 itself may comprise heat transfer tubes or other types of heat transfer surfaces. The FBHE 100 may be configured as a reheater or superheater. Steam is sent from the FBHE outlet 101 into a high-pressure turbine (if the FBHE 100 is a superheater) or an intermediate-pressure turbine (if the FBHE 100 is a reheater). For clarity, the turbine is not shown in FIG. 1. The solids can be returned from the FBHE 100 through the return channel 102 and into the furnace 12. In particular, in larger combustion boilers 10, there may be multiple (two, three, ...) loop seals 160 and FBHEs 100, and return channels 102, preferably arranged parallel to one another, so that there is a respective loop seal 160, FBHE 100, and return channel 102 for each separator 17. In practice, some of the FBHEs 100 may be arranged as superheaters, and others as reheaters.

From the separator 17, the exhaust gas is sent to a horizontal passage 15, from which it is further sent to a rear flue 16 (which may preferably be a vertical passage), and from there to a chimney 19 through an exhaust gas conduit 18.

The rear flue 16 comprises several heat transfer surfaces 21 _i (i=1, 2, 3, ..., k, where k is the number of heat transfer surfaces). Heat transfer surfaces 21 ₁ , 21 ₂ , 21 ₃ , ..., 21 _k-1 , 21 _k are shown in FIG. 1 . Heat transfer surface 21 _k represents an air preheater. Heat transfer surfaces 21 _k-1 and 21 ₂ represent superheaters, and heat transfer surfaces 21 ₁ and 21 ₃ represent reheaters. The actual number of various heat transfer surfaces in each of these components can be selected differently for each combustion boiler, for example, depending on the actual needs. Other components comprising heat transfer surfaces 21 may also be present.

The exhaust gases leaving the last heat transfer surface _21k have an exhaust gas outlet temperature T _FG,exit , which is measured by a temperature sensor _20k .

According to one embodiment, the temperatures before and after each heat transfer surface 21 _i (respectively T _FG,in,i and T _FG,in,i+1 ) can be measured by respective temperature sensors 20 _i (i=1, 2, 3, . . . , k−1, k).

However, according to another aspect, it is preferred that these temperatures do not necessarily have to be measured. It may be sufficient to know the exhaust gas outlet temperature T _FG,exit . The aforementioned temperatures before and after each heat transfer surface 21 _i (T _FG,in,i , T _FG,in,i+1 ) can be obtained numerically, as will be explained further below.

The combustion boiler 10 is equipped with multiple sensors and computer units. In fact, one medium-sized (100-150 MW _th ) combustion boiler 10 can generate 100 million measurements per day, which requires 25 GB of storage space. Figures 1, 2, and 3 show some of the sensors and computer units. Examples of sensors include a combustion gas (usually combustion air) volumetric flow sensor 30 (for measuring the primary and secondary fluidization gas supply), a fuel supply sensor 650, and temperature sensors 20 _i (i=1, 2, ..., k), a temperature sensor in the FBHE and a pressure sensor 116 in the return channel 102 (both present only in CFB boilers), and a sensor 40 in the furnace 12.

Process data may be collected from the sensors by a distributed control system (DCS) 201. The data collection may be most conveniently located, for example, via a fieldbus 290. The DCS 201 may include a display/monitor 202 for displaying operational status information to an operator. An edge server 203 may process the measurement data obtained from the sensors, including filtering and smoothing. There may be local storage 204 for storing the data.

The DCS 201, display/monitor 202, edge server 203, and local storage 204 may be within the combustion boiler/network 280 (the local storage 204 is preferably connected directly to the edge server). The combustion boiler network 280 is preferably independent of the fieldbus 290, which is used to notify the DCS 201 and/or edge server 203 of measurement results from sensors. There may also be an open platform communication server 210 (see Figure 3) between the DCS 201 and edge server 203 to further enhance system interoperability.

The combustion boiler network 280 may be connected to the Internet 200, preferably via a gateway 290. Measurement results may, in this situation, be transferred from the combustion boiler network 280 to a cloud service, such as a process intelligence system 205 located in a computational cloud 206. The applicant currently operates a cloud service that runs the analytics platform. The cloud service may be run in a virtualized server environment, such as Microsoft® Azure®, which is a virtualized, easily scalable environment for distributed computing and cloud storage of data. Other cloud computing services may also be suitable for running the analytics platform. Furthermore, a local or remote server may be used to run the analytics platform instead of or in addition to the cloud computing service.

Figure 2 shows a fired boiler 10 that is a BFB boiler. BFB boilers differ from CFB boilers in that the fluidized bed is a bubbling bed rather than a circulating bed. Therefore, the separator 17, loop seal 160, FBHE 100, and return channel 102 are not required.

Typically, there is at least one superheater 14 within the furnace 12, preferably at the top of the furnace 12. The inlet 141 of the superheater 14 is the inlet from a steam drum or another superheater, and the outlet 142 is preferably the outlet to a high-pressure turbine.

FIG. 4 shows a method for controlling a combustion boiler.
a) The current load Q _h of the combustion boiler 10 is monitored in step K1 (in the method shown in FIG. 4, the exhaust gas outlet temperature T _FG,exit and the heat load Q _fluid,i per heat transfer surface 21 _i in the exhaust gas flow path (vertical passage 16) are also monitored).
b) A value Q _h,candidate is selected (step K3), after which the heat load at the heat transfer surface 21 _i and the flue gas temperature for Q _h,candidate are calculated. The value Q _h,candidate is then used to calculate at least one flue gas coefficient df _i (step K7) using currently monitored process data including a numerical model of the boiler (tested in step K9) that meets the tolerance conditions, and the value Q _h,candidate is selected as the currently calculated maximum instantaneous boiler load Q _h,max (step K11).
c) the current calculated maximum boiler instantaneous load Q _h,max is shown to the operator (such as by displaying on the monitor/screen 202) and/or the current load Q _h is
c1) If it is smaller than the calculated maximum instantaneous boiler load Q _h,max ,
c1i) indicating to the boiler operator that the boiler load _Qh may increase, and/or c1ii) automatically increasing the boiler load _Qh ;
and/or c2) is greater than the calculated maximum instantaneous boiler load Q _h,max ;
c2i) indicate to the boiler operator that the boiler load _Qh exceeds the maximum instantaneous boiler load, and/or c2ii) automatically reduce the boiler load _Qh .

Step b) is preferably carried out on the heat transfer surface 21 _i of the combustion boiler 10 between the furnace 12 and the chimney 19 .

In this method, the currently monitored process data of the boiler may include a) the current flue gas exit temperature T _FG,exit in the flue gas path, and b) the heat load Q _fluid,i for each heat transfer surface 21 _i in the flue gas path (rear flue 16 ).

The method further includes using monitored process data from both a) and b) in calculating the exhaust gas coefficients df _i and in finding the value Q _h,candidate for the current calculated maximum boiler instantaneous load Q _h,max .

This discovery is performed such that if at least one flue gas coefficient df _i calculated using currently monitored process data including a numerical model of the boiler fails to meet the acceptance criteria, the next value Q _h,candidate is automatically selected. The automatic selection is preferably performed iteratively.

This finding can be done, as an example, by performing the following calculation steps:
- I: Step of calculating an estimate of the boiler exhaust gas exit temperature T _boiler,exit that results in a calculated boiler model when the boiler thermal load corresponds to the value Q _h,candidate .
II: Calculating the exhaust gas mass flow rate q _m,fluegas .
III: Calculation of the heat load Q _{fluid,i,candidate} for each heat transfer surface 21 _i in the flue gas flow path (rear flue 16) using the current heat load Q _{fluid,i,current of the heat transfer surface corrected by using the numerical boiler model: Q fluid,i,candidate = Q fluid, i} ,current +Σα _j,i (Q _h,candidate ) ^j -Σpar _j,i (Q _h,current ) ^j .
IV: Using the calculated heat load Q _{fluid,i,candidate} for each heat transfer surface 21 _i in the flue gas flow path (rear flue 16), calculate the flue gas temperature at each heat transfer surface (T fluegas,in,i , T _{fluegas,out,i , i} = _{1, ..., k)} starting from the heat transfer surface 21 _k in the flue gas flow path (rear flue 16) that is closest to the flue gas outlet in the upstream direction of the flue gas flow _, i.e., using the estimated boiler flue gas outlet temperature T fluegas _,out,m = T FG,exit.
V: Calculation of the flue gas coefficient df _i , i=1, . . . , k for each heat transfer surface 21 _i in the flue gas flow path (rear flue 16 ).

The fitting of the parameters (par _j,i ) can be done manually by a human or automatically by a computer using historical data. Automatic updating of the parameters may be performed, for example, once a month. AI and neural network-based algorithms can be used for the automatic updating.

Step II) may include calculating the exhaust gas mass flow rate q _m,fluegas,m for the selected exhaust gas components.

The exhaust gas temperature at each heat transfer surface can be calculated, for example, using the following formula:

where T ₌ the exhaust gas temperature at the inlet of the i-th heat transfer surface, _c = the specific heat capacity, and T ₌ the exhaust gas temperature at the outlet of the i-th heat transfer surface. The exhaust gas temperature can be determined using artificial intelligence tools. The exhaust gas temperature can be determined using neural networks.

Preferably, the exhaust gas coefficients include or are less than or equal to the following:
df _i =k _i (q _{m, fluegas} /(ρ _{fluegas, I} A _{cross, i} )) ⁿ
where k _i is a predetermined non-zero parameter, preferably a positive (non-zero) number, that can be specifically selected for the combustion boiler;
q _m,fluegas is the mass flow rate of the exhaust gas;
n is a positive number (which may be chosen as a natural number, a rational number, a real number, or even a complex number);
ρ _fluegas,i is the flue gas density obtained from the flue gas temperature T _FG,in,i on the i-th heat transfer surface 21 _i ;
A is the cross-sectional area of the exhaust gas channel on the i-th heat transfer surface 21 _i .

Advantageously, n may be chosen to be at least one of the following:
i) if a calculated exhaust gas velocity is used, in the range of 0.9 to 1.1, preferably equal to or about 1.0;
ii) when using calculated corrosion-causing exhaust gases, in the range of 2.9 to 3.5, preferably between 3.2 and 3.35; or iii) when using pressure drop, in the range of 1.8 to 2.2, preferably equal to or about 2.0.
The value of n may be changed over time. Specifically, the value of n may be determined from a group of combustion boilers, the group including at least two separate combustion boilers 10, and thus, the determination uses monitored operational data for each combustion boiler 10.

In the calculation of step I), the calculated value of the flue gas outlet temperature T _FG,exit under an arbitrary value Q _h,candidate selected for the boiler load can be estimated by the following formula:
T _{FG, exit} = α ₀ + Σα _j (Q _{h, candidate} ) ^j
Alternatively, it is preferable that the coefficients α _{0 , α 1 , α 2 , ... are estimated by a linear, quadratic, or third or higher order approximation of the above formula. The coefficients α 0} , α ₁ , α ₂ , ... are obtained in advance by fitting after measuring the values of the exhaust gas outlet temperature T _FG,exit for several individual values of _the boiler load Q steam.

In step II), in order to determine the mass flow rate of the exhaust gas, the calculation of the components q m _,fluegas,m preferably includes at least some, most preferably all, of m = CO ₂ , H ₂ O, N ₂ , SO ₂ , O _2. In other words, in calculation step IV), some or all of q _{m,fluegas,CO 2} , q _{m,fluegas,H 2 O} , q _{m,fluegas,N 2} , q _{m,fluegas,SO 2} , q _{m,fluegas,O 2} can be used as the value of _q m,fluegas,m. These are preferably measured in the exhaust gas conduit 18 or longitudinal groove 19, for which purpose suitable sensors are installed in the exhaust gas passage. In step II), the values of the components can further include fuel parameters.

The exhaust gas mass flow rate may be based on a calculation of the sum of the mass flow rates of the exhaust gas components q _m,fluegas,m, which is calculated based on the fuel analysis (proximate and final fuel analysis), combustion air flow rate, and/or recirculation gas flow rate through a boiler mass and energy balance calculation.

The mass flow rate of the exhaust gas may preferably be calculated by the following formula:
q _m,fluegas =Σq _m,fluegas,i
That is, for example, the sum of the following exhaust gas mass flow components _CO2 , _H2O , _N2 , _SO2 , and _O2 .

where, for example, x _c,fuel represents the carbon in the fuel, i.e., the first subscript represents the component, the second subscript is either the fuel or the combustion air being referenced, q _m,fuel is the fuel flow rate, q _m,air is the combustion air flow rate, and M _x represents the molar mass. Advantageously, the properties of the fuel used and the combustion air in the exhaust gas mass flow components. The moisture content of the fuel can be measured or calculated.

Step b) may be performed remotely to the combustion boiler, such as in the process intelligence system 205. Step b) may alternatively be performed locally at the combustion boiler, preferably in the edge server 203.

Any currently monitored process data and/or current load may be obtained by real-time measurement, processed by filtering, averaging, trending, or any combination thereof.

The permissive conditions may include a hysteresis condition that requires a predetermined minimum change before changing the current calculated maximum boiler instantaneous load Q _h,max .

The acceptance criteria preferably include comparing at least one calculated flue gas coefficient df _i to a respective maximum value df _{max,i ,} which is preferably a preset, boiler-specific value, and the value Q _h,candidate is discarded if it exceeds the maximum value df _max,i .

In the combustion boiler 10, the furnace 12 and associated passages (horizontal passage 15 and rear flue 16) define a flue gas passage. The furnace 12 and passages 15, 16 provide several heat transfer surfaces 21 _i within the flue gas passage. The combustion boiler 10 also includes a measuring device for monitoring the current load Q _h of the combustion boiler, and another measuring device for currently monitoring current process data.

The control system (DCS 201 and edge server 203, or possibly with the involvement of edge server 203, remote process intelligence system 205) is configured to execute the boiler control method.

The edge server 203 may be configured to process real-time measurements of currently monitored process data and/or current load, i.e., by filtering, averaging, and/or calculating trends.

The control system may be configured to perform method step b) and locally determine the current calculated maximum boiler instantaneous load Q _h,max at the fired boiler 10 and/or send the data to a remote, preferably cloud-based (such as the computational cloud 206) computing system (such as the process intelligence system 205) configured to perform method step b) and return the current calculated maximum boiler instantaneous load Q _h,max to the control system. The control system may then present the information to the boiler operator, such as by displaying the information using a display/monitor, as in method step c).

The edge server 203 may be configured to reduce the amount of measurement data passed to the remote computing system.

The combustion boiler calculation system includes a group of combustion boilers 10, each of which includes a boiler control system (CS) including an edge server (203) system configured to process, i.e., filter, average, and/or calculate trends, real-time measurements of currently monitored process data and/or current loads and transmit the processed real-time measurements to a remote computing system. The remote computing system is preferably a cloud-based computing system configured to receive processed data from the real-time measurements, calculate data for each of the combustion boilers 10 using a numerical boiler model, and return the calculation results to each of the boilers 10. The boiler control system may be configured to adapt its functionality based on the calculation results.

The computing system is preferably configured to find a value Q h,candidate for the current calculated maximum boiler instantaneous load Q _h,max for which at least one flue gas coefficient df _i calculated using currently monitored process data including a numerical model of the boiler satisfies an acceptance condition, and to select the value Q _{h ,candidate} as the current calculated maximum boiler instantaneous load Q _h,max .

The boiler calculation system may be configured to use processed measurement data from the combustion boiler 10 to adapt or calibrate a numerical model of the boiler. Alternatively, or additionally, the boiler calculation system may be configured to use processed measurement data collected from other combustion boilers 10 to adapt or calibrate a numerical model of the combustion boiler 10.

Figure 5 shows a modification of the method shown in Figure 4. Steps L1, L3, L7 and L9 are the same as steps K1, K3, K9 and K11, respectively, but step L5 allows the direct calculation of the exhaust gas coefficient df _i for all heat transfer surfaces 20 _i . That is, if T _FG,in,i is measured using the respective temperature sensors 21 _i , no back-calculation is necessary, and therefore step K7 can be omitted in the method shown in Figure 5.

6 shows the available inputs to the numerical boiler model in step N1. In step N3, Q _h,max is calculated numerically using the boiler model, and in step N5, the estimated maximum load Q h,max is presented to the boiler operator via a specific user interface (UI), preferably via a display/monitor 202.

Figure 7 shows the boiler instantaneous load _Qh and the calculated current maximum calculated boiler instantaneous load Qh _,max , as well as the effect of using the method according to the invention during the test period. During the 10-day test period, with a boiler output of 120 MW _th , an average load of 3 to 6 MW _th was obtained than outside the test period. Figure 8 shows the 10-day test period in more detail.

In other words, in the boiler control method, a numerical model using the determined operating parameters of the fluidized bed combustion boiler is used to estimate the current calculated maximum boiler instantaneous load Q _h,max of the combustion boiler. The current boiler load Q _h is calculated using measured data of the steam circuit.

Then, if the boiler load _Qh is less than the current calculated maximum boiler instantaneous load Qh _,max , i) an indication is given to the boiler operator that the boiler load may be increased, and/or ii) the boiler load is automatically increased. Alternatively, or additionally, if the boiler load _Qh is greater than the boiler maximum instantaneous load _Qh,max , i) an indication is given to the boiler operator that the boiler load exceeds the boiler maximum instantaneous load, and/or ii) the boiler load is automatically reduced.

It will be clear to those skilled in the art that, as technology advances, the basic idea of the present invention can be implemented in many different ways. The present invention and its embodiments are therefore not limited to the examples and samples described above, but may vary within the scope of the claims and their legal equivalents.

In addition to, or instead of, using the specific empirical formulas mentioned above, it is possible to utilize artificial intelligence tools and/or neural networks in the numerical model calculations.

In the following claims and in the foregoing description of the invention, unless the context otherwise requires, either by express wording or necessary implication, the word "comprise" or variations such as "comprises" or "comprising" are used in an inclusive sense, i.e., used to specify the presence of stated features but not to exclude the presence or addition of other features in various embodiments of the invention.

T _FG,in,i: Exhaust gas temperature at the inlet of heat exchanger 21 _i (i = 1, 2, ..., k) T _FG,exit: Exhaust gas temperature at the outlet of heat exchanger 21 _k Sensor 20: Temperature sensor (FBHE)
20 _i temperature sensor (i = 1, 2, ... k)
30 Gas volume flow sensor 40 Sensor inside furnace 165 Pressure sensor (loop seal)
650 Fuel supply sensor 10 Combustion boiler 12 Furnace 13 Tube wall 14 Superheater 15 Horizontal passage 16 Rear flue 17 Particle separator 18 Exhaust gas conduit 19 Vertical groove 21 _i Heat transfer surface (i = 1, 2, ... k)
22 Fuel supply section 100 Fluidized bed heat exchanger (FBHE)
101 FBHE outlet 102 Return channel 103 Vortex finder 141 Superheater inlet 142 Superheater outlet 151 Primary fluidization gas supply 152 Secondary fluidization gas supply 153 Fluidization gas supply source 161 Reheater output 200 Internet 201 Distributed control system 202 Display/monitor 203 Edge server 204 Local storage device 205 Process intelligence system 206 Computational cloud 210 Open platform communication server 280 Combustion boiler network 290 Fieldbus

Claims (26)

A combustion boiler control method, comprising:
a) monitoring the boiler load (Q _h ), which is the current load of the combustion boiler;
b) finding a value (Q h,candidate ) for the current calculated maximum boiler instantaneous load (Q _h,max ) such that at least one exhaust gas coefficient (df _i ) calculated by a numerical model of the combustion boiler using currently monitored process data satisfies an acceptable condition, and selecting said value (Q _{h,candidate )} as the current calculated maximum boiler instantaneous load (Q _h,max );
c) indicating the current calculated maximum instantaneous boiler load (Q _h,max ) to an operator, and/or the boiler load (Q _h ) is
c1) If the current calculated maximum boiler instantaneous load (Q _{h,max ) is smaller than the current calculated maximum boiler instantaneous load (Q h,max} ),
c1i) indicating to the operator that the boiler load (Q _h ) may increase, and/or c1ii) automatically increasing the boiler load (Q _h );
and/or c2) if it is greater than the current calculated maximum boiler instantaneous load (Q _h,max ),
c2i) indicating to the operator that the boiler load ( _Qh ) exceeds the current calculated maximum instantaneous boiler load; and/or c2ii) automatically reducing the boiler load ( _Qh ). i) the currently monitored process data of the combustion boiler,
ia) the current exhaust gas exit temperature in the exhaust gas flow path (T _{flue gas,exit,current} );
ib) the heat load (Q _fluid,i ) for each heat transfer surface (i) in the flue gas flow path; and ii) the monitored process data from both ia) and ib) is used in calculating the flue gas coefficients and in finding the value (Q _h,candidate ) for the current calculated maximum boiler instantaneous load (Q _h,max ).
The method of claim 1. 3. The method according to claim 1 or 2, wherein the detection is performed such that if the at least one exhaust gas coefficient (df _i ) calculated by a numerical model of the combustion boiler using currently monitored process data no longer satisfies an acceptable condition, a next value (Q _h,candidate ) is automatically selected. The method of claim 3 , wherein the next value (Q _h,candidate ) is selected iteratively. The discovery
I: calculating an estimate of the boiler exhaust gas outlet temperature (T _boiler,exit ) using a computational boiler model when the thermal load of the combustion boiler corresponds to the value (Q _h,candidate );
- II: Calculating the flue gas mass flow rate (q _m,fluegas ) using the boiler mass and energy balance equation when the thermal load of the combustion boiler corresponds to the value (Q _h,candidate );
III: calculating the heat load (Q _{fluid,i,candidate} ) of each heat transfer surface in the exhaust gas flow path using the current heat load (Q fluid,i, _current ) of said heat transfer surface corrected by using a numerical boiler model ( Q _{fluid,i,candidate} =Q _fluid,i, current +Σα _j,i (Q steam,max ) ^j -Σα _j,i (Q _{stream,current )} ^j );
IV: Using the calculated heat load (Q _{fluid,i,candidate} ) for each heat transfer surface in the flue gas flow path, calculate the flue gas temperature at each heat transfer surface (T _{fluegas,in,i , T fluegas,out,i , i=1, ..., k} ), starting from the heat transfer surface 21 _k in the flue gas flow path that is closest to the boiler flue gas outlet in the upstream direction of the flue gas flow, using the estimated value of the _boiler flue gas outlet temperature (T _fluegas,in,i , T _{fluegas,out,i} , i=1, ..., k);
- V: The method according to any one of claims 1 to 4, carried out by carrying out a step of calculating an exhaust gas coefficient (df _i , i = 1, ..., k) for each heat transfer surface in the exhaust gas flow path. The exhaust gas coefficient includes or is the following formula:

where k _i is a non-zero parameter that may be specifically selected for a combustion boiler;
q _m,fluegas is the mass flow rate of the exhaust gas;
6. The method according to _{claim 5} , wherein n is a model parameter that can be selected specifically for a combustion boiler, ρ is the flue gas density at the i-th heat transfer surface, and A is the cross-sectional area of the flue gas channel at the i-th heat transfer surface. n is
i) in the range of 0.9 to 1.1 when taking into account the calculated exhaust gas velocity;
ii) in the range of 2.9 to 3.5 when taking into account calculated exhaust gas induced corrosion; or iii) in the range of 1.8 to 2.2 when taking into account pressure loss. The method of claim 7, wherein the value of n is changed over time. 9. The method of claim 7 or 8, wherein the value of n is determined using operational data monitored for each of the fired boilers from a group of boilers including at least two separate boilers. In the calculation of step I), the boiler exhaust gas outlet temperature is substantially calculated by the formula T _boiler,exit = α ₀ + Σα _j (Q _h,candidate ) ^j
Alternatively, the method according to any one of claims 5 to 9 is estimated by approximating the correspondence between the boiler exhaust gas outlet temperature and the numerical value (Q _h,candidate ) to the formula, and the respective coefficients (α ₀ , α ₁ , α ₂ , ...) are obtained in advance by measuring values of the boiler exhaust gas outlet temperature (T _{boiler ,exit} ) for several individual values of the boiler load (Q _steam ), and then fitting the measured values to a predetermined function by the fitted function . The method according to any one of claims 5 to 10, wherein in step II) the calculation of the exhaust gas mass flow rate utilizes the mass flow rates of the exhaust gas components (q _m,fluegas,m ), and the exhaust gas components include CO ₂ , H ₂ O, N ₂ , SO ₂ , and O ₂ . The method of any one of claims 5 to 11, wherein in step II), the calculation of the exhaust gas mass flow rate includes fuel parameters. The method of any one of claims 1 to 12, wherein step b) is performed remotely from the combustion boiler. The method of any one of claims 1 to 12, wherein step b) is performed locally in the combustion boiler. wherein the currently monitored process data and/or current load are both obtained by real-time measurement, processed by filtering, processed by averaging, calculating trends, or any combination thereof;
The method according to any one of claims 1 to 14. The method of any one of claims 1 to 15, wherein the permissive condition includes a hysteresis condition that requires a predetermined minimum change in the at least one exhaust gas coefficient (df _i ) before changing the current calculated maximum boiler instantaneous load (Q _h, max ). 17. The method according to any one of claims 1 to 16, wherein the acceptance condition comprises a comparison of the calculated at least one exhaust gas coefficient (df _i ) to a respective design value, and wherein the numerical value (Q _h,candidate ) is discarded if it exceeds the design value. The method of any one of claims 1 to 17, wherein the combustion boiler is a circulating fluidized bed (CFB) boiler or a bubbling fluidized bed (BFB) boiler, and step b) is performed on a heat transfer surface of the combustion boiler, optionally including a furnace (12), located between the furnace (12) and a chimney (19). a furnace (12) and associated passages (15, 16) defining an exhaust gas flow passage and comprising several heat transfer surfaces (21 _i ) located within said exhaust gas flow passage;
a measuring device that monitors the current load (Q _h ) of the combustion boiler (10);
- another measuring device, such as a sensor (20, 20 _i , 30, 40, 116, 165, 650), that monitors current process data;
- a control system (CS 201, 203, 205) adapted to carry out the boiler control method according to any one of claims 1 to 18. A combustion boiler (10) as described in claim 19, wherein the control system (CS) comprises an edge server (203) configured to process real-time measurements of currently monitored process data and/or current load, i.e., by filtering, averaging, and/or calculating trends. 21. The fired boiler of claim 19 or 20, wherein the control system is configured to perform step b) of the method to locally determine the current calculated maximum instantaneous boiler load (Q _h,max ). 21. The combustion boiler of claim 19 or 20, wherein the control system is configured to transmit data to a remote computing system configured to perform step b) of the method and return the current calculated maximum boiler instantaneous load (Q _h,max ) to the control system. the control system is configured to transmit data to a remote computing system configured to perform step b) of the method and return the current calculated maximum boiler instantaneous load (Q _h,max ) to the control system;
The combustion boiler of claim 20 , wherein the edge server is configured to reduce the amount of process data passed to the remote computing system. a group of fired boilers (10) according to any one of claims 19 to 22, comprising at least two separate boilers, each boiler comprising a boiler control system (DCS) comprising an edge server (203) system configured to process, i.e. by filtering, averaging and/or calculating trends, said real-time measurements of currently monitored process data and/or current loads and to transmit said processed real-time measurements to a remote computing system (205);
a remote computing system (205) configured to receive processed data from the real-time measurements, calculate the data for each of said combustion boilers (10) using a numerical boiler model, and return the calculation results to each of said combustion boilers (10);
A combustion boiler calculation system comprising:
the boiler control system is configured to adapt the function of the boiler control system based on the calculation results, and the remote computing system is configured to find a value (Q h,candidate ) for a current calculated maximum boiler instantaneous load (Q _h,max ) such that at least one exhaust gas coefficient (df _i ) calculated by a numerical model of the fired boiler using currently monitored process data satisfies an acceptance condition, and to select the value (Q h _{, candidate} ) as the current calculated maximum boiler instantaneous load (Q _h,max ). The combustion boiler calculation system of claim 24, wherein the combustion boiler calculation system is configured to use processed measurement data of the combustion boiler (10) to adapt or calibrate a numerical model of the combustion boiler (10). The combustion boiler calculation system according to any one of claims 24 to 25, wherein the combustion boiler calculation system is configured to adapt or calibrate a numerical model of the combustion boiler (10) using processed measurement data also collected from other combustion boilers (10).