METHOD OF DETERMINING A LOCAL TEMPERATURE ANOMALY IN A FLUIDIZED BED OF A COMBUSTION BOILER, METHOD OF CALIBRATING A NUMERICAL MODEL OF A FLUIDIZED BED OF A COMBUSTION BOILER, METHOD OF ESTIMATING A RISK OF FLUIDIZED BED COMBUSTION BOILER BED SINTERING, METHOD OF CONTROLLING A FLUIDIZED BED BOILER, AS WELL AS A COMBUSTION BOILER

Abstract

A method of determining a local temperature anomaly in a fluidized bed combustion boiler system that includes at least three temperature sensors together defining a measurement grid, each sensor representing a measurement point, includes monitoring current operation data of the boiler, including measured bed temperature and at least primary air flow, fuel moisture, main steam flow, flue gas oxygen, and bed pressure, preparing a numerical model among operation data, such as primary air flow, fuel moisture, main steam flow, flue gas oxygen, and bed pressure. The measured bed temperatures measurement points are prepared and calibrated. Bed temperatures for the measurement points are monitored using the numerical model. This obtains computed bed temperatures under normal operation conditions, and the measured bed temperatures are compared with the computed bed temperatures for at least some of the measurement points. If an anomaly threshold is exceeded, determining that a local temperature anomaly is present.

Claims

1.-18. (canceled)

19. A method of determining a local temperature anomaly in a fluidized bed of a combustion boiler system that comprises a furnace having a boiler grid that is equipped with at least three temperature sensors that together define a measurement grid where each temperature sensor represents a measurement point (P.sub.i, i=1, . . . , n), the method comprising: monitoring current operation data of the boiler, including the measured bed temperature (T.sub.Mi; i=1, . . . , N) at each measurement point (P.sub.i, i=1, . . . , N) and at least primary air flow (x1), fuel moisture (x2), main steam flow (x3), flue gas oxygen (x4) and bed pressure (x5); is monitored; preparing and calibrating a numerical model between boiler operation data, namely, at least primary air flow (x1), fuel moisture (x2), main steam flow (x3), flue gas oxygen (x4), and bed pressure (x5), and the measured bed temperatures (T.sub.Mi; i=1, . . . , N) at each measurement point (P.sub.i, i=1, . . . , N); computing bed temperatures for the measurement points (P.sub.i, i=1, . . . , n) using the numerical model, to obtain computed bed temperatures (T.sub.Ci; i=1, . . . , n) under normal operation conditions of the combustion boiler system (10); and comparing the measured bed temperatures (T.sub.Mi) with the computed bed temperatures (T.sub.Ci) for at least some of the measurement points (P.sub.i, i=1, . . . , n), and, if an anomaly threshold is exceeded, determining that local temperature anomaly is present.

20. The method according to claim 19, wherein, for at least one measurement point (P.sub.j, j is some 1, . . . , n), the numerical model is used to compute a computed temperature (T.sub.Cj), using current operation data and measured bed temperatures of at least two other measurement points, and the method further comprises comparing the computed temperature (T.sub.ci) and the measured bed temperature (T.sub.Mi) against an anomaly criterion and determining that local temperature anomaly is present if the anomaly criterion is fulfilled.

21. The method according to claim 19, wherein the calibration is performed in a delayed manner using historical data.

22. The method according to claim 19, wherein the calibration is not performed for a predefined time upon detecting a local temperature anomaly.

23. The method according to claim 22, wherein the calibration is not performed for a predefined time upon detecting a local temperature anomaly that fulfills a given threshold.

24. The method according to claim 19, wherein, upon detecting a local bed temperature anomaly, performing at least one of automatically adjusting combustion boiler system operation and indicating the boiler operator that a local bed temperature anomaly is detected.

25. A method according to claim 19, wherein the numerical model between boiler operation data and the measured bed temperatures (T.sub.Mi; i=1, . . . , N) is calibrated such that current operation data of the boiler, including the measured bed temperature (T.sub.Mi; i=1, . . . , N) at each measurement point (Pi, i=1, . . . , n) and at least primary air flow (x1), fuel moisture (x2), main steam flow (x3), flue gas oxygen (x4), and bed pressure (x5), is monitored and collected to historical data, and a numerical model (f) between boiler operation data, namely, at least primary air flow (x1), fuel moisture (x2), main steam flow (x3), flue gas oxygen (x4), and bed pressure (x5), and the measured bed temperatures (T.sub.Mi; i=1, . . . , N) at each measurement point (P.sub.i, i=1, . . . , n) is fitted using at least one numerical fitting method.

26. The method according to claim 25, wherein the calibration is repeated at predefined intervals.

27. The method according to claim 25, wherein the calibration is prevented upon detecting a local temperature anomaly.

28. A method of estimating a risk of fluidized bed combustion boiler bed sintering, wherein the combustion boiler system comprises a furnace having a boiler grid that is equipped with at least three temperature sensors that together define a measurement grid where each temperature sensor represents a measurement point (P.sub.i, i=1, . . . , n), the method comprising measuring current operation data of the boiler, namely, the measured bed temperature (T.sub.Mi; i=1, . . . , N), is at each measurement point (P.sub.i, i=1, . . . , n); computing, based on the current operation data of the boiler: (i) an average of the measured bed temperatures; (ii) a standard deviation of measured bed temperature; (iii) a difference between measured bed maximum temperature and measured bed minimum temperature; and (iv) s spread (x.sub.spread, i=x.sub.ix.sub.xi) for the measured bed temperatures; and (v) using the computation results from (i), (ii), (iii) and (iv) to prepare a bed sintering index.

29. The method according to claim 28, the method further comprising: vi) computing bed temperatures (T.sub.Ci; I=1, . . . , n) for the same measurement points, and residuals between the measured bed temperatures (T.sub.Mi; i=1, . . . , n) and the computed bed temperatures, wherein results from step (v) are also used to prepare the bed sintering index.

30. The method according to claim 28, wherein the computed bed temperatures (T.sub.Ci; I=1, . . . , n) are obtained such that bed temperatures for the measurement points (P.sub.i, i=1, . . . , n) are computed using at least one numerical bed temperature model between boiler operation data and the measured bed temperatures, to obtain computed bed temperatures (T.sub.Ci; i=1, . . . , n) under normal operation conditions of the combustion boiler system.

31. The method according to claim 28, wherein, upon detecting a bed sintering index exceeding a predefined criterion, performing at least one of automatically adjusting combustion boiler system operation and indicating the boiler operator that a bed sintering condition is detected.

32. The method according to claim 29, wherein the automatic adjusting of boiler operation includes at least one (a) increasing or decreasing combustion air feed, (b) increasing or decreasing fuel feed (20), (c) increasing or decreasing at least one of bed material feed and bed material removal, (d) adjusting recirculation gas flow, and (e) restricting the boiler load temporarily.

33. The method according to claim 31, wherein the sintering index is monitored using a numerical model, and a delayed calibration of the numerical model is used to reduce or to avoid the effect of recent bed conditions in the calibration data.

34. The method according to claim 33, wherein the delayed calibration is performed according to calibrating a numerical model (f) between boiler operation data and the measured bed temperatures (T.sub.Mi; i=1, . . . , N) such that current operation data of the boiler, including the measured bed temperature (T.sub.Mi; i=1, . . . , N) at each measurement point (P.sub.i, i=1, . . . , n) and at least primary air flow (x1), fuel moisture (x2), main steam flow (x3), flue gas oxygen (x4), and bed pressure (x5), is monitored and collected to historical data, and a numerical model (f) between boiler operation data, namely, at least primary air flow (x1), fuel moisture (x2), main steam flow (x3), flue gas oxygen (x4), and bed pressure (x5), and the measured bed temperatures (T.sub.Mi; i=1, . . . , N) at each measurement point (P.sub.i, i=1, . . . , n) are fitted using at least one numerical fitting method.

35. A combustion boiler system that is configured to carry out a method of determining a local temperature anomaly in a fluidized bed of a combustion boiler system that comprises a furnace having a boiler grid that is equipped with at least three temperature sensors that together define a measurement grid where each temperature sensor represents a measurement point (P.sub.i, i=1, . . . , n), the method comprising: monitoring current operation data of the boiler, including the measured bed temperature (T.sub.Mi; i=1, . . . , N) at each measurement point (P.sub.i, i=1, . . . , N) and at least primary air flow (x1), fuel moisture (x2), main steam flow (x3), flue gas oxygen (x4), and bed pressure (x5); preparing and calibrating a numerical model (f) between boiler operation data, namely, at least primary air flow (x1), fuel moisture (x2), main steam flow (x3), flue gas oxygen (x4), and bed pressure (x5), and the measured bed temperatures (T.sub.Mi; i=1, . . . , N) at each measurement point (P.sub.i, i=1, . . . , N); computing bed temperatures for the measurement points (P.sub.i, i=1, . . . , n) using the numerical model, to obtain computed bed temperatures (T.sub.Ci; i=1, . . . , n) under normal operation conditions of the combustion boiler system (10); and comparing the measured bed temperatures (T.sub.Mi) with the computed bed temperatures (T.sub.Ci) for at least some of the measurement points (P.sub.i, i=1, . . . , n), and, if an anomaly threshold is exceeded, determining that local temperature anomaly is present.

36. A method of determining a local temperature anomaly in a fluidized bed of a combustion boiler system that comprises a furnace having a boiler grid that is equipped with at least three temperature sensors that together define a measurement grid where each temperature sensor represents a measurement point (P.sub.i, i=1, . . . , n), the method comprising: estimating a risk of fluidized bed combustion boiler bed sintering; measuring current operation data of the boiler, namely, the measured bed temperature (T.sub.Mi; i=1, . . . , N), at each measurement point (P.sub.i, i=1, . . . , n); computing, based on the current operation data of the boiler: (i) an average of the measured bed temperatures; (ii) a standard deviation of measured bed temperature; (iii) a difference between measured bed maximum temperature and measured bed minimum temperature; and (iv) a spread (x.sub.spread, i=x.sub.ix.sub.xi) for the measured bed temperatures; and using the computation results from (i), (ii), (iii) and (iv) to prepare a bed sintering index.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0071] In the following, the methods and the combustion boiler are explained in more detail with reference to the exemplary embodiments shown in the appended drawings in FIG. 1 to 8B, of which:

[0072] FIG. 1 illustrates a CFB boiler system;

[0073] FIG. 2 illustrates a BFB boiler system;

[0074] FIG. 3 illustrates a boiler grid and measurement arrangement therein;

[0075] FIG. 4 illustrates the sintering risk calculation method;

[0076] FIG. 5 illustrates the residual calculation method;

[0077] FIG. 6 illustrates the method of delayed calibration;

[0078] FIG. 7 illustrates the results obtained with the residual calculation method; and

[0079] FIG. 8A and FIG. 8B illustrate the results of risk calculation method utilized on real operation data of a combustion boiler system, for the situation of FIG. 7.

[0080] The same reference numerals refer to same technical features in all figures.

DETAILED DESCRIPTION

[0081] FIG. 1 shows a combustion boiler system 10 that is a CFB boiler and comprises a furnace 12 that has tube walls 13 (typically, comprising a front wall 132, rear wall 134, side walls 131, 133) connected to water-steam circuit of the combustion boiler system 10. Water may be fed from water tank to an 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. A flue gas channel may be provided with economizer and/or superheater/s and/or reheaters.

[0082] Fluidization gas (such as, air and/or oxygen-containing gas) is fed from fluidization gas supply 153 to below the grid 250 via primary fluidization gas feed 151, usually such that the primary fluidization air enters the furnace through nozzles at the grid 250 (to fluidize the fuel and bed material), and secondary fluidization gas feed 152 (to feed oxygen containing gas such as air to control combustion). The effect is that the bed materials will be fluidized and also oxygen-containing gas required for the combustion is provided into the furnace 12.

[0083] Further, fuel is fed into the furnace 12 via the fuel feed 22.

[0084] The combustion can be adjusted by controlling the fuel feed 22 (such as, by reducing or increasing fuel feed 22), and by controlling the fluidization gas feed (such as, by reducing or increasing amount of oxygen or oxygen-containing gas, preferably combustion air, 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.sub.3 and/or clay, for example. In addition or alternatively, 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.

[0085] Bed material introduced into the furnace 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.

[0086] Bottom 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) whereas, part of the ash, so-called fly ash, is carried with flue gas.

[0087] Combustion products, such as flue gas, unburnt fuel, and bed material proceed from the furnace 12 to a particle separator 14 that may comprise a vortex finder 103. The particle separator 14 separates flue gases from solids. Especially, in larger combustion boilers 10, there may be more than one (two, three, . . . ) separators 14, preferably arranged in parallel to each other.

[0088] Solids separated by the separator 14 pass through a loop seal 120 that preferably is located at the bottom of the separator 14. Then the solids pass to fluidized bed heat exchanger (FBHE) 100 that is also a heat transfer surface (such as, but not limited, comprising tubes and/or heat transfer panels) so that the FBHE 100 collects heat from the solids to further heat the steam in the water-steam circuit.

[0089] The FBHE 100 may be fluidized and comprise heat transfer tubes or other kinds of heat transfer surfaces and be arranged as a reheater or as a superheater. From the FBHE outlet 105, 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). The FBHE inlet 104 preferably comes from the economizer (when the FBHE 100 is a superheater) or from the high-pressure turbine (when the FBHE 100 is reheater).

[0090] The solids may exit the FBHE 100 via return channel 102 into furnace 12. Especially, in larger combustion boilers 10, there may be more than one (two, three, . . . ) loop seals 120 and FBHE 100, and return channel 102, preferably, arranged in parallel to each other, such that, for each separator 14, there will be respective loop seal 120, FBHE 100, and return channel 102. In practice, some of the FBHE 100 may be arranged as superheaters while some others may be arranged as reheaters.

[0091] The flue gases are passed from the separator 14 to crossover duct 15 and, from there, further to back pass 16 (that preferably may be a vertical pass) and from there via flue gas duct 18 to stack 19.

[0092] The back pass 16 comprises a number of heat transfer surfaces 21i (where i=1, 2, 3, . . . , k, where k is the number of heat transfer surfaces). In FIG. 1, of the heat transfer surfaces, heat transfer surfaces 21.sub.1, 21.sub.2, 21.sub.3, 21.sub.4, . . . , 21.sub.k are illustrated. Heat transfer surface 21.sub.k depicts an air preheater. Other heat transfer surfaces 21.sub.1 to 21.sub.k-1 may include an economizer, superheaters, and reheaters. The actual number of different heat transfer surfaces in each of these components, for example, 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.

[0093] A combustion boiler system 10 is equipped with a plurality of sensors and computer units. Actually, one middle-size (100 to 150 MWth) combustion boiler system 10 may produce one hundred million measurement results/day, which needs 25 GB of storage space. FIGS. 1 and 2 illustrate some of the sensors and computer units. Examples of sensors are a temperature sensor measuring the output steam temperature at the outlet 105 of the FBHE 100, a pressure sensor measuring pressure at the FBHE 100 chamber, a temperature sensor measuring the flue gas exit temperature at the separator 14, the temperature sensor measuring the temperature in the loop seal 120, and the pressure sensor measuring the pressure in the loop seal.

[0094] Process data may be collected from the sensors by distributed control system (DCS) 301. The data collection may most conveniently be arranged over a field bus 378, for example. DCS 301 may have a display/monitor 302 for displaying operational status information to the operator. An EDGE server 303 may process measurement data from the obtained from sensors, such as, a filter and smooth the data. There may be a local storage 304 for storing data.

[0095] The DCS 301, display/monitor 302, EDGE server 303, local storage 304 may be in combustion boiler network 370 (local storage 304 preferably directly connected to the EDGE server 303). The combustion boiler network 370 is preferably separate from the field bus 380 that is used to communicate measurement results from the sensors to the DCS 301 and/or the EDGE server 303. Between the DCS 301 and EDGE server 303 there may be an open platform communications server to make the systems better interoperable.

[0096] Combustion boiler network 370 may be in connection with the internet 300, preferably, via a gateway 308. In this situation, measurement results may be transferred from the combustion boiler network 370 to a cloud service, such as to process intelligence system 305 located in a computation cloud 306. 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. Further, instead of a cloud computing service, or in addition thereto, a local or a remote server can be used for running the analysis platform.

[0097] FIG. 2 illustrates a combustion boiler system 10 that is a BFB boiler. The BFB boiler differs from the CFB boiler in that the fluidized bed is not a circulating bed, but a bubbling bed. Thus, there is no need for the separator 14, loop seal 120, FBHE 100, and return channel 102.

[0098] There is normally at least one superheater 14 located in the furnace 12, preferably, on top of the furnace 12. Superheater 14 inlet 143 is preferably from steam drum 200 or from another superheater, and the outlet 144 is to a high pressure turbine.

[0099] In the method of determining a local temperature anomaly in a fluidized bed of a combustion boiler system 10 that comprises a furnace 12 having a boiler grid 250 that is equipped with at least three temperature sensors 20.sub.i that preferably are located above the grid 250, the temperature sensors 20.sub.i together defining a measurement grid where each temperature sensor 20.sub.i represents a measurement point P.sub.i, i=1, . . . , n: bed temperatures T.sub.Mi, i=1, . . . , N are measured at the measurement points P.sub.i, i=1, . . . , N; bed temperatures for the measurement points P.sub.i, i=1, . . . , n are computed using at least one numerical bed temperature model, to obtain computed bed temperatures T.sub.Ci; i=1, . . . , n under normal operation conditions of the combustion boiler system 10; and the measured bed temperatures T.sub.Mi are compared with the computed bed temperatures T.sub.Ci for at least some of the measurement points P.sub.i, i=1, . . . , n, and if an anomaly threshold is exceeded (for example DT=T.sub.MiT.sub.Ci is computed for all i, and if DT>DT.sub.limit), determining that local temperature anomaly is present.

[0100] The computed bed temperatures T.sub.Ci; i=1, . . . , N for the measurement points P.sub.i, i=1, . . . N are preferably obtained in the following way: [0101] a numerical model f between boiler operation data, namely at least primary air flow x1, fuel moisture x2, main steam flow x3, flue gas oxygen x4 and bed pressure x5 and the measured bed temperatures T.sub.Mi; i=1, . . . , N at each measurement point (P.sub.i, i=1, . . . , N, is prepared and calibrated, i.e. f(x1, x2, c3, x4, x5)=T.sub.mi; [0102] current operation data of the boiler, including the measured bed temperature T.sub.Mi; i=1, . . . , N at each measurement point P.sub.i, i=1, . . . , N and at least primary air flow x1, fuel moisture x2, main steam flow x3, flue gas oxygen x4 and bed pressure x5, is monitored; [0103] for at least one measurement point P.sub.j, j is some 1, . . . , n, the numerical model is used to compute a computed temperature T.sub.Cj, using current operation data and measured bed temperatures of at least two other measurement points; and comparing the computed bed temperature T.sub.Ci and the measured bed temperature T.sub.Mi against an anomaly criterion and determining that local temperature anomaly is present if the anomaly criteria is fulfilled.

[0104] The calibration may be performed in a delayed manner using historical data that is preferably at least M days old, where M is at least three, preferably, M is at least seven, more preferably, M is at least fourteen.

[0105] The calibration may not be performed for a predefined time upon detecting a local temperature anomaly. In particular, the calibration may not be performed for a predefined time upon detecting a local temperature anomaly that fulfills a given threshold.

[0106] In the method of calibrating a numerical model of a fluidized bed of a combustion boiler system 10 which comprises a furnace 12 having a boiler grid 250 that is equipped with at least three temperature sensors 20.sub.i that together define a measurement grid where each temperature sensor represents a measurement point P.sub.i, i=1, . . . , N, and, wherein the combustion boiler system 10 has been configured to produce measured bed temperatures T.sub.Mi at each of the measurement points P.sub.i, i=1, . . . , N; [0107] current operation data of the boiler, including the measured bed temperature T.sub.Mi; i=1, . . . , N at each measurement point P.sub.i, i=1, . . . , n and at least primary air flow x1, fuel moisture x2, main steam flow x3, flue gas oxygen x4 and bed pressure x5, is monitored and collected to historical data; and [0108] a numerical model f between boiler operation data, namely at least primary air flow x1, fuel moisture x2, main steam flow x3, flue gas oxygen x4 and bed pressure x5 and the measured bed temperatures T.sub.Mi; i=1, . . . , N at each measurement point P.sub.i, i=1, . . . , n is fitted using at least one numerical fitting method, preferably a numerical regression method, advantageously least squares fitting.

[0109] FIG. 3 shows an example where the boiler grid 250 comprises eight temperature sensors 20 (thus, N=5). Basically, any number (though at least three) of temperature sensors 20 can be used.

[0110] The calibration is preferably repeated at predefined intervals, such as, periodically.

[0111] The calibration may be prevented upon detecting a local temperature anomaly.

[0112] In the method of estimating bed sintering risk of fluidized bed combustion boiler system (10) that comprises furnace (12) having a boiler grid (250) that is equipped with at least three temperature sensors (20.sub.i) that together define a measurement grid where each temperature sensor represents a measurement point P.sub.i, i=1, . . . , n. [0113] current operation data of the boiler, namely the measured bed temperature T.sub.Mi; i=1, . . . , N, is measured at each measurement point P.sub.i, i=1, . . . , n; [0114] based on the current operation data of the boiler, [0115] (i) an average of the measured bed temperatures is computed; [0116] (ii) standard deviation of measured bed temperature is computed; [0117] (iii) a difference between measured bed maximum temperature and measured bed minimum temperature is computed; and [0118] (iv) spread x.sub.spread, i=x.sub.ix.sub.xi, is computed for the measured bed temperatures; and [0119] using the computation results from (i), (ii), (iii) and, (iv) to prepare a bed sintering index.

[0120] According to an embodiment of the invention, in computation of spread i=1:N, where N is the total number of bed temperature measurements, xi is an individual bed temperature measurement, and x.sub.xi is the average of all bed temperature measurements other than xi.

[0121] Preferably, in the method, also (v) computed bed temperatures T.sub.Ci; I=1, . . . , n for same measurement points are computed, and residuals between the measured bed temperatures T.sub.Mi; i=1, . . . , n and the computed bed temperatures are computed. The results from step v) are advantageously also used in the preparing of the bed sintering index.

[0122] In the method of controlling a fluidized bed boiler system 10, local bed temperature anomalies and/or a bed sintering index is/are monitored; and, upon detecting a local bed temperature anomaly and/or bed sintering index exceeding a predefined criterion, automatically adjusting combustion boiler system 10 operation and/or indicating the boiler operator that a local bed temperature anomaly and/or a bed sintering condition is detected.

[0123] The automatic adjustment of boiler operation may include at least one of the following: (a) increasing or decreasing primary and/or secondary air feed 151, 152, (b) increasing or decreasing fuel feed 20, (c) increasing or decreasing bed material feed and/or bed material removal and/or (d) adjusting (preferably increasing) recirculation gas flow and/or (e) restricting the boiler load temporarily.

[0124] The automatic adjustment or so-called remedial actions may include at least one of the following: change fuel mix, trigger air pulse through primary air nozzles, and introducing feed additives such as clay which may be hydrous clay (e.g. kaolin), or increasing the amount of feed additives.

[0125] The local bed temperature anomalies and/or the monitoring sintering index is/are preferably monitored using a numerical model. Preferably, delayed calibration of the numerical model is used to reduce or to avoid the effect of recent bed conditions in the calibration data.

[0126] The combustion boiler system 10 is configured to carry out the method according to any one of the preceding claims.

[0127] FIG. 4 illustrates the possible use of the method in a fluidized bed combustion system 10, more particularly, in DCS 301 and/or EDGE server 303, or in process intelligence system 305.

[0128] As data inputs (step J1), fuel moisture is provided to the method. This can be measured from the fuel or result from flue gas analysis, or entered manually.

[0129] In step J3, bed temperature is modelled.

[0130] In step J5, bed diagnostics is performed. As the result, residuals DT=T.sub.CT.sub.M are obtained.

[0131] FIG. 5 illustrates possible inputs to the bed diagnostics step J5. As possible inputs, primary air flow, secondary air flow, flue gas oxygen, flue gas H.sub.2O, bed pressure are provided. They may be measured during the operation of the combustion boiler, preferably by the DCS 301 or EDGE server 303.

[0132] The remedial actions can be taken automatically (preferably by the DCS 301, EDGE server 303 or process intelligence system 305), or the boiler operator may take the actions manually.

[0133] FIG. 6 illustrates the principle of delayed calibration.

[0134] The present inventors analyzed real boiler operation data that was collected during operation of a combustion boiler system 10 until the shutdown of the combustion boiler system 10 because of bed sintering. The present inventors are able to demonstrate (cf. FIG. 7) that, with their method, local bed temperature anomalies can be detected and that local bed temperature anomalies tend to act as precursors for bed sintering. With these methods, local bed temperature anomalies and, also, sintering conditions can be observed early enough within an action window that is suitably long and sufficiently much in advance before the actual problem. In the example of FIG. 7, the action window was about 45 to 25 h before the combustion boiler system 10 had to be shut down because of a bed sintering problem.

[0135] FIGS. 8A and 8B show the respective temperature sensor measurement data of temperature sensors 20.sub.1 to 20.sub.8 that resulted in the curve shown in FIG. 7. Thus, at least eight temperature sensors 20 are sufficiently many to reliably detect a sintering problem early enough to enable a long enough action window for combustion boiler system 10 automatic control or manual control by the boiler operator, to prevent the shut down of the combustion boiler system 10.

[0136] It is obvious to the skilled person that, along with the technical progress, the basic idea of the invention can be implemented in many ways. The invention and its embodiments are thus not limited to the examples and samples described above but they may vary within the contents of patent claims and their legal equivalents.

[0137] In the claims that follow and, in the preceding description of the invention, except where the context requires otherwise due to express language or necessary implication, the word comprise or variations such as comprises or comprising is used in an inclusive sense, i.e., to specify the presence of the stated feature but not to preclude the presence or addition of further features in various embodiments of the invention.