METHOD FOR DETERMINING TUBE LEAKAGE IN A WATER-STEAM CIRCUIT OF A COMBUSTION BOILER SYSTEM, AND COMBUSTION BOILER

Abstract

Objective To improve tube leakage detection in the water-steam circuit of a combustion boiler. In order to improve tube leak detection, a tube leak determination method is used in the water-steam circuit of a combustion boiler system (10), the method comprising: determining the main steam flow rate (Q MS,M ) of the main steam (Q MS,C ) flow rate in the water-steam circuit during operation by utilizing process data in a numerical model of the combustion boiler system (10). MS,C ), comparing the measured water-steam flow rate and the modeled water-steam flow rate to obtain an error measure for the main steam flow rate (ΔMS) included in an error measure set, and monitoring the error measure set and characteristics of the error measure set that exceed a predetermined threshold during a predetermined time period during operation to determine the presence of a water-steam circuit tube leak.

Description

[Technical Field]

[0001] The present invention relates to the detection and assessment of tube leaks in the steam circuits of fired boilers, and in particular to fluidized bed boilers such as circulating fluidized bed (CFB) boilers or bubbling fluidized bed (BFB) boilers. [Background technology]

[0002] Combustion boilers, such as grate boilers and fluidized bed boilers, are commonly used to generate steam that can be used for a variety of purposes, such as to generate electricity and heat.

[0003] In a fluidized bed boiler, a high-temperature bed of fuel and solid particle fluidizing material is introduced into a furnace, and the fluidizing material and fuel are fluidized by introducing a fluidizing gas from the bottom of the furnace. The combustion of the fuel takes place in the fluidized bed. In BFB combustion, the fluidizing gas passes through the bed to form bubbles in the bed. In BFB combustion, the fluidized bed can be controlled rather conveniently by controlling the fluidizing gas supply and the fuel supply.

[0004] In CFB combustion, the fluidizing gas passes through a bed of fluidized bed material. Most of the fluidized particles become entrained in the fluidizing gas and are carried away with the flue gas. The particles are separated from the flue gas in at least one particle separator and circulated back into the furnace. A fluidized bed heat exchanger is often located downstream of the particle separator to recover heat from the particles before they are returned to the furnace.

[0005] A boiler tube leak allows water or steam to escape from the steam circuit, typically at pressures in the range of 100-300 bar, which can then enter the boiler location in an uncontrolled manner. In the worst case scenario, a tube leak can cause the need for extensive boiler repairs. The majority of tube leak situations do not have very serious consequences, at least if the leak is detected reasonably early.

[0006] A boiler tube leak typically requires the shutdown of the combustion boiler, locating the leak, and repairing or replacing the leaking tube. From the standpoint of the combustion boiler operator, this can be an expensive procedure. Not only because of the expense incurred in locating the leak and then repairing or replacing the tube, but also because shutting down the combustion boiler stops the production of steam (which could be used to generate electricity or heat), generally resulting in a loss of income for the boiler operator during the shutdown. In view of the resulting costs and loss of steam production capacity, it is important to avoid unnecessary shutdowns. Leak detection should be performed with a high degree of reliability.

[0007] Applicant's CFB leak detection system was disclosed in Modern Power Systems' (www.modernpowersystems.com) December 2018 article, "Boiler Technology - SmartBoiler™: how the Internet of Things can improve boiler operating performance." The boiler leak detection module closely monitors furnace walls and other boiler heat exchange surfaces and predicts future problems based on regression models and self-learning algorithms using real-world process data. As a result, maintenance can be planned in advance, minimizing downtime. Summary of the Invention [Problem to be solved by the invention]

[0008] The objective is to improve tube leak detection in the water-steam circuits of combustion boilers.

[0009] This object can be achieved by a method according to independent claim 1 and a combustion boiler system according to parallel claim 13.

[0010] The dependent claims describe advantageous aspects of the method. [Means for solving the problem]

[0011] A method for determining a tube leak in a water-steam circuit of a combustion boiler system comprises: The main steam flow Q prevailing in the water-steam circuit of a combustion boiler system during operation MS,M and measuring Main steam Q of a combustion boiler system under conditions of virtually no tube leakage MS,C By utilizing process data in a numerical model of a combustion boiler system that provides the flow rate, the main steam flow rate Q in the water-steam circuit during operation can be calculated. MS,C and modeling the comparing the measured water-steam flow rate and the modeled water-steam flow rate to obtain an error measure ΔMS for the main steam flow rate included in an error measure set; monitoring the set of error measures and characteristics of the set of error measures for exceeding a predetermined threshold during a predetermined time period during operation to determine the presence of a water-steam circuit tube leak; Equipped with.

[0012] The method allows for improved tube leak detection in the water-steam circuits of combustion boilers. Even though there may be large variations in the main steam flow rate between successive measurements, with an appropriate numerical model of the combustion boiler system, the main steam flow rate can be calculated numerically under conditions where there is substantially no tube leakage, rapidly enough that the error measure ΔMS indicates with sufficient probability the presence of a tube leak.

[0013] Furthermore, with the characteristic monitors properly arranged, it is possible to select a predetermined threshold value such that i) a sufficiently large error measure ΔMS (e.g., exceeding a predetermined threshold value) will result in a determination of a water-steam circuit leak sooner than a smaller error measure ΔMS, and ii) a smaller error measure ΔMS will also result in a determination of a water-steam circuit leak if persisted for a predetermined time (or number of measurements). The selection of this characteristic monitor, and more particularly the selected "boosting factor" technique developed by the inventors and used in monitoring the error measure set and characteristics of the error measure set, contributes significantly to the functionality of the method.

[0014] The "boosting factor" approach reflects the inventor's observation that tube leaks in the water-steam circuit of a combustion boiler system can develop gradually, i.e., start as small leaks. A small leak, if unnoticed, can become a large leak within some time. Reliably detecting small leaks has not previously been possible without the use of specific markers in the water-steam circuit in terms of large fluctuations or differences in main steam measurements. Thus, tube leaks have traditionally tended to be reliably detected only after the leak has become sufficiently severe. However, this tends to increase the effort required to repair the combustion boiler system. The present invention can improve tube leak detection reliability, thereby enabling faster tube leak detection while helping to avoid false alarms (which can lead to unnecessary shutdowns and costly unused time for the combustion boiler system).

[0015] The main steam flow is preferably measured in the water-steam circuit between the final superheater and the turbine.

[0016] The error measure ΔMS for the main steam flow is the sum of the measured steam flow (Q MS,MESURED ) and the calculated steam flow rate (Q MS,COMPUTED ) and the difference (ΔMS=Q MS,MESURED -Q MS,COMPUTED ) is preferred.

[0017] Alternatively, the error measure ΔMS for the main steam flow is the sum of the measured steam flow (Q MS,MESURED ) and the calculated steam flow rate (Q MS,COMPUTED ) may be a ratio.

[0018] These aspects are such that the error measure ΔMS for the main steam flow is: The measured steam flow rate (Q MS,MESURED ) and the calculated steam flow rate (Q MS,COMPUTED ) and the difference (ΔMS=Q MS,MESURED -Q MS,COMPUTED ) and / or The measured steam flow rate (Q MS,MESURED ) and the calculated steam flow rate (Q MS,COMPUTED ) may be combined.

[0019] The method is: measuring at least one process parameter across at least one location of the fireside of the combustion boiler system; modeling at least one of the corresponding process parameters during operation of the combustion boiler system by utilizing the process data in a numerical model that provides the corresponding process parameter of the combustion boiler system under substantially leak-free conditions; comparing the at least one measured process parameter and the corresponding at least one modeled process parameter to each other to obtain an error measure for at least one process parameter that is also included in the error measure set; Further provided are:

[0020] Using this approach, fireside measurements can be arranged to improve the accuracy of the method and / or to also include detection of components of a fired boiler system where tube leaks are present. Most conveniently, the process parameters comprise or consist of at least one of temperature and / or pressure.

[0021] The error measure for the at least one process fireside parameter may be the difference between the measured process parameter and the modeled process parameter.

[0022] Alternatively, the error measure for the at least one process fireside parameter may be a ratio between the measured process parameter and the modeled process parameter.

[0023] These may be combined, so that the error measure for at least one process hearth parameter may be the difference between the measured and modeled process parameters and / or the ratio of the measured and modeled process parameters.

[0024] According to one embodiment of the present invention, the characteristics of the error measure set may comprise a number of occurrences exceeding a predetermined threshold during a predetermined time period while driving.

[0025] The feedwater flow rate is preferably measured before the economizer.

[0026] Although the preferred embodiment of the present invention is a circulating fluidized bed (CFB) boiler system, the present invention can be implemented in other types of combustion boiler systems as well, in particular in bubbling fluidized bed (BFB) boiler systems.

[0027] In the case of a CFB boiler system, the process parameter measured at at least one location at the furnace end preferably includes or consists of the pressure in a return section arranged to return separated particles into the furnace, or in other words, a loop seal arranged downstream of the particle separator in the return channel.

[0028] In this situation, the method preferably comprises monitoring the number of occurrences of an error measure for the main steam flow rate exceeding a predetermined threshold, the number of occurrences of the exceedance being included in the characteristic of the error measure, and the method further comprises monitoring the number of occurrences of an error measure for the pressure at the loop seal exceeding a predetermined threshold, the number of occurrences of the exceedance being included in the characteristic of the error measure. A water-steam circuit leak may then be determined to be in the loop seal if i) the error measure for the main steam flow rate and the number of occurrences of the error measure for the main steam flow rate exceed a predetermined threshold, and further ii) the number of occurrences of the error measure for the pressure at the loop seal and the loop seal parameter for the pressure at the loop seal exceed a predetermined threshold.

[0029] In the case of a CFB boiler system, the process parameter measured at at least one location on the fireside preferably comprises or consists of the flue gas temperature at the outlet of the particle separator.

[0030] In this situation, it is preferable that a leak is determined to be in the particle separator when i) both the error measure for the main steam flow rate and the number of occurrences of the error measure for the main steam flow rate exceed predetermined thresholds for the corresponding error measures, and further, ii) both the error measure for the flue gas temperature at the outlet of the particle separator and the number of occurrences of the flue gas temperature at the outlet of the particle separator exceed predetermined thresholds for the flue gas temperature error measure, respectively.

[0031] In the case of a CFB boiler system, the process parameters measured at at least one location in the fire end preferably include or consist of bed temperatures in a fluidized bed heat exchanger comprising reheater tubes (the reheater is located after the water-steam circuit) and / or superheater tubes. Since the outputs of both of these components are actually connected to turbines (intermediate pressure turbine for the reheater and high pressure turbine for the superheater) that are located after the water-steam circuit of the CFB boiler system, it has been particularly difficult to detect water-steam circuit tube leaks in both components based on monitoring the water-steam circuit.

[0032] In this context, the process parameter preferably comprises or consists of the bed temperature in a fluidized bed heat exchanger comprising the superheater tubes.

[0033] Furthermore, since the reheater is located after the water-steam circuit, a tube leak is preferably determined in the fluidized bed heat exchanger when both the error measure of the bed temperature of the fluidized bed heat exchanger and the number of occurrences of the error measure each exceed a predetermined threshold, preferably without requiring the error measure for the main steam flow rate to exceed a respective threshold.

[0034] Common to all aspects and embodiments of the method is that the characteristic of the error measure may include or consist of the respective number of occurrences that exceed a predetermined threshold.

[0035] The combustion boiler includes a local control system and / or is connected to a remote control system configured to implement the tube leak determination method, and the combustion boiler system further includes an indication means, such as a display / monitor, for indicating to boiler operators the presence of a tube leak detected using the method.

[0036] The method and the fired boiler system will now be described in more detail with reference to exemplary embodiments disclosed in the accompanying drawings. [Brief explanation of the drawings]

[0037] [Figure 1] FIG. 1 is a diagram showing a CFB boiler system. [Figure 2] FIG. 1 is a diagram showing a BFB boiler system. [Figure 3] FIG. 1 illustrates a calibration method for a numerical model in a CFB boiler system. [Figure 4] FIG. 1 illustrates the training of mathematical models and the possibility of using data. [Figure 5]FIG. 1 illustrates pipe leak risk calculations. [Figure 6A] FIG. 1 shows selected data from a test in which the method was applied to real CFB boiler system data to verify the function of the method. [Figure 6B] FIG. 1 shows selected data from a test in which the method was applied to real CFB boiler system data to verify the function of the method. [Figure 6C] FIG. 1 shows selected data from a test in which the method was applied to real CFB boiler system data to verify the function of the method. [Figure 6D] FIG. 1 shows selected data from a test in which the method was applied to real CFB boiler system data to verify the function of the method. [Figure 6E] FIG. 1 shows selected data from a test in which the method was applied to real CFB boiler system data to verify the function of the method. [Figure 6F] FIG. 1 shows selected data from a test in which the method was applied to real CFB boiler system data to verify the function of the method. [Figure 6G] FIG. 1 shows selected data from a test in which the method was applied to real CFB boiler system data to verify the function of the method. [Figure 6H] FIG. 1 shows selected data from a test in which the method was applied to real CFB boiler system data to verify the function of the method. [Figure 6I] FIG. 1 shows selected data from a test in which the method was applied to real CFB boiler system data to verify the function of the method. DETAILED DESCRIPTION OF THE INVENTION

[0038] In all figures, the same reference numbers refer to the same technical features.

[0039] Figure 1 shows a combustion boiler system 10, which is a CFB boiler and includes a furnace 12 with tube walls 13 (typically having a front wall, a back wall, and side walls) connected to the water-steam circuit of the combustion boiler system 10. Figure 1 shows the case of an OTU boiler in which water is delivered from a water tank 50 to an evaporator (furnace wall) and then conducted to a turbine (not shown) via a superheater. An economizer and / or superheater may be provided in the flue gas channel.

[0040] Fluidizing gas (such as air and / or oxygen-containing gas) is delivered below the grate from fluidizing gas supply 153 (the grate is not shown in FIG. 1). This fluidizing gas is typically delivered via primary fluidizing gas feed 151 (to fluidize the fluidizing medium and fuel), with primary fluidizing air entering the furnace through nozzles at grate 250, and via secondary fluidizing gas feed 152 (to deliver an oxygen-containing gas, such as air, to control combustion). The effect is to fluidize the fluidizing medium and also to provide oxygen necessary for combustion into furnace 12. Additionally, fuel is delivered into furnace 12 via fuel feed 22.

[0041] Combustion can be adjusted by controlling the fuel feed 22 (e.g., decreasing or increasing the fuel feed) and the fluidizing gas feed (e.g., decreasing or increasing the supply of oxygen-containing gas (such as combustion air) to the furnace 12). The fuel can be fed with additives, particularly additives that act as alkaline sorbents, such as CaCO and / or clay. Additionally or alternatively, a NOx reducing agent, such as ammonium or urea, can be fed into or above the combustion zone of the furnace 12.

[0042] A fluidizing medium is also fed into the furnace, which may comprise sand, limestone, and / or clay, and may particularly comprise kaolin. One effect of fluidization, and combustion in general, is that in the water-steam circuit, water and steam are heated at the tube walls 13, converting the water to steam. Bottom ash falls to the bottom of the furnace 12 and can be removed via an ash chute (omitted from FIG. 1 for clarity). A portion of the ash, called fly ash, will be carried along with the flue gases.

[0043] Combustion products such as flue gases, unburned fuel, and fluidized medium pass from the furnace 12 to a particle separator 17, which may comprise a vortex finder 103. The particle separator 17 separates the flue gases from the solids. In particularly large combustion boilers 10, there may be more than one (two, three, ...) separators 17, preferably arranged in parallel.

[0044] The solids separated by separator 17 pass through a loop seal 200, which is preferably located at the bottom of separator 17. The solids then pass to a fluidized bed heat exchanger (FBHE) 100, which is also a heat transfer surface (e.g., comprising, but not limited to, 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.

[0045] The FBHE 100 may be fluidized, may include heat transfer tubes or other types of heat transfer surfaces, and may be arranged as a reheater or superheater. Steam passes from the FBHE exhaust 101 to the high-pressure turbine (if the FBHE 100 is a superheater) or to the intermediate-pressure turbine (if the FBHE 100 is a reheater).

[0046] The solids can exit the FBHE 100 and enter the furnace 12 via the return channel 102. In particularly large combustion boilers 10, there may be more than one (two, three, ...) loop seals 160, FBHEs 100, and return channels 102, preferably arranged in parallel. Thus, for each separator 17, there will be a respective loop seal 160, FBHE 100, and return channel 102. In fact, some of the FBHEs 100 may be arranged as superheaters, while others may be arranged as reheaters.

[0047] From the separator 17 the flue gas passes to a crossover duct 15 and from there to a back passage 16 (which may preferably be a vertical passage) and from there via a flue gas duct 18 to a chimney 19 .

[0048] The rear passage 16 comprises several heat transfer surfaces 21i (where i=1, 2, 3, ..., k, where k is the number of heat transfer surfaces). In FIG. 1, the heat transfer surfaces 211, 212, 213, 214, 215, 216, 217, 218, 219, 220, 221, 222, 223, 224, 225, 226, 227, 228, 229, 230, 231, 232, 233, 234, 235, 236, 237, 238, 239, 240, 241, 242, 243, 244, 245, 246, 247, 248, 249, 250, 251 k is shown. Heat transfer surface 21 k indicates an air preheater. Other heat transfer surfaces include the economizer, superheater, and reheater in the flue gas channel (rear path 16). For example, the actual number of different heat transfer surfaces in each of these components may be selected differently for each combustion boiler according to actual needs. There may also be additional components with heat transfer surfaces 21.

[0049] The combustion boiler system 10 includes multiple sensors and a computer unit. In fact, one medium-sized (100-150 MWth) combustion boiler system 10 may generate 100 million measurements per day, requiring 25 GB of storage space. Figures 1 and 2 show some of the sensors and computer units. Examples of sensors include a main steam flow sensor 260 measuring the output steam temperature at the FBHE 100 exhaust outlet 101, a temperature sensor 280 measuring the bed temperature in the FBHE 100 chamber, a temperature sensor 270 measuring the flue gas outlet temperature in the separator 17, a temperature sensor 290 measuring the temperature in the loop seal 200, and / or a pressure sensor 291 measuring the pressure in the loop seal 200. The FBHE may also be equipped with a pressure sensor to measure the pressure in the FBHE chamber. Specifically, the FBHE 100 is the final superheater from which steam is introduced to the turbine via the FBHE exhaust outlet 101.

[0050] Process data can be collected from sensors by a distributed control system (DCS) 301. Data collection may be most conveniently located via, for example, fieldbus 370. The DCS 301 may have a display / monitor 302 for displaying operational status information to operators. An EDGE server 303 can process the measurement data from the sensor acquisitions, for example, by filtering and smoothing. There may be local storage 304 for saving the data.

[0051] The DCS 301, display / monitor 302, EDGE server 303, and local storage 304 may be within a combustion boiler network 380 (with local storage 304 preferably connected directly to the EDGE server 303). The combustion boiler network 380 is preferably separate from the fieldbus 370 used to communicate measurements from sensors to the DCS 301 and / or EDGE server 303. To make the systems more interoperable, there may be an open platform communication server between the DCS 301 and the EDGE server 303.

[0052] The combustion boiler network 380 may be connected to the Internet 306, preferably via a gateway 305. In this situation, measurement results can be transmitted from the combustion boiler network 380 to a cloud service, such as a process intelligence system 308 located in a computation cloud 207. The applicant currently operates a cloud service that runs the analytics platform. The cloud service may be operated, for example, on a virtual server environment such as Microsoft® Azure®, which is a virtualized and 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, instead of or in addition to a cloud computing service, a local or remote server can be used to run the analytics platform.

[0053] Figure 2 shows a fired boiler system 10 that is a BFB boiler. A BFB boiler differs from a CFB boiler in that the fluidized bed is a bubbling bed rather than a circulating bed. Therefore, there is no need for a separator 17, loop seal 160, FBHE 100, or return channel 102.

[0054] In a drum boiler, water is generally delivered to an economizer and from the economizer through a steam drum to an evaporative heat transfer surface such as the furnace wall of the boiler, from which it may be directed through the steam drum to a superheater and then to a turbine.

[0055] Typically, there is at least one superheater 14 within the furnace 12, preferably located at the top of the furnace 12. The inlet 143 of the superheater 14 may come from a steam drum, and the outlet 144 leads to the high-pressure turbine. A temperature sensor 240 measures the temperature at the superheater outlet 144. Specifically, a main steam flow sensor 240 measures the main steam flow at the outlet 144 of the last superheater from which the steam is directed to the turbine.

[0056] A method for determining a tube leak in a water-steam circuit of a combustion boiler system 10 comprises: The main steam flow Q prevailing in the water-steam circuit of the combustion boiler system 10 during operation MS,M and measuring Main steam Q of combustion boiler system 10 under conditions of substantially no tube leakage MS,C By utilizing process data in a numerical model of the combustion boiler system 10 that provides the flow rate, the main steam flow rate Q in the water-steam circuit during operation is calculated. MS,C and modeling the Error measure Δ for main steam flow included in the error measure set MS comparing the measured water-steam flow rate and the modeled water-steam flow rate to each other to obtain monitoring the set of error measures and characteristics of the set of error measures for exceeding a predetermined threshold during a predetermined time period during operation to determine the presence of a water-steam circuit tube leak; Equipped with.

[0057] The method is: measuring at least one process parameter across at least one location of the fireside of the combustion boiler system; modeling at least one of the corresponding process parameters during operation of the combustion boiler system 10 by utilizing the process data in a numerical model that provides the corresponding process parameter of the combustion boiler system 10 under substantially leak-free conditions; comparing the at least one measured process parameter and the corresponding at least one modeled process parameter to each other to obtain an error measure for at least one process parameter that is also included in the error measure set; may further comprise:

[0058] The process parameters may comprise or consist of at least one of temperature and / or pressure.

[0059] Loop seal 290: The process parameter may include or consist of a pressure at a loop seal 290 located downstream of the particle separator 17 in a return section configured to return separated particles into the furnace 12. The method then preferably includes monitoring the number of occurrences of an error measure for the main steam flow rate exceeding a predetermined threshold, the number of occurrences being included in the error measure characteristic. The method further includes monitoring the number of occurrences of an error measure for the pressure at the loop seal exceeding a predetermined threshold, the number of occurrences being included in the error measure characteristic. A water-steam circuit leak is determined to be in the loop seal if the error measure for the main steam flow rate and the number of occurrences of the error measure for the main steam flow rate exceed a predetermined threshold, and further if the number of occurrences of the error measure for the pressure at the loop seal and the loop seal parameter for the pressure at the loop seal exceed a predetermined threshold.

[0060] Separator 17: The process parameter may include or consist of the flue gas temperature at the outlet of the particle separator. A leak is then preferably determined to be in the particle separator when both the error measure for the main steam flow rate and the number of occurrences of the error measure for the main steam flow rate exceed predetermined thresholds for the corresponding error measures, and further when both the error measure for the flue gas temperature at the outlet of the particle separator and the number of occurrences of the flue gas temperature at the outlet of the particle separator exceed predetermined thresholds for the flue gas temperature error measure, respectively.

[0061] FBHE100 (Reheater): The process parameters may include or consist of the bed temperature in a fluidized bed heat exchanger with reheater tubes, the reheater being located after the water-steam circuit.

[0062] FBHE 100 (Superheater): The process parameters may include or consist of the bed temperature in the FBHE 100 with the superheater tubes.

[0063] Superheater 14: The process parameters may include or consist of the bed temperature in the superheater 14 of the BFB boiler system, which is a fluidized bed heat exchanger with superheater tubes.

[0064] A tube leak can be determined in a fluidized bed heat exchanger 100 with a reheater when both the error measure of the bed temperature and the number of occurrences of the error measure exceed predetermined thresholds, preferably without requiring the error measure for the main steam flow rate to exceed the respective thresholds, since the reheater is located after the water-steam circuit.

[0065] Common to all embodiments is that the characteristic of the error measure may include or consist of the respective number of occurrences that exceed a predetermined threshold.

[0066] Common to all embodiments is that the exceedance is tested within an evaluation time window, which may be a suitably chosen time interval such as the last 60 minutes.

[0067] As described above, the combustion boiler system 10 includes local control systems 301, 303 and / or is connected to a remote control system 308. The control systems are configured to implement the leak determination method. The combustion boiler system 10 includes an indication means, such as a display / monitor 302, for indicating to boiler operators the presence of a tube leak detected using the method.

[0068] 3 shows an example of a model building or calibration process. After start-up (step A1), in step A3 a numerical model for the water / steam balance in the combustion boiler system 10 is built, for example by means of a regression model. The model may differ depending on the type of combustion boiler system 10, for example:

[0069] Equation for Water / Steam Balance, Drum Boiler: Q ms,c =a0+a1Q fw +a2Dt(Q fw )+a3Q cbd +a4Q sbd +a5Dt(DL) In the above equation, Q ms,c is the modeled main steam flow rate, Q fw is the feedwater flow rate, which can be measured before the economizer, Dt(Q fw ) is Dt (feedwater flow rate), which is the time derivative of the feedwater flow rate (how much the feedwater flow rate changes in a specific time), Q cbd is the constant blowdown flow rate from the steam and is the water discharged from the drum, Q sbd is the soot blowing steam flow rate, which may be steam from the superheater flow path before the final superheater; Dt(DL) is Dt(drum level), which is the time derivative of the drum level (how much the drum level changes in a specific time), a0, a1... a5 are calibration coefficients determined by linear regression.

[0070] Alternatively, the modeled main steam flow may be obtained using artificial intelligence tools and / or neural networks.

[0071] Equation for water / steam balance, OTU boiler: Q ms,c =a0+a1Q fw +a2DT(Q fw )+a3P fw +a4Dt(P fw ) In the above equation, Q ms,c is the modeled main steam flow rate, Q fw is the feedwater flow rate, Dt(Q fw ) is Dt (feedwater flow rate), P fw is the water supply pressure, Dt(P fw ) is Dt (water supply pressure), a0, a1, ..., a4 are calibration coefficients determined by linear regression.

[0072] Alternatively, the modeled main steam flow may be obtained using artificial intelligence tools and / or neural networks.

[0073] In process A5, each FBHE100 i For example, by using a regression model, i A numerical model is constructed for the temperature calculation of

[0074] FBHE i Equations for bed temperature calculation T i,j,c =b0+b1T w,i +b2T se,i +b3Qms,m +b4Dt(Q ms,m ) In the above equation, T i,j FBHE100 i is the modeled bed temperature, (The number of temperature points is N, so j=1,…,N) T w,i Loop Seal 200 i is the temperature, T se,i Separator 17 i is the flue gas outlet temperature, Q ms,m is the main steam flow rate, Dt(Q ms,m ) is Dt (main steam flow rate), b0, b1...b4 are coefficients determined by linear regression.

[0075] Alternatively, the modeled bed temperature may be obtained using artificial intelligence tools and / or neural networks.

[0076] In step A7, each separator 17 i For example, by a regression model, i A numerical model is constructed for the temperature calculation of

[0077] separator i Equations for Temperature Calculation T separator exit,i,c =c0+c1T inlet,i +c2T msei In the above equation, T separator exit,i,c is the modeled separator 17 i is the flue gas outlet temperature, T msei (Separator i That is, all other separators 17 except j≠i j (calculated for other separators 17) j is the average of T separator inlet,i Separator 17 i is the inlet temperature, c0, c1...c2 are coefficients determined by linear regression.

[0078] Alternatively, the modeled separator flue gas outlet temperature may be obtained using artificial intelligence tools and / or neural networks.

[0079] In step A9, each loop seal 200 i For example, by using a regression model, i A numerical model for the pressure at is constructed.

[0080] Loop Seal 200 i Equation for pressure calculation: P ws,i =d0+d1P mwsi In the above equation, P wsi The modeled loop seal i It is pressure, P mwsi (Loop Seal 200 i That is, all other loop seals 200 except j≠i j is the average of the other loop seal pressures (calculated for d0 and d1 are factors determined by linear regression.

[0081] Alternatively, the modeled laminar loop seal pressure may be obtained using artificial intelligence tools and / or neural networks.

[0082] Figure 4 shows the operation of the leak detection system, with diagnostics (A) and training (B) separate.

[0083] In diagnostic block (A), a leak diagnostic method J1 is preferably executed at predetermined intervals, such as every minute, or periodically.

[0084] The training block (B) has at least two sets of training data. The training data set K1 comprises process data for X2 days from X1 days ago. The training data set K3 comprises process data for X2 days from X1 days ago. However, the start and / or end times of the training data sets K1, K3 are different (the difference is shown as X3 days). The training data sets K1, K3 may be partially overlapping or may be separated so as not to overlap.

[0085] Model training for dataset K1 (see FIG. 3) can be invoked in step K5 at predetermined intervals, such as every X1 days, or periodically. Similarly, model training for dataset K3 (see FIG. 3) can be invoked in step K7 after a predetermined interval (X3 days have passed).

[0086] The purpose of this practice is that if there is a tube leak in the water-steam circuit of the combustion boiler system 10, the tube leak will corrupt the calibration data. This is believed to improve the reliability of the detection algorithm, as some tube leaks develop slowly.

[0087] Example of how to use the model: Model outputs are modeled values ​​compared to expected values, such as:

[0088] Water / Steam Balance: ΔMS=Q' ms -Q ms Q' ms is the modeled main steam flow rate, Q ms is the measured main steam flow rate, ΔMS<ΔMS under normal process conditions limit and ΔMS limit is a process / model / boiler dependent value.

[0089] separator 17 i(where i=1, 2, ... N, and N is the number of separators 17 in the combustion boiler system 10) i is the number of ): Δse i =T' se,i -T se,i T' se,i is the modeled separator 17 i is the flue gas outlet temperature, T se,i is the measured separator 17 i is the flue gas outlet temperature, Under normal process conditions of the separator, Δse i <Δse limit and Δse limit is a process / model / boiler dependent value.

[0090] FBHE100: ΔT i1…n =T' i1…n -T i1…n T' i1…n FBHE100 i are the modeled bed temperatures 1...n, T i1…n FBHE100 i are the measured bed temperatures 1...n, Under normal process conditions of FBHE, ΔT i1…n <ΔT limit and ΔT limit is a process / model / boiler dependent value.

[0091] Loop Seal 200 i (where i=1, 2, ... N, and N is the loop seal 200 in the combustion boiler system 10) i is the number of ): Δp i =p' ws,i -p ws,i p' ws,i Modeled after Loopseal 200 i It is pressure, p ws,iis measured by LoopSeal 200 i It is pressure, Under normal process conditions of the separator, Δp i <Δp limit and Δp limit is a process / model / boiler dependent value.

[0092] Superheater 14: ΔT sh =T' SH -T SH T' SH is the modeled temperature of the superheater 14, T SH is the measured temperature of the superheater 14, Under normal process conditions in the superheater 14, ΔT SH <ΔT SH,limit and ΔT SH,limit is a process / model / boiler dependent value.

[0093] FIG. 5 shows the leak diagnosis step (J1 in FIG. 4), and more specifically the calculation of the pipe leak risk.

[0094] In step J13, the difference is calculated.

[0095] First, in a CFB boiler system, ΔMS and, optionally, Δse i and / or ΔT i1…n and / or Δp i (and ΔMS and optionally ΔT for BFB boiler systems, respectively) sh , and similarly) can be calculated over a predetermined time interval, such as the last 60 minutes.

[0096] In the next step J15, the difference is compared with the respective warning limits. The warning limits are set as constants for each model, and when the difference is below the respective warning limit, the process is in a normal state. The diagnosis then calculates the warning limit exceeded in step J17. iIn the case of multiple models such as i1…n If the component exceeds the respective process / model / boiler dependent value, such as when >x, the component is set as abnormal.

[0097] The pipe leak risk level can be calculated using the equation (internal value): n e *BF>t u If so, R=100+(n e *BF-t u ) / t r *100 Otherwise, Rc=(n e *BF-t l ) / (t u -t l )*100 In the above equation, Rc is the leakage risk level of the component (location) or water / steam balance, n e is the excess in the reference period, t r is the length of the reference period (minutes), t l is a lower bound, t u is an upper bound, BF is the boost factor.

[0098] BF = 1 + (E s / (WL*N)-1)*B In the above equation, BF is the boosting factor, B is the boosting gradient, WL is the warning limit for errors, N is the excess number, E s is sum(error) when error > warning limit.

[0099] The leakage index can be calculated using the equation: R c <100 then I c =Rc , R c >100 then I c =100 In the above equation, I c is the component leakage index (location) or water / steam balance index, R c is the leakage risk level component (location) or water / steam balance.

[0100] A leak index greater than or equal to 50 but less than 100 is a "yellow" warning for the location or water / steam balance. A leak index greater than 100 is a "red" warning for the location or water / steam balance.

[0101] Total Breach Indicators: I cm If <50, I=R ws / 2 I cm If ≧50, I=R ws / 2+I cm / 2 In the above equation, I is the total leakage index, R ws is the water / steam balance leakage risk level, I cm is the maximum component leakage index.

[0102] The inventors have validated the functionality of the method on archived real data collected from a CFB-fired boiler system. The data is disclosed in Figures 6A through 6I and shows in one exemplary manner (as can be seen simulating what is displayed on the DCS 301, the EDGE system, and the display / monitor 302 to the boiler operator, possibly with the participation of a remote process intelligence system 308) how the method can be used to indicate to a boiler operator the presence of a tube leak in the water-steam circuit of the fired boiler system.

[0103] Figure 6A shows the calculated total leakage index I for the test period, calculated as described above. As can be seen, the index reaches 100 in the right-most time period column. A boiler leak is present. In the actual situation in which the process data was collected, the boiler was shut down.

[0104] FIG. 6B shows the calculated water / steam balance difference, or ΔMS, for the same fired boiler system 10 process data. Somewhat larger fluctuations are visible, with a significant increase in the right-most time period column. FIG. 6C shows the leakage index, I, calculated for the water / steam balance only. MS This shows:

[0105] FIG. 6D shows the calculated difference, i.e., ΔT 3 1-n The difference increases somewhat slowly. Figure 6E shows the leakage index I FBHE 3 , i.e., the leakage index calculated only for component FBHE1003.

[0106] FIG. 6F shows the calculated difference, Δse3, for the separator 173 of the same combustion boiler system 10 process data. SE,3 , i.e., the leakage index calculated for component separator 173 only.

[0107] FIG. 6H shows the calculated difference, Δws3, for the loop seal 2003 of the same combustion boiler system 10 process data. WS,3 , i.e., the leakage index calculated for component loop seal 2003 only.

[0108] With the total leak indicator I, the presence of a tube leak in the water-steam circuit of the combustion boiler system 10 can be detected reliably, and in some cases earlier than in previous implementations of the applicant's combustion boiler system.

[0109] Component-specific leakage indicators are preferably calculated for all leak-prone components of the combustion boiler system 10 (in this example, for each FBHE 100) i , each separator 17 i , 200 each loop seal i By means of the leak indicator for , the location of the component where the pipe leak is present can be reliably detected.

[0110] In other words, in the leak detection method according to the first aspect of the present invention, the risk level is calculated using a time series of measures between model-based quantities estimated for the actual bed conditions using the determined fluidized bed combustion boiler operating parameters and respective quantities calculated from the measurements, so that the measures each contribute disproportionately to the risk level relative to their magnitude. The risk level can be indicated to the boiler operator. If the risk level exceeds a preset limit, the exceedance is indicated to the boiler operator, the boiler operator is alerted, and / or a boiler shutdown is automatically proposed or initiated.

[0111] In a leak detection method according to a second aspect of the present invention, a risk level is calculated using time series measures between model-based quantities estimated for actual bed conditions using the determined fluidized bed combustion boiler operating parameters and respective quantities calculated from measurements, where the measures are evaluated in at least two overlapping time windows of different lengths, where a narrower time window requires a proportionally greater number of measures exceeding thresholds than a wider time window. The risk level can be indicated to boiler operators. If the risk level exceeds a preset limit, the exceedance is indicated to the boiler operators, who are alerted and / or a boiler shutdown is automatically proposed or initiated.

[0112] In a leak detection method according to a third aspect of the present invention, a risk level is calculated using a time series of measurements between model-based quantities estimated for actual bed conditions using the determined fluidized bed combustion boiler operating parameters and respective quantities calculated from measurements, and the model-based quantities are then estimated using calibrated values, where the calibrated values ​​are obtained by analyzing historical data as training data from further back in time than the time series used in calculating the risk level. The risk level can be indicated to a boiler operator. If the risk level exceeds a preset limit, the exceedance is indicated to the boiler operator, the boiler operator is alerted, and / or a boiler shutdown is automatically proposed or initiated.

[0113] The model-based quantities estimated for the actual bed conditions using the determined fluidized bed combustion boiler operating parameters and the respective quantities calculated from the measured values ​​preferably include one or more of the water-steam balance, flue gas outlet temperature, bed temperature, and pressure, and thus the water-steam balance is advantageously used.

[0114] The risk level is preferably calculated as a weighted sum of any different measures, optionally requiring that for each measure, the exceedance of a specific threshold for that measure be included in the calculation. The risk level may further be calculated such that it is only displayed as 100% when the risk level exceeds 100%.

[0115] The differences between the model-based quantities and the respective quantities calculated from measurements can be rather large. These are due to the fact that the combustion conditions are under continuous change and there are certain fluctuations that occur in a fired boiler all the time. For a fired boiler that produces superheated steam at a rate of 400 kg / s, in reality the steam flow rate can fluctuate up and down by 5-10 kg / s.

[0116] The discovery behind the first aspect of the present invention is that given moderately large fluctuations in the model-based quantities and the respective quantities calculated from measurements, there is a high probability that smaller measures will be very frequent in the time series analysis, while larger measures are less likely to be present multiple times in the time series analysis without justification. Thus, if several threshold-crossing measures in a time window are disproportionately large relative to their magnitudes, occupying a risk level proportional to the sum of the measure magnitudes, a larger tube leak in a combustion boiler can be detected much faster than in the background art (Modern Power Systems, December 2018 article). As an example, we refer to the results of the Modern Power Systems article, Ill. 6, p. 38. Applicant's previous method was able to detect a leak in the furnace wall approximately 30 minutes (second arrow from the left) after the onset of the leak (first arrow from the left). Using this method, the inventors were able to reliably detect the same leak based on the same data in approximately 2-4 minutes.

[0117] The discovery behind the second aspect of the present invention is that, given moderately large fluctuations in the model-based quantities and the respective quantities calculated from measurements, there is a high probability that smaller measures will be very frequent in the time series analysis, while it is less certain that smaller measures will be present for longer periods of time without justification. Thus, if measures are evaluated in at least two overlapping time windows of different lengths, such that a narrower time window requires a proportionally greater number of small measures exceeding a threshold than a wider time window, smaller tube leaks in a combustion boiler can be detected significantly more reliably than in the background art (Modern Power Systems, December 2018 article). Using this method, the inventors were able to more frequently rule out suspected tube leaks as not leaks, even in situations where the background art method would have resulted in false leak alerts.

[0118] The discovery behind the third aspect is that relatively large fluctuations in the model-based quantities and the respective quantities calculated from measurements may have some time-shift characteristics in time-series analysis. When there is a time shift, calculation of estimated values ​​using a numerical model gives inaccurate results that may no longer be reliable. In this situation, since the model-based quantities are estimated using a mathematical model calibrated with coefficient values ​​obtained using numerical fitting, the effect of the time-shift characteristics can be suppressed or even eliminated if the calibrated values ​​are obtained by analyzing historical data from further back in time than the time series used in calculating the risk level when the numerical fitting is repeated on the training data. The historical data should preferably be from at least several days ago, and even better, from one or even two weeks ago. This method can detect slowly developing pipe leaks more reliably than the method described in the Background Art (Modern Power Systems, December 2018 article).

[0119] In a fourth aspect of the present invention, a risk level is calculated using a time series of measurements between model-based quantities estimated for actual bed conditions using the determined fluidized bed combustion boiler operating parameters and respective quantities calculated from measurements, including at least one, but preferably all, of at least one separator, at least one solids return chamber heat exchanger, and at least one loop seal. The risk level can be indicated to boiler operators. If the risk level exceeds a preset limit, the exceedance is indicated to the boiler operators, who are alerted and / or a boiler shutdown is automatically proposed or initiated.

[0120] The discovery behind the fourth aspect is that in a fluidized bed boiler, a tube leak can cause an effect generally equivalent to sandblasting, in which an abrasive fluidizing medium is pressed against boiler structures, such as other tubes, by high-pressure steam or water. Thus, CFB boiler leak detection performed on at least one separator, at least one solids return chamber heat exchanger, and / or at least one loop seal can help reduce damage to those parts of the boiler.

[0121] While a tube leak does not necessarily have very negative consequences within the furnace if the furnace wall water tube leaks, the situation is significantly different in certain CFB boiler structures (separators, solids return chamber heat exchangers, loop seals) where heat exchanger tubes are relatively close to each other. For example, in a solids return chamber heat exchanger, adjacent heat exchanger tubes may be separated by only 10 cm. A tube leak in such a component, which also has a high bed media density, can rapidly worsen the leak due to the increased abrasive effect of the bed media caused by the leak. For example, in the lower parts of a CFB furnace, bed media densities may be in the range of several tens of kg / m3, while in a solids return chamber heat exchanger, bed media densities may be in the range of 1000–1500 kg / m3. Furthermore, leaks in the furnace tube walls generally do not damage adjacent tubes because they are not in the direction of the bed media blast caused by the leak.

[0122] It is obvious to those skilled in the art that with technological advances, the basic idea of ​​the present invention can be implemented in many ways. Therefore, the present invention and its embodiments are not limited to the examples and samples described above, but may vary within the content of the claims and their legal equivalents.

[0123] In the claims that follow, and in the preceding description of the invention, except in contexts which dictate otherwise due to linguistic expression or necessary implication, the terms "comprise" or variations such as "comprises" or "comprising" are used in an inclusive sense, i.e., to specify the presence of stated features in various embodiments of the invention, but do not preclude the presence or addition of further features. [Explanation of symbols]

[0124] 10 Combustion boiler 12 Furnace 13 Pipe wall 14 Superheater 15 Crossover duct 16 Posterior Pathway 17 Particle separator 18 Flue gas duct 19 Chimney 280 Temperature Sensor (FBHE) 21i Heat transfer surface (i=1, 2, …k) 22 Fuel supply section 50 Water Tank 100 Fluidized Bed Heat Exchanger (FBHE) 101 FBHE exhaust port 102 Return Channel 103 Vortex Finder 131 Pipe wall entrance 132 Pipe wall exhaust port 141 FBHE Entrance 142 FBHE exhaust port 143 Superheater inlet 144 Superheater exhaust port 151 Primary flow gas supply section 152 Secondary flow gas supply section 153 Fluidizing gas supply unit 200 Loop Stickers 240 Temperature sensor (superheater) 250 grid 260 Temperature Sensor (FBHE) 270 Temperature sensor (separator) 280 Pressure Sensor (FBHE) 290 Temperature sensor (loop seal) 291 Pressure sensor (loop seal) 301 Distributed Control System (DCS) 302 Display / Monitor 303 EDGE Server 304 Local Storage 305 Gateway 306 Internet 308 Process Intelligence System 307 Computation Cloud 370 Fieldbus 380 Combustion Boiler Network

Claims

1. A method for determining a tube leak in a water-steam circuit of a combustion boiler system (10), comprising: The main steam flow rate (Q) prevailing in the water-steam circuit of the combustion boiler system (10) during operation ＭＳ，Ｍ ) measuring the The main steam (Q) of the combustion boiler system (10) under substantially no tube leakage conditions ＭＳ，Ｃ In the numerical model of the combustion boiler system (10), which gives a flow rate of the main steam, the main steam flow rate (Q ＭＳ，Ｃ ) modeling the The error measure (Δ ＭＳ comparing the measured water-steam flow rate and the modeled water-steam flow rate to obtain a monitoring said set of error measures and the number of occurrences in said set of error measures during operation; During a given time period, the error measure (Δ ＭＳ determining the presence of a water-steam circuit tube leak if the error measure set exceeds a predetermined threshold or if the number of occurrences in said error measure set exceeds a predetermined threshold; A method comprising:

2. measuring at least one process parameter across at least one location of the fireside of the combustion boiler system (10); modeling at least one of the corresponding process parameters during operation of the combustion boiler system (10) by utilizing process data in a numerical model that provides the corresponding process parameter of the combustion boiler system (10) under substantially leak-free conditions; comparing the at least one measured process parameter and the corresponding at least one modeled process parameter to each other to obtain an error measure for the at least one process parameter that is also included in the set of error measures; The method of claim 1 further comprising:

3. The method of claim 2 , wherein the process parameters comprise or consist of at least one of temperature and / or pressure.

4. 4. The method according to any one of claims 1 to 3, wherein the combustion boiler system (10) is a circulating fluidized bed boiler system.

5. 5. The method of claim 4 in combination with claim 2 or 3, wherein the process parameters comprise or consist of a pressure at a loop seal (290) located downstream of the particle separator (17) in a return section (102) arranged to return the separated particles into the furnace (12).

6. the method comprising monitoring a number of occurrences of an error measure for main steam flow exceeding a predetermined threshold, the number of occurrences exceeding being included in the characteristic of the error measure; The method further comprises detecting a pressure (P ｗ，ｄ monitoring the number of occurrences of an error measure for the error measure, an excess of said occurrences being included in said characteristic of the error measure; Water-steam circuit leaks if the error measure for main steam flow and the number of occurrences of error measure for main steam flow exceed the predetermined threshold; and If the error measure relating to the pressure at the loop seal (200) and the number of occurrences of the pressure at the loop seal (200) parameter at the loop seal exceed the predetermined threshold, The method of claim 5, wherein the loop seal (200) is determined to be in the loop seal.

7. The process parameter is the flue gas temperature (T ｓｅ，ｉ ) or the flue gas temperature (T ｓｅ，ｉ 10. The method of claim 4 in combination with claim 2 or 3, or alternatively claim 6, comprising:

8. The leak, if both the error measure for main steam flow and the number of occurrences of error measure for main steam flow exceed the predetermined threshold for the corresponding error measure, respectively; and when both an error measure related to the flue gas temperature at the outlet of the particle separator and the number of occurrences of the flue gas temperature at the outlet of the particle separator each exceed a predetermined threshold value for the flue gas temperature error measure; The method of claim 7 , wherein the particle separator is determined to be in the particle separator.

9. 9. The method of claim 4 in combination with claim 2 or 3, or alternatively any one of claims 6, 7, or 8, wherein the process parameter comprises or consists of a bed temperature in a fluidized bed heat exchanger comprising a reheater tube, the reheater being located after the water-steam circuit.

10. 10. The method of claim 4 in combination with claim 2 or 3, or alternatively any one of claims 6, 7, 8, 9, wherein the process parameters comprise or consist of a bed temperature in a fluidized bed heat exchanger comprising superheater tubes.

11. Pipe leaks, and when both the error measure of the bed temperature of the fluidized bed heat exchanger and the number of occurrences of the error measure exceed predetermined thresholds, respectively. The method of claim 10 determined in the fluidized bed heat exchanger.

12. 12. The method of claim 1, wherein the characteristic of the error measure comprises or consists of the number of occurrences each exceeding a predetermined threshold.

13. A combustion boiler system (10) comprising a control system (301, 303, 308) configured to implement the method according to any one of claims 1 to 12.

14. 14. The combustion boiler system (10) of claim 13, comprising an indication means, such as a display / monitor (302), for indicating to boiler operators the presence of a tube leak detected using the method.

Images