Method for determining tube leakage in the steam circuit of a combustion boiler system and combustion boiler

Abstract

In the steam circuit of a combustion boiler system (10), a tube leak detection method is used to improve tube leak detection, and the method is, - A step of measuring the main steam flow (QMS,M) prevalent in the steam circuit of the combustion boiler system (10) during operation; - A step of modeling the main steam flow (QMS,C) in the steam circuit during operation by using process data in a numerical model of a combustion boiler system (10) that provides the main steam (QMS,C) flow of the combustion boiler system (10) under conditions where there is practically no tube leakage; - A step of comparing the measured steam flow and the modeled steam flow with each other to obtain an error measurement (ΔMS) for the main steam flow included in the error measurement set; and - Includes a step of determining the presence of a vapor circuit tube leak by monitoring the characteristics of an error measurement set and an error measurement set that exceed a predetermined threshold during a predetermined time period while in operation.

Description

Technology Field

[0001] The present invention relates to the detection and evaluation of tube leakage in the water steam circuit of a combustion boiler, particularly a fluidized bed boiler such as a circulating fluidized bed (CFB) boiler or a bubble fluidized bed (BFB) boiler. Background Technology

[0002] Combustion boilers, such as grate boilers and fluidized bed boilers, are generally used to generate steam that can be used for various purposes, such as electricity and heat production.

[0003] In a fluidized bed boiler, a high-temperature bed of fuel and solid particulate bed material is introduced into the furnace, and a fluidizing gas is introduced from the bottom of the furnace to fluidize the bed material and fuel. Combustion of the fuel occurs in the fluidized bed. In BFB combustion, the fluidizing gas passes through the bed and forms bubbles in the bed. In BFB, the fluidized bed can be conveniently controlled by controlling the supply of fluidizing gas and fuel.

[0004] In CFB combustion, fluidized gas passes through the bed material. Most bed particles are carried along with the fluidized gas and flue gas. The particles are separated from the flue gas at at least one particle separator, circulated, and returned to the furnace. It is common practice to arrange a fluidized bed heat exchanger downstream of the particle separator(s) to recover heat from the particles before they are returned to the furnace.

[0005] Boiler tube leaks cause water or steam to escape from the steam circuit; since the pressure typically ranges from 100 to 300 bar, the escaped water or steam can flow into specific locations within the boiler in an uncontrolled manner. In the worst-case scenario, a tube leak can necessitate comprehensive boiler repairs. Most tube leak situations result in much less serious consequences, at least if the leak is detected reasonably quickly.

[0006] Boiler tube leaks typically require shutting down the combustion boiler, locating the leak, and repairing or replacing the leaking tube. From the perspective of a combustion boiler operator, this can be a costly procedure. In addition to the cost of repairing or replacing the tube after locating the leak, shutting down the combustion boiler stops the production of steam (which can be used to generate electricity or heating), meaning the operator typically loses a source of income during the shutdown. Considering the resulting costs and the loss of steam production capacity, it is important to avoid unnecessary shutdowns. Leak detection must be performed reliably.

[0007] The applicant's CFB leak detection system is disclosed in the December 2018 article "Boiler Technology - SmartBoiler™: how the Internet of Things can improve boiler operating performance" by Modern Power Systems (www.modernpowersystems.com). The boiler leak detection module closely monitors the furnace wall and other boiler heat exchange surfaces and predicts future problems based on actual process data and regression models using self-learning algorithms, allowing maintenance to be planned in advance and restoration time to be minimized. The problem to be solved

[0008] The purpose is to improve tube leak detection in the steam circuit of a combustion boiler. means of solving the problem

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

[0010] Dependent terms describe advantageous modes of the method.

[0011] A method for determining tube leakage in the steam circuit of a combustion boiler system is

[0012] - Main steam flow Q prevalent in the steam circuit of the combustion boiler system during operation MS,M Step of measuring;

[0013] - 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 providing flow, the main steam flow Q of the steam circuit during operation MS,C Step of modeling;

[0014] - A step of comparing the measured steam flow and the modeled steam flow with each other to obtain an error measurement ΔMS for the main steam flow included in the error measurement set; and

[0015] - Includes a step of determining the presence of a vapor circuit tube leak by monitoring the characteristics of an error measurement set and an error measurement set that exceeds a predetermined threshold during a predetermined time period while in operation.

[0016] Using this method, it will be possible to improve tube leak detection in the steam circuit of a combustion boiler. By using an appropriate numerical model of the combustion boiler system, the main steam flow can be numerically and quickly calculated under conditions where there is virtually no tube leak, even if the main steam flow may have large fluctuations between continuous measurements, so that the error measurement ΔMS will indicate the presence of a tube leak with sufficient probability.

[0017] In addition, by properly preparing the characteristic monitoring, it is possible to select a predetermined threshold such that i) an error measurement ΔMS that is sufficiently large (e.g., exceeding a predefined threshold) determines the steam circuit tube leak faster than a smaller error measurement ΔMS; and ii) also determine the steam circuit tube leak when the smaller error measurement ΔMS persists for a predefined time (or number of measurements). This selection of characteristic monitoring developed by the inventors, particularly the selected "boosting factor" approach used for monitoring the set of error measurements and the characteristics of the set of error measurements, contributes significantly to the functionality of the method.

[0018] The "boosting factor" approach reflects the inventors' observation that tube leaks in the steam circuit of a combustion boiler system can occur gradually, that is, they can start as small leaks. If not careful, a small leak can soon become a large leak. Due to large fluctuations or changes in main steam measurements, it has been impossible to reliably detect small leaks in the steam circuit without using specific markers. Therefore, there has been a tendency to reliably detect tube leaks only after the leak has become sufficiently severe, which, however, tends to increase the effort required to repair the combustion boiler system. According to the present invention, the reliability of tube leak detection can be improved, which helps avoid false alarms (leading to unnecessary shutdowns and costly downtime of the combustion boiler system) while still enabling rapid detection of tube leaks.

[0019] The main steam flow is preferably measured in the steam circuit between the final superheater and the turbine.

[0020] The error measurement ΔMS for the main steam flow is preferably the measured steam flow (Q MS, MEASURED ) and calculated steam flow (Q MS, COMPUTED The difference between (ΔMS = QMS, MEASURED - Q MS, COMPUTED )am.

[0021] Alternatively, the error measurement ΔMS for the main steam flow is the measured steam flow (Q MS, MEASURED ) and calculated steam flow (Q MS, COMPUTED It can be a ratio between ).

[0022] These embodiments can be combined so that the error measurement ΔMS for the main steam flow can be as follows:

[0023] - Measured steam flow (Q MS, MEASURED ) and calculated steam flow (Q MS, COMPUTED The difference between (ΔMS = Q MS, MEASURED - Q MS, COMPUTED );

[0024] and / or

[0025] - Measured steam flow (Q MS, MEASURED ) and calculated steam flow (Q MS, COMPUTED The ratio between ).

[0026] This method may further include the following steps:

[0027] - A step of measuring at least one dominant process parameter at at least one fireside location of the combustion boiler system;

[0028] - A step of modeling at least one of the corresponding process parameters during the operation of a combustion boiler system by using process data of a numerical model that provides the corresponding process parameters of the combustion boiler system under conditions where there is practically no leakage;

[0029] - A step of comparing the at least one measured process parameter with the corresponding at least one modeled process parameter and also obtaining an error measurement for at least one process parameter included in the error measurement set.

[0030] Using this approach, fireside measurements are utilized to improve the accuracy of the method and / or may also include the detection of combustion boiler system components where tube leaks are present. Most conveniently, the process parameters include or consist of at least one of temperature and / or pressure.

[0031] The error measurement for at least one process roadside parameter may be the difference between the measured process parameter and the modeled process parameter.

[0032] Alternatively, an error measurement for at least one process roadside parameter may be the ratio between the measured process parameter and the modeled process parameter.

[0033] These can be combined such that the error measurement for at least one process roadside parameter is the difference between the measured process parameter and the modeled process parameter and / or the ratio between the measured process parameter and the modeled process parameter.

[0034] According to an embodiment of the present invention, the characteristics of an error measurement set may include the number of occurrences exceeding a predetermined threshold during a predetermined time period while in operation.

[0035] Preferably, the water supply flow rate is measured before the economizer.

[0036] A preferred embodiment of the present invention is a circulating fluidized bed (CFB) boiler system, but the present invention can also be realized in other types of combustion boiler systems, particularly in bubble fluidized bed (BFB) boiler systems.

[0037] In the case of a CFB boiler system, process parameters measured at at least one location on the furnace side preferably include or consist of the pressure of a loop seal arranged downstream of the particle separator of the return leg, i.e., the return leg is arranged to return the separated particles into the furnace.

[0038] In this situation, preferably, the method includes the step of monitoring whether the number of occurrences of error measurements for the main steam flow exceeds a predetermined threshold, the number of excess occurrences being included in the characteristics of the error measurements, and the method further includes the step of monitoring whether the number of occurrences of error measurements for the pressure of the loop seal exceeds a predetermined threshold, the number of excess occurrences being included in the characteristics of the error measurements. i) if the number of occurrences of error measurements for the main steam flow and error measurements for the main steam flow exceeds a predetermined threshold, and additionally ii) if the number of occurrences of error measurements related to the pressure of the loop seal and the pressure of the loop seal parameters exceeds a predetermined threshold, a steam circuit leak may be determined to be present in the loop seal.

[0039] In the case of a CFB boiler system, process parameters measured at at least one location along the furnace preferably include or consist of the flue gas temperature at the outlet of the particle separator.

[0040] In this situation, preferably, if i) both the error measurement for the main steam flow and the number of occurrences of the error measurement for the main steam flow each exceed a predetermined threshold for the corresponding error measurement, and additionally ii) both the error measurement 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 for the flue gas temperature error measurement, it is determined that there is a leak in the particle separator.

[0041] In the case of a CFB boiler system, process parameters measured at at least one location along the fireside preferably include or consist of the bed temperature of a fluidized bed heat exchanger comprising reheater tubes (where the reheater is located after the steam circuit) and / or superheater tubes. Since the outputs of both components actually lead to turbines located after the steam circuit of the CFB boiler system (medium-pressure turbines in the case of reheaters, and high-pressure turbines in the case of superheaters), it has been particularly difficult to detect steam circuit tube leaks in both of these components based on monitoring of the steam circuit.

[0042] In this situation, preferably, the process parameter includes or is composed of the bed temperature of a fluidized bed heat exchanger including superheater tubes.

[0043] Additionally, preferably, tube leakage in a fluidized bed heat exchanger is determined when both the error measurement of the bed temperature of the fluidized bed heat exchanger and the number of occurrences of the error measurement each exceed a predetermined threshold value, and

[0044] Preferably, since the reheater is located after the steam circuit, it is not required that the error measurement for the main steam flow exceed each threshold.

[0045] A common feature of all aspects and embodiments of the method is that the characteristics of the error measurement may include or be composed of each occurrence exceeding a predetermined threshold.

[0046] The combustion boiler includes a local control system and / or is connected to a remote control system, and the control system(s) are configured to perform a tube leak determination method. The combustion boiler system further includes display means, such as a display / monitor, for indicating to the boiler operator the presence of a tube leak detected using this method. Brief explanation of the drawing

[0047] Hereinafter, a method and a combustion boiler system will be described in more detail with reference to exemplary embodiments disclosed in the attached drawings. FIG. 1 illustrates a CFB boiler system; FIG. 2 illustrates a BFB boiler system; Figure 3 illustrates a calibration method for a numerical model of a CFB boiler system; Figure 4 illustrates the possibilities for training mathematical models and using data; Figure 5 illustrates the calculation of the risk of tube leakage; Figures 6a through 6i show selected data from a test in which the method was applied to actual CFB boiler system data to verify the function of the method. Identical drawing symbols indicate identical technical features in all drawings. Specific details for implementing the invention

[0048] FIG. 1 illustrates a combustion boiler system (10) comprising a furnace (12) having tube walls (13) (typically including front walls, rear walls, and side walls) connected to the steam circuit of the combustion boiler system (10), which is a CFB boiler. FIG. 1 illustrates an OTU boiler case in which water is supplied from a water tank (50) to an evaporator (wall of the furnace) and then guided through a superheater to a turbine (not shown in the drawing). An economizer and / or superheater may be provided in the flue gas channel.

[0049] Fluidizing gas (e.g., air and / or oxygen-containing gas) is supplied down below the grate (not shown in FIG. 1) through a primary fluidizing gas feed (151) from a fluidizing gas source (153) and a secondary fluidizing gas feed (152) (to supply oxygen-containing gas, such as air, to control combustion), so that primary fluidizing air enters the furnace through a nozzle of the grid (250) (to fluidize the bed material and fuel). The effect is that the bed material is fluidized and the oxygen required for combustion is supplied to the furnace (12). Additionally, fuel is supplied into the furnace (12) through a fuel feed (22).

[0050] Combustion can be controlled by controlling the fuel feed (22) (e.g., by decreasing or increasing the fuel feed) and by controlling the fluidized gas feed (e.g., by decreasing or increasing the amount of oxygen-containing gas (e.g., combustion air) supplied into the furnace (12). The fuel may be supplied with additives, particularly additives that act as alkali adsorbents, such as CaCO3 and / or clay. Additionally or alternatively, a NOx reducing agent, such as ammonium or urea, may be supplied into or over the combustion zone of the furnace (12).

[0051] The layer material is also supplied to the furnace, and the layer material may include sand, limestone and / or clay, and in particular may include kaolin. One effect of the layer and generally combustion is that in the steam circuit, water and steam are heated at the tube wall (13) and the water is converted into steam.

[0052] Bottom ash falls to the bottom of the furnace (12) and can be removed through an ash chute (omitted in Fig. 1 for clarity), and some of the ash, called fly ash, will be carried along with the flue gas.

[0053] Combustion products such as flue gas, unburned fuel, and bed material are passed from the furnace (12) to a particle separator (17) which may include a vortex finder (103). The particle separator (17) separates the flue gas from the solid. In particular, in a large combustion boiler (10), there may preferably be two or more (two, three, ...) separators (17) arranged in parallel with each other.

[0054] The solid separated by the separator (17) passes through a loop seal (200) located at the bottom of the separator (17). Then, the solid is transferred to a fluidized bed heat exchanger (FBHE) (100), which is also a heat transfer surface (e.g., tubes and / or heat transfer panels, but not limited thereto), so that the FBHE (100) collects heat from the solid to further heat the steam in the steam circuit.

[0055] The FBHE (100) can be fluidized and may include heat transfer tubes or other types of heat transfer surfaces and may be arranged as a reheater or a superheater. From the FBHE outlet (101), steam is transferred to a high-pressure turbine (if the FBHE (100) is a superheater) or a medium-pressure turbine (if the FBHE (100) is a reheater).

[0056] Solids can exit from the FBHE (100) to the furnace (12) through the return channel (102). In particular, in a large combustion boiler (10), two or more (two, three, ...) loop seals (160) and FBHEs (100) and return channels (102) are preferably arranged parallel to each other, so that for each separator (17), there will be a respective loop seal (160), FBHE (100), and return channel (102). In practice, some of the FBHEs (100) may be arranged as superheaters and others as reheaters.

[0057] The flue gas is transferred from the separator (17) to the cross duct (15), from there to the reverse path (16) (preferably a vertical path), and from there to the stack (19) via the flue gas duct (18).

[0058] The reverse path (16) includes a plurality of heat transfer surfaces (21i) (where i = 1, 2, 3, ..., k, where k is the number of heat transfer surfaces). In FIG. 1, among the heat transfer surfaces, heat transfer surfaces (211, 212, 213, 214 21 k This is exemplified. Heat transfer surface 21 k describes an air preheater. Other heat transfer surfaces include an economizer, a superheater, and a reheater in the flue gas channel (reverse path (16)). For example, the actual number of different heat transfer surfaces for each of these components may be selected differently for each combustion boiler according to actual needs. There may also be additional components including heat transfer surfaces (21).

[0059] The combustion boiler system (10) is equipped with multiple sensors and computer devices. In fact, one medium-sized (100–150 MWth) combustion boiler system (10) can generate 100 million measurement results per day, and this requires 25 GB of storage space. FIGS. 1 and FIGS. 2 illustrate some of the sensors and computer devices. Examples of sensors include a main steam flow sensor (260) for measuring the discharge steam temperature at the outlet (101) of the FBHE (100), a temperature sensor (280) for measuring the layer temperature in the FBHE (100) chamber, a temperature sensor (270) for measuring the flue gas outlet temperature at the separator (17), a temperature sensor (290) for measuring the temperature of the loop seal (200), and / or a pressure sensor (291) for measuring the pressure of the loop seal (200). The FBHE may be provided with a pressure sensor for measuring the pressure in the FBHE chamber.

[0060] Specifically, the FBHE (100) is a final superheater through which steam flows into the turbine via the FBHE outlet (101).

[0061] Process data can be collected from sensors by a distributed control system (DCS) (301). Data collection can be arranged most conveniently, for example, via a field bus (370). The DCS (301) may have a display / monitor (302) for displaying operating status information to an operator. An EDGE server (303) may perform processing such as filtering and smoothing the measurement data acquired from the sensors. There may be a local storage (304) for storing data.

[0062] The DCS (301), display / monitor (302), EDGE server (303), and local storage (304) may be located within the combustion boiler network (380) (the local storage (304) is preferably directly connected to the EDGE server (303)). The combustion boiler network (380) is preferably separated from the field bus (370) used to communicate measurement results from the sensor to the DCS (301) and / or the EDGE server (303). Between the DCS (301) and the EDGE server (303), there may be an open platform communication server to improve the interoperability of the system.

[0063] The combustion boiler network (380) may preferably be connected to the Internet (306) via a gateway (305). In this situation, measurement results may be transmitted from the combustion boiler network (380) to a cloud service, such as a process intelligence system (308) located in a computing cloud (207). The applicant currently operates a cloud service that runs the analysis platform. The cloud service may be operated in a virtualized server environment, such as Microsoft® Azure®, which is a virtualized and easily scalable environment for distributed computing and cloud storage for data. Other cloud computing services may also be suitable for running the analysis platform. Additionally, local or remote servers may be used instead of, or in addition to, a cloud computing service to run the analysis platform.

[0064] FIG. 2 illustrates a combustion boiler system (10) that is a BFB boiler. A BFB boiler differs from a CFB boiler in that the fluidized bed is a bubble bed rather than a circulation bed. Therefore, a separator (17), a loop seal (160), an FBHE (100), and a return channel (102) are not required.

[0065] In a drum boiler, water is typically supplied to an economizer and then supplied from the economizer to an evaporative heat transfer surface, such as the furnace wall of the boiler, through a steam drum, then guided through a steam drum to a superheater, and then supplied to a turbine.

[0066] Generally, at least one superheater (14) is located within the furnace (12), preferably in the upper part of the furnace (12). The inlet (143) of the superheater (14) may be from a steam drum and the outlet (144) may be to a high-pressure turbine. A temperature sensor (240) measures the temperature of the superheater outlet (144). Specifically, a main steam flow sensor (240) measures the main steam flow at the superheater outlet (144), and the superheater is the final superheater from which steam is guided to the turbine.

[0067] A method for determining tube leakage in the steam circuit of a combustion boiler system (10) is,

[0068] - Main steam flow Q prevalent in the steam circuit of the combustion boiler system (10) during operation MS,M Step of measuring;

[0069] - Main steam Q of the combustion boiler system (10) under conditions where there is practically no tube leakage MS,C By using process data in a numerical model of a combustion boiler system (10) that provides the flow, the main steam flow Q of the steam circuit during operation MS,C Step of modeling;

[0070] - Error measurement Δ for the main steam flow included in the error measurement set MS A step of comparing the measured water vapor flow and the modeled water vapor flow to obtain the above; and

[0071] - Includes a step of determining the presence of a vapor circuit tube leak by monitoring the characteristics of an error measurement set and an error measurement set that exceeds a predetermined threshold during a predetermined time period while in operation.

[0072] This method may further include the following steps:

[0073] - A step of measuring at least one dominant process parameter at at least one location on the fireside of the combustion boiler system (10);

[0074] - A step of modeling at least one of the corresponding process parameters during the operation of the combustion boiler system (10) by using process data of a numerical model that provides the corresponding process parameters of the combustion boiler system (10) under conditions where there is practically no leakage;

[0075] - A step of comparing the at least one measured process parameter with the corresponding at least one modeled process parameter and also obtaining an error measurement for at least one process parameter included in the error measurement set.

[0076] Process parameters may include at least one of temperature and / or pressure, or consist of at least one.

[0077] Loop seal (290): The process parameter may include or be composed of the pressure of the loop seal (290) arranged downstream of the particle separator (17) of the return leg arranged to return the separated particles to the furnace (12). Then, the method preferably includes the step of monitoring whether the number of occurrences of error measurements for the main steam flow exceeds a predetermined threshold. The number of occurrences of the excess is included in the characteristics of the error measurement. The method further includes the step of monitoring whether the number of occurrences of error measurements for the pressure of the loop seal exceeds a predetermined threshold, and the number of occurrences of the excess is included in the characteristics of the error measurement. If the number of occurrences of error measurements for the main steam flow and error measurements for the main steam flow exceeds a predetermined threshold, and additionally, if the number of occurrences of error measurements related to the pressure of the loop seal and the pressure of the loop seal parameter of the loop seal exceeds a predetermined threshold, it is determined that a steam circuit leak is present in the loop seal.

[0078] Separator (17): Process parameters may include or be composed of the flue gas temperature at the outlet of the particle separator. Then, preferably, if both the error measurement for the main steam flow and the number of occurrences of the error measurement for the main steam flow each exceed a predetermined threshold for the corresponding error measurement, and additionally, if both the error measurement 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 for the flue gas temperature error measurement, it is determined that there is a leak in the particle separator.

[0079] FBHE(100) (Reheater): The process parameters may include or be configured with the bed temperature of a fluidized bed heat exchanger containing reheater tubes, and the reheater is located after the steam circuit.

[0080] FBHE(100) (Superheater): Process parameters may include or be configured with the layer temperature of the FBHE (100) including the superheater tube.

[0081] Superheater (14): The process parameter may include or be configured with the bed temperature of the superheater (14) of the BFB boiler system, which is a fluidized bed heat exchanger including superheater tubes.

[0082] Tube leakage can be determined in a fluidized bed heat exchanger (100) including a reheater in the following cases:

[0083] When both the error measurement of the bed temperature of the fluidized bed heat exchanger and the number of occurrences of the error measurement each exceed a predetermined threshold, and preferably when the error measurement for the main steam flow does not need to exceed each threshold because the reheater is located after the steam circuit.

[0084] A common feature of all embodiments is that the characteristics of the error measurement may include or be configured to include each occurrence exceeding a predetermined threshold.

[0085] A common feature across all embodiments is that the excess is tested within an evaluation time window. This may be an appropriately selected time interval, such as the last 60 minutes.

[0086] As described above, the combustion boiler system (10) includes a local control system (301, 303) and / or is connected to a remote control system (308). The control system(s) are configured to perform a leak determination method. The combustion boiler system (10) further includes a display means, such as a display / monitor (302), for indicating to the boiler operator the presence of a tube leak detected using this method.

[0087] Figure 3 shows an example of a model building or calibration process.

[0088] After initiation (step A1), in step A3, a numerical model for the water / steam balance of the combustion boiler system (10) is constructed, for example, by regression modeling. Depending on the type of combustion boiler system (10), the model may differ as follows:

[0089] Water / Steam Balance, Equation for Drum Boiler:

[0090] Q ms, c a0 + a1Q fw + a2Dt(Q fw ) + a3Q cbd + a4Q sbd + a5Dt(DL)

[0091] Here:

[0092] Q ms, c = Modeled main steam flow

[0093] Q fw = Water flow can be measured before the economizer

[0094] Dt (Q fw ) = Dt(settlement flow) is the time derivative of the supply flow (how much the supply flow changes at a specific time).

[0095] Q cbd The continuous blowdown flow from the steam is water discharged from the drum.

[0096] Q sbd = Soot blow steam flow may be steam from the superheater before the final superheater

[0097] Dt(DL) = Dt(drum level) is the time derivative of the drum level (how much the drum level changes at a specific time).

[0098] a0, a1 ... a5 = correction coefficients determined by the linear regression method.

[0099] Alternatively, the modeled main steam flow can be obtained using artificial intelligence tools and / or neural networks.

[0100] Water / Steam Balance Equation for OTU Boiler:

[0101] Q ms,c - a0 + a1Q fw + a2DT (Q fw ) + a3P fw + a4Dt (P fw )

[0102] Here:

[0103] Q ms, c = Modeled main steam flow

[0104] Q fw = Water supply flow

[0105] Dt (Q fw ) = Dt(series flow)

[0106] P fw = Water supply pressure

[0107] Dt(P fw ) = Dt(water supply pressure)

[0108] a0, a1 ..., a4 = correction coefficients determined by the linear regression method.

[0109] Alternatively, the modeled main steam flow can be obtained using artificial intelligence tools and / or neural networks.

[0110] In step A5, each FBHE(100 i Regarding ), FBHE i A numerical model for calculating the temperature is constructed, for example, by the following regression modeling:

[0111] FBHE i Equation for calculating layer temperature

[0112] T i,j,c = b0 + b1T w,i + b2T se,i + b3Q ms,m + b4Dt (Q ms,m)

[0113] Here:

[0114] T i , j = FBHE(100 i Modeled layer temperature of )

[0115] (Since the number of temperature points is N, j = 1, ..., N)

[0116] T w,i = Loop seal(200 i ) temperature

[0117] T se,i = Separator(17 i Flue gas outlet temperature of )

[0118] Q ms, m = Main steam flow

[0119] Dt (Q ms, m ) = Dt(main steam flow)

[0120] b0, b1 ... b4 = coefficients determined by the linear regression method.

[0121] Alternatively, the modeled layer temperature can be obtained using artificial intelligence tools and / or neural networks.

[0122] In step A7, each separator (17 i Regarding ), the separator (17 iA numerical model for calculating the temperature of ) is constructed, for example, by the following regression modeling:

[0123] Separator i Equation for temperature calculation

[0124] T separator exit,i,c = c0 + c1T inlet,i + c2T msei

[0125] In the formula:

[0126] T separatorexit,i,c = Modeled separator(17 i ) Flue gas outlet temperature

[0127] T msei = (separator(17 i The average of the other separators (17j) excluding ), i.e., calculated for all other separators (17j) where j≠i

[0128] T separator,inlet,i = Separator(17 i ) Inlet temperature

[0129] c0, c1 ... c2 = coefficients determined by the linear regression method

[0130] Alternatively, the modeled separator flue gas outlet temperature can be obtained using artificial intelligence tools and / or neural networks.

[0131] In step A9, each loop seal (200 i Regarding ), loop sealing (200 i A numerical model for the pressure of ) is constructed, for example, by the following regression modeling:

[0132] Loop seal (200 i Equation for pressure calculation:

[0133] P ws,i = d0 + d1P mwsi

[0134] In the formula:

[0135] P wsi = Modeled loop seal i enter

[0136] P mwsj = (Loop sealing(200 i The average of the other loop seal pressures (calculated for all other loop seals (200j) where j≠i), excluding ).

[0137] d0, d1 = Factors determined by linear regression method

[0138] Alternatively, the modeled layer loop sealing pressure can be obtained using artificial intelligence tools and / or neural networks.

[0139] FIG. 4 illustrates the operation of a leak detection system: diagnosis (A) and training (B) are separated:

[0140] In the diagnostic block (A), the leak diagnosis method J1 is preferably executed periodically, such as at predefined intervals or every minute.

[0141] The training block (B) contains at least two sets of training data. Training data set K1 contains process data from day X1 to day X2. The training data set contains process data from day X1 to day X2. However, the start and / or end times of training data sets K1 and K3 are different (the difference is indicated by day X3). Training data sets K1 and K3 may partially overlap or be separated so as not to overlap.

[0142] Model training for data set K1 (see FIG. 3) can be called at step K5 at predefined intervals or periodically, for example, every X1 day. Similarly, model training for data set K3 (see FIG. 3) can be called at step K7 after a predefined interval (after X3 days have elapsed).

[0143] The purpose of this implementation is that if there is a tube leak in the steam circuit of the combustion boiler system (10), the tube leak can damage the calibration data. Since some tube leaks occur slowly, this is considered to improve the reliability of the detection algorithm.

[0144] Examples of model usage:

[0145] The model output is the modeled value compared to the following expected value:

[0146] Water / Steam Balance:

[0147] ΔMS = Q' ms - Q ms

[0148] Q' ms = Modeled main steam flow

[0149] Q ms = Measured main steam flow

[0150] In a normal process state, ΔMS < ΔMS limit

[0151] ΔMS limit = Process / Model / Boiler dependent values

[0152] Separator (17 i ) (where i = 1, 2, ...N, where N is a separator (17) in a combustion boiler system (10) i It is the number of ):

[0153] Δse i = T' se,i - T se,i

[0154] T' se,i = Modeled separator(17 i ) Flue gas outlet temperature

[0155] T se,i = Measured separator(17 i ) Flue gas outlet temperature

[0156] In the normal process state of the separator, Δse i < Δse limit ​

[0157] Δse limit = Process / Model / Boiler dependent values

[0158] FBHE(100):

[0159] ΔT i1 ... n = T' i1 ... n - T i1...n

[0160] T' i1 ... n = FBHE(100 i Modeled layer temperatures of ) 1...n

[0161] T i1...n = FBHE(100 i Measured layer temperatures of 1...n

[0162] ΔT in the normal process state for FBHE i1 ... n < ΔT limit

[0163] ΔT limit = Process / Model / Boiler dependent values

[0164] Loop seal (200 i ) (where i = 1, 2, ...N, where N is a loop seal (200) in a combustion boiler system (10) i It is the number of ):

[0165] Δp i = p' ws, i - P ws, i

[0166] p' ws, i = Modeled loop seal (200 i ) enter

[0167] P ws, i = Measured loop seal (200 i ) enter

[0168] Δp in the normal process state for the separator i < Δp limit

[0169] Δp limit = Process / Model / Boiler dependent values

[0170] Superheater (14):

[0171] ΔT sh = T' SH - T SH

[0172] T' SH = Modeled temperature of the superheater (14)

[0173] T SH = Measured temperature of the superheater (14)

[0174] ΔT in the normal process state of the superheater (14) SH < ΔT SH , limit

[0175] ΔT SH , limit = Process / Model / Boiler dependent values

[0176] Figure 5 illustrates the leak diagnosis step (J1 in Figure 4), specifically the calculation of the risk of tube leakage.

[0177] In step J13, delta is calculated.

[0178] Initially in the CFB boiler system, ΔMS, and optionally Δse i and / or ΔT i1...n and / or Δp i (And in each BFB boiler system, ΔMS and optionally also ΔT sh ) can be calculated for a predefined time interval, such as the last 60 minutes.

[0179] In the next step J15, the delta is compared to the respective warning threshold. The warning threshold is set as a constant for each model, and if the delta is lower than the respective warning threshold, the process is in a steady state. Then, the diagnostic calculates the warning threshold exceedance in step J17. FBHE(100 i In the case of a multi-model such as ), for example, ΔT i1...n When x, if the respective process / model / boiler dependency values ​​are exceeded, the component is set to abnormal.

[0180] The risk level of tube leakage can be calculated using the equation (internal value):

[0181] n e * BF > t u In the case of:

[0182] R = 100 + (n e * BF - t u ) / t r 100

[0183] otherwise:

[0184] R c = (n e * BF - t l ) / (t u - t l ) * 100

[0185] Here:

[0186] R c = Leak risk level of component (location) or water / vapor balance

[0187] n e = Reference period t r Number of excesses at = Reference period (minutes) t l Length of = lower bound

[0188] t u = Upper limit

[0189] BF = Boost Factor

[0190] BF = 1 + (E s / (WL * N) - 1) * B

[0191] Here:

[0192] BF = Boosting Factor

[0193] B = Boosting gradient

[0194] WL = Warning limit for error

[0195] N: Number of excesses

[0196] err > If it is a warning limit, E s = sum(err)

[0197] The leakage index can be calculated using the following equation:

[0198] R c If < 100, I c = R c ; R c If > 100, I c = 100

[0199] In the formula:

[0200] I c = Component Leakage Index (Location) or Water / Vapor Balance Index

[0201] R c = Leak risk level of component (location) or water / vapor balance

[0202] If the leakage index is 50 or higher but less than 100,

[0203] "Yellow" warning regarding location or water / steam balance.

[0204] If the leak index is greater than 100, a "red" warning for the location or water / steam balance.

[0205] Total Leakage Index:

[0206] I cm If < 50:

[0207] I = R ws / 2

[0208] I cm If >= 50:

[0209] I = R ws / 2 + I cm / 2

[0210] Here:

[0211] I = Total leakage index

[0212] R ws = Leakage risk level of water / steam balance

[0213] I cm = Maximum Component Leakage Index

[0214] The inventors verified the functionality of the method for actual data collected from a stored CFB combustion boiler system. The data is disclosed in FIGS. 6A through 6I and exemplarily shows how the method can be used to notify a boiler operator of the presence of a tube leak in the steam circuit of a combustion boiler system (as can be understood as simulating the DCS (301) and EDGE systems with the participation of a remote process intelligence system (308) and displayed to the boiler operator on a display / monitor (302).

[0215] Figure 6A shows the total leakage index I calculated during the test cycle as described above. As can be seen, the index reaches 100 in the rightmost cycle column. Boiler leakage is present. In the actual situation where process data is collected from the boiler, operation was stopped.

[0216] FIG. 6b shows the delta of the water / steam balance, i.e., ΔMS calculated for the same combustion boiler system (10) process data. Somewhat large fluctuations can be seen. There is a significant increase in the rightmost time cycle column. FIG. 6c shows the leakage index I calculated only for the water / steam balance. MS It shows.

[0217] FIG. 6d is the delta for FBHE (1003), i.e., ΔT calculated for the same combustion boiler system (10) process data. 3 1-n It plots. The increase in delta is somewhat slow. Fig. 6e is the leakage index I FBHE 3 , that is, the leakage index calculated only for component FBHE (1003) is shown.

[0218] FIG. 6f shows the delta for the separator (173), i.e., Δse3 calculated for the same combustion boiler system (10) process data. FIG. 6g is

[0219] Leakage Index ISE, 3 , that is, the leakage index calculated only for the component separator (173) is shown.

[0220] FIG. 6h shows the delta for the loop seal (2003), i.e., Δws3 calculated for the same combustion boiler system (10) process data. FIG. 6i shows the leakage index I ws, 3 , that is, the leakage index calculated only for the component loop seal (2003) is shown.

[0221] From the total leakage index I, the presence of tube leakage in the steam circuit of the combustion boiler system (10) can be reliably detected, and if possible, detected sooner than in the applicant's previous realization of the combustion boiler system.

[0222] A component-specific leak index (in this example, each FBHE (100)) preferably calculated for all components of the combustion boiler system (10) prone to leakage. i For each separator (17) i For ), and each loop seal (200 i From the leakage index for ), the location of the component with the tube leak can be reliably detected.

[0223] That is, in the leak detection method according to the first aspect of the present invention, a risk level is calculated using time-series measurements between a model-based quantity estimated for actual bed conditions using determined fluidized bed combustion boiler operating parameters and each quantity calculated from measurements, wherein the risk level is described in an excessively proportional manner relative to the magnitude of the measurements. The risk level can be displayed to the boiler operator.

[0224] If the risk level exceeds a preset limit, the exceedance is indicated to the boiler operator, an alarm sounds for the boiler operator, and / or the boiler shutdown is automatically suggested or initiated.

[0225] In a leak detection method according to a second aspect of the present invention, a risk level is calculated using time-series measurements between a model-based quantity estimated for actual bed conditions and each quantity calculated from measurements using determined fluidized bed combustion boiler operation parameters, wherein the measurements are evaluated in at least two overlapping time windows of different lengths, and the narrower time window requires a proportionally larger number of measurements exceeding a threshold than the wider time window. The risk level may be displayed to the boiler operator. If the risk level exceeds a preset limit, the exceedance is displayed to the boiler operator, an alarm is sounded to the boiler operator, and / or a boiler shutdown is automatically suggested or initiated.

[0226] In a leak detection method according to a third aspect of the present invention, a risk level is calculated using time-series measurements between a model-based quantity estimated for actual bed conditions and each quantity calculated from measurements, using determined fluidized bed combustion boiler operation parameters, wherein the model-based quantities are estimated using corrected values, and the corrected values ​​are obtained by analyzing historical data from a time further in the past than the time series used to calculate the risk level as training data. The risk level may be displayed to the boiler operator. If the risk level exceeds a preset limit, the exceedance is displayed to the boiler operator, an alarm is sounded to the boiler operator, and / or a boiler shutdown is automatically suggested or initiated.

[0227] Each quantity calculated from the model-based quantities estimated for actual bed conditions and measurements using the determined fluidized bed combustion boiler operating parameters preferably includes one or more of the following: steam balance, flue gas outlet temperature, bed temperature, pressure, and advantageously, steam balance is used.

[0228] The risk level is preferably calculated as a weighted sum of any different measurements, optionally requiring each measurement to be included in the calculation exceeding a specific threshold. If the risk level exceeds 100%, the risk level may be further calculated so that it is displayed as 100% only.

[0229] The difference between the model-based quantities and the respective quantities calculated from measurements can be somewhat large. This stems from the fact that combustion conditions are constantly changing and certain fluctuations always occur in the combustion boiler. In the case of a combustion boiler generating superheated steam at a rate of 400 kg / s, the steam flow can actually fluctuate up or down by 5 - 10 kg / s.

[0230] The finding behind the first aspect of the present invention is that, given somewhat large variations between the model-based quantity and the respective quantity calculated from the measurement, smaller measurements occur very frequently with high probability in the time-series analysis, whereas larger measurements are not very likely to appear multiple times in the time-series analysis without a just cause. Therefore, larger tube leaks in combustion boilers can be detected significantly faster than in the background technology (Modern Power Systems December 2018 article), and occur in an excessively proportional manner to the exceedance of the threshold for size, where the number of threshold exceedances in time-window measurements describes the risk level in proportion to the sum of the measurement sizes. For example, refer to the results on page 38 of the Modern Power Systems article in I11.6. The applicant's previous method was able to detect a leak in the furnace wall about 30 minutes after the onset of the leak (first arrow from the left) (second arrow from the left). Using the present method, the inventors were able to reliably detect the same leak within about 2-4 minutes based on the same data.

[0231] The finding behind the second aspect of the invention is that, given somewhat large fluctuations between the model-based quantity and the respective quantity calculated from the measurement, smaller measurements occur very frequently with high probability in time-series analysis, whereas it is not very likely that smaller measurements will appear over longer time periods without a legitimate cause. Therefore, smaller tube leaks in combustion boilers can be detected much more reliably than in the background technology (Modern Power Systems December 2018 article), and if measurements are evaluated in at least two overlapping time windows of different lengths, the narrower time window will require a greater number of small measurements exceeding the threshold than the wider time window in proportion to the time window length. Using this method, the inventors were able to more frequently rule out suspected tube leaks as leak-free, even in situations where false leak alarms would occur using the background technology method.

[0232] The finding behind the third aspect is that somewhat large fluctuations in model-based quantities and each quantity calculated from measurements may exhibit some time-shifting characteristics in time-series analysis. In the presence of time-shifting, calculations of estimates using numerical models provide inaccurate results that are no longer reliable. In such situations, since model-based quantities are estimated using a mathematical model corrected with coefficient values ​​obtained through numerical fitting, the influence of time-shifting characteristics can be suppressed or even eliminated if corrected values ​​are obtained by analyzing training data—historical data from a much further past than the time series used to calculate the current risk level—through repeated numerical fitting. Preferably, the historical data is from at least a few days ago, and even better, from one or two weeks ago. Using this method allows for the more reliable detection of slow-progressing tube leaks compared to the method described in the background technology (Modern Power Systems December 2018 article).

[0233] In a tube leak detection method according to a fourth aspect of the present invention, a risk level is calculated using time-series measurements between a model-based quantity estimated for actual bed conditions and each quantity calculated from measurements using determined fluidized bed combustion boiler operating parameters, and comprises at least one, but preferably all, of the following: at least one separator, at least one solid return chamber heat exchanger, and one low-risk loop seal. The risk level may be displayed to the boiler operator. If the risk level exceeds a preset limit, the exceedance is displayed to the boiler operator, an alarm is sounded to the boiler operator, and / or a boiler shutdown is automatically suggested or initiated.

[0234] The finding following the fourth aspect is that tube leakage in a fluidized bed boiler can generally cause an effect similar to sandblasting, where the abrasive bed material is pressurized against other tube-like boiler structures by high-pressure steam or water. Therefore, CFB boiler leakage detection performed on at least one separator, at least one solid return chamber heat exchanger, and / or at least one loop seal can help reduce damage to these parts of the boiler.

[0235] In the event of a leak in the furnace wall water tubes, the tube leak does not necessarily lead to very bad consequences for the furnace; however, the situation will be significantly different in certain CFB boiler structures (separators, solid return chamber heat exchangers, loop seals) where heat exchanger tubes are relatively close to each other. For example, in a solid return chamber heat exchanger, the spacing between adjacent heat exchanger tubes may be only 10 cm, and a leak in a component with a higher layer material density can lead to rapid deterioration of the leak due to the increasing abrasive effect on the layer material caused by the leak. For instance, the layer material density in the lower part of a CFB furnace may be in the range of tens of kg / m³, whereas in a solid return chamber heat exchanger, it may be in the range of 1,000 to 1,500 kg / m³. Furthermore, a leak in the furnace tube wall generally does not damage neighboring tubes because the adjacent tubes are not in the direction of the layer material blasting caused by the leak.

[0236] It is obvious to those skilled in the art that the basic concept of the present invention can be implemented in various ways depending on technological advancements. The present invention and its embodiments are not limited to the examples and samples described above, and various modifications are possible according to the claims and their legal equivalents.

[0237] In the subsequent claims and the foregoing description of the invention, words such as “comprising” or “comprising” or variations thereof are used in an inclusive sense, except where contextually required otherwise due to expressive language or necessary connotations, and

[0238] That is, the existence of the mentioned features is specified, but the existence or addition of additional features in various embodiments of the present invention is not excluded. Explanation of the symbols

[0239] 10 Combustion Boiler 12 No 13 tube walls 14 Superheater 15 crossover ducts 16 Reverse path 17 particle separator 18 years gas duct 19 stack 280 Temperature Sensor (FBHE) 21i heat transfer surface (i = 1, 2, ... k) 22 Fuel Supply 50 water tanks 100 Fluidized Bed Heat Exchanger (FBHE) 101 FBHE Exit 102 Return Channel 103 Vortex Finder 131 Tube wall entrance 132 Tube Wall Exit 141 FBHE Entrance 142 FBHE Exit 143 Superheater Inlet 144 Superheater Exit 151 Primary fluidization gas feed 152 Secondary fluidization gas feed 153 Fluidization Gas Supply Source 200 loop seals 240 Temperature Sensor (Superheater) 250 grid 260 Temperature Sensor (FBHE) 270 Temperature Sensor (Superheater) 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 Systems 307 Compute Cloud 370 Field Bus 380 Combustion Boiler Network

Claims

Claim 1 A method for determining tube leakage in the steam circuit of a combustion boiler system (10), - the main steam flow (Q) prevalent in the steam circuit of the combustion boiler system (10) during operation MS,M A step of measuring ) - the main steam (Q) of the combustion boiler system (10) under conditions where there is no tube leakage. MS,C By using process data in a numerical model of the combustion boiler system (10) that provides the ) flow, the main steam flow (Q) in the steam circuit during operation MS,C Step of modeling ) - Error measurement for the main steam flow included in the error measurement set (Δ MS A step of comparing the measured steam flow and the modeled steam flow with each other to obtain ); - a step of monitoring the error measurement set and the number of occurrences of the error measurement set during operation; and - error measurements (Δ MS A method for determining tube leakage in a steam circuit of a combustion boiler system (10), comprising the step of determining the presence of a steam circuit tube leakage when the number of occurrences of the set of errors exceeds a predetermined threshold, or when the number of occurrences of the set of errors exceeds a predetermined threshold during a predetermined time period. Claim 2 A method for determining tube leakage in a steam circuit of a combustion boiler system (10), further comprising: - measuring at least one process parameter prevalent at at least one location on the fireside of the combustion boiler system (10); - modeling at least one of the corresponding process parameters during the operation of the combustion boiler system (10) by using process data in a numerical model that provides the corresponding process parameter of the combustion boiler system (10) under leak-free conditions; and - comparing the at least one measured process parameter with the corresponding at least one modeled process parameter to obtain an error measurement for the at least one process parameter included in the set of error measurements. Claim 3 A method for determining tube leakage in a steam circuit of a combustion boiler system (10), wherein, in claim 2, the process parameters include or consist of at least one of temperature and / or pressure. Claim 4 A method for determining tube leakage in the steam circuit of a combustion boiler system (10), wherein, in any one of claims 1 to 3, the combustion boiler system (10) is a circulating fluidized bed boiler system. Claim 5 A method for determining tube leakage in a steam circuit of a combustion boiler system (10), wherein the process parameter comprises or is composed of the pressure of a loop seal (290) arranged downstream of the particle separator (17) in the return leg (102), and the return leg (102) is arranged to return the separated particles to the furnace (12). Claim 6 In claim 5, the method comprises the step of monitoring whether the number of occurrences of error measurements for the main steam flow exceeds a predetermined threshold, said number of occurrences exceeding the threshold is included in the characteristics of the error measurements; the method comprises the step of monitoring whether the number of occurrences of error measurements for the pressure of said loop seal (200) exceeds a predetermined threshold, said number of occurrences exceeding the threshold is included in said characteristics of the error measurements; a method for determining a tube leak in the steam circuit of a combustion boiler system (10), wherein the steam circuit leak is determined to be present in said loop seal (200) when the error measurement for the main steam flow and said number of occurrences of error measurements for the main steam flow exceed said predetermined threshold, and additionally, when the error measurement related to the pressure of said loop seal (200) and said number of occurrences of the pressure of said loop seal (200) exceed said predetermined threshold. Claim 7 In claim 2 or 6, the process parameter is the flue gas temperature (T) at the outlet of the particle separator (17). se,i A method for determining tube leakage in the steam circuit of a combustion boiler system (10) comprising or composed of ). Claim 8 In claim 7, a method for determining a tube leak in the steam circuit of a combustion boiler system (10), wherein a leak is determined to exist in the particle separator in the following cases: when both the error measurement for the main steam flow and the number of occurrences of the error measurement for the main steam flow each exceed the predetermined threshold for the corresponding error measurements, and additionally when both the error measurement 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 the predetermined threshold for the flue gas temperature error measurements. Claim 9 A method for determining tube leakage in the steam circuit of a combustion boiler system (10), wherein, in claim 2 or 6, the process parameter comprises or is composed of the fluidized bed temperature of a fluidized bed heat exchanger including reheater tubes, and the reheater is located after the steam circuit. Claim 10 A method for determining tube leakage in a steam circuit of a combustion boiler system (10), wherein, in claim 2 or 6, the process parameter includes or is composed of the fluidized bed temperature of a fluidized bed heat exchanger including superheater tubes. Claim 11 In claim 10, a method for determining tube leakage in the steam circuit of a combustion boiler system (10), wherein the tube leakage is determined in a fluidized bed heat exchanger when: both the error measurement of the fluidized bed temperature of the fluidized bed heat exchanger and the number of occurrences of the error measurement each exceed a predetermined threshold value. Claim 12 A method for determining tube leakage in a steam circuit of a combustion boiler system (10), wherein, in any one of claims 1 to 3, 5 and 6, the characteristics of the error measurement include or consist of the number of occurrences of each occurrence exceeding a predetermined threshold. Claim 13 A combustion boiler system (10), wherein the combustion boiler system (10) comprises a control system (301, 303, 308) configured to perform a method according to any one of claims 1 to 3, 5 and 6. Claim 14 In claim 13, the combustion boiler system (10) comprises a display means including a display / monitor (302) for indicating to the boiler operator the presence of a tube leak detected using the method.

Images