Steam flow control device, power plant, steam flow control method, and steam flow control program

Abstract

The present invention provides a steam flow control device, a power plant, a steam flow control method, and a steam flow control program that enable load reduction while maintaining dry operation. [Solution] The steam flow control device 50 is a steam flow control device 50 for a power plant that includes a bypass line for bypassing steam passing through the heat recovery section of a boiler and a bypass valve for adjusting the steam flow rate, and comprises an acquisition unit 51 for acquiring the required power generation amount of the power plant, a calculation unit 52 for calculating the corresponding steam flow rate and bypass valve opening degree, which is the opening degree of the bypass valve, based on the acquired required power generation amount, and an adjustment unit 53 for adjusting the opening degree of the bypass valve so that it corresponds to the calculated steam flow rate.

Description

Technical Field

[0001] The present disclosure relates to a steam flow rate control device, a power generation plant, a steam flow rate control method, and a steam flow rate control program.

Background Art

[0002] Large boilers such as power generation boilers have a furnace installed vertically with a hollow shape, and a plurality of burners are arranged along the circumferential direction of the furnace on the furnace wall. Further, a large boiler has a flue connected above the furnace in the vertical direction, and a heat exchanger for generating steam is arranged in this flue. Then, a flame is formed by injecting a mixture of fuel and air (oxidizing gas) into the furnace by the burner, combustion gas is generated and flows into the flue. A heat exchanger is installed in the region where the combustion gas flows, and water and steam flowing in the heat transfer tubes constituting the heat exchanger are heated to generate superheated steam.

[0003] In the generation of superheated steam, the flow rate of steam bypassing the heat exchanger is controlled to control the temperature of the superheated steam. For example, Patent Document 1 discloses connecting a heat transfer tube on the downstream side and a heat transfer tube on the upstream side of a superheater with a bypass pipe, supplying the superheated steam on the upstream side to the downstream side, and setting the temperature of the steam flowing through the heat transfer tube on the downstream side to a predetermined temperature.

Prior Art Documents

Patent Documents

[0004]

Patent Document 1

Summary of the Invention

Problems to be Solved by the Invention

[0005] The invention of Patent Document 1 controls the superheated steam temperature in order to suppress deterioration and efficiency reduction of a steam turbine. In recent years, electricity generation using renewable energy sources has been carried out. However, renewable energy generation presents challenges in ensuring a stable power supply, and a gap can occur between electricity demand and the amount of electricity generated by renewable energy. Thermal power plants, such as coal-fired power plants, are required to shift from their current base-load operation to operation used to adjust the gap between electricity demand and the amount of electricity generated by renewable energy. In particular, coal-fired power plants using supercritical boilers (once-through boilers) are considered for use as adjustment power, but they have constraints on load operation, such as the minimum load at which they can be operated.

[0006] Once-through boilers have two operating states, dry operation and wet operation, depending on their operating load. Normal operation, where the boiler load (evaporation rate) is above a predetermined value, is considered dry operation (once-through operation), where the amount of feedwater supplied to the boiler is approximately equal to the evaporation rate. On the other hand, in low-load operation, where the boiler load (evaporation rate) is less than the minimum feedwater flow rate set to protect the furnace walls, the amount of feedwater supplied to the boiler is greater than the evaporation rate, resulting in wet operation (circulation operation), where some of the feedwater circulates through the boiler's furnace walls.

[0007] To transition from dry operation to wet operation, it is necessary to reduce the load change rate and lower the load in order to ensure the stability of the power plant.

[0008] Similarly, when transitioning from wet operation to dry operation, it is necessary to reduce the load change rate and increase the load to ensure the stability of the power plant. Since the amount of feedwater is increased while maintaining the minimum feedwater flow rate, the boiler enters an unstable operating range. In the process of water passing through the boiler furnace wall and changing to steam, a two-phase gas-liquid flow may occur, resulting in uneven flow velocity. To suppress this, the load change rate is kept low while increasing the load. Furthermore, after transitioning to dry operation, it is necessary to maintain the load until the boiler stabilizes.

[0009] However, as mentioned above, the invention described in Patent Document 1 controls the superheated steam temperature to suppress deterioration and efficiency reduction of the steam turbine, and does not consider the control of the steam flow rate during the transition between dry and wet operation.

[0010] This disclosure is made in view of these circumstances and aims to provide a steam flow control device, a power plant, a steam flow control method, and a steam flow control program that enable load reduction while maintaining dry operation. [Means for solving the problem]

[0011] To solve the above problems, the steam flow control device, power plant, steam flow control method, and steam flow control program of this disclosure employ the following means. The steam flow control device of the present disclosure is a steam flow control device for a power plant comprising a bypass line that bypasses steam passing through the heat recovery section of a boiler, and a bypass valve that adjusts the steam flow rate of the steam passing through the bypass line, comprising: an acquisition unit that acquires the required amount of power generated by the power plant; a calculation unit that calculates the corresponding steam flow rate and the bypass valve opening degree, which is the opening degree of the bypass valve, based on the acquired required amount of power generated; and an adjustment unit that adjusts the opening degree of the bypass valve so that it corresponds to the calculated steam flow rate.

[0012] The power plant of this disclosure comprises a bypass line for bypassing steam passing through the heat recovery section of a boiler, a bypass valve for adjusting the steam flow rate of the steam passing through the bypass line, and the steam flow control device according to claim 1.

[0013] The steam flow rate control method of the present disclosure is a steam flow rate control method for a power plant comprising a bypass line that bypasses steam passing through the heat recovery section of a boiler, and a bypass valve that adjusts the steam flow rate of the steam passing through the bypass line, wherein a computer performs an acquisition step of acquiring the required power generation amount of the power plant, a calculation step of calculating the corresponding steam flow rate and the bypass valve opening degree, which is the opening degree of the bypass valve, based on the acquired required power generation amount, and an adjustment step of adjusting the opening degree of the bypass valve so that it corresponds to the calculated steam flow rate.

[0014] The steam flow rate control program of this disclosure causes a computer to execute the steam flow rate control method described above. [Effects of the Invention]

[0015] According to this disclosure, the load can be reduced while maintaining dry operation. [Brief explanation of the drawing]

[0016] [Figure 1] This is a schematic diagram showing a boiler in some embodiments of the present disclosure. [Figure 2] This is a schematic diagram showing a heat exchanger provided in a boiler in some embodiments of the present disclosure. [Figure 3] This is a schematic diagram illustrating conventional steam flow control. [Figure 4] This figure shows an example of the hardware configuration of a steam flow control device in some embodiments of the present disclosure. [Figure 5] This figure shows an example of the function of a steam flow control device in some embodiments of the present disclosure. [Figure 6] This is a schematic diagram illustrating steam flow control using a steam flow control device in several embodiments of the present disclosure. [Figure 7] This figure shows the control flow of a steam flow control device in several embodiments of the present disclosure. [Modes for carrying out the invention]

[0017] Hereinafter, an embodiment of a steam flow rate control device, a power generation plant, a steam flow rate control method, and a steam flow rate control program according to the present disclosure will be described with reference to the drawings.

[0018] Hereinafter, an embodiment according to the present disclosure will be described with reference to the drawings. Note that the present disclosure is not limited by this embodiment, and when there are a plurality of embodiments, those configured by combining each embodiment are also included. In the following description, "up" and "upper" indicate the upper side in the vertical direction, and "down" and "lower" indicate the lower side in the vertical direction. The vertical direction is not strict and includes errors.

[0019] FIG. 1 is a schematic configuration diagram showing a boiler in some embodiments of the present disclosure.

[0020] The boiler 10 of the power generation plant 1 of this embodiment is a boiler capable of burning pulverized fuel obtained by pulverizing solid fuel with a burner and exchanging heat generated by this combustion with feed water or steam to generate superheated steam. As the solid fuel, biomass fuel, coal, or the like is used.

[0021] The boiler 10 has a furnace 11, a combustion device 20, and a combustion gas passage 12. The furnace 11 has a hollow shape of a rectangular cylinder and is installed along the vertical direction. The furnace wall 101 constituting the inner wall surface of the furnace 11 is composed of a plurality of heat transfer tubes and fins connecting the heat transfer tubes to each other, and recovers heat generated by the combustion of pulverized fuel by exchanging heat with water or steam flowing inside the heat transfer tubes, while suppressing an increase in the temperature of the furnace wall 101.

[0022] The combustion device 20 is installed in the lower region of the furnace 11. In this embodiment, the combustion device 20 has a plurality of burners 21A, 21B, 21C, 21D, 21E, and 21F (hereinafter sometimes collectively referred to as "burners 21") mounted on the furnace wall 101. The burners 21 are arranged in multiple vertical rows, with each set consisting of burners 21 arranged at equal intervals along the circumferential direction of the furnace 11 (for example, four burners installed at each corner of a rectangular furnace 11). In Figure 1, for illustrative purposes, only two burners from one set are shown, and each set is labeled with the reference numerals 21A, 21B, 21C, 21D, 21E, and 21F. The shape of the furnace, the number of burner rows, the number of burners in each row, and the arrangement of the burners are not limited to this embodiment.

[0023] Burners 21A, 21B, 21C, 21D, 21E, and 21F are each connected to multiple mills 31A, 31B, 31C, 31D, 31E, and 31F (hereinafter collectively referred to as "mills 31") via multiple fine fuel supply pipes 22A, 22B, 22C, 22D, 22E, and 22F (hereinafter collectively referred to as "fine fuel supply pipes 22"). Mills 31 crush solid fuel to produce fine fuel, and are, for example, vertical roller mills configured such that a crushing table (not shown) is supported inside so as to be rotatable, and multiple crushing rollers (not shown) are supported above the crushing table so as to be rotatable in conjunction with the rotation of the crushing table. The solid fuel crushed by the cooperation of the crushing rollers and the crushing table is conveyed to a classifier (not shown) equipped in mill 31 by primary air (conveying gas, oxidizing gas) supplied to mill 31. In the classifier, the crushed solid fuel is classified into fine fuel particles with a particle size suitable for combustion in the burner 21 and coarse fuel particles with a particle size larger than that. The fine fuel particles that pass through the classifier are supplied to the burner 21 via the fine fuel supply pipe 22 along with primary air. The coarse fuel particles that do not pass through the classifier fall onto the crushing table inside the mill 31 due to their own weight and are crushed again.

[0024] An air register 23 is provided on the outside of the furnace 11 where the burner 21 is installed, and one end of an air duct 24 is connected to this air register 23. A forced draft fan (FDF) 32 is connected to the other end of the air duct 24. The air supplied from the forced draft fan 32 is heated by an air preheater 42 installed in the air duct 24 (details will be described later), and is supplied to the burner 21 as secondary air (combustion air, oxidizing gas) via the air register 23 and introduced into the furnace 11.

[0025] The combustion gas passage 12 is connected to the upper vertical part of the furnace 11. The combustion gas passage 12 is equipped with superheaters 102A, 102B, 102C (hereinafter sometimes collectively referred to as "superheater 102"), reheaters 103A, 103B (hereinafter sometimes collectively referred to as "reheater 103"), and an economizer 104 as heat exchangers for recovering heat from the combustion gas. Heat exchange takes place between the combustion gas generated in the furnace 11 and the feedwater or steam circulating inside each heat exchanger. Note that the arrangement and shape of each heat exchanger are not limited to the configuration shown in Figure 1.

[0026] Downstream of the combustion gas passage 12 is a flue 13 through which the combustion gas, whose heat has been recovered by the heat exchanger, is discharged. An air preheater (air heater) 42 is installed between the flue 13 and the air duct 24, and heat exchange takes place between the air flowing through the air duct 24 and the combustion gas flowing through the flue 13. By heating the primary air supplied to the mill 31 and the secondary air supplied to the burner 21, heat is further recovered from the combustion gas after heat exchange with water or steam.

[0027] Furthermore, a denitrification device 43 may be provided in the flue 13 at a position upstream of the air preheater 42. The denitrification device 43 supplies a reducing agent, such as ammonia or urea solution, which has the effect of reducing nitrogen oxides, to the combustion gas flowing through the flue 13. The reaction between the nitrogen oxides (NOx) in the combustion gas to which the reducing agent has been supplied and the reducing agent is promoted by the catalytic action of a denitrification catalyst installed in the denitrification device 43, thereby removing and reducing nitrogen oxides in the combustion gas. A gas duct 41 is connected downstream of the air preheater 42 in the flue 13. The gas duct 41 is equipped with dust collection devices 44, such as an electrostatic precipitator, to remove ash and other particles from the combustion gas, and environmental devices such as a desulfurization device 46 to remove sulfur oxides, as well as an induced draft fan (IDF) 45 to guide the exhaust gas to these environmental devices. The downstream end of the gas duct 41 is connected to the chimney 47, and the combustion gas treated by the environmental devices is discharged outside the system as exhaust gas.

[0028] In the boiler 10, when multiple mills 31 are driven, the crushed and classified pulverized fuel is supplied to the burner 21 via the pulverized fuel supply pipe 22 along with primary air. In addition, secondary air heated by the air preheater 42 is supplied to the burner 21 from the air duct 24 via the wind box 23. The burner 21 blows a pulverized fuel mixture, which is a mixture of pulverized fuel and primary air, into the furnace 11, and also blows secondary air into the furnace 11. The pulverized fuel mixture blown into the furnace 11 ignites and reacts with the secondary air to form a flame. The flame is formed in the lower region of the furnace 11, and the high-temperature combustion gas rises inside the furnace 11 and flows into the combustion gas passage 12. In this embodiment, air is used as the oxidizing gas (primary air, secondary air), but a gas with a higher or lower oxygen content than air may also be used, and stable combustion in the furnace 11 can be achieved by adjusting the ratio of oxygen to the supplied fuel amount to an appropriate range.

[0029] Furthermore, above the mounting position of the burner 21 in the furnace 11, a number of additional air ports (AA ports) 25 are provided to supply additional combustion air (AA) into the furnace 11. The ends of additional air ducts (AA ducts) 26, which branch off from the air duct 24, are connected to the additional air ports 25, and a portion of the air supplied from the forced draft fan 32 can be supplied to the additional air ports 25 as additional combustion air via the additional air ducts 26.

[0030] In region A inside the furnace 11 shown in Figure 1 (the region corresponding to the height range of installation of the wind box 23), a flame is formed by the combustion of a mixture of primary air and pulverized fuel with secondary air. Here, the air ratio in region A is set to 1 or less. Specifically, the amount of air supplied to the burner 21 (the total amount of primary and secondary air) is set to be less than the theoretical amount of air relative to the amount of fuel supplied to the burner 21. As a result, regions A and B inside the furnace 11 (the region between the top of the burner 21 and the bottom of the additional air port 25) become a reducing atmosphere, and nitrogen oxides (NOx) generated by combustion are reduced inside the furnace 11. Subsequently, in region C (the region above the bottom of the additional air port 25), additional combustion air is supplied from the additional air port 25 to the combustion gas from which NOx has been reduced, and combustion is completed. However, the amount of NOx generated is reduced by the reduction effect in regions A and B.

[0031] The combustion gas flowing into the combustion gas passage 12 undergoes heat exchange with water and steam in the superheater 102, reheater 103, and economizer 104 located inside the combustion gas passage 12, before being discharged into the flue 13. There, nitrogen oxides are removed in the denitrification device 43, and after heat exchange with primary and secondary air in the air preheater 42, it is further discharged into the gas duct 41. Ash and other contaminants are removed in the dust collector 44, and sulfur oxides are removed in the desulfurization device 46 before being discharged out of the system through the chimney 47. Note that the arrangement of each heat exchanger in the combustion gas passage 12 and each device from the flue 13 to the gas duct 41 does not necessarily have to be in the order described above with respect to the combustion gas flow.

[0032] Next, the superheater 102, reheater 103, and economizer 104, which are provided in the combustion gas passage 12 as heat exchangers, will be described in detail. Figure 2 is a schematic diagram showing heat exchangers provided in a boiler in some embodiments of this disclosure. Note that Figure 1 does not accurately show the positions of each heat exchanger (superheaters 102A, 102B, 102C, reheaters 103A, 103B, and economizer 104) within the combustion gas passage 12, and the arrangement order of each heat exchanger relative to the combustion gas flow is not limited to that shown in Figure 1.

[0033] As shown in Figure 2, the power plant 1 of this embodiment includes a heat exchanger installed in a boiler 10, a steam turbine 111 that is rotationally driven by the steam generated in the boiler 10, and a generator 113 connected to the steam turbine 111 that generates electricity using the rotational force of the steam turbine 111.

[0034] The steam turbine 111, which is rotationally driven by steam generated in the boiler 10, is composed of, for example, a high-pressure turbine 111A, an intermediate-pressure turbine 111B, and a low-pressure turbine 111C. After the steam superheated in the superheater 102 of the boiler 10 rotates the high-pressure turbine 111A, it is re-superheated in the reheater 103 of the boiler 10 and rotates the intermediate-pressure turbine 111B and the low-pressure turbine 111C. A condenser 112 is connected to the low-pressure turbine 111C, and the steam that rotates the low-pressure turbine 111C condenses into condensate in this condenser 112 through heat exchange with cooling water (for example, seawater or river water). The condenser 112 is connected to an economizer 104 via a feedwater line L1. The feedwater line L1 is equipped with, for example, a condensate pump (CP) 121, a low-pressure feedwater heater 122, a boiler feedwater pump (BFP) 123, and a high-pressure feedwater heater 124. A portion of the steam that drives the steam turbine 111 is extracted from the low-pressure feedwater heater 122 and the high-pressure feedwater heater 124 and supplied as a heat source via an extraction line (not shown), which heats the feedwater supplied to the economizer 104.

[0035] Boiler 10 is a once-through boiler. The economizer 104 is connected to the heat transfer tubes that make up the furnace wall 101. The feedwater heated in the economizer 104 is heated by radiation from the flame in the furnace 11 (see Figure 1) as it passes through the heat transfer tubes that make up the furnace wall 101, and is then led to the steam-water separator 125. The steam separated in the steam-water separator 125 is supplied to the superheater 102, and the condensate separated in the steam-water separator 125 flows into the steam-water separator drain tank 126 and is led to the condensate 112 via the drain water line L2 equipped with a drain water valve 128.

[0036] Furthermore, during startup or low-load operation of the once-through boiler, the feedwater supplied from the economizer 104 may not evaporate completely as it passes through the heat transfer tubes constituting the furnace wall 101, resulting in a wet operation state (circulation operation state) where a water level exists in the steam-water separator 125. In this wet operation state, the drain water separated in the steam-water separator 125 and discharged into the steam-water separator drain tank 126 may be recirculated and supplied from the economizer 104 to the heat transfer tubes constituting the furnace wall 101 by using a boiler circulation pump (BCP) 127 to join the feedwater line L1 via a circulation line L6.

[0037] As combustion gas flows through the combustion gas passage 12, heat is recovered from this combustion gas in the superheater 102, reheater 103, and economizer 104. Meanwhile, feedwater supplied from the boiler feedwater pump (BFP) 123 is preheated in the economizer 104, then heated to steam as it passes through the heat transfer tubes that make up the furnace wall 101, and is led to the steam-water separator 125. The steam separated in the steam-water separator 125 is introduced into the first superheater 102A, the second superheater 102B, and the third superheater 102C, where it is superheated by the combustion gas. The superheated steam generated in superheater 102 is supplied to the high-pressure turbine 111A via the steam line L3, which rotates the high-pressure turbine 111A. The steam discharged from the high-pressure turbine 111A is introduced into the first reheater 103A and the second reheater 103B, where it is re-superheated. The reheated steam is supplied to the low-pressure turbine 111C via the steam line L5, passing through the intermediate-pressure turbine 111B, and rotating both the intermediate-pressure turbine 111B and the low-pressure turbine 111C. The rotating shaft of the steam turbine 111 rotates the generator 113, generating electricity. The steam discharged from the low-pressure turbine 111C is cooled in the condenser 112 to become condensate, which is then sent back to the economizer 104 via the feedwater line L1. As it passes through the heat transfer tubes that make up the furnace wall 101, the entire amount evaporates, becoming dry steam, and the steam-water separator 125 enters a dry operation state (through-flow operation state) where there is no water level.

[0038] The superheater 102 and reheater 103 may be provided with means for controlling the temperature of the steam superheated in each heat exchanger (hereinafter, the temperature of the superheated steam at the outlet of the third superheater 102C will be referred to as the "main steam temperature," and the temperature of the superheated steam at the outlet of the second reheater 103B will be referred to as the "reheat steam temperature"). For example, a superheater spray valve (not shown) and a reheater spray valve (not shown) may be provided to control the steam temperature by adjusting the amount of water mixed and injected into the superheated steam (hereinafter, the water injected for main steam temperature control will be referred to as "superheater spray water," and the water injected for reheat steam temperature control will be referred to as "reheater spray water"). The superheater spray water and reheater spray water are supplied, for example, by branching off a portion of the feedwater to the boiler 10 from the outlet of the boiler feedwater pump 123. Furthermore, the location where the superheater spray water is mixed and injected is not limited to the outlet of the third superheater 102C, but can be any location where the main steam temperature can be controlled, for example, it can be installed at any location between the outlet of the steam separator 125 and the inlet of the high-pressure turbine 111A. Similarly, the location where the reheater spray water is mixed and injected is not limited to the outlet of the second reheater 103B, but can be any location where the reheat steam temperature can be controlled, for example, it can be installed at any location between the outlet of the high-pressure turbine 111A and the inlet of the intermediate-pressure turbine 111B.

[0039] Furthermore, suit blowers (ash removal devices), not shown, may be placed in the gaps between the heat transfer tubes constituting each heat exchanger, such as the superheater 102, reheater 103, and economizer 104, or in the gaps between each heat exchanger. The suit blowers are positioned extending in a direction substantially perpendicular to the wall surface of the combustion gas passage 12. The suit blowers are injection devices that inject steam (gas) in a direction perpendicular to the axial direction, with the direction perpendicular to the wall surface of the combustion gas passage 12 as their axial direction, and the injection direction can also be varied. The steam injected from the suit blowers toward the heat exchangers, such as the superheater 102, reheater 103, and economizer 104, removes combustion ash adhering to and accumulated on the surface of the heat transfer tubes constituting the heat exchangers, thereby suppressing a decrease in the heat exchange efficiency of the heat transfer tubes.

[0040] As mentioned above, boiler 10 has two operating states: dry operation (on-flow operation) and wet operation (circulation operation). In wet operation, some of the feedwater heated by the furnace wall 101 circulates inside boiler 10 without being discharged outside the system, resulting in lower thermal efficiency of boiler 10 compared to dry operation.

[0041] In dry operation, superheated steam (dry steam) is produced at the outlet of the furnace wall 101 of the boiler 10. On the other hand, in wet operation, saturated steam (moist steam) is produced at the outlet of the furnace wall 101. In wet operation, condensate in the moist steam is separated by the steam-water separator 125 and discharged into the steam-water separator drain tank 126.

[0042] Boiler 10 is supplied with the necessary feedwater flow rate according to the load (evaporation rate, main steam flow rate supplied from boiler 10 to external systems such as high-pressure turbine 111A). During boiler 10 operation, the feedwater flow rate must always be above a predetermined amount to protect the furnace wall 101. This lower limit of feedwater flow rate is defined as the minimum feedwater flow rate. The first load is defined as the lower limit of the load at which a stable dry operation state can be maintained while ensuring a feedwater flow rate above the minimum feedwater flow rate. Above the first load, dry operation is performed, and the feedwater flow rate supplied is according to the load (evaporation rate). On the other hand, when the load falls below the first load, the operation switches from dry operation to wet operation. At this time, a constant minimum feedwater flow rate is supplied regardless of the load to protect the furnace wall 101.

[0043] Figure 3 is a schematic diagram illustrating conventional steam flow control. As shown in Figure 3, the conventional power plant 1 mainly consists of a boiler 10, a superheater 102, a high-pressure turbine 111A, a reheater 103, an intermediate-pressure turbine 111B and a low-pressure turbine 111C, a condenser 112, a vacuum pump 135, a feedwater heater (low-pressure feedwater heater) 122, an extraction shutoff valve 132, and a vacuum breaking valve 190. The same components as in Figure 2 are given the same reference numerals.

[0044] Steam heated by passing through heat transfer tubes that constitute the furnace wall 101 of the boiler 10 is supplied to the superheater 102. In this disclosure, the superheater 102 comprises multiple superheaters (heat transfer tubes) 102 (102A to 102C). Figure 3 illustrates a case with three superheaters 102, but the number of superheaters 102 is not limited. Hereinafter, when it is necessary to distinguish between superheaters 102A, 102B, and 102C, they will be referred to as superheater 102A, 102B, and 102C, and when it is not necessary to distinguish between them, they will simply be referred to as superheater 102. The same treatment will be applied to other configurations.

[0045] The steam superheated in the superheater 102 is supplied to the high-pressure turbine 111A, which rotates. The steam discharged from the high-pressure turbine 111A is introduced to the reheater 103 and re-superheated. In this disclosure, the reheater 103 comprises multiple reheaters (heat transfer tubes) 103 (103A, 103B). Figure 3 illustrates a case with two reheaters 103, but the number of reheaters 103 is not limited. The re-superheated steam is supplied to the low-pressure turbine 111C via the intermediate-pressure turbine 111B, which rotates both the intermediate-pressure turbine 111B and the low-pressure turbine 111C. The rotating shaft of the steam turbine 111 rotates the generator 113, generating electricity.

[0046] Steam discharged from the low-pressure turbine 111C is cooled in the condenser 112 to become condensate, which is then sent to the low-pressure feedwater heater 122 via the condensate pump 121. In this disclosure, the low-pressure feedwater heater 122 comprises multiple low-pressure feedwater heaters 122 (122A to 122C). Figure 3 illustrates a case with three low-pressure feedwater heaters 122, but the number of low-pressure feedwater heaters 122 is not limited. Steam is extracted from the low-pressure turbine 111C to the low-pressure feedwater heaters 122. Each low-pressure feedwater heater 122 is connected to a corresponding extraction line from the low-pressure turbine 111C. Each extraction line is provided with extraction shut-off valves 132A, 132B, and 132C, respectively. The extraction shutoff valve 132 controls whether or not to supply steam extracted from the exhaust of the intermediate-pressure turbine 111B to the low-pressure feedwater heater 122 by switching it ON / OFF. In this embodiment of the disclosure, the steam extracted from the exhaust of the intermediate-pressure turbine 111B is supplied to the low-pressure feedwater heater 122, but the extraction point is not limited to the exhaust of the intermediate-pressure turbine 111B, and the extracted steam may also be supplied to the high-pressure feedwater heater 124.

[0047] A vacuum pump 135 is connected to the condenser 112. The vacuum pump 135 reduces the pressure inside the condenser 112 from atmospheric pressure. For example, a liquid-sealed centrifugal vacuum pump is used as the vacuum pump 135.

[0048] A vacuum-breaking valve 190 is connected to the condenser 112. When the vacuum-breaking valve 190 opens, the pressure inside the condenser 112 increases.

[0049] In the conventional power plant 1 shown in Figure 3, it is necessary to switch from dry operation to wet operation when the load falls below the first load. As mentioned above, when switching operating states, there is a problem that a waiting time occurs to stabilize the operating state of the power plant 1 and boiler 10, and it is not possible to immediately move to the next step. This disclosure describes a configuration that allows for a reduction in generator output while maintaining a dry operation state without switching operating states.

[0050] Figure 4 shows an example of the hardware configuration of a steam flow control device in some embodiments of the present disclosure. As shown in Figure 4, the steam flow control device (Controller) 50 is a computer system, and for example, it includes a CPU (Central Processing Unit: processor) 1100, secondary storage (ROM, Secondary storage: memory) 1200, main memory (RAM, Main Memory) 1300, a hard disk drive (HDD) 1400 as a mass storage device, and a communication unit 1500 for connecting to a network, etc. A solid-state drive (SSD) may be used as the mass storage device. These parts are connected via a bus 1800.

[0051] The CPU 1100 controls the entire steam flow control device 50 using an OS (Operating System) stored in a secondary storage device 1200 connected via a bus 1800, and also performs various processes by executing various programs stored in the secondary storage device 1200. One or more CPUs 1100 may be provided and may cooperate with each other to achieve processing.

[0052] The main memory 1300 consists of writable memory such as cache memory and RAM (Random Access Memory), and is used as a work area for reading the CPU 1100's executable program and writing processing data by the executable program.

[0053] The secondary storage device 1200 is a non-transitory computer-readable storage medium. Examples of secondary storage devices 1200 include magnetic disks, magneto-optical disks, CD-ROMs, DVD-ROMs, and semiconductor memory. Examples of secondary storage devices 1200 include ROM (Read Only Memory), HDD (Hard Disk Drive), SSD (Solid State Drive), and flash memory. The secondary storage device 1200 stores, for example, an OS for controlling the entire information processing device such as Windows®, iOS®, and Android®, a BIOS (Basic Input / Output System), various device drivers for hardware operation of peripheral devices, various application software, and various data and files. Furthermore, the secondary storage device 1200 stores programs for implementing various processes and various data required to implement those processes. Multiple secondary storage devices 1200 may be provided, and the aforementioned programs and data may be divided and stored in each secondary storage device 1200.

[0054] Furthermore, the steam flow control device 50 may include an input unit consisting of a keyboard or mouse, and a display unit consisting of a liquid crystal display device or the like for displaying data. It may also include a notification unit that includes a display unit and outputs lights, sounds, and especially alarm sounds, such as a speaker.

[0055] Figure 5 shows an example of the function of a steam flow control device in some embodiments of the present disclosure. As shown in Figure 5, the steam flow rate control device 50 includes an acquisition unit 51, a calculation unit 52, and an adjustment unit 53.

[0056] The series of processes required to realize the functions of the steam flow control device 50 are stored in the form of a program in the secondary storage device 1200 (see Figure 4), and the CPU (processor) 1100 (see Figure 4) reads this program into the main memory 1300 (see Figure 4) and performs information processing and calculations to realize various functions. The program may be pre-installed in the secondary storage device 1200, provided stored in other non-temporary computer-readable storage media, or distributed via wired or wireless communication. Examples of non-temporary computer-readable storage media include magnetic disks, magneto-optical disks, CD-ROMs, DVD-ROMs, and semiconductor memory.

[0057] The acquisition unit 51 shown in Figure 5 acquires the required power generation amount requested by the power plant 1. The acquisition unit 51 may also acquire various other values ​​necessary for control.

[0058] The calculation unit 52 calculates the corresponding steam flow rate and the bypass valve opening, which is the opening degree of the bypass valves 150 and 160 described later, based on the requested power generation amount acquired by the acquisition unit 51.

[0059] The adjustment unit 53 adjusts the opening degrees of the bypass valves 150 and 160 so that they correspond to the bypass valve opening degree calculated by the calculation unit 52.

[0060] Figure 6 is a schematic diagram illustrating steam flow control using a steam flow control device in several embodiments of the present disclosure. Components identical to those in Figure 3 are given the same reference numerals and their descriptions are omitted. The power plant 1 of this disclosure is provided with a superheater bypass line 155 that connects the outlet of the furnace wall 101, i.e., the upstream side of the superheater 102A, to the inlet of the high-pressure turbine 111A, i.e., the downstream side of the superheater 102C, thereby bypassing the superheater 102. A superheater bypass valve (bypass valve) 150 is provided on the superheater bypass line 155. The superheater bypass valve 150 is a flow control valve.

[0061] The power plant 1 of this disclosure is provided with a reheater bypass line 165 that connects the outlet of the high-pressure turbine 111A, i.e., the upstream side of the reheater 103A, to the inlet of the intermediate-pressure turbine 111B, i.e., the downstream side of the reheater 103B, thereby bypassing the reheater 103. A reheater bypass valve (bypass valve) 160 is provided on the reheater bypass line 165. The reheater bypass valve 160 is a flow control valve.

[0062] The opening degree of the superheater bypass valve 150 is adjusted to control the steam temperature and steam pressure of the steam supplied to the high-pressure turbine 111A, i.e., the enthalpy of the main steam. When steam flows into the superheater bypass line 155, some of the steam is not superheated by the superheater 102, reducing the power generation (work) of the high-pressure turbine 111A.

[0063] By adjusting the opening of the reheater bypass valve 160, the steam temperature and steam pressure of the steam supplied to the intermediate-pressure turbine 111B and the low-pressure turbine 111C, i.e., the enthalpy of the reheat steam, are adjusted. When steam flows into the reheater bypass line 165, some of the steam is not superheated in the reheater 103, reducing the power generation (work) of the intermediate-pressure turbine 111B and the low-pressure turbine 111C. The amount of power generated is adjusted by adjusting the enthalpy of the steam supplied to each steam turbine 111 based on the required power generation amount.

[0064] Each extraction line of the power plant 1 in this disclosure is provided with extraction flow control valves 182A, 182B, and 182C, respectively. Extraction flow control valve 182 controls the steam flow rate of steam extracted from the intermediate-pressure turbine 111B and the low-pressure turbine 111C and supplied to the low-pressure feedwater heater 122.

[0065] By controlling the extraction flow rate control valve 182 to the open position, the steam flow rate extracted from the exhaust of the intermediate-pressure turbine 111B is increased, and the power generation (work) of the low-pressure turbine 111C is reduced.

[0066] The power plant 1 of this disclosure is provided with a condenser vacuum pressure regulating valve 170 connected to the condenser 112. When the condenser vacuum pressure regulating valve 170 is controlled to the open direction, the pressure inside the condenser 112 is increased. This reduces the power generation (work) of the intermediate pressure turbine 111B and the low pressure turbine 111C.

[0067] Figure 7 shows the control flow of a steam flow control device in several embodiments of the present disclosure. In step S701, the acquisition unit 51 of the steam flow control device 50 acquires the required power generation amount of the power plant 1.

[0068] In step S702, the steam flow rate control device 50 determines whether the requested power generation amount acquired by the acquisition unit 51 is less than the power generation amount corresponding to the first load of the boiler 10. If the requested power generation amount is less than the power generation amount corresponding to the first load, the device proceeds to step S703. On the other hand, if the requested power generation amount is equal to or greater than the power generation amount corresponding to the first load, the device returns to step S701, as it is considered that operation is possible in the conventional dry operation state.

[0069] If the requested power generation is less than the power generation corresponding to the first load (YES in S702), the calculation unit 52 calculates the steam flow rate corresponding to the requested power generation, and the bypass valve openings of the superheater bypass valve 150 and the reheater bypass valve 160 corresponding to the steam flow rate (S703). In step S703, in addition to the bypass valve openings, the calculation unit may also calculate the extraction flow rate control valve opening, which is the opening of the extraction flow rate control valve 182 corresponding to the steam flow rate, the opening of the condenser vacuum pressure control valve 170 corresponding to the steam flow rate, and the operating amount of the vacuum pump 135 (for example, the rotational speed of the vacuum pump 135). One of these values ​​may be calculated, or two or more values ​​may be calculated in combination for control.

[0070] In step S704 of Figure 7, the adjustment unit 53 adjusts the bypass valve opening of the superheater bypass valve 150 so that it matches the value calculated by the calculation unit 52 (for example, the bypass valve opening of the superheater bypass valve 150).

[0071] In step S705, for example, the opening degree of the superheater bypass valve 150 is adjusted to control the amount of power generated by the generator 113 (see Figure 6). When the opening degree of the superheater bypass valve 150 is controlled to the open direction, the amount of steam bypassing the superheater 102 increases, which reduces the enthalpy of the superheated steam supplied to the high-pressure turbine 111A, and thus reduces the amount of power generated (work) by the high-pressure turbine 111A. This makes it possible to reduce the amount of power generated by the generator 113 of the power plant 1 while maintaining a dry operating state.

[0072] In this way, even when the required power generation is lower than the power generation corresponding to the first load, the power output can be controlled, allowing the generator output to be reduced while maintaining a dry operating state. Conventionally, the power generation corresponding to the first load is, for example, 30-35% of the power generation corresponding to the rated load of the boiler 10, but by controlling with the steam flow control device 50 of this disclosure, the generator output can be reduced to, for example, 10-15%.

[0073] To reduce the generator output while maintaining a dry operating state, the operation of transitioning from a dry operating state to a wet operating state, and vice versa, becomes unnecessary. Furthermore, the waiting time required for the power plant 1 and boiler 10 to stabilize during the transition of operating states is eliminated.

[0074] <Note> The steam flow control device, power plant, steam flow control method, and steam flow control program described in the embodiments above can be understood, for example, as follows.

[0075] A steam flow control device (50) according to a first aspect of the present disclosure is a steam flow control device for a power plant (1) which includes bypass lines (155, 165) that bypass steam passing through the heat recovery sections (102, 103) of a boiler (10), and bypass valves (150, 160) that adjust the steam flow rate of the steam passing through the bypass lines, and comprises an acquisition unit (51) that acquires the required amount of power generated by the power plant, a calculation unit (52) that calculates the corresponding steam flow rate and the bypass valve opening degree based on the acquired required amount of power generated, and an adjustment unit (53) that adjusts the opening degree of the bypass valve so that it corresponds to the calculated steam flow rate.

[0076] By adjusting the bypass valve opening to correspond to the steam flow rate based on the power generation requirements of the power plant, the enthalpy of the steam at the steam turbine inlet is adjusted, thereby reducing the generator output while maintaining through-flow operation.

[0077] In the steam flow control device of a second aspect of the present disclosure, in the first aspect, if the required power generation is less than the power generation of the power plant corresponding to the load of the boiler (10) at which the feedwater flow rate of the boiler (10) is set to a lower limit for the feedwater flow rate to protect the furnace wall (101), the adjustment unit (53) may adjust the bypass valve opening to adjust the steam flow rate that bypasses the heat recovery unit while the boiler (10) maintains a once-through operation state.

[0078] Since the steam flow rate is adjusted by adjusting the bypass valve opening while the boiler maintains a once-through operation state, the generator output can be reduced even when the load falls below the No. 1 load without having to perform an operation to switch from once-through operation to circulating operation. Because there is no transition in operating state, the waiting time for the power plant to stabilize after the transition in operating state is eliminated.

[0079] In the steam flow control device of the third aspect of the present disclosure, the heat collection section may be a superheater (102) and / or a reheater (103) in the first or second aspect.

[0080] A steam flow control device according to a fourth aspect of the present disclosure may include, in any of the first to third aspects, an extraction steam flow control valve (182) for adjusting the extraction steam flow rate supplied from a steam turbine (111) to a feedwater heater (122), wherein the calculation unit calculates the extraction steam flow control valve opening degree, which is the opening degree of the extraction steam flow control valve, based on the acquired required power generation amount, and the adjustment unit adjusts the opening degree of the extraction steam flow control valve.

[0081] By adjusting the amount of steam supplied to the steam turbine, the amount of work done by the steam turbine can be adjusted to control the generator output to match the required power generation.

[0082] A steam flow control device according to a fifth aspect of the present disclosure may, in any of the first to fourth aspects, include a condenser vacuum pressure regulating valve (170) and a vacuum pump (135) for adjusting the vacuum level of a condenser (112), wherein the calculation unit calculates the opening degree of the condenser vacuum pressure regulating valve and / or the operating amount of the vacuum pump based on the acquired required power generation amount, and the adjustment unit adjusts the opening degree of the condenser vacuum pressure regulating valve and / or the operating amount of the vacuum pump.

[0083] By adjusting the differential pressure between the steam turbine and the condenser, it is possible to control the steam turbine's workload to obtain a generator output that matches the required power generation.

[0084] A power plant according to the sixth aspect of the present disclosure includes a bypass line for bypassing steam passing through the heat recovery section of a boiler, a bypass valve for adjusting the steam flow rate of the steam passing through the bypass line, and a steam flow control device according to any of the first to fifth aspects.

[0085] A steam flow control method according to a seventh aspect of the present disclosure is a steam flow control method for a power plant comprising a bypass line for bypassing steam passing through the heat recovery section of a boiler, and a bypass valve for adjusting the steam flow rate of the steam passing through the bypass line, wherein a computer performs an acquisition step of acquiring the required power generation amount of the power plant, a calculation step of calculating the corresponding steam flow rate and the bypass valve opening degree, which is the opening degree of the bypass valve, based on the acquired required power generation amount, and an adjustment step of adjusting the opening degree of the bypass valve so that it corresponds to the calculated steam flow rate.

[0086] The steam flow rate control program of the eighth aspect of this disclosure causes a computer to execute the steam flow rate control method described in the seventh aspect. [Explanation of symbols]

[0087] 1. Power plant 10 Boilers 11 Furnace 12 Combustion gas passage 13 Flue 20 Combustion device 21 Burner 22 Fine fuel supply pipe 23. Air register 24. Air ducts 25 Additional Air Ports 26 Additional air ducts 31. Mill (Grinder) 32 Forced draft fan (FDF) 41 Gas duct 42 Air preheater 43 Denitration equipment 44 Dust collection device 45. Induced Draft Fan (IDF) 46 Desulfurization equipment 47 Chimney 50 Steam flow control device 51 Acquisition Department 52 Calculation Section 53 Adjustment part 101 Furnace wall 102 Superheater (heat collection section) 102A 1st superheater 102B 2nd superheater 102C 3rd superheater 103 Reheater (heat absorption part) 103A 1st reheater 103B 2nd reheater 104 Economizer 111 Steam Turbine 111A High-Pressure Turbine 111B Intermediate Pressure Turbine 111C Low-Pressure Turbine 112 Condenser 113 Generator 121 Condensate pump (CP) 122 Low-pressure feedwater heater (feedwater heater) 122A, 122B, 122C Low-pressure water supply heater 123 Boiler feedwater pump (BFP) 124 High-pressure water supply heater 125 Brackish water separator 126 Brackish water separator drain tank 127 Boiler circulation pump (BCP) 132 Extraction shutoff valve 132A, 132B, 132C Extraction shutoff valves 135 Vacuum pump L1 Water supply line L2 Drain water line L3~L5 Steam Line L6 Circulation Line 150 Superheater Bypass Valve (Bypass Valve) 155 Superheater Bypass Line 160 Reheater Bypass Valve (Bypass Valve) 165 Reheater Bypass Line 170 Condenser vacuum pressure regulating valve 182 Extraction air flow control valve 182A, 182B, 182C Extraction Air Flow Control Valves 1100 CPU 1200 Secondary storage 1300 Main storage 1500 Communications Department 1800 Bus

Claims

1. A steam flow control device for a power plant, comprising a bypass line for bypassing steam passing through the heat recovery section of a boiler, and a bypass valve for adjusting the steam flow rate of the steam passing through the bypass line, An acquisition unit that acquires the required power generation amount of a power plant, A calculation unit calculates the corresponding steam flow rate and the bypass valve opening degree, which is the opening degree of the bypass valve, based on the acquired power generation amount. An adjustment unit that adjusts the opening degree of the bypass valve so that it corresponds to the calculated steam flow rate, A steam flow control device equipped with the following features.

2. The steam flow control device according to claim 1, wherein if the requested power generation amount falls below the power generation amount of the power plant corresponding to the load of the boiler at which the feedwater flow rate of the boiler is set to a lower limit for the feedwater flow rate to protect the furnace wall, the adjustment unit adjusts the bypass valve opening to adjust the steam flow rate that bypasses the heat recovery unit while the boiler maintains a once-through operation state.

3. The steam flow control device according to claim 1, wherein the heat collection section is a superheater and / or a reheater.

4. It is equipped with an extraction steam flow control valve that adjusts the extraction steam flow rate supplied from the steam turbine to the feedwater heater, The calculation unit calculates the extraction flow control valve opening degree, which is the opening degree of the extraction flow control valve, based on the acquired required power generation amount. The steam flow control device according to claim 1, wherein the adjustment unit adjusts the opening degree of the extraction gas flow rate adjustment valve.

5. Equipped with a condenser vacuum pressure regulating valve and vacuum pump to adjust the vacuum level of the condenser, The calculation unit calculates the opening degree of the condenser vacuum pressure regulating valve and / or the operating amount of the vacuum pump based on the acquired required power generation amount. The steam flow control device according to claim 1, wherein the adjustment unit adjusts the opening degree of the condenser vacuum pressure adjustment valve and / or the operating amount of the vacuum pump.

6. A bypass line that bypasses the steam passing through the heat recovery section of the boiler, A bypass valve that adjusts the steam flow rate of the steam passing through the bypass line, A power plant comprising the steam flow control device described in claim 1.

7. A steam flow control method for a power plant, comprising a bypass line for bypassing steam passing through the heat recovery section of a boiler, and a bypass valve for adjusting the steam flow rate of the steam passing through the bypass line, The acquisition process involves obtaining the required power generation amount for a power plant, A calculation step that calculates the corresponding steam flow rate and the bypass valve opening degree, which is the opening degree of the bypass valve, based on the acquired required power generation amount, A steam flow control method in which a computer performs an adjustment step of adjusting the opening of a bypass valve so that the opening of the bypass valve corresponds to the calculated steam flow rate.

8. A steam flow rate control program for causing a computer to execute the method of claim 7.

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