JP2013204584A - Coal gasification-combined electric power plant and operation control method thereof - Google Patents

Abstract

PROBLEM TO BE SOLVED: To provide a coal gasification-combined electric power plant in which load following capability is improved by increasing a response speed of a steam system, and to provide an operation control method of the coal gasification-combined electric power plant.SOLUTION: A cold water supply system 19 is provided for supplying cold water from a water supply pump 16 to an inlet part of a syngas cooler evaporator 6 while being bypassed. When a load is changed, an opening degree of a cold water supply valve 32 is adjusted to control an evaporation amount in a syngas cooler 3. Furthermore, an opening degree of a syngas cooler steam flow rate control valve 31 is adjusted to control a flow rate of steam to be introduced from a syngas cooler drum 4 to an exhaust heat recovery boiler drum 13.

Description

  The present invention relates to a coal gasification combined power plant and an operation control method thereof, and more particularly, to a coal gasification combined power plant and an operation control method thereof that improve load following performance in the entire plant.

  In a coal gasification combined power plant, a gas turbine is driven using fuel gas generated in a gasification furnace, and steam obtained by heat exchange with the fuel gas and steam obtained by heat exchange with the gas turbine exhaust gas. Is used to drive the steam turbine. In this coal gasification combined power plant, the response speed of the steam turbine is slower than that of the gas turbine, and the load following performance of the entire plant is reduced due to the delay of the steam turbine.

  In Patent Document 1 (Japanese Patent Application Laid-Open No. 2000-303804), in a coal gasification combined power plant, load follow-up due to a time delay until coal reaches a gas turbine combustor after being input into a gasification furnace and converted into purified gas. In order to reduce the delay, a system for bypassing the purified gas to the purified gas combustion device and a system for introducing the combustion gas of the purified gas combustion device into the gas turbine exhaust gas recovery device are provided, and the amount of purified gas bypass is adjusted when the load fluctuates. Thus, a technique for performing a steam turbine load change in advance is disclosed.

JP 2000-303804 A

  In patent document 1, the refined gas combustion apparatus is used at the time of load change, and when use of a purified gas combustion apparatus has restrictions, the technique of patent document 1 cannot be applied. Further, even when the high-temperature gas flow rate to the gas turbine exhaust gas recovery device is increased as in Patent Document 1, it takes time to transfer heat from the high-temperature gas to the steam and to increase the pressure of the steam drum. Arise.

  An object of the present invention is to provide a coal gasification combined power plant with high load following performance and an operation control method thereof by improving the response speed of the steam system.

  In order to achieve the above object, the present invention is obtained by driving a gas turbine using fuel gas generated in a gasification furnace and exchanging heat between the steam obtained by heat exchange with the fuel gas and the gas turbine exhaust gas. In a combined coal gasification combined power plant that drives a steam turbine using the generated steam, the amount of evaporation in the syngas cooler is controlled or the amount of steam in the syngas cooler and the flow rate of steam from the syngas cooler drum are controlled to follow the load. Features.

  According to the present invention, since the evaporation amount and the steam flow rate of the syngas cooler are directly controlled, the response speed of the steam system can be improved, and a coal gasification combined power plant with high load following performance can be obtained. .

1 is a schematic view of a combined coal gasification combined power plant according to a first embodiment of the present invention. Explanatory drawing of the control method in 1st Example of this invention. Explanatory drawing of the control method in 1st Example of this invention. Explanatory drawing of the control method in 1st Example of this invention. The schematic of the coal gasification combined cycle power plant by the 2nd example of the present invention. Explanatory drawing of the fuel conveyance amount in a 2nd Example of this invention, a syngas cooler drum pressure, a syngas cooler drum steam flow, and a steam turbine output.

Embodiments of the present invention are described below with reference to the drawings.
(First embodiment)
The coal gasification combined cycle plant of this embodiment includes a fuel transfer pipe for transferring fuel, a gasification furnace for generating fuel gas by gasifying the fuel, a syngas cooler economizer and a syngas cooler evaporator from the fuel gas. A syngas cooler that recovers heat to generate steam, a syngas cooler drum that recovers steam obtained from the syngas cooler, a circulation pump that circulates the can water of the syngas cooler drum, and a fuel that is unburned by connecting to the syngas cooler From a dust removal device that collects waste gas, a gas purification facility that is connected to the dust removal device to remove unnecessary substances in the fuel gas to produce purified gas, a gas turbine that uses purified gas as a power source, and an exhaust gas from the gas turbine Waste heat recovery boiler that obtains steam, water supply pump that supplies water to the exhaust heat recovery boiler, and exhaust heat that recovers steam obtained from the exhaust heat recovery boiler and the syngas cooler drum Collector boiler drum, steam turbine powered by steam obtained from exhaust heat recovery boiler drum, main steam pipe for directing steam from exhaust heat recovery boiler drum to steam turbine, inlet of syngas cooler evaporator bypassing feed water pump A chilled water supply system for supplying chilled water to the section, a steam turbine output measuring means provided in the main steam pipe, a steam turbine output detecting means for calculating the actual steam turbine output, the actual steam turbine output and the steam turbine load command value A calculation device that calculates the flow rate of the chilled water supply system so that the output deviation is 0 and a chilled water supply valve that adjusts the flow rate of the chilled water supply system based on a command from the calculation device are basic components.

  Further, in this embodiment, the syngas cooler steam bypass system for guiding the steam from the syngas cooler drum to the condenser, the pressure gauge for measuring the syngas cooler drum pressure, the pressure of the syngas cooler drum pressure setting value and the pressure gauge measurement value An arithmetic device that calculates the flow rate of the syngas cooler steam bypass system so that the deviation is zero, a syngas cooler steam bypass valve that adjusts the flow rate of the syngas cooler steam bypass system based on a command from the arithmetic device, and an output deviation of zero First syngas cooler steam flow rate determining means for determining the first syngas cooler steam flow rate command value, and second syngas cooler steam flow rate determining value for determining the second syngas cooler steam flow rate command value so that the pressure deviation becomes zero. And a low value selection of the first syngas cooler steam flow command value and the second syngas cooler steam flow command value. An arithmetic unit for calculating the Shingasukura steam flow, has a configuration provided with the steam flow rate adjusting valve for adjusting the Shingasukura steam flow rate based on the command of the arithmetic unit.

  FIG. 1 shows a schematic diagram of a combined coal gasification combined power plant according to this embodiment. Coal gasification combined power plant includes a gasification part for gasifying fuel, a gas purification part for purifying the obtained gas, a power generation part for extracting power from the purified gas and the obtained steam, and control devices thereof It is composed of

  The gasification part is composed of a gasification furnace 2 and a syngas cooler 3. The gasification furnace 2 gasifies the fuel transported by the fuel transport pipe 1, and the syngas cooler 3 cools the fuel gas by heat exchange with the syngas cooler economizer 5 and the syngas cooler evaporator 6. The water supply to the syngas cooler economizer 5 is supplied from an exhaust heat recovery boiler 12 (low pressure economizer). Circulating water to the syngas cooler evaporator 6 is forcedly circulated by the circulation pump 17 from the syngas cooler drum 4. The steam generated by the syngas cooler 3 is recovered by the syngas cooler drum 4.

  A cold water supply system 19 that supplies cold water to the inlet of the syngas cooler evaporator 6 is provided to be branched from a water supply pump 16 that supplies water to the exhaust heat recovery boiler 12. The cold water supply system 19 is provided with a cold water supply valve 32. In addition, a syngas cooler steam bypass system 20 is provided for releasing steam from the syngas cooler drum 4 to the condenser 18, and a syngas cooler steam bypass valve 33 is installed in the syngas cooler steam bypass system 20.

  The gas refining part is composed of a dust collector 7 that collects unburned components from the fuel gas, and a gas refining facility 8 that removes unnecessary substances to obtain purified gas. The purified gas is supplied to the gas turbine 10 through the fuel pipe 9. A fuel control valve 11 is installed in the fuel pipe 9, and the flow rate of purified gas supplied to the combustor of the gas turbine 10 is controlled by the fuel control valve 11.

  The power generation portion includes a gas turbine 10, an exhaust heat recovery boiler 12, and a steam turbine 15. In the gas turbine 10, the purified gas is burned to obtain power (the generator is not shown). The exhaust heat recovery boiler 12 introduces exhaust gas from the gas turbine 10 and generates steam by heat exchange between the feed water from the feed water pump 16 and the gas turbine exhaust gas. The steam is recovered by the exhaust heat recovery boiler drum 13. The steam from the syngas cooler drum 4 joins the exhaust heat recovery boiler drum 13 via the syngas cooler steam flow rate adjustment valve 31. The steam of the exhaust heat recovery boiler drum 13 is superheated by the superheater of the exhaust heat recovery boiler 12 and supplied to the steam turbine 15 via the main steam pipe 14 to obtain power in the steam turbine 15 (the generator is not shown). doing.).

  In this embodiment, the steam turbine 15 is composed of a high-pressure turbine and a low-pressure turbine, and the exhaust steam of the high-pressure turbine is superheated by the superheater of the exhaust heat recovery boiler 12 and introduced into the low-pressure turbine via the main steam pipe 14. It has come to be. The exhaust steam from the low-pressure turbine is condensed by the condenser 18 and supplied again to the low-pressure economizer of the exhaust heat recovery boiler by the feed water pump 16. In the exhaust heat recovery boiler shown in FIG. 1, the low-pressure drum and the like are not shown.

  Next, the operation / control system in the coal gasification combined power plant of this embodiment will be described with reference to FIG. The connection between the apparatus in FIG. 2 and the combined coal gasification combined power plant is shown in FIG.

  The measured values (flow rate F, pressure P, temperature T) obtained from the steam turbine output measuring means 36 are input to the steam turbine output detecting means 37, and the actual steam turbine output is calculated. In this embodiment, since the gas turbine 10 and the steam turbine 15 are uniaxially configured, the actual output of the steam turbine is calculated based on the measured values (flow rate F, pressure P, temperature T). When the steam turbine 15 and the multi-shaft configuration are separated, the output of the steam turbine 15 can be directly measured.

The output deviation ΔMW between the actual steam turbine output and the steam turbine output command value MWD _ST is input to the chilled water flow rate control means 38, and the chilled water supply valve 32 is adjusted so that ΔMW becomes zero. The cooling water flow rate control means 38 is controlled based on the relationship between the output deviation obtained in advance and the cooling water flow rate.

  Further, the output deviation ΔMW is input to the first syngas cooler steam flow rate determining means 41, and the first syngas cooler steam flow rate command value is determined so that ΔMW becomes zero. Next, the pressure of the syngas cooler drum 4 is measured by the pressure gauge 35, and the pressure deviation ΔP between the measured value and the pressure set value is input to the second syngas cooler steam flow rate determining means 42, and the second is set so that ΔP becomes zero. The syngas cooler steam flow rate command value is determined. The syngas cooler steam flow rate control means 43 selects a low value from the first syngas cooler steam flow rate command value and the second syngas cooler steam flow rate command value, and adjusts the syngas cooler steam flow rate control valve 31. In the first syngas cooler steam flow rate determining means 41 and the second syngas cooler steam flow rate determining means 42, the command value is determined based on the relationship between the output deviation or pressure deviation and the syngas cooler steam flow rate obtained in advance. Has been.

  Further, the pressure deviation ΔP is input to the syngas cooler steam bypass valve control means 40, and the syngas cooler steam bypass valve 33 is adjusted so that ΔP becomes zero. The syngas cooler steam bypass valve control means 40 is controlled based on the relationship between the pressure deviation obtained in advance and the syngas cooler bypass steam flow rate.

  Next, a specific operation method when the load is increased will be described with reference to FIG. The thick line portion in FIG. 3 is involved when the load increases.

  In the present embodiment, the amount of evaporation in the syngas cooler is suppressed by supplying cold water to the inlet of the syngas cooler evaporator at the time of partial load. I try to increase the steam. That is, by supplying cold water to the inlet portion of the syngas cooler evaporator 6 at the time of partial load, the evaporator inlet temperature is lowered and the evaporation amount is suppressed in advance. When the evaporation amount is insufficient at the time of increasing the load, the cold water flow control means 38 closes the cold water supply valve 32 to reduce or stop the supply of the cold water supply amount and increase the inlet temperature of the syngas cooler evaporator 6. As the inlet temperature rises, the amount of evaporation in the syngas cooler increases, and as a result, the amount of steam supplied to the steam turbine can be quickly increased, so that the load following performance is improved.

  In this embodiment, the steam flow rate is increased within a range in which the syngas cooler drum pressure does not fall below the pressure set value by controlling the steam flow rate at the outlet of the syngas cooler drum. That is, the first syngas cooler steam flow rate command value calculated by the first syngas cooler steam flow rate determining means 41 and the second syngas cooler steam flow rate command value calculated by the second syngas cooler steam flow rate determining means 42. The low value is selected by the syngas cooler steam flow rate control means 43. The steam flow control valve 31 is opened based on the syngas cooler steam flow rate command value obtained by the syngas cooler steam flow control means 43, and the steam flow at the syngas cooler drum outlet is increased within a range where the syngas cooler drum pressure does not fall below the pressure set value. I try to let them. Thereby, since the syngas cooler drum pressure is held at the set value, the time required for the drum pressure to rise when the load rises is reduced, and the load following performance is further improved.

  Next, a specific operation method at the time of load drop will be described with reference to FIG. The thick line portion in FIG. 4 relates to the load drop.

  In the present embodiment, the amount of evaporation is reduced by increasing the amount of cold water supplied to the inlet of the syngas cooler evaporator 6 when the load drops and lowering the temperature of the inlet of the syngas cooler evaporator. That is, when the output becomes excessive when the load drops, the chilled water flow control means 38 opens the chilled water supply valve 32, increases the chilled water supply amount, and lowers the inlet temperature of the syngas cooler evaporator 6 to reduce the temperature in the syngas cooler. Reduce evaporation.

  In this embodiment, the steam flow rate is reduced by controlling the steam flow rate at the outlet of the syngas cooler drum. That is, the first syngas cooler steam flow rate determining means 41 throttles the steam flow rate control valve 31 to decrease the syngas cooler steam flow rate. Thereby, the evaporation amount and the steam flow rate are rapidly reduced, and the load following performance is further improved. When the output at the time of load drop is excessive, the first syngas cooler steam flow rate command value calculated by the first syngas cooler steam flow rate determining means 41 is calculated by the second syngas cooler steam flow rate determining means 42. Since the value is lower than the second syngas cooler steam flow rate command value, the first syngas cooler steam flow rate determination means 41 does not select a low value, and the steam flow rate control valve is used. The flow rate command value may be sent directly to 31.

Further, in this embodiment, the syngas cooler drum pressure is lowered by opening the syngas cooler steam bypass valve when the syngas cooler drum pressure rises and letting the steam escape to the syngas cooler steam bypass system. That is, there is a possibility that the syngas cooler drum pressure is increased by restricting the steam flow rate control valve 31. In this case, the syngas cooler steam bypass control means 40 opens the syngas cooler steam bypass valve 33 and releases the steam to the syngas cooler steam bypass system 20 to lower the syngas cooler drum pressure. Thereby, the safe operation of the syngas cooler drum 4 becomes possible.
(Second embodiment)
In this embodiment, the fuel transport pipe is provided with a flow meter, and drum pressure determining means for determining the syngas cooler drum pressure setting value from the flow meter measurement value is provided, and the syngas cooler drum pressure setting value is changed according to the operating situation It is what you do.

  Further, in this embodiment, the drum pressure is determined so that the syngas cooler drum pressure changes with a delay from the flow meter measurement value.

  FIG. 5 shows a schematic diagram of a combined coal gasification combined power plant according to this embodiment. In the first embodiment described above, the syngas cooler drum pressure set value is controlled as a fixed value (set pressure at the rated load). On the other hand, in this embodiment, a flow meter 34 is installed in the fuel transfer pipe 1. In addition, the measured value of the flow meter 34 is input to the drum pressure determining means 39 to determine the syngas cooler drum pressure set value. Other configurations are the same as those of the first embodiment, and a description thereof will be omitted.

  The means for determining the syngas cooler drum pressure setting value will be described.

  FIG. 6 illustrates the fuel conveyance amount, the syngas cooler drum pressure, the syngas cooler drum steam flow, and the steam turbine output in the coal gasification combined power plant of this embodiment. As a comparative example, an operation method in which the syngas cooler drum pressure is not controlled and the syngas cooler drum pressure is determined by the balance between the evaporation amount and the steam flow rate (hereinafter referred to as “transforming operation”) is also illustrated.

  In the coal gasification combined power plant of the present embodiment, the syngas cooler drum pressure set value is set higher than the pressure during the transformer operation at the partial load (a in FIG. 6). Next, the syngas cooler drum pressure set value is determined so that the pressure changes with a delay with respect to the change in the fuel conveyance amount when the load changes (b in FIG. 6). In other words, the syngas cooler drum pressure set value starts to increase as the fuel transport amount increases, but the fuel transport amount has reached the target value (the change has been completed), assuming a delay in the syngas cooler drum pressure change with respect to the change in the fuel gas flow rate. ), The set value is determined so that the syngas cooler drum pressure reaches the target with a predetermined time delay. As a result, the rate of change in pressure is reduced, and the syngas cooler steam flow rate changes preferentially (c in FIG. 6). Since the flow rate of the syngas cooler preferentially changes, the load following performance is improved (d in FIG. 6).

  Here, the higher the pressure set value, the better the load following performance. That is, by increasing the pressure setting value, the rate of change of the syngas cooler drum pressure is reduced, the syngas cooler steam flow rate is preferentially changed, and the load following performance is improved. On the other hand, the lower the pressure set value, the lower the saturation temperature in the syngas cooler drum and the temperature difference between the syngas cooler drum water temperature and the fuel gas increases, thereby improving the plant efficiency at the partial load. As a result, by changing the pressure setting value, the operation that emphasizes the efficiency at the time of partial load (setting the pressure setting value low) and the operation that emphasizes the load following performance (setting the pressure setting value high) are selected. It becomes possible.

  Even if the pressure setting value is lowered to emphasize the efficiency at the time of partial load, the syngas cooler drum pressure setting value is determined so that the pressure changes with a delay with respect to the change in the fuel transport amount when the load changes. Since the rate of change in pressure can be reduced, it is possible to suppress a decrease in load following performance.

1 ... Fuel transfer pipe
2 ... Gasification furnace
3 ... Syngas cooler
4 ... Syngas cooler drum
5 ... Syngas cooler economizer
6 ... Syngas cooler evaporator
7 ... Dust collector
8 ... Gas purification equipment
9 ... Fuel piping
10 ... Gas turbine
11 ... Fuel control valve
12 ... Waste heat recovery boiler
13 ... Waste heat recovery boiler drum
14 ... Main steam piping
15 ... Steam turbine
16 ... Water supply pump
17 ... Circulation pump
18 ... Condenser
19 ... Chilled water supply system
20 ... Syngas cooler steam bypass system
31 ... Syngas cooler steam flow control valve
32 ... Cold water supply valve
33 ... Syngas cooler steam bypass valve
34 ... Flow meter
35 ... Pressure gauge
36 ... Steam turbine output measuring means
37 ... Steam turbine output detection means
38 ... Cooling water flow control means
39 ... Drum pressure determining means
40 ... Syngas cooler steam bypass valve control means
41 ... First syngas cooler steam flow determining means
42. Second syngas cooler steam flow determining means
43 ... Syngas cooler steam flow control means

Claims (9)

  A fuel transport pipe for transporting fuel, a gasification furnace for gasifying the fuel to generate fuel gas, and a thin gas generating steam by recovering heat from the fuel gas by a syngas cooler economizer and a syngas cooler evaporator A gas cooler, a syngas cooler drum that collects steam generated by the syngas cooler, a gas turbine that uses the fuel gas as a power source, an exhaust heat recovery boiler that obtains steam from the exhaust gas of the gas turbine, and the exhaust heat recovery boiler A water supply pump that supplies water, an exhaust heat recovery boiler drum that recovers steam obtained from the exhaust heat recovery boiler and the syngas cooler drum, a steam turbine that uses steam obtained from the exhaust heat recovery boiler drum as a power source, and A main steam pipe for guiding steam from the exhaust heat recovery boiler drum to the steam turbine; A chilled water supply system that supplies chilled water to the inlet of the cooler evaporator, a chilled water supply valve that adjusts the flow rate of the chilled water supply system, and a direction that eliminates an output deviation between the actual output of the steam turbine and the load command value of the steam turbine. A coal gasification combined power plant, comprising: a control device that controls an opening degree of the cold water supply valve. In claim 1,
A steam flow rate adjusting valve for adjusting a steam flow rate obtained from the syngas cooler drum, and a first syngas cooler steam flow rate command value determining means for determining a first syngas cooler steam flow rate command value so that the output deviation becomes zero. The second syngas cooler steam flow rate command value is determined so that the pressure deviation between the pressure gauge provided in the syngas cooler drum and the pressure set value of the syngas cooler drum and the measured value of the pressure gauge becomes zero. And a control for controlling the opening degree of the steam flow control valve by selecting a low value of the first syngas cooler steam flow command value and the second syngas cooler steam flow command value. And a coal gasification combined cycle power plant. In claim 2,
A syngas cooler steam bypass system that directs steam from the syngas cooler drum to the condenser of the steam turbine, a syngas cooler steam bypass valve that controls the flow rate of the syngas cooler steam bypass system, and a pressure provided in the syngas cooler drum And a control device for controlling the opening of the syngas cooler steam bypass valve in a direction that eliminates a pressure deviation between a pressure setting value of the syngas cooler drum and a measured value of the pressure gauge. Gasification combined power plant. In claim 2 or 3,
A coal gasification combined power plant comprising: a flow meter provided in the fuel transfer pipe; and a drum pressure determining means for determining a pressure setting value of the syngas cooler drum from a measurement value of the flow meter. In claim 4,
The coal gasification combined power plant characterized in that the drum pressure determining means determines the pressure set value so that the syngas cooler drum pressure changes with a delay from a measured value of the flow meter. In claim 1, 2, 3, 4 or 5,
The gas turbine and the steam turbine are coaxially configured, and the actual output of the steam turbine is calculated based on the steam turbine output measuring means provided in the main steam pipe and the measurement value obtained by the steam turbine output measuring means. A coal gasification combined cycle power plant, comprising: A gas turbine is driven using a fuel gas generated in a gasification furnace, and a steam turbine using steam obtained by heat exchange with the fuel gas and steam obtained by heat exchange with the exhaust gas of the gas turbine In the operation control method of the coal gasification combined cycle power plant that drives
An operation control method for a combined coal gasification combined power plant, wherein the load is followed by controlling an evaporation amount in a syngas cooler that performs heat exchange with the fuel gas when the load changes. A gas turbine is driven using a fuel gas generated in a gasification furnace, and a steam turbine using steam obtained by heat exchange with the fuel gas and steam obtained by heat exchange with the exhaust gas of the gas turbine In the operation control method of the coal gasification combined cycle power plant that drives
An operation control method for a coal gasification combined power plant, wherein, when the load changes, the load is followed by controlling an evaporation amount in a syngas cooler that performs heat exchange with the fuel gas and a steam flow rate from the syngas cooler drum. In claim 7 or 8,
During partial load, by supplying cold water to the syngas cooler evaporator inlet of the syngas cooler, the inlet temperature of the syngas cooler evaporator is lowered to suppress the amount of evaporation in the syngas cooler, and when the load increases, the cold water supply An operation control method for a combined coal gasification combined cycle plant, wherein the amount of evaporation is increased by decreasing or stopping to increase the amount of steam flowing into the steam turbine.

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