JP7720682B2 - Waste heat recovery boilers, steam turbine equipment and gasification equipment - Google Patents

Description

The present invention relates to a waste heat recovery steam generator, a steam turbine facility, and a gasification facility.

Integrated coal gasification combined cycle (IGCC) power plants are known as plants that generate combined power by supplying carbon-containing solid fuel, such as coal, into a gasification furnace and partially combusting and gasifying the carbon-containing solid fuel (see, for example, Patent Document 1).

Patent Document 1 discloses a heat recovery boiler equipped with a high-pressure superheater, a high-pressure evaporator, and a low-pressure economizer, and states that a steam turbine is driven by steam supplied from the high-pressure superheater.

Japanese Patent Application Laid-Open No. 2017-206643

A portion of the steam generated by the heat recovery boiler is supplied as auxiliary steam to various equipment (e.g., gasifiers, gas purification facilities, etc.).

Such auxiliary steam is sometimes supplied from the high-pressure turbine outlet, but in the configuration disclosed in Patent Document 1, the pressure at the high-pressure turbine outlet may be designed based on the pressure required for the auxiliary steam. In this case, the steam turbine must be designed taking into account the pressure required for the auxiliary steam, which limits the freedom of design for the steam turbine and can result in the steam turbine not being operated under optimal conditions.

Furthermore, depending on the load of the gas turbine, the temperature of the exhaust gas introduced into the heat recovery steam generator may fluctuate (for example, during partial load). In this case, it may be impossible to extract auxiliary steam at a constant pressure from the same extraction point. For this reason, to be able to extract auxiliary steam at a constant pressure when the temperature of the exhaust gas fluctuates, other extraction points may be provided at positions with higher temperatures and pressures than the extraction point at rated load, and these extraction points may be configured to be switchable. However, configuring the extraction point to be switchable may increase equipment costs and reduce economic efficiency.
In addition, in consideration of partial load of the gas turbine, the extraction point may be located on the high-temperature, high-pressure side of the extraction point at rated load. However, in this configuration, auxiliary steam is extracted from an extraction point with sufficient capacity at rated load, which is one cause of reduced efficiency.

The present invention was made in light of these circumstances, and aims to provide a heat recovery steam generator, steam turbine equipment, and gasification equipment that can extract auxiliary steam at a constant pressure regardless of the load on the gas turbine, and that can operate the steam turbine under optimal conditions regardless of the required auxiliary steam pressure.

In order to solve the above problems, the heat recovery steam generator, steam turbine facility, and gasification facility according to the present invention employ the following measures.
That is, a heat recovery boiler according to one aspect of the present invention is a heat recovery boiler that generates steam from exhaust gas that is guided from a gas turbine and flows through a flow path, and is equipped with a first superheater that superheats steam at a predetermined pressure, a steam pipe connected to the steam outlet of the first superheater, a pressure regulating valve provided on the steam pipe, an auxiliary steam pipe connected to the steam pipe upstream of the pressure regulating valve in the steam flow direction, and a pressure gauge that is provided on the steam pipe upstream of the pressure regulating valve in the steam flow direction and measures the pressure of steam flowing through the steam pipe.

The heat recovery boiler according to this aspect generates steam from exhaust gas guided from a gas turbine and flowing through a flow path, and includes a first superheater that superheats steam at a predetermined pressure, a steam pipe connected to the steam outlet of the first superheater, a pressure regulating valve provided in the steam pipe, an auxiliary steam pipe connected to the steam pipe upstream of the pressure regulating valve in the steam flow direction, and a pressure gauge that is provided in the steam pipe upstream of the pressure regulating valve in the steam flow direction and measures the pressure of the steam flowing through the steam pipe.
This enables the use of a pressure regulating valve and a pressure gauge to control the front pressure of the auxiliary steam pipe (controlling the pressure upstream of the pressure regulating valve using the pressure regulating valve), and steam at a constant pressure can be extracted as auxiliary steam from the first superheater through the auxiliary steam pipe regardless of the load on the gas turbine. The "pressure upstream of the pressure regulating valve" referred to here refers to, for example, the steam pressure of the first superheater, the steam pressure in the steam pipe, and the steam pressure in the auxiliary steam pipe.
Furthermore, when a first evaporator that supplies steam at a predetermined pressure to the first superheater is installed, the pressure in the first evaporator can be adjusted by a pressure regulating valve through front pressure control.
Furthermore, even if a second superheater for superheating steam at a pressure higher than a predetermined pressure is installed upstream of the first superheater in the exhaust gas flow direction, when the steam supplied from the second superheater or the steam discharged from the steam turbine driven by that steam is extracted as auxiliary steam, the steam turbine may not be able to operate under optimal conditions depending on the required pressure of the auxiliary steam, which may result in a decrease in performance of the entire facility. However, by using the steam extracted from the first superheater as auxiliary steam as in this embodiment, the steam turbine can be operated under optimal conditions regardless of the required pressure of the auxiliary steam. This is because the first superheater, which serves as the auxiliary steam supply source, and the second superheater, which serves as the steam supply source for driving the steam turbine, are independent superheaters.
The auxiliary steam is used, for example, as a heating source for fuel gas supplied to a gas turbine.

Furthermore, a heat recovery steam generator according to one aspect of the present invention is equipped with a control unit that determines the opening degree of the pressure regulating valve based on information from the pressure gauge.

The heat recovery steam generator according to this embodiment is equipped with a control unit that determines the opening degree of the pressure adjustment valve based on information from the pressure gauge. This enables front pressure control.

Furthermore, a heat recovery steam generator according to one aspect of the present invention includes a first evaporator that generates steam at the predetermined pressure and supplies the steam at the predetermined pressure to the first superheater, and an extraction pipe that extracts exhaust gas from the flow path downstream of the first evaporator in the gas flow direction.

The heat recovery boiler according to this aspect includes a first evaporator that generates steam at a predetermined pressure and supplies the steam at the predetermined pressure to the first superheater, and an extraction pipe that extracts exhaust gas from a flow path downstream of the first evaporator in the gas flow direction.
As a result, by maintaining the pressure of the first evaporator constant using the pressure regulating valve, the temperature of the first evaporator can be maintained constant. Therefore, the temperature of the exhaust gas in the flow path downstream of the first evaporator in the flow direction of the exhaust gas (particularly, at a position close to the first evaporator) can be maintained constant. Then, by extracting exhaust gas from the flow path downstream of the first evaporator in the flow direction of the exhaust gas, exhaust gas at a constant temperature can be extracted regardless of the load on the gas turbine. The extracted exhaust gas is used, for example, to dry a carbon-containing solid fuel.
In addition, compared to when exhaust gas is extracted from upstream of the first superheater in the flow direction of the exhaust gas, the amount of heat exchanged between the steam and the exhaust gas in the first superheater or the first evaporator can be increased.
The first evaporator may be configured to supply steam to the first superheater connected to the steam pipe, and the pressure (for example, low pressure, medium pressure, high pressure, etc.) is not limited.

In one aspect of the present invention, the heat recovery steam generator has a second evaporator that generates steam at the first pressure, where the predetermined pressure is higher than the first pressure, and the extraction pipe extracts exhaust gas from the flow path between the first evaporator and the second evaporator.

In the heat recovery boiler of this embodiment, the predetermined pressure is set to a pressure higher than the first pressure, and the boiler is provided with a second evaporator that generates steam at the first pressure, and the extraction piping extracts exhaust gas from the flow path between the first evaporator and the second evaporator.
By maintaining the pressure of the first evaporator constant using the pressure regulating valve, the temperature of the first evaporator can be maintained constant. Therefore, the temperature of the exhaust gas in the flow path between the first evaporator and the second evaporator (particularly, the position close to the first evaporator) can be maintained constant. Then, by extracting the exhaust gas from between the first evaporator and the second evaporator, it is possible to extract exhaust gas at a constant temperature regardless of the load on the gas turbine. The extracted exhaust gas is used, for example, to dry a carbon-containing solid fuel.
In addition, compared to when exhaust gas is extracted from upstream of the first superheater in the flow direction of the exhaust gas, the amount of heat exchanged between the steam and the exhaust gas in the first superheater and the second evaporator can be increased.

Furthermore, a steam turbine facility according to one aspect of the present invention includes the above-mentioned heat recovery steam generator provided with a second superheater that superheats steam at a second pressure higher than the predetermined pressure, and a steam turbine driven by steam supplied from the second superheater.

The steam turbine equipment according to this aspect includes the above-mentioned heat recovery boiler provided with a second superheater that superheats steam at a second pressure higher than the predetermined pressure, and a steam turbine driven by steam supplied from the second superheater.
This allows the first superheater, which serves as a supply source of auxiliary steam, and the second superheater, which serves as a supply source of steam for driving the steam turbine, to be independent superheaters, allowing the steam turbine to be operated under optimal conditions regardless of the required pressure of auxiliary steam.

A gasification system according to one aspect of the present invention includes the above-described exhaust heat recovery boiler, a gasification furnace that gasifies a carbon-containing solid fuel, a gas purification system that purifies the product gas gasified in the gasification furnace, and a gas turbine driven by the fuel gas purified by the gas purification system, and the steam extracted by the auxiliary steam piping heats the fuel gas supplied to the gas turbine.

The gasification equipment according to this embodiment includes the above-mentioned exhaust heat recovery boiler, a gasification furnace that gasifies the carbon-containing solid fuel, a gas purification facility that purifies the product gas gasified in the gasification furnace, and a gas turbine driven by the fuel gas purified by the gas purification facility, and the steam extracted by the auxiliary steam piping heats the fuel gas supplied to the gas turbine.
This allows fuel gas with the highest possible temperature to be supplied to the gas turbine, thereby improving the combustion efficiency in the gas turbine.

Furthermore, a gasification facility according to one aspect of the present invention includes the above-described exhaust heat recovery boiler and a gasification furnace that gasifies carbon-containing solid fuel, and the exhaust gas extracted by the extraction pipe dries the carbon-containing solid fuel that is supplied to the gasification furnace.

The gasification equipment according to this embodiment includes the above-mentioned exhaust heat recovery boiler and a gasification furnace that gasifies carbon-containing solid fuel, and the exhaust gas extracted through the extraction pipe dries the carbon-containing solid fuel that is supplied to the gasification furnace. This allows the carbon-containing solid fuel to be dried using exhaust gas at a constant temperature regardless of the load on the gas turbine, thereby avoiding a shortage of drying heat.

The heat recovery steam generator, steam turbine equipment, and gasification equipment of the present invention can extract auxiliary steam at a constant pressure regardless of the load on the gas turbine, and can operate the steam turbine under optimal conditions regardless of the required auxiliary steam pressure.

1 is a schematic configuration diagram showing an integrated coal gasification combined cycle power generation facility according to an embodiment of the present invention. FIG. 2 is a schematic diagram showing the arrangement of heat exchangers and piping of a heat recovery boiler. FIG. 10 is a diagram showing the relationship between the load of the gas turbine and the outlet gas temperature and saturation temperature of the intermediate-pressure evaporator.

The following describes a heat recovery steam generator, steam turbine equipment, and gasification equipment according to one embodiment of the present invention, using diagrams.

[Overall configuration of integrated coal gasification combined cycle power generation facility]
FIG. 1 shows a schematic configuration of an integrated coal gasification combined cycle power generation facility according to this embodiment.
The integrated coal gasification combined cycle (IGCC) plant 1 includes a gasifier 3. The gasifier 3 uses air as an oxidizer and employs an air combustion system to generate combustible gas (produced gas) from carbon-containing solid fuel such as coal. The integrated coal gasification combined cycle plant 1 refines the produced gas generated in the gasifier 3 in a gas refinement system 5 to produce fuel gas, which is then supplied to a gas turbine unit 7 to generate power. In other words, the integrated coal gasification combined cycle plant 1 is an air combustion (air-blown) power generation plant.
Although the present embodiment will be described as air-blown, oxygen-blown may also be used. As the carbon-containing solid fuel supplied to the gasification furnace facility 3, for example, coal is used.

The integrated coal gasification combined cycle power generation facility 1 includes a coal supply facility 9, a gasifier facility 3, a char recovery facility 11, a gas purification facility 5, a gas turbine unit 7, a steam turbine unit 18, a generator 19, and a heat recovery steam generator (HRSG) 20.

The coal supply facility 9 receives coal, a carbon-containing solid fuel, from a coal supply bunker as raw coal, and pulverizes the coal in a coal mill 13 to produce pulverized coal. The pulverized coal produced in the coal mill 13 is pressurized by nitrogen gas, an inert gas for transport supplied from the air separation facility 42, from each pulverized coal hopper 14 via a coal supply line 15 and supplied to the gasification facility 3. An inert gas is an inert gas with an oxygen content of approximately 5% by volume or less. Typical examples include nitrogen gas, carbon dioxide gas, and argon gas, but it is not necessarily limited to approximately 5% or less.

If the coal contains a large amount of moisture, the coal may be dried using exhaust gas extracted from the heat recovery steam generator 20. Details of the extracted gas will be described later.

The gasification furnace facility 3 is supplied with pulverized coal produced by the coal supply facility 9, and char (unreacted coal and ash) recovered by the char recovery facility 11 is returned and supplied for reuse.

A compressed air supply line 41 from the gas turbine unit 7 (compressor 61) is connected to the gasifier facility 3, and a portion of the compressed air compressed by the gas turbine unit 7 is boosted to a predetermined pressure by a booster 68 so that it can be supplied to the gasifier (gasification section) 16. The air separation facility 42 separates and generates nitrogen and oxygen from atmospheric air, and is connected to the gasifier facility 3 by a first nitrogen supply line 43. The first nitrogen supply line 43 is connected to the coal feed line 15 from the coal feed facility 9. A second nitrogen supply line 45 branching off from the first nitrogen supply line 43 is also connected to the gasifier facility 3, and a char return line 46 from the char recovery facility 11 is connected to the second nitrogen supply line 45. The air separation facility 42 is further connected to the compressed air supply line 41 by an oxygen supply line 47. The nitrogen separated by the air separation equipment 42 flows through a first nitrogen supply line 43 and a second nitrogen supply line 45, and is used as a carrier gas for coal and char. The oxygen separated by the air separation equipment 42 flows through an oxygen supply line 47 and a compressed air supply line 41, and is used as an oxidizing agent in the gasification furnace equipment 3.

The gasification furnace facility 3 includes, for example, a two-stage entrained flow type gasification furnace 16. The gasification furnace facility 3 gasifies coal (pulverized coal) and char supplied therein by partially burning them with an oxidizing agent (air, oxygen) to produce a generated gas. The interior of the gasification furnace 16 is pressurized, for example, to 3 to 4 MPa (gauge pressure).
The burners 30 and 31 are provided in two stages, one above the other. A combustor section 32 is provided at a position corresponding to the lower burner 30, and supplies heat for gasification by burning a portion of the pulverized coal. A reductor section 33 is provided at a position corresponding to the upper burner 31, and gasifies the pulverized coal.
A syngas cooler 35 (a product gas cooler) is provided downstream of the reductor section 33, and cools the product gas to a predetermined temperature before supplying it to the char recovery facility 11. Steam is generated in the syngas cooler 35, and the generated steam is guided to a heat recovery steam generator (HRSG) 20.

A product gas line 49 is connected to the gasification furnace equipment 3, which supplies product gas to the char recovery equipment 11, allowing the product gas containing char to be discharged.

The char recovery equipment 11 is equipped with a dust collection equipment 51 and a supply hopper 52. In this case, the dust collection equipment 51 is composed of one or more cyclones or porous filters and is capable of separating char contained in the product gas generated in the gasification furnace equipment 3. The product gas from which the char has been separated is then sent to the gas purification equipment 5 via a gas discharge line 53. The supply hopper 52 stores the char separated from the product gas in the dust collection equipment 51. A char bin 54 is disposed between the dust collection equipment 51 and the supply hopper 52. Multiple supply hoppers 52 are connected to the char bin 54. A char return line 46 from the supply hopper 52 is connected to the second nitrogen supply line 45.

The gas purification equipment 5 purifies the product gas from which the char has been separated by the char recovery equipment 11 by removing impurities such as sulfur compounds and nitrogen compounds.
The gas purification equipment 5 purifies the produced gas to produce fuel gas, which is supplied to the gas turbine unit 7. Since the produced gas from which the char has been separated still contains sulfur components (such as _H2S ), the gas purification equipment 5 removes and recovers the sulfur components using an amine absorbent or the like for effective use.

Specifically, after passing through a COS converter 21, a scrubber 22, and a cooling and scrubbing tower 23, the wastewater is introduced into an _H2S absorption tower 24 where _H2S is absorbed. The absorbing solution that has absorbed _H2S in the _H2S absorption tower 24 is regenerated in an absorbing solution regeneration tower 25 and returned to the _H2S absorption tower 24. The _H2S gas separated from the absorbing solution in the _H2S absorption tower 24 is incinerated in an off-gas combustion furnace 26 and then introduced into a flue gas desulfurization system 27.

The gas turbine unit 7 includes a compressor 61, a combustor 62, and a gas turbine 63. The compressor 61 and the gas turbine 63 are connected by a rotating shaft 64. A compressed air supply line 65 from the compressor 61 is connected to the combustor 62, and a fuel gas supply line 66 is connected to the gas purification facility 5.

A combustion gas supply line 67 is connected between the combustor 62 and the gas turbine 63. The gas turbine device 7 is provided with a compressed air supply line 41 extending from the compressor 61 to the gasifier equipment 3, with a booster 68 installed midway through. Therefore, the combustor 62 generates combustion gas by mixing and burning a portion of the compressed air supplied from the compressor 61 with at least a portion of the fuel gas supplied from the gas purification equipment 5, and supplies the generated combustion gas to the gas turbine 63. The gas turbine 63 then drives the generator 19 by rotating its rotating shaft 64 using the supplied combustion gas.

The steam turbine unit 18, which is included in the steam turbine facility, includes a steam turbine 69 connected to the rotating shaft 64 of the gas turbine unit 7. A condenser 72 is connected downstream of the steam turbine 69. The generator 19 is connected to the base end of the rotating shaft 64. The generator 19 may be disposed between the steam turbine 69 and the gas turbine 63. The exhaust gas line 70 from the gas turbine 63 is connected to the heat recovery steam generator 20, which generates steam by exchanging heat between the feedwater guided from the condenser 72 and the exhaust gas from the gas turbine 63. A steam supply line 71 is provided between the heat recovery steam generator 20 and the steam turbine unit 18. The steam generated by the heat recovery steam generator 20 includes steam generated by heat exchange with the generated gas in the syngas cooler (SGC) 35 of the gasifier 16. Therefore, in the steam turbine device 18, the steam turbine 69 is driven to rotate by steam supplied from the heat recovery boiler 20, which rotates the rotating shaft 64 and thereby drives the generator 19 to rotate.

A chimney 75 is connected to the outlet of the heat recovery steam generator 20, and combustion gas is released into the atmosphere. Gas purification equipment may also be installed at the outlet of the heat recovery steam generator 20.

[Operation of coal gasification combined cycle power generation facility]
Next, the operation of the integrated coal gasification combined cycle power generation facility 1 according to this embodiment will be described.
In the integrated coal gasification combined cycle power generation plant 1, when raw coal (coal) is supplied to the coal mill 13 of the coal supply facility 9, the coal is pulverized into fine particles in the coal mill 13. At this time, if the coal contains a large amount of moisture, the coal is dried by the exhaust gas extracted from the heat recovery boiler 20.

Pulverized coal produced in the coal feeding facility 9 is supplied to the gasifier facility 3 through a first nitrogen supply line 43 by nitrogen supplied from an air separation facility 42. Furthermore, char recovered in a char recovery facility 11 (described later) is supplied to the gasifier facility 3 through a second nitrogen supply line 45 by nitrogen supplied from the air separation facility 42. Furthermore, compressed air extracted from a gas turbine unit 7 (described later) is pressurized by a booster 68, and then supplied to the gasifier facility 3 through a compressed air supply line 41 together with oxygen supplied from the air separation facility 42.
In the gasifier 3, the supplied pulverized coal and char are combusted with compressed air (oxygen) and gasified to generate a generated gas. The generated gas is then discharged from the gasifier 3 through a generated gas line 49 and sent to the char recovery facility 11.

In this char recovery facility 11, the generated gas is first supplied to a dust collection facility 51, which separates the fine char particles contained in the generated gas. The generated gas from which the char has been separated is then sent to the gas purification facility 5 via a gas discharge line 53. Meanwhile, the fine char particles separated from the generated gas are deposited in a supply hopper 52 and returned to the gasification furnace facility 3 via a char return line 46 for recycling.

The product gas from which the char has been separated in the char recovery system 11 is purified in the gas purification system 5 to remove impurities such as sulfur compounds and nitrogen compounds, producing fuel gas. The purified fuel gas is heated by the heater 105 using auxiliary steam extracted from the heat recovery boiler 20 as a heating source. At this time, the fuel gas is heated to a predetermined temperature range (e.g., approximately 200°C). Note that before heating, the fuel gas is at approximately 120°C to 130°C.

The fuel gas heated by the heater 105 may be further heated by a fuel gas heater 80 installed midway along the fuel gas supply line 66. In this case, the fuel gas is heated to approximately 300°C to 600°C. The fuel gas heater 80 uses auxiliary steam extracted from the heat recovery steam generator 20 as its heating source.

The compressor 61 generates compressed air and supplies it to the combustor 62. The combustor 62 mixes the compressed air supplied from the compressor 61 with fuel gas heated by the fuel gas heater 80 and burns the mixture to generate combustion gas. This combustion gas drives the gas turbine 63, which in turn drives the compressor 61 and generator 19 via the rotating shaft 64. In this way, the gas turbine device 7 can generate electricity.

The heat recovery boiler 20 generates steam by exchanging heat between the exhaust gas discharged from the gas turbine 63 and the feedwater supplied from the condenser 72, and supplies the generated steam to the steam turbine device 18. The steam turbine device 18 is rotationally driven by the steam supplied from the heat recovery boiler 20, thereby rotating the generator 19 via the rotating shaft 64, thereby generating electricity.
The gas turbine unit 7 and the steam turbine unit 18 do not have to rotate and drive one generator 19 on the same shaft, but may rotate and drive a plurality of generators on different shafts.

[Configuration of waste heat recovery boiler]
Next, the configuration of the heat recovery steam generator 20 according to this embodiment will be described.
2 shows the heat recovery steam generator 20 in which a plurality of heat exchangers are provided in a flow path 82. Exhaust gas (GT exhaust gas) guided from the gas turbine 63 flows from bottom to top in the figure. The heat recovery steam generator 20 has a three-pressure configuration having, in order from the bottom (upstream side of the GT exhaust gas), high-pressure (second pressure), medium-pressure (predetermined pressure), and low-pressure (first pressure) heat exchangers.
The arrangement of the heat exchangers may be changed as appropriate depending on the specifications of the facility, and the order of the heat exchangers may be reversed or multiple heat exchangers may be installed in parallel.

In the portion of the flow path 82 located upstream of the GT exhaust gas, a high-pressure superheater (second superheater) 93a, a high-pressure evaporator 93b, and a high-pressure economizer 93c are provided in this order from the upstream side of the GT exhaust gas. In addition, a reheater 94 is provided between the high-pressure superheater 93a and the high-pressure evaporator 93b in the flow direction of the GT exhaust gas. Furthermore, a denitration device 90 is provided between the high-pressure evaporator 93b and the high-pressure economizer 93c.
A steam supply line 71 is connected to the steam outlet of the high-pressure superheater 93 a so that steam can be supplied to the steam turbine 69 .

In a portion of the flow path 82 located midstream of the GT exhaust gas, an intermediate-pressure superheater (first superheater) 92a and an intermediate-pressure evaporator (first evaporator) 92b are provided, in that order from the upstream side of the GT exhaust gas. A steam pipe PS1 is provided between the intermediate-pressure superheater 92a and the reheater 94, connecting the steam outlet of the intermediate-pressure superheater 92a to the steam inlet of the reheater 94. A pipe through which steam discharged from the steam turbine 69 is conducted may be connected to the steam pipe PS1. A pressure regulating valve 100 is provided in the steam pipe PS1 upstream of this connection in the steam flow direction.
Furthermore, an auxiliary steam pipe PS2 branches off from the steam pipe PS1 upstream of the pressure regulating valve 100.
Furthermore, the steam pipe PS1 upstream of the branch point of the auxiliary steam pipe PS2 is provided with a pressure gauge 102 capable of measuring the pressure of the steam. Note that the installation location of the pressure gauge 102 is not limited to the location shown in the figure, and it may be provided in, for example, the medium-pressure evaporator 92b (drum).

In the portion of the flow path 82 located downstream of the GT exhaust gas, a low-pressure evaporator (second evaporator) 91b and a low-pressure economizer 91c are provided, in that order from the upstream side of the GT exhaust gas.

A high-temperature extraction pipe PG1 is provided between the medium-pressure evaporator 92b and the low-pressure evaporator 91b, and is configured to extract the GT exhaust gas flowing through the flow path 82 between the medium-pressure evaporator 92b and the low-pressure evaporator 91b. The extraction position via the high-temperature extraction pipe PG1 is preferably close to the medium-pressure evaporator 92b.

A low-temperature extraction pipe PG2 is provided downstream of the low-pressure economizer 91c, and is configured to extract exhaust gas flowing through the flow path 82 downstream of the low-pressure economizer 91c.

The high-temperature extraction pipe PG1 and the low-temperature extraction pipe PG2 are joined together and configured to be led to the coal mill 13 as a single piping system.

[Operation of the heat recovery boiler, steam pipes, and auxiliary steam pipes]
Next, the operation of the heat recovery steam generator 20 according to this embodiment will be described.
High-temperature GT exhaust gas guided from the gas turbine 63 flows from bottom to top through the flow path 82. Each heat exchanger (superheater, evaporator, economizer, reheater, etc.) exchanges heat between the GT exhaust gas and water (including steam) to heat feedwater, generate steam at a predetermined pressure, superheat the steam, etc. In addition, a denitrification device 90 neutralizes harmful substances contained in the GT exhaust gas flowing through the flow path 82.

The low-pressure economizer 91c heats the feedwater supplied from the condenser 72. The low-pressure evaporator 91b generates low-pressure (first pressure) steam using the water heated by the low-pressure economizer 91c.

The intermediate-pressure evaporator 92b generates intermediate-pressure steam using water heated by an intermediate-pressure economizer (not shown). The steam generated by the intermediate-pressure evaporator 92b is superheated by the intermediate-pressure superheater 92a.
The degree of superheating by the intermediate pressure superheater 92a can be set to, for example, the following: That is, the degree of superheating is set to a degree (for example, 10°C or more and 15°C or less) that prevents the auxiliary steam from becoming wet steam due to pressure loss in the pressure regulating valve 100 or temperature reduction while the auxiliary steam is being supplied to the user.

The high-pressure evaporator 93b generates high-pressure (second pressure) steam using water heated in the high-pressure economizer 93c. Furthermore, the steam generated in the high-pressure evaporator 93b is superheated by the high-pressure superheater 93a and then supplied to the steam turbine 69 via the steam supply line 71. Note that if the steam turbine 69 is a two-pressure or three-pressure type, the steam superheated by the high-pressure superheater 93a is supplied to the high-pressure steam turbine.

Next, the operation of the steam pipe PS1 and the auxiliary steam pipe PS2 will be described.
A portion of the steam superheated by the intermediate-pressure superheater 92a is extracted as high-temperature, intermediate-pressure auxiliary steam via the steam pipe PS1 and the auxiliary steam pipe PS2. The auxiliary steam can be supplied to a wide variety of destinations, but one example is to supply it to the fuel gas heater 80 and use it to heat the fuel gas. This allows the fuel gas cooled in the gas purification equipment 5 provided in the gasification equipment to be supplied to the gas turbine 63 at a temperature close to the combustion temperature in the gas turbine 63, thereby improving the efficiency of operation of the gas turbine 63.
The gas turbine 63 is provided, for example, in a gasification facility in which the gas purification facility 5 is provided.

At this time, the pressure of the auxiliary steam supplied through the auxiliary steam pipe PS2 is controlled by so-called front pressure control using a pressure regulating valve 100. This makes it possible to maintain the pressure of the auxiliary steam constant regardless of, for example, the temperature and pressure of the GT exhaust gas, which fluctuate depending on the load on the gas turbine 63.
In addition, by controlling the front pressure using the pressure regulating valve 100, the steam pressure of the intermediate pressure superheater 92a, the steam pressure of the intermediate pressure evaporator 92b, the steam pressure in the steam pipe PS1, etc. are kept constant regardless of the load on the gas turbine 63.
Furthermore, when the pressure of the intermediate-pressure evaporator 92b is kept constant by the front-pressure control, the saturation temperature in the intermediate-pressure evaporator 92b is kept constant. Therefore, the temperature downstream of the intermediate-pressure evaporator 92b (the outlet temperature of the intermediate-pressure evaporator 92b) is also kept constant. As a result, the temperature of the GT exhaust gas heat-exchanged by the intermediate-pressure evaporator 92b is kept constant regardless of the load on the gas turbine 63.

GT exhaust gas extracted from near the outlet of the medium-pressure evaporator 92b through the high-temperature extraction pipe PG1 is mixed with GT exhaust gas extracted through the low-temperature extraction pipe PG2, and after the temperature is adjusted to, for example, between 180°C and 270°C, it is supplied to the coal mill 13 as gas for drying coal.

Here, the opening degree of the pressure regulating valve 100 is determined by the control unit 104 based on pressure-related information obtained from the pressure gauge 102. In other words, the pressure gauge 102 and control unit 104 are configured to monitor the steam pressure upstream of the pressure regulating valve 100, and the control unit 104 is configured to appropriately determine the opening degree of the pressure regulating valve 100.

The control unit 104 is composed of, for example, a CPU (Central Processing Unit), RAM (Random Access Memory), ROM (Read Only Memory), and computer-readable storage media. The series of processes required to realize various functions are stored, for example, in the form of a program on storage media. The CPU reads this program into RAM and executes information processing and arithmetic operations to realize various functions. The program may be pre-installed on ROM or other storage media, provided stored on computer-readable storage media, or distributed via wired or wireless communication means. Examples of computer-readable storage media include magnetic disks, magneto-optical disks, CD-ROMs, DVD-ROMs, and semiconductor memories.

This embodiment has the following advantages.
The pressure regulating valve 100 enables control of the front pressure for the auxiliary steam pipe PS2, and auxiliary steam at a constant pressure can be extracted from the intermediate pressure superheater 92a via the steam pipe PS1 and the auxiliary steam pipe PS2 regardless of the load on the gas turbine 63.
Furthermore, if the steam supplied from the high-pressure superheater 93a or the steam discharged from the steam turbine 69 driven by that steam were extracted as auxiliary steam, the auxiliary steam would have a high degree of superheat and would therefore have to be cooled using spray water. This cooling would lead to heat loss throughout the entire facility, which is undesirable. However, the auxiliary steam extracted from the intermediate-pressure superheater 92a is at a lower temperature than the steam supplied from the high-pressure superheater 93a, etc. This makes it possible to avoid losses due to cooling the auxiliary steam using spray water.

Furthermore, the pressure of the intermediate-pressure evaporator 92b can be maintained constant by the pressure regulating valve 100. This allows the saturation temperature of the intermediate-pressure evaporator 92b to be maintained constant, as shown in FIG. 3 . Therefore, the temperature of the GT exhaust gas in the flow path 82 between the low-pressure evaporator 91b and the intermediate-pressure evaporator 92b (particularly, at a position close to the intermediate-pressure evaporator 92b) can be maintained constant (a temperature equal to or higher than the temperature required for drying coal (T1 in the figure)). By extracting the GT exhaust gas from between the low-pressure evaporator 91b and the intermediate-pressure evaporator 92b, GT exhaust gas at a constant temperature can be extracted regardless of the load on the gas turbine 63. By using the extracted GT exhaust gas to dry coal, the coal can be stably dried using the GT exhaust gas at a constant temperature. If the pressure of the intermediate-pressure evaporator 92b is not controlled, for example, the temperature of the extracted GT exhaust gas may decrease as the load on the gas turbine 63 decreases.
In addition, compared to when GT exhaust gas is extracted from upstream of the medium-pressure superheater 92a, the amount of heat exchanged between the steam and exhaust gas in the medium-pressure superheater 92a and the medium-pressure evaporator 92b can be increased.

In addition, by extracting steam from the intermediate-pressure superheater 92a as auxiliary steam and using steam from the high-pressure superheater 93a as the driving source for the steam turbine 69, the steam turbine 69 can be operated under optimal conditions regardless of the required auxiliary steam pressure.

In the above embodiment, the configuration of the heat recovery steam generator 20 was described using a three-pressure configuration as an example, but it may also be a two-pressure configuration, for example, high pressure and medium pressure.

1. Coal gasification combined cycle power generation facility (gasification facility)
5 Gas purification equipment 16 Gasification furnace 18 Steam turbine device 20 Exhaust heat recovery boiler 63 Gas turbine 69 Steam turbine 82 Flow path 91b Low-pressure evaporator (second evaporator)
92a Medium pressure superheater (first superheater)
92b Medium pressure evaporator (first evaporator)
93a High pressure superheater (second superheater)
100 Pressure regulating valve 102 Pressure gauge 104 Control unit PG1 High temperature extraction piping (extraction piping)
PS1 Steam pipe PS2 Auxiliary steam pipe

Claims (5)

A heat recovery boiler that generates steam using exhaust gas guided from a gas turbine and flowing through a flow path,
a first superheater for superheating steam at a predetermined pressure;
a steam pipe connected to a steam outlet of the first superheater;
a pressure regulating valve provided in the steam pipe;
an auxiliary steam pipe connected to the steam pipe upstream of the pressure regulating valve in the steam flow direction;
a pressure gauge that is provided in the steam pipe upstream of the pressure regulating valve in a steam flow direction and that measures the pressure of steam flowing through the steam pipe;
a first evaporator that generates steam at the predetermined pressure and supplies the steam at the predetermined pressure to the first superheater;
an extraction pipe that extracts exhaust gas from the flow path downstream of the first evaporator in a gas flow direction;
Equipped with
The predetermined pressure is higher than the first pressure,
a second evaporator for generating steam at the first pressure;
The exhaust gas extraction pipe extracts exhaust gas from the flow path between the first evaporator and the second evaporator . a control unit that determines the opening degree of the pressure regulating valve based on information from the pressure gauge;
The heat recovery steam generator according to claim 1, comprising: a heat recovery boiler that generates steam using exhaust gas guided from a gas turbine and flowing through a flow path, the heat recovery boiler comprising: a first superheater that superheats steam at a predetermined pressure; a steam pipe connected to a steam outlet of the first superheater; a pressure regulating valve provided in the steam pipe; an auxiliary steam pipe connected to the steam pipe upstream of the pressure regulating valve in a steam flow direction; a pressure gauge that is provided in the steam pipe upstream of the pressure regulating valve in the steam flow direction and measures the pressure of steam flowing through the steam pipe; and a second superheater that superheats steam at a second pressure higher than the predetermined pressure;
a steam turbine driven by steam supplied from the second superheater;
Steam turbine installations equipped with: a heat recovery boiler that generates steam using exhaust gas that is guided from a gas turbine and flows through a flow path, the heat recovery boiler comprising: a first superheater that superheats steam at a predetermined pressure; a steam pipe connected to a steam outlet of the first superheater; a pressure regulating valve provided in the steam pipe; an auxiliary steam pipe connected to the steam pipe upstream of the pressure regulating valve in the steam flow direction; and a pressure gauge that is provided in the steam pipe upstream of the pressure regulating valve in the steam flow direction and that measures the pressure of steam flowing through the steam pipe ;
a gasifier for gasifying the carbon-containing solid fuel;
a gas purification facility that purifies the generated gas gasified in the gasification furnace;
the gas turbine driven by the fuel gas purified by the gas purification facility;
Equipped with
The steam extracted by the auxiliary steam pipe heats the fuel gas supplied to the gas turbine. The heat recovery steam generator according to claim 1 or 2 ;
a gasifier for gasifying the carbon-containing solid fuel;
Equipped with
The exhaust gas extracted by the extraction pipe is supplied to the gasification furnace, and the carbon-containing solid fuel is dried in the gasification facility.