US20110094228A1

US20110094228A1 - Method of Increasing the Performance of a Carbonaceous Fuel Combusting Boiler System

Info

Publication number: US20110094228A1
Application number: US12/603,869
Authority: US
Inventors: Zhen Fan; Horst Hack; Andrew Seltzer
Original assignee: Foster Wheeler Energy Corp
Current assignee: Foster Wheeler Energy Corp
Priority date: 2009-10-22
Filing date: 2009-10-22
Publication date: 2011-04-28
Also published as: WO2011048520A2; WO2011048520A3

Abstract

A method of increasing the power of a carbonaceous fuel combusting boiler system includes the steps of (a) feeding carbonaceous fuel into a furnace of the boiler system, (b) feeding oxidant gas into the furnace for combusting fuel to produce exhaust gas, (c) discharging the exhaust gas from the furnace via an exhaust gas channel, (d) conveying a stream of feedwater from a boiler economizer arranged in the exhaust gas channel to evaporating and superheating heat exchange surfaces arranged in the furnace and in the exhaust gas channel for converting the feedwater to superheated steam, (e) expanding the superheated steam in a high-pressure steam turbine for generating power, (f) extracting steam from the high-pressure steam turbine at a decreased rate for preheating the feedwater, (g) conveying steam from the high-pressure steam turbine at an increased rate to a reheater arranged in the exhaust gas channel for generating reheated steam, (h) expanding the reheated steam in an intermediate pressure steam turbine for generating power, and (i) conveying the exhaust gas in the exhaust gas channel from the reheater through a boiler economizer to a gas heater. The heat exchange surface area of at least one of the reheater and the boiler economizer is increased and/or a high pressure economizer is added downstream of the boiler economizer and upstream of the gas heater.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention
The present invention relates to a method of increasing the performance, i.e., the thermal efficiency and/or power of a carbonaceous fuel combusting boiler system.
2. Description of the Related Art
In a carbonaceous fuel combusting boiler system, the flue gas discharged from a furnace along a flue gas channel is cooled down in a heat recovery area (HRA), including superheater (SH) and reheater (RH) sections, downstream of which the heat is recovered by a boiler economizer (ECO) to heat up feedwater, followed by a gas heater (GH), such as an air heater, to heat up oxidant gas for the combustion. The superheated steam is expanded in a high-pressure steam turbine (HPST). At least a portion of the expanded steam is reheated in the RH section and conducted to an intermediate-pressure steam turbine (IPST), and further, to a low-pressure steam turbine (LPST). The expanded steam is cycled back to the boiler via a condenser, a series of feedwater heaters and the boiler ECO.
It is known to increase the thermal efficiency of a carbonaceous fuel combusting boiler system by reducing the stack gas temperature by means of a low pressure economizer (LPECO) arranged downstream of the air heater, or a low pressure or high pressure economizer (HPECO) arranged parallel in the air heater. These alternatives, or combinations thereof, result in increased thermal efficiency due to added low-grade heat recovery and lower discharged flue gas temperature. A difficulty with an LPECO is that to avoid condensation of acid compounds in the flue gas on the heat exchange surfaces of the LPECO, the feedwater, heated by steam extracted from the turbines, has to be initially at a certain temperature, for example, above 120° C. for high sulfur fuel. Such a high water inlet temperature to the LPECO leads to a low heat transfer coefficient, and may result in a significant increase of the LPECO.
U.S. Pat. No. 6,964,167 discloses a method of increasing the peak power of a steam generating power plant by sending a portion of the feedwater to bypass feedwater heaters and causing the portion to mix with heated feedwater just before the boiler economizer. This results in more steam flow through the steam turbine, because of less steam extraction, due to a reduced amount of feedwater flow through feedwater heaters. In this manner, such an arrangement generates more power at a reduced efficiency.
The use of steam extractions from the steam turbines to heat up the condensate and feedwater in the feedwater heaters improves the steam cycle efficiency, because the latent heat of steam is used and carried back to the boiler, which reduces the heat discharged to the condenser and the fuel firing. For the same feedwater temperature increment, the improvement of the steam cycle efficiency decreases with the increase of steam extraction pressure, due to losing more power by losing steam at high pressure. The steam extraction from the high pressure steam turbine section (HPST) decreases the generated power, and also, the steam flow to the reheater.
There is a need for improving the performance of a carbonaceous fuel combusting boiler system by modifying the steam cycle, especially, for supercritical (SC) and ultra supercritical (USC) steam conditions, and for oxy-combustion.

SUMMARY OF THE INVENTION

An object of the present invention is to provide a method of increasing the power of a carbonaceous fuel combusting boiler system without substantially decreasing the thermal efficiency.
In one aspect, the present invention provides a method of increasing the power of a carbonaceous fuel combusting boiler system, the method comprising the steps of (a) feeding carbonaceous fuel into a furnace of the boiler plant at a fuel feeding rate, (b) feeding oxidant gas into the furnace for combusting the fuel to produce exhaust gas, (c) discharging the exhaust gas from the furnace via an exhaust gas channel, (d) conveying a stream of feedwater from a boiler economizer arranged in the exhaust gas channel to evaporating and superheating heat exchange surfaces arranged in the furnace and in the exhaust gas channel for converting the feedwater to superheated steam, (e) expanding the superheated steam in a high-pressure steam turbine for generating power, (f) extracting steam from the high-pressure steam turbine at a decreased rate for preheating the feedwater, (g) conveying steam from the high-pressure steam turbine at an increased rate to a reheater arranged in the exhaust gas channel for generating reheated steam, (h) expanding the reheated steam in an intermediate pressure steam turbine for generating power, and (i) conveying the exhaust gas in the exhaust gas channel from the reheater through a boiler economizer to a gas heater. The method also comprises increasing the heat exchange surface area of at least one of the reheater and the boiler economizer and/or adding a high pressure economizer downstream of the boiler economizer and upstream of the gas heater.
To improve the performance of a carbonaceous fuel combusting boiler system, an approach has been proposed wherein the recovery of heat from the high temperature flue gas is increased, and high-grade steam is saved for expansion in a steam turbine. According to the present invention, this is done by increasing the heat transfer surface area of the boiler economizer (ECO) and/or steam reheater (RH), to compensate for the reduced feedwater temperature and increased reheat steam flow, because of less, or even no, steam extraction from the high pressure steam turbine section (HPST). Alternatively, a high pressure economizer (HPECO) may be added upstream of the gas heater (GH). In this way, additional heat is recovered from the flue gas at a relatively high temperature, upstream of the GH. Simultaneously, high pressure (HP) steam is saved to generate more power.
Due to the increased recovery of heat, the temperature of the flue gas at the inlet of the GH is reduced, which lowers the temperature of the oxidant gas fed to the boiler. The lowered oxidant gas temperature is advantageously compensated for by firing more fuel in the furnace, so as to obtain the original temperature in the furnace. The increase of the flue gas flow due to firing more fuel tends to raise the logarithmic mean temperature difference (LMTD) between the flue gas and the heat transfer medium in the HRA, and thereby, tends to increase the heat transfer to the medium. The additional heat available in the flue gas is partly utilized to heat up an increased flow of RH steam.
According to an embodiment of the present invention, an HPECO is used to recover heat from the flue gas upstream of the GH, and meanwhile, top feedwater heaters are shut off and replaced by this HPECO. The feedwater exit from the HPECO is fed to the boiler economizer. Two economizers, the HPECO and boiler ECO, can be lumped together, if preferred. The HPECO can advantageously be so sized that it heats up the feedwater, at a reduced temperature due to the partly shut off top feedwater heater, to a temperature that results in a flue gas temperature to HPECO that is suitable for a catalyst for selective catalytic NOx reduction (SCR).
Both the peak power operation described in U.S. Pat. No. 6,964,167 and the present approach result in a lowered feedwater temperature, increased reheat steam flow, increased steam flow through the steam turbine, reduced flue gas temperature to the air heater, reduced air preheating temperature, and so, increased boiler firing. The additional power must be paid for by firing additional fuel. From the steam turbine point of view, the extra steam flow to the end stage will be the same for the same amount of steam saved, independent of where it is saved. However, according to U.S. Pat. No. 6,964,167, steam extractions are evenly reduced for all high pressure feedwater heaters, while, according to the present invention, only top feedwater heaters are shut off and replaced by an HPECO, which boosts the efficiency and generates more power for the same amount of steam saved.
The method of U.S. Pat. No. 6,964,167 is applicable for peak power operation for all boiler systems, if desired, without the addition of HPECO. The present invention, with an HPECO upstream of the gas heater, is for efficiency improvement through reducing stack gas temperature, if required, as an alternative to the addition of the LPECO. As a result, the present method can be used to reduce stack gas temperature and can generate more power.
The addition of the HPECO before the air heater adds the freedom to manipulate the feedwater temperature and the flue gas temperature between two economizers, which allows operating an SCR at a desired temperature. The feedwater can advantageously partly bypass the HPECO for SCR temperature control for the entire load range.
The above brief description, as well as other objects, features, and advantages of the present invention will be more fully appreciated by reference to the following detailed description of the currently preferred, but nonetheless illustrative, embodiments and examples of the present invention, taken in conjunction with the accompanying drawing.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a schematic diagram of a boiler system in accordance with an embodiment of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 shows a schematic diagram of a carbonaceous fuel combusting boiler system 10 in accordance with a preferred embodiment of the present invention. The boiler system 10 comprises a boiler 12, which may be, for example, a pulverized coal (PC) boiler or a circulating fluidized bed (CFB) boiler. The boiler 12 shown in FIG. 1 is an air-firing boiler, i.e., it uses air as the oxidant gas, but the boiler may alternatively be an oxycombustion boiler using oxygen or a mixture of oxygen and recirculated flue gas as the oxidant gas. The boiler 12 comprises conventional fuel feeding means 16, such as a fuel chute, for introducing carbonaceous fuel into the furnace 14 of the boiler, air feeding means, such as an air pipe 18, for introducing air into the furnace 14, and an exhaust gas channel 20 for discharging exhaust gas produced by combusting the fuel with the air. The details and types of some elements of the boiler 12, such as the fuel feeding means 16 and air feeding means 18, depend, naturally, on the type of the boiler. Such details, for example, burners, coal mills, means for separately feeding primary and secondary air, are, however, not important for the present invention, and they are, thus, not shown in FIG. 1.
The walls of the furnace 14 are preferably formed as a tube-wall construction, which forms an evaporating heat transfer surface 32, for converting preheated feedwater to steam. The heat recovery area (HRA) of the exhaust gas channel 20 comprises a series of heat transfer surfaces, a superheater (SH) 34, a reheater (RH) 36, a boiler economizer (ECO) 38, a high pressure economizer (HPECO) 40, a combustion gas heater (GH) 42 and a low pressure economizer (LPECO) 44, for recovering heat from the exhaust gas. LPECO is optional for air-firing, but it is required for oxyfuel combustion. The combustion gas heater GH 42 can be of a recuperative or regenerative type, for transferring heat from the exhaust gas to the oxidant gas of the boiler 12. The exhaust gas channel 20 also usually comprises different units for cleaning the exhaust gas from particles and gaseous pollutants, but because they are not important for the present invention, such units are not shown in FIG. 1.
Steam from the evaporating heat transfer surfaces 32 is conducted to the SH 34 to produce superheated steam to be conveyed to the inlet of a high-pressure steam turbine (HPST) 50 for generating power in a generator 46. Expanded steam from the outlet side of the HPST 50 is conveyed along line 48 to the RH 36 for recovering further heat from the exhaust gas. For some cases, primary superheating and reheating surfaces may be located in the exhaust gas channel 20 and additional finishing superheating and reheating surfaces, for example, in the furnace 14.
Another portion of steam from the HPST 50 may be conveyed through a line 74 to a high pressure (HP) feedwater heater 58, or through lines 74 to a group of HP feedwater heaters 68. Reheated steam is conveyed from the RH 36 to the inlet of an intermediate-pressure steam turbine (IPST) 52 for generating power. A portion of steam extracted from the IPST 52 is conveyed along line 76 to another feedwater heater 66, or through lines 67 to another group of feedwater heaters 66. Another portion of steam expanded in the IPST 52 is conveyed to a low-pressure steam turbine (LPST) 54. A portion of steam extracted from the LPST 54 is conveyed along line(s) 78 to a third group of feedwater heaters 60. In practice, the number of steam extraction lines and corresponding feedwater heaters may be larger or smaller than what is described above.
The steam cycle of the boiler 12 comprises, in a conventional manner, a condenser 56 downstream of the LPST 54. The condensed steam, i.e., feedwater of the next steam cycle, is conducted from the condenser 56 through a condenser pump 58, a feedwater pump 64, a de-aerator 62, and a series of feedwater heaters 60, 66, 68. The steam cycle advantageously also comprises an L 44, upstream of the feedwater pump 64, and an HPECO 40 and an ECO 38, downstream of the feedwater pump 64. The LPECO can be upstream or downstream, or in parallel with the feedwater heater 60 connected to the low-pressure steam turbine.
In some embodiments, the HPECO 40 and ECO 38 can be lumped together, but, according to a preferred embodiment of the present invention, they are separate and the exhaust gas channel 20 comprises, downstream of the ECO 38 and upstream of the HPECO 40, a catalyst for NOx reduction (SCR). The use of separate ECO 38 and HPECO 40 makes it possible to adjust their heat transfer surface areas, so that the flue gas temperature between two economizers allows the SCR be operated at an optimum temperature. The feedwater line to the HPECO 40 advantageously comprises a controlled bypass line 72, which allows the feedwater to partly bypass the HPECO 40, for controlling the SCR temperature suitable for the whole load range of the boiler.
According to the present invention, the amount of high temperature steam extraction from the HPST 50, along the line 74, is reduced. The HP steam extraction may be completely stopped, or, at least, it is clearly less than normal in this type of boiler. At the same time, the combined size of the ECO 38 and HPECO 40 is clearly larger than normal in this type of boiler. Increasing the size of the ECO or adding an HPECO upstream of the GH is more efficient than using an LPECO downstream of the GH for the same heat recovered.
According to an aspect of the present invention, the invention relates to retrofitting an existing boiler system by adding an HPECO upstream of the air heater, or adding the heat transfer surface area of the ECO, and decreasing, permanently, or in a controllable manner, the high pressure steam extraction.
The decreasing of the high pressure steam extraction brings about the reducing of the feedwater temperature and the increase of the reheat steam flow. The increasing of the heat transfer area of the reheater and boiler economizer are thus direct results of less or no high pressure steam extraction. Thereby, the decreased high pressure steam extraction also lowers the temperature entering the low pressure economizer. As a main result, the decreased high pressure steam extraction results in more power production, and a lower cost of electricity (COE), as will be shown below.
The new approach is applicable to PC and CFB boilers when using air or oxyfuel firing with subcritical or supercritical steam conditions. Generally, when using advanced steam turbines, the feedwater temperature increases, which results in a high temperature of the flue gas entering the GH, and in a potentially high flue gas exit temperature from the GH to the stack. Therefore, there is a high potential for installing an HPECO (and a LEPCO) to reduce the exit temperature of the flue gas to obtain a better efficiency of the boiler and to generate more power. For oxyfuel firing, the steam saved by decreasing the high pressure steam extraction is advantageously used to drive compressors, such as CO₂compressors, of the boiler system. To more clearly show the advantages of the present invention on the boiler performance, below are described two examples based on model calculations:
Example 1: Air-fired sub-critical PC boiler with reheat.
Example 2: Air-fired super-critical PC boiler with reheat.
In Examples 1 and 2, the boiler ECO is re-sized in accordance with the present invention. In the examples, it has been assumed that both the main steam and reheat steam pressures are kept the same as in a reference plant, which means that the steam turbine (ST) has been modified to accommodate the increased steam flow. In this manner, there is no gain claimed from steam pressure due to an increase of reheat steam flow. It has been assumed that an LPECO is installed downstream of the GH, to set the flue gas temperature the same for comparison. In this manner, there will be no extra gain claimed from different flue gas temperature to the stack when different approaches are analyzed. It has also been assumed for Examples 1 and 2 that the temperature of the hot flue gas is fixed.

Example 1

Air-Fired Sub-Critical PC Boiler

Below are described the main results of a calculation of the effects of the present invention in a sub-critical PC boiler with reheat, fired with lignite fuel. The arrangement of heat exchangers arranged in series in the HRA includes RH, SH, ECO, GH and LEPCO. In this example, the reference case includes steam extraction from an HPST section, which will be shut off in the new case. In the example, the low temperature feedwater is heated up by an enlarged economizer to the same temperature as in the reference case, which results in no change of evaporation duty in the furnace. The heat transfer to the combustion air at the GH is reduced due to a lowered temperature of the flue gas entering the GH. As a result, the boiler fires more fuel to compensate for the low inlet air temperature. Thus, the increased firing of fuel does not increase the total heat flux in the furnace. Due to the increased reheat steam flow, the reheat duty is increased. It is assumed that the IP/LP steam turbine section has been sized up for increased RH steam flow without a pressure increase.
According to the analysis performed, due to the shutting off of the high pressure steam extraction, the temperature of the feedwater decreases by 42° C., from 251° C. to 290° C. At the same time, the economizer duty more than doubles, but the duty of water evaporation and steam superheat are kept unchanged. The RH steam flow and duty increase by 10%. The flue gas temperature to the ECO rises due to the increased firing and flue gas flow, but the flue gas temperature to GH drops due to increased economizer duty, which leads to the lowering of the temperature, by 58° C., of the air introduced into the furnace and a fuel firing rate, which is increased by 7.1%. It is assumed that the 7.1% firing rate increase is in a range of the existing boiler. According to the new approach, the LEPCO duty drops by 40.3%, where an arbitrary 157° C. LPECO exit gas temperature is maintained, for comparison.
As a result, the plant net power increases by 39 MW (6.8%) with a minor efficiency drop of 0.09%. In practice, the final result is a trade-off between the net efficiency and the net power. If no HPECO were added, the feedwater temperature would drop from 251° C. to 209° C. and the steam cycle efficiency would drop by 0.55% points from 48.99% to 48.44%. While, according to the present invention, the drop of the net efficiency is only about 0.1% points, i.e., clearly less than 0.55% points, it is clear that the present invention involves a clear efficiency gain. The cost of energy (COE), estimated by a simple method to be described below, is reduced by 4.2% due to an increase in net power.

Example 2

Air-Fired Super-Critical PC Boiler

Below are described the main results of a calculation of the effects of the present invention in an SC PC boiler, with an RH and a parallel pass HRA. Two cases, named New 1 and New 2, are analyzed, corresponding to the shutting off of one, and one and one-half, correspondingly, of two high-pressure steam extractions from the high pressure steam turbine section.
Due to shutting off of the high pressure steam extractions, the temperature of the feedwater decreases from 298° C. by 32° C. and 52° C. for the cases of New 1 and New 2, the duty of the economizer rises by 60% and 120%, respectively, but the evaporation and superheat is kept unchanged. The RH steam flow and duty increase by 7% and 14%, respectively. The gas temperature to the economizer rises due to increased firing and flue gas flow, but the temperature of the flue gas at the inlet of the GH drops due to increased economizer duty, which leads to a lowering of the air temperature to the furnace and causes an increased firing rate by 5.7% and 10.9%, respectively. The duty of the LPECO drops when using an arbitrary 127° C. LEPCO exit gas temperature, for comparison.
As a result, the plant net power increased in the two cases from 437 MWe by 24 MWe and 46 MWe, with a minor efficiency drop of 0.03% and 0.15% points, respectively. The estimated cost of electricity (COE) is decreased in the two cases by 3.8% and 6.8%, respectively. Here, again, without the addition of the HPECO, the steam cycle efficiency would drop by 0.60% points when the feedwater temperature changes from 298° C. to 246° C., while the net efficiency drops by only 0.15% point due to the gain from the new approach. The final result is, in practice, a trade-off between the net efficiency and net power. In consideration of the very minor difference in efficiency, the gain power is more advantageous in view of the COE.
The COE changes presented above are estimated on the basis of a simple method, where the cost of fuel is assumed to be 25-30%, and the investment cost to be 70-75%. In the total investment, the cost from the boiler system is assumed as 35%, steam turbine as 20%, balance of plant as 25%, solid handling as 8%, and emission control as 12%. From these assumptions, the effect of different options on the COE can be simply estimated, for comparison.
When considering the steam cycle, the steam extraction helps to improve the efficiency. However, the present analyses have surprisingly shown that the shutting off of high pressure steam extraction to lower feedwater temperature can be used to increase the power without considerably decreasing the total efficiency. The gain to be obtained in practice is affected by fuel, ambient condition, and main steam condition, as well as some issues in design or operation. It will also be different in application between a retrofit and a green-field design.
A calculation shows that by using the method of the present invention in oxyfuel combustion, the net power can be considerably increased, while the net efficiency is, at the same time, slightly increased. In oxyfuel combustion, an LPECO is required to maintain the same outlet stack temperature as with air firing, since the GH acts as a recuperator with lower heat duty than in air firing, since the inlet temperature of recycled gas, which is, in oxyfuel combustion heated in the GH, greater than that of air. Also, the recycled gas flow is lower than the air flow. This provides an even greater opportunity to generate more power by adding an HPECO and firing more fuel.
In the examples described above, a new approach has been used, where extra heat in the flue gas is reduced before the GH, through an increase of the heat duty of the ECO, with a low feedwater temperature caused by shutting off steam extractions from HPST, which results in the lowering of the exit flue gas temperature and the production of more power.
While the invention has been described herein by way of examples in connection with what are, at present, considered to be the most preferred embodiments, it is to be understood that the invention is not limited to the disclosed embodiments, but is intended to cover various combinations or modifications of its features and several other applications included within the scope of the invention, as defined in the appended claims.

Claims

1. A method of increasing the power of a carbonaceous fuel combusting boiler system, the method comprising the steps of:

(a) feeding carbonaceous fuel into a furnace of the boiler system at a fuel feeding rate;

(b) feeding oxidant gas into the furnace for combusting the fuel to produce exhaust gas;

(c) discharging the exhaust gas from the furnace via an exhaust gas channel;

(d) conveying a stream of feedwater from a boiler economizer arranged in the exhaust gas channel to evaporating and superheating heat exchange surfaces arranged in the furnace and in the exhaust gas channel, for converting the feedwater to superheated steam;

(e) expanding the superheated steam in a high-pressure steam turbine for generating power;

(f) extracting steam from the high-pressure steam turbine at a decreased rate for preheating the feedwater;

(g) conveying steam from the high-pressure steam turbine at an increased rate to a reheater arranged in the exhaust gas channel for generating reheated steam;

(h) expanding the reheated steam in an intermediate pressure steam turbine for generating power;

(i) conveying the exhaust gas in the exhaust gas channel from the reheater through a boiler economizer to a gas heater; and

(j) effecting at least one of (i) increasing the heat exchange surface area of at least one of the reheater and the boiler economizer and (ii) adding a high pressure economizer downstream of the boiler economizer and upstream of the gas heater.

2. The method according to claim 1, further comprising feeding carbonaceous fuel into the furnace at an increased fuel feeding rate.

3. The method according to claim 1, wherein at least one of (i) the decreased steam extraction rate and increased steam conveying rate and (ii) the increased fuel feeding rate are as compared to a typical earlier use of the same boiler.

4. The method according to claim 1, wherein at least one of (i) the decreased steam extraction rate and increased steam conveying rate and (ii) the increased fuel feeding rate are as compared to a typical use of a similar boiler.

5. The method according to claim 1, further comprising stopping the extracting of steam from the high-pressure steam turbine for preheating the feedwater.

6. The method according to claim 1, wherein the boiler system is a retrofitted boiler and the increase of the heat exchange surface area of the boiler economizer or the heat exchange area of the added high pressure economizer is at least 50% of the original heat exchange surface area of the boiler economizer.

7. The method according to claim 1, wherein the increase of the heat exchange surface area of the boiler economizer or the heat exchange area of the added high pressure economizer is at least 50% of a typical heat exchange surface area of the boiler economizer of a similar boiler system.

8. The method according to claim 1, further comprising adding a high pressure economizer downstream of the boiler economizer and upstream of the gas heater, and arranging an NOx catalyst in the exhaust gas channel downstream of the boiler economizer and upstream of the high pressure economizer.

9. The method according to claim 8, further comprising arranging a controllable feedwater line bypassing the high pressure economizer.

10. The method according to claim 2, wherein at least one of (i) the decreased steam extraction rate and increased steam conveying rate and (ii) the increased fuel feeding rate are as compared to a typical earlier use of the same boiler.

11. The method according to claim 2, wherein at least one of (i) the decreased steam extraction rate and increased steam conveying rate and (ii) the increased fuel feeding rate are as compared to a typical use of a similar boiler.

12. The method according to claim 2, further comprising stopping the extracting of steam from the high-pressure steam turbine for preheating the feedwater.