Steam Power Stations for Electricity and Heat Generation
4.1 Pulverised Hard Coal Fired Steam Power Plants .1 Energy Conversion and System Components.1 Energy Conversion and System Components
4.1.2 Design of a Condensation Power Plant
Figure 4.3 shows the simplified schematic design of a modern pulverised coal fired power station unit.
The fuel, coal, is transported from the coal storage area of the power station to the coal bunkers, which are arranged inside the boiler house and have a storage capacity of up to 1 day. Feeders transport coal from the bunkers to the mills for drying and pulverising. The milling fineness of the pulverised coal is adjusted according to the requirements of the firing. The combined drying and pulverising process of hard coal fired furnaces uses hot air that is heated up to 350–400◦C in an air preheater.
The high moisture content of brown coals requires hot flue gas for drying.
The pulverised coal is transported to the burners by the transport air flow, which is also used for the drying process. The transport air is further used in the combustion process as primary air. Complete combustion of the fuel is achieved by injecting secondary air, heated in the preheater to 300–400◦C, into the furnace.
In the furnace, the pulverised coal burns almost completely, radiating heat to the furnace walls, producing flame temperatures between 1,400 and 1,600◦C. The volumetric flow increases about 10-fold in the process, while it decreases again to nearly the input volume in the flue gas cooling path. The furnace wall, made of
Eco Reheater SH
Evaporator Feed water
Live steam Reheater Reheater
HP MP G LP
Condenser
LP- Pre-heater
HP- Pre-heater
Feed water tank
Separator
Coal bunker Feeder
Ash extractor
Ammonia
Mill fan
FD fan Coal- x
mills
Air heater
Electrostatic precipitator
Induced-draught fan (ID fan) DeNOX - unit
Steam generator
Turbine generator
Cooling tower
Stack
Water/condensate Steam Air Gas Coal
FGD- unit
Fig. 4.3 Schematic diagram of a hard coal fired thermal power station
76 4 Steam Power Stations for Electricity and Heat Generation tightly welded membranes, forms the evaporative heating surface, which vaporises the feed water. After the flue gases are cooled to about 1,200–1,300◦C at the end of the furnace, they are further cooled down by the convective heating surfaces of the superheater (SH), the reheater (RH) and the feed water preheater, also called the economiser. Then nitrogen is removed from the flue gas in a DeNOx unit at a temperature range of 300–400◦C. In the air heaters the flue gases transfer their residual heat to the combustion air, during which they are cooled to the exit flue gas temperature of the steam generator.
For further cleaning, the flue gas is conducted through an electrostatic precipita- tor (ESP) to remove dust and, through a flue gas desulphurisation unit, to meet the allowed sulphur dioxide emission standards. The gases are discharged to the envi- ronment via a stack or natural-draught cooling tower. One or more induced-draught fans transport the flue gas from the furnace to the outlet. In the course of retrofitting measures in various power plants, further series-connected induced-draught fans have been added to the existing equipment to transport the flue gas through the desulphurisation and DeNOx units. In new power stations, equipped with flue gas desulphurisation and DeNOx units from the outset, one or more induced-draught fans are connected in parallel to overcome the pressure loss of all installations and components in the flue gas train.
In the steam generator, the energy released in combustion is transferred to the steam – water cycle, and the enthalpy of the steam is converted into mechanical work by the turbine. The turbine exhaust steam is turned to water in the condenser.
The steam – water cycle is a substantial parameter in the overall design of the power plant. The thermodynamic data of the water – steam cycle is the basis for the steam generator and turbine configurations and determine the power plant’s effi- ciency.
Condensate pumps transport the condensate to the feed water tanks via low- pressure preheaters (LP preheaters), which are heated by steam from the lower pressure-staged turbine extraction. In the feed water tanks, the condensate is further preheated and degassed by steam from the mid-section turbine extraction in a direct- contact heater. The high-pressure feed water pump sets the operating pressure in the water – steam section of the boiler and transports the feed water to the boiler inlet via the high-pressure preheaters, which are heated by steam from the upper pressure turbine extraction stages. The feed water is preheated to the entry temperature of the boiler in 6–9 stages. In the preheater, the extraction steam is cooled, condensed and possibly supercooled and drained back into the condensate or feed water flow before the preheater. The higher the feed water temperature of the respective preheating stage is, the higher the boiling temperatures have to be, and hence the extraction pressure of the associated extraction steam flow. The last preheating stage before the boiler is fed with steam taken from the cold reheater in a conventional design or from the HP turbine extraction in an advanced design.
In the boiler, the preheated feed water is further heated in the economiser, the last convective heating surface in the flue gas path, and then conducted to the evaporator heat exchanger surface. The superheater heats the steam coming from the evaporator up to exit temperature of the superheater, i.e. to the level of the so-called live steam
4.1 Pulverised Hard Coal Fired Steam Power Plants 77 temperature. The level of the turbine entry temperature is slightly lower, by the amount of the temperature drop in the connecting high-pressure steam piping. After partial expansion in the HP turbine, most power plants heat the steam up to levels such as the live steam temperature or higher in a so-called reheater (exchanging heat with the flue gas). Higher temperatures in the reheater are possible due to the lower pressure.
In the condenser, the turbine exhaust steam condenses, with the waste heat being transferred to the cooling water circuit. Closed cooling water circuits are mostly equipped with natural-draught cooling towers for the re-cooling of the water. The buoyancy in the cooling tower makes the heated cooling air flow upwards after it has taken up heat from the cooling water in a trickle cooler. The heated cooling air exits to the environment via the cooling tower mouth at the top.
4.1.3 Development History of Power Plants – Correlation Between Unit Size, Availability and Efficiency
The block power station was born out of the need for higher power plant capacities (due to increasing energy demands), changing expectations with respect to lower investment costs and the desire for a higher reliability in power supply. Besides other parameters, it is, in particular, the
• unit output,
• efficiency and
• availability
that describe the development of the block power station unit.
Given the high availability of each of the large plant parts, modern hard coal fired power plants are generally designed as block units, meaning all the process units are contained together in one “block”. The direct physical interactions of steam generators, turbines and auxiliary installations involve less investment because of shorter connecting pipes. In addition, the pressure and heat losses are lower than the range-type power stations that were common earlier in the 1900s. In range- type power stations, several boilers feed one steam range which can supply several turbines.
From the early 1950s, condensation power plants were built as block units with simple reheating for base and for intermediate loads. At the beginning, the unit capacities were some 60 MW or more; live steam and reheater temperatures were at 525◦C, while the live steam pressure was at about 125 bar.
The maximum block capacity rose with the maximum capacities of single plant components. Step by step, the power station unit has been supplemented by addi- tional components and plants. Today, the largest unit capacities are 1,010 MW in Europe, which will increase to 1,100 MW by 2010, and 1,300 MW in the USA (see Fig. 4.4) (Eitz 1996; Smith 1996). Conventional live steam conditions proven in operation are 180–250 bar and 540◦C, with reheater temperatures at 540◦C as
78 4 Steam Power Stations for Electricity and Heat Generation Fig. 4.4 Maximum unit
capacity
well. All over the world, one can see a trend towards higher live steam conditions.
Figure 4.5 shows the development of live steam conditions in Germany.
With the unit capacities and the live steam conditions increasing, the efficiency levels rose as well (see Fig. 4.6). The power station costs decreased, depending on
Fig. 4.5 Evolution of live steam conditions of German plants
4.1 Pulverised Hard Coal Fired Steam Power Plants 79 Fig. 4.6 Evolution of the
efficiency level of German plants
the capacity, making efficiency-enhancing measures become more cost-effective.
Higher efficiencies of large units can also be explained physically: specific surface heat losses of boilers and losses of rotating machinery due to leakiness diminish with higher capacities.
Availability of technology becomes important with increasing capacities, the need for more pollution control equipment and the desire for technical develop- ments towards higher efficiency levels. High availability is desirable for reliable electricity production and is a necessary comparative criterion of technical develop- ments. Further development of steam power plants should therefore be based on the comparable availability of proven power plant concepts.
Besides being economically significant, availability also has an environmental impact. The lowest CO2 emission level is achieved by a generation system when the power plants with the highest efficiency are of comparably high availability.
Lower availability rates, in consequence, deteriorate the gain in efficiency. Until the second half of the 1960s, the development of the power plant unit efficiency was sustained by development of the plant’s thermal efficiency. There are numerous scientific studies on this subject (Knizia 1966). In the 1970s, the efficiency was further enhanced along with increasing unit sizes from 150 via 300 to more than 600 MW. At the same time, the availability rate was increased and thus the effect of the efficiency enhancement improved.
While the flue gas particulate collector was a fixed component in the plant design from the very beginning, the plants were augmented by flue gas desulphurisation units only from the mid-1970s and by nitrogen oxide control devices from the mid- 1980s on. The availabilities of these components were at first low but then increased as they developed. For example, in Germany gas cleaning devices for SO2and NOx
80 4 Steam Power Stations for Electricity and Heat Generation Table 4.1 Data for the reference power plant (Spliethoff and Abr¨oll 1985)
Power plant unit
Gross rated power 740 MW
Net rated power 690 MW
Efficiency 39%
Mechanical capacity of the feed pump 21 MW
Auxiliary power requirement 50 MW
Mode of service Intermediate load range (170 starts p.a.) Steam generator
Capacity 2250 t/h (625 kg/s)
Construction Once-through boiler
Live steam condition 209 bar, 535◦C
Steam condition after reheater 39.6 bar, 535◦C Entry temperature of feed water 250◦C Firing
Air ratio 1.3
Flue gas temperature 130◦C
Coal mills 4×74 t/h
Forced-draught fan (FD fan) 1×100%
Induced-draught fan (ID fan) 1×100%
Range of control 40–100%
Steam generator efficiency 94%
Boiler feed pump 1×100% duty turbine-driven pump
1×50% duty motor-driven pump Steam turbine generator
Construction Operational mode
Condensation turbine with single reheating modified sliding-pressure operation with throttling of the intake valves (5%) Turbine pressure sections/number of
extractions
4 (1×HP,1×MP,2×LP)/6
Live steam condition 190 bar/530◦C
Exhaust steam pressure 0.0549 bar
Back-cooling system
Cooling tower construction Natural-draught wet-type cooling tower
Heat rejection 894 MW
Air temperature 10◦C, max. 35◦C
Cold water temperature 16.6◦C, max. 29◦C Flue gas cleaning unit
Particulate collector Electrostatic precipitator (ESP) Nitrogen oxide control device High-dust catalyst before air preheater Desulphurisation unit Wet desulphurisation with limestone
Flue gas off-take Stack, reheat after FGD unit
became required by law in 1988 with the inception of ordinances of the German Bundesimmissionsschutzgesetz (BImSchG), or Federal Pollution Control Act. Any power plant with emission levels exceeding the prescribed standards concerning dust, SO2and NOxmay be operated only at limited duty or not at all.
4.2 Steam Generators 81 Different national standards in some countries have in consequence differing nitrogen oxide control methods. Higher limits make it possible to develop and apply less complex emission control techniques as well as the more advanced technolo- gies. In such situations, more lenient emission standards may mean higher energy conversion efficiencies and lower losses as compared to power stations with stricter emission standards.
The environmental stipulations that have an impact on the efficiency of inland power plants also limit the use of cooling water and once-through cooling cycles.
Comparisons of efficiency and availability across national borders should take these differences into account.