large-scale electrical generation systems

8/10/2019 Large-scale Electrical Generation Systems

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5.1.1 IntroductionThis chapter describes the various technologies for

converting the chemical energy of fossil fuels into

electricity. Only large-scale plants (indicatively,

Pe100 MW) producing solely electrical energy and

powering high-voltage distribution grids will be dealt

with here. Other technologies addressed in following

chapters are: medium-to-large size plants for the

combined production of electrical energy and heat

(cogeneration, see Chapter 5.2) and small-scale

distributed generation systems interfaced to middle- and

low-voltage distribution grids (see Chapter 5.3).

Evolution of global demand for electrical energy

One constant trend common to all societies and

economies is the continuous, progressive increase in

demand for electrical energy, in both relative and

absolute terms, due to its being the cleanest, most highly

valued energy available. Over the last 30 years (Fig. 1),

the global demand for electrical energy has increased by

over 50% (from less than 10% to more than 15% of the

total energy used worldwide) in contrast with the direct

exploitation of fuels, which has decreased considerably

(for the most part coal, although to some extent, oil)

despite the fact that oil products still maintain their

dominant role in the field of transportation. The

consumption rates shown in Fig. 1 refer to all energy

sources (fossil, nuclear, hydroelectric and other

renewable sources). The values for fossil fuels

refer to the energy content of the raw fuels, before

being subjected to any refinement process, andinclude cogeneration applications. Fig.2 shows the

electricity consumption trends by sector in Mtoe

(1 Mtoe11,630 TWh). Consistent growth has been

experienced in all sectors (the average yearly increase in

global consumption over the last decade is in the order

of 500 TWh/yr). The greatest increases have been in

377VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY

5.1

Large-scale electrical

generation systems

coal13.4%

naturalgas

14.6%

combustiblerenewablesand waste*

14.3%

electricity9.5%

other**1.7%

* prior to 1994 combustible renewables and waste final consumption has been estimated** other includes geothermal, solar, wind, heat, etc.

1973 2003

other**3.5%

oil46.5%

coal7.4%

naturalgas

16.4%

combustiblerenewablesand waste*

14.0%

electricity16.1%

oil42.6%

Fig. 1. Evolutionof total global energyconsumption by sourcefor 1973 and 2003

(IEA, 2005).


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residential uses, the service sector, public services and

agriculture (indicated as other sectors in Fig. 2), all areas

where the trend towards ever-increasing dependence on

electricity, a clean, efficient and therefore highly-prized

vector, is irreversible. (The portion of electricity demand

currently satisfied by cogeneration systems are, instead,

not included in Fig. 2.)

It is widely held that, barring any unforeseen

obstacles, this thirty-year trend will continue, essentially

unabated, in coming decades. Therefore, it is anticipated

that the demand for new generation capacity will

continue at a constant rate of over 100 GW/yr, which

will thus have to be met by new installations. The

resulting new capacity will be directed, in part, to

satisfying the abovementioned increasing global demand

for electricity and, in part, to replacing obsolete systems,particularly coal-fired plants (over 60% of the coal-based

capacity installed in Europe is over 20 years old, a

figure that in the United States reaches 80%). Although

a large number of these new plants will be located in

developing countries (particularly China and India),

significant growth in the number of plants is also

foreseen in heavily industrialized areas. For example,

Europe, whose installed capacity at the turn of the

millennium was in the order of 600 GW, is expected to

increase its overall capacity by nearly the same amount

by 2030 (i.e. 550 GW). About two-thirds of this is

destined to replace obsolete central power stations, whilethe remaining one-third will go to satisfying the increase

in demand of electrical energy. Analogous growth

scenarios are also expected in the United States as well.

Contribution of fossil fuels to satisfying the demand

for electrical energy

Fig. 3 shows the breakdown of the energy sources

used to meet the global demand for electrical energy and

its evolution over time. Although the period considered

(1973-2003) includes the boom years of nuclear power

(a phenomenon that is not likely to be repeated in

the next twenty years), the overall contribution of fossilfuels remained consistently very high; among fossil

fuels, the use of natural gas rose substantially, while the

role of coal increased only slightly and the consumption

of oil products fell sharply.

Table 1 shows the breakdown of the energy sources

supplying electricity according to geographical area;

the overall electrical energy produced amounts to

16,670 TWh and the contribution of fossil fuels is over

60% in all areas, with the exception of South America,

where hydroelectric systems play a dominant role. The

overall share of fossil fuels is in the order of 11,000

TWh (29.2% from natural gas, 60.4% from coal and

10.4% from oil). Apart from fossil fuels, the only

technologies that contribute significantly to current

electricity generation are large-scale hydroelectric and

nuclear plants; wind, solar and geothermal sources

furnish only marginal contributionsIn the likely scenario of business as usual, the role

of fossil fuels is expected to grow even further in

coming years; although the use of renewable energy

sources is expected to increase greatly, their

contribution, in absolute terms, will remain limited.

Moreover, it is unlikely that nuclear or hydroelectric

technologies will manage to maintain their current share

of energy production. The standard energy sources for

meeting the worlds demand for electricity will continue

to be coal and gas. For this reason, a large part of this

chapter is dedicated to plants based on these two types

of fuels.

The dominant technology of the Twentieth century:

the external-combustion steam cycle

In the Twentieth century, the dominant technology

for the production of electrical energy from fossil fuels

was the steam power station; its two fundamental

features are external combustion and the steam cycle.

There are many advantages in combining external

combustion with the steam cycle; the most important

ones are the following:

As combustion is external, the path followed by the

fuel and the combustion products is completelyisolated from the working fluid. This enables using

378 ENCYCLOPAEDIA OF HYDROCARBONS

POWER GENERATION FROM FOSSIL RESOURCES

worldelectricitydemand

(M

toe)

0

200

400

600

800

1,000

1,200

1971 1973 1975 1977

industry

transport

other sectors

1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003

Fig. 2. Evolutionof world electricitydemand from 1971 to 2003(IEA, 2005).


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any type of fuel, even low quality ones, such as coal,

orimulsion (an aqueous bitumen emulsion produced

in the Orinoco Belt in Venezuela), heavy oil fractions

and, in the near future, bituminous schists, without

contaminating or compromising the integrity of the

surfaces in contact with the working fluid of the

power cycle (turbine blades, heat transfer surfaces).

As the power cycle consists of a closed loop (the

fluid in the cycle always remains the same: water), it

is possible to use a fluid that undergoes a phase

change, condensing from the gaseous state to the

liquid phase when it releases heat, thereby obtaining

two important advantages that are precluded in gas

cycles and are peculiar to steam cycles. These are,

firstly, that heat transfer to the environment takes

place through an isothermal process, with theconsequent possibility of exploiting only small

temperature differences during the entire process of

heat exchange between the working fluid and the

environment and, secondly, that the working fluid is

compressed in the liquid phase; thus, very high

operating pressures can be attained with modest

energy expenditure.

These advantages make the steam thermodynamic

cycle a high-quality one. That is, high efficiencies can be

achieved, even when operating at relatively modest

maximum temperatures; an average steam plant,

operating at a maximum temperature in the order of

550C, can attain net electrical efficiencies (electrical

energy/fuel chemical energy) of over 40%. Such

efficiency is superior to that obtainable even with todays

most modern industrial gas turbine plants which,

however, operate at maximum temperatures near

1,400C and are based on turbines operating under

extremely complex fluid dynamic conditions.

On the other hand, the combination of externalcombustion and the steam cycle also involves

considerable disadvantages:

External combustion calls for heat transfer surfaces

operating at temperatures higher than the


LARGE-SCALE ELECTRICAL GENERATION SYSTEMS

worldelectricitygeneration

(T

Wh)

0

1971 1973 1975 1977

other

hydro

nuclear

thermal

1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003

4,000

2,000

8,000

6,000

12,000

10,000

14,000

16,000

18,000Fig. 3. Breakdownby energy sourceof global electricitygeneration (IEA, 2005).

Table 1. Breakdown (by percent) of electricity generation by energy source and geographical area

(data 2003)

Energy source EuropeNorthAmerica

SouthAmerica

Africa Asia Oceania World

Hydroelectric 14.5 13.2 55.7 17.7 12.5 15.3 16.3

Wind 0.8 0.3 0.0 0.1 0.1 0.3 0.4

Solar 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Thermoelectric 61.5 67.5 40.5 79.6 77.2 83.4 67.3

Geothermal 0.1 0.3 0.7 0.1 0.4 1.0 0.3

Nuclear 23.0 18.7 3.0 2.5 9.8 0.0 15.8

Total energy generatedper continentin relation to world

production

32.7 27.6 6.3 3.0 28.8 1.6 100.0


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temperature of the working fluid. The high pressures

attained by steam require primary heat exchangers

made of metal. This limits the maximum possible

temperature of the power cycle, thereby reducing the

efficiency of the cycle. The current state of the art

allows for maximum steam temperatures of about

600C, in contrast with 540C in the 1980s and 560-580C in the 1990s. The technological and,

especially, economic difficulties associated with

increasing the maximum temperature to 700C, for

example, seem insurmountable at present (Table 2)

given that increasing the temperature calls for tubes

with higher thickness to diameter ratios, on the one

hand, because of the greater pressure to be withstood,

and on the other, because at such high temperatures

materials become less resistant.

The steam cycle is not suitable for the adoption of

very high temperatures, not only because of the

technological and economic aspects mentioned

above, but because the critical point of water (373C)

is decidedly lower than the temperatures permissible

in the current state of the art of metal materials

science. Even adopting cycles with various stages of

superheating, the fraction of heat transferred to the

relatively low-temperature cycle remains high. In

principle, this obstacle could be overcome via two

different approaches: either by using a different

working fluid with a higher critical temperature than

water, or by completely abandoning steam cycles in

favour of gas cycles, which allow heat to beintroduced into the high-temperature cycle without

any limitations on pressure.

Although neither of the two approaches, which have

been under investigation for several decades, appears

technologically mature or economically competitive,

they could achieve net efficiencies of over 50%. In the

first case, current research is focussed on liquid

metal/water steam binary cycles (Fig. 4), with

intermediate bleedings from the topping turbine

(potassium) to minimize the temperature differences

between the two cycles. The second approach focusses

on solutions based on high-temperature ceramic

exchangers that transfer high-temperature heat to

compressed air before it enters the turbine, where it

expands. Combustion is initiated and the exhaust fumes

are ducted to the ceramic exchanger and then to the

steam section. Such solutions (Fig. 5) are termed EFCCs

(Externally Fired Combined Cycles). In confirmation of

the excellent characteristics of water/steam as the

working fluid for medium-to-low temperature

thermodynamic cycles, both approaches call for the

adoption of a combined cycle: the primary cycle(topping) absorbs high-temperature heat, while a

secondary cycle (bottoming) utilizes steam as the

working fluid.

Emerging alternative technologies: internal

combustion power plants

Until twenty years ago, internal combustion plants

found little application in large fossil fuel f ired power

stations, the only exception being gas turbines,

adopted because of their low cost and their ability to

quickly adapt their output to load variations. Thus,

they served as backup units to satisfy peak demandand were consequently operated only for short periods

(often as little as hundreds or even tens of hours per

year). High fuel (often gas-oil) costs and their low

efficiencies discouraged their use for energy

generation to satisfy base or average loads (mid-merit,

see below). With the advent of combined gas/steam

cycles and the widespread distribution of natural gas,

the picture changed radically, and a significant

proportion of world orders for new installations over

the last twenty years are based on the use of natural

gas in combined cycles.

From a conceptual perspective, adopting internalcombustion offers important advantages (all linked to



tem

perature(C)

0

100

200300

400

500

600

700

800

900

entropy (kJ/kg K)0 21 3 4 5 6 7 8 9

potassiumcycle

steamcycle

Fig. 4. Schematic representationof the temperature-entropy plot of a potassium-watersteam binary cycle.

Table 2. Comparison of the unit costs

of superheater tubing for steam generatorsoperating at 600C and 700C

Tmax 600C Tmax 700C

Dimensions, mm(inner diameterthickness)

22132 17560

Material P91 Alloy A617 A130

Material cost per kg 5.5 48.0

Material cost per metre 1,100 16,600

Ratio of costs per metrefor equal gauge 1 24


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the lack of a heat exchanger, given that the working fluid

itself undergoes combustion):

The walls in contact with the hot fluid are several

orders of magnitude smaller than those of the

primary exchanger in an external combustion system

of equal power, as the pressures they must withstand

are far lower; thus, even very expensive materials can

be used in their construction without however

incurring excessive costs.

Cooling mechanisms can be implemented to

maintain the surfaces in contact with the working

fluid at very low temperatures; for example, in

modern gas turbines, the gases enter the turbine at

temperatures in the order of 1,400C, while the

temperatures of the superalloys constituting the

blades never exceed 850-900C.

The disadvantages of internal combustion stem fromthe fact that the working fluids must necessarily be air

before combustion and then, following combustion,

exhaust gases. As in all gas cycles, this means that

isothermal processes are not possible. The stage of heat

transfer to the environment, in particular, takes place at

constant pressure through the release into the

atmosphere of hot gases through a completely

irreversible process, which heavily penalizes the

thermodynamic quality of the cycle, and therefore its

efficiency. Moreover, the internal combustion solution

requires the use of clean, high-quality fuels, which

generally means higher specific costs. In practice,modern gas turbines call for gaseous fuels (natural or

synthetic gas) or suitably purified liquid fuels. The

combination of low efficiency and expensive fuel makes

simple gas cycle turbines unattractive for base-load

electrical generation, despite their being the simplest,

most compact and least expensive of all plant designs.

Therefore, the best solution to date is represented by

the combined cycle, which, as mentioned, involves

combining an open upper cycle (costitued by a gas

turbine) and a closed lower cycle (made up of a steam

cycle that recovers the heat of the turbine exhaust gases),

able to exploit the specific advantages of the twodifferent cycles involved. As in open cycles, combined

cycles make use of internal combustion, which enables

the attainment of high temperatures, while, like a closed

steam cycle, they release heat into the environment at

low temperatures, for the most part through the

isothermal, isobaric process of condensation, while the

remaining heat exchange occurs through dispersion into

the atmosphere of the products of combustion, by then at

temperatures (about 90-100C) near that of the

environment (Fig. 6).

The two cycles are coupled through the transfer of

the heat of the turbine exhaust gases to the steam cycle.

The heat transfer process is optimized, which signifies

that the temperature difference between the medium

releasing heat and the medium that receives heat is

minimized at all points of the exchange, thanks to the



electricgenerator 1

1,250C

570C

420C

air

120C

600C

HRSG

600C

1,400C

steam turbine

filter

fuel

gas turbine

electricgenerator 2

ceramicheat

exchanger

compressor

combus

tor

Fig. 5. Schematicrepresentationof an EFCC(HRSG, Heat RecoverySteam Generator).

temperature

entropy

heat inputto gas cycle

gas cycle

steam cycle

heat released to environment

ambient temperature

heat from gas cycle

to steam cycle

Fig. 6. Temperature-entropy diagramof a combined cycle.


8/46

multiple evaporation levels. The result (see Section

5.1.4) is a net electrical efficiency which, in the current

state of the art, reaches values of about 58% under

nominal conditions. Such levels are unattainable by

closed cycles.

In the case of clean fuels (liquid or gas), the most

logical solution is to carry out combustion in a gasturbine inserted in a combined cycle. The most

widespread technique for using low-quality liquid or

solid fuels with a gas turbine is gasification (see Section

5.1.5) by means of various system designs integrated

with the combined cycle, all known as IGCC (Integrated

Gasification Combined Cycles). In the case of solid

fuels, an interesting alternative approach (which,

however, has yet to produce any meaningful applications

to date) is the use of pressurized fluid-bed combustors;

the pressurized products of combustion are first cleaned,

then allowed to expand in a gas turbine which in a

normal combined cycle fed the exhaust gases with a

recovery boiler, and the steam cycle may also receive

additional heat from coal combustion.

Future prospects

In the decades to come, a large deal of electricity will

continue to be produced by power stations fed with coal

and natural gas. Over the last decade, the application of

natural gas-fired combined cycle technology has

increased considerably, exceeding that of steam-based

systems in terms of newly built or contracted plants.

This trend is likely to continue throughout most of theworld, especially where environmental issues are most

keenly felt (Europe, Japan, and the United States, where

natural gas is expected to have a predominant role over

coal). The prospects in the emerging countries (e.g.

China, India) are different; coal will continue to be the

energy source of choice for electrical energy generation.

Future energy choices, in particular the relative

contributions of natural gas and coal to electrical energy

production, will be heavily influenced by a number of

factors. The price trends of the two fuels, which are

difficult to predict, will play a fundamental role in the

choices made by energy suppliers; recent years have

seen significant fluctuations (Fig.7) not only in the priceof natural gas (traditionally influenced by oil prices), but

also in that of coal, the cost of which had previously

been held quite stable.

Furthermore, it is interesting to compare the specific

costs associated with electrical energy generation by two

modern plants: a coal-fired steam-electric power station

and a natural gas fired combined cycle. For the purposes

of the comparison, the following hypotheses have been

assumed:

Both are state-of-the-art, in terms of both energy

performance and pollution-control.

Both are base-load power stations, that is, operating

for 7,000-8,000 h/yr.

The specific costs of the fuels during the lifetime of

the plants do not diverge significantly from the

average values recorded over the last f ive years

(assumed in the following to be 2.2 /GJ for coal,

and 5 /GJ for natural gas).

The results reveal a situation of substantial balance,

with overall costs (investmentoperationfuel) in the

order of 45 /MWh, although the breakdown of the

various contributing items for the two cases is

significantly different (Table 3). In brief, while theinvestment and operation costs account for over 63% of

the overall cost in coal-fired plants, for natural gas fired

combined cycles the most important factor by far is

represented by fuel costs. Therefore, if the specific cost

of natural gas were to rise significantly beyond the

assumed value, the coal solution would be more



price(/GJ)

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

natural gas

coal

heavy fuel

1991

-1

1992

-3

1993

-4

1995

-1

1996

-2

1997

-3

1998

-4

2000

-1

2001

-2

2002

-3

2003

-4

2003

-9

2004

-2

2004

-7

2004-12

2005

-5

yearyear

0

Fig. 7. Price of fossil fuelsover the last fifteen years.


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competitive, while the opposite would be true in the

event of a return to Twentieth century natural gas prices.

With reference to the type of plant, one important

determining factor is that the demand for electrical

energy varies widely over the course of a year, with

demand peaks that are normally more than double the

minimum. Even if a portion of the necessary production

adjustments to load can be covered by hydroelectric

systems or pumping storage systems, a significant

number of new fossil fuel fired plants will be required to

operate ever more frequently at varying loads, with

frequent shut-downs and restarts. Power stations areconventionally grouped into different functional

categories on the basis of the equivalent hours

of yearly operations (ratio between the energy produced

yearly and nominal net power capacity): base-load

(5,000 h/yr), middle-load (between 2,000 and

5,000 h/yr) and peak-load (2,000 h/yr).

Coal plants only operate well at base load. For

peak-load plants, the best solution is a simple-gas

cycle turbine, as they have low capital costs and are

highly flexible. Analyses of all reasonable costs

scenarios reveal that combined-cycle systems are

unbeatable for satisfying middle loads (Fig. 8), whilethe relative economic competitiveness of natural-gas

combined cycles and coal-fired plants for operation

as base-load stations depends for the most part on

the cost of natural gas, as has already been pointed

out above.

As far as the evolution of regulations on plant

emissions is concerned, following increased interest in

environmental issues over the last few decades,

electricity suppliers have been forced to meet ever

more stringent requirements for toxic emissions; not

only have the emissions standards required by law

become stricter by the decade, but local situations oftenimpose even tougher limits than general governing

regulations. Moreover, the limits set on some power

stations under construction are often an order of

magnitude lower than those currently required; for

example, at the Hekinan plant in Japan (21,000 MW)

the required specific emissions of NOx and SOx are

below 30 and 75 mg/Nm3 respectively (both referred to

6% O2 molar concentration in the exhaust gases)values that were unthinkable up to only a few years

ago. Obviously, such a trend has made plants more

expensive and complex to run and has moreover

prompted the development and adoption of the cleanest

possible fuelnatural gasfor new plant construction.

However, not even natural gas-fired combined cycles

are immune to the need to adopt more expensive and

complex solutions; although todays most sophisticated

premixed flame burners can attain NOx emissions

levels below 30 mg/Nm3 (with 15% O2), some

regulations (for example, in Japan and California) call

for limits that can only be reached by Selective

Catalytic Reduction (SCR).

The energy costs considered in Table 3 do not take

into account the possibility of a carbon tax. If, following

concerns over climatic changes, the cost items

associated with electrical energy production were to

include an expense linked to CO2 emissions, the relative

economic competitiveness of coal and gas described

above could change radically (Fig. 9). First of all, a

relatively moderate carbon tax would favour natural gas

(which discharges substantially lower specific emissions

than coal-fired plants) whereas a high carbon tax wouldinstead favour near-zero emission solutions (nuclear

power). As far as fossil fuels are concerned, it would be

necessary to resort to the capture and subsequent

geological storage of the carbon dioxide discharged, a

process known as Carbon Capture and Sequestration

(CCS), which would be possible for both natural gas and

coal plants, although such technology involves

significant investment costs and disadvantages in terms

of efficiency.



peaking powerstation (simple cycle

gas turbine)

coal powerstation

combined cycle(high natural

gas price)

combined cycle(low naturalgas price)

yearlyoperatingcosts

yearly equivalent hours of operation

Fig. 8. Plot of yearly operating

costs-equivalent hours for different typesof fossil fuel power stations.

Table 3. Percentage contribution of various cost items

to the overall cost of the electricity generated

by a modern pulverized-coal

steam turbine plant and a modern natural gas

combined-cycle power station.

ItemUltrasupercritical

coal duststation

Natural-gascombined

cycle

Capital investment 48.1 18.6

Operationsand Maintenance

14.7 8.0

Fuel 37.2 73.4

Total 100.0 100.0


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5.1.2 Steam electric power stations

To date, power plants based on the water/steam

thermodynamic cycle are the undisputed leaders in the

production of electrical energy. They are adaptable to a

wide variety of primary energy sources: fossil fuels of

various types and qualities, nuclear fuel, renewable

sources such as biomass, solar thermal energy, urban

solid waste and others.

The adaptability of the steam cycle to different fuels

stems from the fact that such systems operate in a closed

cycle (see above), which protects the machinerys mostdelicate components (turbine, heat exchangers) from

contact with the contaminated products of combustion.

Moreover, two important characteristics of steam cycle

have been exploited for the adoption of modest

technologies. One is the capacity of water steam to take

up and give off heat at a constant temperature during a

phase change, enabling the achievement of acceptable

efficiency levels without the need for high temperatures

and the other is that the work output of the expansion

phase that generates power is much higher than the work

input required to compress water.

These two characteristics have been known since theindustrial revolution and have determined the feasibility

of converting thermal energy into mechanical energy.

Although steam technology is well known and

widespread today, after more than two centuries it is still

undergoing important developments in terms of

improving energy-conversion efficiency and reducing

polluting emissions that are discussed below.

Evolution of the water steam cycle

In its simplest form, the steam cycle (Rankine cycle;

Fig. 10 A), involves the following four processes: a) an

increase in the pressure of the working medium from a

low to a high value realized by a pump; b) conversion of

water into steam at constant high pressure (isobaric); this

is carried out in a heat exchanger (Steam Generator,

SG), where the working fluid is heated and evaporated to

generate saturated steam; c) expansion, during which

pressure falls, producing mechanical work; d) isobaric

and isothermal conversion of the water back to the liquid

phase, carried out in a heat exchanger (condenser).

Heat is absorbed by the working medium in part at

varying temperatures, during heating of the liquid up to

saturation, and in part at a constant temperature, during

evaporation. Such a cycle has numerous drawbacks:

The necessary heat is absorbed by the liquid at low

temperatures, which is not very efficient. In fact, the

higher the temperature at which heat is absorbed, the

higher the efficiency of heat input and, vice versa,

the lower the temperature at which it is released to

the environment, the higher the efficiency of heat

output or return. In the case of heat input and returnat variable temperatures, the parameter utilized to

describe the process is the mean transformation

temperature, defined as Dh/Ds (where h ands arethe specific enthalpy and entropy of the fluid as it

evolves during the cycle).

During expansion, the fluid remains within the phase

transition curve and thus droplets of liquid are

formed, which apart from decreasing cycle

efficiency, also create problems in the turbine; as the

liquid particles are far more dense than steam, their

impacting the turbine blades causes erosion, which

drastically reduces the lifetime of the turbine. In practice, it is impossible to reach even relatively

high temperatures. Increasing the pump delivery

pressure, and thereby the evaporation pressure,

would increase the corresponding temperature;

however, this would also exacerbate the

aforementioned negative effects of droplet

formation.

The first drawback can be overcome, at least in part,

by means of Feed Water Heating (FWH); in order to

properly heat the low-temperature fluid (the feed water),

a low temperature heat source is used rather than the

valuable high-temperature heat produced by combustionof the primary energy source. This low-temperature heat



costofelectricity(/MWh)

30

40

50

60

70

80

90

carbon tax (/t CO2)

natural gas fuelled combined cycle (4 /GJ)

natural gas fuelled combined cycle (6 /GJ)

USC coal fuelled power station

natural gas fuelled combined cycle with CO2sequestration (4 /GJ)

natural gas fuelled combined cycle with CO2sequestration(6 /GJ)

IGCC fuelled by coal with CO2 sequestrationwind farm

nuclear power station

0 20 40 60 80

Fig. 9. Effects of a carbon tax on electricity costsfor various conversion technologies.


11/46

source is produced by extracting an appropriate anount

of steam from the turbine, theoretically at a pressure

corresponding to the temperature to which the liquid is

to be heated (actually, it is extracted at a slightly higher

temperature to ensure a reasonable DTfor heat transfer).Steam condenses in the exchanger (Fig. 10 B), heating the

liquid at high pressure, and the condensate is sent to thehot well of the condenser. The regeneration process is

shown in Fig. 10B for a single-feed water heater,

whereas, in practice, it is usually accomplished by the

rather high number (6-10) of feed-water heaters.

The technique of SuperHeating (SH) steam is

decisive (Fig. 10 C) in increasing the temperature at

which heat is introduced into the cycle and, at the same

time, in solving the problem of the presence of liquid in

the turbine. Although superheated steam increases

efficiency by raising the mean temperature at which heat

is absorbed by the working fluid, its implementation

involves subjecting plant components to very high

temperatures. Thus, high temperature materials must be

utilized. Repeatedly superheating (RH, ReHeating)

steam is the key to obtaining high conversion

efficiencies because it allows the adoption of very high

evaporation pressures (and therefore even higher

temperature heat input to the cycle), without incurring

the serious problems caused by liquid in the turbine.

Performance

The performance of a thermodynamic cycle (its

efficiency, in particular) is determined by the

performance of the plant components (turbine, boiler,etc.), as well as the operating parameters and the type of

cycle. An analysis of plant components will be taken up

later whereas the following will examine the main

operating parameters that determine the

thermodynamics of the cycle as well as the plant design.

Maximum cycle temperature. An increase in the

temperature of the steam leaving the superheater and the

reheaters yields considerable increases in the efficiency

of the cycle, in that, as already stated, it raises the mean

temperature at which heat is introduced into the cycle.

Moreover, it reduces the likelihood of liquid forming in

the turbine by shifting the expansion curve of the steam

toward the right (see again Fig. 10C).

The steam temperatures obtainable are limited by the

heat-resistance of the metal materials used to build the

plant components: the superheater and reheater tube

banks, the superheated steam collectors, the pipelines

connecting the boiler to the turbine, the turbine control

valves, the turbine casing and rotary blades (at least in

the zones in contact with the high-temperature steam).

Adopting particularly sophisticated materials, such as

for example, the nickel-based superalloys used for the

rotor blades of the gas turbines, is however prohibitive,owing to both the intrinsic cost of the materials and the

sophisticated technology needed to manufacture these

components. Nowadays, the materials most often used in

modern plants are ferrite steels, although austenitic

steels are also used to some extent; current research aims

to develop the technologies for the widespread adoption

of austenitic steels in the near future. The type of

material used sets rather rigid limits to the steam

temperatures achievable (Table 4); such temperatures

vary from 538C for standard steam-turbine units (with

some applications reaching 565C) to 590-610C for the

most advanced technologies available. Some noteworthyresearch programmes aim to extend such limits to

700C, but industrial applications at such temperatures

will probably not be forthcoming until 2020, at the

earliest. A rough estimate of the efficiencies that can be

expected by adopting different materials, in relation to

the maximum practicable temperatures and pressures,

reveals that at 540C and 170 bar pressure, efficiency is

42%, while at 560C and 250 bar, it is 43-44%, and at

600C and 300 bar it is 45%, and lastly, at 700C and

350 bar, it can become as high as 47-48%.

Maximum cycle pressure. At any given maximum

temperature, increasing the maximum cycle pressurealso involves an increase in the mean temperature at



A S

SG

T

T

T

B S

SG

C S

SG

SH

saturated cycle

regenerative cycle

superheated cycle

Fig. 10. Conceptual schemes for three types of steam cycles.


12/46

which heat is introduced into the cycle and therefore, as

mentioned above, higher efficiency. However, the effects

of liquid forming in the turbine must be evaluated in that

increasing the pressure shifts the expansion curve of the

steam to the left; the beneficial effects are therefore only

fully realized when adequate superheating is carried out

(in terms of the number and of the temperature reached).

The ability to operate plants at pressures above the

critical pressure of steam (221.2 bar) is based on well-

established technology, known for decades. Thus, in

practice, both subcritical (generally at 170 bar), as well

as supercritical systems (usually at 240-250 bar) are

currently in use. Even higher pressures, in the order of

300 bar, have recently been reached (known as USC,

Ultra Super Critical) and applied in some of the mostadvanced power stations. The pressures obtainable are

obviously limited by the necessary dimensions of the

components involved (steam generator tube banks,

collectors and pipelines, tube banks of the hottest

regenerators, steam generator tube connections, live

steam valves, very high-pressure turbine sections). The

thickness, and consequently the bulk and cost, of the

components under pressure therefore become a

determining factor; it is worthwhile recalling that, given

equal diameter, the thickness of a pipeline is directly

proportional to the pressure, while the thermodynamic

benefits depend on the temperature (the average atwhich heat is input), which has an approximately

logarithmic relation to the pressure. Thus, large increases

in pressure are needed to achieve relatively small

increases in temperature. Therefore, pressures

significantly beyond 350 bar are not to be expected even

in future systems.

Minimum cycle pressure. Low pressure and

consequently low condensation temperatures are

accompanied by significantly higher cycle efficiency.

The value of the condensation pressure is in fact

determined by the availability of coolant at the plant site:

indeed, an abundant supply of water for cooling thecondenser is one of the main criteria for choosing a site

to build a plant. Large power stations are often situated

near the sea or other large bodies of water. Whenever

possible, very low condensation pressures are adopted.

Some Scandinavian plants utilize a nominal

condensation pressure of 0.028 bar (23C) and achieve

very high efficiency values. Moreover, In Italy, in the

most advanced Italian plants, given a nominal seawater

temperature of 18C, the pressure is relatively low

(0.042 bar, which corresponds to 29.8C). In general, for

any given temperature of the water available as coolant,

the difference between the coolant temperature and that

of condensation (DTC) is determined by economicconsiderations, bearing in mind the increasing costs

associated with decreasing DTC, the condenser heat

transfer surfaces, circulation pumps, intake anddischarge operations, and a larger turbine exhaust

section. For central power stations cooled by evaporative

towers or dry condensers (see below), the investment

costs of heat discharge systems are higher and shift the

economic optimum toward higher values of DTC:condensation pressures of 0.06-0.08 or 0.10-0.12 bar are

frequent for evaporative towers and dry solutions,

respectively, with evident negative consequences for

efficiency.

Number of regenerators. The advantages of utilizing

regenerative systems to heat the feed water have been

discussed above. By adopting a large number ofregenerators it is possible to use steam at lower pressure

to obtain the same heat transfer to the water, as it is

likewise possible to obtain feed water at higher

temperatures (see Table 4).

Number of SHRH. Increasing the number of

superheating stages has the same effect as increasing the

maximum temperature, with the added benefit that more

advanced materials are not needed. However, the

investment costs associated with adopting an extra RH

are substantially higher in that it involves adopting some

crucial high temperature components (tube banks,

turbine casing, piping, etc.). Therefore, conversion froma conventional single reheat solution (SHRH) to a



Table 4. Indicative parameter values and net efficiency of steam turbine power stations

ParameterConventional

technologyBest available

technologyR&Dgoals

Maximum cycle temperature (C) 535-565 590-620 700-720Maximum cycle pressure (bar) 170-250 250-320 350-375

Number of SHRH 11 11 or 12 11 or 12

Number of regenerators/feed-temperature(C)

6-8/280 8-10/310 10/340

Net efficiency (percent) 40-42 44-46 48-50


13/46

double reheat (SHRHRH) is not economical.

Moreover, it must be borne in mind that increasing the

steam temperature makes reheating less effective.

Although the double RH technique is well established

and has been utilized for many decades, even in the most

modern high-tech, high-performance designs, adopting a

single reheat cycle is generally deemed optimal from theeconomic point of view.

Modern plant design

In the light of what has been said so far, Fig. 11

illustrates the layout of a modern steam power station,

specifically, a supercritical plant with double reheat.

The station utilizes three low-pressure regenerators

and four high-pressure ones, with a deaerator in

between. Apart from acting as a regenerative exchanger

(mixing water and steam at an intermediate pressure of

about 5-7 bar), the deaerator carries out the important

function of separating the gases dissolved in water,

which occurs due to re-entry of air into the sections at

subatmospheric pressures. At high temperatures, the

dissolved gases, particularly oxygen, are highly

corrosive, and must therefore be removed. This is

accomplished by stripping the gases from a steam jet

flowing in the direction opposite to that of the feed water

in the deaerator. Then the gases are discharged into the

atmosphere.Although the steam turbine is mounted on a single

shaft, it is divided into different cylinders, between

which the low-pressure flow is split (see below); a

second turbine drives the main feed pump. Such an

arrangement reduces the power requirements of the

electrical machinery (and the associated losses),

although its main purpose is to simplify the regulation of

the flow rate of the circulating water. The upper portion

of Fig. 11 shows the components found along the flow

of the combustion air and exhaust gases: there are two

fans for the circulation of air/fumes (a forced draught

fan for the air and an induced draught fan for the

exhaust, to maintain the combustion chamber at



line/limestone

FGD

EXHAUST HANDLING

POWER CYCLE

gypsum

stack

final heat exchange air pre-heater

ESPFF

LP LP

low pressure pre-heater HP pre-heaters

deaeretor

condensate extraction pump feed turbopump

IP HP VHP

pulverized coal

RH2RH1

SH

SCRhigh dust

ammonia injection

turbopump

leakages

leakages

0.05 barcondenser

580C, 26 bar

580C, 90 bar

580C,300 bar

315C

crossover, 3 bar

air

Fig. 11. Layout of a steampower station.(LP, Low Pressure;HP, High Pressure;IP, Intermediate Pressure;VHP, Very High Pressure).


14/46

atmospheric pressure); the regenerative exchanger,

which heats the combustion air by drawing heat from

the exhaust gases; and lastly, the pollution control

devices (nitrogen oxideSelective Catalytic

Reduction, SCR; particulate matterElectro Static

Precipitator, ESP; sulphur oxidesFlue Gas

Desulphuration, FGD) which will be addressed in moredetail below.

The diagram does not, however, include some of the

many other auxiliary systems that make up a complete

power station, such as, for example: the condenser

cooling water circulation system, often with evaporative

cooling towers; coal treatment system, which includes,

pulverizing, conveying, etc.; makeup-water

demineralization; the systems for the treatment of

reagents and by-products of pollution control systems,

as well as others, whose description is beyond the aims

of this chapter.

The steam turbine

In water/steam plants, the fundamental component is

the steam turbine. This is where the expansion of steam

converts enthalpy into mechanical work. Large steam

turbines are made up of a large number of axial flow

stages grouped together in sections. It should be recalled

that each stage includes a fixed blade (the stator or

nozzle) and a mobile one (the rotor). Stages are

classified into two types, impulse or reaction, depending

on the arrangement of the blades and how the energy is

extracted from them. An impulse stage is defined as onein which the entire expansion takes place in the stators;

thus, the pressure is the same both upstream and

downstream of the rotor (i.e. there is no pressure drop

across the stage). In a reaction stage, instead, the

pressure difference is split between the stator and the

rotor. The main advantage of impulse-stage solutions

lies in their ability to handle a larger enthalpy drop at

equal peripheral velocities than reaction stages. On the

other hand, reaction stages yield higher efficiencies. The

characteristics of such axial-flow stages are determined

by several dimensionless parameters:13 13

Vex Vex VexNSw13441; DSD/13441; VR144Dhis3/4 Dhis1/4 VinwhereNSis the specific speed;DSthe specific diameter;

VR the ratio of volumetric expansion; Dhis is theisentropic enthalpy drop per unit mass; Vex and Vin are

the flow rates at outlet and inlet for the isentropic

expansion respectively; w is the angular velocity of

rotation andD the mean blade diameter (from base to

tip). Given a certain speed of rotation, which in large

units is dictated by direct coupling with the alternator

(3,000 rpms for 50 Hz grids and 3,600 rpms for 60 Hz

grids), and given a maximum admissible peripheralvelocity (uwD/2), which depends upon the maximum

centrifugal force sustainable by the constituent materials

of the blades and wheels on which the blades are

mounted (stress proportional to u2), the maximum

enthalpy drop, Dhis, achievable in a stage is proportionalto u2/2 through a proportionality coefficient,Kis, known

as the load coefficient, which can vary only within

rather narrow limits, from 2 to 5, for proper fluid-dynamic sizing of the stage. With metal materials and

current technology, the maximum enthalpy drop

attainable by any stage is in the order of 100-150 kJ/kg,

in contrast to an overall drop in enthalpy in the order of

1,500 kJ/kg over the whole expansion. This would

indicate the need to use at least ten stages, although in

reality a much greater number is necessary due, for the

most part, to the enormous volume change during the

expansion of steam, which increases by about 3,000

times from entry to exit. In this repect:

Parameter VR cannot reasonably exceed a value of

1.5-1.7 for any single stage, in order not to cause

wide variations in speed and, above all, to keep the

operation within the subsonic field (the shock

phenomena associated with supersonic flows

penalizes efficiency).

The need to maintain the specific diameter within an

optimal range of values to achieve good efficiency

calls for using smaller diameters for lower flow

rates, which at equal rotational speed w would

provide for smaller enthalpy drops and therefore the

need for more stages, the high-pressure sections.

The same conclusions can be reached by analysingthe specific speed, a particularly important parameter

because it significantly influences stage efficiency; at a

low value ofNSthe blade height is small in comparison

to the stage diameter. Such an arrangement involves

high losses due to secondary flows (created at the

casing and hub surfaces) and leakage through the

clearance between the rotating blades and the housing.

Instead, a highNSmeans that the blades are excessively

long relative to their diameter, with the consequence

that the difference in circumferential velocity between

the blade root and its tip does not allow for adopting

optimal velocity triangles along the entire radialextension of the blade.

In fact, it is impossible to size all stages of a steam

turbine (from first to last) with near optimalNSvalues

(between 0.15 and 0.35 to attain high efficiencies). The

flow rate is much higher than the value that would

correspond to such a range. It should moreover be noted

that the mass flow of steam turbines used in traditional

plants actually decreases as expansion progresses,

because of bleeding from the regenerative feed water

system (the mass flow in the last stage is usually 55-60%

of the first). In steam turbines for combined cycles,

instead, the opposite occurs because steam produced atlower pressures is introduced, and this complicates the




15/46

problems consequent to variations in flow rate. In

conclusion, steam turbines not only require many stages

(30-40 and more), but the medium or low pressure steam

flow must be split over two to four (sometimes even six)

separate turbines in parallel, mounted on the same shaft

(flow splitting).

The basic technology for large-scale steam turbineswas developed during the 1960s, when units with power

capacities of 600-800 MWe were successfully built. Over

the last decade, significant progress has been made in

blade design, following a better understanding of the

causes of energy loss in the various mechanical

components. Such advances have come mostly from the

field of computational fluid dynamics and numerical

methods, which have thrown further light on the state of

mechanical and thermal stress in the blades.

Advances in steam turbine design have come from

three major developments: increased height of the

low-pressure blades; the use of high-reaction mixed

stages, even in the high and medium pressure sections;

and the ever more widespread application of 3D-profile

blades.

As far as the first improvement is concerned, a good

example of the technological progress made is the

development of a 1,219 mm (48) steel blade mounted

on a base 1,880 mm in diameter, with a tip-to-base

diameter ratio of nearly 2.3 (Fig. 12). The outlet area is

about 12 m2, which consequently reduces the outflow

speed and the associated discharge kinetic energy losses.

With regard to the second advancement, an interestingfact is that even those manufacturers most committed to

impulse designs are progressively adopting high-reaction

solutions, despite the higher number of stages involved

(about twice as many: typically, theKis defined above

decreases from 4 to 2 in the transition from a fully

impulse stage to a 50% mixed reaction stage). Thus, the

most advanced, recent systems can attain very high

adiabatic efficiencies: as high as 94-95%, in the high

and medium pressure sections.

Steam generators

A general overview of steam generators is notpresented here, but the following addresses some

specific points relevant to the generators in large

supercritical power stations, very different in both size

and design from other types of industrial generators.

The steam generator (also known simply as a

boiler) is where combustion takes place. The heat

released by combustion is transferred from the

combustion products to the working medium of the

thermodynamic cycle; that is, liquid water is heated,

evaporated (also at supercritical pressure), then

superheated (either SH and 1 or 2 RH, see above).

Fig. 13 shows the general layout of a large generator.In the combustion chamber (lower left in Fig. 13), the

fuel is channelled to the burners by specialized fuel

delivery systems (a pneumatic system in the case of

powdered coal). The combustion air from windboxes is

forced by a fan through a regenerative heat exchanger

for preheating (see below), and then enters to react withthe fuel in the combustion chamber, where the flame

can reach temperatures of over 2,000C. The heat of

combustion radiates onto the walls of the chamber,

which are lined with the pipelines through which the

steam flows while changing phase. The numerous tubes

that make up the so-called evaporator (even in

supercritical systems, although no true evaporation

with two different phasesactually takes place), are

arranged in such a way as to isolate the hottest areas

from the external environment, through the so-called

membrane walls (piping joined through welded plates).

The heat transfer coefficient of the steam within thetubes is very high and must be so in order to maintain

the metal walls at a temperature near that of the steam

itself (about 400C, a temperature that even rather

economical carbon steels can withstand), despite the

presence of very high temperature gases.

When the gases leave the combustion chamber

(upper portion in Fig. 13) they are at more moderate

temperatures (about 1,000C) and flow to the

superheaters. The various heat exchangers are not

inserted counter current, but are arranged so as to limit

the temperature of the pipeline walls. The exchangers

making up the SH and RHs (two RHs in Fig. 13) arearranged in such as way as to minimize the need for



Fig. 12. Rotor blade of the final stageof a steam turbine (courtesy of Gepower).


16/46

materials able to withstand the very high temperatures

(and therefore particularly expensive) in the areas of the

maximum steam temperature. Each SH/RH is divided

into at least two exchangers, between which is inserted a

desuperheater, where some water is injected into the line

in order to allow for precise control of the finaltemperature of the superheated steam, thereby avoiding

any conditions approaching the critical resistance of the

materials. Subsequently, the exhaust gases, by now at

relatively low temperature (400-450C), undergo final

cooling to about 350C in the economizer, which is an

exchanger that heats the feed water from its state at

inflow to the generator (as it exits the regenerative

preheaters) to near evaporation conditions. At this point,

the gases can no longer release heat to the fluid

(water/steam) but are subsequently cooled in a

regenerative exchanger where they release heat to the

combustion air, thereby falling to a final temperature ofabout 120-150C (cooling to lower temperatures should

be avoided because an acid condensate would form due

to the presence of sulphur in the fuel). These exchangers

(not shown in Fig. 13) are often Ljungstrom air

preheaters, which consist of a central rotating metallic

matrix through which the gas flows. The hot exhaust gas

flows over the central rotor, transferring some of its heat

to the element, which rotates quite slowly to allowoptimum heat transfer first from the hot exhaust gases to

the element, then as it rotates, from the element to the

cooler air in the environment.

The water/steam circulation in the evaporative

section of a steam generator is necessarily of the forced

type (once-through) in supercritical generators, in which

the liquid and steam phases do not coexist; water is

channelled through numerous pipes arranged in parallel,

at the end of which evaporation is complete. The steam

is then collected in a collector and piped to the SH. Such

a simple arrangement, however, has the serious

drawback that, if an adequate supply of liquid does not

reach all pipes simultaneously, temperature peaks, which

are difficult to control, can easily occur in the pipe walls.

If a single pipe is not thoroughly cooled by the water

undergoing evaporation, it can easily reach intolerably

high temperatures (with a consequently disastrous

fracture), due to the extremely high temperature of the

gases in the combustion chamber.

Such a risk can be eliminated (or at least drastically

reduced) only by generating steam at more moderate

pressures, or in any event below the critical value.

To this end, two different design approaches have beenadopted.

Firetube boilers, in which the hot exhaust gases flow

within pipes immersed in a pool of boiling water. Such

an arrangement is however incompatible with high

pressures and is thus absolutely impractical in steam

generators of power plants, although it has found

widespread application in the generation of industrial

steam at pressures in the order of 10-15 bar.

Water-tube boilers, in which the water reaches a

cylindrical container (drum) where it coexists with

steam. The hot working medium (water) passes through

a descending tube (downcomer) to a lower collector, andthen rises again, to the drum through boiler tubes

(Fig. 14). The evaporated part of the fluid is collected in

the upper area of the dome, which thus releases saturated

steam. Such a solution avoids the risk of localized

superheating. The outflow steam is clearly saturated

under all operating conditions (barring any unwished-for

transport of droplets, which is minimized by special

separators), and thus regulates superheater operations.

As the system is based on the density difference between

liquid water and steam, it is applicable only to two-phase

systems, which excludes not only supercritical

processes, but also those too near the critical pressure(never exceeding 170 bar). Circulation may be left to a



IP 2

LP 2

IP 1

LP 1

economizer

evaporator

final super-heater

platen super-heater IP 3

SH 1(walls)

LP 3

Fig. 13. Schematic diagram of a large-scalesupercritical steam generator.


17/46

passive process, although in some cases a circulation

pump is used.

The efficiency of a steam generator (hSG) is the ratio

between the heat actually transferred to the fluid to be

heated and the heat released by the fuel (heating value,

usually the Lower Heating Value, LHV). The value of

hSGcan be evaluated indirectly (and also experimentally)

as the complement of 1 of the sum of all heat losses.

Losses stem from various causes: incomplete heat

recovery from exhaust gases; release of still hot

combustion products into the environment; defectivethermal isolation of the generator walls (inappropriately

called radiation losses); discharge of unburnt fuel, which

signals incomplete exploitation of the chemical energy

in the fuel; the release of other substances at high

temperature, for example, coal ash collected at the

bottom of the boiler. Quantitatively, the first type of loss

mentioned is by far the most significant.

In order to achieve high efficiencies, the temperature

of the exhaust gases must be kept as low as possible (for

example, by using a Ljungstrom exchanger). Moreover,

a proper mass ratio between air and fuel must be used.

This ratio must be above the stoicheiometric value inorder to avoid any significant amounts of unburnt fuel,

which, apart from reducing efficiency, includes quite

hazardous toxic substances (carbon monoxide, unburnt

hydrocarbons). However, an excess of air results in

greater heat loss via the release of gases into the

environment, in that it increases the mass flow rate;

optimal control of the quantity of air relative to the fuel

is therefore a crucial factor in steam generator

performance, in both energy and environmental terms.

The large steam generators used in thermoelectric plants

can reach efficiencies in the order of 94-95 %.

In terms of technological developments, over the lastfew decades designers have concentrated their efforts on

pollution control (see below); significant developments

in this field include modified burners, improved air-flow

control mechanisms, integration with removal devices

(SCR and others), and superheater materials able to

withstand steam temperatures of over 600C. Also worth

mentioning are some interesting projects for

rationalizing the overall lay-out of boilers, which call formodifying the traditional dual-pass arrangement shown

in Fig. 13 to a tower (or single pass) or even a highly

innovative horizontal layout.

Condensers

Condensers must discharge into the environment a

great deal of heat per unit time, equal to or even

slightly greater than the electrical power of the plant.

This calls for large fluid flow rates to absorb heat

from the condensing steam. There are only are three

possible alternatives for such fluid: river or seawater,

air from the atmosphere, or a stream of water cooled

by air flow from the atmospheric air. The devices

used in the three cases are.

Water heat exchangers, in which water from a

natural body of water (or even water cooled via a water-

air heat exchanger) makes the steam condense. In the

case of an open circuit (river or sea water), the water is

withdrawn from and then returned to the reservoir at a

higher temperature by circulation pumps.

Air heat exchangers or condensers cooled directly by

atmospheric air via convection heat transfer; these are

known as dry exchangers to differentiate them fromwet evaporative towers.

Evaporative towers, which utilize a semi-closed

circuit to cool the water heated by exchangers like those

described above. The transfer of heat from the water in

the evaporative tower to the atmosphere involves an

exchange of mass.

In principle, the first solutionthe water-steam

exchangeris the most efficient and economic one;

therefore it is also the one most frequently used in large

plants. In fact, water possesses much better thermal

exchange properties than air (at equal flow velocities

and diameters, the convective heat transfer coefficient ofwater is 500 times that of air) and therefore allows the

construction of relatively small, inexpensive exchangers.

The technical and economic optimization of such

exchangers, therefore, leads to solutions with a limited

temperature difference between the water and the

condensate, as has already been underlined when

describing the influence of the pressure of condensation

on cycle performance. From the perspective of

construction, the design solution most often utilized is

the shell and tube exchanger. Therefore, considering the

relatively low investment costs (which favour adopting

solutions with small DTand low condensationpressures), the smaller seasonal temperature variations



saturated steamto super-heater

evaporator pipes(water-steam mixture)

gas

feed waterfrom

economizer

downcomer(water)

Fig. 14. Circulationin a water-tube boiler.


18/46

of water compared to air, and the rather low power

requirements needed to circulate water, it is

understandable that open circuit condensation yields the

best performance. There are nevertheless some

significant limitations to the use of such open circuit

solutions. First of all, the water must be drawn from

natural sources such as rivers, lakes or seas. Accordingly,plants must be constructed near such a body of water,

which often means in natural areas with scenic value.

This seriously limits the availability of sites, especially

in densely populated areas. Moreover, returning the

water to its environment involves issues of thermal

pollution, which have often been neglected in plant

design (especially in older plants).

These problems limit the areas suitable for

constructing new plants. In fact, the combined effects of

two electrical power stations in the same area may easily

exceed locally imposed limits; environmental studies

and associations have long stressed the damage caused

by discharging hot water into natural settings, including

disturbances to ecosystems. Thus, governing legislative

limits to plant hot water discharge must be carefully

taken into account at the design stage.

Faced with such limitations and the often onerous

search for sites with large quantities of water, the

technical solution of dry heat exchangers has received

renewed interest. However, such solutions involve a

considerable amount of effort in terms of plant design,

costs and performance. The reasons lie in the

aforementioned low thermal exchange capacity of air(therefore the need for large exchange surfaces), as well

as the power required by the fans. The enormous

volumetric capacity of air calls for large flow areas (a

600 MWe unit needs about 50,000 m3/s of air; at a speed

of 2.5 m/s, this corresponds to a cross-section

of 20,000 m2, the surface area of three football fields),

with consequent problems of space. However, the most

serious obstacles to the use of dry exchangers is the need

to keep them air-tight (the re-entry of air causes a

pressure increase in the turbine discharge), and the

formation of ice (with possible tube rupture). Despite

these difficulties, a wide range of air condensers iscommercially available, most of which adopt modular

hut solutions, with forced draft to the exchanger, which

is made up of banks of finned, vertically arranged tubes.

Dry heat exchangers are widely used in the steam

section of combined cycle plants, which have lower heat

discharge requirements than steam cycles.

Steam cycles, however, more often employ

evaporative towers, which have the advantage of very

low (although non-zero) water consumption in

comparison to open systems, thereby offering

considerable savings over dry solutions. Evaporative

towers (Fig. 15) are direct contact air-water heatexchangers in which the two fluids are not separated by

any physical barrier (pipe), but can also interact to

exchange mass. Thus, a part, albeit a small one, of the

water evaporates to bring the air to saturation. The two

fluids flow in opposite directions (countercurrent flow)

and therefore, in the process of heat exchange, the air is

heated by contact with the warmer water, which at the

same time progressively increases the quantity of waterthat can be absorbed by the air through evaporation.

The hot water therefore cools to some extent because it

relinquishes a significant amount of heat to the air, but

especially because the phase transition releases the

latent heat of evaporation. The lower temperature limit

for the cooled water is that of the ambient air under

conditions corresponding to the wet bulb temperature.

In a dry exchanger, on the other hand, this lower limit

is the dry bulb temperature, which is significantly

higher than the wet bulb temperature under summer

conditions of maximum load. Evaporative towers are

thus able to ensure lower condensation temperatures

than dry systems, especially under more demanding

operating conditions.

An evaporative tower consumes far less water than

open systems; 1 kg of water in a tower removes

2,500 kJ (corresponding to the heat of water

evaporation2,500 kJ/kg), compared to about 30 kJ/kg

for open systems. Actually, water consumption turns out

to be somewhat higher (about double), because it is

necessary not only to make up for the evaporated water

lost to the atmosphere, but also that lost in the so-called

blowdown which is necessary to maintain acceptably



drifteliminators

waterdistribution

exchangesurface

air

air

hotwater

cooled waterbasin

Fig. 15. Schematic illustration of a natural

air-circulation evaporative cooling tower usedin large-scale power stations (Hamon).


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low concentrations of solid substances in the water

circulation (calcium and other salts). The air flow

necessary is quite limited in comparison to dry

systems, because the enthalpy change of humid air is

increased by the contribution of the latent heat

associated to the difference in the quantity of steam at

inlet and outlet. Moreover, the smaller volume of air inthe flow occupies less space and therefore, in principle,

involves lower energy consumption to drive any fans

that may be needed.

Evaporative towers, however, are not free of

problems. The major drawbacks are the proliferation of

bacteria in the damp hot environment, particularly

Legionella pneumophila, which poses a serious health

hazard and the formation of so-called plumes (clouds

of condensation forming from the water contained in

the outflow of damp air as it comes in contact with the

colder outside air). This phenomenon, undesirable for

both aesthetic reasons and the consequent fall of water

droplets to the ground, can be effectively avoided by

using various techniques (for example, by mixing it

with atmospheric air heated in a dry section of the

tower) which, however, significantly increase

investment costs.

Pollution control

Gaseous pollutant emissions and their control are of

fundamental importance in operating fossil fuel burning

plants. Nowadays, energy efficiency and low cost per

kWh produced alone are not enough to guarantee thesuccess of an investment in the field of electrical energy

production; environmental impact must be a primary

consideration in plant design and operations. This holds

for all fuels, but especially coal, which is generally

considered highly polluting. This, however, is not

entirely true. The environmental impact of even dirty

fuels, such as coal, can be contained to within acceptable

limits, if, that is, so-called Best Available Technology

(BAT) is adopted. Due consideration must therefore be

given to such technologies in the plant design.

The principal pollutants present in the combustion

products of coal plants are nitrogen oxides, generallyindicated as NOx (nitrogen monoxide, NO, being the

predominant form released at the time of combustion,

and nitrogen dioxide, NO2, into which the nitrogen

oxides are converted in the atmosphere), sulphur oxides

(SO2 and, in a much smaller proportion, SO3) and

particulate matter (PMs, all the residual solid particles,

whose chemical composition and grain size vary

widely). The emissions of such pollutants (taken to be

NO2 for the NOx and SO2 for the sulphur oxides) are

generally expressed in mg/Nm3 in dry gases with 6% O2(3% for liquid or gaseous fuels).

European regulation 2001/80/CE, which goes intoeffect on January 1st 2008, sets the reference emissions

values for a large coal plant at 200 mg/Nm3 for NO2 and

SO2, and 30 mg/Nm3 for particulates. To appreciate

exactly how restrictive such values are, it should be

enough to consider that meeting the SO2 limit of

200 mg/Nm3 in the absence of any exhaust purification

systems would require using coal with a sulphur content

below about 0.1% (a rare quality indeed) or, alternatively,coal with 1% sulphur content and a desulphurization

system able to capture at least 90% of the SO2present in

the exhaust gases (commercial coals have a sulphur

content varying from 0.5 to 4%). It must also be borne in

mind that local emissions limits are often even more

restrictive, especially for nitrogen oxides.

Pollutants can be controlled by adopting two

methods: primary methods, which try to prevent

pollutant formation, and secondary methods, by which

the toxic compounds are removed from the exhaust

gases. No economically feasible primary technologies

exist for particulate matter or sulphur oxides. Thus, only

their removal will be examined here, while for nitrogen

oxides both approaches can be, or rather must be, used

in conjunction.

Low NO emissions combustors

Combustion produces NO through two fundamental

mechanisms:

Molecular nitrogen (N2) contained in the air

undergoes thermal dissociation and subsequent

oxidation (that is, favoured by high temperatures,

and accordingly termed thermal NO). Nitrogen present in the fuel, not as molecular nitrogen

but chemically bound in the form of cyano- and

amino-compounds, at a high temperature, give rise to

nitrogen compounds such as NH3 and HCN, and

subsequently, NO (termed fuel-bound NO).

A fuel such as coal contains considerable quantities

of nitrogen. The production of the two types of N,

thermal and fuel-bound, are comparable, their relative

amounts depending on the composition of the fuel.

Although the production of both is strongly influenced

by the flame temperature, the fuel-bound fraction is

produced at temperatures far below those present in thecombustion chamber, so its formation is extremely

difficult to avoid. As far as thermal NO is concerned, the

three main reactions involved are (extending Zeldovichs

mechanism):

ON2

NON

NO2

NOO

NOHNOH

The first two reactions are reversible, while the third

is shifted almost completely to the right. The NO

concentration in the combustion products is consistently

quite different from the equilibrium concentration. Thestrategies for obtaining acceptable NOx emissions by




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limiting its formation during combustion can be

summed up as follows:

Reducing the residence times - hardly a feasible

approach in steam generators and combustion

chambers (even of gas turbines).

Reducing the N2 concentration also negligible

for air-fed combustion, since the nitrogenconcentration in combustion chambers is, in any

event, extremely high.

Reducing the concentration of O2 in the proximity of

the flame - which is possible with a rich mixture. As

this involves high emissions of CO and other unburnt

by-products, it must be followed by strong dilution

with air to eliminate such by-products and bring

combustion to completion. Known as staged

combustion, this is one of the main approaches

being pursued in low emissions combustors.

Decreasing the equilibrium temperature of the flame

by adding to the fuel or combustion air an inert

component that does not react and therefore dilutes

the flame, reducing its temperature. Water or steam

are used as inert components. However, their

addition causes a drastic decrease in the performance

of the boiler (lower boiler efficiency). This technique

is known as Exhaust Gas Recirculation (EGR).

Although it is an effective way to reduce NOx, it

however involves an increase in the flow of

circulating boiler gas (combustion airrecirculated

gas) and, as a result, increased dimensions of the

exchange surfaces and higher cost. Therefore, onlymoderate recirculation ratios can be used, which

alone are generally insufficient to guarantee sizeable

emissions reduction. Another way to reduce the

flame temperature consists of carrying out

combustion under non-stoicheiometric conditions,

either via a lean mixture (the excess air does not

participate in the combustion and thus acts as an

inert compound, thereby reducing the efficiency and

increasing the dimensions of the boiler), or, on the

other hand, using an excess of fuel, which has been

dealt with in the previous point (reduced O2

concentration).All told, staged combustion is currently the most

promising technology for reducing NOx during

combustion, and this is implemented by combining

two of the approaches suggested by the Zeldovich

formulation. One of the techniques successfully

applied to accomplish this is afterburning:

combustion initially takes place under conditions

very near stoicheiometric proportions, which

produces less NOx than normal combustion with a

somewhat lean mixture. Subsequently, additional fuel

(typically 10% of the total) is injected, so as to create

a reducing atmosphere that consumes the previouslyformed and still chemically active NO, converting it

into N2 (afterburning). This second combustion is

however accompanied by the production of a great

deal of unburnt fuel (mostly CO), which is

subsequently oxidized by further injection of air

(OverFire Air, OFA). In practice, the temperature

peak of normal lean combustion is not reached at any

point in the chamber. Thus, the effects of the lowerpeak temperature are combined with the effect of

chemical reduction in the afterburning zone, which

acts to reduce fuel-bound NO.

This mechanism is repeated on a smaller scale in low

emissions burners that go through the same sequence of

staged combustion, applying it to the flame itself: a

secondary jet of fuel is injected into the central zone of

the flame (carried out in approximately stoicheiometric

proportions). This supplies the reducing effect, and is

followed by an injection of secondary air through the

burners outermost ring for the final oxidation. These

combined measures are generally not enough to

guarantee NOx emissions within levels required by the

strictest regulations (especially with coal, due to the

contribution of fuel-bound NO), although they can

achieve pollutant reductions of 50 to 70% over

conventional burners. Therefore, the most highly eco-

compatible plants (the only type allowed for new

construction in the European Union) combine the

measures described above with additional systems for

removing NOx from the exhaust gases.

NOx removalNOx is eliminated directly from the combustion

products of the steam generator by SCR; the process is

carried out by injecting a reducing agent that drives the

reduction reaction in an oxygen rich environment such

as the exhaust gases.

In fact, when CO must be removed (which happens

very rarely), no extra reagents need be added, since the

oxygen necessary for conversion of CO into CO2 is

already present in the gases; all that is needed is a

catalyst to accelerate the reactions. This reducing agent

is usually ammonia which, in the presence of a suitable

catalyst, undergoes the following reactions:

4NO4NH3O24N26H2O

6NO28NH37N212H2O

In practice, the reaction is catalysed by sprinkling

ammonia either on a ceramic honeycomb matrix or,

more frequently, on an appropriately corrugated metal

matrix, which serve the purpose of offering an extensive

surface over which the exhaust can come into contact

with the metals covering it. These carry out the function

of catalyst (usually, vanadium pentoxide, V2O5 or

tungsten trioxide, WO3). The reactions takes place with

the maximum efficiency in a gas temperature range ofabout 300-380C, although with suitably refined




21/46

catalysts it is possible to broaden this operating range.

In large steam plants with coal boilers, the required

temperature is compatible with the gas discharge from

the economizer.

The use of pure ammonia as the reducing agent

poses significant problems in storing and transporting

such an extremely toxic and inflammable reagent,which moreover must be kept at pressures of over 10-15

bar for it to remain liquid at ambient temperature. One

possible solution is to make use of a hydrated solution,

NH4OH, which is liquid at ambient pressure. However,

NH4OH must be made to evaporate for the injection,

which involves the consumption of energy. Another

possible solution utilizes urea, (NH2)2CO, which is

transported as a solid and is then diluted in water.

Although urea is safer, it is far more expensive and

therefore better suited for use in relatively small

systems (for example, cogeneration plants). Regardless

of the catalyst used, the operating principles underlying

SCR remain the same. The fundamental requirements

and drawbacks of SCR operations are:

The conversion efficiency (percentage of NOxconverted to nitrogen) depends on: the catalyst; the

geometry and surface area of the catalyser; correct,

uniform feeding of the ammonia; and the operating

temperature, which must remain within a rather

narrow range. The attainable efficiency is generally

between 85 and 90%; higher values involve higher

costs.

Their use involves gas pressure losses, due to thepresence of the base metal catalyst, whose

dimensions must be limited to avoid increasing

power consumption by the fans.

A certain amount of ammonia is not converted in the

reaction and is therefore released with the exhaust

gases.

This phenomenon, called ammonia-slip, must be

kept

large-scale electrical generation systems

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