Industrial Cogeneration

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5.2.1 IntroductionAfter a brief review of the physical bases,

operating principles and the characteristic

operating parameters of cogeneration systems, the

following goes on to describe the technologies

exploited in medium-to-large size industrial

applications (1 MWe); for a description of the

smaller sized applications, more widespread in

residential and tertiary sector applications, see

Chapter 5.3.

Physical basesBy the second law of thermodynamics, the

generation of mechanical or electrical power via

thermal processes is inevitably associated with the

transfer of thermal power at medium to low

temperatures. In plants designed to produce

electrical energy alone, such heat transfer is not

exploited in any way; the heat is simply lost into

the surrounding environment, either directly

(through the release of the products of combustion

into the atmosphere) and/or indirectly (through a

heat carrier fluid, generally air or water drawn from

groundwater or rivers, lakes and seas). Althoughstill one of the most widespread practices, the

direct production of heat at low temperature in a

boiler is one of the most improper uses in the

thermodynamic sense of the chemical energy

available in fuels.

Cogeneration is the technique of combining the

generation of both electricity and heat in a single

series of processes. It enables, on the one hand, the

exploitation of the heat that would otherwise be

irretrievably lost through transfer to the environment,

and on the other, avoids the (highly irreversible) direct

conversion of the energy liberated by combustion intolow-temperature heat.

Operating principles

There are numerous and varied designations for

cogeneration systems, for example, Combined Heat

and Power (CHP) or total energy systems. Apart from

the terminology adopted, two fundamental features of

the technology are alwais present: the joint production

of electrical energy and heat, for the most part through

a serial process; and primary energy savings over the

separate production of electricity or heat alone. Of the

various types of systems designs, two broad categories

of cogeneration processes can be defined.

By far the most widespread and important process

is the topping cycle, which exploits a cycle thatreceives energy from a fuel (or some other

high-temperature energy source) and converts part of

it into mechanical work, and subsequently into

electricity. A portion of the total energy not converted

into work is recovered as usable low-to-medium

temperature heat, while the remaining part is released

into the environment. The fraction of unconverted

energy that can be recovered depends on the type of

plant and the temperatures at which the heat can be

utilized. Topping cycles can be implemented in a wide

range of different cogeneration plants, in terms of both

prime mover (steam power plants, alternative primemovers or gas turbine systems, gas-steam combined

cycles), and scale (from the few kWe of

micro-cogeneration systems, to the hundreds of MWeof the large-scale combined gas-steam cycles adopted

in industry).

Although the bottoming cycle is less widespread in

its application, it is also of practical interest. In this

process, the generation of work (or electrical energy)

is performed downstream, rather than upstream from

where the heat is utilized. Such systems are generally

applied in industrial production requiring

high-temperature heat (for example, cement and glassworks, tile and ceramic plants, etc.). A part of the heat

421VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY

5.2

Industrial cogeneration


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available at medium to high temperature is recovered

via a cycle (using water steam, or organic fluids) that

produces electrical energy and, at times,

lower-temperature heat as needed for thermal process

uses.

Due to their far more widespread application, the

following discussion will be limited to cogenerationsystems of the first, topping-cycle, type.

Characteristic operating parameters

The technical literature furnishes a disparate

variety of criteria for evaluating the thermodynamic

quality of a cogeneration system.

The simplest and most common criterion (though

also the most approximate) makes reference to the

first law of thermodynamics. It defines the first-law

efficiency, hI(also known as the fuel utilization factor

or total efficiency) of a cogeneration plant as the ratio

between the sum total of a plants useful effects

(electrical energy,E, and heat, Qu) and the energy

released by the fuel,Ec, as a rule, taken to be the

Lower Heat Value (LHV):

hI(EQu)Echeht

where the terms heEEc andhtQuEc are

respectively the electrical efficiency and the thermal

efficiency of the cogeneration system.

Another frequently used index, which stresses the

production of electrical energy through cogeneration,

is the electrical index:IetE(QuE)he(heht)

which varies from 0 (for systems that produce heat

alone) to 1 (for systems that produce solely electrical

energy).

However, there are drawbacks to defining

efficiency in first-law terms. They stem from the fact

that the same weight is attributed to the two terms (E

andQu), whose energetic and economic importance

are actually very different. However, no universally

accepted criterion exists for attributing the correct

weight to the two terms; the most thermodynamicallycorrect criterion would be to convert the term Qu into

energy (electrical energy or mechanical work). To this

end, Qu, considered to be available at medium

temperature, TQ, is multiplied by the efficiency of a

reversible cycle having Qu as the heat supplied and an

environment with infinite thermal capacity as the heat

well (conventionally assumed to be at temperature T0).

Under such assumptions, we now instead refer to

second-law efficiency, hII, equal to:

hII[EQu(1-T0TQ)]Ec

which essentially corresponds to the exergy efficiency.However, it must be borne in mind that the usual

values of the ratio T0/TQ have very low corresponding

values of the multiplicative heat coefficient, which

tend to penalize cogeneration.

Perhaps the most suitable criterion for expressing

the quality of a cogeneration plant, in that it goes right

to the crux of the matter, consists of comparing a

cogeneration system with a corresponding unit withoutcogeneration, thereby providing a measure of the fuel

savings afforded by cogeneration in comparison to the

separate generation of the same quantities of electrical

energy and heat. The fuel consumptionEc,s with

separate generation ofEandQu is given by:

Ec,sEhe,sQuht,s

where he,s andht,s are respectively the reference

electrical efficiency (for example, the mean efficiency

of the pool of thermoelectric plants feeding the grid to

which the cogeneration system is connected, including

transmission and distribution losses), and the reference

thermal efficiency (generally the typical efficiency of

a boiler). The index of primary energy savingsIPEis

thereby defined as:

IPE(Ec,sEc)/Ec,s11{hehe,s+

+he[ht,sIet/(1Iet)]}

This primary energy savings index is zero when

hehe,s andIet1, that is when the system produces

only electrical energy with an efficiency equal to the

reference value, or whenIet0 andhtht,s, that is, the

system produces only heat with an efficiency htht,s.The index is positive when hehe,s (that is when the

cogeneration systems electrical efficiency is greater

than the reference value) and/or when the contribution

of heat generation (Iet1) is able to compensate for the

lower electrical efficiency.

Another way to compare cogeneration systems

with separate electrical generation is to consider the

equivalent electrical efficiency, which calculates the

electrical energy that can be generated from that part

of the fuel remaining after having subtracted the fuel

hypothetically consumed to produce heat Qu in an

equivalent boiler. Thus, with the notations used in theforegoing, we have:

hel,eqE(EcQuht,s)he(1htht,s)

It should be noted that an equivalent electrical

efficiency above the reference value he,s denotes

primary energy savings, and therefore a positive value of

IPE. However, it may also happen that very high values

ofhel,eq, yield low values ofIPE, or vice versa; the first

case indicates systems with low electrical indices,

which, despite their high equivalent efficiencies,

produce a modest quantity of electrical energy, while the

second occurs in plants with high electrical indicesproducing large amounts of electrical energy.

422 ENCYCLOPAEDIA OF HYDROCARBONS

POWER GENERATION FROM FOSSIL RESOURCES


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Evolution and current trends

The potential advantages of cogeneration, in terms

of both energy production and environmental

friendliness, are such that it would be desirable (and

much legislation does in fact impose) that all plans for

the construction of new thermoelectric plants include

prior study of the technical-economic feasibility ofrecovering heat at low temperature through a

cogeneration process. Vice versa, any application

generating low temperature heat should also be

evaluated for the possibility of simultaneously

producing electricity. In reality, cogeneration is not

always feasible, both for technical reasons (the

demands for heat and electricity are separated in time

and/or space, difficulties in accumulating and

distributing heat over long distances), and for

economic reasons (competition from large-scale

thermoelectric plants, which enjoy the significant

advantages offered by economy of scale and the use of

cheaper energy sources), to which must be added

legislative and pricing obstacles (associated to

difficulties in connecting cogeneration plants to the

electric grid, and the low market value attributed to

electrical energy exported to the grid).

Cogeneration plants are potentially applicable to a

great number of sectors: industrial, civil and tertiary.

Cogenerated heat can be, for example, used to feed

heating networks (which generally use hot water as the

heat carrier fluid, typically at temperatures of 120C

for the outflow collector, and 60C for the return) to

supply domestic heating and hot water to entire

districts or cities. Indeed, such applications are very

widespread in northern Europe, where the heating

season is long.

The most significant and widespread applications

of cogeneration, however, are in industry. Over the last

few decades, industrial cogeneration has been basedprimarily onsteam cycles: instead of producing steam

(or warm water) under the conditions required by

production processes (for the most part at relatively

modest pressures), high-temperature, high-pressure

steam generators have been developed that generate

electricity by exploiting the difference in steam

pressure between the boiler output and the pressures

required by production. Such a strategy has been

applied in many industrial processes (for instance, in

the textile, paper, chemical, petrochemical,

pharmaceutical, and food industries, etc.), whose heat

requirements are high, and generally constant over

time, for a large total number of hours yearly. It should

be noted that such cycles are generally closed, though

in some cases they may not be: if the steam is

delivered directly from turbines to the industrial

process, the condensate can be totally returned (closed

cycle), or not (open cycle); if the specific use process

requires warm water, the steam cycle is closed, which

involves the presence of an exchanger.

In the most traditional approach, the system is

sized and managed according to the requirements of

the thermal application, and the electrical energy


INDUSTRIAL COGENERATION

A

B

E

AHE

G ST

ST ST

P

thermaluser

PQ

u

E

AHE

CD

G

P

thermaluser

P

D

Qu

back-pressure steam turbine

condensing/extraction steam turbine

Fig. 1. Schematic layout

of external combustion

systems for cogeneration.

G, steam generator;

P, pump; ST, steam turbine;

HE, heat exchanger;

CD, condenser.


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CDCD

A

B

E

HE

HE

HE

HE

HE

HE

to stack

to stack

turbocharged internal combustion engine

simple cycle gas turbine with recovering boiler

steam-injected gas turbine

back-pressure combined cycle

condensing/extraction combined cycle

to stack

steam injection

C GT

C GT

C GT

CC

CC

AB

P

Qu

A

E

A

thermaluser

thermaluser

P

D

Qu

E

A

P

E

PD

O

Qu

A

N

M

HE

to stack

HE

C GT ST

TA

CC

AB

thermaluser

E

P

Qu

A

N

M

HE

to stack

HE

C GT ST ST

TA

CC

AB

thermaluser

E

P

Qu

A

N

M

D O

Fig. 2. A, schematic layout

of internal combustion systems

for cogeneration;

B, schematic layout

of combined cycle systems

for cogeneration.

CC, combustion chamber;

C, compressor;

GT, gas turbine;

TA, turboalternator;

AB, afterburner.


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cogenerated used, for the most part, to satisfy the

needs of the industrial process itself. Often, this has

made production facilities almost self-sufficient

hardly any electricity need be imported from the

electric grid, usually only to cover peak demand, and

any excess production can be fed into the distribution

grid. Apart from the advantages in terms of energybalance and economy, cogeneration has always offered

other significant, often strategically important benefits

for many productive processes, such as the possibility

to operate in isolation (that is, without being

connected to the electric grid), immunity from grid

blackouts, and improved quality of electrical service.

Over the last two decades, also the cogeneration

plants have undergone the particularly significant

evolution already described for large-scale

thermoelectric plants (see Chapter 5.1); apart from

traditional technical solutions (external

combustionsteam cycle), industrial cogeneration has

become ever more oriented towards internal combustion

solutions based on alternative prime movers for

small-scale systems (characteristically, 5-10 MWe),

while for power outputs of up to 20-50 MWe the trend

is towards simple recovery gas turbines. Lastly, an

especially important trend is towards combined

gas-steam cycles, often implemented by repowering

already existing cogeneration steam plants. The

reasons underlying this last solution are the same as

those which have promoted the widespread adoption

of combined-cycle plants for the generation ofelectricity, namely: a) the widespread availability of

natural gas at competitive prices with respect to fuel

oil; b) technological advances in internal combustion

engines in terms of performance, specific costs and

emissions; c) the great potential for energy savings

and reductions in greenhouse gas emissions;

d) increased public ecological awareness, which has

tended to favour environmentally-friendly solutions.

Since internal combustion technologies, in contrast

to external combustion, are characterized by very high

electrical indices, in cogeneration applications, the

electrical energy produced often greatly exceeds therequirements of the productive process. Thus, the

ability to transfer surplus electricity (which may

represent a significant fraction of total capacity) to the

distribution grid at competitive rates becomes of

fundamental importance.

Plant layouts

Industrial cogeneration plants can be grouped into

two broad categories, depending on the type ofprime

mover on which plant operations are based: external

combustion (steam turbines) and internal combustion

(alternative prime movers, such as the Otto cycle orDiesel cycle, or the gas turbine).

Figs. 1 and2 schematically illustrate the most

widespread layouts for plants based on external and

internal combustion, which will be described in

Sections 5.2.2 and 5.2.3, respectively. Each of the

figures include indications on the plant operating

ranges in terms of a plot of electrical energy vs. heat,

Evs. Qu (also, electrical power output vs. thermalpower utilized).

Table 1. moreover, shows the operating parameters,

in term of electrical power output and the typical

values of the previously defined indices for each of the

plant designs represented in Figs. 1 and 2. Some

noteworthy conclusions can be drawn from the figures

and table:

The highest first-law efficiencies can be obtained

with pure back-pressure steam cycles or with

alternative total heat-recovery engines; in both

cases, exhaust losses are relatively low because

high excesses of air are unnecessary for the

combustion process, in contrast to the gas turbine.

Back-pressure steam power plants are

characterized by very low values of the electrical

indexIet; electrical energy production via

extraction and condensation plants is greater, but at

the expense of the energy savings indexIPE, which

may even become negative; in other words,

cogeneration with steam extraction and

condensation cycles may even involve greater fuel

consumption than the separate generation of

thermal or electrical energy via modern high-performance combined cycles.

Alternative prime movers exhibit good

thermodynamic characteristics for cogeneration

applications, above all when it is possible to

recover all the heat produced, that is, when the

thermal process demand

medium-to-low-temperature heat.

Simple recovery gas turbines are characterized by

high equivalent electrical efficiencies, which

remain high even when afterburning is adopted;

substituting simple heat recovery with a bottoming

steam cycle (combined cycle) yields a signif icantincrease in the electrical index value and also

provides the maximum primary energy savings.

5.2.2 Plants with externalcombustion prime movers

The fundamental advantage of such plants is their

great flexibility in terms of primary energy source:

adopting a closed-cycle, external combustion engine

(specifically, a water steam cycle), the nature of the

fuel employed has no influence on systemperformance. Thus, solid, liquid or gaseous fuels, even




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the wasteby-products of other processes andlow-quality fuels can be used interchangeably. In

practice, however, certain low-quality fuels (e.g. heavy

oils, tar, lignite, peat, etc.) are often avoided because

of emissions regulations and the consequent

investments involved in treating the combustion

products. This ability to admit low-cost fuels, together

with the proven reliability and intrinsically good

characteristics of the technology, played a decisive role

in plant design choices up to the late 1980s, during

which, in fact, open-cycle solutions (gas turbine and

alternative prime movers) were relegated to a marginal

role. Even the low ratio between electrical energy andthe thermal energy produced in these systems was

considered an advantage in those years, given that

electricity markets were often in the hands of

monopolies, which limited or prohibited marketing the

cogenerated electrical energy to third parties, and

moreover applied tariff conditions fees for services,

which discouraged the sale of electricity to the grid.

Modern cogeneration technology often favours

choices different from classical steam cycle solutions.

This, however, has not affected the very important role

that steam turbines continue to play in cogeneration:

not only are they still present in many existing plants,but they are also being adopted in new plants. Indeed,

there are important niches in the market in which thedemand for steam cycle systems is high; apart from

situations in which natural gas is unavailable, there are

also numerous industries that produce fuels as

by-products of industrial processes. A further,

particularly noteworthy aspect is the enormous

potential offered by the techniques ofrepowering the

existing pool of steam-based cogeneration plants.

Steam turbines for cogeneration

In contrast to the other prime movers used for

cogeneration (gas turbine and alternative prime

movers), which are available in a range of commercialmodels whose technical characteristics and

performance (capacity, pressure, temperature, power

output, efficiency) are well-defined and generally not

subject to modification for specific application

requirements, steam turbines are normally

custom-designed, although they generally use

standard, modular components.

It is therefore possible to design all the functional

characteristics of such machines, in particular, the

number of turbine steam inlets and outlets, the

nominal steam flow rate through the various turbine

sections, the steam pressures and temperatures at theturbine inflow points, the steam pressure at outflow. It



Table 1. Power output ranges and characteristic indices (indicative mean values)

of the cogeneration plant designs illustrated in figs. 1 and 2

Plant design

Pe hI he ht hII(1) Iet hel,eq

(2) IPE(2)

MW % % % % %

external combustion

Back-pressure steam turbine 1-25 88 15 73 38 0.17 79 9

Extraction-condensation steam turbine 10-500 65 30 35 41 0.46 49 5

internal combustion

Alternative prime movers with full heat recovery 0.1-10 86 40 46 55 0.47 82 21

Alternative prime movers with high-temp. heatrecovery only

0.1-10 65 40 25 48 0.62 55 3

Gas turbine with simple heat recovery 1-100 80 30 50 46 0.38 68 11

Gas turbine with afterburning 1-100 83 25 58 44 0.30 71 11

Gas turbine with full steam-injection 5-60 50 45 5 47 0.90 48 11

Combined cycle with back-pressure steam turbine 20-50 80 45 35 56 0.56 74 19

Combined cycle with condensation and extractionsteam turbine

50-400 70 50 20 56 0.71 64 14

(1) Calculations ofhIIare based on assumed values T015C andTQ150C(2) Calculations ofhel,eq andIPEare based on assumed values he,s53% andht,s90%, representative of the annual mean outputsof a large-scale combined cycle for separate production of electrical energy and an industrial boiler, respectively


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should be recalled that in modern, advanced cycles,

apart from the inflow of live steam, a reheater may be

present. In fact, combined-cycle applications normally

have two, or even three, steam inlets, as the better

exploitation of the discharge gases implies the

adoption of multi-level evaporative recovery boilers. It

should also be recalled that the outflow temperature ofthe steam is determined by its expansion curve, and

that if the degree of overheating the steam is greater

than that required for thermal process use, tempering

is required.

The market offers an extremely wide and

diversified range of products, both in terms of

technological complexity and sophistication and

electrical power output (from single-stage turbines

with outputs of tens of kWe, to large, highly complex

multiple-flow and multiple-unit assemblies, whose

maximum capacities can exceed one million kWe

).

Main plant designs

The most common cogeneration applications

normally adopt the plant types illustrated in Fig. 1,

which for the sake of simplicity can be classified into

two categories.

The first category is back-pressure turbines, simple

and relatively compact units, due to the absence of the

low-pressure section, whose main applications are in

small-to-medium power outputs (25 MWe). The

discharge steam from the turbine can be sent directly

to the industrial process, which can return it, wholly orpartly, to the cogeneration plant in the form of

condensate. Alternatively, the steam can be made to

transfer its heat to another fluid via a condenser. Such

units may be pure back-pressure systems, in which

case, the entire flow required by thermal process use

traverses the entire series of turbine blading, or there

may be an intermediate stage of steam extraction, in

which case, the flow rates up- and down-stream of the

extraction point are different. In both cases, a strict,

well-defined link exists between the thermal energy

utilized to drive production processes and the

electrical power generated, which means that operators

of such cogeneration plants cannot vary the generation

of electrical energy at their discretion, but must

accept the value imposed by the thermal processes.This is shown by the straight lineAPin Fig. 1 (top

right), where pointA represents the technical

minimum, pointPthe condition of maximum load and

the intermediate points the various operating

conditions possible.

The second category is made up of turbines with

extraction (or bleeds) and condensation, units generally

adopted in larger-scale plants (tens and possibly even

hundreds of MWe), as opposed to back-pressure

turbines. These allow for the possibility to tap steam

and divert it to thermal uses (at the expense of

electricity generation), as is shown by the linePD in

Fig. 1 (lower right), which describes full load

operations with varying degrees of flow extraction;

pointD represents no extraction at all, while at pointP

extraction is at a maximum. Therefore, the entire area

underlying the discontinuous lineAPD represents the

possible operating regimes. Going into more detail,

apart from one or more steam extraction points, the

unit also includes a low pressure section in which a

fraction of the steam flow expands down to the

pressure of condensation; while, on the one hand, this

involves lower total efficiency and a greater complexityof the unit, on the other, it makes it possible to regulate

systems operations over a broad range, which allows

plant managers to optimize the plants economic

(and/or energy) efficiency at all times.

Steam extraction methods

Tapping steam from the turbine can be carried out

in two main ways, either controlled or uncontrolled.



0

129 / 538 1,800 / 1,000

bar C

inlet steam conditions steam turbine flow rate

psig F

101 / 510 1,450 / 950

87.2 / 482 1,250 / 900

59.7 / 440 850 / 825

42.4 / 399 600 / 750

28.6 / 343 400 / 650

17.5 / 260 250 / 500 100 200 3001,000 lb/h

t/h

400 500 600

0 45 91 136 182 227 273

Fig. 3. Typical inlet steam

conditions with varying

plant capacities.


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Controlled extraction is required when the steam

pressure must be maintained at certain values dictated

by process use, which moreover exhibits varying flow

requirements. In such cases, it is necessary to fit a

valve between the stages up- and down-stream of each

controlled extraction. The valve serves to regulate

steam flow area of the control stage downstream of theextraction. Of course, this adds greater complexity and

expense to the unit, but the choice may an obligatory

one, if, as is often the case in industrial applications,

the process use cannot tolerate pressure variations.

In uncontrolled extraction, the steam is tapped at a

specific point between two stages. Naturally, the flow

rate of the extracted steam can be regulated via a valve

fitted on the collecting tubes, but the conditions of the

extracted steam, in particular its pressure, depend

entirely on its expansion and cannot thus be varied for

the process use.

Whether controlled or not, more than one steam

extraction can be carried out, since cogeneration plants

often feed two (or more) steam circuits at different

pressures. Moreover, it is common practice to extract

steam for use by the deaerator and, in plants of a

certain size, other (uncontrolled) bleeds are used to

feed surface exchangers in the feed-water preheating

line, both at low pressure (upstream from the

deaerator) and at high pressure (downstream of the

deaerator).

Steam-turbine operating conditionsAs already mentioned, the conditions under which

steam turbines operate vary widely; in turbines fed by

conventional steam generators, the conditions of the

steam at the inlet are chosen so as to optimize the

systems technical-economic efficiency, which leads to

the indicative values shown in Fig. 3; pressures and

temperatures increase with the size of the unit.

Although a number of promising proposals have been

advanced to push steam conditions to hypercritical

pressures and extremely high temperatures, to date,

none have found practical application.

5.2.3 Plants with internalcombustion prime movers

Alternative prime movers

Alternative prime movers are the most widespread

combustion engines in small power-output

applications, from a few kWe up to several MWe. As in

the case of gas turbines, recent developments in these

technologies have made great strides forward in terms

of performance and reliability. Their initial field of

application was vehicle drive systems, whence onlysubsequently was it extended to stationary applications.

The classification of such engines depends on the type

of thermodynamic cycle exploited: the Otto cycle, or

controlled ignition engine, in which combustion takes

place at approximately constant volume following an

initiating spark (by a spark plug); and the Diesel cycle,

or spontaneous ignition engine, in which combustion

occurs at approximately constant pressure without theneed for initiation by a separate device. To this end, the

temperature of the comburent (air) within the cylinder

must be particularly high, which is obtainable by virtue

of the higher compression ratios of Diesel engines

compared to Otto cycle engines, in which, on the other

hand, high compression ratios are to be avoided, so as

not to provoke the phenomenon of uncontrolled

spontaneous detonation (engine knocking).

As far as utilizable fuels are concerned, whereas

mainly liquid fuels are used in drive applications, in

stationary units, natural gas has earned widespread

adoption by virtue of its inherently clean

characteristics, which enable a signif icant reduction of

emissions, as well as maintenance costs, and promote

long engine lifetimes. Adapting existing Otto cycle

engines to use natural gas does not call for any

significant structural modifications, apart from the

obvious changes necessary to the feed system.

Adapting Diesel engines, on the other hand, calls for

rather more substantial changes because the very low

flammability of methane (the main constituent of

natural gas) makes it quite difficult to trigger

self-ignition. Thus, it is often necessary to resort todual fuel solutions, that is, injecting a small amount

(typically 5-10%) of diesel, together with the natural

gas to help initiate combustion.

The major advantage of alternative prime movers

for stationary applications is the high electrical

efficiencies attainable (ranging from 35% for

capacities of a few hundred kWe to 45% and beyond

for several MWe Diesel-based designs), which are

clearly superior to those obtainable with steam or gas

turbines of equal power. Some further positive features

of stationary applications of this technology are:

a) operating flexibility (rapid start-up, ability toregulate the load in a wide range of power output);

b) high reliability, mostly due to the great deal of past

experience with drive applications; c) modularity of

constituent components; the number of cylinders can

be varied as a function of the desired power capacity,

making the specific cost (euro/kWe) of these machines

relatively independent of the nominal power output;

d) widespread availability of maintenance services

and personnel, thanks to the large number

of automotive and naval versions requiring similar

upkeep procedures.

On the other hand, some of the negative aspects tobe taken into account are:




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Higher maintenance costs than other stationary

technologies; indeed, the rather high maintenance

requirements are one of the main reasons that often

make other technologies based on turbines

preferable for power outputs over a few MWe.

Rather high emissions of all the major pollutants

regulated by law (CO, HC, NOx and, for Diesels,particulate matter); in recent years significant

advances have been made in this f ield involving

modifying the combustion process (lean mixtures,

stratified charges, etc.), as well as fitting pollution

control devices to the cylinder exhaust system

(three-way catalytic converters, oxidizing reactors,

particulate filters, etc.). For years, the drive

towards ever-lower emissions has been the main

stimulus for the technological evolution of these

machines; in applications that call for NOxemissions comparable to those of the cleanest gas

turbines, processes of catalytic denitrification

(SCR, Selective Catalytic Reduction) are adopted.

Fig. 2 A (top) shows the layout of a simplified

cogeneration plant utilizing an alternative prime

mover. A positive feature of all plants with internal

combustion engines (with the exception of combined-

cycle plants with a steam section) is that heat recovery

does not, in any way, compromise the generation of

electricity: in fact, heat that would otherwise be

dissipated is put to good use.

There are four potential sources of heat for

cogeneration: Exhaust gases, which represent the

thermodynamically most valuable source in that it

is available at relatively high temperatures, ranging

from approximately 400 to 500C. In contrast to all

other heat recovery methods, heat from exhaust

gases enables steam to be produced at medium

pressures. Moreover, combustion products account

for 30-35% of the heat contained in the fuel. As a

result of the absence of sulphur, the use of natural

gas, permits maximum possible recovery, cooling

the exhaust gases down to 100-110C, without the

formation of corrosive acid condensates. Cooling water, which accounts for 10-20% of the

total fuel heat content, a fraction that is, however,

made available at temperatures below 100 C (to

avoid pressurizing the cooling circuit). Its recovery

clearly cannot be exploited to produce steam, but

the heat is instead used to produce warm water.

Lubricating oil also supplies low temperature heat,

at 75-90C, and accounts for 4 to 7% of the heat

input.

Supercharger air is available only in the case of

turbochargers engines, which, however, are used in

all high-power applications. To reduce the worknecessary for compression in the cylinder, the air

from the supercharger system is normally cooled to

60-80C; the quantity of heat recoupable through

this cooling process is in the same order of

magnitude as for lubrication oil.

In conclusion, a substantial fraction of the

recoupable heat is available at relatively low

temperatures. However, this is not a disadvantage forapplications that require water at relatively contained

temperatures (for example, distributed heating

networks). On the other hand, it can significantly

compromise the energy performance of alternative

prime movers in many industrial applications, in which

production processes usually require steam alone and

not warm water.

With regards to operating range, alternative prime

movers belong to the class of so-called

single-degree-of-freedom systems, by which the only

regulation possible is on the electrical power output;

once the power output has been fixed, the useful heat

produced can only be variednegativelyby dissipating

into the environment a part of the heat otherwise

recoupable. This situation is shown in Fig. 2 A (top

right) by the lineAP(A, at the technical minimum;P,

at full load), a situation analogous to gas turbines.

Gas turbine plants

Simple-cycle gas turbines, whether industrial or

aeroderivative, are clearly well-suited to cogeneration

applications; heat from the exhaust gases is technically

easy to recover and use in industrial processes (or forother thermal applications), either via a recovery

boiler or, in particular cases, through direct utilization

of the exhaust itself (for example, in high-temperature

industrial furnaces).

In the case of steam production, the recovery boiler

has characteristics similar to those used in combined



turbogas

afterburner

fresh-air firing(optional)

drum

thermaluser

bypass

Fig. 4. Schematic illustration

of a simple recovery gas turbine

cogeneration plant, with systems

for regulating heat output(exhaust bypass and boiler afterburner).


10/14

cycles. Due to the high temperature of the exhaust

gases, gas turbines enable production of steam with

highly desirable characteristics. It must, however, be

borne in mind that the quantity of steam produced

(and as a result, plant performance) falls, albeit

moderately, with an increase in pressure (and therefore

evaporation temperature). This is because such anincrease is accompanied by a corresponding increase

in the temperature of the flue gases and therefore a

greater loss of heat into the atmosphere. In this

situation, it should be recalled that the heat lost with

the exhaust gases is particularly high in gas turbines,

which operate with a large excess of air to limit the

inflow temperature to the turbine. Depending on

specific usage needs, the steam can be generated at

different pressure levels, producing a thermal

exchange that enables the exhaust gas temperatures to

be lowered. In the event that the adopted heat carrier

fluids do not undergo a phase change, such as water or

diathermic oil (less frequent in industrial processes),

the configuration is even simpler, consisting of a

single bank of tubes running counter to the gas flow.

Just as in the case of plants with alternative prime

movers, the recovery of heat does not alter the

performance of gas turbine systems, in terms of

electrical energy production, with the exception of a

pressure drop in the recovery boiler, which leads to a

modest back-pressure at the turbine exhaust.

The simpler plant layout (gas turbine-recovery

boiler) involves a strict coupling of the electrical and

thermal energy outputs (see again Fig. 2 A, centre

right). Such systems are therefore not amenable to the

flexible management required of cogeneration plants,

which are often called upon to satisfy variable

demands for electrical and thermal power over time.However, it is possible to adopt more complex designs,

which provide increased operating flexibility; one

example is represented in Fig. 4, which includes the

following additions compared to the simplif ied layout

in Fig. 2 A:

A diverter, inserted into the exhaust gas duct

connecting the gas turbine to the recovery boiler.

As its name implies, the diverter can direct a part

of, or even all, the gases directly to the external

environment through a bypass flue, thereby

regulating the quantity of heat transmitted to the

steam.

Afterburning system, capable of producing an

additional quantity of heat above that available

from the gas turbine exhaust gases. Afterburning,

which is only possible due to the high oxygen

content of the gases discharged from the turbine,

yields greater thermal efficiencies and lowers

investment costs (by exploiting the structure and

exchange surfaces of the recovery boiler itself).

Moreover, such systems have much more rapid

response times than conventional steam generators.

Fresh air firing fan that drives fresh air to theafterburning nozzles, with the purpose of

maintaining thermal production in the event of gas

turbine outages.

Such modifications yield the operating range

shown in Fig. 5 in the plot of electrical energy vs. heat,

in which the following curves are shown:

Normal operating line, which joins points des and

min; the first point indicates the units nominal

operation (full power), the second, the technical



Qu

E

engine regulation linewith full afterburning

smin

min

afterburningzone

zone withheat waste

engine regulation linewithout afterburning

sdes

des

Fig. 5. Operating range, in the plane

of electricity vs. heat, of a gas turbinecogeneration plant with afterburning.

turbogas

afterburner

drum

thermaluser

feed watersteam injection line

Fig. 6. Schematic illustration of a gas turbinecogeneration plant with steam injection.


11/14

minimum. As the electrical power output falls,

there is a corresponding decrease in the useful heat

extracted by the recovery boiler, independent of

any regulation of the gas turbine. Even though gas

turbines could operate normally even at null net

electrical output, modern gas turbines fitted withlow-emissions burners are subject to regulations on

specific emissions, which limit their operating

range to the minimum output at which stable

conditions of premixed combustion can be

ensured. For powers below the technical minimum

(or in the event of gas turbine outages), the heat

supply can be ensured by thefresh-airsystem,

which is operated with the diverter completely

isolated from the gas turbine.

Line of maximum afterburning, which joins points

sdes andsmin and represents the technical limits of

the system, due to the limitations imposed onafterburner outflow gas temperatures by the

structural characteristics of the recovery boiler

(HRSG, Heat Recovery Steam Generator), which

cannot normally sustain the high flame

temperatures typical of conventional boilers. This

limit is usually reached before complete

combustion of the oxygen present in the turbine

exhaust gases (short of a margin for O2 content,

which must, however, always be maintained to

avoid significant production of CO).

The two lines described above define the area in

the plane of electrical energy vs. heat (or electricalpower vs. thermal power) in which the cogeneration

system can operate without heat dissipation whereas

the area below the normal operating line represents the

operating conditions attainable by discharging some

heat into the environment.

A gas turbine with steam injection (Fig. 6) is a

further possible modification to the layout of a simple

recovery gas turbine plant which provides a furtherdegree of operational freedom; instead of being sent

for thermal process use, a part (or all, if technically

feasible) of the steam produced in the recovery boiler

can be injected into the combustor, depending on

whether priority is to be given to the production of

heat or electrical energy. This allows for far greater

flexibility in operations compared to the preceding

case, as shown in Fig. 7, which refers back to the

system illustrated in Fig. 2 A (lower right). The normal

operating line extends into the line des-max, which

represents the operation of the gas turbine maintained

at maximum power, with varying degrees of steam

injection, from zero to the maximum (in the example,

assumed to coincide with the entire flow produced by

the HRSG). Point max represents operations in the

case of production of electrical energy alone (all the

steam produced is injected into the combustors and

there is therefore no production of heat), while the

point des indicates when the entire steam flow is

directed to thermal usage, and the gas turbine

functions as a simple cycle. The line joining the two

points represents all the intermediate solutions. The

line min-des now represents gas turbine operations inthe absence of steam injection; the area under the line



Qu

E

line with fullafterburning


full load line

at variablesteam injection

smin

min

sdes

afterburningzone

operating zone

operating linewithout steam injection

smax

max

des

Fig. 7. Operating range, in the plane of electricity

vs. heat, of a gas turbine cogeneration plant with steam

injection and afterburning.

Qu

E


line with maximum afterburningwith ST due to

steam flow rate increase

line with GT atfull load and

variable steamextraction

smin

min

sdes

afterburningzone

operating zone

operating line GTSTwith maximumsteam extraction

smaxmax

des

Fig. 8. Operating range, in the plane of electricity

vs. heat, of a combined cycle cogeneration plant

with gas turbine and extraction-condensationsteam turbine with afterburning.


12/14



A

B

C

make-up

gas turbineLM2500

thermalusers

27,040 (0) kW

F76,506 kW

repowering: combined cycle with condensation and extraction

p50 bar p5.1 bar T106Ctotal electricity produced

26,350 kWnet electricity produced

26,150 kW

total electricity produced

5,840 (11,145) kWnet electricity produced

5,716 (11,030) kW

G10.97 kg/s

p46 bar

T480C

G214 kg/s

p5 bar

T200C

G10.76 kg/s

p5 bar

T226CG10.45 (0) kg/s

p5 bar

T222C

G2.45 kg/s

(G12.9 kg/s)

p0.11 bar

T47.7C

G86.9 kg/s

p1.04 bar

T533C

make-up

make-up

gas turbineLM2500

thermalusers

27,040 (0) kW

F61,065 kW

F36,345 kW

(h0.9)

repowering: combined cycle with back-pressure

existing back-pressure plant

p40 bar p5.1 bar T121C



20,934 kW



4,404 kW



2,842 kW

G9.35 kg/s

p37 bar

T420C

G9.19 kg/s

p5 bar

T213CG10.6 kg/s

T206C

G1.41 kg/s

p5 bar

T160C

G69.9 kg/s

p1.04 bar

T536C

G12.6 kg/s

p48 bar

T420C

G12.6 kg/s

p54 bar

T153C

G12.45 kg/s

p

5 barT187C

G1.7 kg/s G10.75 kg/s

p4.9 barG10.9 kg/s

T75C

thermalusers

27,040 (0) kW

Fig. 9. Heat balance

consequent to repowering

a pure back-pressure

steam cogeneration plant

via conversion to

combined cycle

operations.

F, available power;

G, mass flow;

p, pressure;

T, temperature.


13/14

min-des-max is no longer characterized by any thermal

dissipation, but its points can be obtained by suitable

regulation of the unit, both in terms of fuel flow and

injected steam; the system therefore becomes

considerably more efficient at low thermal loads. The

injection of steam, which enables low emissions to be

achieved with diffusion combustion systems, offers thefurther advantage of extending the field of operations

into the zones of low electrical power output. Similar

to the preceding case, the line of maximum

afterburning is extended into thesdes-smax, that is,

from no steam injection to maximum injection.

If, on the one hand, the injection of steam introduces

the above-mentioned operational advantages, it should

also be recalled that it significantly penalizes the

potential energy advantages of cogeneration. In fact,

releasing the reinjected steam into the atmosphere

significantly increases the loss of heat to the stack. The

effective ability to achieve significant energy savings

over the course of a year therefore depends on resorting

to steam injection only during limited periods of the

year, when low thermal demand is accompanied by high

need for electrical energy.

Combined-cycle plants

Combined cycles are finding ever more

widespread application in large-scale plants (electrical,

though not necessarily thermal); combined gas-steam

cycle plants, in fact, can be managed as cogeneration

systems if some hot fluid (steam, or less frequentlywater) is extracted for other uses from the steam

turbine and/or the recovery boiler. Although there is no

reason that the steam cycle cannot be simply a

modified back-pressure turbine (see again Fig. 2 B,

top), a more widespread solution is the adoption of an

extraction and condensation system (see again Fig. 2 B,

bottom), which guarantees greater operational

flexibility; the possibility to adjust the degree of

condensation (partial or total) allows the plant to

produce electrical energy economically, by virtue of

the high efficiencies typical of combined cycles, even

during periods of low or zero thermal demand.

A qualitative illustration of the operating range of a

combined-cycle cogeneration system in the plane of

electrical energy vs. heat is presented in Fig. 8, which

refers back to the system shown in Fig. 2 B (lower

right); the line min-des now represents the production

of useful energy with maximum steam extraction at

varying gas turbine loads; the electrical energyproduced also includes the contribution of the steam

turbine, whose power output varies with the steam

flow rate from the recovery boiler. The line des-max

represents the operating conditions with the gas

turbine at full load, with varying steam extraction,

which goes to zero at point max, where the plant

operates at full condensation. The points below these

two lines represent varying combinations of gas

turbine load and steam extraction, which, as in the

preceding case, do not involve any dissipation of heat

discharge from the gas turbine through the bypass flue.

Fig. 8 shows the operating range achievable with

afterburning; apart from the increase in useful heat,

afterburning yields an increase in the production of

electrical energy by virtue of the greater steam flow to

the turbine.

In contrast to simple-recovery gas turbine plants,

the pressure at which the steam is required influences

the generation of electrical energy because the steam

subtracted from the expansion yields power that varies

with the extraction pressure. The fundamental reason

underlying the advantages for cogeneration of

combined-cycle plants over its steam-cyclealternatives is their high electrical efficiency, which

provides significant energy savings and cost

reductions, even when there is limited demand for

thermal energy. These advantages are particularly

evident if one compares the performance of a

combined-cycle cogeneration plant with that of an

existing steam plant that has been repowered.

Consider the example in Fig. 9, which shows the

heat balances attainable by transforming a small-

size, back-pressure steam plant (fig. 9 A,Pe4.4

MWe) into a combined-cycle system, under two

different hypotheses: maintaining the back-pressure



Table 2. Power output ranges and characteristic indices (indicative mean values) of the cogeneration

plant designs illustrated in Fig. 9

Pe, TG Pe, TV Pe, tot Pc Qu hI he ht hII Iet hel,eq IPE

Case MW MW MW MW MW % % % % %

A 0 4.404 4.40 36.34 27.04 86.53 12.12 74.41 35.86 0.14 69.95 5.25

B 20.93 2.84 23.78 61.06 27.04 83.22 38.94 44.28 53.07 0.47 76.66 18.48

C 26.10 5.72 31.82 76.51 27.04 76.93 41.59 35.34 52.86 0.54 68.48 15.06


14/14

steam cycle with the same steam turbine, and

adding an aeroderivate gas turbine of about 20

MWe capacity (Fig. 9 B); adopting an extraction-

condensation steam cycle, which allows for more

flexible management of the plant according to

varying thermal demand; this involves fitting a

different steam turbine and a larger gas turbine(Fig. 9 C, about 26 MWe).

Comparing the various energy indices under the

same hypotheses adopted in Table 1 leads to the

results shown in Table 2. Given equal thermal

output for process use, the results are that: both the

combined-cycle solutions increase the plant overall

net power output (by a factor of 5.4 and 7.2,

respectively); the combined-cycle solution with a

pure back-pressure steam turbine yields the

maximum energy savings index, which is

nonetheless very high even for the extraction-

condensation system; the total and equivalent

electrical efficiencies, whose values are high even

for the initial arrangements, are also very high in

the combined-cycle solutions.

While the advantages of combined-cycle solutions

in terms of energy efficiency are indisputable, the

economy of repowering operations depends on many

factors, in particular, on the availability of high-quality

fuel to feed the gas turbine and the possibility of

profitably marketing the electrical energy produced.

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Ennio Macchi

Giovanni Lozza

Dipartimento di Energetica

Politecnico di Milano

Milano, Italy



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