industrial cogeneration
TRANSCRIPT
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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
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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.
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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
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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
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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.
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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
429VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY
INDUSTRIAL COGENERATION
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).
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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
430 ENCYCLOPAEDIA OF HYDROCARBONS
POWER GENERATION FROM FOSSIL RESOURCES
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.
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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
431VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY
INDUSTRIAL COGENERATION
Qu
E
line with fullafterburning
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 fullafterburning
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.
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432 ENCYCLOPAEDIA OF HYDROCARBONS
POWER GENERATION FROM FOSSIL RESOURCES
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
total electricity produced
21,134 kWnet electricity produced
20,934 kW
total electricity produced
4,631 kWnet electricity produced
4,404 kW
total electricity produced
3,050 kWnet electricity produced
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.
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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
433VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY
INDUSTRIAL COGENERATION
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
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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
434 ENCYCLOPAEDIA OF HYDROCARBONS
POWER GENERATION FROM FOSSIL RESOURCES