Micro Gas Turbines

Abstract

This overview of the state of the art of MGTs has highlighted the critical function of heat recovery in enhancing the energy competitiveness of the technology. Cogeneration or trigeneration must therefore be viewed as native applications of MGTs. The main limitations of the MGT technology are the high sensitivity of electrical power production to ambient temperature and electrical efficiency. The dependence on ambient temperature can be mitigated by using IAC techniques; in particular, the fogging system was seen to be preferable under all respects to an ad hoc-designed direct expansion plant. Two options have been analysed to increase electrical efficiency: organic Rankine cycles and a STIG configuration. The former technology is easier to apply, since it does not require design changes to the MGT, but merely replacement of the recovery boiler with an organic vapour generator. Furthermore, the technology is already available on the market, since it has already been developed for other low-temperature heat recovery applications. In contrast, the STIG configuration requires complete redesign of the combustion chamber, as well as revision of both the control system and the housing. Both technologies enhance electrical efficiency to the detriment of global efficiency, since both discharge heat at lower temperature, so that cogeneration applications are often not feasible.

Full text

7
Micro Gas Turbines
Flavio Caresana1, Gabriele Comodi1,
Leonardo Pelagalli1 and Sandro Vagni2
1Dipartimento di Energetica – Università Politecnica delle Marche
2Università degli Studi e-Campus
Italy
1. Introduction
Conventional gas turbines (GTs) range from a size of one or a few MWe to more than
350 MWe (GTW, 2009). Those at the small end of the range are commonly used in industrial
applications, for mechanical or onsite electrical power production, while the larger ones are
usually installed in large-scale electrical power plants, often in combined cycle plants, and
are typically located far away from the consuming region.
In the future distributed energy systems based on small local power plants are likely to
spread; since they lie close to the final users, they reduce electrical transport losses, and
make thermal energy recovery profitable both in energy-related and in economic terms
(Papermans et al., 2005; IEA, 2002). These benefits explain the increasing interest in small-
size generation systems.
Recently, gas turbines < 1 MWe, defined as micro gas turbines (MGTs), have appeared on
the market. MGTs are different from large GTs and cannot therefore be considered merely
as their smaller versions. Their advantages as distributed energy systems lie in their low
environmental impact in terms of pollutants and in their competitive operation and
maintenance (O&M) costs. MGTs appear to be particularly well suited for service sector,
household and small industrial applications (Macchi et al., 2005; Zogg et al., 2007).
2. The technology of Micro Gas Turbines
The small power size of MGTs entails implications that affect the whole structure. In
particular the low gas mass flow rate is reflected in machine size and rotational speed: the
smaller the former, the greater the latter. MGTs therefore differ significantly from GTs,
mainly in (i) the type of turbomachines used; (ii) the presence of a regenerator; and (iii) the
high rotational speed, which is independent of grid frequency. In fact unlike GTs, MGTs
commonly use high-revving, single-stage radial turbomachines rather than multi-stage axial
ones, to achieve greater compactness and low manufacturing costs. As a consequence of the
high rotational speed, the electrical current is generated at high frequency and is then
converted to the grid frequency value (50 or 60 Hz) by power electronics. The
turbocompressor and turbine are usually fitted on the same shaft as the electrical generator,
which also serves as the starting motor. Single-stage radial machines afford limited
compression ratios and need a regenerative cycle to attain satisfactory electrical efficiency.

Gas Turbines
146
Therefore a regenerator is usually installed between the compressor and the combustion
chamber. Figures 1 and 2 show, respectively, the layout and corresponding thermodynamic
cycle of a typical cogeneration MGT.
EG GC GT
HRBR
CC
2
34
5
67
PE
Electricity
Fuel
Exhausts
Water
In
Water
Out
BPV
PE Power Electronics CC Combustion Chamber
EG Electrical Generator R Regenerator
GC Gas Compressor BPV ByPass Valve
GT Gas Turbine HRB Heat Recovery Boiler
Fig. 1. Layout of a typical cogeneration MGT
0
100
200
300
400
500
600
700
800
900
1000
3.6 3.8 4 4.2 4.4 4.6 4.8 5 5.2 5.4
s (kJ/(kg K))
t (°C)
Fig. 2. MGT regenerative Brayton-Joule cycle
The ambient air (1, in both figures) is compressed by the centrifugal compressor; it then
enters the regenerator (2), where it is preheated by the exhausts coming from the turbine,
and is conveyed from the regenerator (3) to the combustion chamber, where it is used in the
17
6
4
5
3
2

Micro Gas Turbines
147
combustion process to achieve the design turbine inlet temperature (4). The hot gases then
expand through the turbine (5) and enter the regenerator. Given their fairly high
temperature at the power unit exit (6), the exhausts can be sent to a heat recovery boiler
(HRB), where they are used to heat water, before being discharged to the flue (7). In this
configuration combined heat and power (CHP) production increases fuel energy conversion
efficiency. When the thermal power demand is lower than the power that can be recovered
from the exhausts, part of the fumes is conveyed directly to the chimney (7) via a bypass
valve (BPV). The core power unit is fitted with auxiliary systems that include (i) fuel, (ii)
lubrication, (iii) cooling, and (iv) control systems. The fuel feeding system compresses the
fuel to the required injection pressure and regulates its flow to the combustion chamber
according to the current operating condition. The lubrication system delivers oil to the
rolling components, with the dual effect of reducing friction and removing heat. The cooling
system keeps the operational temperatures of the different components, lubrication oil
included, in the design ranges. The cooling fluid can be air, water, or both. The function of
the electronic control system is to monitor MGT operation through continuous, real time
checking of its main operational parameters.
3. Operation modes
MGTs can usually operate in two modes:
1. Non-cogeneration (electricity production only): the MGT provides the electrical power
required by the user and all the available thermal power is discharged to the flue.
2. Cogeneration (combined production of electrical and thermal energy): the MGT
produces the electrical and thermal power required by the user. MGTs operating in
cogeneration mode can usually be set to work with electrical or with thermal power
priority.
a. Electrical priority operating mode
In this operating mode the MGT produces the electrical power set by the user,
while heat production is regulated by the BPV installed before the HRB. This is not
an energy efficiency-optimized operating mode, because in conditions of high
electrical and low thermal power demand a considerable amount of the recoverable
heat is discharged to the flue.
b. Thermal priority operating mode
Thermal priority operation involves complete closure of the MGT bypass valve, so
that all the exhaust gases from the regenerator pass through the HRB for thermal
power recovery. Thermal power production is regulated by setting the electrical
power. This mode maximizes MGT efficiency in all operating conditions.
4. Performance and emissions
The considerations made so far apply to most MGTs. The data presented below have been
obtained from theoretical studies and experimental testing of a specific machine, a
Turbec T100 PH (Turbec, 2002), which the authors have been using for their research work
for several years (Caresana et al., 2006). With due caution, these findings can be extended to
most MGTs. In this section, the performance and emissions of a real MGT-based plant are
reported and some criticalities connected to MGT behaviour highlighted.
The main performance parameters of an MGT are:

Gas Turbines
148
• electrical power el
P;
• thermal power th
P;
• electrical efficiency el
η
, defined as:
el
el
f
P
mLHV
η
= (1)
• thermal efficiency th
η
, defined as:
th
th
f
P
mLHV
η
= (2)
• total efficiency tot
η
, defined as:
el th
tot el th
f
PP
mLHV
η
ηη
+
==+
 (3)
where
f
m
and LHV are the mass flow rate and the Lower Heating Value of the fuel,
respectively.
Since electrical power is the main final output, we have represented the dependence of the
other performance parameters on Pel (Figures 3-7). Unless specified otherwise, the
experimental data refer to ISO ambient conditions, i.e. temperature and relative humidity
(R.H.) equal to 15 °C and 60 % respectively (ISO, 1989).
18
20
22
24
26
28
30
32
30 40 50 60 70 80 90 100 110
Electrical power (kW)
Electrical efficiency (%
)
Fig. 3. Electrical efficiency
Figure 3 plots the trend of the electrical efficiency, which is consistently high from the
nominal power down to a partial load of about 70 %, with a maximum slightly > 29 %
around 80 kWe. Figures 4 and 5 report the thermal power and total efficiency data,
respectively, for different degrees of BPV opening, calculated as the ratio between the
thermal power recovered and that which can be recovered at the nominal power. The tests
were conducted at a constant water flow rate of 2 l/s entering the HRB at a temperature of
50 °C.

Micro Gas Turbines
149
0
20
40
60
80
100
120
140
160
180
30 40 50 60 70 80 90 100 110
Ele ctrical power (kW)
Thermal power (kW)
0 %
60 %
88 %
100 %
Fig. 4. Thermal power for different degrees of BPV opening
0
10
20
30
40
50
60
70
80
30 40 50 60 70 80 90 100 110
Electrical po wer (kW)
Total efficiency (%)
0 %
60 %
88 %
100 %
Fig. 5. Efficiencies for different degrees of BPV opening
As expected, greater BPV opening entailed a progressive reduction in the thermal power
recovered, and consequently reduced total efficiency. This confirms that the thermal priority
cogeneration mode maximizes fuel energy conversion efficiency. Figure 4 shows that a small
part of the discharged thermal power is however transferred from the exhausts to the water,
even with a completely open BPV. If this thermal power (about 25 kW at full load) is
usefully recovered, total efficiency remains greater than electrical efficiency, as shown in
Figure 5, otherwise total and electrical efficiencies necessarily coincide.
Figures 6 and 7 show the level of pollutants CO and NOX, respectively. CO concentrations in
the exhausts are low from 70 % to 100 % of the load, but they rise steeply with lower loads.
The NOX concentration is very low in all working conditions.

Gas Turbines
150
0
200
400
600
800
1000
1200
1400
1600
1800
30 40 50 60 70 80 90 100 110
Electrical power (kW)
CO (ppmv)
Fig. 6. CO concentration @ 15 % O2
0
1
2
3
4
5
6
7
30 40 50 60 70 80 90 100 110
Electrical power (kW)
NOx (ppmv)
Fig. 7. NOX concentration @ 15 % O2
50
70
90
110
130
-25 -15 -5 5 15 25 35
Ambient temperature (°C)
Pel (kW)
26
28
30
32
34
Electrical efficiency (%)
Fig. 8. Electrical performance vs ambient temperature

Micro Gas Turbines
151
4.1 Influence of ambient parameters
The performance of MGTs, like those of GTs, are strongly affected by ambient conditions,
particularly temperature. Figure 8 shows the values of nominal electrical power and
efficiency as a function of the ambient temperature. In the T100 PH machine, electrical
power generation at temperatures < 0 °C is limited electronically, to avoid overworking the
machine. The decline observed at higher temperatures is explained by the lower air density
and consequently lower mass flow rate through the power unit. A parallel decrease in
electrical efficiency can also be noted.
4.2 Influence of heat recovery
The performance of a cogeneration system can be evaluated by comparison with the
separate production of heat and electricity. The most commonly used index is the Primary
Energy Saving (PES) index which, as the name suggests, quantifies the primary energy
savings offered by a CHP plant compared with (conventional) separate production of
electrical and thermal energy.
The PES index is calculated as (European Parliament, 2004):
__
1
1
el th
el re
f
th re
f
PES
ηη
ηη
=−
+
(4)
where:
• el
η
and th
η
are the electrical and thermal efficiencies of the cogeneration system
averaged over a given period; and
• _el re
f
η
and _th re
f
η
are the reference values of efficiency for separate production of
electrical and thermal energy.
A positive value of the index means that the primary energy consumption of the CHP
system is lower compared with separate production over the time period considered.
Figure 9 shows the PES index of a Turbec T100 PH in different operating conditions for
0
20
40
60
80
100
020406080100
Electrical efficiency (%)
Thermal efficiency (%)
0 %
60 %
88 %
100 %
PES = 0
PES = 0.1
PES = 0.2
Total efficiency = 1
Fig. 9. PES for different degrees of BPV opening

Gas Turbines
152
different degrees of BPV opening, calculated considering values of 40 % and 90 % of _el re
f
η
and _th re
f
η
, respectively. It is worth noting that heat recovery is crucial to achieve a positive
PES. In fact, even minor opening of the BPV adversely affects the index. This confirms that
thermal priority operation (0 % BPV opening) is the mode maximizing fuel savings and
consequently that it is preferable to the electrical priority mode.
5. Enhancing performances
As noted above, major limitations to the further spread of MGTs are their lower electrical
efficiency compared with their main competitors, i.e. reciprocating engines, and lower
electrical power production at rising ambient temperatures. Their main advantages, low
emissions and competitive O&M costs, do not seem to offset these drawbacks.
In the following paragraphs we describe the research work being conducted by the Systems
for Energy and the Environment team of Dipartimento di Energetica, Università Politecnica
delle Marche, Ancona, Italy, to enhance MGT performance. We employed the same MGT
model that was used to obtain the experimental performance and emissions data, focusing on:
1. Inlet Air Cooling (IAC);
2. Bottoming organic Rankine cycles;
3. Micro STIG;
4. Trigeneration.
5.1 Inlet Air Cooling (IAC)
The simplest way to limit the power reduction consequent to rising ambient temperature is
to cool the air entering the compressor.
The air intake system of the MGT studied consists of a single duct carrying the working air
and the cooling air, which both enter a single ambient inside the cabinet. From here part of
the air is sucked in by the compressor, while the remaining air flow is conveyed to the
cooling system via an external fan. Clearly, only the air processed by the compressor
influences performance. Hence the need for separating the two flows, in order to cool only
the working air. This can be achieved with minimum changes to the MGT cabinet and by
mounting a cooling system in the working air inlet duct.
For the MGT model studied ice formation in the air flow and on the walls, a common risk in
GTs, is excluded by the manufacturer, who states extreme working condition (-25 °C air
temperature, 100 % R.H.) that are much more severe than those that can be achieved with
any cooling system.
We used a test bed to evaluate two different IAC techniques:
• direct expansion IAC system;
• fogging IAC system.
The tests were conducted in the summer in the ambient condition of an Adriatic seaside
town in central Italy.
Direct expansion IAC system
This system consists of a refrigerating engine, whose evaporator is housed directly in the
working air intake duct. The refrigerating engine and the condenser fans are electrically
driven by means of inverters, to improve efficiency. The system uses R507A as the
refrigerating fluid and is designed to keep the inlet air temperature at the value set by the
user, external ambient conditions and refrigerating engine power permitting. In fact,

Micro Gas Turbines
153
although an inlet air cooled temperature of 15 °C (ISO, 1989) was set for all the tests, it was
not reached consistently. As an example, Figures 10 and 11 show the electrical power and
efficiency, respectively, in relation to ambient temperature, R.H., and corresponding IAC
temperature over 200 time steps (about 15 min), with the machine working at maximum
load. Since the R.H. was greater than the design R.H. (50 %), the minimum IAC temperature
that could be achieved was slightly > 15 °C (about 17 °C).
0
20
40
60
80
100
0 50 100 150 200
Time steps
Gross electrical power (kW)
Net electrical power (kW)
Electrical power according to
ambient temperature (kW)
Amb ie nt R.H. (%)
Amb ie nt temperature (°C)
IAC temperature (°C)
Fig. 10. Effects of the direct expansion IAC system on inlet air and MGT electrical power
production
0
5
10
15
20
25
30
35
0 50 100 150 200
Time steps
50
55
60
65
70
75
80
85
R.H.
Electrical efficiency (%)
Electrical effici ency acco rdi ng
to ambient temperature (%)
Ambient temperature (°C)
IAC temperature (°C)
Ambient R.H. (%)
Fig. 11. Effects of the direct expansion IAC system on inlet air and MGT electrical efficiency
The IAC temperature induced a significant increase in gross electrical power production,
from about 80 kW (without IAC) to around 95 kW.
However, the net electrical power, which is the crucial output, reached only 84 kW, due to the
strong influence of the refrigerating engine performance: the lower its coefficient of
ηel, t

Gas Turbines
154
performance (COP), the higher its consumption and the lower the net electrical power of the
MGT. The COP thus emerges as a crucial parameter, since an excessively low COP can entail a
net electrical power even lower than the one without IAC. The COP measured during these
tests was about 2.5. The power increase notwithstanding, the consumption of the refrigerating
engine adversely affects the electrical efficiency of the MGT. To sum up, the direct expansion
IAC system can be used to increase electrical power, but it does not enhance efficiency.
Fogging IAC system
This system cools the inlet working air via adiabatic saturation (Chaker et al., 2000). The
main components of the apparatus are nozzles (4 in our test bed) and a high-pressure pump.
Demineralized water is pumped at a pressure of 70 bar to the nozzles, housed in the intake
duct, and is then nebulized as droplets whose diameter is usually < 20 µm (Chaker et al.,
2002). The fogging system thus achieves nearly total adiabatic saturation by cooling the air
to wet bulb temperature, which is the lowest achievable temperature, at an R.H. of about
100 %. For this reason, the final cool air temperature cannot be preset, but is strongly
dependent on ambient conditions: the drier the air, the greater the temperature reduction.
Figures 12 and 13 show electrical power and efficiency, respectively, over a period of 200
time steps with the machine working at its maximum load. Thanks to the IAC temperature,
electrical power production increases from about 84 kW to 88 kW, but unlike in the direct
expansion IAC system, here it is very close to the net electrical power, since the high-
pressure pump consumes only 550 W. Furthermore, the fogging system slightly improves
electrical efficiency, by about 1 %.
In conclusion, both IAC techniques were effective in limiting the electrical power reduction
consequent to rising ambient temperature. Despite the comparable power gain, the fogging
technique is however preferable, ambient conditions permitting, since besides enhancing
efficiency it involves a much simpler and, last but not least, cheaper plant. Expansion
techniques would be interesting if the refrigerating engine were also used for other
purposes, such as air conditioning of large spaces (e.g. shopping malls, cinemas, office
blocks). Since air conditioning plants are designed on the warmest local conditions, they
work at partial load most of the time; the residual power could therefore be used for IAC.
0
20
40
60
80
100
120
0 50 100 150 200
Time steps
Ele ctr ical power (kW)
Electrical power according to
ambient temperature (kW)
Ambient R.H. (%)
Ambient temperature (°C)
IAC temperature (°C)
Fogging outlet R.H. (%)
Fig. 12. Effects of the fogging IAC system on inlet air and MGT electrical power production

Micro Gas Turbines
155
0
5
10
15
20
25
30
35
0 50 100 150 200
Time steps
50
55
60
65
70
75
80
85
R.H.
Electrical efficiency (%)
Electrical efficiency according
to ambient temperature (%)
Amb ient temperature (°C )
IAC temperature (°C)
Amb ient R.H. (%)
Fig. 13. Effects of the fogging IAC system on inlet air and MGT electrical efficiency
5.2 Bottoming organic Rankine cycles
The solution proposed here aims to enhance the electrical efficiency of the MGT by
recovering the heat lost, producing additional electricity. This goal can be achieved with a
micro combined cycle using bottoming organic Rankine cycles (Caresana et al., 2008). This
micro combined configuration consists of an MGT, a Heat Recovery Vapour Generator
(HRVG), and a bottoming vapour plant (Figure 14). This solution minimizes the changes to
the standard CHP model, since it merely requires replacing the original HRB with an
HRVG. The MGT exhausts enter the HRVG and are discharged to the environment after
heating the bottoming working fluid. The vapour generated in the HRVG expands through
a turbine that drives an electrical generator.
C
EG
GC
MTG
EG
P
1 2
HRVG
CC
VT
4
GT
R
3
Ex OutEx In
EG Electrical Generator GC Gas Compressor
GT Gas Turbine CC Combustion Chamber
R Regenerator C Condenser
VT Vapour Turbine HRVG Heat Recovery Vapour Generator
P Pump
Fig. 14. Layout of the micro combined plant
ηel, t

Gas Turbines
156
Clearly, this configuration greatly affects the cogeneration plant’s performance, since the
thermal energy is discharged at the bottoming cycle condenser at very low temperatures.
Selection of the bottoming cycle working fluid
Whereas traditional, large-size, combined plants commonly use water as the bottoming
cycle working fluid, organic fluids seem to be more appropriate in micro scale plants,
because their thermodynamic properties are better suited to the low temperature of the
exhausts leaving the MGT. Compared with steam, organic fluids allow both more compact
solutions, by virtue of their higher density, and simpler layouts, by virtue of their
significantly narrower density variation through evaporation and expansion.
This work does not examine some common, technically suitable organic fluids, i.e.
chlorofluorocarbons (CFCs), because they have been banned (United Nations, 2000), and
hydrochlorofluorocarbons (HCFCs), because they will be banned in the European Union,
from January 1st 2015 (European Parliament, 2000). Therefore the choice necessarily falls on
hydrofluorocarbons (HFCs) due to thermo-physical and technical criteria. In fact, the fluid
in question needs to be:
• thermally stable in the range of pressures and temperatures involved in the cycles;
• non-toxic;
• non-corrosive;
• non-explosive;
• non-flammable;
• compatible with the plant’s process component materials;
• low ozone-depleting;
• global warming-neutral.
HFCs meeting these criteria include R245ca, R245fa, R134a, R407C and R410A, the last two
being mixtures. Their liquid-vapour curves are reported in a T-s diagram in Figure 15 and
their critical properties in Table 1.
0
20
40
60
80
100
120
140
160
180
0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0
s (kJ/(kg K))
t (°C)
R245ca
R245fa
R134a
R407C
R410A
Fig. 15. T-s diagrams of five HFC organic fluids

Micro Gas Turbines
157
In particular Figure 15 shows that R245fa and R245ca are “dry fluids”, R407C and R410A are
“wet fluids”, and R134a is an almost “isoentropic fluid”. A dry fluid is one whose vapour
saturation curve with reference to a given temperature interval has a positive slope on a T-s
diagram (dT/dS>0); a wet fluid is one having a negative slope (dT/dS<0), and an
isoentropic fluid is a fluid having a vertical saturation line (dT/dS= ∞).
R245ca R245fa R134a R407C R410A
Temperature (°C) 174.42 154.05 101.06 86.03 71.36
Pressure (MPa) 3.925 3.640 4.059 4.630 4.903
Table 1. Critical points of the five HFCs
Bottoming cycles
Vapour cycles can be: (i) non-superheated or Rankine type; (ii) superheated or Hirn type; or
(iii) supercritical. Steam cycles are commonly superheated, due to thermodynamic efficiency
requirements and to the need for limiting droplet condensation during vapour expansion
through the turbine. With organic cycles the latter problem is partially addressed by proper
selection of the working fluid. Use of a dry fluid prevents droplet condensation in the
turbine even without superheating. In fact, at a suitable evaporating pressure the expanding
dry fluid does not enter the liquid-vapour equilibrium zone and condensation does not take
place, even starting from the saturated vapour line. However, superheating is still a valuable
option, since the benefit of removing the superheater must be weighed against the
consequent decrease in efficiency. In this subsection we present the results of simulations,
performed with an in house-developed program, where different vapour cycle
configurations were tested using the five organic fluids mentioned above.
Since the exhaust mass flow rate and outlet temperature of the MGT studied are known, the
bottoming cycles can be defined completely by setting the values of the following
parameters:
• vapour cycle condensing pressure, c
p
;
• HRVG pressure, v
p
;
• vapour cycle maximum temperature, 3
t.
Furthermore, setting the exhaust temperature at the HRVG outlet, Ex Out
t, allows calculation
of the thermal power that can be recovered from the exhausts, _trec
P, as:
(
)
__trec e
gp
e
g
Ex In Ex Out
Pmctt=⋅ ⋅ −
 (5)
where e
g
m
and _
p
e
g
c are the exhaust mass flow rate and its specific heat, respectively.
Considering the HRVG as adiabatic, the organic fluid mass flow rate, V
m
, is therefore:
_trec
V
in
P
mq
=
 (6)
where in
q is the heat received by the organic fluid unit of mass (see fluid states of
Figure 14), which is equal to the increase in enthalpy through the HRVG:
32in
qhh
=
− (7)

Gas Turbines
158
The condensing pressure c
p
depends closely on the temperature of the cooling fluid at the
condenser, _c
f
in
t, and results in a condensing temperature, c
t, of:
_ccfin cf
tt t
τ
=
+Δ + (8)
where, as shown in Figure 16, c
f
t
Δ
is the temperature increase of the cooling fluid through
the condenser and
τ
is the temperature difference between the condensing organic fluid
and the cooling fluid at the outlet.
The values of
τ
and c
f
t
Δ
are the result of a technical and economic trade-off. The lower
these values, the lower the condensing temperature and the greater the cycle’s efficiency, as
well as the heat exchanger’s surface and cost. The study considers four condensing
technologies, of which the water-cooled system is the most appropriate. However, it also
addresses cooling technologies that reduce the amount of water needed, such as cooling
towers, or that completely obviate the need for it, such as air condensers for use at sites
where water is not consistently available. Finally, it examines condensation with water
coming from a panel heating system, which makes the plant a micro combined cogeneration
system. The condensing technologies considered, the assumed values of _c
f
in
t,c
f
tΔ,
τ
and
the resulting c
tand c
p
are reported in Table 2.
Thermal power
Tem peratur e
Organic fluid
Cooling fluid
Fig. 16. Condenser heat exchange diagram
_c
f
in
t c
f
t
Δ
τ
c
t
Condensing technology
(°C) (°C) (°C) (°C)
Condenser cooled by ambient air 15 8 7 30
Condenser cooled by ambient water 12 8 7 27
Condenser cooled by water from cooling tower 15 8 7 30
Condenser cooled by water from panel heating 30 5 7 42
Table 2. Main parameters of the condensing technologies
An air temperature of 15 °C and an R.H. of 60 % are assumed for condensers cooled by
ambient air and by water from a cooling tower, according to the ambient ISO conditions
considered for the gas cycle. In particular, the temperature of the water from the cooling
Δ
tcf
τ
1
4
4′

Micro Gas Turbines
159
tower is assumed to be 4 °C warmer than the wet bulb temperature of the air, which is about
11 °C in ISO conditions. For the water cooled condenser, the ambient water temperature is
assumed to be 12 °C. Finally, if the heat discharged by the vapour cycle is recovered in a
panel heating plant, it is considered to require water at 35 °C, which then returns to the
condenser at 30 °C.
Once pc has been calculated, all relevant plant parameters can then be obtained using the set
of equations listed in Table 3, where the indexes refer to the points in Figures 14-22 and the
assumed efficiencies are listed in Table 4.
The efficiency of the combined plant was then optimized for Rankine, Hirn and supercritical
bottoming cycles using this set of equations (eqs. 5-18).
For each condensing pressure, the optimization process involved identification of the
combination of pv and t3 maximizing the efficiency of the combined plant and meeting the
following conditions:
1. minimum vapour quality at the turbine outlet equal to 0.9;
2. minimum temperature difference, min
τ
, of 15 °C between the exhausts and the organic
fluid inside the HRVG.
The heat exchange and T-s diagrams of the different cycle configurations examined are
reported in Figures 17-22.
Vapour cycle output heat per
unit of mass 41out
qhh
=
− (9)
Vapour cycle expansion work
per unit of mass 34 34
()
turbine is turbine
lhhhh
η
=
−= − ⋅ (10)
Vapour cycle pumping work
per unit of mass
21
21 is
pump
p
um
p
hh
lhh
η
−
=−= (11)
Vapour cycle thermodynamic
efficiency
turbine
p
um
p
in
ll
q
η
−
= (12)
Vapour cycle electrical power
()
___
__
pump
el V turbine m t el
g
vaux
mp elp
l
Pl m
η
ηη
ηη
⎡⎤
⎛⎞
⎢⎥
⎜⎟
=⋅⋅− ⋅⋅
⎜⎟
⋅
⎢⎥
⎝⎠
⎣⎦
 (13)
Combined plant electrical
power __el CC el el V
PPP
=
+ (14)
Combined plant electrical
efficiency
_
_
el CC
el CC
f
P
mLHV
η
=⋅
 (15)
Vapour cycle thermal power
output _th CC V out
Pm
q
=
⋅
 (16)
Combined plant thermal
efficiency
(panel heating system)
_
_
th CC
th CC
f
P
mLHV
η
=⋅
 (17)
Combined plant global
efficiency
(panel heating system)
__
_
el CC th CC
gCC
f
PP
mLHV
η
+
=⋅
 (18)
Table 3. Equations used to define the main parameters of the combined plant

Gas Turbines
160
Turbine efficiency turbine
η
0.75
Turbine mechanical efficiency _mt
η
0.98
Electrical generator efficiency _el
g
η
0.97
Pump efficiency
p
um
p
η
0.70
Pump mechanical efficiency _m
p
η
0.98
Pump motor electrical efficiency _el
p
η
0.92
Auxiliary system efficiency (water-cooled condenser and panel
heating system) * aux
η
0.90
Auxiliary system efficiency (air condenser and cooling tower)* aux
η
0.80
* The power used by fan coils is assumed to reduce the auxiliary system efficiency of the air-cooled
condenser and of the cooling tower
Table 4. Efficiency values assumed for the calculations
Thermal power
Temperatur e
Exhausts
Org ani c flui d
Fig. 17. Rankine cycle heat exchange diagram
0
50
100
150
200
1.01.21.41.61.82.0
s (kJ/(kg K))
t (°C)
Fig. 18. Rankine cycle
2′
2
τ
mi
n
1 ≈ 2
4
4is
3
2′
3
Ex I
n
Ex Out
4′

Micro Gas Turbines
161
Thermal power
Temperature
Exhausts
Org anic fluid
Fig. 19. Hirn cycle heat exchange diagram
0
50
100
150
200
1.01.21.41.61.8 2.02.2
s (kJ/(kg K))
t (°C)
Fig. 20. Hirn cycle
Thermal power
Temperature
Exhausts
Org anic fluid
Fig. 21. Supercritical cycle heat exchange diagram
Ex I
n
1 ≈ 2
4
4is
3
2′2″
2
2′
3
τ
mi
n
Ex Out
2″
Ex I
n
2
3
τ
mi
n
Ex Out
4′

Gas Turbines
162
0
50
100
150
200
250
1.01.21.41.61.8 2.02.2
s (kJ/(kg K))
t (°C)
Fig. 22. Supercritical cycle
Performance and results
As expected, the optimization process highlighted that the ambient water condensing
technology maximizes the power production of all bottoming cycle configurations with all
the organic fluids studied, thus also maximizing both the power production and the
electrical efficiency of the whole micro combined plant. The main results of the optimization
processes for the ambient water condenser are reported for illustrative purposes in Table 5,
where the operating data of each cycle configuration and organic fluid are compared. Only
the dry fluids R245 ca and R245 fa are entered for the Rankine cycle. For the Hirn cycle the
evaporating pressure is clearly lower than the critical one.
Table 5 shows the organic fluids R245ca and R245fa to be those offering the best
performance, with slightly better results for the former. Even though these fluids can be
employed in Rankine cycles, achieving an electrical efficiency of 36 - 37 %, compared with
the original 30 % of the MGT, better results are achieved with the Hirn (37 %) and,
especially, the supercritical cycle (37 - 38 %). The performances of the latter cycles are
slightly better than that of the Rankine cycle, but they are based on significantly higher
values of HRVG pressure and of t3. The Rankine bottoming cycle therefore remains a good
option, due to the lower pressure and temperature levels and to the simpler plant
configuration.
The results of the optimization process of the ambient water condenser with R245fa
supercritical cycles are shown in Figure 23, where the electrical power produced by the
bottoming cycle is plotted as a function of the evaporating pressure and is parameterized
with reference to the t3.
The electrical power that can be achieved based on tc with R245ca supercritical cycles as a
function of the evaporating pressure is reported in Figure 24 with reference to the water
cooling technology. These data are also representative of the other condensing technologies,
the only difference being the efficiency of the auxiliary system.
1 ≈ 2
4
4is
3
4′

Micro Gas Turbines
163
Supercritical
pv t
v
η
v
m
 _el V
P _el CC
P _el CC
η
Working fluid (MPa) (°C) (%) (kg/s) (kW) (kW) (%)
R245ca 7.82 226 17.11 0.577 26.57 126.57 38.01
R245fa 8.92 226 16.51 0.594 25.66 125.66 37.74
R134a 8.25 181 13.71 0.702 21.13 121.13 36.38
R407C 8.33 161 11.78 0.736 17.89 117.89 35.40
R410A 9.65 160 11.74 0.716 17.66 117.66 35.33
Hirn
pv t
v
η
v
m
 _el V
P _el CC
P _el CC
η
Working fluid (MPa) (°C) (%) (kg/s) (kW) (kW) (%)
R245ca 3.72 186 16.24 0.586 25.37 125.37 37.65
R245fa 3.63 183 15.15 0.598 23.68 123.68 37.14
R134a 4.05 180 11.54 0.604 17.94 117.94 35.42
R407C 4.33 162 9.34 0.630 14.47 114.47 34.38
R410A 4.60 162 8.36 0.601 12.93 112.93 33.91
Rankine
pv t
v
η
v
m
 _el V
P _el CC
P _el CC
η
Working fluid (MPa) (°C) (%) (kg/s) (kW) (kW) (%)
R245ca 2.45 148 15.10 0.658 23.62 123.62 37.12
R245fa 2.31 129 13.66 0.728 21.32 121.32 36.43
Table 5. Condenser cooled by ambient water (tc = 27 °C)
Fig. 23. Pel_V as a function of pv and t3 for an R245fa supercritical cycle at tc = 27 °C
Pel_V (kW)
pv(MPa)
3.6 6.64.6 5.6 7.6 8.6
24.5
24.0
23.5
23.0
22.5
22.0
21.5
21.0
25.0
25.5
26.0
t3 = 227.0 °C
214.5 °C
202.0 °C
189.5 °C
177.0 °C
4.1 5.1 6.1 7.1 8.1

Gas Turbines
164
Fig. 24. Pel_V as a function of pv and tc for an R245ca supercritical cycle
Figure 24 confirms that the lower the condensing pressure, the more the electrical power
generated; this applies to all the organic fluids studied. Nevertheless, despite the influence
of the high condensing temperature on electrical performances, the cogeneration solution
with the panel heating system results in increased global efficiency due to heat recovery.
5.3 Micro STIG
The acronym STIG stands for “Steam-Injected Gas” turbines, a technique used to improve
the electrical and environmental performance of large-size GTs. The enhanced electrical
power production and system efficiency are related to the different composition and
quantity of the working fluid mass flowing through the turbine, due to the steam injected
into the combustion chamber zone. The steam also involves a reduction in the combustion
temperature and therefore of the NOx formed in the exhausts.
Our group has recently addressed the advantages of applying the well-known STIG
technique to MGTs, from a theoretical standpoint.
In the micro STIG plant layout reported in Figure 25 the original HRB is replaced with a heat
recovery steam generator (HRSG), which produces the steam to be injected into the
combustion chamber.
The aim was to devise a mathematical model of the micro STIG plant. Each component was
defined by a set of equations describing its mass and energy balances and its operating
characteristics, the most significant of which are the performance curves of the
turbomachines.
The model was used to assess the influence of steam mass flow rate on electrical power and
efficiency. Figures 26 to 28 report examples of the preliminary results obtained with the
model. In particular, Figures 26 and 27 show electrical power and efficiency, respectively, as
a function of the injected steam mass flow rate in fixed thermodynamic conditions (10 bar
and 280 °C). Figure 28 shows, for a given flow rate (50 g/s), the trend of the electrical
efficiency as a function of steam pressure and temperature.
4.5 6.55.0 6.05.5 7.0 7.5 8.0 8.5
27
26
25
24
23
22
21
tc = 27 °C
30 °C
Pel_V (kW)
pv(MPa)
33 °C
36 °C
39 °C
42 °C

Micro Gas Turbines
165
GCEG
HRSG
CC
GT
R
Steam
Water
EG Electrical Generator GC Gas Compressor
GT Gas Turbine CC Combustion Chamber
R Regenerator HRSG Heat Recovery Steam Generator
Fig. 25. Layout of the STIG cycle-based micro gas turbine
Fig. 26. Electrical power vs. injected steam mass flow rate
Fig. 27. Electrical efficiency vs. injected steam mass flow rate
Electrical power (kW)
In
j
ected steam mass flow rate (
g
/s)
0 1020304050
140
130
120
110
Electrical efficiency (%)
In
j
ected steam mass flow rate (
g
/s)
01020304050
36
34
33
32
35

Gas Turbines
166
Preliminary simulations showed that the more steam is injected the greater are electrical
power and efficiency. Nevertheless, the amount of steam that can be injected is affected on
the one hand by the thermal exchange conditions at the HRSG—which limit its
production—and on the other by the turbine choke line, which limits the working mass flow
rate.
Once the amount of steam to be injected has been set, the higher its temperature and
pressure, the greater the electrical efficiency.
Fig. 28. Electrical efficiency vs. injected steam thermodynamic state
We are currently conducting a sensitivity analysis to assess the thermodynamic state and the
amount of injected steam that will optimize the performance of the STIG cycle.
5.4 Trigeneration
The issue of heat recovery has been addressed in paragraph 4.2. Cogeneration systems are
characterized by the fact that whereas in the cold season the heat discharged by the MGT
can be recovered for heating, there are fewer applications enabling useful heat recovery in
the warm season. In fact, apart from industrial processes requiring thermal energy
throughout the year, cogeneration applications that include heating do not work
continuously, especially in areas with a short winter. The recent development of absorption
chillers allows production of cooling power for air conditioning or other applications. This
configuration, where the same plant can simultaneously produce electrical, thermal and
cooling power, is called trigeneration. The main components of an actual trigeneration
plant, designed by our research group for an office block, is shown in Figure 29. The plant,
whose data acquisition apparatus is still being developed, consists of a 100 kWe MGT (right)
coupled to a heat recovery boiler (centre) and to a 110 kWf absorption chiller (left). The
exhausts can be conveyed to the boiler or to the chiller, the latter being a direct exhausts
model.
Electrical efficiency (%)
Steam temperature (K) Steam pressure (MPa)
32
33
34
35
0.7
0.6
550
500 0.8 0.9 1.0 1.1
450

Micro Gas Turbines
167
Fig. 29. Trigeneration plant
6. Conclusions
This overview of the state of the art of MGTs has highlighted the critical function of heat
recovery in enhancing the energy competitiveness of the technology. Cogeneration or
trigeneration must therefore be viewed as native applications of MGTs. The main limitations
of the MGT technology are the high sensitivity of electrical power production to ambient
temperature and electrical efficiency. The dependence on ambient temperature can be
mitigated by using IAC techniques; in particular, the fogging system was seen to be
preferable under all respects to an ad hoc-designed direct expansion plant.
Two options have been analysed to increase electrical efficiency: organic Rankine cycles and
a STIG configuration. The former technology is easier to apply, since it does not require
design changes to the MGT, but merely replacement of the recovery boiler with an organic
vapour generator. Furthermore, the technology is already available on the market, since it
has already been developed for other low-temperature heat recovery applications.
In contrast, the STIG configuration requires complete redesign of the combustion chamber,
as well as revision of both the control system and the housing. Both technologies enhance
electrical efficiency to the detriment of global efficiency, since both discharge heat at lower
temperature, so that cogeneration applications are often not feasible.
7. Acknowledgements
This work was supported by the Italian Environment Ministry and by the Marche Regional
Government (Ancona, Italy) within the framework of the project "Ricerche energetico-
ambientali per l'AERCA di Ancona, Falconara e bassa valle dell'Esino".
Thanks to Dr. Silvia Modena for the language review.

Gas Turbines
168
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