**4.2 Direct internal heat recovery**

Direct internal heat recovery, achieved by transferring thermal energy from the gas turbine exhaust to the compressed air upstream from the combustor, is represented by curve OC on the characteristic plane.

At point O the temperature difference on the hot side of the regenerator (Δ*TRG*) is zero. Since there is no heat exchange between exhaust gas and air at the compressor exit, gas turbine efficiency coincides with the baseline simple cycle with no heat recovery. Moving along the curve OC the temperature difference increases, as well as regenerator effectiveness and gas turbine efficiency, reaching a maximum value at point C, corresponding to a temperature difference of 40 ° C.

Neglecting pressure losses, point C shows a slight power derating with respect to the reference plant (point O) due to the smaller amount of primary fuel introduced into the combustor.

To evaluate the influence of pressure ratio and the turbine inlet temperature on efficiency increase through thermodynamic regeneration, it suffices to compare the OC curve of the different baseline non-recovery gas turbines. As shown in Figure 9, efficiency gain is maximised at low pressure ratios and high turbine inlet temperatures. Focusing the attention on point C, we see that direct recovery parameter (*ξ*=-*χ*) increases from 0.08 at low maximum gas temperature (*TTI*=1200°C) and high pressure ratio (*β*=20) up to 0.24 at *TTI*=1300°C and *β*=15. Consequently, the efficiency ratio *η/η\** passes from 1.08 to 1.29, the efficiency *η* of the regenerative cycle from 42.9% to 48.9% and the flue gas temperature *TFG* from 470°C to 420°C.

### **4.3 Indirect internal heat recovery**

The points inside the region OAB (Fig. 9) represent performance achievable with waste heat recovery performed by steam injection upstream from the combustion chamber. This region

Curves HI and JK represent the performance obtained for external heat recovery through a bottoming steam cycle (combined cycle). In particular, the curve HI refers to the case of a combined cycle with one pressure level at the HRSG, whereas curve JK to a combined cycle with three pressure levels and reheat. Points H and J correspond to the case of combined cycle without supplementary firing, the primary energy supplied from outside (*χ* = 0) remaining the same. Points I and K correspond instead to the case of supplementary firing using exhaust gases exiting the turbine and setting the limit temperature at the duct burner

Without supplementary firing, the combined cycle with three pressure levels HRSG and reheat (point J) is the leading solution in power generation, providing efficiencies of 54.6%- 56.8% in the explored range of *β* and *TIT*, higher by 2-3 percentage points than those obtained with one pressure level HRSG (point H). With supplementary firing, the further power increase is obtained at the expense of efficiency (I and K). Only in the case of one pressure level HRSG, with modest additional combustion and low values of *TIT*, a slight improvement in performance is achieved, as a result of the greater recovery feasible at low

Direct internal heat recovery, achieved by transferring thermal energy from the gas turbine exhaust to the compressed air upstream from the combustor, is represented by curve OC on

At point O the temperature difference on the hot side of the regenerator (Δ*TRG*) is zero. Since there is no heat exchange between exhaust gas and air at the compressor exit, gas turbine efficiency coincides with the baseline simple cycle with no heat recovery. Moving along the curve OC the temperature difference increases, as well as regenerator effectiveness and gas turbine efficiency, reaching a maximum value at point C, corresponding to a temperature

Neglecting pressure losses, point C shows a slight power derating with respect to the reference plant (point O) due to the smaller amount of primary fuel introduced into the combustor.

To evaluate the influence of pressure ratio and the turbine inlet temperature on efficiency increase through thermodynamic regeneration, it suffices to compare the OC curve of the different baseline non-recovery gas turbines. As shown in Figure 9, efficiency gain is maximised at low pressure ratios and high turbine inlet temperatures. Focusing the attention on point C, we see that direct recovery parameter (*ξ*=-*χ*) increases from 0.08 at low maximum gas temperature (*TTI*=1200°C) and high pressure ratio (*β*=20) up to 0.24 at *TTI*=1300°C and *β*=15. Consequently, the efficiency ratio *η/η\** passes from 1.08 to 1.29, the efficiency *η* of the regenerative cycle from 42.9% to 48.9% and the flue gas temperature *TFG*

The points inside the region OAB (Fig. 9) represent performance achievable with waste heat recovery performed by steam injection upstream from the combustion chamber. This region

**4.1 Direct external heat recovery** 

**4.2 Direct internal heat recovery** 

the characteristic plane.

difference of 40 ° C.

from 470°C to 420°C.

**4.3 Indirect internal heat recovery** 

exit to 800 ° C.

temperatures.

is bounded by two curves at *ξ*=0 (OA and OB) and by the curve AB corresponding to the minimum temperature difference at pinch point of the heat recovery steam generator (*ΔTPP*=10°C). As mentioned above, the slope of the curve with *ξ*=0 depends on the gas turbine plant with no heat recovery, *η\** and on marginal efficiency *ηAF*.

In particular the curve OA refers to the case of maximum marginal efficiency *ηAF* obtained by injecting steam superheated to the same temperature as the turbine exhaust, while curve OB refers to the case of minimum *ηAF*, corresponding to injection of saturated steam. The entire region can be covered varying the hot side temperature difference in the superheater and the minimum temperature difference in the evaporator.

Efficiency gains due to steam injection diminish with steam temperature, while both steam mass flow rate and power produced increase. In practice the power increase is limited by problems associated with the large water requirements and compressor-turbine matching.

To evaluate the influence of *β* and *TTI* on steam injection capabilities, points A and B are examined. In both cases, steam mass flow rate as well as power increase with temperature, while the opposite trend is observed when pressure ratio is increased.

In particular, at point A (superheated steam) the mass flow rate increase passes from a minimum of 20% at low maximum gas temperature (*TTI*=1200°C) and high pressure ratio (*β*=20) to 30% at *TTI*=1300°C and *β*=15. On the other hand, at point B (saturated steam) the mass flow rate increase ranges from 34 to 55%, under the same pressure and turbine inlet temperature conditions.

### **4.4 Combined internal heat recovery**

Performances associated with points inside the region OCDA (Fig. 9) can only be obtained considering recovery techniques that combine direct (thermodynamic regeneration) and indirect recovery (steam injection). The effects associated with the auxiliary fluid occur in different ways, with regard to marginal efficiency value (*ηAF*), which depends on the thermodynamic conditions of the auxiliary fluid upstream from the combustion chamber.

The region OCDA can be covered varying the hot side temperature difference in the regenerator and the minimum temperature difference in the evaporator.

Heat can also be indirectly recovered using unconventional techniques, such as humid air regeneration and steam reforming of the fuel.

The performance of HAT plants is represented by the points on curve CE. Keeping the hot side temperature difference in the regenerator at 40°C, curve CE has been obtained increasing the mass of water introduced into the saturator from zero (point C) to the maximum permissible value for saturation of the compressed air upstream from the regenerator (point E). On this curve the value of *ξ*, defined at point C, remains constant, since this parameter is established by the capabilities of the plant with no heat recovery with respect to thermodynamic regeneration.

Gas turbine plants with chemical recovery are represented on curve FG, where methane is used as primary fuel. The methane reforming process is described by the following two reactions:

The Recovery of Exhaust Heat from Gas Turbines 181

instability phenomenon, the axial compressor operates in nominal conditions, with a certain

However, when steam injection occurs, both the mass flow rate and the turbine inlet pressure increases. The compressor follows the turbine behaviour by increasing the

Therefore the injection rate must be regulated to keep the pressure ratio below the surge line. In practice, for existing gas turbines, injected steam flow rate is limited to 10% of the

Moreover, the water introduced into the gas turbine may create problems associated with availability and treatment and with the mass flow rate increase through the expander.

In the presence of low-temperature heat users, the exhaust gases could be cooled down to 50

The water can be condensed in an indirect surface heat exchanger, that uses water or ambient air to cool the exhaust gas or in a direct-contact condenser, where water is sprayed

Large amounts of water are required for partially condensing steam, so these power plants should be located near to water sources (sea, lakes, rivers). In cases of low water availability, "closed loop" refrigeration is conducted, sending the water at the condenser outlet to a

To ensure proper operation of the gas turbine, the limit on maximum flow rate increase at the turbine inlet, results in a reduction of the maximum performance achievable by the

In this regard, Figure 11 shows the characteristic plane of heat recovery for a baseline gas turbine *TIT* = 1300°C and *β=15*. In this plane, the dash-dot line curve refers to an increase in mass flow rate at the turbine inlet of 10%. As shown in Figure 11, the performance region for steam injection is significantly reduced, passing from OAB to OA'B'; similarly the region

compression ratio and, consequently, approaching the surge line.

Fig. 10. Gas turbine operating line in dry and wet conditions [17]

**4.5.1 Effect of limits on the characteristic plane of heat recovery** 

° C, in order to achieve partial water condensation.

different internal heat recovery techniques.

margin from the surge region.

compressor inlet air flow [18].

into the exhaust gas [2].

cooling tower.

$$\rm{CH}\_4 + \rm{H}\_2\rm{O} \rightarrow \rm{CO} + \rm{3H}\_2\tag{6}$$

$$CO + H\_2O \to H\_2 + CO\_2 \tag{7}$$

The reforming reaction (Eq. (6)) is highly endothermic and is favoured by higher temperatures, lower pressures and higher steam-to-methane mole ratios. The water gas shift reaction (Eq. (7)), slightly exothermic, favours lower temperatures and is unaffected by pressure [16].

Keeping the hot side temperature difference in the reformer at 40°C, curve FG refers to steam reforming performed varying the steam-to-methane mole ratio from the stoichiometric value n=2 (point F) to the maximum value corresponding to the minimum pinch point temperature difference (point G).

Curve FG is characterized by a steep slope, for increasing values of *ξ*. In fact, the thermal energy directly recovered, denoted with *ξ*, is the chemical energy variation associated with the reforming process that increases with steam-to-methane mole ratio (n).

The influence of *β* and *TTI* on combined internal heat recovery capabilities are discussed focusing the attention on points representing maximum heat recovery conditions for each solution: point D for regenerative steam injected cycle, point E for humid air regenerative cycle, point G for chemically recuperated cycle.

For regenerative steam injected cycle (point D) at high turbine inlet temperature (*TTI*=1300°C) and low pressure ratio (*β*=15), direct and indirect recovery have comparable effects on *χ*; therefore primary fuel energy introduced into the cycle remains practically unchanged, while efficiency exceeds 54.3%, due to the significant power increase (*π*=0.45). On the contrary, at *TTI*=1200°C and *β*=20, effects of indirect recovery prevail, producing a higher power increase (*π*=0.54) and a lower efficiency gain (*η/η\**=1.3).

For humid air regenerative cycle (point E), efficiency gains achievable are higher than the regenerative steam injected cycle (point D), particularly at high maximum gas temperature and low pressure ratio. At *TTI*=1300°C and *β*=15, HAT plants attain efficiencies of up to 55%, limiting the relative mass flow rate increase in the turbine to 10%.

In the case of the chemically recuperated cycle (point G), since steam methane reforming reactions prefer low pressure and high temperature, the greatest efficiency gains are obtained at high turbine inlet temperature and low pressure ratio. At *TTI*=1300°C and *β*=15, methane conversion ratio is close to 55% and, consequently, efficiency increases up to 53.8%.

## **4.5 Limits of indirect internal heat recovery**

Steam injection in a gas turbine is affected by operational constraints related to compressorturbine matching, defined on the basis of the characteristic curves of turbomachines. Figure 10 shows a typical axial compressor map, bounded above by the surge line and below by the choke line. Operation limits in the surge region are due to an increase in the angle of incidence between the fluid and the compressor blades, produced by a decrease in fluid flow rate or an increase in rotational speed. Any excessive increase of the angle of incidence may cause fluid separation and flow reversal, generally accompanied by strong noise and violent vibrations which can severely damage the machinery. In order to avoid this

The reforming reaction (Eq. (6)) is highly endothermic and is favoured by higher temperatures, lower pressures and higher steam-to-methane mole ratios. The water gas shift reaction (Eq. (7)), slightly exothermic, favours lower temperatures and is unaffected by

Keeping the hot side temperature difference in the reformer at 40°C, curve FG refers to steam reforming performed varying the steam-to-methane mole ratio from the stoichiometric value n=2 (point F) to the maximum value corresponding to the minimum

Curve FG is characterized by a steep slope, for increasing values of *ξ*. In fact, the thermal energy directly recovered, denoted with *ξ*, is the chemical energy variation associated with

The influence of *β* and *TTI* on combined internal heat recovery capabilities are discussed focusing the attention on points representing maximum heat recovery conditions for each solution: point D for regenerative steam injected cycle, point E for humid air regenerative

For regenerative steam injected cycle (point D) at high turbine inlet temperature (*TTI*=1300°C) and low pressure ratio (*β*=15), direct and indirect recovery have comparable effects on *χ*; therefore primary fuel energy introduced into the cycle remains practically unchanged, while efficiency exceeds 54.3%, due to the significant power increase (*π*=0.45). On the contrary, at *TTI*=1200°C and *β*=20, effects of indirect recovery prevail, producing a

For humid air regenerative cycle (point E), efficiency gains achievable are higher than the regenerative steam injected cycle (point D), particularly at high maximum gas temperature and low pressure ratio. At *TTI*=1300°C and *β*=15, HAT plants attain efficiencies of up to 55%,

In the case of the chemically recuperated cycle (point G), since steam methane reforming reactions prefer low pressure and high temperature, the greatest efficiency gains are obtained at high turbine inlet temperature and low pressure ratio. At *TTI*=1300°C and *β*=15, methane conversion ratio is close to 55% and, consequently, efficiency increases up to 53.8%.

Steam injection in a gas turbine is affected by operational constraints related to compressorturbine matching, defined on the basis of the characteristic curves of turbomachines. Figure 10 shows a typical axial compressor map, bounded above by the surge line and below by the choke line. Operation limits in the surge region are due to an increase in the angle of incidence between the fluid and the compressor blades, produced by a decrease in fluid flow rate or an increase in rotational speed. Any excessive increase of the angle of incidence may cause fluid separation and flow reversal, generally accompanied by strong noise and violent vibrations which can severely damage the machinery. In order to avoid this

the reforming process that increases with steam-to-methane mole ratio (n).

higher power increase (*π*=0.54) and a lower efficiency gain (*η/η\**=1.3).

limiting the relative mass flow rate increase in the turbine to 10%.

pressure [16].

pinch point temperature difference (point G).

cycle, point G for chemically recuperated cycle.

**4.5 Limits of indirect internal heat recovery** 

4 2 <sup>2</sup> *CH H O CO H* + →+ 3 (6)

*CO H O H CO* + →+ 2 22 (7)

instability phenomenon, the axial compressor operates in nominal conditions, with a certain margin from the surge region.

However, when steam injection occurs, both the mass flow rate and the turbine inlet pressure increases. The compressor follows the turbine behaviour by increasing the compression ratio and, consequently, approaching the surge line.

Fig. 10. Gas turbine operating line in dry and wet conditions [17]

Therefore the injection rate must be regulated to keep the pressure ratio below the surge line. In practice, for existing gas turbines, injected steam flow rate is limited to 10% of the compressor inlet air flow [18].

Moreover, the water introduced into the gas turbine may create problems associated with availability and treatment and with the mass flow rate increase through the expander.

In the presence of low-temperature heat users, the exhaust gases could be cooled down to 50 ° C, in order to achieve partial water condensation.

The water can be condensed in an indirect surface heat exchanger, that uses water or ambient air to cool the exhaust gas or in a direct-contact condenser, where water is sprayed into the exhaust gas [2].

Large amounts of water are required for partially condensing steam, so these power plants should be located near to water sources (sea, lakes, rivers). In cases of low water availability, "closed loop" refrigeration is conducted, sending the water at the condenser outlet to a cooling tower.

## **4.5.1 Effect of limits on the characteristic plane of heat recovery**

To ensure proper operation of the gas turbine, the limit on maximum flow rate increase at the turbine inlet, results in a reduction of the maximum performance achievable by the different internal heat recovery techniques.

In this regard, Figure 11 shows the characteristic plane of heat recovery for a baseline gas turbine *TIT* = 1300°C and *β=15*. In this plane, the dash-dot line curve refers to an increase in mass flow rate at the turbine inlet of 10%. As shown in Figure 11, the performance region for steam injection is significantly reduced, passing from OAB to OA'B'; similarly the region

The Recovery of Exhaust Heat from Gas Turbines 183

However, steam injection can be seen as the only indirect recovery technique introducing an innovative scheme, whereby steam injection is not used as a means of traditional internal heat recovery, reintroducing steam into the gas turbine combustion chamber. On the contrary heat is recovered externally, generating steam for repowering an

The design concept of the proposed scheme is shown in Figure 12. As discussed in [19], it is based on the addition of a gas turbine and a heat recovery steam generator to an existing combined cycle. The integration of new components into the baseline combined cycle is achieved by injecting the steam generated by the additional HRSG into the combustion

The power increase is, thus, the sum of the power produced by the new gas turbine and the additional power generated in the original combined cycle, by the additional steam flow in

The pressure required to inject steam into the turbine is relatively low compared to that usually employed in steam turbines. Therefore the additional heat recovery steam generator can have a single pressure level and a low pinch point, thereby reducing stack temperature

Another significant benefit of this solution is the ability to generate additional power without the need to find new sites, simply improving utilization of electricity generation sites where combined cycle plants are already installed, without affecting their excellent performance and environmental compatibility. Another significant feature of the proposed repowering scheme is its operational flexibility. Because of the inherent flexibility of the gas turbine, the entire additional section can be switched off in a short time, yielding a part load efficiency equal to that of the original plant. An international (PCT) patent application has

> Existing Combined Cycle Power Plant

Fig. 12. Schematic diagram of combined cycle repowering through steam injection

L.P.

H.P. I.P.

existing combined cycle.

**5.1 Description of the repowering scheme** 

chamber of the existing combined cycle.

(close to 120°C) and hence increasing exhaust heat recovery.

been filed for the proposed repowering scheme [20].

G.T. G.T.

the gas turbine and steam cycle.

Added Section

related to combined recovery (obtained by means of thermodynamic regeneration and steam injection) is reduced from OCDA to OCD'A'.

### **Indirect external heat recovery**

The issue of limiting the maximum flow rate increase at the turbine inlet can be overcome by carrying out indirect external heat recovery, represented by curve OL in Figure 11. This recovery option, which will be discussed in detail in the following paragraph, is achieved by injecting superheated steam produced in the combustion chamber of an existing combined system. The existing combined cycle has a three pressure levels HRSG, with characteristics similar to those indicated in the following paragraph. Efficiencies defined by curve OL are assessed in marginal terms, i.e. appropriately taking into account only primary energy and power output increases attributable to the steam injected into the combustion chamber.

The curve OL shows the typical trend of internal recovery through steam injection (curve OA'). However, this recovery option is not affected by limits on the maximum steam flow rate, the gas turbine being appropriately sized for integration with the existing combined cycle, in order to keep steam injection flow rates below 10% of the air flow at the compressor inlet.

Moreover, it is interesting to note that the slope of curve OL is greater than curve OA, due to the improved performance of the combined cycle compared to the simple gas turbine. This allows to better exploit the injected steam, leading to higher efficiency gains.

Fig. 11. Characteristic plane of heat recovery restricted by limiting the maximum injected steam flow rate to 10% of the compressor inlet air flow (*OL: Steam injection within an existing combined cycle*)

### **5. Repowering of combined cycle power plants through steam injection**

The analysis carried out by means of the characteristic plane of heat recovery has shown that steam injection cannot compete with combined heat recovery techniques, such as humid air regeneration or fuel steam reforming.

related to combined recovery (obtained by means of thermodynamic regeneration and

The issue of limiting the maximum flow rate increase at the turbine inlet can be overcome by carrying out indirect external heat recovery, represented by curve OL in Figure 11. This recovery option, which will be discussed in detail in the following paragraph, is achieved by injecting superheated steam produced in the combustion chamber of an existing combined system. The existing combined cycle has a three pressure levels HRSG, with characteristics similar to those indicated in the following paragraph. Efficiencies defined by curve OL are assessed in marginal terms, i.e. appropriately taking into account only primary energy and power output increases attributable to the steam injected into the combustion chamber.

The curve OL shows the typical trend of internal recovery through steam injection (curve OA'). However, this recovery option is not affected by limits on the maximum steam flow rate, the gas turbine being appropriately sized for integration with the existing combined cycle, in order to keep steam injection flow rates below 10% of the air flow at the compressor

Moreover, it is interesting to note that the slope of curve OL is greater than curve OA, due to the improved performance of the combined cycle compared to the simple gas turbine. This

Fig. 11. Characteristic plane of heat recovery restricted by limiting the maximum injected

**5. Repowering of combined cycle power plants through steam injection** 

The analysis carried out by means of the characteristic plane of heat recovery has shown that steam injection cannot compete with combined heat recovery techniques, such as

steam flow rate to 10% of the compressor inlet air flow (*OL: Steam injection within an existing combined cycle*)

humid air regeneration or fuel steam reforming.

allows to better exploit the injected steam, leading to higher efficiency gains.

steam injection) is reduced from OCDA to OCD'A'.

**Indirect external heat recovery** 

inlet.

However, steam injection can be seen as the only indirect recovery technique introducing an innovative scheme, whereby steam injection is not used as a means of traditional internal heat recovery, reintroducing steam into the gas turbine combustion chamber. On the contrary heat is recovered externally, generating steam for repowering an existing combined cycle.

### **5.1 Description of the repowering scheme**

The design concept of the proposed scheme is shown in Figure 12. As discussed in [19], it is based on the addition of a gas turbine and a heat recovery steam generator to an existing combined cycle. The integration of new components into the baseline combined cycle is achieved by injecting the steam generated by the additional HRSG into the combustion chamber of the existing combined cycle.

The power increase is, thus, the sum of the power produced by the new gas turbine and the additional power generated in the original combined cycle, by the additional steam flow in the gas turbine and steam cycle.

The pressure required to inject steam into the turbine is relatively low compared to that usually employed in steam turbines. Therefore the additional heat recovery steam generator can have a single pressure level and a low pinch point, thereby reducing stack temperature (close to 120°C) and hence increasing exhaust heat recovery.

Another significant benefit of this solution is the ability to generate additional power without the need to find new sites, simply improving utilization of electricity generation sites where combined cycle plants are already installed, without affecting their excellent performance and environmental compatibility. Another significant feature of the proposed repowering scheme is its operational flexibility. Because of the inherent flexibility of the gas turbine, the entire additional section can be switched off in a short time, yielding a part load efficiency equal to that of the original plant. An international (PCT) patent application has been filed for the proposed repowering scheme [20].

Fig. 12. Schematic diagram of combined cycle repowering through steam injection

The Recovery of Exhaust Heat from Gas Turbines 185

CC model designation GE S109FA Number and model of GT 1 x PG9351FA

Pressure ratio 15.4 Exhaust gas temperature, °C 610.6 Exhaust gas mass flow rate, kg/s 626.6 Net output, MW 254.2 Net efficiency, % 37.1

HP steam pressure, bar 125.1 HP steam mass flow rate, kg/s 69.7 IP steam pressure, bar 28.0 IP steam mass flow rate, kg/s 16.1 LP steam pressure, bar 4.2 LP steam mass flow rate, kg/s 9.8 Condenser pressure, kPa 5.1 Net CC output, MW 386.7 Net CC efficiency, % 56.3

Varying *β* (from 10 to 30), *TTI* (from 1200 to 1600°C) and degree of superheat (saturated and superheated steam), the repowering unit has always been rated such that the amount of steam generated for injection into the existing combined cycle matches the required *μ* value. To avoid compressor and turbine matching problems, considering that General Electric has offered injection for power augmentation for 40 years on all of its production machines [18], a steam-to-air mass ratio *μ*=5% is assumed, corresponding to 30.6 kg/s of steam injected into

As shown in Figure 13, injection of superheated steam produces higher values of marginal

Marginal power output increases with *β*, while it is little influenced by *TTI*; for a pressure ratio of 30, superheated steam injection produces a power increase of 165 MW, of which about 60% (102 MW) produced by the added gas turbine. On the contrary, marginal efficiency is strongly influenced by *TTI*, especially at high pressure ratios*.* In this regard, for the added gas turbine operating at *β*=30, marginal efficiency attains 53.1% at *TTI*=1200°C and

More interestingly, the proposed repowering scheme offers the possibility of maintaining high efficiency over a wide range of marginal power outputs. In fact, marginal efficiency is strongly influenced by existing CC and added GT characteristics, but only slightly by the steam-to-air mass ratio *μ*. As shown in Figure 14, by varying *μ* from 3% to 9%, repowering

Therefore, though the steam mass flow rate for injection is limited by compressor and turbine matching problems or water availability and treatment requirements, the proposed repowering scheme could be beneficially implemented, as it is still characterized by high

can generate a marginal power output of up to 100 MW and 300 MW, respectively.

Table 2. Design performance of baseline combined cycle

**Gas turbine**

**Steam cycle**

the GE S109FA combustor.

57.4% at *TTI*=1600°C.

power and efficiency, for any *β* and *TTI*.

marginal efficiency and significant marginal power.

The major drawback of this configuration is water consumption related to the flow entering the new HRSG, which is inevitably lost at the stack. This can limit the applicability of the present scheme to sites with large fresh water availability, though the specific water requirements are fairly low, as shown in [19].

Moreover, if a low temperature thermal load is available near the power plant, water can be recovered through steam condensation. The implementation of a water recovery technique has to be carefully evaluated, because of the very large size and the very low temperature level of such a heat sink.
