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From the perspective of energy security and environmental sustainability, highly effective uses for fossil fuel in energy industries are demanded. Power plants having integrated gasification combined cycle (IGCC) with advanced configurations are being developed worldwide to use coal and biomass more efficiently and thus cleanly. Gasification forms the major component within the IGCC systems and has the best fuel flexibility of any of the advanced technologies for power production, with the current technology well adapted to use biomass and other low-value feedstock that have high-ash residues (Liu and Niksa, 2004). Gasification also provides an opportunity to control and reduce gaseous pollutant emissions, and a lowest cost approach to concentrate the carbon dioxide at high pressure to facilitate sequestration (Trapp, 2005).

The gasifier operating conditions include temperature, pressure, air/oxygen stream, steam requirement, and the end product conditions (Higman and Burgt, 2003). Sugiyama et al. (2003) reported the performance of gasification process in multi-staged enthalpy extraction technology (MEET) system. Numerical simulation of coal gasification in entrained flow coal gasifier was performed and the corresponding gasification details were reported by Watanabe and Otaka (2006) in support of the numerical model. Performance of gasification in a pressurized fluid-ized bed gasifier were observed through the high temperature Winkler process setup by Bhattacharya (2006) with about 90% carbon conversion of Australian lignite. Yun et al. (2007) found various factors that affect the performance of the gasifier in an IGCC system. The factors considered were conversion efficiencies, moisture content, sulphur content, ash content, ash-melting temperature, slag viscosity, slag characteristics, and coal reactivity. They found that the best coal type for IGCC applications appears to be the one that contains low ash content with low-enough slag viscosity and high reactivity in coal. A review of co-gasification of coal, petroleum coke, and up to 10% of several types of biomass was done by

I. Dincer et al. (eds.), Global Warming, Green Energy and Technology,

DOI 10.1007/978-1-4419-1017-2_9, © Springer Science+Business Media, LLC 2010

Valero and Uson (2006). The influence of fuel variation in gasifier efficiency and modifications in operation that should be made in oxy-co-gasification are obtained. The performance enhancement for an IGCC using different supplementary firing options revealed (Gnanapragasam et al., 2008) that the specific net CO2 emissions are the highest for the case without supplementary firing and the lowest for the case with partial gasification.

Fig. 9.1 Integrated gasification combined cycle power plant configuration under investigation to study the performance of the gasifier.

The effect of the gasifier/gasification performance within an IGCC power generation system as shown in Fig. 9.1 is hard to find since the proposed system is new way of improving the IGCC performance with lower CO2 emissions. The current work focuses on the performance of gasification process based on two of the gasi-fier-operating conditions: (i) air flow rate and (ii) steam flow rate. The effect of these two conditions on the CO2 emissions of the IGCC system is investigated. The relation between feedstock (source fuels) and CO2 emissions of gas and steam cycles are established by using four different solid fuels in the gasification process. The fuels are selected based on decreasing carbon content and heating value and they are anthracite, lignite, loblolly pine, and wood chips. The amount of CO2 emitted is correlated to the carbon content and heating value of the feedstock based on the estimation of specific CO2 emission. The effect of operating conditions of the combined cycle within the IGCC system on the gasifier performance is also investigated. This is achieved by setting different temperature conditions at three locations within the IGCC, namely compressed air inlet temperature to the gas turbine combustion chamber; gas turbine inlet temperature; and inlet temperature to the HRSG. The effect of temperature conditions of the combined cycle on relative CO2 emission is estimated to find the optimal cycle operating temperature where moderate network output and corresponding CO2 emission are expected. The proposed IGCC system provides opportunities to investigate these effects in detail so that it can be applied for full scale IGCC facility.

9.2 Partial Gasification-Based IGCC System

9.2.1 Partial gasification process

Partial gasification allows only part of the solids fed into the gasifier to be converted into gas, while retaining some of the solid carbon elements to be combusted in a supplementary combustor to improve the system performance. Gasification (partial or full) of coal and its pressurized fluidized bed combustion are the two most important developments for the topping gas cycle (McMullan et al., 1997) in a combined cycle arrangement for power generation. As an improvement to the basic combined cycle, simultaneous introduction of partial gasification and pressurized fluidized bed combustion of coal in the topping gas cycle has already been proposed (De and Nag, 2000a). A synthesis of some existing proposals (Cai and Gou, 2007) adopts partial gasification to reduce the primary investment of the gasification equipment. The un-gasified surplus solid is then fed to a pressurized fluidized bed boiler similar to the system in this work as shown in Fig. 9.1.

9.2.2 Proposed IGCC system with supplementary firing

The IGCC configuration considered in this study (Fig. 9.1) uses coal gasification to convert coal to a fuel gas (syngas) which is fired in the gas turbine combustion chamber (GTCC) creating high-temperature pressurized gas which expands in the high-pressure gas turbine (HPGT). The gas is then reheated in the reheat combus-tor (RHC) which also uses syngas from the gasifier to generate the required thermal energy. The heated low-pressure gas expands in the low-pressure gas turbine (LPGT). The LPGT exhaust is directed to the supplementary firing arrangement to increase its temperature before entering the heat recovery steam generator (HRSG). The resulting high-temperature gases pass through the HRSG, generating steam that drives a two-stage steam turbine in the bottoming cycle. The supplementary firing combustor/furnace has three purposes: (i) reheat the gas turbine exhaust (from T9 to T10); (ii) pre-heat the compressed air before it enters the gas turbine combustion chamber (from T4 to T5); and (iii) reheat the low-pressure steam in the steam cycle (from T13 to T14).

9.3 Thermodynamic Analysis

The mass balance is accompanied by the chemical balance of species involved with reactants and products. The gas turbine combustion chamber, reheat combus-tor, supplementary firing combustors involve combustion processes burning syngas (fuel gas) and char/coal in them. The enthalpy at each state is estimated based on basic thermodynamic relations, here the chemical balance of the combustion processes are listed followed by the mass and energy balance of the combustion processes.

9.3.1 Gasification and combustion reactions

The chemical reaction during partial gasification of coal follows the form (Nag and Raha, 1994) which is based on the Amagat model for ideal gas mixtures:

coal

air steam

Fuel Gas

char

The combustion reactions for the GTCC and the reheat combustor within the gas cycle for all cases are as follows:

(i) Gas turbine combustion chamber (GTCC)

( FCO2c02+ FCOc0 + FpH2H2+ ^ FFg' IFCO.ch4 + FN,PGn3 +FHS,PGh3oJ + ^ +3'76N2) - (9.2)

FCO2PGCCO2 + FstPGCH2O + FN2PGCN2 + FO2PGCO2

(ii) Reheat combustor

FFg21 FCH4CH4 + FN2PGN2 + FstpG^oJ + ( FCO2PGCCO2 + FstPGCH2O ( FCO2PRHCO2 + FstPRHH2O

I FN,PGCN2+ FO,PGCO2 J I FN,PRHN2+ FO,PRHO2 J

(iii) Char combustor f_Additional coal when used_^

MCch (C) + (FCO2PRHCO2 + FstPRHH2O + FN2PRHN2 + FO2PRHO2 ) +

(FCO2PCCCO2 + FstPCCH2O + FN2PCCN2 + FO2PCCO2

Materials are supplied such that, following the balances, there is always sufficient oxygen present in the product gases to permit any subsequent combustion.

9.3.2 Mass and energy balance

The mass and energy balances for the gas cycle (GTCC, HPGT, RHC, and LPGT) are the same for all four supplementary cases. The enthalpy and mass flow rate of the GTCC products exiting at state 6 are h6 = (™aGCh5 + FFg1™FghFg + FFg1™FgHHVFg) /(gC) (9J)

The enthalpy and mass flow rate of the reheat combustor products exiting at state 8 are h8 = ( mhGCh7 + FFg2™Fg hFg + FFg2™FgHHVFg ) 1 ((RH ) (9J)

™RH = ™GC + FFg2™ Fg = ™aGC + FFg1™Fg + FFg2™Fg (9.8)

The enthalpy and mass flow rate of the char combustor products exiting at state 10 are

IL" RH"9 "*Cch^"vch 1 '"cC^^'cJ I , ,-Qo-, h10 = 1 r . ^ . , Mf1 mCh (9-9)

[m RH h9 + m CchCVch + mcCHHVc ] I-[maGC (h5 - h4) + mst (h14 - h13)]J mCh = mRH + m Cch + mcC = maGC + FFg1mFg + FFg2mFg + mCch + mcC (9-10)

9.3.3 Gas cycle performance

The net work output rate of the gas cycle can be expressed as

WnetGC = ma (( - \ ) + ma (h4 - h3 )-mGC ( - h7 )-mRH (( - h9 ) (9.11)

and the rate of heat supplied to the gas cycle as

!0GC = QL [mGCh6 - mmaGCh5 + mRH¿8 - mlGCh7] (9.12) Thermal efficiency of gas cycle is subsequently n?thGC = (9-13)

Constant polytropic efficiency for the compressor and isentropic efficiencies for gas turbine and steam turbine are assumed and a value of 85% is used (Shi and Che, 2007; Polyzakis et al., 2008).

9.3.4 Steam cycle performance

The net work output rate of the steam cycle, accounting for additional air (mair) that may be required depending on the excess oxygen balance, follows

WnetSC = mst [(h12 - h13 ) + (( - h15 )- (h17 - h16)) - mairh1 (9.14)

The rate of heat supplied to the steam cycle, not accounting for the mass flow rate of any solids since they are retained within the combustor as ash and bed material, follows

QSC = QL [mPRH (h10 - h11) + mst (h14 - h13)) (9.15)

Thermal efficiency of steam cycle is as follows:

An overall fractional heat loss QL of 3% of the heat input is assumed, and accounted for by setting QL = 0.97 (Ramaprabhu and Roy, 2004).

9.3.5 Combined cycle performance

The net work output rate of the combined cycle can be written as

and the combined cycle thermal efficiency as

9.4 System Performance Analysis

The results for the proposed IGCC configuration shown in Fig. 9.1 is computed based on fixed temperature conditions (except for the analyses explicitly involving parameter variations). That is, T3 = 370 K, T5 = T4, T6 = 1,600 K, T8 = 1600 K, T10 = 1100 K, T11 = 400 K, T12 = 900 K, and T14 = 900 K. These temperatures are chosen in such a way that it is close to the maximum operating value for the corresponding components. The mass flow rates of fuel (coal, syngas, char) are estimated from the calculations for different operating conditions in the analysis. The results are discussed based on variations of parameters (efficiency, work output, coal/char consumption, steam production, and CO2 emission) with respect to operating conditions such as pressure ratio (5-50), GTCC air inlet temperature (T5 = T4 and T5 = T4 + 100 K), gas turbine inlet temperature (1,000-1,700 K), and supplementary firing temperature (1,000 and 1,100 K). The pressure of steam used in the steam cycle are P12 = P17 = 80 bar and P13 = 40 bar. The chemical composition of four different solid fuels is given in Table 9.1 (Parikh et al., 2005), anthracite will be used for all the analyses when compared to other three fuel types.

Table 9.1 Four different solid fuels with the corresponding chemical composition (dry mass % wt) and higher heating values (Parikh et al., 2005).

Elements

Anthracite

Lignite

Pine

Wood chips

C

83.67

63.89

56.3

48.1

h2

3.56

4.97

5.6

5.99

o2

2.84

24.54

37.7

45.74

n2

0.55

0.57

0.00001

0.08

S

1.05

0.48

0.00001

0.00001

Ash

8.32

4.5

0.4

0.1

HHV (MJ)

32.85

25.1

21.77

19.92

9.4.1 Effect of gasification on combined cycle performance

The operating conditions of the combined cycle unit within the IGCC system will affect the output of the gasifier since the amount of coal consumed by gasifier is determined by operating temperatures at each state of the cycle as shown in Fig. 9.1. For the given set of temperature conditions as mentioned in the passage above, the change in values of different parameters with respect to percentage gasification are shown in Fig. 9.2. The parameters include combined cycle efficiency (CC eff), coal consumed in the gasifier (Coal,Gasif), coal consumed in the char combustor (Coal,CFBC), total coal consumed (Coal,Total), steam produced in the steam cycle (Steam), char produced in the gasifier (Char,Prod), char used in the char combustor (Char,Used), and the net work output rate (Wnet). There is significant change in the values of all the parameters up to about 45% of gasification since the amount of total coal used and char produced are highest in the region below 45% gasification. The combined cycle efficiency is lower at 30% gasification and increases rapidly up to 45% gasification and then is almost constant until full gasification is achieved. The net work output rate decreases with increase in gasification due to the reduction in mass flow rate of the stream since, the fuel input and corresponding airflow are reduced to the gasifier as gasification is increased. Total coal and coal consumed in the gasifier are same up to 75% gasification, beyond which additional coal is consumed in the char combustor to furnish the energy required to increase the temperature of the gas turbine exhaust to T10 = 1,100 K. Since the efficiency is almost constant at this point (beyond 75%) and network output is higher than at full gasification, for an IGCC shown in Fig. 9.1 partial gasification of 80% can be adapted to save coal consumption, but will have to wait till the discussion on CO2 emissions for the same conditions.

Fig. 9.2 Variation in values of parameters under investigation for the given IGCC configuration with increase in percentage gasification.

9.4.2 Effect of operating temperatures on combined cycle performance with respect to gasification

Operating temperatures refer to the inlet temperatures at three different locations within the IGCC configuration as shown in Fig. 9.1; inlet to the gas turbine combustion chamber at state 5, inlet to the gas turbine at state 6, and inlet to the HRSG

at state 10. In Fig. 9.3 eight different combinations of these three temperatures are used to observe the changes in relative net work output rate with respect to increasing gasification.

Gasification (%)

Fig. 9.3 Comparison of relative net work output among eight different temperature conditions for the IGCC configuration with increase in percentage gasification.

Gasification (%)

Fig. 9.3 Comparison of relative net work output among eight different temperature conditions for the IGCC configuration with increase in percentage gasification.

The legends are representing values of three temperatures in this fashion T5:T6:T10. From the trends in Fig. 9.3 it is clear that the temperature condition of 74:1,600:1,100 has the highest net work output rate and the lowest is with conditions of 74+100:1,500:1,000. Increasing the temperature of air (75) before it enters the gas turbine combustion chamber by 100 K decreases the net work output for all the temperature cases (four thick lines). The reason for this is that an increase in 75 reduces the syngas use in the gas turbine combustion chamber thus reducing the coal/air input to the gasifier which decreases the mass flow of the total stream bringing down the net work output. The same action happens when there is an increase in T10 (third number in each legend) which can be observed from the results in Fig. 9.3 for the respective curves where T10 is higher. Using a supplementary firing arrangement as shown in Fig. 9.1 gives an opportunity to study the influence of demand for syngas on cycle performance, based on different temperature conditions. From the set of results given in Fig. 9.3 it is better to run the unit at T4:1,600:1,100 temperature conditions.

9.4.3 Effect of operating temperature on net CO2 emissions with respect to gasification

The relative net CO2 emissions (includes CO2 emissions from gas turbine combustion chamber, reheat combustor, char combustor) for the same set of eight different temperature conditions are shown in Fig. 9.4 with increasing gasification. There is rapid decrease in CO2 emission up to about 75% of gasification mainly for the temperature cases where T5 = T4. The reason for this is the similar behaviour exhibited by coal and char consumption in Fig. 9.2. The CO2 emissions are higher for cases involving increase in T5 by 100 K (four thick lines) beyond 60% gasification compared to the four cases with T5 = T4. The reason for this is the generation of CO2 in the char combustor due to combustion of char and additional amount of coal in these cases (observed in Fig. 9.4 as abrupt change in CO2 emission trend). Because of the additional coal combusted in char combustor for supplementary firing, the trend in maximum CO2 emissions is reversed in the respective cases. Toward full gasification (beyond 70%) the highest CO2 emission is for the temperature condition of T4+100:1,500:1,100.

Fig. 9.4 Comparison of relative CO2 emission among eight different temperature conditions for the IGCC configuration with increase in percentage gasification.

This clearly proves the point discussed regarding additional coal bringing in more CO2 emission, since this temperature condition puts three loads on the char combustor - increase in T5, decrease in T6, and increase in T10. On the contrary the lowest CO2 emission (beyond 70% gasification) is reported for the temperature condition of 74:1,600:1,000 which is when all the three loads for the char combus-tor are removed.

9.4.4 Effect of gasifier-operating conditions on net specific CO2 emissions with respect to gasification

The operating conditions of gasifiers vary depending on the type of gasifier. In the current work air gasification is used and so a Lurgi moving bed gasifier is assumed. Mass flow of steam and air are the only variable-operating conditions that are tested in the current work. Figure 9.5 shows the use of four different mass flow rate of steam (40, 50, 60, 70) and four different air flow rate (50, 60, 70, 80) conditions chosen arbitrarily to study the effect of the variation.

-St = 40%:Air = 80% ---------St = 50%:Air = 80%----St = 60%:Air = 80%

-----St = 70%:Air = 80% -St = 50%:Air = 50% ---------St = 50%:Air = 60%

-----St = 70%:Air = 80% -St = 50%:Air = 50% ---------St = 50%:Air = 60%

Gasification (%)

Fig. 9.5 Comparison of CO2 emission per kg of coal in gas and steam cycles among four different flow rates of steam (St) and air (Air), respectively, used as the operating condition for the gasifier.

Gasification (%)

Fig. 9.5 Comparison of CO2 emission per kg of coal in gas and steam cycles among four different flow rates of steam (St) and air (Air), respectively, used as the operating condition for the gasifier.

The mass flow rates are specified here as percentage of coal used. The effect of these operating conditions on the net specific CO2 emissions is shown in Fig. 9.5. The specific CO2 emissions increase with gasification which is an established fact about gasification processes (Damen et al., 2006). This trend is not to be confused with that from Fig. 9.4, since that is relative CO2 emissions. The clarity of the result curves in Fig. 9.5 can be understood by looking at the thin lines first, starting with St=40%:Air=80% which has the highest CO2 emissions and the rest of the thin lines representing increase in steam mass flow percentage have equally lower CO2 emissions with one another and have merged (equal values) with decreasing air flow rate conditions. For the thick lines the condition at St=50%:Air=50% has the lowest specific CO2 emissions. With increasing steam flow rate there is decrease in specific CO2 emissions and with increase in air flow rate there is increase in the specific CO2 emissions. Remember these conditions are percentage of coal used in the gasifier. When the flow rates are increased the use of coal will also increase suggesting increased CO2 emissions. When steam flow is increased no major increase in the net stream (includes all the gases put together which exit through the stack as shown in Fig. 9.1) is observed since steam will be used for gas conversion reactions. But when air flow is increased, the inert nitrogen gas in the air continues throughout the cycle which increases the bulk of the net stream. The increase of air flow in gasifier also suggests higher syngas production, which has about 14% CO2 by weight and this contributes to the increase in specific CO2 emission. The specific CO2 emission results as shown in Fig. 9.5 suggest that it is better to send equal amounts of air and steam with corresponding quantity of coal to have lower specific CO2 emissions.

9.4.5 Effect of feedstock on net specific CO2 emissions with respect to gasification

The gasifier performance is mainly affected by the nature and chemical composition of the feedstock. In actual gasifier units, for each feedstock the corresponding syngas composition will vary. In this work the syngas composition is fixed so that the unified effect of feedstock composition on the specific CO2 emissions can be estimated. Four types of solid fuels are used as feedstock in the calculations one at a time. As listed in Table 9.1, four different fuels are chosen with decreasing heating values (which corresponds to decreasing carbon percentage). The specific CO2 emissions by the gas cycle (includes CO2 from gas turbine combustion chamber and reheat combustor) which uses syngas and by steam cycle (CO2 from the char combustor) which uses char and coal are compared with increasing gasification in Fig. 9.6. Within the gas cycle the anthracite coal emits the maximum amount of specific CO2 due to the higher carbon content of the fuel. The wood chip emits the lowest specific CO2 due to lower carbon content. The trends can be attributed to the heating value as well, since anthracite has highest heating value of all the four fuels will be consumed less thus increasing the specific emission. But since they are not relatively compared, the corresponding specific CO2 emission suggests the impact of carbon content in source fuel (feedstock). The sudden change in the CO2 emissions after certain percentage of gasification (70 for anthracite, 60 for lignite, 50 for pine, and 40 for wood chip) is caused mainly by the operating conditions of the combined cycle and is nothing to do with the composition of feedstock. For steam cycle the trend among the feedstock in terms of the difference in specific

CO2 emission values follows the gas cycle (anthracite the most and wood the least). The steam cycle has reverse trend with respect to gasification when compared to gas cycle. The reason for this is the amount of the respective fuel used from low to full gasification. Based on the net work output data (not presented) using anthracite coal is efficient especially at higher gasification but it is associated with higher CO2 emission as well. Using lignite or blend of lignite and anthracite will have moderate work output as well as CO2 emissions.

60 70

Gasification (%)

Fig. 9.6 Comparison of CO2 emission per kg coal in gas and steam cycles among four different solid fuel types as mentioned in Table 9.1. In the legends G represents gas cycle and S represents steam cycle.

60 70

Gasification (%)

Fig. 9.6 Comparison of CO2 emission per kg coal in gas and steam cycles among four different solid fuel types as mentioned in Table 9.1. In the legends G represents gas cycle and S represents steam cycle.

9.4.6 Validation of the current results with published results

Validation of the results of the current work was made by comparing them with published results. The validation becomes inconsistent since the considered IGCC design differs and the comparison based on gasification percentage is not observed. Nonetheless, the efficiency (50-56%) and net work output (150-190 MW) for the current work for varying inlet temperature conditions to the gas turbine combustion chamber (T5) and gas turbine (T6) are similar in behavior to the trends published in several gasification and combined cycle works. The operating conditions used in these works differ from those used here. For example, De and Nag (2000a, 200b) considered pressure ratios of 4-40 and obtained overall efficiencies of 37-53%, Srinivas et al. (2006) used pressure ratios of 4-32 and obtained specific work values of 2-10 MJ/kg, Butcher and Reddy (2007) used net work output (10-17 MW) and observed exhaust gas inlet temperatures of T9 = 500-600 oC. The latter is the same range as in the current work. The enthalpy values for the steam cycle at each state are within the operating range when compared with an existing power plant (Dsouza and Li, 2006). The resulting CO2 emissions (from 200 to 1400 g/kWh for all ranges of operating conditions used in this work) are within the range reported in some other works including Garcia et al. (2006), who compared three gasifiers from 750 to 900 g/kWh. Other CO2 emissions reported include 0.709 kg/kWh (Amelio et al., 2007), 0.735 and 0.777 kg/kWh (Kanniche and Bouallou, 2007), and 710-920 g/kWh (Wall, 2007). Thus the thermodynamic calculations used in the current work appear to be reliable within the range of operating conditions and for the assumptions used.

9.5 Conclusions

The effect of combined cycle and gasifier-operating conditions on the CO2 emissions and performance of an IGCC power generation system was investigated. The following conclusions were inferred from the results and discussion:

• Since the efficiency is almost constant beyond 75% gasification for the given conditions and network output is higher than at full gasification, partial gasification of about 75% can be adapted to save coal consumption.

• Supplementary firing arrangement as shown in Fig. 9.1 affects the demand for syngas in the gas cycle based on different temperature conditions of the IGCC. To have higher work output and lower CO2 emissions it is better not to increase the compressed air temperature before it enters the gas turbine combustion chamber.

• CO2 emission increases with gasification and the lowest relative CO2 emission at higher gasification is observed for the temperature condition with lower compressed air temperature and lower HRSG inlet temperature.

• Based on the operating conditions of the gasifier, the specific CO2 emission can be moderated when equal amounts of air and steam with corresponding quantity of coal are sent into the gasifier.

• High carbon content of the feedstock generates more CO2 but is efficient especially at higher gasification. Using lignite (low carbon coal) or blend of lignite and anthracite (high carbon coal) will have moderate work output as well as CO2 emissions. When CO2 emission reduction is the priority, wood chips are best for gasification.

Acknowledgment

The authors kindly acknowledge financial support from the Natural Sciences and Engineering Research Council of Canada.

Nomenclature

C

Elemental carbon

ch4

Methane

CO

Carbon monoxide

CO2

Carbon dioxide

F

Fraction

h

Specific enthalpy [J/kg]

H2

Elemental hydrogen

h2o

Water

M

Molar mass

m

Mass flow rate [kg/s]

n2

Elemental nitrogen

O2

Elemental oxygen

Q

Heat rate [J/s]

Ql

Heat loss

W

Work rate [J/s]

Subscripts

a

Air

CC

Coal/char combustor

CCC

Carbon of coal in combustor

Cch

Carbon of char

Ch

Char

GC

Gas cycle or gas combustor (GTCC)

FF

Fuel gas furnace

Fg

Fuel gas

Fg1

Fuel gas used in GTCC

Fg2

Fuel gas used in reheat combustor

PCC

Product of char combustor or coal combustor

PFF

Product of fuel gas furnace

PGC

Product of GTCC

PRH

Product of reheat combustor

RH

Reheat combustor

SC

Steam cycle

st

Steam

th

Thermal

Greek symbols r¡

Energy efficiency

Abbreviations

GTCC

HPGT

HPST

HRSG

LPGT

LPST

Gas turbine

Gas turbine combustion chamber Higher heating value [J/kg] High pressure compressor High pressure gas turbine High pressure steam turbine Heat recovery steam generator Low pressure compressor Low pressure gas turbine Low pressure steam turbine

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