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Effects of syngas type on the operation and performance of a gas turbine

in integrated gasification combined cycle

Young Sik Kim a, Jong Jun Lee a, Tong Seop Kim b,⇑, Jeong L. Sohn c

a Graduate School, Inha University, Incheon 402-751, Republic of Koreab Dept. of Mechanical Engineering, Inha University, Incheon 402-751, Republic of Koreac Center for Next Generation Heat Exchangers, Busan 618-230, Republic of Korea

a r t i c l e i n f o

Article history:

Received 28 February 2010

Received in revised form 2 January 2011

Accepted 15 January 2011

Keywords:

Integrated gasification combined cycle

Syngas type

Gas turbine

Integration degree

Turbine metal temperature

Compressor surge

a b s t r a c t

We investigated the effects of firing syngas in a gas turbine designed for natural gas. Four different syng-

ases were evaluated as fuels for a gas turbine in the integrated gasification combined cycle (IGCC). A full

off-design analysis of the gas turbine was performed. Without any restrictions on gas turbine operation,

as the heating value of the syngas decreases, a greater net system power output and efficiency is possible

due to the increased turbine mass flow. However, the gas turbine is more vulnerable to compressor surge

and the blade metal becomes more overheated. These two problems can be mitigated by reductions in

two parameters: the firing temperature and the nitrogen flow to the combustor. With the restrictions

on surge margin and metal temperature, the net system performance decreases compared to the cases

without restrictions, especially in the surge margin control range. The net power outputs of all syngas

cases converge to a similar level as the degree of integration approaches zero. The difference in net power

output between unrestricted and restricted operation increases as the fuel heating value decreases. The

optimal integration degree, which shows the greatest net system power output and efficiency, increases

with decreasing syngas heating value.

2011 Elsevier Ltd All rights reserved.

1. Introduction

Coal has the largest reserves among fossil fuels. Therefore,

worldwide efforts are focused on developing performance enhance-

ments for current coal-based power plants and devising advanced

systems [1]. The integrated gasification combined cycle (IGCC) is

considered to be the most environmentally friendly method of

using coal. IGCC plants have been in commercial operation formore

than a decade. Four full-size plants are under operation [2], and a

number of IGCC projects are ongoing worldwide [3]. Gas turbine

original equipment manufacturers (OEMs) are actively supplying

engines that are suitable for IGCC applications [4]. All of the major

OEMs, including General Electric [5], Mitsubishi Heavy Industries

[6] and Siemens [7], are preparing for the IGCC era. In addition,

studies on the constructability of IGCC plants are also being per-

formed [8]. In particular, OEMS are trying to improve gas turbine

performance and adapt their engines to the IGCC environment

[9,10]. IGCC technology is particularly promising in terms of coping

with global warming issues such as the reduction and ultimate

elimination of CO2 emissions, as illustrated in recent studies. Kanni-

che and Bouallou [11] introduced a method to capture CO2, and

Descamps et al. [12] predicted the variation in IGCC plant

performance due to CO2 capture. Dennis and Harp [13] summarized

the prospects for coal-based power generation systems, especially

the IGCC, with CO2 capture. Julianne [14] presented detailed perfor-

mance and economic data for the IGCC and other systems adopting

CO2 capture. Costas et al. [15] assessed the competitiveness of the

IGCC in terms of CO2 capture capability. In summary, the high po-

tential for relatively economical and energy efficient CO2 capture

is the major driving force for the expansion of IGCC-based systems.

An IGCC plant consists of a gasifier block and a power block. The

gasifier block converts coal to syngas and supplies the syngas to the

gas turbine. The power block is a conventional combined cycle com-

posedof a gasturbine, a heat recoverysteamgenerator, anda steam

turbine. When existing commercial gas turbines are used in IGCC

plants, their operating condition may deviate from the original de-

sign condition due to many factors. The heating value of syngas,

which consists mainly of carbon monoxide and hydrogen, is much

lower than that of natural gas, which gas turbines are usually de-

signed for.Therefore, more fuel is suppliedto the combustor, result-

ing in larger mass flow in the turbine. In addition, various options

are available to integrate the gas turbine with the air separation

unit (ASU) [2]. Turbine mass flow varies greatly depending on the

degree of integration, which is defined as a percentage of ASU air

supplied by the gas turbine compressor. Therefore, practical opera-

tional issues may limit the obtainable performance of IGCC plants.

However, most studies have not fully considered such operational

0196-8904/$ - see front matter 2011 Elsevier Ltd All rights reserved.doi:10.1016/j.enconman.2011.01.009

⇑ Corresponding author. Tel.: +82 32 860 7307; fax: +82 32 868 1716.

E-mail address: [email protected] (T.S. Kim).

Energy Conversion and Management 52 (2011) 2262–2271

Contents lists available at ScienceDirect

Energy Conversion and Management

j o u r n a l h o m e p a g e : w w w . e l s e v i e r . c o m / l o c a t e / e n c o n m a n

http://dx.doi.org/10.1016/j.enconman.2011.01.009mailto:[email protected]://dx.doi.org/10.1016/j.enconman.2011.01.009http://www.sciencedirect.com/science/journal/01968904http://www.elsevier.com/locate/enconmanhttp://www.elsevier.com/locate/enconmanhttp://www.sciencedirect.com/science/journal/01968904http://dx.doi.org/10.1016/j.enconman.2011.01.009mailto:[email protected]://dx.doi.org/10.1016/j.enconman.2011.01.009


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limitations. Several recent studies have shown that the degree of

integration significantly affects the performanceand operating con-

dition of gas turbines [16,17]. The change of operating condition

may also cause considerable changes in critical operating parame-

ters related to engine safety and lifetime. In particular, as stated

by Lee et al., the reduction of compressor surge margin is the most

critical issue [16]. The overheating of turbine metal is another seri-

ous problem as investigated by Oluyede and Phillips [18] and Kim

et al. [19]. In particular, Kim et al. [19] considered the two opera-

tional issues simultaneously. They demonstrated that a careful

selection of operating parameters is required for a safe operation

of IGCC gas turbines, and that well-controlled operation could pro-vide a safe margin for both compressor surge and turbine blade

temperature.

The properties of syngas are important issues in designing an

IGCC plant. Syngas composition may vary considerably depending

on the gasification process. Currently operating commercial IGCC

plants use syngases with diverse compositions and heating values

as shown by Dennis et al. [2]. Ligang and Edward [20] and Osamu

et al. [21] illustrated differences in syngas compositions depending

on the gasification process, and presented the results of IGCC per-

formance simulations. Moreover, if carbon capture and storage

(CCS) is applied to the gasification process, syngas composition

changes even more, increasing hydrogen content [11]. Ultimately,

the production of almost pure hydrogen is possible [22]. Therefore,

the syngas type (i.e., its composition) significantly affects gas tur-bine operation and performance, and a detailed comparative study

on the effects of syngas composition on the performance and oper-

ating conditions of gas turbines is required. Most studies dealing

with syngas property variations have not considered the effect of

syngas properties on the operability of the gas turbine, and have

not carried out full off-design analyses that could provide insights

into the realizable performance of IGCC plants. Only several groups

have performed meaningful off-design analysis. In particular, Kim

et al. [19] presented limitations on the obtainable performance of

an IGCC plant due to critical operating issues of gas turbine compo-

nents. However, their research was focused on a single syngas type.

Therefore, an evaluation of the effects of firing different types of

syngas in an IGCC plant is required. Such a study should adopt

off-design analysis and take into account the operational limita-tions of the gas turbine.

We investigated the effect of syngas type on the operation and

performance of a gas turbine and the entire power block of an IGCC

plant. Four different syngas compositions were considered for use

in a state-of-the art gas turbine engine. Comprehensive component

models including turbine blade cooling were used. A full off-design

analysis using a compressor map was adopted to perform a realis-

tic simulation. The analysis examined the simultaneous influences

of syngas type and integration degree on compressor surge margin

and turbine blade temperature. Then, system performance under

the restrictions of the two parameters was investigated.

2. System modeling

2.1. System configuration

Fig. 1 shows the system analyzed in this study. Since our goal

was to investigate the operation and performance of the power

block, especially the gas turbine, the details of the gasification

block were not modeled. Instead, syngas compositions and corre-

sponding mass balance data were taken from the literature. The

systemincludes the entire power block, which consists of a gas tur-

bine and a bottoming steam turbine cycle. Also included in the

analysis are the auxiliary air compressor, and the oxygen andnitro-

gen compressors that interact with the gas turbine. The analysis

was performed using GateCycle [23].Oxygen is separated from the air at the ASU and supplied to the

gasifier to produce syngas. There are various ways to supply air to

the ASU. Air can be supplied solely by the gas turbine compressor,

which is called 100% integration degree design. On the other hand,

an auxiliary air compressor can supply all the air to the ASU, in

which case the integration degree is 0%. An integration degree be-

tween 0% and 100% means that both the gas turbine compressor

and the independent compressor supply air to the ASU. Integration

degree is defined as follows [16,19]:

Integration degree ¼ Air to ASU from GTTotal air to ASU

¼ _m1_m3

ð1Þ

The turbine gas flow rate varies greatly depending on the inte-

gration degree, which affects the operating condition of the gasturbine.

Nomenclature

A area (m2)ASU air separation unitC cooling constantc p specific heat (kJ/kg K)GT gas turbine

i locationIGCC integrated gasification combined cycleLHV lower heating value (kJ/kg)_m mass flow rate (kg/s)

P pressure (kPa)PR pressure ratioR gas constant (kJ/kg K)T temperature (K)TRIT turbine rotor inlet (firing) temperature (K)_W power (MW)

Greek symbols/ cooling effectivenessc specific heat ratiog efficiency

j constant

Subscriptsaux auxiliaryb blade metal

C compressorc coolantCC combined cyclecomp auxiliary compressord design point g gas gen generatorin inletm mechanicalref reference dataST steam turbinesys systemT turbine1 asymptotic

Y.S. Kim et al. / Energy Conversion and Management 52 (2011) 2262–2271 2263


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2.2. Syngas

Table 1 shows the compositions and heating values of four dif-

ferent syngas fuels used in this study and those of natural gas used

for the reference design calculation. These values were taken from

literatures [14,24], which published complete mass and energy

balances for IGCC plants including syngas properties. Syngas A

has the lowest heating value, and syngas B has a slightly higher

heating value than A. The major components are carbon monoxide

and hydrogen. Application of the CO2 capture process to syngas Bproduces syngas C. Hence, the hydrogen content of syngas C is

much higher than those of syngases A and B. Syngas D is pure

hydrogen. The relative mass flow rates at different locations, as re-

ported in [14,24], were used; thus, a detailed analysis of the gas-

ifier block was not necessary. Instead, we adopted a simplified

method used in [19]. A mass balance for the system in this study

was obtained by scaling the mass balance data given in the litera-

tures [14,24]. The relative mass flow rates per unit syngas flow rate

in the four syngas types were calculated from the literature and are

shown in Table 2. The required syngas flow rate ( _m6) was deter-

mined by the gas turbine calculation. Then, the following equation

yielded flow rates at other locations [19]:

_mi ¼ _m6 _mi_m6

ref

ð2Þ

The subscript i denotes locations 3–5 (where the flow rates

should be determined), and the subscript ‘ref’ means the flow ratio

from the literature. Finally, for any given integration degree, the air

flow rates at locations 1 and 2 were obtained. This method is quite

feasible. According to Ligang and Edward [20] and Osamu et al.

[21], syngas composition and mass flow rates remain constant

once the gasifier operation reaches a normal operation. Thus, it is

reasonable to assume that the syngas composition of a specific pro-

cess (each of the four cases in this study) is unchanged even though

the absolute flow rate of the syngas may vary depending on the

fuel supply required by the gas turbine.

2.3. Gas turbine

Table 3 showsthemajor design dataof thegasturbineusedin thisanalysis. The power output and efficiency represents state-of-the-

Fig. 1. Schematic diagram of the system.

Table 1

Properties syngas and natural gas.

Component (mole fraction) Natural gas Syngas

A B C D

Ar (%) – 0.88 0.86 0.99 0

CH4 (%) 91.33 0.06 0.03 0.04 0

C2H6 (%) 5.36 – – – –

C3H8 (%) 2.14 – – – –

C4H10 (%) 0.95 – – – –

CO (%) – 35.12 50.8 2.56 0

CO2 (%) – 13.1 0.05 2.04 0

H2 (%) – 31.42 25.79 85.84 100H2O (%) – 16.39 17.52 3.27 0

N2 (%) 0.22 3.01 4.94 5.26 0

LHV (kJ/kg) 49303.0 8621.6 10493.8 37018.1 119914.6

Table 2

Relative mass flow rates.

Element (location) A B C D

ASU (3) 1.684 1.766 6.923 29.058

N2 compressor (4) 1.297 1.324 5.333 18.708

O2 compressor (5) 0.387 0.442 1.589 6.971

Syngas (6) 1.0 1.0 1.0 1.0

2264 Y.S. Kim et al. / Energy Conversion and Management 52 (2011) 2262–2271


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art frame F gas turbines, especially the GE7FA [25,26]. The design

fuelis naturalgas. Comprehensivecomponentmodels including tur-

bine blade cooling were used. The turbine rotor inlet temperature

(TRIT) is the inlet temperature of the first stage rotor, which is often

referred to as the firing temperature. All five blade rows except the

last rotor blade were cooled. The simulation results are in good

agreement with performance data from the literature [25].

An off-design analysis of the gas turbine is required to examine

the change in operation and performance caused by the fuel

change from natural gas to syngas. A compressor map was used

to model the operating characteristics of the compressor. Themap will be illustrated in the results section with illustrations of

operating point changes. The design surge margin of the compres-

sor was assumed to be 20%. The surge margin is defined as [16,19]

Surge margin ¼ PR surge PR operationPR operation

ð3Þ

The off-design operation of the turbine is represented by the

following choking condition [27].

_min ffiffiffiffiffiffiT in

p

j AinP in¼ constant; where j ¼

ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffifficR

2

cþ 1 cþ1

c1

v uut ð4ÞThus, the operating condition of the gas turbine was determined

by matching the characteristics of the compressor and the turbine.

Therefore, if the turbine inlet condition changes (e.g., an increase in

mass flow), the matching between the turbine and the compressor

causes a change in the working pressure ratio of the compressor,

thereby affecting the surge margin.

Analysis of the change in turbine blade temperature due to the

fuel change is another purpose of this study. We focused on the

change in temperature of the stator vane (nozzle) of the first tur-

bine stage. A simple thermodynamic model was adopted. The cool-

ing effectiveness is defined as follows [28]:

/ ¼ T g T bT g T c ð5Þ

At the design point, the gas temperature, the coolant temperature,and the blade metal temperature were 1670 K, 681 K, and 1144 K

respectively. The corresponding design cooling effectiveness was

determined to be 53.2%. The main parameter governing the change

in the cooling effectiveness for off-design conditions is the ratio be-

tween the thermal capacities ( _m c p) of the coolant and the hot gas.

The following equation represents this relationship [28]:

_mc c p;c _m g c p; g ¼ C

/

/1 / ð6Þ

where /1

represents the asymptotic cooling effectiveness, the va-

lue of which is 1.0, corresponding to a very high thermal capacity

ratio. C represents the technology level of the cooling scheme, and

it value was decided to satisfy Eq. (6) at the design condition. The

equation is an asymptotic curve between the thermal capacity ratio

and the effectiveness [19], and was used to determine theblade me-

tal temperature at off-design conditions.

The following model [29] was used to simulate the change in

coolant flow rate due to a variation in operation conditions.

_mc ¼ _mc ;d P c P c ;d

T c ;dT c

0:5ð7Þ

Once the flow rates and temperatures of the hot gas and the

coolant were known for an off-design operation, the cooling effec-

tiveness was calculated using Eq. (6). Then, the blade metal tem-

perature was calculated using Eq. (5).

The net power output and efficiency of the gas turbine are de-

fined as follows.

_W GT ¼ ð _W T gm W C Þ g gen ð8Þ

gGT ¼_W GT

ð _m LHVÞsyngasð9Þ

2.4. Power block performance

A triple pressure steam turbine bottoming cycle was used (see

Fig. 1). The major parameters of the bottoming cycle are listed in

Table 4. The combined cycle power output is defined as follows:

_W CC ¼ _W GT þ _W ST ð10Þ

Table 3

Design specifications of the gas turbine.

Item This work Reference data [25,26]

Inlet Air temperature (K) 288.2 288.2

Air pressure (kPa) 101.3 101.3

Pressure loss (%) 0.5 NA

Air flow (kg/s) 435.5 NA

Compressor Pressure ratio 16 16

Number of stages 18 18

Polytropic efficiency (%) 90.0 NA

Combustor Fuel Natural gas Natural gas

Fuel lower heating value (kJ/kg) 49,244 NA

Fuel flow (kg/s) 9.47 NA

Pressure loss (%) 4.0 NA

Turbine Turbine inlet temperature (K) 1670 NA

Turbine rotor inlet temperature (K) 1600 1600

Turbine exhaust temperature (K) 874.2 878.2

Number of stages 3 3

Stage efficiency (%) 88.1 NA

Total coolant relative to compressor inlet air flow (%) 18.3 NA

Coolant of the first stage vane relative to compressor inlet air flow (%) 7.3 NA

Exhaust pressure loss (%) 0.5 NA

Exhaust gas flow (kg/s) 445.0 445.0

Performance Mechanical efficiency (%) 99.5 NA

Generator efficiency (%) 98.5 NA

Power output (MW) 171.6 171.7

Thermal efficiency (%) 36.8 36.8



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The steam turbine cycle power includes the power consump-tion of the pumps in the bottoming cycles.

Thenet performance of the entiresystem was less than the com-

bined cycle performance because the entire system consumed con-

siderable auxiliary power. The amount of auxiliary power depends

significantly on system design options such as the integration de-

gree. The power consumption of the auxiliary air compressor and

the oxygen and nitrogen compressors were calculated using the

previously determined mass flows at locations 2, 4, and 5. The as-

sumed values of the parameters for the auxiliary components are

listed in Table 5. The total auxiliary power consumption was calcu-

lated as follows:

_W aux ¼ _W air ;comp þ _W O2 ;comp þ _W N 2 ;comp ð11ÞThen, the net power output and efficiency of the entire power

block were obtained by substracting the auxiliary power consump-

tion from the combined cycle power output:

_W sys ¼ _W CC _W aux;gsys ¼_W sys

ð _m LHVÞsyngasð12Þ

Our analysis consists of two parts. The first part had no restric-

tions on gas turbine operation. The general trend of gas turbine

operation and performance with respect to the syngas type and

the integration degree was examined. The only limitation was that

the compressor surge margin was greater than zero. The second

part was an analysis with practical considerations on the restric-

tions of the compressor and turbine operation. Combined restric-

tions on the allowable surge margin and turbine metal

temperature were assumed, and their effect on system perfor-

mance was comparatively evaluated for various syngas fuels.

3. Results and discussion

3.1. Validation

The design point analysis was validated by the excellent agree-

ment between the simulation and the reference design data, as

shown in Table 1. The most important point in this study was

the capability of the program to precisely simulate the perfor-

mance variation at off-design operating conditions. As a validation

of the off-design simulation model, the variation in the full load

(full firing; i.e., the design TRIT) performance of the gas turbine(GE7FA) was predicted and compared with the reference data.

Fig. 2 shows the simulated results along with reference data from

[26]. We adopted the 7FA compressor map embedded in GateCycle

[23]. The simulation results are in good agreement with the refer-

ence data. The deviation of the exhaust mass flow is almost negli-

gible, and the maximum deviations of power output and thermal

efficiency were only 1.3% and 0.5%, respectively. Therefore, both

the design and off-design simulation results confirmed that the

current simulation tool could provide a feasible simulation of gas

turbine operation.

3.2. Gas turbine operation without restrictions

Previous works [16,19] showed that the working condition of a

gas turbine is significantly affected by the selection of the integra-

tion degree. A lower integration degree increases the inlet gas flow

of the turbine, and thus increases the pressure at the turbine inlet.

Therefore, a lower integration degree causes the working pressure

ratio of the compressor to rise, thereby reducing the surge margin

considerably. The present study intended to demonstrate the com-

bined effects of syngas type and integration degree on the opera-

bility and performance of a gas turbine.

As an introductory example, the predicted working conditionsof a gas turbine fed by the four different syngases at a fixed integra-

tion degree of 50% are shown on the compressor map in Fig. 3. The

ambient condition is the ISO condition (288 K, 101.3 kPa) that the

gas turbine was designed for. The firing temperature (TRIT) is also

fixed at the design temperature (1600 K); i.e., all the points on the

Table 4

Parameters of the bottoming cycle.

High pressure turbine inlet pressure (kPa) 18,000

Intermediate pressure turbine inlet pressure (kPa) 4000

Low pressure turbine inlet pressure (kPa) 300

High pressure steam temperature (K) 833

Reheat steam temperature (K) 833

Condensing pressure (kPa) 7

Pinch temperature difference (K) 10

Isentropic efficiency of turbine (%) 82

Gas side pressure loss at HRSG (%) 3

Table 5

Parameters of auxiliary compressors.

Auxiliary air

compressor

N2compressor

O2compressor

Inlet pressure (kPa) 101.3 634.3 634.3

Outlet pressure (kPa) 1314.1 3171.6 5102.1

Isentropic efficiency (%) 90 90 90

Motor efficiency (%) 90 90 90

-10 -5 0 5 10 15 20 25 30

Calcluation results

Reference data

R e l a t i v e v a r i a t i o n s

Ambient Temperature (OC)

Design point

Power

Thermal efficiency

Exhaust mass flow

0.8

0.9

1.0

1.1

1.2

1.3

Fig. 2. Validation of the off-design simulation: variation in full load performance of

the gas turbine with ambient temperature.

0.90 0.95 1.00 1.05

P R / P R d

Relative flow

Design point

D

C

B

A1171 K

1159 K

1156 K

1150 K

Turbine 1st vanetemperature (K) Syngas

0.7

0.8

0.9

1.0

1.1

1.2

1.3

Fig. 3. Full load conditions of the gas turbine using different syngas fuels on thecompressor working line for the case of 50% integration degree.



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map are full load conditions. All the nitrogen from the air separa-

tion unit is supplied to the gas turbine combustor (full dilution).

The design point means the full load conditions of the gas turbine

using natural gas as fuel. It is clearly shown in Fig. 3 that the work-

ing pressure ratio of the compressor varied significantly according

to the type of syngas fuel. As the heating value of the fuel de-

creased (from D to A), the gas turbine needed a larger amount of

fuel flow to maintain the same firing temperature, thus causing

the turbine inlet gas flow to increase. Then, according to the

matching between the turbine inlet and the compressor exit condi-

tions, the compressor pressure ratio increased. Hence, syngas A,

which had the lowest heating value, exhibited the highest pressure

ratio, while syngas D showed the lowest pressure ratio. Even in this

50% integration degree, syngas A resulted in a very small surge

margin which is not usually tolerable for safe gas turbine opera-

tion. Thus, an integration degree less than this value cannot be

adopted in practice. Also indicated in Fig. 3 are the blade metal

temperatures for operation with different syngas fuels. All cases

cause the metal temperature to rise above the design temperature

(1144 K). The influence of syngas type is explained as follows. Since

the turbine rotor inlet temperature is maintained at a constant va-

lue, the inlet gas temperature of the first stage vane is almost con-

stant. However, as the heating value decreases, the gas flow rate at

the first vane inlet increases, resulting in decreased cooling effec-

tiveness (Eq. (6)). Furthermore, the cooling air temperature also

rises due to the increased coolant pressure (i.e., the compressor

discharge pressure). As a result, as the heating value of the syngas

fuel decreases, metal overheating becomes more serious.

Figs. 4 and 5 show the combined effects of syngas type and inte-

gration degree on the compressor surge margin and the first vane

metal temperature. It is clearly seen that the syngas type strongly

affects the operating condition. In the entire integration degree

range, surge margin decreases and metal temperature rises as

the heating value of the syngas decreases. The two problems be-

come worse with decreasing integration degree for all syngas

types. At 100% integration degree where all the air for the ASU is

extracted from the gas turbine compressor, the surge margins of A and B are smaller than the design margin of 20% (i.e., the com-

pressor discharge pressure is higher) because the turbine mass

flow is greater than that of the natural gas-fired case due to the

greater fuel flow. The increased turbine hot gas flow also increases

the first vane metal temperature compared to the natural gas-fired

case. However, syngases C and D exhibited larger compressor surge

margins compared to the natural gas-fired case in the high integra-

tion degree regime. Note that the syngases C and D were produced

by applying the CO2 capture process to the raw syngas in the gas-

ifier. Thus, much of the oxygen supplied by the compressor and the

carbon supplied by coal was extracted out of the gasifier and was

not fed to the combustor. This is explained by the large difference

between the ASU air flow and the syngas flow as shown in Table 2.

As the purity of the hydrogen became higher (from C to D), the

fraction of the extracted gas from the gasifier increased, and thus

the turbine inlet flow rates decreased to a greater degree. Due to

this flow extraction, the compressor discharge pressure was lower

than that of the natural gas-fired case in the high integration de-

gree regime, resulting in a greater surge margin.

A lower integration degree causes a reduction in surge margin

and an increase in turbine metal temperature due to increased tur-

bine flow, which is the same trend as in previous studies [16,19]. In

fuels C and D, a positive surge margin is still left even at 0% integra-

tion degree. In particular, the pure hydrogen case may allow more

than 5% surge margin at 0% integration degree. On the other hand,

fuels A and B do not allow a positive surge margin at near-zero

integration degrees. As the heating value of the syngas decreases,the value of the lowest realizable integration degree, which guar-

antees a minimum surge margin, becomes higher. For example, if

we assume that a minimum surge margin of 5% should be ensured

for all circumstances, the lowest obtainable integration degrees are

55% and 30% for syngases A and B, respectively. At these operating

conditions, the first vane metal temperature exceeds the design va-

lue by about 25 K. This overheating may reduce blade lifetime

considerably because the lifetime decays exponentially with

increasing temperature [30]. With fuels C and D, even though the

gas turbine is still operable at very high integration degrees, the

turbine metal overheating problem still exists and thus should be

alleviated.

Fig. 6 shows the net gas turbine power output and efficiency. A

larger turbine flow is affirmative in terms of gas turbine power out-put [16,19]. Therefore, for all fuels, a reduced integration degree

yields a larger power output. The effect of syngas heating value

can be similarly understood. A lower syngas heating value causes

an increase in turbine flow, thus leading to a larger gas turbine

power output. Hence, fuels A and B generally produce more power

output than fuels C and D. In fuels C and D, since the hydrogen con-

tent of the fuel is very high, the combustion gas contains consider-

able H2O. This is advantageous in terms of turbine power because

the specific heat of H2O is higher than the specific heats of other

combustion gas components. This explains the relatively small

power gap between fuel C and B as shown in Fig. 6. The major

parameter that governs gas turbine efficiency is the pressure ratio.

Therefore, a lower integration degree or a lower fuel heating value

leads to higher gas turbine efficiency due to an increased pressureratio.

0 20 40 60 80 100

Syngas A

Syngas B

Syngas C

Syngas D

S u r g e m a r g i n ( % )

Integration Degree (%)

-5

0

5

10

15

20

25

30

Fig. 4. Variation in surge margin with integration degree.

1130

1140

1150

1160

1170

1180

1190

Syngas A

Syngas B

Syngas C

Syngas D

T e m p e r a t u r e ( O C )


0 20 40 60 80 100

Fig. 5. Variation in first vane metal temperature with integration degree.



7/10

Fig. 7 shows the net system performance. The steam turbine

power increases with decreasing integration degree in proportionto the increased gas flow, but the auxiliary power consumption

also increases because of the increased demand of the air supply

from the auxiliary compressor. Therefore, the increase in the net

system power by a reduction in the integration degree is not as

large as the increase in the gas turbine power output. For example,

in fuel C, the benefit of a net system power output with 0% integra-

tion degree over 100% integration degree is about 43 MW, while

the benefit in the gas turbine power is 72 MW. The increased tur-

bine gas flow with decreasing syngas heating value is positive in

terms of the steam turbine power output. As a result, the net sys-

tem power output and efficiency also increase with decreasing

syngas heating value. With regard to the power increase, mechan-

ical issues, such as limits of generator capacity, blade stress and

thrust bearing, might also be examined. Since this study intended

to present thermodynamic performance capacities associated with

fuel change, mechanical issues were not considered in detail.

Mechanical reinforcements or redesign of critical components

might be required if the power increase exceeds the design margin,

but their effects on thermodynamic performance would be very

limited.

In summary, as the heating value of the syngas decreases, great-

er net systempower output and efficiency is possible, but the surge

margin reduces and the turbine metal becomes increasingly over-

heated. As a result, the limiting (lowest obtainable) integration de-

gree increases as the syngas heating value decreases. In other

words, operable integration degree range decreases as the syngas

heating value decreases.

3.3. Restrictions on compressor and turbine operation

The operation of gas turbines in IGCC plants has two critical is-

sues: operational safety of the compressor associated with reduced

surge margin, and significantly increased turbine metal tempera-

ture [19]. We showed another important issue related to the syn-

gas type as discussed in the previous section: a lower fuel

heating value is favorable in terms of thermodynamic perfor-

mance, but is negative with respect to these two problems. The

previous study [19] demonstrated the possibility of mitigating

the two problems by modulating gas turbine parameters such as

firing temperature, nitrogen flow and turbine coolant flow. The

problem of overheating the turbine metal can be prevented by

reducing the firing temperature. Thus, for any working environ-

ment (integration degree and syngas type), firing temperature

can be modulated to meet a desired blade temperature. The reduc-

tion of firing temperature also has the advantage of naturally

decreasing the compressor discharge pressure. Fig. 8 shows an

example of the effect of reducing firing temperature to keep the

first vane metal temperature at the design value on the working

condition of compressor for syngas B. At all integration degrees,

the blade overheating problem is solved and the surge margin im-

proves. However, the surge margin in the low integration degree

range is still too small. The situation is even worse with syngas

A: even at a relatively moderate integration degree (e.g. 50%), the

operating pressure closely approaches or exceeds the surge point.

The firing temperature may be further decreased to hold the surge

margin at a safe value in the low integration degree range. How-

ever, this results in too great a penalty in gas turbine power output

[19]. Accordingly, a more practical option is to maintain an allow-

able surge margin over the entire integration degree range using acombined modulation of multiple parameters.

As a case study, a surge margin of 10% was considered to be a

minimum value below which the gas turbine should not operate,

as described in [19]. Fig. 9 shows the operating strategy of the

gas turbine using syngas A in terms of compressor surge margin

and firing temperature. The strategy was intended to solve both

the turbine overheating problem and the surge problem by simul-

taneously modulating the firing temperature and the nitrogen flow

to the combustor. In regime ‘a,’ the firing temperature is modu-

lated to produce the design metal temperature of the first stage

vane. In that region, the surge margin decreases as the integration

0 20 40 60 80 100

Syngas A

Syngas B

Syngas C

Syngas D

η GT

( % )


W G

T ( M W )

50

100

150

200

250

30

35

40

45

50

Fig. 6. Variations in gas turbine power output and efficiency with integration

degree.

50

51

52

53

54

55

0 20 40 60 80 100

Syngas A

Syngas B

Syngas C

Syngas D

s y s ( % )


W s y s

( M W )

160

180

200

220

240

260

280

300

Fig. 7. Variations in net system power output and efficiency with integrationdegree.

0.7

0.8

0.9

1

1.1

1.2

1.3

0.90 0.95 1.00 1.05

operation with a fixed firing temperature

operation with a fixed 1st vane metal temperature

P R / P R d

Relative flow

Integrationdegree

0%

25%

50%

75%

100%

Fig. 8. Effect of firing temperature reduction on compressor operation for syngas B.



8/10

degree decreases. Below an integration degree such that the surge

margin reaches the minimum value of 10%, the turbine metal tem-

perature is still maintained as constant by keeping the firing tem-

perature. At the same time, the surge margin is forced to be

maintained at 10% by modulating the nitrogen flow. By reducing

the nitrogen flow in regime ‘b,’ the net turbine inlet flow is kept

constant to maintain the target surge margin. Modulation of tur-

bine coolant flow would provide a similar effect of keeping the tar-

get surge margin, and could also yield higher engine performance

[19], but this could require a full revision of the engine components

such as the secondary air system and cooled turbine blades. Thus,

in this study, only the nitrogen flow modulation was adopted to

minimize engine modification.

Fig. 10 shows the variations in the flow rates of the turbine inlet

gas and the supplied syngas for syngas A. In regime ‘a’ where the

firing temperature is reduced with decreasing integration degree,

the gas flow to the turbine increased with decreasing integrationdegree because the amount of air supplied to the ASU by the aux-

iliary compressor increases. In regime ‘b,’ the turbine inlet gas flow

remained constant while the fuel supply decreased as the integra-

tion degree decreased. Fig. 11 shows the variations of powers with

respect to the integration degree. In regime ‘a,’ the gas turbine

power output increases with decreasing integration degree. This

means that even though the firing temperature decreases, the in-

creased turbine gas flow dominates. In regime ‘b,’ gas turbine

power did not increase with decreasing integration degree. It re-

mained effectively unchanged because both the firing temperature

and turbine gas flow remained constant. The combined cycle

power output showed a pattern similar to the gas turbine power.

The auxiliary power consumption increased with decreasing inte-gration degree because the air supply from the auxiliary compres-

sor increased. The resulting net system power output and

efficiency are shown in Fig. 12. The nitrogen modulation reduced

the net system power output as the integration degree decreased

in surge-controlled regime ‘b’ because the gas turbine power out-

put remained nearly constant, but the auxiliary power consump-

tion still increased. The net system efficiency increased slightly

as the integration degree decreased in regime ‘a.’ However, in re-

gime ‘b,’ efficiency decreased with decreasing integration degree.

Therefore, the net system power output and efficiency have a peak

value at the boundary of the two regimes.

Similar calculations under the restrictions of the blade temper-

ature and surge margin were carried out for the other three syngas

cases, and Figs. 13 and 14 show net system performance for allsyngas cases together. The results of the unrestricted operations

shown in Fig. 7 are also shown as dotted lines for comparison.

All four cases have peak values, but the corresponding integration

degrees are quite different. The peak point moved to a lower inte-

gration degree range as the fuel heating values decreased. This is

quite natural because unrestricted operation gives a larger surge

margin for a higher fuel heating value over the entire integration

degree range (Fig. 4). Even in regime ‘a,’ power output of the re-

stricted operation is smaller compared to the unrestricted opera-

1550

1560

1570

1580

1590

1600

Surge margin

Firing temperature

S u r g e m a r g i n ( % )

F i r i n g t em p er a t ur e ( K )

Integration degree (%)

ab

modlation of

firing temp.

Modulation of

diluting nitrogen

0 25 50 75 1000

5

10

15

20

Fig. 9. Surge margin and firing temperature setting for a safe gas turbine operation

(syngas A).

56

58

60

62

64

0 25 50 75 100

Turbine inlet gas flow

Syngas flow

T u r b i n e i n l e t g a s f l o w ( k g / s

)

S yn g a sf l ow

( k g / s )


370

380

390

400

410

420

430

Fig. 10. Variations in turbine inlet gas flow and syngas fuel flow with integrationdegree for the operation with restrictions (syngas A).

0 25 50 75 100

Gas turbine power Combined cycle power

Auxiliary power consumption

P o

w e r ( M W )


0

50

100

150

200

250

300

350

Fig. 11. Variations in power outputs and auxiliary power consumption with

integration degree for the operation with restrictions (syngas A).

0 25 50 75 100

System power

System efficiency

P o w e r ( M W )

E f f i ci en c y ( % )


240

250

260

270

280

290

300

50.5

51.0

51.5

52.0

Fig. 12. Variations in net system power output and efficiency with integrationdegree for the operation with restrictions (syngas A).



9/10

tion. However, a much greater penalty in power output was ob-

served in regime‘b.’ It is interesting to note that the net power out-puts of all cases converged to a similar level as the integration

degree approached zero. As a result, the difference in the net power

outputs of the unrestricted and restricted operations became

greater as the fuel heating value decreased. For example, at 50%

integration degree, the power penalties of fuels A, B, C, and D are

26.9, 13.4, 8.9, and 4.2 MW, respectively. If we extrapolate the per-

formance of fuels A and B up to 0% integration degree (with the as-

sumed design surge margin of 20%, the gas turbine cannot operate

without the restrictions using fuels A or B), the power penalties are

roughly 57 and 40 MW for A and B, respectively. The power penal-

ties for C and D at 0% integration degree are 29.9 and 16.8 MW,

respectively. The efficiency showed a trend similar to the power

output. However, the efficiency differences among the four cases

are not considerable, and the efficiency penalty from the unre-stricted operation remains within one percentage point.

The analysis described in this section demonstrates that there is

an optimal integration degree, considering practical restrictions on

the gas turbine operation. The optimal point is the peak perfor-

mance point and is recommended for design. The optimal integra-

tion degree increases with decreasing syngas heating value. Table 6

summarizes the optimal performance of all syngas cases. Fuel A

has the largest peak power output. It exhibits a peak power output

that is 12.8 MW greater than fuel D. This means that the practical

restrictions on the gas turbine components have a leveling effect

on the obtainable performance among different syngas fuels.

4. Conclusion

We investigated the influence of syngas type on the perfor-

mance of a gas turbine and the entire power block of an IGCC plant.

As the heating value of the syngas decreased, a greater net system

power output and efficiency was possible due to increased turbine

mass flow; however, the gas turbine is more vulnerable to com-

pressor surge and the blade metal became increasingly overheated.

As a result, the limiting (lowest obtainable) integration degree be-

came higher as the syngas heating value decreased, i.e. the opera-

ble integration degree range decreased with decreasing heatingvalue.

The problems of compressor surge margin reduction and tur-

bine metal overheating can be solved by a combination of reduc-

tions in the firing temperature and the nitrogen flow to the

combustor. With these restrictions, the net system power output

and efficiency increased as the integration degree decreased until

the surge margin control began. After this peak point, the system

performance decreased with decreasing integration degree. The

net power outputs of all fuel cases converged to a similar level as

the integration degree approached zero. As a result, the difference

in the net power outputs of unrestricted and restricted operation

became larger as the fuel heating value decreased. The optimal

integration degree, which shows the greatest net system power

output and efficiency, increased with decreasing syngas heatingvalue. The variation in net system efficiency among the different

syngas types is marginal. The restrictions on the gas turbine com-

ponents have a leveling effect on the obtainable performance

among different syngas fuels.

Acknowledgments

This research was supported by Basic Research Program

through the National Research Foundation of KOREA (NRF) funded

by the Ministry of Education, Science and Technology (2009-

0073734).

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